Respondent Description Order Type Date

BP Whiting Settlement 

(Flaring)

The U.S. Environmental Protection Agency (EPA) and 

the U.S. Department of Justice announced that BP 

North America Inc. has agreed to pay an $8 million 

penalty and invest more than $400 million to install 

state-of-the-art pollution controls and cut emissions 

from BP's petroleum refinery in Whiting, Ind. 

Consent 

Decree 05/23/2012 

QEPFS Facilities 

Services

The U.S. Environmental Protection Agency (EPA) and 

the U.S. Department of Justice announced a settlement 

with QEP Field Services Co. (QEPFS), formerly 

Questar Gas Management Co., to resolve alleged 

violations of the Clean Air Act at five natural gas 

compressor stations on the Uintah and Ouray 

Reservation in Northeastern Utah. 

Consent 

Decree 05/16/2012 

EPA, Precision 

National Plating reach 

cleanup agreement for 

further work at 

Precision National 

Corporation Site

On May 12, 2012, the U.S. Environmental Protection 

Agency reached a settlement with Precision National 

Plating Services, Inc. on a plan to clean up 

groundwater and surface water contamination at the 

Precision National Corporation site in Clarks Summit, 

Penn. where a chrome plating facility had been in 

operation from 1958 to 1999. 

Administrative 

Order on 

Consent 

05/12/2012 

Hess Corporation Clean 

Air Act Settlement

Hess Corporation has agreed to pay an $850,000 civil 

penalty and spend more than $45 million in new 

pollution controls to resolve Clean Air Act violations 

at its Port Reading, New Jersey refinery, the U.S. 

Department of Justice and the U.S. Environmental 

Protection Agency announced today. 

Consent 

Decree 04/25/2012 

City of Memphis, 

Tennessee Sanitary 

Sewer Overflow 

Settlement

The U.S. Environmental Protection Agency, the U.S. 

Department of Justice, the Tennessee Department of 

Environment and Conservation and the Office of the 

Tennessee Attorney General announced a 

comprehensive Clean Water Act (CWA) settlement 

with the City of Memphis, Tenn. Memphis has agreed 

to make improvements to its sewer systems to 

eliminate unauthorized overflows of untreated raw 

sewage. Memphis estimates such work will cost 

approximately $250 million. 

Consent 

Decree 04/16/2012 

EPA Fines Violators of 

the Lead Renovation, 

Repair and Painting 

Rule

The U.S. Environmental Protection Agency (EPA) 

announced three enforcement actions for violations of 

the Lead Renovation, Repair and Painting Rule (RRP) 

and other lead rules. 

04/05/2012 

Marathon Petroleum 

Company, LP and 

Catlettsburg Refining, 

LLC Settlement 

(Flaring)

The Department of Justice and the U.S. Environmental 

Protection Agency (EPA) today announced an 

innovative environmental agreement with Ohio-based 

Marathon Petroleum Company that already has 

significantly reduced air pollution from all six of the 

company’s petroleum refineries. 

Consent 

Decree 04/05/2012 

Civil Cases and Settlements | Enforcement | US EPA Page 38 of 104

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Menu

Enforcement

BP Whiting Settlement (Flaring)

(Washington, DC - May 23, 2012) The U.S. Environmental Protection Agency (EPA) and the U.S. 

Department of Justice announced that BP North America Inc. has agreed to pay an $8 million penalty and 

invest more than $400 million to install state-of-the-art pollution controls and cut emissions from BP's 

petroleum refinery in Whiting, Ind. When fully implemented, the agreement is expected to reduce harmful 

air pollution that can cause respiratory problems such as asthma and are significant contributors to acid 

rain, smog and haze, by more than 4,000 tons per year.

On this page:

Settlement Resources

• Press Release

• Consent Decree

• Overview of Company and Location of Facility 

• Violations

• Injunctive Relief

• Supplemental Environmental Project 

• Pollutant Reductions

• Health and Environmental Effects 

• Civil Penalty

• Other Plaintiffs

• Comment Period

• Contact

Overview of Company and Location of Facility

BP Products North America Inc., headquartered in Warrenville IL, engages in the exploration, 

development, production and marketing of oil and natural gas, and additionally operates petroleum 

refineries in California, Indiana, Ohio, Texas and Washington. BP North America Inc. is a subsidiary of 

BP p.l.c., headquartered in London, England. The Whiting Refinery has a refining capacity of 

approximately 405,000 barrels per day (bpd), and is the 6th largest refinery in the United States.

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Violations

The complaint alleges violations of Clean Air Act requirements at the Whiting Refinery relating to BP’s 

compliance with a 2001 Consent Decree as well as, inter alia, violations of the following federal and state 

requirements in connection with construction and expansion of the Whiting Refinery:

• New Source Review/Prevention of Significant Deterioration (NSR/PSD), 40 C.F.R. Parts 51 and 52.

• New Source Performance Standards (NSPS), 40 C.F.R. Part 60, Subparts A, J, VV, VVa, GGG, and 

GGGa; and Part 61 Subparts J and V.

• National Emission Standards for Hazardous Air Pollutants (NESHAP), 40 C.F.R. Part 63, Subpart 

CC.

• Title V of the Clean Air Act, 40 C.F.R. Part 70.

• Indiana State Implementation Plan (SIP) Rule 326 IAC 2-1-03 and 326 IAC 2-2-3(2).

Injunctive Relief

NSR/PSD 

• Final FCCU nitrogen oxides (NOx) emission limits, as follows:

◦ FCU 500, not more than: 

◾ 35 parts per million (ppm) on a 365-day rolling average basis

◾ 80 ppm on a 7-day rolling average basis

◦ FCU 600, not more than: 

◾ 10 ppm on a 365-day rolling average basis

◾ 20 ppm on a 7-day rolling average basis

• Final FCCU sulfur dioxide (SO2) limits of 10 ppm on a 365-day rolling average basis and 50 ppm on 

a 7-day rolling average basis for both FCU 500 and FCU 600.

• Operation of NOx and SO2 continuous emission monitors.

• Particulate emissions limits, as follows: 

◦ FCU 500: 

◾ 1.0 pound of particulate matter (PM) per 1,000 pounds of coke burned

◾ 0.9 pound of particulate matter with a diameter of 10 microns or less (PM10 ) per 1,000 

pounds of coke burned

◾ 1.2 pounds of all particulate matter regardless of size (PMTOTAL) per 1,000 pounds of 

coke burned

◦ FCU 600: 

◾ 1.0 pound of PM per 1,000 pounds of coke burned

◾ 0.7 pounds of PM10 per 1,000 pounds of coke burned

◾ 0.2 pounds of PMTOTAL per 1,000 pounds of coke burned.

◦ Carbon monoxide emission limit of 500 ppm on a 1-hour average basis at each FCCU.

◦ Installation of Selective Catalytic Reduction and Ultra Low NOx Burners on refinery heaters 

and boilers, and a sulfur limit of 70 ppm on any refinery fuel gas that is burned in heaters and 

boilers.

NSPS and Flaring

• Compliance with SO2 standards of Subpart J and/or Ja for combustion devices burning refinery fuel 

gas, including flaring devices.

• Compliance with SO2 standards of Subpart Ja at all sulfur recovery processes, including the sulfur 

pit.

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• Installation of flare gas recovery systems.

• Flare Minimization: 

◦ Implementation of a waste gas minimization plan (a detailed plan for reducing waste gas to 

flares).

◦ Root cause analysis and implement corrective action for flaring incidents greater than 500 

lb/day SO2 or 500,000 standard cubic feet per day (scf) waste gas flow.

◦ An overall limit on flaring (a “flare cap”).

• Flare Efficiency: 

◦ Install and operate monitoring systems and equipment on all flaring devices.

◦ Automated controls and standards to achieve a 98% combustion efficiency of waste gas 

burned in each flaring device.

Benzene Waste NESHAP

• Compliance with the EPA-preferred “6 BQ” benzene compliance option

• Modified management of change procedures to ensure that new benzene streams are included in the 

total annual benzene (TAB) calculation

• Conduct laboratory audits

• Quarterly sampling and TAB calculation

• Training for those who sample benzene

• Control of benzene leaks to cooling tower waters. 

• Installation of a new Dissolved Air Flotation unit and to install new covers for the API Separator at 

the Whiting Refinery to control fugitive benzene emissions 

Leak Detection and Repair (LDAR) Program

• Refinery-wide compliance with LDAR requirements

• Training, including refresher courses, for refinery personnel with LDAR responsibility

• Required LDAR compliance audits

• Strict internal leak definitions (500 ppm for valves and 2000 ppm for pumps)

• Internal first attempt at repair at 200 ppm for valves 

• More frequent monitoring than required by regulation

• Limitation on use of “Delay of Repair” exception

• Installation of “low-leaking” valve or valve packing technology in all new applications

Best Available Control Technology (BACT) Controls for the Delayed Coking Unit

• A coke drum depressurization standard of 2.0 pounds per square inch gauge to control volatile 

organic compounds (VOCs) and other pollutants, including greenhouse gas (GHG) emissions.

• An enclosed “coke pit” and coke conveyance system to control dust and PM.

• An enclosed coker quench water system to control VOCs.

Additional Projects

As part of the settlement, BP will undertake additional projects at the Whiting Refinery, including:

• A study of energy efficiency measures at the refinery to reduce GHG emissions, and the expenditure 

of $9.5 million to implement GHG reducing measures.

• A study of energy efficiency measures and the effect of such practices on reduction of GHG 

emissions.

• Measures to enhance the reliability and operation of continuous emissions monitors.

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Supplemental Environmental Project

As a supplemental environmental project, BP will install, operate and maintain a $2 million fence line 

monitoring system at the Whiting Refinery and will make the data collected available to the public by 

posting the information on a publicly-accessible website. Fenceline monitors will continuously monitor 

benzene, toluene, pentane, hexane, SO2, hydrogen sulfide (H2S) and all “reduced sulfur compounds” (all 

compounds containing reduced sulfur). 

Pollutant Reductions

When fully implemented, the new controls and requirements under the Consent Decree are estimated to 

reduce emissions by over 4,000 tons per year (tpy) of the following pollutants, as follows:

• NOx will be reduced by approximately 328 tpy

• SO2 by approximately 377 tpy

• VOCs by approximately 3,224 tpy

• Hazardous Air Pollutants by approximately 85 tpy

• Additional reductions of PM, PM10, PMTOTAL, carbon monoxide (CO) and H2S

In addition, the controls required by the Consent Decree will result in a reduction of GHGs by 

approximately 108,009 tpy (as carbon dioxide equivalents, or CO2e).

Health and Environmental Effects

• Nitrogen Oxides – Nitrogen oxides can cause ground-level ozone, acid rain, particulate matter, 

global warming, water quality deterioration, and visual impairment. Nitrogen oxides play a major 

role, with volatile organic chemicals, in the atmospheric reactions that produce ozone. Children, 

people with lung diseases such as asthma, and people who work or exercise outside are susceptible 

to adverse effects such as damage to lung tissue and reduction in lung function.

• Sulfur Dioxide – High concentrations of SO2 affect breathing and may aggravate existing respiratory 

and cardiovascular disease. Sensitive populations include asthmatics, individuals with bronchitis or 

emphysema, children and the elderly. Sulfur dioxide is also a primary contributor to acid deposition, 

or acid rain.

• Volatile Organic Compounds - VOCs, along with NOx, play a major role in the atmospheric 

reactions that produce ozone, which is the primary constituent of smog. People with lung disease, 

children, older adults, and people who are active can be affected when ozone levels are unhealthy. 

Ground-level ozone exposure is linked to a variety of short-term health problems, including lung 

irritation and difficulty breathing, as well as long-term problems, such as permanent lung damage 

from repeated exposure, aggravated asthma, reduced lung capacity, and increased susceptibility to 

respiratory illnesses such as pneumonia and bronchitis.

• Benzene - Acute (short-term) inhalation exposure of humans to benzene may cause drowsiness, 

dizziness, headaches, as well as eye, skin, and respiratory tract irritation, and, at high levels, 

unconsciousness. Chronic (long-term) inhalation exposure has caused various disorders in the 

blood, including reduced numbers of red blood cells and anemia in occupational settings. 

Reproductive effects have been reported for women exposed by inhalation to high levels, and 

adverse effects on the developing fetus have been observed in animal tests. Increased incidences of 

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leukemia have been observed in humans occupationally exposed to benzene. EPA has classified 

benzene as a Group A human carcinogen.

• Greenhouse Gases – The release of GHGs into the atmosphere traps heat. The continued release of 

GHGs at or above the current rate will increase average temperatures around the globe. Increases in 

global temperatures will most likely change our planet’s climate in ways that will have significant 

long-term effects on people and the environment.

• Particulate Matter – PM, especially fine particles, contain microscopic solids or liquid droplets that 

are so small that they can get deep into the lungs and cause serious health problems. PM is linked to 

a variety of problems, including increased respiratory symptoms such as irritation of the airways, 

coughing, or difficulty breathing, decreased lung function, aggravated asthma, and premature death 

in people with heart or lung disease.

Civil Penalty

BP will pay an $8 million civil penalty as follows:

• $7.2 million to the United States

• $800,000 to the State of Indiana 

Other Plaintiffs

The State of Indiana participated in the settlement negotiations and is a party to the Consent Decree. In 

addition, the following organizations and individuals also participated in and/or are also a party to the 

Consent Decree:

• The Sierra Club

• Save the Dunes

• The Natural Resources Defense Council

• The Hoosier Environmental Council

• The Environmental Law and Policy Center

• The Environmental Integrity Project

• Susan Eleuterio and Tom Tsourlis

Comment Period

The proposed settlement is lodged in the U.S. District Court for the Northern District of Indiana. The 

consent decree will be subject to a 30-day public comment period and final court approval. Information on 

submitting comment is available at the Department of Justice website.

For more information, contact:

Patrick W. Foley

Senior Environmental Engineer

U.S. Environmental Protection Agency (2242A)

1200 Pennsylvania Ave., N.W.

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Last updated on March 2, 2015

Washington, DC 20460-0001

(202) 564-7978

foley.patrick@epa.gov

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Newsroom

News Releases By Date

BP Agrees to Add More Than $400 Million in Pollution Controls at 

Indiana Refinery and Pay $8 Million Clean Air Act Penalty 

Release Date: 05/23/2012

Contact Information: Stacy Kika, kika.stacy@epa.gov, 202-564-0906 , 202-564-4355

WASHINGTON – The U.S. Environmental Protection Agency (EPA) and the U.S. Department of Justice announced that BP 

North America Inc. has agreed to pay an $8 million penalty and invest more than $400 million to install state-of-the-art 

pollution controls and cut emissions from BP’s petroleum refinery in Whiting, Ind. When fully implemented, the agreement is 

expected to reduce harmful air pollution that can cause respiratory problems such as asthma and are significant contributors 

to acid rain, smog and haze, by more than 4,000 tons per year.

“Today's settlement will protect the residents of northwestern Indiana from harmful air pollution by requiring state-of-the-art

pollution controls,” said Cynthia Giles, assistant administrator for EPA’s Office of Enforcement and Compliance 

Assurance."BP's agreement to install fenceline monitoring will also ensure that residents have access to critical information 

about pollution that may be affecting their community.”

“In this case, BP North America has not lived up to all of its obligations under an earlier settlement agreement and has 

committed new violations of the Clean Air Act at its Whiting refinery in Indiana,” said Ignacia S. Moreno, Assistant Attorney 

General for the Environment and Natural Resources Division of the Department of Justice. “This settlement secures a 

significant penalty, requires state-of-the-art controls, and is a fair and just resolution that will address BP’s violations. We will 

continue to hold BP accountable and ensure that it complies with the nation’s environmental laws.”

The complaint alleges violations of Clean Air Act (CAA) requirements at the Whiting refinery in connection with construction 

and expansion of the Whiting Refinery, as well as violations of a 2001 consent decree with the company that covered all of 

BP’s refineries and was entered into as part of EPA’s Petroleum Refinery Initiative. 

Today’s settlement will lead to the installation of innovative pollution controls on the largest sources of emissions at the 

Whiting refinery, including extensive new controls on the refinery’s flaring devices. Flaring devices are used to burn-off 

waste gases. The more waste gases sent to a flare, and the less efficient the flare is when burning those gases, the more 

pollution that will occur. Under the settlement, BP will install new equipment that will limit the amount of waste gas sent to 

flaring devices in the first place, as well as implement innovative, cutting-edge controls to ensure proper combustion 

efficiency for any gases that are burned in a flaring device. The requirements, similar to those included in a recent 

settlement with Marathon Petroleum Corp., are part of EPA’s national effort to reduce emissions from flares at refineries, 

petrochemical and chemical plants. 

In addition to the controls on the refinery’s flares, the settlement will also result in reduced emissions by imposing some of 

the lowest emission limits in refinery settlements to date, enhancing controls on wastewater containing benzene and 

providing for an enhanced leak detection and repair program. Today’s settlement also requires the Whiting refinery to spend 

$9.5 million on projects at the refinery to reduce the emissions of greenhouse gases.

BP will perform a supplemental environmental project in which they will install, operate and maintain a $2 million fence line 

emission monitoring system at the Whiting refinery and will make the data collected available to the public by posting the 

information on a publicly-accessible website. Fenceline monitors will continuously monitor benzene, toluene, pentane, 

hexane, sulfur dioxide, hydrogen sulfide and all compounds containing reduced sulfur. 

BP Products North America Inc., headquartered in Warrenville Ill., engages in the exploration, development, production and 

marketing of oil and natural gas, and additionally operates petroleum refineries in California, Indiana, Ohio, Texas and 

Washington. BP North America Inc. is a subsidiary of BP p.l.c., headquartered in London, England. The Whiting Refinery 

has a refining capacity of approximately 405,000 barrels per day, and is the 6th largest refinery in the United States.

The state of Indiana, the Sierra Club, Save the Dunes, the Natural Resources Defense Council, the Hoosier Environmental 

Council, the Environmental Law and Policy Center, the Environmental Integrity Project, Susan Eleuterio and Tom Tsourlis 

also joined in this settlement.

The consent decree is subject to a 30-day public comment period and final court approval. 

More information about the settlement: http://www.epa.gov/compliance/resources/cases/civil/caa/bp-whiting.html

More about EPA’s civil enforcement of the Clean Air Act: http://www.epa.gov/compliance/civil/caa/index.html

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Last updated on February 17, 2015

Enforcement

Consent Decree: BP Products North America Inc., 

Civil No. 2:12 CV 207

This is the Clean Air Act consent decree for BP Products North America Inc. Issued May 23, 2012. Also 

see, BP Products North America Inc. settlement summary information.

You will need Adobe Reader to view some of the files on this page. See EPA’s About PDF page to 

learn more.

• Consent Decree: BP Products North America Inc., Civil No. 2:12 CV 207 (PDF) (325 pp, 10 MB)

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case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 1 of 325 page 1 of 324 

IN THE UNITED STATES DISTRICT COURT 

FOR THE NORTHERN DISTRICT OF INDIANA 

HAMMOND DIVISION 

UNITED STATES OF AMERICA, and 

THE STATE OF INDIANA, 

Plaintiffs, 

and 

THE SIERRA CLUB, SAVE THE DUNES, 

THE NATURAL RESOURCES DEFENSE 

COUNCIL, THE HOOSIER 

ENVIRONMENTAL COUNCIL, SUSAN 

ELEUTERIO and TOM TSOURLIS, 

Plaintiff-Intervenors 

v. 

BP PRODUCTS NORTH AMERICA INC., 

Defendant 

) 

) 

) 

) 

) Civil No. 2:12 CV 207 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

) 

________________________________________) 

CONSENT DECREE 
 


 



 


 


 

	 
 

	 
 

	 
 


 


 

	 
 

	 
 

	 
 


 

	 
 

	 
 

	 
 

	 
 

	 
 

	 
 

	 
 


 

	 
 

	 
 


 

	 
 

	 


 


 


 


 


 


 


 

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TABLE OF CONTENTS 

I. JURISDICTION AND VENUE ..........................................................................................4 

II. APPLICABILITY AND BINDING EFFECT.....................................................................5 

III. OBJECTIVES ......................................................................................................................6 

IV. DEFINITIONS.....................................................................................................................6 

V. AFFIRMATIVE RELIEF/ENVIRONMENTAL PROJECTS ..........................................12 

A. NOx Emissions Reductions from FCCUs..............................................................12 

B. SO2 Emissions Reductions from FCCUs...............................................................14 

C. Particulate Matter Emissions Reductions from FCCUs.........................................16 

D. CO Emissions Reductions from FCCUs................................................................21 

E. VOC Emissions Reductions from FCCUs.............................................................22 

F. NOx Emissions Reductions from Heaters and Boilers ..........................................23 

G. SO2 Emissions Reductions from Heaters and Boilers ...........................................28 

H. Fuel Gas Sulfur Content.........................................................................................29 

I. CEMS Downtime Minimization, O&M and Corrective Action............................31 

J. Benzene Waste NESHAP ......................................................................................34 

K. Leak Detection and Repair.....................................................................................47 

L. Sulfur Recovery Plant and Sulfur Pits ...................................................................48 

M. Requirements for Certain Tanks ............................................................................52 

N. VOC, PM, TRS, and H2S Emission Reductions from the Whiting Refinery New 

Coker......................................................................................................................55 

O. Emission Reductions from Flares and Control of Flaring Events .........................56 

P. Incorporation of Consent Decree Requirements into Federally Enforceable 

Permits ...................................................................................................................57 

VI. EMISSION CREDIT GENERATION ..............................................................................58 

VII. SUPPLEMENTAL ENVIRONMENTAL PROJECT AND ADDITIONAL 

INJUNCTIVE RELIEF 

A. Supplemental Environmental Project ....................................................................61 

B. Additional Injunctive Relief. .................................................................................64 

VIII. REPORTING AND RECORDKEEPING .........................................................................66 

IX. CIVIL PENALTY..............................................................................................................69 

X. STIPULATED PENALTIES.............................................................................................71 

A. Requirements for NOx Emissions Reductions from FCCUs.................................71 

B. Requirements for SO2 Emissions Reductions from FCCUs. .................................71 

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C. Requirements for PM Emissions Reductions from FCCUs...................................72 

D. Requirements for CO Emissions Reductions from FCCUs...................................72 

E. Requirements for VOC Emissions Reductions from FCCUs................................73 

F. Requirements for NOx Emissions Reductions from Heaters and Boilers .............73 

G. Requirements for SO2 Emissions Reductions from Heaters and Boilers ..............75 

H. Requirements for Fuel Gas Sulfur Content............................................................75 

I. Requirements for CEMS Downtime Minimization, O&M and Corrective 

Action.....................................................................................................................76 

J. Requirements for Benzene Waste NESHAP .........................................................77 

K. Requirements for Leak Detection and Repair .......................................................78 

L. Requirements for Sulfur Recovery Plant and Sulfur Pit........................................83 

M. Requirements for Certain Tanks ............................................................................84 

N. Requirements for Whiting New Coker ..................................................................85 

O. Requirements for Flaring Devices .........................................................................85 

P. Requirements for Incorporation of Consent Decree Requirements Into Permits ..94 

Q. Requirements for Supplemental Environmental Project .......................................94 

R. Requirements for Reporting and Record Keeping.................................................94 

S. Requirements for Payment of Civil Penalties........................................................95 

T. General Provisions Related to Stipulated Penalties .............................................95 

XI. INTEREST.........................................................................................................................96 

XII. RIGHT OF ENTRY...........................................................................................................97 

XIII. FORCE MAJEURE ...........................................................................................................97 

XIV. RETENTION OF JURISDICTION/DISPUTE RESOLUTION .......................................99 

XV. EFFECT OF SETTLEMENT ..........................................................................................101 

XVI. GENERAL PROVISIONS ..............................................................................................114 

XVII. TERMINATION..............................................................................................................120 

XVIII. INTEGRATION...............................................................................................................125 

XIX. SIGNATORIES ...............................................................................................................125 

ii 
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TABLE OF APPENDICES 

A Fuel Gas Sulfur Monitoring Locations 

B Enhanced LDAR Program 

C Beavon Stretford Monitoring Procedure 

D Emission Reductions from Flares and Control of Flaring Events 

E Fenceline Monitoring SEP 

F FOVs and NOVs 

iii 
 


 

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CONSENT DECREE 

WHEREAS, Plaintiff the United States of America (“United States”), by the 

authority of the Attorney General of the United States and through its undersigned 

counsel, acting at the request and on behalf of the United States Environmental Protection 

Agency (“EPA”), has simultaneously filed a Complaint and lodged this Consent Decree 

against defendant BP Products North America Inc., (“BPP” or “Defendant”) for alleged 

environmental violations at its refinery located in Whiting, Indiana (the “Whiting 

Refinery”); 

WHEREAS, the State of Indiana (“Indiana”) has joined in this matter alleging 

violations of its applicable State Implementation Plan provisions and/or other state rules, 

regulations, and permits incorporating and implementing the requirements of the Clean 

Air Act; 

WHEREAS, the Sierra Club, Save the Dunes, the Natural Resources Defense 

Council, the Hoosier Environmental Council, the Environmental Integrity Project, the 

Environmental Law and Policy Center, Susan Eleuterio and Tom Tsourlis (“CitizenIntervenors”) by their execution of and entry into this Consent Decree are hereby seeking 

to intervene in this action, with the consent of the United States, Indiana and BPP, for the 

purpose of resolving claims they have made concerning the adequacy of certain permits 

issued to BPP by Indiana, and the entry of this Consent Decree shall constitute the 

granting of such intervention; 

WHEREAS, the United States, Indiana and BPP are among the parties to a 

Consent Decree entered by this Court in Civ. No. 2:96 CV 095 RL on August 29, 2001 

(the “2001 Consent Decree”), which has been amended several times between 2001 and 

2009, and which covers the five refineries owned and operated by BP, including the 

Whiting Refinery; 

WHEREAS, EPA has issued several Notices of Violation and Findings of 

Violations to BPP relating to the Whiting Refinery’s compliance with various 

requirements of both the 2001 Consent Decree and the Clean Air Act; 

WHEREAS, BPP is presently engaged in a capital improvement project, referred 

to by BPP as the Whiting Refinery Modernization Project (“WRMP”), that will 

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modernize much of the Refinery and will enable BPP to substitute Canadian crude oil for 

a major portion of its existing crude slate; 

WHEREAS on May 1, 2008, the Indiana Department of Environmental 

Management (“IDEM”) issued a final Significant Source Modification permit authorizing 

BPP to proceed with the construction needed to implement the WRMP (“the WRMP 

Construction Permit”); 

WHEREAS, the terms and conditions of the WRMP Construction Permit were 

added to the Whiting Refinery’s existing Title V operating permit (Operation Permit No. 

T089-6741-00453, hereinafter “the WRMP Operating Permit”) on June 16, 2008; 

WHEREAS, pursuant to these permits, BPP has been engaged in the construction 

activities necessary to implement the WRMP; 

WHEREAS, on May 19, 2008, several of the Citizen-Intervenors jointly filed 

petitions for review with the Indiana Office of Environmental Adjudication (“OEA”) 

challenging both the WRMP Construction Permit and the WRMP Operating Permit, 

which petitions for review are still pending before OEA in, Cause Nos. 08-A-J-4115 and 

08-A-J-4142; 

WHEREAS, on August 19, 2008, the Environmental Law and Policy Center, 

Hoosier Environmental Council, Natural Resources Defense Council, Save the Dunes 

Council, Inc., Sierra Club, Inc., Susan Eleuterio and Tom Tsourlis (“Title V Petitioners”) 

submitted a petition to EPA pursuant to Section 505(b)(2) of the Clean Air Act (“Title V 

Petition”) requesting that EPA object to the Title V permit modification issued by IDEM 

on June 16, 2008; 

WHEREAS, the Title V Petitioners alleged in their Title V Petition that the Title 

V permit did not comply with Clean Air Act requirements because, inter alia, BPP’s 

permit application omitted emissions data necessary to determine applicable Clean Air 

Act requirements and to establish appropriate emission limits, that the calculation to 

determine appropriate NSR requirements was done incorrectly and that the permit did not 

include appropriate BACT or LAER limits for flares and other sources, among other 

items; 

WHEREAS, on October 16, 2009, EPA issued an order (“EPA Order”) granting 

in part and denying in part the Title V Petition; 

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WHEREAS, the EPA Order specified that the NSR emissions calculations and 

analyses for the Whiting Refinery did not appropriately address the following emissions: 

emissions from new and existing flaring devices resulting from start-up, shut-down and 

malfunction of refinery process units; emissions from vessel depressurization; emissions 

from increased coking and coke drum depressurization; and emissions of fugitive sulfur 

compounds. The EPA Order also granted the Title V Petition on the issue that IDEM had 

not provided a sufficient rationale and response to comment on the issue of sulfur content 

of the Canadian crude oil feedstock to be refined at the Whiting Refinery. The EPA 

Order also directed IDEM to re-evaluate the issues of concerns and, if necessary, modify 

BPP’s permit; 

WHEREAS, the injunctive relief required by Part V of this Consent Decree 

(“Affirmative Relief/Environmental Projects”) covers the matters on which the EPA 

Order granted the Title V Petitioners’ request to object to BPP’s Title V permit; 

WHEREAS, the Parties intend that, once the applicable requirements of Part V of 

this Consent Decree are incorporated into a revised Title V permit for the Whiting 

Refinery, and such permit is issued by IDEM, the matters raised by the EPA Order will 

be addressed; 

WHEREAS, by entering into this Consent Decree, BPP is committed to undertake 

an extensive set of projects at the Whiting Refinery (i) to assure present and future 

compliance with the Clean Air Act, and regulations and permits issued thereunder and (ii) 

to substantially reduce emissions of pollutants from the Whiting Refinery; 

WHEREAS, the design cycle time for the New Coker built as part of WRMP 

includes five hours for the Quench Water Fill Time (and this Consent Decree requires no 

less than a 45-minute Quench Water Soak Time); 

WHEREAS, BPP intends to continue to operate the fenceline monitoring program 

described in Appendix E of this Consent Decree beyond the minimum term specified in 

Appendix E; 

WHEREAS, in conjunction with the negotiation of this Consent Decree, BPP has 

applied to IDEM for a Significant Source Permit Modification that incorporates terms 

and conditions implementing various requirements of this Consent Decree and to add 

those terms and conditions into the Whiting Title V Permit; 

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WHEREAS, because this Consent Decree incorporates all remaining obligations 

and requirements of the 2001 Consent Decree and its amendments that pertain to the 

Whiting Refinery (in addition to resolution of the matters described above), 

simultaneously with the lodging of this Consent Decree, the United States, Indiana and 

BPP have lodged a Seventh Amendment to the 2001 Consent Decree that would 

terminate all obligations under the 2001 Consent Decree that apply to the Whiting 

Refinery and otherwise amend the 2001 Consent Decree as needed to reflect the 

termination of the provisions applicable to the Whiting Refinery; 

WHEREAS, by entering into this Consent Decree, BPP is committed to 

proactively resolving environmental concerns related to its operations; 

WHEREAS, discussions between the Parties have resulted in the settlement 

embodied in this Consent Decree; 

WHEREAS, BPP has waived any applicable federal or state requirements of 

statutory notice of the alleged violations; 

WHEREAS, notwithstanding the foregoing reservations, the Parties agree that: (a) 

settlement of the matters set forth in the Complaint is in the best interests of the Parties 

and the public; and (b) entry of the Consent Decree without litigation is the most 

appropriate means of resolving this matter; and 

WHEREAS, the Parties recognize, and the Court by entering the Consent Decree 

finds, that the Consent Decree has been negotiated at arms length and in good faith and 

that the Consent Decree is fair, reasonable, and in the public interest; 

NOW THEREFORE, with respect to the matters set forth in the Complaint, and in 

Part XV of the Consent Decree (“Effect of Settlement”), and before the taking of any 

testimony, without adjudication of any issue of fact or law, and upon the consent and 

agreement of the Parties to the Consent Decree, it is hereby ORDERED, ADJUDGED 

and DECREED as follows: 

I. JURISDICTION AND VENUE 

1. This Court has jurisdiction over the subject matter of this action and over 

the Parties pursuant to 28 U.S.C. §§ 1331, 1345, and 1355. In addition, this Court has 

jurisdiction over the subject matter of this action pursuant to Sections 113(b) and 167 of 

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the CAA, 42 U.S.C. §§ 7413(b) and 7477. The United States’ Complaint states a claim 

upon which relief may be granted for injunctive relief and civil penalties against BPP 

under the Clean Air Act. Authority to bring this suit is vested in the United States 

Department of Justice by 28 U.S.C. §§ 516 and 519 and Section 305 of the CAA, 

42 U.S.C. § 7605. 

2. Venue is proper in the Northern District of Indiana pursuant to Section 

113(b) of the CAA, 42 U.S.C. § 7413(b), and 28 U.S.C. §§ 1391(b) and (c) and 1395(a). 

BPP consents to the personal jurisdiction of this Court, waives any objections to venue in 

this District, and does not object to the participation of the State of Indiana in this action. 

3. Notice of the commencement of this action has been given to the State of 

Indiana in accordance with Section 113(a)(1) of the CAA, 42 U.S.C. § 7413(a)(1), and as 

required by Section 113(b) of the CAA, 42 U.S.C. § 7413(b). 

II. APPLICABILITY AND BINDING EFFECT 

4. The provisions of this Consent Decree shall apply to the Whiting Refinery, 

and shall be binding upon the United States, the State of Indiana, the Sierra Club, Save 

the Dunes, the Natural Resources Defense Council, the Hoosier Environmental Council, 

the Environmental Integrity Project, the Environmental Law and Policy Center, Susan 

Eleuterio and Tom Tsourlis and BPP and their agents, successors, and assigns. 

5. BPP agrees not to contest the validity of this Consent Decree in any 

subsequent proceeding to implement or enforce its terms. BPP further agrees that, in any 

action to enforce this Consent Decree, it shall not raise as a defense the failure by any of 

its officers, directors, employees, agents, or contractors to take any actions necessary to 

comply with the provisions of this Consent Decree. 

6. Effective from the Date of Entry of this Consent Decree until termination 

pursuant to Part XVII, BPP agrees that the Whiting Refinery is covered by this Consent 

Decree. Effective from the Date of Entry of this Consent Decree, BPP shall give written 

notice of this Consent Decree to any successors in interest to the Whiting Refinery prior 

to the transfer of ownership or operation of any portion of the refinery and shall provide a 

copy of this Consent Decree to any successor in interest. BPP shall notify the United 

States and Indiana, in accordance with the notice provisions set forth in Paragraph 210 

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(“Notice”), of any successor in interest at least 30 days prior to any such transfer. 

7. BPP shall condition any transfer, in whole or in part, of ownership of, 

operation of, or other interest (exclusive of any non-controlling, non-operational 

shareholder or membership interest) in the Whiting Refinery upon the execution by the 

transferee of a modification to this Consent Decree, which makes the terms and 

conditions of this Consent Decree applicable to the transferee. In the event of such 

transfer, BPP shall notify the United States and the State of Indiana in accordance with 

the notice provisions in Paragraph 210 (“Notice”). By no earlier than 30 days after such 

notice, BPP may file a motion to modify this Consent Decree with the Court to make the 

terms and conditions of this Consent Decree applicable to the transferee. BPP shall be 

released from the obligations and liabilities of this Consent Decree unless the United 

States or the State of Indiana opposes the motion and the Court finds that the transferee 

does not have the financial and technical ability to assume the obligations and liabilities 

under this Consent Decree. 

8. Except as provided in Paragraph 7, BPP shall be solely responsible for 

ensuring that performance of the work required under this Consent Decree is undertaken 

in accordance with the deadlines and requirements contained in this Consent Decree and 

any attachments hereto. BPP shall provide a copy of the applicable provisions of this 

Consent Decree (or a link to the information on the internet) to each consulting or 

contracting firm that is retained to perform work required under this Consent Decree 

upon execution of any contract relating to such work. Copies of the applicable portions 

of this Consent Decree (or a link to the information on the internet) do not need to be 

supplied to firms who are retained solely to supply materials or equipment to satisfy the 

requirements of this Consent Decree. 

III. OBJECTIVES 

9. It is the purpose of the Parties to this Consent Decree to further the 

objectives of the Clean Air Act. 

IV. DEFINITIONS 

10. Unless otherwise defined herein, terms used in this Consent Decree shall 

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have the meaning given to those terms in the Clean Air Act and the implementing 

regulations promulgated thereunder. The following terms used in this Consent Decree 

shall be defined, solely for purposes of this Consent Decree and the reports and 

documents submitted pursuant thereto, as follows: 

A. “7-day rolling average” shall mean the average daily emission rate or 

concentration during the preceding 7 days. For purposes of clarity, the first day used in a 

7-day rolling average compliance period is the first day on which the emission limit is 

effective, and the first complete 7-day average compliance period is 7 days later (e.g., for 

a limit effective on January 1, the first day in the period is January 1 and the first 

complete 7-day period is January 1 through January 7). 

B. “365-day rolling average” shall mean the average daily emission rate or 

concentration during the preceding 365 days. For purposes of clarity, the first day used in 

a 365-day rolling average compliance period is the first day on which the emission limit 

is effective, and the first complete 365-day average compliance period is 365 days later 

(e.g., for a limit effective on January 1, the first day in the period is January 1 and the 

first complete 365-day period is January 1 through December 31). 

C. “12-month rolling average” shall mean the sum of the average rate or 

concentration of the pollutant in question for the most recent complete calendar month 

and each of the previous 11 calendar months, divided by 12. A new 12-month rolling 

average shall be calculated for each new complete month. For purposes of clarity, the 

first month used in a 12-month rolling average compliance period is the first full calendar 

month in which the emission limit is effective, and the first complete 12-month rolling 

average compliance period is 12 calendar months later (e.g., for a limit effective on 

December 31, the first month in the period is January and the first complete 12-month 

period is January through the following December). 

D. “Calendar Quarter” shall mean any one of the three month periods 

ending on March 31st, June 30th, September 30th, and December 31st

. 

E. “CEMS” shall mean a continuous emissions monitoring system. 

F. “CEMS Root Cause Failure Analysis” means a process of analysis and 

investigation to determine the primary cause(s) for CEMS downtime. 

G. “Claus Offgas Treater” or “COT” shall mean a “reduction control 

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system” as defined in 40 C.F.R 60.101a followed by an incinerator. 

H. “CO” shall mean carbon monoxide. 

I. “Coke Drum” shall mean a pressurized vessel where coke is formed. 

The New Coker has the following Coke Drums: CD-201, CD-202, CD-203, CD-204, 

CD-205, and CD-206. 

J. “Coke Drum Overhead Pressure” or “Coke Drum OH Pressure” shall 

mean the difference between the absolute pressure inside a Coke Drum and atmospheric 

pressure, expressed as psig, as measured on the coke drum overhead vapor line, during 

the coke steaming and quenching operations prior to commencing Coke Drum Venting. 

K. “Coke Drum Steam Vent” or “Steam Vent” shall mean the vent and 

associated valves and piping on a Coke Drum that is used to vent vapors to the 

atmosphere. “Coke Drum Steam Vents” do not include the opening at the top of the 

Coke Drum used to insert the coke cutting device or the opening at the base of the Coke 

Drum used to discharge coke. The New Coker Coke Drums have the following Coke 

Drum Steam Vents: 

Identification of Coke Drum	 Identification of Coke Drum Steam Vents Valves 

CD-201 XZV38160A/B 

CD-202 XZV38260A/B 

CD-203 XZV38360A/B 

CD-204 XZV38460A/B 

CD-205 XZV38560A/B 

CD-206 XZV38660A/B 

L. “Coke Drum Venting” or “Venting” shall mean the period between the 

opening of both of the Coke Drum’s Steam Vent Valves and visual verification of no 

significant steam exiting the steam vent to the atmosphere. 

M. “Coke Pit” shall mean a walled area into which coke and Quench Water 

are discharged from the opening at the base of the Coke Drum after cooling and cutting. 

N. “Consent Decree” or “Decree” shall mean this Consent Decree, 

including any and all appendices attached to this Consent Decree, and any amendments 

thereto. 

O. “Continuously Operate” or “Continuous Operation” shall mean, with 

respect to SCR, that it shall be used at all times the associated unit is in operation, except 

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as necessary for consistency with the manufacturer’s specifications and good engineering 

and maintenance practices for such equipment and the unit. 

P. “Date of Entry” shall mean the date on which this Consent Decree is 

entered by the United States District Court for the Northern District of Indiana. 

Q. “Date of Lodging” shall mean the date this Consent Decree is lodged 

with the United States District Court for the Northern District of Indiana. 

R. “Day” or “Days” shall mean a calendar day or days. “Working Day” 

shall mean a day other than a Saturday, Sunday, or Federal holiday. In computing any 

period of time under this Consent Decree, where the last day would fall on a Saturday, 

Sunday, or Federal holiday, the period shall run until the close of business on the next 

Working Day, except that when a compliance date is specified in this Consent Decree, 

compliance must be achieved on or before that date. 

S. “Downtime” or “monitor downtime” shall mean the period of time 

during operation of the emission unit being monitored in which any of the required 

CEMS data are either not recorded or are invalid for any reason (e.g., monitor 

malfunctions, data system failures, preventive maintenance, unknown causes, etc.), but 

shall not include downtime associated with routine CEMS zero and span checks and 

QA/QC activities required by this Consent Decree. CEMS data that meet the 

requirements of 40 C.F.R. § 60.13 shall be considered valid for purposes of determining 

downtime. 

T. “EPA” or “U.S. EPA” shall mean the United States Environmental 

Protection Agency and any successor departments or agencies of the United States. 

U. “ESP” shall mean electrostatic precipitator. 

V. “Federal Financial Assistance Transaction” shall mean a grant, 

cooperative agreement, loan, federally-guaranteed loan or other mechanism for providing 

federal financial assistance. An “open” Federal Financial Assistance Transaction is one 

for which the performance period has not yet expired. 

W. “FCCU” or “FCU” as used herein shall mean a fluidized catalytic 

cracking unit and its regenerator. 

X. “Fuel gas” or “refinery fuel gas” shall have the meaning set out in 40 

C.F.R. § 60.101a. 

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Y. “Fuel gas combustion device” shall have the meaning set out in 40 

C.F.R. § 60.101a. 

Z. “Fuel gas system” or “refinery fuel gas system” shall mean the piping 

and control system that gathers gaseous streams generated by the Whiting Refinery’s 

operations (including any that are blended with other sources of gas), and that are used as 

fuel in refinery heaters, furnaces, boilers, incinerators, gas turbines, and any other fuel 

gas combustion devices. 

AA. “Fuel Oil” shall mean any liquid fossil fuel with sulfur content of 

greater than 0.05% by weight. 

BB. “IDEM” shall mean the Indiana Department of Environmental 

Management and any successor departments or agencies of the State of Indiana. 

CC. “Low NOx Burner” or “LNB” shall mean a burner that is designed to 

achieve a NOx emission rate of less than or equal to 0.040 lb NOx/mmBTU (HHV) when 

firing natural gas at 3% stack oxygen at full design load without air preheat, even if upon 

installation actual emissions exceed 0.040 lb NOx/mmBTU (HHV). 

DD. “Malfunction” shall mean, as specified in 40 C.F.R. § 60.2, “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.” 

EE. “New Coker” or “Whiting New Coker” shall mean the delayed coking 

unit at the Whiting Refinery identified as the “New #2 Coker” in the WRMP Operating 

Permit. The New Coker includes, but is not limited to, the Coke Drums, the Quench 

Water System, and the associated coke handling systems. 

FF. “NOx” shall mean nitrogen oxides. 

GG. “Paragraph” shall mean a portion of this Consent Decree identified by 

an Arabic numeral. 

HH. “Part” shall mean a portion of this Consent Decree identified by a 

Roman numeral. 

II. “Parties” shall mean the United States, the State of Indiana, CitizenIntervenors and BPP. 

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JJ. “PM” shall mean particulate matter as measured by EPA Methods 5B 

or 5F as specified in 40 C.F.R. Part 60, Subpart Ja. “PM10” shall mean all filterable and 

condensable particulate matter ten microns or less in diameter, as measured by EPA 

Methods 201A and 202. “PMTOTAL” shall mean all filterable and condensable matter, 

regardless of size, as measured by EPA Methods 5 and 202. 

KK. “PSIG” or “psig” shall mean pounds per square inch gauge, which is 

the difference between absolute pressure at the measurement point and atmospheric 

pressure. 

LL. “Quench Water” shall mean the water, in liquid phase, used to cool 

coke after it is formed in a Coke Drum. 

MM. “Quench Water Fill Time” shall mean the duration of time between (i) 

the commencement of the initial addition of Quench Water to a Coke Drum after 

discontinuing the steam sweep and (ii) the point at which the coke bed has been covered 

with water and the water addition rate drops below 100 gallons per minute. 

NN. “Quench Water Soak Time” shall mean the duration of time from the 

end of the Quench Water Fill Time and the start of Quench Water draining. 

OO. “Quench Water Make-Up” shall mean the water, in liquid phase, added 

to the Quench Water System to compensate for water loss. 

PP. “Quench Water System” shall mean the system used to receive, 

manage, treat, or convey Quench Water commencing from the point of discharge from 

the coke drum drains continuing through the Coke Pit, maze (coke fines settling basin), 

clean water sump and Quench Water Tank to the Coke Drums. 

QQ. “Quench Water Tank” shall mean any tank that holds Quench Water. 

RR. “Section” shall mean a portion of this Consent Decree identified by a 

capital letter. 

SS. “Selective Catalytic Reduction” or “SCR” shall mean an air pollution 

control device consisting of ammonia injection and a catalyst bed to selectively catalyze 

the reduction of NOx with ammonia to nitrogen and water. 

TT. “SO2” shall mean sulfur dioxide. 

UU. “Startup,” as specified in 40 C.F.R. § 60.2, shall mean the setting in 

operation of equipment for any purpose. 

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VV. “Shutdown,” as specified in 40 C.F.R. § 60.2, shall mean the cessation 

of operation of equipment for any purpose. 

WW. “Tier III Motor Vehicle Emission and Fuel Standards” shall mean the 

new standards that EPA intends to promulgate pursuant to Title II of the Clean Air Act 

(42 U.S.C. § 7521 et. seq.), including Clean Air Act sections 202(a) and 211(v), as 

described in the Unified Agenda of Federal Regulatory and Deregulatory Actions under 

Regulatory Identification Number (RIN) 2060-AQ86. 

XX. “Total Quench Time” shall mean the sum of Quench Water Fill Time 

and Quench Water Soak Time. 

YY. “Total sulfur” shall mean all sulfur containing compounds, measured in 

parts per million. 

ZZ. “Whiting Refinery” shall mean the refinery owned and operated by BPP 

and located at 2815 Indianapolis Boulevard in Whiting, Indiana. 

AAA. “Ultra-Low NOx Burners” or “ULNBs” shall mean those burners that 

are designed to achieve a NOx emission rate of less than or equal to 0.020 lb/mmBTU 

HHV when firing natural gas at 3% stack oxygen at full design load without air preheat, 

even if upon installation actual emissions exceed 0.020 lb/mmBTU HHV. 

BBB. “United States” shall mean the United States of America, including the 

United States Department of Justice and the United States Environmental Protection Agency. 

CCC. “2001 Consent Decree” shall mean the civil consent decree entered in 

United States, et al. v. BP Exploration and Oil, et al., Civil No. 2:96 CV 095 RL (N.D. 

Ind.) on August 29, 2001 and as thereafter amended. 

V. AFFIRMATIVE RELIEF/ENVIRONMENTAL PROJECTS 

A. NOx Emissions Reductions from FCCUs 

Summary: BPP shall reduce NOx emissions at the Whiting Refinery FCCUs. BPP is 

also required to incorporate the NOx emission limits into its operating permits and will 

demonstrate future compliance with the lower emission limits through the use of CEMS. 

CEMS required under this Section are to be operated and data recorded pursuant to 

applicable law. 

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11. NSPS Applicability to FCCUs. By no later than the Date of Entry, 

FCU 500 and FCU 600 at the Whiting Refinery shall each be an “affected facility” as that 

term is used in 40 C.F.R. Part 60, Subparts A and Ja, and shall be subject to and comply 

with the requirements of 40 C.F.R. Part 60, Subparts A and Ja, for NOx applicable to 

FCCUs. Entry of this Consent Decree and compliance with the relevant monitoring 

requirements of this Consent Decree for the FCCUs shall satisfy the notice requirements 

of 40 C.F.R. § 60.7(a) and the initial performance test requirement of 40 C.F.R. § 60.8(a). 

12. Interim and Final FCCU NOx Emission Limits. 

a. Interim Limits. Beginning on the Date of Entry, BPP shall comply 

with the following NOx emission limits at the Whiting Refinery: 

i. FCU 500: BPP shall continue to comply with a long-term 

FCCU emission limit of 40 ppmvd NOx @ 0% O2 (365-day rolling 

average) and a short-term FCCU emission limit of 80 ppmvd NOx @ 0% 

O2 (7-day rolling average). 

ii. FCU 600: BPP shall continue to comply with a long-term 

FCCU emission limit of 20 ppmvd NOx @ 0% O2 (365-day rolling 

average) and a short-term FCCU emission limit of 40 ppmvd NOx @ 0% 

O2 (7-day rolling average). 

b. Final Limits. By no later than 90 Days after the Date of Entry, 

BPP shall comply with the following NOx emission limits at the Whiting 

Refinery: 

i. FCU 500: BPP shall comply with a long-term FCCU 

emission limit of 35 ppmvd NOx @ 0% O2 (365-day rolling average) and 

a short-term FCCU emission limit of 80 ppmvd NOx @ 0% O2 (7-day 

rolling average); and 

ii. FCU 600: BPP shall comply with a long-term FCCU 

emission limit of 10 ppmvd NOx @ 0% O2 (365-day rolling average) and 

a short-term FCCU emission limit of 40 ppmvd NOx @ 0% O2 (7-day 

rolling average). 

c. NOx emissions during periods of Startup, Shutdown, or 

Malfunction shall not be used in determining compliance with the 7-day rolling 

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average emission limit required by this Paragraph, provided that during such 

periods BPP implements good air pollution control practices as required by 40 

C.F.R. § 60.11(d) to minimize NOx emissions. NOx emissions during periods of 

Startup, Shutdown, or Malfunction shall be used in determining compliance with 

the 365-day rolling average emission limit required by this Paragraph. 

13. Demonstrating Compliance with FCCU NOx Emission Limits. By no 

later than the Date of Entry, BPP shall use NOx and O2 CEMS to monitor performance of 

the Whiting Refinery FCCUs and to report compliance with the terms and conditions of 

this Consent Decree. CEMS will be used to demonstrate compliance with the NOx 

emission limits established pursuant to Paragraph 12. BPP shall make CEMS data 

available to EPA and IDEM (as applicable) upon request. BPP shall install, certify, 

calibrate, maintain, and operate all CEMS required by this Paragraph at the Whiting 

Refinery in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to 

CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring 

Systems) and Part 60, Appendices A and F, and the applicable performance specification 

test of 40 C.F.R. Part 60, Appendix B. BPP must also conduct Cylinder Gas Audits each 

Calendar Quarter during which a Relative Accuracy Audit (“RAA”) or a Relative 

Accuracy Test Audit (“RATA”) is not performed. 

B. SO2 Emissions Reductions from FCCUs 

Summary: BPP is required to limit SO2 emissions at the Whiting Refinery FCCUs. BPP 

is also required to incorporate the lower SO2 emission limits into its operating permits 

and will demonstrate future compliance with these limits through the use of CEMS. 

CEMS required under this Section are to be operated and data recorded pursuant to 

applicable law. 

14. NSPS Applicability to FCCUs. By no later than the Date of Entry, 

FCU 500 and FCU 600 at the Whiting Refinery shall each be an “affected facility” as that 

term is used in 40 C.F.R. Part 60, Subparts A and Ja. By no later than the Date of Entry, 

FCU 500 shall be subject to and comply with the requirements of 40 C.F.R. Part 60, 

Subparts A and Ja, for SO2 applicable to FCCUs, and by no later than September 1, 2013, 

FCU 600 shall be subject to and comply with the requirements of 40 C.F.R. Part 60, 

Subparts A and Ja, for SO2 applicable to FCCUs. Entry of this Consent Decree and 

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compliance with the relevant monitoring requirements of this Consent Decree for the 

FCCUs shall satisfy the notice requirements of 40 C.F.R. § 60.7(a) and the initial 

performance test requirement of 40 C.F.R. § 60.8(a). 

15. Interim and Final FCCU SO2 Emission Limits. 

a. Interim Limits. Beginning on the Date of Entry, BPP shall comply 

with the following SO2 emission limits at the Whiting Refinery: 

i. FCU 500: BPP shall continue to comply with a FCCU 

emissions limit of 25 ppmvd SO2 @ 0% O2 (365-day rolling average) and 

50 ppmvd SO2 @ 0% O2 (7-day rolling average). 

ii. FCU 600: BPP shall continue to comply with a long-term 

FCCU emission limit of 50 ppmvd SO2 @ 0% O2 (365-day rolling 

average) and a short-term FCCU emission limit of 125 ppmvd SO2 @ 0% 

O2 (7-day rolling average). 

b. Final Limits. BPP shall comply with the following SO2 emission 

limits at the Whiting Refinery: 

i. FCU 500: By no later than December 31, 2012, BPP shall 

comply with a FCCU emissions limit of 10 ppmvd SO2 @ 0% O2 (365­

day rolling average) and 50 ppmvd SO2 @ 0% O2 (7-day rolling average). 

ii. FCU 600: By no later than September 1, 2013, BPP shall 

comply with a FCCU emissions limit of 10 ppmvd SO2 @ 0% O2 (365­

day rolling average) and 50 ppmvd SO2 @ 0% O2 (7-day rolling average). 

c. SO2 emissions during periods of Startup, Shutdown, or 

Malfunction shall not be used in determining compliance with the 7-day rolling 

average emission limit required by this Paragraph, provided that during such 

periods BPP implements good air pollution control practices as required by 40 

C.F.R. § 60.11(d) to minimize SO2 emissions. SO2 emissions during periods of 

Startup, Shutdown, or Malfunction shall be used in determining compliance with 

the 365-day rolling average emission limit required by this Paragraph. 

16. Demonstrating Compliance with FCCU SO2 Emission Limits. By no 

later than Date of Entry, BPP shall use an SO2 and O2 CEMS to monitor the performance 

of the Whiting Refinery FCCUs and to report compliance with the terms and conditions 

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of this Consent Decree. CEMS will be used to demonstrate compliance with the SO2 

emission limits established pursuant to Paragraph 15. BPP shall make CEMS data 

available to EPA and IDEM (as applicable) upon request. BPP shall install, certify, 

calibrate, maintain, and operate all CEMS required by this Paragraph at the Whiting 

Refinery in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to 

CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring 

Systems) and Part 60 Appendices A and F, and the applicable performance specification 

test of 40 C.F.R. Part 60 Appendix B. BPP must also conduct Cylinder Gas Audits each 

Calendar Quarter during which a RAA or a RATA is not performed. 

C. Particulate Matter Emissions Reductions from FCCUs 

Summary: BPP is required to control and limit emissions of PM, PM10 and PMTOTAL 

from the Whiting FCCUs as provided in this Section. 

17. NSPS Applicability to FCCUs. By no later than the Date of Entry, 

FCU 500 and FCU 600 at the Whiting Refinery shall each be an “affected facility” as that 

term is used in 40 C.F.R. Part 60, Subparts A and Ja, and shall be subject to and comply 

with the requirements of 40 C.F.R. Part 60, Subparts A and Ja, for PM applicable to 

FCCUs. Entry of this Consent Decree and compliance with the relevant monitoring 

requirements of this Consent Decree for the FCCUs shall satisfy the notice requirements 

of 40 C.F.R. § 60.7(a) and the initial performance test requirement of 40 C.F.R. § 60.8(a). 

a. By no later than 180 Days after the Date of Entry, and on a semiannual basis thereafter, BPP shall conduct a performance test on each of FCU 500 

and FCU 600 pursuant to 40 C.F.R. §§ 60.8 and 60.104a. Upon demonstrating 

through at least four (4) semi-annual tests that the PM limit in 40 C.F.R. § 

60.102a(b)(1) is not being exceeded, BPP may reduce the required testing 

frequency to an annual basis. BPP shall provide notice to EPA no later than 30 

Days in advance of the performance testing to be conducted pursuant to this 

subparagraph, and shall provide the results of such testing upon request by EPA. 

b. In addition to the performance testing required by this Paragraph, 

BPP may conduct testing to identify any parameters that may need to be 

maintained to assure compliance with the PM limits during testing. BPP shall 

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provide EPA with notice no later than 30 Days in advance of testing to identify 

parameters pursuant to this subparagraph, and shall provide the results of such 

testing upon request by EPA. 

18. Emission Limits for PM10 and PMTOTAL. By no later than December 

31, 2013, BPP shall comply with the following PM10 and PMTOTAL emission limits at the 

Whiting Refinery: 

a. FCU 500: 

i. BPP shall comply with an emissions limit of 0.9 pound of 

PM10 per 1,000 pounds of coke burned, as determined by EPA Methods 

specified in Paragraph 21.a.ii. 

ii. BPP shall comply with an emissions limit of 1.2 pounds of 

PMTOTAL per 1,000 pounds of coke burned, as determined by EPA 

Methods specified in Paragraph 21.a.ii. 

b. FCU 600: 

i. BPP shall comply with an emissions limit of 0.7 pounds of 

PM10 per 1,000 pounds of coke burned, as determined by EPA Methods 

specified in Paragraph 21.a.ii. 

ii. BPP shall comply with an emissions limit of 1.2 pounds of 

PMTOTAL per 1,000 pounds of coke burned, as determined by EPA 

Methods specified in Paragraph 21.a.ii. 

19. Supplemental FCCU PM Monitoring Requirements. In addition to the 

monitoring requirements of this Consent Decree and NSPS Subparts A and Ja applicable 

to FCCUs, by no later than the Date of Entry, BPP shall monitor and record the daily 

values for the following operating parameters: 

a. The feed rate, in barrels per day, for each FCCU; 

b. The average rate, in pounds per hour, at which SO2-reducing 

catalyst additive is added to each FCCU; and 

c. The average amount of ammonia in pounds per hour injected into 

the FCU 500 ESP and the average amount of ammonia in pounds per hour that is 

separately injected into the FCU 600 vaporizer and the ESP. 

20. Demonstrating Compliance with PM10 and PMTOTAL Emission Limits. 

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a. Compliance with the PM10 and PMTOTAL emission limits in 

Paragraphs 18.a.i-ii and 18.b.i-ii shall be based on the emission rate computed 

from the most recent performance test completed pursuant to Paragraph 21.a. 

b. BPP shall maintain compliance with the PM operating limits 

established under 40 C.F.R. § 60.102a(c)(1) during its demonstration of 

compliance with the PM10 and PMTOTAL emission limits in Paragraph 18. 

c. For the purposes of this Paragraph, BPP may use Method 201A in 

lieu of Method 5 to determine PMTOTAL emissions, provided that BPP follows the 

procedures in Method 201A for the collection and analysis of PM greater than 10 

microns. 

21. FCCU Performance Testing. 

a. Testing Protocols for PM10 and PMTOTAL Emissions: By no later 

than 180 Days after the Date of Entry, BPP shall implement a performance testing 

protocol as provided in this Paragraph: 

i. Testing Frequency: BPP shall conduct performance tests to 

measure emissions of PM10 and PMTOTAL from FCU 500 and FCU 600 on 

at least a semi-annual basis, with each semi-annual performance test being 

no sooner than four (4) calendar months from the date of completion of 

the previous semi-annual test. This shall not preclude BPP from 

conducting additional performance tests which are more frequent. 

(1) Upon demonstrating, through at least four (4) valid, 

consecutive semi-annual tests conducted after December 31, 2013 

that (i) the PM10 and PMTOTAL limits are not being exceeded, (ii) 

the average of all four valid semi-annual tests is not more than 

80% of the PM10 and PMTOTAL limits, and (iii) the average result 

from any valid semi-annual test is not greater than 90% of the 

PM10 and PMTOTAL limits, BPP may reduce the frequency of 

performance testing to an annual basis. 

(2) BPP may request EPA approval to reduce the 

frequency of such testing in other circumstances. EPA has sole 

discretion to approve or disapprove BPP’s request, which shall not 

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be subject to Dispute Resolution. In the event that a subsequent 

annual test indicates an exceedance of a PM10 or PMTOTAL limit, 

EPA may elect to reinstate the requirement for semi-annual testing. 

EPA’s decision to reinstate semi-annual testing shall not be subject 

to Dispute Resolution. 

ii. Test Methods for PM10 and PMTOTAL Emissions: BPP shall 

measure PM10 emissions using Methods 201A and 202. BPP may use 

Method 5 in lieu of Method 201A for purposes of demonstrating 

compliance with the PM10 emission limit provided that BPP considers all 

PM measured by Method 5 as PM10. BPP shall measure PMTOTAL 

emissions using Methods 5 and 202. BPP may use Method 201A in lieu of 

Method 5 for purposes of demonstrating compliance with the PMTOTAL 

emission limit provided that BPP also follows the procedures in Method 

201A for the collection and analysis of PM greater than 10 microns in 

diameter. 

iii. Test Run Duration: Each performance test shall be 

comprised of at least three (3) valid two-hour stack test runs. BPP shall 

discard any invalid test runs, such as those that are compromised because 

of sample contamination. If a test run is discarded, BPP shall replace it 

with an additional valid test run. BPP shall report the results of the 

discarded test runs and shall provide all information necessary to 

document why the test run was not valid. 

iv. Valid Performance Tests: A PM10 and PMTOTAL test shall 

not be considered a valid test, and BPP will not have met the requirement 

of this Paragraph to test, unless each of the following conditions is met for 

that test: 

(1) The average coke burn rate for all runs used in 

determining compliance with the PM10 and PMTOTAL emission 

limits must not be less than the actual average coke burn rate over 

the time period since the previous performance test; 

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(2) The average SO2 concentration for all runs used in 

determining compliance with the PM10 and PMTOTAL emission 

limits must not be greater than 10 ppmvd @ 0% O2; and 

(3) The average total ammonia injection rate for all 

runs used in determining compliance with the PM10 and PMTOTAL 

emission limits must not be less than average total ammonia 

injection rate over the time period since the previous performance 

test. 

(4) Throughout the performance test, BPP shall target 

the average ESP total primary power since the last stack test. The 

average ESP total primary power for all the runs used in 

determining compliance with the PM10 and PMTOTAL emission 

limits must not be greater than 120% of the average ESP total 

primary power since the last stack test. 

v. Additional Parametric Monitoring During the Tests: BPP 

shall monitor or calculate and record SO2 concentration, NOx 

concentration, catalyst additive rates, ammonia addition prior to ESP, 

ammonia addition at the SCR, ammonia slip, the coke burn-off rate, 

regenerator overhead temperatures, and FCCU feed rate for each test run. 

BPP shall reduce this monitoring data to an average that matches the time 

period of each test run. 

22. FCCU Consultation. By no later than 3 months after the Date of Entry, 

BPP shall retain an outside consultant to evaluate the ESPs for FCU 500 and 600. The 

outside consultant shall produce a report with recommendations on how to optimize the 

performance of each ESP to enable each FCU to meet the PM, PM10 and PMTOTAL 

emission limits in Paragraphs 17 and 18. By no later than 9 months after the Date of 

Entry, BPP shall provide this report to EPA and Citizen-Intervenors. BPP shall inform 

EPA and Citizen-Intervenors of any action taken to optimize the ESPs based on this 

report. 

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D. CO Emissions Reductions from FCCUs 

Summary: BPP is required to operate the Whiting Refinery FCCUs in a manner that 

minimizes CO emissions while complying with the NOx limits as required in this 

Section. 

23. NSPS Applicability to FCCUs. By no later than the Date of Entry, 

FCU 500 and FCU 600 at the Whiting Refinery shall each be an “affected facility” as that 

term is used in 40 C.F.R. Part 60, Subparts A and Ja, and shall be subject to and comply 

with the requirements of 40 C.F.R. Part 60, Subparts A and Ja, for CO applicable to 

FCCUs. Entry of this Consent Decree and compliance with the relevant monitoring 

requirements of this Consent Decree for the FCCUs shall satisfy the notice requirements 

of 40 C.F.R. § 60.7(a) and the initial performance test requirement of 40 C.F.R. § 60.8(a). 

24. FCU 500 CO Emissions Limits. By no later than Date of Entry, BPP 

shall limit CO emissions from FCU 500 to 500 ppmvd or less on a 1-hour block average 

basis corrected to 0% O2. 

25. FCU 600 CO Emissions Limits. By no later than Date of Entry, BPP 

shall limit CO emissions from FCU 600 to 500 ppmvd or less on a 1-hour block average 

basis corrected to 0% O2. 

26. CO emissions during periods of Startup, Shutdown, or Malfunction 

shall not be used in determining compliance with the 1-hour 500 ppmvd emissions limit, 

provided that during such periods BPP implements good air pollution control practices to 

minimize CO emissions. 

