air individual permit major amendment 04700061-101 for reg ... · reg albert lea, llc (reg) is a...

Air Individual Permit Major Amendment

04700061-101 Permittee: REG Albert Lea LLC

Facility name: REG Albert Lea LLC 15200 780th Ave Albert Lea, MN 56007-7082 Freeborn County

Operating permit issuance date: September 14, 2004 Expiration date: Non-expiring Permit * All Title I Conditions do not expire Major Amendment: February 26, 2018 Permit characteristics: State; Limits to avoid Part 70/ True minor for NSR The emission units, control equipment and emission stacks at the stationary source authorized in this permit amend are as described in the Permit Applications Table. This permit amend supersedes Air Emission Permit No. 04700061-003 and authorizes the Permittee to operate the stationary source at the address listed above unless otherwise noted in the permit. The Permittee must comply with all the conditions of the permit. Any changes or modifications to the stationary source must be performed in compliance with Minn. R. 7007.1150 to 7007.1500. Terms used in the permit are as defined in the state air pollution control rules unless the term is explicitly defined in the permit. Unless otherwise indicated, all the Minnesota rules cited as the origin of the permit terms are incorporated into the SIP under 40 CFR § 52.1220 and as such are enforceable by the U.S. Environmental Protection Agency (EPA) Administrator or citizens under the Clean Air Act.

Signature: Carolina Espejel-Schutt This document has been electronically signed. for the Minnesota Pollution Control Agency

for Don Smith, P.E., Manager Air Quality Permits Section Industrial Division

Table of Contents

Page

1. Permit applications table ............................................................................................................................................. 3 2. Where to send submittals ............................................................................................................................................ 4 3. Facility description ....................................................................................................................................................... 5 4. Summary of subject items ........................................................................................................................................... 6 5. Limits and other requirements .................................................................................................................................... 7 6. Submittal/action requirements ................................................................................................................................. 46 7. Appendices ................................................................................................................................................................. 48

Appendix A. Insignificant Activities and General Applicable Requirements ............................................................ 48 Appendix B. TRE Index Value Calculation Methods ................................................................................................. 50 Appendix C. Flare Calculations ................................................................................................................................. 52 Appendix D. EAW Modeling for Permit No. 04700061-003 .................................................................................... 53 Appendix E. Equipment Leaks Calculation ............................................................................................................... 54 Appendix F. Modeling for Permit No. 04700061-101 .............................................................................................. 55 Appendix G. 40 CFR pt. 60, subp. A – General Provisions........................................................................................ 56

Permit issued: February 26, 2018 04700061-101 Permit expires: Non-expiring of 181

1. Permit applications table

Subsequent permit applications: Title description Application receipt date Action number Minor Amendment October 20, 2016 04700061-101 Major Amendment October 20, 2016, with supplemental

information received on November 9, 2017, and January 9, 2018

04700061-101


2. Where to send submittals

Send submittals that are required to be submitted to the EPA regional office to: Chief Air Enforcement Air and Radiation Branch EPA Region V 77 West Jackson Boulevard Chicago, Illinois 60604

Each submittal must be postmarked or received by the date specified in the applicable Table. Those submittals required by Minn. R. 7007.0100 to 7007.1850 must be certified by a responsible official, defined in Minn. R. 7007.0100, subp. 21. Other submittals shall be certified as appropriate if certification is required by an applicable rule or permit condition.

Send submittals that are required by the Acid Rain Program to:

U.S. Environmental Protection Agency Clean Air Markets Division 1200 Pennsylvania Avenue NW (6204N) Washington, D.C. 20460

Send any application for a permit or permit amendment to:

Fiscal Services – 6th Floor Minnesota Pollution Control Agency 520 Lafayette Road North St. Paul, Minnesota 55155-4194

Also, where required by an applicable rule or permit condition, send to the Permit Document Coordinator notices of:

a. Accumulated insignificant activities b. Installation of control equipment c. Replacement of an emissions unit, and d. Changes that contravene a permit term

Unless another person is identified in the applicable Table, send all other submittals to:

AQ Compliance Tracking Coordinator Industrial Division Minnesota Pollution Control Agency 520 Lafayette Road North St. Paul, Minnesota 55155-4194

Or Email a signed and scanned PDF copy to: [email protected] (for submittals related to stack testing) [email protected] (for other compliance submittals) (See complete email instructions in “Routine Air Report Instructions Letter” at http://www.pca.state.mn.us/nwqh472.)

mailto:[email protected]

mailto:[email protected]

http://www.pca.state.mn.us/nwqh472


3. Facility description

The REG Albert Lea LLC (Facility) is located at 15200 780th Ave in Albert Lea, MN, Freeborn County, Minnesota. REG Albert Lea, LLC (REG) is a biodiesel manufacturing plant located near Albert Lea, Minnesota. The facility produces biodiesel from soybean oil and methanol, and lower quality feedstocks such as used cooking oil, inedible corn oil, and lower quality animal fats. Currently, the facility is restricted by a production permit limit of 38,000,000 gallons of biodiesel per year. The facility is a true minor source under the federal Prevention of Significant Deterioration (PSD) program. The facility is a synthetic minor source under the federal National Emission Standards for Hazardous Air Pollutants (NESHAP) and Part 70 programs for methanol (a federally-designated Hazardous Air Pollutant, HAP) and total HAPs. The main sources of methanol emissions are equipment leaks and from the distillation process. A flare (TREA 2) controls VOC and HAP emissions from the process equipment and four storage tanks. In the minor amendment, REG is proposing the installation of a natural gas boiler with a maximum design capacity of 33.5 mmBtu/hr. REG currently receives plant process steam from the neighboring POET bio-refining Glenville East (POET) ethanol plant. This boiler will provide process steam during periods that steam cannot be obtained from POET. In the major amendment, REG is proposing to increase its maximum production rate from the currently permitted 38 million gallons per year to 44 million gallons per year. No physical changes to the facility are required to accomplish this production increase.


4. Summary of subject items

SI ID: Description

Relationship Type

Related SI ID: Description

TFAC 1: REG Albert Lea LLC

ACTV 4: All IAs COMG 4: Facility Limits has

members EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 55, EQUI 58, EQUI 61

EQUI 31: Biodiesel Loadout

sends to STRU 1: Flare Stack

EQUI 31: Biodiesel Loadout

is controlled by

TREA 2: Flaring

EQUI 32: Hot Oil Heater #2

sends to STRU 6: Hot Oil Heater #2

EQUI 34: Fresh Methanol Tank 6


EQUI 34: Fresh Methanol Tank 6

is controlled by

TREA 2: Flaring

EQUI 37: Water Absorber


EQUI 37: Water Absorber

is controlled by

TREA 2: Flaring

EQUI 38: Deacidification System

sends to STRU 9: Deacidification System

EQUI 39: Vacuum Pump (Biodiesel Process)


EQUI 39: Vacuum Pump (Biodiesel Process)

is controlled by

TREA 2: Flaring

EQUI 43: Boiler sends to STRU 5: Boiler Stack

EQUI 45: Transesterification Reactors


EQUI 45: Transesterification Reactors

is controlled by

TREA 2: Flaring

EQUI 48: Biodiesel Distillation


EQUI 48: Biodiesel Distillation

is controlled by

TREA 2: Flaring

EQUI 49: HCl Tank 4 sends to STRU 10: HCl

SI ID: Description

Relationship Type

Related SI ID: Description Tank

EQUI 54: Cooling Tower 1

sends to STRU 11: Cooling Tower 1

EQUI 55: Acidulation sends to STRU 1: Flare Stack

EQUI 55: Acidulation is controlled by

TREA 2: Flaring

EQUI 58: Process Methanol Tank 7


EQUI 58: Process Methanol Tank 7

is controlled by

TREA 2: Flaring

EQUI 59: Hot Oil Heater #1

sends to STRU 4: Hot Oil Heater #1

EQUI 60: Cooling Tower 2

sends to STRU 8: Cooling Tower 2

EQUI 61: Sodium Methylate Tank 8


EQUI 61: Sodium Methylate Tank 8

is controlled by

TREA 2: Flaring

FUGI 1: Equipment Leaks (MeOH, ethanol, VOCs)

STRU 1: Flare Stack STRU 4: Hot Oil Heater #1

STRU 5: Boiler Stack STRU 6: Hot Oil Heater #2

STRU 8: Cooling Tower 2 STRU 9: Deacidification System

STRU 10: HCl Tank STRU 11: Cooling Tower 1

STRU 12: BLDG 1 STRU 13: BLDG 2 STRU 14: BLDG 6 STRU 15: BLDG 7.1 STRU 16: BLDG 7.2 STRU 17: BLDG 8 STRU 18: BLDG 50 STRU 19: COOL 2 TREA 2: Flaring

Permit Issued: February 26, 2018 04700061-101 Permit Expires: Non-expiring of 181

5. Limits and other requirements

Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation TFAC 1 04700061 REG Albert Lea

LLC

5.1.1 Permit Appendices: This permit contains appendices as listed in the permit Table of Contents. The Permittee shall comply with all requirements contained in the Appendices. The appendices are as follows: Appendix A. Insignificant Activities and Applicable Requirements; Appendix B. TRE Index Value Calculation Methods; Appendix C. Flare Calculations; Appendix E. Equipment Leaks Calculation; and Appendix G. 40 CFR pt. 60, subp. A - General Provisions Modeling parameters in Appendix D. EAW Modeling for Permit No. 04700061-003 and Appendix F. Modeling for Permit No. 04700061-101 are included for reference only as described elsewhere in this permit. [40 CFR pt. 60, subp. NNN, 40 CFR pt. 60, subp. RRR, Minn. R. 4410.4300, Minn. R. 7007.0800, subp. 2]

5.1.2 Modeled Parameters for PM10, PM2.5, NO2, CO, and SO2: The parameters used in PM10, PM2.5, NO2, CO, and SO2 modeling for an EAW associated with permit number 04700061-003 are listed in Appendix D of this permit. The parameters used in PM2.5 modeling for permit number 04700061-101 are listed in Appendix F of this permit. The parameters describe the operation of the facility at maximum permitted capacity. The purpose of listing the parameters in the appendix is to provide a benchmark for future changes. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.3 The Permittee shall comply with National Primary and Secondary Ambient Air Quality Standards, 40 CFR pt. 50, and the Minnesota Ambient Air Quality Standards, Minn. R. 7009.0010 to 7009.0090. Compliance shall be demonstrated upon written request by the MPCA. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 1, Minn. R. 7007.0800, subp. 2, Minn. R. 7007.0800, subp. 4, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.4 PERMIT SHIELD: Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permit shall be deemed compliance with the specific provision of the applicable requirement identified in the permit as the basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2, notwithstanding the conditions of this permit specifying compliance practices for applicable requirements, any person (including the Permittee) may also use other credible evidence to establish compliance or noncompliance with applicable requirements.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation This permit shall not alter or affect the liability of the Permittee for any violation of applicable requirements prior to or at the time of permit issuance. [Minn. R. 7007.1800, (A)(2)]

5.1.5 Circumvention: Do not install or use a device or means that conceals or dilutes emissions, which would otherwise violate a federal or state air pollution control rule, without reducing the total amount of pollutant emitted. [Minn. R. 7011.0020]

5.1.6 Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding process equipment and emission units are operated. [Minn. R. 7007.0800, subp. 16(J), Minn. R. 7007.0800, subp. 2]

5.1.7 Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all air pollution control equipment. At a minimum, the O & M plan shall identify all air pollution control equipment and control practices and shall include a preventative maintenance program for the equipment and practices, a description of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipment and practices to proper operation to meet applicable permit conditions, a description of the employee training program for proper operation and maintenance of the control equipment and practices, and the records kept to demonstrate plan implementation. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 16(J)]

5.1.8 Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practical steps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may require feasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions units that have an unreasonable shutdown or breakdown frequency of process or control equipment shall be permitted to operate. [Minn. R. 7019.1000, subp. 4]

5.1.9 Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in a manner which may allow avoidable amounts of particulate matter to become airborne. Comply with all other requirements listed in Minn. R. 7011.0150. [Minn. R. 7011.0150]

5.1.10 Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at all times during the operation of any emission units. This is a state only requirement and is not enforceable by the EPA Administrator or citizens under the Clean Air Act. [Minn. R. 7030.0010-7030.0080]

5.1.11 Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R. 7007.0800, subp. 9(A). [Minn. R. 7007.0800, subp. 9(A)]

5.1.12 The Permittee shall comply with the General Conditions listed in Minn. R. 7007.0800, subp. 16. [Minn. R. 7007.0800, subp. 16]

5.1.13 Performance Testing: Conduct all performance tests in accordance


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation with Minn. R. ch. 7017 unless otherwise noted in this permit. [Minn. R. ch. 7017]

5.1.14 Performance Test Notifications and Submittals: Performance Test Notification and Plan: due 30 days before each Performance Test Performance Test Pre-test Meeting: due 7 days before each Performance Test Performance Test Report: due 45 days after each Performance Test The Notification, Test Plan, and Test Report must be submitted in a format specified by the commissioner. [Minn. R. 7017.2017, Minn. R. 7017.2030, subps. 1-4, Minn. R. 7017.2035, subps. 1-2]

5.1.15 Limits set as a result of a performance test (conducted before or after permit issuance) apply until superseded as stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is based on formal review of a subsequent performance test on the same unit as specified by Minn. R. 7017.2025, subp. 3. The limit is final upon issuance of a permit amendment incorporating the change. [Minn. R. 7017.2025, subp. 3]

5.1.16 Monitoring Equipment Calibration - The Permittee shall either: 1. Calibrate or replace required monitoring equipment every 12 months; or 2. Calibrate at the frequency stated in the manufacturer's specifications. For each monitor, the Permittee shall maintain a record of all calibrations, including the date conducted, and any corrective action that resulted. The Permittee shall include the calibration frequencies, procedures, and manufacturer's specifications (if applicable) in the Operations and Maintenance Plan. Any requirements applying to continuous emission monitors are listed separately in this permit. [Minn. R. 7007.0800, subp. 4(D)]

5.1.17 Operation of Monitoring Equipment: Unless noted elsewhere in this permit, monitoring a process or control equipment connected to that process is not necessary during periods when the process is shutdown, or during checks of the monitoring systems, such as calibration checks and zero and span adjustments. If monitoring records are required, they should reflect any such periods of process shutdown or checks of the monitoring system. [Minn. R. 7007.0800, subp. 4(D)]

5.1.18 Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for NO2 1-hour NAAQS: Changes that do not require a permit amendment or that require a minor or administrative permit amendment do not trigger the EBD Modeling Submittal requirement. The Permittee shall keep updated records on site of all modeled NO2 1-hour parameters and emission rates listed in Appendix D. The Permittee shall submit any changes to modeled NO2 1-hour parameters and emission rates with the next required modeling submittal. [Minn. R. 4410.4300, Minn. R. 7007.0100,


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.19 Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for PM10 24-hour NAAQS and MAAQS: Changes that do not require a permit amendment or that require a minor or administrative permit amendment do not trigger the EBD Modeling Submittal requirement. The Permittee shall keep updated records on site of all modeled PM10 24-hour parameters and emission rates listed in Appendix D. The Permittee shall submit any changes to modeled PM10 24-hour parameters and emission rates with the next required modeling submittal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.20 Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for PM2.5 24-hour and annual NAAQS and MAAQS: Changes that do not require a permit amendment or that require a minor or administrative permit amendment do not trigger the EBD Modeling Submittal requirement. The Permittee shall keep updated records on site of all modeled PM2.5 parameters and emission rates listed in Appendix F. The Permittee shall submit any changes to modeled PM2.5 parameters and emission rates with the next required modeling submittal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.21 EBD Modeling Triggers (Modeling Required) for NO2 1-hour NAAQS: Changes that require, or would require, a moderate or major permit amendment due to an increase in NO2 emissions and affect any modeled NO2 1-hour parameter or emission rate listed in Appendix D, or an addition to the information documented in Appendix D, trigger the EBD Remodeling Submittal requirement. The Permittee shall include previously made changes to modeled NO2 1-hour parameters and emission rates listed in Appendix D that did not previously trigger the EBD Modeling Submittal requirement with this modeling submittal. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.22 EBD Modeling Triggers (Modeling Required) for PM10 24-hour NAAQS and MAAQS: Changes that require, or would require, a moderate or major permit amendment due to an increase in PM10 emissions and affect any modeled PM10 24-hour parameter or emission rate listed in Appendix D, or an addition to the information documented in Appendix D, trigger the EBD Remodeling Submittal requirement. The Permittee shall include previously made changes to modeled PM10 24-hour parameters and emission rates listed in Appendix D that did not previously trigger the EBD Modeling Submittal requirement with this


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation modeling submittal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.23 EBD Modeling Triggers (Modeling Required) for PM2.5 24-hour and annual NAAQS and MAAQS: Changes that require, or would require, a moderate or major permit amendment due to an increase in PM2.5 emissions and affect any modeled PM2.5 parameter or emission rate listed in Appendix F, or an addition to the information documented in Appendix F, trigger the EBD Remodeling Submittal requirement. The Permittee shall include previously made changes to modeled PM2.5 parameters and emission rates listed in Appendix F that did not previously trigger the EBD Modeling Submittal requirement with this modeling submittal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.24 EBD Modeling Submittal for NO2 1-hour NAAQS: For changes meeting the criteria in the EBD Modeling Triggers (Modeling Required) requirement, the Permittee shall submit an EBD modeling submittal in accordance with the current version of the MPCA Air Dispersion Modeling Guidance and shall wait for written approval (for major amendments, in the form of an issued permit amendment; for moderate amendments, in the form of a construction authorization letter) before making such changes. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.25 EBD Modeling Submittal for PM10 24-hour NAAQS and MAAQS: For changes meeting the criteria in the EBD Modeling Triggers (Modeling Required) requirement, the Permittee shall submit an EBD modeling submittal in accordance with the current version of the MPCA Air Dispersion Modeling Guidance and shall wait for written approval (for major amendments, in the form of an issued permit amendment; for moderate amendments, in the form of a construction authorization letter) before making such changes. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.26 EBD Modeling Submittal for PM2.5 24-hour and annual NAAQS and MAAQS: For changes meeting the criteria in the EBD Modeling Triggers (Modeling Required) requirement, the Permittee shall submit an EBD modeling submittal in accordance with the current version of the MPCA Air Dispersion Modeling Guidance and shall wait for written approval (for major amendments, in the form of an issued permit amendment; for moderate amendments, in the form of a construction authorization letter) before making such changes. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.27 EBD Modeling Submittal Content for PM10, PM2.5, and NO2: The information submitted must include, for stack and vent sources, source emission rate, location, height, diameters, exit velocity, exit temperature, discharge direction, use of rain caps or rain hats, and, if applicable, locations and dimensions of nearby buildings. For non-stack/vent sources, this includes the source emission rate, location, size and shape, release height, and, if applicable, any emission rate scalars, and the initial lateral dimensions and initial vertical dimensions and adjacent building heights. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.28 Outdated EBD Baseline Modeling for PM10, PM2.5, and NO2: Prior to conducting the EBD analysis, the Permittee shall use the current version of the MPCA Air Dispersion Modeling Guidance to determine if the Baseline Modeling (the most recent refined modeling demonstration) is outdated. If the Baseline Modeling is outdated, the Permittee shall update the Baseline Modeling to be consistent with the current version of the MPCA Air Dispersion Modeling Guidance. The updated modeling will become the new Baseline Modeling. This requirement does not require the Permittee to complete a new refined modeling demonstration using the revisions made for the EBD demonstration. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.29 EBD Modeling Results for PM2.5: The dispersion characteristics due to the revisions of the information in Appendix F must be equivalent to or better than the dispersion characteristics modeled for Permit No. 04700061-101. The Permittee shall demonstrate this equivalency in the proposal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.30 EBD Modeling Results for PM10: The dispersion characteristics due to the revisions of the information in Appendix D must be equivalent to or better than the dispersion characteristics modeled for permit No. 04700061-003. The Permittee shall demonstrate this equivalency in the proposal. [Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.31 At any time, the Permittee may submit a refined dispersion modeling protocol using the current version of the MPCA modeling


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation guidance in order to demonstrate that predicted ambient concentrations of PM10 and PM2.5 are below the NAAQS. Upon MPCA approval of the modeling protocol, the Permittee may submit refined dispersion modeling results using the current version of the MPCA modeling guidance. The EBD modeling triggers listed in this permit may be revised based on the results of the refined dispersion modeling demonstration and MPCA approval. The permit shall be revised to include the revised EBD modeling triggers by submitting an amendment application to the MPCA. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.32 EBD Modeling Results for NO2: The dispersion characteristics due to the revisions of the information in Appendix D must be equivalent to or better than the dispersion characteristics modeled for Permit No. 04700061-003. The Permittee shall demonstrate this equivalency in the proposal. [Minn. R. 4410.4300, Minn. R. 7007.0100, subp. 7(A), 7(L), & 7(M), Minn. R. 7007.0800, subp. 4, Minn. R. 7007.0800, subps. 1-2, Minn. R. 7009.0010-7009.0090, Minn. Stat. 116.07, subd. 4a, Minn. Stat. 116.07, subd. 9]

5.1.33 Recordkeeping: Maintain records describing any insignificant modifications (as required by Minn. R. 7007.1250, subp. 3) or changes contravening permit terms (as required by Minn. R. 7007.1350, subp. 2), including records of the emissions resulting from those changes. [Minn. R. 7007.0800, subp. 5(B)]

5.1.34 Recordkeeping: Retain all records at the stationary source, unless otherwise specified within this permit, for a period of five (5) years from the date of monitoring, sample, measurement, or report. Records which must be retained at this location include all calibration and maintenance records, all original recordings for continuous monitoring instrumentation, and copies of all reports required by the permit. Records must conform to the requirements listed in Minn. R. 7007.0800, subp. 5(A). [Minn. R. 7007.0800, subp. 5(C)]

5.1.35 Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of any control equipment or process equipment if the shutdown would cause any increase in the emissions of any regulated air pollutant. If the owner or operator does not have advance knowledge of the shutdown, notification shall be made to the Commissioner as soon as possible after the shutdown. However, notification is not required in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 3. At the time of notification, the owner or operator shall inform the Commissioner of the cause of the shutdown and the estimated duration. The owner or operator shall notify the Commissioner when the shutdown is over. [Minn. R. 7019.1000, subp. 3]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.1.36 Notification of Deviations Endangering Human Health or the

Environment: As soon as possible after discovery, notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permit conditions which could endanger human health or the environment. [Minn. R. 7019.1000, subp. 1]

5.1.37 Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hour duration of any control equipment or process equipment if the breakdown causes any increase in the emissions of any regulated air pollutant. The 24-hour time period starts when the breakdown was discovered or reasonably should have been discovered by the owner or operator. However, notification is not required in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 2. At the time of notification or as soon as possible thereafter, the owner or operator shall inform the Commissioner of the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissioner when the breakdown is over. [Minn. R. 7019.1000, subp. 2]

5.1.38 Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days of discovery, notify the Commissioner in writing of any deviation from permit conditions which could endanger human health or the environment. Include the following information in this written description: 1. the cause of the deviation; 2. the exact dates of the period of the deviation, if the deviation has been corrected; 3. whether or not the deviation has been corrected; 4. the anticipated time by which the deviation is expected to be corrected, if not yet corrected; and 5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation. [Minn. R. 7019.1000, subp. 1]

5.1.39 Application for Permit Amendment: If a permit amendment is needed, submit an application in accordance with the requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500. Submittal dates vary, depending on the type of amendment needed. Upon adoption of a new or amended federal applicable requirement, and if there are 3 or more years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150 - 7007.1500]

5.1.40 Extension Requests: The Permittee may apply for an Administrative Amendment to extend a deadline in a permit by no more than 120 days, provided the proposed deadline extension meets the requirements of Minn. R. 7007.1400, subp. 1(H). Performance testing deadlines from the General Provisions of 40 CFR pt. 60 and


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation pt. 63 are examples of deadlines for which the MPCA does not have authority to grant extensions and therefore do not meet the requirements of Minn. R. 7007.1400, subp. 1(H). [Minn. R. 7007.1400, subp. 1(H)]

5.1.41 If the Permittee determines that no permit amendment or notification is required prior to making a change, the Permittee must retain records of all calculations required under Minn. R. 7007.1200. For non-expiring permits, these records shall be kept for a period of five years from the date that the change was made. The records shall be kept at the stationary source for the current calendar year of operation and may be kept at the stationary source or office of the stationary source for all other years. The records may be maintained in either electronic or paper format. [Minn. R. 7007.1200, subp. 4]

5.1.42 Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance. Submit in a format specified by the Commissioner. [Minn. R. 7019.3000-7019.3100]

5.1.43 Emission Fees: due 30 days after receipt of an MPCA bill. [Minn. R. 7002.0005-7002.0095]

COMG 4 GP003 Facility Limits 5.2.1 Methanol <= 1.25 tons per year 12-month rolling sum. The 12-

month rolling Sum shall be calculated by the 15th day of each month for the previous 12-month period as described later in this permit. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.2.2 Production <= 44.0 million gallons per year 12-month rolling sum. The 12-month Rolling Sum of biodiesel shall be calculated by the 15th day of each month as described later in this permit. This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. [Minn. R. 4410.4300, Minn. R. 7007.0800, subp. 2]

5.2.3 The Permittee shall vent emissions from all emission units listed in COMG 4 to a flare meeting the permit requirements of TREA 2. See TREA 2 for requirements for the flare. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.2.4 Monthly Methanol Calculation: By the 15th day of each month, the Permittee shall calculate and record the following: 1) Methanol emissions from biodiesel production for the previous month using the following equation: Methanol emissions from biodiesel production (tons/month) = (EF*H)/2000 where:


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation EF = The emission factor, in pounds per hour, for methanol emissions from the biodiesel production process as determined from the last MPCA approved performance test. H = Hours of operation for COMG 4 for the previous month. 2) The 12-month rolling sum of methanol emissions by summing the monthly methanol emissions calculations for the previous 12-month period. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.2.5 Daily Recordkeeping: The Permittee shall maintain records of daily biodiesel production on-site. This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. [Minn. R. 4410.4300, Minn. R. 7007.0800, subps. 4-5]

5.2.6 Monthly Recordkeeping - Biodiesel Production: By the 15th of the month, the Permittee shall calculate, record, and maintain the following: 1) The total amount of biodiesel produced in gallons for the previous month based on daily records; and 2) The 12-month rolling sum of biodiesel produced for the previous 12-month period by summing the monthly biodiesel production data for the previous 12 months. This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. [Minn. R. 4410.4300, Minn. R. 7007.0800, subps. 4-5]

5.2.7 Daily Recordkeeping - Hours of operation: On each day of operation, the Permittee shall record the hours of operation for the biodiesel production plant for the previous day of operation. [Minn. R. 4410.4300, Minn. R. 7007.0800, subps. 4-5, Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.2.8 Monthly Recordkeeping - Hours of Operation: By the 15th day of each month, the Permittee shall calculate and record the number of operating hours for the previous month. [Minn. R. 4410.4300, Minn. R. 7007.0800, subps. 4-5, Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

EQUI 31 EU003 Biodiesel Loadout 5.3.1 The Permittee shall vent emissions from EQUI 31 to control

equipment meeting the requirements of TREA 2 whenever EQUI 31 operates. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.3.2 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)] 5.3.3 Particulate Matter <= 0.30 grains per dry standard cubic foot of

exhaust gas unless required to further reduce emissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735. [Minn. R. 7011.0715, subp. 1(A)]

EQUI 32 EU008 Hot Oil Heater #2 5.4.1 The Permittee must comply with all applicable requirements of 40

CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(4); 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c); 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.15(a); 40 CFR 60.15(b); 40 CFR 60.15(c); 40 CFR 60.15(d); 40 CFR 60.15(e); 40 CFR 60.15(f); and 40 CFR 60.15(g). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]

5.4.2 Permitted Fuels: The Permittee shall burn only natural gas. [Minn. R. 7007.0800, subp. 2]

5.4.3 Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gas combusted in Hot Oil Heater #2 during the previous calendar month. These records shall consist of purchase records, receipts, or fuel meter readings. [40 CFR 60.48c(g), Minn. R. 7011.0570]

EQUI 34 TK006 Fresh Methanol

Tank 6

5.5.1 The Permittee shall vent emissions from EQUI 34 to control


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation equipment meeting the requirements of TREA 2 whenever EQUI 34 operates. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.5.2 Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas unless required to further reduce emissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735. [Minn. R. 7011.0715, subp. 1(A)]

5.5.3 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)] EQUI 37 EU011 Water Absorber 5.6.1 The Permittee shall vent emissions from EQUI 37 to control


5.6.2 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)] 5.6.3 Particulate Matter <= 0.30 grains per dry standard cubic foot of


EQUI 38 EU006 Deacidification

System



EQUI 39 EU001 Vacuum Pump

(Biodiesel Process)

5.8.1 The Permittee shall vent emissions from EQUI 39 to control equipment meeting the requirements of TREA 2 whenever EQUI 39 operates. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.8.2 The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.1(b); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(4); 40 CFR 60.7(b); 40 CFR 60.8(a); 40 CFR 60.8(b); 40 CFR 60.8(c);


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 40 CFR 60.8(d); 40 CFR 60.8(e); 40 CFR 60.8(f); 40 CFR 60.11(a); 40 CFR 60.11(d); 40 CFR 60.12; 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c); 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.17; 40 CFR 60.19(a); 40 CFR 60.19(b); 40 CFR 60.19(c); 40 CFR 60.19(d); and 40 CFR 60.19(e). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]

5.8.3 The Permittee shall maintain the affected facility such that it has a total resource effectiveness (TRE) index value greater than 8.0. [40 CFR 60.660(c)(4), Minn. R. 7011.2900(C)]

5.8.4 For each vent stream, the Permittee shall maintain a TRE index value greater than 1.0 without use of VOC emission control devices. [40 CFR 60.662(c), Minn. R. 7011.2900(C)]

5.8.5 The test methods in appendix A to 40 CFR pt. 60, except as provided under CFR Section 60.8(b), shall be used for determining the net heating value of the gas combusted to determine compliance under 40 CFR Section 60.662(b) and for determining the process vent stream TRE index value to determine compliance under 40 CFR Section 60.662(c). [40 CFR 60.664(e), Minn. R. 7011.2900(C)]

5.8.6 For the purposes of complying with 40 CFR Section 60.662(c) the Permittee shall calculate the TRE index value of the vent stream using the equation for incineration in paragraph (f)(1) of 40 CFR Section 60.664 for halogenated vent streams. The Permittee shall determine the TRE index value for nonhalogenated vent streams by calculating values using both the incinerator equation in 40 CFR Section 60.664(f)(1) and the flare equation in 40 CFR Section 60.664(f)(2) and selecting the lower of the two values. [40 CFR 60.664(f), Minn. R. 7011.2900(C)]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.8.7 TRE Index Value Calculation Method: The Permittee shall calculate

the TRE index values using both the equations listed in Appendix B of this permit. [40 CFR 60.664(f)(1) and (2), Minn. R. 7011.2900(C)]

5.8.8 The Permittee shall recalculate the TRE index value when process changes are made. Examples of process changes included changes in production capacity, feedstock type, or catalyst type, or whenever there is replacement, removal, or addition of recovery equipment. The TRE index value shall be recalculated based on test data, or on best engineering estimates of the effects of the change to the recovery system. Recalculated index value less than 1.0: Notify the Administrator within 1 week of the recalculation and conduct a performance test according to the methods and procedures required by 40 CFR Section 60.664 in order to determine compliance with 40 CFR Section 60.662(a). Recalculated TRE index value is greater than 1.0, but less than 8.0: Conduct a performance test according to the methods and procedures required by 40 CFR Sections 60.8 and 60.664 and comply with 40 CFR Section 60.663, 60.664, and 60.665. Performance test should be conducted as soon as possible, but must be conducted within 180 days of the process change. Recalculation of the TRE index value was conducted on October 30, 2013. [40 CFR 60.664(g), Minn. R. 7011.2900(C)]

5.8.9 The Permittee shall keep up-to-date, readily accessible records of: (1) Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal, or addition of recovery equipment or a distillation unit; (2) Any recalculation of the TRE index value performed pursuant to 40 CFR Section 60.664(f); and (3) The results of any performance test performed pursuant to the methods and procedures required by 40 CFR Section 60.664(d). [40 CFR 60.665(h), Minn. R. 7011.2900(C)]

5.8.10 The Permittee shall route the vent stream from the affected facility to a distillation unit subject to 40 CFR pt. 60, subp. NNN. The facility is exempt from all provisions of 40 CFR pt. 60, subp. RRR except for Section 60.705(r). [40 CFR 60.700(c)(5), Minn. R. 7011.3430]

5.8.11 The Permittee shall submit to the Administrator a process design description as part of the initial semiannual report required by 40 CFR Section 60.665(l). This process design description must be retained for the life of the process. No other records or reports are required unless process changes are made.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation The process description was submitted on June 18, 2014. [40 CFR 60.705(r), Minn. R. 7011.3430]

EQUI 43 Boiler 5.9.1 The Permittee must comply with all applicable requirements of 40

CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(1); 40 CFR 60.7(a)(3); 40 CFR 60.7(a)(4); 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c); 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.15(a); 40 CFR 60.15(b); 40 CFR 60.15(c); 40 CFR 60.15(d); 40 CFR 60.15(e); 40 CFR 60.15(f); and 40 CFR 60.15(g). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]


5.9.3 Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gas combusted in the boilers during the previous calendar month. These records shall consist of purchase records, receipts, or fuel meter readings. [40 CFR 60.48c(g), Minn. R. 7011.0570]

EQUI 45 EU002 Transesterification

Reactors

5.10.1 The Permittee shall vent emissions from EQUI 45 to control equipment meeting the requirements of TREA 2 whenever EQUI 45 operates. [Title I Condition: Avoid major source under 40 CFR 63,


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.10.2 The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.1(b); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(4); 40 CFR 60.7(b); 40 CFR 60.8(a); 40 CFR 60.8(b); 40 CFR 60.8(c); 40 CFR 60.8(d); 40 CFR 60.8(e); 40 CFR 60.8(f); 40 CFR 60.11(a); 40 CFR 60.11(d); 40 CFR 60.12; 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c); 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.17; 40 CFR 60.19(a); 40 CFR 60.19(b); 40 CFR 60.19(c); 40 CFR 60.19(d); and 40 CFR 60.19(e). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]

5.10.3 The Permittee shall maintain the affected facility such that it has a total resource effectiveness (TRE) index value greater than 8.0. [40 CFR 60.700(c)(2), Minn. R. 7011.3430]

5.10.4 The Total Resource Effectiveness (TRE) index value shall be maintained greater than 1.0 without the use of a VOC emission control device. [40 CFR 60.702(c), Minn. R. 7011.3430]

5.10.5 The net heating value shall be calculated using the equation in (d)(4). Methods ASTM D2382-76, D2382-88, or D4809-95, as specified in Section 60.17, shall be used to determine the net heats


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation of combustion. [40 CFR 60.704(d), Minn. R. 7011.3430]

5.10.6 TRE index value Calculation Method: The Permittee shall calculate the TRE index values using both of the equations listed in Appendix B, EQUI 45 of this permit (from 40 CFR Sections 60.704(e)(1) and (e)(2)). The lower of the two values shall be selected. [40 CFR 60.704(e), Minn. R. 7011.3430]

5.10.7 The Permittee shall recalculate the TRE index value for the vent stream using the methods listed in 40 CFR Section 60.704(d) whenever process changes are made. Examples of process changes include changes in production capacity, feedstock type, or whenever there is replacement, removal, or addition of recovery equipment. Recalculated TRE index value less than 1.0: Notify the Administrator within 1 week of the recalculation and conduct a performance test according to the methods and procedures required by 40 CFR Section 60.704 in order to determine compliance with 40 CFR Section 60.702(a) or (b). Recalculated TRE index value greater than 1.0 but less than 8.0: Conduct a performance test according to the methods and procedures required by 40 CFR Sections 60.8 and 60.704 and comply with 40 CFR Sections 60.703, 60.704, and 60.705. Performance test shall be conducted as soon as possible after the process change but no later than 180 days from the time of the process change. [40 CFR 60.704(f), Minn. R. 7011.3430]

5.10.8 The Permittee shall keep up-to-date, readily accessible records of the following: 1. Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal, or addition of recovery equipment or reactors; 2. Any recalculation of the TRE index value performed pursuant to Section 60.704(f); and 3. The results of any performance test performed pursuant to the methods and procedures required by Section 60.704(d). [40 CFR 60.705(g), Minn. R. 7011.3430]

5.10.9 The Permittee shall maintain a record of the initial test for determining the total resource effectiveness index and the results of the initial total resource effectiveness index calculation. [40 CFR 60.705(t), Minn. R. 7011.3430]

EQUI 48 EU009 Biodiesel

Distillation


5.11.2 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.11.3 Particulate Matter <= 0.30 grains per dry standard cubic foot of


EQUI 49 TK004 HCl Tank 4 5.12.1 Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)] 5.12.2 Particulate Matter <= 0.30 grains per dry standard cubic foot of


EQUI 55 EU005 Acidulation 5.13.1 The Permittee shall vent emissions from EQUI 55 to control




EQUI 58 TK007 Process Methanol

Tank 7




EQUI 59 EU007 Hot Oil Heater #1 5.15.1 The Permittee must comply with all applicable requirements of 40

CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(4); 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c);


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.15(a); 40 CFR 60.15(b); 40 CFR 60.15(c); 40 CFR 60.15(d); 40 CFR 60.15(e); 40 CFR 60.15(f); and 40 CFR 60.15(g). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]


5.15.3 Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gas combusted in Hot Oil Heater #1 during the previous calendar month. These records shall consist of purchase records, receipts, or fuel meter readings. [40 CFR 60.48c(g), Minn. R. 7011.0570]

EQUI 61 TK008 Sodium Methylate

Tank 8




FUGI 1 FS001 Equipment Leaks

(MeOH, ethanol, VOCs)

5.17.1 Methanol <= 2.65 tons per year 12-month rolling sum to be calculated by the 15th day of each month for the previous 12-month period as described later in this permit and using the emission factors listed in Appendix E. The Permittee shall use the most recent monitored value in place


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation of the screening value when calculating emissions from gas valves, light liquid valves, light liquid pumps, connectors, pressure relief valves, and agitators. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.17.2 Daily Recordkeeping - Hours of Operation: On each day of operation, the Permittee shall record the hours of operation for the biodiesel production plant for the previous day of operation. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.17.3 Monthly Recordkeeping - Hours of Operation: By the 15th day of each month, the Permittee shall calculate and record the number of operating hours for the previous month. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.17.4 Monthly Calculation - Methanol Emissions: By the 15th day of each month, the Permittee shall calculate and record the monthly methanol emissions, in tons, using the emission factors determined using the methods listed in Appendix E of this permit and the hours of operation for the month. By the 15th day of each month the Permittee shall calculate and record the 12-month rolling sum of methanol emissions, in tons, based on methanol emissions for the previous 12 months. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.17.5 The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows: 40 CFR 60.1(a); 40 CFR 60.1(b); 40 CFR 60.2; 40 CFR 60.3; 40 CFR 60.4; 40 CFR 60.7(a)(4); 40 CFR 60.7(b); 40 CFR 60.11(a); 40 CFR 60.11(d); 40 CFR 60.12; 40 CFR 60.14(a); 40 CFR 60.14(b); 40 CFR 60.14(c); 40 CFR 60.14(e); 40 CFR 60.14(f); 40 CFR 60.14(g); 40 CFR 60.17; 40 CFR 60.18(g)-(i); 40 CFR 60.19(a); 40 CFR 60.19(b); 40 CFR 60.19(c); 40 CFR 60.19(d); and


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 40 CFR 60.19(e). A copy of 40 CFR pt. 60, subp. A is included in Appendix G. If the standard changes or upon adoption of a new or amended federal applicable requirement, and if there are more than 3 years remaining in the permit term, the Permittee shall file an application for an amendment within nine months of promulgation of the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3. [40 CFR pt. 60, subp. A, Minn. R. 7007.0400, subp. 3, Minn. R. 7007.1150-1500, Minn. R. 7011.0050, Minn. R. 7017.1010, Minn. R. 7017.2025, Minn. R. 7019.0100]

5.17.6 The Permittee shall demonstrate compliance with the requirements of 40 CFR Sections 60.482-1a through 60.482-10a or Section 60.480a(e) for all equipment within 180 days of initial startup. [40 CFR 60.482-1a(a), Minn. R. 7011.2900(D)]

5.17.7 Equipment that the Permittee designates as being in VOC service less than 300 hr/yr is excluded from the requirements of 40 CFR Section 60.482-2a - 60.482.11a if it is identified as required in 40 CFR Section 60.486(e)(6) and it meets any of the following conditions: 1) The equipment is in VOC service only during startup and shutdown, excluding startup and shutdown between batches of the same campaign for a batch process. 2) The equipment is in VOC service only during process malfunctions or other emergencies. 3) The equipment is backup equipment that is in VOC service only when the primary equipment is out of service. [40 CFR 60.482-1a(e), Minn. R. 7011.2900(D)]

5.17.8 If a dedicated batch process unit operates less than 365 days during a year, the Permittee may monitor at a reduced frequency as specified in 40 CFR Section 60.482-1a(f). [40 CFR 60.482-1a(f), Minn. R. 7011.2900(D)]

5.17.9 If the storage vessel is shared with multiple process units, the process unit with the greatest annual amount of stored materials (predominant use) is the process unit the storage vessel is assigned to. If the storage vessel is shared equally among process units, and one of the process units has equipment subject to 40 CFR pt. 60, subp. VVa, the storage vessel is assigned to that process unit. If the storage vessel is shared equally among process units, none of which have equipment subject to 40 CFR pt. 60, subp. VVa of this part, the storage vessel is assigned to any process unit subject to 40 CFR pt. 60, subp. VV. If the predominant use of the storage vessel varies from year to year, then the Permittee must estimate the predominant use initially and reassess every 3 years. The Permittee must keep records of the information and supporting calculations that show how predominant use is determined. All equipment on the storage vessel must be monitored when in VOC service. [40 CFR 60.482-1a(g), Minn. R. 7011.2900(D)]

5.17.10 Pumps in light liquid service: (1) Each pump in light liquid service shall be monitored monthly to


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation detect leaks by the methods specified in 40 CFR Section 60.485a(b), except as provided in 40 CFR Section 60.482-1a(c) and (f) and 40 CFR Section 60.482-2a(d), (e) and (f). A pump that begins operation in light liquid service after the initial startup date for the process unit must be monitored for the first time within 30 days after the end of its startup period, except for a pump that replaces a leaking pump and except as provided in Section 60.482-1a(c) and 40 CFR Section 60.482-2a(d), (e) and (f). (2) Each pump in light liquid service shall be checked by visual inspection each calendar week for indications of liquids dripping from the pump seal, except as provided in 40 CFR Section 60.482-1a(f). [40 CFR 60.482-2a(a), Minn. R. 7011.2900(D)]

5.17.11 For the purpose of the requirements of this section of the permit, the instrument reading that defines a leak is as follows: (i) 5,000 parts per million (ppm) or greater for pumps handling polymerizing monomers; (ii) 2,000 ppm or greater for all other pumps. [40 CFR 60.482-2a(b)(1), Minn. R. 7011.2900(D)]

5.17.12 If there are indications of liquids dripping from the pump seal, the Permittee shall follow one of the procedures specified in this item. This requirement does not apply to a pump that was monitored after a previous weekly inspection and the instrument reading was less than the concentration listed above, whichever is applicable. (i) Monitor the pump within 5 days as specified in 40 CFR Section 60.485a(b). If a leak is detected, the leak shall be repaired using the procedures in 40 CFR Section 60.482-2a(c). (ii) Designate the visual indications of liquids dripping as a leak, and repair the leak using either the procedures in 40 CFR Section 60.482-2a(c) or by eliminating the visual indications of liquids dripping. [40 CFR 60.482-2a(b)(2), Minn. R. 7011.2900(D)]

5.17.13 (1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it is detected, except as provided in 40 CFR Section 60.482-9a. (2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. First attempts at repair include, but are not limited to, the practices described in 40 CFR Section 60.482-2a(c)(2)(i) and (ii), where practicable. (i) Tightening the packing gland nuts; (ii) Ensuring that the seal flush is operating at design pressure and temperature. [40 CFR 60.482-2a(c), Minn. R. 7011.2900(D)]

5.17.14 Each pump equipped with a dual mechanical seal system that includes a barrier fluid system is exempt from the requirements of 40 CFR Section 60.482-2a(a), provided the requirements specified in 40 CFR Section 60.482-2a(d)(1) through (6) are met. [40 CFR 60.482-2a(d), Minn. R. 7011.2900(D)]

5.17.15 Any pump that is designated, as described as follows, for no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, is exempt from the requirements of 40 CFR Section 60.482-2a(a), (c), and (d) if the pump: (1) Has no externally actuated shaft penetrating the pump housing;


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation (2) Is demonstrated to be operating with no detectable emissions as indicated by an instrument reading of less than 500 ppm above background as measured by the methods specified in 40 CFR Section 60.485a(c); and (3) Is tested for compliance with 40 CFR Section 60.482-2a(e)(2) initially upon designation, annually, and at other times requested by the Commissioner. [40 CFR 60.482-2a(e), Minn. R. 7011.2900(D)]

5.17.16 If any pump is equipped with a closed vent system capable of capturing and transporting any leakage from the seal or seals to a process or to a fuel gas system or to a control device that complies with the requirements of 40 CFR Section 60.482-10a, it is exempt from 40 CFR Section 60.482-2a(a) through (e). [40 CFR 60.482-2a(f), Minn. R. 7011.2900(D)]

5.17.17 Any pump that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitor pump is exempt from the monitoring and inspection requirements of 40 CFR Section 60.482-2a(a) and (d)(4) through (6) if: (1) The Permittee demonstrates that the pump is unsafe-to-monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with 40 CFR Section 60.482-2a(a); and (2) The Permittee has a written plan that requires monitoring of the pump as frequently as practicable during safe-to-monitor times, but not more frequently than the periodic monitoring schedule otherwise applicable, and repair of the equipment according to the procedures in 40 CFR Section 60.482-2a(c) if a leak is detected. [40 CFR 60.482-2a(g), Minn. R. 7011.2900(D)]

5.17.18 Any pump that is located within the boundary of an unmanned plant site is exempt from the weekly visual inspection requirement of 40 CFR Section 60.482-2a(a)(2) and (d)(4), and the daily requirements of 40 CFR Section 60.482-2a(d)(5), provided that each pump is visually inspected as often as practicable and at least monthly. [40 CFR 60.482-2a(h), Minn. R. 7011.2900(D)]

5.17.19 Except during pressure releases, each pressure relief device in gas/vapor service shall be operated with no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background as determined by the methods specified in 40 CFR Section 60.485a(c). [40 CFR 60.482-4a(a), Minn. R. 7011.2900(D)]

5.17.20 (1) After each pressure release, the pressure relief device shall be returned to a condition of no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, as soon as practicable, but no later than 5 calendar days after the pressure release, except as provided in 40 CFR Section 60.482-9a. (2) No later than 5 calendar days after the pressure release, the pressure relief device shall be monitored to confirm the conditions of no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, by the methods specified in 40 CFR Section 60.485a(c). [40 CFR 60.482-4a(b), Minn. R. 7011.2900(D)]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.17.21 Any pressure relief device that is routed to a process or fuel gas

system or equipped with a closed vent system capable of capturing and transporting leakage through the pressure relief device to a control device as described in Section 60.482-10a is exempted from the requirements of paragraphs (a) and (b) of 40 CFR 60.482-4a. [40 CFR 60.482-4a(c), Minn. R. 7011.2900(D)]

5.17.22 (1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief device is exempt from the requirements of paragraphs (a) and (b) of 40 CFR 60.482-4a, provided the Permittee complies with the requirements in paragraph (d)(2) of 40 CFR 60.482-4a. (2) After each pressure release, a new rupture disk shall be installed upstream of the pressure relief device as soon as practicable, but no later than 5 calendar days after each pressure release, except as provided in 40 CFR Section 60.482-9a. [40 CFR 60.482-4a(d), Minn. R. 7011.2900(D)]

5.17.23 Each sampling connection system shall be equipped with a closed-purge, closed-loop, or closed-vent system, except as provided in 40 CFR Section 60.482-1a(c) and 40 CFR Section 60.482-5a(c). [40 CFR 60.482-5a(a), Minn. R. 7011.2900(D)]

5.17.24 Each closed-purge, closed-loop, or closed-vent system as required in 40 CFR Section 60.482-5a(a) shall comply with the following requirements: (1) Gases displaced during filling of the sample container are not required to be collected or captured. (2) Containers that are part of a closed-purge system must be covered or closed when not being filled or emptied. (3) Gases remaining in the tubing or piping between the closed-purge system valve(s) and sample container valve(s) after the valves are closed and the sample container is disconnected are not required to be collected or captured. (4) Each closed-purge, closed-loop, or closed-vent system shall be designed and operated to meet requirements in either 40 CFR Section 60.482-5a(b)(4)(i), (ii), (iii), or (iv). [40 CFR 60.482-5a(b), Minn. R. 7011.2900(D)]

5.17.25 In-situ sampling systems and sampling systems without purges are exempt from the requirements of 40 CFR Section 60.482-5a(a) and (b). [40 CFR 60.482-5a(c), Minn. R. 7011.2900(D)]

5.17.26 (1) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a second valve, except as provided in 40 CFR 60.482-1a(c) and paragraphs (d) and (e) of this section. (2) The cap, blind flange, plug, or second valve shall seal the open end at all times except during operations requiring process fluid flow through the open-ended valve or line. [40 CFR 60.482-6a(a), Minn. R. 7011.2900(D)]

5.17.27 Each open-ended valve or line equipped with a second valve shall be operated in a manner such that the valve on the process fluid end is closed before the second valve is closed. [40 CFR 60.482-6a(b), Minn. R. 7011.2900(D)]

5.17.28 When a double block-and-bleed system is being used, the bleed


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation valve or line may remain open during operations that require venting the line between the block valves but shall comply with 40 CFR Section 60.482-6a(a) at all other times. [40 CFR 60.482-6a(c), Minn. R. 7011.2900(D)]

5.17.29 Open-ended valves or lines in an emergency shutdown system which are designed to open automatically in the event of a process upset are exempt from the requirements of 40 CFR Section 60.482-6a(a), (b), and (c). [40 CFR 60.482-6a(d), Minn. R. 7011.2900(D)]

5.17.30 Open-ended valves or lines containing materials which would autocatalytically polymerize or would present an explosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleed system as specified in 40 CFR Section 60.482-6a(a) through (c) are exempt from the requirements of 40 CFR Section 60.482-6a(a) through (c). [40 CFR 60.482-6a(e), Minn. R. 7011.2900(D)]

5.17.31 (1) Each valve shall be monitored monthly to detect leaks by the methods specified in 40 CFR Section 60.485a(b) and shall comply with 40 CFR Section 60.482-7a(b) through (e), as detailed in this permit, except as provided in 40 CFR Section 60.482-7a(f), (g), and (h), 40 CFR Section 60.482-1a(c) and (f), and 40 CFR Sections 60.483-1a and 60.483-2a. The valve shall be monitored for the first time within 30 days after the end of its startup period to ensure proper installation. (2) A valve that begins operation in gas/vapor service or light liquid service after the initial startup date for the process unit shall be monitored according to 40 CFR Section 60.482-7a(a)(2), except for a valve that replaces a leaking valve and except as provided in 40 CFR Sections 60.482-7a(f) - (h), 60.482-1a(c); and 60.483-1a and 60.483-2a. [40 CFR 60.482-7a(a), Minn. R. 7011.2900(D)]

5.17.32 If the existing valves in the process unit are monitored in accordance with 40 CFR Sections 60.483-1a or 60.483-2a, count the new valve as leaking when calculating the percentage of valves leaking as described in 40 CFR Section 60.483-2a(b)(5). If less than 2.0 percent of the valves are leaking for that process unit, the valve shall be monitored for the first time during the next scheduled monitoring event for existing valves in the process unit or within 90 days, whichever comes first. [40 CFR 60.482-7a(a), Minn. R. 7011.2900(D)]

5.17.33 If an instrument reading of 500 ppm or greater is measured, a leak is detected. [40 CFR 60.482-7a(b), Minn. R. 7011.2900(D)]

5.17.34 (1)(i) Any valve for which a leak is not detected for 2 successive months may be monitored the first month of every quarter, beginning with the next quarter, until a leak is detected. (ii) As an alternative to monitoring all of the valves in the first month of a quarter, an Permittee may elect to subdivide the process unit into two or three subgroups of valves and monitor each subgroup in a different month during the quarter, provided each subgroup is monitored every 3 months. The Permittee must keep records of the valves assigned to each subgroup. (2) If a leak is detected, the valve shall be monitored monthly until


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation a leak is not detected for 2 successive months. [40 CFR 60.482-7a(c), Minn. R. 7011.2900(D)]

5.17.35 (1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after the leak is detected, except as provided in 40 CFR Section 60.482-9a. (2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. [40 CFR 60.482-7a(d), Minn. R. 7011.2900(D)]

5.17.36 First attempts at repair include, but are not limited to, the following best practices where practicable: (1) Tightening of bonnet bolts; (2) Replacement of bonnet bolts; (3) Tightening of packing gland nuts; (4) Injection of lubricant into lubricated packing. [40 CFR 60.482-7a(e), Minn. R. 7011.2900(D)]

5.17.37 Any valve that is designated, as described in 40 CFR Section 60.486a(e)(2), for no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background, is exempt from the requirements of 40 CFR Section 60.482-7a(a) if the valve: (1) Has no external actuating mechanism in contact with the process fluid, (2) Is operated with emissions less than 500 ppm above background as determined by the method specified in 40 CFR Section 60.485a(c), and (3) Is tested for compliance with the previous paragraph initially upon designation, annually, and at other times requested by the Commissioner. [40 CFR 60.482-7a(f), Minn. R. 7011.2900(D)]

5.17.38 Any valve that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitor valve is exempt from the requirements of 40 CFR Section 60.482-7a(a) if: (1) The Permittee demonstrates that the valve is unsafe to monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with 40 CFR Section 60.482-7a(a), and (2) The Permittee adheres to a written plan that requires monitoring of the valve as frequently as practicable during safe-to-monitor times. [40 CFR 60.482-7a(g), Minn. R. 7011.2900(D)]

5.17.39 Any valve that is designated, as described in 40 CFR Section 60.486a(f)(2), as a difficult-to-monitor valve is exempt from the requirements of 40 CFR Section 60.482-7a(a) if: (1) The Permittee demonstrates that the valve cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface. (2) The process unit within which the valve is located: (i) Becomes an affected facility through 40 CFR Section 60.14 or 60.15 and was constructed on or before January 5, 1981; or (ii) Has less than 3.0 percent of its valves designated as difficult-to-monitor by the Permittee.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation (3) The Permittee follows a written plan that requires monitoring of the valve at least once per calendar year. [40 CFR 60.482-7a(h), Minn. R. 7011.2900(D)]

5.17.40 If evidence of a potential leak is found by visual, audible, olfactory, or any other detection method at pumps, valves, and connectors in heavy liquid service and pressure relief devices in light liquid or heavy liquid service, the Permittee shall follow either one of the following procedures: (1) The Permittee shall monitor the equipment within 5 days by the method specified in 40 CFR Section 60.485a(b) and shall comply with the requirements of 40 CFR Section 60.482-8a(b) through (d). (2) The Permittee shall eliminate the visual, audible, olfactory, or other indication of a potential leak within 5 calendar days of detection. [40 CFR 60.482-8a(a), Minn. R. 7011.2900(D)]

5.17.41 If an instrument reading of 10,000 ppm or greater is measured, a leak is detected. [40 CFR 60.482-8a(b), Minn. R. 7011.2900(D)]

5.17.42 (1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it is detected, except as provided in 40 CFR Section 60.482-9a. (2) The first attempt at repair shall be made no later than 5 calendar days after each leak is detected. [40 CFR 60.482-8a(c), Minn. R. 7011.2900(D)]

5.17.43 First attempts at repair include, but are not limited to, the best practices described under 40 CFR Sections 60.482-2a(c)(2) and 60.482-7a(e). [40 CFR 60.482-8a(d), Minn. R. 7011.2900(D)]

5.17.44 Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15 days is technically infeasible without a process unit shutdown. Repair of this equipment shall occur before the end of the next process unit shutdown. Monitoring to verify repair must occur within 15 days after startup of the process unit. [40 CFR 60.482-9a(a), Minn. R. 7011.2900(D)]

5.17.45 Delay of repair of equipment will be allowed for equipment which is isolated from the process and which does not remain in VOC service. [40 CFR 60.482-9a(b), Minn. R. 7011.2900(D)]

5.17.46 Delay of repair for valves and connectors will be allowed if: (1) The Permittee demonstrates that emissions of purged material resulting from immediate repair are greater than the fugitive emissions likely to result from delay of repair, and (2) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control device complying with 40 CFR Section 60.482-10a. [40 CFR 60.482-9a(c), Minn. R. 7011.2900(D)]

5.17.47 Delay of repair for pumps will be allowed if: (1) Repair required the use of a dual mechanical seal system that includes a barrier fluid system, and (2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected. [40 CFR 60.482-9a(d), Minn. R. 7011.2900(D)]

5.17.48 Delay of repair beyond a process unit shutdown will be allowed for


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation a valve, if valve assembly replacement is necessary during the process unit shutdown, valve assembly supplies have been depleted, and valve assembly supplies had been sufficiently stocked before the supplies were depleted. Delay of repair beyond the next process unit shutdown will not be allowed unless the next process unit shutdown occurs sooner than 6 months after the first process unit shutdown. [40 CFR 60.482-9a(e), Minn. R. 7011.2900(D)]

5.17.49 When delay of repair is allowed for a leaking pump, valve, or connector that remains in service, the pump, valve, or connector may be considered to be repaired and no longer subject to delay of repair requirements if two consecutive monthly monitoring instrument readings are below the leak definition. [40 CFR 60.482-9a(f), Minn. R. 7011.2900(D)]

5.17.50 If the Permittee utilizes closed vent systems and control devices used to comply with provisions of 40 CFR pt. 60, subp. VVa, the Permittee shall comply with the provisions of 40 CFR Section 60.482-10a as detailed in this permit. [40 CFR 60.482-10a(a), Minn. R. 7011.2900(D)]

5.17.51 Vapor recovery systems (for example, condensers and absorbers) shall be designed and operated to recover the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20 parts per million by volume (ppmv), whichever is less stringent. [40 CFR 60.482-10a(b), Minn. R. 7011.2900(D)]

5.17.52 Enclosed combustion devices shall be designed and operated to reduce the VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20 ppmv, on a dry basis, corrected to 3 percent oxygen, whichever is less stringent or to provide a minimum residence time of 0.75 seconds at a minimum temperature of 816 deg C. [40 CFR 60.482-10a(c), Minn. R. 7011.2900(D)]

5.17.53 Flares used to comply with 40 CFR pt. 60, subp. VVa shall comply with the requirements of 40 CFR Section 60.18. [40 CFR 60.482-10a(d), Minn. R. 7011.2900(D)]

5.17.54 The Permittee shall monitor the control devices to ensure that they are operated and maintained in conformance with their designs. [40 CFR 60.482-10a(e), Minn. R. 7011.2900(D)]

5.17.55 Except as provided in 40 CFR Section 60.482-10a(i) through (k), each closed vent system shall be inspected according to the following procedures: (1) If the vapor collection system or closed vent system is constructed of hard-piping, the Permittee shall comply with the following requirements: (i) Conduct an initial inspection according to the procedures in 40 CFR Section 60.485a(b); and (ii) Conduct annual visual inspections for visible, audible, or olfactory indications of leaks. (2) If the vapor collection system or closed vent system is constructed of ductwork, the Permittee shall:


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation (i) Conduct an initial inspection according to the procedures in 40 CFR Section 60.485a(b); and (ii) Conduct annual inspections according to the procedures in 40 CFR Section 60.485a(b). [40 CFR 60.482-10a(f), Minn. R. 7011.2900(D)]

5.17.56 Leaks, as indicated by an instrument reading greater than 500 ppmv above background or by visual inspections, shall be repaired as soon as practicable except as provided in 40 CFR Section 60.482-10a(h). (1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected. (2) Repair shall be completed no later than 15 calendar days after the leak is detected. [40 CFR 60.482-10a(g), Minn. R. 7011.2900(D)]

5.17.57 Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is technically infeasible without a process unit shut down or if the Permittee determines that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of such equipment shall be complete by the end of the next process unit shutdown. [40 CFR 60.482-10a(h), Minn. R. 7011.2900(D)]

5.17.58 If a vapor collection system or closed vent system is operated under a vacuum, it is exempt from the inspection requirements of 40 CFR Section 60.482-10a(f)(1)(i) and f(2). [40 CFR 60.482-10a(i), Minn. R. 7011.2900(D)]

5.17.59 Any parts of the closed vent system that are designated, as described in 40 CFR Section 60.482-10a(l)(1), as unsafe to inspect are exempt from the inspection requirements of 40 CFR Section 60.482-10a(f)(1)(i) and (f)(2) if they comply with the following requirements: (1) The Permittee determines that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with 40 CFR Section 60.482-10a(f)(1)(i) or (f)(2); and (2) The Permittee has a written plan that requires inspection of the equipment as frequently as practicable during safe-to-inspect times. [40 CFR 60.482-10a(j), Minn. R. 7011.2900(D)]

5.17.60 Any parts of the closed vent system that are designated, as described in 40 CFR Section 60.482-10a(l)(2), as difficult to inspect are exempt from the inspection requirements of 40 CFR Section 60.482-10a(f)(1)(i) and (f)(2) if they comply with the requirements specified in 40 CFR Section 60.482-10a(k)(1) through (3): (1) The Permittee determines that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface; and (2) The process unit within which the closed vent system is located becomes an affected facility through 40 CFR Sections 60.14 or 60.15, or the Permittee designates less than 3.0 percent of the total number of closed vent system equipment as difficult to inspect; and (3) The Permittee has a written plan that requires inspection of the


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation equipment at least once every 5 years. A closed vent system is exempt from inspection if it is operated under a vacuum. [40 CFR 60.482-10a(k), Minn. R. 7011.2900(D)]

5.17.61 The Permittee shall record the information specified below: (1) Identification of all parts of the closed vent system that are designated as unsafe to inspect, an explanation of why the equipment is unsafe to inspect, and the plan for inspection. (2) Identification of all parts of the closed vent system that are designated as difficult to inspect, an explanation of why the equipment is difficult to inspect, and the plan for inspection. (3) For each inspection during which a leak is detected, a record of the information specified in 40 CFR Section 60.486a(c). (4) For each inspection during which no leaks are detected, a record of the inspection , the inspection date, and a statement that no leaks were detected. (5) For each visual inspection conducted in accordance with 40 CFR Section 60.482-10a(f)(1)(ii) during which no leaks are detected, a record of the inspection, the inspection date, and a statement that no leaks were detected. [40 CFR 60.482-10a(l), Minn. R. 7011.2900(D)]

5.17.62 Closed vent systems and control devices used to comply with provisions of 40 CFR pt. 60, subp. VVa shall be operated at all times when emissions may be vented to them. [40 CFR 60.482-10a(m), Minn. R. 7011.2900(D)]

5.17.63 The Permittee shall initially monitor all connectors in the process unit for leaks by the later of either 12 months after the compliance date or 12 months after initial startup. If all connectors in the process unit have been monitored for leaks prior to the compliance date, no initial monitoring is required provided either no process changes have been made since the monitoring or the Permittee can determine that the results of the monitoring, with or without adjustments, reliably demonstrate compliance despite process changes. If required to monitor because of a process change, the Permittee is required to monitor only those connectors involved in the process change. [40 CFR 60.482-11a(a), Minn. R. 7011.2900(D)]

5.17.64 Except as allowed in 40 CFR Section 60.482-1a(c), 40 CFR Section 60.482-10a, or as specified in 40 CFR Section 60.482-11a(e), the Permittee shall monitor all connectors in gas and vapor and light liquid service as specified in 40 CFR Sections 60.482-11a(a) and (b)(3). (1) The connectors shall be monitored to detect leaks by the method specified in 40 CFR Section 60.485a(b) and, as applicable, 40 CFR Section 60.485a(c). (2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is detected. (3)The Permittee shall perform monitoring, subsequent to the initial monitoring required in 40 CFR Section 60.482-11a(a), as specified in 40 CFR Section 60.482-11a(b)(3)(i) through (iii). The required period in which monitoring must be conducted shall be determined from 40 CFR Section 60.482-11a(b)(3)(i) through (iii) using the monitoring results from the preceding monitoring period.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation Depending upon the percent of leaking connectors, each connector may require annual monitoring, or monitoring frequency may be reduced to every 8 years. The percent leaking connectors shall be calculated as specified in 40 CFR Section 60.482-11a(c). (4) If, during the monitoring conducted pursuant to 40 CFR Section 60.482-11a(b)(3)(i) through (iii), a connector is found to be leaking, it shall be re-monitored once within 90 days after repair to confirm that it is not leaking. (5) The Permittee shall keep a record of the start date and end date of each monitoring period under this section for each process unit. [40 CFR 60.482-11a(b), Minn. R. 7011.2900(D)]

5.17.65 For use in determining the monitoring frequency, as specified in 40 CFR Section 60.482-11a(a) and (b)(3), the percent leaking connectors as used in 40 CFR Section 60.482-11a(a) and (b)(3) shall be calculated by using the following equation: %CL= CL/ Ct* 100 Where: %CL= Percent of leaking connectors as determined through periodic monitoring required in 40 CFR Section 60.482-11a(a) and (b)(3)(i) through (iii). CL= Number of connectors measured at 500 ppm or greater, by the method specified in 40 CFR Section 60.485a(b). Ct= Total number of monitored connectors in the process unit or affected facility. [40 CFR 60.482-11a(c), Minn. R. 7011.2900(D)]

5.17.66 When a leak is detected pursuant to 40 CFR Section 60.482-11a(a) and (b), it shall be repaired as soon as practicable, but not later than 15 calendar days after it is detected, except as provided in 40 CFR Section 60.482-9a. A first attempt at repair as defined in 40 CFR pt. 60, subp. VVa shall be made no later than 5 calendar days after the leak is detected. [40 CFR 60.482-11a(d), Minn. R. 7011.2900(D)]

5.17.67 Any connector that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitor connector is exempt from the requirements of 40 CFR Section 60.482-11a(a) and (b)(3)(i) through (iii) if: (1) The Permittee of the connector demonstrates that the connector is unsafe-to-monitor because monitoring personnel would be exposed to an immediate danger as a consequence of complying with 40 CFR Section 60.482-11a(a) and (b); and (2) The Permittee of the connector has a written plan that requires monitoring of the connector as frequently as practicable during safe-to-monitor times but not more frequently than the periodic monitoring schedule otherwise applicable, and repair of the equipment according to the procedures in 40 CFR Section 60.482-11a(d) if a leak is detected. [40 CFR 60.482-11a(e), Minn. R. 7011.2900(D)]

5.17.68 Inaccessible, ceramic, or ceramic-lined connectors . (1) Any connector that is inaccessible or that is ceramic or ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt from the monitoring requirements of 40 CFR Section 60.482-11a(a) and (b), from the leak repair requirements of 40 CFR Section 60.482-11a(d),


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation and from the recordkeeping and reporting requirements of 40 CFR Sections 63.1038 and 63.1039. An inaccessible connector is one that meets any of the provisions specified in 40 CFR Section 60.482-11a(f)(1)(i) through (vi), as applicable. (2) If any inaccessible, ceramic, or ceramic-lined connector is observed by visual, audible, olfactory, or other means to be leaking, the visual, audible, olfactory or other indications of a leak to the atmosphere shall be eliminated as soon as practical. [40 CFR 60.482-11a(f), Minn. R. 7011.2900(D)]

5.17.69 Except for instrumentation systems and inaccessible, ceramic, or ceramic-lined connectors meeting the provisions of 40 CFR Section 60.482-11a(f), identify the connectors subject to the requirements of 40 CFR pt. 60, subp. VVa. Connectors need not be individually identified if all connectors in a designated area or length of pipe subject to the provisions of 40 CFR pt. 60, subp. VVa are identified as a group, and the number of connectors subject is indicated. [40 CFR 60.482-11a(g), Minn. R. 7011.2900(D)]

5.17.70 The Permittee shall determine compliance with the standards in 40 CFR Sections 60.482-1a through 60.482-11a, 60.483a, and 60.484a by: (1) Using Method 21 to determine the presence of leaking sources. The instrument shall be calibrated before use each day of its use by the procedures specified in Method 21 of 40 CFR pt. 60, appendix A-7. The following calibration gases shall be used: (i) Zero air (less than 10 ppm of hydrocarbon in air); and (ii) A mixture of methane or n-hexane and air at a concentration no more than 2,000 ppm greater than the leak definition concentration of the equipment monitored. If the monitoring instrument's design allows for multiple calibration scales, then the lower scale shall be calibrated with a calibration gas that is no higher than 2,000 ppm above the concentration specified as a leak, and the highest scale shall be calibrated with a calibration gas that is approximately equal to 10,000 ppm. If only one scale on an instrument will be used during monitoring, the Permittee need not calibrate the scales that will not be used during that day's monitoring. (2) A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day. Check the instrument using the same calibration gas(as) that were used to calibrate the instrument before use. Follow the procedures specified in Method 21 of 40 CFR pt. 60, appendix A-7, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. Record the instrument reading for each scale used as specified in 40 CFR Section 60.486a(e)(7). Calculate the average algebraic difference between the three meter readings and the most recent calibration value. Divide this algebraic calibration difference by the initial calibration value and multiply by 1-to express the calibration drift as a percentage. If any calibration drift assessment shows a negative drift of more than 10 percent from the initial calibration value, then all equipment monitored since the last calibration with instrument readings


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation below the appropriate leak definition and above the leak definition multiplied by (100 minus the percent of negative drift/divided by 100) must be re-monitored. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the Permittee's discretion, all equipment since the last calibration with instrument readings above the appropriate leak definition and below the leak definition multiplied by (10 plus the percent of positive drift/divided by 100) may be re-monitored. [40 CFR 60.485a(b), Minn. R. 7011.2900(D)]

5.17.71 The Permittee shall conduct performance tests required in 40 CFR Section 60.8 using as reference methods and procedures the test methods in 40 CFR pt. 60, appendix A or other methods and procedures as specified in 40 CFR pt. 60, subp. VVa, except as provided in 40 CFR Section 60.8(b). [40 CFR 60.485a(a), Minn. R. 7011.2900(D)]

5.17.72 The Permittee shall determine compliance with the no-detectable-emissions standards in 40 CFR Section 60.482-2a(e), 60.482-3a(i), 60.482-4a, 60.482a(f), and 60.482-10a(e) as follows: (1) The requirements of 40 CFR Section 60.485a(b) shall apply. (2) Method 21 of 40 CFR pt. 60, appendix A-7 shall be used to determine the background level. All potential leak interfaces shall be traversed as close to the interface as possible. The arithmetic difference between the maximum concentration indicated by the instrument and the background level is compared with 500 ppm for determining compliance. [40 CFR 60.485a(c), Minn. R. 7011.2900(D)]

5.17.73 (d) The Permittee shall test each piece of equipment unless the Permittee demonstrates that a process unit is not in VOC service, i.e., that the VOC content would never be reasonably expected to exceed 10 percent by weight. For purposes of this demonstration, the following methods and procedures shall be used: (1) Procedures that conform to the general methods in ASTM E260-73, 91, or 96, E168-67, 77, or 92, E169-63, 77, or 93 (incorporated by reference-see 40 CFR 60.17) shall be used to determine the percent VOC content in the process fluid that is contained in or contacts a piece of equipment. (2) Organic compounds that are considered by the Administrator to have negligible photochemical reactivity may be excluded from the total quantity of organic compounds in determining the VOC content of the process fluid. (3) Engineering judgment may be used to estimate the VOC content, if a piece of equipment had not been shown previously to be in service. If the Administrator disagrees with the judgment, 40 CFR Section 60.485a(d)(1) and (2) of this section shall be used to resolve the disagreement. [40 CFR 60.485a(d), Minn. R. 7011.2900(D)]

5.17.74 (e) The Permittee shall demonstrate that a piece of equipment is in light liquid service by showing that all the following conditions apply: (1) The vapor pressure of one or more of the organic components is greater than 0.3 kPa at 20 deg C (1.2 in. H2O at 68 deg F).