27. Demonstrating Compliance with FCCU CO Emission Limits. By no 

later than the Date of Entry, BPP shall use a CO CEMS to monitor the performance of 

each FCCU and to report compliance with the terms and conditions of this Consent 

Decree. CEMS will be used to demonstrate compliance with the CO emission limits 

established pursuant to this Section. BPP shall make CEMS data available to EPA and 

IDEM upon request. BPP shall install, certify, calibrate, maintain, and operate all CEMS 

at the Whiting Refinery required by this Paragraph in accordance with the provisions of 

40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable 

only to Continuous Opacity Monitoring Systems) and Part 60, Appendices A and F, and 

the applicable performance specification test of 40 C.F.R. Part 60, Appendix B. BPP 

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must also conduct Cylinder Gas Audits each Calendar Quarter during which a RAA or a 

RATA is not performed. 

E. VOC Emissions Reductions from FCCUs 

Summary: BPP is required to operate the Whiting Refinery FCCUs in a manner that 

minimizes VOC emissions as provided in this Section. 

28. FCU 500 VOC Emissions Limits. By no later than December 31, 2013, 

BPP shall limit VOC emissions from FCU 500 to 3.3 pounds of VOC per 1000 barrels of 

fresh feed. 

29. FCU 600 VOC Emissions Limits. By no later than December 31, 2013, 

BPP shall limit VOC emissions from FCU 600 to 3.3 pounds of VOC per 1000 barrels of 

fresh feed. 

30. Demonstrating Compliance with FCCU VOC Emission Limits. 

a. BPP shall calculate VOC emissions using the following equations: 

⎛ C ×Q × MW × 60 ⎞ ⎛1000 ⎞ E = ⎜

⎜ ⎟⎟×⎜ ⎟ ⎝ Vm ⎠ ⎝ F ⎠

C = C total methane ethane − C − C

Where: 

E = FCCU VOC Emissions in lb/1000 bbl feed 

Concentration of non-methane and non-ethane C = organic carbon as carbon in volume fraction 

Concentration of total organic carbon in volume 

Ctotal = fraction, as carbon, as measured by EPA Method 

25a 

Concentration of methane in volume fraction, as Cmethane = carbon, as measured by EPA Method 18 

Concentration of ethane in volume fraction, as Cethane = carbon, as measured by EPA Method 18 

MW = Molecular weight of carbon = 12.01 lb/lb-mole 

FCCU stack flow in dry standard cubic feet per Q = minute as measured by EPA Method (s) 1-4 

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Conversion factor to put emissions on a per 1000 1000 = bbl feed 

385.3 dscf of gas per lb-mol at standard conditions Vm = (68° F) 

FCCU feed rate in bbl/hour, averaged over period F = of source test 

60 = conversion factor for 60 minutes per hour 

b. BPP shall conduct the first stack test at each FCCU no later than 

December 31, 2013, and shall thereafter conduct annual stack tests at each FCCU, 

except as provided in Subparagraph 30.c below. 

c. After the first stack test has been conducted for each FCCU 

pursuant to this Consent Decree: 

i. If a stack test for a FCCU demonstrates that VOC 

emissions from that FCCU are less than half of the applicable VOC 

emissions limit, BPP may thereafter elect to conduct stack tests at least 

once every three (3) years at that FCCU in lieu of annual stack testing. 

ii. If, after BPP exercises the option to conduct stack testing at 

least once every three (3) years pursuant to this Paragraph, a stack test 

demonstrates an exceedance of the applicable VOC emissions limit for 

that FCCU, BPP shall resume annual stack testing for that FCCU. 

F. NOx Emissions Reductions from Heaters and Boilers 

Summary: BPP is required to undertake measures to reduce emissions of NOx from the 

Heaters and Boilers at the Whiting Refinery, as provided in this Section. 

31. Installation of Ultra Low-NOx Burners On Certain Heaters. 

a. By no later than the Date of Lodging, BPP shall conduct NOx 

emission tests on heaters F-2 and F-3 in the 4UF process unit and heater H-1X in 

the 11A Pipestill process unit for purposes of determining the baseline emission 

rate of each of these three heaters prior to installation of the controls required by 

this Paragraph. These tests shall be conducted using 40 C.F.R. Part 60 Appendix 

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A, Method 7E in combination with either EPA Method 19, or EPA Methods 1, 2, 

3, and 4, or an EPA-approved alternative test method. 

b. BPP shall install Ultra-Low NOx Burners by no later than the dates 

specified in the table below, and shall maintain, continuously operate and comply 

with the applicable emission limit by no later than the dates set forth for each 

listed heater and boiler: 

Unit Installation Date 

Emission Limit 

(12-Month 

Rolling Average) Compliance Date 

11A Pipestill H-1X December 31, 2013 0.06 lb/mmBtu December 31, 2013 

4UF F-2 Furnace December 31, 2016 0.04 lb/mmBtu December 31, 2016 

4UF F-3 Furnace December 31, 2016 0.04 lb/mmBtu December 31, 2016 

32. By no later than the compliance dates specified in Paragraph 31.b., BPP 

shall install, operate, calibrate and maintain NOx CEMS on each heater identified in that 

Paragraph and shall use CEMS to demonstrate and report compliance with the NOx 

emission limits applicable to those heaters. 

33. NSPS Subparts A & Ja Applicability to New and Modified Heaters and 

Boilers. 

a. Upon the Date of Entry, each of the following heaters and boilers 

shall be an “affected facility” as that term is used in 40 C.F.R. Part 60, Subparts A 

and Ja, and shall be subject to and comply with the applicable requirements of 40 

C.F.R. Part 60, Subparts A and Ja for NOx emissions for process heaters by the 

date specified in Subpart Ja: 

i. 12 Pipestill heaters (H-101A, H-101B and H-102). 

ii. #2 Coker heaters (F-201, F-202 and F-203). 

iii. GOHT heaters (F-901A, F-901B). 

iv. BOU F-401 furnace. 

b. By no later than December 31, 2013, 11C Pipestill heater H-200 

shall be an “affected facility” as that term is used in 40 C.F.R. Part 60, Subparts A 

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and Ja, and shall be subject to and comply with the applicable requirements of 

NSPS Subparts A and Ja for NOx emissions from process heaters. 

c. Entry of this Consent Decree and compliance with the relevant 

monitoring requirements of Subpart Ja shall satisfy the notice requirements of 40 

C.F.R. § 60.7(a) and the initial performance test requirement of 40 C.F.R. § 

60.8(a) for each heater listed in this Paragraph. 

34. Additional Requirements For New and Modified Heaters. 

a. BPP shall comply with the emission limits and Continuously 

Operate the listed NOx control technology listed in the following table by no later 

than the date of initial startup of the relevant unit: 

Unit 

Rated Capacity 

(mmBTU/hr) 

Control 

Technology Emission Limit 

11C Pipestill H-200 

Heater 249.5 ULNB 0.05 

lbs/mmBtu 

12 Pipestill H-101A 

Heater 355 ULNB 77.7 tpy 

12 Pipestill H-101B 

Heater 355 ULNB 77.7 tpy 

12 Pipestill H-102 

Heater 331 ULNB 72.5 tpy 

BOU F-401 

Furnace 35 0.098 lbs/mmBtu 

#2 Coker F-201 

Heater 208 ULNB & SCR 18.2 tpy 

#2 Coker F-202 

Heater 208 ULNB & SCR 18.2 tpy 

#2 Coker F-203 

Heater 208 ULNB & SCR 18.2 tpy 

DHT B-601-A 

Heater 42 ULNB 7.3 tpy 

GOHT F-901A 

Heater 47 ULNB 0.04 lbs/mmBtu 

GOHT F-901B 

Heater 47 ULNB 0.04 lbs/mmBtu 

b. The rated capacities listed in Paragraph 34.a are those as of the 

Date of Lodging and are included solely for purposes of identification of the 

relevant control technology and emission limit in Paragraph 34.a, and of the 

relevant monitoring requirement in Paragraph 35. 

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35. Monitoring and Testing. BPP shall monitor and test the following 

heaters at the Whiting Refinery as follows: 

a. Affected Heaters with a Capacity Greater Than 100 mmBTU/hr. 

Once every five years, BPP shall conduct a NOx performance test for each of the 

following process heaters with a rated capacity greater than 100 mmBTU/hr that 

are not monitored by a NOx CEMS : 

i. 4UF Furnaces F-4, F-5, and F-6 (venting through a 

common stack). 

ii. 4UF Furnaces F-1, F-8A, and F-8B (venting through a 

common stack). 

iii. ARU Furnace F-200A. 

iv. ARU Furnace F-200B. 

v. 11C Pipestill Heater H-300. 

vi. HU Heater B-501. 

vii. ISOM Heater H-1. 

BPP shall comply with the performance test protocols established by EPA 

Method 7E in conjunction with either EPA Method 19 or EPA Methods 1, 2, 3 

and 4, or an EPA-approved alternative test method. 

b. New and Modified Heaters with a Capacity Greater Than 100 

mmBTU/hr. BPP shall install or continue to operate a NOx CEMS on the heaters 

and boilers listed in Paragraph 34 with a maximum rated capacity greater than 

100 mmBTU/hr (HHV) by no later than December 31, 2013 (for the 11C Pipestill 

H-200 Heater) or the date of initial startup of the heater (for all other heaters). 

c. In the permit applications required by Paragraph 83.a, BPP shall 

apply to remove the authority that is currently contained in the existing permit to 

replace the existing burners in the ISOM Heater H-1 with larger burners. 

36. CEMS Monitoring Requirements. 

a. Performance Specifications. Beginning no later than one hundred 

and eighty (180) days after installing the applicable control technology on a heater 

or boiler that shall be monitored by use of a NOx CEMS required by Paragraph 

34, BPP shall install, certify, calibrate, maintain, and operate these CEMS in 

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accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS 

(excluding those provisions applicable only to Continuous Opacity Monitoring 

Systems) and 40 C.F.R. Part 60, Appendices A and F, and the applicable 

performance specification test of 40 C.F.R. Part 60, Appendix B. Unless 

Appendix F requirements are specifically required by NSPS or state regulations, 

BPP must conduct either a RAA or a RATA on each CEMS at least once every 

three (3) years in lieu of the requirements of 40 C.F.R. Part 60, Appendix F §§ 

5.1.1, 5.1.3 and 5.1.4. BPP shall conduct a Cylinder Gas Audit each Calendar 

Quarter during which a RAA or a RATA is not performed. 

b. Calculations. 

i. NOx emissions in lbs/mmBtu shall be calculated using 40 

C.F.R. Part 60, Appendix A, Method 19 and either the 12-month rolling 

average NOx concentration as determined by CEMS (for units monitored 

by a CEMS) or the NOx concentration measured in the most recent stack 

test demonstrating compliance (for units not monitored by a CEMS). 

ii. NOx emissions in tons/year shall be calculated using the 

following equation: 

Etpy = lb/mmBtu NOx * H * 1 ton/2000 lbs. 

Where: 

Etpy = Stack NOx emissions in tons per year 

H =	 Total heat input in mmBtu to the unit from 

fuels fired in the unit(s) over the previous 

rolling 12-month period 

lb/mmBtu NOx =	 lb/mmbtu emissions rate determined in 

accordance with Paragraph 36.b.i. 

37. The requirements of this Section do not exempt the Whiting Refinery 

from complying with any and all Federal, state, regional, and local requirements that may 

mandate technology, equipment, monitoring, or other upgrades that are: (a) based on 

actions or activities occurring after the Date of Entry of this Consent Decree; or (b) based 

upon new or modified regulatory, statutory, or permit requirements after the Date of 

Lodging. 

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38. BPP shall retain all records required to support its reporting 

requirements under this Section of the Consent Decree until its termination pursuant to 

Part XVII (Termination). BPP shall make such records and all CEMS data and test 

results available to EPA and IDEM upon request. 

G. SO2 Emissions Reductions from Heaters and Boilers 

Summary: BPP is required by this Section to undertake measures to reduce SO2 

emissions from refinery heaters and boilers by restricting H2S in refinery fuel gas and not 

burning Fuel Oil, except as specifically permitted under the provisions set forth in this 

Section. 

39. NSPS Applicability to Heaters and Boilers. 

a. Subpart Ja Applicability to Certain Existing Heaters and Boilers. 

Upon the Date of Entry, each of the following heaters and boilers shall be an 

“affected facility” for SO2 as that term is used in 40 C.F.R. Part 60, Subparts A 

and Ja, and shall be subject to and comply with the applicable requirements of 

NSPS Subparts A and Ja for SO2 emissions for fuel gas combustion devices: 

i. 11A Pipestill heaters (H-1X, H-2 and H-3). 

ii. 11C Pipestill heaters (H-200 and H-300). 

iii. New Hydrogen Unit heaters (HU-1 and HU-2). 

iv. BOU F-401 furnace. 

v. ISOM H-1 heater. 

vi. HU B-501. 

vii. CFHU heaters (F-801A, F-801B and F-801C) 

viii. DDU heaters (WB-301 and WB-302). 

ix. 4 UF heaters (F-1, F-2, F-3, F-4, F-5, F-6, F-7, F-8A and F8B). 

x. ARU heaters (F200A and F-200B). 

xi. 3SPS boilers (#1, #2, #3, #4 and #6). 

xii. 3SPS Duct Burners. 

xiii. CRU heaters (F-101 and F-102A). 

b. Subpart Ja Applicability to Certain New Heaters and Boilers. 

Upon the date of initial start-up, each of the following heaters and boilers shall be 

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an “affected facility” for SO2 as that term is used in 40 C.F.R. Part 60, Subparts A 

and Ja, and shall be subject to and comply with the applicable requirements of 40 

C.F.R. Part 60, Subparts A and Ja for SO2 emissions for fuel gas combustion 

devices: 

i. 12 Pipestill heaters (H-101A, H-101B and H-102). 

ii. #2 Coker heaters (F-201, F-202 and F-203). 

iii. GOHT heaters (F-901A, F-901B. 

iv. New Boiler 1. 

c. Entry of this Consent Decree and compliance with the relevant 

monitoring requirements of Subpart Ja shall satisfy the notice requirements of 40 

C.F.R. § 60.7(a) and the initial performance test requirement of 40 C.F.R. § 

60.8(a) for the heaters listed in Paragraph 39.a. 

40. Elimination of Fuel Oil Burning. 

a. Existing Heaters and Boilers. Effective on the Date of Entry, BPP 

shall not burn Fuel Oil in any heater or boiler at the Whiting Refinery in existence 

as of the Date of Lodging. 

b. Heaters or Boilers Constructed After Entry. After the Date of 

Entry, BPP shall not construct any new heater or boiler that burns Fuel Oil unless 

the air pollution control equipment controlling the combustion device either: 

i. has an SO2 control efficiency of 90% or greater; or 

ii. achieves an SO2 concentration of 20 ppm or less at 0% O2 

or less on a 3-hour rolling average basis, rolled hourly. 

Nothing in this Paragraph shall exempt BPP from securing all necessary permits before 

constructing a new heater or boiler at the Whiting Refinery. 

H. Fuel Gas Sulfur Content 

41. Limit on Total Sulfur Content in Refinery Fuel Gas. By no later than 

July 1, 2014, the total sulfur concentration of refinery fuel gas combusted in any heater, 

furnace or boiler at the Whiting Refinery shall not exceed 70 ppmvd total sulfur 

calculated as H2S on a 12-month rolling average basis. 

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42. Demonstrating Compliance with Total Sulfur Emission Limits. 

a. By no later than December 31, 2013, BPP shall install three Total 

Sulfur Continuous Analyzers on the refinery fuel gas systems to continuously 

monitor, measure and record the total sulfur concentration in refinery fuel gas, 

and to report compliance with the terms and conditions of this Consent Decree. 

The Total Sulfur Continuous Analyzers will be used to demonstrate compliance 

with the fuel gas sulfur concentration limit established pursuant to Paragraph 41. 

Consistent with 40 C.F.R. § 60.107a(a)(2)(iv), BPP shall monitor refinery fuel gas 

at locations that accurately represent the total sulfur concentration in the refinery 

fuel gas being burned in all heaters and boilers in the refinery, other than refinery 

fuel gas that would be exempt from monitoring under 40 C.F.R. § 60.107a(a)(3). 

The locations currently planned for these monitors are indicated in Appendix A. 

If BPP changes the location of any of these monitors, BPP shall notify EPA and 

submit a revised Appendix A showing the new locations in the next report 

required by Part VIII. 

b. BPP shall begin reporting data from the total sulfur analyzers to 

EPA and the Citizen-Intervenors once the analyzers are placed into service and 

certified. 

c. The Total Sulfur Continuous Analyzers required by this Paragraph 

shall be installed, operated and calibrated pursuant to ASTM D7166-10 and 40 

C.F.R. Part 60 Appendices A and F, and the applicable performance specification 

test of 40 C.F.R. Part 60, Appendix B, except that in lieu of the requirements of 

40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3 and 5.1.4, BPP must conduct either 

a RAAor RATA on each Total Sulfur Continuous Analyzer at least once every 

three (3) years. BPP must also conduct Cylinder Gas Audits each Calendar 

Quarter during which a RAA or a RATA is not performed. For RATA and RAA 

reference method comparisons, ASTM D3246-05 shall be used as the reference 

method. BPP shall make total sulfur analyzer data available to EPA and IDEM 

(as applicable) upon request. 

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I. CEMS Downtime Minimization, O&M and Corrective Action 

43. By no later than 180 days after the Date of Entry, BPP shall develop 

and submit for EPA review as provided in Paragraph 47 a comprehensive CEMS 

Operation and Maintenance Plan (“CEMS O&M Plan” or “Plan”) for the Whiting 

Refinery that is designed to enhance the performance of CEMS components, improve 

CEMS accuracy and stability, and minimize periods of CEMS downtime. This CEMS 

O&M Plan shall include at a minimum each of the elements identified in Paragraphs 44 

through 46. 

44. CEMS Operations and Maintenance Training. The CEMS O&M Plan 

shall provide for regular training for all individuals (BPP employees and contractors) 

involved in CEMS operations and maintenance to maintain necessary levels of 

monitoring competency. All newly-hired individuals (BPP employees and contractors) 

involved in CEMS operations and maintenance shall be trained prior to undertaking any 

CEMS-related responsibilities. The CEMS O&M Plan shall additionally ensure that all 

individuals involved in CEMS operations and maintenance have access to and are 

familiar with the CEMS O&M Plan. 

45. CEMS Testing and Calibration. BPP shall certify, calibrate, maintain, 

and operate all CEMS in accordance with the provisions of 40 C.F.R. § 60.13 that are 

applicable to CEMS (excluding those provisions applicable only to Continuous Opacity 

Monitoring Systems) and Part 60, Appendices A and F, and the applicable performance 

specification test of 40 C.F.R. Part 60, Appendix B. These requirements shall be 

included in the CEMS O&M Plan. 

46. Preventative Maintenance and Repair, and Quality Assurance/Quality 

Control (“QA/QC”). The Whiting Refinery’s CEMS O&M Plan shall include the 

following: 

a. A CEMS preventive maintenance program to provide for a 

regularly scheduled set of activities designed to prevent problems before they 

occur. Such activities and procedures may be based initially on the CEMS 

vendor’s recommendations. Routine preventative maintenance procedures shall 

be updated periodically to include such procedures as may be necessary or 

appropriate based on experience with each CEMS. 

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b. A CEMS QA/QC program to include provisions for assessing and 

maintaining the quality of continuous emission monitoring data, including regular 

(e.g., daily, weekly monthly) routine internal (and, as needed, external) 

maintenance and operation checks designed to maintain or improve data quality 

and minimize CEMS downtime. Internal checks include, but are not limited to, 

CEMS inspections, periodic calibrations, routine maintenance and measures to 

assess the quality of CEMS data (i.e., accuracy and precision). External checks 

include, but are not limited to, independent third-party CEMS audits, third-party 

sampling and analysis for accuracy and precision, or other assessments to ensure 

continuous and accurate CEMS operations. 

c. A CEMS repair program to ensure the timely repair of CEMS to 

address both routine maintenance and repair and non-routine maintenance and 

repair. BPP shall maintain a spare parts inventory adequate to meet the normal 

operating and CEMS preventative maintenance requirements. BPP shall establish 

procedures for acquisition of parts on an emergency basis (e.g., vendor 

availability on a next-day basis). An individual at the Whiting Refinery shall be 

designated for overall responsibility for maintaining the adequacy of the spare 

parts inventory. The on-site spare parts inventory may be based on the vendor's 

recommendations and shall be modified on an as-needed basis. 

47. EPA Review and Comment on CEMS Operation and Maintenance 

Plan. EPA may provide written comments on the CEMS Operation and Maintenance 

Plan submitted by BPP, in whole or in part, or EPA may decline to comment, as provided 

in this Paragraph. 

a. If EPA provides written comments within sixty (60) days of 

receiving a CEMS O&M Plan, then within forty-five (45) days of receiving such 

comments BPP shall either: (a) modify and implement the Plan consistent with 

EPA’s written comments, or (b) submit the matter for dispute resolution under 

Part XIV of the Consent Decree. 

b. After sixty (60) Days from the date of BPP’s submission of a 

CEMS O&M Plan, EPA may nonetheless provide written comments requiring 

changes to the Plan, which BPP shall thereafter implement unless implementation of 

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the written comments would (1) be unduly burdensome given the degree to which 

BPP has proceeded with implementing the CEMS O&M Plan or (2) would be 

otherwise unreasonable. If BPP determines that implementation of the written 

comments is unduly burdensome or otherwise unreasonable, it shall so notify EPA. 

Within sixty (60) days of receiving BPP’s position EPA may either accept BPP’s 

position or invoke dispute resolution pursuant to Part XIV of the Consent Decree. 

c. Upon the expiration of sixty (60) days from the date of BPP’s 

submission of a CEMS O&M Plan, or upon completion of any Dispute Resolution 

process under Part XIV of the Consent Decree regarding a submission, BPP shall 

implement the CEMS O&M Plan in accordance with the requirements and 

schedule within the Plan. 

48. CEMS Root Cause Failure Analysis. For any CEMS having a 

downtime greater than 5% of the total time for each of two consecutive calendar quarters, 

BPP shall conduct a CEMS Root Cause Failure Analysis and develop a corrective action 

plan to promptly address the findings of the CEMS Root Cause Failure Analysis. The 

CEMS Root Cause Failure Analysis shall include the following elements, at a minimum: 

a. An identification and detailed analysis setting forth the root 

cause(s) of the CEMS downtime; 

b. The steps, if any, taken to limit the duration of the CEMS 

downtime; 

c. An analysis of the measures reasonably available to prevent the 

root cause(s) of the CEMS downtime from recurring. This analysis shall include 

an evaluation of possible design, operational, and maintenance measures. For any 

CEMS for which a Root Cause Failure Analysis is required twice within 12 

consecutive calendar quarters, BPP shall retain an independent third party to 

evaluate BPP’s assessment of CEMS downtime cause(s), which may include 

recommendations for additional corrective actions and/or modifications to BPP’s 

CEMS O&M Plan. 

The findings of the CEMS Root Cause Failure Analysis and corrective action plan, 

including a schedule for implementation, shall be submitted to EPA in a written report 

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included with the first semi-annual report required by Part VIII of the Consent Decree 

following completion of the Root Cause Failure Analysis. 

49. Corrective Action. The corrective action plan shall require BPP to 

undertake as expeditiously as reasonably possible such reasonably available corrective 

actions as are necessary to correct the cause of the CEMS monitor downtime and to 

prevent a recurrence of the root cause(s) identified in the CEMS Root Cause Failure 

Analysis. The corrective action plan shall include a description of any corrective actions 

already completed or, if not complete, a schedule for their implementation including 

proposed commencement and completion dates. 

a. After a review of a CEMS Root Cause Failure Analysis and 

corrective action plan, EPA may notify BPP in writing of (1) any deficiencies in 

the corrective actions listed in the findings; and/or (2) any objections to the 

schedules of implementation of the corrective actions and explain the basis for 

EPA’s objections. 

i. If BP has not yet commenced implementation of the 

corrective plan, BP will implement an alternative or revised corrective 

action or implementation schedule based on EPA’s comments. 

ii. If a corrective action that EPA has identified as deficient 

has already commenced or is already completed, then BP is not obligated 

to implement the corrective action identified by EPA. However, BP shall 

be on notice that EPA considers such corrective action deficient and not 

acceptable for remedying any subsequent, similar root cause(s) of any 

future CEMS monitor downtime. 

b. If EPA and BP cannot agree on the appropriate corrective action(s) 

or implementation schedule(s), if any, to be taken in response to a CEMS Root 

Cause Failure Analysis, either party may invoke the Dispute Resolution 

provisions of Part XIV of the Consent Decree. 

J. Benzene Waste NESHAP 

Summary: BPP shall undertake the following measures to minimize or eliminate fugitive 

benzene waste emissions at its Whiting Refinery. Unless otherwise stated, all compliance 

requirements shall commence on the Date of Entry of the Consent Decree. Nothing in 

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this Section shall relieve BPP of its independent obligation to comply with the 

requirements of the Benzene Waste Operations NESHAP. 

50. Facility Compliance Status. 

a. Compliance Option. BPP shall comply with the compliance option 

set forth at 40 C.F.R. § 61.342(e) (the “6 BQ Option” or “6 Mg Option”) of the 

Benzene Waste Operations NESHAP. 

b. Changes to Compliance Option. BPP shall not change the 

compliance status of the Whiting Refinery from the 6 BQ Option to the 2 Mg 

compliance option. Any change in compliance strategy not expressly prohibited 

by this Section J must be accomplished in accordance with the requirements of 

the Benzene Waste Operations NESHAP. 

c. Organic Benzene Wastes. BPP shall ensure that waste 

management units at the Whiting Refinery handling Organic Benzene Wastes are 

in compliance with all standards applicable to such waste management units 

under the Benzene Waste Operations NESHAP. 

d. Aqueous Benzene Wastes. For purposes of complying with the 6 

Mg Option, all waste management units at the Whiting Refinery handling 

Aqueous Benzene Wastes shall either: (1) meet the applicable control standards of 

the Benzene Waste Operations NESHAP, or (2) have their uncontrolled benzene 

quantity count toward the 6 Mg compliance limit. Nothing in this sub-paragraph 

shall be construed to limit the ability of BPP to treat and manage Aqueous 

Benzene Wastes in accordance with the requirements of 40 C.F.R. § 61.355(k)(4). 

e. Annual TAB Report. Beginning on April 1, 2012 for the calendar 

year 2011 TAB report and continuing thereafter on or before each April 1st, BPP 

shall submit its annual TAB report for the preceding calendar year required 

pursuant to 40 C.F.R. § 61.357(d)(2). 

51. Waste Stream and Wastewater System Compliance Audit. BPP 

certifies that it has completed and, on January 25, 2010, submitted to EPA a report on a 

comprehensive Waste Stream and Wastewater System Compliance Audit, conducted by 

an independent third-party, of the Whiting Refinery’s benzene waste stream inventory, 

TAB calculation, all waste management units, and entire wastewater treatment system in 

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order to assess compliance with all applicable Benzene Waste Operation NESHAP 

requirements. BPP further certifies that, as reported in the January 25, 2010 report, it has 

completed implementation of all corrective actions necessary to remedy the findings of 

the Waste Stream and Wastewater System Compliance Audit. 

52. Carbon Canisters. At all locations within the Whiting Refinery where 

carbon canisters are currently installed and used as the control device for complying with 

the Benzene Waste Operations NESHAP, BPP shall implement and comply with the 

following: 

a. Dual Carbon Canisters/Beds. 

i. Except as provided for in sub-paragraph 52.b, by no later 

than 12 months after the Date of Entry of the Consent Decree, BPP shall 

install primary and secondary carbon canisters and operate them in series 

(the “dual-canister” option). BPP may comply with the requirements of 

the dual canister option required under this sub-paragraph by using a 

single canister with a “dual carbon bed” if the dual carbon bed 

configuration allows for breakthrough monitoring between the primary 

and secondary beds in accordance with this sub-paragraph. 

ii. Breakthrough monitoring. BPP shall conduct breakthrough 

monitoring between the primary and secondary carbon canisters or beds 

when there is actual flow to the carbon canister. Such monitoring shall be 

conducted in accordance with the frequency specified in 40 C.F.R. § 

61.354(d) using as the design basis the applicable breakthrough definition 

specified in sub-paragraph 52.a.iii. If a carbon canister or bed becomes 

unsafe to monitor because it is located within a temporary exclusion zone, 

BPP shall monitor the canister or bed as soon as is practicable after the 

exclusion zone is no longer in effect, but in no case later than the end of 

the normal monitoring interval for the canister or bed or within 3 days of 

the end of the exclusion period, whichever is sooner. BPP shall include in 

its semi-annual report a list of all canisters or beds which BPP has 

designated as unsafe to monitor during the reporting period. 

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iii. Breakthrough definition. BPP may use either 50 ppmv 

VOC or 1 ppmv benzene as the design value for the primary carbon 

canister or bed. BPP shall immediately replace the primary carbon 

canister or bed when the design value for the primary canister or bed is 

exceeded (as monitored between the primary and secondary carbon 

canister or carbon bed). Unless both the primary and secondary carbon 

canisters or beds are replaced with fresh ones, the original secondary 

carbon canister or bed shall become the new primary carbon canister or 

bed and a fresh secondary carbon canister or bed shall be installed. In all 

cases, any carbon canister or bed used as the primary unit shall have 

sufficient capacity to meet the breakthrough definition of this subparagraph. For purposes of this sub-paragraph 52.a, “immediately” means 

no later than within twenty-four (24) hours. 

iv. BPP shall maintain a sufficient supply of fresh carbon 

canisters and carbon beds at the Whiting Refinery at all times. 

v. For any new waste management unit(s) or refinery process 

unit(s) at the Whiting Refinery where carbon canisters will be installed 

and used as the control device for complying with the Benzene Waste 

Operations NESHAP, BPP shall comply with the dual-canister option, 

except as provided in sub-paragraph 52.b. 

b. Single Carbon Canisters. 

i. Permitted locations. After the Date of Entry, for any 

carbon canister at the Whiting Refinery subject to this Paragraph 52, BPP 

may use the “single canister” option described in this sub-paragraph at the 

following locations: 

(1) If BPP demonstrates that it is technologically 

infeasible or unsafe to comply with the dual-canister option under 

sub-paragraph 52.a, BPP may use a single carbon canister at that 

specific location. BPP shall submit a written request to EPA to 

comply with the “single canister” option for each such canister. 

This request shall specifically identify each carbon canister for 

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which BPP claims that it is technologically infeasible or unsafe to 

comply with the dual-canister option and shall provide a detailed 

explanation of the specific technical and/or safety reasons for the 

request. This request shall be subject to EPA approval. 

(2) BPP may use a single carbon canister at locations 

where breakthrough, as defined in this sub-paragraph 52.b, has 

been documented as occurring less than once per calendar year. 

(3) BPP may use a single carbon canister on temporary 

waste management units (e.g., FRAC or Baker tanks), provided 

that such temporary units are used for no more than 30 Days. 

(4) Until December 31, 2015, BPP may use single 

carbon canisters at the DAF unit and API Separator that are subject 

to sub-paragraph 60.g. Within 12 months after the Date of Entry 

and continuing until December 31, 2015, BPP shall optimize the 

use of bio-filters or other control or treatment technologies to 

minimize breakthrough at the single carbon canisters at the DAF 

and API Separator. 

ii. Breakthrough monitoring. By no later than the Date of 

Entry, BPP shall conduct breakthrough monitoring for each single carbon 

canister at the Whiting Refinery when there is actual flow to the canister. 

Such monitoring shall be conducted in accordance with all requirements 

specified in 40 C.F.R. § 61.354(d) using as the design basis the applicable 

breakthrough definition specified in sub-paragraph 52.b.iii, but in no case 

less frequently than on a monthly basis. If a carbon canister or bed 

becomes unsafe to monitor because it is located within a temporary 

exclusion zone, BPP shall monitor the canister or bed as soon as is 

practicable after the exclusion zone is no longer in effect, but in no case 

later than the end of the normal monitoring interval for the canister or bed 

or within 3 days of the end of the exclusion period, whichever is sooner. 

BPP shall include in its semi-annual report a list of all canisters or beds 

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which BPP has designated as unsafe to monitor during the reporting 

period. 

iii. Breakthrough definition. Single carbon canisters will be 

replaced immediately when breakthrough is detected as follows: 

(1) For canisters less than or equal to 55-gallon drum 

size, breakthrough is any reading of VOC or benzene above 

background. 

(2) For canisters larger than 55 gallons, breakthrough is 

defined as either: 

a.	 50 ppmv VOC; or 

b.	 1 ppmv benzene. To use 1 ppmv benzene, 

canisters must be monitored for VOC. 

When a reading of 10 ppmv VOC is 

detected, monitoring for benzene must be 

conducted on the following schedule: 

i.	 Daily if the representative historical 

replacement interval is two weeks or 

less, or 

ii.	 Three times per week and not on 

consecutive days, if the 

representative historical replacement 

interval is greater than two weeks. 

(3) For purposes of this sub-paragraph 52.b, the term 

“immediately” shall mean: within eight (8) hours for single 

canisters with representative historical replacement intervals of 

two weeks or less; or within twenty-four (24) hours for single 

canisters with a representative historical replacement interval of 

more than two weeks. 

iv. Canister Replacement. Single carbon canisters may be 

replaced with a dual carbon canister or carbon bed system at any time 

provided EPA is notified and the monitoring requirements for single 

canisters are continued until the second canister or bed is installed. BPP 

shall comply with the monitoring requirements for dual-carbon canisters 

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or dual-carbon beds provided in sub-paragraph 52.a upon installation of 

such system, and BPP shall notify EPA of such replacement in its next 

quarterly report submitted pursuant to Part VIII of the Consent Decree. 

c. Alternative Control/Treatment Devices. Nothing in Paragraph 52 

of this Section of the Consent Decree is intended to preclude BPP from electing to 

use other control devices at the Whiting Refinery to comply with the Benzene 

Waste Operations NESHAP instead of or in addition to carbon adsorption, 

provided that such other control technology meets all applicable control and/or 

treatment requirements under the Benzene Waste Operations NESHAP and the 

compliance monitoring point is unaffected by the use of such other control 

devices. If BPP elects to use another control technology, BPP shall submit 

written notification to EPA in its next semi-annual report submitted pursuant to 

Part VIII of the Consent Decree providing both the location where such other 

control technology shall be used instead of or in addition to carbon adsorption and 

a description of the other technology to be used. 

d. Records. Records regarding compliance with Paragraph 52 shall 

be maintained in accordance with 40 C.F.R. § 61.356(j)(10). 

53. Annual Program. BPP shall continue to implement an annual program 

of reviewing process information for the Whiting Refinery, including but not limited to 

construction projects, to ensure that all new benzene waste streams are included in the 

Whiting Refinery’s waste stream inventory and TAB Report, and to ensure that all new 

waste management units are properly accounted for and managed in accordance with the 

Benzene Waste Operations NESHAP. 

54. Laboratory Audits. BPP shall conduct audits of all laboratories that 

perform analyses of samples used to determine compliance with the Benzene Waste 

Operations NESHAP at the Whiting Refinery. These audits shall review procedures and 

methods in order to ensure that proper analytical and quality assurance practices are 

followed. BPP shall conduct such audits at each laboratory at least every two (2) 

calendar years from the date of the last audit conducted by the Whiting Refinery pursuant 

to Paragraph 19.H of the 2001 Consent Decree or prior to using a new lab for analysis of 

benzene samples. 

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55. Benzene Spills. At least once per calendar year, BPP shall review all 

CERCLA reportable spills at the Whiting Refinery to determine if benzene waste was 

generated. BPP shall account for all benzene wastes generated through such spills in its 

annual TAB calculation and report. All benzene wastes generated through such spills 

that are not managed solely in controlled waste management units shall count toward the 

6 Mg compliance limit. 

56. Training. BPP shall: 

a. Develop and implement annual training for all employees at the 

Whiting Refinery with responsibility to sample benzene waste streams; 

b. Establish standard operating procedures for all control devices 

used to comply with the Benzene Waste Operations NESHAP and include 

training on such procedures as part of the annual training for employees assigned 

to operate these devices; and 

c. Ensure that third-party contractors hired to perform any 

requirement of this Section J of the Consent Decree have a proper training 

program to implement the provisions of this Paragraph. 

57. Waste/Slop Oil Management. BPP shall maintain records of waste/slop 

oil movements for waste streams (organic or aqueous) that are not controlled, as 

identified in the slop oil plan prepared by the Whiting Refinery. EPA may review the 

plan and recommend revisions to add uncontrolled waste streams resulting from 

waste/slop oil movements, in accordance with the provisions of 40 C.F.R. Part 61, 

Subpart FF. 

58. Sampling (6 Mg/yr). BPP shall conduct quarterly “end-of-line” 

(“EOL”) benzene determinations as follows: 

a. If no changes will be made to the sampling locations or methods 

for flow calculations currently used in the quarterly and annual benzene 

determinations for the Whiting Refinery, BPP shall comply with and continue 

sampling under the refinery’s existing EOL Sampling Plan; 

b. If BPP proposes to make any changes to the sampling locations or 

methods for flow calculations to be used in the quarterly benzene determinations 

for the Whiting Refinery, within 30 Days after the Date of Entry of the Consent 

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Decree, BPP shall submit a revised EOL Sampling Plan that shall contain any 

proposed changes. The revised EOL Sampling Plan shall be subject to EPA 

approval. BPP shall comply with and commence sampling under the revised EOL 

Sampling Plan by no later than the first full Calendar Quarter following submittal 

of the plan to EPA, regardless of whether the plan is approved at that time; 

c. On an annual basis, BPP shall sample all uncontrolled waste 

streams that count toward the 6 Mg compliance limit and contain greater than 

0.05 Mg/yr of benzene; and 

d. If changes in processes, operations, or other factors lead BPP to 

conclude that the EOL Sampling Plan for the Whiting Refinery may no longer 

provide a representative basis for estimating the Whiting Refinery’s annual or 

quarterly EOL benzene quantity, then by no later than ninety (90) Days after BPP 

makes this determination, BPP will submit to EPA a newly proposed revised EOL 

Sampling Plan. Upon receipt of EPA approval, BPP shall commence sampling 

consistent with the requirements and schedule contained in the newly approved 

EOL Sampling Plan. 

59. Groundwater Conveyance Systems. BPP shall manage all groundwater 

conveyance systems located at the Whiting Refinery in accordance with, and to the extent 

required by, 40 C.F.R. § 61.342(a). 

60. Miscellaneous Measures. By no later than the Date of Entry, BPP shall 

implement the measures identified in subparagraphs a.-f: 

a. BPP shall conduct monthly visual inspections of all water traps 

within its individual drain systems that are subject to the Benzene Waste 

NESHAP; 

b. BPP shall identify/mark all area drains that are segregated 

stormwater drains; 

c. BPP shall include each controlled individual drain system subject 

to the Benzene Waste Operations NESHAP at the Whiting Refinery on all 

inspection schedules pertaining to Benzene Waste Operation NESHAP 

compliance, and shall conduct inspections of each such drain system in 

accordance with such schedules set forth in 40 C.F.R. Part 61, Subpart FF; 

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d. BPP shall monitor the flow indicators on all conservation vents on 

process sewers for detectable leaks on a weekly basis; 

e. BPP shall conduct quarterly monitoring of oil/water separators in 

benzene service in accordance with 40 C.F.R. § 61.347; and 

f. BPP shall account for and include in the annual TAB Report all 

slop oil recovered from its oil/water separators or sewer system until recycled or 

put into a feed tank, in accordance with 40 C.F.R. § 61.342(a). All tanks handling 

waste benzene shall meet the control standards specified in 40 C.F.R. § 61.343 or 

§ 61.351, except that Tank P1 and Tank P2 at the Whiting Refinery shall meet the 

tank control standard at 40 C.F.R. § 61.343. 

g. DAF Installation/API Separator Covers. By no later than 

December 31, 2015, BPP shall complete construction and installation of a new 

Dissolved Air Flotation (DAF) unit at the Whiting Refinery. By no later than 

December 31, 2015, BPP shall complete construction and installation of new 

covers for the API Separator at the Whiting Refinery. By no later than December 

31, 2015, emissions from both the new DAF and API Separator shall be routed to 

control devices, such as carbon canisters, that meet all applicable control and/or 

treatment requirements under the Benzene Waste Operations NESHAP. 

61. Heat Exchange Systems and Cooling Towers. 

a. Applicability. In complying with the National Emission Standards 

for Hazardous Air Pollutants from Petroleum Refineries, 40 C.F.R. Part 63, 

Subpart CC, BPP may only claim that a heat exchange system is not in “organic 

HAP service” pursuant to 40 C.F.R. § 63.654(b)(2) if the heat exchange system 

only cools process fluids that contain less than 2.5% by weight of total HAPs (as 

listed in Table 1 to Subpart CC). 

b. TAB Reporting. Beginning with the first TAB Report submitted 

for the refinery after October 29, 2012, and for each TAB report thereafter, BPP 

shall report as a separate line-item the entire benzene quantity identified by 

monitoring conducted pursuant to 40 C.F.R. §63.654(c) at all heat exchange 

systems at the Whiting Refinery subject to 40 C.F.R. Part 63, Subpart CC and 

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those identified above in sub-paragraph 61.a. This line-item shall not be counted 

towards the uncontrolled benzene quantity under the 6 Mg Option. 

62. Semi - Annual Benzene Waste NESHAP Report. By no later than 

February 15 and August 15 of each calendar year after the Date of Entry, BPP shall 

submit a semi-annual report to EPA that includes the following information for the 

Whiting Refinery regarding compliance with the Benzene Waste NESHAP requirements 

of this Section (the “Semi-Annual Benzene Waste NESHAP Report”). Each SemiAnnual Benzene Waste NESHAP Report shall include the following information for the 

two most recently completed Calendar Quarters (the “reporting period”): 

a. EOL Report: 

i. As part of each Semi-Annual Benzene Waste NESHAP 

Report, BPP shall submit to EPA the following information: 

(1) a list of all waste streams sampled at the Whiting 

Refinery pursuant to Paragraph 58; 

(2) the results of the quarterly and annual sampling 

conducted pursuant to Paragraph 58, including the results of the 

benzene analysis for each sample; 

(3) the computation of the EOL benzene quantity for 

each quarter; and 

(4) any other related information required under a 

revised EOL Sampling Plan if submitted pursuant to Paragraph 58. 

ii. As part of the EOL Report, BPP shall use all sampling 

results and approved flow calculation methods pursuant to Paragraph 58 to 

calculate and report a quarterly and a calendar year uncontrolled benzene 

quantity for the Whiting Refinery against the 6 Mg Option. 

iii. If the quarterly uncontrolled benzene quantity (for any 

Calendar Quarter during the reporting period) at the Whiting Refinery 

exceeds 1.5 Mg or the annual uncontrolled benzene quantity exceeds 6 

Mg, then BPP shall, as specified below, conduct a Root Cause Failure 

Analysis and develop a corrective action plan (including a schedule for 

completing the corrective actions) to promptly address the findings of the 

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Root Cause Failure Analysis. The findings of the Root Cause Failure 

Analysis and corrective action plan shall be submitted to EPA in a written 

report within 30 Days following completion of the Root Cause Failure 

Analysis. This corrective action plan shall be subject to EPA approval. 

BPP shall begin to implement the corrective action plan by no later than 

60 Days after submission to EPA, and shall complete the corrective action 

pursuant to the proposed schedule. 

(1) Root Cause Failure Analysis. The Root Cause 

Failure Analysis required under this sub-paragraph shall include 

the following elements: 

a. If the root cause(s) of the quarterly or annual 

uncontrolled benzene exceedance is 

attributable to at least one discrete event, or 

to at least one discrete series of related 

events, resulting in 0.5 Mg or more of 

uncontrolled benzene, BPP shall include an 

estimate of the quantity of uncontrolled 

benzene emitted into the ambient air along 

with the calculations used to determine such 

emissions; 

b. The steps, if any, taken to limit the duration 

and/or quantity of uncontrolled benzene 

exceeding 1.5 Mg per quarter or the 6 Mg 

Option; 

c. A detailed analysis setting forth the root 

cause(s) for exceeding 1.5 Mg per quarter or 

the 6 Mg Option; and 

d. An analysis of the measures reasonably 

available to prevent the root cause(s) for the 

exceedance from recurring. This analysis 

shall include an evaluation of possible 

design, operational, and maintenance 

measures. This analysis shall also include a 

discussion of alternative measures that are 

reasonably available, their relative probable 

effectiveness, and their relative costs. 

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(2) Corrective Action Plan. The corrective action plan 

required under this sub-paragraph shall require BPP to undertake 

as expeditiously as possible any such interim and/or long-term 

corrective actions as are necessary and consistent with good air 

pollution control practices to prevent a recurrence of the root 

cause(s) identified in the Root Cause Failure Analysis. The 

corrective action plan shall include a description of any corrective 

actions already completed or, if not complete, a schedule for their 

implementation including proposed commencement and 

completion dates. 

iv. BPP shall identify all labs used during the quarter to 

analyze benzene waste samples collected at the Whiting Refinery pursuant 

to this Section J, and BPP shall provide the date of the most recent audit of 

each lab. 

b. Carbon Canister Report. 

i. As part of the second Semi-Annual Benzene Waste 

NESHAP Report required by the Consent Decree, BPP shall submit a 

project completion report to EPA detailing the actions performed to 

comply with the requirements of Paragraph 52. BPP shall include a list of 

all locations within the refinery using the dual-canister option, the 

installation date of each such dual-canister, and the date that each dualcanister was put into operation. 

ii. As part of each Semi-Annual Benzene Waste NESHAP 

Report, for all locations at which single carbon canisters are used, BPP 

shall identify each such location and provide the results of all 

breakthrough monitoring and carbon canister change-outs that occurred 

during the reporting period. For each single carbon canister, BPP shall 

also identify: i) the date(s) and approximate time when breakthrough was 

first detected; and ii) for each breakthrough event, the date and time when 

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annual report a list of all canisters or beds which BPP has designated as 

unsafe to monitor during the reporting period. 

c. Audit Reporting: As part of each Semi-Annual Benzene Waste 

NESHAP Report, BPP shall identify all labs audited pursuant to the requirements 

of Paragraph 54 during the reporting period, and shall submit the results and the 

reports regarding any such audits. For each lab audited, BPP shall also provide a 

description of the methods used in the audit. 

d. Training Reporting: As part of each Semi-Annual Benzene Waste 

NESHAP Report, BPP shall identify the employees who received training during 

the reporting period pursuant to the requirements of Paragraph 56, and shall 

describe the training these employees received. BPP shall also describe the 

training scheduled to be performed during the next reporting period. 

e. BPP shall certify each Semi-Annual Benzene Waste NESHAP 

Report required in accordance with the certification statement required under 

Paragraph 102 of the Consent Decree. 

K. Leak Detection and Repair 

63. NSPS Applicability. Upon the Date of Entry, each “process unit” (as 

defined by 40 C.F.R. § 60.590a(e)) at the Whiting Refinery shall be an “affected facility” 

for purposes of 40 C.F.R. Part 60, Subpart GGGa, and shall be subject to and comply 

with the requirements of Subpart GGGa no later than one year from the Date of Entry, 

except as specifically provided in this Paragraph. 

a. The requirements of 40 C.F.R. Part 60, Subpart GGGa, shall not 

apply to compressors at the Whiting Refinery. 

b. Process units on which construction commenced prior to January 

4, 1983, shall not be subject to the requirements in 40 C.F.R. § 60.482-7a(h)(2)(ii) 

regarding difficult-to-monitor valves. 

c. Entry of this Consent Decree satisfies the following notification 

and testing requirements that are triggered by initial applicability of 40 C.F.R. 

Part 60, Subparts A and GGGa: 40 C.F.R 60.7, 60.8, 60.18 (but only with respect 

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to the following flares: FCU, Alky, 4UF, DDU, SRU and VRU), 60.482-1a(a) 

and 60.487a(e).

d. The two consecutive months of monitoring that BPP previously 

conducted for purposes of 40 C.F.R. Part 60, Subpart GGGa in 2011 satisfies the 

requirement to conduct monitoring of those components for two consecutive 

months following the initial applicability of 40 C.F.R. Part 60, Subpart GGGa for 

the following units of the Whiting Refinery: FCU 500, VRU 300, 4UF, Alky 

Analyzer, ARU, Indiana Tank Field, J&L Tank Field, Lake George Tank Field, 

Marketing Terminal, Oil Movements Diluent, Oil Movements North, South Tank 

Field and Stieglitz Park Tank Field. 

Nothing in this Paragraph or in Appendix B to this Consent Decree shall relieve BPP of 

its independent obligation to comply with the requirements any other federal, state or 

local LDAR regulation that may be applicable to Equipment at the Whiting Refinery. 

64. Enhanced Leak Detection and Repair. BPP shall implement and 

comply with the requirements of the Enhanced Leak Detection and Repair Program 

(“ELP”) set forth in Appendix B to this Consent Decree by the dates specified therein. 

The requirements of Appendix B are in addition to the applicable requirements under 40 

C.F.R. Part 60, Subpart GGGa; Part 61, Subparts J and V; and Part 63, Subparts H and 

CC. The terms “in light liquid service” and “in gas/vapor service” shall have the 

definitions set forth in the applicable provisions of 40 C.F.R. Part 60, Subpart GGGa; and 

Part 63, Subpart CC. 

L. Sulfur Recovery Plant and Sulfur Pits 

Summary: BPP is required to accept NSPS Subpart Ja applicability for its Sulfur 

Recovery Plant (“SRP”), and to route all emissions from its sulfur pits and sealed sulfur 

collection drums such that all emissions are treated and included as SRP emissions 

subject to 40 C.F.R. Part 60, Subparts A and Ja. 

65. Sulfur Recovery Plant and NSPS Applicability. The Whiting Refinery 

currently has a single SRP with three parallel Claus sulfur recovery units, with two Tail 

Gas Units (an SBS unit and a Beavon Stretford unit) serving as control devices. As a part 

of WRMP, two new Claus sulfur recovery units will be added to the SRP, and the SBS 

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and Beavon Stretford units will be shut down and replaced by two new Claus Offgas 

Treaters (COT1 and COT2), as provided in this Section. Upon completion of WRMP, 

the design of the SRP will allow tail gas from all five Claus sulfur recovery units to be 

routed to either or both of the two new COTs. By no later than the Date of Entry, the 

Whiting Refinery SRP shall be an “affected facility” as that term is used in 40 C.F.R. Part 

60, Subparts A and Ja, for all pollutants applicable to SRPs, and shall be subject to and 

comply with all applicable requirements of 40 C.F.R. Part 60, Subparts A and Ja except 

as provided in this Paragraph 65. 

a. Each of the two new Claus sulfur recovery units and Claus Offgas 

Treaters being installed as a part of WRMP shall achieve and thereafter maintain 

compliance with the emission limit in 40 C.F.R. § 60.102a(f)(1)(i) and the 

monitoring requirements in 40 C.F.R. § 60.106a(a)(1) by no later than 60 days 

after achieving the maximum production rate at which the unit will be operated, 

or 180 days after initial startup, whichever comes first. 

b. The Beavon Stretford and SBS units at the Whiting Refinery SRP 

shall be shut down and permanently removed from service by no later than 180 

days after the initial startup of the later of the two new Claus sulfur recovery units 

and associated Claus Offgas Treaters (COT1 or COT 2) being installed as a part 

of WRMP. Initial startup of the two new Claus sulfur recovery units and the 

Claus Offgas Treaters shall be by no later than the initial startup of the New 

Coker. Until the Beavon Stretford unit is shut down, BPP shall continue to 

monitor emissions from that unit and determine compliance with the emission 

limits in 40 C.F.R. § 60.102a(f)(1) in accordance with the monitoring procedure 

specified in Appendix C. 

66. SRP Emission Limits. Beginning no later than the date by which the 

later of the two new Claus Sulfur Recovery Units and associated Claus Offgas Treaters 

being installed as a part of WRMP is required to achieve compliance under Paragraph 

65.a of this Section, the Whiting Refinery SRP shall comply with the following 

requirements: 

a. An SO2 emission limit of 194.8 tons per each rolling 12-month 

period. Compliance with this limit shall be determined each month by adding the 

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total emissions for that month to the total emissions for the preceding 11 months. 

Total emissions for each month shall be determined with CEMS emission data 

converted by the following equation: 

⎛ F × h×C × MW ⎞ E = ⎜

⎜	 ⎟⎟

V × 2000×106

⎝ m ⎠

E = TGTU SO2 Emissions in tons per month 

F = Measured total TGTU incinerator stack flow rate, dscf at 

standard conditions (60o F), for the month 

C = Average concentration of SO2 in TGTU incinerator 

exhaust for the month, in ppmvd 

MW = Molecular weight of SO2 = 64.06 

Vm = 379.4 dscf of gas per lb-mol at standard conditions (60o F) 

2000 = conversion factor for 2000 pound per ton 

106 

= conversion factor for ppmv to volume fraction 

b. 40 C.F.R. § 60.102a (f)(1)(i) during all periods of operation of the 

SRP, other than periods of Startup, Shutdown or Malfunction of the SRP or 

malfunction of a Tail Gas Unit (TGU) to the extent provided under 40 C.F.R. § 

60.8. 

c. At all times, including, but not limited to, periods of Startup, 

Shutdown, Malfunction and maintenance, BPP shall, to the extent practicable, 

operate and maintain the SRP, including its TGU, its sulfur pits and sealed sulfur 

collection drums, any supplemental control devices on the SRP, and Pit 2400 and 

the molten sulfur storage tanks, in accordance with its obligation to minimize 

emissions through implementation of good air pollution control practices as 

required by 40 C.F.R. § 60.11(d). 

67. SRP Operations and Maintenance. 

a. By no later than 60 Days after the Date of Lodging, BPP shall 

submit to EPA an updated plan for operating and maintaining the SRP, including, 

but not limited to, the existing TGUs, sulfur pits A, B, C, and 2400, as well as 

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upstream process units, in accordance with good air pollution control practices for 

minimizing emissions. 

b. By no later than December 31, 2012, BPP shall submit to EPA an 

updated plan (“SRP O&M Plan”) for operating and maintaining the SRP, 

including, but not limited to, the two new Claus sulfur recovery units and Claus 

Offgas Treaters, the sealed sulfur collection drums, the molten sulfur storage 

tanks, as well as upstream process units, in accordance with good air pollution 

control practices for minimizing emissions. 

c. BPP shall comply with the most recently submitted SRP O&M 

Plan at all times, including, but not limited to, periods of Startup, Shutdown, and 

Malfunction of the SRP. BPP may make reasonable modifications to the SRP 

O&M Plan submitted under this Paragraph, provided that BPP provides EPA with 

a copy of the modification in its next semi-annual report submitted pursuant to 

Part VIII of the Consent Decree. 

68. Sulfuric Acid Mist Testing. By no later than 180 days after the 

commencement of operations of the two new COTs (COT1 and COT2), BPP shall 

conduct a one-time test at each COT stack under representative conditions to measure the 

sulfuric acid mist (“SAM”) emission rate. 

69. Sulfur Pit and/or Sulfur Collection Drum and Tank Emissions. 

a. Sulfur Pit Emissions. By no later than the Date of Entry, BPP shall 

(i) comply with the requirements of 40 C.F.R. § 60.102a(f) as it applies to Sulfur 

Pits A, B and C and (ii) continue to operate and maintain the following control 

and monitoring equipment until Pits A, B, C and 2400 are decommissioned: 

i. Pit sweep system for Pits A, B, C and 2400; 

ii. Temperature indicators located at each eductor inlet at Pits 

A, B, C and 2400; and 

iii. Caustic scrubber to treat emissions from Pits A, B, C and 

2400 in the event that pit sweep emissions are routed to the Beavon 

Stretford unit. 

b. Sulfur Pit 2400 Degas System. By no later than the Date of Entry, 

BPP shall, to the extent practicable, maintain and operate the newly redesigned 

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degas system to minimize the entrainment of H2S vapor in the sulfur routed to Pit 

2400 in a manner consistent with good air pollution control practice for 

minimizing emissions. 

c. Emissions From Sealed Sulfur Collection Drums and Molten 

Sulfur Tanks.

 i. By no later than 180 Days after initial startup of the New 

Coker, BPP shall replace Sulfur Pits A, B and C with sealed sulfur 

collection drums, and shall replace Pit 2400 with molten sulfur storage 

tanks. By no later than the date that BPP replaces Sulfur Pits A, B and C 

with sealed collection drums and Pit 2400 with storage tanks, BPP shall 

route all sulfur emissions from the sealed sulfur collection drums and the 

molten sulfur storage tanks such that they are treated, monitored, and 

included as part of the SRP’s emissions subject to the NSPS Subpart Ja 

limit for SO2, 40 C.F.R. § 60.102a (f)(1)(i). 

ii. For a period of one year commencing from the first use of 

each molten sulfur storage tank, BPP shall monitor on a continuous basis 

and report to EPA on a semi-annual basis the duration of all relief valve 

releases from each molten sulfur storage tank. 

iii. Nothing in this subparagraph 69.c shall preclude BPP from 

undertaking maintenance on the sealed sulfur collection drums consistent 

with the provisions of 40 C.F.R. § 60.102a(f)(3), or the molten sulfur 

storage tanks consistent with subparagraph 72.b of Section M of this 

Consent Decree (Requirements for Certain Tanks). 

M. Requirements for Certain Tanks 

70. Stormwater Equalization Tank (TK-5052): BPP shall continue to 

operate and maintain an external floating roof on the stormwater equalization tank 

designated as Tank 5052 at the Whiting Refinery consistent with the requirements of 40 

C.F.R. § 61.351(a)(2). 

71. Brine Treatment Tanks (TK-101, TK-102, TK-103 and TK-104): 

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a. The Brine Treatment Tanks (TK-101, TK-102, TK-103 and TK104) at the Whiting Refinery shall be equipped with fixed roofs and shall be 

vented to (i) an iron sponge control system followed by (ii) a carbon canister 

meeting the requirements of 40 C.F.R. § 61.349(a)(2) and Paragraph 52 of Section 

J of this Consent Decree (Benzene Waste NESHAP). Subject to EPA approval, 

BPP shall have the ability to utilize an alternative to the carbon canister 

authorized by 40 C.F.R. § 61.349(a)(2). 

b. BPP shall monitor and record daily average H2S concentration on 

the outlet of the iron sponge system and daily total vapor flow to the iron sponge 

system. Process analyzers calibrated in accordance with manufacturer’s 

recommendations may be used for these purposes. 

72. Sulfur Storage Tanks (TK-315 and TK-316): 

a. Each of the sulfur storage tanks designated as TK-315 and TK-316 

at the Whiting Refinery shall be steam or nitrogen blanketed and equipped with a 

water eductor system that routes H2S emissions back to the sulfur recovery plant 

at all times except during periods when the tanks are vented to atmosphere to 

allow for maintenance on equipment associated with the tank (i.e., valves and 

level transmitters). 

b. Tanks TK-315 and TK-316 shall not be vented to atmosphere 

except during periods of maintenance on equipment associated with the tank, and 

during those periods for no more than 100 hours per rolling12-month period. 

73. Off-Spec Brine Tanks (TK-3559 and TK-3560): 

a. BPP shall continue to operate and maintain an internal floating 

roof on each Off-Spec Brine Tank (TK-3559 and TK-3560) consistent with the 

requirements of 40 C.F.R. § 61.351(a)(1). 

b. VOC emissions from the Off-Spec Brine Tanks shall not exceed a 

total of 2.1 tons per rolling 12-month period. 

c. For each of the Off-Spec Brine Tanks, BPP shall: 

i. monitor and record throughput on a monthly total basis; 

and 

ii. sample the material in the tank off the tank's floating 

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suction line and measure and record the Reid Vapor Pressure (“RVP”) of 

any oil layer once per month. 

d. Using the throughput data collected under Paragraph 73.c.i, and the 

most recent RVP measurement collected under Paragraph 73.c.ii, BPP shall use 

USEPA’s “TANKS” model to determine and record, on a monthly basis, the 

monthly and rolling12-month VOC emissions from the Off-Spec Brine Tanks. 

e. Except for periods when a tank is out of service, BPP shall 

maintain in each Off-Spec Brine Tank a level sufficient to assure that the floating 

roof remains in contact with the liquid in the tank. 

74. Coker Feed Tank (TK-6254): 

a. The Coker Feed Tank (TK-6254) shall be equipped with a fixed 

roof, shall be nitrogen blanketed and shall be vented to an iron sponge control 

system except during periods when the iron sponge is offline for maintenance. 

b. Emissions of H2S from the TK-6254 shall not exceed 2.84 tons per 

rolling 12-month period. Emissions during periods when the iron sponge is 

offline for maintenance shall be included in determining compliance with this 

emission limit. 

c. BPP shall monitor and record the daily average H2S concentration 

at the outlet of the iron sponge system and shall determine the daily average vapor 

flow based on the nitrogen purge rate to TK-6254. The H2S concentration and 

nitrogen purge flow will be used to calculate the H2S emissions rate. Process 

analyzers calibrated in accordance with the manufacturer’s recommendations, 

may be used for this purpose. 

d. Emissions of VOC from the TK-6254 shall not exceed 10.0 tons 

per rolling 12-month period. On a monthly basis, BPP shall (a) monitor the VOC 

concentration at the outlet of the iron sponge system in accordance with the 

methods used to comply with the requirements for breakthrough monitoring for 

carbon canisters in Paragraph 52.a.ii and Paragraph 52.b.ii of Section J of this 

Consent Decree, and (b) record the results of such monitoring.. BPP shall verify 

and record that flow is present when the VOC concentration is measured at the 

tank vent. BPP shall determine the monthly average vapor flow based on the 

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nitrogen purge rate to TK-6254. The VOC concentration and nitrogen purge flow 

will be used to calculate the VOC emissions rate. 

75. FLIR Monitoring: Annually, BPP shall use an Optical Gas Imaging 

Camera to video image and record emissions from the tank roof and related vent systems 

on the Stormwater Equalization Tank (TK-5052), the brine treatment tanks (TK-101, TK102, TK-103, TK-104), Off-Spec Brine Tanks (TK-3559, TK-3560), and the Coker Feed 

Tank (TK-6254). If imaging indicates emissions inconsistent with well maintained 

floating roof tanks, seals, fittings, or welds, BPP shall inspect and, if necessary, repair the 

leaks consistent with the underlying Federal, State or local regulations applicable to the 

tank(s). BPP will report the results of these inspections and any corrective actions 

required during the next semi-annual Part VIII report. 

76. The provisions in this Section will take effect upon startup of each tank 

or the Date of Entry, whichever is later. 

N. VOC, PM, TRS, and H2S Emission Reductions from the Whiting Refinery 

New Coker 

Summary: BPP will limit VOC, PM, TRS and H2S emissions by depressuring the Coke 

Drum to no more than 2.0 psig prior to venting, by controlling the quality of the makeup 

water added to the Quench Water System, by requiring a minimum total Quench Water 

volume subject to a high level trip and a minimum Quench Water Soak Time and by 

designing the Coke Pit so as to minimize fugitive dust from the coke. The requirements 

in this Section to control particulate emissions at the Coke Pit are in addition to the coke 

handling requirements contained in the Whiting Refinery’s permit, including an enclosed 

and wetted coke conveyance system, enclosed coke storage buildings, and other measures 

to control fugitive PM. 

77. Control of VOC, PMTOTAL, PM10, TRS, and H2S Emissions from the 

Whiting New Coker. Upon initial startup of the New Coker, BPP shall not commence 

Coke Drum Venting until the Coke Drum Overhead Pressure is 2.0 psig or less. 

78. New Coker Coke Drum Operating Parameter Limits. Upon initial 

startup of the New Coker, BPP shall comply with the following operating limits: 

a. Total Quench Water added to a coke drum shall be at least 260,000 

gallons per cycle or until the water reaches the high level trip in the Coke drum, 

whichever is less; and 

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b. Quench Water Soak Time shall be at least 45 minutes per cycle. 

79. Control of VOC, TRS, and H2S Emissions from the Whiting New 

Coker Quench Water System. Commencing upon the initial startup of the New Coker, 

for all components and pieces of equipment within the Quench Water System other than 

the Coke Pit, the Maze (coke fines settling basin), clean water sump and Quench Water 

Tank, BPP shall maintain a hard-piped system that has no emissions points to the 

atmosphere. 

80. Quench Water Operating Practices. 

a. Commencing upon the initial startup of the New Coker, BPP shall 

use only the following for the New Coker Quench Water Make-Up: 

i. Water that is fresh (i.e., water brought into the Whiting 

Refinery that has not been in contact with process water or process 

wastewater); 

ii. Non-contact cooling water blowdown; 

iii. Water that has been stripped in a sour water stripper; 

iv. Water from other refinery sources where the water has a 

TOC concentration of less than 745 ppm and a total sulfide concentration 

of less than 35 ppm; or 

v. Some combination of water from i-iv. 

b. Commencing upon the initial startup of the New Coker, BPP shall 

not feed or dispose of any materials with a TOC concentration of 745 ppm or 

greater into any New Coker Coke Drum during the quench cycle. 

81. Control of Particulate Emissions from the Coke Pit. By no later than 

the date of initial startup of the New Coker, BPP shall construct a Coke Pit with walls on 

all four sides that are at least forty feet (40’) above the floor of the Coke Pit. 

O. Emission Reductions from Flares and Control of Flaring Events 

82. BPP shall implement and comply with the requirements to control and 

minimize emissions from the flaring devices at the Whiting Refinery set forth in 

Appendix D to this Consent Decree. 

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P. Incorporation of Consent Decree Requirements into Federally Enforceable 

Permits 

83. Permits. Where any compliance obligation under the Consent Decree 

requires BPP to obtain a federal, state, or local permit or approval, including any 

preconstruction, construction, or operating permits, BPP shall submit timely and 

complete applications and take all other actions necessary to obtain all such permits or 

approvals. 

a. By no later than the Date of Lodging, BPP shall submit all 

necessary applications and information to IDEM for a permit modification to the 

WRMP Operating Permit to incorporate the emission limits and standards 

contained in Part V of this Consent Decree that address EPA’s October 16, 2009 

Title V Order. 

b. BPP shall thereafter timely submit all necessary applications and 

information to IDEM for a CAA Title I source modification permit for the 

Whiting Refinery. The application(s) shall seek to obtain all required, federally 

enforceable permits for the construction of the pollution control technology and/or 

the installation of equipment necessary to implement the requirements of this 

Consent Decree. The application(s) shall also seek to incorporate all emissions 

limits and standards required by the following requirements of this Consent 

Decree that will survive termination of the Consent Decree: 

i. Paragraphs 11, 12.b.i-ii and 13 in Part V, Section A (FCCU 

NOx limits); 

ii. Paragraphs 14, 15.b.i-ii and 16 in Part V, Section B (FCCU 

SO2 limits); 

iii. Paragraphs 17, 18, 19, 20 and 21 in Part V, Section C 

(FCCU PM limits); 

iv. Paragraphs 23, 24, 25, 26 and 27 in Part V, Section D 

(FCCU CO limits); 

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v. Paragraphs 28, 29 and 30 in Part V, Section E (FCCU VOC 

limits); 

vi. Paragraphs 31.b, 32, 33.a-b, 34, 35 and 36 in Part V, 

Section F (NOx Heater and Boiler limits); 

vii. Paragraphs 39.a and 40 in Part V, Section G (SO2 Heater 

and Boiler limits); 

viii. Paragraph 41 in Part V, Section H (Fuel Gas Sulfur limits); 

ix. Paragraphs 65, 66 and 69 in Part V, Section L (Sulfur 

Recovery Plant and Sulfur Pit); 

x. Paragraphs 71, 72, 73 and 74 in Part V, Section M 

(Requirements for Certain Tanks); 

xi. Paragraphs 77, 78, 79, 80 and 81 in Part V, Section N 

(Whiting Refinery New Coker); 

xii. Paragraphs 6-13, 15-17, 25-32, 33.b, 34-37, 41-42, 44-46, 

48.d-e, 51, 67.c-d, and 69-70 of Appendix D (Flares and Control of 

Flaring Events); and 

xiii. All of Part VI (Emission Credit Generation). 

c. The Parties agree that the incorporation of emission limits and 

standards into the Title V operating permit for the Whiting Refinery as required 

by Paragraphs 83.a and 83.b shall be in accordance with the applicable rules for 

Indiana’s consolidated Title V construction and operating permit program. 

d. BPP may seek relief under the provisions of Part IX of this 

Consent Decree (“Force Majeure”) for any delay in the performance of any such 

obligation resulting from a failure to obtain, or a delay in obtaining, any permit or 

approval required to fulfill such obligation, if BPP has submitted timely and 

complete applications and has taken all other actions necessary to obtain all such 

permits or approvals. 

VI. EMISSION CREDIT GENERATION 

Summary: This Part addresses the use of certain emissions required by the 2001 Consent 

Decree and all emissions reductions required by this Consent Decree for the purpose of 

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emissions netting or emissions offsets in any permitting action at the Whiting Refinery 

initiated after the Date of Entry. 

84. Prohibitions on Emission Credits. 

a. General Prohibition. BPP shall not generate or use any NOx, SO2, 

H2S, TRS, reduced sulfur compounds, PM, PM2.5, PM10, PMTOTAL, VOC, or CO 

emissions reductions (“CD Emission Reductions”), or apply for and obtain any 

emission reduction credits, that result from any projects conducted or controls 

utilized pursuant to this Consent Decree as netting reductions or emissions offsets 

in any PSD, major non-attainment, and/or minor New Source Review permit or 

permit proceeding. 

b. Specific Prohibition on Reductions under 2001 Consent Decree. 

BPP shall not generate or use any NOx emission reductions, or apply for and 

obtain any NOx emission reduction credits, that are achieved as a result of the 

following projects required by the 2001 Consent Decree as netting reductions or 

emissions offsets in any PSD, major nonattainment, and/or minor New Source 

Review permit or permit proceeding: 

3 Stanolind Power Station 

Boilers 31, 32, 33, 34 and 36 

Installation of 

SCRs 

Completed December 31, 

2010 

1 Stanolind Power Station 

Boilers 13, 14, 16 and 17 

Shutdown Completed April 1, 2010 

85. Exception to Prohibitions on Emission Credits. Notwithstanding 

the prohibitions set forth in Paragraph 84, BPP may use 8 tons per year (tpy) of 

VOC, 26 tpy of NOx, 6 tpy of PM10, and 18 tpy of CO from emissions reductions 

required by this Consent Decree or the 2001 Consent Decree as credits or offsets 

in any PSD, major non-attainment and/or minor NSR permit or permit proceeding 

occurring after the Date of Lodging of the Consent Decree at the Whiting 

Refinery; provided that the new, modified or affected emissions units for which 

credits are being used: (1) is being constructed, modified or affected for purposes 

of compliance with Tier III Vehicle Emission and Fuel Standards; and (2) has a 

federally enforceable, non-Title V Permit (i.e, a permit issued pursuant to the 

State of Indiana’s consolidated Title V construction and operating permit 

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program) that reflects the following requirements that are applicable to the 

pollutants for which credits are being used: 

a. For heaters and boilers, a limit of 0.027 lbs. NOx per million BTU 

on a 3-hour rolling average basis; 

b. For heaters and boilers, a limit of 0.10 grains of H2S per dry 

standard cubic foot of fuel gas or 20 ppmvd SO2 corrected to 0% O2 both on a 3­

hour rolling average basis; 

c. For heaters and boilers, no liquid or solid fuel firing authorization; 

d. For FCCUs, a limit of 20 ppmvd NOx corrected to 0% O2 on a 

365-day rolling average basis; 

e. For FCCUs, a limit of 25 ppmvd SO2 corrected to 0% O2 on a 365­

day rolling average basis; 

f. For FCCUs, a limit of 0.5 pounds of PM per 1,000 pounds of coke 

burned on a 3-hour average basis; and 

g. For SRPs, a limit of 100 ppmvd SO2 at 0% O2 on a 24-hour rolling 

average basis. 

86. Conditions Precedent to Utilizing Exception to General Prohibition. 

Utilization of the exception set forth in Paragraph 85 to the general prohibition against 

the generation or utilization of CD Emissions Reductions set forth in Paragraph 84 is 

subject to the following conditions: 

a. Under no circumstances shall BPP use CD Emissions Reductions 

for netting and/or offsets prior to the time that actual CD Emissions Reductions 

have occurred; 

b. CD Emissions Reductions may be used only at the Whiting 

Refinery; 

c. The CD Emissions Reductions provisions of this Consent Decree 

are for purposes of this Consent Decree only and neither BPP nor any other entity 

may use CD Emissions Reductions for any purpose, including in any subsequent 

permitting or enforcement proceeding, except as provided herein; and 

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d. BPP still shall be subject to all federal, state and local regulations 

applicable to the PSD, major non-attainment and/or minor NSR permitting 

process. 

87. Outside the Scope of the General Prohibition. Nothing in this Part is 

intended to prohibit BPP from seeking to, or IDEM from denying BPP’s request to: 

a. Utilize or generate emissions credits from refinery units that are 

covered by this Consent Decree to the extent that the proposed credits or 

reductions represent the difference between the emissions limitations set forth in 

or required by this Consent Decree for these refinery units and the more stringent 

emissions limitations that BPP may elect to accept for these refinery units in a 

permitting process; or 

b. Utilize or generate emissions credits or reductions on refinery units 

that are not subject to an emission limitation pursuant to this Consent Decree; or 

c. Utilize emissions reductions pursuant to this Consent Decree for 

the Whiting Refinery’s compliance with any rules or regulations designed to 

address regional haze or the non-attainment status of any area (excluding PSD and 

Non-Attainment New Source Review Rules, but including, for example, RACT 

rules) that apply to the Whiting Refinery. Notwithstanding the preceding 

sentence, BPP will not trade or sell any emissions reductions that result from any 

projects conducted or controls utilized pursuant to this Consent Decree. 

VII. SUPPLEMENTAL ENVIRONMENTAL PROJECT AND ADDITIONAL 

INJUNCTIVE RELIEF
 

A. Supplemental Environmental Project 

88. BPP shall implement as a Supplemental Environmental Project (“SEP”) 

a project to install monitors at the fenceline or perimeter of the Whiting Refinery to 

monitor certain emissions and make the data publicly available (“Fenceline Monitoring 

SEP”), as provided in Appendix E of this Consent Decree. BPP shall spend not less than 

$2 million to implement the Fenceline Monitoring SEP, the installation and 

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commencement of operation of which shall be completed by no later than 18 months after 

the Date of Entry. 

89. BPP is responsible for the satisfactory completion of the Fenceline 

Monitoring SEP as provided in this Consent Decree. BPP may use contractors or 

consultants in planning and implementing the SEP. 

a. If BPP does not expend the entire amount specified in Paragraph 

88, BPP shall pay a stipulated penalty equal to the difference between the amount 

expended as demonstrated in the certified cost report and the amount specified in 

Paragraph 88. The stipulated penalty shall be paid as provided in Part X 

(“Stipulated Penalties”) of this Consent Decree. 

b. As an alternative to payment of such stipulated penalty, BPP may 

request approval from EPA to use unexpended SEP funds for an alternative SEP. 

90. With regard to the Fenceline Monitoring SEP, BPP certifies the truth 

and accuracy of each of the following: 

a. that all cost information provided to EPA in connection with the 

Fenceline Monitoring SEP is complete and accurate; 

b. that, as of the date of executing this Consent Decree, BPP is not 

required to perform or develop the SEP by any federal, state, or local law or 

regulation and is not required to perform or develop the SEP by agreement, grant, 

or as injunctive relief awarded in any other action in any forum; 

c. that the SEP is not a project that BPP was planning or intending to 

construct, perform, or implement other than in settlement of the claims resolved in 

this Consent Decree; 

d. that BPP has not received and will not receive credit for the SEP in 

any other enforcement action; 

e. that BPP will not receive any reimbursement for any portion of the 

SEP from any other person; 

f. that BPP is not a party to any Open Federal Financial Assistance 

Transaction that is or could be used to fund the same activity as the SEP described 

in Appendix E; and 

g. that based upon a reasonable inquiry: 

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i. the activity covered by this SEP has not been described in 

an unsuccessful Federal Financial Assistance Transaction proposal 

submitted by BPP to EPA within two years of the date of executing this 

Consent Decree (unless the project was barred from funding as statutorily 

ineligible); and 

ii. BPP is not aware of any open Federal Financial Assistance 

Transaction that is funding or could fund the same activity as the SEP 

described in Appendix E. 

91. BPP shall include in each report required by Paragraph 98.c of Part 

VIII (“Reporting and Recordkeeping”) a description of its progress toward implementing 

the SEP required by this Section. In addition, the report required by Paragraph 98.c. for 

the period in which the SEP is completed shall contain the following information with 

respect to the SEP (“SEP Completion Report”): 

a. a detailed description of the SEP as implemented; 

b. a description of any problems encountered in completing the SEP 

and the solutions thereto; 

c. an itemized list of all eligible SEP costs expended; 

d. certification that the SEP has been fully implemented pursuant to 

the provisions of this Decree; and 

e. a description of the environmental and public health benefits 

resulting from implementation of the SEP (with a quantification of the benefits 

and pollutant reductions, if feasible). 

EPA may require information in addition to that described in this Paragraph, in order to 

evaluate BPP’s SEP Completion Report. 

92. Disputes concerning the satisfactory performance of this SEP and the 

amount of eligible SEP costs may be resolved under Part XIV of this Decree (“Dispute 

Resolution”). No other disputes arising under this Section shall be subject to Dispute 

Resolution. 

93. BPP agrees that it must clearly indicate that the Fenceline Monitoring 

SEP is being or has been undertaken as part of the settlement of an action to enforce the 

Clean Air Act and corollary state statutes in any public statements regarding the project. 

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94. For federal income tax purposes, BPP agrees that it will neither 

capitalize into inventory or basis nor deduct any costs or expenditures incurred in 

performing the SEP. 

B. Additional Injunctive Relief 

95. Energy Efficiency and Greenhouse Gas (“GHG”) Improvements. 

a. Study: BPP certifies that it has retained KBC Advanced 

Technologies, Inc. (“KBC”) to conduct an energy study for the Whiting Refinery 

consistent with the “KBC Whiting Energy Study Scope” description provided to 

Citizen-Intervenors on June 10, 2010. By no later than three (3) months after the 

Date of Entry of the Consent Decree, BPP shall provide Citizen-Intervenors a 

report on the results of that study. This report shall include: 

i. A facility-wide assessment of fuel, steam, power, and other 

utility consumption; 

ii. A comprehensive evaluation of potential opportunities to 

reduce fossil fuel usage, including solar-assisted boilers, flameless 

oxidation heater and boiler technology and other energy efficiency 

technologies and practices as may be identified by BPP or KBC; 

iii. An estimate of GHG emissions from all units identified in 

the KBC Whiting Energy Study Scope, including all associated heaters, 

boilers, and flares; and 

iv. A complete list of the potential GHG reduction projects 

identified by the KBC Whiting Energy Study Scope including: 

(1) A tabulation of the estimated cost of each project; 

(2) Potential savings in fuel, steam, power, and other 

utilities; 

(3) Estimated GHG reductions of each project; and 

(4) Estimated payback (if any). 

b. Confidential Business Information (“CBI”). CBI may be redacted 

from the report. The following classes of information shall not be defined as CBI: 

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i. The data and the calculation methodologies used to 

estimate GHG emissions and potential reductions; 

ii. The costs and payback period of potential GHG projects 

and the underlying assumptions used to determine costs and benefits; 

iii. The estimated savings in fuel, steam, power, or other 

utilities of potential GHG projects; and 

iv. The projects selected by BPP to satisfy its commitments 

under this Section. 

c. Project Selection Report. By no later than six (6) months after the 

Date of Entry of the Consent Decree, BPP shall submit a report to CitizenIntervenors identifying each of the GHG projects that BPP plans to undertake and 

the anticipated timeline for completion of each project. The projects BPP 

identifies shall have an estimated cost of at least $9.5 million, and shall not 

include expenditures on audits, studies, or recommendations required under 

Paragraph 95.a. BPP will use good faith efforts to select projects that maximize 

the potential for GHG reductions, taking into account cost effectiveness, safety, 

operability and relevant permitting requirements. 

d. Limitations. No improvements otherwise required by this Consent 

Decree, state, or federal regulation shall constitute a qualifying energy efficiency 

or GHG improvement for the purposes of this Paragraph. 

e. Timeline. By no later than five (5) years after the Date of Entry of 

the Consent Decree, BPP shall: 

i. Spend no less than $9.5 million to complete the GHG 

reduction projects identified in subparagraph b of this Paragraph; and 

ii. Provide Citizen-Intervenors with a report documenting: 

(1) The GHG projects chosen; 

(2) The cost of the projects chosen; 

(3) Reductions in GHG emissions achieved by each 

project; and 

(4) The savings in fuel, steam, power, or utilities 

related to the GHG reduction projects. 

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f. Permits. BPP shall comply with all applicable Federal, state, and 

local permitting requirements for such projects. 

96. BPP shall provide copies of any reports or other submissions required 

by Paragraph 95 to EPA. 

VIII. REPORTING AND RECORDKEEPING 

97. BPP shall retain all records required to be maintained in accordance 

with this Consent Decree for a period of five (5) years or until Termination, whichever is 

longer, unless applicable regulations require the records to be maintained longer. 

98. On or before February 15 and August 15 each year, BPP shall submit to 

EPA and IDEM a semi-annual report as provided in this Part. Each semi-annual report 

shall contain the following information for the previous six month period (i.e., January to 

June to be addressed in the report to be submitted by August 15, and July to December to 

be addressed in the report submitted by February 15): 

a. For the period covered by the report, a summary of the emissions 

data for the Whiting Refinery that is specifically required by the reporting 

requirements of the Consent Decree for the period covered by the report; 

b. A description of any problems that have occurred or are anticipated 

with respect to meeting the requirements of this Consent Decree at the Whiting 

Refinery; 

c. A description of the Supplemental Environmental Project and 

implementation activity in accordance with this Consent Decree; 

d. The information specified in Paragraph 72 of Appendix D 

(“Monitoring Instrument/Equipment Downtime; Override of ACS; and Emissions 

Exceedances”); 

e. Any additional matters as BPP believes should be brought to the 

attention of EPA and IDEM; and 

f. Any additional items required by any other Paragraph of this 

Consent Decree to be submitted with a semi-annual report. 

99. Emissions Data. In the semi-annual report required by this Part VIII of 

the Consent Decree to be submitted by August 15 of each calendar year, BPP shall 

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provide a summary of annual emissions data for the Whiting Refinery for the prior 

calendar year, to include: 

a. NOx emissions in tons per year for each heater and boiler greater 

than 40 mmBTU/hr maximum fired duty; 

b. NOx emissions in tons per year as a sum for all heaters and boilers 

less than 40 mmBTU/hr maximum fired duty; 

c. SO2, CO and PM emissions in tons per year as a sum for all heaters 

and boilers; 

d. SO2 emissions from the Sulfur Recovery Plant in tons per year; 

e. SO2 emissions from all Acid Gas Flaring and Tail Gas Incidents by 

flare in tons per year; 

f. NOx, SO2, PM and CO emissions in tons per year as a sum for all 

other emissions units for which emissions information is required to be included 

in the facilities’ annual emissions summaries and that are not identified above; 

and 

g. NOx, SO2, CO and PM emissions in tons per year for each FCCU; 

and 

h. Emissions from Covered Flares and the LPG Flare as specified in 

Paragraph 73 of Appendix D. 

i. For each of the estimates or calculations in Subparagraphs 99.a 

through 99.h above, the basis for the emissions estimate or calculation (i.e., stack 

tests, CEMS, emission factor, etc.). 

To the extent that the required emissions summary data are available in other reports 

generated by BPP, such other reports can be attached or the appropriate information can 

be extracted from such other reports and attached to the report to satisfy the requirement. 

100. Exceedances of Emission Limits and CEMS Downtime: In each semiannual report required by Part VIII of the Consent Decree, BPP will provide a summary 

of all exceedances of emission limits required or established by this Consent Decree, 

which will include the following: 

a. For operating unit emissions limits that are required by this 

Consent Decree and monitored with CEMS, for each CEMS: 

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i. Total period when the emissions limit was exceeded, if 

applicable, expressed as a percentage of operating time for each calendar 

quarter; 

ii. Where the operating unit has exceeded the emissions limit 

more than 1% of the total time of the calendar quarter, identification of 

each averaging period that exceeded the limit by time and date, the actual 

emissions of that averaging period (in the units of the limit), and any 

identified cause for the exceedance (including Startup, Shutdown, 

maintenance or Malfunction), and, if it was a malfunction, an explanation 

and any corrective actions taken; 

iii. Total downtime of the CEMS, if applicable, expressed as a 

percentage of operating time for the calendar quarter; 

iv. Where the CEMS downtime is greater than 5% of the total 

time in a calendar quarter for a unit, identify the periods of downtime by 

time and date, any cause of the downtime (including maintenance or 

malfunction), and, if it was a malfunction, an explanation and any 

corrective action taken. 

v. If a report filed pursuant to another applicable legal 

requirement contains all of the information required by Paragraph 100.a.iiv above in similar or the same format, the requirements of Paragraph 

100.a.i-iv above may be satisfied by attaching a copy of such report. 

b. For any exceedance of an emissions limit required by this Consent 

Decree from an operating unit monitored through stack testing: 

i. A summary of the results of the stack test in which the 

exceedance occurred; and 

ii. A copy of the full stack test report in which the exceedance 

occurred. 

iii. To the extent that a refinery has already submitted the stack 

test results to the EPA and IDEM, BPP need not resubmit them, but may 

instead reference the submission in the report (e.g., date, addressee, reason 

for submission). 

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101. FCCU Reporting and Recordkeeping Requirements. 

a. BPP shall include in each semi-annual report required by this Part 

VIII the results of all testing of FCU 500 and FCU 600 required by Paragraph 21 

(“FCCU Performance Testing”). The performance test reports shall include all 

relevant testing data and information, including, but not limited to the following: 

PM, PM10, PM TOTAL, SO2 concentration, NOx concentration, catalyst additive 

rates, ammonia addition prior to ESP, ammonia addition at the SCR, ammonia 

slip, the average total power and secondary current to the entire ESP system, the 

coke burn-off rate, regenerator overhead temperature, and the FCCU feed rate. 

b. BPP shall include in each semi-annual report copies of all 

applicable reports required by 40 C.F.R. § 60.108a for the previous 6-month 

period. 

c. Concurrent with submission to EPA, BPP shall submit copies to 

Citizen-Intervenors of all reports of emissions testing required by this Paragraph. 

BPP may redact from the reports submitted to Citizen-Intervenors any 

information meeting the requirements for Confidential Business Information 

(“CBI”) pursuant to 40 C.F.R. Part 2, Subpart B, except that the data (including 

the operating parameters identified in Paragraph 21.a) and the calculation 

methodologies used to estimate emissions shall not be redacted as CBI. 

102. Each report will be certified for BPP by an officer of BPP responsible 

for overseeing implementation of this Consent Decree, as follows: 

“I certify under penalty of law that this information was prepared 

under my direction or supervision by personnel qualified to properly 

gather and evaluate the information submitted. Based on my directions 

and after reasonable inquiry of the person(s) directly responsible for 

gathering the information, the information submitted is, to the best of my 

knowledge and belief, true, accurate and complete.” 

IX. CIVIL PENALTY 

103. Within 30 Days after the Date of Entry of this Consent Decree, BPP 

shall pay the sum of $7,200,000 as a civil penalty to the United States and the sum of 

$800,000 as a civil penalty to the State of Indiana in accordance with the following: 

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a. Payment to the United States. BPP shall pay the civil penalty due 

by FedWire Electronic Funds Transfer (“EFT”) to the U.S. Department of Justice 

in accordance with written instructions to be provided to Defendant, following 

entry of the Consent Decree, by the Financial Litigation Unit of the U.S. 

Attorney’s Office for the Northern District of Indiana, 5400 Federal Plaza, Suite 

1500, Hammond, In. 46320. At the time of payment, BPP shall send a copy of 

the EFT authorization form and the EFT transaction record, together with a 

transmittal letter, which shall state that the payment is for the civil penalty owed 

pursuant to the Consent Decree in United States, et al. v. BP Products North 

America Inc., and shall reference the civil action number and DOJ case number 

90-5-2-1-09244, to the United States in accordance with Part XIV of this Decree 

(“Notices”); by email to acctsreceivable.CINWD@epa.gov; and by mail to: 

EPA Cincinnati Finance Office 

26 Martin Luther King Drive 

Cincinnati, Ohio 45268 

b. Payment to the State of Indiana. Payment to Indiana shall be made 

by certified check or checks or cashier’s checks made payable to ““Environmental 

Management Special Fund” referencing the name and address of the party making 

payment, and the civil action number. BPP shall send the check(s) to: 

Indiana Department of Environmental Management 

Cashier - MC 50-10C 

100 North Senate Avenue 

Indianapolis, IN 46204-2251 

104. The civil penalty set forth herein, as well as any stipulated penalty 

incurred pursuant to Part X (“Stipulated Penalties”), is a penalty within the meaning of 

Section 162(f) of the Internal Revenue Code, 26 U.S.C. § 162(f), and, therefore, BPP will 

not treat such penalty payment as tax deductible for purposes of federal or state law. 

105. Upon the Date of Entry, this Consent Decree will constitute an 

enforceable judgment for purposes of post-judgment collection in accordance with Rule 

69 of the Federal Rules of Civil Procedure, the Federal Debt Collection Procedures Act, 

28 U.S.C. § 3001, et seq., and other applicable federal authority. The United States will 

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be deemed a judgment creditor for purposes of collecting any unpaid amounts of the 

penalty and interest pursuant to this Part, or any stipulated penalty owed pursuant to Part 

X (“Stipulated Penalties”). 

X. STIPULATED PENALTIES 

106. Stipulated penalties shall be paid to the United States and to Indiana as 

provided herein for each failure by BPP to comply with the terms of this Consent Decree. 

In no event shall any stipulated penalty assessed exceed $37,500 per day for any 

individual violation of this Consent Decree. Stipulated penalties shall be calculated in the 

amounts specified in this Part X. For those provisions where a stipulated penalty of 

either a fixed amount or 1.2 times the economic benefit of delayed compliance is 

available, the decision of which alternative to seek shall rest exclusively within the 

discretion of the United States. 

A. Requirements for NOx Emissions Reductions from FCCUs 

107. For failure to meet any emissions limit for NOx set forth in Paragraph 

12, per day, per unit: $2500 for each calendar day on which the specified 7-day or 365­

day rolling average exceeds the applicable limit. 

108. For failure to install, certify, calibrate, maintain, and/or operate a NOx 

CEMS as required by Paragraph 13, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $500 

31st through 60th day after deadline $1000 

Beyond 60th

 day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

B. Requirements for SO2 Emissions Reductions from FCCUs. 

109. For each failure to meet any SO2 emission limit set forth in Paragraph 

15, per unit, per day: $3000 for each calendar day on which the specified 7-day or 365­

day average exceeds the applicable limit. 

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110. For failure to install, certify, calibrate, maintain, and/or operate a SO2 

CEMS as required by Paragraph 16, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $500 

31st through 60th day after deadline $1000 

Beyond 60th

 day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

C. Requirements for Particulate Matter Emissions Reductions from FCCUs 

111. For failure to conduct PM testing, as required by Paragraphs 17 and 21, 

per day, per test, per FCCU: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $200 

31st through 60th day after deadline $500 

Beyond 60th

 day after deadline $1000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

112. For each failure to meet any applicable PM emission limit for FCCUs 

as set forth in Paragraph 18, per day, per unit: $750 for each calendar day on which the 

emission limit is exceeded. 

113. For each failure to monitor and/or record any supplemental monitoring 

as set forth in Paragraph 19: $250 per day. 

D. Requirements for CO Emissions Reductions from FCCUs 

114. For each failure to meet the applicable CO emission limits for FCCUs 

as set forth in Paragraphs 24-25: $2500 for each calendar day on which the specified 1­

hour rolling average exceeds the applicable limit. 

115. For failure to install, certify, calibrate, maintain, and/or operate a CO 

CEMS as required by Paragraph 27, per unit, per day: 

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Period of Delay or Non-Compliance	 Penalty per Day 

1st

 through 30th day after deadline $500 

31st

 through 60th day after deadline $1000 

Beyond 60th day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

E. Requirements for VOC Emissions Reductions from FCCUs 

116. For each failure to meet the applicable VOC emission limits for FCCUs 

as set forth in Paragraphs 28-29: $750 for each calendar day on which the applicable limit 

is exceeded. 

117. For failure to conduct VOC stack testing, as required by Paragraph 30, 

per day, per test, per FCCU: 

Period of Delay or Non-Compliance	 Penalty per Day 

1st

 through 30th day after deadline $200 

31st through 60th day after deadline $500 

Beyond 60th

 day after deadline $1000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

F. Requirements for NOx Emissions Reductions from Heaters and Boilers 

118. For failure to install required control technologies by the dates specified 

in Paragraph 31.b and 34.a: 

Period of Delay or Non-Compliance Penalty per Day
 

1st

 through 30th day after deadline $1500 

31st through 60th day after deadline $2000 

Beyond 60th

 day after deadline $3000 

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119. For failure to install, certify, calibrate, maintain, and/or operate a NOx 

CEMS as required by Paragraphs 32, 35.b and 36, per unit, per day: 

Period of Delay or Non-Compliance 

1st

 through 30th day after deadline 

31st

 through 60th day after deadline 

Beyond 60th day after deadline 

Penalty per Day 

$500 

$1000 

$2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

120. For failure to comply with an applicable emission limit at a heater or 

boiler listed in Paragraphs 31.b and 34.a, or failure to comply with the NSPS Subparts A 

and Ja emission limits at a heater or boiler as specified in Paragraph 33, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $500 

31st through 60th day after deadline $1000 

Beyond 60th day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

121. For failure to conduct NOx testing, as required by Paragraph 35.a, per 

day, per test, per unit: 

Period of Delay or Non-Compliance 

1st

 through 30th day after deadline 

31st through 60th day after deadline 

Beyond 60th

 day after deadline 

Penalty per Day 

$200 

$500 

$1000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

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G. Requirements for SO2 Emissions Reductions from Heaters and Boilers 

122. For failure to comply with an applicable emission limit or monitoring 

requirement of NSPS Subparts A and Ja at a heater or boiler as specified in Paragraph 39, 

per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $500 

31st

 through 60th day after deadline $1000 

Beyond 60th

 day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

123. For burning Fuel Oil in a manner inconsistent with the requirements of 

Paragraph 40, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1750 

Beyond 30th day after deadline $5000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

H. Requirements for Fuel Gas Sulfur Content 

124. For failure to install, certify, calibrate, maintain, and/or operate a Total 

Sulfur Continuous Analyzer as required by Paragraph 41, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $500 

31st

 through 60th day after deadline $1000 

Beyond 60th day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

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125. For failure to comply with total sulfur emission limit as specified in 

Paragraph 41, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $500 

31st

 through 60th day after deadline $1000 

Beyond 60th day after deadline $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

I. Requirements for CEM Downtime Minimization, O&M and Corrective Action 

126. For failure to develop and/or submit the CEMS O&M Plan required by 

Paragraph 43, and for failure to include CEMS Testing and Calibration requirements in 

the CEMS O&M Plan as required by Paragraph 45: 

Period of Delay or Non-Compliance Penalty per Day
 

1st through 30th day after deadline $200 

31st

 through 60th day after deadline $500 

Beyond 60th day after deadline $1000 

127. For failure to develop or implement the CEMS O&M training programs 

specified in Paragraph 44: $10,000. 

128. For failure to develop or implement a Preventive Maintenance and 

Repair, and QA/QC program as specified in Paragraph 46: 

Period of Delay or Non-Compliance Penalty per Day
 

1st

 through 30th day after deadline $500 

31st through 60th day after deadline $1500 

Beyond 60th

 day after deadline $2000 

129. For failure to conduct a CEMS Root Cause Failure Analysis required 

by Paragraph 48: $5,000 per month, per analysis. 

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130. For failure to implement any actions necessary to correct noncompliance as required by Paragraph 49: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1250 

31st

 through 60th day after deadline $3000 

Beyond 60th day after deadline $5000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

J. Requirements for Benzene Waste NESHAP 

131. For failure to comply with the 6 BQ Option required by Paragraph 50.a 

and 50.b: $30,000 for each 0.6 Mg (10%) increment by which the 6 BQ Option 

uncontrolled benzene limit is exceeded, up to $1.5 million per year that the limit is 

exceeded. 

132. For failure to comply with the Organic Benzene Waste control 

requirements of Paragraph 50.c: $12,500 per month per uncontrolled waste management 

unit. 

133. For failure to install and/or operate carbon canisters as required by 

Paragraph 52: $1,000 per day, per carbon canister. 

134. For failure to establish an annual review program to identify new 

benzene waste streams as required by Paragraph 53: $2,500 per month. 

135. For failure to perform laboratory audits as required by Paragraph 54: 

$5,000 per month, per audit. 

136. For failure to implement the training requirements as set forth in 

Paragraph 56: $10,000 per quarter. 

137. For failure to maintain or submit any plan, report or other deliverable 

required by Paragraphs 57, 58, 61 or 62: $5,000 per month. 

138. For failure to conduct monthly visual inspections of all water traps as 

required by Paragraph 60.a, and for failure to inspect each drain system as required by 

Paragraph 60.c: $500 per drain or drain system not inspected. 

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139. For failure to identify/mark segregated storm water drains as required 

in Paragraph 60.b: $1,000 per week, per drain. 

140. For failure to monitor conservation vents as required by Paragraph 

60.d: $500 per vent not monitored. 

141. If it is determined through federal, state, or local investigation that BPP 

has failed to include all benzene waste streams in its TAB calculation submitted pursuant 

to Section J., BPP shall pay the following, per waste stream: 

Waste Stream Penalty
 

For waste streams < 0.03 Mg/yr $250 

For waste streams between 0.03 and 0.1 Mg/yr $1000 

For waste streams between 0.1 and 0.5 Mg/yr $5000 

For waste streams > 0.5 Mg/yr $10,000 

142. For failure to complete construction of a new DAF unit by the date 

specified in Paragraph 60.g, or to route emissions from the DAF unit and API Separator 

as required by Paragraph 60.g: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1250 

31st through 60th day after deadline $3000 

Beyond 60th

 day after deadline $5000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

143. For failure to perform any requirement of a Root Cause Failure 

Analysis or Corrective Action required by Paragraph 62.a.iii: $2,500 per week, per 

requirement. 

K. Requirements for Leak Detection and Repair Program Enhancements 

144. The following stipulated penalties shall accrue per violation per day 

unless otherwise specified below, for each violation of a requirement of the ELP as set 

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forth in Part V, Section K of this Consent Decree (“Leak Detection and Repair”) and 

Appendix B (“Enhanced LDAR Program”) as specified below: 

a. Failure to timely develop and complete a written facility-wide 

LDAR Program Plan, or to timely update the LDAR Program Plan, as required by 

Paragraph 3: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 15th day after deadline $300 

16th

 through 30th day after deadline $400 

Beyond 30th

 day after deadline $500 

b. Failure to timely perform monitoring at the frequencies set forth in 

Paragraph 4 or 5: $100 per component per day, but no more than $25,000 per 

month. 

c. Failure to comply with Method 21 (or the AWP, as applicable) in 

performing LDAR monitoring, as indicated by the leak percentage ratio 

calculated under Paragraph 29.c. of the ELP (Appendix B), but only if the auditor 

identifies a leak rate of at least 0.5% per component type in the process unit: 

Comparative Monitoring Leak Ratio As Penalty per Process Unit 

Determined Under ¶29.c. of the ELP 

3.0 or greater but less than 4.0 $15,000 

4.0 or greater but less than 5.0 $30,000 

5.0 or greater but less than 6.0 $45,000 

6.0 or greater $60,000 

d. Failure to use a monitoring device that is attached to a data logger; 

failure, during each monitoring event, to directly electronically record the 

Screening Value, date, time, identification number of the monitoring equipment, 

or the identification of the technician, as required by Paragraph 6: $100 per 

failure per piece of Covered Equipment, but not greater than $5,000 per unit per 

month. 

e. Failure to transfer monitoring data to an electronic database on at 

least a weekly basis, as required by Paragraph 6: $150 per day for each day that 

the transfer is late. 

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f. Failure to timely perform a first attempt at repair, as required by 

Paragraph 11 or 12. For purposes of this subparagraph, the term “repair” includes 

the required repair verification monitoring in Paragraph 13 after the first repair 

attempt (in which case the stipulated penalties of Paragraph 144.h do not apply): 

$150 per day for each day after deadline, not to exceed $1500 per leak. 

g. Failure to timely perform a final attempt at repair, as required by 

Paragraph 12. For purposes of this subparagraph, the term “repair” includes the 

required repair verification monitoring in Paragraph 13 after the first repair 

attempt (in which case the stipulated penalties of Paragraph 144.h do not apply): 

Equipment Type Penalty per Day, Per Component Not to Exceed 

Valves, connectors $300 $37,500 

Pumps, agitators $1200 $150,000 

h. Failure to timely perform Repair Verification Monitoring, as 

required by Paragraph 13, where the first attempt to repair was made to within 5 

days and the final attempt to repair was made within 15 days: 

Equipment Type Penalty per Day, Per Component Not to Exceed 

Valves, connectors $150 $18,750 

Pumps, agitators $600 $75,000 

i. Failure to undertake drill-and-tap repairs, as required by Paragraph 

14: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 15th day after deadline $200 

16th

 through 30th day after deadline $350 

Beyond 30th

 day after deadline $500, not to exceed $37,500 

j. Failure to record the information required by Paragraph 15: $100 

per component, per item of missed information. 

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k. Improperly placing a piece of Covered Equipment on the DOR list 

(i.e., placing a piece of Covered Equipment on the DOR list even though it is 

feasible to repair without a process unit shutdown), as required by Paragraph 17: 

Equipment Type Penalty per Day, Per Component Not to Exceed 

Valves, connectors $300 $75,000 

Pumps, agitators $1200 $300,000 

l. Failure of the relevant manager or official to sign-off on placing a 

piece of Covered Equipment on the DOR list, as required by Paragraph 17.a: 

$250 per piece of Covered Equipment. 

m. Failure to comply with the 0.10% limit on valves that may be 

placed on the DOR list, as required by Paragraph 17.c: $5,000 per valve. 

n. Failure to install a Certified Low-Leaking Valve or to fit a valve 

with Certified Low-Leaking Valve Packing, as required by Paragraph 19: $1000 

per valve required by Paragraph 19.c and $5,000 per valve required by Paragraph 

19.d. 

o. Failure to add a piece of Covered Equipment to the LDAR 

program, as required by Paragraph 23: $300 per piece of Covered Equipment 

(plus an amount, if any, due under Paragraph 144.b for any missed monitoring for 

a component that should have been added to the LDAR program). 

p. Failure to remove a piece of Covered Equipment from the LDAR 

program, as required by Paragraph 23: $150 per piece of Covered Equipment. 

q. Failure to timely develop a training protocol, as required by 

Paragraph 24: $50 per day of noncompliance. 

r. Failure to perform initial, refresher, or new personnel training, as 

required by Paragraph 24: $1000 per person, per month of noncompliance. 

s. Failure of a monitoring technician to complete the certification 

required by Paragraph 25: $100 per failure, per technician. 

t. Failure to perform any of the requirements of Paragraph 26: $1000 

per missed requirement, per year. 

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u. Failure to conduct an LDAR audit in accordance with the schedule 

set forth in Paragraph 28: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 15th day after deadline $300 

16th through 30th day after deadline $400 

Beyond 30th

 day after deadline $500, not to exceed $100,000 

per audit 

v. Failure to use a third-party auditor, or to use a third-party auditor 

that is not experienced in LDAR audits, as required by Paragraph 28: $25,000 per 

audit. 

w. Failure to comply with the requirements in Paragraph 29 except for 

Paragraphs 29.a-c: $10,000 per missed requirement, not to exceed $100,000 per 

audit. 

x. Failure to comply with the requirements of Paragraphs 29.a-c: 

$50,000 per audit. 

y. Failure to timely develop and/or submit a Corrective Action Plan, 

as required by Paragraph 31: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 15th day after deadline $100 

16th through 30th day after deadline $250 

Beyond 30th

 day after deadline $500, not to exceed $100,000 

per audit 

z. Failure to implement corrective action within 90 days after the 

LDAR Audit Completion Date, or pursuant to the approved schedule, as required 

by Paragraph 31: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 15th day after deadline $500 

16th

 through 30th day after deadline $750 

Beyond 30th

 day after deadline $1000, not to exceed $200,000 

per audit 

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aa. Failure to timely submit a Certification of Compliance, as required 

by Paragraph 32: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 15th day after deadline $100 

16th through 30th day after deadline $250 

Beyond 30th

 day after deadline $500, not to exceed $100,000 

per audit 

bb. Failure to secure and retain documentation required pursuant to 

Paragraph 21: $1000 per valve or packing type. 

L. Requirements for Sulfur Recovery Plant and Sulfur Pits 

145. For failure to comply with the NSPS Subparts A and Ja emission limits 

for SRPs (as required by Paragraph 65) or sulfur pits (as required by Paragraph 69.a), or 

with the SRP emission limit (as required by Paragraph 66), or to control emissions from 

drums and tanks (as required by Paragraph 69.b), per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1000 

31st

 through 60th day after deadline $2000 

Beyond 60th day after deadline $3000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

146. For failure to operate and maintain control and monitoring equipment as 

required by Paragraph 69.a, per unit, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1000 

31st through 60th day after deadline $2000 

Beyond 60th

 day after deadline $3000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

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147. For failure to route all sulfur pit emissions in accordance with the 

requirements of Paragraph 69.c.i: 

Period of Delay or Non-Compliance

1st

 through 30th day after deadline 

31st through 60th day after deadline 

Beyond 60th

 day after deadline 

M. Requirements for Certain Tanks 

Penalty per Day 

$2000 

$3500 

$5000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

148. a. For failure to install or operate the control equipment in 

accordance with the requirements of Paragraphs 70 through 74, or to timely repair leaks 

identified through the Optical Gas Imaging Camera Monitoring as required by Paragraph 

75, per day, per unit: 

Period of Delay or Non-Compliance

1st

 through 30th day after deadline 

31st

 through 60th day after deadline 

Beyond 60th day after deadline 

Penalty per Day 

$500 

$1500 

$2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

b. For failure to conduct sampling or monitoring as required by 

Paragraphs 70 through 75: 

Daily sampling or monitoring: 

Monthly and Annual monitoring or 

sampling: 

$500 per missed sampling or 

monitoring event 

$1000 per missed sampling or 

monitoring event, plus $500 

for each additional day after 

deadline up until the next 

required monitoring event 

c. For failure to keep records as required by Paragraphs 70 through 

75: $500 per missing daily sampling or monitoring record; $1000 per missing 

monthly or annual sampling or monitoring record. 

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d. For failure to meet emission limits set forth in Paragraphs 73 and 

74: $5000 per month of violation. 

N. Requirements for VOC, PM, TRS, and H2S Emissions Reductions from the 

Whiting Refinery New Coker 

149. For failure to comply with the depressurization level for the coker (as 

specified by Paragraph 77), the coke drum parameters (as specified by Paragraph 78), the 

Quench Water System or Operating Practices (as specified by Paragraphs 79 and 80), or 

the coke pit requirements (as specified by Paragraph 81), per requirement, per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $1000 

31st

 through 60th day after deadline $2000 

Beyond 60th day after deadline $3000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever is 

greater 

O. Requirements for Flaring Devices 

150. The following stipulated penalties shall apply to violations of 

requirements set forth in Appendix D “(Emission Reductions From Flares and Flaring 

Devices”) as specified below: 

a. Violation of Paragraph 1.a or 1.b. Failure to timely install a 

system that complies with the requirements of Paragraph 1.a or failure to timely 

complete operator and supervisor training that conforms to the requirements of 

Paragraph 1.b: 

Period of Delay or Non-Compliance Penalty per Day 

(per Flare, for Paragraph 1.a) 

Days 1-30 $500 

Days 31-60 $1500 

Days 61 and later $2500 

b. Violation of Paragraph 1.c. For the time period between 90 days 

after Date of Entry and the compliance date in Paragraph 34.a, failure to minimize 

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the S/VG ratio to the extent practical with the existing monitoring and 

instrumentation: Penalty per Flare per day or fraction thereof: $1500. 

c. Violation of Paragraph 2 or 3. Failure to timely upgrade or 

replace, as necessary, Sweep and Purge Gas flow meters that conform to the 

requirements of Paragraph 2 or failure to timely implement the measures 

necessary to minimize Sweep and Purge Gas flow: 

Period of Delay or Non-Compliance Penalty per Day
 

(per meter, for Paragraph 2)
 

Days 1-30 $250 

Days 31-60 $500 

Days 61 and later $1250 

d. Violation of Survey Requirements of Paragraph 4. Failure to 

timely complete the Initial PRV Leak Survey required in Paragraph 4: 

Period of Delay or Non-Compliance Penalty per Day 

Days 1-30 $250 

Days 31-60 $500 

Days 61 and later $1250 

e. Violation of Repair Requirements of Paragraph 4. Failure to 

timely repair each leaking PRV: 

Period of Delay or Non-Compliance Penalty per Day 

Days 1-30 $500 

Days 31-60 $700 

Days 61 and later $1000 

f. (i) Violation of Paragraph 5. Failure to timely submit a report as 

required by Paragraph 5: 

Period of Delay or Non-Compliance Penalty per Day 

Days 1-30 $300 

Days 31-60 $400 

Days 61 and later $500 

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(ii) Violation of Paragraph 5. Failure to submit a report that 

conforms to the requirements of Paragraph 5: $50,000 per report. 

g. (i) Violation of Paragraphs 18, 19, or 20. Failure to timely submit 

a plan as required by those Paragraphs: 

Period of Delay or Non-Compliance Penalty per Day 

Days 1-30 $500 

Days 31-60 $750 

Days 61 and later $1000 

(ii) Violation of Paragraphs 18, 19, or 20. Failure to submit a plan 

that conforms to the requirements of those Paragraphs: Paragraph 18: 

$100,000 per plan; Paragraphs 19 and 20: $50,000 per plan. 

h. Violation of Paragraph 6, 7, 8, 9, 10, 11, 12, 13, 15, 16, or 42. 

Failure to timely install the equipment and monitoring systems required by 

Paragraphs 7-13 and 42 in accordance with the respective, applicable technical 

specifications in those Paragraphs, Paragraph 16, and Appendix FLR-11 (except 

for the requirements of Appendix FLR-11 found in Subparagraphs I.g, III.e, IV, 

V.B, and VI.a; those are QA/QC requirements covered in Subparagraph 150.i 

below): 

Period of Delay or Non-Compliance, Penalty per Day 

per monitoring system per monitoring system 

Days 1-30 $750 

Days 31-60 $1250 

Days 61 and later $2000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever 

is greater 

i. Violation of the QA/QC requirements in Appendix FLR-11. 

Failure to comply with the QA/QC requirements in Appendix FLR-11 at 

Paragraphs I.g, III.e, IV, V.B, or VI.a: 

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Violation of a: Penalty 

Daily requirement $100 

Quarterly requirement $200 per day late 

Annual requirement $500 per day late 

j. Violation of Paragraph 17. Except for 110 hours per calendar 

quarter, failure to operate the monitoring instrument in Paragraphs 7-9, 11-13, 

42.a. or 42.b: 

Per monitoring instrument, Number Penalty per Hour per monitoring 

of Hours per Calendar Quarter of instrument 

Downtime over 110 

0.25-50.0 $250 

50.25-100.0 $500 

Over 100.0 $1000 

k. Violation of Paragraph 23, 24, or 25.a. Failure to timely install, in 

accordance with Paragraph 23, a Flare Gas Recovery System that conforms to the 

requirements of Paragraph 24, or failure to timely equip, in accordance with 

Paragraph 25.a, automatic startup capability on each FGRS: 

Period of Delay or noncompliance, Penalty per Day per FGRS 

per FGRS 

Days 1-30 $1250 

Days 31-60 $3000 

Days 61 and later $5000 or an amount equal to 1.2 

times the economic benefit of 

delayed compliance, whichever 

is greater 

l. Violation of Paragraph 25.b. Failure to have the required number 

of compressors at each FGRS available for operation at least 95% of the time in a 

rolling 8760-hour rolling average period: 

Per FGRS, the number of hours or fraction thereof – over 438 – in a 

rolling 8760-hour period that a compressor required to be available for 

operation is not: $750 

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m. Violation of Paragraph 25.c. Failure to comply with the 

requirements of Paragraphs 25.c.i or 25.c.ii: Per FGRS, per hour or fraction 

thereof of noncompliance: $750 

n. Violation of Subparagraph 26.a (or any subsequent 30-day limit set 

pursuant to Paragraph 27.a.i). Failure to comply with the refinery-wide, 30-day 

rolling average limit on waste gas flaring 

Magnitude of Exceedance Penalty per Day 

≤ 10% $6250 

>10% to ≤ 20% $12,500 

>20% $18,750 

o. Violation of Subparagraph 26.b (or any subsequent 365-day limit 

set pursuant to Paragraph 27.a.ii). Failure to comply with the refinery-wide 

365-day rolling average limit on waste gas flaring: 

Magnitude of Exceedance Penalty per Day 

≤ 10% $12,500 

>10% to ≤ 20% $18,750 

>20% $37,500 

p. Violation of Paragraph 30 or 42.c. Failure to timely comply with 

the requirements of Paragraph 30 (for the Covered Flares) or Paragraph 42.c (for 

the LPG Flare): Penalty per Flare per day: $500. 

q. Violation of Paragraph 33.b – Covered Flares except DDU Flare. 

For each Covered Flare except the DDU Flare, failure to comply with the Net 

Heating Value in the Combustion Zone Gas (NHVcz)standard in Paragraph 33.b: 

On a per Covered Flare basis, Hours per Penalty per Hour or fraction 

Calendar Quarter in Noncompliance thereof per Covered Flare 

Hours 0.25-50.0 $150 

Hours 50.25-100.0 $350 

Hours over 100 $500 

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For purposes of calculating the number of hours of noncompliance with the 

NHV standard, all 15-minute periods of violation shall be added together 

to determine the total. 

r. Violation of Paragraph 33.b – DDU Flare. For the DDU Flare, 

failure to comply with the Net Heating Value in the Combustion Zone Gas 

(NHVcz) standard in Paragraph 33.b: 

Hours per calendar basis, Hours per 

Calendar Quarter in Noncompliance 

Penalty per Hour or fraction 

thereof per Covered Flare 

Hours 0.25-50.0 $25 

Hours 50.25-100.0 $75 

Hours over 100.0 $150 

s. Violations of Paragraphs 45, 48.d, or 49.b. For the LPG Flare, 

failure to comply with the ṁair-asst/ṁair-stoich-vg standard in Paragraph 45, 48.d, or 

49.b, as applicable: 

Hours per calendar basis, Hours per Penalty per Hour or fraction 

Calendar Quarter in Noncompliance thereof per Covered Flare 

Hours 0.25-50.0 $100 

Hours 50.25-100.0 $200 

Hours over 100.0 $300 

For purposes of calculating the number of hours of noncompliance with the 

ṁair-asst/ṁair-stoich-vg standard, all five minute periods of violation shall be 

added together to determine the total. 

t. Violation of Subparagraph 35.b. Failure to comply with the 

prohibition on Discontinuous Wake Dominated Flow: 

Flare Tip Size (inches) Penalty per Hour or fraction 

thereof 

1.0-24.0 $150 

24.1-48.0 $225 

Over 48.0 $525 

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u. Violation of Subparagraph 35.c. Failure to comply with the 

applicable MFR standard: 

Flare Tip Size (inches) Penalty per Hour or fraction 

thereof 

1.0-24.0 $50 

24.1-48.0 $75 

Over 48.0 $175 

For purposes of calculating the number of hours of noncompliance with the 

MFR limit, all 5-minute periods of violation shall be added together to 

determine the total. 

v. Violation of Paragraph 38 or 48.a. Failure to timely conduct the 

testing set forth in Paragraph 38 or 48.a (if required) in accordance with the 

protocol: 

For each flare test, Period of Delay or Penalty per Day 

Noncompliance 

Days 1-30 $250 

Days 31-60 $500 

Days 61 and later $1000 

w. (i) Violation of Paragraph 38, 39, or 48.b. Failure to timely 

submit a test protocol as required by Paragraph 38 or failure to timely 

submit a test report as required by Paragraph 39 or 48.b: 

For each flare test, Period of Penalty per Day 

Delay or Noncompliance 

Days 1-30 $200 

Days 31-60 $300 

Days 61 and later $400 

(ii) Violation of Paragraph 38, 39, or 48.b. Failure to submit a test 

protocol that conforms to the requirements of Paragraph 38, or failure to 

submit a test report that conforms to the requirements of Paragraph 30 or 

48.b: $50,000 per protocol or report. 

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x. Violation of Paragraph 41. Failure to record any information 

required to be recorded pursuant to Paragraphs 41.a, b, c, or d: $100 per day. 

y. Violation of Paragraph 54. Failure to timely develop a report that 

conforms to the requirements in Paragraph 54 or failure to keep it as an internal 

record: 

Period of Delay or Noncompliance Penalty per Day 

Days 1-30 $800 

Days 31-60 $1600 

Days 61 and later $3000 

z. Violation of Paragraph 55. For those corrective action(s) which 

BPP: (i) agrees to undertake following receipt of an objection by EPA pursuant to 

Paragraph 55.c; or (ii) is required to undertake following dispute resolution, then, 

from the date that either: (i) a final agreement is reached between EPA and BPP 

regarding the corrective action; or (ii) a court order regarding the corrective action 

is entered, BPP shall be liable for stipulated penalties: 

Period of Delay or Noncompliance

Days 1-120 

Days 121-180 

Days 181-365 

Days over 365 

Penalty per Day 

$50 

$100 

$300 

$3000 or 1.2 times the economic 

benefit resulting from BPP’s 

failure to implement the 

corrective action(s). 

The decision of whether to demand as a stipulated penalty the “per day” 

amounts or the economic benefit amount shall rest exclusively within the 

discretion of the United States. 

aa. Violation of Paragraph 55. Failure to complete any corrective 

action under Paragraph 55.a in accordance with the schedule for corrective action 

agreed to by BPP (with any such extensions thereto as to which EPA and BPP 

may agree in writing): 

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Period of Delay or Noncompliance Penalty per Day 

Days 1-30 $1000 

Days 31-60 $2000 

Days 61 and later $5000 

bb. Violation of Subparagraph 67.d. Failure to ensure that a 

Temporary-Use Flare that falls under the conditions of Paragraph 67.d.i or 

Paragraph 67.d.ii complies with the requirements of those Subparagraphs: 

Number of Days Temporary-Use Penalty per Day 

Flare did not comply 

Days 1-7 $1000 

Days 8-15 $2000 

Days 16 and later $5000 

cc. Violation of Paragraph 69 or 70. Failure to comply with the H2S 

emission limit at a Covered Flare or the LPG Flare after that Covered Flare or the 

LPG Flare becomes subject to Subpart J of the NSPS or Subpart Ja of the NSPS: 

On a per Covered Flare basis, Hours Penalty per Hour per 

per calendar quarter in noncompliance Covered Flare 

Hours 1-50.0 $ 50 

Hours 51-100.0 $100 

Hours over 100.0 $200 

For purposes of calculating the number of hours of noncompliance with the 

H2S limit, all one-hour periods of violation shall be added together to 

determine the total. 

dd. Violation of Paragraph 71. Failure to timely decommission the 

SRU Flare in conformance with the requirements of Paragraph 71: 

Period of Delay or Noncompliance Penalty per Day 

Days 1-30 $1000 

Days 31-60 $2500 

Days 61 and later $5000 

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P. Requirements for Incorporation of Consent Decree Requirements into Federally 

Enforceable Permits 

151. For each failure to submit an application to incorporate Consent Decree 

requirements into relevant local, state and/or federal permits as required by Paragraph 83: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $500 

31st through 60th day after deadline $1500 

Beyond 60th day after deadline $3000 

Q. Requirements for SEP Implementation 

152. For failure to comply with any requirement of Paragraphs 88-94 and 

Appendix E: 

Period of Delay or Non-Compliance Penalty per Day 

1st through 30th day after deadline $500 

31st through 60th day after deadline $1500 

Beyond 60th

 day after deadline $3000 

R. Requirements for Reporting and Record Keeping 

153. For each failure to submit reports as required by Part VIII, per report, 

per day: 

Period of Delay or Non-Compliance Penalty per Day 

1st

 through 30th day after deadline $300 

31st

 through 60th day after deadline $1000 

Beyond 60th day after deadline $2000 

154. Reserved. 

155. Reserved. 

156. Reserved. 

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S. Requirements for Payment of Civil Penalties 

157. For the failure to pay the civil penalties as specified in Part IX of this 

Consent Decree, BPP will be liable for $15,000 per day plus interest on the amount 

overdue at the rate specified in 28 U.S.C. § 1961(a). 

T. General Provisions Related to Stipulated Penalties 

158. Demand for Stipulated Penalties. BPP will pay stipulated penalties 

upon written demand by the United States by no later than sixty (60) days after BPP 

receives such demand. A demand for the payment of stipulated penalties will identify the 

particular violation(s) to which the stipulated penalty relates, the stipulated penalty 

amount that the United States is demanding for each violation (as can be best estimated), 

the calculation method underlying the demand, and the grounds upon which the demand 

is based. The United States may, in its unreviewable discretion, waive payment of all or 

any portion of stipulated penalties that may accrue under this Consent Decree. 

159. Payment of Stipulated Penalties. Stipulated penalties shall be 

apportioned as follows: 70% to the United States and 30% to Indiana. Stipulated 

penalties owing to the United States of under $10,000 will be paid by check and made 

payable to “U.S. Department of Justice,” referencing DOJ Number 90-5-2-09244, and 

delivered to the U.S. Attorney’s Office in the Northern District of Indiana. Stipulated 

penalties owing to the United States of $10,000 or more and stipulated penalties owing to 

Indiana will be paid in the manner set forth in Part X (“Civil Penalty”). 

160. Stipulated Penalties Dispute. Stipulated penalties will begin to accrue 

on the day after performance is due or the day a violation occurs, whichever is applicable, 

and will continue to accrue until performance is satisfactorily completed or until the 

violation ceases. However, in the event of a dispute over stipulated penalties, stipulated 

penalties will not accrue commencing upon the date BPP files a petition with the Court 

under Part XIV (“Retention of Jurisdiction/Dispute Resolution”) if BPP has placed the 

disputed amount demanded in a commercial escrow account with interest. If the dispute 

thereafter is resolved in BPP’s favor, the escrowed amount plus accrued interest will be 

returned to BPP; otherwise, the United States and Indiana (as applicable) will be entitled 

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to the amount that was determined to be due by the Court, plus the interest that has 

accrued in the escrow account on such amount. 

161. The United States and Indiana reserve the right to pursue any other 

nonmonetary remedies to which they are legally entitled, including but not limited to, 

injunctive relief, for BPP’s violations of this Consent Decree. Where a violation of this 

Consent Decree is also a violation of the Clean Air Act, its regulations, or a federallyenforceable state law, regulation, or permit, the United States will not seek civil penalties 

where it already has demanded and secured stipulated penalties from BPP for the same 

violations nor will the United States demand stipulated penalties from BPP for a Consent 

Decree violation if the United States has commenced litigation under the Clean Air Act 

for the same violations. Where a violation of this Consent Decree is also a violation of 

state law, regulation or a permit, Indiana will not seek civil penalties where the United 

States already has demanded and/or secured stipulated penalties from BPP for the same 

violations. 

XI. INTEREST 

162. BPP will be liable for interest on the unpaid balance of the civil penalty 

specified in Part IX, and for interest on any unpaid balance of stipulated penalties to be 

paid in accordance with Part X. All such interest will accrue at the rate established 

pursuant to 28 U.S.C. § 1961(a) – i.e., a rate equal to the coupon issue yield equivalent 

(as determined by the Secretary of Treasury) of the average accepted auction price for the 

last auction of 52-week U.S. Treasury bills settled prior to the Date of Lodging of the 

Consent Decree. Interest will be computed daily and compounded annually. Interest will 

be calculated from the date payment is due under the Consent Decree through the date of 

actual payment. For the purposes of this Paragraph, interest pursuant to this Paragraph 

will cease to accrue on the amount of any stipulated penalty payment made into an 

interest bearing escrow account as contemplated by Paragraph 160 of this Consent 

Decree. Monies timely paid into escrow will not be considered to be an unpaid balance 

under this Part. 

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XII. RIGHT OF ENTRY 

163. Any authorized representative of EPA or the State of Indiana, upon 

presentation of credentials, will have a right of entry upon the premises of the Whiting 

Refinery at any reasonable time for the purpose of monitoring compliance with the 

provisions of this Consent Decree, including inspecting plant equipment and systems, and 

inspecting all records maintained by the Whiting Refinery required by this Consent 

Decree or deemed necessary by EPA or IDEM to verify compliance with this Consent 

Decree. Except where other time periods specifically are noted, the Whiting Refinery 

will retain such records for the period of the Consent Decree. Nothing in this Consent 

Decree will limit the authority of EPA or IDEM to conduct tests, inspections, or other 

activities under any statutory or regulatory provision. 

XIII. FORCE MAJEURE 

164. “Force majeure,” for purposes of this Consent Decree, is defined as any 

event arising from causes beyond the control of BPP, of any entity controlled by BPP, or 

of BPP’s contractors, which delays or prevents the performance of any obligation under 

this Consent Decree or causes a violation of any provision of this Consent Decree despite 

BPP’s best efforts to fulfill the obligation. The requirement that BPP exercise “best 

efforts to fulfill the obligation” includes using best efforts to anticipate any potential 

force majeure event and best efforts to address the effects of any such event (a) as it is 

occurring and (b) after it has occurred to prevent or minimize any resulting delay to the 

greatest extent possible. “Force Majeure” does not include BPP’s financial inability to 

perform any obligation under this Consent Decree. 

165. If any event occurs or has occurred that may delay the performance of 

any obligation under this Consent Decree, as to which BPP intends to assert a claim of 

Force Majeure, BPP shall notify EPA and IDEM in writing as soon as practicable, but in 

no event later than fifteen (15) calendar days following the date BPP first knew, or by the 

exercise of due diligence should have known, that the event caused or may cause such 

delay. The notice shall include an explanation and description of the reasons for the 

delay; the anticipated duration of the delay; all actions taken or to be taken to prevent or 

minimize the delay; a schedule for implementation of any measures to be taken to prevent 

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or mitigate the delay or the effect of the delay; and BPP’s rationale for attributing such 

delay to a force majeure event BPP shall include with any notice all available 

documentation supporting the claim that the delay was attributable to a force majeure. 

Failure to comply with the above requirements shall preclude BPP from asserting any 

claim of force majeure for that event for the period of time of such failure to comply, and 

for any additional delay caused by such failure. BPP shall be deemed to know of any 

circumstance of which BPP, any entity controlled by BPP, or BPP’s contractors knew or 

should have known. 

166. If EPA, after a reasonable opportunity for review and comment by 

IDEM, agrees that the delay or anticipated delay is attributable to a force majeure event, 

the time for performance of the obligations under this Consent Decree that are affected by 

the force majeure event will be extended by EPA, after a reasonable opportunity for 

review and comment by IDEM, for such time as is necessary to complete those 

obligations. An extension of the time for performance of the obligations affected by the 

force majeure event shall not, of itself, extend the time for performance of any other 

obligation. EPA will notify BPP in writing of the length of the extension, if any, for 

performance of the obligations affected by the force majeure event. 

167. If EPA, after a reasonable opportunity for review and comment by 

IDEM, does not agree that the delay or anticipated delay has been or will be caused by a 

force majeure event, EPA will notify BPP in writing of its decision. 

168. If BPP elects to invoke the dispute resolution procedures set forth in 

Part XIV (“Dispute Resolution”), it shall do so no later than 15 days after receipt of 

EPA’s notice. In any such proceeding, BPP shall have the burden of demonstrating by a 

preponderance of the evidence that the delay or anticipated delay has been or will be 

caused by a force majeure event, that the duration of the delay or the extension sought 

was or will be warranted under the circumstances, that best efforts were exercised to 

avoid and mitigate the effects of the delay, and that BPP complied with the requirements 

of Paragraphs 164 and 165, above. If BPP carries this burden, the delay at issue shall be 

deemed not to be a violation by BPP of the affected obligation of this Consent Decree 

identified to EPA and the Court. 

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XIV. RETENTION OF JURISDICTION/DISPUTE RESOLUTION 

169. This Court will retain jurisdiction of this matter for the purposes of 

implementing and enforcing the terms of the Consent Decree and for the purpose of 

adjudicating all disputes of the Consent Decree between the United States and BPP that 

may arise under the provisions of this Consent Decree, until the Consent Decree 

terminates in accordance with Part XVII of this Consent Decree. 

170. Unless otherwise expressly provided for in this Consent Decree, the 

dispute resolution procedures of this Part shall be the exclusive mechanism to resolve 

disputes arising under or with respect to this Consent Decree. BPP’s failure to seek 

resolution of a dispute under this Part shall preclude BPP from raising any such issue as a 

defense to an action by the United States to enforce any obligation of BPP arising under 

this Decree. 

171. Informal Dispute Resolution. Any dispute subject to Dispute 

Resolution under this Consent Decree shall first be the subject of informal negotiations. 