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation Standard reference texts or ASTM D2879-83, 96, or 97 (incorporated by reference-see 40 CFR 60.17) shall be used to determine the vapor pressures. (2) The total concentration of the pure organic components having a vapor pressure greater than 0.3 kPa at 20 deg C (1.2 in. H2O at 68 deg F) is equal to or greater than 20 percent by weight. (3) The fluid is a liquid at operating conditions. [40 CFR 60.485a(e), Minn. R. 7011.2900(D)]

5.17.75 (f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be representative of the process fluid that is contained in or contacts the equipment or the gas being combusted in the flare. [40 CFR 60.485a(f), Minn. R. 7011.2900(D)]

5.17.76 (g) The owner or operator shall determine compliance with the standards of flares as follows: (1) Method 22 of appendix A-7 of this part shall be used to determine visible emissions. (2) A thermocouple or any other equivalent device shall be used to monitor the presence of a pilot flame in the flare. (3) The maximum permitted velocity for air assisted flares shall be computed using the equation in Appendix C of this permit. [40 CFR 60.485a(g), Minn. R. 7011.2900(D)]

5.17.77 When each leak is detected, the following requirements apply: (1) A weatherproof and readily visible identification, marked with the equipment identification number, shall be attached to the leaking equipment. (2) The identification on a valve may be removed after it has been monitored for 2 successive months as specified in 40 CFR Section 60.482-7a(c) and no leak has been detected during those 2 months. (3) The identification on a connector may be removed after it has been monitored as specified in 40 CFR Section 60.482-11a(b)(3)(iv) and no leak has been detected during that monitoring. (4) The identification on equipment, except on a valve or connector, may be removed after it has been repaired. [40 CFR 60.486a(b), Minn. R. 7011.2900(D)]

5.17.78 When each leak is detected the following information shall be recorded in a log and shall be kept for 2 years in a readily accessible location: (1) The instrument and operator identification numbers and the equipment identification number. (2) The date the leak was detected and the dates of each attempt to repair the leak. (3) Repair methods applied in each attempt to repair the leak. (4) Maximum instrument reading measured by Method 21 of appendix A-7 of 40 CFR pt. 60 at the time the leak is successfully repaired or determined to be nonrepairable, except when a pump is repaired by eliminating indications of liquids dripping. (5) Repair delayed and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak. (6) The signature of the Permittee whose decision it was that the repair could not be affected without a process shutdown.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation (7) The expected date of successful repair of the leak if a leak is not repaired within 15 days. (8) Dates of process unit shutdown that occur while the equipment is unrepaired. (9) The date of successful repair of the leak. [40 CFR 60.486a(c), Minn. R. 7011.2900(D)]

5.17.79 The information pertaining to the design requirements for closed vent systems and required control devices described in 40 CFR Section 60.482-10a shall be recorded and kept in a readily accessible location: (1) Detailed schematics, design specifications, and piping and instrumentation diagrams. (2) The dates and descriptions of any changes in the design specifications. (3) A description of the parameter(s) monitored per 40 CFR Section 60.482-10a(e), to ensure that control devices are operated and maintained in conformance with their design and an explanation of why that parameter(s) was selected. (4) Periods when the closed vent systems and required control devices are not operated as designed, including periods when a flare pilot light does not have a flame. (5) Dates of startups and shutdowns of the closed vent systems and required control devices. [40 CFR 60.486a(d), Minn. R. 7011.2900(D)]

5.17.80 Information pertaining to all equipment subject to the requirements in 40 CFR Section 60.482-1a to 60.482-11a shall be recorded in a log that is kept in a readily accessible location and contain the information specified in 40 CFR Section 486a(e)(1) through (10). [40 CFR 60.486a(e), Minn. R. 7011.2900(D)]

5.17.81 The following information pertaining to all valves subject to the requirements of 40 CFR Section 60.482-7a(g) and (h), all pumps subject to the requirements of 40 CFR Section 60.482-2a(g), and all connectors subject to the requirements of 40 CFR Section 60.482-11a(e) shall be recorded in a log that is kept in a readily accessible location: (1) A list of identification numbers for valves, pumps, and connectors that are designated as unsafe-to-monitor, an explanation for each valve, pump, or connector stating why the valve, pump, or connector is unsafe-to-monitor, and the plan for monitoring each valve, pump, or connector. (2) A list of identification numbers for valves that are designated as difficult-to-monitor, an explanation for each valve stating why the valve is difficult-to-monitor, and the schedule for monitoring each valve. [40 CFR 60.486a(f), Minn. R. 7011.2900(D)]

5.17.82 The following information shall be recorded for valves complying with 40 CFR Section 60.483-2a: (1) A schedule of monitoring. (2) The percent of valves found leaking during each monitoring period. [40 CFR 60.486a(g), Minn. R. 7011.2900(D)]

5.17.83 The following information shall be recorded in a log that is kept in


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation a readily accessible location: (1) Design criterion required in 40 CFR Sections 60.482-2a(d)(5) and 60.482-3a(e)(2) and explanation of the design criterion; and (2) Any changes to this criterion and the reasons for the changes. [40 CFR 60.486a(h), Minn. R. 7011.2900(D)]

5.17.84 The following information shall be recorded in a log that is kept in a readily accessible location for use in determining exemptions as provided in 40 CFR Section 60.480a(d): (1) An analysis demonstrating the design capacity of the affected facility, (2) A statement listing the feed or raw materials and products from the affected facilities and an analysis demonstrating whether these chemicals are heavy liquids or beverage alcohol, and (3) An analysis demonstrating that equipment is not in VOC service. [40 CFR 60.486a(i), Minn. R. 7011.2900(D)]

5.17.85 Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in a log that is kept in a readily accessible location. [40 CFR 60.486a(j), Minn. R. 7011.2900(D)]

5.17.86 The provisions of 40 CFR Section 60.7(b) and (d) do not apply to affected facilities subject to 40 CFR pt. 60, subp. VVa. [40 CFR 60.486a(k), Minn. R. 7011.2900(D)]

5.17.87 All semiannual reports to the Commissioner shall include the following information, summarized from the information in 40 CFR Section 60.486a; (1) Process unit identification. (2) For each month during the semiannual reporting period, (i) Number of valves for which leaks were detected as described in 40 CFR Section 60.482-7a(b) or 40 CFR 60.483-2a (ii) Number of valves for which leaks were not repaired as required in 40 CFR Section 60.482-7a(d)(1), (iii) Number of pumps for which leaks were detected as described in 40 CFR Section 60.482-2a(b), (d)(4)(ii)(A) or (B), or (d)(5)(iii), (iv) Number of pumps for which leaks were not repaired as required in 40 CFR Section 60.482-2a(c)(1) and (d)(6), (v) Number of compressors for which leaks were detected as described in 40 CFR Section 60.482-3a(f), (vi) Number of compressors for which leaks were not repaired as required in 40 CFR Section 60.482-3a(g)(1), (vii) Number of connectors for which leaks were detected as described in 40 CFR Section 60.482-11a(b), and (viii) Number of connectors for which leaks were not repaired as required in 40 CFR Section 60.482-11a(d). (3) Dates of process unit shutdowns which occurred within the semiannual reporting period. and (4) Revisions to items reported according to 40 CFR Section 60.487a(b) if changes have occurred since the initial report or subsequent revisions to the initial report. [40 CFR pt. 60, 487a(c), Minn. R. 7011.2900(D)]

5.17.88 Notification: If the Permittee elects to comply with the provisions of 40 CFR Sections 60.483-1a or 60.483-2a, the Permittee shall notify the Administrator of the alternative standard selected 90 days before implementing either of the provisions. [40 CFR 60.487a(d), Minn. R. 7011.2900(D)]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 5.17.89 Report the results of all performance tests in accordance with 40

CFR Section 60.8. The provisions of 40 CFR Section 60.8(d) do not apply to affected facilities subject to the provisions of 40 CFR pt. 60, subp. VVa except that the Permittee must notify the Commissioner of the schedule for the initial performance tests at least 30 days before the initial performance tests. [40 CFR 60.487a(e), Minn. R. 7011.2900(D)]

TREA 2 CE001 Flaring 5.18.1 The Permittee shall operate and maintain a flare to control

emissions from biodiesel processing equipment in methanol service, including, new and modified biodiesel processing equipment in methanol service that achieves an overall control efficiency for Methanol >= 98 percent control efficiency. [Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.18.2 The Permittee shall vent emissions from all biodiesel processing equipment, including existing, modified, or new processing equipment, to a flare meeting the requirements of TREA 2. The flare shall be operated at all times when emissions may be vented to it. [40 CFR 60.18(e), Minn. R. 7011.0050, Title I Condition: Avoid major source under 40 CFR 63, To avoid major source under 40 CFR 70.2 & Minn. R. 7007.0200]

5.18.3 The flare shall be designed and operated with no visible emissions as determined by Method 22, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. [Minn. R. 7007.0800, subp. 2, Minn. R. 7007.0800, subp. 4]

5.18.4 The flare shall be operated with a pilot flame present at all times. The presence of a flare pilot flame shall be monitored using a thermocouple or other equivalent device to detect the presence of a flame. [Minn. R. 7007.0800, subp. 4]

5.18.5 The flare shall adhere to the following specifications: (1) The flare shall be used only with the net heating value of the gas being combusted being 300 BTU/scf or greater if the flare is steam assisted or air assisted; or with the net heating value of the gas being combusted being 200 BTU/scf or greater if the flare is nonassisted. The heating value of the gas being combusted shall be determined using the methods specified in 40 CFR Section 60.18(f)(3). (2) Steam-assisted and nonassisted flares shall be designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4) of 40 CFR Section 60.18, less than 60 ft/sec, except as provided in paragraphs (c)(4)(ii) and (iii) of 40 CFR Section 60.18. (3) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in 40 CFR Section 60.18(f)(4), equal to or greater than 60


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation ft/sec, but less than 400 ft/sec are allowed if the net heating value of the gas being combusted is greater than 1,000 BTU/scf. (4) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in paragraph 40 CFR Section 60.18(f)(4), less than the velocity, Vmax, as determined by the method specified in paragraph 40 CFR Section 60.18(f)(5), and less than 400 ft/sec are allowed. [Minn. R. 7007.0800, subp. 2]

5.18.6 (1) Method 22 of appendix A of 40 CFR pt. 60 shall be used to determine the compliance of flares with the visible emission provisions of 40 CFR pt. 60, subp. A. The observation period is 2 hours and shall be used according to Method 22. (2) 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. (3) The net heating value of the gas being combusted in a flare shall be calculated using the equation in Appendix C. (4) The actual exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip. (5) The maximum permitted velocity, Vmax, for flares complying with paragraph (c)(4)(iii) of 40 CFR Section 60.18 shall be determined using the equation in Appendix C. (6) The maximum permitted velocity, Vmax, for air-assisted flares shall be determined by the equation in Appendix C. [Minn. R. 7007.0800, subp. 4]

5.18.7 At all times, including periods of startup, shutdown, and malfunction, the Permittee shall maintain and operate any affected facility in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. [Minn. R. 7007.0800, subp. 14, Minn. R. 7007.0800, subp. 16(J)]

5.18.8 The Permittee shall record all periods when the pilot flame is not present during operation of any emissions unit that vents to the flare. Record the time, duration, cause (if known), and whether or not any emissions were vented to the flare during the period in which the pilot flame was not present. Document the corrective actions taken to restore the pilot flame.


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation Periods when the pilot flame is not present during operation of any emissions unit that vents to the flare shall be reported as deviations on the semiannual deviations report. For periods when the pilot flame is not present, emissions shall be calculated assuming uncontrolled operation of the facility for the purposes of calculating emissions for COMG 4. Records shall be maintained for a period of 5 years. [Minn. R. 7007.0800, subp. 5]


6. Submittal/action requirements

This section lists most of the submittals required by this permit. Please note that some submittal requirements may appear in the Limits and Other Requirements section, or, if applicable, within a Compliance Schedule section.

Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation TFAC 1 04700061 REG Albert Lea

LLC

6.1.1 The Permittee shall submit a semiannual deviations report : Due semiannually, by the 30th of January and July. The first semiannual report submitted by the Permittee shall cover the calendar half-year in which the permit is issued. The first report of each calendar year covers January 1 - June 30. The second report of each calendar year covers July 1 - December 31. Submit this on form DRF-2 (Deviation Reporting Form). If no deviations have occurred, submit the signed report certifying that there were no deviations. [Minn. R. 7007.0800, subp. 6(A)(2)]

6.1.2 The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previous calendar year). Submit this on form CR-04 (Annual Compliance Certification Report). This report covers all deviations experienced during the calendar year. If no deviations have occurred, submit the signed report certifying that there were no deviations. [Minn. R. 7007.0800, subp. 6(C)]

EQUI 39 EU001 Vacuum Pump

(Biodiesel Process)

6.2.1 The Permittee shall submit to the Administrator semiannual reports: due before end of each half-year starting 05/01/2005. The semiannual reports shall contain the following recorded information: (1) Exceedances of monitored parameters recorded under 40 CFR Section 60.665(c) and (g). (2) All periods recorded under 40 CFR Section 60.665(d) when the vent stream is diverted from the control device or has no flow rate. (3) All periods recorded under 40 CFR Section 60.665(e) when the boiler or process heater was not operating. (4) All periods recorded under 40 CFR Section 60.665(f) in which the pilot flame of the flare was absent. [40 CFR 60.665(I), Minn. R. 7011.2900(C)]

EQUI 43 Boiler 6.3.1 The Permittee shall submit a notification of date construction

began: Due 30 calendar days after Date of Construction Start (or reconstruction). Submit the name and number of the Subject Item and the date construction began. [40 CFR 60.48c(a), 40 CFR 60.7(a)(1), Minn. R. 7019.0100, subp. 1]


Subject Item Sec.SI.Reqt SI des:SI desc Requirement & Citation 6.3.2 The Permittee shall submit a notification of the actual date of

initial startup: Due 15 calendar days after Initial Startup Date. [40 CFR 60.7(a)(3), Minn. R. 7019.0100, subp. 1]

EQUI 45 EU002 Transesterificatio

n Reactors

6.4.1 Submit a semiannual deviations report : Due by 30 days after end of each calendar half-year starting 09/14/2004. The initial report shall be submitted within 6 months after the initial start-up date. The semiannual deviation report shall include the following recorded information: 1. Exceedances of monitored parameters recorded under Section 60.705(g); 2. Any recalculation of the TRE index value, as recorded under Section 60.705(g). [40 CFR 60.705(I)(1) and (6), Minn. R. 7011.3430]

FUGI 1 FS001 Equipment Leaks

(MeOH, ethanol, VOCs)

6.5.1 The Permittee shall submit a report: Due semiannually, effective after Initial Startup, by the 31st of January and July that includes the information specified in 40 CFR Section 60.487 and that is summarized at FUGI 1 in this permit. [40 CFR 60.487a(a), Minn. R. 7011.2900(D)]


7. Appendices Appendix A. Insignificant Activities and General Applicable Requirements The table below lists the insignificant activities that are currently at the Facility and their associated general applicable requirements.

Minn. R. Rule description of the activity General applicable requirement Minn. R. 7007.1300, subp. 3(G) Emissions from a laboratory, as defined in

Minn. R. 7007.1300, subp. 3(G) REG Albert Lea has a product quality lab.

PM, variable depending on airflow Opacity <= 20% (Minn. R. 7011.0715)

Minn. R. 7007.1300, subp. 3(H)(3)

Brazing, soldering or welding equipment REG Albert Lea has maintenance activities that fall under this category.

PM, variable depending on airflow Opacity <= 20% (Minn. R. 7011.0715)

Minn. R. 7007.1300, subp. 3(I) Individual units with potential emissions less than 2000 lb/year of certain pollutants REG Albert Lea currently has 12 tanks for storage. These tanks have PTEs less than the listed thresholds in Minn. R. 7007.1300, subp. I. These storage tanks are listed in Table A-2 below for informational purposes only.

Minn. R. 7011.1505

Minn. R. 7007.1300, subp. 3(J) Fugitive dust emissions from unpaved entrance roads and parking lots REG Albert Lea has unpaved roads, and paved roads and parking lots.

Requirement to take reasonable measures to prevent PM from becoming airborne (Minn. R. 7011.0150)

The facility also has space heaters on-site. The heat for these heaters is in the form of steam which is provided by a neighboring facility, POET Bio-refining - Glenville East. These units are not required to be listed (steam is not a pollutant) and are mentioned here for information purposes only.

Table A-2. Storage Tanks – Qualify as Insignificant Activities under Minn. R. 7007.1300, subp. I Tank Description Products Stored Tank Capacity (gallons) TK009 Above Ground Carbon Steel Crude Feedstock 500,000 TK010 Above Ground Carbon Steel Finished Biodiesel 500,000 TK011 Above Ground Carbon Steel Finished Biodiesel 500,000 TK012 Above Ground Stainless Steel

Glycerin 100,000

TK013 Above Ground Carbon Steel Biodiesel Rework 20,000 TK014 Above Ground Carbon Steel Free Fatty Acids 11,000 TK015 Above Ground Carbon Steel Soapstop/Wastewater 14,000 TK016 Above Ground Carbon Steel Finished Biodiesel 5,000,000 TK017 Above Ground Carbon Steel Crude Feedstock 500,000


TK018 Above Ground Carbon Steel Crude Feedstock 11,000 TK019 Above Ground Stainless Steel

Distillation Bottoms 25,000

TK020 Above Ground Stainless Steel

Free Fatty Acid 100,000


Appendix B. TRE Index Value Calculation Methods

EU 001 - Vacuum Pump Design category B for Non-halogenated process vent streams, if 0< net heating value (btu/scf) < 13 40 CFR 60.664(f)(1) Subpart NNN

TRE = (l/ETOC)*[a + b(Qs)+c(Qs)A0.88+d(Qs)(Ht)+e(Qs)A0.88(Ht)A0.88+f(Ys)A0.5]

TRE = 689 ETOC 0.0274 kg/hr Qs 3 scf/min Ht 0.75 btu/scf Ys 3 a 18.83268 d -0.000398 b 0.00659 e 0 c 0.008647 f 0.003803

40 CFR 60.664(f)(2) Subpart NNN

TRE = (l/ETOC)*[a(Qs)+b(Qs)A0.8+c(Qs)(Ht)+d(ETOC) +e]

TRE = 186 ETOC 0.0274 kg/hr Qs 3 scf/min Ht 0.75 btu/scf a 0.14 d -0.0051 b 0.0367 e 4.59 c -0.000448

EU 002 - Nitrogen Blanket Design category B for Non-halogenated process vent streams, if 0< net heating value (btu/scf) < 13 40 CFR 60.704(e)(1) TRE = (1/ETOC)* [a + b(Qs)+c(Qs)A0.88+d(Qs)(Ht)+e(Qs)A0.88(Ht)A0.88+f(Ys)A0.5] TRE = 46,037 ETOC 0.00041 kg/hr Qs 3 scf/min Ht 0.00028 btu/scf Ys 0.00023 a 18.83268 d -0.000398 b 0.00659 e 0 c 0.008647 f 0.003803 40 CFR 60.704(e)(2)

TRE = (l/ETOC)*[a(Qs)+b(Qs)A0.8+c(Qs)(Ht)+d(ETOC) +e]

TRE = 12,435


ETOC 0.00041 kg/hr Qs 3 scf/min Ht 0.00028 btu/scf a 0.14 d -0.0051 b 0.0367 e 4.59 c -0.000448

* Although the constant values in Subparts NNN and RRR do not appear to be the same, NNN gives the constants in both English and metric systems. RRR gives the constant values only in metric. In comparison of the two, they are the same constants, and therefore the same constants are used for both calculations.


Appendix C. Flare Calculations From 40 CFR §60.18(f)(3), the net heating value of the gas being combusted in a flare shall be calculated using the following equation:

𝐻𝐻𝑇𝑇 = 𝐾𝐾 � 𝐶𝐶𝑖𝑖𝐻𝐻𝑖𝑖

𝑛𝑛

𝑖𝑖=1

Where: 𝐻𝐻𝑇𝑇 = net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based on combustion at 25°C and 760 mmHg, but the standard temperature for determining the volume corresponding to one mole is 20°C; 𝐾𝐾 = constant, 1.740 ∗ 10−7 � 1

𝑝𝑝𝑝𝑝𝑚𝑚� �𝑔𝑔 𝑚𝑚𝑚𝑚𝑙𝑙𝑙𝑙

𝑠𝑠𝑠𝑠𝑚𝑚� � 𝑀𝑀𝑀𝑀

𝑘𝑘𝑠𝑠𝑐𝑐𝑙𝑙� where the standard temperature for �𝑔𝑔 𝑚𝑚𝑚𝑚𝑙𝑙𝑙𝑙

𝑠𝑠𝑠𝑠𝑚𝑚� is 20°C;

𝐶𝐶𝑖𝑖 = concentration of sample component 𝑖𝑖 in ppm on a wet basis, as measured for organics by Reference Method 18 and measured for hydrogen and carbon monoxide by ASTM D1946-77 or 90; and 𝐻𝐻𝑖𝑖 = net heat of combustion of sample component 𝑖𝑖, kcal/g mole at 25°C and 760 mmHg. The heats of combustion may be determined using ASTM D2382-76 or 88 or D4809-95 if published values are not available or cannot be calculated. From 40 CFR §60.18(f)(5), the maximum permitted velocity, 𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥 of a flare complying with paragraph (c)(4)(iii) or 40 CFR §60.18 shall be calculated using the following equation:

log10(𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥) =(𝐻𝐻𝑇𝑇 + 28.8)

31.7

Where: 𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥 = maximum permitted velocity, M/sec; 28.8 = constant; 31.7 = constant; and 𝐻𝐻𝑇𝑇 = the next heating values as determined in paragraph (f)(3) of 40 CFR §60.18. From 40 CFR §60.18(f)(6), the maximum permitted velocity, 𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥 for air-assisted flares shall be calculated using the following equation:

𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥 = 8.706 + 0.7084(𝐻𝐻𝑇𝑇) Where: 𝑉𝑉𝑚𝑚𝑐𝑐𝑥𝑥 = maximum permitted velocity, M/sec; 8.706 = constant; 0.7084 = constant; and 𝐻𝐻𝑇𝑇 = the net heating values as determined in paragraph (f)(3) of 40 CFR §60.18.


Appendix D. EAW Modeling for Permit No. 04700061-003 Table D-1: Modeled Parameters

Modeling ID

Permit ID

Operating Scenario #

Stack Height

(m)

Stack Diameter

(m)

Exit Velocity

(m/s)

Exit Temperature

(K) Pollutant Averaging

Period

Emission Rate

(lb/hr)

Emission Rate (g/s)

EU4PM EU 004 1 9.1436 9.727 3.048 288.71 PM2.5 24-hr 0.0004 0.0000504 EU4PM EU 004 1 9.1436 9.727 3.048 288.71 PM2.5 Annual 0.0004 0.0000504 EU4PM EU 004 1 9.1436 9.727 3.048 288.71 PM10 24-hr 0.6 0.0756 EU4PM EU 004 1 9.1436 9.727 3.048 288.71 PM10 Annual 0.6 0.0756 EU7CO EU 007 1 9.1436 0.711 4.752 449.82 CO 1-hr 1.51 0.19026 EU7CO EU 007 1 9.1436 0.711 4.752 449.82 CO 8-hr 1.51 0.19026

EU7NO2 EU 007 1 9.1436 0.711 4.752 449.82 NO2 1-hr 1.8 0.2268 EU7NO2 EU 007 1 9.1436 0.711 4.752 449.82 NO2 Annual 1.8 0.2268 EU7PM25 EU 007 1 9.1436 0.711 4.752 449.82 PM2.5 24-hr 0.14 0.01764 EU7PM25 EU 007 1 9.1436 0.711 4.752 449.82 PM2.5 Annual 0.14 0.01764 EU7PM10 EU 007 1 9.1436 0.711 4.752 449.82 PM10 24-hr 0.14 0.01764 EU7PM10 EU 007 1 9.1436 0.711 4.752 449.82 PM10 Annual 0.14 0.01764 EU7SO2 EU 007 1 9.1436 0.711 4.752 449.82 SO2 1-hr 0.01 0.00126 EU7SO2 EU 007 1 9.1436 0.711 4.752 449.82 SO2 3-hr 0.01 0.00126 EU7SO2 EU 007 1 9.1436 0.711 4.752 449.82 SO2 24-hr 0.01 0.00126 EU7SO2 EU 007 1 9.1436 0.711 4.752 449.82 SO2 Annual 0.01 0.00126 EU8CO EU 008 1 9.1436 0.711 4.752 449.82 CO 1-hr 1.51 0.19026 EU8CO EU 008 1 9.1436 0.711 4.752 449.82 CO 8-hr 1.51 0.19026

EU8NO2 EU 008 1 9.1436 0.711 4.752 449.82 NO2 1-hr 1.8 0.2268 EU8NO2 EU 008 1 9.1436 0.711 4.752 449.82 NO2 Annual 1.8 0.2268 EU8PM25 EU 008 1 9.1436 0.711 4.752 449.82 PM2.5 24-hr 0.14 0.01764 EU8PM25 EU 008 1 9.1436 0.711 4.752 449.82 PM2.5 Annual 0.14 0.01764 EU8PM10 EU 008 1 9.1436 0.711 4.752 449.82 PM10 24-hr 0.14 0.01764 EU8PM10 EU 008 1 9.1436 0.711 4.752 449.82 PM10 Annual 0.14 0.01764 EU8SO2 EU 008 1 9.1436 0.711 4.752 449.82 SO2 1-hr 0.01 0.00126 EU8SO2 EU 008 1 9.1436 0.711 4.752 449.82 SO2 3-hr 0.01 0.00126 EU8SO2 EU 008 1 9.1436 0.711 4.752 449.82 SO2 24-hr 0.01 0.00126 EU8SO2 EU 008 1 9.1436 0.711 4.752 449.82 SO2 Annual 0.01 0.00126 EU10PM EU 010 1 12.192 4.864 3.048 288.71 PM2.5 24-hr 0.0002 0.0000252 EU10PM EU 010 1 12.192 4.864 3.048 288.71 PM2.5 Annual 0.0002 0.0000252 EU10PM EU 010 1 12.192 4.864 3.048 288.71 PM10 24-hr 0.32 0.04032 EU10PM EU 010 1 12.192 4.864 3.048 288.71 PM10 Annual 0.32 0.04032 SV1CO SV 001 1 7.6196 1.067 1.583 310.93 CO 1-hr 0.74 0.09324 SV1CO SV 001 1 7.6196 1.067 1.583 310.93 CO 8-hr 0.74 0.09324

SV1NO2 SV 001 1 7.6196 1.067 1.583 310.93 NO2 1-hr 0.14 0.01764 SV1NO2 SV 001 1 7.6196 1.067 1.583 310.93 NO2 Annual 0.14 0.01764 SV1PM25 SV 001 1 7.6196 1.067 1.583 310.93 PM2.5 24-hr 0.02 0.00252 SV1PM25 SV 001 1 7.6196 1.067 1.583 310.93 PM2.5 Annual 0.02 0.00252 SV1PM10 SV 001 1 7.6196 1.067 1.583 310.93 PM10 24-hr 0.02 0.00252


Appendix E. Equipment Leaks Calculation

Equipment Type

Emission Factor (source: EPA’s Protocol for

Equipment Leak Emission Estimates (11/95) Tables

2-1 and 2-9)

Screening Value from NSPS Subp.

VVa (ppm)

Equipment Count

Control Efficiency (%) (source: EPA’s Protocol

for Equipment Leak Emission Estimates (11/95) Table 5-2)

Emissions (lb/hr)

Gas Valves EF (lb/hr) = 1.87 * 10-6 * (SV)0.873 * 2.204 500 66 87 0.0080

Light Liquid Valves

EF (lb/hr) = 6.41 * 10-6 * (SV)0.797 * 2.204 500 323 84 0.1034

Light Liquid Pumps

EF (lb/hr) = 1.9 * 10-5 * (SV)0.824 * 2.204 2000 17 69 0.1159

Connectors EF (lb/hr) = 3.05 * 10-6 * (SV)0.885 * 2.204 500 1104 93 0.1271

Pressure Relief Valves

EF (lb/hr) = 1.9 * 10-5 * (SV)0.824 * 2.204 500 24 NA 0.1684

Open-ended Lines

EF (lb/hr) = 0.00170 * 2.204 NA 0 NA 0.0000

Agitators EF (lb/hr) = 1.9 * 10-5 * (SV)0.824 * 2.204 2000 3 NA 0.0660

Total (lb/hr) 0.589

* The Permittee shall use the most recent monitored value in place of the screening value when calculating emissions from gas valves, light liquid valves, light liquid pumps, connectors, pressure relief valves, and agitators.


Appendix F. Modeling for Permit No. 04700061-101 Table F-1: Modeled Parameters, Point Sources

Permit ID

Model ID Pollutant Averaging Period

Operating Scenario #

Release Type

Emission Rate

(lb/hr)

Emission Rate (g/s)

Exit Temp

(K)

Exit Velocity

(m/s)

Flow Rate

(acfm) EQUI 43 BOILPM10 PM10 24-hr 1 Vertical 0.2496 0.031450 449.82 11.078 8,030 EQUI 43 BOILPM25 PM2.5 24-hr 1 Vertical 0.2496 0.031450 449.82 11.078 8,030 EQUI 43 BOILPM25 PM2.5 Annual 1 Vertical 0.2496 0.031450 449.82 11.078 8,030 SV 001 SV1PM25 PM2.5 24-hr 1 Vertical 0.0149 0.0018776 310.93 1.583 3,000 SV 004 SV4PM25 PM2.5 24-hr 1 Vertical 0.000797 0.00010037 288.71 3.048 480,000 SV 007 SV7PM25 PM2.5 24-hr 1 Vertical 0.134 0.016899 449.82 4.752 4,000 SV 008 SV8PM25 PM2.5 24-hr 1 Vertical 0.134 0.016899 449.82 4.752 4,000 SV 009 SV9PM25 PM2.5 24-hr 1 Vertical 0.000425 0.000053530 228.71 3.048 120,000

Table F-1: Modeled Parameters, Point Sources (continued)

Permit ID Model ID Release Type

X –Coordinate

(m)

Y – Coordinate

(m)

Base Elevation

(m)

Stack Height

(m)

Stack Diameter

(m) EQUI 43 BOILPM10 Vertical 475,712.82 4,824,624.83 379.20 7.163 0.66 EQUI 43 BOILPM25 Vertical 475,712.82 4,824,624.83 379.20 7.163 0.66 EQUI 43 BOILPM25 Vertical 475,712.82 4,824,624.83 379.20 7.163 0.66 SV 001 SV1PM25 Vertical 475,776.20 4,824,638.00 379.17 7.62 1.067 SV 004 SV4PM25 Vertical 475,775.10 4,824,593.00 379.15 9.144 9.727 SV 007 SV7PM25 Vertical 475,728.90 4,824,574.00 379.00 9.144 0.711 SV 008 SV8PM25 Vertical 475,732.80 4,824,574.00 379.13 9.144 0.711 SV 009 SV9PM25 Vertical 475,715.00 4,824,574.00 378.89 12.19 4.864


Appendix G. 40 CFR pt. 60, subp. A – General Provisions e-CFR data is current as of July 25, 2017

Title 40: Protection of Environment PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

Subpart A—General Provisions

Contents §60.1 Applicability. §60.2 Definitions. §60.3 Units and abbreviations. §60.4 Address. §60.5 Determination of construction or modification. §60.6 Review of plans. §60.7 Notification and record keeping. §60.8 Performance tests. §60.9 Availability of information. §60.10 State authority. §60.11 Compliance with standards and maintenance requirements. §60.12 Circumvention. §60.13 Monitoring requirements. §60.14 Modification. §60.15 Reconstruction. §60.16 Priority list. §60.17 Incorporations by reference. §60.18 General control device and work practice requirements. §60.19 General notification and reporting requirements. Table 1 to Subpart A of Part 60—Detection Sensitivity Levels (grams per hour)

§60.1 Applicability. (a) Except as provided in subparts B and C, the provisions of this part apply to the owner or operator of any stationary source which contains an affected facility, the construction or modification of which is commenced after the date of publication in this part of any standard (or, if earlier, the date of publication of any proposed standard) applicable to that facility.

(b) Any new or revised standard of performance promulgated pursuant to section 111(b) of the Act shall apply to the owner or operator of any stationary source which contains an affected facility, the construction or


modification of which is commenced after the date of publication in this part of such new or revised standard (or, if earlier, the date of publication of any proposed standard) applicable to that facility.

(c) In addition to complying with the provisions of this part, the owner or operator of an affected facility may be required to obtain an operating permit issued to stationary sources by an authorized State air pollution control agency or by the Administrator of the U.S. Environmental Protection Agency (EPA) pursuant to Title V of the Clean Air Act (Act) as amended November 15, 1990 (42 U.S.C. 7661). For more information about obtaining an operating permit see part 70 of this chapter.

(d) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia. (1) This paragraph applies only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”).

(2) Except for compliance with 40 CFR 60.49b(u), the site shall have the option of either complying directly with the requirements of this part, or reducing the site-wide emissions caps in accordance with the procedures set forth in a permit issued pursuant to 40 CFR 52.2454. If the site chooses the option of reducing the site-wide emissions caps in accordance with the procedures set forth in such permit, the requirements of such permit shall apply in lieu of the otherwise applicable requirements of this part.

(3) Notwithstanding the provisions of paragraph (d)(2) of this section, for any provisions of this part except for Subpart Kb, the owner/operator of the site shall comply with the applicable provisions of this part if the Administrator determines that compliance with the provisions of this part is necessary for achieving the objectives of the regulation and the Administrator notifies the site in accordance with the provisions of the permit issued pursuant to 40 CFR 52.2454.

[40 FR 53346, Nov. 17, 1975, as amended at 55 FR 51382, Dec. 13, 1990; 59 FR 12427, Mar. 16, 1994; 62 FR 52641, Oct. 8, 1997]

§60.2 Definitions. The terms used in this part are defined in the Act or in this section as follows:

Act means the Clean Air Act (42 U.S.C. 7401 et seq.)

Administrator means the Administrator of the Environmental Protection Agency or his authorized representative.

Affected facility means, with reference to a stationary source, any apparatus to which a standard is applicable.

Alternative method means any method of sampling and analyzing for an air pollutant which is not a reference or equivalent method but which has been demonstrated to the Administrator's satisfaction to, in specific cases, produce results adequate for his determination of compliance.

Approved permit program means a State permit program approved by the Administrator as meeting the requirements of part 70 of this chapter or a Federal permit program established in this chapter pursuant to Title V of the Act (42 U.S.C. 7661).


Capital expenditure means an expenditure for a physical or operational change to an existing facility which exceeds the product of the applicable “annual asset guideline repair allowance percentage” specified in the latest edition of Internal Revenue Service (IRS) Publication 534 and the existing facility's basis, as defined by section 1012 of the Internal Revenue Code. However, the total expenditure for a physical or operational change to an existing facility must not be reduced by any “excluded additions” as defined in IRS Publication 534, as would be done for tax purposes.

Clean coal technology demonstration project means a project using funds appropriated under the heading ‘Department of Energy-Clean Coal Technology’, up to a total amount of $2,500,000,000 for commercial demonstrations of clean coal technology, or similar projects funded through appropriations for the Environmental Protection Agency.

Commenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification.

Construction means fabrication, erection, or installation of an affected facility.

Continuous monitoring system means the total equipment, required under the emission monitoring sections in applicable subparts, used to sample and condition (if applicable), to analyze, and to provide a permanent record of emissions or process parameters.

Electric utility steam generating unit means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility.

Equivalent method means any method of sampling and analyzing for an air pollutant which has been demonstrated to the Administrator's satisfaction to have a consistent and quantitatively known relationship to the reference method, under specified conditions.

Excess Emissions and Monitoring Systems Performance Report is a report that must be submitted periodically by a source in order to provide data on its compliance with stated emission limits and operating parameters, and on the performance of its monitoring systems.

Existing facility means, with reference to a stationary source, any apparatus of the type for which a standard is promulgated in this part, and the construction or modification of which was commenced before the date of proposal of that standard; or any apparatus which could be altered in such a way as to be of that type.

Force majeure means, for purposes of §60.8, an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents the owner or operator from complying with the regulatory requirement to conduct performance tests within the specified timeframe despite the affected facility's best efforts to fulfill the obligation. Examples of such events


are acts of nature, acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility.

Isokinetic sampling means sampling in which the linear velocity of the gas entering the sampling nozzle is equal to that of the undisturbed gas stream at the sample point.

Issuance of a part 70 permit will occur, if the State is the permitting authority, in accordance with the requirements of part 70 of this chapter and the applicable, approved State permit program. When the EPA is the permitting authority, issuance of a Title V permit occurs immediately after the EPA takes final action on the final permit.

Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operation are not malfunctions.

Modification means any physical change in, or change in the method of operation of, an existing facility which increases the amount of any air pollutant (to which a standard applies) emitted into the atmosphere by that facility or which results in the emission of any air pollutant (to which a standard applies) into the atmosphere not previously emitted.

Monitoring device means the total equipment, required under the monitoring of operations sections in applicable subparts, used to measure and record (if applicable) process parameters.

Nitrogen oxides means all oxides of nitrogen except nitrous oxide, as measured by test methods set forth in this part.

One-hour period means any 60-minute period commencing on the hour.

Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background.

Owner or operator means any person who owns, leases, operates, controls, or supervises an affected facility or a stationary source of which an affected facility is a part.

Part 70 permit means any permit issued, renewed, or revised pursuant to part 70 of this chapter.

Particulate matter means any finely divided solid or liquid material, other than uncombined water, as measured by the reference methods specified under each applicable subpart, or an equivalent or alternative method.

Permit program means a comprehensive State operating permit system established pursuant to title V of the Act (42 U.S.C. 7661) and regulations codified in part 70 of this chapter and applicable State regulations, or a comprehensive Federal operating permit system established pursuant to title V of the Act and regulations codified in this chapter.

Permitting authority means:


(1) The State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to carry out a permit program under part 70 of this chapter; or

(2) The Administrator, in the case of EPA-implemented permit programs under title V of the Act (42 U.S.C. 7661).

Proportional sampling means sampling at a rate that produces a constant ratio of sampling rate to stack gas flow rate.

Reactivation of a very clean coal-fired electric utility steam generating unit means any physical change or change in the method of operation associated with the commencement of commercial operations by a coal-fired utility unit after a period of discontinued operation where the unit:

(1) Has not been in operation for the two-year period prior to the enactment of the Clean Air Act Amendments of 1990, and the emissions from such unit continue to be carried in the permitting authority's emissions inventory at the time of enactment;

(2) Was equipped prior to shut-down with a continuous system of emissions control that achieves a removal efficiency for sulfur dioxide of no less than 85 percent and a removal efficiency for particulates of no less than 98 percent;

(3) Is equipped with low-NOX burners prior to the time of commencement of operations following reactivation; and

(4) Is otherwise in compliance with the requirements of the Clean Air Act.

Reference method means any method of sampling and analyzing for an air pollutant as specified in the applicable subpart.

Repowering means replacement of an existing coal-fired boiler with one of the following clean coal technologies: atmospheric or pressurized fluidized bed combustion, integrated gasification combined cycle, magnetohydrodynamics, direct and indirect coal-fired turbines, integrated gasification fuel cells, or as determined by the Administrator, in consultation with the Secretary of Energy, a derivative of one or more of these technologies, and any other technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of November 15, 1990. Repowering shall also include any oil and/or gas-fired unit which has been awarded clean coal technology demonstration funding as of January 1, 1991, by the Department of Energy.

Run means the net period of time during which an emission sample is collected. Unless otherwise specified, a run may be either intermittent or continuous within the limits of good engineering practice.

Shutdown means the cessation of operation of an affected facility for any purpose.

Six-minute period means any one of the 10 equal parts of a one-hour period.


Standard means a standard of performance proposed or promulgated under this part.

Standard conditions means a temperature of 293 K (68F) and a pressure of 101.3 kilopascals (29.92 in Hg).

Startup means the setting in operation of an affected facility for any purpose.

State means all non-Federal authorities, including local agencies, interstate associations, and State-wide programs, that have delegated authority to implement: (1) The provisions of this part; and/or (2) the permit program established under part 70 of this chapter. The term State shall have its conventional meaning where clear from the context.

Stationary source means any building, structure, facility, or installation which emits or may emit any air pollutant.

Title V permit means any permit issued, renewed, or revised pursuant to Federal or State regulations established to implement title V of the Act (42 U.S.C. 7661). A title V permit issued by a State permitting authority is called a part 70 permit in this part.

Volatile Organic Compound means any organic compound which participates in atmospheric photochemical reactions; or which is measured by a reference method, an equivalent method, an alternative method, or which is determined by procedures specified under any subpart.

[44 FR 55173, Sept. 25, 1979, as amended at 45 FR 5617, Jan. 23, 1980; 45 FR 85415, Dec. 24, 1980; 54 FR 6662, Feb. 14, 1989; 55 FR 51382, Dec. 13, 1990; 57 FR 32338, July 21, 1992; 59 FR 12427, Mar. 16, 1994; 72 FR 27442, May 16, 2007]

§60.3 Units and abbreviations. Used in this part are abbreviations and symbols of units of measure. These are defined as follows:

(a) System International (SI) units of measure:

A—ampere

g—gram

Hz—hertz

J—joule

K—degree Kelvin

kg—kilogram

m—meter


m3—cubic meter

mg—milligram—10−3 gram

mm—millimeter—10−3 meter

Mg—megagram—106 gram

mol—mole

N—newton

ng—nanogram—10−9 gram

nm—nanometer—10−9 meter

Pa—pascal

s—second

V—volt

W—watt

Ω—ohm

µg—microgram—10−6 gram

(b) Other units of measure:

Btu—British thermal unit

°C—degree Celsius (centigrade)

cal—calorie

cfm—cubic feet per minute

cu ft—cubic feet

dcf—dry cubic feet

dcm—dry cubic meter

dscf—dry cubic feet at standard conditions


dscm—dry cubic meter at standard conditions

eq—equivalent

°F—degree Fahrenheit

ft—feet

gal—gallon

gr—grain

g-eq—gram equivalent

hr—hour

in—inch

k—1,000

l—liter

lpm—liter per minute

lb—pound

meq—milliequivalent

min—minute

ml—milliliter

mol. wt.—molecular weight

ppb—parts per billion

ppm—parts per million

psia—pounds per square inch absolute

psig—pounds per square inch gage

°R—degree Rankine

scf—cubic feet at standard conditions


scfh—cubic feet per hour at standard conditions

scm—cubic meter at standard conditions

sec—second

sq ft—square feet

std—at standard conditions

(c) Chemical nomenclature:

CdS—cadmium sulfide

CO—carbon monoxide

CO2—carbon dioxide

HCl—hydrochloric acid

Hg—mercury

H2O—water

H2S—hydrogen sulfide

H2SO4—sulfuric acid

N2—nitrogen

NO—nitric oxide

NO2—nitrogen dioxide

NOX—nitrogen oxides

O2—oxygen

SO2—sulfur dioxide

SO3—sulfur trioxide

SOX—sulfur oxides

(d) Miscellaneous:


A.S.T.M.—American Society for Testing and Materials

[42 FR 37000, July 19, 1977; 42 FR 38178, July 27, 1977]

§60.4 Address. (a) All requests, reports, applications, submittals, and other communications to the Administrator pursuant to this part shall be submitted in duplicate to the appropriate Regional Office of the U.S. Environmental Protection Agency to the attention of the Director of the Division indicated in the following list of EPA Regional Offices.

Region I (Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, Vermont), Director, Office of Ecosystem Protection, U.S. Environmental Protection Agency, 5 Post Office Square—Suite 100, Boston, MA 02109-3912.

Region II (New Jersey, New York, Puerto Rico, Virgin Islands), Director, Air and Waste Management Division, U.S. Environmental Protection Agency, Federal Office Building, 26 Federal Plaza (Foley Square), New York, NY 10278.

Region III (Delaware, District of Columbia, Maryland, Pennsylvania, Virginia, West Virginia), Director, Air Protection Division, Mail Code 3AP00, 1650 Arch Street, Philadelphia, PA 19103-2029.

Region IV (Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina, Tennessee), Director, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, 61 Forsyth St. SW., Suite 9T43, Atlanta, Georgia 30303-8960.

Region V (Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin), Director, Air and Radiation Division, U.S. Environmental Protection Agency, 77 West Jackson Boulevard, Chicago, IL 60604-3590.

Region VI (Arkansas, Louisiana, New Mexico, Oklahoma, Texas); Director; Air, Pesticides, and Toxics Division; U.S. Environmental Protection Agency, 1445 Ross Avenue, Dallas, TX 75202.

Region VII (Iowa, Kansas, Missouri, Nebraska), Director, Air and Waste Management Division, 11201 Renner Boulevard, Lenexa, Kansas 66219.

Region VIII (Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming) Director, Air and Toxics Technical Enforcement Program, Office of Enforcement, Compliance and Environmental Justice, Mail Code 8ENF-AT, 1595 Wynkoop Street, Denver, CO 80202-1129.

Region IX (Arizona, California, Hawaii and Nevada; the territories of American Samoa and Guam; the Commonwealth of the Northern Mariana Islands; the territories of Baker Island, Howland Island, Jarvis Island, Johnston Atoll, Kingman Reef, Midway Atoll, Palmyra Atoll, and Wake Islands; and certain U.S. Government activities in the freely associated states of the Republic of the Marshall Islands, the Federated States of Micronesia, and the Republic of Palau), Director, Air Division, U.S. Environmental Protection Agency, 75 Hawthorne Street, San Francisco, CA 94105.


Region X (Alaska, Oregon, Idaho, Washington), Director, Air and Waste Management Division, U.S. Environmental Protection Agency, 1200 Sixth Avenue, Seattle, WA 98101.

(b) Section 111(c) directs the Administrator to delegate to each State, when appropriate, the authority to implement and enforce standards of performance for new stationary sources located in such State. All information required to be submitted to EPA under paragraph (a) of this section, must also be submitted to the appropriate State Agency of any State to which this authority has been delegated (provided, that each specific delegation may except sources from a certain Federal or State reporting requirement). The appropriate mailing address for those States whose delegation request has been approved is as follows:

(1) [Reserved]

(2) State of Alabama: Alabama Department of Environmental Management, P.O. Box 301463, Montgomery, Alabama 36130-1463.

(3) State of Alaska, Department of Environmental Conservation, Pouch O, Juneau, AK 99811.

(4) Arizona:

Arizona Department of Environmental Quality, 1110 West Washington Street, Phoenix, AZ 85007.

Maricopa County Air Quality Department, 1001 North Central Avenue, Suite 900, Phoenix, AZ 85004.

Pima County Department of Environmental Quality, 33 North Stone Avenue, Suite 700, Tucson, AZ 85701.

Pinal County Air Quality Control District, 31 North Pinal Street, Building F, Florence, AZ 85132.

NOTE: For tables listing the delegation status of agencies in Region IX, see paragraph (d) of this section.

(5) State of Arkansas: Chief, Division of Air Pollution Control, Arkansas Department of Pollution Control and Ecology, 8001 National Drive, P.O. Box 9583, Little Rock, AR 72209.

(6) California:

Amador County Air Pollution Control District, 12200-B Airport Road, Jackson, CA 95642.

Antelope Valley Air Quality Management District, 43301 Division Street, Suite 206, Lancaster, CA 93535.

Bay Area Air Quality Management District, 939 Ellis Street, San Francisco, CA 94109.

Butte County Air Quality Management District, 2525 Dominic Drive, Suite J, Chico, CA 95928.

Calaveras County Air Pollution Control District, 891 Mountain Ranch Road, San Andreas, CA 95249.

Colusa County Air Pollution Control District, 100 Sunrise Blvd., Suite A-3, Colusa, CA 95932-3246.


El Dorado County Air Quality Management District, 2850 Fairlane Court, Bldg. C, Placerville, CA 95667-4100.

Eastern Kern Air Pollution Control District, 2700 “M” Street, Suite 302, Bakersfield, CA 93301-2370.

Feather River Air Quality Management District, 1007 Live Oak Blvd., Suite B-3, Yuba City, CA 95991.

Glenn County Air Pollution Control District, 720 N. Colusa Street, P.O. Box 351, Willows, CA 95988-0351.

Great Basin Unified Air Pollution Control District, 157 Short Street, Suite 6, Bishop, CA 93514-3537.

Imperial County Air Pollution Control District, 150 South Ninth Street, El Centro, CA 92243-2801.

Lake County Air Quality Management District, 885 Lakeport Blvd., Lakeport, CA 95453-5405.

Lassen County Air Pollution Control District, 707 Nevada Street, Suite 1, Susanville, CA 96130.

Mariposa County Air Pollution Control District, P.O. Box 5, Mariposa, CA 95338.

Mendocino County Air Quality Management District, 306 E. Gobbi Street, Ukiah, CA 95482-5511.

Modoc County Air Pollution Control District, 619 North Main Street, Alturas, CA 96101.

Mojave Desert Air Quality Management District, 14306 Park Avenue, Victorville, CA 92392-2310.

Monterey Bay Unified Air Pollution Control District, 24580 Silver Cloud Court, Monterey, CA 93940.

North Coast Unified Air Quality Management District, 2300 Myrtle Avenue, Eureka, CA 95501-3327.

Northern Sierra Air Quality Management District, 200 Litton Drive, Suite 320, P.O. Box 2509, Grass Valley, CA 95945-2509.

Northern Sonoma County Air Pollution Control District, 150 Matheson Street, Healdsburg, CA 95448-4908.

Placer County Air Pollution Control District, 3091 County Center Drive, Suite 240, Auburn, CA 95603.

Sacramento Metropolitan Air Quality Management District, 777 12th Street, Third Floor, Sacramento, CA 95814-1908.

San Diego County Air Pollution Control District, 10124 Old Grove Road, San Diego, CA 92131-1649.

San Joaquin Valley Air Pollution Control District, 1990 E. Gettysburg, Fresno, CA 93726.

San Luis Obispo County Air Pollution Control District, 3433 Roberto Court, San Luis Obispo, CA 93401-7126.


Santa Barbara County Air Pollution Control District, 260 North San Antonio Road, Suite A, Santa Barbara, CA 93110-1315.

Shasta County Air Quality Management District, 1855 Placer Street, Suite 101, Redding, CA 96001-1759.

Siskiyou County Air Pollution Control District, 525 So. Foothill Drive, Yreka, CA 96097-3036.

South Coast Air Quality Management District, 21865 Copley Drive, Diamond Bar, CA 91765-4182.

Tehama County Air Pollution Control District, P.O. Box 8069 (1750 Walnut Street), Red Bluff, CA 96080-0038.

Tuolumne County Air Pollution Control District, 22365 Airport, Columbia, CA 95310.

Ventura County Air Pollution Control District, 669 County Square Drive, 2nd Floor, Ventura, CA 93003-5417.

Yolo-Solano Air Quality Management District, 1947 Galileo Court, Suite 103, Davis, CA 95616-4882.


(7) State of Colorado, Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80222-1530.

NOTE: For a table listing Region VIII's NSPS delegation status, see paragraph (c) of this section.

(8) State of Connecticut, Bureau of Air Management, Department of Environmental Protection, State Office Building, 165 Capitol Avenue, Hartford, CT 06106.

(9) State of Delaware, Department of Natural Resources & Environmental Control, 89 Kings Highway, P.O. Box 1401, Dover, Delaware 19903.

(10) District of Columbia, Department of Public Health, Air Quality Division, 51 N Street, NE., Washington, DC 20002.

(11) State of Florida: Florida Department of Environmental Protection, Division of Air Resources Management, 2600 Blair Stone Road, MS 5500, Tallahassee, Florida 32399-2400.

(12) State of Georgia: Georgia Department of Natural Resources, Environmental Protection Division, Air Protection Branch, 4244 International Parkway, Suite 120, Atlanta, Georgia 30354.

(13) Hawaii:

Clean Air Branch, Hawaii Department of Health, 919 Ala Moana Blvd., Suite 203, Honolulu, HI 96814.



(14) State of Idaho, Department of Health and Welfare, Statehouse, Boise, ID 83701.

(15) State of Illinois: Illinois Environmental Protection Agency, 1021 North Grand Avenue East, Springfield, Illinois 62794.

(16) State of Indiana: Indiana Department of Environmental Management, Office of Air Quality, 100 North Senate Avenue, Indianapolis, Indiana 46204.

(17) State of Iowa: Iowa Department of Natural Resources, Environmental Protection Division, Air Quality Bureau, 7900 Hickman Road, Suite 1, Urbandale, IA 50322.

(18) State of Kansas: Kansas Department of Health and Environment, Bureau of Air and Radiation, 1000 S.W. Jackson, Suite 310, Topeka, KS 66612-1366.

(19) Commonwealth of Kentucky: Kentucky Department for Environmental Protection, Division for Air Quality, 300 Sower Boulevard, 2nd Floor, Frankfort, Kentucky 40601 or local agency, Louisville Metro Air Pollution Control District, 701 W. Ormsby Ave., Suite 303, Louisville, Kentucky 40203.

(20) State of Louisiana: Louisiana Department of Environmental Quality, P.O. Box 4301, Baton Rouge, Louisiana 70821-4301.

NOTE: For a list of delegated standards for Louisiana (excluding Indian country), see paragraph (e)(2) of this section.

(21) State of Maine, Bureau of Air Quality Control, Department of Environmental Protection, State House, Station No. 17, Augusta, ME 04333.

(22) State of Maryland, Department of the Environment, 1800 Washington Boulevard, Suite 705, Baltimore, Maryland 21230.

(23) Commonwealth of Massachusetts, Division of Air Quality Control, Department of Environmental Protection, One Winter Street, 7th floor, Boston, MA 02108.

(24) State of Michigan: Michigan Department of Natural Resources and Environment, Air Quality Division, P.O. Box 30028, Lansing, Michigan 48909.

(25) State of Minnesota: Minnesota Pollution Control Agency, Division of Air Quality, 520 Lafayette Road North, St. Paul, Minnesota 55155.

(26) State of Mississippi: Hand Deliver or Courier: Mississippi Department of Environmental Quality, Office of Pollution Control, Air Division, 515 East Amite Street, Jackson, Mississippi 39201, Mailing Address: Mississippi Department of Environmental Quality, Office of Pollution Control, Air Division, P.O. Box 2261, Jackson, Mississippi 39225.

(27) State of Missouri: Missouri Department of Natural Resources, Division of Environmental Quality, P.O. Box 176, Jefferson City, MO 65102.


(28) State of Montana, Department of Environmental Quality, 1520 E. 6th Ave., PO Box 200901, Helena, MT 59620-0901.


(29) State of Nebraska, Nebraska Department of Environmental Control, P.O. Box 94877, State House Station, Lincoln, NE 68509.

Lincoln-Lancaster County Health Department, Division of Environmental Health, 2200 St. Marys Avenue, Lincoln, NE 68502

(30) Nevada:

Nevada Division of Environmental Protection, 901 South Stewart Street, Suite 4001, Carson City, NV 89701-5249.

Clark County Department of Air Quality and Environmental Management, 500 S. Grand Central Parkway, 1st Floor, P.O. Box 555210, Las Vegas, NV 89155-5210.

Washoe County Health District, Air Quality Management Division, 1001 E. 9th Street, Building A, Suite 115A, Reno, NV 89520.


(31) State of New Hampshire, Air Resources Division, Department of Environmental Services, 64 North Main Street, Caller Box 2033, Concord, NH 03302-2033.

(32) State of New Jersey: New Jersey Department of Environmental Protection, Division of Environmental Quality, Enforcement Element, John Fitch Plaza, CN-027, Trenton, NJ 08625.

(1) The following table lists the specific source and pollutant categories that have been delegated to the states in Region II. The (X) symbol is used to indicate each category that has been delegated.

Subpart State

New Jersey

New York

Puerto Rico

Virgin Islands

D Fossil-Fuel Fired Steam Generators for Which Construction Commenced After August 17, 1971 (Steam Generators and Lignite Fired Steam Generators)

X X X X

Da Electric Utility Steam Generating Units for Which Construction Commenced After September 18, 1978 X X

Db Industrial-Commercial-Institutional Steam Generating Units X X X X E Incinerators X X X X F Portland Cement Plants X X X X


G Nitric Acid Plants X X X X H Sulfuric Acid Plants X X X X I Asphalt Concrete Plants X X X X J Petroleum Refineries—(All Categories) X X X X

K Storage Vessels for Petroleum Liquids Constructed After June 11, 1973, and prior to May 19, 1978 X X X X

Ka Storage Vessels for Petroleum Liquids Constructed After May 18, 1978 X X X

L Secondary Lead Smelters X X X X M Secondary Brass and Bronze Ingot Production Plants X X X X N Iron and Steel Plants X X X X O Sewage Treatment Plants X X X X P Primary Copper Smelters X X X X Q Primary Zinc Smelters X X X X R Primary Lead Smelters X X X X S Primary Aluminum Reduction Plants X X X X T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X X X U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X X X V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X X X X W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X X X Phosphate Fertilizer Industry: Granular Triple Superphosphate X X X X Y Coal Preparation Plants X X X X Z Ferroally Production Facilities X X X X AA Steel Plants: Electric Arc Furnaces X X X X

AAa Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels in Steel Plants X X X

BB Kraft Pulp Mills X X X CC Glass Manufacturing Plants X X X DD Grain Elevators X X X EE Surface Coating of Metal Furniture X X X GG Stationary Gas Turbines X X X HH Lime Plants X X X KK Lead Acid Battery Manufacturing Plants X X LL Metallic Mineral Processing Plants X X X MM Automobile and Light-Duty Truck Surface Coating Operations X X NN Phosphate Rock Plants X X PP Ammonium Sulfate Manufacturing Plants X X


QQ Graphic Art Industry Publication Rotogravure Printing X X X X RR Pressure Sensitive Tape and Label Surface Coating Operations X X X SS Industrial Surface Coating: Large Appliances X X X TT Metal Coil Surface Coating X X X UU Asphalt Processing and Asphalt Roofing Manufacture X X X VV Equipment Leaks of Volatile Organic Compounds in Synthetic

Organic Chemical Manufacturing Industry X X WW Beverage Can Surface Coating Industry X X X XX Bulk Gasoline Terminals X X X FFF Flexible Vinyl and Urethane Coating and Printing X X X GGG Equipment Leaks of VOC in Petroleum Refineries X X HHH Synthetic Fiber Production Facilities X X JJJ Petroleum Dry Clearners X X X KKK Equipment Leaks of VOC from Onshore Natural Gas Processing

Plants

LLL Onshore Natural Gas Processing Plants; SO2 Emissions X OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X X

(33) State of New Mexico: New Mexico Environment Department, P.O. Box 5469, Santa Fe, New Mexico 87502-5469. Note: For a list of delegated standards for New Mexico (excluding Bernalillo County and Indian country), see paragraph (e)(1) of this section.

(i) Albuquerque-Bernalillo County Air Quality Control Board, c/o Environmental Health Department, P.O. Box 1293, Albuquerque, New Mexico 87103.

(ii) [Reserved]

(34) New York: New York State Department of Environmental Conservation, 50 Wolf Road Albany, New York 12233, attention: Division of Air Resources.

(35) State of North Carolina: North Carolina Department of Environmental Quality, Division of Air Quality, 1641 Mail Service Center, Raleigh, North Carolina 27699-1641 or local agencies, Forsyth County Office of Environmental Assistance and Protection, 201 North Chestnut Street, Winston-Salem, North Carolina 27101-4120; Mecklenburg County Land Use and Environmental Services Agency, Air Quality, 2145 Suttle Avenue, Charlotte, North Carolina 28208; Western North Carolina Regional Air Quality Agency, 125 S. Lexington Ave., Suite 101, Asheville, North Carolina 28801-3661.

(36) State of North Dakota, Division of Air Quality, North Dakota Department of Health, P.O. Box 5520, Bismarck, ND 58506-5520.



(37) State of Ohio:

(i) Medina, Summit and Portage Counties; Director, Akron Regional Air Quality Management District, 146 South High Street, Room 904, Akron, OH 44308.

(ii) Stark County; Director, Canton City Health Department, Air Pollution Control Division, 420 Market Avenue North, Canton, Ohio 44702-1544.

(iii) Butler, Clermont, Hamilton, and Warren Counties; Director, Hamilton County Department of Environmental Services, 250 William Howard Taft Road, Cincinnati, Ohio 45219-2660.

(iv) Cuyahoga County; Commissioner, Cleveland Department of Public Health, Division of Air Quality, 75 Erieview Plaza 2nd Floor, Cleveland, Ohio 44114.

(v) Clark, Darke, Greene, Miami, Montgomery, and Preble Counties; Director, Regional Air Pollution Control Agency, 117 South Main Street, Dayton, Ohio 45422-1280.

(vi) Lucas County and the City of Rossford (in Wood County); Director, City of Toledo, Division of Environmental Services, 348 South Erie Street, Toledo, OH 43604.

(vii) Adams, Brown, Lawrence, and Scioto Counties; Portsmouth Local Air Agency, 605 Washington Street, Third Floor, Portsmouth, OH 45662.

(viii) Allen, Ashland, Auglaize, Crawford, Defiance, Erie, Fulton, Hancock, Hardin, Henry, Huron, Marion, Mercer, Ottawa, Paulding, Putnam, Richland, Sandusky, Seneca, Van Wert Williams, Wood (Except City of Rossford), and Wyandot Counties; Ohio Environmental Protection Agency, Northwest District Office, Air Pollution Control, 347 North Dunbridge Road, Bowling Green, Ohio 43402.

(ix) Ashtabula, Caroll, Colombiana, Holmes, Lorain, and Wayne Counties; Ohio Environmental Protection Agency, Northeast District Office, Air Pollution Unit, 2110 East Aurora Road, Twinsburg, OH 44087.

(x) Athens, Belmont, Coshocton, Gallia, Guemsey, Harrison, Hocking, Jackson, Jefferson, Meigs, Monroe, Morgan, Muskingum, Noble, Perry, Pike, Ross, Tuscarawas, Vinton, and Washington Counties; Ohio Environmental Protection Agency, Southeast District Office, Air Pollution Unit, 2195 Front Street, Logan, OH 43138.

(xi) Champaign, Clinton, Highland, Logan, and Shelby Counties; Ohio Environmental Protection Agency, Southwest District Office, Air Pollution Unit, 401 East Fifth Street, Dayton, Ohio 45402-2911.

(xii) Delaware, Fairfield, Fayette, Franklin, Knox, Licking, Madison, Morrow, Pickaway, and Union Counties; Ohio Environmental Protection Agency, Central District Office, Air Pollution control, 50 West Town Street, Suite 700, Columbus, Ohio 43215.

(xiii) Geauga and Lake Counties; Lake County General Health District, Air Pollution Control, 33 Mill Street, Painesville, OH 44077.


(xiv) Mahoning and Trumbull Counties; Mahoning-Trumbull Air Pollution Control Agency, 345 Oak Hill Avenue, Suite 200, Youngstown, OH 44502.

(38) State of Oklahoma, Oklahoma State Department of Health, Air Quality Service, P.O. Box 53551, Oklahoma City, OK 73152.

(i) Oklahoma City and County: Director, Oklahoma City-County Health Department, 921 Northeast 23rd Street, Oklahoma City, OK 73105.

(ii) Tulsa County: Tulsa City-County Health Department, 4616 East Fifteenth Street, Tulsa, OK 74112.

(39) State of Oregon. (i) Oregon Department of Environmental Quality (ODEQ), 811 SW Sixth Avenue, Portland, OR 97204-1390, http://www.deq.state.or.us.

(ii) Lane Regional Air Pollution Authority (LRAPA), 1010 Main Street, Springfield, Oregon 97477, http://www.lrapa.org.

(40)(i) City of Philadelphia, Department of Public Health, Air Management Services, 321 University Avenue, Philadelphia, Pennsylvania 19104.

(ii) Commonwealth of Pennsylvania, Department of Environmental Protection, Bureau of Air Quality Control, P.O. Box 8468, 400 Market Street, Harrisburg, Pennsylvania 17105.

(iii) Allegheny County Health Department, Bureau of Environmental Quality, Division of Air Quality, 301 39th Street, Pittsburgh, Pennsylvania 15201.

(41) State of Rhode Island, Division of Air and Hazardous Materials, Department of Environmental Management, 291 Promenade Street, Providence, RI 02908.

(42) State of South Carolina: South Carolina Department of Health and Environmental Control, 2600 Bull Street, Columbia, South Carolina 29201.

(43) State of South Dakota, Air Quality Program, Department of Environment and Natural Resources, Joe Foss Building, 523 East Capitol, Pierre, SD 57501-3181.

NOTE: For a table listing Region VIII's NSPS delegation status, see paragragh (c) of this section.

(44) State of Tennessee: Tennessee Department of Environment and Conservation, Division of Air Pollution Control, William R. Snodgrass Tennessee Tower, 312 Rosa L. Parks Avenue, 15th Floor, Nashville, Tennessee 37243, or local agencies, Knox County Air Quality Management—Department of Public Health, 140 Dameron Avenue, Knoxville, Tennessee 37917; Metro Public Health Department, Pollution Control Division, 2500 Charlotte Ave., Nashville, Tennessee 37209; Chattanooga-Hamilton County Air Pollution Control Bureau, 6125 Preservation Drive, Chattanooga, Tennessee 37416; Shelby County Health Department, Pollution Control Section, 814 Jefferson Avenue, Memphis, Tennessee 38105.

(45) State of Texas, Texas Air Control Board, 6330 Highway 290 East, Austin, TX 78723.


(46) State of Utah, Division of Air Quality, Department of Environmental Quality, P.O. Box 144820, Salt Lake City, UT 84114-4820.


(47) State of Vermont, Air Pollution Control Division, Agency of Natural Resources, Building 3 South, 103 South Main Street, Waterbury, VT 05676.

(48) Commonwealth of Virginia, Department of Environmental Quality, 629 East Main Street, Richmond, Virginia 23219.

(49) State of Washington. (i) Washington State Department of Ecology (Ecology), P.O. Box 47600, Olympia, WA 98504-7600, http://www.ecy.wa.gov/

(ii) Benton Clean Air Authority (BCAA), 650 George Washington Way, Richland, WA 99352-4289, http://www.bcaa.net/

(iii) Northwest Air Pollution Control Authority (NWAPA), 1600 South Second St., Mount Vernon, WA 98273-5202, http://www.nwair.org/

(iv) Olympic Regional Clean Air Agency (ORCAA), 909 Sleater-Kinney Road S.E., Suite 1, Lacey, WA 98503-1128, http://www.orcaa.org/

(v) Puget Sound Clean Air Agency (PSCAA), 110 Union Street, Suite 500, Seattle, WA 98101-2038, http://www.pscleanair.org/

(vi) Spokane County Air Pollution Control Authority (SCAPCA), West 1101 College, Suite 403, Spokane, WA 99201, http://www.scapca.org/

(vii) Southwest Clean Air Agency (SWCAA), 1308 NE. 134th St., Vancouver, WA 98685-2747, http://www.swcleanair.org/

(viii) Yakima Regional Clean Air Authority (YRCAA), 6 South 2nd Street, Suite 1016, Yakima, WA 98901, http://co.yakima.wa.us/cleanair/default.htm

(ix) The following table lists the delegation status of the New Source Performance Standards for the State of Washington. An “X” indicates the subpart has been delegated, subject to all the conditions and limitations set forth in Federal law and the letters granting delegation. Some authorities cannot be delegated and are retained by EPA. Refer to the letters granting delegation for a discussion of these retained authorities. The dates noted at the end of the table indicate the effective dates of Federal rules that have been delegated. Authority for implementing and enforcing any amendments made to these rules after these effective dates are not delegated.

NSPS Subparts Delegated to Washington Air Agencies


Subpart1 Washington

Ecology2

BCAA3

NWAPA4

ORCAA5

PSCAA6

SCAPCA7

SWCAA8

YRCAA9

A General Provisions X X X X X X X X B Adoption and Submittal of State Plans for Designated Facilities

C Emission Guidelines and Compliance Times

Cb Large Municipal Waste Combustors that are Constructed on or before September 20, 1994 (Emission Guidelines and Compliance Times)

Cc Municipal Solid Waste Landfills (Emission Guidelines and Compliance Times)

Cd Sulfuric Acid Production Units (Emission Guidelines and Compliance Times)

Ce Hospital/Medical/Infectious Waste Incinerators (Emission Guidelines and Compliance Times)

D Fossil-Fuel-Fired Steam Generators for which Construction is Commenced after August 17, 1971

X X X X X X X X

Da Electric Utility Steam Generating Units for which Construction is Commenced after September 18, 1978

X X X X X X X X

Db Industrial-Commercial-Institutional Steam Generating Units

X X X X X X X X

Dc Small Industrial-Commercial-Institutional Steam Generating Units

X X X X X X X X

E Incinerators X X X X X X X X Ea Municipal Waste Combustors for which X X X X X X X X


Construction is Commenced after December 20, 1989 and on or before September 20, 1994 Eb—Large Municipal Waste Combustors X X X X

Ec—Hospital/Medical/Infectious Waste Incinerators

X X X X X X

F Portland Cement Plants X X X X X X X X G Nitric Acid Plants X X X X X X X X H Sulfuric Acid Plants X X X X X X X X I Hot Mix Asphalt Facilities X X X X X X X X J Petroleum Refineries X X X X X X X X K Storage Vessels for Petroleum Liquids for which Construction, Reconstruction, or Modification Commenced after June 11, 1973 and prior to May 19, 1978

X X X X X X X X

Ka Storage Vessels for Petroleum Liquids for which Construction, Reconstruction, or Modification Commenced after May 18, 1978 and prior to July 23, 1984

X X X X X X X X

Kb VOC Liquid Storage Vessels (including Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or Modification Commenced after July 23, 1984

X X X X X X X X

L Secondary Lead Smelters X X X X X X X X M Secondary Brass and Bronze Production Plants X X X X X X X X

N Primary Emissions from Basic Oxygen Process Furnaces for which Construction is Commenced after June 11, 1973

X X X X X X X X

Na Secondary Emissions X X X X X X X X


from Basic Oxygen Process Steel-making Facilities for which Construction is Commenced after January 20, 1983 O Sewage Treatment Plants X X X X X X X X P Primary Copper Smelters X X X X X X X X Q Primary Zinc Smelters X X X X X X X X R Primary Lead Smelters X X X X X X X X S Primary Aluminum Reduction Plants10 X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants

X X X X X X X X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants

X X X X X X X X

V Phosphate Fertilizer Industry: Diammonium Phosphate Plants

X X X X X X X X

W Phosphate Fertilizer Industry: Triple Superphosphate Plants

X X X X X X X X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities

X X X X X X X X

Y Coal Preparation Plants X X X X X X X X Z Ferroalloy Production Facilities X X X X X X X X

AA Steel Plants: Electric Arc Furnaces Constructed after October 21, 1974 and on or before August 17, 1983

X X X X X X X X

AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed after August 7, 1983

X X X X X X X X

BB Kraft Pulp Mills11 X CC Glass Manufacturing Plants X X X X X X X X


DD Grain Elevators X X X X X X X X EE Surface Coating of Metal Furniture X X X X X X X X

GG Stationary Gas Turbines X X X X X X X X HH Lime Manufacturing Plants X X X X X X X X

KK Lead-Acid Battery Manufacturing Plants X X X X X X X X

LL Metallic Mineral Processing Plants X X X X X X X X

MM Automobile and Light Duty Truck Surface Coating Operations

X X X X X X X X

NN Phosphate Rock Plants X X X X X X X X PP Ammonium Sulfate Manufacture X X X X X X X X

QQ Graphic Arts Industry: Publication Rotogravure Printing

X X X X X X X X

RR Pressure Sensitive Tape and Label Surface Coating Standards

X X X X X X X X

SS Industrial Surface Coating: Large Appliances X X X X X X X X

TT Metal Coil Surface Coating X X X X X X X X

UU Asphalt Processing and Asphalt Roof Manufacture X X X X X X X X

VV Equipment Leaks of VOC in Synthetic Organic Chemical Manufacturing Industry

X X X X X X X X

WW Beverage Can Surface Coating Industry X X X X X X X X

XX Bulk Gasoline Terminals X X X X X X X X AAA New Residential Wood Heaters

BBB Rubber Tire Manufacturing Industry X X X X X X X X

DDD VOC Emissions from Polymer Manufacturing X X X X X X X X


Industry FFF Flexible Vinyl and Urethane Coating and Printing X X X X X X X X

GGG Equipment Leaks of VOC in Petroleum Refineries X X X X X X X X

HHH Synthetic Fiber Production Facilities X X X X X X X X

III VOC Emissions from Synthetic Organic Chemical Manufacturing Industry Air Oxidation Unit Processes

X X X X X X X X

JJJ Petroleum Dry Cleaners X X X X X X X X KKK Equipment Leaks of VOC from Onshore Natural Gas Processing Plants

X X X X X X X X

LLL Onshore Natural Gas Processing: SO2 Emissions X X X X X X X X

NNN VOC Emissions from Synthetic Organic Chemical Manufacturing Industry Distillation Operations

X X X X X X X X

OOO Nonmetallic Mineral Processing Plants X X X PPP Wool Fiberglass Insulation Manufacturing Plants

X X X X X X X X

QQQ VOC Emissions from Petroleum Refinery Wastewater Systems

X X X X X X X X

RRR VOCs from Synthetic Organic Chemical Manufacturing Industry Reactor Processes

X X X X X X X X

SSS Magnetic Tape Coating Facilities X X X X X X X X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

X X X X X X X X

UUU Calciners and Dryers in Mineral Industries X X X X X X X X

VVV Polymeric Coating of X X X X X X X X


Supporting Substrates Facilities WWW Municipal Solid Waste Landfills X X X X X X X X

AAAA Small Municipal Waste Combustion Units for which Construction is Commenced after August 30, 1999 or for which Modification or Reconstruction is Commenced after June 6, 2001

X X X X X X

BBBB Small Municipal Waste Combustion Units Constructed on or before August 30, 1999 (Emission Guidelines and Compliance Times)

CCCC Commercial and Industrial Solid Waste Incineration Units for which Construction is Commenced after November, 30, 1999 or for which Modification or Reconstruction is Commenced on or after June 1, 2001

X X X X X X

DDDD Commercial and Industrial Solid Waste Incineration Units that Commenced Construction on or before November 30, 1999 (Emission Guidelines and Compliance Times)

1Any authority within any subpart of this part that is not delegable, is not delegated. Please refer to Attachment B to the delegation letters for a listing of the NSPS authorities excluded from delegation.