The dispute shall be considered to have arisen when BPP sends the United States a 

written Notice of Dispute. Such Notice of Dispute shall state clearly the matter in 

dispute. The period of informal negotiations shall not exceed 60 Days from the date the 

dispute arises, unless that period is modified by written agreement. If the Parties cannot 

resolve a dispute by informal negotiations, then the position advanced by the United 

States shall be considered binding unless, within 30 Days after the United States has 

notified BPP of the conclusion of the informal negotiation period, BPP invokes formal 

dispute resolution procedures as set forth below. 

172. Formal Dispute Resolution. BPP shall invoke formal dispute resolution 

procedures, within the time period provided in the preceding Paragraph, by serving on the 

United States a written Statement of Position regarding the matter in dispute. The 

Statement of Position shall include, but need not be limited to, any factual data, analysis, 

or opinion supporting BPP’s position and any supporting documentation relied upon by 

BPP. 

173. The United States shall serve its Statement of Position within 45 Days 

of receipt of BPP’s Statement of Position. The United States’ Statement of Position shall 

include, but need not be limited to, any factual data, analysis, or opinion supporting that 

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position and any supporting documentation relied upon by the United States. The United 

States’ Statement of Position shall be binding on BPP, unless BPP files a motion for 

judicial resolution of the dispute in accordance with the following Paragraph. 

174. BPP may seek judicial resolution of the dispute by filing with the Court 

and serving on the United States, in accordance with Paragraph 210 of this Consent 

Decree (“Notice”), a motion requesting judicial resolution of the dispute. The motion 

must be filed within 20 Days of receipt of the United States’ Statement of Position 

pursuant to the preceding Paragraph. The motion shall contain a written statement of 

BPP’s position on the matter in dispute, including any supporting factual data, analysis, 

opinion, or documentation, and shall set forth the relief requested and any schedule 

within which the dispute must be resolved for orderly implementation of the Consent 

Decree. 

175. The United States shall respond to BPP’s motion within the time period 

allowed by the Local Rules of this Court. BPP may file a reply memorandum, to the 

extent permitted by the Local Rules. 

176. Standard of Review. In all disputes arising under the Consent Decree, 

BPP shall bear the burden of demonstrating that its position complies with this Consent 

Decree and the CAA and that BPP is entitled to relief. The United States reserves the 

right to argue that its position is reviewable only on the administrative record and must be 

upheld unless arbitrary and capricious or otherwise not in accordance with law, and BPP 

reserves the right to argue to the contrary. 

177. The invocation of dispute resolution procedures under this Part shall 

not, by itself, extend, postpone, or affect in any way any obligation of BPP under this 

Consent Decree unless and until final resolution of the dispute so provides. Stipulated 

penalties with respect to the disputed matter shall continue to accrue from the first Day of 

noncompliance, but payment shall be stayed pending resolution of the dispute as 

provided in Paragraph 162. If BPP does not prevail on the disputed issue, stipulated 

penalties shall be assessed and paid as provided in Part X (“Stipulated Penalties”). As 

part of the resolution of any dispute under this Part, the Parties, by agreement, or the 

Court, by order, may, in appropriate circumstances, extend or modify the schedule for 

completion of work under this Consent Decree to account for the delay in work that 

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occurred as a result of the dispute resolution process. BPP shall be liable for stipulated 

penalties for its failure thereafter to complete the work in accordance with the extension 

or modified schedule. 

XV. EFFECT OF SETTLEMENT 

178. Definitions. For purposes of this Part XV (Effect of Settlement), the 

following definitions apply: 

a. “Hazardous Air Pollutants” or “HAPs” shall have the meaning set forth in 

42 U.S.C. § 7412(b)(1); 

b. “Whiting Refinery Modernization Project” or “WRMP” shall mean: 1) the 

projects authorized to be constructed and operated at the Whiting Refinery 

pursuant to Significant Source Modification 089-25484-00453 issued by IDEM 

on May 1, 2008 and Part 70 Permit T089-6741-00453 as modified by Significant 

Permit Modification 089-25488-00453 issued by IDEM on June 16, 2008, and 2) 

any other contemporaneous project included for emissions netting purposes and 

identified in the same permits. This project originally was named the “CXHO 

Project,” was subsequently re-named the “Operation Canadian Crude Project,” 

and later was re-named the “Whiting Refinery Modernization Project;” 

c. “Post-Lodging Compliance Dates” shall mean any dates in this Part XV 

(“Effect of Settlement”) after the Date of Lodging; 

d. “PSD/NNSR Requirements” shall mean the Prevention of Significant 

Deterioration and Non-Attainment New Source Review requirements found in the 

following: 42 U.S.C. § 7475; 40 C.F.R. §§ 52.21(a)(2)(iii) and 

52.21(j) - 52.21(r)(5); 42 U.S.C. §§ 7502(c)(5), 7503(a)-(c); 40 C.F.R. Part 51, 

Appendix S, Part IV, Conditions 1-4; any applicable, federally approved and 

federally enforceable state or local regulation that implements, adopts, or 

incorporates the federal provisions cited in this Paragraph; any Title V permit 

requirement that implements, adopts, or incorporates the federal, or federally 

approved state, provisions cited in this Paragraph; and any applicable state or 

local regulation enforceable by the State of Indiana that implements, adopts, or 

incorporates the federal provisions cited in this Paragraph; 

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e. “Stayed Subpart Ja Requirements” shall mean the following requirements 

of 40 C.F.R. Part 60, Subpart Ja, that are currently stayed pursuant to 73 Fed. Reg. 

78,549 (Dec. 22, 2008); 

i. SO2 and H2S emissions limits applicable to flares (set forth 

in 40 C.F.R. § 60.102a(g)(1) (2010)); 

ii. SO2 emissions limits applicable to heaters (set forth in 40 

C.F.R. § 60.102a(g)(1) (2010)); 

iii. NOx emission limits applicable to heaters (set forth in 40 

C.F.R. § 60.102a(g)(2) (2010)); 

iv. Sulfur monitoring for flares (set forth in 40 C.F.R. 

§ 60.107a(d) (2010)); and 

v. Flow monitoring for flares (set forth in 40 C.F.R. 

§ 60.107a(e) (2010)). 

If a final rule encompassing these Stayed Subpart Ja Requirements places 

them in different locations in Subpart Ja with different citations, the 

definition herein refers to the subject of the regulation (e.g., “SO2 emission 

limits applicable to flares”) and not to the citation. 

179. Entry of this Consent Decree shall resolve the civil claims of the United 

States and the State of Indiana for the violations that occurred through the Date of 

Lodging of the Consent Decree as alleged in the Complaints (filed by the United States 

and the State concurrently with the lodging of this Consent Decree). 

180. Resolution of Claims Alleged in Notices of Violation (“NOVs”) and 

Findings of Violations (“FOVs”). Entry of this Consent Decree shall resolve the civil 

claims of the United States for the violations that occurred through the Date of Lodging 

of the Consent Decree as alleged in the following NOVs and FOVs: 

a. FOV – EPA-5-07-IN-03 (Jan. 25, 2007); 

b. NOV/FOV – EPA-5-08-IN-01 (Nov. 29, 2007); 

c. Amendment to NOV/FOV – EPA-5-08-IN-01 (Oct. 1, 2008) at the process 

units identified by unit name and number; 

d. NOV – EPA-5-09-IN-13 (May 18, 2009); and 

e. FOV – EPA-5-10-04-IN (Feb. 11, 2010). 

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These NOVs and FOVs are attached hereto in Appendix F. 

181. Resolution of Claims for Violating PSD/NNSR Requirements at the 

Covered, LPG, and SRU Flares. With respect to emissions of SO2, VOCs, CO and H2S 

from the following flares, entry of this Consent Decree shall resolve the civil claims of 

the United States and the State of Indiana against BPP for violations of the PSD/NNSR 

Requirements resulting from construction or modification that occurred during the 

WRMP from the date those claims accrued through the following dates: 

a. SRU, DDU, GOHT, and South Date of Lodging 

flares 

b. LPG flare December 31, 2012 

c. FCU, VRU, and Alky flares December 31, 2015 

d. 4UF flare December 31, 2016 

e. UIU flare December 31, 2017 

182. Resolution of Claims for Violating PSD/NNSR Requirements at Other 

Process Units. With respect to emissions of the following pollutants from the following 

process units, entry of this Consent Decree shall resolve the civil claims of the United 

States and the State of Indiana against BPP for violations of the PSD/NNSR 

Requirements resulting from construction or modification that occurred during the 

WRMP from the date those claims accrued through the Date of Lodging: 

a. At FCU 500 and 600 with respect to SO2 and NOx; 

b. At the Whiting New Coker (also referred to as the #2 Coker) with 

respect to VOCs, H2S, PMTOTAL, and PM10; and 

c. At the following heaters and units: 

i. With respect to NOx: the #2 Coker heaters (F-201, F-202, 

and F-203); and 

ii.	 With respect to SO2: 

A. 11 A Pipestill heaters (H-1X, H-2, and H-3); 

B. 11 C Pipestill heaters (H-200 and H-300); 

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C. 12 Pipestill heaters (H-101A, H-101B, and H-102); 

D. #2 Coker heaters (F-201, F-202, and F-203); 

E. GOHT heaters (F-901A and F-901B); 

F. BOU F-401 furnace; 

G. ISOM H-1 heater; 

H. New Hydrogen Unit heaters (HU-1 and HU-2); 

I. HU B-501; 

J. CFHU heaters (F-801A, F-801B, and F-801C); 

K. DDU heaters (WB-301 and WB-302); 

L. 4UF heaters (F-1, F-2, F-3, F-4, F-5, F-6, F- 7, F8A, and F-8B); 

M. ARU heaters (F-200A and F-200B); 

N. CRU heaters (F-101 and F-102A); 

O. 3SPS boilers (#1, #2, #3, #4, and #6); 

P. 3SPS Duct Burners; and 

Q. New Boiler 1. 

183. Resolution of Pre-Lodging Claims Under Listed Regulations at the 

Covered Flares, LPG Flare, and Other Process Units. With respect to emissions of the 

following pollutants at the following flares and process units, entry of this Consent 

Decree shall resolve the civil claims of the United States and the State of Indiana against 

BPP for violations of the listed regulations and any applicable state regulations that 

implement, adopt, or incorporate any of the listed regulations that occurred from 

December 1, 2002 through the Date of Lodging:, except that the violations of 40 C.F.R. 

§ 60.102a(f)(1)(ii) shall be resolved from September 26, 2008 through the Date of 

Lodging: 

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Flare(s)/ 

Process Unit(s) 

Pollutant(s) Regulation(s) 

Covered Flares VOCs and 40 C.F.R. § 60.11(d); 

and LPG Flare HAPs 

40 C.F.R. §§ 60.18(c)(1)-(2), (c)(3)(ii), (c)(4)-(5), (d), 

(e) and (f); 

40 C.F.R. § 63.6(e)(1)(i); 

40 C.F.R. §§ 63.11(b)(1), (3)-(5), (6)(ii), and (7)-(8); 

40 C.F.R. § 60.482-10(d), but only to the extent that 

this provision requires compliance with 40 C.F.R. 

§§ 60.18(c)(3)(ii) and (d); 

40 C.F.R. § 60.482-10(e), but only to the extent that 

this provision relates to flares; 

40 C.F.R. § 60.592(a), but only to the extent that this 

provision: (a) relates to flares, and (b) requires 

compliance with 40 C.F.R. §§ 60.18(c)(3)(ii) and (d); 

40 C.F.R. §§ 63.643(a)(1), 63.648(a), and Table 6 of 

Part 63, Subpart CC, but only to the extent that these 

provisions: (a) relate to flares, and (b) require 

compliance with 40 C.F.R. §§ 60.18(c)(3)(ii) and (d), 

63.6(e)(1)(i), and 63.11(b)(1) and (b)(6)(ii); and 

40 C.F.R. § 63.1566(a)(1)(i) and Tables 15 and 44 of 

Part 63, Subpart UUU, but only to the extent that these 

provisions: (a) relate to flares, and (b) require 

compliance with 40 C.F.R. §§ 63.11(b)(1), (b)(6)(ii) 

and (e)(1). 

Covered Flares 

and LPG Flare 

SO2 and H2S 40 C.F.R. Part 60, Subparts A and J 

FCU 500 and 

FCU 600 

SO2, CO, 

NOx and 

PM 

40 C.F.R. Part 60, Subparts A, J, and Ja 

Heaters, boilers, 

and other units 

listed in 

Paragraph 185.b 

SO2 40 C.F.R. Part 60, Subparts A and J. 

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Flare(s)/ 

Process Unit(s) 

Pollutant(s) Regulation(s) 

Sulfur Pits A, B, 

C, and 2400 

H2S and 

reduced 

sulfur 

compounds 

40 C.F.R. §§ 60.102a(f)(1)(ii), 60.106a(a)(2), and 40 

C.F.R. Part 60, Subparts A and J 

184. Resolution of Claims Continuing Post-Lodging Under Listed 

Regulations at the Covered Flares and the LPG Flare. 

a. Resolution of Claims for Failure to Comply with Requirements Related to 

Monitoring, Operation, and Maintenance According to Flare Design. With 

respect to emissions of VOCs and HAPs at the following flares, entry of this 

Consent Decree shall resolve the civil claims of the United States and the State of 

Indiana against BPP for violations of the listed regulations from the Date of 

Lodging through the following dates, but only to the extent that these claims are 

based upon BPP’s use of too much steam in relation to vent gas flow: 

Flare(s) Date Regulation(s) 

LPG Flare 1 year after Date of 

Entry 

40 C.F.R. §§ 60.18(d); 

40 C.F.R. §§ 63.11(b)(1); 

40 C.F.R. § 60.482-10(d), but only to the extent 

that this provision requires compliance with 40 

C.F.R. § 60.18(d); 

40 C.F.R. § 60.482-10(e), but only to the extent 

that this provision relates to flares; 

40 C.F.R. § 60.592(a), but only to the extent that 

this provision: (a) relates to flares, and (b) 

requires compliance with 40 C.F.R. § 60.18(d); 

40 C.F.R. §§ 63.643(a)(1) and 63.648(a), but 

only to the extent that these provisions: (a) relate 

to flares, and (b) require compliance with 40 

C.F.R. §§ 60.18(d) and 63.11(b)(1); and 

40 C.F.R. § 63.1566(a)(1)(i) and Table 15 of 

Part 63, Subpart UUU, but only to the extent that 

these provisions: (a) relate to flares, and (b) 

require compliance with 40 C.F.R. § 63.11(b)(1). 

Covered Flares December 31, 2014 

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b. Resolution of NSPS Subpart J Claims. With respect to emissions of SO2 

at the following flares, entry of this Consent Decree shall resolve the civil claims 

of the United States and the State of Indiana against BPP for violations of the 

listed regulations from the Date of Lodging through the following dates: 

Flare(s) 40 C.F.R. § 60.104(a)(1) 

(Standards for sulfur oxides) 

40 CFR § 60.105(a)(4) 

(Monitoring of emissions and 

operations) 

FCU December 31, 2015 December 31, 2013 

VRU December 31, 2015 December 31, 2013 

Alky December 31, 2015 December 31, 2013 

4UF December 31, 2016 December 31, 2013 

UIU December 31, 2017 December 31, 2013 

185. Conditional Resolution of Claims Under Stayed NSPS Subpart Ja 

Requirements. If EPA lifts the stay on the Stayed Subpart Ja Requirements and 

promulgates final regulations encompassing the Stayed Subpart Ja Requirements, then 

entry of this Consent Decree shall resolve the civil claims of the United States and the 

State of Indiana against BPP for violations of the Stayed Subpart Ja Requirements as 

follows: 

a. For the following flares and the following Stayed Subpart Ja 

Requirements, from the date that a final rule encompassing the Stayed Subpart Ja 

Requirements is effective through the following dates: 

Name of 

Flare 

SO2 and H2S Emission Limits 

(currently at 40 C.F.R. § 

60.102a(g)(1)) 

Sulfur and Flow Monitoring 

(currently at 40 C.F.R. §§ 60.107a(d), 

(e)) 

DDU Date of Lodging December 31, 2013 

FCU December 31, 2015 December 31, 2013 

VRU December 31, 2015 December 31, 2013 

Alky December 31, 2015 December 31, 2013 

4UF December 31, 2016 December 31, 2013 

UIU December 31, 2017 December 31, 2013 

b. For the following heaters and units with respect to the following 

pollutants, from the date that a final rule encompassing the Stayed Subpart Ja 

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Requirements is effective through the Date of Lodging, except for 11 C Pipestill 

heater H-200: 

i.	 With respect to NOx emissions (currently, the limit is set forth in 

stayed provision 40 C.F.R. § 60.102a(g)(2)): 

A. 12 Pipestill heaters (H-101A, H-101B, and H-102); 

B. 11 C Pipestill heater H-200 through December 31, 

2013; 

C. #2 Coker heaters (F-201, F-202, and F-203); 

D. GOHT heaters (F-901A and F-901B); and 

E. BOU F-401 furnace. 

ii.	 With respect to SO2 emissions (currently, the limit is set forth in 

stayed provision 40 C.F.R. § 60.102a(g)(1)): 

A. 11 A Pipestill heaters (H-1X, H-2, and H-3); 

B. 11 C Pipestill heaters (H-200 and H-300); 

C. 12 Pipestill heaters (H-101A, H-101B, and H-102); 

D. #2 Coker heaters (F-201, F-202, and F-203); 

E. GOHT heaters (F-901A and F-901B); 

F. BOU F-401 furnace; 

G. ISOM H-1 Heater; 

H. New Hydrogen Unit Heaters (HU-1 and HU-2); 

I. HU B-501; 

J. CFHU heaters (F-801A, F-801B, and F-801C); 

K. DDU heaters (WB-301 and WB-302); 

L. 4UF heaters (F-1, F-2, F-3, F-4, F-5, F-6, F-7, F8A, and F-8B); 

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M. ARU heaters (F-200A and F-200B); 

N. CRU heaters (F-101 and F-102A); 

O. 3SPS boilers (#1, #2, #3, #4, and #6); 

P. 3SPS Duct Burners; and 

Q. New Boiler 1. 

186. Resolution of LDAR violations. Entry of this Consent Decree shall 

resolve the civil claims of the United States and the State of Indiana against BPP for 

violations of (i) 40 C.F.R. Part 60, Subpart GGG and GGGa; (ii) 40 CFR Part 61, 

Subparts J and V; (iii) the LDAR provisions of 40 C.F.R. Part 63, Subpart CC; and (iv) 

326 I.A.C. 8-4-8, that occurred from December 1, 2002 through the Date of Lodging of 

the Consent Decree at each process unit (as defined by 40 C.F.R. § 60.590a(e)) at the 

Whiting Refinery. 

187. Resolution of Liability Regarding Benzene Waste NESHAP 

Requirements. Entry of this Consent Decree shall resolve the civil claims of the United 

States and the State of Indiana against BPP for violations of 40 C.F.R. Part 61, Subpart 

FF that occurred from December 1, 2002 through the Date of Lodging of the Consent 

Decree at waste management units at the Whiting Refinery. 

188. Resolution of Title V violations. Entry of this Consent Decree shall 

resolve the civil claims of the United States and the State of Indiana against BPP for the 

violations at the Whiting Refinery of Sections 502(a), 503(c), and 504(a) of the CAA, 42 

U.S.C. §§ 7661a(a), 7661b(c), 7661c(a), and of 40 C.F.R. §§ 70.1(b), 70.5(a) and (b), 

70.6(a) and (c), and 70.7(b), that are based upon the violations resolved by Paragraphs 

181-184, 186 and 187 for the time frames set forth in those Paragraphs. 

189. Resolution of Consent Decree violations. Entry of this Consent Decree 

shall resolve the civil claims of the United States against BPP for the following violations 

at the Whiting Refinery of the Consent Decree entered on August 29, 2001 in United 

States, et al. v. BP Exploration and Oil Co., et al., Civil No. 2:96 CV 095 RL (N.D. Ind.): 

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a. Violations of Paragraph 19.A.ii. (Facility Current Compliance 

Status) that occurred prior to December 31, 2008; 

b. Violations of Paragraphs 20.B.i. (Training), 20.D (Leak 

Definition), 20.G First Attempt at Repair on Valves), 20.H.i. (LDAR Monitoring 

Frequency), 20.L (Adding New Valves and Pumps), and 20.S (Quarterly Reports) 

that occurred prior to the Date of Lodging; and 

c. Violations of Paragraph 21.A (Sulfur Pit Emissions) that occurred 

at Sulfur Pits, A, B, C, and 2400 that occurred prior to the Date of Lodging. 

190. The resolutions of liability in this Part are based exclusively on claims 

at BPP’s Whiting Refinery. 

191. Reservation of Rights: Resolution in Paragraphs 181, 184, 185 and 187 

Can Be Rendered Void. Notwithstanding the resolutions of liability contained in 

Paragraphs 181, 184, 185 and 187 for the period of time between the Date of Lodging 

and the Post-Lodging Compliance Dates, those resolutions of liability shall be rendered 

void if BPP materially fails to comply with any of the obligations and requirements of 

Section F (NOx Emissions Reductions from Heaters and Boilers), Section O (Emissions 

Reductions from Flares and Control of Flaring Events), and Section P (Incorporation of 

Consent Decree Requirements into Federally Enforceable Permits) of Part V, and Part VI 

(Emission Credit Generation). However, the resolutions of liability in Paragraphs 181, 

184, 185 and 187 shall not be rendered void if BPP remedies such material failure as 

expeditiously as practicable and pays all stipulated penalties due as a result of such 

material failure. 

192. The United States and IDEM further reserve all legal and equitable 

remedies available to enforce the provisions of this Consent Decree. This Consent 

Decree shall not be construed to limit the rights of the United States or IDEM to obtain 

penalties or injunctive relief under the CAA or implementing regulations, or under other 

federal or state laws, regulations, or permit conditions, except as expressly specified in 

Paragraphs 179-188. The United States and IDEM further reserve all legal and equitable 

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remedies to address any imminent and substantial endangerment to the public health or 

welfare or the environment arising at, or posed by, BPP’s Whiting Refinery, whether 

related to the violations addressed in this Consent Decree or otherwise. 

193. In any subsequent administrative or judicial proceeding initiated by the 

United States or IDEM for injunctive relief, civil penalties, other appropriate relief 

relating to the Whiting Refinery for violations of PSD/NSR, NSPS, NESHAP and/or 

LDAR requirements not identified in this Part: 

a. BPP shall not assert, and may not maintain, any defense or claim based 

upon the principles of waiver, res judicata, collateral estoppel, issue preclusion, 

claim preclusion, claim-splitting, or other defenses based upon any contention that 

the claims raised by the United States or IDEM in the subsequent proceeding 

were or should have been brought in the instant case, except with respect to 

claims that have been specifically resolved pursuant to Paragraphs 179-188 of this 

Part and for which the resolution of liability has not been voided pursuant to 

Paragraph 190. 

b. Except as set for in Subparagraph a., the United States and the State of 

Indiana may not assert or maintain that this Consent Decree constitutes a waiver, 

or determination of, or otherwise obviates, any claim or defense by BPP 

whatsoever, or that this Consent Decree constitutes an acceptance by BPP of any 

interpretation or guidance issued by EPA related to the matters addressed in this 

Consent Decree. 

194. This Consent Decree is not a permit, or a modification of any permit, 

under any federal, State, or local laws or regulations. BPP is responsible for achieving 

and maintaining complete compliance with all applicable federal, State, and local laws, 

regulations, and permits; and BPP’s compliance with this Consent Decree shall be no 

defense to any action commenced pursuant to any such laws, regulations, or permits, 

except as set forth herein. The United States and IDEM do not, by their consent to the 

entry of this Consent Decree, warrant or aver in any manner that BPP’s compliance with 

any aspect of this Consent Decree will result in compliance with provisions of the Act, 42 

U.S.C. § 7401 et seq., or with any other provisions of federal, State, or local laws, 

regulations, or permits. 

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195. This Consent Decree does not limit or affect the rights of BPP, the 

United States, or IDEM against any third parties that are not party to this Consent Decree, 

nor does it limit the rights of third parties that are not party to this Consent Decree against 

BPP, except as otherwise provided by law. 

196. This Consent Decree shall not be construed to create rights in, or grant 

any cause of action to, any third party not party to this Consent Decree. 

197. Nothing in this Consent Decree will be construed to limit or disqualify 

BPP, on the grounds that information was not discovered voluntarily, from seeking to 

apply EPA’s Audit policy to any violation or noncompliance that BPP discovers during 

the course of any audit, investigation, or enhanced monitoring the BPP is required to 

undertake pursuant to this Consent Decree. 

198. Resolution of Citizen-Intervenors Claims. In consideration of the 

commitments and agreements being made by BPP in this Consent Decree, CitizenIntervenors hereby agree as follows: 

a. Citizen-Intervenors shall not file or support the filing (by providing legal 

representation or financial contributions over which the Citizen-Intervenors have 

control) of any judicial or administrative objection(s), appeal(s), petitions(s) for 

review, petition to EPA pursuant to Section 505(b)(2) of the Clean Air Act, or 

citizen suit(s) relating to: 

i. the issuance of any Source Modification Permit or any 

revision of the WRMP Operating Permit that is required by, contemplated 

by or necessary to implement this Consent Decree and the settlement of 

claims embodied herein; or 

ii. any allegation that WRMP has been constructed or will 

operate without required permits; 

provided that the foregoing shall not apply if the terms and conditions of any such 

permit differ in material respects from the terms and conditions of the draft terms 

and conditions that have been provided to Citizen-Intervenors prior to the date 

hereof and Citizen-Intervenors have not consented to such differences. The 

foregoing shall not prohibit the Citizen-Intervenors from communicating with 

other groups or individuals. 

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b. Upon the later of the (i) Date of Entry of this Consent Decree and (ii) the 

issuance of the WRMP Operating Permit in materially the same form as has been 

provided to the Citizen-Intervenors prior to the date hereof or with such 

modifications as have been consented to by the Citizen-Intervenors, Save the 

Dunes, Sierra Club, the Hoosier Environmental Council, Tom Tsourlis and Susan 

Eleuterio shall dismiss with prejudice their petitions for review pending before the 

OEA in Cause Nos. 08-A-J-4115 and 08-A-J-4142. 

c. Citizen-Intervenors shall not file a citizen suit or support the filing (by 

providing legal representation or financial contributions over which CitizenIntervenors have control) of any third party action related to the acts or omissions 

that form the basis of the claims of the United States and Indiana that are resolved 

in Part XV. 

d. Citizen-Intervenors may seek to enforce the obligations of BPP under this 

Decree, except for the obligations under Part IX (Civil Penalty) and Part X 

(Stipulated Penalties), by filing with the Court a motion for appropriate relief. 

Such motion shall be governed by the Federal Rules of Civil Procedure and 

applicable law. 

e. BPP’s sole and exclusive remedy for a breach of this Agreement by 

Citizen-Intervenors shall be an action for specific performance or injunction. In 

no event shall BPP be entitled to monetary damages for breach of this Agreement. 

In addition, no legal action for specific performance or injunction shall be brought 

or maintained until: (a) BPP provides written notice to the breaching Party which 

explains with particularity the nature of the claimed breach, and (b) within (30) 

days after receipt of said notice, the breaching Party fails to cure the claimed 

breach or, in the case of a claimed breach which cannot be reasonably remedied 

within a thirty (30) day period, the breaching Party fails to commence to cure the 

claimed breach within such (30) day period, and thereafter diligently complete the 

activities reasonably necessary to remedy the claimed breach. 

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XVI. GENERAL PROVISIONS 

199. Other Laws. Except as specifically provided by this Consent Decree, 

nothing in this Consent Decree will relieve BPP of its obligations to comply with all 

applicable federal, state, regional and local laws and regulations, including, but not 

limited to, more stringent standards. In addition, nothing in this Consent Decree will be 

construed to prohibit or prevent the United States or IDEM from developing, 

implementing, and enforcing more stringent standards subsequent to the Date of Lodging 

of this Consent Decree through rulemaking, the permit process, or as otherwise 

authorized or required under federal, state, regional, or local laws, or as otherwise 

authorized or required under federal, state, regional, or local laws and regulations. 

Subject to Part XV (“Effect of Settlement”), Part X (“Stipulated Penalties”), and 

Paragraph 201 (“Permit Violations”) of this Consent Decree, nothing contained in this 

Consent Decree will be construed to prevent or limit the rights of the United States or 

IDEM to seek or obtain other remedies or sanctions available under other federal, state, 

regional, or local statutes or regulations, by virtue of BPP’s violations of the Consent 

Decree or of the statutes and regulations upon which the Consent Decree is based, or for 

BPP’s violations of any applicable provision of law. This will include the right of the 

United States or IDEM to invoke the authority of the Court to order BPP’s compliance 

with this Consent Decree in a subsequent contempt action. The requirements of this 

Consent Decree do not exempt BPP from complying with any and all new or modified 

federal, state, regional, and/or local statutory or regulatory requirements that may require 

technology, equipment, monitoring, or other upgrades after the Date of Lodging of this 

Consent Decree. 

200. Startup, Shutdown, and Malfunction. Notwithstanding the provisions 

of this Consent Decree regarding Startup, Shutdown, and Malfunction, this Consent 

Decree does not exempt BPP from the requirements of state laws and regulations or from 

the requirements of any permits or plan approvals issued to BPP, as these laws, 

regulations, permits, and/or plan approvals may apply to Startups, Shutdowns, and 

Malfunctions. 

201. Permit Violations. Except as specifically identified in Part XV (“Effect 

of Settlement”), nothing in this Consent Decree will be construed to prevent or limit the 

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right of the United States or IDEM to seek injunctive or monetary relief for violations of 

permits; provided, however, that with respect to monetary relief, the United States and 

IDEM must elect between filing a new action for such monetary relief or seeking 

stipulated penalties under this Consent Decree, if stipulated penalties also are available 

for the alleged violation(s). 

202. Failure of Compliance. The United States and IDEM do not, by their 

consent to the entry of this Consent Decree, warrant or aver in any manner that BPP’s 

complete compliance with the Consent Decree will result in compliance with the 

provisions of the CAA or the corollary state and local statutes. Notwithstanding the 

review or approval by EPA or IDEM of any plans, reports, policies or procedures 

formulated pursuant to the Consent Decree, BPP will remain solely responsible for 

compliance with the terms of the Consent Decree, all applicable permits, and all 

applicable federal, state, regional, and local laws and regulations, except as provided in 

Part XIII (“Force Majeure”). 

203. Changes to Law. In the event that during the life of this Consent 

Decree there is a change to the statutes or regulations that provide the underlying basis 

for the Consent Decree such that BPP would not otherwise be required to perform any of 

the obligations herein or would have the option to undertake or demonstrate compliance 

in an alternative or different manner, BPP may petition the Court for relief from any such 

requirements, in accordance with Fed. R. Civ. P. 60. However, if BPP applies to the 

Court for relief under this Paragraph, the United States reserves the right to seek to void 

all or part of the Resolution of Liability reflected in Part XVII (“Effect of Settlement”). 

Nothing in this Paragraph is intended to enlarge the Parties’ rights under Fed. R. Civ. P. 

60, nor is this Paragraph intended to confer on any Party any independent basis, outside 

of Fed. R. Civ. P. 60, for seeking such relief. 

204. Alternative Monitoring Plans. If, for any monitoring required by this 

Consent Decree (other than CEMS), BPP submits an AMP to EPA for approval, then 

BPP shall comply with the proposed AMP pending EPA’s approval or disapproval of the 

submitted AMP. If an AMP is not approved, then within ninety (90) Days of BPP’s 

receipt of disapproval, BPP will submit to EPA for approval a plan and schedule that 

provide for compliance with the applicable monitoring requirements as soon as 

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practicable. Such plan may include physical or operational changes to the equipment, or 

additional or different monitoring. 

205. Service of Process. BPP hereby agrees to accept service of process by 

mail with respect to all matters arising under or relating to this Consent Decree and to 

waive the formal service requirements set forth in Fed. R. Civ. P. 4 and any applicable 

local rules of this Court, including, but not limited to, service of a summons. 

206. Post-Lodging, Pre-Entry Obligations. Obligations of BPP under this 

Consent Decree to perform duties after the Date of Lodging but prior to the Date of Entry 

shall be legally enforceable only on or after the Date of Entry. Liability for stipulated 

penalties, if applicable, shall accrue for violations of such obligations, and the United 

States may demand payment as provided in the Decree, provided that stipulated penalties 

accruing between the Date of Lodging and the Date of Entry may not be collected unless 

and until this Decree is entered by the Court. 

207. Costs. Each Party to this action shall bear its own costs and attorneys’ 

fees. 

208. Public Documents. All information and documents submitted by BPP 

pursuant to this Consent Decree shall be subject to public inspection in accordance with 

applicable federal law, unless subject to legal privileges or protection, or identified and 

supported as trade secrets or confidential business information in accordance with the 

applicable federal statutes or regulations. 

209. Public Notice and Comment. The Parties agree to this Consent Decree 

and agree that this Consent Decree may be entered upon compliance with the public 

notice procedures set forth at 28 C.F.R. § 50.7, and upon notice to the Court from the 

United States Department of Justice requesting entry of this Consent Decree. The United 

States reserves the right to withdraw or withhold its consent to this Consent Decree at any 

time prior to the Date of Entry if public comments disclose facts or considerations 

indicating that this Consent Decree is inappropriate, improper, or inadequate. 

210. Notice. Unless otherwise provided herein, notifications to or 

communications between the Parties shall be deemed submitted on the date they are 

postmarked and sent by U.S. Mail or overnight mail, postage prepaid, or to EPA by 

electronic mail as provided below, except for notices under Part XV (“Force Majeure”) 

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and Part XVI (“Retention of Jurisdiction/Dispute Resolution”), which shall be sent by 

overnight mail or by certified or registered mail, return receipt requested. Notifications 

to or communications mailed to BPP shall be deemed to be received on the earlier of (i) 

actual receipt by BPP or (ii) receipt of an electronic version sent to the addressees set 

forth in this Paragraph. Each report, study, notification, or other communication of BPP 

shall be submitted as specified in this Consent Decree. If the date for submission of a 

report, study, notification, or other communication falls on a Saturday, Sunday or federal 

holiday, the report, study, notification, or other communication will be deemed timely if 

it is submitted the next Working Day. Except as otherwise provided herein, all reports, 

notifications, certifications, or other communications required or allowed under this 

Consent Decree shall be addressed as follows: 

As to the United States: 

Chief 

Environmental Enforcement Section 

Environment and Natural Resources Division 

U.S. Department of Justice 

P.O. Box 7611 

Ben Franklin Station 

Washington, DC 20044-7611 

Reference Case No. 90-5-2-1-09244 

As to EPA Headquarters: 

Electronic submissions (and, if necessary, hard-copy submissions) shall be 

addressed to: 

Director, Air Enforcement Division
 

Office of Civil Enforcement (2242A) 

Office of Enforcement and Compliance Assurance 

U.S. Environmental Protection Agency 

1200 Pennsylvania Ave., N.W.
 

Washington, D.C. 20004 

and submitted electronically to: 

csullivan@matrixneworld.com 

foley.patrick@epa.gov 

Submissions not delivered electronically shall be sent to the address above and to: 

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Director, Air Enforcement Division
 

Office of Civil Enforcement
 

c/o Matrix New World Engineering, Inc. 

120 Eagle Rock Ave., Suite 207 

East Hannover, NJ 07936-3159 

As to EPA Region 5: 

Hard-copy and electronic submissions shall be addressed to: 

Compliance Tracker (AE-17J) 

Air Enforcement and Compliance Assurance Branch 

U.S. EPA, Region 5 

77 W. Jackson Blvd. 

Chicago, IL 60604 

and 

Office of Regional Counsel 

U.S. EPA, Region 5 

77 West Jackson Blvd. (C-14J) 

Chicago, IL 60604 

and submitted electronically to: 

csullivan@matrixneworld.com 

Submissions not delivered electronically shall be sent to the address above. 

As to the State of Indiana: 

Office of the Indiana Attorney General 

Environmental Litigation Division 

Indiana Government Center South- Fifth Floor 

302 West Washington Street 

Indianapolis, IN 46204 

Chief, Air Compliance and Enforcement Branch 

Indiana Department of Environmental Management 

100 North Senate Avenue 

MC 61-53, IGCN 1003 

Indianapolis, IN 46204-2251 

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As to BPP: 

Refinery Manager 

BPP Whiting Refinery 

2815 Indianapolis Blvd. 

Whiting, Indiana 46394 

HSSE Manager 

BPP Whiting Refinery 

2815 Indianapolis Blvd. 

Whiting, Indiana 46394 

Managing Attorney – HSSE 

BP America, Inc.
 

150 W. Warrenville Road 

Mail Code 200-1W 

Naperville, Illinois 60563 

and submitted electronically to: 

Whiting.CD.Tracker@bp.com 

Any Party may change either the notice recipient or the address for providing 

notices to it by serving the other Party with a notice setting forth such new notice 

recipient or address. In addition, the nature and frequency of reports required by this 

Consent Decree may be modified by mutual consent of the Parties. The consent of the 

United States to such modification must be in the form of a written notification from 

EPA, but need not be filed with the Court to be effective. 

211. Approvals. All EPA approvals or comments required under this 

Consent Decree shall be in writing. 

212. Paperwork Reduction Act. The information required to be maintained 

or submitted pursuant to this Consent Decree is not subject to the Paperwork Reduction 

Act of 1980, 44 U.S.C. § 3501 et seq. 

213. Modification. This Consent Decree contains the entire agreement of 

the Parties and will not be modified by any prior oral or written agreement, 

representation, or understanding. Non-material modifications to this Consent Decree will 

be effective when signed by the United States and BPP. The United States will file nonmaterial modifications with the Court on a periodic basis. For purposes of this 

Paragraph, non-material modifications include, but are not limited to, modifications to the 

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frequency of reporting obligations and modifications to schedules that do not extend the 

date for compliance with emissions limitations following the installation of control 

equipment, provided that such changes are agreed upon in writing between the United 

States and BPP. Material modifications to this Consent Decree will be in writing, signed 

by the Parties, and will be effective upon approval by the Court. Specific provisions in 

this Consent Decree that govern specific types of modifications shall be effective as set 

forth in the specific provision governing the modification. 

214. Effect of Shutdown. The permanent Shutdown of an emissions unit or 

equipment and the surrender of all permits for that emissions unit or equipment shall be 

deemed to satisfy all requirements of this Consent Decree applicable to that emissions 

unit or equipment on and after the later of: (i) the date of the permanent Shutdown of the 

emissions unit or equipment; and (ii) the date of the surrender of all permits applicable to 

the unit or piece of equipment. The permanent Shutdown of the Whiting Refinery and 

the surrender of all air permits for the Refinery shall be deemed to satisfy all 

requirements of this Consent Decree applicable to the Refinery on and after the later of: 

(i) the date of the Shutdown of the Refinery; or (ii) the date of the surrender of all air 

permits 

XVII. TERMINATION 

215. Certification of Completion: Applicable Sections. Prior to moving for 

termination under Paragraph 220, BPP may seek to certify completion of one or more of 

the following Sections/Parts of the Consent Decree. 

a. Part V, Sections A through E - Fluid Catalytic Cracking Units (including 

operation of the units for one (1) year in compliance with the final emission limits 

established pursuant to this Consent Decree); 

b. Part V, Section F – NOx Emissions Reductions from Heaters and Boilers 

(including operation of the relevant units for one (1) year after installation of 

required emission controls and compliance with applicable emission limits 

established pursuant to this Consent Decree); 

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c. Part V, Section G – SO2 Emissions Reductions from Heaters and Boilers 

(including operation of the relevant units for one (1) year after completion in 

compliance with the emission limits established pursuant to this Consent Decree); 

d. Part V, Section H – Fuel Gas Sulfur Content (including operation of the 

relevant units for one (1) year after completion in compliance with the emission 

limits established pursuant to this Consent Decree); 

e. Part V, Sections I through K – CEMS Downtime, Benzene NESHAP and 

LDAR; 

f. Part V, Section L – Sulfur Recovery Plant (including operation of the 

relevant units for one (1) year after completion in compliance with the emission 

limits established pursuant to this Consent Decree); 

g. Part V, Section M – Tanks (including operation of the relevant units for 

one (1) year after completion in compliance with the emission limits established 

pursuant to this Consent Decree); 

h. Part V, Section N – Coker (including operation of the relevant units for 

one (1) year after completion in compliance with the emission limits established 

pursuant to this Consent Decree); and 

i. Part V, Section O and Appendix D – Flares; (including operation of the 

relevant units for one (1) year after completion in compliance with the flare 

efficiency requirements and the flare flow cap established pursuant to this 

Consent Decree); and; 

j. Part VII – Supplemental Environmental Project and Additional Injunctive 

Relief. 

216. Certification of Completion: BPP Actions. If BPP concludes that any 

of the Section(s) or Part(s) identified in Paragraph 215 have been completed, BPP may 

submit a written report to EPA and IDEM describing the activities undertaken and 

certifying that the applicable Section(s) or Part(s) have been completed in full satisfaction 

of the requirements of this Consent Decree, and that BPP is in substantial and material 

compliance with the relevant Section of the Consent Decree. The report will contain the 

following statement, signed by a responsible corporate official of BPP. 

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“I certify under penalty of law that this information was prepared under 

my direction or supervision by personnel qualified to properly gather and 

evaluate the information submitted. Based on my directions and after 

reasonable inquiry of the person(s) directly responsible for gathering the 

information, the information submitted is, to the best of my knowledge 

and belief, true, accurate and complete.” 

217. Certification of Completion: EPA Actions. Upon receipt of BPP’s 

certification, EPA will notify BPP whether the requirements set forth in the applicable 

Section(s) or Part(s) have been completed in accordance with this Consent Decree: 

a. If EPA concludes that the requirements have not been fully 

complied with, EPA will notify BPP as to the activities that must be undertaken to 

complete the applicable Section. BPP will perform all activities described in the 

notice, subject to its right to invoke the dispute resolution procedures set forth in 

Part XVI (“Dispute Resolution”); and/or 

b. If EPA concludes that the requirements of the applicable Section 

or Part have been completed in accordance with this Consent Decree, EPA will so 

certify in writing to BPP. This certification will constitute the certification of 

completion of the applicable Section or Part for purposes of this Consent Decree. 

The parties recognize that ongoing obligations under such Sections remain and 

necessarily continue (e.g., reporting, recordkeeping, training, auditing requirements), and 

that BPP’s certification is that it is in current compliance with all such obligations. 

218. Certification of Completion: No Impediment to Stipulated Penalty 

Demand. Nothing in Paragraphs 216 and 217 will preclude the United States from 

seeking stipulated penalties for a violation of any of the requirements of the Consent 

Decree regardless of whether a Certification of Completion has been issued under 

Subparagraph 217.b. In addition, nothing in this Paragraph will permit BPP to fail to 

implement any ongoing obligations under the Consent Decree regardless of whether a 

Certification of Completion has been issued. 

219. Termination: Conditions Precedent. This Consent Decree will be 

subject to termination upon motion by the Parties or upon motion by BPP acting alone 

under the conditions identified in this Paragraph. Prior to seeking termination, BPP must 

have completed and satisfied all of the following requirements of this Consent Decree: 

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a. Installation of control technology systems as specified in this Consent 

Decree; 

b. Compliance with all provisions contained in this Consent Decree; such 

compliance may be established for specific parts of the Consent Decree in 

accordance with Paragraphs 216 and 217; 

c. Payment of all penalties and other monetary obligations due under the 

terms of the Consent Decree; unless all penalties and/or other monetary 

obligations owed to the United States or the State of Indiana are fully paid as of 

the time of the motion; 

d. Satisfaction of Part VII (“Supplemental Environmental Projects and 

Additional Injunctive Relief”); 

e. Application for and receipt of permits incorporating the emission limits 

and standards established under this Consent Decree; and 

f. For parts of the Consent Decree for which Certificates of Compliance 

have not been issued in accordance with Paragraphs 216 and 217, operation for at 

least one (1) year of each unit in compliance with the emission limits established 

herein and certification of such compliance for each unit within the first progress 

report following the conclusion of the compliance period. 

220. Termination: Procedure. At such time as BPP believes that it has 

satisfied the requirements for termination set forth in Paragraph 219, BPP will certify 

such compliance and completion to the United States and the State of Indiana in 

accordance with the certification language of Paragraph 216. Unless either the United 

States or the State of Indiana objects in writing with specific reasons within 120 days of 

receipt of BPP certification under this Paragraph, the Court may upon motion by BPP 

order that this Consent Decree be terminated. If either the United States or the State of 

Indiana objects to the certification by BPP, then the matter will be submitted to the Court 

for resolution under Part XVI (Retention of Jurisdiction/Dispute Resolution). In such 

case, BPP will bear the burden of proving that this Consent Decree should be terminated. 

221. Optional Provision for Termination of Part V, Sections F and G 

(Heaters and Boilers). At any time after installation of all controls required by, and 

operation for one (1) year in compliance with the emission limits established pursuant to, 

123
 
 


 


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Part V, Sections F and G, BPP may move for termination of Part V, Sections F and G, as 

provided in this Paragraph: 

a. BPP shall prepare and submit to EPA and IDEM a Certification of 

Completion as provided in Paragraph 216 covering Part V, Sections F and G. 

b. In its Certification, BPP shall certify or demonstrate (as applicable) that it 

has satisfied the requirements of Paragraphs219.a, 219.b, 219.c, 219.e and 219.f 

that are applicable to the requirements of Part V, Sections F and G. 

i. With respect to the requirement in Paragraph 219.c for the 

payment of penalties and monetary obligations, BPP shall certify that it 

has complied with the requirements of Part IX (“Civil Penalty”) and Part 

X, Sections F and G (“Stipulated Penalties”). 

ii. With respect to the requirement in Paragraph 219.e for the 

application and receipt of permits incorporating the emission limits and 

standards established under this Consent Decree, BPP shall include copies 

of the relevant portions of all applicable permits as required by Part V, 

Section P (“Incorporation of Consent Decree Requirements into Federally 

Enforceable Permits”). 

c. EPA shall review and respond to BPP’s Certification of Completion for 

Part V, Sections F and G as provided in Paragraph 217. If EPA concludes that the 

requirements of Part V, Sections F and G have been completed, EPA shall so 

notify BPP in lieu of certifying pursuant to Paragraph 217.b, and the Parties shall 

proceed to terminate Part V, Sections F and G as provided in Paragraph220. 

d. Certification of Completion: No Impediment to Stipulated Penalty 

Demand. Nothing in this Paragraph will preclude the United States from seeking 

stipulated penalties for a violation of any of the requirements of Part V, Sections 

F or G regardless of whether a Certification of Completion has been issued under 

Subparagraph 221.c. In addition, no other provision of this Consent Decree may 

be terminated pursuant to this Paragraph. 

124
 
 

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222. Each of the undersigned representatives certifies that she or he is fully 

authorized to enter into this Consent Decree on behalf of the applicable Party, and to 

execute and to bind such Party to this Consent Decree. 

XVIII. INTEGRATION 

223. This Consent Decree constitutes the final, complete, and exclusive 

agreement and understanding among the Parties with respect to the settlement embodied 

in the Consent Decree and supersedes all prior agreements and understandings, whether 

oral or written, concerning the settlement embodied herein. No other document, nor any 

representation, inducement, agreement, understanding, or promise, constitutes any part of 

this Consent Decree or the settlement it represents, nor shall it be used in construing the 

terms of this Consent Decree. Headings and Summaries in this Consent Decree are 

provided for convenience only and shall not affect the substance of any provision. 

XIX. SIGNATORIES 

224. Each of the undersigned representatives certifies that she or he is fully 

authorized to enter into this Consent Decree on behalf of the applicable Party, and to 

execute and to bind such Party to this Consent Decree. 

Dated and entered this _______ day of ________________, 2012. 

UNITED STATES DISTRICT JUDGE 

125
 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

Date: ~~ ~Z---

Date: ~ (Y~ `~"

Date: `~ ((~ 1

FOR PLAINTIFF THE UNITED STATES OF

AMERICA:

I ACIA S. MORENO

Assistant Attorney General

Environment and Natural Resources Division

United States Department of Justice

SUSAN AKERS

Senior Attorney

Environmental Enforcement Section

Environment and Natural Resources Division

United States Department of Justice

P.O. Box 7611

Washington, DC 20044-7611

STEVEN D. SHERMER

Trial Attorney

Environment and Natural Resources Division

United States Department of Justice

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 130 of 325 page 130 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North AmeNica (N.D. Ind.).

Date: -~ Z$ l Z

Date: ! L Y

Date: 2! ~ ~' (Z

FOR THE UNITED STATES

ENVIRONMENTAL PROTECTION AGENCY:

~I

C H A GILES

Assi an Administrator

Office of Enforcement and Compliance Assurance

United States Environmental Protection Agency

Washington, D.C. 20460

PAMELA J. M KAS

Acting Director, Office of Civil Enforcement

Office of Enforcement and Compliance Assurance

United States Environmental Protection Agency

Washington, D.C. 20460

JOHN FO ARl`Y'Y

Associ irector, Office of Civil Enforcement

Office of Enforcement and Compliance Assurance

United States Environmental Protection Agency

Washington, D.C. 20460

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 131 of 325 page 131 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

Date: !~~h l b , Za I Z

Date: ~ ~~, , ~Cj ~~

Date: `L- ~ ( ~L--

FOR THE UNITED STATES

ENVIRONMENTAL PROTECTION AGENCY,

REGION 5:

SUSAN HEDMAN

US EPA Region 5

Ralph Metcalfe Federal Building

77 West Jackson Blvd.

Chicago, IL 60604-3590

R BERT A. KAPLAN

Regional Counsel

US EPA Region 5

Ralph Metcalfe Federal Building

77 West Jackson Blvd.

Chicago, IL 60604-3590

WILLIAM WAG

US EPA Region 5

Ralph Metcalfe Federal Building

77 West Jackson Blvd.

Chicago, IL 60604-3590

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 132 of 325 page 132 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

Date: ~e„~ ~L~, Z o I Z

Date: ~ ~ ~ ~Z

Date: ~J'/°R/L 27 ~JZ_

FOR THE STATE OF INDIANA:

GREGORY F. ZOELLER

Indiana Attorney General

PATRICIA ORLOFF ERDMANN

Chief Counsel of Litigation

Office of the Attorney General

Indiana Government Center South, 5th Floor

402 West Washington Street

Indianapolis, Indiana 46204

ALERIE A HTIRIS

Deputy Attorney General

Office of the Attorney General

Environmental D~i~on

.EASTERLY

Commissioner

Indiana Department of Environmental

Management

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Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

Date: ~ ~~~~1~

FOR PLAINTIFF-INTERVENOR THE

SIERRA CLITB: ./~

ISAVID MAIDENBERG~

Director, Sierra Club Ho ier Chapter

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Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

FOR PLAINTIFF-INTERVENOR SAVE THE

DUNES CONSERVATION FUND, INC., DB/A

SAVE THE DUNES:

/ ~~ ~

Date: 2/27/ l 2

NICOLE BARKER

Executive Director

Save the Dunes

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 135 of 325 page 135 of 324 
 

 

 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 136 of 325 page 136 of 324 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED 

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP 

Products North America (N.D. Ind.). 

FOR PLAINTIFF-INTERVENOR THE 

NATURAL RESOURCES DEFENSE 

COUNCIL: 

Date: ____2/27/12_________________ _______________________________________ 

HENRY HENDERSON 

Director, Midwest Program 

Natural Resources Defense Council 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products Noy°th America (N.D. Ind.).

Date: (~ 3 L ~O o20 I Z.

FOR PLAINTIFF-INTERVENOR THE

ENVIRONMENTAL INTEGRITY PROJECT:

G c,~~

ERIC SCHAEFFER

Executive Director

Environmental Integrity

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 137 of 325 page 137 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

FOR PLAINTIFF-INTERVENOR THE

ENVIRONMENTAL LAW AND POLICY

CENTER:

Date: 3 ~ S 2d lZ

HOWARD A. LEARNER

President and Executive Director

Environmental Law and Policy Center

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 138 of 325 page 138 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, Tf~ UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

Date:

FOR PLAINTIFF-INTERVENOR SUSAN

ELEUTERIO:

C

SUSAN ELEUT'ERIO

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 139 of 325 page 139 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

FOR PLAINTIFF-INTERVENOR TOM

TSOURLIS:

Date: !~3 --- l ~ 

c_. 12 /lh.~. _ ~L2~

TOM TSOURLIS

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 140 of 325 page 140 of 324 
 

Subject to the notice and comment provisions of 28 C.F.R. § 50.7, THE UNDERSIGNED

PARTIES enter into this Consent Decree entered in the matter of United States, et al., v. BP

Products North America (N.D. Ind.).

FOR DEFENDANT BP PRODUCTS NORTH

AMERICA INC.:

Date: ~~r~~. C:~~ <~ot ~

EV .0 KNELL

President

BP Products North America Inc.

Date: ~~` S, ~-o (~ ~c/~~S ✓`~ .~„ .5L

JAMES A. NOLAN, Jr., ES

Managing Counsel-HSSE

BP America, Inc.

Date: ~e~~ ~-~ ~ 20~ Z ~'~~'~

J L M. GROSS, ESQ.

Arnold &Porter LLP

Date: ~./~ li ~ ~ ~"1~ctr~~~j 1 ~~S Y ZC f Z :~~`~ C= l

WILLIAM L. PATBERG, E

Shumaker, Loop &Kendrick, L

ATTORNEYS FOR BP PRODUCTS NORTH

AMERICA INC.

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case 2:12-cv-00207-PPS-APR document 7-1 filed 09/18/12 page 142 of 325 

 


 
 
 


 
 


case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 143 of 325 page 142 of 324 APPENDIX A 

LOCATION OF FUEL GAS SULFUR MONITORS

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APPENDIX B
 

ENHANCED LDAR PROGRAM 

Definitions: 

1.	 The definitions set forth in the Consent Decree shall apply for purposes of 

this Appendix B. For purposes of this Appendix B to the Consent Decree, 

the following definitions shall also apply: 

a.	 “Certified Low-Leaking Valves” shall mean valves for which a 

manufacturer has issued either: (i) a written guarantee that the valve 

will not leak above 100 parts per million (ppm) for five years; or (ii) a 

written guarantee, certification or equivalent documentation that the 

valve has been tested pursuant to generally-accepted good engineering 

practices and has been found to be leaking at no greater than 100 ppm. 

b. “Certified Low-Leaking Valve Packing Technology” shall mean valve 

packing technology for which a manufacturer has issued either: (i) a 

written guarantee that the valve packing technology will not leak 

above 100 ppm for five years; or (ii) a written guarantee, certification 

or equivalent documentation that the valve packing technology has 

been tested pursuant to generally-accepted good engineering practices 

and has been found to be leaking at no greater than 100 ppm. 

c.	 “Covered Equipment” shall mean all pumps and valves, in light liquid, 

heavy liquid, or gas/vapor service in all Covered Process Units. 

d.	 “Covered Process Units” shall mean any process unit that is, or under 

the terms of this Consent Decree becomes, subject to the equipment 

leak provisions of 40 C.F.R. Part 60, Subpart GGGa. 

e.	 “DOR” shall mean Delay of Repair. 

f.	 “ELP” shall mean the Enhanced Leak Detection and Repair Program 

specified in this Appendix B. 

g. “Equipment” shall mean any equipment as defined in 40 C.F.R. § 

60.591a. 

h.	 “LDAR” shall mean Leak Detection and Repair. 

i.	 “LDAR Audit Commencement Date” or “Commencement of an 

LDAR Audit” shall mean the first day of the on-site inspection that 

accompanies an LDAR audit. 

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j. “LDAR Audit Completion Date” or “Completion of an LDAR Audit” 

shall mean one hundred twenty (120) calendar Days after the LDAR 

Audit Commencement Date. 

k. “Maintenance Shutdown” shall mean a shutdown of a Covered Process 

Unit that lasts longer than 30 calendar days. 

l. “Method 21” shall mean the test method found at 40 C.F.R. Part 60, 

Appendix A, Method 21. 

m. “Repair Verification Monitoring” shall mean the utilization of 

monitoring (or another method that indicates the relative size of the 

leak) by no later than the end of the next calendar day of each attempt 

at repair of a leaking piece of Covered Equipment to achieve the best 

repair/lowest emission rate possible. 

n.	 “Screening Value” shall mean the highest emission level that is 

recorded at each piece of Covered Equipment as it is monitored in 

compliance with Method 21. 

Part A: General 

2.	 The requirements of the ELP shall apply to all Covered Equipment. In 

addition, the requirements of Paragraphs 3, 23, 26.a., 26.b., 27-28, 31 

(except the non-federally enforceable provisions of Paragraph 31.c), and 

32 of this Appendix shall also apply to all Equipment at the Whiting 

Refinery that is regulated under any federal, state, or local LDAR 

program. The requirements of this ELP are in addition to, and not in lieu 

of, the requirements of any federal, state or local LDAR regulation that 

may be applicable to a piece of Covered Equipment. If there is a conflict 

between a federal, state or local LDAR regulation and this ELP, BPP shall 

follow whichever regulation is more stringent. 

3.	 By no later than sixty (60) Days after the Date of Entry, BPP shall develop 

a written facility-wide LDAR Program that describes: (i) its facility-wide 

LDAR program (e.g., applicability of regulations to process units and/or 

specific Equipment; leak definitions; monitoring frequencies); (ii) a 

tracking program (e.g., Management of Change) that ensures that new 

pieces of Equipment added to the Whiting Refinery for any reason are 

integrated into the LDAR program and that pieces of Equipment that are 

taken out of service are removed from the LDAR program; (iii) the roles 

and responsibilities of all employee and contractor personnel assigned to 

LDAR functions at the Whiting Refinery; (iv) how the number of 

personnel dedicated to LDAR functions is sufficient to satisfy the 

requirements of the LDAR program; and (v) how the Whiting Refinery 

plans to implement this ELP. BPP shall review this document on an 

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annual basis and update it as needed by no later than December 31 of each 

year, beginning December 31, 2012. 

Part B: Monitoring Frequency 

4.	 By no later than the Date of Entry, for all Covered Equipment, BPP shall 

comply with the monitoring frequency for valves as required by 40 C.F.R. 

§ 60.482-7a, 40 C.F.R. § 60.482-4a, 40 C.F.R. § 60.482-8a, and 40 C.F.R. 

§ 60.482-10a, except as provided in 40 C.F.R. § 60.482-1a, and for pumps 

as required by 40 C.F.R. § 60.482-2a. and 40 C.F.R. § 60.482-8a. 

5. Alternative Standards for Valves – Skip Period Leak Detection and 

Repair. BPP may elect to comply with the skip period monitoring 

requirements set forth in 40 C.F.R. § 60.483-2a, if applicable. 

Part C: Monitoring Methods and Equipment 

6. Method 21 and Alternative Work Practice Monitoring. 

a. Except as provided in subparagraph 6.b., by no later than the Date of 

Entry, for all Covered Equipment, BPP shall comply with Method 21 

in performing LDAR monitoring, using a Toxic Vapor Analyzer 

1000B Flame Ionization Detector (FID) attached to a data logger, or 

equivalent equipment, which directly electronically records the 

Screening Value detected at each piece of Covered Equipment, the 

date and time that each Screening Value is taken, and the identification 

numbers of the monitoring instrument and technician. BPP shall 

transfer this monitoring data to an electronic database on at least a 

weekly basis for recordkeeping purposes. Notwithstanding the 

foregoing, BPP may use paper logs where necessary or more feasible 

(e.g., small rounds, re-monitoring, or when data loggers are not 

available or broken). Any manually recorded monitoring data shall be 

transferred to the electronic database within 7 days of monitoring. 

b. Alternative Work Practice. 

(i)	 From the Date of Entry, BPP may utilize the Alternative Work 

Practice as defined at 40 C.F.R. 60.18(g) (“the AWP”) for 

monitoring Equipment that meets the “difficult to monitor” 

criteria set out at 40 C.F.R. § 60.482-7a(h)(1). 

(ii) No sooner than three (3) years from the Date of Entry, BPP 

may submit a request for review and approval of an AWP for 

LDAR monitoring of all Covered Equipment. Such request 

shall include a protocol that, at a minimum, addresses the 

following operational criteria: 

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(A) calibration procedures; 

(B) startup (i.e., warming-up the Optical Gas Imaging 

(OGI) Instrument)/shutdown procedures; 

(C) video recording and storage; 

(D) site-specific impact of weather conditions (e.g.,

 wind speed, temperature, and visibility); 

(E) maintenance of the OGI Instrument; 

(F) certification of personnel to use the OGI instrument; 

(G) minimum number of hours of field use by certified 

personnel prior to certified personnel performing 

compliance monitoring; and 

(H) identification of process unit(s) where certified 

personnel may monitor with an OGI instrument. 

If such request is approved by EPA, BPP may utilize the AWP for 

monitoring all Covered Equipment. 

7. BPP shall conduct all calibrations of LDAR monitoring equipment as 

required by Subpart GGGa in accordance with 40 C.F.R. Part 60, EPA 

Reference Test Method 21, prior to each time LDAR monitoring 

equipment is placed into service before each monitoring shift or is 

restarted during a monitoring shift, except as provided below. BPP shall 

conduct calibration drift assessment rechecks of the LDAR monitoring 

equipment at the end of each monitoring shift and prior to each time 

LDAR monitoring equipment is turned off during each monitoring shift, 

except when LDAR monitoring equipment is unable to function such that 

the calibration drift assessment recheck cannot be performed before the 

LDAR monitoring equipment turns off. BPP is not required to conduct a 

calibration drift assessment re-check during the same monitoring shift in 

the event of a “flame-out” of the instrument if the instrument can be 

immediately re-ignited. The calibration drift assessment shall be 

conducted using calibration gas as provided in 40 C.F.R. § 60.485a(b)(1) 

with a concentration approximately equal to the applicable internal leak 

definition. If any calibration drift assessment after the initial calibration 

shows a negative drift of more than 10% from the previous calibration, 

BPP shall re-monitor all components that had a reading greater than 250 

ppm. BPP shall retain all calibration records for at least one year, or as 

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otherwise required by any federal state or local law, whichever is most 

stringent. 

Part D: Leak Detection and Repair Action Levels 

8. To the extent required by 40 C.F.R. Part 60, Subpart GGGa, BPP shall 

identify leaks through Method 21 monitoring (or the AWP pursuant to 

Paragraph 6.b.), and audio, visual, and olfactory sensing inspections. 

9. Leak Definitions and Repairs for Valves and Pumps. 

a. By no later than the Date of Entry, for each leak detected at or above 

the leak definition for valves defined at 40 C.F.R. § 60.482-7a(b), BPP 

shall perform repairs in accordance with Paragraphs 11 - 16 of this 

Appendix. 

b. By no later than the Date of Entry, for each leak detected at or above 

the leak definition for pumps defined at 40 C.F.R. §60.482­

2a(b)(1)(ii), BPP shall perform repairs in accordance with Paragraphs 

12 - 16 of this Appendix. 

10. By no later than the Date of Entry, for all Covered Equipment, at any time, 

including outside of periodic monitoring, that a leak is detected through 

audio, visual, or olfactory sensing, BPP must repair the piece of Covered 

Equipment in accordance with 40 C.F.R. Part 60, Subpart GGGa, and with 

Paragraphs 12 - 16 of this Appendix. 

Part E: Leak Repairs 

11. BPP shall make an “initial attempt” at repair on any valve that has a 

reading greater than 100 ppm of VOCs, excluding control valves and other 

valves that LDAR personnel are not authorized to repair. 

12. For each leak subject to Paragraph 9 of this Appendix, by no later than 

five (5) Days after detecting a leak, BPP shall perform a first attempt at 

repair. By no later than fifteen (15) Days after detection, BPP shall 

perform a final attempt at repair or may place the valve or pump covered 

by Paragraph 9 on the Delay of Repair list provided that BPP has 

complied with 40 C.F.R. Part 60, Subpart GGGa and with the 

requirements of Paragraphs 13 – 15 and 17 of this Appendix. 

13. For each attempt at repair as set forth in paragraphs 11 and 12 of this 

Appendix, BPP shall perform Repair Verification Monitoring. 

14. Drill-and-Tap Repairs. 

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a. Except as provided in Subparagraph 14.b, for leaking valves (other than 

control valves), when other repair attempts have failed to reduce 

emissions below the applicable leak definition and BPP is not able to 

remove the leaking valve from service, BPP shall attempt at least one 

drill-and-tap repair (with a second injection of sealant if the first 

injection is unsuccessful at repairing the leak) before placing the valve 

on the DOR list. 

b. Drill-and-tap is not required when there is a major safety, mechanical, 

product quality, or environmental issue with repairing the valve using 

the drill-and-tap method, in which case, BPP shall document the 

reason(s) why any drill-and-tap attempt was not performed prior to 

placing any valve on the DOR list. 

15. For each leak, BPP shall record the following information: the date of all 

repair attempts; the repair methods used during each repair attempt; the 

date, time and Screening Values for all re-monitoring events; and, if 

relevant, the information required under Paragraph 14 and 17 of this 

Appendix for Covered Equipment placed on the DOR list. 

16. Nothing in Paragraphs 12 - 15 of this Appendix is intended to prevent BPP 

from taking a leaking piece of Covered Equipment out of service; 

provided however, that prior to placing the leaking piece of Covered 

Equipment back in service, BPP must repair the leak or must comply with 

the requirements of Part F of this Appendix (Delay of Repair) to place the 

piece of Covered Equipment on the DOR list. 

Part F: Delay of Repair 

17. By no later than the Date of Entry, for all Covered Equipment placed on 

the DOR list, BPP shall require the following: 

a.	 Sign-off from the plant manager, a corporate official responsible for 

environmental management and compliance, a corporate official 

responsible for plant engineering, an operations manager, or an area 

superintendent that the piece of Covered Equipment is technically 

infeasible to repair without a process unit shutdown; 

b.	 Periodic monitoring, at the frequency required for other pieces of 

Covered Equipment of that type in the process unit, of the Covered 

Equipment placed on the DOR list; 

c.	 No more than 0.10% of all valves may be on the DOR list at any one 

time. If a valve (i) is isolated and taken out of VOC and/or HAP 

service at the same time it is placed on the DOR list and is repacked 

with Certified Low-Leaking Valve Packing Technology or is replaced 

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with Certified Low-Leaking Valves before it is placed back into VOC 

and/or HAP service, or (ii) is repacked with Certified Low-Leaking 

Valve Packing Technology or replaced with Certified Low-Leaking 

Valves at the next Maintenance Shutdown, such valve shall not be 

included in computing the applicable percentage limitation of valves 

that may be on the DOR list at any one time; and 

d. Covered Equipment may be removed from the DOR list if is 

monitored at the frequency required for other pieces of Covered 

Equipment of that type in the process unit for two successive 

monitoring periods without detecting a leak greater than the Leak 

Definition as set forth in 40 C.F.R. Part 60, Subpart GGGa for that 

type of Covered Equipment. 

Part G: Valve Replacement/Improvement Program 

18. Commencing no later than the Date of Entry, and continuing until 

termination, BPP shall implement the program set forth in Paragraphs 19 

through 22 of this Appendix to replace and/or improve the emissions 

performance of the valves in each Covered Process Unit.

 19. Valves. 

a. By no later than the Date of Entry: 

(i) BPP shall implement modified purchasing procedures that 

evaluate the availability of valves and valve packing that meet 

the requirements for a Certified Low-Leaking Valve or 

Certified Low-Leaking Valve Packing Technology at the time 

that the valves and/or valve packing is acquired. 

(ii) Except as provided in Paragraph 20, BPP shall install valve 

packing material that meets the requirements for Certified 

Low-Leaking Valve Packing Technology whenever repacking 

any valve in gas/vapor or light liquid VOC service in a 

Covered Process Unit. 

b. By no later than 90 days after the Date of Entry (except as provided in 

Paragraph 20), BPP shall ensure that each new valve in gas/vapor or 

light liquid VOC service that it purchases for use in any Covered 

Process Unit either is a Certified Low-Leaking Valve or is fitted with 

Certified Low-Leaking Valve Packing Technology. 

c. By no later than the dates specified below (except as provided in 

Paragraph 20), BPP shall ensure that each new valve in gas/vapor or 

light liquid VOC service that it installs in any Covered Process Unit 

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either is a Certified Low-Leaking Valve or is fitted with Certified 

Low-Leaking Valve Packing Technology: 

(i) For all Process Units other than the new Coker and the new 

GOHT, by no later than 18 months after Date of Entry; and 

(ii) For the new Coker and the new GOHT, by no later than 24 

months after Date of Entry. 

d. Replacing or Repacking Existing Valves that have Screening Values 

At or Above 5,000 ppm. Except as provided in Paragraph 20, for each 

Existing Valve in each Covered Process Unit that has a Screening 

Value at or above 5,000 ppm during any monitoring event, BPP shall 

replace or repack the Existing Valve with a Certified Low-Leaking 

Valve or with Certified Low-Leaking Valve Packing Technology. 

BPP shall undertake this replacement or repacking by no later than 30 

days after the monitoring event that triggers the replacement or 

repacking requirement, unless the replacement or repacking requires a 

process unit shutdown. If the replacement or repacking requires a 

process unit shutdown, BPP shall undertake the replacement or 

repacking during the Maintenance Shutdown that follows the 

monitoring event that triggers the requirement to replace or repack the 

valve. If BPP completes the replacement or repacking within 30 days 

of detecting the leak, BPP shall not be required to comply with Part E 

of this Appendix. If BPP does not complete the replacement or 

repacking within 30 days, or if, at the time of the leak detection, BPP 

reasonably can anticipate that it might not be able to complete the 

replacement or repacking within 30 days, BPP shall comply with all 

applicable requirements of Part E of this Appendix. 

20. Commercial Unavailability of a Certified Low-Leaking Valve or Certified 

Low-Leaking Valve Packing Technology. 

a.	 BPP shall not be required to utilize a Certified Low-Leaking Valve or 

Certified Low-Leaking Valve Packing Technology to replace or 

repack a valve if a Certified Low-Leaking Valve or Certified LowLeaking Valve Packing Technology is commercially unavailable in 

accordance with the provisions in Part O of this Appendix. Prior to 

claiming this commercial unavailability exemption, BPP must contact 

a reasonable number of vendors of valves and obtain a written 

representation or equivalent documentation from each vendor that the 

particular valve that BPP needs is commercially unavailable either as a 

Certified Low-Leaking Valve or with Certified Low-Leaking Valve 

Packing Technology. In the Compliance Status Reports due under 

Part N of this Appendix, BPP shall: (i) identify each valve for which it 

could not comply with the requirement to replace or repack the valve 

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with a Certified Low-Leaking Valve or Certified Low-Leaking Valve 

Packing Technology; (ii) identify the vendors it contacted to determine 

the unavailability of such a Valve or Packing Technology; and 

(iii) include the written representations or documentation that BPP 

secured from each vendor regarding the unavailability. 

b.	 Ongoing Assessment of Availability. BPP may use a prior 

determination of Commercial Unavailability of a valve or valve 

packing pursuant to this Paragraph and Part O of this Appendix for a 

subsequent Commercial Unavailability claim for the same valve or 

valve packing (or valve or valve packing in the same or similar 

service), provided that the previous determination was completed 

within the preceding 12-month period. After one year, BPP must 

conduct a new assessment of the availability of a valve or valve 

packing meeting Certified Low-Leaking Valve or Certified LowLeaking Valve Packing Technology requirements. 

21. Records of Certified Low-Leaking Valves and Certified Low-Leaking 

Valve Packing Technology. Prior to installing any Certified LowLeaking Valves or Certified Low-Leaking Valve Packing Technology, 

BPP shall secure from each manufacturer documentation that 

demonstrates that the proposed valve or packing technology meets the 

definition of “Certified Low-Leaking Valve” and/or “Certified LowLeaking Valve Packing Technology.” BPP shall retain that documentation 

for the duration of this Consent Decree and make it available upon 

request. 

22. Valve Replacement/Improvement Report. In each Compliance Status 

Report due under Part N of this Appendix, BPP shall include a separate 

section in the Report that: (i) describes the actions it took to comply with 

this Part G, including identifying each valve that was replaced or 

upgraded; and (ii) identifies the schedule for any future replacements or 

upgrades. 

Part H: Management of Change 

23. Management of Change: For each Management of Change process or 

analysis, BPP shall ensure that each piece of Equipment added to the 

Whiting Refinery or removed from the Whiting Refinery for any reason is 

evaluated to determine if it is or was subject to LDAR requirements and 

that such pieces of Equipment are integrated into or removed from the 

LDAR program. 

Part I: Training 

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24. By no later than six (6) months after the Date of Entry, BPP shall have 

ensured that all employees and contractors responsible for LDAR 

monitoring, maintenance of LDAR monitoring equipment, LDAR repairs, 

and/or any other duties generated by the LDAR program have completed 

training on all aspects of LDAR that are relevant to the person’s duties. 

By that same time, BPP shall develop a training protocol to ensure that 

refresher training is performed once per calendar year and that new 

personnel are sufficiently trained prior to any involvement in the LDAR 

program. 

Part J: Quality Assurance (“QA”)/Quality Control (“QC”) 

25. Daily Certification by Monitoring Technicians. Commencing no later 

than the Date of Entry, on each day that monitoring occurs, at the end of 

such monitoring day to the extent practical but in no case later than the 

next work day for the monitoring technician, BPP shall ensure that each 

monitoring technician certifies that the data collected represents the 

monitoring performed for that day by requiring the monitoring technician 

to sign a form that includes the following certification: 

On [insert date], I reviewed the monitoring data that I 

collected on [insert date] and to the best of my knowledge 

and belief, the data accurately represents the monitoring I 

performed today. 

In lieu of a form for each technician for each day of monitoring, a log 

sheet may be created that includes the certification that the monitoring 

technicians would date and sign each day that the technician collects data. 

26. Commencing by no later than the first full calendar quarter after the Date 

of Entry, during each calendar quarter, at unannounced times, an LDARtrained employee or contractor of BPP, who does not serve as an LDAR 

monitoring technician on a routine basis, shall undertake the following: 

a. review Management of Change documentation for the previous 

calendar quarter, and conduct process unit walk-throughs to determine 

whether all pieces of Equipment identified in the previous calendar 

quarter’s Management of Change documentation as being subject to 

the LDAR program are included in the LDAR database and are 

properly tagged; 

b. during the process unit walk-throughs required by subparagraph 26.a., 

and during such additional walk-throughs as may be necessary to 

assure that all Covered Process Units are reviewed at least once per 

year, conduct spot checks of Equipment to verify that the Equipment 

checked is included in the LDAR database and is properly tagged; 

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c. review the LDAR database to: 

(i) verify that Covered Equipment was monitored at the appropriate 

frequency; 

(ii) verify that proper documentation and sign-offs have been recorded 

for all Covered Equipment placed on the shutdown or DOR list; 

(iii) ensure that repairs have been performed within the required 

timeframe; 

(iv) review monitoring data and Covered Equipment counts (e.g., 

number of pieces of Covered Equipment monitored per Day) for 

feasibility and unusual trends; 

(v) verify that proper calibration records and monitoring instrument 

maintenance information are stored and maintained; 

d. conduct spot checks of LDAR program records to verify that those 

records are maintained as required; and 

e. observe each LDAR monitoring technician in the field to ensure 

monitoring is being conducted as required. 

BPP shall correct any deficiencies detected or observed as soon as 

practicable. BPP shall maintain a log that: (i) records the date and time 

that the reviews, verifications, and observations required by this Paragraph 

were undertaken; and (ii) describes the nature and timing of any corrective 

actions taken. 

Part K: LDAR Audits and Corrective Action 

27. BPP shall conduct LDAR audits pursuant to the schedule in Paragraph 28 

and the requirements of Paragraph 29 of this Appendix. BPP shall retain a 

third-party with experience in conducting LDAR audits to conduct no less 

than the initial audit and follow-up audits every two (2) years until 

termination of the Consent Decree. To perform the third-party audit, BPP 

shall select a different company than its regular LDAR contractor. At its 

discretion, in years in which BPP is not required to retain a third-party 

auditor, BPP may conduct the audit internally by using its own personnel, 

provided that the personnel BPP uses are not employed at the Whiting 

Refinery but rather are employed at a facility that currently uses Certified 

Low-Leaking Valve and/or Certified Low-Leaking Valve Packing 

Technology. All such internal audits must be conducted by personnel 

familiar with regulatory LDAR requirements and this ELP. 

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28. Internal LDAR Audits. Until termination of this Consent Decree, BPP 

shall ensure that an LDAR audit at the Whiting Refinery is conducted by 

an independent contractor with expertise in LDAR program requirements 

to perform a third party audit for all regulatory LDAR requirements and 

this ELP every twenty-four (24) months in accordance with the following 

schedule: for the first LDAR audit at the Whiting Refinery, the LDAR 

Audit Commencement Date shall be no later than the second calendar 

quarter after the Date of Entry. For each subsequent LDAR audit, the 

LDAR Audit Completion Date shall occur within the same calendar 

quarter that the first LDAR Audit Completion Date occurred. 

29. Each LDAR audit shall include but not be limited to reviewing 

compliance with all applicable regulations, reviewing and/or verifying the 

same items that are required to be reviewed and/or verified in Paragraph 

26 of this Appendix, and performing the following activities for Covered 

Equipment: 

a. Calculating a Comparative Monitoring Audit Leak Percentage. 

Covered Equipment, excluding pumps and valves in heavy liquid 

service, shall be monitored to calculate a leak percentage for each 

Covered Process Unit broken down by Covered Equipment type (i.e., 

valves and pumps). The monitoring that takes place during the audit 

shall be called “comparative monitoring” and the leak percentages 

derived from the comparative monitoring shall be called the 

“Comparative Monitoring Audit Leak Percentage.” Until termination 

of this Consent Decree, BPP shall conduct a comparative monitoring 

audit pursuant to this Paragraph during each LDAR audit. Each 

Covered Process Unit at the Whiting Refinery that is not the subject of 

the current audit shall have a comparative monitoring audit at least 

once before a previously-audited Covered Process Unit is audited 

again. 

b. Calculating the Historic, Average Leak Percentage from Prior Periodic 

Monitoring Events. For the Covered Process Unit that is audited, the 

historic average leak percentage from prior monitoring events, broken 

down by Covered Equipment type (i.e., valves and pumps) shall be 

calculated. The following number of complete monitoring periods 

immediately preceding the comparative monitoring audit shall be used 

for this purpose: valves - 2 periods; and pumps - 12 periods. 

c. Calculating the Comparative Monitoring Leak Ratio. For the Covered 

Process Unit that is audited, the ratio of the comparative monitoring 

audit leak percentage from Paragraph 29.a to the historic average leak 

percentage from Paragraph 29.b shall be calculated. If a calculated 

ratio yields an infinite result, BPP shall assume one leaking piece of 

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Covered Equipment was found in the process unit through its routine 

monitoring during the 12-month period before the audit, and the ratio 

shall be recalculated. 

In addition to these items, LDAR audits after the first audit shall 

include reviewing the Whiting Refinery’s compliance with this ELP. 

30. When More Frequent Periodic Monitoring is Required. If a comparative 

monitoring audit leak percentage calculated pursuant to Paragraph 29.a 

triggers a more frequent monitoring schedule under any applicable federal, 

state, or local law or regulation than the frequencies listed in Paragraphs 4, 

5 or 6 of Part B of this Appendix for the equipment type in that Covered 

Process Unit, BPP shall monitor the affected type of Covered Equipment 

at the greater frequency unless and until less frequent monitoring is again 

allowed under the specific federal, state, or local law or regulation. At no 

time may BPP monitor at intervals less frequently than those in the 

applicable Paragraph in Part B of this Appendix. 

31. Corrective Action Plan. 

a.	 Requirements of a CAP. By no later than 30 days after each LDAR 

Audit Completion Date, BPP shall develop a preliminary corrective 

action plan (“CAP”) if the results of an LDAR audit identify any 

deficiencies or if the Comparative Monitoring Leak Ratio calculated 

pursuant to Subparagraph 29.c is 3.0 or higher. The CAP shall 

describe the actions that BPP shall take to correct the deficiencies 

and/or the systemic causes of a Comparative Monitoring Leak Ratio 

that is 3.0 or higher. The CAP also shall include a schedule by which 

those actions shall be undertaken. BPP shall complete each corrective 

action as expeditiously as possible with the goal of completing each 

action within 90 days after the LDAR Audit Completion Date. If any 

action is not completed or is not expected to be completed within 90 

days after the LDAR Audit Completion Date, BPP shall explain the 

reasons in the final CAP to be submitted under Subparagraph 31.b, 

together with a proposed schedule for completion of the action(s) as 

expeditiously as practicable. 

b.	 Submissions of the CAP to EPA. By no later than 120 days after the 

LDAR Audit Completion Date, BPP shall submit the final CAP to 

EPA, together with a certification of the completion of corrective 

action(s). For any corrective actions requiring more than 90 days to 

complete, BPP shall include an explanation together with a proposed 

schedule for completion as expeditiously as practicable. 

c. Approval/Disapproval of All or Parts of a CAP. 

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i. Unless within 60 days after receipt of the CAP, EPA 

disapproves all or part of a CAP’s proposed actions and/or 

schedules, the CAP shall be deemed approved. 

ii. By no later than 60 days after receipt of BPP’s CAP, EPA may 

disapprove any or all aspects of the CAP. Each item that is not 

specifically disapproved shall be deemed approved. Except for 

good cause, EPA may not disapprove any action within the 

CAP that already has been completed. Within 45 days of 

receipt of any disapproval from EPA, BPP shall submit a 

revised CAP that addresses the deficiencies that EPA 

identified. BPP shall implement the revised CAP either 

pursuant to the schedule that EPA proposed, or, if EPA did not 

so specify, as expeditiously as practicable. 

iii. A dispute arising with respect to any aspect of a CAP shall be 

resolved in accordance with the dispute resolution provisions 

of this Decree. 

Part L: Certification of Compliance 

32. Within 180 days after the initial LDAR Audit Completion Date, BPP shall 

submit a certification to EPA and IDEM that, to the best of the certifier’s 

knowledge and belief after reasonable inquiry: (i) the Whiting Refinery is 

in compliance with all applicable LDAR regulations; (ii) BPP has 

completed all corrective actions, if applicable, or is in the process of 

completing all corrective actions pursuant to a CAP; and (iii) all 

Equipment at the Whiting Refinery that is regulated under any federal, 

state, or local leak detection program has been identified and included in 

the Whiting Refinery’s LDAR program. 

Part M: Recordkeeping 

33. BPP shall keep all records, including copies of all LDAR audits, to 

document compliance with the requirements of this ELP in accordance 

with Section VIII (Reporting and Recordkeeping) of this Consent Decree. 

All monitoring data, leak repair data, training records, and audits will be 

retained for five (5) years, except for the calibration records (including 

calibration drift assessments) which will be retained for one (1) year. 

Upon request by EPA, BPP shall make all such documents available to 

EPA and shall provide, in their original electronic format, all LDAR 

monitoring data generated during the life of this Consent Decree. 

Part N: Reporting 

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34. Compliance Status Reports. On the dates and for the time periods set forth 

in Paragraph 35 of this Appendix, BPP shall submit, in the manner set 

forth in Section XVI (General Provisions) of the Consent Decree, a 

compliance status report regarding compliance with this ELP. The 

compliance status report shall include the following information: 

a. The number of personnel assigned to LDAR functions at the Whiting 

Refinery and the percentage of time each person dedicated to 

performing his/her LDAR functions; 

b. An identification and description of any non-compliance with the 

requirements of this Appendix; 

c. An identification of any problems encountered in complying with the 

requirements of this Appendix; 

d. The information required in Paragraph 20 of this Appendix; 

e. A description of any LDAR training required in accordance with Part I 

of this Appendix; 

f. Any deviations identified in the QA/QC performed under Part J of this 

Appendix B, as well as any corrective actions taken under that Part; 

g. A summary of LDAR audit results including specifically identifying 

all deficiencies; and 

h. The status of all actions under any CAP that was submitted pursuant to 

Part K of this Appendix during the reporting period. 

35. Due Dates. The first compliance status report shall be due thirty-one (31) 

days after the first full half-year after the Date of Entry (i.e., either: (i) 

January 31 of the year after the Date of Entry, if the Date of Entry is 

between January 1 and June 30 of the preceding year; or (ii) July 31 of the 

year after the Date of Entry, if the Date of Entry is between July 1 and 

December 31). The initial report shall cover the period between the Date 

of Entry and the first full half year after the Date of Entry (a “half year” 

runs between January 1 and June 30 and between July 1 and December 

31). Until termination of this Decree, each subsequent report will be due 

on the same date in the following year and shall cover the prior two half 

years (i.e., either January 1 to December 31 or July 1 to June 30). 

36. Each compliance status report submitted under this Part shall be signed by 

the plant manager, a corporate official responsible for environmental 

management and compliance, or a corporate official responsible for plant 

engineering management, and shall include the following certification: 

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I certify under penalty of law that I have examined and am familiar 

with the information in the enclosed document(s), including all 

attachments. Based on my inquiry of those individuals with 

primary responsibility for obtaining the information, I certify that 

the statements and information are, to the best of my knowledge 

and belief, true and complete. I am aware that there are significant 

penalties for knowingly submitting false statements and 

information, including the possibility of fines or imprisonment 

pursuant to Section 113(c)(3) of the Clean Air Act and 18 U.S.C. 

Sections 1001 and 1341. 

Part O: Process and Factors for “Commercial Unavailability” of Low-Leaking 

Valve or Packing Technology 

Summary: This Part outlines a process to be followed and factors to be taken into 

consideration to establish that a Certified Low-Leaking Valve or Certified Low-Leaking 

Valve Packing Technology is not “commercially available” pursuant to Paragraph 20 of 

this Appendix. Factors and procedures other than those identified in this Part may also 

be utilized to establish that a Certified Low-Leaking Valve or Certified Low-Leaking 

Valve Packing Technology is not commercially available. 

37. Factors. The following factors shall be taken in to account for 

determining the availability of safe and suitable Certified Low-Leaking 

Valve or Certified Low-Leaking Valve Packing Technologies: 

(1) Valve type; 

(2) Valve service and operating conditions; 

(3) Type of refinery process equipment in which the valve is used; 

(4) Seal performance; 

(5) Service life; 

(6) Packing friction; 

(7) Temperature and pressure limitations; and 

(8)	 Retrofit applications (e.g., re-piping or space limitations). 

The following factors may also be relevant for consideration, depending 

on the process unit or equipment in use at the refinery: 

(9) Valve or valve packing specifications identified by the licensor of 

the process unit or equipment in use at the refinery (including 

components that are part of a design package by a specialtyequipment provider as part of a larger process unit); or 

(10) Valve or valve packing vendor or manufacturer recommendations 

for the relevant refinery unit and/or process unit components. 

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38. Process. The following procedure shall be followed for determining the 

availability of a Certified Low-Leaking Valve or Certified Valve Packing 

Technology: 

a. BPP must contact a reasonable number of vendors of valves and valve 

packing technologies, taking into account the relevant factors 

identified above, prior to asserting a claim that Certified Low-Leaking 

Valve or Certified Low-Leaking Valve Packing Technology is not 

commercially available. 

i. For purposes of this Consent Decree, a reasonable number of 

vendors shall mean at least three vendors of valves and three 

vendors of valve packing technologies; 

ii.	 If fewer than three vendors of valve or valve packing 

technologies are contacted, the determination of whether such 

fewer number is reasonable for purposes of this Consent 

Decree shall be based on Factors (9) and/or (10) above, or on a 

demonstration that fewer than three vendors offer valves or 

valve packing technologies for the service and operating 

conditions of the valve to be replaced, in consideration of 

Factors (1) through (8) above, as applicable. 

b. BPP shall obtain a written representation from each vendor contacted 

or equivalent documentation that the valve or valve packing does not 

meet the specifications for a Certified Low-Leaking Valve or Certified 

Low-Leaking Valve Packing Technology. 

c. BPP shall prepare a written report fully explaining the basis for each 

claim that a valve or valve packing is not commercially available, to 

include all relevant documentation and other information supporting 

the claim. Such report shall also identify the commercially-available 

valve or packing technology that comes closest to meeting the 

requirements for a Certified Low-Leaking Valve or Certified LowLeaking Valve Packing Technology that is selected and installed by 

BPP pursuant to Paragraph 19 of this Appendix. Such report shall be 

included in the Semi-Annual Report required by Section VIII of the 

Consent Decree, for the period in which the valve or valve packing is 

replaced. 

39. EPA Review of Claim of Commercial Unavailability. Upon discretionary 

review by EPA of any claim of commercial unavailability, if EPA 

disagrees that a valve or valve-packing technology is commercially 

unavailable, EPA shall notify BPP in writing, specifying the valve or 

valve packing EPA believes to be commercially available and the basis for 

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its availability for the service and operating conditions of the valve. 

Following receipt by BPP of EPA’s notice, the following shall apply: 

a. BPP is not required to retrofit the valve or valve packing for which 

the unavailability claim was asserted (unless otherwise required to 

do so pursuant to some other provision of this Consent Decree). 

b. EPA’s notification shall serve as notice to BPP of EPA’s intent that a 

future claim of commercial unavailability will not be accepted for (a) 

the valve or valve packing that was the subject of the unavailability 

claim, or (b) for a valve or valve packing in the same or similar 

service, taking into account the factors identified in this Appendix. If 

BPP disagrees with EPA’s notification, BPP and EPA may informally 

discuss the basis for the claim of commercial unavailability. EPA may 

thereafter revise its notification, if necessary. 

c. If BPP makes a subsequent commercial unavailability claim for the 

same valve or valve packing (or valve or valve packing in the same 

or similar service) that was the subject of a prior unavailability 

claim which was not accepted by EPA, and such subsequent claim 

is also denied by EPA on the same basis as provided in EPA’s prior 

notification, BPP shall retrofit the valve or valve packing with the 

commercially available valve or valve packing technology at the 

next unit turnaround. 

d. Any disputes concerning EPA’s notification to BPP of the commercial 

availability of a valve or valve packing technology in a particular 

application pursuant to Paragraph 39.c of this Appendix shall be 

addressed under the Dispute Resolution provisions in Section XIV of 

this Consent Decree. 

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APPENDIX C
 

BEAVON STRETFORD MONITORING PROCEDURE
 

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APPENDIX D
 

EMISSION REDUCTIONS FROM FLARES AND CONTROL OF FLARING EVENTS 

FACTUAL BACKGROUND 

BPP already has installed or has agreed to install through this Consent Decree a Gas 

Chromatograph (“GC”), and not a vent gas net heating value analyzer, on each Steam-Assisted 

Flare covered by this Consent Decree (“Covered Flares”). 

BPP will utilize the measured values from each GC together with other measured and/or 

calculated Net Heating Values to calculate the Net Heating Value of the Vent Gas directed to 

each Covered Flare. 

The response time of a GC requires the use of an averaging time that is greater than the 

averaging time needed for a flare that utilizes a Vent Gas Net Heating Value 

Analyzers/Calculator. 

Prior to completion of WRMP, Acid Gas will be routed to the SRU Flare, and after 

completion of WRMP, Acid Gas will be routed to the South Flare or to an alternative flare when 

the South Flare is out of service. 

BPP does not have staged flares at the Whiting Refinery. 

DEFINITIONS 

“Acid Gas” shall mean any gas that contains hydrogen sulfide and is generated at a 

refinery by the regeneration of an amine scrubber solution, but does not include Tail Gas. 

“Acid Gas Flaring” or “AG Flaring” shall mean the combustion of Acid Gas and/or Sour 

Water Stripper Gas in one or more AG Flaring Device(s). 

“Acid Gas Flare” or “AG Flare” shall mean a Flare that is used for the purpose of 

combusting Acid Gas and/or Sour Water Stripper Gas, except facilities in which gases are 

combusted to produce sulfur or sulfuric acid. BPP currently operates a Flare it has designated as 

the “SRU Flare” as an AG Flare at the Refinery. To the extent that, during the duration of this 

Consent Decree, BPP commences operation of an AG Flare other than or in addition to the SRU 

Flare for the purpose of combusting Acid Gas and/or Sour Water Stripper Gas, that or those AG 

Flare(s) shall be covered under Sections H and I of this Appendix. 

“Acid Gas Flaring Incident” or “AG Flaring Incident” shall mean the continuous or 

intermittent combustion of Acid Gas and/or Sour Water Stripper Gas in an AG Flare that results 

in the emission of SO2 equal to, or in excess of, 500 pounds in any 24-hour period; provided, 

however, that if 500 pounds or more of sulfur dioxide has been emitted in a 24-hour period and 

Acid Gas Flaring continues into subsequent, contiguous, non-overlapping 24-hour period(s), 

each period of which results in emissions equal to, or in excess of, 500 pounds of SO2, then only 

one AG Flaring Incident shall have occurred. Subsequent, contiguous, non-overlapping periods 

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are measured from the initial commencement of flaring within the AG Flaring Incident. If, at 

any time during the term of this Consent Decree, the Whiting Refinery has more than one AG 

Flare, and if AG Flaring occurs within a 24 hour period at more than one such AG Flare, the 

quantity of sulfur dioxide attributable to AG Flaring emitted from each such AG Flare shall be 

added together for purposes of determining whether there is one AG Flaring Incident, unless the 

root causes of the flaring at the various AG Flares are not related to each other. 

“Air-Assisted Flare” shall mean a Flare that utilizes forced air piped to a Flare tip to 

assist in combustion; a Flare that utilizes a Minimum Steam Reduction System is a 

Steam-Assisted, not an Air-Assisted, Flare. 

“Air Mass Flow Rate at Stoichiometric Conditions based on Vent Gas Mass Flow Rate” 

or “ṁair-stoich-vg” shall mean the mass of air needed to reach a stoichiometric ratio based on the 

actual Vent Gas Mass Flow Rate. The ṁair-stoich-vg is represented by and shall be calculated 

according to Equation 4 in Appendix FLR-15 of this Consent Decree. 

“Assist Air” or “Airasst” shall mean all air that intentionally is introduced into an 

Air-Assisted Flare to assist in combustion. Assist Air does not include ambient air, air 

introduced through in a Minimum Steam Reduction System, or air entrained in Vent Gas. 

“Assist Air Mass Flow Rate” or “ṁair-asst” shall mean the mass flow rate of all Assist Air 

supplied to an Air-Assisted Flare, in pounds per hour (lb/hr), on a 5-minute block average basis. 

The ṁair-asst” is represented by and shall be calculated according to Equation 5 in Appendix FLR15 of this Consent Decree. 

“Automatic Control System” shall mean a system that utilizes programming logic to 

automate the operation of the instrumentation and systems required in Paragraphs 7 – 13, 42.a 

and 42.b of this Decree so as to produce the operational results required in Paragraphs 30, 33 –

 35, 37, and 45. 

“Baseload Waste Gas Flow Rate” shall mean, for a particular Covered Flare, the daily 

average flow rate, in scfd, to the Flare, excluding all flows during periods of startup, shutdown, 

and Malfunction. The flow rate data period that shall be used to determine Baseload Waste Gas 

Flow Rate for the Covered Flares is set forth in Subparagraph 18.b.ii. The Baseload Waste Gas 

Flow Rate shall be identified in the Initial Waste Gas Minimization Plan due under 

Subparagraph 18.b.ii and may be updated in subsequent Waste Gas Minimization Plans due 

under Paragraphs 19 and 20. 

“BTU/scf” shall mean British Thermal Unit per standard cubic feet. 

“Calendar Quarter” shall mean a three-month period ending on March 31, June 30, 

September 30, or December 31. 

“Center Steam” or “Scen” shall mean steam piped into the center of a Flare stack or center 

of the lower part of the Flare tip where it mixes directly with Vent Gas without entraining air. 

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Diagrams illustrating the meaning and location of Center, Lower, and Upper Steam are set forth 

in Appendix FLR-1 to this Consent Decree. 

“Center Steam Volumetric Flow Rate” or “Qs-cen” shall mean the volumetric flow rate of 

Center Steam supplied to a Flare, in scfm, as either measured (if applicable) or estimated using 

best engineering judgment, on a 5-minute block average. 

“Center Steam Mass Flow Rate” or “ṁs-cen”” shall mean the mass flow rate of Center 

Steam supplied to a Flare, in pounds per hour, as either measured (if applicable) or estimated 

using best engineering judgment, on a 5-minute block average using Equation 2 in 

Appendix FLR-2. 

“Cold Startup of the Refinery” shall mean the setting into operation of the entire Refinery 

after the entire Refinery has been shut down. 

“Combustion Efficiency” or “CE” shall mean a Flare’s efficiency in converting the 

organic carbon compounds found in Vent Gas to carbon dioxide. Combustion Efficiency shall 

be determined as set forth in Equation 1 in Appendix FLR-2. 

“Combustion Efficiency Multipliers” or “CE Multipliers” shall mean empirically-derived 

factors that are used as multipliers of the Net Heating Value of the Vent Gas at its Lower 

Flammability Limit to ensure an acceptable Combustion Efficiency. The CE Multipliers are set 

forth in Table 2 of Appendix FLR-3 of this Consent Decree. 

“Combustion Zone” shall mean the area of the Flare flame where the combustion of 

Combustion Zone Gas occurs. 

“Combustion Zone Gas” shall mean the mixture of all gases and steam found just after a 

Flare tip. This gas includes all Vent Gas, all Pilot Gas, all Total Steam (if the Flare is SteamAssisted), and all Assist Air (if the Flare is Air-Assisted). 

“Consent Decree” shall mean this Consent Decree, including any and all appendices 

attached hereto. 

“Covered Flare” shall mean each of the following Elevated, Steam-Assisted Flares at the 

Refinery: 

Name ID Number

 VRU 

FCU 

Alky 

4UF 

UIU 

South 

GOHT 

241-01 

230-02 

140-01 

224-06 

220-04 

800-04 

802-03 

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DDU 698-02 

“Discontinuous Wake Dominated Flow” shall mean gas flow exiting a Flare tip that is 

identified visually by: 

i. the presence of a flame that is: (1) immediately adjacent to the exterior of 

the Flare tip body; and (2) below the exit plane of the Flare tip; and 

ii. pockets of flame that are detached from the portion of the flame that is 

immediately adjacent to the exterior of the Flare tip body. 

Representations of Discontinuous Wake Dominated Flow are set forth in Appendix FLR-13. 

“Elevated Flare” shall mean a Flare that supports combustion at a tip that is situated at the 

upper end of a vertical conveyance (e.g., pipe, duct); the combustion zone is elevated in order to 

separate the heat generated by combustion from people, equipment, or structures at grade level. 

“Exit Velocity” shall mean the velocity (“v”) of the Vent Gas and Center Steam as it exits 

the flare tip. Exit Velocity shall be calculated by adding together the Vent Gas Volumetric Flow 

Rate and the Center Steam Volumetric Flow Rate and dividing by the Unobstructed Cross 

Sectional Area of the Flare Tip. 

“External Power Loss” shall mean a loss in the supply of electrical power to the Refinery 

that is caused by events occurring outside the boundaries of the Refinery, excluding power losses 

due to an interruptible power service agreement. 

“First Updated Waste Gas Minimization Plan” or “First Updated WGMP” shall mean the 

document submitted pursuant to Paragraph 19 as the first update to the Initial WGMP. 

“Flare” shall mean a combustion device that uses an uncontrolled volume of ambient air 

to burn gases. 

“Flare Gas Recovery System” or “FGRS” shall mean a system of one or more 

compressors, piping, and associated water seal, rupture disk, or similar device used to divert gas 

from a Flare and direct the gas to a fuel gas system, to a combustion device other than the Flare, 

or to a product, co-product, by product, or raw material recovery system. 

“Hydrocarbon Flaring” or “HC Flaring” shall mean the combustion of refinery-generated 

gases, except for Acid Gas, Sour Water Stripper Gas, and/or Tail Gas, in a Hydrocarbon Flare. 

“Hydrocarbon Flare” or “HC Flare” shall mean a Flare used to combust any 

refinery-generated gas other than Acid Gas and/or Sour Water Stripper Gas and/or Tail Gas. The 

Hydrocarbon Flares that BPP operates at the Refinery include each of the Covered Flares and the 

LPG Flare. To the extent that, during the duration of the Consent Decree, BPP commences 

operation of any HC Flaring Devices other than or in addition to those specified herein for the 

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purposes of combusting any excess of a refinery-generated gas other than Acid Gas and/or Sour 

Water Stripper Gas and/or Tail Gas, then any such flares that are: (i) Steam-Assisted shall be 

covered by Sections A-F, H, and J-K of this Appendix; or (ii) Air-Assisted shall be covered by 

Sections E, G-H, and J-K of this Appendix. Compliance with the applicable requirements shall 

commence on the first date of that any such new flare receives Waste Gas from the Refinery.

 “Hydrocarbon Flaring Incident” or “HC Flaring Incident” shall mean either of the 

following: 

i. “HC Flaring Incident – Trigger 1”: the continuous or intermittent 

combustion of refinery-generated gases, except for Acid Gas, Sour Water 

Stripper Gas, or Tail Gas, at a Hydrocarbon Flare that results in the 

emission of sulfur dioxide equal to or greater than five-hundred (500) 

pounds in any 24-hour period; provided, however, that if 500 pounds or 

more of sulfur dioxide has been emitted in any 24-hour period and flaring 

continues into subsequent, contiguous, non-overlapping 24-hour period(s), 

each period of which results in emissions equal to, or in excess of, 500 

pounds of sulfur dioxide, then only one HC Flaring Incident shall have 

occurred. Subsequent, contiguous, non-overlapping periods are measured 

from the initial commencement of Flaring within the HC Flaring Incident. 

When HC Flaring occurs within a 24-hour period at more than one HC 

Flare, the quantity of sulfur dioxide attributable to HC Flaring emitted 

from each HC Flare shall be added together for purposes of determining 

whether there is one HC Flaring Incident, unless the root causes of the 

flaring at the various HC Flaring Devices are not related to each other; or 

ii. “HC Flaring Incident – Trigger 2”: the combustion of 500,000 standard 

cubic feet or more of Waste Gas (excluding Acid Gas, Sour Water 

Stripper Gas, and Tail Gas) within a 24-hour period at a Hydrocarbon 

Flare. For purposes of calculating Waste Gas flow rate, the following 

flows may be excluded: (i) the pro-rated Baseload Waste Gas Flow Rate 

(pro-rated on the basis of the duration of the Flaring Incident); and (ii) if 

BPP has instrumentation capable of measuring the volumetric flow rate of 

hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or 

steam in the Waste Gas, the contribution of all measured flows of any of 

these elements/compounds. Subsequent, contiguous, non-overlapping 

periods are measured from the initial commencement of Flaring within the 

HC Flaring Incident. When HC Flaring occurs within a 24-hour period at 

more than one HC Flare, the volume of Waste Gas attributable to HC 

Flaring emitted from each HC Flare shall be added together for purposes 

of determining whether there is one HC Flaring Incident, unless the root 

causes of the flaring at the various HC Flaring Devices are not related to 

each other. 

“Initial Waste Gas Minimization Plan” or “Initial WGMP” shall mean the document 

submitted pursuant to Paragraph 18. 

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“Lower Flammability Limit” or “LFL” shall mean the lowest volumetric concentration of 

a combustible gas in air that, at a given temperature and pressure, will still combust. 

“Lower Flammability Limit Table” shall mean Table 1 of Appendix FLR-3. Table 1 

lists, inter alia, the LFLs of individual compounds found in Vent Gas. 

“Lower Flammability Limit of Vent Gas” or “LFLvg” shall mean the weighted average of 

the LFLs of each of the individual compounds in Vent Gas, weighted by their volume percent in 

the Vent Gas. LFLvg is represented by and shall be calculated according to Equation 1 in 

Appendix FLR-3 of this Consent Decree. 

“Lower Heating Value” or “LHV” shall mean the theoretical total quantity of heat 

liberated by the complete combustion of a unit volume or weight of a fuel initially at 25̊

Centigrade and 760 mmHg, assuming that the produced water is vaporized and all combustion 

products remain at, or are returned to, 25̊ Centigrade; however, the standard for determining the 

volume corresponding to one mole is 20̊ Centigrade. 

“Lower Steam” shall mean steam piped to an exterior annular ring near the lower part of 

a Flare tip, which entrains Air which flows through tubes to the Flare tip, and ultimately exits the 

tubes at the Flare tip. Diagrams illustrating the meaning and location of Center, Lower, and 

Upper Steam are set forth in Appendix FLR-1 to this Consent Decree. 

“LPG Flare” shall mean the Elevated, Air-Assisted Flare at the Refinery that BPP 

designates by ID No. 604-01. 

“Malfunction” shall mean 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. In any action under this Consent Decree involving this definition, BPP shall have 

the burden of proving a Malfunction and, in interpreting this definition, the ten requirements for 

a “malfunction” set forth in Section II (“Affirmative Defenses for Malfunctions”) of EPA’s 

Policy on Excess Emissions during Malfunctions, Startup, and Shutdown shall apply. This 

Policy is attached as Appendix FLR-4. 

“Minimum Steam Rate” or “Minimum Steam” shall mean the Total Steam Mass Flow 

Rate, in standard cubic feet per minute or in pounds per hour, recommended by the manufacturer 

of the Flare’s tip at the time of flare tip installation, or such lower Total Steam Mass Flow Rate 

as determined by the Flare tip manufacturer after Flare tip installation upon re-examination of the 

tip’s requirements. 

“Minimum Steam Reduction System” or “MSRS” shall mean a system that utilizes a 

mixed stream of air and steam to reduce the minimum steam requirements of a Steam-Assisted 

Flare. 

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“Momentum Flux Ratio” or “MFR” shall mean the ratio of the Vent Gas and Center 

Steam momentum flux to the wind momentum flux, where momentum flux is the momentum per 

unit area, per unit time. MFR characterizes the degree to which the ambient air affects the 

trajectory of the Vent Gas and Center Steam just as it exits the Flare tip. MFR is represented by 

Equation 1 in Appendix FLR-5 and shall be calculated in accordance with the equations, 

conversion factors, MFR constants, MFR measured variables, and MFR calculated variables set 

forth in Appendix FLR-5. 

“Net Heating Value” shall mean Lower Heating Value. 

“Net Heating Value of Combustion Zone Gas” or “NHVcz” shall mean the Lower Heating 

Value, in BTU/scf, of the Combustion Zone Gas in a Flare. NHVcz is represented by Equation 5 

in Appendix FLR-3 to this Consent Decree and shall be calculated in accordance with 

Equations 5 - 8 of Appendix FLR-3. To the extent a Covered Flare ever is equipped with a 

Minimum Steam Reduction System, BPP also shall use Equations 9 – 13 to calculate NHVcz. 

“Net Heating Value of the Combustion Zone Gas Limit” or “NHVcz-limit” shall mean the 

minimum Net Heating Value that the Combustion Zone Gas must have to ensure an acceptable 

Combustion Efficiency. NHVcz-limit shall be calculated no less than one time every 15 minutes 

through the use of Equation 4 in Appendix FLR-3 of this Consent Decree. 

“Net Heating Value of Hydrogen as Adjusted” or “NHVH2-adj” shall mean 1212 BTU/scf. 

NHVH2-adj represents an adjustment to hydrogen’s actual Net Heating Value for use, consistent 

with Step 3 of Appendix 1.3, in the calculation of the Net Heating Value of Vent Gas. 

“Net Heating Value of Vent Gas” or “NHVvg” shall mean the Lower Heating Value, in 

BTU/scf, of the Vent Gas directed to a Flare. NHVvg is calculated as set forth in Equation 2 in 

Appendix FLR-3. 

“Net Heating Value of Vent Gas at its Lower Flammability Limit” or “NHVvg-LFL” shall 

mean the Lower Heating Value, in BTU/scf, of the Vent Gas at its LFL. NHVvg-LFL is 

represented by and shall be calculated in accordance with Equation 3 of Appendix FLR-3 of this 

Consent Decree. 

“Passive FTIR” shall mean a Fourier Transform Infrared System that collects thermal 

(infrared) radiation emitted by a hot gas plume, and through the analysis of the resulting 

emission spectrum, identifies and quantifies the compounds producing values proportional to the 

path-integrated gas concentrations. 

“Pilot Gas” shall mean all gas introduced through the pilot tip of a Flare to maintain a 

flame. 

“Prevention Measure” shall mean an instrument, device, piece of equipment, system, 

process change, physical change to process equipment, procedure, or program to minimize or 

eliminate flaring. 

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“Purge Gas” shall mean the minimum amount of gas introduced between a Flare header’s 

water seal and the Flare tip to prevent oxygen infiltration (backflow) into the Flare tip. For a 

Flare with no water seal, the function of Purge Gas is performed by Sweep Gas, and therefore, by 

definition, such a Flare has no Purge Gas. 

“Refinery” shall mean the refinery that BPP owns and operates at 2815 Indianapolis 

Blvd, Whiting, Indiana. 

“Reportable Flaring Incident” shall mean each of the following: Acid Gas Flaring 

Incident; Tail Gas Incident; and Hydrocarbon Flaring Incident. 

“Root Cause Analysis” shall mean the primary and any contributing causes of a 

Reportable Flaring Incident as determined through a process of investigation. 

“SCFD” or “scfd” shall mean standard cubic feet per day. 

“SCFM” or “scfm” shall mean standard cubic feet per minute. 

“Shutdown” shall mean the cessation of operation for any purpose. 

“Sour Water Stripper Gas” or “SWS Gas” shall mean the gas produced by the process of 

stripping refinery sour water. 

“Smoke Emissions” shall have the definition set forth in Section 3.5 of Method 22 of 40 

C.F.R. Part 60, Appendix A. Smoke Emissions may be documented by either a person certified 

pursuant to Method 22 or by a video camera. 

“SRU Flare” shall mean the Elevated Flare associated with the sulfur recovery unit at the 

Refinery that BPP designates with ID No. 162-03. 

“Standard Conditions” shall mean a temperature of 68 degrees Fahrenheit and a pressure 

of 1 atmosphere. Unless otherwise expressly set forth in this Consent Decree or an Appendix, 

Standard Conditions shall apply. 

“Startup” shall mean the setting in operation for any purpose. 

“Steam-Assisted Flare” shall mean a Flare that utilizes steam piped to a Flare tip to assist 

in combustion. A Flare that utilizes a Minimum Steam Reduction System is a Steam-Assisted, 

not an Air-Assisted, Flare. 

“Supplemental Gas” shall mean all gas introduced to a Flare to comply with the net 

heating value requirements of 40 C.F.R. § 60.18(b), 40 C.F.R. § 63.11(b), and/or Paragraph 33 of 

this Appendix. 

“S/VG” or “Total-Steam-Mass-Flow-Rate-to-Vent-Gas-Mass-Flow-Rate Ratio” shall 

mean the ratio of the Total Steam Mass Flow Rate to the Vent Gas Mass Flow Rate. 

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“Sweep Gas” shall mean: 

i. For a Flare with a Flare Gas Recovery System: the minimum amount of 

gas introduced into a Flare header in order to: (a) prevent oxygen buildup, corrosion, and/or 

freezing in the Flare header; and (b) maintain a safe flow of gas through the Flare header. Sweep 

Gas in these Flares is introduced prior to and is intended to be recovered by the Flare Gas 

Recovery System; 

ii. For a Flare without a Flare Gas Recovery System: the minimum amount 

of gas introduced into a Flare header in order to: (a) prevent oxygen buildup, corrosion, and/or 

freezing in the Flare header; (b) maintain a safe flow of gas through the Flare heater; and (c) 

prevent oxygen infiltration (backflow) into the Flare tip. 

“Tail Gas” shall mean the exhaust gas from the Claus train(s) of a sulfur recovery plant 

and/or from the Tail Gas Unit. 

“Tail Gas Incident” shall mean either of the following: 

i. “Tail Gas Incident – Trigger 1”: Tail Gas that is combusted in a flare and 

results in excess emissions of 500 pounds or more of SO2 in any 24-hour 

period; or 

ii. “Tail Gas Incident – Trigger 2”: Tail Gas that is combusted in a thermal 

incinerator and results in excess emissions of 500 pounds or more of SO2 

emissions in any twenty-four (24) hour period. Only emissions which are 

in excess of a SO2 concentration of 250 ppm (rolling twelve-hour average) 

shall be used to determine the amount of excess SO2 emissions from the 

incinerator. 

Tail Gas Incidents may include, but are not limited to, any of the following: a TGU shutdown, a 

TGU bypass, and a scheduled or unscheduled shutdown of a sulfur recovery plant. For Tail Gas 

Incidents – Trigger 2, BPP shall use good engineering judgment and/or other monitoring data to 

calculate emissions during periods in which the SO2 continuous emission analyzer has exceeded 

the range of the instrument or the instrument is out of service. 

“Tail Gas Unit” or “TGU” shall mean a control system utilizing a technology for 

reducing emissions of sulfur compounds from a sulfur recovery plant. 

“Temporary-Use Flare” shall mean a flare that receives Waste Gas that has been 

redirected to it from another flare for 504 hours or less on a rolling 1095 day average period. 

“Total Steam” or “S” shall mean the total of all steam that intentionally is introduced into 

a Steam-Assisted Flare to assist in combustion. Total Steam includes, but is not limited to, 

Lower Steam, Center Steam, and Upper Steam. 

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“Total Steam Volumetric Flow Rate” or “Qs” shall mean the volumetric flow rate of 

Total Steam supplied to a Flare, in scfm as measured on a 5-minute block average. 

“Total Steam Mass Flow Rate” or “ṁs” shall mean the mass flow rate of Total Steam 

supplied to a Flare, in pounds per hour as calculated on a 5-minute block average. Total Steam 

Mass Flow Rate shall be calculated as set forth in Equation 3 in Appendix FLR-2. 

“Unobstructed Cross Sectional Area of the Flare Tip” or “Atip-unob” shall mean the open, 

unobstructed area of a Flare tip through which Vent Gas and Center Steam pass. Diagrams of 

four common flare types are set forth in Appendix FLR-6 together with the equations for 

calculating the Atip-unob of these four types. 

“Upper Steam,” sometimes called Ring Steam, shall mean steam piped to nozzles located 

on the exterior perimeter of the upper end of a Flare tip. Diagrams illustrating the meaning and 

location of Center, Lower, and Upper Steam are set forth in Appendix FLR-1 to this Consent 

Decree. 

“Variable Speed Motor” shall mean a motor that operates at continuously variable speeds 

between a minimum and maximum as regulated by a Variable Speed Drive. 

“Variable Speed Drive” shall mean a piece of equipment that regulates the speed and 

rotational force, or torque output, of an electric motor and that outputs a variable frequency to a 

motor to allow it to operate at variable speeds between the motor’s minimum and maximum 

speed. 

“Velocity of the Wind” or “ݒ୵୧୬ୢ” shall mean the velocity of the ambient air, in ft/s on a 

one-minute block average, measured at the Meteorologic Station required pursuant to 

Paragraph 12 of this Appendix. 

“Vent Gas” shall mean the mixture of all gases found prior to the Flare tip. This gas 

includes all Waste Gas, Sweep Gas, Purge Gas, and Supplemental Gas, but does not include Pilot 

Gas, Total Steam, or Assist Air. 

“Vent Gas Volumetric Flow Rate” or “Qvg” shall mean the volumetric flow rate of Vent 

Gas directed to a Covered Flare, in wet scfm, on a 5-minute block average basis. 

“Vent Gas Mass Flow Rate” or “ṁvg” shall mean the mass flow rate of Vent Gas directed 

to a Covered Flare, in pounds per hour on a 5-minute block average. Vent Gas Mass Flow Rate 

shall be calculated as set forth in Equation 4 in Appendix FLR-2. 

“Vent Gas Molecular Weight” or “MWvg” shall mean the Molecular Weight, in pounds 

per pound-mole, of the Vent Gas, on a 5-minute block average. 

“Visible Emissions” shall mean five minutes or more during any two consecutive hours 

of Smoke Emissions. For purposes of this Appendix, Visible Emissions may be documented by 

either a person certified pursuant to Method 22 or by a video camera. 

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“VOC” or “Volatile Organic Compounds” shall have the definition set forth in 40 C.F.R. 

Section 51.100(s). 

“VOC Vent Gas Concentration” shall mean the volumetric concentration of VOCs in the 

Vent Gas and shall be calculated as set forth in Equation 16 of Table 2 of Appendix FLR-3. 

“Waste Gas” shall mean the mixture of all gases from facility operations that is directed 

to a flare for the purpose of disposing of the gas. “Waste Gas” does not include gas introduced 

to a flare exclusively to make it operate safely and as intended; therefore, “Waste Gas” does not 

include Pilot Gas, Total Steam, Assist Air, or the minimum amount of Sweep Gas and Purge Gas 

that is necessary to perform the functions of Sweep Gas and Purge Gas. “Waste Gas” also does 

not include gas introduced to a flare to comply with regulatory requirements; therefore, “Waste 

Gas” does not include Supplemental Gas. Depending upon the instrumentation that measures 

Waste Gas, certain compounds (hydrogen, nitrogen, oxygen, carbon dioxide, carbon monoxide, 

and/or water (steam)) that are directed to a Flare for the purpose of disposing of these 

compounds may be excluded from calculations relating to Waste Gas flow; in the substantive 

provisions of this Appendix, the circumstances in which such exclusions are permitted are 

specifically identified. Appendix FLR-7 to this Consent Decree depicts the meaning of “Waste 

Gas,” together with its relation to other gases associated with Flares. 

CONTROLS OF FLARES AND FLARING EVENTS 

A.	 Interim Measures for Flare Combustion Efficiency and Vent and Waste Gas 

Minimization at the Covered Flares 

1. Interim Combustion Efficiency Measures. 

a. By no later than 45 days after the Date of Entry, based on the monitoring 

systems and instrumentation existing at each Covered Flare as of the Date of Entry, BPP shall 

complete the installation of a system that depicts, on each Covered Flare’s control panel, a visual 

image of the S/VG ratio of each Covered Flare. 

b By no later than 90 days after the Date of Entry, for all operators and 

supervisors with responsibility and/or oversight for the operation of each Covered Flare, BPP 

shall complete training on steam control for each Covered Flare. Such training shall include 

describing and identifying the existing monitoring and instrumentation systems, how to manually 

adjust Total Steam Volumetric Flow Rate so as to optimize Combustion Efficiency and minimize 

oversteaming, and how to target the S/VG ratio at the lowest possible value to just avoid Smoke 

Emissions. 

c. By no later than 90 days after the Date of Entry, based on the visual 

readout at the control panel for each Covered Flare, BPP shall operate each Covered Flare to 

minimize the S/VG ratio to the extent practical with the existing monitoring and instrumentation 

systems. 

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2. Evaluating and Upgrading or Replacing, as Necessary, Meters Measuring Sweep 

Gas and Purge Gas Volumetric Flow Rates. By no later than one year after the Date of Entry, 

BPP shall complete an evaluation of all meters that measure the flow of Sweep Gas and Purge 

Gas to each Covered Flare and shall upgrade or replace, as necessary, each such meter in order to 

ensure an acceptable level of control over flow. 

3. Minimizing Sweep and Purge Gas Flow Rates based on Survey Findings. Prior to 

one year after the Date of Entry, BPP shall complete a survey of the amount of Sweep Gas and 

Purge Gas introduced to each Covered Flare. Based on the results of the survey, by no later than 

one year after the Date of Entry, BPP shall complete the implementation of all measures 

necessary to minimize the amount of Sweep Gas and Purge Gas being directed to each Covered 

Flare. If the implementation of any such measure takes longer than one year after the Date of 

Entry, BPP shall complete the implementation as soon as practicable and shall provide a 

schedule for such completion in the first semi-annual report under Section VIII of this Decree 

that is due after one year after the Date of Entry. Under no circumstances may BPP implement 

any such measure later than the turnaround for the affected unit that first occurs after one year 

after the Date of Entry. 

4. Minimizing Leaking Pressure Relief Valves (“PRVs”). By no later than one year 

after the Date of Entry, BPP shall conduct and complete a survey (“Initial PRV Leak Survey”) of 

the large, high-pressure hydrocarbon pressure relief valves (“PRVs”) at the Refinery identified in 

Appendix FLR-8. The Initial PRV Leak Survey will include but not be limited to acoustic 

monitoring. During the first Maintenance Shutdown that occurs after eighteen months following 

completion of the Initial PRV Leak Survey of any unit that houses any PRV listed in Appendix 

FLR-8, BPP shall repair or replace each leaking PRV in that unit. For all other hydrocarbon 

PRVs at the Refinery (that is, all those that are not identified in Appendix FLR-8) that are tied 

into Flare headers and subheaders, BPP shall conduct acoustic monitoring pursuant to a plan and 

schedule that BPP shall include in the Initial Waste Gas Minimization Plan due under 

Paragraph 18. 

B. Instrumentation and Monitoring Systems for Covered Flares 

5. Flare Data and Monitoring Systems and Protocol Report (“Flare Data and 

Monitoring Systems and Protocol Report”). By no later than June 30, 2013, for all Covered 

Flares, BPP shall submit a report to EPA that includes the following: 

a. The information, diagrams, and drawings specified in Parts 1 – 8 of 

Appendix FLR-9; 

b. A detailed description of each instrument and piece of monitoring 

equipment, including the specific model and manufacturer, that BPP has 

installed or will install in compliance with Paragraphs 7 – 13 (Part 9 of 

Appendix FLR-9); and 

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c. A narrative description of the monitoring methods and calculations that 

BPP shall use to comply with the requirements of Paragraphs 33 – 35 (Part 

10 of Appendix FLR-9). 

d. The identification of the calibration gases to be used to comply with 

Subparagraph V.B.1 of Appendix FLR-11 (Part 11 of Appendix FLR-9). 

For any H2S CEMS required pursuant to 40 C.F.R. Part 60, Subpart J or Subpart Ja, this report 

shall satisfy the notification requirements of 40 C.F.R. § 60.7(a)(5). 

6. Installation and Operation of Monitoring Systems. 

a.	 By no later than startup of the South Flare, and December 31, 2013 for all 

other Covered Flares, BPP shall have completed the installation and 

commenced the operation of the instrumentation, controls, and monitoring 

systems set forth in Paragraphs 7 - 13. 

b.	 BPP may elect to re-position or upgrade the existing Panametric flow meters 

on the DDU, VRU, FCU, Alky, 4UF and UIU Flares in order to meet the 

accuracy requirement in Appendix FLR-11. BPP shall complete any such 

upgrades or re-positioning by December 31st of the following years: 

Covered Flare Re-position or Upgrade Panametric Flow Meter

 DDU 2014 

FCU 2014 

VRU 2015 

Alky 2016 

4UF 2016 

UIU 2017 

7. Vent Gas Flow Monitoring System. By means of this system, BPP shall 

determine the Vent Gas Volumetric and Mass Flow Rates at each Covered Flare. This system 

shall: 

a. Continuously measure the total flow, in scfm or pounds per hour, of the 

gas flowing through it; 

b. Continuously analyze pressure and temperature at each point of flow 

measurement; 

c. Have dual channel measurement at each point of flow measurement for 

flow meters using an ultrasonic flow measurement method; and 

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d. Have retractable or removable sensors at each point of flow measurement 

to ensure that the flow meter is maintainable online. 

Prior to any necessary relocation of the Panametrics flow meter pursuant to Paragraph 6, the 

Vent Gas Flow Monitoring System shall consist of (1) an ultrasonic flow meter that is measuring 

the flow of gas in the header prior to the flare stack (after all addition of Waste Gas from process 

units) or in the flare stack; (2) a flow meter measuring any Supplemental Gas that may be 

supplied to the flare stack and that is not already measured by the ultrasonic flow meter; and (3) 

a flow meter measuring any Purge Gas that may be supplied to the flare stack and that is not 

already measured by the ultrasonic flow meter. After the relocation of the ultrasonic flow meter 

pursuant to Paragraph 6, the Vent Gas Flow Monitoring System shall consist of (1) an ultrasonic 

flow meter that is measuring the flow of gas in the header prior to the water seal and after any 

FGRS; (2) a flow meter measuring any Supplemental Gas that may be supplied to the flare stack 

and that is not already measured by the ultrasonic flow meter; and (3) a flow meter measuring 

any Purge Gas that may be supplied to the flare stack and that is not already measured by the 

ultrasonic flow meter. In all cases, the system, in its complete configuration, shall accurately 

measure Volumetric Vent Gas Flow Rate as defined by this Consent Decree. 

8. Vent Gas Average Molecular Weight Analyzer. By means of this system, BPP 

shall determine the average Molecular Weight of the Vent Gas at each Covered Flare. BPP shall 

utilize the molecular weight analyzer in the ultrasonic flow meter at each Covered Flare to 

determine the molecular weight of the gas flowing to each such flow meter. BPP shall assume a 

constant molecular weight for the Purge Gas and Supplemental Gas that is representative of the 

molecular weight of natural gas supplied from the local gas company (NIPSCO) at each Covered 

Flare. 

9. Total Steam Flow Monitoring System. This system shall: 

a. Continuously measure the flow, in scfm and pounds per hour, of the Total 

Steam to the Covered Flare; and 

b. Continuously analyze the pressure and temperature of steam at a 

representative point of steam flow measurement. 

10. Steam Control Equipment. This equipment, including, as necessary, main and 

trim control valves and piping, shall enable BPP to control steam flow in a manner sufficient to 

ensure compliance with this Decree.

 11. Gas Chromatograph (“GC”). This instrument shall be capable of speciating the 

gas constituents set forth in Appendix FLR-10. For all constituents except Hydrogen Sulfide 

(“H2S”), the GC shall measure the concentration on a mole percent (“mol/mol%”) basis; for H2S, 

the GC shall measure the concentration on a parts per million volume basis (“ppmv”). 

12. Meteorologic Station or “Met Station” (for the Refinery, not each Covered Flare). 

This station shall include meteorologic data instruments capable of measuring wind speed. The 

station shall be located in the refinery at Gate 36. 

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13. Video Camera. This instrument shall record, in digital format, the flame of, and 

any Smoke Emissions and/or Wake Dominated Flow from, each Covered Flare. 

14. Instrumentation and Monitoring Systems: Optional Equipment for any Covered 

Flare. At its option, BPP may elect to install (if not already installed) and continuously measure 

the flow, in scfm or pounds per hour (if the instrument automatically converts flow from scfm to 

lb/hr), of all Pilot Gas to a Covered Flare. BPP may utilize the data generated by this system as 

part of the calculation of the Net Heating Value of the Combustion Zone Gas. 

15. Instrumentation and Monitoring Systems: Specifications. The instrumentation 

and monitoring systems identified in Paragraphs 7 – 9 and 11 - 12 shall meet or exceed the 

specifications set forth in Appendix FLR-11. 

16. Instrumentation and Monitoring Systems: Recording and Averaging Times. The 

instrumentation and monitoring systems identified in Paragraphs 7 – 9 and 11 - 13 shall be able 

to produce and record data measurements and calculations for each parameter at the following 

time intervals: 

Instrumentation and Monitoring System Recording and Averaging Times 

Vent Gas Flow; 

Vent Gas Average Molecular Weight; 

Total Steam Flow; 

Pilot Gas Flow (if installed) 

Measure continuously and record 5 

minute block averages 

Gas Chromatograph Measure no less than once every 15 

minutes and record that value 

Wind Speed Measure continuously and record 5 

minute block averages 

Video Camera Record at a rate of no less than 4 

frames per minute 

17. Instrumentation and Monitoring Systems: Operation and Maintenance. BPP shall 

operate each of the instruments and monitoring systems required in Paragraphs 7 - 9, 11 - 13, and 

42.a and 42.b on a continuous basis except for the following periods: 

a. Malfunction of an instrument and/or monitoring system; 

b. Maintenance following instrument Malfunction; 

c. Scheduled maintenance of an instrument in accordance with the 

manufacturer’s recommended schedule; 

d. Quality Assurance/Quality Control activities; and/or 

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e. When the Covered Flare that the instrument or monitoring system is 

associated with is not in service. 

Provided however, that in no event shall the excepted activities in Subparagraphs 17.a—17.c for 

any instrument exceed 110 hours in any calendar quarter. The calculation of instrument 

downtime shall be made in accordance with 40 C.F.R. § 60.13(h)(2) and Paragraph VI of 

Appendix FLR-11. If the excepted activities in Subparagraphs 17.a—17.c exceed 110 hours in 

any calendar quarter, EPA shall be entitled to seek stipulated penalties under Paragraph 150.j of 

Part X (“Stipulated Penalties”) and BPP shall be entitled to assert that the period of 

instrumentation and monitoring system downtime was justified under the circumstances. 

Nothing in this Paragraph is intended to prevent BPP from claiming a force majeure defense to 

any period of instrumentation and/or monitoring system downtime. Nothing in this Paragraph 

supersedes or replaces the monitoring requirements, including operation, maintenance, and 

quality assurance/quality control requirements, of 40 C.F.R. Part 60, Subparts J and Ja (including 

monitoring requirements in 40 C.F.R. Part 60, Subpart Ja that may be stayed as of the Date of 

Lodging of this Consent Decree but may become effective after the Date of Lodging) at such 

time as those requirements become applicable pursuant to Paragraphs 69 and 70. All such 

requirements shall apply in accordance with the terms set forth in 40 C.F.R. Part 60, Subparts J 

and Ja. 