2Washington State Department of Ecology, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

3Benton Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.


4Northwest Air Pollution Authority, for all NSPS delegated, as in effect on July 1, 2000.

5Olympic Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

6Puget Sound Clean Air Authority, for all NSPS delegated, as in effect on July 1, 2002.

7Spokane County Air Pollution Control Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

8Southwest Clean Air Agency, for all NSPS delegated, as in effect on July 1, 2000.

9Yakima Regional Clean Air Authority, for 40 CFR 60.17(h)(1), (h)(2), (h)(3) and 40 CFR part 60, subpart AAAA, as in effect on June 6, 2001; for 40 CFR part 60, subpart CCCC, as in effect on June 1, 2001; and for all other NSPS delegated, as in effect February 20, 2001.

10Subpart S of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority to regulate Primary Aluminum Plants, pursuant to Washington Administrative Code 173-415-010.

11Subpart BB of this part is not delegated to local agencies in Washington because the Washington State Department of Ecology retains sole authority to regulate Kraft and Sulfite Pulping Mills, pursuant to Washington State Administrative Code 173-405-012 and 173-410-012.

(50) State of West Virginia, Department of Environmental Protection, Division of Air Quality, 601 57th Street, SE., Charleston, West Virginia 25304.

(51) State of Wisconsin: Wisconsin Department of Natural Resouces, 101 South Webster St., P.O. Box 7921, Madison, Wisconsin 53707-7921.

(52) State of Wyoming, Department of Environmental Quality, Air Quality Division, Herschler Building, 122 West 25th Street, Cheyenne, WY 82002.


(53) Territory of Guam: Guam Environmental Protection Agency, P.O. Box 22439 GMF, Barrigada, Guam 96921.


(54) Commonwealth of Puerto Rico: Commonwealth of Puerto Rico Environmental Quality Board, P.O. Box 11488, Santurce, PR 00910, Attention: Air Quality Area Director (see table under §60.4(b)(FF)(1)).


(55) U.S. Virgin Islands: U.S. Virgin Islands Department of Conservation and Cultural Affairs, P.O. Box 578, Charlotte Amalie, St. Thomas, VI 00801.

(56) American Samoa: American Samoa Environmental Protection Agency, P.O. Box PPA, Pago Pago, American Samoa 96799.


(57) Commonwealth of the Northern Mariana Islands: CNMI Division of Environmental Quality, P.O. Box 501304, Saipan, MP 96950.


(c) The delegation status table for New Source Performance Standards for Region VIII can be found online athttp://www2.epa.gov/region8/air-program.

(d) The following tables list the specific part 60 standards that have been delegated unchanged to the air pollution control agencies in Region IX. The (X) symbol is used to indicate each standard that has been delegated. The following provisions of this subpart are not delegated: §§60.4(b), 60.8(b), 60.9, 60.11(b), 60.11(e), 60.13(a), 60.13(d)(2), 60.13(g), 60.13(i).

(1) Arizona. The following table identifies delegations for Arizona:

Delegation Status for New Source Performance Standards for Arizona

Subpart Air pollution control agency

Arizona DEQ

Maricopa County

Pima County

Pinal County

A General Provisions X X X X

D Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971 X X X X

Da Electric Utility Steam Generating Units Constructed After September 18, 1978 X X X X

Db Industrial-Commercial-Institutional Steam Generating Units X X X X

Dc Small Industrial-Commercial-Institutional Steam Generating Units X X X X

E Incinerators X X X X

Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994 X X X X

Eb Large Municipal Waste Combustors Constructed After September 20, 1994 X X X

Ec Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996 X X X


F Portland Cement Plants X X X X G Nitric Acid Plants X X X X

Ga Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011 X X

H Sulfuric Acid Plant X X X X I Hot Mix Asphalt Facilities X X X X J Petroleum Refineries X X X X

Ja Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 X X

K Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

X X X X

Ka Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

X X X X

Kb

Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

X X X X

L Secondary Lead Smelters X X X X M Secondary Brass and Bronze Production Plants X X X X

N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973 X X X X

Na Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

X X X X

O Sewage Treatment Plants X X X X P Primary Copper Smelters X X X X Q Primary Zinc Smelters X X X X R Primary Lead Smelters X X X X S Primary Aluminum Reduction Plants X X X X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X X X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X X X V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X X X X W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities X X X X

Y Coal Preparation and Processing Plants X X X X


Z Ferroalloy Production Facilities X X X X

AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983 X X X X

AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983 X X X X

BB Kraft Pulp Mills X X X X

BBa Kraft Pulp Mill Sources for which Construction, Reconstruction or Modification Commenced after May 23, 2013 X X

CC Glass Manufacturing Plants X X X X DD Grain Elevators X X X X EE Surface Coating of Metal Furniture X X X X FF (Reserved)

Ga Nitric Acid Plants for which Construction, Reconstruction or Modification Commenced after October 14, 2011 X

GG Stationary Gas Turbines X X X X HH Lime Manufacturing Plants X X X X KK Lead-Acid Battery Manufacturing Plants X X X X LL Metallic Mineral Processing Plants X X X X MM Automobile and Light Duty Trucks Surface Coating Operations X X X X NN Phosphate Rock Plants X X X X PP Ammonium Sulfate Manufacture X X X X QQ Graphic Arts Industry: Publication Rotogravure Printing X X X X RR Pressure Sensitive Tape and Label Surface Coating Operations X X X X SS Industrial Surface Coating: Large Appliances X X X X TT Metal Coil Surface Coating X X X X UU Asphalt Processing and Asphalt Roofing Manufacture X X X X

VV Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing X X X X

VVa

Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

X X X

WW Beverage Can Surface Coating Industry X X X X XX Bulk Gasoline Terminals X X X X AAA New Residential Wood Heaters X X X X BBB Rubber Tire Manufacturing Industry X X X X CCC (Reserved) DDD Volatile Organic Compounds (VOC) Emissions from the X X X X


Polymer Manufacturing Industry EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X X X GGG Equipment Leaks of VOC in Petroleum Refineries X X X X

GGGa Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

X X X

HHH Synthetic Fiber Production Facilities X X X X

III Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

X X X X

JJJ Petroleum Dry Cleaners X X X X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X X X X

LLL Onshore Natural Gas Processing: SO2 Emissions X X X X MMM (Reserved)

NNN Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

X X X X

OOO Nonmetallic Mineral Processing Plants X X X X PPP Wool Fiberglass Insulation Manufacturing Plants X X X X QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X X X X

RRR Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes X X

SSS Magnetic Tape Coating Facilities X X X X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X X X X

UUU Calciners and Dryers in Mineral Industries X X X VVV Polymeric Coating of Supporting Substrates Facilities X X X X WWW Municipal Solid Waste Landfills X X X

AAAA

Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001

X X X

CCCC

Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

X X X

EEEE Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which X X X


Modification or Reconstruction is Commenced on or After June 16, 2006

GGGG (Reserved) HHHH (Reserved) IIII Stationary Compression Ignition Internal Combustion Engines X X X JJJJ Stationary Spark Ignition Internal Combustion Engines X X KKKK Stationary Combustion Turbines X X X LLLL New Sewage Sludge Incineration Units X MMMM Emissions Guidelines and Compliance Times for Existing

Sewage Sludge Incineration Units X

OOOO Crude Oil and Natural Gas Production, Transmission, and Distribution X X

QQQQ Standards of Performance for New Residential Hydronic Heaters and Forced-Air Furnaces X X

TTTT Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units X

(2) California. The following tables identify delegations for each of the local air pollution control agencies of California.

(i) Delegations for Amador County Air Pollution Control District, Antelope Valley Air Quality Management District, Bay Area Air Quality Management District, and Butte County Air Quality Management District are shown in the following table:

Delegation Status for New Source Performance Standards for Amador County APCD, Antelope Valley AQMD, Bay Area AQMD, and Butte County AQMD

Subpart

Air pollution control agency Amador County APCD

Antelope Valley AQMD

Bay Area

AQMD

Butte County AQMD

A General Provisions X

D Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971 X X

Da Electric Utility Steam Generating Units Constructed After September 18, 1978 X X

Db Industrial-Commercial-Institutional Steam Generating Units X X Dc Small Industrial-Commercial-Institutional Steam

Generating Units X X E Incinerators X X Ea Municipal Waste Combustors Constructed After December X X


20, 1989 and On or Before September 20, 1994

Eb Large Municipal Waste Combustors Constructed After September 20, 1994 X

Ec Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996 X

F Portland Cement Plants X X G Nitric Acid Plants X X Ga Nitric Acid Plants For Which Construction, Reconstruction

or Modification Commenced After October 14, 2011

H Sulfuric Acid Plant X X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X

Ja Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 X

K Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978 X X

Ka Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984 X X

Kb


X X

L Secondary Lead Smelters X X M Secondary Brass and Bronze Production Plants X X N Primary Emissions from Basic Oxygen Process Furnaces

for Which Construction is Commenced After June 11, 1973 X X

Na Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983 X X

O Sewage Treatment Plants X X P Primary Copper Smelters X X Q Primary Zinc Smelters X X R Primary Lead Smelters X X S Primary Aluminum Reduction Plants X X T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid

Plants X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X


V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X X

W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X Phosphate Fertilizer Industry: Granular Triple

Superphosphate Storage Facilities X X Y Coal Preparation and Processing Plants X X Z Ferroalloy Production Facilities X X AA Steel Plants: Electric Arc Furnaces Constructed After

October 21, 1974 and On or Before August 17, 1983 X X

AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983 X X

BB Kraft Pulp Mills X X CC Glass Manufacturing Plants X X DD Grain Elevators X X EE Surface Coating of Metal Furniture X X FF (Reserved) GG Stationary Gas Turbines X X HH Lime Manufacturing Plants X X KK Lead-Acid Battery Manufacturing Plants X X LL Metallic Mineral Processing Plants X X MM Automobile and Light Duty Trucks Surface Coating

Operations X X NN Phosphate Rock Plants X X PP Ammonium Sulfate Manufacture X X QQ Graphic Arts Industry: Publication Rotogravure Printing X X RR Pressure Sensitive Tape and Label Surface Coating

Operations X X SS Industrial Surface Coating: Large Appliances X X TT Metal Coil Surface Coating X X UU Asphalt Processing and Asphalt Roofing Manufacture X X VV Equipment Leaks of VOC in the Synthetic Organic Industry

Chemicals Manufacturing X X

VVa


X

WW Beverage Can Surface Coating Industry X X XX Bulk Gasoline Terminals AAA New Residential Wood Heaters X X


BBB Rubber Tire Manufacturing Industry X X CCC (Reserved)

DDD Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry X X

EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X GGG Equipment Leaks of VOC in Petroleum Refineries X X

GGGa Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006 X

HHH Synthetic Fiber Production Facilities X X

III Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes X

JJJ Petroleum Dry Cleaners X X KKK Equipment Leaks of VOC From Onshore Natural Gas

Processing Plants X X LLL Onshore Natural Gas Processing: SO2 Emissions X MMM (Reserved)

NNN Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations X X

OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X X QQQ VOC Emissions From Petroleum Refinery Wastewater

Systems X

RRR Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes X

SSS Magnetic Tape Coating Facilities X X TTT Industrial Surface Coating: Surface Coating of Plastic Parts

for Business Machines X X UUU Calciners and Dryers in Mineral Industries X X VVV Polymeric Coating of Supporting Substrates Facilities X X WWW Municipal Solid Waste Landfills X

AAAA


X

CCCC Commercial and Industrial Solid Waste Incineration Units X


for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

EEEE

Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

X

GGGG (Reserved) HHHH (Reserved)

IIII Stationary Compression Ignition Internal Combustion Engines X

JJJJ Stationary Spark Ignition Internal Combustion Engines X KKKK Stationary Combustion Turbines X LLLL New Sewage Sludge Incineration Units

OOOO Crude Oil and Natural Gas Production, Transmission, and Distribution

(ii) [Reserved]

(iii) Delegations for Glenn County Air Pollution Control District, Great Basin Unified Air Pollution Control District, Imperial County Air Pollution Control District, and Kern County Air Pollution Control District are shown in the following table:

Delegation Status for New Source Performance Standards for Glenn County APCD, Great Basin Unified APCD, Imperial County APCD, and Kern County APCD

Subpart

Air pollution control agency

Glenn County APCD

Great Basin

Unified APCD

Imperial County APCD

Kern County APCD

A General Provisions X X



Db Industrial-Commercial-Institutional Steam Generating Units X X

Dc Small Industrial Steam Generating Units X X E Incinerators X X Ea Municipal Waste Combustors Constructed After X


December 20, 1989 and On or Before September 20, 1994

Eb Municipal Waste Combustors Constructed After September 20, 1994

Ec Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June 20, 1996

F Portland Cement Plants X X G Nitric Acid Plants X X H Sulfuric Acid Plants X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X

K

Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978

X X

Ka

Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

X X

Kb


X X

L Secondary Lead Smelters X X M Secondary Brass and Bronze Production Plants X X

N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973 X X


O Sewage Treatment Plants X X P Primary Copper Smelters X X Q Primary Zinc Smelters X X R Primary Lead Smelters X X S Primary Aluminum Reduction Plants X X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X




W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities X X

Y Coal Preparation Plants X X Z Ferroalloy Production Facilities X X

AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983 X X


BB Kraft pulp Mills X X CC Glass Manufacturing Plants X X DD Grain Elevators X X EE Surface Coating of Metal Furniture X X FF (Reserved) GG Stationary Gas Turbines X X HH Lime Manufacturing Plants X X KK Lead-Acid Battery Manufacturing Plants X X LL Metallic Mineral Processing Plants X X

MM Automobile and Light Duty Trucks Surface Coating Operations X X

NN Phosphate Rock Plants X X PP Ammonium Sulfate Manufacture X X QQ Graphic Arts Industry: Publication Rotogravure Printing X X

RR Pressure Sensitive Tape and Label Surface Coating Operations X X

SS Industrial Surface Coating: Large Appliances X X TT Metal Coil Surface Coating X X UU Asphalt Processing and Asphalt Roofing Manufacture X X

VV Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry X X

WW Beverage Can Surface Coating Industry X X XX Bulk Gasoline Terminals AAA New Residential Wool Heaters X X BBB Rubber Tire Manufacturing Industry X X


CCC (Reserved)


EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X GGG Equipment Leaks of VOC in Petroleum Refineries X X HHH Synthetic Fiber Production Facilities X X

III Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes X X

JJJ Petroleum Dry Cleaners X X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X X

LLL Onshore Natural Gas Processing: SO2 Emissions X MMM (Reserved)


OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X X

QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X X


SSS Magnetic Tape Coating Facilities X X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X X

UUU Calciners and Dryers in Mineral Industries X X VVV Polymeric Coating of Supporting Substrates Facilities X X WWW Municipal Solid Waste Landfills X

(iv) Delegations for Lake County Air Quality Management District, Lassen County Air Pollution Control District, Mariposa County Air Pollution Control District, and Mendocino County Air Pollution Control District are shown in the following table:

Delegation Status for New Source Performance Standards for Lake County Air Quality Management District, Lassen County Air Pollution Control District, Mariposa County Air Pollution Control District, and Mendocino County Air Pollution Control District


Subpart

Air pollution control agency Lake

County AQMD

Lassen County APCD

Mariposa County AQMD

Mendocino County AQMD




Db Industrial-Commercial-Institutional Steam Generating Units X

Dc Small Industrial Steam Generating Units X X E Incinerators X X

Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

X X

Eb Municipal Waste Combustors Constructed After September 20, 1994


F Portland Cement Plants X X G Nitric Acid Plants X X H Sulfuric Acid Plants X X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X

K


X X

Ka


X X

Kb


X X

L Secondary Lead Smelters X X M Secondary Brass and Bronze Production Plants X X N Primary Emissions from Basic Oxygen Process X X


Furnaces for Which Construction is Commenced After June 11, 1973


X X

O Sewage Treatment Plants X X P Primary Copper Smelters X X Q Primary Zinc Smelters X X R Primary Lead Smelters X X S Primary Aluminum Reduction Plants X X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X






AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983

X X

AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983

X X

BB Kraft Pulp Mills X X CC Glass Manufacturing Plants X X DD Grain Elevators X X EE Surface Coating of Metal Furniture X X FF (Reserved) GG Stationary Gas Turbines X X HH Lime Manufacturing Plants X X KK Lead-Acid Battery Manufacturing Plants X X LL Metallic Mineral Processing Plants X X



NN Phosphate Rock Plants X X PP Ammonium Sulfate Manufacture X X

QQ Graphic Arts Industry: Publication Rotogravure Printing X X

RR Pressure Sensitive Tape and Label Surface Coating Operations X X

SS Industrial Surface Coating: Large Appliances X X TT Metal Coil Surface Coating X X

UU Asphalt Processing and Asphalt Roofing Manufacture X X

VV Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry X X

WW Beverage Can Surface Coating Industry X X XX Bulk Gasoline Terminals AAA New Residential Wool Heaters X X BBB Rubber Tire Manufacturing Industry X X CCC (Reserved)


EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X GGG Equipment Leaks of VOC in Petroleum Refineries X X HHH Synthetic Fiber Production Facilities X X

III

Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

X X

JJJ Petroleum Dry Cleaners X X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X X

LLL Onshore Natural Gas Processing: SO2 Emissions X X MMM (Reserved)


X X

OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X X

QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X X


RRR Volatile Organic Compound Emissions from Synthetic Organic Chemical Manufacturing Industry (SOCMI) Reactor Processes

X

SSS Magnetic Tape Coating Facilities X X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines

UUU Calciners and Dryers in Mineral Industries X X

VVV Polymeric Coating of Supporting Substrates Facilities X X

WWW Municipal Solid Waste Landfills X

(v) Delegations for Modoc Air Pollution Control District, Mojave Desert Air Quality Management District, Monterey Bay Unified Air Pollution Control District and North Coast Unified Air Quality Management District are shown in the following table:

Delegation Status for New Source Performance Standards for Modoc County APCD, Mojave Desert AQMD, Monterey Bay Unified APCD, and North Coast Unified AQMD

Subpart


Modoc County APCD

Mojave Desert AQMD

Monterey Bay Unified

APCD

North Coast

Unified AQMD





Dc Small Industrial-Commercial-Institutional Steam Generating Units X X


Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994 X




F Portland Cement Plants X X X X G Nitric Acid Plants X X X X

Ga Nitric Acid Plants For Which Construction, Reconstruction or Modification Commenced After October 14, 2011

H Sulfuric Acid Plant X X X X I Hot Mix Asphalt Facilities X X X X J Petroleum Refineries X X X X


K


X X X X

Ka


X X X X

Kb


X X X X


N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973

X X X X


X X X X

O Sewage Treatment Plants X X X X P Primary Copper Smelters X X X X Q Primary Zinc Smelters X X X X R Primary Lead Smelters X X X X S Primary Aluminum Reduction Plants X X X X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X X X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X X X

V Phosphate Fertilizer Industry: Diammonium Phosphate X X X X


Plants

W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities X X X X

Y Coal Preparation and Processing Plants X X X X Z Ferroalloy Production Facilities X X X X

AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before August 17, 1983 X X X X


X X X X

BB Kraft Pulp Mills X X X X CC Glass Manufacturing Plants X X X X DD Grain Elevators X X X X EE Surface Coating of Metal Furniture X X X X FF (Reserved) GG Stationary Gas Turbines X X X X HH Lime Manufacturing Plants X X X X KK Lead-Acid Battery Manufacturing Plants X X X X LL Metallic Mineral Processing Plants X X X X

MM Automobile and Light Duty Trucks Surface Coating Operations X X X X

NN Phosphate Rock Plants X X X X PP Ammonium Sulfate Manufacture X X X X

QQ Graphic Arts Industry: Publication Rotogravure Printing X X X X

RR Pressure Sensitive Tape and Label Surface Coating Operations X X X X

SS Industrial Surface Coating: Large Appliances X X X X TT Metal Coil Surface Coating X X X X UU Asphalt Processing and Asphalt Roofing Manufacture X X X X

VV Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing X X X X

VVa


X

WW Beverage Can Surface Coating Industry X X X X


XX Bulk Gasoline Terminals AAA New Residential Wood Heaters X X X X BBB Rubber Tire Manufacturing Industry X X X X CCC (Reserved)

DDD Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry X X X

EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X X X GGG Equipment Leaks of VOC in Petroleum Refineries X X X X


HHH Synthetic Fiber Production Facilities X X X X


JJJ Petroleum Dry Cleaners X X X X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X X X X

LLL Onshore Natural Gas Processing: SO2 Emissions X X X X MMM (Reserved)


X X X

OOO Nonmetallic Mineral Processing Plants X X X X PPP Wool Fiberglass Insulation Manufacturing Plants X X X X

QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X X X X


SSS Magnetic Tape Coating Facilities X X X X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X X X X

UUU Calciners and Dryers in Mineral Industries X X VVV Polymeric Coating of Supporting Substrates Facilities X X X WWW Municipal Solid Waste Landfills X

AAAA Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or X


for Which Modification or Reconstruction is Commended After June 6, 2001

CCCC


X

EEEE


X





(vi) Delegations for Northern Sierra Air Quality Management District, Northern Sonoma County Air Pollution Control District, Placer County Air Pollution Control District, and Sacramento Metropolitan Air Quality Management District are shown in the following table:

Delegation Status for New Source Performance Standards for Northern Sierra Air Quality Management District, Northern Sonoma County Air Pollution Control District, Placer County Air Pollution Control District, and Sacramento Metropolitan Air Quality Management District

Subpart


Northern Sierra AQMD

Northern Sonoma County APCD

Placer County APCD

Sacramento Metropolitan

AQMD





Dc Small Industrial Steam Generating Units X


E Incinerators X X


Eb Municipal Waste Combustors Constructed After September 20, 1994 X


F Portland Cement Plants X X G Nitric Acid Plants X X H Sulfuric Acid Plants X X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X

K


X X

Ka


X X

Kb


X


N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973 X X

Na

Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983

X

O Sewage Treatment Plants X X P Primary Copper Smelters X X Q Primary Zinc Smelters X X R Primary Lead Smelters X X S Primary Aluminum Reduction Plants X X T Phosphate Fertilizer Industry: Wet Process X X


Phosphoric Acid Plants







AAa Steel Plants: Electric Arc Furnaces and Argon-Oxygen Decarburization Vessels Constructed After August 7, 1983 X

BB Kraft pulp Mills X X CC Glass Manufacturing Plants X X DD Grain Elevators X X EE Surface Coating of Metal Furniture X FF (Reserved) GG Stationary Gas Turbines X X HH Lime Manufacturing Plants X X KK Lead-Acid Battery Manufacturing Plants X LL Metallic Mineral Processing Plants X


NN Phosphate Rock Plants X PP Ammonium Sulfate Manufacture X X

QQ Graphic Arts Industry: Publication Rotogravure Printing X

RR Pressure Sensitive Tape and Label Surface Coating Operations X

SS Industrial Surface Coating: Large Appliances X TT Metal Coil Surface Coating X

UU Asphalt Processing and Asphalt Roofing Manufacture X

VV Equipment Leaks of VOC in the Synthetic X


Organic Chemicals Manufacturing Industry WW Beverage Can Surface Coating Industry X XX Bulk Gasoline Terminals AAA New Residential Wool Heaters X BBB Rubber Tire Manufacturing Industry X CCC (Reserved)

DDD Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry X

EEE (Reserved)

FFF Flexible Vinyl and Urethane Coating and Printing X

GGG Equipment Leaks of VOC in Petroleum Refineries X

HHH Synthetic Fiber Production Facilities X

III

Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes

X

JJJ Petroleum Dry Cleaners X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X

LLL Onshore Natural Gas Processing: SO2 Emissions X

MMM (Reserved)

NNN

Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations

X

OOO Nonmetallic Mineral Processing Plants X

PPP Wool Fiberglass Insulation Manufacturing Plants X

QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X


SSS Magnetic Tape Coating Facilities X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X

UUU Calciners and Dryers in Mineral Industries X


VVV Polymeric Coating of Supporting Substrates Facilities X

WWW Municipal Solid Waste Landfills X

(vii) Delegations for San Diego County Air Pollution Control District, San Joaquin Valley Unified Air Pollution Control District, San Luis Obispo County Air Pollution Control District, and Santa Barbara County Air Pollution Control District are shown in the following table:

Delegation Status for New Source Performance Standards for San Diego County APCD, San Joaquin Valley Unified APCD, San Luis Obispo County APCD, and Santa Barbara County APCD

Subpart


San Diego

County APCD

San Joaquin Valley Unified APCD

San Luis Obispo County APCD

Santa Barbara County APCD





Dc Small Industrial-Commercial-Institutional Steam Generating Units X X X X


Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994

X X X

Eb Large Municipal Waste Combustors Constructed After September 20, 1994 X X X


X X

F Portland Cement Plants X X X G Nitric Acid Plants X X X


H Sulfuric Acid Plant X X X


I Hot Mix Asphalt Facilities X X X X J Petroleum Refineries X X X X


K


X X X X

Ka


X X X X

Kb


X X X X



X X X


X X X

O Sewage Treatment Plants X X X X P Primary Copper Smelters X X X Q Primary Zinc Smelters X X X R Primary Lead Smelters X X X S Primary Aluminum Reduction Plants X X X T Phosphate Fertilizer Industry: Wet Process

Phosphoric Acid Plants X X X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X X

V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X X X

W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities X X X

Y Coal Preparation and Processing Plants X X X


Z Ferroalloy Production Facilities X X X AA Steel Plants: Electric Arc Furnaces Constructed After

October 21, 1974 and On or Before August 17, 1983 X X X


X X X

BB Kraft Pulp Mills X X X CC Glass Manufacturing Plants X X X X DD Grain Elevators X X X X EE Surface Coating of Metal Furniture X X X FF (Reserved) GG Stationary Gas Turbines X X X X HH Lime Manufacturing Plants X X X KK Lead-Acid Battery Manufacturing Plants X X X LL Metallic Mineral Processing Plants X X X MM Automobile and Light Duty Trucks Surface Coating

Operations X X X NN Phosphate Rock Plants X X X PP Ammonium Sulfate Manufacture X X X QQ Graphic Arts Industry: Publication Rotogravure

Printing X X X

RR Pressure Sensitive Tape and Label Surface Coating Operations X X X

SS Industrial Surface Coating: Large Appliances X X X TT Metal Coil Surface Coating X X X UU Asphalt Processing and Asphalt Roofing Manufacture X X X VV Equipment Leaks of VOC in the Synthetic Organic

Industry Chemicals Manufacturing X X X

VVa


X

WW Beverage Can Surface Coating Industry X X X XX Bulk Gasoline Terminals AAA New Residential Wood Heaters X X X X BBB Rubber Tire Manufacturing Industry X X X CCC (Reserved)



EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X X GGG Equipment Leaks of VOC in Petroleum Refineries X X X


HHH Synthetic Fiber Production Facilities X X X


X X

JJJ Petroleum Dry Cleaners X X X KKK Equipment Leaks of VOC From Onshore Natural Gas

Processing Plants X X X LLL Onshore Natural Gas Processing: SO2 Emissions X X X MMM (Reserved)


X X

OOO Nonmetallic Mineral Processing Plants X X X X PPP Wool Fiberglass Insulation Manufacturing Plants X X X QQQ VOC Emissions From Petroleum Refinery

Wastewater Systems X X X


X X X

SSS Magnetic Tape Coating Facilities X X X TTT Industrial Surface Coating: Surface Coating of Plastic

Parts for Business Machines X X X UUU Calciners and Dryers in Mineral Industries X X X X VVV Polymeric Coating of Supporting Substrates Facilities X X X X WWW Municipal Solid Waste Landfills X X X X

AAAA


X X

CCCC


X X


EEEE


X X



JJJJ Stationary Spark Ignition Internal Combustion Engines X

KKKK Stationary Combustion Turbines X X LLLL New Sewage Sludge Incineration Units


(viii) Delegations for Shasta County Air Quality Management District, Siskiyou County Air Pollution Control District, South Coast Air Quality Management District, and Tehama County Air Pollution Control District are shown in the following table:

Delegation Status for New Source Performance Standards for Shasta County AQMD, Siskiyou County APCD, South Coast AQMD, and Tehama County APCD

Subpart

Air pollution control agency Shasta County AQMD

Siskiyou County APCD

South Coast

AQMD

Tehama County APCD

A General Provisions X X X D Fossil-Fuel Fired Steam Generators Constructed After

August 17, 1971 X X

Da Electric Utility Steam Generating Units Constructed After September 18, 1978 X


Dc Small Industrial-Commercial-Institutional Steam Generating Units X

E Incinerators X X Ea Municipal Waste Combustors Constructed After

December 20, 1989 and On or Before September 20, 1994 X


Ec Hospital/Medical/Infectious Waste Incinerators for Which X


Construction is Commenced After June 20, 1996 F Portland Cement Plants X X G Nitric Acid Plants X X


H Sulfuric Acid Plant X X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X


K


X X

Ka


X

Kb


X



X X

Na Secondary Emissions from Basic Oxygen Process Steelmaking Facilities for Which Construction is Commenced After January 20, 1983 X

O Sewage Treatment Plants X X P Primary Copper Smelters X X Q Primary Zinc Smelters X X R Primary Lead Smelters X X S Primary Aluminum Reduction Plants X X T Phosphate Fertilizer Industry: Wet Process Phosphoric

Acid Plants X X






Y Coal Preparation and Processing Plants X X Z Ferroalloy Production Facilities X X AA Steel Plants: Electric Arc Furnaces Constructed After

October 21, 1974 and On or Before August 17, 1983 X X


BB Kraft Pulp Mills X X CC Glass Manufacturing Plants X DD Grain Elevators X X EE Surface Coating of Metal Furniture X FF (Reserved) GG Stationary Gas Turbines X HH Lime Manufacturing Plants X X KK Lead-Acid Battery Manufacturing Plants X LL Metallic Mineral Processing Plants X MM Automobile and Light Duty Trucks Surface Coating

Operations X NN Phosphate Rock Plants X PP Ammonium Sulfate Manufacture X QQ Graphic Arts Industry: Publication Rotogravure Printing X RR Pressure Sensitive Tape and Label Surface Coating

Operations X SS Industrial Surface Coating: Large Appliances X TT Metal Coil Surface Coating X UU Asphalt Processing and Asphalt Roofing Manufacture X VV Equipment Leaks of VOC in the Synthetic Organic

Industry Chemicals Manufacturing X

VVa


X

WW Beverage Can Surface Coating Industry X


XX Bulk Gasoline Terminals AAA New Residential Wood Heaters X X BBB Rubber Tire Manufacturing Industry X X CCC (Reserved)


EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X GGG Equipment Leaks of VOC in Petroleum Refineries X




JJJ Petroleum Dry Cleaners X KKK Equipment Leaks of VOC From Onshore Natural Gas

Processing Plants X LLL Onshore Natural Gas Processing: SO2 Emissions X MMM (Reserved)

NNN Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical Manufacturing Industry (SOCMI) Distillation Operations X

OOO Nonmetallic Mineral Processing Plants X PPP Wool Fiberglass Insulation Manufacturing Plants X QQQ VOC Emissions From Petroleum Refinery Wastewater

Systems X X


SSS Magnetic Tape Coating Facilities X X TTT Industrial Surface Coating: Surface Coating of Plastic

Parts for Business Machines X X UUU Calciners and Dryers in Mineral Industries X VVV Polymeric Coating of Supporting Substrates Facilities X WWW Municipal Solid Waste Landfills X AAAA Small Municipal Waste Combustion Units for Which

Construction is Commenced After August 30, 1999 or for X X X


Which Modification or Reconstruction is Commended After June 6, 2001

CCCC


X

EEEE


X





(ix) Delegations for Tuolumne County Air Pollution Control District, Ventura County Air Pollution Control District, and Yolo-Solano Air Quality Management District are shown in the following table:

Delegation Status for New Source Performance Standards for Tuolumne County Air Pollution Control District, Ventura County Air Pollution Control District, and Yolo-Solano Air Quality Management District

Subpart

Air Pollution Control Agency Tuolumne

County APCD

Ventura County APCD

Yolo-Solano AQMD

A General Provisions X X D Fossil-Fuel Fired Steam Generators Constructed After August

17, 1971 X X

Da Electric Utility Steam Generating Units Constructed After September 18, 1978 X

Db Industrial-Commercial-Institutional Steam Generating Units X X Dc Small Industrial Steam Generating Units X E Incinerators X


Eb Municipal Waste Combustors Constructed After September 20, X


1994


F Portland Cement Plants X G Nitric Acid Plants X H Sulfuric Acid Plants X I Hot Mix Asphalt Facilities X X J Petroleum Refineries X X Ja Petroleum Refineries for Which Construction, Reconstruction,

or Modification Commenced After May 14, 2007


X X

Ka Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984

X

Kb


X

L Secondary Lead Smelters X M Secondary Brass and Bronze Production Plants X

N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is Commenced After June 11, 1973 X


X

O Sewage Treatment Plants X P Primary Copper Smelters X Q Primary Zinc Smelters X R Primary Lead Smelters X S Primary Aluminum Reduction Plants X

T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X

U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X W Phosphate Fertilizer Industry: Triple Superphosphate Plants X

X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities X


Y Coal Preparation Plants X Z Ferroalloy Production Facilities X



BB Kraft pulp Mills X CC Glass Manufacturing Plants X DD Grain Elevators X EE Surface Coating of Metal Furniture X FF (Reserved) GG Stationary Gas Turbines X HH Lime Manufacturing Plants X KK Lead-Acid Battery Manufacturing Plants X LL Metallic Mineral Processing Plants X MM Automobile and Light Duty Trucks Surface Coating Operations X NN Phosphate Rock Plants X PP Ammonium Sulfate Manufacture X QQ Graphic Arts Industry: Publication Rotogravure Printing X RR Pressure Sensitive Tape and Label Surface Coating Operations X SS Industrial Surface Coating: Large Appliances X TT Metal Coil Surface Coating X UU Asphalt Processing and Asphalt Roofing Manufacture X

VV Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry X

VVa

Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006

WW Beverage Can Surface Coating Industry X XX Bulk Gasoline Terminals AAA New Residential Wood Heaters X BBB Rubber Tire Manufacturing Industry X CCC (Reserved)


EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X


GGG Equipment Leaks of VOC in Petroleum Refineries X




X

JJJ Petroleum Dry Cleaners X

KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X

LLL Onshore Natural Gas Processing: SO2 Emissions X MMM (Reserved)


X

OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X


SSS Magnetic Tape Coating Facilities X

TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X

UUU Calciners and Dryers in Mineral Industries X VVV Polymeric Coating of Supporting Substrates Facilities X WWW Municipal Solid Waste Landfills X X

AAAA

Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commenced After June 6, 2001

X

CCCC


X

EEEE


GGGG (Reserved)


IIII Stationary Compression Ignition Internal Combustion Engines JJJJ Stationary Spark Ignition Internal Combustion Engines KKKK Stationary Combustion Turbines

(3) Hawaii. The following table identifies delegations for Hawaii:

Delegation Status for New Source Performance Standards for Hawaii:

Delegation Status for New Source Performance Standards for Hawaii

Subpart Hawaii A General Provisions X D Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971 X Da Electric Utility Steam Generating Units Constructed After September 18, 1978 X Db Industrial-Commercial-Institutional Steam Generating Units X Dc Small Industrial Steam Generating Units X E Incinerators X


Eb Municipal Waste Combustors Constructed After September 20, 1994 X


F Portland Cement Plants X G Nitric Acid Plants H Sulfuric Acid Plants I Hot Mix Asphalt Facilities X J Petroleum Refineries X

Ja Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007

K Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978 X

Ka Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984 X

Kb Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984 X

L Secondary Lead Smelters M Secondary Brass and Bronze Production Plants N Primary Emissions from Basic Oxygen Process Furnaces for Which Construction is

Commenced After June 11, 1973



O Sewage Treatment Plants X P Primary Copper Smelters Q Primary Zinc Smelters R Primary Lead Smelters S Primary Aluminum Reduction Plants T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants U Phosphate Fertilizer Industry: Superphosphoric Acid Plants V Phosphate Fertilizer Industry: Diammonium Phosphate Plants W Phosphate Fertilizer Industry: Triple Superphosphate Plants X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities Y Coal Preparation Plants X Z Ferroalloy Production Facilities AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and On or Before

August 17, 1983 X


BB Kraft pulp Mills CC Glass Manufacturing Plants DD Grain Elevators EE Surface Coating of Metal Furniture FF (Reserved) GG Stationary Gas Turbines X HH Lime Manufacturing Plants KK Lead-Acid Battery Manufacturing Plants LL Metallic Mineral Processing Plants MM Automobile and Light Duty Trucks Surface Coating Operations NN Phosphate Rock Plants PP Ammonium Sulfate Manufacture QQ Graphic Arts Industry: Publication Rotogravure Printing RR Pressure Sensitive Tape and Label Surface Coating Operations SS Industrial Surface Coating: Large Appliances TT Metal Coil Surface Coating UU Asphalt Processing and Asphalt Roofing Manufacture VV Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry X VVa Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for


Which Construction, Reconstruction, or Modification Commenced After November 7, 2006 WW Beverage Can Surface Coating Industry X XX Bulk Gasoline Terminals X AAA New Residential Wool Heaters BBB Rubber Tire Manufacturing Industry CCC (Reserved) DDD Volatile Organic Compounds (VOC) Emissions from the Polymer Manufacturing Industry EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing GGG Equipment Leaks of VOC in Petroleum Refineries X


HHH Synthetic Fiber Production Facilities III Volatile Organic Compound (VOC) Emissions From the Synthetic Organic Chemical

Manufacturing Industry (SOCMI) Air Oxidation Unit Processes JJJ Petroleum Dry Cleaners X KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants LLL Onshore Natural Gas Processing: SO2 Emissions MMM (Reserved) NNN Volatile Organic Compound (VOC) Emissions From Synthetic Organic Chemical

Manufacturing Industry (SOCMI) Distillation Operations X

OOO Nonmetallic Mineral Processing Plants X PPP Wool Fiberglass Insulation Manufacturing Plants QQQ VOC Emissions From Petroleum Refinery Wastewater X


SSS Magnetic Tape Coating Facilities TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines UUU Calciners and Dryers in Mineral Industries X VVV Polymeric Coating of Supporting Substrates Facilities X WWW Municipal Solid Waste Landfills X

AAAA Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commenced After June 6, 2001

X

CCCC Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

X

EEEE Other Solid Waste Incineration Units for Which Construction is Commenced After December


9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006 GGGG (Reserved) IIII Stationary Compression Ignition Internal Combustion Engines JJJJ Stationary Spark Ignition Internal Combustion Engines KKKK Stationary Combustion Turbines

(4) Nevada. The following table identifies delegations for Nevada:

Delegation Status for New Source Performance Standards for Nevada

Subpart


Nevada DEP

Clark County

Washoe County

A General Provisions X X X D Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971 X X X


Db Industrial-Commercial-Institutional Steam Generating Units X X Dc Small Industrial-Commercial-Institutional Steam Generating Units X X E Incinerators X X X

Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September 20, 1994 X X

Eb Large Municipal Waste Combustors Constructed After September 20, 1994 X X Ec Hospital/Medical/Infectious Waste Incinerators for Which Construction is

Commenced After June 20, 1996 X X F Portland Cement Plants X X X G Nitric Acid Plants X X Ga Nitric Acid Plants For Which Construction, Reconstruction or Modification

Commenced After October 14, 2011 X

H Sulfuric Acid Plant X X I Hot Mix Asphalt Facilities X X X J Petroleum Refineries X X Ja Petroleum Refineries for Which Construction, Reconstruction, or

Modification Commenced After May 14, 2007 X


X X X

Ka Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior X X X


to July 23, 1984

Kb Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984

X X

L Secondary Lead Smelters X X X M Secondary Brass and Bronze Production Plants X X N Primary Emissions from Basic Oxygen Process Furnaces for Which

Construction is Commenced After June 11, 1973 X X


O Sewage Treatment Plants X X X P Primary Copper Smelters X X X Q Primary Zinc Smelters X X X R Primary Lead Smelters X X X S Primary Aluminum Reduction Plants X X T Phosphate Fertilizer Industry: Wet Process Phosphoric Acid Plants X X U Phosphate Fertilizer Industry: Superphosphoric Acid Plants X X V Phosphate Fertilizer Industry: Diammonium Phosphate Plants X X W Phosphate Fertilizer Industry: Triple Superphosphate Plants X X X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage

Facilities X X Y Coal Preparation and Processing Plants X X X Z Ferroalloy Production Facilities X X AA Steel Plants: Electric Arc Furnaces Constructed After October 21, 1974 and

On or Before August 17, 1983 X X


BB Kraft Pulp Mills X X CC Glass Manufacturing Plants X X DD Grain Elevators X X X EE Surface Coating of Metal Furniture X X X FF (Reserved) GG Stationary Gas Turbines X X X HH Lime Manufacturing Plants X X X KK Lead-Acid Battery Manufacturing Plants X X X LL Metallic Mineral Processing Plants X X X MM Automobile and Light Duty Trucks Surface Coating Operations X X X NN Phosphate Rock Plants X X X


PP Ammonium Sulfate Manufacture X X QQ Graphic Arts Industry: Publication Rotogravure Printing X X X RR Pressure Sensitive Tape and Label Surface Coating Operations X X SS Industrial Surface Coating: Large Appliances X X X TT Metal Coil Surface Coating X X X UU Asphalt Processing and Asphalt Roofing Manufacture X X X

VV Equipment Leaks of VOC in the Synthetic Organic Industry Chemicals Manufacturing X X X

VVa Equipment Leaks of VOC in the Synthetic Organic Industry for Which Construction, Reconstruction, or Chemicals Manufacturing Modification Commenced After November 7, 2006

X X

WW Beverage Can Surface Coating Industry X X XX Bulk Gasoline Terminals X X AAA New Residential Wood Heaters X BBB Rubber Tire Manufacturing Industry X X CCC (Reserved)


EEE (Reserved) FFF Flexible Vinyl and Urethane Coating and Printing X X GGG Equipment Leaks of VOC in Petroleum Refineries X X GGGa Equipment Leaks of VOC in Petroleum Refineries for Which Construction,

Reconstruction, or Modification Commenced After November 7, 2006 X X HHH Synthetic Fiber Production Facilities X X III Volatile Organic Compound (VOC) Emissions From the Synthetic Organic

Chemical Manufacturing Industry (SOCMI) Air Oxidation Unit Processes X X JJJ Petroleum Dry Cleaners X X X KKK Equipment Leaks of VOC From Onshore Natural Gas Processing Plants X X LLL Onshore Natural Gas Processing: SO2 Emissions X X MMM (Reserved)


OOO Nonmetallic Mineral Processing Plants X X PPP Wool Fiberglass Insulation Manufacturing Plants X X QQQ VOC Emissions From Petroleum Refinery Wastewater Systems X X RRR Volatile Organic Compound Emissions from Synthetic Organic Chemical

Manufacturing Industry (SOCMI) Reactor Processes X X SSS Magnetic Tape Coating Facilities X X


TTT Industrial Surface Coating: Surface Coating of Plastic Parts for Business Machines X X X

UUU Calciners and Dryers in Mineral Industries X X X VVV Polymeric Coating of Supporting Substrates Facilities X X X WWW Municipal Solid Waste Landfills X X X

AAAA Small Municipal Waste Combustion Units for Which Construction is Commenced After August 30, 1999 or for Which Modification or Reconstruction is Commended After June 6, 2001

X X X

CCCC Commercial and Industrial Solid Waste Incineration Units for Which Construction Is Commenced After November 30, 1999 or for Which Modification or Reconstruction Is Commenced on or After June 1, 2001

X X X

EEEE Other Solid Waste Incineration Units for Which Construction is Commenced After December 9, 2004, or for Which Modification or Reconstruction is Commenced on or After June 16, 2006

X X X

GGGG (Reserved) HHHH (Reserved) IIII Stationary Compression Ignition Internal Combustion Engines X X X JJJJ Stationary Spark Ignition Internal Combustion Engines X X X KKKK Stationary Combustion Turbines X X X LLLL New Sewage Sludge Incineration Units X OOOO Crude Oil and Natural Gas Production, Transmission, and Distribution X

(5) Guam. The following table identifies delegations as of June 15, 2001:

Delegation Status for New Source Performance Standards for Guam

Subpart Guam A General Provisions X D Fossil-Fuel Fired Steam Generators Constructed After August 17, 1971 X Da Electric Utility Steam Generating Units Constructed After September 18, 1978 Db Industrial-Commercial-Institutional Steam Generating Units Dc Small Industrial Steam Generating Units E Incinerators Ea Municipal Waste Combustors Constructed After December 20, 1989 and On or Before September

20, 1994 Eb Municipal Waste Combustors Constructed After September 20, 1994 Ec Hospital/Medical/Infectious Waste Incinerators for Which Construction is Commenced After June

20, 1996 F Portland Cement Plants X


G Nitric Acid Plants H Sulfuric Acid Plants I Hot Mix Asphalt Facilities X J Petroleum Refineries X

K Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978 X

(e) The following lists the specific part 60 standards that have been delegated unchanged to the air pollution control agencies in Region 6.

(1) New Mexico. The New Mexico Environment Department has been delegated all part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters; and subpart HHHH—Emission Guidelines and Compliance Times for Coal-Fired Electric Steam Generating Units, as amended in the FEDERAL REGISTER through September 23, 2013.

(2) Louisiana. The Louisiana Department of Environmental Quality has been delegated all part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters, as amended in the FEDERAL REGISTER through July 1, 2013.

Delegation Status for Part 60 Standards—State of Louisiana

[Excluding Indian Country]

Subpart Source category LDEQ1 A General Provisions Yes

Ce Emission Guidelines and Compliance Times for Hospital/Medical/Infectious Waste Incinerators Yes

D Fossil Fueled Steam Generators (>250 MM BTU/hr) Yes Da Electric Utility Steam Generating Units (>250 MM BTU/hr) Yes Db Industrial-Commercial-Institutional Steam Generating Units (100 to 250 MM BTU/hr) Yes Dc Industrial-Commercial-Institutional Small Steam Generating Units (10 to 100 MM BTU/hr) Yes E Incinerators (>50 tons per day) Yes Ea Municipal Waste Combustors Yes Eb Large Municipal Waste Combustors Yes Ec Hospital/Medical/Infectious Waste Incinerators Yes F Portland Cement Plants Yes G Nitric Acid Plants Yes Ga Nitric Acid Plants (after October 14, 2011) Yes H Sulfuric Acid Plants Yes I Hot Mix Asphalt Facilities Yes


J Petroleum Refineries Yes Ja Petroleum Refineries (After May 14, 2007) Yes K Storage Vessels for Petroleum Liquids (After 6/11/73 & Before 5/19/78) Yes Ka Storage Vessels for Petroleum Liquids (After 6/11/73 & Before 5/19/78) Yes

Kb Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Stg/Vessels) After 7/23/84 Yes

L Secondary Lead Smelters Yes Yes M Secondary Brass and Bronze Production Plants Yes

N Primary Emissions from Basic Oxygen Process Furnaces (Construction Commenced After June 11, 1973) Yes

Na Secondary Emissions from Basic Oxygen Process Steelmaking Facilities Construction is Commenced After January 20, 1983 Yes

O Sewage Treatment Plants Yes P Primary Copper Smelters Yes Q Primary Zinc Smelters Yes R Primary Lead Smelters Yes S Primary Aluminum Reduction Plants Yes T Phosphate Fertilizer Industry: Wet Process Phosphoric Plants Yes U Phosphate Fertilizer Industry: Superphosphoric Acid Plants Yes V Phosphate Fertilizer Industry: Diammonium Phosphate Plants Yes W Phosphate Fertilizer Industry: Triple Superphosphate Plants Yes X Phosphate Fertilizer Industry: Granular Triple Superphosphate Storage Facilities Yes Y Coal Preparation Plants Yes Z Ferroalloy Production Facilities Yes AA Steel Plants: Electric Arc Furnaces After 10/21/74 & On or Before 8/17/83 Yes AAa Steel Plants: Electric Arc Furnaces & Argon-Oxygen Decarburization Vessels After 8/07/83 Yes BB Kraft Pulp Mills Yes CC Glass Manufacturing Plants Yes DD Grain Elevators Yes EE Surface Coating of Metal Furniture Yes GG Stationary Gas Turbines Yes HH Lime Manufacturing Plants Yes KK Lead-Acid Battery Manufacturing Plants Yes LL Metallic Mineral Processing Plants Yes MM Automobile & Light Duty Truck Surface Coating Operations Yes NN Phosphate Manufacturing Plants Yes PP Ammonium Sulfate Manufacture Yes


QQ Graphic Arts Industry: Publication Rotogravure Printing Yes RR Pressure Sensitive Tape and Label Surface Coating Operations Yes SS Industrial Surface Coating: Large Appliances Yes TT Metal Coil Surface Coating Yes UU Asphalt Processing and Asphalt Roofing Manufacture Yes VV VOC Equipment Leaks in the SOCMI Industry Yes VVa VOC Equipment Leaks in the SOCMI Industry (After November 7, 2006) Yes XX Bulk Gasoline Terminals Yes AAA New Residential Wood Heaters No BBB Rubber Tire Manufacturing Industry Yes DDD Volatile Organic Compound (VOC) Emissions from the Polymer Manufacturing Industry Yes FFF Flexible Vinyl and Urethane Coating and Printing Yes GGG VOC Equipment Leaks in Petroleum Refineries Yes HHH Synthetic Fiber Production Yes III VOC Emissions from the SOCMI Air Oxidation Unit Processes Yes JJJ Petroleum Dry Cleaners Yes KKK VOC Equipment Leaks From Onshore Natural Gas Processing Plants Yes LLL Onshore Natural Gas Processing: SO2 Emissions Yes NNN VOC Emissions from SOCMI Distillation Operations Yes OOO Nonmetallic Mineral Processing Plants Yes PPP Wool Fiberglass Insulation Manufacturing Plants Yes QQQ VOC Emissions From Petroleum Refinery Wastewater Systems Yes RRR VOC Emissions from SOCMI Reactor Processes Yes SSS Magnetic Tape Coating Operations Yes TTT Industrial Surface Coating: Plastic Parts for Business Machines Yes UUU Calciners and Dryers in Mineral Industries Yes VVV Polymeric Coating of Supporting Substrates Facilities Yes WWW Municipal Solid Waste Landfills Yes

AAAA Small Municipal Waste Combustion Units (Construction is Commenced After 8/30/99 or Modification/Reconstruction is Commenced After 6/06/2001) Yes

CCCC Commercial & Industrial Solid Waste Incineration Units (Construction is Commenced After 11/30/1999 or Modification/Reconstruction is Commenced on or After 6/01/2001) Yes

DDDD Emission Guidelines & Compliance Times for Commercial & Industrial Solid Waste Incineration Units (Commenced Construction On or Before 11/30/1999) Yes

EEEE Other Solid Waste Incineration Units (Constructed after 12/09/2004 or Modification/Reconstruction is commenced on or after 06/16/2004) Yes

IIII Stationary Compression Ignition Internal Combustion Engines Yes


JJJJ Stationary Spark Ignition Internal Combustion Engines Yes KKKK Stationary Combustion Turbines (Construction Commenced After 02/18/2005) Yes LLLL New Sewage Sludge Incineration Units Yes MMMM Emission Guidelines and Compliance Times for Existing Sewage Sludge Incineration Units Yes OOOO Crude Oil and Natural Gas Production, Transmission and Distribution Yes

1The Louisiana Department of Environmental Quality (LDEQ) has been delegated all Part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters—as amended in the FEDERAL REGISTER through July 1, 2013.

(3) Albuquerque-Bernalillo County Air Quality Control Board. The Albuquerque-Bernalillo County Air Quality Control Board has been delegated all part 60 standards promulgated by EPA, except subpart AAA—Standards of Performance for New Residential Wood Heaters, as amended in the FEDERAL REGISTER through September 13, 2013.

[40 FR 18169, Apr. 25, 1975]

EDITORIAL NOTE: For FEDERAL REGISTER citations affecting §60.4, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.fdsys.gov.

§60.5 Determination of construction or modification. (a) When requested to do so by an owner or operator, the Administrator will make a determination of whether action taken or intended to be taken by such owner or operator constitutes construction (including reconstruction) or modification or the commencement thereof within the meaning of this part.

(b) The Administrator will respond to any request for a determination under paragraph (a) of this section within 30 days of receipt of such request.

[40 FR 58418, Dec. 16, 1975]

§60.6 Review of plans. (a) When requested to do so by an owner or operator, the Administrator will review plans for construction or modification for the purpose of providing technical advice to the owner or operator.

(b)(1) A separate request shall be submitted for each construction or modification project.

(2) Each request shall identify the location of such project, and be accompanied by technical information describing the proposed nature, size, design, and method of operation of each affected facility involved in such project, including information on any equipment to be used for measurement or control of emissions.

(c) Neither a request for plans review nor advice furnished by the Administrator in response to such request shall (1) relieve an owner or operator of legal responsibility for compliance with any provision of this part or of


any applicable State or local requirement, or (2) prevent the Administrator from implementing or enforcing any provision of this part or taking any other action authorized by the Act.

[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974]

§60.7 Notification and record keeping. (a) Any owner or operator subject to the provisions of this part shall furnish the Administrator written notification or, if acceptable to both the Administrator and the owner or operator of a source, electronic notification, as follows:

(1) A notification of the date construction (or reconstruction as defined under §60.15) of an affected facility is commenced postmarked no later than 30 days after such date. This requirement shall not apply in the case of mass-produced facilities which are purchased in completed form.

(2) [Reserved]

(3) A notification of the actual date of initial startup of an affected facility postmarked within 15 days after such date.

(4) A notification of any physical or operational change to an existing facility which may increase the emission rate of any air pollutant to which a standard applies, unless that change is specifically exempted under an applicable subpart or in §60.14(e). This notice shall be postmarked 60 days or as soon as practicable before the change is commenced and shall include information describing the precise nature of the change, present and proposed emission control systems, productive capacity of the facility before and after the change, and the expected completion date of the change. The Administrator may request additional relevant information subsequent to this notice.

(5) A notification of the date upon which demonstration of the continuous monitoring system performance commences in accordance with §60.13(c). Notification shall be postmarked not less than 30 days prior to such date.

(6) A notification of the anticipated date for conducting the opacity observations required by §60.11(e)(1) of this part. The notification shall also include, if appropriate, a request for the Administrator to provide a visible emissions reader during a performance test. The notification shall be postmarked not less than 30 days prior to such date.

(7) A notification that continuous opacity monitoring system data results will be used to determine compliance with the applicable opacity standard during a performance test required by §60.8 in lieu of Method 9 observation data as allowed by §60.11(e)(5) of this part. This notification shall be postmarked not less than 30 days prior to the date of the performance test.

(b) Any owner or operator subject to the provisions of this part shall maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of an affected facility; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative.


(c) Each owner or operator required to install a continuous monitoring device shall submit excess emissions and monitoring systems performance report (excess emissions are defined in applicable subparts) and-or summary report form (see paragraph (d) of this section) to the Administrator semiannually, except when: more frequent reporting is specifically required by an applicable subpart; or the Administrator, on a case-by-case basis, determines that more frequent reporting is necessary to accurately assess the compliance status of the source. All reports shall be postmarked by the 30th day following the end of each six-month period. Written reports of excess emissions shall include the following information:

(1) The magnitude of excess emissions computed in accordance with §60.13(h), any conversion factor(s) used, and the date and time of commencement and completion of each time period of excess emissions. The process operating time during the reporting period.

(2) Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected facility. The nature and cause of any malfunction (if known), the corrective action taken or preventative measures adopted.

(3) The date and time identifying each period during which the continuous monitoring system was inoperative except for zero and span checks and the nature of the system repairs or adjustments.

(4) When no excess emissions have occurred or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.

(d) The summary report form shall contain the information and be in the format shown in figure 1 unless otherwise specified by the Administrator. One summary report form shall be submitted for each pollutant monitored at each affected facility.

(1) If the total duration of excess emissions for the reporting period is less than 1 percent of the total operating time for the reporting period and CMS downtime for the reporting period is less than 5 percent of the total operating time for the reporting period, only the summary report form shall be submitted and the excess emission report described in §60.7(c) need not be submitted unless requested by the Administrator.

(2) If the total duration of excess emissions for the reporting period is 1 percent or greater of the total operating time for the reporting period or the total CMS downtime for the reporting period is 5 percent or greater of the total operating time for the reporting period, the summary report form and the excess emission report described in §60.7(c) shall both be submitted.


Figure 1—Summary Report—Gaseous and Opacity Excess Emission and Monitoring System Performance Pollutant (Circle One—SO2/NOX/TRS/H2S/CO/Opacity)

Reporting period dates: From _____ to _____

Company:

Emission Limitation

Address:

Monitor Manufacturer and Model No. Date of Latest CMS Certification or Audit

Process Unit(s) Description:

Total source operating time in reporting period1 Emission data summary1 CMS performance summary1

1. Duration of excess emissions in reporting period due to: 1. CMS downtime in reporting period due to:

a. Startup/shutdown a. Monitor equipment malfunctions b. Control equipment problems b. Non-Monitor equipment malfunctions c. Process problems c. Quality assurance calibration d. Other known causes d. Other known causes e. Unknown causes e. Unknown causes

2. Total duration of excess emission 2. Total CMS Downtime 3. Total duration of excess emissions × (100) [Total source operating time] %2 3. [Total CMS Downtime] × (100) [Total

source operating time] %2

1For opacity, record all times in minutes. For gases, record all times in hours.

2For the reporting period: If the total duration of excess emissions is 1 percent or greater of the total operating time or the total CMS downtime is 5 percent or greater of the total operating time, both the summary report form and the excess emission report described in §60.7(c) shall be submitted.

On a separate page, describe any changes since last quarter in CMS, process or controls. I certify that the information contained in this report is true, accurate, and complete.


Name

Signature

Title

Date

(e)(1) Notwithstanding the frequency of reporting requirements specified in paragraph (c) of this section, an owner or operator who is required by an applicable subpart to submit excess emissions and monitoring systems performance reports (and summary reports) on a quarterly (or more frequent) basis may reduce the frequency of reporting for that standard to semiannual if the following conditions are met:

(i) For 1 full year (e.g., 4 quarterly or 12 monthly reporting periods) the affected facility's excess emissions and monitoring systems reports submitted to comply with a standard under this part continually demonstrate that the facility is in compliance with the applicable standard;

(ii) The owner or operator continues to comply with all recordkeeping and monitoring requirements specified in this subpart and the applicable standard; and

(iii) The Administrator does not object to a reduced frequency of reporting for the affected facility, as provided in paragraph (e)(2) of this section.

(2) The frequency of reporting of excess emissions and monitoring systems performance (and summary) reports may be reduced only after the owner or operator notifies the Administrator in writing of his or her intention to make such a change and the Administrator does not object to the intended change. In deciding whether to approve a reduced frequency of reporting, the Administrator may review information concerning the source's entire previous performance history during the required recordkeeping period prior to the intended change, including performance test results, monitoring data, and evaluations of an owner or operator's conformance with operation and maintenance requirements. Such information may be used by the Administrator to make a judgment about the source's potential for noncompliance in the future. If the Administrator disapproves the owner or operator's request to reduce the frequency of reporting, the Administrator will notify the owner or operator in writing within 45 days after receiving notice of the owner or operator's intention. The notification from the Administrator to the owner or operator will specify the grounds on which the disapproval is based. In the absence of a notice of disapproval within 45 days, approval is automatically granted.

(3) As soon as monitoring data indicate that the affected facility is not in compliance with any emission limitation or operating parameter specified in the applicable standard, the frequency of reporting shall revert to


the frequency specified in the applicable standard, and the owner or operator shall submit an excess emissions and monitoring systems performance report (and summary report, if required) at the next appropriate reporting period following the noncomplying event. After demonstrating compliance with the applicable standard for another full year, the owner or operator may again request approval from the Administrator to reduce the frequency of reporting for that standard as provided for in paragraphs (e)(1) and (e)(2) of this section.

(f) Any owner or operator subject to the provisions of this part shall maintain a file of all measurements, including continuous monitoring system, monitoring device, and performance testing measurements; all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device calibration checks; adjustments and maintenance performed on these systems or devices; and all other information required by this part recorded in a permanent form suitable for inspection. The file shall be retained for at least two years following the date of such measurements, maintenance, reports, and records, except as follows:

(1) This paragraph applies to owners or operators required to install a continuous emissions monitoring system (CEMS) where the CEMS installed is automated, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. An automated CEMS records and reduces the measured data to the form of the pollutant emission standard through the use of a computerized data acquisition system. In lieu of maintaining a file of all CEMS subhourly measurements as required under paragraph (f) of this section, the owner or operator shall retain the most recent consecutive three averaging periods of subhourly measurements and a file that contains a hard copy of the data acquisition system algorithm used to reduce the measured data into the reportable form of the standard.

(2) This paragraph applies to owners or operators required to install a CEMS where the measured data is manually reduced to obtain the reportable form of the standard, and where the calculated data averages do not exclude periods of CEMS breakdown or malfunction. In lieu of maintaining a file of all CEMS subhourly measurements as required under paragraph (f) of this section, the owner or operator shall retain all subhourly measurements for the most recent reporting period. The subhourly measurements shall be retained for 120 days from the date of the most recent summary or excess emission report submitted to the Administrator.

(3) The Administrator or delegated authority, upon notification to the source, may require the owner or operator to maintain all measurements as required by paragraph (f) of this section, if the Administrator or the delegated authority determines these records are required to more accurately assess the compliance status of the affected source.

(g) If notification substantially similar to that in paragraph (a) of this section is required by any other State or local agency, sending the Administrator a copy of that notification will satisfy the requirements of paragraph (a) of this section.

(h) Individual subparts of this part may include specific provisions which clarify or make inapplicable the provisions set forth in this section.

[36 FR 24877, Dec. 28, 1971, as amended at 40 FR 46254, Oct. 6, 1975; 40 FR 58418, Dec. 16, 1975; 45 FR 5617, Jan. 23, 1980; 48 FR 48335, Oct. 18, 1983; 50 FR 53113, Dec. 27, 1985; 52 FR 9781, Mar. 26, 1987; 55 FR 51382, Dec. 13, 1990; 59 FR 12428, Mar. 16, 1994; 59 FR 47265, Sep. 15, 1994; 64 FR 7463, Feb. 12, 1999]


§60.8 Performance tests. (a) Except as specified in paragraphs (a)(1),(a)(2), (a)(3), and (a)(4) of this section, within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of such facility, or at such other times specified by this part, and at such other times as may be required by the Administrator under section 114 of the Act, the owner or operator of such facility shall conduct performance test(s) and furnish the Administrator a written report of the results of such performance test(s).

(1) If a force majeure is about to occur, occurs, or has occurred for which the affected owner or operator intends to assert a claim of force majeure, the owner or operator shall notify the Administrator, in writing as soon as practicable following the date the owner or operator first knew, or through due diligence should have known that the event may cause or caused a delay in testing beyond the regulatory deadline, but the notification must occur before the performance test deadline unless the initial force majeure or a subsequent force majeure event delays the notice, and in such cases, the notification shall occur as soon as practicable.

(2) The owner or operator shall provide to the Administrator a written description of the force majeure event and a rationale for attributing the delay in testing beyond the regulatory deadline to the force majeure; describe the measures taken or to be taken to minimize the delay; and identify a date by which the owner or operator proposes to conduct the performance test. The performance test shall be conducted as soon as practicable after the force majeure occurs.

(3) The decision as to whether or not to grant an extension to the performance test deadline is solely within the discretion of the Administrator. The Administrator will notify the owner or operator in writing of approval or disapproval of the request for an extension as soon as practicable.

(4) Until an extension of the performance test deadline has been approved by the Administrator under paragraphs (a)(1), (2), and (3) of this section, the owner or operator of the affected facility remains strictly subject to the requirements of this part.

(b) Performance tests shall be conducted and data reduced in accordance with the test methods and procedures contained in each applicable subpart unless the Administrator (1) specifies or approves, in specific cases, the use of a reference method with minor changes in methodology, (2) approves the use of an equivalent method, (3) approves the use of an alternative method the results of which he has determined to be adequate for indicating whether a specific source is in compliance, (4) waives the requirement for performance tests because the owner or operator of a source has demonstrated by other means to the Administrator's satisfaction that the affected facility is in compliance with the standard, or (5) approves shorter sampling times and smaller sample volumes when necessitated by process variables or other factors. Nothing in this paragraph shall be construed to abrogate the Administrator's authority to require testing under section 114 of the Act.

(c) Performance tests shall be conducted under such conditions as the Administrator shall specify to the plant operator based on representative performance of the affected facility. The owner or operator shall make available to the Administrator such records as may be necessary to determine the conditions of the performance tests. Operations during periods of startup, shutdown, and malfunction shall not constitute representative conditions for the purpose of a performance test nor shall emissions in excess of the level of the applicable


emission limit during periods of startup, shutdown, and malfunction be considered a violation of the applicable emission limit unless otherwise specified in the applicable standard.

(d) The owner or operator of an affected facility shall provide the Administrator at least 30 days prior notice of any performance test, except as specified under other subparts, to afford the Administrator the opportunity to have an observer present. If after 30 days notice for an initially scheduled performance test, there is a delay (due to operational problems, etc.) in conducting the scheduled performance test, the owner or operator of an affected facility shall notify the Administrator (or delegated State or local agency) as soon as possible of any delay in the original test date, either by providing at least 7 days prior notice of the rescheduled date of the performance test, or by arranging a rescheduled date with the Administrator (or delegated State or local agency) by mutual agreement.

(e) The owner or operator of an affected facility shall provide, or cause to be provided, performance testing facilities as follows:

(1) Sampling ports adequate for test methods applicable to such facility. This includes (i) constructing the air pollution control system such that volumetric flow rates and pollutant emission rates can be accurately determined by applicable test methods and procedures and (ii) providing a stack or duct free of cyclonic flow during performance tests, as demonstrated by applicable test methods and procedures.

(2) Safe sampling platform(s).

(3) Safe access to sampling platform(s).

(4) Utilities for sampling and testing equipment.

(f) Unless otherwise specified in the applicable subpart, each performance test shall consist of three separate runs using the applicable test method.

(1) Each run shall be conducted for the time and under the conditions specified in the applicable standard. For the purpose of determining compliance with an applicable standard, the arithmetic means of results of the three runs shall apply. In the event that a sample is accidentally lost or conditions occur in which one of the three runs must be discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other circumstances, beyond the owner or operator's control, compliance may, upon the Administrator's approval, be determined using the arithmetic mean of the results of the two other runs.

(2) Contents of report (electronic or paper submitted copy). Unless otherwise specified in a relevant standard or test method, or as otherwise approved by the Administrator in writing, the report for a performance test shall include the elements identified in paragraphs (f)(2)(i) through (vi) of this section.

(i) General identification information for the facility including a mailing address, the physical address, the owner or operator or responsible official (where applicable) and his/her email address, and the appropriate Federal Registry System (FRS) number for the facility.


(ii) Purpose of the test including the applicable regulation(s) requiring the test, the pollutant(s) and other parameters being measured, the applicable emission standard and any process parameter component, and a brief process description.

(iii) Description of the emission unit tested including fuel burned, control devices, and vent characteristics; the appropriate source classification code (SCC); the permitted maximum process rate (where applicable); and the sampling location.

(iv) Description of sampling and analysis procedures used and any modifications to standard procedures, quality assurance procedures and results, record of process operating conditions that demonstrate the applicable test conditions are met, and values for any operating parameters for which limits were being set during the test.

(v) Where a test method requires you record or report, the following shall be included: Record of preparation of standards, record of calibrations, raw data sheets for field sampling, raw data sheets for field and laboratory analyses, chain-of-custody documentation, and example calculations for reported results.

(vi) Identification of the company conducting the performance test including the primary office address, telephone number, and the contact for this test program including his/her email address.