C. Vent and Waste Gas Minimization for Covered Flares 

18. Initial Waste Gas Minimization Plan (“Initial WGMP”). By no later than June 30, 

2015, for all Covered Flares, BPP shall submit to EPA an Initial Waste Gas Minimization Plan 

for each Covered Flare that discusses and evaluates flaring Prevention Measures both 

Refinery-wide and on a Flare-specific basis. The Initial WGMP shall include but not be limited 

to: 

a. Updates. BPP shall submit updates, if and as necessary, to the 

information, diagrams, and drawings provided in the Flare Data and Monitoring Systems and 

Protocol Report required under Paragraph 5. 

b. Waste Gas Characterization and Mapping. BPP shall undertake to 

characterize the Waste Gas being disposed of at each Covered Flare and determine its source as 

follows: 

i. Volumetric (in scfm) and mass (in pounds) flow rate. BPP shall 

identify the volumetric flow of Waste Gas, in scfm on a 30-day rolling average, and the mass 

flow rate, in pounds per hour on a 30-day rolling average, vented to each Covered Flare between 

January 1, 2014, and December 31, 2014. To the extent that, for any particular Covered Flare, 

BPP has instrumentation capable of measuring the volumetric and mass flow rate of hydrogen, 

nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or steam in the Waste Gas, BPP may 

break down the volumetric and mass flow as between: (i) All Waste Gas flows excluding 

hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam); and (ii) 

hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam) flows in the 

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Waste Gas. BPP may use either an engineering evaluation or measurements from monitoring or 

a combination to determine flow rate. In determining flow rate, flows during all periods 

(including but not limited to normal operations and periods of startup, shutdown, Malfunction, 

process upsets, relief valve leakages, power losses due to an interruptible power service 

agreement, and emergencies arising from events within the boundaries of the Refinery), except 

those described in the next sentence, shall be included. Flows that could not be prevented 

through reasonable planning and are caused by a natural disaster, act of war or terrorism, or 

External Power Loss are the only flows that shall be excluded from the calculation of flow rate. 

BPP shall specifically describe the date, time, and nature of the event that results in the exclusion 

of any flows from the calculation. 

ii. Baseload Waste Gas Flow Rates. BPP shall utilize flow rate data 

to determine the Baseload Waste Gas Flow Rate, in scfd, to each Covered Flare, other than the 

South and GOHT Flares. The Baseload Waste Gas Flow Rate shall not include flows during 

periods of startup, shutdown, and Malfunction. The Baseload Waste Gas Flow Rate shall be 

based on the period between January 1, 2014, and December 31, 2014 

iii. Identification of Constituent Gases. BPP shall use best efforts to 

identify the constituent gases within each Covered Flare’s Waste Gas and the percentage 

contribution of each such constituent during baseload conditions. BPP may use either an 

engineering evaluation or measurements from monitoring or a combination to determine Waste 

Gas constituents.

 iv. Waste Gas Mapping. Using instrumentation, isotopic tracing, 

and/or engineering calculations, BPP shall identify and estimate the flow from each process unit 

flare header to the main Flare header(s). Using that information and all other available 

information, BPP shall complete an identification of each Waste Gas tie-in to the main Flare 

header(s) and process unit flare header(s), as applicable, consistent with Appendix FLR-12. 

Temporary connections to a Flare’s header(s) and/or subheader(s) are not required to be included 

in the mapping. 

c. Reductions previously realized. BPP shall describe the equipment, 

processes and procedures installed or implemented within the last three years to reduce flaring. 

The description shall specify the date of installation or implementation and the amount of 

reductions realized. 

d. Planned reductions. BPP shall describe the equipment, processes, or 

procedures that BPP plans to install or implement to eliminate or reduce flaring. The description 

shall specify a schedule for expeditious installation and commencement of operation and a 

projection of the amount of reductions to be realized. In formulating this plan, BPP specifically 

shall review and evaluate the results of the Waste Gas Mapping required by 

Subparagraph 18.b.iv. 

e. Taking a Covered Flare out of Service. BPP shall identify any Covered 

Flare that it intends to take out of service, including the date for completion of the 

decommissioning. Taking a Covered Flare “out of service” means physically removing piping in 

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the Flare header or physically isolating the piping with a welded blind so as to eliminate direct 

piping to the Covered Flare. 

f. Prevention Measures. BPP shall describe and evaluate all Prevention 

Measures, including a schedule for the expeditious implementation and commencement of 

operation of all prevention measures, to address the following: 

i. Flaring that has occurred or may reasonably be expected to occur 

during planned maintenance activities, including startup and shutdown. The evaluation shall 

include a review of flaring that has occurred during these activities in the past three years and 

shall consider the feasibility of performing these activities without flaring. 

ii. Flaring that may reasonably be expected to occur due to issues of 

gas quantity and quality. The evaluation shall include an audit of the flare gas recovery capacity 

of each Covered Flare, the storage capacity available for excess Waste Gases, and the scrubbing 

capacity available for Waste Gases including any limitations associated with scrubbing Waste 

Gases for use as fuel. The evaluation shall consider the feasibility of reducing flaring through 

the recovery, treatment, and use of the Waste Gas. 

iii. Flaring caused by the recurrent failure of air pollution control 

equipment, process equipment, or a process to operate in a normal or usual manner. The 

evaluation shall consider the adequacy of existing maintenance schedules and protocols for such 

equipment. A failure is “recurrent” if it occurs more than twice during any five year period as a 

result of the same root cause. 

19. First Updated Waste Gas Minimization Plan. By no later than June 30, 2016, for 

all Covered Flares, BPP shall submit to EPA a First Updated WGMP, which shall update for the 

preceding calendar year, if and as necessary, the information required in Subparagraphs 18.a – 

18.f and shall also include the following: 

a. Updated Waste Gas Mapping. BPP shall update the Waste Gas mapping 

as more information becomes available. BPP shall use this updated 

mapping to plan reductions; 

b. Reductions based on Root Cause Analysis. BPP shall review all of the 

Root Cause Analysis reports prepared pursuant to Paragraph 54 to 

determine if reductions in addition to the reductions achieved through any 

corrective action under Paragraph 55 can be realized; and 

c. Revised Schedule. To the extent that BPP proposes to extend any 

schedule set forth in the Initial WGMP, BPP shall do so only with good 

cause.

 20. Subsequent Updates to Waste Gas Minimization Plan. In the first semi-annual 

report required under Part VIII that is due after June 30, 2017, BPP shall submit a Second 

Updated WGMP. On an annual basis thereafter until termination of the Decree, BPP shall 

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submit an updated WGMP as part of the applicable semi-annual report. Each update shall 

update, if and as necessary, the information required in Subparagraphs 18.a – 18.f, 19.a, and 

19.b. To the extent that BPP proposes to extend any schedule set forth in a previous WGMP, 

BPP shall do so only with good cause. 

21. a. Waste Gas Minimization Plan: Implementation. By no later than the 

dates specified in a WGMP, BPP shall implement the actions described therein. If (i) no 

implementation date and/or (ii) no completion date for actions that do not require ongoing 

implementation (such as the installation of a piece of a equipment) is (are) set forth in the 

WGMP, the implementation and/or completion date shall be deemed the date of the submission 

of the WGMP. 

b. Waste Gas Minimization Plan: Enforceability. The terms of each WGMP 

(including Initial, First Updated, and Subsequent Updated WGMPs) submitted under this 

Appendix are specifically enforceable. 

22. Overlapping Requirements: Flare Management Plan Provisions of the NSPS 

Subpart Ja that are Stayed as of the Date of Lodging. To the extent that currently-stayed 

provisions of Subpart Ja of the NSPS that prescribe affirmative work practice requirements for 

flare management plans, see 73 Fed. Reg. 78522, 78538-39 (December 22, 2008), are finalized 

after the Date of Lodging of this Consent Decree, and to the extent compliance with those 

provisions overlaps with compliance with Paragraphs 18 – 21 and 43, BPP shall comply with the 

requirements of the finalized Subpart Ja and also comply with each requirement in 

Paragraphs 18 – 21 and 43 that is not inconsistent with the requirements of a finalized 

Subpart Ja. 

D. Flare Gas Recovery Systems for all Covered Flares Except the DDU Flare 

23. Dates of Installation and Commencement of Operation of Flare Gas Recovery 

Systems 

a. Except as specifically provided in Subparagraph 23.b, by no later than the 

following dates for the following Covered Flares or groups of Covered Flares, BPP shall 

complete installation and commence operation of the following Flare Gas Recovery Systems: 

ID Covered Flares Date 

FGRS 1 South Flare Upon startup of South Flare 

FGRS 2 GOHT Upon startup of GOHT Flare 

FGRS 3 VRU, FCU, Alky December 31, 2015 

FGRS 4 4UF, UIU December 31, 2016 

b. BPP shall complete the tie-in of the UIU Flare to FGRS 4 by no later than 

December 31, 2017, and commence recovery of Waste Gas by that time. 

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24. Design of Flare Gas Recovery Systems 

a. Capacity. BPP shall design and install Flare Gas Recovery Systems of the 

following flow capacities: 

Capacity 

of Each Total System 

No. of Compressor Capacity 

ID Covered Flares Compressors (kscfh) (kscfh) 

FGRS 1 South Flare 2 62.5 125 

FGRS 2 GOHT 2 62.5 125 

FGRS 3 VRU, FCU, Alky 4 62.5 250 

FGRS 4 4UF, UIU 3 62.5 187.5 

The flow capacities are based on the compression of air with a molecular weight equal to 29. 

b. Other. If either FGRS 3 or 4 is shutdown due to a loss of the water level 

in the seal drum for a period greater than 10 hours in any consecutive 12 month period, then 

within one year of the date that the 10 hours was exceeded, BPP shall make any necessary 

changes to prevent any future shutdown of the appropriate FGRS due to a loss of water level in 

the seal drum. 

25. Operation of Flare Gas Recovery Systems. Each Flare Gas Recovery System 

shall be operated in a manner to minimize Waste Gas to the Flares while ensuring safe refinery 

operations. BPP shall operate the equipment consistent with good engineering and maintenance 

practices and in accordance with the manufacturer’s specifications. 

a. Each compressor shall be capable of starting automatically from an idle 

mode in a time period and manner consistent with the manufacturer’s specifications when 

necessary to process additional Waste Gas. BPP shall equip the compressors with 

automatic startup capability by no later than the following dates: 

ID Covered Flares Date 

FGRS 1 South Flare December 31, 2015 

FGRS 2 GOHT December 31, 2015 

FGRS 3 VRU, FCU, Alky Upon startup of FGRS 3 

FGRS 4 4UF, UIU Upon startup of FGRS 4 

b. A compressor in a standby mode and capable of automatic startup shall be 

considered to be available for operation. Once the compressors at the applicable FGRS 

are capable of automatic startup as specified in subparagraph 25.a., the FGRS shall have 

the following number of compressors available for operation at least 95% of the time, 

based on an 8760-hour rolling average, rolled hourly: 

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No. of Compressors that must be available 

ID Covered Flares at least 95% of the time 

FGRS 1 South Flare 1 

FGRS 2 GOHT 1 

FGRS 3 VRU, FCU, Alky 3 

FGRS 4 4UF, UIU 2 

Each FGRS shall be designed to automatically startup available compressors to process surplus 

Waste Gas until all available compressors are in operation, including times when a FGRS has all 

of its installed compressors available for operation. Prior to the installation of automatic startup 

at FGRS 1 and FGRS 2, BPP shall start compressors manually from standby mode to process 

surplus Waste Gas within one hour. 

c. Additional Requirements Applicable to FGRS 3 and 4 

i. At all times, except during the periods described in subparagraphs 

iii or iv below, BPP shall have one compressor in operations at FGRS 3 and at least one 

additional compressor either in operation or in a standby mode and capable of automatic startup. 

ii. At all times, except during the periods described in subparagraphs 

iii or iv below, BPP shall have one compressor in operation at FGRS 4. 

iii. The requirements of subparagraphs i and ii shall not apply to an 

FGRS during periods of maintenance on common equipment within that FGRS. These periods 

of maintenance shall not exceed 336 hours per FGRS on a five year rolling average period, rolled 

daily. BPP will make best efforts to schedule these maintenance activities during process unit 

turnarounds and to minimize the generation of Waste Gas during such periods. 

iv. The requirements of subparagraph i and ii shall not apply during 

periods when compressors are shut down consistent with the manufacturer’s specifications or 

good engineering practices to preserve the mechanical integrity of the compressors (for example, 

as a result of high pressure or temperature). 

E. Limitations on Flaring 

26. Limitations on Flaring: Initial Limit. By no later than December 31, 2018, BPP 

shall comply with the following limitations on flaring at the Refinery: 

a. From all Covered Flares and the LPG Flare, BPP shall not flare more than 

3.1 MMscfd of Waste Gas on a 30-day rolling average basis, rolled daily; 

and 

b. From all Covered Flares and the LPG Flare, BPP shall not flare more than 

2.1 MMscfd of Waste Gas on a 365-day rolling average basis, rolled daily. 

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Each exceedance of the 30-day rolling average limit or each exceedance of the 365-day rolling 

average limit shall constitute one day of violation. An exceedance of either or both of the limits 

shall not prohibit ongoing refinery operations. 

27. Limitations on Flaring: Requesting an Increase in the Limit. 

a. Once per calendar year commencing no sooner than January 2019, BPP 

may submit a request to EPA to increase the limitations on flaring set forth in Subparagraphs 

26.a and/or 26.b. Any request for an increase in the limitations on flaring shall be based upon an 

increase in crude capacity that is due to a post-WRMP permitted modification. In any such 

request, BPP shall propose (a) new limit(s) based upon the following equations: 

i. For the Refinery-wide, 30-day rolling average limit: 

Refinery Flaring ≤ 750,000 scfd x Whiting Crude Cap. x Whiting Complexity 

100,000 bpd Industry Avg Complexity 

ii. For the Refinery-wide, 365-day rolling average limit: 

Refinery Flaring ≤ 500,000 scfd x Whiting Crude Cap. x Whiting Complexity 

100,000 bpd Industry Avg Complexity 

b. For purposes of Subparagraph 27.a: 

i. The items in italics are variables that will change over time. 

ii. The Whiting Crude Capacity shall be based on the projected 

capacity of the Refinery, as reported annually by BPP to the 

Department of Energy for the year of the request date. 

iii. The Whiting Complexity shall be calculated in accordance with 

Equation 1 of Appendix FLR-14. The crude capacity will be the 

capacity reported by BPP to the Department of Energy for the year 

that the limit will be in effect. The process unit capacities will be 

the capacities published the Oil & Gas Journal in barrels per 

calendar day for the year that the limit will be in effect. BPP shall 

certify the accuracy of the process unit capacities used to support 

any request for a change to the limitations on flaring. 

iv. The Industry Average Complexity shall be calculated in accordance 

with Equation 2 of Appendix FLR-14. 

c. EPA Response to Request. EPA shall evaluate any request under 

Subparagraph 27.a on the basis of consistency with Subparagraphs 27.a and 27.b. If EPA does 

not act on BPP’s request within 90 days of submission, BPP may invoke the dispute resolution 

provisions of this Decree. The new limit(s) shall take effect, if ever, beginning on the date that 

EPA approves the request or a dispute is resolved in BPP’s favor. Nothing in this Consent 

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Decree shall be construed to relieve BPP of an obligation to evaluate, under applicable 

Prevention of Significant Deterioration and Nonattainment New Source Review requirements, 

any increase in a Refinery-Wide Limit on Flaring. 

28. Meaning and Calculation of “Waste Gas” Flow for Purposes of the Limitation on 

Flaring. For purposes of the meaning and calculation of “Waste Gas” flow in the limitations on 

flaring in Paragraphs 26 and 27, the following shall apply: 

a. To the extent that BPP has instrumentation capable of measuring the 

volumetric flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, 

carbon dioxide, and/or water (steam) in the Waste Gas, the contribution of 

all measured flows of any of these elements/compounds may be excluded 

from the Waste Gas flow rate calculation. 

b. Waste Gas flows during all periods (including but not limited to normal 

operations and periods of startup, shutdown, Malfunction, process upsets, 

relief valve leakages, power losses due to an interruptible power service 

agreement, and emergencies arising from events within the boundaries of 

the Refinery), except those expressly described in Subparagraph 28.c 

and/or the next sentence, shall be included. Waste Gas flows that could 

not be prevented through reasonable planning and are caused by a natural 

disaster, act of war or terrorism, or External Power Loss may be excluded 

from the calculation of flow rate. 

c. By no later than 180 days prior to a Cold Startup of the Refinery, BPP 

may submit to EPA a plan to minimize Waste Gas flaring during a Cold 

Startup of the Refinery (“Cold Startup Waste Gas Minimization Plan”). If 

BPP submits a Cold Startup Waste Gas Minimization Plan and operates in 

accordance with it, BPP may exclude, from the Refinery-Wide 30-day 

rolling average limit, Waste Gas flows during any Cold Startup that occurs 

more than 180 days after submission of the Cold Startup Waste Gas 

Minimization Plan. BPP may not exclude any such flows from the 

refinery-wide 365-day rolling average limit. 

d. Except for hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, 

and/or water (steam) contributions to the flow rate that are excluded by 

virtue of instrumentation measuring these flows, by no later than thirty 

days after the occurrence of any flow that is not included in a computation, 

BPP shall submit a written report to EPA that specifically identifies the 

event that resulted in the exclusion. If the event is a Cold Startup of the 

Refinery, BPP shall describe dates, durations, and volumes of the flows 

during the Cold Startup as well as the steps BPP took in compliance with 

the Cold Startup Waste Gas Minimization Plan. If the event is anything 

other than a cold startup, BPP shall describe the following: the date(s) and 

duration(s) of the flows caused by the event; the estimated VOC emissions 

during the event; whether flows from the event are anticipated to persist 

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after the notice, and if so, for how long; and the measures taken or to be 

taken to prevent or minimize the flows, including, for future anticipated 

flow, the schedule by which those measures will be implemented. 

F. Flare Combustion Efficiency Requirements for Covered Flares 

29. Emission Standards and Work Practices Applicable to each Covered Flare upon 

the Date of Entry. By no later than the Date of Entry, BPP shall comply with the following 

requirements at each Covered Flare: 

a. Operation during Emissions Venting. BPP shall operate each Covered 

Flare at all times when emissions may be vented to it. 

b. No Visible Emissions. Except for periods of Startup, Shutdown, and/or 

Malfunction, BPP shall operate each Covered Flare with no Visible Emissions. Method 22 in 40 

C.F.R. Part 60, Appendix A, shall be used to determine compliance with this standard. However, 

for purposes of this Appendix, Visible Emissions may be determined by either a person certified 

pursuant to Method 22 or by a video camera. 

c. Flame Presence. Except for periods of Malfunction of the Flare, BPP shall 

operate each Covered Flare with a flame present at all times. BPP shall monitor the presence of 

the pilot flame using a thermocouple or any other equivalent device to detect the presence of the 

pilot flame. 

d. Exit Velocity. Except for periods of Startup, Shutdown, and/or 

Malfunction, BPP shall operate each Covered Flare with an Exit Velocity less than 18.3 m/sec 

(60 ft/sec) on a one-hour block average; provided however, that: 

i. If any Covered Flare combusts Vent Gas with a Net Heating Value 

of greater than 1000 BTU/scf, BPP may operate the Covered Flare 

with an Exit Velocity equal to or greater than 18.3 m/sec (60 

ft/sec) but less than 122 m/sec (400 ft/sec) on a one-hour block 

average; and 

ii. If any Covered Flare has a maximum permitted velocity (Vmax), 

BPP may operate the Covered Flare with an Exit Velocity less than 

Vmax provided that it also operates the applicable Flare with an Exit 

Velocity of less than 122 m/sec (400 ft/sec) on a one-hour block 

average. 

Vmax shall be calculated in accordance with 40 C.F.R. § 60.18(f)(5). The Unobstructed Cross 

Sectional Area of the Flare Tip shall be calculated consistent with Appendix FLR-6. 

e. Monitoring According to Applicable Provisions. BPP shall comply with 

all applicable Subparts of 40 C.F.R. Parts 60, 61, or 63 that state how a particular Covered Flare 

must be monitored. 

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f. Good Air Pollution Control Practices. At all times, including during 

periods of Startup, Shutdown, and/or Malfunction, BPP shall implement good air pollution 

control practices to minimize emissions from each Covered Flare; provided however, that BPP 

shall not be in violation of this requirement for any practice that this Consent Decree requires 

BPP to implement after the Date of Lodging for the period between the Date of Lodging and the 

implementation date or compliance date (whichever is applicable) for the particular practice. 

30. Work Practice Standards for each Covered Flare.. By no later than January 31, 

2014, for all Covered Flares utilizing the instrumentation and controls required to be installed 

pursuant to Paragraphs 7 – 13, BPP shall install and operate on each Covered Flare an Automatic 

Control System that shall: 

a. automate the control of the Supplemental Gas flow rate to the respective 

Flare; and 

b. automate the control of the Total Steam Flow Rate to the respective Flare. 

31. Exception to Part of the Work Practice Standards in Subparagraph 30.b. BPP 

manually may override the operation of the Automatic Control System required in 

Subparagraph 30.b (for control of Total Steam Mass Rate) if the exception in Paragraph 51 

applies and/or in order to achieve the following: 

a. Stop Smoke Emissions that are occurring; 

b. Meet the Net Heating Value requirements of Paragraph 33; 

c. Prevent extinguishing the Flare; 

d. Protect personnel safety; 

e. Stop Discontinuous Wake Dominated Flow; and/or 

f. During Startup, Shutdown, or Malfunction of a process unit that feeds the 

Covered Flare. 

32. Operation According to Design. By no later than December 31, 2014, for all 

Covered Flares, BPP shall operate and maintain each Covered Flare in accordance with its 

design, except if, and only to the extent that, operation and maintenance of the Covered Flare in 

conformance with its design conflicts with compliance with one or more of the requirements of 

this Appendix. 

33. Net Heating Value Standards for each Covered Flare 

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a. NHVvg. Beginning on the Date of Entry and continuing until the earlier of: 

(i) termination of this Consent Decree; or (ii) the requirements in 40 C.F.R. §§ 60.18(c)(3)(ii) 

and 63.11(b)(6)(ii) related to the NHVvg are modified, BPP shall operate each Covered Flare with 

an NHVvg of greater than or equal to 300 BTU/scf on a three-hour rolling average basis, rolled 

every fifteen minutes, except as provided in Paragraph 51. 

b. NHVcz-limit. By no later than December 31, 2014, for all Covered Flares, 

and except as provided in Paragraph 51, BPP shall calculate an NHVcz-limit at each Covered Flare 

no less than every fifteen minutes. Except as provided in Paragraph 51, BPP shall operate each 

Covered Flare so as to ensure that the Covered Flare’s NHVcz, on a three-hour rolling average 

basis, rolled every fifteen minutes, is greater than or equal to its NHVcz-limit on a three-hour rolling 

average basis, rolled every fifteen minutes. BPP shall utilize the equations and directives set 

forth in Appendix FLR-3 to meet the requirements of this Subparagraph. 

34. S/VG Standards. 

a. By no later than December 31, 2014, for all Covered Flares, BPP shall 

operate each Covered Flare at less than or equal to an S/VG of 3.0 on a one-hour rolling average, 

rolled every five minutes. 

b. Exceptions. Notwithstanding the requirements of Subparagraph 34.a, BPP 

is not subject to the emissions standard in that Subparagraph if the exception in Paragraph 51 

applies and/or in order to achieve the following: 

i. Stop Smoke Emissions that are occurring; 

ii.	 Meet the Net Heating Value requirements of Paragraph 33; 

iii.	 Prevent extinguishing the Flare; and/or 

iv. Protect personnel safety. 

35. Prohibition on Discontinuous Wake Dominated Flow or Requirement for 

Minimum MFR for Covered Flares. 

a. By no later than December 31, 2014, for all Covered Flares, BPP shall 

comply with either Subparagraph 35.b. or 35.c. In the first semi-annual report due after the 

applicable compliance date, BPP shall identify which compliance option it selects for each 

Covered Flare. BPP may select different alternatives for different Covered Flares and may 

change its election for any given Covered Flare by providing EPA with 30 days prior notice of 

the change.

 b. Prohibition on Discontinuous Wake Dominated Flow. 

i. BPP shall not operate the Covered Flares with Discontinuous 

Wake Dominated Flow, except for periods not to exceed a total of 

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five minutes during any two consecutive hours. BPP shall add 

Supplemental Gas as necessary to prevent such instances of 

Discontinuous Wake Dominated Flow at the Covered Flares. 

ii.	 Prior to the effective date of the prohibition in 

Subparagraph 35.b.i, for all operators and supervisors with 

responsibility and/or oversight for the operation of each Covered 

Flare, BPP shall complete training on the meaning and prevention 

of Discontinuous Wake Dominated Flow. After the effective date, 

operators shall monitor the operation of each Covered Flare at 

intervals appropriate for the weather conditions and service of the 

Covered Flare in order to comply with the prohibition in 

Subparagraph 35.b.i. 

c. MFR Requirements. MFR shall be calculated in accordance with the 

equations, conversion factors, MFR constants, MFR measured variables, and MFR calculated 

variables set forth in Appendix FLR-5. BPP shall either: 

i. Maintain a minimum MFR of 0.0030 on a 60 minute rolling 

average basis, rolled every 5 minutes, at each Covered Flare; or 

ii. Propose a Flare-specific MFR. BPP shall submit such a proposal 

to EPA for approval. In any such proposal, BPP shall demonstrate, 

using, at a minimum, photographs correlated to MFR, that at the 

proposed MFR, Discontinuous Wake Dominated Flow will not 

occur for the Covered Flare that is the subject of the request. 

d. Notwithstanding Subparagraphs 35.b and c., BPP shall not be required to 

add Supplemental Gas at any time that the wind speed at the Refinery is greater than or equal to 

35 mph on a 60-minute rolling average basis, rolled every 5 minutes, and/or if the exception in 

Paragraph 51 applies. 

36. 98% Combustion Efficiency. By no later than December 31, 2014, for all 

Covered Flares, BPP shall operate each Covered Flare with a minimum of a 98% Combustion 

Efficiency at all times when Waste Gases are vented to it. To demonstrate continuous 

compliance with the 98% Combustion Efficiency, BPP shall operate each Covered Flare within 

the range of operating parameters set forth in Paragraphs 33 – 35. 

37. Inapplicability of Paragraphs 33 – 36. The requirements of Paragraphs 33 – 36 

are not applicable to any Covered Flare when the only gas or gases being vented to the Covered 

Flare is/are Pilot Gas and/or Purge Gas. Pilot Gas and Purge Gas will be considered to be the 

only gases being vented to those Flares if both of the following conditions are met for the water 

seal drum that is part of the FGRS associated with the respective Covered Flare: 

a. The pressure difference between the inlet pressure and outlet pressure is 

less than the water seal pressure as set by the static head of water between 

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the opening of the dip tube in the drum and the level-setting weir in the 

drum; and 

b. The water level in the drum is at the level of the weir. 

38. Emissions and Combustion Efficiency Testing at Certain Covered Flares: 

Requirements. In order to evaluate emissions and Flare Combustion Efficiency, BPP shall 

conduct Passive FTIR testing on the DDU and the Alky Flares by no later than September 1, 

2014. By no later than 60 days prior to each test, BPP shall submit an Emissions and Flare 

Combustion Efficiency Test Protocol in accordance with the general requirements in Appendix 

FLR-16. BPP shall complete the testing on each Covered Flare within 30 days of commencing 

the testing of the Flare. 

39. Emissions and Combustion Efficiency Testing at Certain Covered Flares: 

Reporting. By no later than four months after completing the testing required in Paragraph 38, 

BPP shall submit a report to EPA that sets forth the following: 

a. The detailed results of the testing done pursuant to Paragraph 38 that 

includes minute by minute electronic data in Excel format for all 

measurements and process data and is consistent with the requirements of 

Appendix FLR-17; 

b. A detailed description of the extent to which the NHVcz, affects 

Combustion Efficiency; 

c. A detailed description of the range of the NHVcz that the Covered Flares 

must be operated at to ensure 98% Combustion Efficiency, taking into 

consideration variability in Vent Gas flow rate; 

d. The “A” Combustion Efficiency Multiplier set forth in FLR-3 for 

calculating the NHVcz-limit at which BPP proposes to operate the Covered 

Flare in order to achieve a Combustion Efficiency of no less than 98% on 

a continuous basis; and 

e. A detailed evaluation of whether the results of the testing at the Covered 

Flare that is the subject of the report impact the “A” Combustion 

Efficiency Multiplier for calculating the NHVcz-limit at the six Covered 

Flares that will not be subject to Passive FTIR testing. 

40. EPA Response to PFTIR Report(s). EPA shall review the reports and establish 

the “A” Combustion Efficiency Multiplier for calculating the NHVcz-limit for the specific Flare 

that is the subject of the report. The “B” Combustion Efficiency Multiplier set forth in Table 2 

of Appendix FLR-3 shall apply according to the terms in that Table. The “A” Combustion 

Efficiency Multiplier will be based on the results of the testing and a consideration of emissions 

impacts, and will be set at a point where the limits ensure that a Combustion Efficiency of at 

least 98% is continuously achieved with a reasonable certainty of compliance. EPA also shall 

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review whether the results of the testing impact the “A” Combustion Efficiency Multiplier for 

calculating the NHVcz-limit at the six Covered Flares that will not be subject to Passive FTIR 

testing. Disputes arising under this Paragraph shall be resolved in accordance with the dispute 

resolution provisions of this Decree. 

41. Recordkeeping: Timing and Substance. BPP shall comply with the following 

recordkeeping requirements: 

a. By no later than March 31, 2014, for all Covered Flares, BPP shall 

calculate and record, in accordance with the recording and averaging times required in Paragraph 

16, each of the following parameters: 

i. Total Steam Volumetric Flow Rate (in scfm) and Total Steam 

Mass Flow Rate (in lb/hr) 

ii. Vent Gas Flow and Mass Rates (in scfm and lb/hour) 

iii.	 S/VG (in lbs steam/lbs Vent Gas)

 iv. NHVvg (in BTU/scf) 

v. NHVcz (in BTU/scf) 

vi. NHVcz-limit (in BTU/scf) 

b. By no later than June 30, 2014, for all Covered Flares, commencing if and 

when any instrument subject to Paragraph 17 operates at less than 95% in any calendar quarter of 

the in-service time of the Covered Flare that is being monitored by the respective instrument, 

BPP shall record the duration of the deviation, an explanation of the cause(s) of the deviation, 

and a description of the corrective action(s) that BPP took. 

c. By no later than January 31, 2014, for all Covered Flares, for compliance 

with the work practice standards in Paragraph 30: (i) BPP shall record each time it manually 

overrides its Automatic Control System, including the date, time, duration, reason for the 

override, and corrective actions that BPP took; and (ii) where the reason for the override was to 

stop Smoke Emissions that were occurring, BPP shall include a copy of the digital video record 

(with a time stamp) of the Covered Flare during the period of the manual override. 

d. At any time that BPP deviates from the standards in Paragraphs 29, 

33 - 36, after the effective date of those standards, BPP shall record the duration of the deviation, 

an explanation of the cause(s) of the deviation, and a description of the corrective action(s) that 

BPP took. 

e. Recordkeeping: Document Retention. For purposes of this Appendix, and 

except with respect to the data produced by video cameras required pursuant to Paragraph 13, 

BPP shall retain all records created pursuant to this Appendix, including the raw data values, in 

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accordance with Part VIII (“Reporting and Recordkeeping”) and shall make any such 

documents available to EPA upon request. BPP shall retain the data recorded by the Video 

Cameras required pursuant to Paragraph 13 for six months except that BPP shall comply with the 

data retention requirements in Part VIII for those periods when BPP overrode the Automatic 

Control System. 

G. LPG Flare Requirements 

42. LPG Flare Requirements: Instrumentation and Monitoring Systems. By no later 

than one year after the Date of Entry, BPP shall undertake the following for the LPG Flare: 

a. Install a flow meter in order to determine the Vent Gas Volumetric and 

Mass Flow Rates to the LPG Flare. The air flow rate shall be determined 

from the fan speed on the Assist Air blower. 

b. Install a Variable Speed Motor on the LPG Flare’s Assist Air blower; 

c. Install a control system that will automate the control of the Variable 

Speed Motor on the LPG Flare’s Assist Air blower to enable BPP to 

comply with the standard set forth in Paragraph 45; and 

d. In the semi-annual report required under Paragraph 98 of Part VIII that is 

the first one due after one year after the Date of Entry of this Consent 

Decree, provide a detailed description of the installations made in 

compliance with Subparagraphs 42.a. and 42.b, including the specific 

models and manufacturers. 

43. Waste Gas Minimization for LPG Flare. Commencing thirty days after the 

installation of the flow meter required pursuant to Subparagraph 42.a, and continuing through 

December 31, 2014, BPP will identify and implement Prevention Measures for the minimization 

of Vent Gas flow to the LPG Flare. In the first semi-annual report due after the installation of 

the flow meter required pursuant to Subparagraph 42.a and continuing through the semi-annual 

report due in January of 2015, BPP will provide, for the time period covered by the semi-annual 

report, the following information: (i) the volumetric flow of Waste Gas, in scfm, on a 30-day 

rolling average, and the mass flow rate, in pounds per hour, on a 30-day rolling average, vented 

to the LPG Flare; (ii) the Prevention Measures implemented for the reporting period; and (iii) the 

Prevention Measures expected to be implemented in the future, together with a schedule for 

prompt implementation. 

44. Emission Standards Applicable to the LPG Flare. By no later than one year after 

the Date of Entry, BPP shall comply with each of the requirements in Paragraph 29 at the LPG 

Flare, except that, with respect to Exit Velocity, BPP shall comply with the requirements in 40 

C.F.R. § 60.18(c)(5) and not those in Subparagraph 29(d). 

45. Standard for ṁair-asst/ṁair-stoich-vg. By no later than one year after the Date of Entry 

of this Consent Decree and continuing through to either: (i) the date that EPA sets a new limit 

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pursuant to either Subparagraph 48.d or 49.b; or (ii) the termination of this Consent Decree, 

whichever is applicable, BPP shall operate the LPG Flare so as to ensure that ṁair-asst < 10 x 

ṁair-stoich-vg, on a one-hour rolling average, rolled every five minutes. BPP shall utilize the 

equations and directives set forth in Appendix FLR-15 to meet the requirements of this 

Paragraph. Notwithstanding the requirements of this Paragraph, BPP is not subject to the 

standard set forth in this Paragraph if the exception in Paragraph 51 applies and/or in order to (1) 

stop Smoke Emissions that are occurring, (2) prevent extinguishing the Flare, (3) protect 

personnel safety, and /or (4) prevent Wake Dominated Flow. 

46. Operation According to Design. By no later than one year after the Date of Entry 

of this Consent Decree, BPP shall operate and maintain the LPG Flare in accordance with its 

design, except if, and only to the extent that, operation and maintenance of the LPG Flare in 

conformance with its design conflicts with compliance with one or more of the requirements of 

this Appendix. 

47. Testing Depending on Annual Average Vent Gas Volumetric Flow Rate to the 

LPG Flare: Determining the Annual Average Vent Gas Flow Rate of the LPG Flare for Calendar 

Year 2015. By no later than March 31, 2016, BPP shall determine the annual average Vent Gas 

Flow Rate, in scfm, for the LPG Flare for the calendar year 2015. To determine the annual 

average Vent Gas Flow Rate for calendar year 2015, BPP shall use the Vent Gas Flow Rate data 

gathered in 2015. All flows shall be included. 

48. Testing Depending on Annual Average Vent Gas Volumetric Flow Rate to the 

LPG Flare: Consequences if the Annual Average Vent Gas Flow Rate for 2015 for the LPG 

Flare Equals or Exceeds Certain Figures. 

a. Passive FTIR Testing. If the annual average Vent Gas Flow Rate of the 

LPG Flare for 2015 equals or exceeds 35 scfm (if the Whiting Refinery is located in an area 

designated as non-attainment for the eight-hour ozone standard at the end of calendar year 2015) 

or 70 scfm (if the Whiting Refinery is located in an area designated as attainment for the 

eight-hour ozone standard at the end of calendar year 2015), then, by no later than September 30, 

2016, BPP shall conduct Passive FTIR testing on the LPG Flare. By no later than 60 days prior 

to the testing, BPP shall submit an Emissions and Flare Combustion Efficiency Test Protocol in 

accordance with the general requirements in Appendix FLR-16. BPP shall complete the testing 

on the LPG Flare within 30 days of commencing testing. 

b. Passive FTIR Report. By no later than four months after completing the 

testing required in Subparagraph 48.a, BPP shall submit a report to EPA for approval that sets 

forth the following: 

i. The detailed results of the testing that include minute by minute 

electronic data in Excel format for all measurements and process 

data and is consistent with the requirements of Appendix FLR-17 

that are relevant to an Air-Assisted Flare; 

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ii. A detailed description of the extent to which the ṁair-asst/ṁair-stoich-vg 

affects Combustion Efficiency; 

iii.	 A detailed description of the range of the ṁair-asst/ṁair-stoich-vg, that 

the Covered Flares must be operated at to ensure 98% Combustion 

Efficiency or as high an efficiency as reliably obtainable, taking 

into consideration variability in Vent Gas flow rate. 

iv. The maximum ṁair-asst/ṁair-stoich-vg at which BPP proposes to 

operate the LPG Flare in order to achieve a Combustion Efficiency 

as high as reliably obtainable; and 

v. A proposed Combustion Efficiency applicable to the LPG Flare 

that is as high as reliably obtainable.

 c. Compliance with Proposed Operating Limits in Passive FTIR Report. 

Unless and until EPA establishes different limits under Subparagraph 48.d, BPP shall comply 

with the operating limits that it proposes pursuant to Subparagraph 48.b.iv. 

d. EPA-Established Operating Limits and Combustion Efficiency. Based on 

all of the available information from the testing conducted pursuant to Subparagraph 48.a and the 

report submitted pursuant to Subparagraph 48.b, EPA shall establish a ṁair-asst/ṁair-stoich-vg that 

will enable BPP to achieve a Combustion Efficiency as high as reliably obtainable. EPA also 

shall establish a Combustion Efficiency for the LPG Flare that is reliably obtainable, but shall be 

no higher than 98%. Within 60 days of receiving written notice establishing such limits, BPP 

shall comply with the ṁair-asst/ṁair-stoich-vg and Combustion Efficiency established by EPA. 

e. Exceptions to Compliance with Limits in Subparagraphs 48.c and 48.d. 

BPP shall not be subject to the limits in Subparagraphs 48.c. or 48.d if the exception in 

Paragraph 51 applies and/or in order to achieve the following: 

(1)	 Stop Smoke Emissions that are occurring; 

(2)	 Meet Net Heating Value requirements; 

(3) Prevent extinguishing the Flare; and/or 

(4)	 Protect personnel safety. 

49. Testing Depending on Annual Average Vent Gas Volumetric Flow Rate to the 

LPG Flare: Consequences if the Annual Average Vent Gas Flow Rate for 2015 for the LPG 

Flare is Below Certain Figures. 

a. Annual Redetermination of the Annual Average Vent Gas Flow Rate. If 

the annual average Vent Gas Flow Rate of the LPG Flare for 2015 is less than 35 scfm (if the 

Whiting Refinery is located in an area designated as non-attainment for the eight-hour ozone 

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standard at the end of calendar year 2015) or 70 scfm (if the Whiting Refinery is located in an 

area designated as attainment for the eight-hour ozone standard at the end of calendar year 2015), 

then for the duration of the Consent Decree, on an annual basis in the first calendar quarter of 

each year, BPP shall determine the average annual Vent Gas Flow Rate, in scfm, for the LPG 

Flare for the prior calendar year. 

b. Consequences if the Annual Average Vent Gas Flow Rate Equals or 

Exceeds Certain Limits. If, during an annual review, the annual average Vent Gas Flow Rate for 

the LPG Flare for the prior calendar year equals or exceeds 35 scfm (if the Whiting Refinery is 

located in an area designated as non-attainment for the eight-hour ozone standard at the end of 

prior calendar year) or 70 scfm (if the Whiting Refinery is located in an area designated as 

attainment for the eight-hour ozone standard at the end of prior calendar year), then BPP shall 

conduct, complete, and comply with the requirements set forth in Subparagraphs 48.a – 48.c by 

no later than September 30 of the applicable year. EPA thereafter will establish a 

ṁair-asst/ṁair-stoich-vg and Combustion Efficiency pursuant to Subparagraph 48.d 

c. Reporting. If as a result of an annual review of the annual average Vent 

Gas Flow Rate for the LPG Flare, BPP is not required to conduct Passive FTIR Testing, BPP 

shall report the results of the annual review in the first semi-annual report that is due after the 

annual review has been completed. If as a result of an annual review, BPP is required to conduct 

Passive FTIR Testing, BPP shall notify EPA by no later than April 30 of the applicable year of 

the results of the review and the schedule that it will follow to comply with the requirements in 

Subparagraphs 48.a and 48.b. 

50. Testing Depending on Annual Average Vent Gas Volumetric Flow Rate to the 

LPG Flare: Recordkeeping. If at any time under this Paragraph, BPP is required to undertake 

Passive FTIR Testing, then commencing within 90 days after submitting its Passive FTIR 

Report, BPP shall comply with all applicable recordkeeping requirements of Paragraph 41, but 

“Assist Air” or “ṁair-asst ” shall be substituted for any reference to “Total Steam” or “S” in 

Paragraph 41. 

H. Exception for Instrument Downtime 

51. A failure to comply with the work practices or standards in Paragraphs 30.b, 33.a, 

33.b, 34.a, 35.b, 35.c, 45, 48.c, or 48.d shall not constitute a violation of such work practice or 

standard if the noncompliance results from downtime of instruments or equipment due to the 

following: 

a. Malfunction of an instrument, for an instrument needed to meet the 

requirement(s); 

b. Maintenance following instrument Malfunction, for an instrument needed 

to meet the requirement(s); 

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c. Scheduled maintenance of an instrument in accordance with the 

manufacturer’s recommended schedule, for an instrument needed to meet the requirement; 

and/or 

d. Quality Assurance/Quality Control activities on an instrument needed to 

meet the requirement. 

Provided, however, that this exception shall no longer be applicable if the activities in 

Subparagraphs 51a. through d. exceed 110 hours in any calendar quarter for any instrument. 

The calculation of instrument downtime shall be made in accordance with 40 C.F.R. § 

60.13(h)(2) and Paragraph VI of Appendix FLR-11. 

I. Control of Reportable Flaring Incidents 

52. Flares Subject to Subsection I. Each Covered Flare, the LPG Flare, and the SRU 

Flare are subject to the requirements of Subsection I. 

53. Dates of Applicability of the Requirements in Subsection I. The requirements of 

Subsection I shall apply to Reportable Flaring Incidents that occur on and after the following 

dates: 

Type of Reportable Flaring Incident Applicability Date

 AG Flaring Incident Date of Entry 

Tail Gas Incident (Triggers 1 and 2) Date of Entry 

HC Flaring Incident – Trigger 1 Date of Entry 

HC Flaring Incident – Trigger 2 Date of Submission of First Updated 

Waste Gas Minimization Plan 

54. Root Cause Analysis, Internal Reporting, and Recordkeeping. Except as 

expressly provided in Paragraph 56, by no later than 45 days following the end of a Reportable 

Flaring Incident, BPP shall conduct an investigation into the Root Cause(s) of the Incident and 

prepare and keep as a record an internal report that shall include, at a minimum, the following: 

a. The date and time that the Reportable Flaring Incident started and ended. 

To the extent that the Reportable Flaring Incident involved multiple releases either within a 

twenty-four (24) hour period or within subsequent, contiguous, non-overlapping twenty-four (24) 

hour periods, BPP shall set forth the starting and ending dates and times of each release; 

b. An estimate of the volume of gases flared (or combusted, for Tail Gas 

Incidents – Trigger 2), the quantity of SO2 and VOCs emitted, and the calculations that were 

used to determine these values; 

c. The steps, if any, that BPP took to limit the duration of the Reportable 

Flaring Incident, the volume of gas flared or combusted, and the quantity of SO2 and VOC 

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emissions associated therewith; 

d. A detailed analysis that sets forth the Root Cause, including all 

contributing causes, of the Reportable Flaring Incident, to the extent determinable; 

e. An analysis of the measures, if any, that are available to reduce the 

likelihood of a recurrence of a Reportable Flaring Incident resulting from the same Root Cause, 

or contributing causes, in the future. The analysis shall discuss all reasonable alternatives, if any, 

that are available, and the probable effectiveness and cost of the alternatives. Possible design 

and operation and maintenance changes shall be evaluated. If BPP concludes that corrective 

action(s) is/are available, the report will include a description of the action(s) and, if not already 

completed, a schedule for its (their) implementation, including proposed commencement and 

completion dates. If BPP concludes that corrective action is not available, the report will explain 

the basis for that conclusion; 

f. To the extent that the investigation of the causes and/or possible corrective 

actions still are underway 45 days after the end of a Reportable Flaring Incident, a statement of 

the anticipated date by which a follow-up report fully conforming to the requirements of this 

Paragraph will be completed; provided however, that if the investigation of the causes and/or 

possible corrective actions still are underway 90 days after the end of a Reportable Flaring 

Incident and if BPP has not sought by that time an extension of time to complete the 

investigation, stipulated penalties for failing to timely complete the investigation shall apply but 

BPP shall retain the right to dispute, under the dispute resolution provisions of this Consent 

Decree, any demand for stipulated penalties that was issued as a result of BPP’s failure to timely 

complete the investigation. Nothing in this Subparagraph shall be deemed to excuse BPP from 

its investigation, reporting, recordkeeping, and corrective action obligations of this Subsection H 

for any Reportable Flaring Incident that occurs after a Reportable Flaring Incident for which BPP 

has requested an extension of time. 

g. To the extent that completion of the implementation of corrective 

action(s), if any, is not finalized by 45 days after the end of a Reportable Flaring Incident, then 

BPP will include in each semi-annual report due under Part VIII of this Decree, an identification 

of the corrective action(s) taken or still to be taken and the dates of commencement and 

completion, or proposed completion, of implementation. 

h. For Acid Gas and Tail Gas Incidents only: A statement that: 

(i) specifically identifies each of the grounds for stipulated penalties in Paragraphs 61, 62, and 63 

of this Appendix and describes whether the Acid Gas Flaring or Tail Gas Incident falls under any 

of those grounds; (ii) if an Acid Gas Flaring or Tail Gas Incident falls under Paragraph 65 of this 

Decree, describes which Subparagraph -- 63.a or 63.b -- applies and why; and (iii) if an Acid Gas 

Flaring or Tail Gas Incident falls under either Paragraph 62 or 63.b, states whether or not BPP 

asserts a defense, and if so, a description of the defense. BPP shall not be required to comply 

with the requirements of this Subparagraph if BPP chooses, instead, to submit a payment of 

stipulated penalties in the nature of settlement at the time that it submits the semi-annual report, 

see Paragraph 57, that includes the report completed under this Paragraph. Such payment of 

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stipulated penalties shall not constitute an admission of liability, nor shall it raise any 

presumption whatsoever about the nature, existence or strength of BPP’s potential defenses 

55. Corrective Action Implementation. 

a. In response to any Reportable Flaring Incident, BPP shall take, as 

expeditiously as practicable, such interim and/or long-term corrective actions, if any, as are 

consistent with good engineering practice to minimize the likelihood of a recurrence of the Root 

Cause, including all contributing causes, of that Reportable Flaring Incident. 

b. EPA does not, by its agreement to the entry of this Consent Decree or by 

its failure to object to any corrective action that BPP may take in the future, warrant or aver in 

any manner that any of BPP’s corrective actions in the future will result in compliance with the 

provisions of the Clean Air Act or its implementing regulations. Notwithstanding EPA’s review 

of any plans, reports, corrective actions or procedures under this Subsection I, BPP shall remain 

solely responsible for non-compliance with the Clean Air Act and its implementing regulations. 

Nothing in this Paragraph shall be construed as a waiver of EPA’s rights under the Clean Air Act 

and its regulations for future violations of the Act or its regulations. 

c. After a review of any report required by Paragraph 54 and submitted as 

required by Paragraph 57, EPA shall notify BPP in writing of: (i) any deficiencies in the 

corrective actions listed in the findings; and/or (ii) any objections to the schedules of 

implementation of the corrective actions and explain the basis for EPA’s objections. If BPP has 

not commenced a corrective action that EPA has identified as deficient, BPP will implement an 

alternative or revised corrective action or implementation schedule based on EPA’s comments. 

If a corrective action that EPA has identified as deficient has already commenced or is already 

completed, then BPP is not obligated to implement corrective action identified by EPA for that 

Reportable Flaring Incident provided that BPP completes the corrective action that it has 

identified and commenced. 

d. For purposes of Paragraph 55.c, “commenced” means BPP 

has: (i) commenced actual physical construction on the corrective action; or (ii) completed the 

engineering design for the corrective action and has purchased or entered into a binding 

contractual obligation (with adverse consequences from its breach) to purchase equipment 

necessary to implement the corrective action. However, BPP will be put on notice that such 

corrective action is deficient and not acceptable for remedying any subsequent, similar Root 

Cause(s) of any Reportable Flaring Incident. If EPA and BPP cannot agree on the appropriate 

corrective action(s) or implementation schedule(s), if any, to be taken in response to a Root 

Cause, either party may invoke the Dispute Resolution provisions of Part XIV of the Consent 

Decree. 

e. Nothing in this Subsection I shall be construed to limit the right of BPP to 

take such corrective actions as it deems necessary and appropriate immediately following a 

Reportable Flaring Incident or in the period during preparation and review of any reports 

required under this Paragraph. 

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56. Exceptions to the Requirements in Paragraphs 54 and 55 for Certain HC Flaring 

Incidents. The requirements of Paragraphs 54 and 55 shall not apply to the following 

Hydrocarbon Flaring Incidents: 

a. For the six (6) month period after the installation of a Flare Gas Recovery 

System (that is, during the time in which the FGRS is being commissioned), for each Root 

Cause, including all contributing causes, that is directly related to the commissioning of the 

FGRS; 

b. For each Root Cause, including contributing causes, that BPP previously 

had analyzed as attributable to the startup or shutdown of a unit; in such cases, BPP may rely 

upon and cross-reference the prior analysis. 

57. Submitting the Internal Flaring Incident Reports to EPA and IDEM. In each 

semi-annual report due under Part VIII of this Consent Decree, BPP shall include copies of each 

Reportable Flaring Incident report that BPP was required to prepare in compliance with 

Paragraph 54 during the six month period that the semi-annual report covers. Each semi-annual 

report also shall include summary of each of the Incidents including the following: 

a. Date; 

b. Duration; 

c. Amount of SO2 and VOC released; 

d. Root Cause(s); 

e. Corrective Action(s) completed; 

f.	 Corrective Action(s) still outstanding; 

g. Stipulated penalties, if any, due 

h. An analysis of any trends identified by BPP in terms of the number of 

Incidents, the Root Causes, or the types of Corrective Action 

58. Calculating SO2 Emissions. The equations for calculating sulfur dioxide 

emissions from Reportable Flaring Incidents are set forth in Appendix FLR-18. 

59. Reserved. 

J. Stipulated Penalties for Acid Gas Flaring Incidents and Tail Gas Incidents 

60. An Acid Gas Flaring Incident or a Tail Gas Incident, in and of itself, may subject 

BPP to stipulated penalties under this Subsection J. A Hydrocarbon Flaring Incident, in and of 

itself, will not subject BPP to stipulated penalties under this Subsection J. However, a failure by 

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BPP to comply with all other provisions of Subsection I, including Root Cause Analysis, internal 

reporting, recordkeeping, and corrective action, may subject BPP to stipulated penalties 

regardless of whether the type of Reportable Flaring Incident was an Acid Gas, Tail Gas or 

Hydrocarbon Flaring Incident. Stipulated penalties for those other potential violations are found 

in Part X of this Decree (“Stipulated Penalties”). 

61. The stipulated penalties in Paragraph 66 of this Appendix shall apply to each Acid 

Gas Flaring or Tail Gas Incident for which the Root Cause is one or more of the following acts, 

omissions, or events: 

a. Error resulting from careless operation by the personnel charged with 

responsibility for the sulfur recovery plant, the Tail Gas Unit, or process 

units upstream of the sulfur recovery plant; 

b. Failure to follow written procedures; or 

c. A failure of equipment that is due to a failure by BPP to operate and 

maintain that equipment in a manner consistent with good engineering 

practice. 

62. If the Root Cause of the Acid Gas Flaring or Tail Gas Incident is not identified in 

Paragraph 61, then, except as provided in Paragraph 64, stipulated penalties in Paragraph 66 of 

this Appendix shall apply if the Acid Gas Flaring or Tail Gas Incident: 

a. Results in emissions of SO2 at a rate greater than twenty (20.0) pounds per 

hour continuously for three (3) consecutive hours or more and BPP failed 

to take any action during the Acid Gas Flaring Incident to limit the 

duration and/or quantity of SO2 emissions associated with such incident; 

or 

b. Causes the total number of Acid Gas Flaring Incidents in a rolling twelve 

(12) month period to exceed five (5). 

63. With respect to any Acid Gas Flaring or Tail Gas Incident that does not fall under 

either Paragraph 61 or 62, the following provisions shall apply: 

a. First Time: If the Root Cause of the Acid Gas Flaring or Tail Gas Incident 

was not a recurrence of the same Root Cause that resulted in a previous 

Acid Gas Flaring or Tail Gas Incident that occurred since the Date of 

Entry, then: 

i. If the Root Cause of the Acid Gas Flaring or Tail Gas Incident was 

sudden, infrequent, and not reasonably preventable through the 

exercise of good engineering practice, then that cause shall be 

designated as an agreed-upon Malfunction for purposes of 

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reviewing subsequent Acid Gas Flaring and Tail Gas Incidents; the 

stipulated penalty provisions of Paragraph 66 shall not apply. 

ii. If the Root Cause of the Acid Gas Flaring Incident was sudden and 

infrequent, but was reasonably preventable through the exercise of 

good engineering practice, then BPP shall implement corrective 

action(s) pursuant to Paragraph 55, but the stipulated penalty 

provisions of Paragraph 66 shall not apply. 

b. Recurrence: If the Root Cause is a recurrence of the same Root Cause that 

resulted in a previous Acid Gas Flaring or Tail Gas Incident that occurred 

since the Date of Entry, then BPP shall be liable for stipulated penalties 

under Paragraph 66 unless: 

i. The AG Flaring or Tail Gas Incident resulted from a Malfunction 

or other defense that BPP successively asserts; or 

ii. The Root Cause previously was designated as an agreed-upon 

Malfunction under Paragraph 63.a.i; or 

iii.	 The Acid Gas Flaring or Tail Gas Incident had as its Root Cause 

the recurrence of a Root Cause for which BPP had previously 

developed, or was in the process of developing, a corrective action 

plan and for which BPP had not yet completed implementation. 

64. Defenses. By definition, the Root Causes identified in Paragraph 61 are not 

Malfunctions or Force Majeure events, and therefore, BPP shall have not have a Malfunction or 

Force Majeure defense to a demand for stipulated penalties that is based on the Root Causes 

identified in Paragraph 61. For Incidents under Paragraphs 62 - 63, BPP may assert a 

Malfunction or Force Majeure defense. In addition, in any dispute under Paragraphs 62 and 63, 

BPP may also assert a Startup and/or Shutdown defense, but the United States shall be entitled to 

assert that such defenses are not available. 

65. If no Acid Gas Flaring Incident (other than ones caused by a Malfunction or Force 

Majeure) and no Tail Gas Incident (other than ones caused by a Malfunction or Force Majeure) 

occur for a rolling 36-month period, then the stipulated penalty provisions of Paragraph 68 shall 

no longer apply. EPA may elect to reinstate the stipulated penalty provisions if the Refinery has 

an Acid Gas Flaring Incident which would otherwise be subject to stipulated penalties. EPA’s 

decision shall not be subject to dispute resolution. Once reinstated, the stipulated penalty 

provision shall thereafter apply to future Acid Gas Flaring and Tail Gas Incidents and shall 

continue for the remaining life of this Consent Decree. 

66. Stipulated Penalty Table for Acid Gas Flaring and Tail Gas Incidents 

a. The following table shall be used to calculate stipulated penalties that become due 

under Paragraphs 61 - 64: 

39
 
 


 

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Tons of SO2 Emitted 

in Acid Gas Flaring 

Incident 

Length of Time from 

Commencement of 

Flaring within the 

Acid Gas Flaring 

Incident to 

Termination of 

Flaring within the 

Acid Gas Flaring 

Incident is 3 hours or 

less 

Length of Time from 

Commencement of 

Flaring within the 

Acid Gas Flaring 

Incident to 

Termination of 

Flaring within the 

Acid Gas Flaring 

Incident is greater 

than 3 hours but less 

than or equal to 24 

hours 

Length of Time from 

Commencement of 

Flaring within the 

Acid Gas Flaring 

Incident to 

Termination of 

Flaring within the 

Acid Gas Flaring 

Incident is greater 

than 24 hours 

5 Tons or Less $500 per ton $750 per ton $1000 per ton 

Greater than 5 tons, 

but less than or equal 

to 15 tons 

$1,200 per ton $1,800 per ton $2,300 per ton, up to, 

but not exceeding, 

$32,500 in any one 

calendar day 

Greater than 15 tons $1,800 per ton, up to, 

but not exceeding, 

$32,500 in any one 

calendar day 

$2,300 per ton, up to, 

but not exceeding, 

$32,500 in any one 

calendar day 

$32,500 in any one 

calendar day 

b. For purposes of calculating stipulated penalties pursuant to this Paragraph, 

only one cell within the matrix shall apply. Thus, for example, for an Acid Gas Flaring Incident 

in which the Acid Gas Flaring starts at 1:00 p.m. and ends at 3:00 p.m., and for which 14.5 tons 

of SO2 are emitted, the penalty would be $17,400 (14.5 x $1,200); the penalty would not be 

$13,900 [(5 x $500) + (9.5 x $1200)]. 

c. For purposes of determining which column in the table applies under 

circumstances in which Acid Gas Flaring occurs intermittently during an Acid Gas Flaring 

Incident, the Acid Gas Flaring shall be deemed to commence at the time that the Acid Gas 

Flaring that triggers the initiation of an Acid Gas Flaring Incident commences, and shall be 

deemed to terminate at the time of the termination of the last episode of Acid Gas Flaring within 

the Acid Gas Flaring Incident. Thus, for example, for Acid Gas Flaring within an Acid Gas 

Flaring Incident that (i) starts at 1:00 p.m. on Day 1 and ends at 1:30 p.m. on Day 1; (ii) 

recommences at 4:00 p.m. on Day 1 and ends at 4:30 p.m. on Day 1; (iii) recommences at 1:00 

a.m. on Day 2 and ends at 1:30 a.m. on Day 2; and (iv) no further Acid Gas Flaring occurs within 

the Acid Gas Flaring Incident, the AG Flaring within the AG Flaring Incident shall be deemed to 

last 12.5 hours – not 1.5 hours – and the column for Acid Gas Flaring of “greater than 3 hours 

but less than or equal to 24 hours” shall apply. 

K. Miscellaneous

 67. Temporary-Use Flares. 

40
 
 


 

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a. Applicability. The provisions of this Paragraph shall apply to 

Temporary-Use Flares.

 b. Distinction between Planned and Unplanned Outages of Covered Flares. 

For purposes of this Paragraph, a “planned” outage of a Covered Flare shall mean an outage that 

is scheduled 30 days or more in advance of the outage. An “unplanned” outage is an outage that 

either is scheduled less than 30 days in advance or is unscheduled. 

c. 504 hours or less. For any planned or unplanned outage of a Covered 

Flare that BPP knows or reasonably anticipates will result in 504 hours or less of downtime on a 

rolling 1095 day average period, BPP shall make good faith efforts to ensure that the 

Temporary-Use Flare that replaces the Covered Flare complies with all of the requirements of 

this Consent Decree that are applicable to the Covered Flare that the Temporary-Use Flare 

replaces. 

d. More than 504 hours. 

i. Planned. For any planned outage of a Covered Flare that BPP 

knows or reasonably can anticipate will last 504 hours or more on a rolling three-year average 

period, BPP shall ensure that the Temporary-Use Flare complies with all of the requirements of 

this Appendix related to the Covered Flare that it replaces as of the date that the Temporary-Use 

Flare is placed into service. 

ii. Unplanned. For any unplanned outage of a Covered Flare that, in 

advance of the outage, BPP cannot reasonably anticipate will last longer than 504 hours, BPP 

shall ensure that the Temporary-Use flare complies with all of the requirements of this Appendix 

related to the Covered Flare that it replaces by no later than 30 days after the date that BPP 

knows or reasonably should have known that the outage would last 504 hours or more. 

e. Recordkeeping. BPP shall keep records sufficient to document 

compliance with the requirements of this Paragraph any time it uses a Temporary-Use flare.

 68. Miscellaneous. Whenever this Appendix requires compliance within a certain 

number of “months” after a triggering event, the compliance obligation commences on the 

anniversary of the numerical date that triggers the obligation. For example, if compliance is 

required by no later than three months after the submission of a particular document, and if the 

document is submitted on March 23, 2010, the compliance obligation commences on June 23, 

2010. 

L. NSPS Subparts A, J, and Ja Applicability for Flares 

69. NSPS Subparts A and J. 

a. Beginning on the Date of Entry, and continuing until they become subject 

to the provision of 40 C.F.R. Part 60, Subpart Ja under Paragraph 70, the DDU and LPG Flares 

will each continue to be an “affected facility” within the meaning of Subparts A and J of 40 

41
 
 


 


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C.F.R. Part 60, will be subject to Subparts A and J, and will comply with the requirements of 

Subparts A and J, including all monitoring, recordkeeping, reporting, and operating 

requirements. 

b. Beginning upon the date of initial startup, and continuing until they 

become subject to the provisions of 40 C.F.R. Part 60, Subpart Ja under Paragraph 70, the South 

and GOHT Flares shall each be an “affected facility” within the meaning of Subparts A and J of 

40 C.F.R. Part 60. No later than 180 Days after the date of initial startup, and continuing until 

they become subject to the provisions of 40 C.F.R. Part 60, Subpart Ja under Paragraph 70, the 

South and GOHT Flares shall comply with the requirements of Subparts A and J, related to 

Flares, including all monitoring, recordkeeping, reporting, and operating requirements. 

c. Beginning on the dates by which they are required to be tied into a FGRS 

under Paragraph 23 and continuing until they become subject to the provisions of 40 C.F.R. Part 

60, Subpart Ja under Paragraph 70, the VRU, Alky, FCU, UIU and 4UF Flares shall each be an 

“affected facility” within the meaning of Subparts A and J of 40 C.F.R. Part 60, will be subject to 

Subparts A and J, and will comply with the requirements of Subparts A and J, including all 

monitoring, recordkeeping, reporting, and operating requirements. 

70. NSPS Subpart Ja. 

a. The DDU and the LPG Flare will each be an “affected facility” within the 

meaning of Subpart Ja of 40 C.F.R. Part 60, will be subject to Subpart Ja, and will comply with 

the requirements of Subpart Ja, including all monitoring, recordkeeping, reporting, and operating 

requirements, by the later of the Date of Entry or the date of compliance required by Subpart Ja 

when the stay of Subpart Ja no longer is in effect. The other Covered Flares will each be an 

“affected facility” within the meaning of Subpart Ja of 40 C.F.R. Part 60, will be subject to 

Subpart Ja, and will comply with the requirements of Subpart Ja, including all monitoring, 

recordkeeping, reporting, and operating requirements, by the later of: (i) the date by which that 

Flare is required to be tied into a FGRS under Paragraph 23; or (ii) the date of compliance 

required by Subpart Ja when the stay of Subpart Ja no longer is in effect. 

b. For each Covered Flare and the LPG Flare, upon the date that each such 

flare becomes an “affected facility” as set forth in Subparagraph 70.a, the requirements in 

Sections I. and J. of this Appendix will no longer be applicable to such flare. 

M. Decommissioning the SRU Flare

 71. SRU Flare. By no later than 180 days after initial startup of the new Coker, BPP 

shall permanently decommission the SRU Flare. For purposes of this Paragraph, “permanently 

decommissioned” means the waste gas piping has been disconnected from the SRU Flare by the 

installation of a welded blind on the piping. By no later than six months after permanently 

decommissioning the SRU Flare, BPP shall submit a request to IDEM to amend the Title V 

permit to reflect the permanent disconnection of this flare. 