(g) The performance testing shall include a test method performance audit (PA) during the performance test. The PAs consist of blind audit samples supplied by an accredited audit sample provider and analyzed during the performance test in order to provide a measure of test data bias. Gaseous audit samples are designed to audit the performance of the sampling system as well as the analytical system and must be collected by the sampling system during the compliance test just as the compliance samples are collected. If a liquid or solid audit sample is designed to audit the sampling system, it must also be collected by the sampling system during the compliance test. If multiple sampling systems or sampling trains are used during the compliance test for any of the test methods, the tester is only required to use one of the sampling systems per method to collect the audit sample. The audit sample must be analyzed by the same analyst using the same analytical reagents and analytical system and at the same time as the compliance samples. Retests are required when there is a failure to produce acceptable results for an audit sample. However, if the audit results do not affect the compliance or noncompliance status of the affected facility, the compliance authority may waive the reanalysis requirement, further audits, or retests and accept the results of the compliance test. Acceptance of the test results shall constitute a waiver of the reanalysis requirement, further audits, or retests. The compliance authority may also use the audit sample failure and the compliance test results as evidence to determine the compliance or noncompliance status of the affected facility. A blind audit sample is a sample whose value is known only to the sample provider and is not revealed to the tested facility until after they report the measured value of the audit sample. For pollutants that exist in the gas phase at ambient temperature, the audit sample shall consist of an appropriate concentration of the pollutant in air or nitrogen that can be introduced into the sampling system of the test method at or near the same entry point as a sample from the emission source. If no gas phase audit samples are available, an acceptable alternative is a sample of the pollutant in the same matrix that would be produced when the sample is recovered from the sampling system as required by the test method. For samples that exist only in a liquid or solid form at ambient temperature, the audit sample shall consist of an appropriate concentration of the pollutant in the same matrix that would be produced when the sample is recovered from the sampling system as required by the test method. An accredited audit sample provider (AASP) is an organization that has been accredited to prepare audit samples by an independent, third party accrediting body.


(1) The source owner, operator, or representative of the tested facility shall obtain an audit sample, if commercially available, from an AASP for each test method used for regulatory compliance purposes. No audit samples are required for the following test methods: Methods 3A and 3C of appendix A-3 of part 60, Methods 6C, 7E, 9, and 10 of appendix A-4 of part 60, Methods 18 and 19 of appendix A-6 of part 60, Methods 20, 22, and 25A of appendix A-7 of part 60, Methods 30A and 30B of appendix A-8 of part 60, and Methods 303, 318, 320, and 321 of appendix A of part 63 of this chapter. If multiple sources at a single facility are tested during a compliance test event, only one audit sample is required for each method used during a compliance test. The compliance authority responsible for the compliance test may waive the requirement to include an audit sample if they believe that an audit sample is not necessary. “Commercially available” means that two or more independent AASPs have blind audit samples available for purchase. If the source owner, operator, or representative cannot find an audit sample for a specific method, the owner, operator, or representative shall consult the EPA Web site at the following URL, www.epa.gov/ttn/emc, to confirm whether there is a source that can supply an audit sample for that method. If the EPA Web site does not list an available audit sample at least 60 days prior to the beginning of the compliance test, the source owner, operator, or representative shall not be required to include an audit sample as part of the quality assurance program for the compliance test. When ordering an audit sample, the source owner, operator, or representative shall give the sample provider an estimate for the concentration of each pollutant that is emitted by the source or the estimated concentration of each pollutant based on the permitted level and the name, address, and phone number of the compliance authority. The source owner, operator, or representative shall report the results for the audit sample along with a summary of the emission test results for the audited pollutant to the compliance authority and shall report the results of the audit sample to the AASP. The source owner, operator, or representative shall make both reports at the same time and in the same manner or shall report to the compliance authority first and then report to the AASP. If the method being audited is a method that allows the samples to be analyzed in the field and the tester plans to analyze the samples in the field, the tester may analyze the audit samples prior to collecting the emission samples provided a representative of the compliance authority is present at the testing site. The tester may request and the compliance authority may grant a waiver to the requirement that a representative of the compliance authority must be present at the testing site during the field analysis of an audit sample. The source owner, operator, or representative may report the results of the audit sample to the compliance authority and report the results of the audit sample to the AASP prior to collecting any emission samples. The test protocol and final test report shall document whether an audit sample was ordered and utilized and the pass/fail results as applicable.

(2) An AASP shall have and shall prepare, analyze, and report the true value of audit samples in accordance with a written technical criteria document that describes how audit samples will be prepared and distributed in a manner that will ensure the integrity of the audit sample program. An acceptable technical criteria document shall contain standard operating procedures for all of the following operations:

(i) Preparing the sample;

(ii) Confirming the true concentration of the sample;

(iii) Defining the acceptance limits for the results from a well qualified tester. This procedure must use well established statistical methods to analyze historical results from well qualified testers. The acceptance limits shall be set so that there is 95 percent confidence that 90 percent of well qualified labs will produce future results that are within the acceptance limit range.


(iv) Providing the opportunity for the compliance authority to comment on the selected concentration level for an audit sample;

(v) Distributing the sample to the user in a manner that guarantees that the true value of the sample is unknown to the user;

(vi) Recording the measured concentration reported by the user and determining if the measured value is within acceptable limits;

(vii) The AASP shall report the results from each audit sample in a timely manner to the compliance authority and then to the source owner, operator, or representative. The AASP shall make both reports at the same time and in the same manner or shall report to the compliance authority first and then report to the source owner, operator, or representative. The results shall include the name of the facility tested, the date on which the compliance test was conducted, the name of the company performing the sample collection, the name of the company that analyzed the compliance samples including the audit sample, the measured result for the audit sample, and whether the testing company passed or failed the audit. The AASP shall report the true value of the audit sample to the compliance authority. The AASP may report the true value to the source owner, operator, or representative if the AASP's operating plan ensures that no laboratory will receive the same audit sample twice.

(viii) Evaluating the acceptance limits of samples at least once every two years to determine in cooperation with the voluntary consensus standard body if they should be changed;

(ix) Maintaining a database, accessible to the compliance authorities, of results from the audit that shall include the name of the facility tested, the date on which the compliance test was conducted, the name of the company performing the sample collection, the name of the company that analyzed the compliance samples including the audit sample, the measured result for the audit sample, the true value of the audit sample, the acceptance range for the measured value, and whether the testing company passed or failed the audit.

(3) The accrediting body shall have a written technical criteria document that describes how it will ensure that the AASP is operating in accordance with the AASP technical criteria document that describes how audit samples are to be prepared and distributed. This document shall contain standard operating procedures for all of the following operations:

(i) Checking audit samples to confirm their true value as reported by the AASP;

(ii) Performing technical systems audits of the AASP's facilities and operating procedures at least once every two years;

(iii) Providing standards for use by the voluntary consensus standard body to approve the accrediting body that will accredit the audit sample providers.

(4) The technical criteria documents for the accredited sample providers and the accrediting body shall be developed through a public process guided by a voluntary consensus standards body (VCSB). The VCSB shall operate in accordance with the procedures and requirements in the Office of Management and Budget Circular A-119. A copy of Circular A-119 is available upon request by writing the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW., Washington, DC 20503, by calling (202)


395-6880 or downloading online at http://standards.gov/standards_gov/a119.cfm. The VCSB shall approve all accrediting bodies. The Administrator will review all technical criteria documents. If the technical criteria documents do not meet the minimum technical requirements in paragraphs (g)(2) through (4)of this section, the technical criteria documents are not acceptable and the proposed audit sample program is not capable of producing audit samples of sufficient quality to be used in a compliance test. All acceptable technical criteria documents shall be posted on the EPA Web site at the following URL, http://www.epa.gov/ttn/emc.

(h) Unless otherwise specified in the applicable subpart, each test location must be verified to be free of cyclonic flow and evaluated for the existence of emission gas stratification and the required number of sampling traverse points. If other procedures are not specified in the applicable subpart to the regulations, use the appropriate procedures in Method 1 to check for cyclonic flow and Method 7E to evaluate emission gas stratification and selection of sampling points.

(i) Whenever the use of multiple calibration gases is required by a test method, performance specification, or quality assurance procedure in a part 60 standard or appendix, Method 205 of 40 CFR part 51, appendix M of this chapter, “Verification of Gas Dilution Systems for Field Instrument Calibrations,” may be used.

[36 FR 24877, Dec. 23, 1971, as amended at 39 FR 9314, Mar. 8, 1974; 42 FR 57126, Nov. 1, 1977; 44 FR 33612, June 11, 1979; 54 FR 6662, Feb. 14, 1989; 54 FR 21344, May 17, 1989; 64 FR 7463, Feb. 12, 1999; 72 FR 27442, May 16, 2007; 75 FR 55646, Sept. 13, 2010; 79 FR 11241, Feb. 27, 2014; 81 FR 59809, Aug. 30, 2016]

§60.9 Availability of information. The availability to the public of information provided to, or otherwise obtained by, the Administrator under this part shall be governed by part 2 of this chapter. (Information submitted voluntarily to the Administrator for the purposes of §§60.5 and 60.6 is governed by §§2.201 through 2.213 of this chapter and not by §2.301 of this chapter.)

§60.10 State authority. The provisions of this part shall not be construed in any manner to preclude any State or political subdivision thereof from:

(a) Adopting and enforcing any emission standard or limitation applicable to an affected facility, provided that such emission standard or limitation is not less stringent than the standard applicable to such facility.

(b) Requiring the owner or operator of an affected facility to obtain permits, licenses, or approvals prior to initiating construction, modification, or operation of such facility.

§60.11 Compliance with standards and maintenance requirements. (a) Compliance with standards in this part, other than opacity standards, shall be determined in accordance with performance tests established by §60.8, unless otherwise specified in the applicable standard.


(b) Compliance with opacity standards in this part shall be determined by conducting observations in accordance with Method 9 in appendix A of this part, any alternative method that is approved by the Administrator, or as provided in paragraph (e)(5) of this section. For purposes of determining initial compliance, the minimum total time of observations shall be 3 hours (30 6-minute averages) for the performance test or other set of observations (meaning those fugitive-type emission sources subject only to an opacity standard).

(c) The opacity standards set forth in this part shall apply at all times except during periods of startup, shutdown, malfunction, and as otherwise provided in the applicable standard.

(d) At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.

(e)(1) For the purpose of demonstrating initial compliance, opacity observations shall be conducted concurrently with the initial performance test required in §60.8 unless one of the following conditions apply. If no performance test under §60.8 is required, then opacity observations shall be conducted within 60 days after achieving the maximum production rate at which the affected facility will be operated but no later than 180 days after initial startup of the facility. If visibility or other conditions prevent the opacity observations from being conducted concurrently with the initial performance test required under §60.8, the source owner or operator shall reschedule the opacity observations as soon after the initial performance test as possible, but not later than 30 days thereafter, and shall advise the Administrator of the rescheduled date. In these cases, the 30-day prior notification to the Administrator required in §60.7(a)(6) shall be waived. The rescheduled opacity observations shall be conducted (to the extent possible) under the same operating conditions that existed during the initial performance test conducted under §60.8. The visible emissions observer shall determine whether visibility or other conditions prevent the opacity observations from being made concurrently with the initial performance test in accordance with procedures contained in Method 9 of appendix B of this part. Opacity readings of portions of plumes which contain condensed, uncombined water vapor shall not be used for purposes of determing compliance with opacity standards. The owner or operator of an affected facility shall make available, upon request by the Administrator, such records as may be necessary to determine the conditions under which the visual observations were made and shall provide evidence indicating proof of current visible observer emission certification. Except as provided in paragraph (e)(5) of this section, the results of continuous monitoring by transmissometer which indicate that the opacity at the time visual observations were made was not in excess of the standard are probative but not conclusive evidence of the actual opacity of an emission, provided that the source shall meet the burden of proving that the instrument used meets (at the time of the alleged violation) Performance Specification 1 in appendix B of this part, has been properly maintained and (at the time of the alleged violation) that the resulting data have not been altered in any way.

(2) Except as provided in paragraph (e)(3) of this section, the owner or operator of an affected facility to which an opacity standard in this part applies shall conduct opacity observations in accordance with paragraph (b) of this section, shall record the opacity of emissions, and shall report to the Administrator the opacity results along with the results of the initial performance test required under §60.8. The inability of an owner or operator to


secure a visible emissions observer shall not be considered a reason for not conducting the opacity observations concurrent with the initial performance test.

(3) The owner or operator of an affected facility to which an opacity standard in this part applies may request the Administrator to determine and to record the opacity of emissions from the affected facility during the initial performance test and at such times as may be required. The owner or operator of the affected facility shall report the opacity results. Any request to the Administrator to determine and to record the opacity of emissions from an affected facility shall be included in the notification required in §60.7(a)(6). If, for some reason, the Administrator cannot determine and record the opacity of emissions from the affected facility during the performance test, then the provisions of paragraph (e)(1) of this section shall apply.

(4) An owner or operator of an affected facility using a continuous opacity monitor (transmissometer) shall record the monitoring data produced during the initial performance test required by §60.8 and shall furnish the Administrator a written report of the monitoring results along with Method 9 and §60.8 performance test results.

(5) An owner or operator of an affected facility subject to an opacity standard may submit, for compliance purposes, continuous opacity monitoring system (COMS) data results produced during any performance test required under §60.8 in lieu of Method 9 observation data. If an owner or operator elects to submit COMS data for compliance with the opacity standard, he shall notify the Administrator of that decision, in writing, at least 30 days before any performance test required under §60.8 is conducted. Once the owner or operator of an affected facility has notified the Administrator to that effect, the COMS data results will be used to determine opacity compliance during subsequent tests required under §60.8 until the owner or operator notifies the Administrator, in writing, to the contrary. For the purpose of determining compliance with the opacity standard during a performance test required under §60.8 using COMS data, the minimum total time of COMS data collection shall be averages of all 6-minute continuous periods within the duration of the mass emission performance test. Results of the COMS opacity determinations shall be submitted along with the results of the performance test required under §60.8. The owner or operator of an affected facility using a COMS for compliance purposes is responsible for demonstrating that the COMS meets the requirements specified in §60.13(c) of this part, that the COMS has been properly maintained and operated, and that the resulting data have not been altered in any way. If COMS data results are submitted for compliance with the opacity standard for a period of time during which Method 9 data indicates noncompliance, the Method 9 data will be used to determine compliance with the opacity standard.

(6) Upon receipt from an owner or operator of the written reports of the results of the performance tests required by §60.8, the opacity observation results and observer certification required by §60.11(e)(1), and the COMS results, if applicable, the Administrator will make a finding concerning compliance with opacity and other applicable standards. If COMS data results are used to comply with an opacity standard, only those results are required to be submitted along with the performance test results required by §60.8. If the Administrator finds that an affected facility is in compliance with all applicable standards for which performance tests are conducted in accordance with §60.8 of this part but during the time such performance tests are being conducted fails to meet any applicable opacity standard, he shall notify the owner or operator and advise him that he may petition the Administrator within 10 days of receipt of notification to make appropriate adjustment to the opacity standard for the affected facility.

(7) The Administrator will grant such a petition upon a demonstration by the owner or operator that the affected facility and associated air pollution control equipment was operated and maintained in a manner to minimize the


opacity of emissions during the performance tests; that the performance tests were performed under the conditions established by the Administrator; and that the affected facility and associated air pollution control equipment were incapable of being adjusted or operated to meet the applicable opacity standard.

(8) The Administrator will establish an opacity standard for the affected facility meeting the above requirements at a level at which the source will be able, as indicated by the performance and opacity tests, to meet the opacity standard at all times during which the source is meeting the mass or concentration emission standard. The Administrator will promulgate the new opacity standard in the FEDERAL REGISTER.

(f) Special provisions set forth under an applicable subpart shall supersede any conflicting provisions in paragraphs (a) through (e) of this section.

(g) For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in violation of any standard in this part, nothing in this part shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed.

[38 FR 28565, Oct. 15, 1973, as amended at 39 FR 39873, Nov. 12, 1974; 43 FR 8800, Mar. 3, 1978; 45 FR 23379, Apr. 4, 1980; 48 FR 48335, Oct. 18, 1983; 50 FR 53113, Dec. 27, 1985; 51 FR 1790, Jan. 15, 1986; 52 FR 9781, Mar. 26, 1987; 62 FR 8328, Feb. 24, 1997; 65 FR 61749, Oct. 17, 2000]

§60.12 Circumvention. No owner or operator subject to the provisions of this part shall build, erect, install, or use any article, machine, equipment or process, the use of which conceals an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere.

[39 FR 9314, Mar. 8, 1974]

§60.13 Monitoring requirements. (a) For the purposes of this section, all continuous monitoring systems required under applicable subparts shall be subject to the provisions of this section upon promulgation of performance specifications for continuous monitoring systems under appendix B to this part and, if the continuous monitoring system is used to demonstrate compliance with emission limits on a continuous basis, appendix F to this part, unless otherwise specified in an applicable subpart or by the Administrator. Appendix F is applicable December 4, 1987.

(b) All continuous monitoring systems and monitoring devices shall be installed and operational prior to conducting performance tests under §60.8. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.


(c) If the owner or operator of an affected facility elects to submit continous opacity monitoring system (COMS) data for compliance with the opacity standard as provided under §60.11(e)(5), he shall conduct a performance evaluation of the COMS as specified in Performance Specification 1, appendix B, of this part before the performance test required under §60.8 is conducted. Otherwise, the owner or operator of an affected facility shall conduct a performance evaluation of the COMS or continuous emission monitoring system (CEMS) during any performance test required under §60.8 or within 30 days thereafter in accordance with the applicable performance specification in appendix B of this part, The owner or operator of an affected facility shall conduct COMS or CEMS performance evaluations at such other times as may be required by the Administrator under section 114 of the Act.

(1) The owner or operator of an affected facility using a COMS to determine opacity compliance during any performance test required under §60.8 and as described in §60.11(e)(5) shall furnish the Administrator two or, upon request, more copies of a written report of the results of the COMS performance evaluation described in paragraph (c) of this section at least 10 days before the performance test required under §60.8 is conducted.

(2) Except as provided in paragraph (c)(1) of this section, the owner or operator of an affected facility shall furnish the Administrator within 60 days of completion two or, upon request, more copies of a written report of the results of the performance evaluation.

(d)(1) Owners and operators of a CEMS installed in accordance with the provisions of this part, must check the zero (or low level value between 0 and 20 percent of span value) and span (50 to 100 percent of span value) calibration drifts at least once each operating day in accordance with a written procedure. The zero and span must, at a minimum, be adjusted whenever either the 24-hour zero drift or the 24-hour span drift exceeds two times the limit of the applicable performance specification in appendix B of this part. The system must allow the amount of the excess zero and span drift to be recorded and quantified whenever specified. Owners and operators of a COMS installed in accordance with the provisions of this part must check the zero and upscale (span) calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is defined in the applicable version of PS-1 in appendix B of this part. For a COMS, the optical surfaces, exposed to the effluent gases, must be cleaned before performing the zero and upscale drift adjustments, except for systems using automatic zero adjustments. The optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity.

(2) Unless otherwise approved by the Administrator, the following procedures must be followed for a COMS. Minimum procedures must include an automated method for producing a simulated zero opacity condition and an upscale opacity condition using a certified neutral density filter or other related technique to produce a known obstruction of the light beam. Such procedures must provide a system check of all active analyzer internal optics with power or curvature, all active electronic circuitry including the light source and photodetector assembly, and electronic or electro-mechanical systems and hardware and or software used during normal measurement operation.

(e) Except for system breakdowns, repairs, calibration checks, and zero and span adjustments required under paragraph (d) of this section, all continuous monitoring systems shall be in continuous operation and shall meet minimum frequency of operation requirements as follows:


(1) All continuous monitoring systems referenced by paragraph (c) of this section for measuring opacity of emissions shall complete a minimum of one cycle of sampling and analyzing for each successive 10-second period and one cycle of data recording for each successive 6-minute period.

(2) All continuous monitoring systems referenced by paragraph (c) of this section for measuring emissions, except opacity, shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period.

(f) All continuous monitoring systems or monitoring devices shall be installed such that representative measurements of emissions or process parameters from the affected facility are obtained. Additional procedures for location of continuous monitoring systems contained in the applicable Performance Specifications of appendix B of this part shall be used.

(g) When the effluents from a single affected facility or two or more affected facilities subject to the same emission standards are combined before being released to the atmosphere, the owner or operator may install applicable continuous monitoring systems on each effluent or on the combined effluent. When the affected facilities are not subject to the same emission standards, separate continuous monitoring systems shall be installed on each effluent. When the effluent from one affected facility is released to the atmosphere through more than one point, the owner or operator shall install an applicable continuous monitoring system on each separate effluent unless the installation of fewer systems is approved by the Administrator. When more than one continuous monitoring system is used to measure the emissions from one affected facility (e.g., multiple breechings, multiple outlets), the owner or operator shall report the results as required from each continuous monitoring system.

(h)(1) Owners or operators of all continuous monitoring systems for measurement of opacity shall reduce all data to 6-minute averages and for continuous monitoring systems other than opacity to 1-hour averages for time periods as defined in §60.2. Six-minute opacity averages shall be calculated from 36 or more data points equally spaced over each 6-minute period.

(2) For continuous monitoring systems other than opacity, 1-hour averages shall be computed as follows, except that the provisions pertaining to the validation of partial operating hours are only applicable for affected facilities that are required by the applicable subpart to include partial hours in the emission calculations:

(i) Except as provided under paragraph (h)(2)(iii) of this section, for a full operating hour (any clock hour with 60 minutes of unit operation), at least four valid data points are required to calculate the hourly average, i.e., one data point in each of the 15-minute quadrants of the hour.

(ii) Except as provided under paragraph (h)(2)(iii) of this section, for a partial operating hour (any clock hour with less than 60 minutes of unit operation), at least one valid data point in each 15-minute quadrant of the hour in which the unit operates is required to calculate the hourly average.

(iii) For any operating hour in which required maintenance or quality-assurance activities are performed:

(A) If the unit operates in two or more quadrants of the hour, a minimum of two valid data points, separated by at least 15 minutes, is required to calculate the hourly average; or


(B) If the unit operates in only one quadrant of the hour, at least one valid data point is required to calculate the hourly average.

(iv) If a daily calibration error check is failed during any operating hour, all data for that hour shall be invalidated, unless a subsequent calibration error test is passed in the same hour and the requirements of paragraph (h)(2)(iii) of this section are met, based solely on valid data recorded after the successful calibration.

(v) For each full or partial operating hour, all valid data points shall be used to calculate the hourly average.

(vi) Except as provided under paragraph (h)(2)(vii) of this section, data recorded during periods of continuous monitoring system breakdown, repair, calibration checks, and zero and span adjustments shall not be included in the data averages computed under this paragraph.

(vii) Owners and operators complying with the requirements of §60.7(f)(1) or (2) must include any data recorded during periods of monitor breakdown or malfunction in the data averages.

(viii) When specified in an applicable subpart, hourly averages for certain partial operating hours shall not be computed or included in the emission averages (e.g., hours with < 30 minutes of unit operation under §60.47b(d)).

(ix) Either arithmetic or integrated averaging of all data may be used to calculate the hourly averages. The data may be recorded in reduced or nonreduced form (e.g., ppm pollutant and percent O2 or ng/J of pollutant).

(3) All excess emissions shall be converted into units of the standard using the applicable conversion procedures specified in the applicable subpart. After conversion into units of the standard, the data may be rounded to the same number of significant digits used in the applicable subpart to specify the emission limit.

(i) After receipt and consideration of written application, the Administrator may approve alternatives to any monitoring procedures or requirements of this part including, but not limited to the following:

(1) Alternative monitoring requirements when installation of a continuous monitoring system or monitoring device specified by this part would not provide accurate measurements due to liquid water or other interferences caused by substances in the effluent gases.

(2) Alternative monitoring requirements when the affected facility is infrequently operated.

(3) Alternative monitoring requirements to accommodate continuous monitoring systems that require additional measurements to correct for stack moisture conditions.

(4) Alternative locations for installing continuous monitoring systems or monitoring devices when the owner or operator can demonstrate that installation at alternate locations will enable accurate and representative measurements.

(5) Alternative methods of converting pollutant concentration measurements to units of the standards.


(6) Alternative procedures for performing daily checks of zero and span drift that do not involve use of span gases or test cells.

(7) Alternatives to the A.S.T.M. test methods or sampling procedures specified by any subpart.

(8) Alternative continuous monitoring systems that do not meet the design or performance requirements in Performance Specification 1, appendix B, but adequately demonstrate a definite and consistent relationship between its measurements and the measurements of opacity by a system complying with the requirements in Performance Specification 1. The Administrator may require that such demonstration be performed for each affected facility.

(9) Alternative monitoring requirements when the effluent from a single affected facility or the combined effluent from two or more affected facilities is released to the atmosphere through more than one point.

(j) An alternative to the relative accuracy (RA) test specified in Performance Specification 2 of appendix B may be requested as follows:

(1) An alternative to the reference method tests for determining RA is available for sources with emission rates demonstrated to be less than 50 percent of the applicable standard. A source owner or operator may petition the Administrator to waive the RA test in Section 8.4 of Performance Specification 2 and substitute the procedures in Section 16.0 if the results of a performance test conducted according to the requirements in §60.8 of this subpart or other tests performed following the criteria in §60.8 demonstrate that the emission rate of the pollutant of interest in the units of the applicable standard is less than 50 percent of the applicable standard. For sources subject to standards expressed as control efficiency levels, a source owner or operator may petition the Administrator to waive the RA test and substitute the procedures in Section 16.0 of Performance Specification 2 if the control device exhaust emission rate is less than 50 percent of the level needed to meet the control efficiency requirement. The alternative procedures do not apply if the continuous emission monitoring system is used to determine compliance continuously with the applicable standard. The petition to waive the RA test shall include a detailed description of the procedures to be applied. Included shall be location and procedure for conducting the alternative, the concentration or response levels of the alternative RA materials, and the other equipment checks included in the alternative procedure. The Administrator will review the petition for completeness and applicability. The determination to grant a waiver will depend on the intended use of the CEMS data (e.g., data collection purposes other than NSPS) and may require specifications more stringent than in Performance Specification 2 (e.g., the applicable emission limit is more stringent than NSPS).

(2) The waiver of a CEMS RA test will be reviewed and may be rescinded at such time, following successful completion of the alternative RA procedure, that the CEMS data indicate that the source emissions are approaching the level. The criterion for reviewing the waiver is the collection of CEMS data showing that emissions have exceeded 70 percent of the applicable standard for seven, consecutive, averaging periods as specified by the applicable regulation(s). For sources subject to standards expressed as control efficiency levels, the criterion for reviewing the waiver is the collection of CEMS data showing that exhaust emissions have exceeded 70 percent of the level needed to meet the control efficiency requirement for seven, consecutive, averaging periods as specified by the applicable regulation(s) [e.g., §§60.45(g) (2) and (3), 60.73(e), and 60.84(e)]. It is the responsibility of the source operator to maintain records and determine the level of emissions relative to the criterion on the waiver of RA testing. If this criterion is exceeded, the owner or operator must notify the Administrator within 10 days of such occurrence and include a description of the nature and cause of


the increasing emissions. The Administrator will review the notification and may rescind the waiver and require the owner or operator to conduct a RA test of the CEMS as specified in Section 8.4 of Performance Specification 2.

[40 FR 46255, Oct. 6, 1975]

EDITORIAL NOTE: For FEDERAL REGISTER citations affecting §60.13, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.fdsys.gov.

§60.14 Modification. (a) Except as provided under paragraphs (e) and (f) of this section, any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification within the meaning of section 111 of the Act. Upon modification, an existing facility shall become an affected facility for each pollutant to which a standard applies and for which there is an increase in the emission rate to the atmosphere.

(b) Emission rate shall be expressed as kg/hr of any pollutant discharged into the atmosphere for which a standard is applicable. The Administrator shall use the following to determine emission rate:

(1) Emission factors as specified in the latest issue of “Compilation of Air Pollutant Emission Factors,” EPA Publication No. AP-42, or other emission factors determined by the Administrator to be superior to AP-42 emission factors, in cases where utilization of emission factors demonstrates that the emission level resulting from the physical or operational change will either clearly increase or clearly not increase.

(2) Material balances, continuous monitor data, or manual emission tests in cases where utilization of emission factors as referenced in paragraph (b)(1) of this section does not demonstrate to the Administrator's satisfaction whether the emission level resulting from the physical or operational change will either clearly increase or clearly not increase, or where an owner or operator demonstrates to the Administrator's satisfaction that there are reasonable grounds to dispute the result obtained by the Administrator utilizing emission factors as referenced in paragraph (b)(1) of this section. When the emission rate is based on results from manual emission tests or continuous monitoring systems, the procedures specified in appendix C of this part shall be used to determine whether an increase in emission rate has occurred. Tests shall be conducted under such conditions as the Administrator shall specify to the owner or operator based on representative performance of the facility. At least three valid test runs must be conducted before and at least three after the physical or operational change. All operating parameters which may affect emissions must be held constant to the maximum feasible degree for all test runs.

(c) The addition of an affected facility to a stationary source as an expansion to that source or as a replacement for an existing facility shall not by itself bring within the applicability of this part any other facility within that source.

(d) [Reserved]

(e) The following shall not, by themselves, be considered modifications under this part:


(1) Maintenance, repair, and replacement which the Administrator determines to be routine for a source category, subject to the provisions of paragraph (c) of this section and §60.15.

(2) An increase in production rate of an existing facility, if that increase can be accomplished without a capital expenditure on that facility.

(3) An increase in the hours of operation.

(4) Use of an alternative fuel or raw material if, prior to the date any standard under this part becomes applicable to that source type, as provided by §60.1, the existing facility was designed to accommodate that alternative use. A facility shall be considered to be designed to accommodate an alternative fuel or raw material if that use could be accomplished under the facility's construction specifications as amended prior to the change. Conversion to coal required for energy considerations, as specified in section 111(a)(8) of the Act, shall not be considered a modification.

(5) The addition or use of any system or device whose primary function is the reduction of air pollutants, except when an emission control system is removed or is replaced by a system which the Administrator determines to be less environmentally beneficial.

(6) The relocation or change in ownership of an existing facility.

(f) Special provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions of this section.

(g) Within 180 days of the completion of any physical or operational change subject to the control measures specified in paragraph (a) of this section, compliance with all applicable standards must be achieved.

(h) No physical change, or change in the method of operation, at an existing electric utility steam generating unit shall be treated as a modification for the purposes of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the 5 years prior to the change.

(i) Repowering projects that are awarded funding from the Department of Energy as permanent clean coal technology demonstration projects (or similar projects funded by EPA) are exempt from the requirements of this section provided that such change does not increase the maximum hourly emissions of any pollutant regulated under this section above the maximum hourly emissions achievable at that unit during the five years prior to the change.

(j)(1) Repowering projects that qualify for an extension under section 409(b) of the Clean Air Act are exempt from the requirements of this section, provided that such change does not increase the actual hourly emissions of any pollutant regulated under this section above the actual hourly emissions achievable at that unit during the 5 years prior to the change.

(2) This exemption shall not apply to any new unit that:

(i) Is designated as a replacement for an existing unit;


(ii) Qualifies under section 409(b) of the Clean Air Act for an extension of an emission limitation compliance date under section 405 of the Clean Air Act; and

(iii) Is located at a different site than the existing unit.

(k) The installation, operation, cessation, or removal of a temporary clean coal technology demonstration project is exempt from the requirements of this section. A temporary clean coal control technology demonstration project, for the purposes of this section is a clean coal technology demonstration project that is operated for a period of 5 years or less, and which complies with the State implementation plan for the State in which the project is located and other requirements necessary to attain and maintain the national ambient air quality standards during the project and after it is terminated.

(l) The reactivation of a very clean coal-fired electric utility steam generating unit is exempt from the requirements of this section.

[40 FR 58419, Dec. 16, 1975, as amended at 43 FR 34347, Aug. 3, 1978; 45 FR 5617, Jan. 23, 1980; 57 FR 32339, July 21, 1992; 65 FR 61750, Oct. 17, 2000]

§60.15 Reconstruction. (a) An existing facility, upon reconstruction, becomes an affected facility, irrespective of any change in emission rate.

(b) “Reconstruction” means the replacement of components of an existing facility to such an extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and

(2) It is technologically and economically feasible to meet the applicable standards set forth in this part.

(c) “Fixed capital cost” means the capital needed to provide all the depreciable components.

(d) If an owner or operator of an existing facility proposes to replace components, and the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, he shall notify the Administrator of the proposed replacements. The notice must be postmarked 60 days (or as soon as practicable) before construction of the replacements is commenced and must include the following information:

(1) Name and address of the owner or operator.

(2) The location of the existing facility.

(3) A brief description of the existing facility and the components which are to be replaced.

(4) A description of the existing air pollution control equipment and the proposed air pollution control equipment.


(5) An estimate of the fixed capital cost of the replacements and of constructing a comparable entirely new facility.

(6) The estimated life of the existing facility after the replacements.

(7) A discussion of any economic or technical limitations the facility may have in complying with the applicable standards of performance after the proposed replacements.

(e) The Administrator will determine, within 30 days of the receipt of the notice required by paragraph (d) of this section and any additional information he may reasonably require, whether the proposed replacement constitutes reconstruction.

(f) The Administrator's determination under paragraph (e) shall be based on:

(1) The fixed capital cost of the replacements in comparison to the fixed capital cost that would be required to construct a comparable entirely new facility;

(2) The estimated life of the facility after the replacements compared to the life of a comparable entirely new facility;

(3) The extent to which the components being replaced cause or contribute to the emissions from the facility; and

(4) Any economic or technical limitations on compliance with applicable standards of performance which are inherent in the proposed replacements.

(g) Individual subparts of this part may include specific provisions which refine and delimit the concept of reconstruction set forth in this section.

[40 FR 58420, Dec. 16, 1975]

§60.16 Priority list. Prioritized Major Source Categories

Priority Number1 Source Category

1. Synthetic Organic Chemical Manufacturing Industry (SOCMI) and Volatile Organic Liquid Storage Vessels and Handling Equipment

(a) SOCMI unit processes (b) Volatile organic liquid (VOL) storage vessels and handling equipment (c) SOCMI fugitive sources (d) SOCMI secondary sources 2. Industrial Surface Coating: Cans


3. Petroleum Refineries: Fugitive Sources 4. Industrial Surface Coating: Paper 5. Dry Cleaning (a) Perchloroethylene (b) Petroleum solvent 6. Graphic Arts 7. Polymers and Resins: Acrylic Resins 8. Mineral Wool (Deleted) 9. Stationary Internal Combustion Engines 10. Industrial Surface Coating: Fabric 11. Industrial-Commercial-Institutional Steam Generating Units. 12. Incineration: Non-Municipal (Deleted) 13. Non-Metallic Mineral Processing 14. Metallic Mineral Processing 15. Secondary Copper (Deleted) 16. Phosphate Rock Preparation 17. Foundries: Steel and Gray Iron 18. Polymers and Resins: Polyethylene 19. Charcoal Production 20. Synthetic Rubber (a) Tire manufacture (b) SBR production 21. Vegetable Oil 22. Industrial Surface Coating: Metal Coil 23. Petroleum Transportation and Marketing 24. By-Product Coke Ovens 25. Synthetic Fibers 26. Plywood Manufacture 27. Industrial Surface Coating: Automobiles 28. Industrial Surface Coating: Large Appliances 29. Crude Oil and Natural Gas Production 30. Secondary Aluminum 31. Potash (Deleted) 32. Lightweight Aggregate Industry: Clay, Shale, and Slate2 33. Glass 34. Gypsum 35. Sodium Carbonate


36. Secondary Zinc (Deleted) 37. Polymers and Resins: Phenolic 38. Polymers and Resins: Urea-Melamine 39. Ammonia (Deleted) 40. Polymers and Resins: Polystyrene 41. Polymers and Resins: ABS-SAN Resins 42. Fiberglass 43. Polymers and Resins: Polypropylene 44. Textile Processing 45. Asphalt Processing and Asphalt Roofing Manufacture 46. Brick and Related Clay Products 47. Ceramic Clay Manufacturing (Deleted) 48. Ammonium Nitrate Fertilizer 49. Castable Refractories (Deleted) 50. Borax and Boric Acid (Deleted) 51. Polymers and Resins: Polyester Resins 52. Ammonium Sulfate 53. Starch 54. Perlite 55. Phosphoric Acid: Thermal Process (Deleted) 56. Uranium Refining 57. Animal Feed Defluorination (Deleted) 58. Urea (for fertilizer and polymers) 59. Detergent (Deleted)

Other Source Categories Lead acid battery manufacture3 Organic solvent cleaning3 Industrial surface coating: metal furniture3 Stationary gas turbines4 Municipal solid waste landfills4 1Low numbers have highest priority, e.g., No. 1 is high priority, No. 59 is low priority.

2Formerly titled “Sintering: Clay and Fly Ash”.

3Minor source category, but included on list since an NSPS is being developed for that source category.


4Not prioritized, since an NSPS for this major source category has already been promulgated.

[47 FR 951, Jan. 8, 1982, as amended at 47 FR 31876, July 23, 1982; 51 FR 42796, Nov. 25, 1986; 52 FR 11428, Apr. 8, 1987; 61 FR 9919, Mar. 12, 1996]

§60.17 Incorporations by reference. (a) Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that specified in this section, the EPA must publish notice of change in the FEDERAL REGISTER and the material must be available to the public. All approved material is available for inspection at the EPA Docket Center, Public Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. NW., Washington, DC, telephone number 202-566-1744, and is available from the sources listed below. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call (202) 741-6030 or go to http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.

(b) American Gas Association, available through ILI Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652:

(1) American Gas Association Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (1990), IBR approved for §60.107a(d).

(2) American Gas Association Report No. 3: Orifice Metering for Natural Gas and Other Related Hydrocarbon Fluids, Part 2: Specification and Installation Requirements (2000), IBR approved for §60.107a(d).

(3) American Gas Association Report No. 11: Measurement of Natural Gas by Coriolis Meter (2003), IBR approved for §60.107a(d).

(4) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Revised February 2006), IBR approved for §60.107a(d).

(c) American Hospital Association (AHA) Service, Inc., Post Office Box 92683, Chicago, Illinois 60675-2683. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center (Docket A-91-61, Item IV-J-124), Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

(1) An Ounce of Prevention: Waste Reduction Strategies for Health Care Facilities. American Society for Health Care Environmental Services of the American Hospital Association. Chicago, Illinois. 1993. AHA Catalog No. 057007. ISBN 0-87258-673-5. IBR approved for §§60.35e and 60.55c.

(2) [Reserved]

(d) The following material is available for purchase from the American National Standards Institute (ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036, Telephone (212) 642-4980, and is also available at the following Web site: http://www.ansi.org.


(1) ANSI No. C12.20-2010 American National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR approved for §60.5535(d).

(2) [Reserved]

(e) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005.

(1) API Publication 2517, Evaporation Loss from External Floating Roof Tanks, Second Edition, February 1980, IBR approved for §§60.111(i), 60.111a(f), and 60.116b(e).

(2) API Manual of Petroleum Measurement Standards, Chapter 22—Testing Protocol, Section 2—Differential Pressure Flow Measurement Devices, First Edition, August 2005, IBR approved for §60.107a(d).

(f) American Public Health Association, 1015 18th Street NW., Washington, DC 20036.

(1) “Standard Methods for the Examination of Water and Wastewater,” 16th edition, 1985. Method 303F: “Determination of Mercury by the Cold Vapor Technique.” Incorporated by reference for appendix A-8 to part 60, Method 29, §§9.2.3, 10.3, and 11.1.3.

(2) 2540 G. Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, in Standard Methods for the Examination of Water and Wastewater, 20th Edition, 1998, IBR approved for §60.154(b).

(g) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990, Telephone (800) 843-2763, and is also available at the following Web site: http://www.asme.org.

(1) ASME Interim Supplement 19.5 on Instruments and Apparatus: Application, Part II of Fluid Meters, 6th Edition (1971), IBR approved for §§60.58a(h), 60.58b(i), 60.1320(a), and 60.1810(a).

(2) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, IBR approved for §60.107a(d).

(3) ASME/ANSI MFC-4M-1986 (Reaffirmed 2008), Measurement of Gas Flow by Turbine Meters, IBR approved for §60.107a(d).

(4) ASME/ANSI MFC-5M-1985 (Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR approved for §60.107a(d).

(5) ASME MFC-6M-1998 (Reaffirmed 2005), Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for §60.107a(d).

(6) ASME/ANSI MFC-7M-1987 (Reaffirmed 2006), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for §60.107a(d).

(7) ASME/ANSI MFC-9M-1988 (Reaffirmed 2006), Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for §60.107a(d).


(8) ASME MFC-11M-2006, Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for §60.107a(d).

(9) ASME MFC-14M-2003, Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for §60.107a(d).

(10) ASME MFC-16-2007, Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters, IBR approved for §60.107a(d).

(11) ASME MFC-18M-2001, Measurement of Fluid Flow Using Variable Area Meters, IBR approved for §60.107a(d).

(12) ASME MFC-22-2007, Measurement of Liquid by Turbine Flowmeters, IBR approved for §60.107a(d).

(13) ASME PTC 4.1-1964 (Reaffirmed 1991), Power Test Codes: Test Code for Steam Generating Units (with 1968 and 1969 Addenda), IBR approved for §§60.46b, 60.58a(h), 60.58b(i), 60.1320(a), and 60.1810(a).

(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved for §§60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and (j), 60.105a(d), (f), and (g), §60.106a(a), §60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF, table 2 to subpart JJJJ, §60.285a(f), §§60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w), 60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b) and 60.5413a(d).

(15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes, (Issued December 31, 2014), IBR approved for §60.5580.

(16) ASME PTC 46-1996, Performance Test Code on Overall Plant Performance, (Issued October 15, 1997), IBR approved for §60.5580.

(17) ASME QRO-1-1994, Standard for the Qualification and Certification of Resource Recovery Facility Operators, IBR approved for §§60.54b(a) and (b), 60.56a, 60.1185(a) and (c), and 60.1675(a) and (c).

(h) The following material is available for purchase from ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-2959, (800) 262-1373, http://www.astm.org.

(1) ASTM A99-76, Standard Specification for Ferromanganese, IBR approved for §60.261.

(2) ASTM A99-82 (Reapproved 1987), Standard Specification for Ferromanganese, IBR approved for §60.261.

(3) ASTM A100-69, Standard Specification for Ferrosilicon, IBR approved for §60.261.




(6) ASTM A101-73, Standard Specification for Ferrochromium, IBR approved for §60.261.

(7) ASTM A101-93, Standard Specification for Ferrochromium, IBR approved for §60.261.

(8) ASTM A482-76, Standard Specification for Ferrochromesilicon, IBR approved for §60.261.

(9) ASTM A482-93, Standard Specification for Ferrochromesilicon, IBR approved for §60.261.

(10) ASTM A483-64, Standard Specification for Silicomanganese, IBR approved for §60.261.

(11) ASTM A483-74 (Reapproved 1988), Standard Specification for Silicomanganese, IBR approved for §60.261.

(12) ASTM A495-76, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for §60.261.

(13) ASTM A495-94, Standard Specification for Calcium-Silicon and Calcium Manganese-Silicon, IBR approved for §60.261.

(14) ASTM D86-78, Distillation of Petroleum Products, IBR approved for §§60.562-2(d), 60.593(d), 60.593a(d), 60.633(h).





(19) ASTM D86-96, Distillation of Petroleum Products, (Approved April 10, 1996), IBR approved for §§60.562-2(d), 60.593(d), 60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).

(20) ASTM D129-64, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §§60.106(j) and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.




(23) ASTM D129-00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §60.335(b).

(24) ASTM D129-00 (Reapproved 2005), Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), IBR approved for §60.4415(a).

(25) ASTM D240-76, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.

(26) ASTM D240-92, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for §§60.46(c), 60.296(b), and appendix A-7: Method 19, Section 12.5.2.2.3.

(27) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, (Approved May 1, 2007), IBR approved for §60.107a(d).

(28) ASTM D270-65, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.

(29) ASTM D270-75, Standard Method of Sampling Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.

(30) ASTM D323-82, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§60.111(l), 60.111a(g), 60.111b, and 60.116b(f).

(31) ASTM D323-94, Test Method for Vapor Pressure of Petroleum Products (Reid Method), IBR approved for §§60.111(l), 60.111a(g), 60.111b, and 60.116b(f).

(32) ASTM D388-77, Standard Specification for Classification of Coals by Rank, IBR approved for §§60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.




(36) ASTM D388-98a, Standard Specification for Classification of Coals by Rank, IBR approved for §§60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, and 60.251.

(37) ASTM D388-99 (Reapproved 2004)ϵ1 Standard Classification of Coals by Rank, IBR approved for §§60.41, 60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580.


(38) ASTM D396-78, Standard Specification for Fuel Oils, IBR approved for §§60.41b, 60.41c, 60.111(b), and 60.111a(b).




(42) ASTM D396-98, Standard Specification for Fuel Oils, IBR approved for §§60.41b, 60.41c, 60.111(b), 60.111a(b), and 60.5580.

(43) ASTM D975-78, Standard Specification for Diesel Fuel Oils, IBR approved for §§60.111(b) and 60.111a(b).

(44) ASTM D975-96, Standard Specification for Diesel Fuel Oils, IBR approved for §§60.111(b) and 60.111a(b).

(45) ASTM D975-98a, Standard Specification for Diesel Fuel Oils, IBR approved for §§60.111(b) and 60.111a(b).

(46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, IBR approved for §§60.41b 60.41c, and 60.5580.

(47) ASTM D1072-80, Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for §60.335(b).

(48) ASTM D1072-90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for §60.335(b).

(49) ASTM D1072-90 (Reapproved 1999), Standard Test Method for Total Sulfur in Fuel Gases, IBR approved for §60.4415(a).

(50) ASTM D1137-53, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for §60.45(f).

(51) ASTM D1137-75, Standard Method for Analysis of Natural Gases and Related Types of Gaseous Mixtures by the Mass Spectrometer, IBR approved for §60.45(f).

(52) ASTM D1193-77, Standard Specification for Reagent Water, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60: Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A,


Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.

(53) ASTM D1193-91, Standard Specification for Reagent Water, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.3; Method 5E, Section 7.2.1; Method 5F, Section 7.2.1; appendix A-4 to part 60: Method 6, Section 7.1.1; Method 7, Section 7.1.1; Method 7C, Section 7.1.1; Method 7D, Section 7.1.1; Method 10A, Section 7.1.1; appendix A-5 to part 60: Method 11, Section 7.1.3; Method 12, Section 7.1.3; Method 13A, Section 7.1.2; appendix A-8 to part 60: Method 26, Section 7.1.2; Method 26A, Section 7.1.2; and Method 29, Section 7.2.2.

(54) ASTM D1266-87, Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §§60.106(j) and 60.335(b).



(57) ASTM D1266-98 (Reapproved 2003)ε,1 Standard Test Method for Sulfur in Petroleum Products (Lamp Method), IBR approved for §60.4415(a).

(58) ASTM D1475-60 (Reapproved 1980), Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for §60.435(d), appendix A-8 to part 60: Method 24, Section 6.1; and Method 24A, Sections 6.5 and 7.1.

(59) ASTM D1475-90, Standard Test Method for Density of Paint, Varnish Lacquer, and Related Products, IBR approved for §60.435(d), appendix A-8 to part 60: Method 24, Section 6.1; and Method 24A, §§6.5 and 7.1.

(60) ASTM D1552-83, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §§60.106(j), 60.335(b), and appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.



(63) ASTM D1552-03, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), IBR approved for §60.4415(a).

(64) ASTM D1826-77, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§60.45(f), 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.3.2.4.


(65) ASTM D1826-94, Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for §§60.45(f), 60.46(c), 60.296(b), and appendix A-7 to part 60: Method 19, Section 12.3.2.4.

(66) ASTM D1826-94 (Reapproved 2003), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, (Approved May 10, 2003), IBR approved for §60.107a(d).

(67) ASTM D1835-87, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§60.41Da, 60.41b, and 60.41c.



(70) ASTM D1835-03a, Standard Specification for Liquefied Petroleum (LP) Gases, IBR approved for §§60.41Da, 60.41b, and 60.41c.

(71) ASTM D1945-64, Standard Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for §60.45(f).




(75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR approved for §§60.107a(d), 60.5413(d), 60.5413a(d).

(76) ASTM D1946-77, Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§60.18(f), 60.45(f), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).

(77) ASTM D1946-90 (Reapproved 1994), Standard Method for Analysis of Reformed Gas by Gas Chromatography, IBR approved for §§60.18(f), 60.45(f), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).

(78) ASTM D1946-90 (Reapproved 2006), Standard Method for Analysis of Reformed Gas by Gas Chromatography, (Approved June 1, 2006), IBR approved for §60.107a(d).

(79) ASTM D2013-72, Standard Method of Preparing Coal Samples for Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.


(80) ASTM D2013-86, Standard Method of Preparing Coal Samples for Analysis, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(81) ASTM D2015-77 (Reapproved 1978), Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for §§60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(82) ASTM D2015-96, Standard Test Method for Gross Calorific Value of Solid Fuel by the Adiabatic Bomb Calorimeter, IBR approved for §§60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(83) ASTM D2016-74, Standard Test Methods for Moisture Content of Wood, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.

(84) ASTM D2016-83, Standard Test Methods for Moisture Content of Wood, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.

(85) ASTM D2234-76, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.


(87) ASTM D2234-97b, Standard Methods for Collection of a Gross Sample of Coal, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.1.


(89) ASTM D2369-81, Standard Test Method for Volatile Content of Coatings, IBR approved for appendix A-8 to part 60: Method 24, Section 6.2.







(95) ASTM D2382-76, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).

(96) ASTM D2382-88, Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), IBR approved for §§60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(e), 60.664(e), and 60.704(d).

(97) ASTM D2504-67, Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§60.485(g) and 60.485a(g).

(98) ASTM D2504-77, Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§60.485(g) and 60.485a(g).

(99) ASTM D2504-88 (Reapproved 1993), Noncondensable Gases in C3 and Lighter Hydrocarbon Products by Gas Chromatography, IBR approved for §§60.485(g) and 60.485a(g).

(100) ASTM D2584-68(Reapproved 1985), Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for §60.685(c).

(101) ASTM D2584-94, Standard Test Method for Ignition Loss of Cured Reinforced Resins, IBR approved for §60.685(c).

(102) ASTM D2597-94 (Reapproved 1999), Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for §60.335(b).

(103) ASTM D2622-87, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §§60.106(j) and 60.335(b).



(106) ASTM D2622-05, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §60.4415(a).

(107) ASTM D2879-83Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).

(108) ASTM D2879-96, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).


(109) ASTM D2879-97, Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope, IBR approved for §§60.111b(f)(3), 60.116b(e), 60.116b(f), 60.485(e), and 60.485a(e).

(110) ASTM D2880-78, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§60.111(b), 60.111a(b), and 60.335(d).

(111) ASTM D2880-96, Standard Specification for Gas Turbine Fuel Oils, IBR approved for §§60.111(b), 60.111a(b), and 60.335(d).

(112) ASTM D2908-74, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for §60.564(j).

(113) ASTM D2908-91, Standard Practice for Measuring Volatile Organic Matter in Water by Aqueous-Injection Gas Chromatography, IBR approved for §60.564(j).

(114) ASTM D2986-71, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.

(115) ASTM D2986-78, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.

(116) ASTM D2986-95a, Standard Method for Evaluation of Air, Assay Media by the Monodisperse DOP (Dioctyl Phthalate) Smoke Test, IBR approved for appendix A-3 to part 60: Method 5, Section 7.1.1; appendix A-5 to part 60: Method 12, Section 7.1.1; and Method 13A, Section 7.1.1.2.

(117) ASTM D3173-73, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(118) ASTM D3173-87, Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(119) ASTM D3176-74, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for §60.45(f)(5)(i) and appendix A-7 to part 60: Method 19, Section 12.3.2.3.

(120) ASTM D3176-89, Standard Method for Ultimate Analysis of Coal and Coke, IBR approved for §60.45(f)(5)(i) and appendix A-7 to part 60: Method 19, Section 12.3.2.3.

(121) ASTM D3177-75, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(122) ASTM D3177-89, Standard Test Method for Total Sulfur in the Analysis Sample of Coal and Coke, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.


(123) ASTM D3178-73 (Reapproved 1979), Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for §60.45(f).

(124) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, IBR approved for §60.45(f).

(125) ASTM D3246-81, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for §60.335(b).



(128) ASTM D3246-05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, IBR approved for §60.4415(a)(1).

(129) ASTM D3270-73T, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.

(130) ASTM D3270-80, Standard Test Methods for Analysis for Fluoride Content of the Atmosphere and Plant Tissues (Semiautomated Method), IBR approved for appendix A-5 to part 60: Method 13A, Section 16.1.



(133) ASTM D3286-85, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(134) ASTM D3286-96, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(135) ASTM D3370-76, Standard Practices for Sampling Water, IBR approved for §60.564(j).

(136) ASTM D3370-95a, Standard Practices for Sampling Water, IBR approved for §60.564(j).

(137) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, (Approved May 10, 2003), IBR approved for §§60.107a(d), 60.5413(d), and 60.5413a(d).

(138) ASTM D3699-08, Standard Specification for Kerosine, including Appendix X1, (Approved September 1, 2008), IBR approved for §§60.41b, 60.41c, and 60.5580.


(139) ASTM D3792-79, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.

(140) ASTM D3792-91, Standard Test Method for Water Content of Water-Reducible Paints by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.3.

(141) ASTM D4017-81, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.

(142) ASTM D4017-90, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.

(143) ASTM D4017-96a, Standard Test Method for Water in Paints and Paint Materials by the Karl Fischer Titration Method, IBR approved for appendix A-7 to part 60: Method 24, Section 6.4.

(144) ASTM D4057-81, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.

(145) ASTM D4057-95, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.3.

(146) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for §60.4415(a).

(147) ASTM D4084-82, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §60.334(h).

(148) ASTM D4084-94, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §60.334(h).

(149) ASTM D4084-05, Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), IBR approved for §§60.4360 and 60.4415(a).

(150) ASTM D4177-95, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.2.1.

(151) ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for §60.4415(a).

(152) ASTM D4239-85, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, IBR approved for appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.




(155) ASTM D4294-02, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §60.335(b).

(156) ASTM D4294-03, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectrometry, IBR approved for §60.4415(a).

(157) ASTM D4442-84, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.

(158) ASTM D4442-92, Standard Test Methods for Direct Moisture Content Measurement in Wood and Wood-base Materials, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.

(159) ASTM D4444-92, Standard Test Methods for Use and Calibration of Hand-Held Moisture Meters, IBR approved for appendix A-8 to part 60: Method 28, Section 16.1.1.

(160) ASTM D4457-85 (Reapproved 1991), Test Method for Determination of Dichloromethane and 1,1,1-Trichloroethane in Paints and Coatings by Direct Injection into a Gas Chromatograph, IBR approved for appendix A-7 to part 60: Method 24, Section 6.5.

(161) ASTM D4468-85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, IBR approved for §§60.335(b) and 60.4415(a).

(162) ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, (Approved June 1, 2006), IBR approved for §60.107a(e).

(163) ASTM D4629-02, Standard Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection, IBR approved for §§60.49b(e) and 60.335(b).

(164) ASTM D4809-95, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for §§60.18(f), 60.485(g), 60.485a(g), 60.564(f), 60.614(d), 60.664(e), and 60.704(d).

(165) ASTM D4809-06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), (Approved December 1, 2006), IBR approved for §60.107a(d).

(166) ASTM D4810-88 (Reapproved 1999), Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length of Stain Detector Tubes, IBR approved for §§60.4360 and 60.4415(a).

(167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, (Approved June 1, 2006), IBR approved for §§60.107a(d), 60.5413(d), and 60.5413a(d).


(168) ASTM D5287-97 (Reapproved 2002), Standard Practice for Automatic Sampling of Gaseous Fuels, IBR approved for §60.4415(a).

(169) ASTM D5403-93, Standard Test Methods for Volatile Content of Radiation Curable Materials, IBR approved for appendix A-7 to part 60: Method 24, Section 6.6.

(170) ASTM D5453-00, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for §60.335(b).

(171) ASTM D5453-05, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence, IBR approved for §60.4415(a).

(172) ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, IBR approved for §§60.334(h) and 60.4360.

(173) ASTM D5504-08, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, (Approved June 15, 2008), IBR approved for §§60.107a(e) and 60.5413(d).

(174) ASTM D5762-02, Standard Test Method for Nitrogen in Petroleum and Petroleum Products by Boat-Inlet Chemiluminescence, IBR approved for §60.335(b).

(175) ASTM D5865-98, Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for §§60.45(f) and 60.46(c), and appendix A-7 to part 60: Method 19, Section 12.5.2.1.3.

(176) ASTM D5865-10, Standard Test Method for Gross Calorific Value of Coal and Coke, (Approved January 1, 2010), IBR approved for §§60.45(f), 60.46(c), and appendix A-7 to part 60: Method 19, section 12.5.2.1.3.

(177) ASTM D6216-98, Standard Practice for Opacity Monitor Manufacturers to Certify Conformance with Design and Performance Specifications, IBR approved for appendix B to part 60: Performance Specification 1.

(178) ASTM D6228-98, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for §60.334(h).

(179) ASTM D6228-98 (Reapproved 2003), Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flame Photometric Detection, IBR approved for §§60.4360 and 60.4415.

(180) ASTM D6348-03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, (Approved October 1, 2003), IBR approved for §60.73a(b), table 7 to subpart IIII, table 2 to subpart JJJJ, and §60.4245(d).

(181) ASTM D6366-99, Standard Test Method for Total Trace Nitrogen and Its Derivatives in Liquid Aromatic Hydrocarbons by Oxidative Combustion and Electrochemical Detection, IBR approved for §60.335(b)(9).


(182) ASTM D6420-99 (Reapproved 2004), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry, (Approved October 1, 2004), IBR approved for §60.107a(d) and table 2 to subpart JJJJ.

(183) ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR approved for §60.335(a).

(184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2 to subpart JJJJ, §§60.5413(b) and (d), and 60.5413a(b).

(185) ASTM D6522-11 Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers (Approved December 1, 2011), IBR approved for §60.37f(a), 60.766(a).

(186) ASTM D6667-01, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for §60.335(b).

(187) ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, IBR approved for §60.4415(a).

(188) ASTM D6751-11b, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§60.41b, 60.41c, and 60.5580.

(189) ASTM D6784-02, Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), IBR approved for §60.56c(b) and appendix B to part 60: Performance Specification 12A, Section 8.6.2.

(190) ASTM D6784-02 (Reapproved 2008) Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), (Approved April 1, 2008), IBR approved for §§60.2165(j) and 60.2730(j), tables 1, 5, 6 and 8 to subpart CCCC, and tables 2, 6, 7, and 9 to subpart DDDD, §§60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, and tables 2 and 3 to subpart MMMM.

(191) ASTM D6911-15, Standard Guide for Packaging and Shipping Environmental Samples for Laboratory Analysis, approved January 15, 2015, IBR approved for appendix A-8: Method 30B.

(192) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved August 1, 2010), IBR approved for §§60.41b, 60.41c, and 60.5580.

(193) ASTM E168-67, General Techniques of Infrared Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).


(194) ASTM E168-77, General Techniques of Infrared Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).

(195) ASTM E168-92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400, 60.5400a(f).

(196) ASTM E169-63, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), and 60.632(f) .

(197) ASTM E169-77, General Techniques of Ultraviolet Quantitative Analysis, IBR approved for §§60.485a(d), 60.593(b), and 60.593a(b), 60.632(f).

(198) ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis, (Approved May 15, 1993), IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and 60.5400a(f).

(199) ASTM E260-73, General Gas Chromatography Procedures, IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).

(200) ASTM E260-91, General Gas Chromatography Procedures, (IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), and 60.632(f).

(201) ASTM E260-96, General Gas Chromatography Procedures, (Approved April 10, 1996), IBR approved for §§60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), and 60.5406a(b)(3).

(202) ASTM E617-13, Standard Specification for Laboratory Weights and Precision Mass Standards, approved May 1, 2013, IBR approved for appendix A-3: Methods 4, 5, 5H, 5I, and appendix A-8: Method 29.

(203) ASTM E871-82 (Reapproved 2013), Standard Test Method for Moisture Analysis of Particulate Wood Fuels, (Approved August 15, 2013), IBR approved for appendix A-8: method 28R.

(204) ASTM E1584-11, Standard Test Method for Assay of Nitric Acid, (Approved August 1, 2011), IBR approved for §60.73a(c).

(205) ASTM E2515-11, Standard Test Method for Determination of Particulate Matter Emissions Collected by a Dilution Tunnel, (Approved November 1, 2011), IBR approved for §60.534 and §60.5476.

(206) ASTM E2618-13 Standard Test Method for Measurement of Particulate Matter Emissions and Heating Efficiency of Outdoor Solid Fuel-Fired Hydronic Heating Appliances, (Approved September 1, 2013), IBR approved for §60.5476.

(207) ASTM E2779-10, Standard Test Method for Determining Particulate Matter Emissions from Pellet Heaters, (Approved October 1, 2010), IBR approved for §60.534.

(208) ASTM E2780-10, Standard Test Method for Determining Particulate Matter Emissions from Wood Heaters, (Approved October 1, 2010), IBR approved for appendix A: method 28R.


(209) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography, (Copyright 1997), IBR approved for §60.107a(d).

(i) Association of Official Analytical Chemists, 1111 North 19th Street, Suite 210, Arlington, VA 22209.

(1) AOAC Method 9, Official Methods of Analysis of the Association of Official Analytical Chemists (AOAC), 11th edition, 1970, pp. 11-12, IBR approved for §§60.204(b), 60.214(b), 60.224(b), and 60.234(b).

(2) [Reserved]

(j) U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.

(1) EPA-454/R-98-015, Office of Air Quality Planning and Standards (OAQPS) Fabric Filter Bag Leak Detection Guidance, September 1997, IBR approved for §§60.2145(r), 60.2710(r), 60.4905(b), and 60.5225(b).

(2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, May 2012, IBR approved for §§60.5413(d) and 60.5413a(d).

(k) The Gas Processors Association, 6526 East 60th Street, Tulsa, OK 74145; also available through Information Handling Services, 15 Inverness Way East, PO Box 1154, Englewood, CO 80150-1154. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460.

(1) Gas Processors Association Standard 2172-09, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer (2009), IBR approved for §60.107a(d).

(2) Gas Processors Association Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (2000), IBR approved for §60.107a(d).

(3) Gas Processors Association Standard 2377-86, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes, 1986 Revision, IBR approved for §§60.105(b), 60.107a(b), 60.334(h), 60.4360, and 60.4415(a).

(l) International Organization for Standardization (ISO) available through IHS Inc., 15 Inverness Way East, Englewood, CO 80112.

(1) ISO 8178-4: 1996(E), Reciprocating Internal Combustion Engines—Exhaust Emission Measurement—part 4: Test Cycles for Different Engine Applications, IBR approved for §60.4241(b).

(2) [Reserved]

(m) International Organization for Standardization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11, http://www.iso.org/iso/home.htm.


(1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition (December 15, 2009), IBR approved for §60.5580.

(2) ISO 8316: Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)—First Edition, IBR approved for §60.107a(d).

(n) This material is available for purchase from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, Virginia 22161. You may inspect a copy at the EPA's Air and Radiation Docket and Information Center (Docket A-91-61, Item IV-J-125), Room M-1500, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

(1) OMB Bulletin No. 93-17: Revised Statistical Definitions for Metropolitan Areas. Office of Management and Budget, June 30, 1993. NTIS No. PB 93-192-664. IBR approved for §60.31e.

(2) [Reserved]

(o) North American Electric Reliability Corporation, 1325 G Street NW., Suite 600, Washington, DC 20005-3801, http://www.nerc.com.

(1) North American Electric Reliability Corporation Reliability Standard EOP-002-3, Capacity and Energy Emergencies, updated November 19, 2012, IBR approved for §§60.4211(f) and 60.4243(d). Also available online: http://www.nerc.com/files/EOP-002-3_1.pdf.

(2) [Reserved]

(p) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Suite 115, Peachtree Corners, GA 30092, Telephone (800) 332-8686, and is also available at the following Web site: http://www.tappi.org.

(1) TAPPI Method T 624 cm-11, (Copyright 2011), IBR approved, for §§60.285(d) and 60.285a(d).

(2) [Reserved]

(q) Underwriter's Laboratories, Inc. (UL), 333 Pfingsten Road, Northbrook, IL 60062.

(1) UL 103, Sixth Edition revised as of September 3, 1986, Standard for Chimneys, Factory-built, Residential Type and Building Heating Appliance, IBR approved for appendix A-8 to part 60.

(2) [Reserved]

(r) Water Pollution Control Federation (WPCF), 2626 Pennsylvania Avenue NW., Washington, DC 20037.

(1) Method 209A, Total Residue Dried at 103-105 °C, in Standard Methods for the Examination of Water and Wastewater, 15th Edition, 1980, IBR approved for §60.683(b).

(2) [Reserved]


(s) West Coast Lumber Inspection Bureau, 6980 SW. Barnes Road, Portland, OR 97223.

(1) West Coast Lumber Standard Grading Rules No. 16, pages 5-21, 90 and 91, September 3, 1970, revised 1984, IBR approved for appendix A-8 to part 60.

(2) [Reserved]

(t) This material is available for purchase from the Canadian Standards Association (CSA), 5060 Spectrum Way, Suite 100, Mississauga, Ontario, Canada L4W 5N6, Telephone: 800-463-6727.

(1) CSA B415.1-10, Performance Testing of Solid-fuel-burning Heating Appliances, (March 2010), IBR approved for §60.534 and §60.5476. (The standard is also available at http://shop.csa.ca/en/canada/fuel-burning-equipment/b4151-10/invt/27013322010)

(2) [Reserved]

(u) This European National (EN) standards material is available for purchase at European Committee for Standardization, Management Centre, Avenue Marnix 17, B-1000 Brussels, Belgium, Telephone: + 32 2 550 08 11.

(1) DIN EN 303-5:2012E (EN 303-5), Heating boilers—Part 5: Heating boilers for solid fuels, manually and automatically stoked, nominal heat output of up to 500 kW—Terminology, requirements, testing and marking, (October 2012), IBR approved for §60.5476. (The standard is also available at http://www.en-standard.eu/csn-en-303-5-heating-boilers-part-5-heating-boilers-for-solid-fuels-manually-and-automatically-stoked-nominal-heat-output-of-up-to-500-kw-terminology-requirements-testing-and-marking/?gclid = CJXI2P_97MMCFdccgQodan8ATA)

(2) [Reserved]

[79 FR 11242, Feb. 27, 2014, as amended at 79 FR 18965, Apr. 4, 2014; 80 FR 13701, Mar. 16, 2015; 80 FR 64648, Oct. 23, 2015; 81 FR 35895, June 3, 2016; 81 FR 59313, 59368, Aug. 29, 2016; 81 FR 59809, Aug. 30, 2016; 82 FR 28562, June 23, 2017]

§60.18 General control device and work practice requirements. (a) Introduction. (1) This section contains requirements for control devices used to comply with applicable subparts of 40 CFR parts 60 and 61. The requirements are placed here for administrative convenience and apply only to facilities covered by subparts referring to this section.

(2) This section also contains requirements for an alternative work practice used to identify leaking equipment. This alternative work practice is placed here for administrative convenience and is available to all subparts in 40 CFR parts 60, 61, 63, and 65 that require monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.

(b) Flares. Paragraphs (c) through (f) apply to flares.


(c)(1) Flares shall be designed for and operated with no visible emissions as determined by the methods specified in paragraph (f), except for periods not to exceed a total of 5 minutes during any 2 consecutive hours.

(2) Flares shall be operated with a flame present at all times, as determined by the methods specified in paragraph (f).

(3) An owner/operator has the choice of adhering to either the heat content specifications in paragraph (c)(3)(ii) of this section and the maximum tip velocity specifications in paragraph (c)(4) of this section, or adhering to the requirements in paragraph (c)(3)(i) of this section.

(i)(A) Flares shall be used that have a diameter of 3 inches or greater, are nonassisted, have a hydrogen content of 8.0 percent (by volume), or greater, and are designed for and operated with an exit velocity less than 37.2 m/sec (122 ft/sec) and less than the velocity, Vmax, as determined by the following equation:

Vmax = (XH2−K1)* K2

Where:

Vmax = Maximum permitted velocity, m/sec.

K1 = Constant, 6.0 volume-percent hydrogen.

K2 = Constant, 3.9(m/sec)/volume-percent hydrogen.

XH2 = The volume-percent of hydrogen, on a wet basis, as calculated by using the American Society for Testing and Materials (ASTM) Method D1946-77. (Incorporated by reference as specified in §60.17).

(B) The actual exit velocity of a flare shall be determined by the method specified in paragraph (f)(4) of this section.

(ii) Flares shall be used only with the net heating value of the gas being combusted being 11.2 MJ/scm (300 Btu/scf) or greater if the flare is steam-assisted or air-assisted; or with the net heating value of the gas being combusted being 7.45 MJ/scm (200 Btu/scf) or greater if the flare is nonassisted. The net heating value of the gas being combusted shall be determined by the methods specified in paragraph (f)(3) of this section.

(4)(i) Steam-assisted and nonassisted flares shall be designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4) of this section, less than 18.3 m/sec (60 ft/sec), except as provided in paragraphs (c)(4) (ii) and (iii) of this section.

(ii) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4), equal to or greater than 18.3 m/sec (60 ft/sec) but less than 122 m/sec (400 ft/sec) are allowed if the net heating value of the gas being combusted is greater than 37.3 MJ/scm (1,000 Btu/scf).


(iii) Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in paragraph (f)(4), less than the velocity, Vmax, as determined by the method specified in paragraph (f)(5), and less than 122 m/sec (400 ft/sec) are allowed.

(5) Air-assisted flares shall be designed and operated with an exit velocity less than the velocity, Vmax, as determined by the method specified in paragraph (f)(6).

(6) Flares used to comply with this section shall be steam-assisted, air-assisted, or nonassisted.

(d) Owners or operators of flares used to comply with the provisions of this subpart shall monitor these control devices to ensure that they are operated and maintained in conformance with their designs. Applicable subparts will provide provisions stating how owners or operators of flares shall monitor these control devices.

(e) Flares used to comply with provisions of this subpart shall be operated at all times when emissions may be vented to them.

(f)(1) Method 22 of appendix A to this part shall be used to determine the compliance of flares with the visible emission provisions of this subpart. The observation period is 2 hours and shall be used according to Method 22.

(2) 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.

(3) The net heating value of the gas being combusted in a flare shall be calculated using the following equation:

where:

HT = Net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based on combustion at 25 °C and 760 mm Hg, but the standard temperature for determining the volume corresponding to one mole is 20 °C;

Ci = Concentration of sample component i in ppm on a wet basis, as measured for organics by Reference Method 18 and measured for hydrogen and carbon monoxide by ASTM D1946-77 or 90 (Reapproved 1994) (Incorporated by reference as specified in §60.17); and

Hi = Net heat of combustion of sample component i, kcal/g mole at 25 °C and 760 mm Hg. The heats of combustion may be determined using ASTM D2382-76 or 88 or D4809-95 (incorporated by reference as specified in §60.17) if published values are not available or cannot be calculated.


(4) The actual exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip.

(5) The maximum permitted velocity, Vmax, for flares complying with paragraph (c)(4)(iii) shall be determined by the following equation.

Log10 (Vmax) = (HT + 28.8)/31.7

Vmax = Maximum permitted velocity, M/sec

28.8 = Constant

31.7 = Constant

HT = The net heating value as determined in paragraph (f)(3).

(6) The maximum permitted velocity, Vmax, for air-assisted flares shall be determined by the following equation.

Vmax = 8.706 + 0.7084 (HT)

Vmax = Maximum permitted velocity, m/sec

8.706 = Constant

0.7084 = Constant

HT = The net heating value as determined in paragraph (f)(3).

(g) Alternative work practice for monitoring equipment for leaks. Paragraphs (g), (h), and (i) of this section apply to all equipment for which the applicable subpart requires monitoring with a 40 CFR part 60, appendix A-7, Method 21 monitor, except for closed vent systems, equipment designated as leakless, and equipment identified in the applicable subpart as having no detectable emissions, as indicated by an instrument reading of less than 500 ppm above background. An owner or operator may use an optical gas imaging instrument instead of a 40 CFR part 60, appendix A-7, Method 21 monitor. Requirements in the existing subparts that are specific to the Method 21 instrument do not apply under this section. All other requirements in the applicable subpart that are not addressed in paragraphs (g), (h), and (i) of this section apply to this standard. For example, equipment specification requirements, and non-Method 21 instrument recordkeeping and reporting requirements in the applicable subpart continue to apply. The terms defined in paragraphs (g)(1) through (5) of this section have meanings that are specific to the alternative work practice standard in paragraphs (g), (h), and (i) of this section.

(1) Applicable subpart means the subpart in 40 CFR parts 60, 61, 63, or 65 that requires monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.


(2) Equipment means pumps, valves, pressure relief valves, compressors, open-ended lines, flanges, connectors, and other equipment covered by the applicable subpart that require monitoring with a 40 CFR part 60, appendix A-7, Method 21 monitor.

(3) Imaging means making visible emissions that may otherwise be invisible to the naked eye.

(4) Optical gas imaging instrument means an instrument that makes visible emissions that may otherwise be invisible to the naked eye.

(5) Repair means that equipment is adjusted, or otherwise altered, in order to eliminate a leak.

(6) Leak means:

(i) Any emissions imaged by the optical gas instrument;

(ii) Indications of liquids dripping;

(iii) Indications by a sensor that a seal or barrier fluid system has failed; or

(iv) Screening results using a 40 CFR part 60, appendix A-7, Method 21 monitor that exceed the leak definition in the applicable subpart to which the equipment is subject.

(h) The alternative work practice standard for monitoring equipment for leaks is available to all subparts in 40 CFR parts 60, 61, 63, and 65 that require monitoring of equipment with a 40 CFR part 60, appendix A-7, Method 21 monitor.

(1) An owner or operator of an affected source subject to CFR parts 60, 61, 63, or 65 can choose to comply with the alternative work practice requirements in paragraph (i) of this section instead of using the 40 CFR part 60, appendix A-7, Method 21 monitor to identify leaking equipment. The owner or operator must document the equipment, process units, and facilities for which the alternative work practice will be used to identify leaks.

(2) Any leak detected when following the leak survey procedure in paragraph (i)(3) of this section must be identified for repair as required in the applicable subpart.

(3) If the alternative work practice is used to identify leaks, re-screening after an attempted repair of leaking equipment must be conducted using either the alternative work practice or the 40 CFR part 60, appendix A-7, Method 21 monitor at the leak definition required in the applicable subpart to which the equipment is subject.

(4) The schedule for repair is as required in the applicable subpart.

(5) When this alternative work practice is used for detecting leaking equipment, choose one of the monitoring frequencies listed in Table 1 to subpart A of this part in lieu of the monitoring frequency specified for regulated equipment in the applicable subpart. Reduced monitoring frequencies for good performance are not applicable when using the alternative work practice.


(6) When this alternative work practice is used for detecting leaking equipment the following are not applicable for the equipment being monitored:

(i) Skip period leak detection and repair;

(ii) Quality improvement plans; or

(iii) Complying with standards for allowable percentage of valves and pumps to leak.

(7) When the alternative work practice is used to detect leaking equipment, the regulated equipment in paragraph (h)(1)(i) of this section must also be monitored annually using a 40 CFR part 60, appendix A-7, Method 21 monitor at the leak definition required in the applicable subpart. The owner or operator may choose the specific monitoring period (for example, first quarter) to conduct the annual monitoring. Subsequent monitoring must be conducted every 12 months from the initial period. Owners or operators must keep records of the annual Method 21 screening results, as specified in paragraph (i)(4)(vii) of this section.

(i) An owner or operator of an affected source who chooses to use the alternative work practice must comply with the requirements of paragraphs (i)(1) through (i)(5) of this section.

(1) Instrument Specifications. The optical gas imaging instrument must comply with the requirements in (i)(1)(i) and (i)(1)(ii) of this section.

(i) Provide the operator with an image of the potential leak points for each piece of equipment at both the detection sensitivity level and within the distance used in the daily instrument check described in paragraph (i)(2) of this section. The detection sensitivity level depends upon the frequency at which leak monitoring is to be performed.

(ii) Provide a date and time stamp for video records of every monitoring event.

(2) Daily Instrument Check. On a daily basis, and prior to beginning any leak monitoring work, test the optical gas imaging instrument at the mass flow rate determined in paragraph (i)(2)(i) of this section in accordance with the procedure specified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section for each camera configuration used during monitoring (for example, different lenses used), unless an alternative method to demonstrate daily instrument checks has been approved in accordance with paragraph (i)(2)(v) of this section.

(i) Calculate the mass flow rate to be used in the daily instrument check by following the procedures in paragraphs (i)(2)(i)(A) and (i)(2)(i)(B) of this section.

(A) For a specified population of equipment to be imaged by the instrument, determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable, within the distance to be used in paragraph (i)(2)(iv)(B) of this section, at or below the standard detection sensitivity level.

(B) Multiply the standard detection sensitivity level, corresponding to the selected monitoring frequency in Table 1 of subpart A of this part, by the mass fraction of detectable chemicals from the stream identified in paragraph (i)(2)(i)(A) of this section to determine the mass flow rate to be used in the daily instrument check, using the following equation.


Where:

Edic = Mass flow rate for the daily instrument check, grams per hour

xi = Mass fraction of detectable chemical(s) i seen by the optical gas imaging instrument, within the distance to be used in paragraph (i)(2)(iv)(B) of this section, at or below the standard detection sensitivity level, Esds.

Esds = Standard detection sensitivity level from Table 1 to subpart A, grams per hour

k = Total number of detectable chemicals emitted from the leaking equipment and seen by the optical gas imaging instrument.

(ii) Start the optical gas imaging instrument according to the manufacturer's instructions, ensuring that all appropriate settings conform to the manufacturer's instructions.

(iii) Use any gas chosen by the user that can be viewed by the optical gas imaging instrument and that has a purity of no less than 98 percent.

(iv) Establish a mass flow rate by using the following procedures:

(A) Provide a source of gas where it will be in the field of view of the optical gas imaging instrument.

(B) Set up the optical gas imaging instrument at a recorded distance from the outlet or leak orifice of the flow meter that will not be exceeded in the actual performance of the leak survey. Do not exceed the operating parameters of the flow meter.

(C) Open the valve on the flow meter to set a flow rate that will create a mass emission rate equal to the mass rate specified in paragraph (i)(2)(i) of this section while observing the gas flow through the optical gas imaging instrument viewfinder. When an image of the gas emission is seen through the viewfinder at the required emission rate, make a record of the reading on the flow meter.

(v) Repeat the procedures specified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section for each configuration of the optical gas imaging instrument used during the leak survey.

(vi) To use an alternative method to demonstrate daily instrument checks, apply to the Administrator for approval of the alternative under §60.13(i).

(3) Leak Survey Procedure. Operate the optical gas imaging instrument to image every regulated piece of equipment selected for this work practice in accordance with the instrument manufacturer's operating parameters. All emissions imaged by the optical gas imaging instrument are considered to be leaks and are subject to repair. All emissions visible to the naked eye are also considered to be leaks and are subject to repair.


(4) Recordkeeping. You must keep the records described in paragraphs (i)(4)(i) through (i)(4)(vii) of this section:

(i) The equipment, processes, and facilities for which the owner or operator chooses to use the alternative work practice.

(ii) The detection sensitivity level selected from Table 1 to subpart A of this part for the optical gas imaging instrument.

(iii) The analysis to determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable, as specified in paragraph (i)(2)(i)(A) of this section.

(iv) The technical basis for the mass fraction of detectable chemicals used in the equation in paragraph (i)(2)(i)(B) of this section.

(v) The daily instrument check. Record the distance, per paragraph (i)(2)(iv)(B) of this section, and the flow meter reading, per paragraph (i)(2)(iv)(C) of this section, at which the leak was imaged. Keep a video record of the daily instrument check for each configuration of the optical gas imaging instrument used during the leak survey (for example, the daily instrument check must be conducted for each lens used). The video record must include a time and date stamp for each daily instrument check. The video record must be kept for 5 years.

(vi) Recordkeeping requirements in the applicable subpart. A video record must be used to document the leak survey results. The video record must include a time and date stamp for each monitoring event. A video record can be used to meet the recordkeeping requirements of the applicable subparts if each piece of regulated equipment selected for this work practice can be identified in the video record. The video record must be kept for 5 years.

(vii) The results of the annual Method 21 screening required in paragraph (h)(7) of this section. Records must be kept for all regulated equipment specified in paragraph (h)(1) of this section. Records must identify the equipment screened, the screening value measured by Method 21, the time and date of the screening, and calibration information required in the existing applicable subpart.

(5) Reporting. Submit the reports required in the applicable subpart. Submit the records of the annual Method 21 screening required in paragraph (h)(7) of this section to the Administrator via e-mail to [email protected].

[51 FR 2701, Jan. 21, 1986, as amended at 63 FR 24444, May 4, 1998; 65 FR 61752, Oct. 17, 2000; 73 FR 78209, Dec. 22, 2008]

§60.19 General notification and reporting requirements. (a) For the purposes of this part, time periods specified in days shall be measured in calendar days, even if the word “calendar” is absent, unless otherwise specified in an applicable requirement.

(b) For the purposes of this part, if an explicit postmark deadline is not specified in an applicable requirement for the submittal of a notification, application, report, or other written communication to the Administrator, the


owner or operator shall postmark the submittal on or before the number of days specified in the applicable requirement. For example, if a notification must be submitted 15 days before a particular event is scheduled to take place, the notification shall be postmarked on or before 15 days preceding the event; likewise, if a notification must be submitted 15 days after a particular event takes place, the notification shall be delivered or postmarked on or before 15 days following the end of the event. The use of reliable non-Government mail carriers that provide indications of verifiable delivery of information required to be submitted to the Administrator, similar to the postmark provided by the U.S. Postal Service, or alternative means of delivery, including the use of electronic media, agreed to by the permitting authority, is acceptable.

(c) Notwithstanding time periods or postmark deadlines specified in this part for the submittal of information to the Administrator by an owner or operator, or the review of such information by the Administrator, such time periods or deadlines may be changed by mutual agreement between the owner or operator and the Administrator. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.

(d) If an owner or operator of an affected facility in a State with delegated authority is required to submit periodic reports under this part to the State, and if the State has an established timeline for the submission of periodic reports that is consistent with the reporting frequency(ies) specified for such facility under this part, the owner or operator may change the dates by which periodic reports under this part shall be submitted (without changing the frequency of reporting) to be consistent with the State's schedule by mutual agreement between the owner or operator and the State. The allowance in the previous sentence applies in each State beginning 1 year after the affected facility is required to be in compliance with the applicable subpart in this part. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.

(e) If an owner or operator supervises one or more stationary sources affected by standards set under this part and standards set under part 61, part 63, or both such parts of this chapter, he/she may arrange by mutual agreement between the owner or operator and the Administrator (or the State with an approved permit program) a common schedule on which periodic reports required by each applicable standard shall be submitted throughout the year. The allowance in the previous sentence applies in each State beginning 1 year after the stationary source is required to be in compliance with the applicable subpart in this part, or 1 year after the stationary source is required to be in compliance with the applicable 40 CFR part 61 or part 63 of this chapter standard, whichever is latest. Procedures governing the implementation of this provision are specified in paragraph (f) of this section.

(f)(1)(i) Until an adjustment of a time period or postmark deadline has been approved by the Administrator under paragraphs (f)(2) and (f)(3) of this section, the owner or operator of an affected facility remains strictly subject to the requirements of this part.

(ii) An owner or operator shall request the adjustment provided for in paragraphs (f)(2) and (f)(3) of this section each time he or she wishes to change an applicable time period or postmark deadline specified in this part.

(2) Notwithstanding time periods or postmark deadlines specified in this part for the submittal of information to the Administrator by an owner or operator, or the review of such information by the Administrator, such time periods or deadlines may be changed by mutual agreement between the owner or operator and the Administrator. An owner or operator who wishes to request a change in a time period or postmark deadline for a particular requirement shall request the adjustment in writing as soon as practicable before the subject activity is


required to take place. The owner or operator shall include in the request whatever information he or she considers useful to convince the Administrator that an adjustment is warranted.

(3) If, in the Administrator's judgment, an owner or operator's request for an adjustment to a particular time period or postmark deadline is warranted, the Administrator will approve the adjustment. The Administrator will notify the owner or operator in writing of approval or disapproval of the request for an adjustment within 15 calendar days of receiving sufficient information to evaluate the request.

(4) If the Administrator is unable to meet a specified deadline, he or she will notify the owner or operator of any significant delay and inform the owner or operator of the amended schedule.

[59 FR 12428, Mar. 16, 1994, as amended at 64 FR 7463, Feb. 12, 1998]

Table 1 to Subpart A of Part 60—Detection Sensitivity Levels (grams per hour)

Monitoring frequency per subparta Detection sensitivity level Bi-Monthly 60 Semi-Quarterly 85 Monthly 100

aWhen this alternative work practice is used to identify leaking equipment, the owner or operator must choose one of the monitoring frequencies listed in this table in lieu of the monitoring frequency specified in the applicable subpart. Bi-monthly means every other month. Semi-quarterly means twice per quarter. Monthly means once per month.

[73 FR 78211, Dec. 22, 2008]

Technical Support Document, Permit Number: 04700061-101 Page 1 of 12

Technical Support Document For

Air Emission Permit No. 04700061-101 This technical support document (TSD) is intended for all parties interested in the permit and to meet the requirements that have been set forth by the federal and state regulations (40 CFR § 70.7(a)(5) and Minn. R. 7007.0850, subp. 1). The purpose of this document is to provide the legal and factual justification for each applicable requirement or policy decision considered in the preliminary determination to issue the permit. 1. General information

1.1 Applicant and stationary source location:

Table 1. Applicant and source address

Applicant/Address

Stationary source/Address (SIC Code: 2869 - Industrial Organic Chemicals, Not Elsewhere Classified)

REG Inc 15200 780th Ave Albert Lea, Minnesota 56007-7082

REG Albert Lea LLC 15200 780th Ave Albert Lea, MN 56007-7082

Contact: Eric Hunnicutt Phone: 507-448-0124 ext2408

1.2 Facility description

REG Albert Lea, LLC (REG) is a biodiesel manufacturing plant located near Albert Lea, Minnesota. The facility produces biodiesel from soybean oil and methanol, and lower quality feedstocks such as used cooking oil, inedible corn oil, and lower quality animal fats. Currently, the facility is restricted by a production permit limit of 38,000,000 gallons of biodiesel per year. The facility is a true minor source under the federal Prevention of Significant Deterioration (PSD) program. The facility is a synthetic minor source under the federal National Emission Standards for Hazardous Air Pollutants (NESHAP) and Part 70 programs for methanol (a federally-designated Hazardous Air Pollutant, HAP) and total HAPs. The main sources of methanol emissions are equipment leaks and from the distillation process. A flare (TREA 2) controls VOC and HAP emissions from the process equipment and four storage tanks.

1.3 Description of the activities allowed by this permit action This permit action is for a major and minor amendment. The MPCA has a combined operating and construction permitting program under Minn. R. ch. 7007, and under Minn. R. 7007.0800. In the major amendment, REG is proposing to increase the maximum production rate from the currently permitted 38 million gallons per year to 44 million gallons per year. No physical changes to the facility are required to accomplish this production increase. In the minor amendment, REG is proposing to install a natural gas boiler with a maximum design capacity of 33.5 mmBtu/hr. REG currently receives plant process steam from the neighboring POET bio-refining Glenville East (POET) ethanol plant. The proposed boiler will provide process steam during periods that steam cannot be obtained from POET.


The proposed boiler addition is a minor amendment, which does not require construction authorization due to Minn. R. 7007.1450, subp. 7(A). Therefore, this permit does not authorize construction.

1.4 Description of notifications and applications included in this action

Table 2. Notifications and applications included in this action

Date received Application/notification type and description 10/20/2016 Major Amendment (IND20160003) 10/20/2016 Minor Amendment (IND20160004)

1.5 Facility emissions: The facility is proposing to increase production capacity without making any physical changes to the facility. The potential to emit of the entire facility after the modification are being evaluated against the NSR and 112(g) thresholds to determine if NSR or 112(g) review is required. Therefore, in Table 3 below, the values in the ‘Limited Potential Emissions for the Modification’ column are also the total facility PTE. This includes the emissions from the minor amendment to install a 33.5 mmBtu/hr boiler. The facility is required by their current permit to operate a flare to control emissions at all times any operation controlled by the flare is operating. The facility may take into account all federally enforceable emissions limitations when calculating the unlimited potential to emit; therefore, the unlimited potential emissions from the modification are equal to the limited potential emissions from the modification.

Table 3. Title I emissions summary

Pollutant

Unlimited potential emissions from the modification (tpy)

Limited potential emissions from the modification (tpy)

NSR/112(g) threshold for new major source (tpy)

NSR/112(g) review required? (yes/no)

PM 32.9 32.9 100 No PM10 11.9 11.5 100 No PM2.5 3.2 3.2 100 No NOX 30.4 30.4 100 No SO2 0.18 0.2 100 No CO 28.3 28.3 100 No Ozone (VOC) 18.1 17.9 100 No Lead - - 100 No CO2e* 36,842 36,842 100,000 No Methanol/Total HAPs 8.5/9.5 8.5/9.5 10/25 No

*Carbon dioxide equivalents as defined in Minn. R. 7007.0100. Table 4 shows the potential emissions before and after the addition of the boiler to compare the net change in emissions against modification and amendment thresholds. Table 4. Non-title I emissions increase summary

Pollutant

After change (lb/hr)

Before change (lb/hr)

Net change* (lb/hr)

Insignificant modification thresholds (lb/hr <)

Minor and moderate amendment thresholds (lb/hr < or >)

Type of amendment (minor or moderate)


Pollutant

After change (lb/hr)

Before change (lb/hr)

Net change* (lb/hr)

Insignificant modification thresholds (lb/hr <)

Minor and moderate amendment thresholds (lb/hr < or >)

Type of amendment (minor or moderate)

PM10 0.25 0 0.25 0.855 3.42 NOx 3.28 0 3.28 2.28 9.13 Minor SO2 0.0197 0 0.0197 2.28 9.13 CO 2.76 0 2.76 5.70 22.80 VOC 0.181 0 0.181 2.28 9.13 Lead 0.00002 0 0.00002 0.025 0.11

*The term ‘Net Change’ is not equivalent to ‘Net Emissions Increase’ as defined at 40 CFR Section 52.21(b)(3).

Table 5. Facility classification

Classification Major Synthetic minor/area Minor/area PSD X Part 70 Permit Program X Part 63 NESHAP X

1.6 Changes to permit

The MPCA has a combined operating and construction permitting program under Minnesota Rules Chapter 7007, and under Minn. R. 7007.0800, the MPCA has authority to include additional requirements in a permit. Under that authority, the following changes to the permit are also made through this permit action:

· Industrial Process Equipment requirements for EQUIs 34, 49, 58, and 61 were removed from a group and placed at each individual unit;

· Industrial Process Equipment requirements added to EQUIs 31, 37, 38, 48, and 55; · 40 CFR pt. 60, subp. Dc requirements removed from group for both oil heaters and placed at each

individual unit; · Minnesota Standards of Performance for Indirect Heating Equipment removed from the permit for

both Hot Oil Heater #1 (EQUI 59) and Hot Oil Heater #2 (EQUI 32) because they are already subject to standard of performance under 40 CFR pt. 60, subp. Dc;

· Modeling Parameters from modeling triggered by the minor amendment added as Appendix F to the permit;

· Updated outdated requirement language; · Updated Facility Description and Subject Item Descriptions; · Removed already completed requirements; · Moved flare control efficiency limit from COMG 4 to TREA 2 and added requirements to each EQUI

that vents to TREA that requires each EQUI to vent to TREA 2; · Added Appendix G with 40 CFR pt. 60, subp. A – General Provisions; and · Adjusted modeling language. A discussion of this can be found in this TSD in Section 3.3.

2. Regulatory and/or statutory basis

2.1 New source review (NSR) The potential emissions from the modifications are not subject to NSR as shown in Table 3 because the potential to emit of the facility does not constitute a major source; therefore, this permit action is not subject to NSR. REG receives process steam from the neighboring POET bio-refining Glenville East (POET) ethanol plant. This relationship was evaluated for permit number 04700061-003. It was determined that these were two


separate sources. Please see the TSD to permit number 04700061-003 for the detailed analysis of this determination.

2.2 Part 70 permit program The permit carries forward limits on the facility such that it is a nonmajor source under the Part 70 permit program.

2.3 New source performance standards (NSPS) The Permittee has stated that no New Source Performance Standards (NSPS) apply to the operations at this facility due to the increase in biodiesel production. The proposed boiler (EQUI 43) is subject to 40 CFR pt. 60, subp. Dc – Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units (NSPS Dc). NSPS Dc applicability is based on the maximum design heat input capacity and the date that the steam generating unit commenced construction, modification or reconstruction. NSPS Dc applies if the steam generating unit meets the following criteria:

· Commenced construction, modification, or reconstruction after June 9, 1989, as stated in 40 CFR §60.40c(a); and

· Maximum design heat input capacity of 100 MMBtu/hr or less, but greater than or equal to 10 MMBtu, as stated in 40 CFR §60.40c(a).

Construction has not commenced on the proposed boiler, and the boiler will have a maximum design heat input capacity of 33.5 MMBtu; therefore, it meets both of these criteria and is subject to 40 CFR pt. 60, subp. Dc. The permit allows the proposed boiler to burn only natural gas. Therefore, it is only subject to the recordkeeping requirements for fuel records.

2.4 National emission standards for hazardous air pollutants (NESHAP)

The facility has accepted limits on biodiesel production and methanol emissions such that it is an area source under 40 CFR pt. 63. Thus, no major source NESHAPs apply. In addition, the Permittee has stated that no area source NESHAPs apply to the facility. The proposed Boiler (EQUI 43) is not subject to 40 CFR pt. 63, subp. JJJJJJ – National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources. This Boiler is not subject to 40 CFR pt. 63, subp. JJJJJJ as described in 40 CFR 63.11195 because it meets the definition of a gas-fired boiler as defined in 40 CFR 63.11237.

2.6 Environmental review and air emissions risk analysis (AERA) The proposed increase in biodiesel production does not require an Environmental Assessment Worksheet (EAW).

The proposed increase of the biodiesel production does not require an EAW because the increase of feedstock is below the 25,000 dry tons per year threshold to prepare an EAW under Minn. R. 4410.4300, subp. 5(A). The proposed biodiesel production increase equates to 22,050 dry tons per year of feedstock. (Note: the density of biodiesel is 7.35 lb/gal)

If the facility proposes an additional increase to the biodiesel production limit, the sum of that increase and the increase from this permit action will need to be evaluated for an EAW. This comparison will ensure that production increases that do not require an EAW individually will be evaluated in a way to avoid circumventing the requirement to conduct an EAW.


Previously, an EAW was conducted in 2015 for an increase to the maximum biodiesel production capacity of the facility. Please see the TSD for permit No. 04700061-003 for a detailed explanation of the EAW and the reason it was required.

2.7 Minnesota state rules Portions of the facility are subject to the following Minnesota Standards of Performance:

· Minn. R. 7011.0515 Standards of Performance for New Indirect Heating Equipment · Minn. R. 7011.0715 Standards of Performance for Post-1969 Industrial Process Equipment

Table 6. Regulatory overview of units affected by the modification/permit amendment

Subject item*

Applicable Regulations and Limits Monitoring

Rationale for Regulation Applicability and Discussion of Monitoring

COMG 4 (Facility Limits)

Production <= 44.0 million gallons per year 12-month rolling sum. The 12-month Rolling Sum of biodiesel shall be calculated by the 15th day of each month as described later in this permit. This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. [Minn. R. 4410.4300, Minn. R. 7007.0800, subp. 2]

Daily recordkeeping of biodiesel production and monthly calculation of 12-month rolling sum of biodiesel produced

This limit ensures the facility’s increase use of biomass is less than the threshold that requires an EAW. See section 2.6 of this TSD for a detailed explanation. Daily production records and monthly calculation of the 12-month rolling sum is sufficient to demonstrate compliance with this limit. The language 'This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act' refers to permit requirements that are established only under state law and are not established under or required by the federal Clean Air Act. The language is to clarify the distinction between permit conditions that are required by federal law and those that are required only under state law. State law-only requirements are not enforceable by the EPA or by citizens under the federal Clean Air Act, but are fully enforceable by the MPCA and citizens under provisions of state law.

EQUI 31 (Biodiesel Loadout)

Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas [Minn. R. 7011.0715, subp. 1(A)] Opacity <= 20 percent opacity. [Minn. R. 7011.0715, subp. 1(B)]

None The construction of the Biodiesel Loadout equipment began after July 9, 1969, and the unit meets the definition of industrial process equipment under Minn. R. 7011.0700. It is subject to the state standards of performance for post-1969 industrial process equipment. These include standards for PM and opacity. This unit does not emit particulate matter. Therefore, it is highly unlikely that this unit could violate the applicable requirements.


Subject item*

Applicable Regulations and Limits Monitoring

Rationale for Regulation Applicability and Discussion of Monitoring

EQUI 37 (Water Absorber)


None The construction of the Water Absorber began after July 9, 1969, and the unit meets the definition of industrial process equipment under Minn. R. 7011.0700. It is subject to the state standards of performance for post-1969 industrial process equipment. These include standards for PM and opacity. This unit does not emit particulate matter. Therefore, it is highly unlikely that this unit could violate the applicable requirements.

EQUI 38 (Deacidification System)


None The construction of the Deacidification System began after July 9, 1969, and the unit meets the definition of industrial process equipment under Minn. R. 7011.0700. It is subject to the state standards of performance for post-1969 industrial process equipment. These include standards for PM and opacity. This unit does not emit particulate matter. Therefore, it is highly unlikely that this unit could violate the applicable requirements.

EQUI 43 (Boiler) Permitted Fuels: The Permittee shall burn only natural gas. [Minn. R. 7007.0800, subp. 2]

Recordkeeping: Monthly Fuel records

This unit is only allowed to burn natural gas. Monthly fuel records are required per 40 CFR §60.48c(g).

EQUI 48 (Biodiesel Distillation)


None The construction of the Biodiesel Distillation unit began after July 9, 1969, and the unit meets the definition of industrial process equipment under Minn. R. 7011.0700. It is subject to the state standards of performance for post-1969 industrial process equipment. These include standards for PM and opacity. This unit does not emit particulate matter. Therefore, it is highly unlikely that this unit could violate the applicable requirements.

EQUI 55 (Acidulation)


None The construction of the Acidulation unit began after July 9, 1969, and the unit meets the definition of industrial process equipment under Minn. R. 7011.0700. It is subject to the state standards of performance for post-1969 industrial process equipment. These include standards for PM and opacity. This unit does not emit particulate matter. Therefore, it is highly unlikely that this unit could violate the applicable requirements.

*Location of the requirement in the permit (e.g., EQUI 1, STRU 2,etc.). 3. Technical information

3.1 Calculations of potential to emit


Attachment 1 to this TSD contains detailed spreadsheets and supporting information prepared by the MPCA and the Permittee. For PTE calculation purposes, emissions from COMG 4 (EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 58, EQUI 61, STRU 1, and TREA 2) were calculated on a unit by unit basis.

3.1.1 Vacuum Pump (EQUI 39) The calculations use an emission factor of 1.18 lb/hr based on a biodiesel plant with a maximum capacity of 12 million gallons per year. Permit action 04700061-003 scaled this emission factor up to a maximum capacity of 38 million gallons per year, which resulted in an emission factor of 3.73 lb/hr. The calculations for the production increase to 44 million gallons per year multiply the 3.73 lb/hr emission factor by (44/38) to scale this up to the new production rate.

3.1.2 Transesterification Reactors (EQUI 45)

Emissions from this process tank was calculated for permit action 04700061-003 using the EPA TANKS software, version 4.09D. The calculations for the proposed production increase multiply the previous emission factor by (44/38) to scale this value up from a biodiesel production of 38 million gallons per year to 44 million gallons per year.

3.1.3 Acidulation (EQUI 55) A method for estimating emissions from the acidulation process has not been developed. If there are emissions from this process, they are controlled by the flare.

3.1.4 Deacidification System (EQUI 38) Permit action 04700061-003 calculated the emissions for deacidification using the ideal gas law and assuming an ethanol concentration of 1000 ppm. The calculations for the production increase to 44 million gallons per year multiply the emission factor by (44/38) to scale this up to the new production rate.

3.1.5 Biodiesel Distillation (EQUI 48) Permit action 04700061-003 calculated emissions from biodiesel distillation using the ideal gas law and chemical engineering software by Pfaudler Engineered Systems. The inputs to this program are not public data. Ted West, the General Manager of REG (legally responsible official), certified that the values obtained for VOC and methanol emissions are correct. The calculations for the production increase to 44 million gallons per year multiply the emission factor by (44/38) to scale this up to the new production rate.

3.1.6 Water Absorber (EQUI 37) Permit action 04700061-003 calculated the emissions for the water absorber using the ideal gas law and assuming a methanol concentration of 50 ppm. The calculations for the production increase to 44 million gallons per year multiple the emission factor by (44/38) to scale this up to the new production rate.

3.1.7 Biodiesel Loadout (EQUI 31) Emissions from this process tank were calculated for permit action 04700061-003 using the EPA TANKS software, version 4.09D. The calculations for the proposed production increase multiply the previous emission factor by (44/38) to scale this value up from a biodiesel production of 38 million gallons per year to 44 million gallons per year.

3.1.8 Cooling Towers (EQUI 54 and EQUI 60)


The PM, PM10, and PM2.5 emissions for the cooling towers have reduced due to a change in the maximum total dissolved solids (TDS) value. The calculations from Permit No. 04700061-003 used a TDS value of 4000 ppm from a similar biodiesel facility with a production of 12 million gallons per year. An updated maximum TDS value of 1474 was used by REG due to site-specific measurements. REG obtained conductivity measurements for their cooling towers in 2015 from Nalco and provided updated calculations with the justification for the updated calculations via email from Julie Ingoli at REG Albert Lea LLC to Cynthia Schafer at MPCA on 04/22/2015. These updated calculations were provided in a certified application that was received by the MPCA on 04/23/2015. The TSD for Permit No. 04700061-003 contains an explanation for the new TDS value and how it was obtained from the measured conductivity value. The original calculations used the Canada cooling tower methodology to calculate the PM, PM10, and PM2.5 emissions. However, MPCA conditionally approved REG’s modeling protocol with one condition being the use of the New Mexico method for estimating cooling tower particulate emissions. The emissions calculations have been updated to reflect the New Mexico method for estimating cooling tower particulate emissions to remain consistent with the modeling emission calculations. The New Mexico Environment Department Air Quality Bureau Technical Memo on Calculating TSD, PM-10, and PM-2.5 from Cooling Towers is attachment 5 to this TSD. This method changed the percentage of PM2.5 from 0.2% to 0.36% and the PM10 from 50% to 79%. The methanol calculations use the ratio of the new biodiesel production rate to the production rate of the emission factor. This is a ratio of (44/12) since the emission factor is from a similar facility with a production capacity of 12 million gallons per year.

3.1.9 Boiler (EQUI 43) The calculations for the proposed 33.5 mmBtu/hr boiler use emission factors for natural gas combustion from AP-42 Chapter 1.4 and 40 CFR pt. 98, subp. A. A factor of 1,020 was used to convert emission factors from lb/MMscf to lb/MMBtu.

3.1.10 Combustion Emissions (EQUI 32, EQUI 59, and TREA 2) The calculations for the combustion emissions associated with the flare burner and hot oil heaters are based on the maximum heat input; therefore, the potential emissions associated with these units did not change due to this modification. Individual HAPs from AP-42 Chapter 1.4 listed for TREA 2, EQUI 32, and EQUI 59.

3.1.11 Tanks (EQUI 34, EQUI 49, EQUI 58, and EQUI 61)

Emissions from storage tanks were calculated using the EPA Tanks software, version 4.09D.

REG used methanol as a surrogate for sodium methylate for the TANKS software because sodium methylate was not a substance listed in TANKS software. This is a conservative method because methanol has a higher vapor pressure than sodium methylate.

3.1.12 Insignificant Activity Tanks

Emissions from the insignificant activity tanks were calculated using the EPA Tanks software, version 4.09D for the tanks that have the potential to emit any methanol. The insignificant activity tanks include the glycerin tank and the various biodiesel distillation, bottoms, and product tanks.

3.2 Dispersion modeling


Per MPCA policy, as permitted in Permit No. 04700061-003, the facility triggered the requirement to complete equivalent or better dispersion (EBD) modeling for PM10 and PM2.5 because the addition of the proposed boiler required a minor amendment. Per MPCA practice, a table of the modeled parameters has been added to the permit as an appendix (Appendix F). Other than the requirement to operate the flare (TREA 2), the parameters listed in Appendix F of the permit describe the operation of the facility at maximum capacity. In other words, the flow rates and temperatures listed in Appendix F represent the minimum parameters at the maximum emission rates. The MPCA does not require any specific compliance demonstration with these parameters because they are worst-case conditions. The purpose of listing the parameters in the permit appendix is to provide a benchmark for determining when additional modeling is required. Preliminary analysis modeling for PM10 and PM2.5 showed that emission increases from the proposed boiler resulted in modeled concentrations below the significant impact levels (SILs) except for 24-hour PM2.5, which resulted in a modeled concentration above the SIL; therefore, refined modeling was only required for 24-hour PM2.5. See Table 7 for preliminary analysis modeling results. Table 7. REG Preliminary Analysis Modeling Results

Pollutant Averaging Period

SIL (µg/m3)

Modeled Concentration

(µg/m3)

Requires Refined

Modeling? PM10 24-hour 5 4.360 No

PM2.5 24-hour 1.2 3.603 Yes Annual 0.3 0.283 No

*The PM10 Annual standard is a Minnesota Ambient Air Quality Standard only Results of the refined modeling for 24-hour PM2.5 are shown in Table 8. The results indicate modeled 24-hour PM2.5 NAAQS/MAAQS exceedances; however, the results show that at the exceeding receptors, the highest contributions from REG were below the SIL. Table 8. Refined Modeling Results for 24-hour PM2.5

Pollutant Averaging Period

NAAQS (µg/m3)

SIL (µg/m3)

Total Modeled Concentration

(includes background and nearby sources)

(µg/m3)

Percent of NAAQS

(%)

Background (µg/m3)

REG Maximum Contribution Toward

Modeled Exceedances

(µg/m3) and (% of SIL)

PM2.5 24-hour 35 1.2 46.57 133.0 19 1.17 (97.5%)

The only other source modeled as a nearby source in REG’s refined modeling for PM2.5 was POET. Looking at the differences between the total modeled concentrations, background, and REG’s maximum contribution toward modeled exceedances in Table 8, POET is shown to be the major contributor to the modeled 24-hour PM2.5 exceedances.

3.3 Modeling Language Permit No. 04700061-003 established modeling language for PM10 and PM2.5 so that an EBD analysis was required anytime a change is made that affects the emission rates or modeling parameters for PM10 or PM2.5. This was based on the 2015 modeling required by an EAW that showed NAAQS exceedances for PM10 and PM2.5 24-hour and annual. REG’s culpability analysis showed that they were not culpable for these exceedances and that POET, the only listed nearby source, was the major contributor. However, this


stringent modeling language was chosen on a case-by-case basis due to the high NAAQS exceedances shown in the modeling. POET recently modeled and achieved compliance with the NAAQS and MAAQS for PM10 and PM2.5 for both 24-hour and annual. Based on POET’s modeling results and REG’s culpability analysis, REG’s modeling language is being adjusted. The updated PM2.5 and PM10 24-hour and annual modeling language will require an EBD analysis only for a major or moderate amendment. REG is a relatively small contributor to the PM10 and PM2.5 concentration in the area and REG does not regularly make changes that alter PM2.5 or PM10 emissions. The decision to remove minor amendments in the modeling language was based on REG’s process. REG does not have emissions from material handling and the facility does not make frequent changes resulting in changes to PM2.5 or PM10 emissions.

3.4 Schedule of Compliance (SoC)

REG has been allowed to operate at a biodiesel production limit of 44 million gallons as of December 13, 2016 through a Schedule of Compliance (SoC) between REG and the MPCA. Attachment 4 to this TSD contains the SoC. REG agreed to five requirements as part of this SoC. These requirements from part 6 of the SoC are as follows:

a. Within 20 days of receipt of this Agreement, the Regulated Party agrees to submit complete documentation, and a statement certifying under penalty of law, demonstrating that no environmental review process under state or federal law is necessary prior to increasing the currently-permitted biodiesel production limit;

b. Within 30 days of receipt of this Agreement, the Regulated Party agrees to submit a complete major permit amendment application to increase the currently permitted biodiesel production limit;

c. The Regulated Party agrees to operate its Facility in compliance with the major permit amendment application required under Part b above, including all associated recordkeeping requirements, and to keep records sufficient to demonstrate compliance until the MPCA issues a new air emissions permit;

d. On or before April 1, 2017, the Regulated Party agrees to replace six existing electric motors at the Facility. The electric motors to be replaced are the Cooling Tower 1, Cooling Tower 2, Cooling Tower 3, Thermal Fluid 1, Thermal Fluid 2, and Thermal Fluid 3 motors; and

e. On or before May 1, 2017, the Regulated Party agrees to submit a statement and records, such as purchase records, to certify and demonstrate that the replacement of the engines from the installation of the six energy-efficient electric motors. The quantification shall include megawatt hours and carbon dioxide emissions.

At the time of this permit, REG has completed these requirements and has not violated the SoC. Documentation for items a, d, and e listed above can be found in Attachment 4 to this TSD.

3.5 Monitoring

In accordance with the Clean Air Act, it is the responsibility of the owner or operator of a facility to have sufficient knowledge of the facility to certify that the facility is in compliance with all applicable requirements.

In evaluating the monitoring included in the permit, the MPCA considered the following:

· The likelihood of the facility violating the applicable requirements. · Whether add-on controls are necessary to meet the emission limits. · The variability of emissions over time.


· The type of monitoring, process, maintenance, or control equipment data already available for the emission unit.

· The technical and economic feasibility of possible periodic monitoring methods. · The kind of monitoring found on similar units elsewhere.

Table 6 above summarizes the monitoring requirements associated with these amendments.

3.6 Insignificant activities

REG Albert Lea LLC has several operations that are classified as insignificant activities under the MPCA’s permitting rules. These are listed in Appendix A to the permit. No changes to insignificant activities were made as part of this permit action.

3.7 Permit organization This permit action marks the transition of REG’s air quality permit from MPCA’s Delta permitting system to the Tempo permitting system. The MPCA migrated data from Delta – including the description of the facility (e.g., emission units, stack/vents, and groups) and permit text – to Tempo. In the migration, items were renamed and are now identified differently.

In this permit, federal requirements from NSPS are included in two different formats. The requirements for 40 CFR pt. 60, subp. Dc, 40 CFR pt. 60, subp. NNN, 40 CFR pt. 60, subp. RRR, and 40 CFR pt. 60, subp. VVa are incorporated into the permit as individual permit requirements, which has historically been MPCA’s standard practice. However, the associated General Provisions in 40 CFR pt. 60, subp. A are included in a different way. For these rules, limits, and submittal/actions are included individually in the permit like the other standards. For the remaining portions of the rule, a requirement in Section 5 of the permit lists the citations of all of the applicable parts of the standard along with a reference to the permit appendix where the full text of the standard is included. 40 CFR pt. 63, subp. A is included in Appendix G.

3.8 Comments received

No comments were received from the public during the public notice period. Public Notice Period: January 20, 2018 – February 20, 2018

4. Permit fee assessment Attachment 3 to this TSD contains the MPCA’s assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes two permit applications, both received after the effective date of the rule (July 1, 2009). The major amendment includes the increase to REG’s biodiesel production limit. The biodiesel production limit is a limit to avoid an EAW, so this is a chargeable activity. The minor amendment is for the installation of a 33.5 mmBtu/hr boiler. The boiler incorporated 40 CFR pt. 60, subp. Dc, however this was an existing standard that applied to the facility and is not a chargeable activity. The minor amendment also included PM2.5 refined modeling, which is a chargeable activity.

5. Conclusion Based on the information provided by REG Albert Lea LLC the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 04700061-101 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff members on permit team: Tyler K. Johnson (permit engineer)

Adriane Lorsung (peer reviewer)


Curtis Stock (compliance) Andy Place (compliance) Jenna Ness (enforcement) Daniel Dix (Modeling) Joey Handtmann (data coordinator) Beckie Olson (permit writing assistant) Laurie O'Brien (administrative support)

TEMPO360 Activities: Major Amendment (IND20160003), Minor Amendment (IND20160004)

Attachments: 1. PTE summary and emissions increase calculation spreadsheets

2. Subject item inventory and facility requirements 3. Points calculator 4. Schedule of Compliance with associated documentation 5. New Mexico Environment Department Air Quality Bureau Technical Memorandum: Calculating TSP,

PM-10 and PM-2.5 from Cooling Towers 6. TANKS Reports

Attachment 1 – PTE summary and emissions increase calculation spreadsheets

Technical Support Document Facility Name:Permit Number:

REG Albert Lea LLC04700061-101

Total Facility Emissions Summary

Renewable Energy Group Albert Lea, LLC

Albert Lea, MN

Permit Allowable Potential to Emit (PTE) Summary

Pollutant

COMG 4

Emissions1

(tpy)

EQUI 31

Emissions2

(tpy)

EQUI 32

Emissions

(tpy)

EQUI 34

Emissions2

(tpy)

EQUI 37

Emissions2

(tpy)

EQUI 38

Emissions

(tpy)

EQUI 39

Emissions2

(tpy)

SO2 ‐ ‐ 0.046 ‐ ‐ ‐ ‐NOx ‐ ‐ 7.73 ‐ ‐ ‐ ‐CO ‐ ‐ 6.49 ‐ ‐ ‐ ‐CO2e ‐ ‐ 9,226 ‐ ‐ ‐ ‐PM ‐ ‐ 0.59 ‐ ‐ ‐ ‐PM10 ‐ ‐ 0.59 ‐ ‐ ‐ ‐PM2.5 ‐ ‐ 0.59 ‐ ‐ ‐ ‐VOC ‐ 0.50 0.43 0.02 0.025 7.25 0.38Single HAP (Methanol) 1.25 * ‐ * * ‐ *Total HAPs ‐ 0.50 0.15 0.02 0.025 0.00 0.38

Notes:1) COMG 4 consists of EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 55, EQUI 58, and EQUI 61.2) A value of * means that emission rate is included in the COMG 4 value for the same pollutant.



Albert Lea, MN


Pollutant

SO2

NOx

CO

CO2e

PM

PM10

PM2.5

VOCSingle HAP (Methanol)Total HAPs

Notes:

EQUI 43

Emissions

(tpy)

EQUI 45

Emissions2

(tpy)

EQUI 48

Emissions2

(tpy)

EQUI 49

Emissions

(tpy)

EQUI 54

Emissions

(tpy)

EQUI 55

Emissions2

(tpy)

EQUI 58

Emissions2

(tpy)

EQUI 59

Emissions

(tpy)

0.086 ‐ ‐ ‐ ‐ ‐ ‐ 0.046

14.39 ‐ ‐ ‐ ‐ ‐ ‐ 7.73

12.08 ‐ ‐ ‐ ‐ ‐ ‐ 6.49

17,365 ‐ ‐ ‐ ‐ ‐ ‐ 9226

1.09 ‐ ‐ ‐ 0.97 ‐ ‐ 0.59

1.09 ‐ ‐ ‐ 0.76 ‐ ‐ 0.59

1.09 ‐ ‐ ‐ 0.0035 ‐ ‐ 0.59

0.79 0.052 0.12 ‐ 3.01 0.00 0.03 0.43‐ * * ‐ 3.01 * * ‐

0.27 0.052 0.12 0.39 3.01 0.00 0.03 0.15

1) COMG 4 consists of EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 55, EQUI 58, and EQUI 61.2) A value of * means that emission rate is included in the COMG 4 value for the same pollutant.



Albert Lea, MN


Pollutant

SO2

NOx

CO

CO2e

PM

PM10

PM2.5

VOCSingle HAP (Methanol)Total HAPs

Notes:

EQUI 60

Emissions

(tpy)

EQUI 61

Emissions2

(tpy)

FUGI 1

Emissions

(tpy)

TREA 2

Emissions

(tpy)

Road

Emissions

(tpy)

IA Tanks

Emissions

(tpy)

Total Facility

Emissions

(tpy)

‐ ‐ ‐ 0.0052 ‐ ‐ 0.184

‐ ‐ ‐ 0.60 ‐ ‐ 30.44

‐ ‐ ‐ 3.24 ‐ ‐ 28.31

‐ ‐ ‐ 1,025 ‐ ‐ 36,842

0.52 ‐ ‐ 0.065 29.06 ‐ 32.88

0.41 ‐ ‐ 0.065 8.41 ‐ 11.92

0.0019 ‐ ‐ 0.065 0.89 ‐ 3.23

1.59 0.01 2.79 0.66 ‐ 0.22 18.281.59 * 2.65 ‐ ‐ 0.03 8.541.59 0.01 2.79 0.016 0.00 0.03 9.53

1) COMG 4 consists of EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 55, EQUI 58, and EQUI 61.2) A value of * means that emission rate is included in the COMG 4 value for the same pollutant.

Facility‐Wide Emissions


Albert Lea, MN

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission

Rate (tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Criteria Pollutants

SO2 ‐ ‐ ‐ ‐ ‐ ‐ 1.06E‐02 4.64E‐02 4.64E‐02NOx ‐ ‐ ‐ ‐ ‐ ‐ 1.76E+00 7.73 7.73CO ‐ ‐ ‐ ‐ ‐ ‐ 1.48 6.49 6.49Lead ‐ ‐ ‐ ‐ ‐ ‐ 8.82E‐06 3.86E‐05 3.86E‐05Total PM ‐ ‐ ‐ ‐ ‐ ‐ 0.134 0.59 0.59

PM10 ‐ ‐ ‐ ‐ ‐ ‐ 0.134 0.59 0.59

PM2.5 ‐ ‐ ‐ ‐ ‐ ‐ 0.134 0.59 0.59

VOC ‐ ‐ ‐ 0.10 25.16 0.50 9.71E‐02 0.43 0.43

Greenhouse Gases

CO2 ‐ ‐ ‐ ‐ ‐ ‐ 2,104 9,216 9,216

CH4 ‐ ‐ ‐ ‐ ‐ ‐ 3.96E‐02 0.17 0.17

CH4 ‐ CO2e ‐ ‐ ‐ ‐ ‐ ‐ 9.90E‐01 4.3362 4.3362

N2O ‐ ‐ ‐ ‐ ‐ ‐ 3.96E‐03 0.017 0.017

N2O ‐ CO2e ‐ ‐ ‐ ‐ ‐ ‐ 1.18E+00 5.17 5.17

CO2e ‐ ‐ ‐ ‐ ‐ ‐ 2,106 9,226 9,226

Federal HAPsMethanol ‐ ‐ 1.25 0.10 25.16 * ‐ ‐ ‐2‐Methylnaphthalene ‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐07 1.86E‐06 1.86E‐063‐Methylchloranthene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐077,12‐Dimethylbenz(a)anthracene ‐ ‐ ‐ ‐ ‐ ‐ 2.82E‐07 1.24E‐06 1.24E‐06Acenaphthene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Acenaphthylene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Anthracene ‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐08 1.86E‐07 1.86E‐07Benz(a)anthracene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Benzene ‐ ‐ ‐ ‐ ‐ ‐ 3.71E‐05 1.62E‐04 1.62E‐04Benzo(a)Pyrene ‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08Benzo(b)fluoranthene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Benzo(g,h,i)perylene ‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08Benzo(k)fluoranthene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Chrysene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Dibenzo(a,h)anthracene ‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08Dichlorobenzene ‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐05 9.28E‐05 9.28E‐05Fluoranthene ‐ ‐ ‐ ‐ ‐ ‐ 5.29E‐08 2.32E‐07 2.32E‐07Flourene ‐ ‐ ‐ ‐ ‐ ‐ 4.94E‐08 2.16E‐07 2.16E‐07Formaldehyde ‐ ‐ ‐ ‐ ‐ ‐ 1.32E‐03 5.80E‐03 5.80E‐03Hexane ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐02 0.14 0.14Hydrochloric Acid ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Indeno(1,2,3‐cd)pyrene ‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07Naphthalene ‐ ‐ ‐ ‐ ‐ ‐ 1.08E‐05 4.71E‐05 4.71E‐05Phenanthrene ‐ ‐ ‐ ‐ ‐ ‐ 3.00E‐07 1.31E‐06 1.31E‐06Pyrene ‐ ‐ ‐ ‐ ‐ ‐ 8.82E‐08 3.86E‐07 3.86E‐07

Metals (HAPs)Arsenic ‐ ‐ ‐ ‐ ‐ ‐ 3.53E‐06 1.55E‐05 1.55E‐05Beryllium ‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐07 9.28E‐07 9.28E‐07Cadmium ‐ ‐ ‐ ‐ ‐ ‐ 1.94E‐05 8.50E‐05 8.50E‐05Chromium ‐ ‐ ‐ ‐ ‐ ‐ 2.47E‐05 1.08E‐04 1.08E‐04Cobalt ‐ ‐ ‐ ‐ ‐ ‐ 1.48E‐06 6.49E‐06 6.49E‐06Manganese ‐ ‐ ‐ ‐ ‐ ‐ 6.71E‐06 2.94E‐05 2.94E‐05Mercury ‐ ‐ ‐ ‐ ‐ ‐ 4.59E‐06 2.01E‐05 2.01E‐05Nickel ‐ ‐ ‐ ‐ ‐ ‐ 3.71E‐05 1.62E‐04 1.62E‐04Selenium ‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐07 1.86E‐06 1.86E‐06

Federal HAPsTotal 0.00 0.00 0.00 0.10 25.16 0.50 0.03 0.15 0.15

Notes:1) COMG 4 has a Methanol tpy limit and includes the following units: EQUI 31, EQUI 34, EQUI 37, EQUI 39, EQUI 45, EQUI 48, EQUI 55, EQUI 58, and EQUI 61.2) Values of * means that unit's emissions rate for that pollutant is included in the Permit Allowable Emission Rate (tpy) for the corresponding pollutant for COMG 4.

Pollutant

COMG 41

Facility Limits

EQUI 31

Biodiesel Loadout

EQUI 32

Hot Oil Heater #2



Albert Lea, MN

Criteria Pollutants

SO2

NOxCOLeadTotal PMPM10

PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e

Federal HAPsMethanol2‐Methylnaphthalene3‐Methylchloranthene7,12‐Dimethylbenz(a)anthraceneAcenaphtheneAcenaphthyleneAnthraceneBenz(a)anthraceneBenzeneBenzo(a)PyreneBenzo(b)fluorantheneBenzo(g,h,i)peryleneBenzo(k)fluorantheneChryseneDibenzo(a,h)anthraceneDichlorobenzeneFluorantheneFloureneFormaldehydeHexaneHydrochloric AcidIndeno(1,2,3‐cd)pyreneNaphthalenePhenanthrenePyrene

Metals (HAPs)ArsenicBerylliumCadmiumChromiumCobaltManganeseMercuryNickelSelenium

Federal HAPsTotal

Notes:1) COMG 4 has a Methanol tpy limit and includes2) Values of * means that unit's emissions rate fo

Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.0044 0.96 0.019 0.006 1.26 0.025 1.65 7.25 7.25

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.0044 0.96 * 0.006 1.26 * ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.00 0.96 0.019 0.01 1.26 0.025 0.00 0.00 0.00

EQUI 34

Fresh Methanol Tank 6

EQUI 37

Water Absorber

EQUI 38

Deacidification System



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

‐ ‐ ‐ 1.97E‐02 8.63E‐02 8.63E‐02 ‐ ‐ ‐‐ ‐ ‐ 3.28E+00 14.39 14.39 ‐ ‐ ‐‐ ‐ ‐ 2.76 12.08 12.08 ‐ ‐ ‐‐ ‐ ‐ 1.64E‐05 7.19E‐05 7.19E‐05 ‐ ‐ ‐‐ ‐ ‐ 0.25 1.09 1.09 ‐ ‐ ‐‐ ‐ ‐ 0.25 1.09 1.09 ‐ ‐ ‐‐ ‐ ‐ 0.25 1.09 1.09 ‐ ‐ ‐

0.086 18.92 0.38 1.81E‐01 0.79 0.79 0.0119 2.61 0.0522

‐ ‐ ‐ 3,941 17,262 17,262 ‐ ‐ ‐‐ ‐ ‐ 7.55E‐02 0.33 0.33 ‐ ‐ ‐‐ ‐ ‐ 1.89E+00 8.27 8.27 ‐ ‐ ‐‐ ‐ ‐ 7.23E‐02 0.32 0.32 ‐ ‐ ‐‐ ‐ ‐ 2.15E+01 94.31 94.31 ‐ ‐ ‐‐ ‐ ‐ 3,965 17,365 17,365 ‐ ‐ ‐

0.08637895 18.92 * ‐ ‐ ‐ 0.01192632 2.61 *‐ ‐ ‐ 7.88E‐07 3.45E‐06 3.45E‐06 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.25E‐07 2.30E‐06 2.30E‐06 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 7.88E‐08 3.45E‐07 3.45E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 6.90E‐05 3.02E‐04 3.02E‐04 ‐ ‐ ‐‐ ‐ ‐ 3.94E‐08 1.73E‐07 1.73E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 3.94E‐08 1.73E‐07 1.73E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 3.94E‐08 1.73E‐07 1.73E‐07 ‐ ‐ ‐‐ ‐ ‐ 3.94E‐05 1.73E‐04 1.73E‐04 ‐ ‐ ‐‐ ‐ ‐ 9.85E‐08 4.32E‐07 4.32E‐07 ‐ ‐ ‐‐ ‐ ‐ 9.20E‐08 4.03E‐07 4.03E‐07 ‐ ‐ ‐‐ ‐ ‐ 2.46E‐03 1.08E‐02 1.08E‐02 ‐ ‐ ‐‐ ‐ ‐ 0.06 0.26 2.59E‐01 ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ 5.91E‐08 2.59E‐07 2.59E‐07 ‐ ‐ ‐‐ ‐ ‐ 2.00E‐05 8.78E‐05 8.78E‐05 ‐ ‐ ‐‐ ‐ ‐ 5.58E‐07 2.45E‐06 2.45E‐06 ‐ ‐ ‐‐ ‐ ‐ 1.64E‐07 7.19E‐07 7.19E‐07 ‐ ‐ ‐

‐ ‐ ‐ 6.57E‐06 2.88E‐05 2.88E‐05 ‐ ‐ ‐‐ ‐ ‐ 3.94E‐07 1.73E‐06 1.73E‐06 ‐ ‐ ‐‐ ‐ ‐ 3.61E‐05 1.58E‐04 1.58E‐04 ‐ ‐ ‐‐ ‐ ‐ 4.60E‐05 2.01E‐04 2.01E‐04 ‐ ‐ ‐‐ ‐ ‐ 2.76E‐06 1.21E‐05 1.21E‐05 ‐ ‐ ‐‐ ‐ ‐ 1.25E‐05 5.47E‐05 5.47E‐05 ‐ ‐ ‐‐ ‐ ‐ 8.54E‐06 3.74E‐05 3.74E‐05 ‐ ‐ ‐‐ ‐ ‐ 6.90E‐05 3.02E‐04 3.02E‐04 ‐ ‐ ‐‐ ‐ ‐ 7.88E‐07 3.45E‐06 3.45E‐06 ‐ ‐ ‐

0.09 18.92 0.38 0.06 0.27 0.27 0.01 2.61 0.05

EQUI 39

Vacuum Pump (Biodiesel Process ‐ Pump)

EQUI 45

Transesterification Reactors

EQUI 43

Boiler



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ 0.221 0.97 0.97

‐ ‐ ‐ ‐ ‐ ‐ 0.174 0.76 0.76

‐ ‐ ‐ ‐ ‐ ‐ 0.000802 0.00351 0.00351

0.028 6.09 0.12 ‐ ‐ ‐ 0.688 3.01 3.01

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.02778947 6.09 * ‐ ‐ ‐ 0.688 3.01 3.01‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ 0.09 0.39 0.39 ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.03 6.09 0.12 0.09 0.39 0.39 0.69 3.01 3.01

EQUI 48

Biodiesel Distillation

EQUI 49

HCl Tank 4

EQUI 54

Cooling Tower 1



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

‐ ‐ ‐ ‐ ‐ ‐ 1.06E‐02 4.64E‐02 4.64E‐02‐ ‐ ‐ ‐ ‐ ‐ 1.76E+00 7.73 7.73‐ ‐ ‐ ‐ ‐ ‐ 1.48 6.49 6.49‐ ‐ ‐ ‐ ‐ ‐ 8.82E‐06 3.86E‐05 3.86E‐05‐ ‐ ‐ ‐ ‐ ‐ 0.13411765 0.59 0.59

‐ ‐ ‐ ‐ ‐ ‐ 0.13411765 0.59 0.59

‐ ‐ ‐ ‐ ‐ ‐ 0.13411765 0.59 0.59

0.00 0.00 0.00 0.006 1.26 0.025 9.71E‐02 0.43 0.43

‐ ‐ ‐ ‐ ‐ ‐ 2,104 9,216 9,216

‐ ‐ ‐ ‐ ‐ ‐ 3.96E‐02 0.17 0.17

‐ ‐ ‐ ‐ ‐ ‐ 9.90E‐01 4.3362 4.3362

‐ ‐ ‐ ‐ ‐ ‐ 3.96E‐03 0.0173448 0.0173448

‐ ‐ ‐ ‐ ‐ ‐ 1.18E+00 5.1687504 5.1687504

‐ ‐ ‐ ‐ ‐ ‐ 2106 9226 9226

0.00 0.00 * 0.006 1.26 * ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐07 1.86E‐06 1.86E‐06‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 2.82E‐07 1.24E‐06 1.24E‐06‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐08 1.86E‐07 1.86E‐07‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 3.71E‐05 1.62E‐04 1.62E‐04‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐08 9.28E‐08 9.28E‐08‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐05 9.28E‐05 9.28E‐05‐ ‐ ‐ ‐ ‐ ‐ 5.29E‐08 2.32E‐07 2.32E‐07‐ ‐ ‐ ‐ ‐ ‐ 4.94E‐08 2.16E‐07 2.16E‐07‐ ‐ ‐ ‐ ‐ ‐ 1.32E‐03 5.80E‐03 5.80E‐03‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐02 0.14 1.39E‐01

0.00 0.00 0.00 ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ 3.18E‐08 1.39E‐07 1.39E‐07‐ ‐ ‐ ‐ ‐ ‐ 1.08E‐05 4.71E‐05 4.71E‐05‐ ‐ ‐ ‐ ‐ ‐ 3.00E‐07 1.31E‐06 1.31E‐06‐ ‐ ‐ ‐ ‐ ‐ 8.82E‐08 3.86E‐07 3.86E‐07

‐ ‐ ‐ ‐ ‐ ‐ 3.53E‐06 1.55E‐05 1.55E‐05‐ ‐ ‐ ‐ ‐ ‐ 2.12E‐07 9.28E‐07 9.28E‐07‐ ‐ ‐ ‐ ‐ ‐ 1.94E‐05 8.50E‐05 8.50E‐05‐ ‐ ‐ ‐ ‐ ‐ 2.47E‐05 1.08E‐04 1.08E‐04‐ ‐ ‐ ‐ ‐ ‐ 1.48E‐06 6.49E‐06 6.49E‐06‐ ‐ ‐ ‐ ‐ ‐ 6.71E‐06 2.94E‐05 2.94E‐05‐ ‐ ‐ ‐ ‐ ‐ 4.59E‐06 2.01E‐05 2.01E‐05‐ ‐ ‐ ‐ ‐ ‐ 3.71E‐05 1.62E‐04 1.62E‐04‐ ‐ ‐ ‐ ‐ ‐ 4.24E‐07 1.86E‐06 1.86E‐06

0.00 0.00 0.00 0.006 1.26 0.025 0.03 0.15 0.15

EQUI 55

Acidulation

EQUI 58

Process Methanol Tank 7

EQUI 59

Hot Oil Heater #1



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate2

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.118 0.52 0.52 ‐ ‐ ‐ ‐ ‐ ‐0.0936 0.41 0.41 ‐ ‐ ‐ ‐ ‐ ‐0.000430 0.00189 0.00189 ‐ ‐ ‐ ‐ ‐ ‐0.363 1.59 1.59 0.0018 0.40 0.008 0.636 2.79 2.79

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.363 1.59 1.59 0.0018 0.40 * 0.636 2.79 2.65‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐

0.36 1.59 1.59 0.0018 0.40 0.008 0.64 2.79 2.79

FUGI 1

Equipment Leaks

EQUI 60

Cooling Tower 2

EQUI 61

Sodium Methylate Tank 8



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

1.18E‐03 5.15E‐03 5.15E‐03 ‐ ‐ ‐ ‐ ‐ ‐1.36E‐01 0.60 5.96E‐01 ‐ ‐ ‐ ‐ ‐ ‐0.74 3.24 3.24E+00 ‐ ‐ ‐ ‐ ‐ ‐

9.80E‐07 4.29E‐06 4.29E‐06 ‐ ‐ ‐ ‐ ‐ ‐0.01490196 0.07 6.53E‐02 22.35 29.06 29.06 ‐ ‐ ‐0.01490196 0.07 6.53E‐02 6.47 8.41 8.41 ‐ ‐ ‐0.01490196 0.07 6.53E‐02 0.69 0.89 0.89 ‐ ‐ ‐1.50E‐01 0.66 6.57E‐01 ‐ ‐ ‐ 0.05 0.22 0.22

234 1,024 1,024 ‐ ‐ ‐ ‐ ‐ ‐4.40E‐03 0.02 0.0193 ‐ ‐ ‐ ‐ ‐ ‐1.10E‐01 0.482 0.482 ‐ ‐ ‐ ‐ ‐ ‐4.40E‐04 0.00193 0.00193 ‐ ‐ ‐ ‐ ‐ ‐1.31E‐01 0.5743056 0.5743 ‐ ‐ ‐ ‐ ‐ ‐

234 1025 1,025 ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ 0.01 0.03 0.034.71E‐08 2.06E‐07 2.06E‐07 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.14E‐08 1.37E‐07 1.37E‐07 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐4.71E‐09 2.06E‐08 2.06E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐4.12E‐06 1.80E‐05 1.80E‐05 ‐ ‐ ‐ ‐ ‐ ‐2.35E‐09 1.03E‐08 1.03E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐2.35E‐09 1.03E‐08 1.03E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐2.35E‐09 1.03E‐08 1.03E‐08 ‐ ‐ ‐ ‐ ‐ ‐2.35E‐06 1.03E‐05 1.03E‐05 ‐ ‐ ‐ ‐ ‐ ‐5.88E‐09 2.58E‐08 2.58E‐08 ‐ ‐ ‐ ‐ ‐ ‐5.49E‐09 2.40E‐08 2.40E‐08 ‐ ‐ ‐ ‐ ‐ ‐1.47E‐04 6.44E‐04 6.44E‐04 ‐ ‐ ‐ ‐ ‐ ‐3.53E‐03 1.55E‐02 1.55E‐02 ‐ ‐ ‐ ‐ ‐ ‐

‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐3.53E‐09 1.55E‐08 1.55E‐08 ‐ ‐ ‐ ‐ ‐ ‐1.20E‐06 5.24E‐06 5.24E‐06 ‐ ‐ ‐ ‐ ‐ ‐3.33E‐08 1.46E‐07 1.46E‐07 ‐ ‐ ‐ ‐ ‐ ‐9.80E‐09 4.29E‐08 4.29E‐08 ‐ ‐ ‐ ‐ ‐ ‐

3.92E‐07 1.72E‐06 1.72E‐06 ‐ ‐ ‐ ‐ ‐ ‐2.35E‐08 1.03E‐07 1.03E‐07 ‐ ‐ ‐ ‐ ‐ ‐2.16E‐06 9.45E‐06 9.45E‐06 ‐ ‐ ‐ ‐ ‐ ‐2.16E‐06 9.45E‐06 9.45E‐06 ‐ ‐ ‐ ‐ ‐ ‐1.65E‐07 7.21E‐07 7.21E‐07 ‐ ‐ ‐ ‐ ‐ ‐7.45E‐07 3.26E‐06 3.26E‐06 ‐ ‐ ‐ ‐ ‐ ‐5.10E‐07 2.23E‐06 2.23E‐06 ‐ ‐ ‐ ‐ ‐ ‐4.12E‐06 1.80E‐05 1.80E‐05 ‐ ‐ ‐ ‐ ‐ ‐4.71E‐08 2.06E‐07 2.06E‐07 ‐ ‐ ‐ ‐ ‐ ‐

0.00 0.02 0.02 0.00 0.00 0.00 0.01 0.03 0.03

TREA 2

Flare Pilot BurnerRoad Emissions ‐ IA? IA Tanks



Albert Lea, MN

Criteria Pollutants

SO2


PM2.5

VOC

Greenhouse Gases

CO2

CH4

CH4 ‐ CO2e

N2O

N2O ‐ CO2e

CO2e



Federal HAPsTotal


Pollutant Permit

Allowable

Emission

Rate

(lb/hr)

Unrestricted

Emission Rate

(tpy)

Permit

Allowable

Emission

Rate

(tpy)

0.042 0.18 0.18

6.95 30.44 30.446.46 28.31 28.31

3.50E‐05 1.54E‐04 1.54E‐0423.23 32.88 32.88

7.27 11.92 11.92

1.22 3.23 3.23

4.16 73.81 18.28

8,383.38 36,719.19 36,719.19

0.16 0.70 0.70

3.98 17.43 17.43

0.081 0.35 0.35

24.02 105.22 105.22

8,411.38 36,841.84 36,841.84

1.94 64.08 8.541.68E‐06 7.37E‐06 7.37E‐061.26E‐07 5.53E‐07 5.53E‐071.12E‐06 4.91E‐06 4.91E‐061.26E‐07 5.53E‐07 5.53E‐071.26E‐07 5.53E‐07 5.53E‐071.68E‐07 7.37E‐07 7.37E‐071.26E‐07 5.53E‐07 5.53E‐071.47E‐04 6.45E‐04 6.45E‐048.41E‐08 3.68E‐07 3.68E‐071.26E‐07 5.53E‐07 5.53E‐078.41E‐08 3.68E‐07 3.68E‐071.26E‐07 5.53E‐07 5.53E‐071.26E‐07 5.53E‐07 5.53E‐078.41E‐08 3.68E‐07 3.68E‐078.41E‐05 3.68E‐04 3.68E‐042.10E‐07 9.21E‐07 9.21E‐071.96E‐07 8.60E‐07 8.60E‐075.26E‐03 2.30E‐02 2.30E‐021.26E‐01 5.53E‐01 5.53E‐019.00E‐02 3.94E‐01 3.94E‐011.26E‐07 5.53E‐07 5.53E‐074.28E‐05 1.87E‐04 1.87E‐041.19E‐06 5.22E‐06 5.22E‐063.50E‐07 1.54E‐06 1.54E‐06

1.40E‐05 6.14E‐05 6.14E‐058.41E‐07 3.68E‐06 3.68E‐067.71E‐05 3.38E‐04 3.38E‐049.75E‐05 4.27E‐04 4.27E‐045.89E‐06 2.58E‐05 2.58E‐052.66E‐05 1.17E‐04 1.17E‐041.82E‐05 7.98E‐05 7.98E‐051.47E‐04 6.45E‐04 6.45E‐041.68E‐06 7.37E‐06 7.37E‐06

2.16E+00 6.51E+01 9.53E+00

Total Facility

Facility‐Wide Potential GHG EmissionsRenewable Energy Group Albert Lea, LLCAlbert Lea, MN

Flare

Burner

(TREA 2)

Hot Oil

Heater 1

(EQUI 59)

Hot Oil

Heater 2

(EQUI 32)

Temporary

Boiler

(EQUI 43)

Global

Warming

Potential1

Total

Mass,

tpy

Total

CO2e,

tpyCarbon Dioxide 1,024 9,216 9,216 17,262 1 36,719 36,719Methane 0.019 0.17 0.17 0.33 25 0.70 17Nitrous Oxide 0.002 0.02 0.02 0.32 298 0.35 105

Total: 36,720 36,842

Notes:1) Global warming potential from 40 CFR Part 98 Subpart A Table A‐1.

GHG Potential Emissions by Emission Point (tpy)

Biodiesel Loadout Potential Emissions (EQUI 31)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

Proposed Biodiesel Limitation 44,000,000 gal/yearCurrent Biodiesel Limitation 38,000,000 gal/yearControl Efficiency 98%Hours of Operation 8,760 hours/year

Pollutant

Previous

Uncontrolled

Emission Rate1

(lb/hr)

Uncontrolled

Emission Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions2

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 4.96 4.96 25.16 0.50Methanol 4.96 4.96 25.16 0.50

Total HAPs 4.96 25.16 0.50

Notes:

1) Emission rate from Permit No. 04700061‐003 for 38 MMGal/year operation

2) Annual emissions are scaled according to the production increase. Emission rate does not increase on a lb/hr basis

Hot Oil Heater #2 (EQUI 32)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

Combustion EmissionsBurner Heat Input Capacity: 18 MMBtu/hr

Pollutant

Emission

Factor1

(lb/MMscf)

Emission

Factor2

(lb/MMBtu)

Operating

Hours

Emission

Rate

(lb/hr)

Potential

Emissions

(tpy)2‐Methylnaphthalene 2.40E‐05 2.35E‐08 8,760 4.24E‐07 1.86E‐063‐Methylchloranthrene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐077,12‐Dimethylbenz(a)anthracene 1.60E‐05 1.57E‐08 8,760 2.82E‐07 1.24E‐06Acenaphthene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Acenaphthylene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Anthracene 2.40E‐06 2.35E‐09 8,760 4.24E‐08 1.86E‐07Arsenic 2.00E‐04 1.96E‐07 8,760 3.53E‐06 1.55E‐05Benz(a)anthracene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Benzene 2.10E‐03 2.06E‐06 8,760 3.71E‐05 1.62E‐04Benzo(a)pyrene 1.20E‐06 1.18E‐09 8,760 2.12E‐08 9.28E‐08Benzo(b)fluoranthene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Benzo(g,h,i)perylene 1.20E‐06 1.18E‐09 8,760 2.12E‐08 9.28E‐08Benzo(k)fluoranthene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Beryllium 1.20E‐05 1.18E‐08 8,760 2.12E‐07 9.28E‐07Cadmium 1.10E‐03 1.08E‐06 8,760 1.94E‐05 8.50E‐05Chromium 1.40E‐03 1.37E‐06 8,760 2.47E‐05 1.08E‐04Chrysene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07CO 84 8.24E‐02 8,760 1.48 6.49Cobalt 8.40E‐05 8.24E‐08 8,760 1.48E‐06 6.49E‐06Dibenzo(a,h)anthracene 1.20E‐06 1.18E‐09 8,760 2.12E‐08 9.28E‐08Dichlorobenzene 1.20E‐03 1.18E‐06 8,760 2.12E‐05 9.28E‐05Fluoranthene 3.00E‐06 2.94E‐09 8,760 5.29E‐08 2.32E‐07Fluorene 2.80E‐06 2.75E‐09 8,760 4.94E‐08 2.16E‐07Formaldehyde 7.50E‐02 7.35E‐05 8,760 1.32E‐03 5.80E‐03Hexane 1.80E+00 1.76E‐03 8,760 3.18E‐02 0.14Indeno(1,2,3‐cd)pyrene 1.80E‐06 1.76E‐09 8,760 3.18E‐08 1.39E‐07Lead 5.00E‐04 4.90E‐07 8,760 8.82E‐06 3.86E‐05Manganese 3.80E‐04 3.73E‐07 8,760 6.71E‐06 2.94E‐05Mercury 2.60E‐04 2.55E‐07 8,760 4.59E‐06 2.01E‐05Naphthalene 6.10E‐04 5.98E‐07 8,760 1.08E‐05 4.71E‐05Nickel 2.10E‐03 2.06E‐06 8,760 3.71E‐05 1.62E‐04NOx 100 9.80E‐02 8,760 1.76E+00 7.73Phenanthrene 1.70E‐05 1.67E‐08 8,760 3.00E‐07 1.31E‐06PM 7.6 7.45E‐03 8,760 0.13412 0.59

PM10 7.6 7.45E‐03 8,760 0.13412 0.59

PM2.5 7.6 7.45E‐03 8,760 0.13412 0.59

Pyrene 5.00E‐06 4.90E‐09 8,760 8.82E‐08 3.86E‐07Selenium 2.40E‐05 2.35E‐08 8,760 4.24E‐07 1.86E‐06SO2 0.60 5.88E‐04 8,760 1.06E‐02 4.64E‐02Toluene 3.40E‐03 3.33E‐06 8,760 6.00E‐05 2.63E‐04VOC 5.5 5E‐03 8,760 9.71E‐02 0.43

0.033 0.146

Carbon Dioxide4 116.9 8,760 2,104 9,216

Methane4 2.20E‐03 8,760 3.96E‐02 0.17

Nitrous Oxide4 2.20E‐04 8,760 3.96E‐03 0.017

2106 9226

Notes:1) Emission factors for natural gas combustion are from Tables 1.4‐1, 1.4‐2, 1.4‐3 and 1.4‐4 of AP‐42.