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N. Reporting Requirements for this Appendix 

72. Monitoring Instrument/Equipment Downtime, Override of Automatic Control 

System, and Emissions Exceedances. On and after the date of applicability of any work practice 

or standard, BPP shall provide a summary of the following, per Covered Flare and the LPG Flare 

per calendar quarter (hours shall be rounded to the nearest tenth): 

a. Monitoring Instrument/Equipment Downtime. The total number of hours 

of downtime of each monitoring instrument/equipment required pursuant to Paragraphs 7-9, 11­

13 (and, if applicable, Paragraph 42), expressed as both an absolute number and a percentage of 

time the Covered Flare and the LPG Flare that the instrument/equipment monitors is available 

for operation; 

b. Monitoring Instrument/Equipment Downtime. If the total number of 

hours of downtime of any monitoring instrument/equipment required pursuant to Paragraphs 7-9, 

11-13 (and, if applicable, Paragraph 42), exceeds 110 hours in any calendar quarter, an 

identification of the periods of downtime by date, time, cause (including Malfunction or 

maintenance), and, if the cause is asserted to be a Malfunction, the corrective action taken; 

c. Override of Automatic Control System. The total number of hours in 

which BPP overrode the Automatic Control System required in Paragraph 30 (and, if applicable, 

Paragraph 42), expressed as both an absolute number of hours and a percentage of time the 

Covered Flare and the LPG Flare was available for operation; provided however, that for any 

hour identified, the report shall describe either or both of the following: (i) if the reason for the 

override was one of the exceptions identified in Paragraph 31, a statement of which exception; or 

(ii) if the total number of hours in which the Automatic Control System was overrode was less 

than 110 hours and was caused by one or more of the exceptions identified in Paragraph 51, a 

statement to that effect; 

d. Override of Automatic Control System. If the reason for the override was 

not one of the exceptions set forth in Paragraphs 31 or 45 or if the total number of hours in which 

the Automatic Control System was overrode exceeds 110 hours in any calendar quarter, an 

identification of the periods of override by the date, time, duration, reason for the override, and 

corrective actions taken; 

e. Inapplicability of Emissions Standards. The total number of hours in 

which the requirements of Paragraphs 33-36 were not applicable because the only gas or gases 

being vented was/were Pilot Gas and/or Purge Gas, expressed as both an absolute number of 

hours and a percentage of time the Covered Flare and/or the LPG Flare was available for 

operation; for purposes of Subparagraphs 72.f. and 72.g, all remaining hours shall be termed 

“Hours of Applicability”; 

f. Exceedances of Standards. During the Hours of Applicability, the total 

number of hours of exceedances of the standards in Paragraphs 33.b, 34.a, 34.b, 36 (and, if 

applicable, Paragraph 45), expressed as both an absolute number of hours and a percentage of 

time the Covered Flare and the LPG Flare was available for operation; provided however, that if 

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the exceedance of these standards was less than 110 hours in the calendar quarter and was due to 

one or more of the exceptions set forth in Paragraph 51, the report shall so note; 

g. Exceedances of Standards. During the Hours of Applicability, if the 

exceedance of the standards in Paragraphs 33.b, 34.a, 34.b, 36 (or, if applicable, Paragraph 45), 

was not due to one of the exceptions in Paragraph 51, or if the exceedance was due to one or 

more of the exceptions in Paragraph 51 but the total number of hours caused by the exceptions in 

Paragraph 51 was greater than 110, an identification of each averaging period that exceeded the 

standard, by time and date; the cause of the exceedance (including startup, shutdown, 

maintenance, or Malfunction), and if the cause is asserted to be a Malfunction, an explanation 

and any corrective actions taken; and 

h. Flaring Limitations Exceedances. 

i. For any Waste Gas flows that are excluded from the calculation of 

flow rate because they are asserted to be based on one or more of 

the excludible events identified in Paragraph 28.b, the information 

required in Paragraph 28.d; 

ii.	 An identification of each calendar day in which the limitations on 

flaring set forth in Paragraph 26 (or 27, if applicable) were 

violated; 

iii.	 The cause of the exceedance; 

iv. If the cause is asserted to be a Malfunction, an explanation and any 

corrective actions taken; 

v. A quantification of the total flow and a calculation of the percent 

over the standard. 

73. Emissions Data. In the semi-annual report that is required to be submitted by 

Paragraph 99 of Part VIII of the Consent Decree by August 15 of each year, BPP shall provide, 

for each Covered Flare and the LPG Flare, for the prior calendar year, the amount of emissions 

of the following compounds (in tons per year): VOCs, SO2, H2S, CO2, methane, and ethane. 

44
 
 

Appendix FLR-1
 

Type I Type ][ 

Upper 

Steam 

Center 

Steam 

Stability R"'Il 

Exit Lower 

Steam/Air 

M" ture 

= Vent Gas 

= Fire 

= Steam l Air 

= Steam 

Key 

Yellow 

Red 

Light Blue 

Dark Blue 

Lower 

Steam 

Center 

Steam • 

Upper 

Steam 

Stability Tab 

Stability Tab 

T yp e 1::B 

Pilot 

Upper 

Steam 

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 page 212 of 324 

46
 
 


 



 



 


 


 


 

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APPENDIX FLR-2 

GENERAL EQUATIONS 

Equation 1: “Combustion Efficiency” or “CE”: 

CE = [CO2]/([CO2] + [CO] + [OC])

 where: 

[CO2] = Concentration in volume percent or ppm-meters of carbon dioxide 

in the combusted gas immediately above the Combustion Zone 

[CO] = Concentration in volume percent or ppm-meters of carbon 

monoxide in the combusted gas immediately above the Combustion Zone 

[OC] = Concentration in volume percent or ppm-meters of the sum of all 

organic carbon compounds in the combusted gas immediately above the Combustion Zone, 

counting each carbon molecule separately where the concentration of each individual compound 

is multiplied by the number of carbon atoms it contains before summing (e.g., 0.1 volume 

percent ethane shall count as 0.2 percent OC because ethane has two carbon atoms) 

For purposes of using the CE equation, the unit of measurement for CO2, CO, and OC must be 

the same; that is, if “volume percent” is used for one compound, it must be used for all 

compounds. “Volume percent” cannot be used for one or more compounds and “ppm-meters” 

for the remainder. 

Equation 2: “Center Steam Mass Flow Rate” or “ṁs-cen”: 

ṁs-cen = Qs-cen x (18/385.5)

 where: 

Qs-cen = Center Steam Volumetric Flow Rate 

Equation 3: “Total Steam Mass Flow Rate” or “ṁs”: 

ṁs = Qs x (18/385.5)

 where: 

Qs Total Steam Volumetric Flow Rate 
 


 


 


 


 

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Equation 4: “Vent Gas Mass Flow Rate” or “ṁvg”: 

ṁvg = Qvg x (MWvg/385.5) 

where: 

Qvg = Vent Gas Volumetric Flow Rate 

MWvg = Molecular Weight, in pounds per pound-mole, of the Vent Gas, as measured by 

the Vent Gas Average Molecular Weight Analyzer system described in Paragraph 8 of this 

Consent Decree 

(End of Appendix FLR-2) 
 


 



 


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APPENDIX FLR-3 

CALCULATING NHVcz-limit AND NHVcz FOR STEAM-ASSISTED FLARES 

All abbreviations, constants, and variables are defined in the Key on Pages FLR-3-6 and 

FLR-3-7 (“Key to the Abbreviations”) of this Appendix. 

Steps in the Calculations 

Step 1: Determine the Lower Flammability Limit (“LFL”) of Each Individual Vent Gas 

Compound 

Take the LFL values of each individual Vent Gas compound from Table 1 in this Appendix. 

Step 2: Calculate the LFL of the vent gas mixture 

The average lower flammability limit of the vent gas is calculated by Le Chatelier’s equation 

shown below as Equation 1. This calculation uses the weighted average of the LFLs of the 

individual compounds weighted by their volume percent of the vent gas. All inerts, including 

nitrogen, are assumed to have an infinite lower flammability limit (e.g. LFLN2 = ∞). 

1

ܮܨܮ௩௚ ൌ ௡ ݔ ௜Equation 1 ∑ ቀ ቁ ܨܮܮ௜ ௜ ୀଵ

Step 3: Determine the Net Heating Value of the Vent Gas (NHVvg) 

If a Gas Chromatograph is used: The net heating value of the vent gas is calculated and 

reported from the GC data at the conclusion of each analytical cycle (~10-15 minutes). Equation 

2 is used to calculate the vent gas net heating value from each individual compound net heating 

value. Individual compound volume fractions are measured directly by the GC. A company is 

not required to measure water in Vent Gas, but if it chooses to measure water, then it must 

include water in the calculation of the NHVvg and adjust the concentration of the compounds 

measured by the GC to a wet basis. Individual compound net heating values, including water, 

are listed in Table 1 of this Appendix. 

௡

ܰܪܸ௩௚ ൌ ෍ሺݔ ௜ ௜ܸܪ ·ܰ ሻ Equation 2 

௜ୀଵ

If a Net Heating Value Analyzer/Calculator is used: Use the measured value. 

NOTE: Table 1 includes two alternative values for the Net Heating Value of hydrogen: the 

actual NHV of hydrogen (274 BTU/scf) and an “adjusted” NHV of hydrogen (1212 BTU/scf). 

Companies have the option of using either in calculating NHVvg; however, whichever option is 

selected also must be used in calculating NHVcz. 

FLR-3-1 
 

 



 



 

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Step 4: Calculate the NHVvg at its LFL (NHVvg-LFL) 

Using LFLvg from Equation 1 and NHVvg from Equation 2, the NHVvg-LFL is calculated by 

Equation 3. 

ܰܪܸ௩௚–௅ி௅ ൌ ܰ ܸܪ ௩௚ ܨܮ ·ܮ ௩௚ Equation 3 

Step 5: Multiply NHVvg-LFL by the Combustion Efficiency Multipliers to calculate the 

NHVcz-limit 

The Net Heating Value of the Gases in the Combustion Zone (NHVcz) of a Flare that is needed to 

ensure an acceptable Combustion Efficiency is determined by multiplying NHVvg-LFL by 

Combustion Efficiency Multipliers appropriate to the flare category and the volume percent of 

hydrogen in the Vent Gas as defined in Table 2. 

The Net Heating Value of Combustion Zone Gas Limit is calculated as follows: 

ܰܪܸ௖௭ି௟௜௠௜௧ ൌ ൫ܣ൅ ܤ·ݔ௣௢௥௣௬௟௘௡௘൯·ܰ ܸܪ ௩௚ି௅ி௅ Equation 4 

Step 6: Calculate the Net Heating Value of the Combustion Zone Gas (NHVcz) 

The NHV in the combustion zone (NHVcz) combines the NHVs of the Vent Gas, pilot gas, and 

steam and is calculated by Equation 5a (based on mass flow measurement) or 5b (based on 

volumetric flow measurement). These two equations are equivalent for combustion zone 

conditions, as shown in Addendum A to this Appendix. The NHV of steam is assumed to be 

) and steam flow rate ( ݒ݃ zero. Vent Gas flow rate (mሶ vg ݎ݋ ܳ ( are calculated from on-line ݏ mሶ s ݎ݋ ܳ

) is constant for each flare and set by an ݌݃ flow meters. The pilot gas mass flow rate (mሶ pgݎ݋ ܳ

orifice. 

݉ሶ ௩௚ ௣௚

ܯܹ ൰ ൅ ൬ ܯܹ ൬ ௩௚ ௣௚

݉ሶ ௩௚ ܸܪ ·ܰ ௩௚

௚௩ܹܯ

݉ሶ

௚௣ ܰ ·ܪܸ ௚௣ ሶ݉

ܯܹ ௚௣൬ ൰ ൅ ൬ ൰

݉ሶ ܰܪܸ௖௭ ൌ Equation 5a ௔௜௥

ܯܹ ൰ ൅ ቀ ௔௜௥

ሻ Equation 5b 

൰ ൅ ൬ ቁ ݉௦ሶ

ுమைܹܯ

OR
 

൫ܳ௩௚ כ ܸܪܰ ௩௚൯൅ሺܳ௣௚ ܸכܪ ܰ ௚௣ ܰܪܸ௖௭ ൌ ܳ௩௚ ൅ ܳ௣௚ ൅ ܳ௦ ൅ ܳ௔௜௥

FLR-3-2 
 


 

 
 

 

 

 

 


 
 

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The values for , ݉ሶ ௔௜௥, Qs, and Qair are determined as follows based on the type of flare: ݉௦ሶ

Steam-Assisted Flare without a Minimum Steam Reduction System (“MSRS”) 

ݏ ݁ݑ ݈ܽ ݒ ݎ݀݁ ݑ ܽ݁ݏ ݉ ൌ ܳ ݎ݋ ௦ ሶ݉

ܳ ݎ݋ ௥௜௔ ሶ݉

Steam-Assisted Flare with MSRS 

݉௦ሶ

݉௔௜௥ ሶ

ݎܽ݅ 0 ൌ

ݏ ݁ݑ ݈ܽ ݒ ݀݁ ݎݑ ܽ݁ݏ ݉ ൌ ܳ ݎ݋

6ܽ ݌݁ݐܵ ݅݊ 13 ݊݋݅ݐܽݑݍܧ ݉݋ݎ݂ ݐ݈ݑݏ݁ݎ ൌ ݎܳܽ݅ ݎ݋

OR 

݉௔௜௥ ሶ

not capable ሺeven at minimum vent gas flowሻ of inspirating more than twice the 

stoichiometric volume of air into the vent gas.

The molecular weight of the vent gas (MWvg) is calculated from the GC data using Equation 6. 

An on-line ultrasonic flow meter may also be used to calculate MWvg. 

molecular weights are listed in Table 1 of this Appendix. 

Individual compound 

௡

ܯܹ௩௚ ൌ ෍

௜ୀଵ

ሺݔ ௜ܹ · ௜ܯ ሻ Equation 6 

The NHV of the pilot gas (NHVpg) and MW of the pilot gas (MWpg) are calculated using 

Equations 7 and 8, respectively. These calculations are similar to the vent gas calculations, 

except the individual compound volume fractions are that of the pilot gas and not the vent gas. 

Individual compound volume fractions are measured by laboratory analysis of a pilot gas sample, 

or may be taken from the natural gas supplier’s laboratory certificate of analysis. 

௡

௚௣ܸܪܰ

ݎ݋ ܳܽ݅ݎ ൌ 0 with vendor certification that the MSRS equipment installed on the flare is 

ൌ ෍ሺ݌݃ · ௜ܰ ܸܪ௜ ሻ Equation 7

௜ୀଵ

௡

ሺ௜ ݃݌

௜ୀଵ

Step 6a: Calculation of air mass flow rate for flares equipped with MSRS. 

The complete combustion of an organic compound comprised of a combination of carbon and 

hydrogen atoms is shown in Equation 9: 

ܯܹ ௚௣ൌ ෍ ܹ௜ · ܯ ሻ Equation 8 

ݕ ݕ ܪ௬ ൅ ቀݔ ൅ ቁ ܱଶ ՜ ܥݔܱଶ ൅ ቁቀ ܪଶܱ Equation 9 4 2 ܥ௫

Note: x and y values for each compound are found in Table 1 of this Appendix. 

FLR-3-3 
ሶ

 

 

 
 

 

 


 


 


 

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Therefore, the stoichiometric oxygen molar flow rate (moles/hr) for any given combustible 

compound flow is defined by Equation 10a (mass basis) or Equation 10b (volumetric basis): 

݉ሶ ௩௚ ݊ሶ ቀݔ ൅ ݕ 


4 ைଶି௦௧௢௜௖௛ ൌ ݔ ௝ቆ ቁ Equation 10a ܯܹ௩௚

ቇ

ܱܴ

ܳ௩௚ ൰ ቀݔ ൅ ݕ

4 ൬ ቁ Equation 10b ݊ைଶି௦௧௢௜௖௛ ൌ ݔ ௝385.5 


The stoichiometric oxygen mass flow rate for the vent gas (lb/hr) or stoichiometric oxygen 

volumetric flow rate for the vent gas (scfh) is given by Equation 11a (mass basis) or 11b 

(volumetric basis). 

௡

݉ሶைଶି௦௧௢௜௖௛ି௩௚ ൌ ܯܹைమ כ෍ 

௝ୀଵ

௡

Equation 11a ைଶି௦௧௢௜௖௛ೕ ݊ሶ

ܱܴ

ܳைଶି௦௧௢௜௖௛ି௩௚ ൌ 385.5 כ ைଶି௦௧௢௜௖௛ೕ ݊ሶ

௝ୀଵ

The stoichiometric air mass flow rate (lb/hr) or stoichiometric air volumetric flow rate (scfh) for 

the vent gas is given by Equation 12a (mass basis) or Equation 12b (volumetric basis). 

෍ Equation 11b 

௥௜௔ܹܯ

0.21 ݉ሶ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ൌ כ ݉ሶைଶି௦௧௢௜௖௛ି௩௚ ܹܯ ைమ ·

ܱܴ

݃ݒ݃ݒെ݄݅ܿ݋ݐݏെܱܳ2

Equation 12a 

ൌ Equation 12b ܳ௔௜௥ି௦௧௢௜௖௛ି௩௚ 0.21
 

The air mass flow (lb/hour) or air volumetric flow (scfh) used in Equation 5a or 5b is given by 

subtracting two times the stoichiometric air from the total air provided by the MSRS. This is 

shown in Equation 13. 

݉ሶ ௔௜௥ ൌ ݉ሶ ௔௜௥ିெௌோௌ െ ሺ2כ݉ሶ ௔௜௥ି௦௧௢௜௖௛ି௩௚ሻ Equation 13a 

FLR-3-4 
 


 

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ܱܴ

ܳ௔௜௥ ൌ ܳ௔௜௥ିெௌோௌ െ ሺ2כܳ௥௜௔ି௦௧௢௜௖௛ି௩௚ሻ Equation 13b 

The equation for ݉ሶ ௔௜௥ିெௌோௌ or ܳ௔௜௥ିெௌோௌ is specific to the MSRS installed and must be provided

by the MSRS vendor. The factor of 2 used in Equation 13 is based on the best information 

available as of the Date of Lodging. If new information becomes available thereafter, the parties 

may modify that factor; any such modification does not constitute a material modification to the 

Consent Decree. 

݉ሶ ௔௜௥ ൏ 0 then ݉ሶ ௔௜௥ ൌ 0

If ܳ௔௜௥ ݐ ൏0 ݄ܳ݊݁ ௥௜௔ ൌ 0

If 

OR 

Step 7: Ensure that during flare operation, NHVcz ≥ NHVcz-limit 

The flare must be operated to ensure that NHVcz is equal to or above NHVcz-limit to ensure an 

acceptable combustion efficiency. Equation 14 shows this relationship. 

ܰܪܸ௖௭ ൒ ܰ ܸܪ௖ ௭ି௟௜௠௜௧ Equation 14 

FLR-3-5 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


 


 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 221 of 325 page 220 of 324 

Key to the Abbreviations: 

ሻݎܽ݅ ݈݉݋ – ⁄݈ܾଶ ݈݉݋ܱ –݈ܾ ሺ0.21 ݎܽ݅ ݊݅ ݕݔ݋݁݊݃ ݋݂ ݊݋݅ݐܽܿݎ݂ ݈݁݉݋ 0.21

݈݋݉‐݂ܿ⁄݈ܾݏ 385.5ሺ ܾ݅ܿݑܿ ݐ݂݁݁ ݀ݎܽ݊݀ܽݐݏ ݏ݈݁݋݉ ݋ݐ ݊݀ݑ݋݌ ݉݋ݎ݂ ݊ܿ݋݊݋݅ݏݎ݁ݒ ൌ 385.5

݌݅ݐ݈ݑ݉ ݎ݅݁ ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݈݈ܽݎ݁ݒ݋ ൌ ܣ ௅ி௅ି௚௩ܸܪܰ ݎ݋݂ ሻݏݏ݈݁ݐ݊݅ݑሺ

ሻ

݈

݌݅ݐ݈ݑ݉ ݎ݅݁ ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݈݁݊݁ݕ݌݋ݎ݌ ൌ ܤ ௅ி௅ି௚௩ܸܪܰ ݎ݋݂ ሻݏݏ݈݁ݐ݊݅ݑሺ ݈

௚௩ܥ ሻ% ݈݋ݒሺ ݐ݁݊ݒ ݏ݃ܽ ݄݁ݐ ݅݊ ܱܸܥ ݋݂ ݊݋݅ݐܽݎݐܿ݁݊ ܿ݋݊ ൌ

ሻݏݏ݈݁ݐ݊݅ݑሺ 1 ݅݊ ܾ݈ܶܽ݁ ݅ ݉݊ݑ݈݋ܿ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݅

ሻݏݏ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݅݊ ݆ ݉݊ݑ݈݋ܿ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݆

ሻݏݏ݈݁ݐ݊݅ݑሺ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݄݁ݐ ݋݂ ݐ݊݁݊݋݌݉݋ܿ ݏݑ݋݁ݏ݃ܽ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݇

% ݋ݒ݈ ሻ ሺ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݂݋ ݐ݈݅݉݅ ݕݐ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݈ݎ݁ݓ݋ ൌ௜ ܮܨܮ

௚௩ܮܨܮ ሻ% ݋ݒ݈ ሺ ݏ݃ܽ ݐ݈݅݉݅ ݂݋ ݐ݁݊ݒ ݕݐ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݎ݁ݓ݋݈ ൌ

ሻݎ݈ܾ/݄ሺ ݎܽ݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ௔௜௥ ݉

݁ݐܽݎ ݂݋ ݏݏ݉ܽ ݓ݋݂݈ ݈ܽݐ݋ ൌݐ ெௌோௌି ௔௜௥ሶ݉

ݏ݄݅ܿ݋ݐ݉݅݋݅ݎݐܿ݁ ൌ௚ ௩ି௢௜௖௛௦௧ି௔௜௥

ሶ

݈ܾݎ/݄ ሺ ܽ݊ ܴܵܵܯ ݀݁ݕܾ ܿݑ݀݋ݎݐ݅݊ ܽݎ݅

ሻ ݄ݎ ݈ܾሺ/ ݏ݃ܽ ݐ݁݊ݒ ݄݁ ݐ ݎ݋݂ ݓ݋݂݈ ݎܽ݅

ሻ

݉ሶ

ݎ݈ܾ/݄ሺ ݉݋ܿ݋݌ݐ݊݁݊ ݏ݃ܽ ݊݁݋ݖ ݏݑ݊݋݅ݐ ܾ݉ ݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௞ ሶ݉

ሻݎ݈ܾ⁄݄ሺ ݎ݋݂ ݄݁ݐ ݐ݁݊ݒ ݏ݃ܽ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௚ ௩ି௢௜௖௛௦௧ିைଶ

ሻ

݉ሶ

ሻݎ݈ܾ/݄ሺ ݐ݋݈݅݌ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௣௚ ሶ݉

ݎ݈ܾ/݄ሺ ݁ܽ݉ݐݏ ݈ܽݐ݋ݐ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௦ ሶ݉

௚௩ ሶ݉ ሻݎ݈ܾ/݄ሺ ݐ݁݊ݒ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ

݊ሶݎ ݄⁄ ݈݋݉ሺ ݌݉݋ܿݑ݋݊݀ ݈ܽݑ݅݀ݒ݅݊݀݅ ݎ݋݂ ܽ݊ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ܿ݅ ݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௢௜௖௛ ௦௧ିைଶ

ுమܹܯ ሻ݈݋݉ –݈ܾ/݈ܾ 18.02ሺ ݎ݁ݐܽݓ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ை

ሻ

ሻ

ሻ݈݋݉ –݈ܾ/݈ܾሺ ݌݉݋ܿݑ݋݊݀ ݈ܽݑ݅݀ݒ݅݊݀݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௜ ܹܯ

݉݋݈ – ܾ݈ ݈ܾ/ሺݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ௞ ܹܯ

ைమܹܯ ሻ݈݋݉ –݈ܾ/݈ܾ 32.0ሺ ݃݁݊ݕݔ݋ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ

 28.9ሺ/ ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݈݁ܿ݉݋ݎ݈ܽݑ ൌ௔௜௥ ܹܯ

݈ܾሺ ݏ݃ܽ ݐ݋݈݅݌

ሻ

ሻ ݈݉݋ –݈ܾ ܾ݈

ሻ݈݋݉ –/݈ܾ ݋݂ ݐ݄݁݅݃ݓ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௣௚ ܹܯ

ሻ݈݋݉ –݈ܾ/݈ܾሺ ݐ݁݊ݒ ݏ݃ܽ ݐ݄݁݅݃ݓ ݂݋ ݈ݎܽ ݉ݑ݈݁ܿ݋ ൌ௚ ௩ܹܯ

ሻݏݏ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݉݋ݎ݂ ݏ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݂݋ ݐݏ݈݅ ൌ ݊

⁄ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݁ݑ݈ܽݒ ݂݋ ݄݁ݐ ݅݊݃ݐ݄݁ܽ ݐ݁ ൌ ௭௖ܸܪܰ

ݑ݋݌݉݋݊݀ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݁ݑ݈ܽݒ ݂݋ ݅݊݃ݐ݄݁ܽ ݊ݐ݁ ൌ௜ ܸܪܰ

ݏ ܷܶܤሺ ݐ݈݅݉݅ ݕݐ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݐܽ ݎ݁ݓ݋݈ ݁ݑ݈ܽݒ ݐ݁݊ݒ ݏ݃ܽ ݅݊݃ݐ݄݁ܽ ݐ݁ ൌ௅ ி௅ି௚௩ܸܪܰ

ሻ݂ܿݏ ܷܶܤሺ ݊

ሻ݂ܿݏܷܶ⁄ܤሺ

݊ ⁄
 ݂ܿሻ

ܷܶ⁄ܤሺ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݁ݑ݈ܽݒ ݂݋ ݄݁ݐ ݅݊݃ݐ݄݁ܽ ݐ݊݁ ݈ݐ݅݉݅ ൌ ௧௟௜௠௜ି௭௖ܸܪܰ

ሻ݂ܿݏܷܶ⁄ܤሺ ݏ݃ܽ ݐ݋݈݅݌ ݋݂ ݁ݑ݈ܽݒ ݅݊݃ݐ݄݁ܽ ݊ݐ݁ ൌ௣௚ ܸܪܰ

ሻ݂ܿݏ

ሻ݂ܿݏܷܶ⁄ܤሺ

݂݋ ݑܾ݉݋ܿ ݁ݎݑݏݏ݁ݎ݌ ൌ ௭௖ܲ

݊ ௦௧ௗܲ ሻ݅ݏ݌ 14.696ሺ ݏ݊݋݅ݐ݀ ݋ܿ ݀ݎܽ݊݀ܽݐݏ ݐܽ ݁ݎݑݏݏ݁ݎ݌ ݐܾܽ݉݁݊ ൌ

ݏ݃ܽ ݁ݑ݈ܽݒ ݂݋ ݐ݁݊ݒ ݅݊݃ݐ݄݁ܽ ݊ݐ݁ ൌ௚ ௩ܸܪܰ

ሻ݅ܽݏ݌ሺ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏ

ሻ݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݏ݃ܽ ݅݊ ݐ݋݈݅݌ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ௜ ݃݌

ሻ݂݄ܿݏሺ ܽ݊ ܴܵܵܯ ݕܾ ܿ݁݀ݑ ݎܽ݅ ݀݋ݎݐ݅݊ ݂݋ ݎ݁ݐܽ ݓ݋݂݈ ݎݐ݉݁ݑ݈݋ܿ݅ ݒ ݐ݋݈ܽ ൌݐ ெௌோௌି௔௜௥ܳ

݂݄ܿݏሻሺ ݏ݃ܽ ݐ݁݊ݒ ݄݁ݐ ݎ݋݂ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎܽ݅ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௚ ௩ି௢௜௖௛௦௧ି௔௜௥ܳ

ሻ݂݄ܿݏሺ ݁ݐܽݎ ݓ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ݒ ݐ݊݁݊݋݌݉݋ܿ ݐ݁݊ݒ ݏ݃ܽ ݈݅݀ܽݒ݅݊݀݅ ൌ௞ ܳ

ݐ݂ሺ ݁ݐܽݎ ݓ݋݂݈ ܿ݅ ݎݐ݉݁ݑ݈݋ݒ ݐ݊݁݊݋݌݉݋ܿ ݐ݁݊ݒ ݏ݃ܽ ݈݅݀ܽݒ݅݊݀݅ ൌ௔ ௙௖ ,௞ܳ ଷ ݎ/݄

ܳைଶି௦௧௢௜௖௛ି௩௚

ሻ

ሻ݂݄ܿݏሺ ݏ݃ܽ ݐ݁݊ݒ ݄݁ݐ ݓ݋݂݈ ݎ݋݂ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݃݁݊ݕݔ݋ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ

݂݄ܿݏሻሺ ݁ݐܽݎ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݏ݃ܽ ݐ݁݊ ൌݒ ௚௩ܳ

௚௣ܳ ሻ݂݄ܿݏሺ ݎ݁ݐܽ ݓ݋݂݈ ݎݐ݉݁ݑ݈݋ܿ݅ ݒ ݏ݃ܽ ݐ݋݈݅݌ ൌ

݂݄ܿݏ ሻ ሺ ݁ݐܽݎ ݓ݋݂݈ ݐ݉݁ݑ݈݋݅ܿݎ ݒ ݁ܽ݉ݐݏ ൌ ௦ܳ

ሻ݂݄ܿݏሺ ݁ݐܽݎ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎܽ݅ ൌ௔௜௥ ܳ

FLR-3-6 
 

 

 

 

 

 

 

 

 


 


 

 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 222 of 325 page 221 of 324 

⁄ ݌ ·ݏ݅ ଷ ݐݐ݂ 10.73ሺ ܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ

ݏ݃ܽ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݂݋

(ܴ 
· ݋݈ ݉ െ ܾ݈

ݎݑݐܽݎ݁݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௭௖ܶ

ݑݐܽݎ݁݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௦௧ௗܶ

݂݋ ݈݁݋݉ ݎ݁݌ ݊݋ܾݎܿܽ ݂݋ ݈݁݋݉

݁ ሺ°ܴሻ

ሻ528°ܴሺݏ݊݋݅ݐ݊݀݅݋ܿ ݀ݎܽ݊݀ܽݐݏ ݐܽ ݎ݁

ሻ݈݋݈/݉݋݉ ൌ ݔ

݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ 

ݒሺ

ܥ௫ܪ௬ ሺ

ሻ ݀ ݌݉݋݊ܿݑ݋ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ௜ ݔ

ሻ݊݋݅ݐ ݂ݎܿܽ ݋݈ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ܾ݈݅݁ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ௝ ݔ

݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݈݁݊݁ݕ݌݋ݎ݌ ݂݋ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ൌ௟௘௡௘ ௬௣௥௢௣ݔ

݈݋݈/݉݋݉ሺ ௬ܪ௫ܥ

ሻ

ሻ ݎ݁݌ ݈݁݋݉ ݂݋ ݃݁݊݋ݎ݀ݕ݄ ݂݋ ݏ݈݁݋݉ ൌ ݕ

FLR-3-7 
 


 


 



 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 223 of 325 page 222 of 324 

Table 1 

Individual Compound Properties 

I

(1) 

j Compound NHVi 

(Btu/scf) 

MWi 

(lb/lbmol) 

LFLi 

(vol fraction) 

Cx Hy 

1 1 Hydrogen 274 or 

1212(2) 2.02 0.040 0 2 

2 Oxygen 0 32.00 ∞ na na 

3 Nitrogen 0 28.01 ∞ na na 

4 CO2 0 44.01 ∞ na na 

5 CO 316 28.01 0.125 na na 

6 2 Methane 896 16.04 0.050 1 4 

7 3 Ethane 1595 30.07 0.030 2 6 

8 4 Ethylene 1477 28.05 0.027 2 4 

9 5 Acetylene 1404 26.04 0.025 2 2 

10 6 Propane 2281 44.10 0.021 3 8 

11 7 Propylene 2150 42.08 0.024 3 6 

12 8 iso-Butane 2957 58.12 0.018 4 10 

13 9 n-Butane 2968 58.12 0.018 4 10 

14 10 

iso-Butene, Butene-1, 

trans-Butene-2, cisButene-2 and 1,3 

Butadiene combined 

2826 56.11 0.018 4 8 

15 11 Pentane+ (C5+) 3655 72.15 0.014 5 12 

16 12 Hydrogen Sulfide 587 34.08 0.043 0 2 

17 Water 0 18.02 ∞ na na 

1

 i=all compounds, j=organic compounds and hydrogen 

2 If using an H2-adjusted NHVvg and NHVcz, then use 1212 BTU/scf for hydrogen. 

Note: Benzene and 1,3 butadiene are not required to be speciated by the Gas Chromatograph for this 

refinery settlement (see Appendix FLR-10) because benzene and 1,3 butadiene are present in the Vent Gas 

only in de minimis quantities. Because benzene and 1,3 butadiene speciation are not required, they are not 

listed in Table 1of this Appendix. The Vent Gas composition involved in other future settlements should 

be evaluated on a case-by-case basis to determine if benzene or 1,3 butadiene speciation should be 

required. 

FLR-3-8 
 


 


 



 



 



 


 


 



 



 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 224 of 325 page 223 of 324 

Table 2 

Combustion Efficiency Multipliers for Steam-Assisted Flares:
 

Variables Based on Minimum Steam Requirements
 

and VOC Concentration in the Vent Gas
 

Minimum VOC Vent Gas A Multiplier B Multiplier* 

Steam Concentration Condition A Condition B 

≤ 1000 lb/hr ≤ 20.0% 6.45 4.0 0.0 

≤ 1000 lb/hr > 20.0% 6.85 4.0 0.0 

> 1000 lb/hr ≤ 20.0% 7.1 4.0 0.0 

> 1000 lb/hr > 20.0% 7.4 4.0 0.0 

*The B Multiplier used depends on the relationship of hydrogen and propylene in the vent gas as follows: 

Condition A: 3 ≤ H2% ≤ 8 and Propylene% ≥ H2% (all percents are volume or mole percents) 

Condition B: Any condition not meeting the requirements for Condition A.
 

Note: The specifications for Condition A are based on the best information available as of the 

Date of Lodging. If new information becomes available thereafter, the parties may modify these 

conditions; any such modification does not constitute a material modification to the Consent 

Decree. 

The “VOC Vent Gas Concentration” shall be calculated on an annual average basis as follows: 

௡

 16 Equation 100 כ ௝ ෍ ൌݔ ௚௩ܥ

௝ୀସ

Note: The summation does not include methane or ethane. 

FLR-3-9 
 


 


 


 


 

 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 225 of 325 page 224 of 324 

Addendum A to Appendix FLR-3 

Verification of Equation 5A and Equation 5B Equivalency:
 

In this Appendix, all gaseous flows (i.e, vent gas, steam, pilot gas, and air) may be measured on 

either a mass basis (lb/hr) or a volumetric basis (scfh). Depending on which measurement 

methodology is used, different versions of some equations must be used. These versions are 

designated with an “a” or “b” (e.g. Equation 5a or 5b). In all cases, these equations are 

equivalent. This Addendum demonstrates the equivalence of the two methods for calculating 

NHVcz. 

Equation 5b uses volumetric flow rates for the calculation of NHVcz: 

ሻ Equation 5b 

Equation A1 

Equation A2 

Equation A3 

Equation A4 

Equation A5

385.5

Because the combustion zone is well-mixed, each gaseous component of the combustion zone is 

at the same temperature and pressure. Thus, the last expression reduces to Equation 5a: 

൫ܳ௩௚ ܸכܪ ܰ ௩௚൯൅ሺܳ௣௚ ܸכܪ ܰ ௚௣ ܰܪܸ௖௭ ൌ ܳ௩௚ ൅ ܳ௣௚ ൅ ܳ௦ ൅ ܳ௔௜௥

ܲ௖௭

The ideal gas law provides a method for determining volumetric flow rate of a specific gas, k, in 

the combustion zone at standard conditions: 

ܶ௦௧ௗ ൌ ܳ௞ ௔௖௙ , כ ܶ௖௭

௦௧ௗܲ כ

ܳ௞

݉௞ܴܶ௖௭ ሶ ௔௖௙ ൌ ܯܹ௞ܲ௖௭

ܳ௞,

ൌ ܴܶ௖௭ ܲ௖௭ ܶ௦௧ௗ

ܶ௖௭

כ ݉ሶ ௞ ݉ሶ ௞ܴܶ௦௧ௗ

ܲ௦௧ௗ

ሶ ݉ሶ ௞

௞ܹܯ

385.5

Substitution of this expression into Equation 5b gives NHVcz in terms of mass flow: 

݉ሶ ݉ሶ ௩௚ ௣௚

ܹܯ 385.5൬ ܹܯ

݉௔௜௥ ሶ ݉௦ ௣௚ ሶ ሶ ݉ሶ ௩௚

௩௚ ௣௚

ுమைܹܯ 385.5 ൅ ܹܯ

൅ 385.5

݉

௥௜௔ ௚௣ܹܯ ௚௩ܹܯ 385.5 ൅

௞ܹܯ ௦௧ௗܲ כ

ܳ௞ ൌ ܯܹ௞ܲ௖௭

 
528 כ 10.73 כ ௞

ൌ 14.696

݉

כ ௞ܹܯ ൌ௞ ܳ

ܸכܪ ܰ ௩௚൰ ൅ ൬385.5 ܸכܪ ܰ௚௣ ൰

ܰܪܸ௖௭ ൌ

FLR-3-10 
 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 226 of 325 page 225 of 324 

௩௚ ݉௣௚ ݉ ௔௜௥ ൰൅൬ ܯܹ ൰ ൅ ቀ ܯܹ௩௚ ܯܹ ௚௣ܯܹ మைு ௔௜௥

௚௣ ܰ ·ܪܸ ௚௣ ሶ݉

௚௣ܹܯ

ሶ ௦

൬ ൰

݉ሶ

൰൅൬ ݉ሶ ௩௚ ܸܪ ·ܰ ௩௚

௚௩ܹܯ

ሶ ܰܪܸ௖௭ ൌ Equation 5a ݉ሶ

Therefore demonstrating the equivalence of Equations 5a and 5b. 

൬ ൰൅൬ ቁ

FLR-3-11 
 

APPENDIX FLR·4
 

I'OI.H"' 011 UCl'A DlISn<*s .....IIQ -...crle-.. 8TU:Tm' . AlIt>

-

'1M . pollq •• -.. • ..s I .. ...... _ ..
 

l op1 _'.U ", p l .... l An .1 uy p.-ido for t .
 

"lo1 . U _ . _ d l7y pen ..s. of ox.... .-1. -.. "'0 '0
 

NU\IACt ;'-.. . ' .un..., . "" ....._ . Co_..Uy• • 11><'0 UPO ..
un: 

_ I... 10 ......1..." _1o, o f tM _ U _ l ....1_'
 . . .. qwllty .....,dordo UO _, o f .,... •..."._.., . n
 ..... 0<10 of ox __t _I I .U_ .
 

A<>a>rdJ"II1y. 0D\' rr- tlMo, . n .... t • ... ..... ti.~
 

_ I ..... f••_. _ 1.01..... h prGIlIDlto<l.
 

__• • U .. I_UN o f _h, I ....._ ....1 ••1""" 

.... 1"11 N Il.....' I _ ....._ l7y ''''''''.._. _ . Iroly beyoD<! 'bo 

_ tI'o l of <I.. _ . "" ..". _ y -. _ .....1..... S"'-eo 

Ny. ' lIo..t oro "'1_ of I "" ."o.~'

eI... ..U .... __ ne' t o _u • •"., .... p.-oduc"", 

• • "... _ ..10,," ...... _ 010 I. __•. 

Tll.l. policy 1>""""1.... ..., . 1t.......I ... _ 00 ...:... .,...".
 ell ..,...I _ h . . .... ""d ".,l h • ...,I. _ .. lI>o poe-t.vo 

oontl'lbuU.... or 1""1vI",,"l ....."'•• , .. ,..U~..nt O'<»><:<I" t • • <I""" 

I" 1. " ••1. Oro ..... " lbot DO . I"'!'I 0 n 'It....p 0 1 

.o~ 110. , ... poto"Ud t u . 0" don f t ho MQa 0. 

,.D I"c._ ",.. """TO • • 1"'11 o 11 , roup of 00.....

"". '/l. po,.nl i.l '0 ••••• • n 0• • • 04 o f t ho 08 0. PSD '''o... ... t • ••• I. orto M "" f ... • " If• • d.oxi <lo .nd 100<1. ' 

I PA boll.v• • _!'Pro••" " On on 'o nt eli.ot<oUon uo no< 

.pp. op. I.'.. , ,, ouch c• • eo, .~ t""" • • y h. vo • 

OIwnltl....t OO"" .., • • i09 . " . ""• • do"" v'olatlon .., tho 

-s>II11.aI>lo dord or .'D i~ .r.....' . 

"n>o , . .. IX"." "U" "'I _ u _I....... 1....1 wh 
 

...-d. "''1 .ppUutll" _1..1... 11"",," MolhlArt I QD.....,. • ......... ""'" ....._1"'1>1......_ ..f p .....rol oqW.po.... . 

_ t .... n'W» US"P<I- _ 0 9O_••lIy """He""l. 

' 1.1 ID " I U <1>&< d , , _ <totD coo<l1U _ • 

..U . o<I ,btl,. "portod 0 ' . """ 1..1 0110Io . ....... ex_. _lei DOt 110 _I 'ri o ••'I . 

.."•• polley . h o _ ...... • 1'1'1'1 f on "".-... .., ... _ I . 1" ..... t ..... tlr. "'l .........I. U _ " . Ir". U S r. lei 10

(D .t;. C'U'• •• UUI . , Ioo .-n .-_ .... IOQ .' __ to t l>o 

,:"" . ,.. av->Y """ _ t ..... tloo.... 1. pollq t . 

_ ri... f. _ .5 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 227 of 325 page 226 of 324 
 

Append i~ FLR""" 

. , 

' boo 

Kltooopt _ 

pot.....al ' 0 « 

al"" l 

u 

or ~l v_ o f ........,.. e_' • • of u.o __ 0< PSI> loA. 

1"""_te, 0<.... - 1 lacl_ I 1. n .. . tU.-Un 

<101_.' t or ._• • _ •••1_ 1""'9 .. U.. I Ir ... ....1 .
 

Ilal.,.uo,," Iot.... ..I U ' l><> , ...., 1:001"". U "W._... •• to • I U UI.-. lv.. ""f _ 1<1. boo .... U ..I .. '0 . I . ..... -" o~ . 0U_ _ ' ''9 "",,,dU•• b . o"l1>t 1Il' , 1>0 . UIl. or o;.u....... __• . • <1.0' 1...<1 _ 1Il' '1M ...... _ . '0 

. ..... ..... .... o~. . ..<1 _ ......1<1. boo. I HI Or ..1<10. 0 .¢tloo .' 

I.. a M IU"". h """' 0 11..1..<1. ol . e _.' It _y t>o
 

OPprcprlou t or . 110 Ita'. ' 0 WU" 10 ' 0 a ..,~. "" U'o o •
 

..,,.,."" · oate90ry· ..... e I U o ..loa'"" . ....<10 .<1. a 1'.......10 10n ..atln9
 

t " ol ,Iuo o.houl .. appllo"" l ' ...loal.,." Ii."a' lOn . <I.<> no, a ppl y
 """ '''9 "...o wl y <l.oU".<I.

""' OJ' and .:hu'<Iown p. d""'o.
 

I . IAI~".:"~ A>m "''''')J1C'''~ ll llc , rrlOll 

It a I II o""tol " . a p rolvlOl"" a<l.o<lr. ..11I9 ..c . .. .-1..101>0.
 

It o...-t be ."" , y.... t lwl t 1'<_1 <1.•• 10 . '~ 
 ._tion.. ......_ <>0 ."_1",,. " lib. annvote ..bl. ... a i r _l1t y by

." ,"!iI exo _1..1""" '1wI' co. 0< """trlbu , . '0 • viol. H _ 

o f .-bl u _ 1I. y • • o m.... for 

<l.1..pp<OV1 "!i1 • • ,. 1II.' 1"",1_ <10 . _ '"- _.--ob .... <1.10011...<1 10 ..... .U • • uP _ . Snn ,_.. ' . 

IS" ) aI>d C2 rocl: . ....., . '1.12 (April %7 . 10711 . .... . .....n . 

oU I ...... •w...,.,.. - 1 n' ...rio.""" . ..... ...._1<1.00 . u• .,..t!e 

...-pt...... I "" ......""'"' o f ._. _ _ 10_ . 

Tba 1>0 .. . ..,... tu. ex_ • • *'I.l...ioao ..Ill ...... 1.... r l . ... ... t11 D&Of ot• • I _ _ u ••_ ...... "" • .... U to _ra.. ...... _1_ "'__" _ f o rc-t ""......1.... n '. poll",. 

,.......1 ol .."""U.. __ _ '.l.<>lI _.._ ....."". of
 

...-It ..<I. poll......... . _ ..... . . M . lOOUey _. _ awll .........
 

• 1"!i1"1 o.r _ 11 ,,<>UP of ........... ..... t be pot. o. U l ' 0
 

e n eKCOO""..... o f t l>a ""AOIl or ~SD l nt r _ ote. 

""....,..r. 

.,.". ..,... "flE l n !Io'n .. _ ... . 10 t ,," o"" t ot an 

. 0fOce_n' p<ooaod. l" lI _0
 o . Ilalo n.. pY' fo r <l. by •

<1at...4 ...t . r OIl"..<l.ln ll" whlob tb. cltft " don' h b. bu .<lan ot 1" 001• 

• n<l. t luo ...r H . 0 1 Ol>1 ob . ... I nclapeJ><l.. ,.,tl y <1. obj . otlv. l y 

. ...I""t.<I. ' n a J u<lld., o r a <l.o,hi.o, ..t1v. proc• • <l.l ng . 

'''oau-a a ll ....r l""'"' 0 1 .,,"".. e nJ o. I"" . . .. v iol. .."". 5" <1. 

1>00.""••Hi...t ln <la f . n... p rov l . l o"," y not .Wly ,,, . 0H o n. 

t o r lo jooct l..., •• H .I. un"". no o lro _.t _ . .....1<1 . ..... 0"".' '''' ' ... ""'. of ."" 10 H ,,,, <1. by on .UI U ... ...1.0... to be ·f Ul nt.1t t 1 0' _~ ..POA o . 

~.

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 228 of 325 page 227 of 324 
 

AppendiJ FLR-4
 

, .
 

no'bini In tbi . iU I <Lo" C• • hould b. c o" ", ,,,.d .. "'l ;l ri ..... St.t.. ' 0 In cl oU l r...tlv. ,l" o" . e prov l ""'" In ' ''''Ir slP•• 

Th. ~.A c.n opprovo ° SIP r ev l . ;"" 'ho' or...t oo ." . Ul ' l v. <le too.o. to clol ao fOr peno ltieo I n e"forc _ o"t 

oeti"" ".rdln" exc• •• _ 100 100. c . u...<1 by • • l!un otlono • • 10"9" .. , ,,," <ld ."• • doe. "ot . pp l y to 8U provlolo". tbo . <So rl v. fro

, . .... u l). y p r "",ulg.'... pe",ocn&nce . t on<lard. or ...1o .lon 1I..;to • 

...ch .. ne~ OO" r C. pe r f or-nnc. otond.rdo (HSPSI .n<! ".C'o".l ...10.1""••u"dud. fOr h."r<\ou.o dr po llntont. (IIKS""PS) , ' ' 0 

. <1<U t i <m• • U l ..... tl"" d. te""• • • r . " ot . ppropri .t. l or a roa . a od 

pollu.or.to bor 0 . 1",,10 aOUrOa Or ...11 g r oup o [ . O\<XOOO "". 

,h. pot."t1al to 0."'0 on n o•• do no. 01 t ha IiAAQS or Pa P 

l oc nenent • . Fort ho r ooro ••tt;~t vo do lo" ••• to 010\ _ for "l ~ n c v. ro ll.. Or, n oO ol1owe<! . To bo oppr ovO<!• • n 

. U I ,..oU v. do fM•• PrQv l a i on " ""' provl <lo tllOt ' ho d.Io,,""ot "­ , he "" r don 0 1 p r oo f o f """"n.trotlDi ' bo., 

1 . Tho oxco " nloolono "",ro o.uo e<l by 0 ouddo",
 

un . vo l do bl o bl"no k<lo"" 0 ' , oclu>oloiY. beyond th o oo otr ol or cho
 

OWD'" Or <>po • • to"
 

2. Tl:l. u oo.. 0" 1001"". 101 <lI d 00' o ~ ' roo. any oc c l vJ.t y 

<IT . V. " C tbot OO~U have bo.n ' or • •••o &n<I .voldod . Or plonnod 

' or . 0 0<1 (bl o"" ld no' bovo bo o" ovoi<l.<l "y bett." .,.,..rot;"" ;m<l 

_ i ntono oo . proo;icoo, 

J . To tho "'""''''u. ox ton '
 pn <tio4blo tho olr poll ~ ""

ooDt r ol oq ulpooont Or PT""..... ~.ro ...l"tein.<I orut op . r otod in •
 ..anon oonoiotont w>ch iDO<! p raotlo. l or .inl.hl.... <m",
 

• . Ropeiro wer. _ clo 10 "" o""o<Ii t l "". , ..hiQn whe n t he opo r~tor kne or . h""l<I hav. I<nown t "" c a pp llc. ble 0..1..1"" 

l1 oitoti""o we n helOi ""00_. Oft• • t.ltt l obo r . nd ov. "' l _ ...... h ove be .... utuJz.... to t .... .,.~ t proctioabl o . to ""o~r

tho< . uc h r opoir . woro .. •• dltlo~. o. proot I Oab1. , 

s. Tho . DOunt . nd du r . t l on 01 t~o o o •• oml'.l nn. 

Il n<: l udl oi ."y byp..o ) ...r. IIl n i n h e <l '0 the -xl"". on . ", p<.cUo.l>~ o during pori o<l . of . uoh "lo lo .. , 

'To Ohe ex'~D a St o ' o Inolu.... H. p S <IT &S ""I'S in H . SU • 

• b .. . . ...r d . obo~ld .... . <lov,"'o <='" t~OqO t~ "".... ' Od u o lly 

pro><u1ioted. . ecouo. BPA o.t C~ . tood. r do toHoi inc" . oo""ot , 00"""l""i ••l lI. itotiono, oM l tt"","l ox _ pUo o. ",, "1<1 be 

inopprQPrloto. 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 229 of 325 page 228 of 324 
 

Appendix FLR-4 

. .­

5 . All _ Ibl•••..,. _~ t al<_ 10 ........ U•• of 

. Iot _ ell • • _ ...._ ... _ Iu. air 'I"-.l ltn 

7. Al l _ . ..."" -,tod.., fyO't_ "In u p. ... _utl_ 

If . t .n _.al., 

I. _ .. .... _ . , "" i .... I . ...._ <• •Iot
 

..0 1.,... _ "T p~rl ' 1",",


.<><>'_'"""00.0 "P"''''U"" I or ou..r .... 1......' ••1<1&""",
 

I . "11>. "" co.. •• •• 01 _ ... ..... PO'" o r n-In<J 

po'..m b<1>.eo.U... o f I • • • ""OIv o . "P"'...tl , Or
 ....In• • nu • • ' .n<!
 

•• . or"" O'WfIo" 0" opo •• tor prope r l y . nd p. ....pt .y no . H id
 

tbo OJ>J>ropri.'. ~1 'otY ""...o d t y.
 

n.. EPA ' M."l''''' 01ot00 orl ... I• ............1y . O1>l y tho""
 

....Uune.iono .bot . .. . _'" ......""'i""W. . . ... onpt&<ll . tobl. ' n
 .... 0 ... quo l U y lor . U <le r...... ' or . ""0;>1•• • • •",10 1".t "'elI
 

of • """. t pi!", t "I'" . ho itorl. _ y " ...U f y ondor
 .....UI....U _ 1..... . ..... ...r "",,14 ..... "'" .",,11...,1••
 

_ r . 11 t M r. " lllty 1>04 • bloto ry o f . l lOilar 1l~ 
 

11&""""" " f "", <1&.1..,. I"",tope , _ lat _ ce . or pool
 ""

.,. tl.Dg pn. tlC'&O . ......t.b&.-.... . -.-.. ...t ..... toJ<_ . 11 

"",..l ob•• _ t o ~"..t . f or ""'" .._ 1_ ' M ..ltlmCtl o" . 

It • f o<: l lI' y bo9_ Ii........ I..... to .""... _ 1• • loa• • 

t loa ofU ..... t 401_ -.I d 11& OI'lItop, • • " «Ity l or . 100 po, l ed 

or t l __ee._ry to -"fy 0' curt.1l _nU-.. to .",.. lato 

C'OOII'lI...ee . tbo II... . -.ld ba ...... t o UCUM _ee_ 

.....1-.. 9"_ '''' """" "''''''ad "".-I ed o f ti_ n u. tloo _ ..t ot .,.40....... I_UU. _ bag., ""'" In 1_ •.,. -.. 11. .. . ppllcabl ll'y <of t ba . I U ...u _ ",f ......"",....d iaoJ1y . 

11 1 . ""<255 ""'" ,1*1 lll;PI..l-:l ' no.nvP Ale 

i " V. .... o.l "" IOboot-" "f proce•• ~_..t . , . 

pe n 01 tl>o "" 1 _r r • """,,"ell ......lIOot<l "'" , . "",""ted 

f o , I " . .. p •• ""i 40• • 9" " ."",1_""'''0'' o f _ ,.tt"v 

p.-....... l...- t loo p....,. " nt ,ol equl_"• . ""'. onli ...'y.
 It to __""l. t o . _ tl>o t .&t ~l _d p,,,,,. ..t p l . ",,1"9 ..." 

""01'1" J1 . 11.1"... v lolotl"". 01 _h.l"" aat"'..o" . <l:ll ,in, 

. ucb porlod.1 . 

A. SOllRC1l CArlOOJlV . n CIrI C RULIS rtl~ flAU VP AND Hl1I" PO ""

r." oOftll . ""... o, ,"", tl... g Iven t be typeo o t contr o l 

t . e""" I O<J I• • &""1101>1'. t _y . I1.. oI>ott petlO<lO of 

_ •••1"". Q,ori ... otOtt op <1 ohot ......... vb"", ....,It t .U.,.... 

' . 9. "'. 1>9 pl"""i"9. <Ie.tp ope r.tl ng , ...., 100 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 230 of 325 page 229 of 324 
 

• • 

AppencIK FLR-4 

•
 .........1_ app ll~"' _ u n .. 11. 1t.aU-. -..o ... _ t .
 _ <'4U911' . __ U ... _ _ ... . o U,,:o _.,. o. _ u ...- of _n- "... . hO' _ . ....d <0 eo....... ' co 1._o t u..

I<UIQ;II ...- PlI11 1..,,_.., It _ y ... . 1'I' "0 i " (Z

"'.. I ' ... to 0..... ... ..1l Ilf .i_ t l>o.t UI<e . _ ._l.otI1CAI 11. 1 1.- IIItO . =<>WIt ADlI . 

ot.....1.. appH o "'l l -.lul __ 1I. 1..01.... <I<> DOt . 1'1'17 4uri "i 

.....--l y d . H ooo4 ...rt,. aD4 ~t -" p ..lod• • To ,.. Il'I'rowod • 

• 1>0......v lei-.. ob:Jul<l _ E01l"" I "i "'1\11........,
 

1 . .".. ...vll l-. _ • • ,.. 1I&1t.a<l to _ o U l o . "' ''''_'y.
 

<Ioll_ ""1"<>0 0""11"<'" .'Dg 'POo H l o con'tol I .nt.i ' "
 

(I .i . , ""'lOne r.' lon EacU U ' " to> rn n~ . .. ..I i " &M 11&1" 11
 

_l. oth'. catdyUO r .....tiool ,
 

• . II•• of . ho con,"ol .~ '.gy Eo, thlo . _re1l u~.<y
 

..... ,.. U""" I c d l y l "f..., ,,I. .... r l ..g ... « up or I nu,40vn
 

p..lo<1.. ,
 

1 . .".. fr'"'l""ney . r><I. 411...10.. o f ""••• t l oo i .... u . up 0' 

oh...<1own _ ..... t ... . . " I. IIe<! t o ' M _ d _ u t .nt
 

p.." tlo. bl. ,
 

t . ... part o E i " j v• • U1CAUon o E t bo . If ..v l . I I>t 

. .... .-.old ......l y 0'" _ " ntl.1 ....,.. _... __1..1 ""t 

CO'lll<l .",..... <t. r1n.g n"" aD4 . " ...........,

, . AJ. l poae1.tl l••• t'P" be <abO 00 0/. 1.. 01>0 ~ct

o E _ 1 _ . <0=1"'1" 1_ qulltoy , 

• . " . d l . . ... f..,H!ty ........ ."....to<! U • -=u 

_lo. .... n t b i""'I proetl.. f .... "'oia1 a1"'i ..-i• • I _ , ADlI ... _ CO _ t ",",,... ,.....U o rt u <l.1"'i p l lIIII . ... 1 , 

...... ."....U "" p ... ' 0 _ otbarvl pplloabl• .....I on l lA.l..tI.., _ 

" , 1bo .......... """ AC. l .... ctu. l ", ......... aD4 

. "v•....." I'Irl040 _at be d<>~ ", by p l y .,.,-.d. co"t_r....ou. ""," '.U", 1",• • o . ot!>l 1 "", . YI....""• . 

• • """"!tAl,. ......., .....,·tvlI pnDn PROVIAIOXI £l,A~INQ 'I'll
 

STAP:T<IP Mll _ 

I n _<\die.on t g U,. "PP......" o~'H ""<I I n .. .l o~ II I"! _l><>v.. 

,:a'"" ..y . <><tno •• '''' 1'.01>10. c ! I g "" C9 

4IIrll\'l . ..n up .n<I. oh~ vn "",i o<l. t"r<>uqll .." t o , 

<li ..,...,,=_W r c . ..h , h " " U, • • ""1" I~ IIO "!>O '• • •,"",. "'''''e1I O. " _11 9"''''' 0 1 ..,....,.. ,...., t ile p <>t U . 1 t o e. u•• _c ..e..<1....,. o f til. lIMQII or PI!> iCOT._CU, Itot .......y _ U O rdopt 

10••""i. SI r. .,. . U l tMtlve ~r..... __ .." . "" l~i tM. 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 231 of 325 page 230 of 324 
 

•• 

Appendi x FLR4 

,
 

spp,,,,,oh , .11 pe<1o<la of exoo.. _ I..i on. aciol ng u , . ..rtup 

sn<! . hut do"" ~yot boo "" o, .~ o. v i"latl"..., ond tM atU~t1".

<leI. .... p."" lol"" ~u.t no ' "'" . v. n . b.. 10' " lOh l. 10' lnju"",'I"" 

""Uol , . ..reM.....,• •• ," ... 0Wr<>v..." oooh s !,rov . o l"" .....t
 

p.""I". t"", tbO ""'O"""Dt M O tho !>ur,,"n 01 p roo ' "f
 ~.lOOnoc<0'1"9 th."
 

1. Th . ps<i ""'. "I . xe... s 1lO1 .-1"", ,"'" ooourro,. ~ur nq

o..rtup on" n ut """" "" r • • hOn on<! ~D qu .n 0 04 ,"" uld ne t ho."" 

bee " p , ev.noo,. through c OHl ul lann ~" 0...;1 ""019"; 

2, Th. """".0 ui..I"". _ .... Mt put "f • r.",,=I "9"
 

po ttorn ~n"leot1vo of l""""...,.to ""'. I~ ol'*rotj,<m. o r
 

_lnton.ne.,
 

3. If t ho o oo ~hoiQ woro eo _~ l>y 0 hypn. Ion 

~n"ntie"" "~ vo 01"" Q( ""'''ro1 oqu~I"""D then r he hyp. .. "" . 

unoVQ~<io" lo t o provs nt l e oo 01 h I., psu Qn. 1 lojuy , Qr ••v..... 

prop.r'y <!.mug" , 

. , '" d l • •• tho h cillt y woo o.....to I " O ...>lOU
 

con.l ot.nt wi t h ",,0<1 prot t l Ci' l or nl"'h~n9 lod n. 
 

Tho r.oqu. "oy olld " u,ot loo 01 ope rot lQn I n otonup 0•
 

ohut <lo>wn """,e ""• • ~nl .,l ..d te t ho ox .,"" utont pnoHe o"lo,
 

~' .\1.1 pooo1ble 0" 1'0 VOro ta e>:l '0 . l n l " l .. t n o 1..... 0' 01 

tho "" oo ool ..lon. 011 OlObI.nt . 1, quoUty; 

1 . " 11 ... ..I oo IOOn it" r l ng oy.. "Oro ~ep In op.ratl""
 

If . t oil poooi.blo,
 

8. Tho ,,",nor or opor otor ' , .oti"no " w:lnv tho pori"", of
 

""'00 • • oml ..l o"" we r e ~oe"".n<od by prct>.rly 0 19,," d ,
 

""nt....por."""". ope r. t1 l>q log o, er othor rols vont . vi ""n oo , 00<1
 

,. The ownor or <>pora'", p r " po r l y .n~ p r OlOptly ""tllI.d t ho 

. ppropr lora Tsgulot"ry au'horHy, 

n ..00 1oo1ono " "Ou r duri ng r outl "" nort up or ollu tdown 

pori"",. 0 I t;m,,tion, t bsn t ho.. io.o tsncoo . houl<l be 

tr• • ted . 0 ethor H""" ti""'" t l>o ' ora oubj e et to t ho ...l1"""Uor. 

provioie,.,. 01 t ll h policy. ~R lerenc Pu t I s bovel , 

--",­

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APPENDIX FLR-5 

CALCULATING MOMENTUM FLUX RATIO 

Momentum Flux Ratio (MFR) is the relationship between the density (ρ) and velocity (v) of the 

Vent Gas plus Center Steam to the density and velocity of the wind. It is defined in Equation 1. 

ߩ௩௚ା௦,௖௘௡௧ · ݒ௩௚ା௦,௖௘௡௧

ଶ

௥௜௔ݒ · ௥௜௔ߩ 1 Equation ൌ ܴܨܯ

ଶ

The numerator of the fraction is the “momentum flux” of the Vent Gas plus Center Steam and 

the denominator is the “momentum flux” of the air (wind). As the velocity of the wind 

increases, the MFR will decline for a given Vent Gas composition and flow rate. 

Calculations for the density (ρ) components and velocity (v) components are discussed separately 

below. 

Calculating Density 

The general formula to calculate the density of each component (ρi) – Ambient Air, Vent Gas, 

and Center Steam -- is shown in Equation 2. 

· 10.73 ൌ௜ ܹܯ

ܯܹ ௜ൌ ܴ · ܶ௔௕௦· ܲ · 14.73 ൌ 1.373 ·

460 ൅

௜ ܯܹ

ߩ ௜ሺ460 ൅ ሻ ܶ௜ ܶ௜ Equation 2 

From the final form of Equation 2, the density of Ambient Air (ρair), Vent Gas (ρvg), and Center 

Steam (ρs,cent) can be calculated, shown in Equations 3, 4, and 5. The temperature of Center 

Steam and Ambient Air is measured. The temperature of Ambient Air and Vent Gas is assumed 

to be equal. 

൅ 460 ௥௜௔ߩ · 1.373 ൌ

௥௜௔ ܯܹ

ܶ௔௜௥ Equation 3 

1.373 · ߩ௩௚ ൌ ܹܯ ௩௚

460 ൅

1.373 ·

ܶ௔௜௥ Equation 4 

ுమை ܯܹ

Equation 5 460 ൅ ܶ ௡௘௖௦, ௧

ߩ௦,௖௘௡௧ ൌ

FLR-5-1 
ሶ ሶ ሶ ሶ

ሶ ሶ

ሶ ሶ

 

 

 

 

 

 


 

 

 

 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 234 of 325 page 233 of 324 

The density of the Vent Gas plus Center Steam (ρvg+c,cent) is calculated by combining the mass 

flow rates of the Vent Gas and Center Steam and dividing by the combined volumetric flow rates 

of the Vent Gas and Center Steam. This is shown in Equation 6. 

ߩ௩௚ା௦,௖௘௡ ൌ ݉௩௚ ൅ ݉௦,௖௘௡௧

ܳ௩௚ ൅ ܳ ௖௦, ௘௡௧

ൌ ݉௩௚ ൅ ݉௦,

݉௦,௖௘௡௧ ൅

݉௩௚

,௦ߩ

௖௘௡௧

Equation 6

ߩ௩௚ ௖௘௡௧

Calculating Velocity 

The velocity of the Vent Gas plus Center Steam (vvg+s,cent) is calculated by Equation 7. 

݉௦, ௧௡௘௖ ൅ ߩ௦,௖௘௡௧

A௧௜௣ି௨௡௢௕

݉௩௚

ܳ௩௚ ൅ ܳ௦,௖௘௡௧ ߩ ൌ ௩௚

ܣ௧௜௣ି௨௡௢௕

ݒ௩௚ା௦,௖௘௡௧ ൌ Equation 7 

The wind velocity is measured directly. 