3) Global warming potentials for greenhouse gas pollutants from 40 CFR pt. 98, subp. A Table A‐1.4) Emission factors for greenhouse gas pollutants from 40 CFR pt. 98, subp. A Tables C‐1 and C‐2.

Total HAPs

CO2e3

Greenhouse Gases

2) Emission factors were converted from lb/MMscf to lb/MMBtu using an assumed higher heating value of 1,020 Btu/scf (per footnote "a" of Table 1.4‐1).

Fresh Methanol Tank 6 Emissions (EQUI 34)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor

(lb/hr)

Previous

Emission

Rate1

(lb/hr)

Emission

Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC TANKS 4.09d 0.217 0.220 0.964 0.019Methanol TANKS 4.09d 0.217 0.220 0.964 0.019

Total HAPs 0.22 0.96 0.019

Notes:1‐Emission rate from Permit No. 04700061‐003 TANKS 4.09d reports.2‐Emission rate from TANKS 4.09d tanks report with increased biodiesel production limit of 44,000,000 gal/year

Water Absorber Emissions (EQUI 37)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Previous Emission

Rate (lb/hr)

Emission Rate1

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 0.25 0.29 1.26 0.025Methanol 0.25 0.29 1.26 0.025

Total HAPs 0.29 1.26 0.025

Methanol concentration (estimate) 50 ppmMolecular weight of methanol 32 g/molFlow rate 1000 dscfmDensity of air at standard conditions 0.075 lb/scfMolecular weight of air at standard conditions 28.97 g/mol

Notes:1) Emission rate is scaled according to the production increase

Deacidulation Emissions (EQUI 38)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Previous Emission

Rate (lb/hr)

Emission Rate1

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 1.43 1.65 7.25 7.25

Flow rate 200 dscfConcentration 1000 ppmMolecular weight of EtOH 46 g/molDensity of air at standard conditions 0.075 lb/scfMolecular weight of air at standard conditions 28.97 g/mol* Vented inside building

Notes:1) Emission rate is scaled according to the production increase

Vacuum Pump Potential Emissions (EQUI 39)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor1

(lb/hr)

Previous Emission

Rate2 (lb/hr)

Emission Rate3

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 1.18 3.73 4.32 18.92 0.38Methanol 1.18 3.73 4.32 18.92 0.38

Total HAPs 4.32 18.92 0.38

3) Emission rate is scaled according to the production increase

Notes:1) Emission factor based on a biodiesel plant with 12 MMGal/year capacity2) Emission rate from Permit No. 04700061‐003 for 38 MMGal/year operation of REG Albert Lea

Temporary Boiler Emissions (EQUI 43)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

Potential Combustion EmissionsTotal Heat Input Capacity: 33.5 MMBtu/hr

Pollutant

Emission

Factor1

(lb/MMscf)

Emission

Factor2

(lb/MMBtu)

Operating

Hours

Emission Rate

(lb/hr)

Potential

Emissions


PM10 7.6 7.45E‐03 8,760 0.25 1.09

PM2.5 7.6 7.45E‐03 8,760 0.25 1.09

Pyrene 5.00E‐06 4.90E‐09 8,760 1.64E‐07 7.19E‐07Selenium 2.40E‐05 2.35E‐08 8,760 7.88E‐07 3.45E‐06SO2 0.60 5.88E‐04 8,760 1.97E‐02 8.63E‐02Toluene 3.40E‐03 3.33E‐06 8,760 1.12E‐04 4.89E‐04VOC 5.5 5.39E‐03 8,760 1.81E‐01 0.79

0.062 0.272

Carbon Dioxide4 120,000 118 8,760 3,941 17,262

Methane4 2.3 2.25E‐03 8,760 7.55E‐02 0.33

Nitrous Oxide4 2.2 2.16E‐03 8,760 7.23E‐02 0.32

3,965 17,365


3) Global warming potentials for greenhouse gas pollutants from 40 CFR pt. 98, subp. A Table A‐14) Emission factors for greenhouse gas pollutants from 40 CFR pt. 98, subp. A Tables C‐1 and C‐2

2) Emission factors were converted from lb/MMscf to lb/MMBtu using an assumed higher heating value of 1,020 Btu/scf (per footnote "a"

Greenhouse Gases

Total HAPs

CO2e3

Transesterification Reactors Potential Emissions (EQUI 45)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Previous Emission

Rate1 (lb/hr)

Emission Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 0.515 0.60 2.61 0.052Methanol 0.515 0.60 2.61 0.052

Total HAPs 0.60 2.61 0.052

Notes:

2) Emission rate is scaled according to the production increase1) Emission rate from Permit No. 04700061‐003 for 38 MMGal/year operation

Biodiesel Distillation (EQUI 48)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Previous Emission

Rate1 (lb/hr)

Emission Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 1.2 1.39 6.09 0.12Methanol 1.2 1.39 6.09 0.12

Total HAPs 1.39 6.09 0.12

Notes:1) Emission rate from Permit No. 04700061‐003 for 38 MMGal/year operation of REG Albert Lea2) Emission rate is scaled according to the production increase

HCl Tank 4 Emissions (EQUI 49)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor

(lb/hr)

Previous

Emission

Rate1

(lb/hr)

Emission

Rate2,3

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)

HCl TANKS 4.09d 0.17 0.09 0.39 0.39

Total HAPs 0.09 0.39 0.39

1) Emission rate from Permit No. 04700061‐003 TANKS 4.09d reports.Notes:

2) Emission rate from TANKS 4.09d tanks report with increased biodiesel production limit of 44,000,000 gal/year3) New TANKS 4.09d report used updated vapor pressure data provided by Permittee

Cooling Tower #1 Emissions (EQUI 54) Page 1 of 2Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

PM Emissions1

(tons)

PM10

Emissions1

(tons)

PM2.5

Emissions1

(tons)

VOC

Emissions

(tons)

HAP (MeOH)

Emissions (tons)0.97 0.76 0.0035 3.01 3.01

Notes:

Annual Equations

Total Dissolved Solids (TDS, ppm) 1474

Maximum Recirculation Capacity

(gal/hr)360000

Drift Loss Percent 0.005%Presumed Cooling Water Density

(lb/gal)8.34

Eactual = Actual Facility emissions, ton/yrHours of Operation 8760 EFactual = Actual emission factor, ppm TDSMaximum Recirculation Capacity

(MMgal/year)3,154

Q = Maximum circulation rate, gallons per hourPM Emission Factor (lb/MMgal) 0.61 H = Throughput, hours of per yearPM10 Emission Factor (lb PM10/lb

PM)79%

D = Density of water, lb per gallonPM2.5 Emission Factor (lb PM2.5/lb

PM)0.36%

DL = Drift loss, percentPM Emissions (tpy) 0.97 TDS = Total Dissolved Solids, ppmPM10 Emissions (tpy) 0.76 0.1743781

PM2.5 Emissions (tpy) 0.004 0.0008021

Example Calculation

TDSactual = 1474 ppm TDSQ = 360,000 gallon/hrH = 8,760 hours of operationD = 8.34 lb/galDL = 0.005%

EPM, actual = 1474 ppm x 360,000 gal x 8,760 hr x 8.34 lb x 0.005% x ton = 0.97 tons PM1,000,000 hr yr gal 2,000 lb year

EPM, actual = 0.97 tons PM

year

PMtotal = 0.97 tons PM x 2000 lbs x year = 0.2214612 lbs/hr

year ton 8760 hrs

PMtotal = 1474 mg x 1 lb x 3.785 l x 360000 gal x 0.00005 = 0.2213925

l 453600 mg gal hr2000 ppm 1000 ppm

PM 2.5 dp= 2.7916 PM 2.5 dd= 30 PM 2.5 % mass = 0.226 PM 2.5 dp= 2.9549 PM 2.5 dd= 40 PM 2.5 % mass = 0.514

PM 10 dp= 10.2358 PM 10 dd = 110 PM 10 % mass = 70.509 PM 10 dp= 11.081 PM 10 dd = 150 PM 10 % mass = 88.012

CTDS = 1,474 PM CTDS dd = 350 PM CTDS % mass = 97.011

2000 ppm 1000 ppmPM2.5 = PMtotal x %Mass/100 = 0.0005005 lbs/hr = 0.0021922 tpy PM2.5 = PMtotal x %Mass/100 = 0.0011383 lbs/hr = 0.0049817 tpy

PM10 = PMtotal x %Mass/100 = 0.1561501 lbs/hr = 0.6839373 tpy PM10 = PMtotal x %Mass/100 = 0.1949124 lbs/hr = 0.8530059 tpy

1500 ppmPM 2.5 dp= 2.8733 PM 2.5 dd= 35 PM 2.5 % mass = 0.3625

PM 10 dp= 10.6584 PM 10 dd = 130 PM 10 % mass = 78.8054

1500 ppmPM2.5 = PMtotal x %Mass/100 = 0.0008028 lbs/hr = 0.0035133 tpy

PM10 = PMtotal x %Mass/100 = 0.1745234 lbs/hr = 0.7637762 tpy

Page 2 of 2Cooling Tower #1 Emissions (EQUI 54)Renewable Energy Group Albert Lea, LLC

1) Potential Emission Rates for EQUI 54 were calculated based on maximum annual water usage with an assumed dissolved solids content of 1474 ppm and a 0.005 percent drift. From New Mexico Method, PM10 and PM2.5 are assumed to be 79% and 0.36% of total PM, respectively.

E EF ∗ Q ∗ton

2,000lb EFTDS ppm

1E6 ∗ Q ∗ H ∗ DL ∗ton

2,000lb

Albert Lea, MN

VOC PTE Equations [1]

Where:Liquid Loss Rate (lb/hr) 3Maximum MeOH Concentration 0.07%Ratio of Plant Capacities 3.67Safety Factor 1.5Ratio of Cooling Tower flows 1

PTE MeOH

(lb/hr) 0.69PTE MeOH

(tpy) 3.01

[1] VOC PTE Equation from Permit No. 04700061‐002

3 0.07%4412 60 1.5

60006000

E EF ∗ Q ∗ton

2,000lb

Acidulation Emissions (EQUI 55)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Previous Emission

Rate1 (lb/hr)

Emission Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions

(tpy)VOC 0 0.00 0.00 0.00Methanol 0 0.00 0.00 0.00

Total HAPs 0.00 0.00 0.00

Notes:1) Emission rate from Permit No. 04700061‐003 for 38 MMGal/year operation of REG Albert Lea. The addition of HCl causes the formation of various salts and water, with no associated emissions

2) Emission rate is scaled according to the production increase

Process Methanol Tank 7 Emissions (EQUI 58)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor

(lb/hr)

Previous

Emission

Rate1

(lb/hr)

Emission

Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions


Total HAPs 0.29 1.26 0.025

1) Emission rate from Permit No. 04700061‐003 TANKS 4.09d reports.Notes:

2) Emission rate from TANKS 4.09d tanks report with increased biodiesel production limit of 44,000,000 gal/year

Hot Oil Heater #1 (EQUI 59)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission

Factor1

(lb/MMscf)

Emission

Factor2

(lb/MMBtu)

Operating

Hours

Emission

Rate

(lb/hr)

Potential

Emissions


PM10 7.6 7.45E‐03 8,760 0.13412 0.59

PM2.5 7.6 7.45E‐03 8,760 0.13412 0.59

Pyrene 5.00E‐06 4.90E‐09 8,760 8.82E‐08 3.86E‐07Selenium 2.40E‐05 2.35E‐08 8,760 4.24E‐07 1.86E‐06SO2 0.60 5.88E‐04 8,760 1.06E‐02 4.64E‐02Toluene 3.40E‐03 3.33E‐06 8,760 6.00E‐05 2.63E‐04VOC 5.5 5E‐03 8,760 9.71E‐02 0.43

0.033 0.146

Carbon Dioxide4 116.9 8,760 2,104 9,216

Methane4 2.20E‐03 8,760 3.96E‐02 0.17

Nitrous Oxide4 2.20E‐04 8,760 3.96E‐03 0.017

2106 9226



Greenhouse Gases

Total HAPs

CO2e3


Cooling Tower Emissions (EQUI 60) Page 1 of 2Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

PM Emissions1

(tons)

PM10

Emissions1

(tons)

PM2.5

Emissions1

(tons)

VOC

Emissions

(tons)

HAP (MeOH)

Emissions (tons)0.52 0.41 0.002 1.59 1.59

Notes:

Annual Equations

Total Dissolved Solids (TDS, ppm) 1474Maximum Recirculation Capacity

(gal/hr)192000

Drift Loss Percent 0.005%Presumed Cooling Water Density

(lb/gal)8.34

Eactual = Actual Facility emissions, ton/yrHours of Operation 8760 EFactual = Actual emission factor, ppm TDSMaximum Recirculation Capacity

(MMgal/month)1,682

Q = Maximum circulation rate, gallons per hourPM Emission Factor (lb/MMgal) 0.61 H = Throughput, hours of per yearPM10 Emission Factor (lb PM10/lb

PM)79%

D = Density of water, lb per gallonPM2.5 Emission Factor (lb PM2.5/lb

PM)0.36%

DL = Drift loss, percentPM Emissions (tons) 0.52 TDS = Total Dissolved Solids, ppmPM10 Emissions (tons) 0.41

PM2.5 Emissions (tons) 0.002

Example Calculation

TDSactual = 1474 ppm TDSQ = 192,000 gallon/hrH = 8,760 hours of operationD = 8.34 lb/galDL = 0.005%

EPM, actual = 1474 ppm x 192,000 gal x 8,760 hr x 8.34 lb x 0.005% x ton = 0.52 tons PM1,000,000 hr yr gal 2,000 lb month

EPM, actual = 0.52 tons PM

year

PMtotal = 0.52 tons PM x 2000 lbs x year = 0.1187215 lbs/hr

year ton 8760 hrs

The monthly TDS measurement, the circulation rate, hours of operation, density of water and the drift loss for the Cooling Tower (EU010) are used in the above equation as an example of calculating actual monthly PM and PM10 emissions.

1) Potential Emission Rates for EQUI 60 were calculated based on maximum annual water usage with an assumed dissolved solids content of 1474 ppm and a 0.005 percent drift. From New Mexico Method, PM10 and PM2.5 are assumed to be 79% and 0.36% of total PM, respectively.

E EF ∗ Q ∗ton

2,000lb EFTDS ppm

1E6 ∗ Q ∗ H ∗ DL ∗ton

2,000lb

PMtotal = 1474 mg x 1 lb x 3.785 l x 192000 gal x 0.00005 = 0.118076 lbs/hr

l 453600 mg gal hr2000

PM 2.5 dp= 2.7916 PM 2.5 dd= 30 PM 2.5 % mass = 0.226

PM 10 dp= 10.2358 PM 10 dd = 110 PM 10 % mass = 70.509

CTDS = 1,474 PM CTDS dd = 350 PM CTDS % mass = 97.011

PM2.5 = PMtotal x %Mass/100 = 0.0002683 lbs/hr = 0.0011752 tpy


1500

PM 2.5 dp= 2.8733 PM 2.5 dd= 35 PM 2.5 % mass = 0.3625

PM 10 dp= 10.6584 PM 10 dd = 130 PM 10 % mass = 78.8054

PM2.5 = PMtotal x %Mass/100 = 0.0004304 lbs/hr = 0.001885 tpy


Cooling Tower Emissions (EQUI 60) Page 2 of 2Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

VOC PTE Equations [1]

Where:Liquid Loss Rate (lb/hr) 3

Maximum MeOH Concentration 0.07%Ratio of Plant Capacities 3.67

Safety Factor 1.5Ratio of Cooling Tower flows 0.53

PTE MeOH

(lb/hr) 0.36PTE MeOH

(tpy) 1.59

[1] VOC PTE Equation from Permit No. 04700061‐002

3 0.07%4412 60 1.5

32006000

Sodium Methylate Tank 8 Emissions (EQUI 61)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor

(lb/hr)

Previous

Emission

Rate1

(lb/hr)

Emission

Rate2

(lb/hr)

Maximum

Uncontrolled

Emissions

(tpy)

Maximum

Controlled

Emissions


Total HAPs 0.09 0.40 0.008

Notes:1) Emission rate from Permit No. 04700061‐003 TANKS 4.09d reports.2) Emission rate from TANKS 4.09d tanks report with increased biodiesel production limit of 44,000,000 gal/year

Flare Pilot Potential Emissions (TREA 2)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN


Pollutant

Emission Factor1

(lb/MMscf)

Emission Factor2

(lb/MMBtu) Operating Hours

Emission Rate

(lb/hr)

Potential

Emissions

(tpy)2‐Methylnaphthalene 2.40E‐05 2.35E‐08 8,760 4.71E‐08 2.06E‐073‐Methylchloranthrene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐087,12‐Dimethylbenz(a)anthracene 1.60E‐05 1.57E‐08 8,760 3.14E‐08 1.37E‐07Acenaphthene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Acenaphthylene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Anthracene 2.40E‐06 2.35E‐09 8,760 4.71E‐09 2.06E‐08Arsenic 2.00E‐04 1.96E‐07 8,760 3.92E‐07 1.72E‐06Benz(a)anthracene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Benzene 2.10E‐03 2.06E‐06 8,760 4.12E‐06 1.80E‐05Benzo(a)pyrene 1.20E‐06 1.18E‐09 8,760 2.35E‐09 1.03E‐08Benzo(b)fluoranthene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Benzo(g,h,i)perylene 1.20E‐06 1.18E‐09 8,760 2.35E‐09 1.03E‐08Benzo(k)fluoranthene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Beryllium 1.20E‐05 1.18E‐08 8,760 2.35E‐08 1.03E‐07Cadmium 1.10E‐03 1.08E‐06 8,760 2.16E‐06 9.45E‐06Chromium 1.40E‐03 1.37E‐06 8,760 2.75E‐06 1.20E‐05Chrysene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08CO3 3.70E‐01 8,760 0.74 3.24Cobalt 8.40E‐05 8.24E‐08 8,760 1.65E‐07 7.21E‐07Dibenzo(a,h)anthracene 1.20E‐06 1.18E‐09 8,760 2.35E‐09 1.03E‐08Dichlorobenzene 1.20E‐03 1.18E‐06 8,760 2.35E‐06 1.03E‐05Fluoranthene 3.00E‐06 2.94E‐09 8,760 5.88E‐09 2.58E‐08Fluorene 2.80E‐06 2.75E‐09 8,760 5.49E‐09 2.40E‐08Formaldehyde 7.50E‐02 7.35E‐05 8,760 1.47E‐04 6.44E‐04Hexane 1.80E+00 1.76E‐03 8,760 3.53E‐03 1.55E‐02Indeno(1,2,3‐cd)pyrene 1.80E‐06 1.76E‐09 8,760 3.53E‐09 1.55E‐08Lead 5.00E‐04 4.90E‐07 8,760 9.80E‐07 4.29E‐06Manganese 3.80E‐04 3.73E‐07 8,760 7.45E‐07 3.26E‐06Mercury 2.60E‐04 2.55E‐07 8,760 5.10E‐07 2.23E‐06Naphthalene 6.10E‐04 5.98E‐07 8,760 1.20E‐06 5.24E‐06Nickel 2.10E‐03 2.06E‐06 8,760 4.12E‐06 1.80E‐05NOx3 69 6.80E‐02 8,760 1.36E‐01 0.60Phenanthrene 1.70E‐05 1.67E‐08 8,760 3.33E‐08 1.46E‐07PM 7.6 7.45E‐03 8,760 0.01490 0.07

PM10 7.6 7.45E‐03 8,760 0.01490 0.07

PM2.5 7.6 7.45E‐03 8,760 0.01490 0.07

Pyrene 5.00E‐06 4.90E‐09 8,760 9.80E‐09 4.29E‐08Selenium 2.40E‐05 2.35E‐08 8,760 4.71E‐08 2.06E‐07SO2 0.60 5.88E‐04 8,760 1.18E‐03 5.15E‐03Toluene 3.40E‐03 3.33E‐06 8,760 6.67E‐06 2.92E‐05VOC3 8E‐02 8,760 1.50E‐01 0.66

0.0037 0.0162

Carbon Dioxide5 116.9 8,760 234 1,024

Methane5 2.20E‐03 8,760 4.40E‐03 0.02

Nitrous Oxide5 2.20E‐04 8,760 4.40E‐04 0.002

234 1025

Notes:


Greenhouse Gases

Total HAPs

CO2e4

1) Emission factors for natural gas combustion are from Tables 1.4‐1, 1.4‐2, 1.4‐3 and 1.4‐4 of AP‐42.

3) Emission factors for non‐greenhouse gas pollutants from AP‐42 Chapter 13.5, Tables 13.5‐1 and 13.5‐2. (VOC = 55% of TOC)


Facility‐Wide Potential Emissions ‐ Equipment Leaks (FUGI 1)Renewable Energy Group Albert Lea, LLCAlbert Lea, MN

Process Stream

Equipment

Component

Source Product

Component

Count1

Screening

Value1

(ppm)

Table 2‐1:

SOCMI Average

Emission

Factors2

(kg/hr/source)

Table 2‐9: SOCMI

Leak Rates with

Screen Values3

(kg/hr/source)

Table 5‐2 Control

Efficiencies4

Emission

Rate

(kg/hr)

Emission

Rate

(lb/hr)Valves Gas/Vapor 71 500 0.00042 87% 0.004 0.01Valves Light Liquid 322 500 0.00091 84% 0.047 0.10Pumps Light Liquid 29 2000 0.00997 69% 0.090 0.20Agitators Light Liquid 3 2000 0.00997 0% 0.030 0.07

Pressure‐Relief Valves Gas/Vapor 27 500 0.00318 0% 0.086 0.19Open‐ended Lines All 1 0.0017 0% 0.002 0.00

Flanges (Connectors) All 590 500 0.00075 93% 0.031 0.07Total: 0.289 0.636

VOC Emission

Pollutant Emission Rate (lb/hr)

Operating

Hours

Unrestricted

Potential

Emissions

(tons/yr)

Permit

Allowable

Emissions Rate

(tons/yr)

VOC 0.636 8,760 2.79 2.79

HAP Emissions

Hazardous Air Pollutant Fraction of VOC

Operating

Hours

Unrestricted

Potential

Emissions

(lb/hr)

Unrestricted

Potential

Emissions

(tons/yr)

Permit

Allowable

Emissions Rate5

(tons/yr)

Methanol6 100% 8760 0.636 2.79 2.652.79

Notes:

2) Protocol for Equipment Leaks, Table 2‐1 "SOCMI AVERAGE EMISSION FACTORS"3) Protocol for Equipment Leaks, Table 2‐9 "SOCMI LEAK RATE/SCREENING VALUE CORRELATIONS"4) Protocol for Equipment Leaks, Table 5‐2 "CONTROL EFFECTIVENESS FOR A LDAR PROGRAM AT A SOCMI PROCESS UNIT"

6) Methanol is assumed to be the only VOC based on PTE calculations

Equipment Leaks VOC Emission Summary

5) Permit limit for Methanol of 2.65 tpy from Permit No. 04700061‐003 based on operating hours of 8328 (18 days of downtime)

1) Screening values based on monitoring data (50 ppm) with 1.5x safety factor. See Permit No. 04700061‐003.

Total HAPs

Facility‐Wide

Paved/Unpaved Road Emissions (FS002)


Albert Lea, MN

PM Emissions

(tons/year)

PM10

Emissions

(tons/year)

PM2.5

Emissions

(tons/year)

PM

Emissions

(lb/hr)

PM10

Emissions

(lb/hr)

PM2.5 Emissions

(lb/hr)29.06 8.41 0.89 22.35 6.47 0.69

Truck Traffic

Emissions calculated using PM/PM10/PM2.5 equations listed in AP‐42 equation for Paved and Unpaved Roads, Eq. 1, Chapter 13, Section 2, 8/2008.

Variable Description k k a b

AP‐42 Table 13.2.1‐1 Coefficient Factors PM 0.011 PM 4.9 0.7 0.45

Road surface silt loading, g/m2, annual average PM10 0.0022 PM10 1.5 0.9 0.45

Average weight (tons) of the vehicles traveling the road PM2.5 0.00054 PM2.5 0.15 0.9 0.45

Emission Factor (lb/vehicle miles traveled (VMT))

Haul Road / Traffic Parameters ‐ Annual

Silt Value1Roundtrip

Length

(feet)

Truck

Weight1

(tons)

(g/m2) full Ave.

All Trucks Paved 5 1000 28 10 1 truck 2462All Trucks Unpaved 10 1900 28 10 1 truck 4678

Haul Road / Traffic Parameters ‐ Hourly

Silt Value1Roundtrip

Length

(feet)

Truck

Weight1

(tons)

(g/m2) full Ave.

All Trucks Paved 5 1000 28 10 1 truck 0.95All Trucks Unpaved 10 1900 28 10 1 truck 1.80

Haul Road Emissions ‐ Annual

PM PM10 PM2.5 PM PM10 PM2.5 PM PM10 PM2.5

All Trucks ‐ Paved Roadways 1.40 0.28 0.07 1.72 0.34 0.08

All Trucks ‐ Unpaved Roadways 11.69 3.45 0.35 27.34 8.07 0.81Total: 29.06 8.41 0.89

Haul Road Emissions ‐ Hourly

PM PM10 PM2.5 PM PM10 PM2.5 PM PM10 PM2.5

All Trucks ‐ Paved Roadways 1.40 0.28 0.07 1.3 0.3 0.06

All Trucks ‐ Unpaved Roadways 11.69 3.45 0.35 21.0 6.2 0.62Total: 22.4 6.5 0.69

Notes:

5

5

Activity

PavedEmission Factors

(lb/VMT)

Unpaved Emission Factors

(lb/VMT)

Total Hourly Emission

(lb/hr)

Activity Road Type

Ave. Speed

(mph)

Unrestricted Maximum

Hourly Throughput 2

(units/hr)

Ave. Truck Capacity

(units/truck) Hourly VMT

Activity Road Type

Ave. Speed

(mph)

Unrestricted Maximum

Throughput 2

(units/yr)

Ave. Truck Capacity

(units/truck)

AP‐42 Table 13.2.1‐1

Coefficient factors for

Paved Roads

AP‐42 Table 13.2.2 Coefficient factors for

Unpaved Roads

1) Silt load estimated from AP‐42 Tale 13.2.2‐1 for unpaved roads and AP‐42 Table 13.2.1‐3 for paved roads. All trucks are conservatively assumed to be at their maximum weight for the entire round‐trip route through the facility2) Maximum possible number of trucks set by MPCA Technical Support Document to be 5 trucks per hour based on facility logistical capacity maximum of 5 (all feedstock, biodiesel, chemical, and service trucks) per hour. Assumes all feedstock, biodiesel, and chemicals are shipped by truck with zero rail.

Total Annual Emission

(tons/yr)

Annual VMT

Activity

PavedEmission Factors

(lb/VMT)

UnpavedEmission Factors

(lb/VMT)

13000

13000

, ∗ . ∗ .

, ∗ /12 ∗ /3

Insignificant Activity (Minn. R. 7007.1300, subp. 3(I)) ‐ Tanks EmissionsRenewable Energy Group Albert Lea, LLCAlbert Lea, MN

Tank IDTank

StatusTank Contents

Tank

Capacity

(gallons)

Emission

Factor

(lb/yr)

Historical

Emission Rate1

(lb/yr)

Recalculated

Emission Rate2

(lb/yr)

Methanol

Emission

Rate

(lb/hr)

VOC

Emission

Rate

(lb/hr)

Methanol

Emission

Rate (tpy)

VOC

Emission

Rate (tpy)

TK009 Active Feedstock 500,000 TANKS 4.09d 58.1 105 ‐ 1.20E‐02 ‐ 5.26E‐02TK010 Active Finished Biodiesel IA 500,000 TANKS 4.09d 6 32 1.88E‐03 3.65E‐03 8.23E‐03 1.60E‐02TK011 Active Finished Biodiesel 500,000 TANKS 4.09d 6 32 1.88E‐03 3.65E‐03 8.23E‐03 1.60E‐02TK012 Active Glycerin 100,000 TANKS 4.09d ‐ 15 9.06E‐04 9.06E‐04 3.97E‐03 3.97E‐03TK013 Active Biodiesel Rework 20,000 TANKS 4.09d ‐ 12 1.30E‐03 1.37E‐03 5.70E‐03 6.00E‐03TK014 Active Free Fatty Acids 11,000 ‐ ‐ ‐ ‐ ‐ ‐ ‐TK015 Active Soapstop / Wastewater 14,000 ‐ ‐ ‐ ‐ ‐ ‐ ‐TK016 Active Finished Biodiesel ‐ Loadout 500,000 TANKS 4.09d ‐ 32 1.88E‐03 3.65E‐03 8.23E‐03 1.60E‐02TK017 Active Feedstock IA 500,000 ‐ ‐ 105 ‐ 1.20E‐02 ‐ 5.25E‐02TK018 Active Crude Feedstock 11,000 ‐ ‐ ‐ ‐ ‐ ‐ ‐TK019 Active Biodistillation Bottoms 25,000 TANKS 4.09d ‐ 2 1.14E‐04 2.28E‐04 5.00E‐04 1.00E‐03TK020 Active Free Fatty Acid 100,000 ‐ ‐ ‐ ‐ ‐ ‐ ‐

Active Feedstock 500,000 TANKS 4.09d ‐ 105 ‐ 1.20E‐02 ‐ 5.25E‐02Active Refined Feedstock 88,000 ‐ ‐ ‐ 0.00E+00 0.00E+00 0.00E+00 0.00E+00

7.95E‐03 4.95E‐02 3.48E‐02 2.17E‐01

Notes:1) Emission rates from TANKS 4.09d reports for Permit No. 04700061‐003.2) Emission rates were recalculated with updated TANKS chemical database ‐ TANKS 4.0.9d

Total Emission Rate

Attachment 2 – Subject item inventory and facility requirements


REG Albert Lea LLC 04700061-101

Subject Item Category Description Subject Item Type Description

Activity Insignificant Air Emissions Activity

Agency Interest Conventional Site

Component Group Air Component Group

Equipment Aboveground Storage Tank

Acid Treatment Equipment

Boiler

Distillation Equipment

Loading-Unloading Equipment

Other Emission Unit

Process Heater

Pump

Separation Equipment

Fugitive Equipment Leaks

Structure Building

Stack/Vent

Total Facility Air Quality Total Facility

Treatment 023-Flaring

1

1

1

1

1

2

3

1

1

1

2

4

1

8

8

1

1

Overview of SI's (count) by type

Agency Interest: REG Albert Lea LLCAgency Interest ID: NoneActivity: IND20160003 (None)

Details for:SI Category: AllSI Type: All

Agency Interest Name Subject Item ID SI Designation and Description

REG Albert Lea LLC ACTV4NullAll IAs

AISI104670NullNull

COMG4GP003Facility Limits

EQUI31EU003Biodiesel Loadout

EQUI32EU008Hot Oil Heater #2

EQUI34TK006Fresh Methanol Tank 6

EQUI37EU011Water Absorber

EQUI38 EU006Deacidification System

List of SIs

Agency Interest: REG Albert Lea LLCAgency Interest ID: 104670Activity: IND20160003 (Major Amendment)

Details for:SI Category: NoneSI Type: All

Agency Interest Name Subject Item ID SI Designation and DescriptionREG Albert Lea LLC

EQUI37EU011Water Absorber

EQUI38EU006Deacidification System

EQUI39EU001Vacuum Pump (Biodiesel Process)

EQUI43NullBoiler

EQUI45EU002Transesterification Reactors

EQUI48EU009Biodiesel Distillation

EQUI49TK004HCl Tank 4

EQUI54EU004Cooling Tower 1

EQUI55 EU005Acidulation

List of SIs





EQUI55EU005Acidulation

EQUI58TK007Process Methanol Tank 7



EQUI61TK008Sodium Methylate Tank 8

FUGI1FS001Equipment Leaks (MeOH, ethanol,VOCs)

STRU1SV001Flare Stack

STRU4 SV007Hot Oil Heater #1

List of SIs




STRU1SV001Flare Stack

STRU4SV007Hot Oil Heater #1

STRU5SV010Boiler Stack


STRU8SV009Cooling Tower 2

STRU9SV006Deacidification System

STRU10SV005HCl Tank


STRU12 NullBLDG 1

List of SIs





STRU12NullBLDG 1

STRU13NullBLDG 2

STRU14NullBLDG 6

STRU15NullBLDG 7.1

STRU16NullBLDG 7.2

STRU17NullBLDG 8

STRU18NullBLDG 50

STRU19 NullCOOL 2

List of SIs




STRU18NullBLDG 50

STRU19NullCOOL 2

TFAC104700061REG Albert Lea LLC

TREA2CE001Flaring

List of SIs



Subject Item ID Within 50 miles of these borders Program Description Sub Program Description Sub Program Start Date Sub Program End Date SIC / NAICS

AISI104670 Iowa Null New Source Review - Minor 11/27/2012 Null 2869 - Industrial Organic C..

New Source Review - Synthetic Minor 2/25/2004 7/21/2017 12:00:00 AM 2869 - Industrial Organic C..

NSPS 7/21/2017 Null 2869 - Industrial Organic C..

Part 63 Synthetic Area 7/21/2017 Null 2869 - Industrial Organic C..

Part 70 Nonmajor 11/27/2012 7/21/2017 12:00:00 AM 2869 - Industrial Organic C..

Part 70 Synthetic Minor 2/25/2004 Null 2869 - Industrial Organic C..

AISI Conventional Site


Details for:SI Category: Agency InterestSI Type: Conventional Site

Agency Interest Na.. Activity ID Subject Ite..Subject Item Type Description Subject Item ID SI Designation and Description Status Desc..Sub Attribute Description

REG Albert Lea LLC IND20160003 Activity Insignificant Air Emissions Activity ACTV4 NullAll IAs

Active /Existing

Minn. R. 7007.1300, subp. 3(G)

Minn. R. 7007.1300, subp.3(H)(3)

Minn. R. 7007.1300, subp. 3(I)

Minn. R. 7007.1300, subp. 3(J)

Insignificant air emissions activity


Details for:SI Category: ActivitySI Type: Insignificant Air Emissions Activity

Agency Interest Name Subject Item ID SI Designation and Description Group Member ID (padded)

REG Albert Lea LLC COMG4 GP003Facility Limits

EQUI31

EQUI34

EQUI37

EQUI39

EQUI45

EQUI48

EQUI55

EQUI58

EQUI61

Component Group (Members)

Agency Interest: REG Albert Lea LLCAgency Interest ID: 104670Activity: None (Major Amendment)

Details for:SI Category: Component GroupSI Type: Air Component Group

Subject ItemCategory Description

Subject Item TypeDescription Subject Item ID

Subject ItemDesignation Subject Item Description Pollutant

Potential (lbs/hr)

Unrestricted Potential

(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Component Group Air Component Group COMG4 GP003 Facility Limits Methanol

Equipment Aboveground StorageTank

EQUI34 TK006 Fresh Methanol Tank 6 HAPs - Total

Methanol

Volatile Organic Compounds

EQUI49 TK004 HCl Tank 4 HAPs - Total

Hydrochloric acid

EQUI58 TK007 Process Methanol Tank 7 HAPs - Total

Methanol


EQUI61 TK008 Sodium Methylate Tank 8 HAPs - Total

Methanol


Acid TreatmentEquipment

EQUI38 EU006 Deacidification System Volatile Organic Compounds

EQUI55 EU005 Acidulation Hydrochloric acid

Boiler EQUI43 Null Boiler 1,4-Dichlorobenzene (para-)

2-Methylnaphthalene

3-Methylcholanthrene

7,12-Dimethylbenz[a]anthracene

Acenaphthene

Acenaphthylene

Anthracene

Arsenic compounds

Benzene

Benzo(a)anthracene

Benzo(b)fluoranthene

Benzo(ghi)perylene

Benzo(k)fluoranthene

Benzo[a]pyrene

Beryllium

Cadmium compounds

Carbon Dioxide

Carbon Dioxide Equivalent

1.2500

0.0190

0.019

0.9640.9640.964

0.220.220.22

0.390.39

0.390.39

0.090.09

0.0250

0.025

1.261.261.26

0.290.290.29

0.0080

0.008

0.40.40.4

0.0920.0920.092

7.257.251.65000

17,2620.0001581.73e-061.73e-072.59e-071.73e-072.59e-072.59e-070.0003022.88e-053.45e-072.59e-072.59e-072.3e-062.59e-073.45e-060.000173

17,2620.0001581.73e-061.73e-072.59e-071.73e-072.59e-072.59e-070.0003022.88e-053.45e-072.59e-072.59e-072.3e-062.59e-073.45e-060.000173

3,9413.61e-053.94e-073.94e-085.91e-083.94e-085.91e-085.91e-086.9e-056.57e-067.88e-085.91e-085.91e-085.25e-075.91e-087.88e-073.94e-05

PTE by subject item

Agency Interest: NoneAgency Interest ID: 104670Activity: None (Major Amendment)





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Boiler EQUI43 Null BoilerCarbon Dioxide


Carbon Monoxide

Chromium compounds

Chrysene

Cobalt compounds

Dibenz[a,h]anthracene

Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane

Indeno(1,2,3-cd)pyrene

Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Selenium compounds

Sulfur Dioxide

Toluene


Distillation Equipment EQUI48 EU009 Biodiesel Distillation HAPs - Total

Methanol


0.790.0004890.08633.45e-067.19e-07

1.091.09

2.45e-061.090.3214.4

0.0003028.78e-05

0.333.74e-055.47e-057.19e-052.59e-07

0.260.2720.01084.03e-074.32e-071.73e-071.21e-052.59e-070.000201

12.117,365

0.790.0004890.08633.45e-067.19e-07

1.091.09

2.45e-061.090.3214.4

0.0003028.78e-05

0.333.74e-055.47e-057.19e-052.59e-07

0.260.2720.01084.03e-074.32e-071.73e-071.21e-052.59e-070.000201

12.117,365

0.1810.0001120.01977.88e-071.64e-07

0.250.25

5.58e-070.25

0.07233.28

6.9e-052e-050.07558.54e-061.25e-051.64e-055.91e-080.05910.062

0.002469.2e-089.85e-083.94e-082.76e-065.91e-084.6e-052.763,965

00.12

6.096.09

1.391.39

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Distillation Equipment EQUI48 EU009 Biodiesel DistillationMethanol


Loading-UnloadingEquipment

EQUI31 EU003 Biodiesel Loadout HAPs - Total

Methanol


Other Emission Unit EQUI45 EU002 TransesterificationReactors

HAPs - Total

Methanol


EQUI54 EU004 Cooling Tower 1 HAPs - Total

Methanol

Particulate Matter

PM < 2.5 micron

PM < 10 micron


EQUI60 EU010 Cooling Tower 2 HAPs - Total

Methanol

Particulate Matter

PM < 2.5 micron

PM < 10 micron


Process Heater EQUI32 EU008 Hot Oil Heater #2 1,4-Dichlorobenzene (para-)

2-Methylnaphthalene



Acenaphthene

Acenaphthylene

Anthracene

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


0.126.091.39

0.500.5

25.1625.1625.16

4.964.964.96

0.0520

0.052

2.612.612.61

0.60.60.6

3.010.76

0.00350.973.013.01

3.010.76

0.00350.973.013.01

0.690.1740.00080.220.690.69

1.590.410.0020.521.591.59

1.590.410.0020.521.591.59

0.360.094

0.000430.120.360.36

9.28e-081.39e-071.39e-070.0001621.55e-051.86e-071.39e-071.39e-071.24e-061.39e-071.86e-069.28e-05

9.28e-081.39e-071.39e-070.0001621.55e-051.86e-071.39e-071.39e-071.24e-061.39e-071.86e-069.28e-05

2.12e-083.18e-083.18e-083.71e-053.53e-064.24e-083.18e-083.18e-082.82e-073.18e-084.24e-072.12e-05

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Process Heater EQUI32 EU008 Hot Oil Heater #2Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium

Cadmium compounds

Carbon Dioxide


Carbon Monoxide

Chromium compounds

Chrysene

Cobalt compounds


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane


Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Selenium compounds

Sulfur Dioxide

1.86e-063.86e-07

0.590.59

1.31e-060.590.0177.73

0.0001624.71e-05

0.172.01e-052.94e-053.86e-051.39e-07

0.140.1460.00582.16e-072.32e-079.28e-086.49e-061.39e-070.000108

6.499,2269,2168.5e-059.28e-079.28e-081.39e-07

1.86e-063.86e-07

0.590.59

1.31e-060.590.0177.73

0.0001624.71e-05

0.172.01e-052.94e-053.86e-051.39e-07

0.140.1460.00582.16e-072.32e-079.28e-086.49e-061.39e-070.000108

6.499,2269,2168.5e-059.28e-079.28e-081.39e-07

4.24e-078.82e-080.1340.1343e-070.134

0.003961.76

3.71e-051.08e-050.03964.59e-066.71e-068.82e-063.18e-080.03180.033

0.001324.94e-085.29e-082.12e-081.48e-063.18e-082.47e-05

1.482,1062,104

1.94e-052.12e-072.12e-083.18e-08

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Process Heater EQUI32 EU008 Hot Oil Heater #2Selenium compounds

Sulfur Dioxide

Toluene


EQUI59 EU007 Hot Oil Heater #1 1,4-Dichlorobenzene (para-)

2-Methylnaphthalene



Acenaphthene

Acenaphthylene

Anthracene

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium

Cadmium compounds

Carbon Dioxide


Carbon Monoxide

Chromium compounds

Chrysene

Cobalt compounds


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane


0.430.0002630.0464

0.430.0002630.0464

0.09716e-050.0106

0.140.1460.00582.16e-072.32e-079.28e-086.49e-061.39e-070.000108

6.499,2269,2168.5e-059.28e-079.28e-081.39e-079.28e-081.39e-071.39e-070.0001621.55e-051.86e-071.39e-071.39e-071.24e-061.39e-071.86e-069.28e-05

0.140.1460.00582.16e-072.32e-079.28e-086.49e-061.39e-070.000108

6.499,2269,2168.5e-059.28e-079.28e-081.39e-079.28e-081.39e-071.39e-070.0001621.55e-051.86e-071.39e-071.39e-071.24e-061.39e-071.86e-069.28e-05

0.03180.033

0.001324.94e-085.29e-082.12e-081.48e-063.18e-082.47e-05

1.482,1062,104

1.94e-052.12e-072.12e-083.18e-082.12e-083.18e-083.18e-083.71e-053.53e-064.24e-083.18e-083.18e-082.82e-073.18e-084.24e-072.12e-05

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Equipment Process Heater EQUI59 EU007 Hot Oil Heater #1Hexane


Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Selenium compounds

Sulfur Dioxide

Toluene


Pump EQUI39 EU001 Vacuum Pump (BiodieselProcess)

HAPs - Total

Methanol


Separation Equipment EQUI37 EU011 Water Absorber HAPs - Total

Methanol


Fugitive Equipment Leaks FUGI1 FS001 Equipment Leaks (MeOH,ethanol, VOCs)

HAPs - Total

Methanol


Treatment 023-Flaring TREA2 CE001 Flaring 1,4-Dichlorobenzene (para-)

2-Methylnaphthalene



Acenaphthene

0.430.0002630.04641.86e-063.86e-07

0.590.59

1.31e-060.590.0177.73

0.0001624.71e-05

0.172.01e-052.94e-053.86e-051.39e-07

0.430.0002630.04641.86e-063.86e-07

0.590.59

1.31e-060.590.0177.73

0.0001624.71e-05

0.172.01e-052.94e-053.86e-051.39e-07

0.09716e-050.01064.24e-078.82e-080.1340.1343e-070.134

0.003961.76

3.71e-051.08e-050.03964.59e-066.71e-068.82e-063.18e-08

0.380

0.38

18.9218.9218.92

4.324.324.32

0.0250

0.025

1.261.261.26

0.290.290.29

2.792.652.79

2.792.792.79

0.4260.4260.64

1.37e-071.55e-082.06e-071.03e-05

1.37e-071.55e-082.06e-071.03e-05

3.14e-083.53e-094.71e-082.35e-06

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Treatment 023-Flaring TREA2 CE001 Flaring7,12-Dimethylbenz[a]anthracene

Acenaphthene

Acenaphthylene

Anthracene

Arsenic compounds

Benzene

Benzo(a)anthracene


Benzo(ghi)perylene


Benzo[a]pyrene

Beryllium

Cadmium compounds

Carbon Dioxide


Carbon Monoxide

Chromium compounds

Chrysene

Cobalt compounds


Fluoranthene

Fluorene

Formaldehyde

HAPs - Total

Hexane


Lead

Manganese compounds

Mercury

Methane

Naphthalene

Nickel compounds

Nitrogen Oxides

1.8e-055.24e-060.01932.23e-063.26e-064.29e-061.55e-080.01550.0162

0.0006442.4e-082.58e-081.03e-087.21e-071.55e-081.2e-053.241,0251,024

9.45e-061.03e-071.03e-081.55e-081.03e-081.55e-081.55e-081.8e-051.72e-062.06e-081.55e-081.55e-08

1.8e-055.24e-060.01932.23e-063.26e-064.29e-061.55e-080.01550.0162

0.0006442.4e-082.58e-081.03e-087.21e-071.55e-081.2e-053.241,0251,024

9.45e-061.03e-071.03e-081.55e-081.03e-081.55e-081.55e-081.8e-051.72e-062.06e-081.55e-081.55e-08

4.12e-061.2e-060.00445.1e-077.45e-079.8e-073.53e-090.003530.0037

0.0001475.49e-095.88e-092.35e-091.65e-073.53e-092.75e-06

0.74234234

2.16e-062.35e-082.35e-093.53e-092.35e-093.53e-093.53e-094.12e-063.92e-074.71e-093.53e-093.53e-09

PTE by subject item






Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Treatment 023-Flaring TREA2 CE001 FlaringNickel compounds

Nitrogen Oxides

Nitrous Oxide

Particulate Matter

Phenanthrene

PM < 2.5 micron

PM < 10 micron

Pyrene

Selenium compounds

Sulfur Dioxide

Toluene

Volatile Organic Compounds 0.662.92e-050.005152.06e-074.29e-080.06530.06531.46e-070.06530.00193

0.6

0.662.92e-050.005152.06e-074.29e-080.06530.06531.46e-070.06530.00193

0.6

0.156.67e-060.001184.71e-089.8e-090.01490.01493.33e-080.01490.000440.136

PTE by subject item



Pollutant

Subject ItemCategoryDescription Subject Item Type Description Subject Item ID

Subject ItemDesignation Subject Item Description

Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

1,4-Dichlorobenzene(para-)

Equipment Boiler EQUI43 Null Boiler

Process Heater EQUI32 EU008 Hot Oil Heater #2

EQUI59 EU007 Hot Oil Heater #1

Treatment 023-Flaring TREA2 CE001 Flaring

2-Methylnaphthalene Equipment Boiler EQUI43 Null Boiler




3-Methylcholanthrene Equipment Boiler EQUI43 Null Boiler




7,12-Dimethylbenz[a]ant..Equipment Boiler EQUI43 Null Boiler




Acenaphthene Equipment Boiler EQUI43 Null Boiler




Acenaphthylene Equipment Boiler EQUI43 Null Boiler




Anthracene Equipment Boiler EQUI43 Null Boiler




Arsenic compounds Equipment Boiler EQUI43 Null Boiler




Benzene Equipment Boiler EQUI43 Null Boiler




Benzo(a)anthracene Equipment Boiler EQUI43 Null Boiler



0.0001730.0001733.94e-059.28e-059.28e-052.12e-059.28e-059.28e-052.12e-051.03e-051.03e-052.35e-063.45e-063.45e-067.88e-071.86e-061.86e-064.24e-071.86e-061.86e-064.24e-072.06e-072.06e-074.71e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-092.3e-062.3e-065.25e-071.24e-061.24e-062.82e-071.24e-061.24e-062.82e-071.37e-071.37e-073.14e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-092.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-093.45e-073.45e-077.88e-081.86e-071.86e-074.24e-081.86e-071.86e-074.24e-082.06e-082.06e-084.71e-092.88e-052.88e-056.57e-061.55e-051.55e-053.53e-061.55e-051.55e-053.53e-061.72e-061.72e-063.92e-070.0003020.0003026.9e-050.0001620.0001623.71e-050.0001620.0001623.71e-051.8e-051.8e-054.12e-062.59e-072.59e-075.91e-081.39e-071.39e-073.18e-08

PTE by pollutant



Pollutant



Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Benzo(a)anthracene Equipment Process HeaterEQUI32 EU008 Hot Oil Heater #2



Benzo(b)fluoranthene Equipment Boiler EQUI43 Null Boiler




Benzo(ghi)perylene Equipment Boiler EQUI43 Null Boiler




Benzo(k)fluoranthene Equipment Boiler EQUI43 Null Boiler




Benzo[a]pyrene Equipment Boiler EQUI43 Null Boiler




Beryllium Equipment Boiler EQUI43 Null Boiler




Cadmium compounds Equipment Boiler EQUI43 Null Boiler




Carbon Dioxide Equipment Boiler EQUI43 Null Boiler




Carbon Dioxide Equivalent Equipment Boiler EQUI43 Null Boiler




Carbon Monoxide Equipment Boiler EQUI43 Null Boiler




Boiler EQUI43 Null Boiler

1.39e-071.39e-073.18e-081.55e-081.55e-083.53e-092.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-091.73e-071.73e-073.94e-089.28e-089.28e-082.12e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-092.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-091.73e-071.73e-073.94e-089.28e-089.28e-082.12e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-091.73e-061.73e-063.94e-079.28e-079.28e-072.12e-079.28e-079.28e-072.12e-071.03e-071.03e-072.35e-080.0001580.0001583.61e-058.5e-058.5e-051.94e-058.5e-058.5e-051.94e-059.45e-069.45e-062.16e-0617,26217,2623,9419,2169,2162,1049,2169,2162,1041,0241,02423417,36517,3653,9659,2269,2262,1069,2269,2262,1061,0251,02523412.112.12.766.496.491.486.496.491.483.243.240.74

PTE by pollutant



Pollutant



Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Carbon Monoxide Treatment 023-Flaring TREA2 CE001 FlaringChromium compounds Equipment Boiler EQUI43 Null Boiler




Chrysene Equipment Boiler EQUI43 Null Boiler




Cobalt compounds Equipment Boiler EQUI43 Null Boiler




Dibenz[a,h]anthracene Equipment Boiler EQUI43 Null Boiler




Fluoranthene Equipment Boiler EQUI43 Null Boiler




Fluorene Equipment Boiler EQUI43 Null Boiler




Formaldehyde Equipment Boiler EQUI43 Null Boiler




HAPs - Total Equipment Aboveground Storage Tank EQUI34 TK006 Fresh Methanol Tank 6

EQUI49 TK004 HCl Tank 4

EQUI58 TK007 Process Methanol Tank 7

EQUI61 TK008 Sodium Methylate Tank 8


Distillation Equipment EQUI48 EU009 Biodiesel Distillation

Loading-Unloading Equipment EQUI31 EU003 Biodiesel Loadout

Other Emission Unit EQUI45 EU002 Transesterification Reactors

EQUI54 EU004 Cooling Tower 1



0.0002010.0002014.6e-050.0001080.0001082.47e-050.0001080.0001082.47e-051.2e-051.2e-052.75e-062.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-091.21e-051.21e-052.76e-066.49e-066.49e-061.48e-066.49e-066.49e-061.48e-067.21e-077.21e-071.65e-071.73e-071.73e-073.94e-089.28e-089.28e-082.12e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-094.32e-074.32e-079.85e-082.32e-072.32e-075.29e-082.32e-072.32e-075.29e-082.58e-082.58e-085.88e-094.03e-074.03e-079.2e-082.16e-072.16e-074.94e-082.16e-072.16e-074.94e-082.4e-082.4e-085.49e-090.01080.01080.002460.00580.00580.001320.00580.00580.00132

0.0006440.0006440.0001470.0190.9640.220.390.390.090.0251.260.290.0080.40.0920.2720.2720.0620.126.091.390.525.164.96

0.0522.610.63.013.010.691.591.590.36

PTE by pollutant



Pollutant



Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

HAPs - Total EquipmentOther Emission Unit EQUI60 EU010 Cooling Tower 2Process Heater EQUI32 EU008 Hot Oil Heater #2


Pump EQUI39 EU001 Vacuum Pump (Biodiesel Process)

Separation Equipment EQUI37 EU011 Water Absorber

Fugitive Equipment Leaks FUGI1 FS001 Equipment Leaks (MeOH, ethanol, VOCs)


Hexane Equipment Boiler EQUI43 Null Boiler




Hydrochloric acid Equipment Aboveground Storage Tank EQUI49 TK004 HCl Tank 4

Acid Treatment Equipment EQUI55 EU005 Acidulation

Indeno(1,2,3-cd)pyrene Equipment Boiler EQUI43 Null Boiler




Lead Equipment Boiler EQUI43 Null Boiler




Manganese compounds Equipment Boiler EQUI43 Null Boiler




Mercury Equipment Boiler EQUI43 Null Boiler




Methane Equipment Boiler EQUI43 Null Boiler




Methanol Component Group Air Component Group COMG4 GP003 Facility Limits

Equipment Aboveground Storage Tank EQUI34 TK006 Fresh Methanol Tank 6





EQUI45 EU002 Transesterification Reactors

0.1460.1460.0330.1460.1460.0330.3818.924.320.0251.260.292.792.790.64

0.01620.01620.00370.260.260.05910.140.140.03180.140.140.0318

0.01550.01550.003530.390.390.09000

2.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-097.19e-057.19e-051.64e-053.86e-053.86e-058.82e-063.86e-053.86e-058.82e-064.29e-064.29e-069.8e-075.47e-055.47e-051.25e-052.94e-052.94e-056.71e-062.94e-052.94e-056.71e-063.26e-063.26e-067.45e-073.74e-053.74e-058.54e-062.01e-052.01e-054.59e-062.01e-052.01e-054.59e-062.23e-062.23e-065.1e-07

0.330.330.07550.170.170.03960.170.170.0396

0.01930.01930.00441.250000.9640.2201.260.2900.40.09206.091.39025.164.96

PTE by pollutant



Pollutant



Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Methanol EquipmentLoading-Unloading Equipment EQUI31 EU003 Biodiesel LoadoutOther Emission Unit EQUI45 EU002 Transesterification Reactors






Naphthalene Equipment Boiler EQUI43 Null Boiler




Nickel compounds Equipment Boiler EQUI43 Null Boiler




Nitrogen Oxides Equipment Boiler EQUI43 Null Boiler




Nitrous Oxide Equipment Boiler EQUI43 Null Boiler




Particulate Matter Equipment Boiler EQUI43 Null Boiler

Other Emission Unit EQUI54 EU004 Cooling Tower 1





Phenanthrene Equipment Boiler EQUI43 Null Boiler




PM < 2.5 micron Equipment Boiler EQUI43 Null Boiler







02.610.63.013.010.691.591.590.36018.924.3201.260.29

2.652.790.4268.78e-058.78e-052e-054.71e-054.71e-051.08e-054.71e-054.71e-051.08e-055.24e-065.24e-061.2e-060.0003020.0003026.9e-050.0001620.0001623.71e-050.0001620.0001623.71e-051.8e-051.8e-054.12e-0614.414.43.287.737.731.767.737.731.760.60.60.1360.320.320.07230.0170.0170.003960.0170.0170.00396

0.001930.001930.000441.091.090.250.970.970.220.520.520.120.590.590.1340.590.590.134

0.06530.06530.01492.45e-062.45e-065.58e-071.31e-061.31e-063e-071.31e-061.31e-063e-071.46e-071.46e-073.33e-08

1.091.090.250.00350.00350.00080.0020.0020.000430.590.590.1340.590.590.134

0.06530.06530.0149

PTE by pollutant



Pollutant



Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

PM < 2.5 micron Treatment 023-Flaring TREA2 CE001 FlaringPM < 10 micron Equipment Boiler EQUI43 Null Boiler






Pyrene Equipment Boiler EQUI43 Null Boiler




Selenium compounds Equipment Boiler EQUI43 Null Boiler




Sulfur Dioxide Equipment Boiler EQUI43 Null Boiler




Toluene Equipment Boiler EQUI43 Null Boiler




Volatile OrganicCompounds

Equipment Aboveground Storage Tank EQUI34 TK006 Fresh Methanol Tank 6



Acid Treatment Equipment EQUI38 EU006 Deacidification System




Other Emission Unit EQUI45 EU002 Transesterification Reactors









1.091.090.250.760.760.1740.410.410.0940.590.590.1340.590.590.134

0.06530.06530.01497.19e-077.19e-071.64e-073.86e-073.86e-078.82e-083.86e-073.86e-078.82e-084.29e-084.29e-089.8e-093.45e-063.45e-067.88e-071.86e-061.86e-064.24e-071.86e-061.86e-064.24e-072.06e-072.06e-074.71e-080.08630.08630.01970.04640.04640.01060.04640.04640.01060.005150.005150.001180.0004890.0004890.0001120.0002630.0002636e-050.0002630.0002636e-052.92e-052.92e-056.67e-060.0190.9640.220.0251.260.290.0080.40.0927.257.251.650.790.790.1810.126.091.390.525.164.96

0.0522.610.63.013.010.691.591.590.360.430.430.09710.430.430.09710.3818.924.320.0251.260.292.792.790.4260.660.660.15

PTE by pollutant



Pollutant Subject Item IDSubject ItemDesignation Subject Item Description

Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

1,4-Dichlorobenzene(para-)


EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

2-Methylnaphthalene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

3-Methylcholanthrene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

7,12-Dimethylbenz[a]ant..EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Acenaphthene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Acenaphthylene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Anthracene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

9.28e-059.28e-052.12e-050.0001730.0001733.94e-059.28e-059.28e-052.12e-051.03e-051.03e-052.35e-060.00036890.00036898.415e-051.86e-061.86e-064.24e-073.45e-063.45e-067.88e-071.86e-061.86e-064.24e-072.06e-072.06e-074.71e-087.376e-067.376e-061.6831e-061.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-071.24e-061.24e-062.82e-072.3e-062.3e-065.25e-071.24e-061.24e-062.82e-071.37e-071.37e-073.14e-084.917e-064.917e-061.1204e-061.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-071.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-071.86e-071.86e-074.24e-083.45e-073.45e-077.88e-081.86e-071.86e-074.24e-08

Total PTE by pollutant


Details for:SI Category: NoneSI Type: None


Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

AnthraceneEQUI59 EU007 Hot Oil Heater #1

TREA2 CE001 Flaring

Total

Arsenic compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzo(a)anthracene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzo(b)fluoranthene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzo(ghi)perylene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzo(k)fluoranthene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Benzo[a]pyrene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler

2.06e-082.06e-084.71e-097.376e-077.376e-071.6831e-071.55e-051.55e-053.53e-062.88e-052.88e-056.57e-061.55e-051.55e-053.53e-061.72e-061.72e-063.92e-076.152e-056.152e-051.4022e-050.0001620.0001623.71e-050.0003020.0003026.9e-050.0001620.0001623.71e-051.8e-051.8e-054.12e-060.0006440.0006440.000147321.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-071.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-079.28e-089.28e-082.12e-081.73e-071.73e-073.94e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-093.689e-073.689e-078.415e-081.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-079.28e-089.28e-082.12e-08





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Benzo[a]pyreneEQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Beryllium EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Cadmium compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Carbon Dioxide EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Carbon Dioxide Equivalent EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Carbon Monoxide EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Chromium compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

1.73e-071.73e-073.94e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-093.689e-073.689e-078.415e-089.28e-079.28e-072.12e-071.73e-061.73e-063.94e-079.28e-079.28e-072.12e-071.03e-071.03e-072.35e-083.689e-063.689e-068.415e-078.5e-058.5e-051.94e-050.0001580.0001583.61e-058.5e-058.5e-051.94e-059.45e-069.45e-062.16e-06

0.000337450.000337457.706e-059,2169,2162,10417,26217,2623,9419,2169,2162,1041,0241,02423436,71836,7188,3839,2269,2262,10617,36517,3653,9659,2269,2262,1061,0251,02523436,84236,8428,4116.496.491.4812.112.12.766.496.491.483.243.240.7428.3228.326.46

0.0001080.0001082.47e-050.0002010.0002014.6e-050.0001080.0001082.47e-051.2e-051.2e-052.75e-06





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Chromium compoundsTREA2 CE001 Flaring

Total

Chrysene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Cobalt compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Dibenz[a,h]anthracene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Fluoranthene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Fluorene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Formaldehyde EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

HAPs - Total EQUI31 EU003 Biodiesel Loadout


EQUI34 TK006 Fresh Methanol Tank 6

0.0004290.0004299.815e-051.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-076.49e-066.49e-061.48e-061.21e-051.21e-052.76e-066.49e-066.49e-061.48e-067.21e-077.21e-071.65e-07

2.5801e-052.5801e-055.885e-069.28e-089.28e-082.12e-081.73e-071.73e-073.94e-089.28e-089.28e-082.12e-081.03e-081.03e-082.35e-093.689e-073.689e-078.415e-082.32e-072.32e-075.29e-084.32e-074.32e-079.85e-082.32e-072.32e-075.29e-082.58e-082.58e-085.88e-099.218e-079.218e-072.1018e-072.16e-072.16e-074.94e-084.03e-074.03e-079.2e-082.16e-072.16e-074.94e-082.4e-082.4e-085.49e-098.59e-078.59e-071.9629e-070.00580.00580.001320.01080.01080.002460.00580.00580.00132

0.0006440.0006440.0001470.0230440.0230440.005247

0.525.164.960.1460.1460.033





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

HAPs - TotalEQUI32 EU008 Hot Oil Heater #2


EQUI37 EU011 Water Absorber

EQUI39 EU001 Vacuum Pump (Biodiesel Process)

EQUI43 Null Boiler


EQUI48 EU009 Biodiesel Distillation

EQUI49 TK004 HCl Tank 4






FUGI1 FS001 Equipment Leaks (MeOH, ethanol, VOCs)

TREA2 CE001 Flaring

Total

Hexane EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Hydrochloric acid EQUI49 TK004 HCl Tank 4

EQUI55 EU005 Acidulation

Total

Indeno(1,2,3-cd)pyrene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Lead EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total


0.0190.9640.220.0251.260.290.3818.924.320.2720.2720.0620.0522.610.60.126.091.390.390.390.093.013.010.690.0251.260.290.1460.1460.0331.591.590.360.0080.40.0922.792.790.64

0.01620.01620.00379.489265.024214.07370.140.140.03180.260.260.05910.140.140.0318

0.01550.01550.003530.55550.55550.126230.390.390.09000

0.390.390.091.39e-071.39e-073.18e-082.59e-072.59e-075.91e-081.39e-071.39e-073.18e-081.55e-081.55e-083.53e-095.525e-075.525e-071.2623e-073.86e-053.86e-058.82e-067.19e-057.19e-051.64e-053.86e-053.86e-058.82e-064.29e-064.29e-069.8e-07

0.000153390.000153393.502e-05





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Lead TotalManganese compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Mercury EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Methane EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Methanol COMG4 GP003 Facility Limits

EQUI31 EU003 Biodiesel Loadout











Total

Naphthalene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total


2.94e-052.94e-056.71e-065.47e-055.47e-051.25e-052.94e-052.94e-056.71e-063.26e-063.26e-067.45e-07

0.000116760.000116762.6665e-052.01e-052.01e-054.59e-063.74e-053.74e-058.54e-062.01e-052.01e-054.59e-062.23e-062.23e-065.1e-077.983e-057.983e-051.823e-05

0.170.170.03960.330.330.07550.170.170.0396

0.01930.01930.00440.68930.68930.15911.2500025.164.9600.9640.2201.260.29018.924.3202.610.606.091.39

3.013.010.6901.260.29

1.591.590.3600.40.092

2.652.790.4268.564.05413.638

4.71e-054.71e-051.08e-058.78e-058.78e-052e-054.71e-054.71e-051.08e-055.24e-065.24e-061.2e-06

0.000187240.000187244.28e-05





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

Naphthalene TotalNickel compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Nitrogen Oxides EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Nitrous Oxide EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Particulate Matter EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler




TREA2 CE001 Flaring

Total

Phenanthrene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

PM < 2.5 micron EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler




TREA2 CE001 Flaring

Total

0.0001620.0001623.71e-050.0003020.0003026.9e-050.0001620.0001623.71e-051.8e-051.8e-054.12e-060.0006440.0006440.00014732

7.737.731.7614.414.43.287.737.731.760.60.60.136

30.4630.466.9360.0170.0170.003960.320.320.07230.0170.0170.00396

0.001930.001930.000440.355930.355930.080660.590.590.1341.091.090.250.970.970.220.590.590.1340.520.520.12

0.06530.06530.01493.82533.82530.87291.31e-061.31e-063e-072.45e-062.45e-065.58e-071.31e-061.31e-063e-071.46e-071.46e-073.33e-085.216e-065.216e-061.1913e-06

0.590.590.1341.091.090.25

0.00350.00350.00080.590.590.1340.0020.0020.000430.06530.06530.0149





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)

PM < 2.5 micronTREA2 CE001 Flaring

Total

PM < 10 micron EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler




TREA2 CE001 Flaring

Total

Pyrene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Selenium compounds EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Sulfur Dioxide EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total

Toluene EQUI32 EU008 Hot Oil Heater #2

EQUI43 Null Boiler


TREA2 CE001 Flaring

Total


EQUI31 EU003 Biodiesel Loadout




EQUI38 EU006 Deacidification System


2.34082.34080.534130.590.590.1341.091.090.250.760.760.1740.590.590.1340.410.410.094

0.06530.06530.01493.50533.50530.80093.86e-073.86e-078.82e-087.19e-077.19e-071.64e-073.86e-073.86e-078.82e-084.29e-084.29e-089.8e-09

1.5339e-061.5339e-063.502e-071.86e-061.86e-064.24e-073.45e-063.45e-067.88e-071.86e-061.86e-064.24e-072.06e-072.06e-074.71e-087.376e-067.376e-061.6831e-060.04640.04640.01060.08630.08630.01970.04640.04640.01060.005150.005150.001180.184250.184250.042080.0002630.0002636e-050.0004890.0004890.0001120.0002630.0002636e-052.92e-052.92e-056.67e-060.00104420.00104420.00023867

0.525.164.960.430.430.09710.0190.9640.220.0251.260.297.257.251.65





Potential (lbs/hr)


(tons/yr)

Potential Limited

(tons/yr)

Actual Emissions

(tons/yr)


EQUI38 EU006 Deacidification System


EQUI43 Null Boiler









TREA2 CE001 Flaring

Total

0.3818.924.320.790.790.1810.0522.610.60.126.091.393.013.010.690.0251.260.290.430.430.09711.591.590.360.0080.40.0922.792.790.4260.660.660.15

18.07973.61415.8132




Subject ItemCategoryDescription

Subject Item TypeDescription Subject Item ID SI Designation and Description Relationship

Related SubjectItem ID % Flow

Related Subject ItemType Description

Start Date (RelatedSubject Item)

End Date (RelatedSubject Item)

Equipment AbovegroundStorage Tank

EQUI34 TK006Fresh Methanol Tank 6

is controlledby

TREA2 100 023-Flaring 5/1/2005 Null

sends to STRU1 100 Stack/Vent 6/14/2017 Null



EQUI58 TK007Process Methanol Tank 7

is controlledby



EQUI61 TK008Sodium Methylate Tank 8

is controlledby






EQUI55 EU005Acidulation

is controlledby



Boiler EQUI43NullBoiler


DistillationEquipment

EQUI48 EU009Biodiesel Distillation

is controlledby



is controlledby


SI - SI relationships


Details for:SI Category: EquipmentSI Type: All

Subject ItemCategoryDescription

Subject Item TypeDescription Subject Item ID SI Designation and Description Relationship

Related SubjectItem ID % Flow

Related Subject ItemType Description

Start Date (RelatedSubject Item)

End Date (RelatedSubject Item)

Equipment

DistillationEquipment EQUI48

EU009Biodiesel Distillation sends to STRU1 100 Stack/Vent 5/1/2013 Null

Loading-UnloadingEquipment

EQUI31 EU003Biodiesel Loadout

is controlledby



Other EmissionUnit

EQUI45 EU002Transesterification Reactors

is controlledby







Process Heater EQUI32EU008Hot Oil Heater #2




Pump EQUI39 EU001Vacuum Pump (Biodiesel Process)

is controlledby



SeparationEquipment

EQUI37 EU011Water Absorber

is controlledby



SI - SI relationships


Details for:SI Category: EquipmentSI Type: All

Subject ItemTypeDescription Subject Item ID SI Designation and Description Capacity (gal)Substance Stored

ColumnDiameter (ft)

Number ofColumns Deck Type

InteriorDiameter (ft)

InteriorHeight (ft)

MaximumTrue VaporPressure(psia)

ConstructionType Seal Type

SupportType

AbovegroundStorage Tank

EQUI34TK006Fresh Methanol Tank 6

39000 Methanol Null Null Null 20 17 1.07 Fixed Roof Null Null


15000 Hydrochloric acid Null Null Null 14 13 2.1 Fixed Roof Null Null

EQUI58TK007Process Methanol Tank 7

39000 Methanol Null Null Null 20 17 1.07 Fixed Roof Null Null

EQUI61TK008Sodium Methylate Tank 8

39000 Other Null Null Null 20 17 0.5 Fixed Roof Null Null

Aboveground Storage Tanks, General


Details for:SI Category: EquipmentSI Type: Aboveground Storage Tank

Subject Item TypeDescription Subject Item ID SI Designation and Description Manufacturer Model

Max DesignCapacity

Max DesignCapacity Units(numerator)

Max DesignCapacity Units(denominator) Material

ConstructionStart Date

OperationStart Date

ModificationDate

Subject toCSAPR?

ElectricGeneratingCapacity(MW)



Desmet Desmet Custom 44 million gallons years Product 10/10/2012 5/1/2013 Null Null Null

EQUI55EU005Acidulation

Crown & Iron 8642-20 V-330 44 million gallons years Product 4/1/2004 5/1/2005 Null Null Null

DistillationEquipment EQUI48

EU009Biodiesel Distillation

Pfaudler Group Pfaulder Custom 44 million gallons years Product 10/10/2012 5/1/2013 Null Null Null

Loading-UnloadingEquipment EQUI31

EU003Biodiesel Loadout

Todd & SargentTodd & SargentCustom

44 million gallons years Product 7/1/2004 5/1/2005 Null Null Null

Other Emission UnitEQUI45EU002Transesterification Reactors

Crown Iron 8642-12 V-315 44 million gallons years Product 7/1/2004 5/1/2005 Null Null Null


Tower Tech TTXE-061950 6000 gallons minutes Water 7/1/2004 5/1/2005 Null Null Null


Marley NC Cooling Tower 3000 gallons minutes Water 10/10/2012 5/1/2013 Null Null Null

Process Heater EQUI32EU008Hot Oil Heater #2

Vapor Power ORG-5937-SHK-140 18million Britishthermal units

hours Heat 10/10/2012 5/1/2013 Null Null Null


Vapor Power ORG-5937-SHK-140 18million Britishthermal units

hours Heat 10/10/2012 5/1/2013 Null Null Null

Pump EQUI39EU001Vacuum Pump (Biodiesel Process)

Crown Iron VMX0083KAI-20 44 million gallons years Product 7/1/2004 5/1/2005 Null Null Null

SeparationEquipment EQUI37

EU011Water Absorber

Crown Iron 8642-30 T-381 44 million gallons years Product 7/1/2004 5/1/2005 Null Null Null

Emission Units 1


Details for:SI Category: NoneSI Type: Acid Treatment Equipment, Distillation Equipment, Loading-Unloading Equipment and 4 more

Subject Item TypeDescription Subject Item ID SI Designation and Description Manufacturer Model

Max DesignCapacity

Max DesignCapacity Units(numerator)

Max DesignCapacity Units(denominator) Material

ConstructionStart Date

OperationStart Date

ModificationDate


TBD TBD 33.5million Britishthermal units

hours Heat Null Null Null

Emission Units 2


Details for:SI Category: EquipmentSI Type: Boiler

Subject Item TypeDescription Subject Item ID SI Designation and Description

FiringMethod Engine Use

EngineDisplacement

EngineDisplacementUnits

Subject toCSAPR?

ElectricGeneratingCapacity(MW)


Not coalburning

Null Null Null N Null

Emission Units 2 (continued)


Details for:SI Category: EquipmentSI Type: Boiler

Subject Item TypeDescription Subject Item ID SI Designation and Description Install Year Pollutants Emitted

Equipment Leaks FUGI1 FS001Equipment Leaks (MeOH, ethanol, VOCs)

2005 Methanol


Fugitive Sources


Details for:SI Category: FugitiveSI Type: Equipment Leaks

Subject ItemTypeDescription Subject Item ID SI Designation and Description Height

Units(height) Length

Units(length) Width

Units(width)

Building STRU12NullBLDG 1

21 feet 60 feet 90 feet

STRU13NullBLDG 2


STRU14NullBLDG 6

31 feet 75 feet 74.6 feet

STRU15NullBLDG 7.1


STRU16NullBLDG 7.2


STRU17NullBLDG 8

47 feet 74.6 feet 74.6 feet

STRU18NullBLDG 50


STRU19NullCOOL 2


Buildings, General


Details for:SI Category: StructureSI Type: Building

Subject ItemTypeDescription Subject Item ID SI Designation and Description

Stack Height(feet)

StackDiameter(feet)

Stack Length(feet)

Stack Width(feet)

Stack Flow Rate(cubic ft/min)

DischargeTemperature(°F)

FlowRate/TempInformationSource Discharge Direction

Stack/Vent STRU1SV001Flare Stack

25 3.5 Null Null 3000 100 EstimateUpwards with no cap onstack/vent



STRU5SV010Boiler Stack

21.5 2.17 Null Null 8030 350 EstimateUpwards with no cap onstack/vent




30 Null 10 20 120000 60 EstimateUpwards with no cap onstack/vent

STRU9SV006Deacidification System

4 0.33 Null Null 200 60 Estimate Downward

STRU10SV005HCl Tank



30 Null 20 40 480000 60 EstimateUpwards with no cap onstack/vent

Stack/Vent, General


Details for:SI Category: StructureSI Type: Stack/Vent

Subject ItemTypeDescription Subject Item ID SI Designation and Description Manufacturer Model

InstallationStart Date

PollutantControlled

CaptureEfficiency(%)

Destruction CollectEfficiency (%)

Subject toCAM?

Large orOther PSEU?Efficiency Basis

Otheroperatingparameters?

Other operatingparametersdescription

023-Flaring TREA2CE001Flaring

Westech WGEC2..1/1/2006Volatile OrganicCompounds

100 98 No NullControlEquipment Rule

No Null

Other Control Equipment


Details for:SI Category: TreatmentSI Type: 023-Flaring

Subject ItemID Seq. # Requirement

TFAC 1(04700061)

1

Permit Appendices: This permit contains appendices as listed in the permit Table of Contents. The Permitteeshall comply with all requirements contained in the Appendices. The appendices are as follows:

Appendix A. Insignificant Activities and Applicable Requirements;Appendix B. TRE Index Value Calculation Methods;Appendix C. Flare Calculations;Appendix E. Equipment Leaks Calculation; andAppendix G. 40 CFR pt. 60, subp. A - General Provisions

Modeling parameters in Appendix D. EAW Modeling for Permit No. 04700061-003 and Appendix F. Modeling forPermit No. 04700061-101 are included for reference only as described elsewhere in this permit.

2

Modeled Parameters for PM10, PM2.5, NO2, CO, and SO2: The parameters used in PM10, PM2.5, NO2, CO,and SO2 modeling for an EAW associated with permit number 04700061-003 are listed in Appendix D of thispermit. The parameters used in PM2.5 modeling for permit number 04700061-101 are listed in Appendix F ofthis permit. The parameters describe the operation of the facility at maximum permitted capacity. The purpose oflisting the parameters in the appendix is to provide a benchmark for future changes.

3The Permittee shall comply with National Primary and Secondary Ambient Air Quality Standards, 40 CFR pt. 50,and the Minnesota Ambient Air Quality Standards, Minn. R. 7009.0010 to 7009.0090. Compliance shall bedemonstrated upon written request by the MPCA.

1260

PERMIT SHIELD: Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permitshall be deemed compliance with the specific provision of the applicable requirement identified in the permit asthe basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2,notwithstanding the conditions of this permit specifying compliance practices for applicable requirements, anyperson (including the Permittee) may also use other credible evidence to establish compliance ornoncompliance with applicable requirements.

This permit shall not alter or affect the liability of the Permittee for any violation of applicable requirements priorto or at the time of permit issuance.

1390Circumvention: Do not install or use a device or means that conceals or dilutes emissions, which wouldotherwise violate a federal or state air pollution control rule, without reducing the total amount of pollutantemitted.

1400 Air Pollution Control Equipment: Operate all pollution control equipment whenever the corresponding processequipment and emission units are operated.

1410

Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all airpollution control equipment. At a minimum, the O & M plan shall identify all air pollution control equipment andcontrol practices and shall include a preventative maintenance program for the equipment and practices, adescription of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipmentand practices to proper operation to meet applicable permit conditions, a description of the employee trainingprogram for proper operation and maintenance of the control equipment and practices, and the records kept todemonstrate plan implementation.

1420 Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practicalsteps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may requirefeasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions unitsthat have an unreasonable shutdown or breakdown frequency of process or control equipment shall bepermitted to operate.

40 CFR pt. 60, subp. NNN, 40 CFR pt.60, subp. RRR, Minn. R. 4410.4300,Minn. R. 7007.0800, subp. 2

Minn. R. 4410.4300, Minn. R.7007.0100, subp. 7(A), 7(L), & 7(M),Minn. R. 7007.0800, subp. 4, Minn. R.7007.0800, subps. 1-2, Minn. R.7009.0010-7009.0090, Minn. Stat.116.07, subd. 4a, Minn. Stat. 116.07,subd. 9

Minn. R. 7007.0100, subp. 7(A), 7(L), &7(M), Minn. R. 7007.0800, subp. 1,Minn. R. 7007.0800, subp. 2, Minn. R.7007.0800, subp. 4, Minn. R.7009.0010-7009.0090, Minn. Stat.116.07, subd. 4a, Minn. Stat. 116.07,subd. 9

Minn. R. 7007.1800, (A)(2)

Minn. R. 7011.0020

Minn. R. 7007.0800, subp. 16(J), Minn.R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 14, Minn. R.7007.0800, subp. 16(J)

TSD Requirement (Print version)

Agency Interest Name: REG Albert Lea LLCActivity Number: IND20160003

Subject ItemID Seq. # RequirementTFAC 1(04700061)

1410

Operation and Maintenance Plan: Retain at the stationary source an operation and maintenance plan for all airpollution control equipment. At a minimum, the O & M plan shall identify all air pollution control equipment andcontrol practices and shall include a preventative maintenance program for the equipment and practices, adescription of (the minimum but not necessarily the only) corrective actions to be taken to restore the equipmentand practices to proper operation to meet applicable permit conditions, a description of the employee trainingprogram for proper operation and maintenance of the control equipment and practices, and the records kept todemonstrate plan implementation.

1420

Operation Changes: In any shutdown, breakdown, or deviation the Permittee shall immediately take all practicalsteps to modify operations to reduce the emission of any regulated air pollutant. The Commissioner may requirefeasible and practical modifications in the operation to reduce emissions of air pollutants. No emissions unitsthat have an unreasonable shutdown or breakdown frequency of process or control equipment shall bepermitted to operate.

1430Fugitive Emissions: Do not cause or permit the handling, use, transporting, or storage of any material in amanner which may allow avoidable amounts of particulate matter to become airborne. Comply with all otherrequirements listed in Minn. R. 7011.0150.

1440Noise: The Permittee shall comply with the noise standards set forth in Minn. R. 7030.0010 to 7030.0080 at alltimes during the operation of any emission units. This is a state only requirement and is not enforceable by theEPA Administrator or citizens under the Clean Air Act.

1450 Inspections: The Permittee shall comply with the inspection procedures and requirements as found in Minn. R.7007.0800, subp. 9(A).

1460 The Permittee shall comply with the General Conditions listed in Minn. R. 7007.0800, subp. 16.

1470 Performance Testing: Conduct all performance tests in accordance with Minn. R. ch. 7017 unless otherwisenoted in this permit.

1480

Performance Test Notifications and Submittals:

Performance Test Notification and Plan: due 30 days before each Performance TestPerformance Test Pre-test Meeting: due 7 days before each Performance TestPerformance Test Report: due 45 days after each Performance Test

The Notification, Test Plan, and Test Report must be submitted in a format specified by the commissioner.

1490 Limits set as a result of a performance test (conducted before or after permit issuance) apply until supersededas stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is basedon formal review of a subsequent performance test on the same unit as specified by Minn. R. 7017.2025, subp.3. The limit is final upon issuance of a permit amendment incorporating the change.

Minn. R. 7019.1000, subp. 4

Minn. R. 7011.0150

Minn. R. 7030.0010-7030.0080

Minn. R. 7007.0800, subp. 9(A)

Minn. R. 7007.0800, subp. 16

Minn. R. ch. 7017

Minn. R. 7017.2017, Minn. R.7017.2030, subps. 1-4, Minn. R.7017.2035, subps. 1-2




1480

Performance Test Notifications and Submittals:

Performance Test Notification and Plan: due 30 days before each Performance TestPerformance Test Pre-test Meeting: due 7 days before each Performance TestPerformance Test Report: due 45 days after each Performance Test

The Notification, Test Plan, and Test Report must be submitted in a format specified by the commissioner.

1490

Limits set as a result of a performance test (conducted before or after permit issuance) apply until supersededas stated in the MPCA's Notice of Compliance letter granting preliminary approval. Preliminary approval is basedon formal review of a subsequent performance test on the same unit as specified by Minn. R. 7017.2025, subp.3. The limit is final upon issuance of a permit amendment incorporating the change.

1500

Monitoring Equipment Calibration - The Permittee shall either:

1. Calibrate or replace required monitoring equipment every 12 months; or2. Calibrate at the frequency stated in the manufacturer's specifications.

For each monitor, the Permittee shall maintain a record of all calibrations, including the date conducted, and anycorrective action that resulted. The Permittee shall include the calibration frequencies, procedures, andmanufacturer's specifications (if applicable) in the Operations and Maintenance Plan. Any requirements applyingto continuous emission monitors are listed separately in this permit.

1510

Operation of Monitoring Equipment: Unless noted elsewhere in this permit, monitoring a process or controlequipment connected to that process is not necessary during periods when the process is shutdown, or duringchecks of the monitoring systems, such as calibration checks and zero and span adjustments. If monitoringrecords are required, they should reflect any such periods of process shutdown or checks of the monitoringsystem.

1620

Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for NO2 1-hour NAAQS:Changes that do not require a permit amendment or that require a minor or administrative permit amendment donot trigger the EBD Modeling Submittal requirement. The Permittee shall keep updated records on site of allmodeled NO2 1-hour parameters and emission rates listed in Appendix D. The Permittee shall submit anychanges to modeled NO2 1-hour parameters and emission rates with the next required modeling submittal.

1630

Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for PM10 24-hour NAAQSand MAAQS: Changes that do not require a permit amendment or that require a minor or administrative permitamendment do not trigger the EBD Modeling Submittal requirement. The Permittee shall keep updated recordson site of all modeled PM10 24-hour parameters and emission rates listed in Appendix D. The Permittee shallsubmit any changes to modeled PM10 24-hour parameters and emission rates with the next required modelingsubmittal.

1650

Equivalent or Better Dispersion (EBD) Modeling Triggers (Modeling Not Required) for PM2.5 24-hour andannual NAAQS and MAAQS: Changes that do not require a permit amendment or that require a minor oradministrative permit amendment do not trigger the EBD Modeling Submittal requirement. The Permittee shallkeep updated records on site of all modeled PM2.5 parameters and emission rates listed in Appendix F. ThePermittee shall submit any changes to modeled PM2.5 parameters and emission rates with the next requiredmodeling submittal.

1660

EBD Modeling Triggers (Modeling Required) for NO2 1-hour NAAQS: Changes that require, or would require, amoderate or major permit amendment due to an increase in NO2 emissions and affect any modeled NO2 1-hourparameter or emission rate listed in Appendix D, or an addition to the information documented in Appendix D,trigger the EBD Remodeling Submittal requirement. The Permittee shall include previously made changes tomodeled NO2 1-hour parameters and emission rates listed in Appendix D that did not previously trigger the EBDModeling Submittal requirement with this modeling submittal.

1670 EBD Modeling Triggers (Modeling Required) for PM10 24-hour NAAQS and MAAQS: Changes that require, orwould require, a moderate or major permit amendment due to an increase in PM10 emissions and affect anymodeled PM10 24-hour parameter or emission rate listed in Appendix D, or an addition to the informationdocumented in Appendix D, trigger the EBD Remodeling Submittal requirement. The Permittee shall includepreviously made changes to modeled PM10 24-hour parameters and emission rates listed in Appendix D thatdid not previously trigger the EBD Modeling Submittal requirement with this modeling submittal.

Minn. R. 7017.2025, subp. 3

Minn. R. 7007.0800, subp. 4(D)

Minn. R. 7007.0800, subp. 4(D)


Minn. R. 7007.0100, subp. 7(A), 7(L), &7(M), Minn. R. 7007.0800, subp. 4,Minn. R. 7007.0800, subps. 1-2, Minn.R. 7009.0010-7009.0090, Minn. Stat.116.07, subd. 4a, Minn. Stat. 116.07,subd. 9






1660

EBD Modeling Triggers (Modeling Required) for NO2 1-hour NAAQS: Changes that require, or would require, amoderate or major permit amendment due to an increase in NO2 emissions and affect any modeled NO2 1-hourparameter or emission rate listed in Appendix D, or an addition to the information documented in Appendix D,trigger the EBD Remodeling Submittal requirement. The Permittee shall include previously made changes tomodeled NO2 1-hour parameters and emission rates listed in Appendix D that did not previously trigger the EBDModeling Submittal requirement with this modeling submittal.

1670

EBD Modeling Triggers (Modeling Required) for PM10 24-hour NAAQS and MAAQS: Changes that require, orwould require, a moderate or major permit amendment due to an increase in PM10 emissions and affect anymodeled PM10 24-hour parameter or emission rate listed in Appendix D, or an addition to the informationdocumented in Appendix D, trigger the EBD Remodeling Submittal requirement. The Permittee shall includepreviously made changes to modeled PM10 24-hour parameters and emission rates listed in Appendix D thatdid not previously trigger the EBD Modeling Submittal requirement with this modeling submittal.

1680

EBD Modeling Triggers (Modeling Required) for PM2.5 24-hour and annual NAAQS and MAAQS: Changes thatrequire, or would require, a moderate or major permit amendment due to an increase in PM2.5 emissions andaffect any modeled PM2.5 parameter or emission rate listed in Appendix F, or an addition to the informationdocumented in Appendix F, trigger the EBD Remodeling Submittal requirement. The Permittee shall includepreviously made changes to modeled PM2.5 parameters and emission rates listed in Appendix F that did notpreviously trigger the EBD Modeling Submittal requirement with this modeling submittal.

1690

EBD Modeling Submittal for NO2 1-hour NAAQS: For changes meeting the criteria in the EBD ModelingTriggers (Modeling Required) requirement, the Permittee shall submit an EBD modeling submittal in accordancewith the current version of the MPCA Air Dispersion Modeling Guidance and shall wait for written approval (formajor amendments, in the form of an issued permit amendment; for moderate amendments, in the form of aconstruction authorization letter) before making such changes.

1710

EBD Modeling Submittal for PM10 24-hour NAAQS and MAAQS: For changes meeting the criteria in the EBDModeling Triggers (Modeling Required) requirement, the Permittee shall submit an EBD modeling submittal inaccordance with the current version of the MPCA Air Dispersion Modeling Guidance and shall wait for writtenapproval (for major amendments, in the form of an issued permit amendment; for moderate amendments, in theform of a construction authorization letter) before making such changes.

1720

EBD Modeling Submittal for PM2.5 24-hour and annual NAAQS and MAAQS: For changes meeting the criteriain the EBD Modeling Triggers (Modeling Required) requirement, the Permittee shall submit an EBD modelingsubmittal in accordance with the current version of the MPCA Air Dispersion Modeling Guidance and shall waitfor written approval (for major amendments, in the form of an issued permit amendment; for moderateamendments, in the form of a construction authorization letter) before making such changes.

1740

EBD Modeling Submittal Content for PM10, PM2.5, and NO2: The information submitted must include, for stackand vent sources, source emission rate, location, height, diameters, exit velocity, exit temperature, dischargedirection, use of rain caps or rain hats, and, if applicable, locations and dimensions of nearby buildings. Fornon-stack/vent sources, this includes the source emission rate, location, size and shape, release height, and, ifapplicable, any emission rate scalars, and the initial lateral dimensions and initial vertical dimensions andadjacent building heights.

1750

Outdated EBD Baseline Modeling for PM10, PM2.5, and NO2: Prior to conducting the EBD analysis, thePermittee shall use the current version of the MPCA Air Dispersion Modeling Guidance to determine if theBaseline Modeling (the most recent refined modeling demonstration) is outdated. If the Baseline Modeling isoutdated, the Permittee shall update the Baseline Modeling to be consistent with the current version of theMPCA Air Dispersion Modeling Guidance. The updated modeling will become the new Baseline Modeling.

This requirement does not require the Permittee to complete a new refined modeling demonstration using therevisions made for the EBD demonstration.

1760 EBD Modeling Results for PM2.5: The dispersion characteristics due to the revisions of the information inAppendix F must be equivalent to or better than the dispersion characteristics modeled for Permit No.04700061-101. The Permittee shall demonstrate this equivalency in the proposal.











1750

Outdated EBD Baseline Modeling for PM10, PM2.5, and NO2: Prior to conducting the EBD analysis, thePermittee shall use the current version of the MPCA Air Dispersion Modeling Guidance to determine if theBaseline Modeling (the most recent refined modeling demonstration) is outdated. If the Baseline Modeling isoutdated, the Permittee shall update the Baseline Modeling to be consistent with the current version of theMPCA Air Dispersion Modeling Guidance. The updated modeling will become the new Baseline Modeling.

This requirement does not require the Permittee to complete a new refined modeling demonstration using therevisions made for the EBD demonstration.

1760EBD Modeling Results for PM2.5: The dispersion characteristics due to the revisions of the information inAppendix F must be equivalent to or better than the dispersion characteristics modeled for Permit No.04700061-101. The Permittee shall demonstrate this equivalency in the proposal.

1900

At any time, the Permittee may submit a refined dispersion modeling protocol using the current version of theMPCA modeling guidance in order to demonstrate that predicted ambient concentrations of PM10 and PM2.5are below the NAAQS.

Upon MPCA approval of the modeling protocol, the Permittee may submit refined dispersion modeling resultsusing the current version of the MPCA modeling guidance.

The EBD modeling triggers listed in this permit may be revised based on the results of the refined dispersionmodeling demonstration and MPCA approval. The permit shall be revised to include the revised EBD modelingtriggers by submitting an amendment application to the MPCA.

EBD Modeling Results for NO2: The dispersion characteristics due to the revisions of the information inAppendix D must be equivalent to or better than the dispersion characteristics modeled for Permit No.04700061-003. The Permittee shall demonstrate this equivalency in the proposal.

EBD Modeling Results for PM10: The dispersion characteristics due to the revisions of the information inAppendix D must be equivalent to or better than the dispersion characteristics modeled for permit No.04700061-003. The Permittee shall demonstrate this equivalency in the proposal.

1910Recordkeeping: Maintain records describing any insignificant modifications (as required by Minn. R. 7007.1250,subp. 3) or changes contravening permit terms (as required by Minn. R. 7007.1350, subp. 2), including recordsof the emissions resulting from those changes.

Recordkeeping: Retain all records at the stationary source, unless otherwise specified within this permit, for aperiod of five (5) years from the date of monitoring, sample, measurement, or report. Records which must beretained at this location include all calibration and maintenance records, all original recordings for continuousmonitoring instrumentation, and copies of all reports required by the permit. Records must conform to therequirements listed in Minn. R. 7007.0800, subp. 5(A).

Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of anycontrol equipment or process equipment if the shutdown would cause any increase in the emissions of anyregulated air pollutant. If the owner or operator does not have advance knowledge of the shutdown, notificationshall be made to the Commissioner as soon as possible after the shutdown. However, notification is not requiredin the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 3.

At the time of notification, the owner or operator shall inform the Commissioner of the cause of the shutdownand the estimated duration. The owner or operator shall notify the Commissioner when the shutdown is over.

Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hourduration of any control equipment or process equipment if the breakdown causes any increase in the emissionsof any regulated air pollutant. The 24-hour time period starts when the breakdown was discovered or reasonablyshould have been discovered by the owner or operator. However, notification is not required in thecircumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 2.

At the time of notification or as soon as possible thereafter, the owner or operator shall inform the Commissionerof the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissionerwhen the breakdown is over.



Minn. R. 4410.4300, Minn. R.7007.0100, subp. 7(A), 7(L), & 7(M),Minn. R. 7007.0800, subps. 1-2, Minn.R. 7009.0010-7009.0090, Minn. Stat.116.07, subd. 4a, Minn. Stat. 116.07,subd. 9


Minn. R. 7019.1000, subp. 3

Minn. R. 7007.0800, subp. 5(C)

Minn. R. 7007.0800, subp. 5(B)




1910

Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of a planned shutdown of anycontrol equipment or process equipment if the shutdown would cause any increase in the emissions of anyregulated air pollutant. If the owner or operator does not have advance knowledge of the shutdown, notificationshall be made to the Commissioner as soon as possible after the shutdown. However, notification is not requiredin the circumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 3.

At the time of notification, the owner or operator shall inform the Commissioner of the cause of the shutdownand the estimated duration. The owner or operator shall notify the Commissioner when the shutdown is over.

1920

Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdown of more than one hourduration of any control equipment or process equipment if the breakdown causes any increase in the emissionsof any regulated air pollutant. The 24-hour time period starts when the breakdown was discovered or reasonablyshould have been discovered by the owner or operator. However, notification is not required in thecircumstances outlined in Items A, B and C of Minn. R. 7019.1000, subp. 2.

At the time of notification or as soon as possible thereafter, the owner or operator shall inform the Commissionerof the cause of the breakdown and the estimated duration. The owner or operator shall notify the Commissionerwhen the breakdown is over.

Notification of Deviations Endangering Human Health or the Environment Report: Within 2 working days ofdiscovery, notify the Commissioner in writing of any deviation from permit conditions which could endangerhuman health or the environment. Include the following information in this written description:1. the cause of the deviation;2. the exact dates of the period of the deviation, if the deviation has been corrected;3. whether or not the deviation has been corrected;4. the anticipated time by which the deviation is expected to be corrected, if not yet corrected; and5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of the deviation.

Notification of Deviations Endangering Human Health or the Environment: As soon as possible after discovery,notify the Commissioner or the state duty officer, either orally or by facsimile, of any deviation from permitconditions which could endanger human health or the environment.

1930

The Permittee shall submit a semiannual deviations report : Due semiannually, by the 30th of January and July.The first semiannual report submitted by the Permittee shall cover the calendar half-year in which the permit isissued. The first report of each calendar year covers January 1 - June 30. The second report of each calendaryear covers July 1 - December 31. Submit this on form DRF-2 (Deviation Reporting Form). If no deviations haveoccurred, submit the signed report certifying that there were no deviations.

1940

Application for Permit Amendment: If a permit amendment is needed, submit an application in accordance withthe requirements of Minn. R. 7007.1150 through Minn. R. 7007.1500. Submittal dates vary, depending on thetype of amendment needed.

Upon adoption of a new or amended federal applicable requirement, and if there are 3 or more years remainingin the permit term, the Permittee shall file an application for an amendment within nine months of promulgationof the applicable requirement, pursuant to Minn. R. 7007.0400, subp. 3.

1950

Extension Requests: The Permittee may apply for an Administrative Amendment to extend a deadline in apermit by no more than 120 days, provided the proposed deadline extension meets the requirements of Minn. R.7007.1400, subp. 1(H). Performance testing deadlines from the General Provisions of 40 CFR pt. 60 and pt. 63are examples of deadlines for which the MPCA does not have authority to grant extensions and therefore do notmeet the requirements of Minn. R. 7007.1400, subp. 1(H).

If the Permittee determines that no permit amendment or notification is required prior to making a change, thePermittee must retain records of all calculations required under Minn. R. 7007.1200. For non-expiring permits,these records shall be kept for a period of five years from the date that the change was made. The records shallbe kept at the stationary source for the current calendar year of operation and may be kept at the stationarysource or office of the stationary source for all other years. The records may be maintained in either electronic orpaper format.

The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previouscalendar year). Submit this on form CR-04 (Annual Compliance Certification Report). This report covers alldeviations experienced during the calendar year. If no deviations have occurred, submit the signed reportcertifying that there were no deviations.

Minn. R. 7019.1000, subp. 2

Minn. R. 7019.1000, subp. 1

Minn. R. 7019.1000, subp. 1

Minn. R. 7007.0800, subp. 6(A)(2)

Minn. R. 7007.0400, subp. 3, Minn. R.7007.1150 - 7007.1500

Minn. R. 7007.1400, subp. 1(H)

Minn. R. 7007.1200, subp. 4




1950

If the Permittee determines that no permit amendment or notification is required prior to making a change, thePermittee must retain records of all calculations required under Minn. R. 7007.1200. For non-expiring permits,these records shall be kept for a period of five years from the date that the change was made. The records shallbe kept at the stationary source for the current calendar year of operation and may be kept at the stationarysource or office of the stationary source for all other years. The records may be maintained in either electronic orpaper format.

The Permittee shall submit a compliance certification : Due annually, by the 31st of January (for the previouscalendar year). Submit this on form CR-04 (Annual Compliance Certification Report). This report covers alldeviations experienced during the calendar year. If no deviations have occurred, submit the signed reportcertifying that there were no deviations.

1960 Emission Inventory Report: due on or before April 1 of each calendar year following permit issuance. Submit in aformat specified by the Commissioner.

2030 Emission Fees: due 30 days after receipt of an MPCA bill.

COMG 4(GP003)

2 Methanol <= 1.25 tons per year 12-month rolling sum. The 12-month rolling Sum shall be calculated by the 15thday of each month for the previous 12-month period as described later in this permit.

3

Production <= 44.0 million gallons per year 12-month rolling sum. The 12-month Rolling Sum of biodiesel shallbe calculated by the 15th day of each month as described later in this permit.

This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA)Administrator and citizens under the Clean Air Act.

4

The Permittee shall vent emissions from all emission units listed in COMG 4 to a flare meeting the permitrequirements of TREA 2.

See TREA 2 for requirements for the flare.

5

Monthly Methanol Calculation: By the 15th day of each month, the Permittee shall calculate and record thefollowing:

1) Methanol emissions from biodiesel production for the previous month using the following equation:Methanol emissions from biodiesel production (tons/month) = (EF*H)/2000

where:EF = The emission factor, in pounds per hour, for methanol emissions from the biodiesel production process asdetermined from the last MPCA approved performance test.H = Hours of operation for COMG 4 for the previous month...

6 Daily Recordkeeping: The Permittee shall maintain records of daily biodiesel production on-site.


Minn. R. 7007.0800, subp. 6(C)

Minn. R. 7019.3000-7019.3100

Minn. R. 7002.0005-7002.0095

Title I Condition: Avoid major sourceunder 40 CFR 63, To avoid majorsource under 40 CFR 70.2 & Minn. R.7007.0200

Minn. R. 4410.4300, Minn. R.7007.0800, subp. 2





Subject ItemID Seq. # RequirementCOMG 4(GP003)

5

Monthly Methanol Calculation: By the 15th day of each month, the Permittee shall calculate and record thefollowing:

1) Methanol emissions from biodiesel production for the previous month using the following equation:Methanol emissions from biodiesel production (tons/month) = (EF*H)/2000

where:EF = The emission factor, in pounds per hour, for methanol emissions from the biodiesel production process asdetermined from the last MPCA approved performance test.H = Hours of operation for COMG 4 for the previous month...

6

Daily Recordkeeping: The Permittee shall maintain records of daily biodiesel production on-site.


7

Monthly Recordkeeping - Biodiesel Production: By the 15th of the month, the Permittee shall calculate, record,and maintain the following:

1) The total amount of biodiesel produced in gallons for the previous month based on daily records; and

2) The 12-month rolling sum of biodiesel produced for the previous 12-month period by summing the monthlybiodiesel production data for the previous 12 months.


8 Daily Recordkeeping - Hours of operation: On each day of operation, the Permittee shall record the hours ofoperation for the biodiesel production plant for the previous day of operation.

9 Monthly Recordkeeping - Hours of Operation: By the 15th day of each month, the Permittee shall calculate andrecord the number of operating hours for the previous month.

EQUI 31(EU003)

3680 The Permittee shall vent emissions from EQUI 31 to control equipment meeting the requirements of TREA 2whenever EQUI 31 operates.

3690 Opacity <= 20 percent opacity.

19650 Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas unless required to further reduceemissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735.

5 The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows:

40 CFR 60.1(a);40 CFR 60.2;40 CFR 60.3;40 CFR 60.4;40 CFR 60.7(a)(4);40 CFR 60.14(a);40 CFR 60.14(b);40 CFR 60.14(c);40 CFR 60.14(e);..

Minn. R. 4410.4300, Minn. R.7007.0800, subps. 4-5

Minn. R. 4410.4300, Minn. R.7007.0800, subps. 4-5

Minn. R. 4410.4300, Minn. R.7007.0800, subps. 4-5, Title ICondition: Avoid major source under 40CFR 63, To avoid major source under40 CFR 70.2 & Minn. R. 7007.0200

Minn. R. 4410.4300, Minn. R.7007.0800, subps. 4-5, Title ICondition: Avoid major source under 40CFR 63, To avoid major source under40 CFR 70.2 & Minn. R. 7007.0200


Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)



Subject ItemID Seq. # RequirementEQUI 31(EU003) 19650

Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas unless required to further reduceemissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735.

EQUI 32(EU008)

5

The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows:


6 Permitted Fuels: The Permittee shall burn only natural gas.

7Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gascombusted in Hot Oil Heater #2 during the previous calendar month. These records shall consist of purchaserecords, receipts, or fuel meter readings.

EQUI 34(TK006)




EQUI 37(EU011)



40 CFR pt. 60, subp. A, Minn. R.7007.0400, subp. 3, Minn. R.7007.1150-1500, Minn. R. 7011.0050,Minn. R. 7017.1010, Minn. R.7017.2025, Minn. R. 7019.0100

Minn. R. 7007.0800, subp. 2

40 CFR 60.48c(g), Minn. R. 7011.0570


Minn. R. 7011.0715, subp. 1(A)

Minn. R. 7011.0715, subp. 1(B)




Subject ItemID Seq. # RequirementEQUI 37(EU011)

3680The Permittee shall vent emissions from EQUI 37 to control equipment meeting the requirements of TREA 2whenever EQUI 37 operates.



EQUI 38(EU006)



EQUI 39(EU001)


2


40 CFR 60.1(a);40 CFR 60.1(b);40 CFR 60.2;40 CFR 60.3;40 CFR 60.4;40 CFR 60.7(a)(4);40 CFR 60.7(b);40 CFR 60.8(a);40 CFR 60.8(b); ..

3 The Permittee shall maintain the affected facility such that it has a total resource effectiveness (TRE) indexvalue greater than 8.0.

4 For each vent stream, the Permittee shall maintain a TRE index value greater than 1.0 without use of VOCemission control devices.

Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)

Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)



40 CFR 60.660(c)(4), Minn. R.7011.2900(C)




3The Permittee shall maintain the affected facility such that it has a total resource effectiveness (TRE) indexvalue greater than 8.0.

4 For each vent stream, the Permittee shall maintain a TRE index value greater than 1.0 without use of VOCemission control devices.

5

The test methods in appendix A to 40 CFR pt. 60, except as provided under CFR Section 60.8(b), shall be usedfor determining the net heating value of the gas combusted to determine compliance under 40 CFR Section60.662(b) and for determining the process vent stream TRE index value to determine compliance under 40 CFRSection 60.662(c).

6

For the purposes of complying with 40 CFR Section 60.662(c) the Permittee shall calculate the TRE index valueof the vent stream using the equation for incineration in paragraph (f)(1) of 40 CFR Section 60.664 forhalogenated vent streams. The Permittee shall determine the TRE index value for nonhalogenated vent streamsby calculating values using both the incinerator equation in 40 CFR Section 60.664(f)(1) and the flare equation in40 CFR Section 60.664(f)(2) and selecting the lower of the two values.

7 TRE Index Value Calculation Method: The Permittee shall calculate the TRE index values using both theequations listed in Appendix B of this permit.

8

The Permittee shall recalculate the TRE index value when process changes are made. Examples of processchanges included changes in production capacity, feedstock type, or catalyst type, or whenever there isreplacement, removal, or addition of recovery equipment. The TRE index value shall be recalculated based ontest data, or on best engineering estimates of the effects of the change to the recovery system.

Recalculated index value less than 1.0: Notify the Administrator within 1 week of the recalculation and conduct aperformance test according to the methods and procedures required by 40 CFR Section 60.664 in order todetermine compliance with 40 CFR Section 60.662(a).

Recalculated TRE index value is greater than 1.0, but less than 8.0: Conduct a performance test according tothe methods and procedures required by 40 CFR Sections 60.8 and 60.664 and comply with 40 CFR Section 6..

9

The Permittee shall keep up-to-date, readily accessible records of:

(1) Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal, oraddition of recovery equipment or a distillation unit;

(2) Any recalculation of the TRE index value performed pursuant to 40 CFR Section 60.664(f); and

(3) The results of any performance test performed pursuant to the methods and procedures required by 40 CFRSection 60.664(d).

14 The Permittee shall route the vent stream from the affected facility to a distillation unit subject to 40 CFR pt. 60,subp. NNN. The facility is exempt from all provisions of 40 CFR pt. 60, subp. RRR except for Section 60.705(r).

15 The Permittee shall submit to the Administrator a process design description as part of the initial semiannualreport required by 40 CFR Section 60.665(l). This process design description must be retained for the life of theprocess. No other records or reports are required unless process changes are made.

The process description was submitted on June 18, 2014.

40 CFR 60.662(c), Minn. R.7011.2900(C)

40 CFR 60.664(e), Minn. R.7011.2900(C)

40 CFR 60.664(f), Minn. R.7011.2900(C)

40 CFR 60.664(f)(1) and (2), Minn. R.7011.2900(C)

40 CFR 60.664(g), Minn. R.7011.2900(C)

40 CFR 60.665(h), Minn. R.7011.2900(C)

40 CFR 60.700(c)(5), Minn. R.7011.3430




14The Permittee shall route the vent stream from the affected facility to a distillation unit subject to 40 CFR pt. 60,subp. NNN. The facility is exempt from all provisions of 40 CFR pt. 60, subp. RRR except for Section 60.705(r).

15

The Permittee shall submit to the Administrator a process design description as part of the initial semiannualreport required by 40 CFR Section 60.665(l). This process design description must be retained for the life of theprocess. No other records or reports are required unless process changes are made.

The process description was submitted on June 18, 2014.

19650

The Permittee shall submit to the Administrator semiannual reports: due before end of each half-year starting05/01/2005. The semiannual reports shall contain the following recorded information:

(1) Exceedances of monitored parameters recorded under 40 CFR Section 60.665(c) and (g).(2) All periods recorded under 40 CFR Section 60.665(d) when the vent stream is diverted from the controldevice or has no flow rate.(3) All periods recorded under 40 CFR Section 60.665(e) when the boiler or process heater was not operating.(4) All periods recorded under 40 CFR Section 60.665(f) in which the pilot flame of the flare was absent.

EQUI 43 4The Permittee shall submit a notification of date construction began: Due 30 calendar days after Date ofConstruction Start (or reconstruction). Submit the name and number of the Subject Item and the dateconstruction began.

5 The Permittee shall submit a notification of the actual date of initial startup: Due 15 calendar days after InitialStartup Date.

6


40 CFR 60.1(a);40 CFR 60.2;40 CFR 60.3;40 CFR 60.4;40 CFR 60.7(a)(1);40 CFR 60.7(a)(3);40 CFR 60.7(a)(4);40 CFR 60.14(a);40 CFR 60.14(b);..


8Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gascombusted in the boilers during the previous calendar month. These records shall consist of purchase records,receipts, or fuel meter readings.


40 CFR 60.705(r), Minn. R. 7011.3430

40 CFR 60.665(I), Minn. R.7011.2900(C)

40 CFR 60.48c(a), 40 CFR 60.7(a)(1),Minn. R. 7019.0100, subp. 1

40 CFR 60.7(a)(3), Minn. R.7019.0100, subp. 1


Minn. R. 7007.0800, subp. 2

40 CFR 60.48c(g), Minn. R. 7011.0570



Subject ItemID Seq. # RequirementEQUI 43

8

Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gascombusted in the boilers during the previous calendar month. These records shall consist of purchase records,receipts, or fuel meter readings.

EQUI 45(EU002)


2


40 CFR 60.1(a);40 CFR 60.1(b);40 CFR 60.2;40 CFR 60.3;40 CFR 60.4;40 CFR 60.7(a)(4);40 CFR 60.7(b);40 CFR 60.8(a);40 CFR 60.8(b); ..

3 The Permittee shall maintain the affected facility such that it has a total resource effectiveness (TRE) indexvalue greater than 8.0.

4 The Total Resource Effectiveness (TRE) index value shall be maintained greater than 1.0 without the use of aVOC emission control device.

5 The net heating value shall be calculated using the equation in (d)(4). Methods ASTM D2382-76, D2382-88, orD4809-95, as specified in Section 60.17, shall be used to determine the net heats of combustion.

6TRE index value Calculation Method: The Permittee shall calculate the TRE index values using both of theequations listed in Appendix B, EQUI 45 of this permit (from 40 CFR Sections 60.704(e)(1) and (e)(2)). Thelower of the two values shall be selected.

7

The Permittee shall recalculate the TRE index value for the vent stream using the methods listed in 40 CFRSection 60.704(d) whenever process changes are made. Examples of process changes include changes inproduction capacity, feedstock type, or whenever there is replacement, removal, or addition of recoveryequipment.

Recalculated TRE index value less than 1.0: Notify the Administrator within 1 week of the recalculation andconduct a performance test according to the methods and procedures required by 40 CFR Section 60.704 inorder to determine compliance with 40 CFR Section 60.702(a) or (b).

Recalculated TRE index value greater than 1.0 but less than 8.0: Conduct a performance test according to themethods and procedures required by 40 CFR Sections 60.8 and 60.704 and comply with 40 CFR Sections 60.7..

8 The Permittee shall keep up-to-date, readily accessible records of the following:1. Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal, oraddition of recovery equipment or reactors;2. Any recalculation of the TRE index value performed pursuant to Section 60.704(f); and3. The results of any performance test performed pursuant to the methods and procedures required by Section60.704(d).



40 CFR 60.700(c)(2), Minn. R.7011.3430

40 CFR 60.702(c), Minn. R. 7011.3430

40 CFR 60.704(d), Minn. R. 7011.3430

40 CFR 60.704(e), Minn. R. 7011.3430

40 CFR 60.704(f), Minn. R. 7011.3430




7

The Permittee shall recalculate the TRE index value for the vent stream using the methods listed in 40 CFRSection 60.704(d) whenever process changes are made. Examples of process changes include changes inproduction capacity, feedstock type, or whenever there is replacement, removal, or addition of recoveryequipment.

Recalculated TRE index value less than 1.0: Notify the Administrator within 1 week of the recalculation andconduct a performance test according to the methods and procedures required by 40 CFR Section 60.704 inorder to determine compliance with 40 CFR Section 60.702(a) or (b).

Recalculated TRE index value greater than 1.0 but less than 8.0: Conduct a performance test according to themethods and procedures required by 40 CFR Sections 60.8 and 60.704 and comply with 40 CFR Sections 60.7..

8

The Permittee shall keep up-to-date, readily accessible records of the following:1. Any changes in production capacity, feedstock type, or catalyst type, or of any replacement, removal, oraddition of recovery equipment or reactors;2. Any recalculation of the TRE index value performed pursuant to Section 60.704(f); and3. The results of any performance test performed pursuant to the methods and procedures required by Section60.704(d).

13 The Permittee shall maintain a record of the initial test for determining the total resource effectiveness index andthe results of the initial total resource effectiveness index calculation.

19650

Submit a semiannual deviations report : Due by 30 days after end of each calendar half-year starting09/14/2004. The initial report shall be submitted within 6 months after the initial start-up date. The semiannualdeviation report shall include the following recorded information:1. Exceedances of monitored parameters recorded under Section 60.705(g);2. Any recalculation of the TRE index value, as recorded under Section 60.705(g).

EQUI 48(EU009)




EQUI 49(TK004)



40 CFR 60.705(g), Minn. R. 7011.3430

40 CFR 60.705(t), Minn. R. 7011.3430

40 CFR 60.705(I)(1) and (6), Minn. R.7011.3430


Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)

Minn. R. 7011.0715, subp. 1(B)



Subject ItemID Seq. # RequirementEQUI 49(TK004)



EQUI 55(EU005)




EQUI 58(TK007)




5 The Permittee must comply with all applicable requirements of 40 CFR pt. 60, subp. A as follows:


Minn. R. 7011.0715, subp. 1(A)


Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)


Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)



Subject ItemID Seq. # RequirementEQUI 58(TK007) 19650

Particulate Matter <= 0.30 grains per dry standard cubic foot of exhaust gas unless required to further reduceemissions to comply with the less stringent limit of either Minn. R. 7011.0730 or Minn. R. 7011.0735.

EQUI 59(EU007)

5




7Recordkeeping: By the last day of each calendar month, the Permittee shall record the amount of natural gascombusted in Hot Oil Heater #1 during the previous calendar month. These records shall consist of purchaserecords, receipts, or fuel meter readings.

EQUI 61(TK008)




FUGI 1(FS001)

1

Methanol <= 2.65 tons per year 12-month rolling sum to be calculated by the 15th day of each month for theprevious 12-month period as described later in this permit and using the emission factors listed in Appendix E.

The Permittee shall use the most recent monitored value in place of the screening value when calculatingemissions from gas valves, light liquid valves, light liquid pumps, connectors, pressure relief valves, andagitators.

2 Daily Recordkeeping - Hours of Operation: On each day of operation, the Permittee shall record the hours ofoperation for the biodiesel production plant for the previous day of operation.


Minn. R. 7007.0800, subp. 2

40 CFR 60.48c(g), Minn. R. 7011.0570


Minn. R. 7011.0715, subp. 1(B)

Minn. R. 7011.0715, subp. 1(A)




Subject ItemID Seq. # RequirementFUGI 1(FS001)

1

Methanol <= 2.65 tons per year 12-month rolling sum to be calculated by the 15th day of each month for theprevious 12-month period as described later in this permit and using the emission factors listed in Appendix E.

The Permittee shall use the most recent monitored value in place of the screening value when calculatingemissions from gas valves, light liquid valves, light liquid pumps, connectors, pressure relief valves, andagitators.

2 Daily Recordkeeping - Hours of Operation: On each day of operation, the Permittee shall record the hours ofoperation for the biodiesel production plant for the previous day of operation.

3 Monthly Recordkeeping - Hours of Operation: By the 15th day of each month, the Permittee shall calculate andrecord the number of operating hours for the previous month.

4

Monthly Calculation - Methanol Emissions: By the 15th day of each month, the Permittee shall calculate andrecord the monthly methanol emissions, in tons, using the emission factors determined using the methods listedin Appendix E of this permit and the hours of operation for the month.

By the 15th day of each month the Permittee shall calculate and record the 12-month rolling sum of methanolemissions, in tons, based on methanol emissions for the previous 12 months.

9


40 CFR 60.1(a);40 CFR 60.1(b);40 CFR 60.2;40 CFR 60.3;40 CFR 60.4;40 CFR 60.7(a)(4);40 CFR 60.7(b);40 CFR 60.11(a);40 CFR 60.11(d);..

10 The Permittee shall demonstrate compliance with the requirements of 40 CFR Sections 60.482-1a through60.482-10a or Section 60.480a(e) for all equipment within 180 days of initial startup.

11

Equipment that the Permittee designates as being in VOC service less than 300 hr/yr is excluded from therequirements of 40 CFR Section 60.482-2a - 60.482.11a if it is identified as required in 40 CFR Section60.486(e)(6) and it meets any of the following conditions:1) The equipment is in VOC service only during startup and shutdown, excluding startup and shutdown betweenbatches of the same campaign for a batch process.2) The equipment is in VOC service only during process malfunctions or other emergencies.3) The equipment is backup equipment that is in VOC service only when the primary equipment is out of service.

12 If a dedicated batch process unit operates less than 365 days during a year, the Permittee may monitor at areduced frequency as specified in 40 CFR Section 60.482-1a(f).

13 If the storage vessel is shared with multiple process units, the process unit with the greatest annual amount ofstored materials (predominant use) is the process unit the storage vessel is assigned to. If the storage vessel isshared equally among process units, and one of the process units has equipment subject to 40 CFR pt. 60,subp. VVa, the storage vessel is assigned to that process unit. If the storage vessel is shared equally amongprocess units, none of which have equipment subject to 40 CFR pt. 60, subp. VVa of this part, the storagevessel is assigned to any process unit subject to 40 CFR pt. 60, subp. VV. If the predominant use of the storagevessel varies from year to year, then the Permittee must estimate the predominant use initially and reassessevery 3 years. The Permittee must keep records of the information and supporting calculations that show howpredominant use is determined. All equipment on the storage vessel must be monitored when in VOC service.





40 CFR 60.482-1a(a), Minn. R.7011.2900(D)

40 CFR 60.482-1a(e), Minn. R.7011.2900(D)

40 CFR 60.482-1a(f), Minn. R.7011.2900(D)




12If a dedicated batch process unit operates less than 365 days during a year, the Permittee may monitor at areduced frequency as specified in 40 CFR Section 60.482-1a(f).

13

If the storage vessel is shared with multiple process units, the process unit with the greatest annual amount ofstored materials (predominant use) is the process unit the storage vessel is assigned to. If the storage vessel isshared equally among process units, and one of the process units has equipment subject to 40 CFR pt. 60,subp. VVa, the storage vessel is assigned to that process unit. If the storage vessel is shared equally amongprocess units, none of which have equipment subject to 40 CFR pt. 60, subp. VVa of this part, the storagevessel is assigned to any process unit subject to 40 CFR pt. 60, subp. VV. If the predominant use of the storagevessel varies from year to year, then the Permittee must estimate the predominant use initially and reassessevery 3 years. The Permittee must keep records of the information and supporting calculations that show howpredominant use is determined. All equipment on the storage vessel must be monitored when in VOC service.

14

Pumps in light liquid service:(1) Each pump in light liquid service shall be monitored monthly to detect leaks by the methods specified in 40CFR Section 60.485a(b), except as provided in 40 CFR Section 60.482-1a(c) and (f) and 40 CFR Section60.482-2a(d), (e) and (f). A pump that begins operation in light liquid service after the initial startup date for theprocess unit must be monitored for the first time within 30 days after the end of its startup period, except for apump that replaces a leaking pump and except as provided in Section 60.482-1a(c) and 40 CFR Section60.482-2a(d), (e) and (f).(2) Each pump in light liquid service shall be checked by visual inspection each calendar week for indications ofliquids dripping from the pump seal, except as provided in 40 CFR Section 60.482-1a(f).

15

For the purpose of the requirements of this section of the permit, the instrument reading that defines a leak is asfollows:(i) 5,000 parts per million (ppm) or greater for pumps handling polymerizing monomers;(ii) 2,000 ppm or greater for all other pumps.

16

If there are indications of liquids dripping from the pump seal, the Permittee shall follow one of the proceduresspecified in this item. This requirement does not apply to a pump that was monitored after a previous weeklyinspection and the instrument reading was less than the concentration listed above, whichever is applicable.(i) Monitor the pump within 5 days as specified in 40 CFR Section 60.485a(b). If a leak is detected, the leak shallbe repaired using the procedures in 40 CFR Section 60.482-2a(c).(ii) Designate the visual indications of liquids dripping as a leak, and repair the leak using either the proceduresin 40 CFR Section 60.482-2a(c) or by eliminating the visual indications of liquids dripping.

17

(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days afterit is detected, except as provided in 40 CFR Section 60.482-9a.(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected. Firstattempts at repair include, but are not limited to, the practices described in 40 CFR Section 60.482-2a(c)(2)(i)and (ii), where practicable.(i) Tightening the packing gland nuts;(ii) Ensuring that the seal flush is operating at design pressure and temperature.

18Each pump equipped with a dual mechanical seal system that includes a barrier fluid system is exempt from therequirements of 40 CFR Section 60.482-2a(a), provided the requirements specified in 40 CFR Section60.482-2a(d)(1) through (6) are met.

19

Any pump that is designated, as described as follows, for no detectable emissions, as indicated by aninstrument reading of less than 500 ppm above background, is exempt from the requirements of 40 CFR Section60.482-2a(a), (c), and (d) if the pump:(1) Has no externally actuated shaft penetrating the pump housing;(2) Is demonstrated to be operating with no detectable emissions as indicated by an instrument reading of lessthan 500 ppm above background as measured by the methods specified in 40 CFR Section 60.485a(c); and(3) Is tested for compliance with 40 CFR Section 60.482-2a(e)(2) initially upon designation, annually, and atother times requested by the Commissioner.

20 If any pump is equipped with a closed vent system capable of capturing and transporting any leakage from theseal or seals to a process or to a fuel gas system or to a control device that complies with the requirements of 40CFR Section 60.482-10a, it is exempt from 40 CFR Section 60.482-2a(a) through (e).

40 CFR 60.482-1a(g), Minn. R.7011.2900(D)

40 CFR 60.482-2a(a), Minn. R.7011.2900(D)

40 CFR 60.482-2a(b)(1), Minn. R.7011.2900(D)

40 CFR 60.482-2a(b)(2), Minn. R.7011.2900(D)

40 CFR 60.482-2a(c), Minn. R.7011.2900(D)

40 CFR 60.482-2a(d), Minn. R.7011.2900(D)

40 CFR 60.482-2a(e), Minn. R.7011.2900(D)




19

Any pump that is designated, as described as follows, for no detectable emissions, as indicated by aninstrument reading of less than 500 ppm above background, is exempt from the requirements of 40 CFR Section60.482-2a(a), (c), and (d) if the pump:(1) Has no externally actuated shaft penetrating the pump housing;(2) Is demonstrated to be operating with no detectable emissions as indicated by an instrument reading of lessthan 500 ppm above background as measured by the methods specified in 40 CFR Section 60.485a(c); and(3) Is tested for compliance with 40 CFR Section 60.482-2a(e)(2) initially upon designation, annually, and atother times requested by the Commissioner.

20If any pump is equipped with a closed vent system capable of capturing and transporting any leakage from theseal or seals to a process or to a fuel gas system or to a control device that complies with the requirements of 40CFR Section 60.482-10a, it is exempt from 40 CFR Section 60.482-2a(a) through (e).

21

Any pump that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitor pump isexempt from the monitoring and inspection requirements of 40 CFR Section 60.482-2a(a) and (d)(4) through (6)if:(1) The Permittee demonstrates that the pump is unsafe-to-monitor because monitoring personnel would beexposed to an immediate danger as a consequence of complying with 40 CFR Section 60.482-2a(a); and(2) The Permittee has a written plan that requires monitoring of the pump as frequently as practicable duringsafe-to-monitor times, but not more frequently than the periodic monitoring schedule otherwise applicable, andrepair of the equipment according to the procedures in 40 CFR Section 60.482-2a(c) if a leak is detected.

22

Any pump that is located within the boundary of an unmanned plant site is exempt from the weekly visualinspection requirement of 40 CFR Section 60.482-2a(a)(2) and (d)(4), and the daily requirements of 40 CFRSection 60.482-2a(d)(5), provided that each pump is visually inspected as often as practicable and at leastmonthly.

33Except during pressure releases, each pressure relief device in gas/vapor service shall be operated with nodetectable emissions, as indicated by an instrument reading of less than 500 ppm above background asdetermined by the methods specified in 40 CFR Section 60.485a(c).

34

(1) After each pressure release, the pressure relief device shall be returned to a condition of no detectableemissions, as indicated by an instrument reading of less than 500 ppm above background, as soon aspracticable, but no later than 5 calendar days after the pressure release, except as provided in 40 CFR Section60.482-9a.(2) No later than 5 calendar days after the pressure release, the pressure relief device shall be monitored toconfirm the conditions of no detectable emissions, as indicated by an instrument reading of less than 500 ppmabove background, by the methods specified in 40 CFR Section 60.485a(c).

35Any pressure relief device that is routed to a process or fuel gas system or equipped with a closed vent systemcapable of capturing and transporting leakage through the pressure relief device to a control device as describedin Section 60.482-10a is exempted from the requirements of paragraphs (a) and (b) of 40 CFR 60.482-4a.

36

(1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief device isexempt from the requirements of paragraphs (a) and (b) of 40 CFR 60.482-4a, provided the Permittee complieswith the requirements in paragraph (d)(2) of 40 CFR 60.482-4a.(2) After each pressure release, a new rupture disk shall be installed upstream of the pressure relief device assoon as practicable, but no later than 5 calendar days after each pressure release, except as provided in 40CFR Section 60.482-9a.

37 Each sampling connection system shall be equipped with a closed-purge, closed-loop, or closed-vent system,except as provided in 40 CFR Section 60.482-1a(c) and 40 CFR Section 60.482-5a(c).

40 CFR 60.482-2a(f), Minn. R.7011.2900(D)

40 CFR 60.482-2a(g), Minn. R.7011.2900(D)

40 CFR 60.482-2a(h), Minn. R.7011.2900(D)

40 CFR 60.482-4a(a), Minn. R.7011.2900(D)

40 CFR 60.482-4a(b), Minn. R.7011.2900(D)

40 CFR 60.482-4a(c), Minn. R.7011.2900(D)

40 CFR 60.482-4a(d), Minn. R.7011.2900(D)




36

(1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief device isexempt from the requirements of paragraphs (a) and (b) of 40 CFR 60.482-4a, provided the Permittee complieswith the requirements in paragraph (d)(2) of 40 CFR 60.482-4a.(2) After each pressure release, a new rupture disk shall be installed upstream of the pressure relief device assoon as practicable, but no later than 5 calendar days after each pressure release, except as provided in 40CFR Section 60.482-9a.

37 Each sampling connection system shall be equipped with a closed-purge, closed-loop, or closed-vent system,except as provided in 40 CFR Section 60.482-1a(c) and 40 CFR Section 60.482-5a(c).

38

Each closed-purge, closed-loop, or closed-vent system as required in 40 CFR Section 60.482-5a(a) shall complywith the following requirements:(1) Gases displaced during filling of the sample container are not required to be collected or captured.(2) Containers that are part of a closed-purge system must be covered or closed when not being filled oremptied.(3) Gases remaining in the tubing or piping between the closed-purge system valve(s) and sample containervalve(s) after the valves are closed and the sample container is disconnected are not required to be collected orcaptured.(4) Each closed-purge, closed-loop, or closed-vent system shall be designed and operated to meet requirementsin either 40 CFR Section 60.482-5a(b)(4)(i), (ii), (iii), or (iv).

39 In-situ sampling systems and sampling systems without purges are exempt from the requirements of 40 CFRSection 60.482-5a(a) and (b).

40

(1) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a second valve, except asprovided in 40 CFR 60.482-1a(c) and paragraphs (d) and (e) of this section.(2) The cap, blind flange, plug, or second valve shall seal the open end at all times except during operationsrequiring process fluid flow through the open-ended valve or line.

41 Each open-ended valve or line equipped with a second valve shall be operated in a manner such that the valveon the process fluid end is closed before the second valve is closed.

42When a double block-and-bleed system is being used, the bleed valve or line may remain open duringoperations that require venting the line between the block valves but shall comply with 40 CFR Section60.482-6a(a) at all other times.

43 Open-ended valves or lines in an emergency shutdown system which are designed to open automatically in theevent of a process upset are exempt from the requirements of 40 CFR Section 60.482-6a(a), (b), and (c).

44 Open-ended valves or lines containing materials which would autocatalytically polymerize or would present anexplosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleedsystem as specified in 40 CFR Section 60.482-6a(a) through (c) are exempt from the requirements of 40 CFRSection 60.482-6a(a) through (c).

40 CFR 60.482-5a(a), Minn. R.7011.2900(D)

40 CFR 60.482-5a(b), Minn. R.7011.2900(D)

40 CFR 60.482-5a(c), Minn. R.7011.2900(D)

40 CFR 60.482-6a(a), Minn. R.7011.2900(D)

40 CFR 60.482-6a(b), Minn. R.7011.2900(D)

40 CFR 60.482-6a(c), Minn. R.7011.2900(D)

40 CFR 60.482-6a(d), Minn. R.7011.2900(D)




43Open-ended valves or lines in an emergency shutdown system which are designed to open automatically in theevent of a process upset are exempt from the requirements of 40 CFR Section 60.482-6a(a), (b), and (c).

44

Open-ended valves or lines containing materials which would autocatalytically polymerize or would present anexplosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleedsystem as specified in 40 CFR Section 60.482-6a(a) through (c) are exempt from the requirements of 40 CFRSection 60.482-6a(a) through (c).

45

(1) Each valve shall be monitored monthly to detect leaks by the methods specified in 40 CFR Section60.485a(b) and shall comply with 40 CFR Section 60.482-7a(b) through (e), as detailed in this permit, except asprovided in 40 CFR Section 60.482-7a(f), (g), and (h), 40 CFR Section 60.482-1a(c) and (f), and 40 CFRSections 60.483-1a and 60.483-2a. The valve shall be monitored for the first time within 30 days after the end ofits startup period to ensure proper installation.(2) A valve that begins operation in gas/vapor service or light liquid service after the initial startup date for theprocess unit shall be monitored according to 40 CFR Section 60.482-7a(a)(2), except for a valve that replaces aleaking valve and except as provided in 40 CFR Sections 60.482-7a(f) – (h), 60.482-1a(c); and 60.483-1a and60.483-2a.

46

If the existing valves in the process unit are monitored in accordance with 40 CFR Sections 60.483-1a or60.483-2a, count the new valve as leaking when calculating the percentage of valves leaking as described in 40CFR Section 60.483-2a(b)(5). If less than 2.0 percent of the valves are leaking for that process unit, the valveshall be monitored for the first time during the next scheduled monitoring event for existing valves in the processunit or within 90 days, whichever comes first.

47 If an instrument reading of 500 ppm or greater is measured, a leak is detected.

48

(1)(i) Any valve for which a leak is not detected for 2 successive months may be monitored the first month ofevery quarter, beginning with the next quarter, until a leak is detected.(ii) As an alternative to monitoring all of the valves in the first month of a quarter, an Permittee may elect tosubdivide the process unit into two or three subgroups of valves and monitor each subgroup in a different monthduring the quarter, provided each subgroup is monitored every 3 months. The Permittee must keep records ofthe valves assigned to each subgroup.(2) If a leak is detected, the valve shall be monitored monthly until a leak is not detected for 2 successivemonths.

49(1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days afterthe leak is detected, except as provided in 40 CFR Section 60.482-9a.(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

50

First attempts at repair include, but are not limited to, the following best practices where practicable:(1) Tightening of bonnet bolts;(2) Replacement of bonnet bolts;(3) Tightening of packing gland nuts;(4) Injection of lubricant into lubricated packing.

51 Any valve that is designated, as described in 40 CFR Section 60.486a(e)(2), for no detectable emissions, asindicated by an instrument reading of less than 500 ppm above background, is exempt from the requirements of40 CFR Section 60.482-7a(a) if the valve:(1) Has no external actuating mechanism in contact with the process fluid,(2) Is operated with emissions less than 500 ppm above background as determined by the method specified in40 CFR Section 60.485a(c), and(3) Is tested for compliance with the previous paragraph initially upon designation, annually, and at other timesrequested by the Commissioner.

40 CFR 60.482-6a(e), Minn. R.7011.2900(D)

40 CFR 60.482-7a(a), Minn. R.7011.2900(D)

40 CFR 60.482-7a(a), Minn. R.7011.2900(D)

40 CFR 60.482-7a(b), Minn. R.7011.2900(D)

40 CFR 60.482-7a(c), Minn. R.7011.2900(D)

40 CFR 60.482-7a(d), Minn. R.7011.2900(D)

40 CFR 60.482-7a(e), Minn. R.7011.2900(D)




50

First attempts at repair include, but are not limited to, the following best practices where practicable:(1) Tightening of bonnet bolts;(2) Replacement of bonnet bolts;(3) Tightening of packing gland nuts;(4) Injection of lubricant into lubricated packing.

51

Any valve that is designated, as described in 40 CFR Section 60.486a(e)(2), for no detectable emissions, asindicated by an instrument reading of less than 500 ppm above background, is exempt from the requirements of40 CFR Section 60.482-7a(a) if the valve:(1) Has no external actuating mechanism in contact with the process fluid,(2) Is operated with emissions less than 500 ppm above background as determined by the method specified in40 CFR Section 60.485a(c), and(3) Is tested for compliance with the previous paragraph initially upon designation, annually, and at other timesrequested by the Commissioner.

52

Any valve that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitor valve isexempt from the requirements of 40 CFR Section 60.482-7a(a) if:(1) The Permittee demonstrates that the valve is unsafe to monitor because monitoring personnel would beexposed to an immediate danger as a consequence of complying with 40 CFR Section 60.482-7a(a), and(2) The Permittee adheres to a written plan that requires monitoring of the valve as frequently as practicableduring safe-to-monitor times.

53

Any valve that is designated, as described in 40 CFR Section 60.486a(f)(2), as a difficult-to-monitor valve isexempt from the requirements of 40 CFR Section 60.482-7a(a) if:

(1) The Permittee demonstrates that the valve cannot be monitored without elevating the monitoring personnelmore than 2 meters above a support surface.(2) The process unit within which the valve is located:(i) Becomes an affected facility through 40 CFR Section 60.14 or 60.15 and was constructed on or beforeJanuary 5, 1981; or(ii) Has less than 3.0 percent of its valves designated as difficult-to-monitor by the Permittee.(3) The Permittee follows a written plan that requires monitoring of the valve at least once per calendar year.

54

If evidence of a potential leak is found by visual, audible, olfactory, or any other detection method at pumps,valves, and connectors in heavy liquid service and pressure relief devices in light liquid or heavy liquid service,the Permittee shall follow either one of the following procedures:(1) The Permittee shall monitor the equipment within 5 days by the method specified in 40 CFR Section60.485a(b) and shall comply with the requirements of 40 CFR Section 60.482-8a(b) through (d).(2) The Permittee shall eliminate the visual, audible, olfactory, or other indication of a potential leak within 5calendar days of detection.

55 If an instrument reading of 10,000 ppm or greater is measured, a leak is detected.

56(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days afterit is detected, except as provided in 40 CFR Section 60.482-9a.(2) The first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

57 First attempts at repair include, but are not limited to, the best practices described under 40 CFR Sections60.482-2a(c)(2) and 60.482-7a(e).

58 Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15 days istechnically infeasible without a process unit shutdown. Repair of this equipment shall occur before the end of thenext process unit shutdown. Monitoring to verify repair must occur within 15 days after startup of the processunit.

40 CFR 60.482-7a(f), Minn. R.7011.2900(D)

40 CFR 60.482-7a(g), Minn. R.7011.2900(D)

40 CFR 60.482-7a(h), Minn. R.7011.2900(D)

40 CFR 60.482-8a(a), Minn. R.7011.2900(D)

40 CFR 60.482-8a(b), Minn. R.7011.2900(D)

40 CFR 60.482-8a(c), Minn. R.7011.2900(D)

40 CFR 60.482-8a(d), Minn. R.7011.2900(D)




57First attempts at repair include, but are not limited to, the best practices described under 40 CFR Sections60.482-2a(c)(2) and 60.482-7a(e).

58

Delay of repair of equipment for which leaks have been detected will be allowed if repair within 15 days istechnically infeasible without a process unit shutdown. Repair of this equipment shall occur before the end of thenext process unit shutdown. Monitoring to verify repair must occur within 15 days after startup of the processunit.

59 Delay of repair of equipment will be allowed for equipment which is isolated from the process and which doesnot remain in VOC service.

60

Delay of repair for valves and connectors will be allowed if:(1) The Permittee demonstrates that emissions of purged material resulting from immediate repair are greaterthan the fugitive emissions likely to result from delay of repair, and(2) When repair procedures are effected, the purged material is collected and destroyed or recovered in acontrol device complying with 40 CFR Section 60.482-10a.

61Delay of repair for pumps will be allowed if:(1) Repair required the use of a dual mechanical seal system that includes a barrier fluid system, and(2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.

62

Delay of repair beyond a process unit shutdown will be allowed for a valve, if valve assembly replacement isnecessary during the process unit shutdown, valve assembly supplies have been depleted, and valve assemblysupplies had been sufficiently stocked before the supplies were depleted. Delay of repair beyond the nextprocess unit shutdown will not be allowed unless the next process unit shutdown occurs sooner than 6 monthsafter the first process unit shutdown.

63When delay of repair is allowed for a leaking pump, valve, or connector that remains in service, the pump, valve,or connector may be considered to be repaired and no longer subject to delay of repair requirements if twoconsecutive monthly monitoring instrument readings are below the leak definition.

64If the Permittee utilizes closed vent systems and control devices used to comply with provisions of 40 CFR pt.60, subp. VVa, the Permittee shall comply with the provisions of 40 CFR Section 60.482-10a as detailed in thispermit.

65 Vapor recovery systems (for example, condensers and absorbers) shall be designed and operated to recoverthe VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20parts per million by volume (ppmv), whichever is less stringent.

40 CFR 60.482-9a(a), Minn. R.7011.2900(D)

40 CFR 60.482-9a(b), Minn. R.7011.2900(D)

40 CFR 60.482-9a(c), Minn. R.7011.2900(D)

40 CFR 60.482-9a(d), Minn. R.7011.2900(D)

40 CFR 60.482-9a(e), Minn. R.7011.2900(D)

40 CFR 60.482-9a(f), Minn. R.7011.2900(D)

40 CFR 60.482-10a(a), Minn. R.7011.2900(D)




64

If the Permittee utilizes closed vent systems and control devices used to comply with provisions of 40 CFR pt.60, subp. VVa, the Permittee shall comply with the provisions of 40 CFR Section 60.482-10a as detailed in thispermit.

65Vapor recovery systems (for example, condensers and absorbers) shall be designed and operated to recoverthe VOC emissions vented to them with an efficiency of 95 percent or greater, or to an exit concentration of 20parts per million by volume (ppmv), whichever is less stringent.

66

Enclosed combustion devices shall be designed and operated to reduce the VOC emissions vented to them withan efficiency of 95 percent or greater, or to an exit concentration of 20 ppmv, on a dry basis, corrected to 3percent oxygen, whichever is less stringent or to provide a minimum residence time of 0.75 seconds at aminimum temperature of 816 deg C.

67 Flares used to comply with 40 CFR pt. 60, subp. VVa shall comply with the requirements of 40 CFR Section60.18.

68 The Permittee shall monitor the control devices to ensure that they are operated and maintained in conformancewith their designs.

69

Except as provided in 40 CFR Section 60.482-10a(i) through (k), each closed vent system shall be inspectedaccording to the following procedures:(1) If the vapor collection system or closed vent system is constructed of hard-piping, the Permittee shall complywith the following requirements:(i) Conduct an initial inspection according to the procedures in 40 CFR Section 60.485a(b); and(ii) Conduct annual visual inspections for visible, audible, or olfactory indications of leaks.(2) If the vapor collection system or closed vent system is constructed of ductwork, the Permittee shall:(i) Conduct an initial inspection according to the procedures in 40 CFR Section 60.485a(b); and(ii) Conduct annual inspections according to the procedures in 40 CFR Section 60.485a(b).

70

Leaks, as indicated by an instrument reading greater than 500 ppmv above background or by visual inspections,shall be repaired as soon as practicable except as provided in 40 CFR Section 60.482-10a(h).(1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected.(2) Repair shall be completed no later than 15 calendar days after the leak is detected.

71

Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is technicallyinfeasible without a process unit shut down or if the Permittee determines that emissions resulting fromimmediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of suchequipment shall be complete by the end of the next process unit shutdown.

72 If a vapor collection system or closed vent system is operated under a vacuum, it is exempt from the inspectionrequirements of 40 CFR Section 60.482-10a(f)(1)(i) and f(2).

40 CFR 60.482-10a(b), Minn. R.7011.2900(D)

40 CFR 60.482-10a(c), Minn. R.7011.2900(D)

40 CFR 60.482-10a(d), Minn. R.7011.2900(D)

40 CFR 60.482-10a(e), Minn. R.7011.2900(D)

40 CFR 60.482-10a(f), Minn. R.7011.2900(D)

40 CFR 60.482-10a(g), Minn. R.7011.2900(D)

40 CFR 60.482-10a(h), Minn. R.7011.2900(D)




71

Delay of repair of a closed vent system for which leaks have been detected is allowed if the repair is technicallyinfeasible without a process unit shut down or if the Permittee determines that emissions resulting fromimmediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of suchequipment shall be complete by the end of the next process unit shutdown.

72 If a vapor collection system or closed vent system is operated under a vacuum, it is exempt from the inspectionrequirements of 40 CFR Section 60.482-10a(f)(1)(i) and f(2).

73

Any parts of the closed vent system that are designated, as described in 40 CFR Section 60.482-10a(l)(1), asunsafe to inspect are exempt from the inspection requirements of 40 CFR Section 60.482-10a(f)(1)(i) and (f)(2) ifthey comply with the following requirements:(1) The Permittee determines that the equipment is unsafe to inspect because inspecting personnel would beexposed to an imminent or potential danger as a consequence of complying with 40 CFR Section60.482-10a(f)(1)(i) or (f)(2); and(2) The Permittee has a written plan that requires inspection of the equipment as frequently as practicable duringsafe-to-inspect times.

74

Any parts of the closed vent system that are designated, as described in 40 CFR Section 60.482-10a(l)(2), asdifficult to inspect are exempt from the inspection requirements of 40 CFR Section 60.482-10a(f)(1)(i) and (f)(2)if they comply with the requirements specified in 40 CFR Section 60.482-10a(k)(1) through (3):(1) The Permittee determines that the equipment cannot be inspected without elevating the inspecting personnelmore than 2 meters above a support surface; and(2) The process unit within which the closed vent system is located becomes an affected facility through 40 CFRSections 60.14 or 60.15, or the Permittee designates less than 3.0 percent of the total number of closed ventsystem equipment as difficult to inspect; and(3) The Permittee has a written plan that requires inspection of the equipment at least once every 5 years. Aclosed vent system is exempt from inspection if it is operated under a vacuum.

75

The Permittee shall record the information specified below:(1) Identification of all parts of the closed vent system that are designated as unsafe to inspect, an explanation ofwhy the equipment is unsafe to inspect, and the plan for inspection.(2) Identification of all parts of the closed vent system that are designated as difficult to inspect, an explanationof why the equipment is difficult to inspect, and the plan for inspection.(3) For each inspection during which a leak is detected, a record of the information specified in 40 CFR Section60.486a(c).(4) For each inspection during which no leaks are detected, a record of the inspection , the inspection date, anda statement that no leaks were detected.(5) For each visual inspection conducted in accordance with 40 CFR Section 60.482-10a(f)(1)(ii) during which noleaks are detected, a record of the inspection, the inspection date, and a statement that no leaks were detected.

76 Closed vent systems and control devices used to comply with provisions of 40 CFR pt. 60, subp. VVa shall beoperated at all times when emissions may be vented to them.

77

The Permittee shall initially monitor all connectors in the process unit for leaks by the later of either 12 monthsafter the compliance date or 12 months after initial startup. If all connectors in the process unit have beenmonitored for leaks prior to the compliance date, no initial monitoring is required provided either no processchanges have been made since the monitoring or the Permittee can determine that the results of the monitoring,with or without adjustments, reliably demonstrate compliance despite process changes. If required to monitorbecause of a process change, the Permittee is required to monitor only those connectors involved in the processchange.

78

Except as allowed in 40 CFR Section 60.482-1a(c), 40 CFR Section 60.482-10a, or as specified in 40 CFRSection 60.482-11a(e), the Permittee shall monitor all connectors in gas and vapor and light liquid service asspecified in 40 CFR Sections 60.482-11a(a) and (b)(3).(1) The connectors shall be monitored to detect leaks by the method specified in 40 CFR Section 60.485a(b)and, as applicable, 40 CFR Section 60.485a(c).(2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is detected.(3)The Permittee shall perform monitoring, subsequent to the initial monitoring required in 40 CFR Section60.482-11a(a), as specified in 40 CFR Section 60.482-11a(b)(3)(i) through (iii). The required period in whichmonitoring must be conducted shall be determined from 40 CFR Section 60.482-11a(b)(3)(i) through (iii) usingthe monitoring results from the preceding monitoring period. Depending upon the percent of leaking connectors,each connector may require annual monitoring, or monitoring frequency may be reduced to every 8 years. The ..

79 For use in determining the monitoring frequency, as specified in 40 CFR Section 60.482-11a(a) and (b)(3), thepercent leaking connectors as used in 40 CFR Section 60.482-11a(a) and (b)(3) shall be calculated by using thefollowing equation:%CL= CL/ Ct* 100Where:%CL= Percent of leaking connectors as determined through periodic monitoring required in 40 CFR Section60.482-11a(a) and (b)(3)(i) through (iii).CL= Number of connectors measured at 500 ppm or greater, by the method specified in 40 CFR Section60.485a(b).Ct= Total number of monitored connectors in the process unit or affected facility.

40 CFR 60.482-10a(i), Minn. R.7011.2900(D)

40 CFR 60.482-10a(j), Minn. R.7011.2900(D)

40 CFR 60.482-10a(k), Minn. R.7011.2900(D)

40 CFR 60.482-10a(l), Minn. R.7011.2900(D)

40 CFR 60.482-10a(m), Minn. R.7011.2900(D)

40 CFR 60.482-11a(a), Minn. R.7011.2900(D)

40 CFR 60.482-11a(b), Minn. R.7011.2900(D)




78

Except as allowed in 40 CFR Section 60.482-1a(c), 40 CFR Section 60.482-10a, or as specified in 40 CFRSection 60.482-11a(e), the Permittee shall monitor all connectors in gas and vapor and light liquid service asspecified in 40 CFR Sections 60.482-11a(a) and (b)(3).(1) The connectors shall be monitored to detect leaks by the method specified in 40 CFR Section 60.485a(b)and, as applicable, 40 CFR Section 60.485a(c).(2) If an instrument reading greater than or equal to 500 ppm is measured, a leak is detected.(3)The Permittee shall perform monitoring, subsequent to the initial monitoring required in 40 CFR Section60.482-11a(a), as specified in 40 CFR Section 60.482-11a(b)(3)(i) through (iii). The required period in whichmonitoring must be conducted shall be determined from 40 CFR Section 60.482-11a(b)(3)(i) through (iii) usingthe monitoring results from the preceding monitoring period. Depending upon the percent of leaking connectors,each connector may require annual monitoring, or monitoring frequency may be reduced to every 8 years. The ..

79

For use in determining the monitoring frequency, as specified in 40 CFR Section 60.482-11a(a) and (b)(3), thepercent leaking connectors as used in 40 CFR Section 60.482-11a(a) and (b)(3) shall be calculated by using thefollowing equation:%CL= CL/ Ct* 100Where:%CL= Percent of leaking connectors as determined through periodic monitoring required in 40 CFR Section60.482-11a(a) and (b)(3)(i) through (iii).CL= Number of connectors measured at 500 ppm or greater, by the method specified in 40 CFR Section60.485a(b).Ct= Total number of monitored connectors in the process unit or affected facility.

80

When a leak is detected pursuant to 40 CFR Section 60.482-11a(a) and (b), it shall be repaired as soon aspracticable, but not later than 15 calendar days after it is detected, except as provided in 40 CFR Section60.482-9a. A first attempt at repair as defined in 40 CFR pt. 60, subp. VVa shall be made no later than 5calendar days after the leak is detected.

81

Any connector that is designated, as described in 40 CFR Section 60.486a(f)(1), as an unsafe-to-monitorconnector is exempt from the requirements of 40 CFR Section 60.482-11a(a) and (b)(3)(i) through (iii) if:(1) The Permittee of the connector demonstrates that the connector is unsafe-to-monitor because monitoringpersonnel would be exposed to an immediate danger as a consequence of complying with 40 CFR Section60.482-11a(a) and (b); and(2) The Permittee of the connector has a written plan that requires monitoring of the connector as frequently aspracticable during safe-to-monitor times but not more frequently than the periodic monitoring schedule otherwiseapplicable, and repair of the equipment according to the procedures in 40 CFR Section 60.482-11a(d) if a leak isdetected.

82

Inaccessible, ceramic, or ceramic-lined connectors .(1) Any connector that is inaccessible or that is ceramic or ceramic-lined (e.g., porcelain, glass, or glass-lined), isexempt from the monitoring requirements of 40 CFR Section 60.482-11a(a) and (b), from the leak repairrequirements of 40 CFR Section 60.482-11a(d), and from the recordkeeping and reporting requirements of 40CFR Sections 63.1038 and 63.1039. An inaccessible connector is one that meets any of the provisions specifiedin 40 CFR Section 60.482-11a(f)(1)(i) through (vi), as applicable.(2) If any inaccessible, ceramic, or ceramic-lined connector is observed by visual, audible, olfactory, or othermeans to be leaking, the visual, audible, olfactory or other indications of a leak to the atmosphere shall beeliminated as soon as practical.

83

Except for instrumentation systems and inaccessible, ceramic, or ceramic-lined connectors meeting theprovisions of 40 CFR Section 60.482-11a(f), identify the connectors subject to the requirements of 40 CFR pt.60, subp. VVa. Connectors need not be individually identified if all connectors in a designated area or length ofpipe subject to the provisions of 40 CFR pt. 60, subp. VVa are identified as a group, and the number ofconnectors subject is indicated.

93

The Permittee shall determine compliance with the standards in 40 CFR Sections 60.482-1a through60.482-11a, 60.483a, and 60.484a by:(1) Using Method 21 to determine the presence of leaking sources. The instrument shall be calibrated beforeuse each day of its use by the procedures specified in Method 21 of 40 CFR pt. 60, appendix A-7. The followingcalibration gases shall be used:(i) Zero air (less than 10 ppm of hydrocarbon in air); and(ii) A mixture of methane or n-hexane and air at a concentration no more than 2,000 ppm greater than the leakdefinition concentration of the equipment monitored. If the monitoring instrument's design allows for multiplecalibration scales, then the lower scale shall be calibrated with a calibration gas that is no higher than 2,000 ppmabove the concentration specified as a leak, and the highest scale shall be calibrated with a calibration gas thatis approximately equal to 10,000 ppm. If only one scale on an instrument will be used during monitoring, the Pe..

94The Permittee shall conduct performance tests required in 40 CFR Section 60.8 using as reference methodsand procedures the test methods in 40 CFR pt. 60, appendix A or other methods and procedures as specified in40 CFR pt. 60, subp. VVa, except as provided in 40 CFR Section 60.8(b).

95 The Permittee shall determine compliance with the no-detectable-emissions standards in 40 CFR Section60.482-2a(e), 60.482-3a(i), 60.482-4a, 60.482a(f), and 60.482-10a(e) as follows:(1) The requirements of 40 CFR Section 60.485a(b) shall apply.(2) Method 21 of 40 CFR pt. 60, appendix A-7 shall be used to determine the background level. All potential leakinterfaces shall be traversed as close to the interface as possible. The arithmetic difference between themaximum concentration indicated by the instrument and the background level is compared with 500 ppm fordetermining compliance.

40 CFR 60.482-11a(c), Minn. R.7011.2900(D)

40 CFR 60.482-11a(d), Minn. R.7011.2900(D)

40 CFR 60.482-11a(e), Minn. R.7011.2900(D)

40 CFR 60.482-11a(f), Minn. R.7011.2900(D)

40 CFR 60.482-11a(g), Minn. R.7011.2900(D)

40 CFR 60.485a(b), Minn. R.7011.2900(D)

40 CFR 60.485a(a), Minn. R.7011.2900(D)




94

The Permittee shall conduct performance tests required in 40 CFR Section 60.8 using as reference methodsand procedures the test methods in 40 CFR pt. 60, appendix A or other methods and procedures as specified in40 CFR pt. 60, subp. VVa, except as provided in 40 CFR Section 60.8(b).

95

The Permittee shall determine compliance with the no-detectable-emissions standards in 40 CFR Section60.482-2a(e), 60.482-3a(i), 60.482-4a, 60.482a(f), and 60.482-10a(e) as follows:(1) The requirements of 40 CFR Section 60.485a(b) shall apply.(2) Method 21 of 40 CFR pt. 60, appendix A-7 shall be used to determine the background level. All potential leakinterfaces shall be traversed as close to the interface as possible. The arithmetic difference between themaximum concentration indicated by the instrument and the background level is compared with 500 ppm fordetermining compliance.

96

(d) The Permittee shall test each piece of equipment unless the Permittee demonstrates that a process unit isnot in VOC service, i.e., that the VOC content would never be reasonably expected to exceed 10 percent byweight. For purposes of this demonstration, the following methods and procedures shall be used:(1) Procedures that conform to the general methods in ASTM E260-73, 91, or 96, E168-67, 77, or 92, E169-63,77, or 93 (incorporated by reference—see 40 CFR 60.17) shall be used to determine the percent VOC content inthe process fluid that is contained in or contacts a piece of equipment.(2) Organic compounds that are considered by the Administrator to have negligible photochemical reactivity maybe excluded from the total quantity of organic compounds in determining the VOC content of the process fluid.(3) Engineering judgment may be used to estimate the VOC content, if a piece of equipment had not beenshown previously to be in service. If the Administrator disagrees with the judgment, 40 CFR Section60.485a(d)(1) and (2) of this section shall be used to resolve the disagreement.

97

(e) The Permittee shall demonstrate that a piece of equipment is in light liquid service by showing that all thefollowing conditions apply:(1) The vapor pressure of one or more of the organic components is greater than 0.3 kPa at 20 deg C (1.2 in.H2O at 68 deg F). Standard reference texts or ASTM D2879-83, 96, or 97 (incorporated by reference—see 40CFR 60.17) shall be used to determine the vapor pressures.(2) The total concentration of the pure organic components having a vapor pressure greater than 0.3 kPa at 20deg C (1.2 in. H2O at 68 deg F) is equal to or greater than 20 percent by weight.(3) The fluid is a liquid at operating conditions.

98 (f) Samples used in conjunction with paragraphs (d), (e), and (g) of this section shall be representative of theprocess fluid that is contained in or contacts the equipment or the gas being combusted in the flare.

99

(g) The owner or operator shall determine compliance with the standards of flares as follows:(1) Method 22 of appendix A-7 of this part shall be used to determine visible emissions.(2) A thermocouple or any other equivalent device shall be used to monitor the presence of a pilot flame in theflare.(3) The maximum permitted velocity for air assisted flares shall be computed using the equation in Appendix Cof this permit.

100

When each leak is detected, the following requirements apply:(1) A weatherproof and readily visible identification, marked with the equipment identification number, shall beattached to the leaking equipment.(2) The identification on a valve may be removed after it has been monitored for 2 successive months asspecified in 40 CFR Section 60.482-7a(c) and no leak has been detected during those 2 months.(3) The identification on a connector may be removed after it has been monitored as specified in 40 CFRSection 60.482-11a(b)(3)(iv) and no leak has been detected during that monitoring.(4) The identification on equipment, except on a valve or connector, may be removed after it has been repaired.

101

When each leak is detected the following information shall be recorded in a log and shall be kept for 2 years in areadily accessible location:(1) The instrument and operator identification numbers and the equipment identification number.(2) The date the leak was detected and the dates of each attempt to repair the leak.(3) Repair methods applied in each attempt to repair the leak.(4) Maximum instrument reading measured by Method 21 of appendix A-7 of 40 CFR pt. 60 at the time the leakis successfully repaired or determined to be nonrepairable, except when a pump is repaired by eliminatingindications of liquids dripping.(5) Repair delayed and the reason for the delay if a leak is not repaired within 15 calendar days after discoveryof the leak.(6) The signature of the Permittee whose decision it was that the repair could not be affected without a process..

102 The information pertaining to the design requirements for closed vent systems and required control devicesdescribed in 40 CFR Section 60.482-10a shall be recorded and kept in a readily accessible location:(1) Detailed schematics, design specifications, and piping and instrumentation diagrams.(2) The dates and descriptions of any changes in the design specifications.(3) A description of the parameter(s) monitored per 40 CFR Section 60.482-10a(e), to ensure that controldevices are operated and maintained in conformance with their design and an explanation of why thatparameter(s) was selected.(4) Periods when the closed vent systems and required control devices are not operated as designed, includingperiods when a flare pilot light does not have a flame.(5) Dates of startups and shutdowns of the closed vent systems and required control devices.

40 CFR 60.485a(c), Minn. R.7011.2900(D)

40 CFR 60.485a(d), Minn. R.7011.2900(D)

40 CFR 60.485a(e), Minn. R.7011.2900(D)

40 CFR 60.485a(f), Minn. R.7011.2900(D)

40 CFR 60.485a(g), Minn. R.7011.2900(D)

40 CFR 60.486a(b), Minn. R.7011.2900(D)

40 CFR 60.486a(c), Minn. R.7011.2900(D)




101

When each leak is detected the following information shall be recorded in a log and shall be kept for 2 years in areadily accessible location:(1) The instrument and operator identification numbers and the equipment identification number.(2) The date the leak was detected and the dates of each attempt to repair the leak.(3) Repair methods applied in each attempt to repair the leak.(4) Maximum instrument reading measured by Method 21 of appendix A-7 of 40 CFR pt. 60 at the time the leakis successfully repaired or determined to be nonrepairable, except when a pump is repaired by eliminatingindications of liquids dripping.(5) Repair delayed and the reason for the delay if a leak is not repaired within 15 calendar days after discoveryof the leak.(6) The signature of the Permittee whose decision it was that the repair could not be affected without a process..

102

The information pertaining to the design requirements for closed vent systems and required control devicesdescribed in 40 CFR Section 60.482-10a shall be recorded and kept in a readily accessible location:(1) Detailed schematics, design specifications, and piping and instrumentation diagrams.(2) The dates and descriptions of any changes in the design specifications.(3) A description of the parameter(s) monitored per 40 CFR Section 60.482-10a(e), to ensure that controldevices are operated and maintained in conformance with their design and an explanation of why thatparameter(s) was selected.(4) Periods when the closed vent systems and required control devices are not operated as designed, includingperiods when a flare pilot light does not have a flame.(5) Dates of startups and shutdowns of the closed vent systems and required control devices.

103Information pertaining to all equipment subject to the requirements in 40 CFR Section 60.482-1a to 60.482-11ashall be recorded in a log that is kept in a readily accessible location and contain the information specified in 40CFR Section 486a(e)(1) through (10).

104

The following information pertaining to all valves subject to the requirements of 40 CFR Section 60.482-7a(g)and (h), all pumps subject to the requirements of 40 CFR Section 60.482-2a(g), and all connectors subject to therequirements of 40 CFR Section 60.482-11a(e) shall be recorded in a log that is kept in a readily accessiblelocation:(1) A list of identification numbers for valves, pumps, and connectors that are designated as unsafe-to-monitor,an explanation for each valve, pump, or connector stating why the valve, pump, or connector isunsafe-to-monitor, and the plan for monitoring each valve, pump, or connector.(2) A list of identification numbers for valves that are designated as difficult-to-monitor, an explanation for eachvalve stating why the valve is difficult-to-monitor, and the schedule for monitoring each valve.

105The following information shall be recorded for valves complying with 40 CFR Section 60.483-2a:(1) A schedule of monitoring.(2) The percent of valves found leaking during each monitoring period.

106

The following information shall be recorded in a log that is kept in a readily accessible location:(1) Design criterion required in 40 CFR Sections 60.482-2a(d)(5) and 60.482-3a(e)(2) and explanation of thedesign criterion; and(2) Any changes to this criterion and the reasons for the changes.

107

The following information shall be recorded in a log that is kept in a readily accessible location for use indetermining exemptions as provided in 40 CFR Section 60.480a(d):(1) An analysis demonstrating the design capacity of the affected facility,(2) A statement listing the feed or raw materials and products from the affected facilities and an analysisdemonstrating whether these chemicals are heavy liquids or beverage alcohol, and(3) An analysis demonstrating that equipment is not in VOC service.

108 Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in alog that is kept in a readily accessible location.

109 The provisions of 40 CFR Section 60.7(b) and (d) do not apply to affected facilities subject to 40 CFR pt. 60,subp. VVa.

40 CFR 60.486a(d), Minn. R.7011.2900(D)

40 CFR 60.486a(e), Minn. R.7011.2900(D)

40 CFR 60.486a(f), Minn. R.7011.2900(D)

40 CFR 60.486a(g), Minn. R.7011.2900(D)

40 CFR 60.486a(h), Minn. R.7011.2900(D)

40 CFR 60.486a(i), Minn. R.7011.2900(D)

40 CFR 60.486a(j), Minn. R.7011.2900(D)




108Information and data used to demonstrate that a piece of equipment is not in VOC service shall be recorded in alog that is kept in a readily accessible location.

109 The provisions of 40 CFR Section 60.7(b) and (d) do not apply to affected facilities subject to 40 CFR pt. 60,subp. VVa.

110The Permittee shall submit a report: Due semiannually, effective after Initial Startup, by the 31st of January andJuly that includes the information specified in 40 CFR Section 60.487 and that is summarized at FUGI 1 in thispermit.

112

All semiannual reports to the Commissioner shall include the following information, summarized from theinformation in 40 CFR Section 60.486a; (1) Process unit identification. (2) For each month during thesemiannual reporting period, (i) Number of valves for which leaks were detected as described in 40 CFR Section60.482-7a(b) or 40 CFR 60.483-2a (ii) Number of valves for which leaks were not repaired as required in 40CFR Section 60.482-7a(d)(1), (iii) Number of pumps for which leaks were detected as described in 40 CFRSection 60.482-2a(b), (d)(4)(ii)(A) or (B), or (d)(5)(iii), (iv) Number of pumps for which leaks were not repaired asrequired in 40 CFR Section 60.482-2a(c)(1) and (d)(6),(v) Number of compressors for which leaks were detected as described in 40 CFR Section 60.482-3a(f), (vi)Number of compressors for which leaks were not repaired as required in 40 CFR Section 60.482-3a(g)(1), (vii)Number of connectors for which leaks were detected as described in 40 CFR Section 60.482-11a(b), and (viii)Number of connectors for which leaks were not repaired as required in 40 CFR Section 60.482-11a(d)...

113Notification: If the Permittee elects to comply with the provisions of 40 CFR Sections 60.483-1a or 60.483-2a,the Permittee shall notify the Administrator of the alternative standard selected 90 days before implementingeither of the provisions.

114

Report the results of all performance tests in accordance with 40 CFR Section 60.8. The provisions of 40 CFRSection 60.8(d) do not apply to affected facilities subject to the provisions of 40 CFR pt. 60, subp. VVa exceptthat the Permittee must notify the Commissioner of the schedule for the initial performance tests at least 30 daysbefore the initial performance tests.

TREA 2(CE001)

1The Permittee shall operate and maintain a flare to control emissions from biodiesel processing equipment inmethanol service, including, new and modified biodiesel processing equipment in methanol service thatachieves an overall control efficiency for Methanol >= 98 percent control efficiency.

2The Permittee shall vent emissions from all biodiesel processing equipment, including existing, modified, or newprocessing equipment, to a flare meeting the requirements of TREA 2. The flare shall be operated at all timeswhen emissions may be vented to it.

3 The flare shall be designed and operated with no visible emissions as determined by Method 22, except forperiods not to exceed a total of 5 minutes during any 2 consecutive hours.

40 CFR 60.486a(k), Minn. R.7011.2900(D)

40 CFR 60.487a(a), Minn. R.7011.2900(D)

40 CFR pt. 60, 487a(c), Minn. R.7011.2900(D)

40 CFR 60.487a(d), Minn. R.7011.2900(D)

40 CFR 60.487a(e), Minn. R.7011.2900(D)


40 CFR 60.18(e), Minn. R. 7011.0050,Title I Condition: Avoid major sourceunder 40 CFR 63, To avoid majorsource under 40 CFR 70.2 & Minn. R.7007.0200



Subject ItemID Seq. # RequirementTREA 2(CE001)

2

The Permittee shall vent emissions from all biodiesel processing equipment, including existing, modified, or newprocessing equipment, to a flare meeting the requirements of TREA 2. The flare shall be operated at all timeswhen emissions may be vented to it.

3 The flare shall be designed and operated with no visible emissions as determined by Method 22, except forperiods not to exceed a total of 5 minutes during any 2 consecutive hours.

4 The flare shall be operated with a pilot flame present at all times. The presence of a flare pilot flame shall bemonitored using a thermocouple or other equivalent device to detect the presence of a flame.

5

The flare shall adhere to the following specifications:

(1) The flare shall be used only with the net heating value of the gas being combusted being 300 BTU/scf orgreater if the flare is steam assisted or air assisted; or with the net heating value of the gas being combustedbeing 200 BTU/scf or greater if the flare is nonassisted. The heating value of the gas being combusted shall bedetermined using the methods specified in 40 CFR Section 60.18(f)(3).

(2) Steam-assisted and nonassisted flares shall be designed for and operated with an exit velocity, asdetermined by the methods specified in paragraph (f)(4) of 40 CFR Section 60.18, less than 60 ft/sec, except asprovided in paragraphs (c)(4)(ii) and (iii) of 40 CFR Section 60.18...

6

(1) Method 22 of appendix A of 40 CFR pt. 60 shall be used to determine the compliance of flares with thevisible emission provisions of 40 CFR pt. 60, subp. A. The observation period is 2 hours and shall be usedaccording to Method 22.

(2) The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device todetect the presence of a flame.

(3) The net heating value of the gas being combusted in a flare shall be calculated using the equation inAppendix C.

(4) The actual exit velocity of a flare shall be determined by dividing the volumetric flowrate (in units of standard..

7

At all times, including periods of startup, shutdown, and malfunction, the Permittee shall maintain and operateany affected facility in a manner consistent with good air pollution control practice for minimizing emissions.Determination of whether acceptable operating and maintenance procedures are being used will be based oninformation available to the Administrator which may include, but is not limited to, monitoring results, opacityobservations, review of operating and maintenance procedures, and inspection of the source.

8

The Permittee shall record all periods when the pilot flame is not present during operation of any emissions unitthat vents to the flare. Record the time, duration, cause (if known), and whether or not any emissions werevented to the flare during the period in which the pilot flame was not present. Document the corrective actionstaken to restore the pilot flame.

Periods when the pilot flame is not present during operation of any emissions unit that vents to the flare shall bereported as deviations on the semiannual deviations report. For periods when the pilot flame is not present,emissions shall be calculated assuming uncontrolled operation of the facility for the purposes of calculatingemissions for COMG 4.

Records shall be maintained for a period of 5 years.

Minn. R. 7007.0800, subp. 2, Minn. R.7007.0800, subp. 4

Minn. R. 7007.0800, subp. 4

Minn. R. 7007.0800, subp. 2

Minn. R. 7007.0800, subp. 4

Minn. R. 7007.0800, subp. 14, Minn. R.7007.0800, subp. 16(J)

Minn. R. 7007.0800, subp. 5



Attachment 3 – Points Calculator



Points Calculator

1) AI ID No.: 95817 Total Points 542) Facility Name: REG Albert Lea LLC3) Small business? y/n? n 4) Air Project Tracking Numbers (including all 5686, 5687 5) Date of each Application Received: 10/20/20166) Final Permit No. 04700061-1017) Permit Staff Tyler Johnson

Total TotalApplication Type Air Project Tracking No. Tempo Activity ID Qty. Points Points Additionl Cost DetailsAdministrative Amendment 1 0 -$ Minor Amendment 5687 IND20160004 1 4 4 1,140.00$ Applicability Request 10 0 -$ Moderate Amendment 15 0 -$ Major Amendment 5686 IND20160003 1 25 25 7,125.00$ Individual State Permit (not reissuance) 50 0 -$ Individual Part 70 Permit (not reissuance) 75 0 -$

Additional PointsModeling Review 1 15 15 4,275.00$ PM2.5 Refined Model

BACT Review 15 0 -$ LAER Review 15 0 -$ CAA section 110(a)(2)(D)(i)(I) Review (i.e., Transport Rule/CAIR/CSAPR)

10 0 -$

Part 75 CEM analysis 10 0 -$ NSPS Review 10 0 -$ NESHAP Review 10 0 -$ Case-by-case MACT Review 20 0 -$ Netting 10 0 -$ Limits to remain below threshold 1 10 10 2,850.00$ Limit to Avoid EAWPlantwide Applicability Limit (PAL) 20 0 -$ AERA review 15 0 -$ Variance request under 7000.7000 35 0 -$ Confidentiality request under 7000.1300 2 0 -$ EAW review 0Part 4410.4300, subparts 18, item A; and 29 15 0 -$ Part 4410.4300, subparts 8, items A & B; 10, items A to C; 16, items A & D; 17, items A to C & E to G; and 18, items B & C

35 0 -$

Part 4410.4300, subparts 4; 5 items A & B; 13; 15; 16, items B & C; and 17 item D

70 0 -$

Add'l Points 25

NOTES:

(DQ Points)

Attachment 4 – Schedule of Compliance



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Schedule of Compliance Settlement Offer Not Admissible in Court Proceedings Under Minn. R. Evid. 408

STATE OF MINNESOTA MINNESOTA POLLUTION CONTROL AGENCY

IN THE MATTER OF: REG ALBERT LEA, LLC COMPLIANCE AGREEMENT Part 1. PARTIES. This Compliance Agreement (“Agreement”) applies to and is binding upon the following parties:

a. REG Albert Lea, LLC (“Regulated Party”); and b. The Minnesota Pollution Control Agency (“MPCA”).

Unless specified otherwise in this Agreement, where this Agreement identifies actions to be taken by the MPCA, the Commissioner or the Commissioner’s designees shall act on the MPCA's behalf. Part 2. PURPOSE AND SCOPE OF COMPLIANCE AGREEMENT. The purpose of this Agreement is to establish the terms and conditions that apply to a physical change or a change in operating conditions that the Regulated Party intends to undertake at the facility that would otherwise require an air emissions permit amendment. Nothing in this Agreement allows for changes except for those expressly outlined herein. Nothing in this Agreement relieves the Regulated Party of its obligation to comply with all terms and conditions of its existing air emissions permit that are not modified by this Agreement. Part 3. AUTHORITY. This Agreement is entered under the authority vested in the MPCA by Minn. Stat. ch. 115. Part 4. DEFINITIONS. Unless otherwise explicitly stated, the definitions in Minn. Stat. chs. 115, 115A, 115B, 115C, 116, 116B, and in Minn. R. chs. 7000 to 7151 apply, as appropriate, to the terms used in this Agreement. Part 5. BACKGROUND. The following is the background of this Agreement:

a. The Regulated Party is a limited liability corporation that operates a biodiesel production facility ("Facility") located in Albert Lea, Minnesota.

b. The Regulated Party completed a construction project to include distillation in its biodiesel

refining process in July 2013. This project allowed the Regulated Party to increase the production of biodiesel at its Facility.

c. The MPCA issued the most recent Air Emissions Permit number 04700061‐003 (Permit) to

the Regulated Party on October 6, 2015. The Permit included an increase in the biodiesel production limit to less than or equal to 38.0 million gallons per year, calculated by using a 12‐month rolling sum.

d. In May 2016, the Regulated Party submitted a permit amendment application to increase its

permitted biodiesel production limit, but the MPCA rejected the application for procedural reasons. On October 20, 2016, the Regulated Party resubmitted a major permit amendment application for

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increasing its permitted biodiesel production limit to 44.0 million gallons per year, calculated by using a 12‐month rolling sum. The MPCA deemed the application complete on November 22, 2016.

e. Increasing the permitted biodiesel production limit beyond 38.0 million gallons per year

requires a major permit amendment to the Regulated Party’s air emissions permit. The increase in biodiesel production will cause the Regulated Party to exceed its permitted biodiesel production limit before the MPCA can issue a major amendment to authorize the production increase.

f. The Regulated Party conducted air dispersion modeling in October 2016, which showed that

the Regulated Party can maintain compliance with ambient air standards based on 44.0 million gallons of production. Based on that modeling exercise, the increase in production to 44.0 million gallons per year allowed under this Agreement will not result in noncompliance with ambient air standards.

g. The Regulated Party has agreed to complete an environmental improvement project in

conjunction with exceeding its permitted biodiesel production limit. Part 6. REGULATED PARTY REQUIREMENTS. The Regulated Party agrees to the following:

a. Within 20 days of receipt of this Agreement, the Regulated Party agrees to submit complete documentation, and a statement certifying under penalty of law, demonstrating that no environmental review process under state or federal law is necessary prior to increasing the currently‐permitted biodiesel production limit.

b. Within 30 days of receipt of this Agreement, the Regulated Party agrees to submit a

complete major permit amendment application to increase the currently permitted biodiesel production limit.

...THIS REQUIREMENT HAS BEEN COMPLETED.

c. The Regulated Party agrees to operate its Facility in compliance with the major permit amendment application required under Part 6.b. above, including all associated recordkeeping requirements, and to keep records sufficient to demonstrate compliance until the MPCA issues a new air emissions permit.

d. On or before April 1, 2017, the Regulated Party agrees to replace six existing electric motors

at the Facility. The electric motors to be replaced are the Cooling Tower 1, Cooling Tower 2, Cooling Tower 3, Thermal Fluid 1, Thermal Fluid 2, and Thermal Fluid 3 motors.

e. On or before May 1, 2017, the Regulated Party agrees to submit a statement and records,

such as purchase records, to certify and demonstrate that the replacement of the engines has occurred, as well as a quantification of the energy and associated emissions savings resulting from the installation of the six energy‐efficient electric motors. The quantification shall include megawatt hours and carbon dioxide emissions. Part 7. PENALTIES FOR VIOLATIONS OF THIS AGREEMENT.

a. If the Regulated Party fails to comply with the requirements of Parts 6, a‐e of this Agreement, the Regulated Party shall pay to the MPCA a penalty in the amount of $250 per requirement for each day of failure.

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b. Penalties for failure to comply with requirements of Part 6 of this Agreement shall accrue from the date the Regulated Party was to have fulfilled the requirement until the Regulated Party fulfills the requirement. Penalties shall not accrue while the MPCA considers a timely extension request under Part 11 or during dispute resolution under Part 9, unless the MPCA determines that the Regulated Party filed the request or initiated dispute resolution solely for purposes of delay. If the Regulated Party does not pursue dispute resolution under Part 9 for denial of a timely extension request, penalties shall accrue from the date the extension request is denied by the MPCA Case Contact. If the Regulated Party pursues dispute resolution for denial of an extension request and does not file a timely challenge in a court of competent jurisdiction as provided by Part 9, penalties shall accrue from the date of a Commissioner’s dispute resolution decision against the Regulated Party until the Regulated Party fulfills the requirement that is the subject of the extension request.

c. The Regulated Party shall pay a penalty under this Part within 30 days after receiving written

notice from the MPCA that the penalty is due. The written notice shall specify the provision of the Agreement that the Regulated Party has not fulfilled and indicate the date penalties began to accrue. If the Regulated Party fails to make timely payment, the MPCA may assess and the Regulated Party agrees to pay a late payment charge, in addition to the stipulated penalty, to be assessed as follows. Forty‐five days after receipt of written notice, the Regulated Party shall be obligated to pay a late charge in an amount equal to ten percent of the unpaid stipulated penalty. Sixty days after receipt of written notice, the Regulated Party shall be obligated to pay an additional late charge in an amount equal to 20 percent of the unpaid stipulated penalty.

d. In dispute resolution before the Commissioner under Part 9, the Regulated Party can

contest the factual basis for the MPCA's determination that the Regulated Party has not fulfilled a requirement of this Agreement covered by this Part. However, the Regulated Party waives its right to challenge, on legal grounds, the requirement that it pay penalties under this Part.

e. The Regulated Party shall not be liable for payment of penalties for failure to comply with

requirements of Part 6 of this Agreement covered by this Part if it has submitted to the MPCA a timely request for an extension of schedule under Part 11, and the MPCA has granted the request. The MPCA’s grant of an extension of schedule waives the payment of penalties covered by this Part only on the requirements for which the MPCA granted an extension of schedule and only for the time period specified by the MPCA in the grant of an extension. An extension of schedule for one requirement of Part 6 does not extend the schedule for any other requirement of Part 6.

f. Any requirement of this Agreement may be enforced, as provided in Minn. Stat.§ 115.071 (2008). Payment of a stipulated penalty does not relieve the Regulated Party of its obligation to fulfill and complete requirements under the Agreement and to otherwise comply with the terms and conditions of the Agreement. Part 8. COVENANT NOT TO SUE AND RESERVATION OF REMEDIES. With respect to the Regulated Party, the MPCA agrees not to exercise any administrative, legal or equitable remedies available to the MPCA to address the facility modification or change described in Part 6 as long as the Regulated Party performs according to and has complied with the terms and conditions contained in this Agreement. The MPCA reserves the right to enforce or revoke this Agreement or take any action authorized by law, if the Regulated Party fails to comply with the terms and conditions of this Agreement.

a. Further, the MPCA reserves the right to seek to enjoin violations of this Agreement and to exercise its emergency powers pursuant to Minn. Stat. § 116.11 (2008) in the event conditions or the

4

Regulated Party’s conduct warrant such action. Nothing in this Agreement shall prevent the MPCA from exercising these rights and nothing in this Agreement constitutes a waiver of these rights.

b. The Regulated Party agrees to waive all claims it may now have, as of the effective date of

this Agreement, under Minn. Stat. § 15.472 for fees and expenses arising out of matters leading up to and addressed in this Agreement. Part 9. RESOLUTION OF DISPUTES. The parties to this Agreement shall resolve disputes that arise as to any part of the Agreement as follows:

a. Either party, acting through its Case Contact (as defined in Part 12 below), may initiate dispute resolution by providing to the Case Contact of the other party an initial written statement setting forth the matter in dispute, the position of the party, and the information the party is relying upon to support its position.

b. The other party, acting through its Case Contact, shall provide a written statement of its

position and supporting information to the case contact of the initiating party within 14 calendar days after receipt of the initial written statement.

c. If the parties, acting through their Case Contacts, do not reach a resolution of the dispute

and reduce such resolution to writing in a form agreed upon by the parties within 21 calendar days after the initiating party receives the statement of position from the responding party, the Commissioner shall issue a written decision resolving the dispute. The written decision may address stipulated penalties assessed pursuant to Part 7. The Commissioner's decision shall be considered a final decision of the MPCA for purposes of judicial review.

d. The Commissioner's decision shall become an integral and enforceable part of this Agreement unless the Regulated Party timely challenges the decision in a court of competent jurisdiction. Failure to timely challenge means the Regulated Party agrees to comply with the MPCA Commissioner’s decision on the matter in dispute and to pay any penalties that accrue pursuant to Part 7 for failure to fulfill requirements of this Agreement that are the subject of the dispute resolution. Further, if the Commissioner’s decision assesses penalties pursuant to Part 7 of this Agreement, the Regulated Party agrees to and shall pay the amount of penalty determined by the Commissioner within 60 days after receiving the Commissioner’s decision.

e. Throughout any dispute resolution, the Regulated Party shall comply with all portions of the Agreement that the MPCA determines are not in dispute. Part 10. VENUE. Actions brought by the MPCA to enforce requirements and terms of this Agreement shall be venued in Ramsey County District Court. Part 11. EXTENSION OF SCHEDULES. If the Regulated Party wants an extension of a deadline included in a schedule set out in Part 6, the Regulated Party must request the extension in writing at least 10 days before the scheduled deadline, or as soon as possible before that date if the reason for the extension request arises less than 10 days before the deadline. Each deadline extension request shall separately specify the reason why the extension is needed. No requested extension shall be effective until approved in writing by the MPCA, acting through the MPCA Case Contact or the Commissioner.

5

The MPCA shall grant an extension only for the period of time the MPCA determines is reasonable under the circumstances. The written approval or grant of an extension request shall be considered an enforceable part of the Agreement. The Regulated Party has the burden of demonstrating to the satisfaction of the MPCA that the request for the extension is timely, and that good cause exists for granting the extension. Good cause can include, but is not limited to, the following:

a. Circumstances beyond the reasonable control of the Regulated Party. b. Delays caused by the MPCA in reviewing timely submittals required by this Agreement, the

Regulated Party submitted in complete and approvable form, which make it not feasible for the Regulated Party to meet the required schedules.

c. Good cause does not include unanticipated costs, increases in the cost of control

equipment, or delays in MPCA review of submittals when the submittals are not in complete and approvable form.

d. The Regulated Party may challenge a decision by the MPCA to deny a request for an

extension under Part 9. Part 12. CASE CONTACT. The MPCA and the Regulated Party shall each designate a Case Contact for the purpose of overseeing the implementation of this Agreement. The MPCA Case Contact is Jenna Ness. The Regulated Party's Case Contact is Julie Ingoli. Either party may change its designated Case Contact by notifying the other party in writing within five days of the change. To the extent possible, communications between the Regulated Party and the MPCA concerning the terms and conditions of this Agreement shall be directed through the Case Contacts. The address and telephone number of the MPCA’s Case Contact is: 520 Lafayette Road North, St. Paul, Minnesota 55155, 651‐757‐2082. The address and telephone number of the Regulated Party’s Case Contact is: 15200 ‐ 780th Avenue, Albert Lea, Minnesota 56007‐7082, 515‐239‐8192. Part 13. REGULATED PARTY INFORMATION. The Regulated Party shall not knowingly make any false statement, representation or certification in any record, report, plan or other document filed or required to be submitted to the MPCA under this Agreement. The Regulated Party shall immediately upon discovery report to the MPCA any errors in such record, report, plan or other document. Part 14. REVIEW OF SUBMITTALS. The MPCA, acting through its Commissioner, Case Contact, or other designated MPCA staff, shall review all submittals made by the Regulated Party as required by this Agreement and shall notify the Regulated Party in writing of the approval or disapproval of each submittal, if applicable. The MPCA and the Regulated Party shall consult with each other upon the request of either party during the review of submittals. If any submittal is disapproved in whole or in part, the MPCA Commissioner or designated MPCA staff shall notify the Regulated Party of the specific inadequacies and shall indicate the necessary amendments or reviews. Within 15 calendar days after receipt of any notice of disapproval, the Regulated Party shall submit revisions and take actions to correct the inadequacies. Part 15. ACCESS. During the term of this Agreement, the Regulated Party agrees to provide the MPCA and its staff access to the Facility and its records and documents related to the implementation of this

6

Agreement to the extent provided under Minn. Stat. § 116.091 (2008) or other law, conditioned only upon the presentation of credentials. Part 16. SAMPLING AND DATA AVAILABILITY. The Regulated Party shall make available to the MPCA the results of any sampling, tests, or other data generated by the Regulated Party, or on its behalf, to implement the requirements of this Agreement. Part 17. RETENTION OF RECORDS. The Regulated Party shall retain in its possession all records, documents, reports and data related to this Agreement. The Regulated Party shall preserve these records, documents, reports and data for a minimum of three years after the termination of this Agreement despite any document retention policy of the Regulated Party to the contrary, and shall promptly make all such documentation available for review upon request by the MPCA. Part 18. APPLICABLE LAWS AND PERMITS. The Regulated Party shall undertake all actions required pursuant to this Agreement. Except when the MPCA has specified and authorized a different compliance method in Part 6, the Regulated Party must comply with all applicable permits, orders, stipulation Agreements and schedules of compliance. Nothing in this Agreement exempts or relieves the Regulated Party of its obligation to comply with local governmental requirements. Part 19. OTHER CLAIMS. Nothing herein shall release the Regulated Party from any claims, causes of action or demands in law or equity by any person, firm, partnership or corporation not a signatory to this Agreement for any liability it may have arising out of or relating to the release of any pollutant or contaminant from its operations or from a facility. Neither the Regulated Party nor the MPCA shall be held as a party to any contract entered into by the other party to implement the requirements of this Agreement. Part 20. HOLD HARMLESS. The Regulated Party agrees to indemnify, save and hold the MPCA, its agents and employees harmless from any and all claims or causes of action arising from or on account of acts or omissions of the Regulated Party, its officers, employees, agents, or contractors in implementing the activities conducted pursuant to this Agreement; provided, however, that the Regulated Party shall not indemnify the MPCA or save or hold its employees and agents harmless from any claims or causes of action arising out of the acts or omissions of the MPCA, or its employees and agents. When the Regulated Party is required to hold the MPCA harmless, the MPCA shall give the Regulated Party notice of any claim or cause of action subject to this Part and the Regulated Party has the right to participate in the defense against any claim or cause of action. No settlement shall be effective against the Regulated Party unless the Regulated Party agrees to the settlement. Nothing herein waives or modifies the provisions of the Minnesota Tort Claims Act, Minn. Stat. §§ 3.732, et seq., and other applicable law. Part 21. SUCCESSORS, AGENTS AND CONTRACTORS. This Agreement shall be binding upon the Regulated Party and its successors and assigns and upon the MPCA, its successors and assigns. If the Regulated Party sells or otherwise conveys or assigns any of its right, title or interest in the Facility, the conveyance shall not release the Regulated Party from any obligation imposed by this Agreement, unless the party to whom the right, title or interest has been transferred or assigned agrees in writing to fulfill the obligations of this Agreement and the MPCA approves the transfer or assignment. The Regulated Party shall ensure that the Regulated Party’s agents, contractors and subsidiaries comply with the terms and conditions of this Agreement.

7

Part 22. AMENDMENTS. Except with respect to extensions of schedules granted under Part 11 and approved submittals under Part 14, this Agreement may be amended only by written agreement between the parties. Part 23. EFFECTIVE DATE. This Agreement shall be effective on the date it is signed by the MPCA. Part 24. TERMINATION. The MPCA may revoke this Agreement at any time if the MPCA determines that the Regulated Party did not or is not acting in good faith with regard to this Agreement or the permitting actions pending before the MPCA. The provisions of this Agreement shall be deemed satisfied and terminated when the Regulated Party receives written notice from the MPCA that the Regulated Party Requirements have been completed and a revised air emission permit is in effect. Part 25. SURVIVAL. The provisions of Parts 6.d., 6.e., 8, 10, 17, 18, 19, 20, and 21, of this Schedule and the rights, duties, and obligations of the MPCA and the Regulated Party created in those provisions shall survive termination of this Agreement.

8

BY THEIR SIGNATURES BELOW, THE UNDERSIGNED REPRESENT THAT THEY HAVE AUTHORITY TO BIND THE PARTIES THEY REPRESENT

REG ALBERT LEA. LLC By:

Brad Albin Vice President of Manufacturing

Date:

STATE OF MINNESOTA POLLUTION CONTROL AGENCY By:

Jeff J. Smith Division Director Industrial Division

Date:

New Mexico Environment Department Air Quality Bureau Technical Memorandum: Calculating TSP, PM-10 and PM-2.5 from Cooling Towers



Attachment 5 –

TECHNICAL MEMORANDUM

DATE: September 9, 2013

TO: All Permitting Staff

FROM: Daren Zigich

THROUGH: Ted Schooley, Permit Program Manager Ned Jerabek, Major Source Section Manager

SUBJECT: Calculating TSP, PM-10 and PM-2.5 from Cooling Towers

The goal of this memo is to offer a Department approved step-by-step approach for calculating particulate emissions from cooling towers. While the Department encourages using this approach, other approaches, that do not use a droplet settling ratio may be approved on a case-by-case basis.

Due to the variability of methods used by permittees to estimate particulate emissions from cooling towers, a consistent, defensible approach is warranted. For example, some permittees have used a droplet settling ratio from Reference 3 to lower the total potential emissions rate of total particulate matter (PMtotal). This is unacceptable due to the following:

1. Particulate settling is not appropriate since any verification testing would becompleted inside the cooling tower fan stack. All particulate mass that can bemeasured by an EPA reference method and are emitted to the atmosphere shall becounted as particulate emissions. Particle size distribution can then be used to modifythe emission rate of each regulated particulate size.

2. The Department is not aware of information that verifies the droplet settling data isrepresentative for arid climates where evaporation rates are high.

3. The droplet size distribution and % mass data from Reference 1 only considerdroplets up to 600 microns. Reference 3 states that settling only exists for dropletsgreater than 450 microns. Reference 1 lists the % mass of droplets greater than 450microns to be less than 1 percent of the total mass.

SUSANA MARTINEZ Governor

JOHN A. SANCHEZ Lieutenant Governor

RYAN FLYNN Cabinet Secretary-Designate

BUTCH TONGATE Deputy Secretary

NEW MEXICO ENVIRONMENT DEPARTMENT

Air Quality Bureau

525 Camino de los Marquez, Suite 1 Santa Fe, New Mexico, 87505

Phone (505) 476-4300 Fax (505) 476-4375www.env.nm.gov

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4. Reference 2 test data shows that towers with significant drift droplet diameters greater than 600 microns usually suffer from poor installation of the drift eliminator or from poor water distribution due to issues with the tower packing. Large droplets may indicate that the assumed or guaranteed drift eliminator efficiency is not being met. Providing emissions credit for poor installation, operation or maintenance runs counter to general Department practice.

5. References 1 and 2 make no reference to and assign no credit for the settling theory stated in Reference 3.

For the above reasons, the Reference 3 settling ratio is not an acceptable emissions reduction approach. Acceptable Calculation Method

Cooling tower particulate emissions are a function of the Drift rate and the concentration of dissolved solids present in the water. The Drift rate is normally listed as a percentage of the circulating water flow rate of the cooling tower. Step 1 – Establish maximum water circulation rate (Qcirc) for the cooling tower. This is usually dependent on the capacity of the circulation pumps and the plant cooling system and should be reported as gallons per minute (gpm). The circulation rate is the sum of the circulation rates for each cell in the tower and thus represents the total flow for the tower. Step 2 – Establish Drift rate (Qdrift) of the cooling tower. This information is dependent on the drift eliminator design and is usually supplied by the tower manufacturer. If manufacturer data is unavailable, the standard drift of 0.02 percent, listed in AP-42, should be used. Step 3 – Establish maximum Total Dissolved Solids concentration (TDS) in the circulating cooling water. This is dependent on the facility’s operations. TDS should be reported as parts per million (ppm) or mg/l. Step 4 – Calculate total potential hourly particulate emissions (PMtotal) in pounds per hour

(lbs/hr).

PMtotal = TDS(mg/l) x 1(lbs/mg) x 3.785(l/gal) x Qcirc(gpm) x Qdrift(%Qcirc) x 60(min/hr) 453,600 100 Example: TDS = 3000 ppm or mg/l, Qcirc = 50,000 gpm, Qdrift = 0.004%

PMtotal = 3000 x (1/453,600) x 3.785 x 50,000 x (0.004/100) x 60

PMtotal = 3.0 lbs/hr

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Step 5 – Estimate particulate size distribution of the PMtotal to determine potential emissions of TSP/PM, PM10 and PM2.5.

The current estimating technique used in References 1 and 2 employs a formula for determining a potential particulate size (i.e. diameter) for a given set of variables. The variables are:

dd = Drift droplet diameter, microns CTDS = Concentration of TDS in the circulating water, ppm x 10-6

ρw = Density of Drift droplet, g/cm3 ρsalt = Density of particle, g/cm3

The equation for determining particle size/diameter (dp), in microns is: dp = _______dd_______

(ρsalt / ρwCTDS)1/3 The tables below list particle size related to droplet size for various concentrations (1000 ppm to 12,000 ppm) of TDS in the circulating cooling water. The density of the water droplet (ρw) is assumed to be 1.0 g/cm3 (based on density of pure water) and the average density of the TDS salts is assumed to be 2.5 g/cm3. This assumed density is selected based on the average density of common TDS constituents, CaCO3, CaSO4, CaCl2 NaCl, Na2SO4, and Na2CO3. If actual circulating water constituents are available, that data may be used to estimate the dissolved solids average density.

To determine the droplet size that generates particulate matter of the applicable regulated diameters, TSP/PM (defined as 30 microns or less per NM AQB definition1), PM10 and PM2.5, find the column in the table that matches the maximum circulating water TDS concentration and read the values associated with the PM2.5, PM10 and TSP/PM boxes. Boxed values are not exactly equal to the applicable sizes, but are the values greater than and closest to the applicable sizes, given the listed water droplet values from Reference 1.

The far right column of each table provides mass distribution data from Reference 1. The values indicate what percent of the total particulate mass emission, calculated in Step 4, is associated with the applicable particulate size. Read the value that is on the same line (same color) as the applicable particulate size associated with the specified TDS concentration column. Note: Although the relationship between droplet size and percent mass is not linear, a linear interpolation of the tabulated data is acceptable between two adjacent rows (particle size) to determine an estimate of percent mass for a specific particle size (i.e. PM30, PM10 and PM2.5). Particle sizes for droplets with a non-listed TDS ppm concentration may be calculated using the equation in Step 5.

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Example: Continuing from Step 4,

PMtotal = 3.0 lbs/hr CTDS = 3000 ppm

From Table:

PM2.5: dd = 30 %Mass = 0.226% PM10: dd = 110 %Mass = 70.509%

TSP/PM: dd = 270 %Mass = 96.288% The mass emission of each applicable particulate size is: PM2.5 = PMtotal(%Mass/100) = 3.0(0.00226) = 0.007 lbs/hr PM10 = 3.0(.70509) = 2.115 lbs/hr

TSP/PM = 3.0(.96288) = 2.889 lbs/hr

1Definition of TSP for purposes of permitting emission sources, 11/2/09, see P:\AQB-Permits-Section\NSR-TV-Common\Permitting-Guidance-Documents – Index & Links document

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Size Distribution% Mass

dd dp dd dp dd dp <10 0.7387304 10 0.930527 10 1.0650435 020 1.4774608 20 1.8610539 20 2.130087 PM2.5 0.19630 2.2161912 30 2.7915809 PM2.5 30 3.1951306 PM2.5 0.22640 2.9549216 PM2.5 40 3.7221079 40 4.2601741 0.51450 3.693652 50 4.6526349 50 5.3252176 1.81660 4.4323825 60 5.5831618 60 6.3902611 5.70270 5.1711129 70 6.5136888 70 7.4553046 21.34890 6.6485737 90 8.3747427 90 9.5853917 49.812

110 8.1260345 110 10.235797 PM10 110 11.715479 PM10 70.509130 9.6034953 130 12.096851 130 13.845566 82.023150 11.080956 PM10 150 13.957905 150 15.975653 88.012180 13.297147 180 16.749485 180 19.170783 91.032210 15.513339 210 19.541066 210 22.365914 92.468240 17.72953 240 22.332647 240 25.561045 94.091270 19.945721 270 25.124228 270 28.756175 94.689300 22.161912 300 27.915809 300 31.951306 TSP/PM30 96.288350 25.855564 350 32.568444 TSP/PM30 350 37.276523 97.011400 29.549216 400 37.221079 400 42.601741 98.34450 33.242868 TSP/PM30 450 41.873714 450 47.926958 99.071500 36.93652 500 46.526349 500 53.252176 99.071600 44.323825 600 55.831618 600 63.902611 100

1000 ppm (TDS) 2000 ppm 3000 ppm

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dd dp dd dp dd dp <10 1.1721197 10 1.2625337 10 1.3415607 020 2.3442393 20 2.5250675 PM2.5 20 2.6831215 PM2.5 0.19630 3.516359 PM2.5 30 3.7876012 30 4.0246822 0.22640 4.6884787 40 5.0501349 40 5.366243 0.51450 5.8605984 50 6.3126686 50 6.7078037 1.81660 7.032718 60 7.5752024 60 8.0493645 5.70270 8.2048377 70 8.8377361 70 9.3909252 21.34890 10.549077 PM10 90 11.362804 PM10 90 12.074047 PM10 49.812

110 12.893316 110 13.887871 110 14.757168 70.509130 15.237556 130 16.412938 130 17.44029 82.023150 17.581795 150 18.938006 150 20.123411 88.012180 21.098154 180 22.725607 180 24.148093 91.032210 24.614513 210 26.513208 210 28.172776 92.468240 28.130872 240 30.300809 TSP/PM30 240 32.197458 TSP/PM30 94.091270 31.647231 TSP/PM30 270 34.088411 270 36.22214 94.689300 35.16359 300 37.876012 300 40.246822 96.288350 41.024188 350 44.18868 350 46.954626 97.011400 46.884787 400 50.501349 400 53.66243 98.34450 52.745385 450 56.814018 450 60.370234 99.071500 58.605984 500 63.126686 500 67.078037 99.071600 70.32718 600 75.752024 600 80.493645 100

4000 ppm (TDS) 5000 ppm 6000 ppm

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dd dp dd dp dd dp <10 1.4122241 10 1.4764371 10 1.5354962 020 2.8244482 PM2.5 20 2.9528742 PM2.5 20 3.0709923 PM2.5 0.19630 4.2366724 30 4.4293112 30 4.6064885 0.22640 5.6488965 40 5.9057483 40 6.1419846 0.51450 7.0611206 50 7.3821854 50 7.6774808 1.81660 8.4733447 60 8.8586225 60 9.2129769 5.70270 9.8855688 70 10.33506 PM10 70 10.748473 PM10 21.34890 12.710017 PM10 90 13.287934 90 13.819465 49.812

110 15.534465 110 16.240808 110 16.890458 70.509130 18.358914 130 19.193682 130 19.96145 82.023150 21.183362 150 22.146556 150 23.032442 88.012180 25.420034 180 26.575867 180 27.638931 91.032210 29.656707 210 31.005179 TSP/PM30 210 32.245419 TSP/PM30 92.468240 33.893379 TSP/PM30 240 35.43449 240 36.851908 94.091270 38.130051 270 39.863801 270 41.458396 94.689300 42.366724 300 44.293112 300 46.064885 96.288350 49.427844 350 51.675298 350 53.742365 97.011400 56.488965 400 59.057483 400 61.419846 98.34450 63.550085 450 66.439668 450 69.097327 99.071500 70.611206 500 73.821854 500 76.774808 99.071600 84.733447 600 88.586225 600 92.129769 100

7000 ppm (TDS) 8000 ppm 9000 ppm

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dd dp dd dp dd dp <10 1.5903253 10 1.6416091 10 1.6898701 020 3.1806507 PM2.5 20 3.2832181 PM2.5 20 3.3797403 PM2.5 0.19630 4.770976 30 4.9248272 30 5.0696104 0.22640 6.3613013 40 6.5664363 40 6.7594806 0.51450 7.9516267 50 8.2080453 50 8.4493507 1.81660 9.541952 60 9.8496544 60 10.139221 PM10 5.70270 11.132277 PM10 70 11.491263 PM10 70 11.829091 21.34890 14.312928 90 14.774482 90 15.208831 49.812

110 17.493579 110 18.0577 110 18.588572 70.509130 20.674229 130 21.340918 130 21.968312 82.023150 23.85488 150 24.624136 150 25.348052 88.012180 28.625856 180 29.548963 180 30.417663 TSP/PM30 91.032210 33.396832 TSP/PM30 210 34.47379 TSP/PM30 210 35.487273 92.468240 38.167808 240 39.398618 240 40.556883 94.091270 42.938784 270 44.323445 270 45.626494 94.689300 47.70976 300 49.248272 300 50.696104 96.288350 55.661387 350 57.456317 350 59.145455 97.011400 63.613013 400 65.664363 400 67.594806 98.34450 71.56464 450 73.872408 450 76.044156 99.071500 79.516267 500 82.080453 500 84.493507 99.071600 95.41952 600 98.496544 600 101.39221 100

10,000 ppm (TDS) 11,000 ppm 12,000 ppm

References

1. Calculating Realistic PM10 Emissions from Cooling Towers, Abstract No. 216 Session No. AS-1b, J. Reisman and G. Frisbie, Greyston Environmental Consultants, Inc.

2. Cooling Tower Particulate Matter and Drift Rate Emissions Testing Using the Cooling Technology Institute Test Code – CTI ATC-140, August 2003 EPRI Cooling Tower Technology Conference, K. Hennnon, P.E., D. Wheeler, P.E., Power Generation Technology.

3. Effects of Pathogenic and Toxic Materials Transported Via Cooling Device Drift, Vol. 1 Technical Report, EPA-600/7-79-251a, H.D. Freudenthal, J.E. Rubinstein, and A. Uzzo, November 1979.

TANKS Reports



Attachment 6 –

TANKS 4.0.9dEmissions Report - Detail Format

Tank Indentification and Physical Characteristics

IdentificationUser Identification: TK 004City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Hydrochloric Acid

Tank DimensionsShell Height (ft): 13.00Diameter (ft): 14.00Liquid Height (ft) : 12.00Avg. Liquid Height (ft): 7.00Volume (gallons): 13,818.48Turnovers: 35.10Net Throughput(gal/yr): 485,000.00Is Tank Heated (y/n): N

Paint CharacteristicsShell Color/Shade: Gray/LightShell Condition GoodRoof Color/Shade: Gray/LightRoof Condition: Good

Roof CharacteristicsType: DomeHeight (ft) 0.50Radius (ft) (Dome Roof) 7.00

Breather Vent SettingsVacuum Settings (psig): 0.00Pressure Settings (psig) 0.00

Meterological Data used in Emissions Calculations: Rochester, Minnesota (Avg Atmospheric Pressure = 14.04 psia)

Page 1 of 6TANKS 4.0 Report

8/24/2017file:///C:/Program%20Files%20(x86)/Tanks409d/summarydisplay.htm

TANKS 4.0.9dEmissions Report - Detail Format Liquid Contents of Storage Tank

TK 004 - Vertical Fixed Roof TankAlbert Lea, Minnesota

Daily Liquid Surf.Temperature (deg F)

LiquidBulk

Temp Vapor Pressure (psia)Vapor

Mol.LiquidMass

VaporMass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Hydrochloric Acid 35% All 49.97 41.85 58.10 45.77 1.3291 1.0610 1.6053 36.4600 36.46 Option 1: VP40 = 1 VP50 = 1.33




Detail Calculations (AP-42)


Annual Emission CalcaulationsStanding Losses (lb): 230.2990 Vapor Space Volume (cu ft): 962.1782 Vapor Density (lb/cu ft): 0.0089 Vapor Space Expansion Factor: 0.1066 Vented Vapor Saturation Factor: 0.6943

Tank Vapor Space Volume: Vapor Space Volume (cu ft): 962.1782 Tank Diameter (ft): 14.0000 Vapor Space Outage (ft): 6.2504 Tank Shell Height (ft): 13.0000 Average Liquid Height (ft): 7.0000 Roof Outage (ft): 0.2504

Roof Outage (Dome Roof) Roof Outage (ft): 0.2504 Dome Radius (ft): 7.0000 Shell Radius (ft): 7.0000

Vapor Density Vapor Density (lb/cu ft): 0.0089 Vapor Molecular Weight (lb/lb-mole): 36.4600 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 1.3291 Daily Avg. Liquid Surface Temp. (deg. R): 509.6420 Daily Average Ambient Temp. (deg. F): 43.5292 Ideal Gas Constant R (psia cuft / (lb-mol-deg R)): 10.731 Liquid Bulk Temperature (deg. R): 505.4392 Tank Paint Solar Absorptance (Shell): 0.5400 Tank Paint Solar Absorptance (Roof): 0.5400 Daily Total Solar Insulation Factor (Btu/sqft day): 1,216.2281

Vapor Space Expansion Factor Vapor Space Expansion Factor: 0.1066 Daily Vapor Temperature Range (deg. R): 32.4954 Daily Vapor Pressure Range (psia): 0.5443 Breather Vent Press. Setting Range(psia): 0.0000 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 1.3291 Vapor Pressure at Daily Minimum Liquid Surface Temperature (psia): 1.0610 Vapor Pressure at Daily Maximum Liquid Surface Temperature (psia): 1.6053 Daily Avg. Liquid Surface Temp. (deg R): 509.6420 Daily Min. Liquid Surface Temp. (deg R): 501.5182 Daily Max. Liquid Surface Temp. (deg R): 517.7658 Daily Ambient Temp. Range (deg. R): 19.5917

Vented Vapor Saturation Factor Vented Vapor Saturation Factor: 0.6943 Vapor Pressure at Daily Average Liquid: Surface Temperature (psia): 1.3291 Vapor Space Outage (ft): 6.2504

Working Losses (lb): 559.5757 Vapor Molecular Weight (lb/lb-mole): 36.4600 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 1.3291 Annual Net Throughput (gal/yr.): 485,000.0000 Annual Turnovers: 35.0979 Turnover Factor: 1.0000 Maximum Liquid Volume (gal): 13,818.4838 Maximum Liquid Height (ft): 12.0000 Tank Diameter (ft): 14.0000 Working Loss Product Factor: 1.0000

Total Losses (lb): 789.8747



TANKS 4.0.9dEmissions Report - Detail Format Individual Tank Emission Totals

Emissions Report for: Annual


Losses(lbs)Components Working Loss Breathing Loss Total EmissionsHydrochloric Acid 35% 559.58 230.30 789.87





IdentificationUser Identification: TK 006City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Fresh Methanol Tank 6

Tank DimensionsShell Height (ft): 16.50Diameter (ft): 20.00Liquid Height (ft) : 16.00Avg. Liquid Height (ft): 10.00Volume (gallons): 37,601.32Turnovers: 117.02Net Throughput(gal/yr): 4,400,000.00Is Tank Heated (y/n): N

Paint CharacteristicsShell Color/Shade: Aluminum/DiffuseShell Condition GoodRoof Color/Shade: Aluminum/DiffuseRoof Condition: Good

Roof CharacteristicsType: ConeHeight (ft) 2.00Slope (ft/ft) (Cone Roof) 0.20

Breather Vent SettingsVacuum Settings (psig): -0.03Pressure Settings (psig) 0.03







LiquidBulk


Mol.LiquidMass



Methyl alcohol All 50.75 42.12 59.38 46.13 1.0709 0.8017 1.4144 32.0400 32.04 Option 2: A=7.897, B=1474.08, C=229.13






Annual Emission CalcaulationsStanding Losses (lb): 403.6313 Vapor Space Volume (cu ft): 2,251.4747 Vapor Density (lb/cu ft): 0.0063 Vapor Space Expansion Factor: 0.1103 Vented Vapor Saturation Factor: 0.7108

Tank Vapor Space Volume: Vapor Space Volume (cu ft): 2,251.4747 Tank Diameter (ft): 20.0000 Vapor Space Outage (ft): 7.1667 Tank Shell Height (ft): 16.5000 Average Liquid Height (ft): 10.0000 Roof Outage (ft): 0.6667

Roof Outage (Cone Roof) Roof Outage (ft): 0.6667 Roof Height (ft): 2.0000 Roof Slope (ft/ft): 0.2000 Shell Radius (ft): 10.0000




Working Losses (lb): 1,520.6872 Vapor Molecular Weight (lb/lb-mole): 32.0400 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 1.0709 Annual Net Throughput (gal/yr.): 4,400,000.0000 Annual Turnovers: 117.0172 Turnover Factor: 0.4230 Maximum Liquid Volume (gal): 37,601.3166 Maximum Liquid Height (ft): 16.0000 Tank Diameter (ft): 20.0000 Working Loss Product Factor: 1.0000

Total Losses (lb): 1,924.3185






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsMethyl alcohol 1,520.69 403.63 1,924.32





IdentificationUser Identification: TK 007City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Process Methanol Tank 6











LiquidBulk


Mol.LiquidMass















Working Losses (lb): 2,119.7991 Vapor Molecular Weight (lb/lb-mole): 32.0400 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 1.0709 Annual Net Throughput (gal/yr.): 8,800,000.0000 Annual Turnovers: 234.0344 Turnover Factor: 0.2949 Maximum Liquid Volume (gal): 37,601.3166 Maximum Liquid Height (ft): 16.0000 Tank Diameter (ft): 20.0000 Working Loss Product Factor: 1.0000

Total Losses (lb): 2,523.4303






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsMethyl alcohol 2,119.80 403.63 2,523.43





IdentificationUser Identification: TK 008City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Sodium Methylate TK











LiquidBulk


Mol.LiquidMass









Losses(lbs)Components Working Loss Breathing Loss Total EmissionsMethyl alcohol 403.49 403.63 807.12





IdentificationUser Identification: TK 009City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Feedstock











LiquidBulk


Mol.LiquidMass



Feedstock All 50.75 42.12 59.38 46.13 0.0005 0.0005 0.0005 400.0000 400.00 Option 1: VP50 = .0005 VP60 = .0005












Working Losses (lb): 69.8413 Vapor Molecular Weight (lb/lb-mole): 400.0000 Vapor Pressure at Daily Average Liquid Surface Temperature (psia): 0.0005 Annual Net Throughput (gal/yr.): 14,666,667.0000 Annual Turnovers: 30.7737 Turnover Factor: 1.0000 Maximum Liquid Volume (gal): 476,596.6876 Maximum Liquid Height (ft): 30.0000 Tank Diameter (ft): 52.0000 Working Loss Product Factor: 1.0000







Losses(lbs)Components Working Loss Breathing Loss Total EmissionsFeedstock 69.84 35.43 105.27





IdentificationUser Identification: TK 010City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Finished Biodiesel IA











LiquidBulk


Mol.LiquidMass



Biodiesel All 50.75 42.12 59.38 46.13 0.0001 0.0001 0.0001 292.0000 292.00 Option 1: VP50 = .00012 VP60 = .00015






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsBiodiesel 12.47 6.33 18.79





IdentificationUser Identification: TK 011City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Finished Biodiesel











LiquidBulk


Mol.LiquidMass



Biodiesel All 50.75 42.12 59.38 46.13 0.0001 0.0001 0.0001 292.0000 292.00 Option 1: VP50 = .00012 VP60 = .00015






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsBiodiesel 12.47 6.33 18.79





IdentificationUser Identification: TK 005City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Crude Glycerin











LiquidBulk


Mol.LiquidMass



Crude Glycerin All 50.75 42.12 59.38 46.13 0.0777 0.0561 0.1055 18.9351 61.74 Glycerin 0.0010 0.0010 0.0010 92.0000 0.8800 0.0369 92.10 Option 1: VP50 = .001 VP60 = .001 Methyl alcohol 1.0709 0.8017 1.4144 32.0400 0.0010 0.0450 32.04 Option 2: A=7.897, B=1474.08, C=229.13 Water 0.1838 0.1323 0.2503 18.0000 0.1190 0.9181 18.00 Option 1: VP50 = .178 VP60 = .255






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsCrude Glycerin 129.79 46.83 176.62 Glycerin 4.79 1.73 6.52 Water 119.17 42.99 162.16 Methyl alcohol 5.84 2.11 7.94





IdentificationUser Identification: TK 009City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Biodiesel Rework











LiquidBulk


Mol.LiquidMass



Biodiesel All 50.75 42.12 59.38 46.13 0.0193 0.0145 0.0255 33.3623 287.34 Option 1: VP50 = .0001 VP60 = .0001 Biodiesel 0.0001 0.0001 0.0001 292.0000 0.9980 0.0445 292.00 Option 1: VP50 = .0001 VP60 = .0001 Methyl alcohol 1.0709 0.8017 1.4144 32.0400 0.0020 0.9555 32.04 Option 2: A=7.897, B=1474.08, C=229.13






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsBiodiesel 7.93 3.99 11.92 Biodiesel 0.35 0.18 0.53 Methyl alcohol 7.57 3.82 11.39





IdentificationUser Identification: TK 011City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Finished Biodiesel











LiquidBulk


Mol.LiquidMass



Finnished Biodiesel All 50.75 42.12 59.38 46.13 0.0011 0.0008 0.0014 56.1975 291.76 Biodiesel 0.0001 0.0001 0.0001 292.0000 0.9999 0.4828 292.00 Option 1: VP50 = .0001 VP60 = .0001 Methyl alcohol 1.0709 0.8017 1.4144 32.0400 0.0001 0.5172 32.04 Option 2: A=7.897, B=1474.08, C=229.13






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsFinnished Biodiesel 21.10 10.70 31.80 Biodiesel 10.19 5.17 15.36 Methyl alcohol 10.91 5.54 16.45





IdentificationUser Identification: TK 032City: Albert LeaState: MinnesotaCompany: REG Albert LeaType of Tank: Vertical Fixed Roof TankDescription: Biodiesel Distillation Bottoms

Tank DimensionsShell Height (ft): 30.00Diameter (ft): 12.00Liquid Height (ft) : 29.00Avg. Liquid Height (ft): 15.00Volume (gallons): 24,534.86Turnovers: 30.00Net Throughput(gal/yr): 736,045.77Is Tank Heated (y/n): Y










LiquidBulk


Mol.LiquidMass



Biodiesel Distillation Bottoms All 0.00 0.00 0.00 0.00 0.0018 0.0018 0.0018 49.0542 346.56 Option 1: VP40 = .0001 Biodiesel Distillation Bottoms 0.0001 0.0001 0.0001 350.0000 0.9990 0.3818 350.00 Option 1: VP40 = .0001 Methyl alcohol 0.1618 0.1618 0.1618 32.0400 0.0010 0.6182 32.04 Option 2: A=7.897, B=1474.08, C=229.13






Losses(lbs)Components Working Loss Breathing Loss Total EmissionsBiodiesel Distillation Bottoms 1.59 0.00 1.59 Biodiesel Distillation Bottoms 0.61 0.00 0.61 Methyl alcohol 0.98 0.00 0.98