Constants: 

28.96൬ ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௔௜௥ ܹܯ

݈ܾ

݈݋݈ܾ݉

݈ܾ

൰

ுమܹܯ ݎ݁ݐܽݓ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ ை

݁ݎݑݏݏ݁ݎ݌ ݐܾܽ݉݅݁݊ ݁ݐݑ݈݋ݏܾܽ ൌ ܲ

൬18.02 ൰ ݈ܾ݉݋݈

ሺ14.73 ݏ݌݅ܽሻ

݈݋݈ܾ݉ 10.73ቆ ݅ݏ݌ ݐܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ

· ݂ ቇ °ܴ

ݐଷ

·

Measured variables: 

݈ܾ

݈݈ܾ݋݉ ൬ ݐܸ݁݊ ݏܽܩ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ௚ ௩ܹܯ

݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ,௦௡௘௖௧ ሶ݉

൰ 

݈ܾ ൬ ൰ ݄ݎ

݈ܾ

ݎ݄ ൰ ൬ ݐܸ݁݊ ݏܽܩ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ௚ ௩ ሶ݉

ܶ ሺԬሻ

Ԭሺ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ

ݎ݅ܣ ݐܾ݉݅݁݊ܣ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉ݐ

ܶ௦,௖ ௡௧௘

ൌ௔௜௥ ݒ

௔௜௥ ൌ

ሻ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉ݐ ൌ

൬

ݐ݂

൰ ݅݊݀ݓ ݂݋ ܿ݋݈݁ݕݐ݅ ݒ ݎ݄

FLR-5-2 
 

 


 
 

 

 

 

 

 
 
 

 

 

 

 

 

 

 

 

 


 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 235 of 325 page 234 of 324 

Calculated variables: 

௕௢௡௨ି௜௣௧ܣ ݐ݂ ݁ݎ݂݈ܽ ݌݅ݐ ݁ܽݎܽ ݂݋ ݏ݋݅ݐ݈ܽ݊݁ܿ െ ݏݏ݋ݎܿ ݐݏܾ݋݊ݑݎ݁ݐܿݑ݀ ൌ ሻଶ ሺ

ሻ ݊݅ݑݏݏ݈݁ݐ ሺ ݔݑ݂݈ ݋݅ݐܽݎ ݉ݑݐ݉݁݊݋݉ ൌ ܴܨܯ

ݐ

݋݈ ݈ܾ݉ ൰ ൬௜ ܹܯ ݅ ݊݁ ݊݋݌݉݋ܿ ݐ݄݁݅݃ݓ ݂݋ ݈݁ܿ݉݋݈ܽݑݎ ൌ ݈ܾ

݈ܾ ൬ ݅ܽݎ ݋݂

 
ݕݐ ݊݁ݏ݅ ݀ ൌ௔௜௥ ߩ ݐ݂ ଷ൰

݈ܾ

൰ଷ ൬ ܽܩݏ ݂݋ ݐܸ݁݊ 
ݕ ݀ݐ݅ݏ݁݊ ൌ௚ ௩ߩ ݐ݂

݈ܾ

൰ଷ ൬ ݁ܽ݉ݐܵ ݂݋ ݁ݐ݁݊ܥݎ ݕݐ݅ݏ݀݁݊ ൌ ௧௖௘௡,௦ߩ ݐ݂

݈ܾ

ݐ݂ ൰ ൬ ݅ ݐ ܿ݋݉݌݋݊݁݊ ݋݂ ݕݐ ݊݁ݏ݅ ݀ ൌ௜ ߩ ଷ

ݐ݂ ଷ

ቇ ቆ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ݒ ൌ ௧௖௘௡,௦ܳ ݎ݄

ݐ݂ ଷ

ቇ ቆ௚ ௩ܳ ݐܸ݁݊ ݏܽܩ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ൌݒ ݎ݄

௦௔௕ܶ ሻ°ܴሺ ݁ݎݑݐܽݎ݁݌݁݉ݐ ܽݐݑ݈݋ݏܾ݁ ൌ

ܨ°ሻሺ ݅ ݊݋݌݉݋ܿݐ݁݊ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉ݐ ൌ௜ ܶ

ݒ ൌ௚ ௩ݒ ݎ݄ ൰ ൬ ݐܸ݁݊ ݏܽܩ ݂݋ ܿ݋݈݁ݕݐ݅ ݐ݂

ݐ݂

ݎ݄ ൰ ൬ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥݎ ݂݋ ݕݐܿ݅݋݈݁ݒ ൌ ௧௖௘௡,௦ݒ

FLR-5-3 
 

Appendix FLR-6 

Type I TypB ][ I.D·T

lower 

n, Pilot , 

Sla bdity Tab 

....•.. _­

, 

I

Steaml Air 

Tuoos 

tee:; O .D. , 

SIab<Oty R"'Il 

f> Steam/Air 

Tu bes 

W here	 Aoo-- =Unobstructed Cross 

SectKlnal Area 01Flare Tip 

I.D., = Inside Diameter Flare Tip 

X, = Number of Stability Tabs 

A",. = Area 01a Stab,lity Tab 

Exa m p le :	 I.D.

T = 41.5 inches
 

X, = 3
 

A", = 3 sa inches
 

Aoo--=1'r(415)'14 - (3 • 3)
 

Aoo-- =1344 Sq inches
 

Where:	 Aoo-- =Unobstructed Cross 

Sectional Area 01Flare Tip 

I.D., = Insioo Dlameter Flare Tip 

A",. = Area 01Stab< 11IyROO!> 

O.D., = Outside mamelerof 

JmlA~ Tubes 

NT = Number of Sleam/Air Tuoos 

E xam ple	 I.D., = 41 .5 inche s 

A",. = 100 Sq. inche s 

O.D., = 6.5 inches 

N, = 8 

Aoo-- =1'r (41 5)' /4 - 100 - 8'1'r ' (6 5)'14 

........... = 1322 Sq inches 

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endix FLR-6 

Type JI[ Type R 

' 0 , 

~"

[;" \ .., 

k .c• -

o o

'0 . 

rv ' 

• 

>\0.­=N" 0 (1'I'''{10 .. l'''' - X, ' ......'1 

Whefe >\0.­=unorrstn.otltO Cros$ Are:I Where 

oIFgre TIP 

1.0 .. =_ 0<;00, elel or Onot TIP MoiSM 

..... ="' um lle< 01 

x, lle<oISUl*\l Ta b$ per Modu le 

...... = a or a SlaIl*y' Tab 

>\0.­=lJnobstrucle(l Cross 

SKtocnal_ ol F~ TIP 

LD.T = moe DoomeIetol FIart TIP 

EKample: 10 .. =11 ....:rleS 

..... . 6 )'., = 3 

"s, =3 SQ. " <:he$ 

EKample : 1.0 .• =41.5inche5 

"'-­ =6 · (1'1' 0\11" /4 _ 3 ' 3) 

"-­= 1306 SQ ..,"u .-....- ,..( 15fI

........... . 1353 SQ. "": rleS 

case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 document 7-1 filed 09/18/12 page 237 of 325 page 236 of 324 
 

DEPICTION OF GASES ASSOCIATED
 

WITH STEAM-ASSISTED FLARES
 

WASTE 

GASES 

PILOT 

GAS 

COl"SEl\l DECREE 

DEFINITIONS 

OPERATIONAL 

GASES 

AND STEA:\I 

PURGE 

GAS 

WASTE GAS xxxxxx 

"The mixtureofali gasesfromfacthty operations 

that is directedto aflarefor the purpose ofdtsposmg 

ofthegases." 

HUt<"'"- ifIIfaci/rT)' IKuilUlnUIH'II111tioll clIP"'blr of calnlillillf 

tIl'f1qw,'ra~o!H,..'J 0 CO,CO,.andiiJrHpilltMll'illItGaz. 

til, ronlTifl!jlloll 01aircakulol,djfl1lOI o!rh,JI ,1'lflnrtslcolflptnllllU 

IfIol)" achsdtd from Iflutt Gal; f/(1\I,' rtll, calndDIiOlU. 

SWEEP 

GAS 

VENT GAS --­

------------. 

,--------------, ,------"-------,\ 

I 

L-__JL__------' 1 

I 

I 

I 

I 

I 

" ......" ...... --

----

SUPPLE.\ fE.'ITAL 

GAS 

REGULATORY 

GASES 

--­x --­ ----­

"'[1Ul mtxtwl1 ofali gases found prior to the flare tip 

This includes all mute Gas, Supplemental Gas, 

Sweep Gas, and Purge Gas. .. 

COMBUSTIONZONEGAS - - ­ "11Ul mixture ofall gases and steamfoundjust after IAPPENDIX FLR-7 1 

thej/ore tip This includes all Vent Gas, Pilot Gas, 

and Total Steam. " 

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Appendix FLR‐8
 


 



 



 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


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FLR-9 

OUTLINE OF REQUIREMENTS FOR THE
 

FLARE DATA AND INITIAL MONITORING SYSTEMS REPORT
 

1. Facility-Wide 

1.1 Facility plot plan showing the location of each flare in relation to the general plant 

layout 

2. General Description of Flare 

2.1 Ground or elevated 

2.2 Type of assist system 

2.3 Simple or integrated (e.g., sequential, staged) 

2.4 Date first installed 

2.5 History of any physical changes to the Flare 

2.6 Whether the Flare is a Temporary-Use Flare, and if so, the duration and time periods of 

use 

2.7 Flare Gas Recovery System (“FGRS”), if any, and date first installed 

3. Flare Components: Complete description of each major component of the Flare, except 

the Flare Gas Recovery System (see Part 5), including but not limited to: 

3.1 Flare stack (for elevated flares) 

3.2 Flare tip 

3.1.2.1 Date installed 

3.1.2.2 Manufacturer 

3.1.2.3 Tip Size 

3.1.2.4 Tip Drawing 

3.3 Knockout or surge drum(s) or pot(s), including dimensions and design capacities 

3.4 Water seal(s), including dimensions and design parameters 

3.5 Flare header(s) 

3.6 Sweep Gas system 

3.7 Purge gas system 

3.8 Pilot gas system 

3.9 Supplemental gas system 

3.10 Assist system 

3.11 Ignition system 

4. Simplified process diagram(s) showing the configuration of the components listed in 

Paragraph 3 

5. Existing Flare Gas Recovery System (“FGRS”) 

5.1 Complete description of each major component, including but not limited to: 

FLR-9 - 1
 
 


 


 


 



 


 


 


 


 


 


 


 


 


 


 


 


 



 


 


 


 



 


 


 


 



 


 


 


 


 


 


 



 


 


 


 


 


 


 


 

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5.1.1 Compressor(s), including design capacities 

5.1.2 Water seal(s), rupture disk, or similar device to divert the flow 

5.2 Maximum actual past flow on an scfm basis and the annual average flow in scfm
 

for the five years preceding Date of Lodging 

5.3 Simplified schematic showing the FRGS 

5.4 Process Flow Diagram that adds the FGRS to the PDF(s) in Part 4 

6. Flare Design Parameters 

6.1 Maximum Vent Gas Flow Rate and/or Mass Rate 

6.2 Maximum Sweep Gas Flow Rate and/or Mass Rate 

6.3 Maximum Purge Gas Flow and/or Mass Rate, if applicable 

6.4 Maximum Pilot Gas Flow and/or Mass Rate 

6.5 Maximum Supplemental Gas Flow Rate and/or Mass Rate 

6.6 If steam-assisted, Minimum Total Steam Rate, including all available information 

on how that Rate was derived 

7. Gases Venting to Flare 

7.1. Sweep Gas 

7.1.1 Type of gas used 

7.1.2 Actual set operating flow rate (in scfm)
 

7.1.3 Average lower heating value expected for each type of gas used 

7.2 Purge Gas, if applicable 

7.2.1 Type of gas used 

7.2.2 Actual set operating flow rate (in scfm)
 

7.2.3 Average lower heating value expected for each type of gas used 

7.3 Pilot Gas 

7.3.1 Type of gas used 

7.3.2 Actual set operating flow rate (in scfm)
 

7.3.3 Average lower heating value expected for each type of gas used 

7.4 Supplemental Gas 

7.4.1 Type of gas used 

7.4.2 Average lower heating value expected for each type of gas used 

7.5 Steam (if applicable) 

7.5.1 Drawing showing points of introduction of Lower, Center, Upper, and any 

other steam
 

7.6 Simplified flow diagram that depicts the points of introduction of all gases, 

including Waste Gases, at the Flare (in this diagram, the detailed drawings of 7.5.1 may be 

simplified; in addition, detailed Waste Gas mapping is not required; a simple identification of the 

header(s) that carries(y) the Waste Gas to the Flare and show(s) its(their) location in relation to 

the location of the introduction of the other gases is all that is required) 

8. Existing Monitoring Systems 

8.1 A brief narrative description, including manufacturer and date of installation, of 

all existing monitoring systems, including but not limited to: 

FLR-9 - 2 
 


 


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8.1.1 Waste Gas and/or Vent Gas flow monitoring 

8.1.2 Waste Gas and/or Vent Gas heat content analyzer 

81.3 Sweep Gas flow monitoring 

8.1.4 Purge Gas flow monitoring 

8.1.5 Supplemental Gas flow monitoring 

8.1.6 Steam flow monitoring 

8.1.7 Waste Gas or Vent Gas molecular weight analyzer 

8.1.8 Gas Chromatograph 

8.1.9 Sulfur analyzer(s) 

8.1.10 Video camera 

8.1.11 Thermocouple 

8.2 Drawing(s) showing locations of all existing monitoring systems 

9. Monitoring Equipment Installed to Comply with Consent Decree 

10. Narrative Description of the Monitoring Methods and Calculations that will be used to 

comply with the NHVCZ, S/VG, and Prohibition on Discontinuous Wake Dominated Flow or 

MFR Requirements in the Consent Decree 

11. Identification of calibration gases to be used to comply with Appendix FLR-11 

[End of FLR-9] 

FLR-9 - 3
 
 


 


 


	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

	 

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APPENDIX FLR-10 

LIST OF COMPOUNDS A GAS CHROMATOGRAPH 

MUST BE CAPABLE OF SPECIATING
 

The Gas Chromatograph must be capable of speciating the Waste Gas into the following: 

1.	 Hydrogen 

2.	 Oxygen 

3.	 Nitrogen 

4.	 Carbon Dioxide 

5.	 Carbon Monoxide 

6.	 Methane 

7.	 Ethane 

8.	 Ethene (aka: Ethylene) 

9.	 Acetylene 

10.	 Propane 

11.	 Propene (aka: Propylene) 

12.	 2-Methylpropane (aka: iso-Butane) 

13.	 Butane (aka: n-Butane) 

14.	 But-1-ene (aka: butene, alpha-butylene), 2-methylpropene (aka: 

iso-butylene, iso-butene), trans-Butene-2, cis-Butene-2 and 1,3 Butadiene 

combined into a single measurement 

15.	 Pentane plus (aka: C5 plus) (i.e., all HCs with five Cs or more) 

16.	 Hydrogen Sulfide 

17.	 Water 

Outputs from the Gas Chromatograph shall be on a mole percent basis except for Hydrogen 

Sulfide which will be on a parts per million basis. 

Benzene and 1,3 butadiene are not required to be speciated by the Gas Chromatograph for this 

refinery settlement because benzene and 1,3 butadiene are present in the Vent Gas only in de 

minimis quantities. The Vent Gas composition involved in other future settlements should be 

evaluated on a case-by-case basis to determine if benzene or 1,3 butadiene speciation should be 

required. 

(End of Appendix FLR-10) 
 

 

 

 

 

 

 

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APPENDIX FLR-11
 

EQUIPMENT AND INSTRUMENTATION TECHICAL SPECIFICATIONS
 

AND QUALITY ASSURANCE/QUALITY CONTROL REQUIREMENTS
 

I.	 WASTE GAS FLOW METER 

a.	 Velocity Range: 0.1–250 ft/sec 

b. Repeatability: ± 10% of reading over the velocity range 0.1 ft/s to 1.0 ft/s 

± 1% of reading over the velocity range > 1.0 ft/s to 250 ft/s 

c.	 Design Accuracy: ± 5% initially to 40%, 60%, and 90% of monitor full scale as 

certified by the manufacturer 

d. Operational Accuracy: ± 20% of reading over the velocity range of 0.1–1 ft/s and 

± 5% of reading over the velocity range of 1–250 ft/s 

e.	 Installation: Applicable AGA, ANSI, API, or equivalent standard 

f.	 Flow Rate Determination: Must be corrected to one atmosphere pressure and 

68 °F 

g.	 QA/QC: Annual calibration shall be conducted beginning with the schedule 

given in Paragraph 6 of the flaring section. 

h. Pressure and Temperature Sensors: See Part IV below. 

II.	 WASTE GAS AVERAGE MOLECULAR WEIGHT ANALYZER 

(may be part of the Waste Gas Flow Meter) 

a.	 Molecular Weight Range and Accuracy: 2 to 120 gr/grmol, ± 2% 

III.	 STEAM FLOW METER 

a. Repeatability: ± 1% of reading over the range of the instrument 

b. Accuracy: +/- 1% from 100% to 15% of span
 

+/- 2% from 15% to 6% of span
 

+/- 3% from 6% to 4% of span
 

c.	 Installation: Applicable AGA, ANSI, API, or equivalent standard 

d. Flow Rate Determination: Must be corrected to one atmosphere pressure and 

68 °F 

FLR-11-1
 
 

 

 

 

 

 

 

 

 

 

 

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e.	 QA/QC: Annual calibration shall be conducted. 

f.	 Pressure and Temperature Sensors: See Part IV below. 

IV.	 WASTE GAS AND STEAM FLOW METERS: PRESSURE AND 

TEMPERATURE SENSORS 

Beginning with the schedule given in Paragraph 6 of the flaring section, 

a.	 Temperature monitor must be calibrated annually to ± 5%. 

b.	 Pressure monitor must be calibrated annually to within ± 5%. 

V.	 GAS CHROMATOGRAPH (“GC”) 

A.	 General 

a.	 Accuracy: The gas chromatography system shall be maintained to be 

accurate within 5% of full scale. 

b.	 8-Hour Repeatability (applies to all measured components except water): 

± 0.5% of full scale for full scale ranges from 2-100%; 

± 1% of full scale for full scale ranges from 0.05-2%; 

± 2% of full scale for full scale ranges from 50-500 ppm; 

± 3% of full scale for full scale ranges from 5-50 ppm; 

± 5% of full scale for full scale ranges from 0.5-5 ppm. 

The 8-Hour Repeatability range for water shall not be more than ± 3% of 

full scale. 

c.	 The minimum sampling frequency shall be one sample every 15 minutes. 

d.	 The GC shall be capable of speciating all gas constituents listed in 

Appendix FLR-10. 

e.	 The sampling system shall be heat traced and maintained at 240°F with no 

cold spots. All system components shall be heated, including the probe, 

calibration valve, sample lines, sampling loop (or sample introduction 

system), and GC oven. 

f.	 Where technically feasible, the sampling location should be at least two 

equivalent duct diameters downstream from the nearest control device, 

point of pollutant generation, or other point at which a change in the 

pollutant concentration or emission rate occurs. The location should not 

be close to air in-leakages. Where technically feasible, the location should 

also be at least 0.5 diameter upstream from the exhaust or control device. 

FLR-11-2
 
 

	 

	 

	 

	 

	 

	 


 

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B. Gas Chromatograph Calibration Standards 

1. Net Heating Value and Analyte Measurements. For the Net Heating 

Value and Analyte measurements, the GC shall be operated and 

maintained in accordance with Performance Specification 9 (“PS9”) of 

Appendix B of 40 C.F.R. Part 60 except: 

a. The daily mid-level validation procedure in Section 10.2 shall be 

conducted on the calculated Net Heating Value of the certified 

calibration gas based upon the concentration of each analyte. The 

average instrument response shall not vary by more than 10 

percent from the Net Heating Value of the certified calibration gas. 

b. The multi-point calibration error check procedure in Section 10.1 

shall be conducted quarterly for the limited set of analytes listed in 

Subparagraph V.B.1.c below. No calibration will be required after 

routine maintenance or repair. The GC must meet the calibration 

performance criteria in Sections 13.1 and 13.2 of PS9 for the listed 

analytes only, such that: (i) the average instrument response must 

not differ by more than 10 percent of the calibration gas value; and 

(ii) the precision and linearity check of each analyte listed below 

shall not deviate more than 5 percent from the average 

concentration measured. 

c. The analytes to be used are: 

i. Hydrogen 

ii. Nitrogen 

iii. Methane 

iv. Ethane 

v. Propane 

vi. Propylene 

vii. Ethylene 

d. The calibration gas mixtures may be set by the procedures 

identified in Section 7.1 of PS9 or may be within 10 percent of the 

concentration values listed in Table 1. The gases must be certified 

to ± 2 percent. 

Table 1: Calibration Gas Mixtures for Net Heating Value Calibrations/Validations(1) 

Component Daily 

Mid-Level 

Gas 

Quarterly 

Low-Level Gas 

Quarterly 

Med-Level 

Gas 

Quarterly 

High-Level Gas 

Hydrogen 30 8 30 12 

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Component Daily 

Mid-Level 

Gas 

Quarterly 

Low-Level Gas 

Quarterly 

Med-Level 

Gas 

Quarterly 

High-Level Gas 

Nitrogen 8 65 8 5 

Methane 48 22 48 30 

Ethane 3 2 3 30 

Propane 2 1 2 15 

Propylene 8 1 8 5 

Ethylene 1 1 1 3 

NHV (Btu/scf) 

Unadjusted for 

H2 

793 310 793 1273 

(1) The individual analytes in this Table are in volume percent. 

2. H2S Measurement. For the H2S measurement, the GC shall be operated 

and maintained in accordance with Performance Specification 7 of 

Appendix B of 40 C.F.R. Part 60. Quality assurance procedures set forth 

in Appendix F of 40 C.F.R. Part 60 shall be followed. The span shall be 

set at 320 ppmv H2S or as required by NSPS Subpart Ja, if different. 

VI. Calculation of Instrument Downtime 

1. For purposes of calculating the 110 hours per calendar quarter of instrument 

downtime allowed pursuant to Paragraphs 17 and 51, the time used for GC 

calibration and validation activities required by Subparagraph V.B.1 of this 

Appendix may be excluded. 

2. Any hour that meets the requirements of 40 C.F.R. § 60.13(h)(2) shall not be 

counted toward instrument downtime. Specifically: 

(i) For a full operating hour (any clock hour with 60 minutes of unit 

operation), if there are at least four valid data points to calculate the hourly 

average (that is, one data point in each of the 15-minute quadrants of the 

hour), then there is no period of instrument downtime; 

(ii) For a partial operating hour (any clock hour with less than 60 minutes of 

unit operation), if there is at least one valid data point in each 15-minute 

quadrant of the hour in which the unit operates to calculate the hourly 

average, then there is no period of instrument downtime; and 

(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 and if 

there are at least two valid data points separated by at least 15 

FLR-11-4 
 

	 

	 


 

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minutes to calculate the hourly average, then there is no period of 

instrument downtime; or 

(B) If the unit operates in only one quadrant of the hour and if there is 

at least one valid data point to calculate the hourly average, then 

there is no period of instrument downtime. 

VII. METEOROLOGIC STATION 

a. Wind speed sensors must be calibrated annually to +/- 10%. 

FLR-11-5 
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APPENDIX FLR-12 

WASTE GAS MAPPING: 

LEVEL OF DETAIL NEEDED TO SHOW HEADERS AND PROCESS UNIT HEADERS 

Purpose: 

Waste Gas Mapping is required in order to identify the source(s) of waste gas entering 

each Covered Flare. Waste Gas Mapping can be done using instrumentation, isotopic 

tracing, acoustic monitoring, and/or engineering estimates for all sources entering a 

flare header (e.g. pump seal purges, sample station purges, compressor seal nitrogen 

purges, relief valve leakage, and other sources under normal operations). 

Appendix FLR-15 outlines what needs to be included as the Waste Gas Mapping 

section within the Initial Waste Gas Minimization Plan (“Initial WGMP”) 

Waste Gas Mapping Criteria: 

For purposes of waste gas mapping, a main header is defined as the last pipe segment 

prior to the flare knock out drum. Process unit headers are defined as pipes from inside 

the battery limits of each process unit that connect to the main header. For process unit 

headers that are greater than or equal to six (6) inches in diameter, flow (“Q”) must be 

identified and quantified if it is technically feasible to do so. In addition, all sources 

feeding each process unit header must be identified and listed in a table, but not 

necessarily individually quantified. For process unit headers that are less than six (6) 

inches in diameter, sources must be identified, but they do not need to be quantified. 

Waste Gas Mapping Submission Requirements: 

For each Covered Flare, the following shall be included within the Waste Gas Mapping 

section of the Initial WGMP: 

1. Simplified Schematic consistent with the example schematic included on the second 

page of this Appendix. 

2. Table of all sources connected to each flare main header and process unit header 

consistent with the Table included on the third page of this Appendix. 

1 of 3 

 


 

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 page 249 of 324
 

2 of 3 
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Table 1: Example of Flare Source Description Table 

Process Unit Header 

Sources Detailed Source Description 

QS1 (Ex: FCCU Gas Con Unit) 

3 PSVs PSV-14 on 110-D-5 Gas Con Absorber 

PSV-12 on 110-D-1 Amine Scrubber PSV-7 on 110-F-1 Batch Caustic Vessel 

2 Pump Seal Purges 110-G-1 LPG Pump 

110-G-2 Rich Amine Pump 

1 Sample Station 110-S-1 LPG 1 PSV PSV 17 on 112-D-1 Main Column 1 Pressure Control Valve 

PCV 21 – Emergency Wet Gas Compressor 

1 PSV PSV-21 on Flush Oil Drum 1 Pump Seal Purge 110-G-23 Slurry Oil Pump 

QS2 (Ex: Gas Oil Treater) 

Continue same as QS1 Continue same as QS1 

QS3 Continue same as QS1 Continue same as QS1 

QS4 Continue same as QS1 Continue same as QS1 A-H 1 PSVs PSV-17 on 109-E-42 Slurry Heat Exchanger 

B-H 2 Pump Seal Purges 110-G-3 Gas Oil Feed 

110-G-4 Main Column Reflux 

3 of 3 
 

	 	

	 	

	 	

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APPENDIX FLR-13 

REPRESENTATIONS OF DISCONTINUOUS WAKE DOMINATED FLOW 

Definition 

“Discontinuous Wake Dominated Flow” shall mean gas flow exiting a Flare tip that is identified 

visually by: 

i. the presence of a flame that is: (1) immediately adjacent to the 

exterior of the Flare tip body; and (2) below the exit plane of the Flare tip; and 

ii. a discontinuous flame, such that pockets of flame are detached from 

the portion of the flame that is immediately adjacent to the exterior of the Flare tip body. 

Background 

The gases present just outside of the flare tip are influenced by several factors. All of these 

factors are present all of the time, but as process and environmental conditions change, the 

relative “strength” of each factor will change. The most dominant factors will dictate the flow of 

the Vent Gases, i.e., will determine the size, shape, and direction of the flame. Some of the 

influences on the Vent Gases are: 

o	 The low pressure region, or wake, that is downwind and next to the flare. 

o	 The temperature gradient that causes the warm combustion gases to be buoyant, 

or rise. 

o	 The inertia, or resistance to changes in speed and direction, of the Vent Gases as 

they exit the tip. 

The regimes below show how a flame will appear when the most dominant influences are, 

respectively, the wake, the buoyancy due to temperature, and the inertia due to the gas’s 

momentum. 
 

 

 

 

 

 

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Flare 

Tip 

Images take from: Practical Implications of Prior Research on Today’s Outstanding Flare 

Emissions Questions and a Research Program to Answer Them
 

James Seebold, ChevronTexaco (Retired)
 

Peter Gogolek, Natural Resources Canada
 

John Pohl, Virginia Polytechnic Institute and State University
 

Robert Schwartz, John Zink Company LLC
 

As a wake dominated flame becomes less stable, it becomes segmented, or discontinuous. The 

following is a representation of ―Discontinuous Wake Dominated Flow.‖ The red area is an 

artist’s rendition of a flame. 

FLR-13-2
 
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The following image represents a flame below the plane of the exit of the flare tip. However, 

since the flame is not discontinuous and not immediately adjacent to the tip, this image would 

not represent Discontinuous Wake Dominated Flow. 

The following image represents a flame below the plane of the exit of the flare tip and attached 

to the tip. However, since the flame is not discontinuous, this image would not represent 

Discontinuous Wake Dominated Flow. 

FLR-13-3
 
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In order for the flame to be deemed discontinuous, it should be segmented, and not merely 

possess small pockets of flame at the outer boundary of a single large cohesive flame. 

Furthermore, a discontinuous flame will normally appear thin relative to its length, and lack a 

single bulbous core. The following image represents a flame with a small pocket of flame only 

at the outer edges of the broad main flame. This would not represent a discontinuous flame, and 

therefore would not be Discontinuous Wake Dominated Flow. 

FLR-13-4
 
 


 


 
 


 
 

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APPENDIX FLR-14 

DETERMINING REFINERY-SPECIFIC AND INDUSTRY-AVERAGE COMPLEXITY 

THROUGH USE OF THE NELSON COMPLEXITY INDEX 

For purposes of Paragraph 27 of the Consent Decree, the complexity of the Refinery is to be 

calculated using the following formula: 

Equation 1 

Complexity =

i ⎛

⎜

⎜ n 1 ⎝ ∑=

NCIi 

CAPDist 

⎞

⎟

⎟

⎠

×CAPi

Where: 

NCIi = The 2011 Nelson Complexity Index Coefficient shown 

in Table 1 below for Process i 

The throughput capacity for Process i in barrels per 

CAPi = calendar day as identified by the most recent Oil & Gas 

Journal survey 

The Refinery’s Crude Distillation Capacity in barrels 

CAPDIST = per calendar day as reported in the most recent report 

submitted by BPP to the Department of Energy 

For purposes of Paragraph 27 of the Consent Decree, the industry average complexity is to be 

calculated using the following formula: 

Equation 2 

i ⎛

⎜

⎜

⎝
 

NCIi × ICAPi ⎞

⎟

⎟

⎠
 ∑n =1 

Where: 

The 2011 Nelson Complexity Index Coefficient shown NCIi = in Table 1 below for Process i 

Total US throughput capacity for Process i in barrels 

ICAPi = per calendar day as identified by the most recent Oil & 

Gas Journal survey 

Total US Crude Distillation Capacity in barrels per 

ICAPDIST = calendar day as identified by the most recent Oil & Gas 

Journal survey 

Industry Average _ _ Complexity = ICAPDist 

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APPENDIX FLR-14 

Table 1: 2011 Nelson Complexity Index Coefficients 

Refining Process NCI Coefficients 

Distillation Capacity 1.00 

Vacuum Distillation 1.30 

Thermal Processes 2.75 

Coking 7.50 

Catalytic Cracking 6.00 

Catalytic Reforming 5.00 

Catalytic Hydrocracking 8.00 

Catalytic Hydrorefining 2.50 

Catalytic Hydrotreating 2.50 

Alkylation 10.00 

Polemerization 10.00 

Aromatics 20.00 

Isomerization 3.00 

Lubes 60.00 

Asphalt 1.50 

Hydrogen (MCFD) 1.00 

Oxygenates 10.00 

Sulfur Extraction 240.00 

2 of 2 
 


 



 


 


 


 

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APPENDIX FLR-15
 

LIMITING AIR FLOW TO ENSURE ADEQUATE COMBUSTION EFFICIENCY FOR 

AIR-ASSISTED FLARES 

All abbreviations, constants, and variables are defined in the Key at the end of this 

Appendix. 

Steps in the Calculations 

Step 1: Determine the concentration of the compounds in the Vent Gas 

If a Gas Chromatograph is used: Determine the volume fraction of all prominent compounds 

in the vent stream. 

If a Gas Chromatograph is not used: Determine the volume fractions from bag samples, 

engineering knowledge, or facility estimates. 

Step 2: Calculate oxygen molar demand at a stoichiometric ratio 

The complete combustion of an organic compound comprised of a combination of carbon and 

hydrogen atoms is shown in Equation 1. In the event the Vent Gas contains hydrogen, the value 

for x is zero and for y is two. 

௫ܥ

ݕ ݕ ܪ௬ ൅ ቀݔ ൅ ቁ ܱଶ ՜ ܥݔܱଶ ൅ ቀ ቁ ܪଶܱ Equation 1 4 2

Therefore, the stoichiometric oxygen molar flow rate (moles/hr) for any given combustible 

compound flow is defined by Equation 2: 

݉ሶ ௩௚ ݕ

݊ሶ

ைଶି௦௧௢௜௖௛ ൌ ݔ ௝ቆ ቇ ቀݔ ൅ ቁ Equation 2 ܯܹ௩௚ 4

Step 3: Calculate oxygen demand at stoichiometric conditions 

The stoichiometric oxygen mass flow rate for the vent gas (lb/hr) is given by Equation 3. 

௡

݉ሶைଶି௦௧௢௜௖௛ି௩௚ ൌ ܯܹைమ כ ෍ Equation 3 ைଶି௦௧௢௜௖௛ೕ ݊ሶ

௝ୀଵ

FLR-15-1 
 

 

 


 

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Step 4: Calculate air mass flow rate at stoichiometric conditions 

The mass of air needed to reach a stoichiometric ratio based on the actual Vent Gas flow rate is 

given by Equation 4. 

݉ሶ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ൌ כ ݉ሶைଶି௦௧௢௜௖௛ି௩௚

௥௜௔ܹܯ

ܹܯ ைమ ·10.2 Equation 4 

Step 5: Calculate actual Assist Air mass flow rate (given air flow volume) 

If the assist air mass flow rate is not known directly (via flow meter) it can be calculated from 

the volumetric flow (typically from a fan curve): 

௥௜௔ܹܯ ሶ௔௜௥ ݉

ି௔௦௦௜௦௧ ൌ כ ܸ 385.5 ሶ௔௜௥ି௔௦௦௜௦௧ Equation 5 

Step 6: Ensure that during flare operation, the following is met: 

݉ሶ ௥௔௜ ି௔௦௦௜௦௧ ൏ 106 ·
 ݉ሶ ௔௜௥ି௦௧௢௜௖௛ି௩௚ Equation 6 

FLR-15-2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


 

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Key to the Abbreviations: 

ሻ ݅ܽݎ ݉ –݋݈ ⁄݈ܾଶܱ ݈݋݉ –݈ܾ 0.21ሺ ݅݊ ݎܽ݅ ݂݋ ݃݁݊ݕݔ݋ ݊݋݅ݐܽܿݎ݂ ݈݁݉݋ ൌ 0.21

ሻ݈݁݋݂ܿ/݉ݏሺ ݉ݐܽ 1 ܽ݊݀ ܨ68° @ ݏ݃ܽ ܽ݊ ݈݅݀݁ܽ ݉݁ݑ݈݋ݒ ݂݋ ݉ݎ݈ܽ݋ ൌ 385.5

ሻݏݏ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݅݊ ݅ ݉ݑ݈݋݊ܿ ݉݋ݎ݂ ݉݋ܿ݌݊ݑ݋݀ ݉ݑ݁݀݊ݎܾ݁ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݅

ሻݏݏ ݈݁ ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݅݊ ݆ ݑ݈݋݉݊ܿ ݉݋ݎ݂ ݑ݋݌݉݋݊݀ܿ ܾ݉݁ݑ݁݀݊ݎ ݑ݈ܽ݀ ݒ݅݅݊݀݅ ൌ ݆

ሻݎ݈ܾ/݄ሺ ݐݏ݅ݏݏܽ ݎܽ݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௦௧௜௦௦௔ି ௔௜௥ሶ݉

ݎ݈ܾ/݄ሺݏ݃ܽ ݐ ݎ݋݂ ݄ݐ ݁݊ݒ ݁ ݎܽ݅ ݓ݋݂݈ ݁ݐܽݎ ݏݏ݉ܽ ݉݋݅ܿݎݐ݁ ݏ݄݅ܿ݋ݐ݅ ൌ௢ ௦௧ି௚௜௔௜௥௩ି ௖௛ሶ݉

ሻ ݄ݎ ⁄

ሻ

݈ܾሺ ݏ݃ܽ ݐ ݎ݋݂ ݄݁ݐ ݁݊ݒ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݏ݄݅ܿ݅݋ݐݐ݉݁݋݅ܿݎ ൌ ௦ି௧ைଶ௚௢௩ି ௜௖௛ሶ݉

݈ܾሺ/ሻݎ݄ ݐ݁݊ݒ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ௚ ௩ ሶ݉

ሻ݈݋݉ –݈ܾ/݈ܾ 32.0ሺ ݃݁݊ݕݔ݋ ݐ݄݁݅݃ݓ ݂݋ ݎ݈ܽ ݉ݑ݈݁ܿ݋ ൌ ைమܹܯ

ሻ݈݋݉ –݈ܾ/݈ܾ 28.9ሺ ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ௔௜௥ ܹܯ

ሻ ݈݉݋ –݈ܾ/݈ܾሺ ݐ݁݊ݒ ݏ݃ܽ ݐ݄݁݅݃ݓ ݂݋ ݎ݈ܽ ݉ݑ݈݁ܿ݋ ൌ௚ ௩ܹܯ

ሻ ݏݏ ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݉݋ݎ݂ ݑ݋݌݉݋݀݊ܿݏ ݈ܽݑ ݂݋ ݅݀݅݊݀݅ݒ ݐݏ݈݅ ൌ ݊

݊ሶ

ܸሶ

ሻݎ݄ ݂ܿݏሺ/ ݎܽ݅ ݂݋ ݐݏ݅ݏݏܽ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ ൌݒ ௟௔௧௨௔௖ି௔௜௥

ሻ݈݋݈/݉݋݉ሺ ௬ܪ௫ ݂݋ ܥ ݈݁݋݉ ݎ݁݌ ݊݋ܾݎܿܽ ݂݋ ݏ݈݁݋݉ ݔൌ

݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ ݌݉݋ܿ ݑܾ݉݋ܾ݈݅ܿݐݏ݁ ݑ݈ܽ݅݀ ݒ ݊݀݅݅

ሻ݈݋݈/݉݋݉ሺ ௬ ܥܪ௫ ݂݋

ሻݎ ݄⁄ ݈݋݉ሺ ݊݀ݑ ݌݉݋ܿ݋ ݈ܽݑ݅݀ݒ݅ ݎ݋݂ ܽ݊ ݅݊݀ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݋݄݅ܿ݅݋ݐ݉ݐ݅ܿ݁ݎ ݏ ൌ ି௧௦ைଶ௜௖௛௢

ሻ݊ ݅݋ ݐ ܿܽ ݂ݎ ݋݈ ݒሺ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊ ݋ ൌ௝ ݔ

ݎ݁݌ ݈݋݁݉ ݃݁݊݋ݎ݀ݕ݄ ݂݋ ݏ݈݁݋݉ ൌ ݕ

FLR-15-3 
 


 


 



 

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Table 1 

Individual Compound Properties
 

I

(1) j Compound MWi 

(lb/lbmol) 

x + y/4 

1 1 Hydrogen 2.02 0.5 

2 Oxygen 32.00 0 

3 Nitrogen 28.01 0 

4 CO2 44.01 0 

5 CO 28.01 0 

6 2 Methane 16.04 2 

7 3 Ethane 30.07 3.5 

8 4 Ethylene 28.05 3 

9 5 Acetylene 26.04 2.5 

10 6 Propane 44.10 5 

11 7 Propylene 42.08 4.5 

12 8 iso-Butane 58.12 6.5 

13 9 n-Butane 58.12 6.5 

14 10 

iso-Butene, Butene-1, 

trans-Butene-2, cisButene-2 and 1,3 

Butadiene combined 

56.11 6 

15 14 Pentane+ (C5+) 72.15 8 

16 Water 18.02 0 

1

 i=all compounds, j=organic compounds and hydrogen 

Note: Benzene and 1,3 butadiene are not required to be speciated by the Gas Chromatograph for this 

refinery settlement (see Appendix FLR-10) because benzene and 1,3 butadiene are present in the Vent Gas 

only in de minimis quantities. Because benzene and 1,3 butadiene speciation is not required, it is not listed 

in Table 1of this Appendix. The Vent Gas composition involved in other future settlements should be 

evaluated on a case-by-case basis to determine if benzene or 1,3 butadiene speciation should be required. 

FLR-15-4 
 


 



 



 

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APPENDIX FLR-16 

COMBUSTION EFFICENCY TEST PROTOCOL 

1.0 Test Objectives 

BPP is planning to conduct a performance test on a refinery flare. The flare is an 

elevated steam-assisted flare, with a XX† inches diameter flare tip manufactured by 

XXX† with an effective diameter of XX† inches. The tip has XX† steam injection points, 

XXX for center steam (if applicable), XXX† for lower steam, and XXX† for an upper 

steam ring. The primary objective of the flare performance test is to evaluate the 

impacts of combustion efficiency over a range of steam rates. 

BPP is planning to conduct the test on (ADD DATES†). Passive Fourier Transform 

Infrared (PFTIR) instruments operated by (ADD VENDOR†) will be used to measure 

combustion efficiency of the flare. 

2.0 Flare Performance Test 

During the Test, the S/VG will be varied. Each steam ratio is defined as a “test run.” 

During each test run, one or more PFTIR analyzers will remotely analyze the combustion 

gases in the flare plume to determine combustion efficiency. The result will be a defined 

flare operating envelope defined by the incipient smoke point on one side and 

oversteaming on the other. 

The Refinery is located within a populated region, and therefore, this test plan does not 

include evaluating combustion efficiency on plumes having visible emissions. Each Test 

series will begin at either the incipient smoke point or at the minimum cooling steam rate 

assuming it can be achieved without incurring visible emissions. 

3.0 Procedure 

The anticipated time for the test is about 2 to 4 hours or more depending on the number 

of steam flow conditions to be tested and atmospheric conditions. The duration of each 

test run will be approximately 15-30 minutes and will be synchronized to the GC analysis 

cycle. 

Before the beginning of each Test, a minimum of two GC cycles will be examined to 

ensure something close to the expected flare vent gas composition has been achieved and 

to ensure it is reasonably stable. Once the test begins, each S/VG test run will be 

bracketed by GC results. The results from the end of one S/VG test period will serve as 

†

 To be completed by BPP when submitting the protocol. 

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the results for the beginning of the next. If a comparison of all GC results shows a 

significant change (as defined below), then the S/VG test run will be repeated. 

Once the flare operator receives each new GC analytical report and it appears that no 

significant composition changes have occurred, the operator will notify all test personnel. 

The PFTIR operator will respond as to whether he has been able to obtain sufficient data 

at that test run. If so, the flare operator will then adjust the steam mass flow rate to match 

the next S/VG ratio in the test matrix. The PFTIR operator will then begin to take 

measurements at the new test run. Since PFTIR measurements are affected by transient 

atmospheric conditions such as clouds and wind, the PFTIR operator will notify the flare 

operator if a test run must be held for more than the schedule test time due to a transient 

condition (see Section 7.0 for wind requirements). The PFTIR operator will periodically 

pull off the plume to perform a sky background adjustment on the analyzer. In all such 

cases, the synchronization between GC and PFTIR data will be maintained. 

It is important to note that the base flare gas which is present at all times during testing 

may vary significantly in both flow and composition. During the Test, both flare gas and 

steam flow rates will be measured continuously with ultrasonic flow monitors. 

Determination of molecular weight of the flare gas will also be provided continuously. 

This data should allow operators to hold a steady S/VG ratio even as flow rates and 

composition varies. 

A gas chromatograph to measure the composition of the flare vent gas or ultrasonic flow 

meter to determine the molecular weight of the flare vent gas will not be required at the 

Whiting Refinery LPG flare for PFTIR testing. Instead, Whiting personnel will collect 

and analyze sufficient samples to determine the representative composition and molecular 

weight of vent gas during the test period. The type and frequency of sampling will be 

agreed with the EPA as part of the testing protocol for the LPG flare. 

Test runs representing the range of normal flare operations will be replicated at least two 

times over the course of the test program. This will allow a determination of the 

combustion efficiency variability for each test run over time. During the transition from 

one run to another, the flare may experience short periods of over-steaming due to 

potential limitations in the instrumentation and control logic response times. Smoking, 

however, must be avoided (even for short durations) due to the proximity of the 

surrounding community. The frequency and duration of such smoking periods will be 

recorded. 

At the beginning and end of each test day, the PFTIR operator will calibrate the PFTIR 

according to the calibration protocol found in Appendix A. A Long Term Stability (LTS) 

test will be performed at the beginning of each test day. 

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4.0 Location 

If two PFTIR instruments are used, they will be placed so that at least one instrument is 

capable of collecting valid data regardless of wind speed or direction. 

[ADD PLOT PLAN WITH FLARE LOCATION]† 

Figure 1: Map of equipment locations in relation to flare 

†

 To be completed by BPP when submitting the protocol. 

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5.0 Data Collection 

Data used for final analysis of flare performance will originate from several different 

sources. Each data set from the several sources will be combined for analysis at the end 

of the test program. The final data sets from the several sources, especially PFTIR 

measurements, may change after the test program due to more complete processing of the 

raw measurements. 

5.1 Test Run Log 

A log will be kept of each test run. Each log entry will include the start and stop times of 

the run as well as any events occurring during the run. Runs that are not completed will 

also have an entry and comment on why the run was not completed. 

In addition to run times, each log entry will have a description of the conditions at which 

the run was performed. The entry will also note the visible emissions rating of the flare 

and any ambient factors that could affect the test performance (wind direction, cooling 

tower plume, etc.). The visible emissions rating scale is provided in Appendix C. 

5.2 Process Data 

Process data will be provided by plant operations and include process data, vent gas 

composition data, and meteorological data. Table 2 lists the parameters and time interval 

that will be recorded and delivered by plant operations. The gas chromatograph (GC) 

used for measuring flare gas composition will report the compounds listed in Table 3. 

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Parameter Unit Frequency 

Flare Gas Volumetric Flow Rate scfh 1 minute 

Flare Gas Mass Flow Rate lb/hr 1 minute 

Flare Gas Molecular Weight lb/lb-mole 1 minute 

Flare Gas Composition vol. % 15 minutes 

Estimated Pilot Gas Flow Rate lb/hr N/A 

Steam Mass Flow Rate lb/hr 1 minute 

Steam Temperature at Flow Measurement Point °F 1 minute 

Flare Gas Combustion Zone Net Heating Value BTU/scf 15 minutes 

Vent Gas Net Heating Value BTU/scf 15 minutes 

Actual Total Steam to Vent Gas Ratio -­ 1 minute 

Hydrocarbon Mass Flow Rate lb/hr 15 minutes 

Flare Exit Velocity fps 1 minute 

Wind Direction ° 1 minute 

Wind Speed mph 1 minute 

Ambient Barometric Pressure in. Hg 1 minute 

Ambient Temperature °F 1 minute 

Ambient Humidity % 1 minute 

Momentum Flux Ratio -­ 1 minute 

Table 2: Process data parameters that will be reported 

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Compound Mol. Wt. Range Units 

Hydrogen 2.02 0 - 100 mole % 

Nitrogen 28.02 0 - 100 mole % 

Oxygen 32.00 0 - 100 mole % 

Carbon Dioxide 44.01 0 - 100 mole % 

Carbon Monoxide 28.01 0 - 100 mole % 

Methane 16.04 0 - 100 mole % 

Ethane 30.07 0 - 100 mole % 

Ethylene 28.06 0 - 100 mole % 

Acetylene 26.04 0 - 100 mole % 

Propane 44.10 0 - 100 mole % 

Propylene 42.08 0 - 100 mole % 

Iso-Butane 58.12 0 - 100 mole % 

Normal Butane 58.12 0 - 100 mole % 

iso-Butene, Butene-1, 

cis-butene-2, transbutene-2 and 1,3 

Butadiene combined 

56.11 0 - 100 mole % 

Pentane-Plus (C5+) 72.15 0 - 100 mole % 

Table 3: Compounds reported by the GC for flare gas composition 

5.3 PFTIR 

PFTIR instruments from [INSERT VENDOR] will be used to measure combustion 

efficiency of the flare. The PFTIR instruments will be equipped with dual sensors -

mercury-cadmium-telluride (HgCdTe) and indium-antimonide (InSb). If two PFTIR 

instruments are used to conduct measurements during a test run, then each instrument 

will be located 90° around the base of the flare to the other (see Figure 1). The 

perpendicular placement of the two instruments will allow one instrument to have an 

adequate plume cross-section for any wind direction (see Section 6). 

PFTIR data will be logged into the data acquisition system supplied by the PFTIR 

contractor. PFTIR measurements will be provided for analysis on a minute-by-minute 

timeline. The reported values will constitute an average of several analytical cycles over 

each test run. The software used by the PFTIR contractor is proprietary but will perform 

analyses and report data in accordance with the specifications found in Appendix A. 

Table 4 lists the compounds to be measured. 

The Test Report shall state which wave number was used for quantification of CO2, and 

shall compare and discuss 765 and 2000 wave number data. 

Compound Unit 

Carbon Dioxide (CO2) ppm x m 

Carbon Monoxide (CO) ppm x m 

Methane (CH4) ppm x m 

Ethylene (C2H4) ppm x m 

Propane (C3H8) ppm x m 

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Compound Unit 

Propylene (C3H6) ppm x m 

Butane (C4H10) ppm x m 

1,3 Butadiene (C4H6) ppm x m 

Total Hydrocarbon ppm x m 

(THC) 

Table 4: Compounds reported by the PFTIR 

5.4 Video 

Both thermal and visual video recordings will be collected and stored. A timestamp for 

each image will saved with the video so the video can be reference to each test run. 

One aiming camera mounted to each PFTIR will record the point at which the PFTIR is 

pointed. One high definition visual color camera will be beside each PFTIR to record the 

overall flare flame and plume. One infrared camera will be beside each PFTIR to record 

the thermal image of the flare plume. Specifications on the video cameras are located in 

Appendix B. 

6.0 Stability of Flare 

It should be understood that because this test program is being conducted on a working 

refinery flare, it might not always be possible to maintain stable conditions throughout 

the duration of a test run. The flow rates and flare gas composition could be changing 

throughout the duration of each test run. 

In order to generate reliable data, it is necessary to define conditions under which the 

variability of flare gas flow or composition occurring during the test period is large 

enough to warrant concern over data quality. Therefore, at the end of each test period, we 

will calculate whether the variability in vent gas flow rate or composition during the test 

period would have resulted in an S/VG ratio that would be more than 25% different than 

the S/VG ratio at which the test was conducted. If this is found to be the case, the test run 

will be repeated once a stable flow rate and composition can be maintained. 

During test runs calling for the S/VG ratio, the steam mass flow may change over the test 

period based on vent gas flow, but the ratio will remain constant. 

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7.0 Wind Direction Impacts 

Because a PFTIR measures the thermal radiation of hot gases passively, it is sensitive to 

other background and environmental variables. A consistent cross-section of the plume 

must be measured to obtain a representative area of the plume. Therefore, a PFTIR 

cannot operate under certain wind conditions that would prevent an adequate plume 

cross-section. 

When the wind blows the flare plume away or towards a PFTIR location, a good crosssection of plume cannot be measured. A wind restriction of +/-30 degrees downwind and 

upwind will be applied to the test program (see Figure 2). Only data from the PFTIR 

location with a good cross-section of the flare plume will be considered valid. 

If other ambient conditions prevent collection of a representative sample by either 

PFTIR, the test program will be paused to allow those ambient conditions to subside. 

Examples of such conditions may include cooling tower plume interference, rain or fog, 

and abrupt changes in wind direction. 

[ADD WIND ROSE MAP]† 

Figure 2: Restricted wind directions for PFTIR locations 

†

 To be completed by BPP when submitting the protocol. 

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8.0 Calibration 

Radiance calibrations will be conducted at least once each day with a blackbody IR 

source located at roughly the same distance from the PFTIR as the flare. This involves 

pointing the PFTIR at the black body IR source to collect the radiance of the air between 

the source and the PFTIR. This radiance is the transmission radiance between the flare 

plume and the PFTIR. 

Background radiance calibrations will be performed as needed when the background 

ambient conditions change throughout the day. At minimum, a background radiance 

calibration will be performed once per run. This involves pointing the PFTIR at the sky 

behind the flare plume without including and plume. This radiance is the background 

radiance behind the flare plume. 

By removing the transmission radiance and the background radiance from the measured 

radiance when the PFTIR is pointing at the flare plume, the plume radiance is isolated 

and can be analyzed for concentration x pathlength. 

In order to challenge the PFTIR with known concentrations of gas, hot cell calibrations 

will be performed prior to the test program. In this calibration, a known mixture of CO2, 

CO, and methane are metered by mass flow controllers into a heated cell. This cell is 

placed at the focal point of the collimator used for the radiance and other calibrations and 

which is located at a distance from the PFTIR. The PFTIR then collects data from the cell 

and the data is reduced to produce a concentration result. This result is then compared to 

the known value of the calibration gas concentration. From this hot cell calibration data, 

calibration curves will be produced and can be used for calibration factors that will be 

applied to the measured flare plume data. 

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9.0 Camera Operation and Calibration 

9.1 Thermal – FLIR 

The FLIR is a stand-alone thermal measurement camera that can determine the 

temperature of objects within 2°C or 2% of its calibration range. It has an internal 

computer that calculates object temperatures and outputs a false color image of the 

camera’s field of view. A scale of temperatures is displayed on the image to show what 

the range of the color palate is. The FLIR also has the ability to display custom areas in 

the image as an average temperature. 

A FLIR camera measures the infrared radiance of objects in its field of view. The 

temperature readings from the FLIR camera are calibrated to the radiance from NISTtraceable black body sources. However, the FLIR cameras used in this test plan will be 

attempting to measure the flare plume temperature, which is not a solid object. 

Therefore, temperature measurements by the FLIR cameras are biased low because the 

plume gas is semi-transparent at the wavelengths measured (7.5-13.0μm). The main use 

of the FLIR cameras will be to identify when the flare flame is about to snuff due to over 

steaming. 

9.2 Visible Light Camera 

The visible light camera outputs a high definition 720p or 1080i resolution image at 25 or 

30 frames per second and 16:9 aspect ratio. It has a 10x optical zoom and auto focus. The 

purpose of the camera is to record how the flare flame appears during testing. 

9.3 Aiming Cameras 

The PFTIR at each location will need to be aimed at the flare plume when they are 

collecting data. An infrared camera will be mounted on each PFTIR to assist with aiming. 

Two types of infrared cameras can be used for mounted aiming: the NEC/Mikron 

TH5104 (color) or equivalent and the Agema Thermovision 510 (black & white) or 

equivalent. Both use a bandpass of 3-5μm. 

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10.0 Visual Emissions Scale 

Flame Rating Flame Characteristic 

0 Steam plume 

1 Transparent 

2 Mostly transparent, with occasional yellow flame. 

3 Mostly yellow flame, with occasional transparency. 

4 Yellow to orange flame. 

5 Orange flame with some dark areas in the flame. (Incipient smoke point) 

6 Orange flame with light smoke trail. 

7 Clear steam at the flare tip, with an orange flame and a light smoke trail. 

8 Orange flame with dark smoke trail leaving the flame. 

9 Orange flame with heavy dark smoke trail leaving the flame. 

10 Billowing black smoke 

Table C-1: Visual emissions and flame rating scale 

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APPENDIX FLR-17 

CONTENTS OF REPORTS FOR EMISSIONS AND FLARE COMBUSTION 

EFFICIENCY TESTING 

1. Background and Summary 

1.1 Overview 

1.2 Results
 

2. Introduction 

2.1 Objectives of Test Program 

2.2 Testing Organization 

2.3 Flare System Components 

2.3.1 Purpose 

2.3.2 Flare Tip 

2.3.3 Flare Automatic Steam Control System 

2.4 Video Cameras 

2.5 Passive FTIR 

2.6 Flare Test Program 

2.6.1 Test Conditions 

2.6.2 PFTIR Locations 

2.6.3 Run Length and Replicates 

3. Summary of Results 

3.1 Summary and Key Data Trends by Varied Parameter 

3.2 Summary and Key Data Trends of Whole Data Set 

3.2.1 Composite of All Hydrocarbons Tested 

3.2.2 Visible Emissions and Combustion Efficiency 

3.3 Factors Influencing Test Results 

3.3.1 Run Lengths 

3.3.2 Wind Effects 

3.3.2.1 Momentum Flux Ratio 

3.3.3 PFTIR Aiming 

3.3.4 Overall Test Variability 

3.3.4.1 Long Term Stability 

FLR18-1 
 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 


 



 


 


 


 


 



 


 


 


 


 

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3.3.4.2 Replicate Analysis 

3.3.4.3 Dual PFTIR Simultaneous Measurements 

3.3.4.4 Dilution Assumption 

3.3.4.5 PFTIR Field Hot Cell Checks 

3.3.5 PFTIR Calibration 

3.3.5.1 Background Radiance Calibrations 

3.3.5.2 Atmospheric Radiance and Transmission Calibrations 

3.3.5.3 Hot Cell Calibrations 

3.3.6 PFTIR Detectors 

3.3.6.1 Spectral Regions for CO2

 3.4 Conclusions 

3.4.1 Comparison with other PFTIR flare tests 

3.5 Recommendations for Further Study 

4. PFTIR Testing Method and Procedure 

4.1 Description and Principles of Passive FTIR 

4.2 PFTIR Siting Configuration 

4.3 Background 

4.4 PFTIR Operation 

4.5 PFTIR Data Reduction 

5. Data Tables 

5.1 Data Summary Tables 

5.2 Long Term Stability Test 

5.2.1 Process Conditions

 5.2.2 Wind Conditions
 

6. Appendices 

A.1 Calculations 

A.2 PFTIR Theory and Operation 

A.3 VOC Emissions Calculations 

A.4 Personnel Involved with Flare Performance Test 

A.5 Minute Data of Runs
 

A.6 Video of Runs 

A.7 PFTIR Raw Data and Spectra 

A.8 Flare Visual Rating Data Sheets 

A.9 Gas Calibration Sheets for Field Hot Cell Checks 

FLR18-2 
 

	 

	 

	 

	 

	 

	 

	 

	 


 

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APPENDIX FLR-18 

Calculating Sulfur Dioxide Emissions From Reportable Flaring Incidents

 1. Calculating the Quantity of Sulfur Dioxide Emissions from Acid Gas and 

Hydrocarbon Flaring Incidents 

a. The quantity of SO2 emissions resulting from an AG and HC Flaring 

Incidents shall be calculated by the following equation: 

Tons of SO2 = [FR][TD][ConcS][8.44 x 10-5] (Equation 1) 

b. The meaning of the variables is set forth in Paragraph 3. 

c. The quantity of SO2 emitted shall be rounded to one decimal point. (Thus, 

for example, for a calculation that results in a number equal to 10.050 

tons, the quantity of SO2 emitted shall be rounded to 10.1 tons.) 

d. For purposes of determining the occurrence of, or the total quantity of SO2 

emissions resulting from, an Acid Gas or Hydrocarbon Flaring Incident 

that is comprised of intermittent Flaring, the quantity of SO2 emitted shall 

be equal to the sum of the quantities of SO2 emitted during each 24-hour 

period starting when the gas was first flared. 

2. Calculating the Rate of Sulfur Dioxide Emissions During Acid Gas or 

Hydrocarbon Flaring. 

a. The rate of SO2 emissions resulting from an Acid Gas or HC Flaring 

Incident shall be expressed in terms of pounds per hour and shall be 

calculated by the following formula: 

ER = [FR][ConcS][0.169] (Equation 2) 

b. The meaning of the variables is set forth in Paragraph 3. 

c. The emission rate shall be rounded to one decimal point. (Thus, for 

example, for a calculation that results in an emission rate of 19.95 pounds 

of SO2 per hour, the emission rate shall be rounded to 20.0 pounds of SO2 

per hour; for a calculation that results in an emission rate of 20.05 pounds 

of SO2 per hour, the emission rate shall be rounded to 20.1.) 

[Appendix FLR-18 is continued on next page] 

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3. Meaning of Variables and Derivation of Multipliers Used in the 

Equations 1 and 2: 

ER = Emission Rate in pounds of SO2 per hour 

FR = Average Flow Rate during the Flaring Incident 

in standard cubic feet per hour 

TD = Total Duration of Flaring Incident in hours 

ConcS = Average Concentration of Sulfur in gas during Flaring Incident (or 

immediately prior to Flaring Incident if all gas is being flared) 

expressed as a volume fraction (scf S/scf gas). 

8.44 x 10-5 = [lb mole S/379 scf S][64 lb SO2/lb mole S][Ton/2000 lb] 

0.169 = [lb mole S/379 scf S][1.0 lb mole SO2/lb mole S] 

[64 lb SO2/1.0 lb mole SO2] 

The flow of gas to the Flaring Device(s) (“FR”) shall be as measured by the relevant flow meter 

or reliable flow estimation parameters. Sulfur concentration (“ConcS”) shall be determined from 

the Sulfur Recovery Plant feed gas analyzer, an appropriate flare gas sulfur content analyzer 

(H2S, TRS, or total sulfur), from knowledge of the sulfur content of the process gas being flared, 

by direct measurement by tutwiler or draeger tube analysis, or by any other method approved by 

EPA or IDEM. In the event that any of these data points is unavailable or inaccurate, the missing 

data point(s) shall be estimated according to best engineering judgment. The report required to 

be prepared under Paragraph 54 shall include the data used in the calculation and an explanation 

of the basis for any estimates of missing data points. 

4. Calculating the Quantity of Sulfur Dioxide Emissions from Tail Gas Incidents – 

Trigger 1. For Tail Gas Incidents – Trigger 1, where, by definition, the Tail Gas is combusted in 

a flare, the quantity of SO2 emissions is calculated using Equation 1. 

[Appendix FLR-18 is continued on next page] 

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5. Calculating the Quantity of Sulfur Dioxide Emissions From Tail Gas Incidents – 

Trigger 2. For Tail Gas Incidents – Trigger 2, where, by definition the Tail Gas is combusted in 

a thermal incinerator, the quantity of SO2 emissions is calculated using the following equation: 

ERTGI 

(Equation 3) 

= TDTGI 

ÿ [ FRInc.]i [Conc. SO2 -250]i [0.169 x 10-6]i [(20.9 - % O2)/20.9]i 

i = 1 

Where: 

ERTGI = Emissions from Tail Gas at the incinerator, SO2 lb per 24-hour 

period 

TDTGI = Total Duration (number of hours) when the incinerator CEMS 

exceeded 250 ppmvd SO2 corrected to 0% O2 on a rolling twelve 

hour average, in each 24 hour period of the Incident 

i = Each hourly average 

FRInc. = Incinerator Exhaust Gas Flow Rate (standard cubic feet per hour, 

dry basis) (actual stack monitor data or engineering estimate based 

on the acid gas feed rate to the SRP) for each hour of the Incident 

Conc. SO2 = Each actual 12 hour rolling average SO2 concentration (CEMS 

data) that is greater than 250 ppm in the incinerator exhaust gas, 

ppmvd corrected to 0% O2, for each hour of the Incident. 

% O2 = O2 concentration (CEMS data) in the incinerator exhaust gas in 

volume % on dry basis for each hour of the Incident 

0.169 x 10-6 

= [lb mole of SO2 / 379 SO2] [64 lbs SO2 / lb mole SO2] [1 x 10-6] 

Standard conditions = 68 degree F; 14.7 lbforce/sq.in. absolute 

In the event the concentration SO2 data point is inaccurate or not available or a flow meter for 

FRInc does not exist or is inoperable, then BP shall use estimates based on best engineering 

judgment. 

[End of Appendix FLR-18] 

FLR18-3 
 

	 

	 


 

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APPENDIX E 

FENCE LINE MONITORING SYSTEM SUPPLEMENTAL ENVIRONMENTAL PROJECT 

BPP will install, operate and maintain a fence line monitoring system and make the data 

collected available to the public pursuant to the requirements of Section VII.A of the Consent 

Decree, and in accordance with the specifications and criteria identified in this Appendix. 

A. Equipment: The monitoring system shall consist of four monitoring stations, each of 

which shall be equipped with the following equipment: 

1. Instruments capable of measuring and recording the concentrations of the 

following compounds in air at a minimum detection level of 0.5 parts per billion 

by volume (ppbV) for benzene and toluene, and 1.0 ppbV for the following 

gaseous analytes: 

Pentane 

Hexane 

Sulfur dioxide 

Hydrogen sulfide 

Reduced sulfur compounds (defined as all compounds containing reduced 

sulfur measured as an aggregate sum) 

The monitoring equipment shall be capable of measuring the gases at the abovereferenced concentrations and the data recording system shall reduce those 

measurements to hourly averages. 

Within 60 days of the Date of Entry of this Consent Decree, BPP shall provide 

EPA with a Fence Line Monitoring Plan to include, at a minimum, identifying the 

locations of the meteorological station and each of the monitoring stations and 

how those sites meet the requirements of this Appendix; a Quality Assurance 

Project Plan (QAPP) that describes the Quality Assurance/Quality Control 

procedures, specifications, and other technical activities to be implemented to 

ensure that the results of the Fenceline Monitoring SEP meets project 

specifications; and implementation of the data availability requirements of this 

Appendix. 

a. SO2, Reduced Sulfur Compounds and H2S. Ambient 

concentrations of sulfur dioxide (SO2) will be continuously measured using 

Teledyne-API Model T100 or equivalent in accordance with 40 C.F.R. Part 53, 

Subparts A and C. The SO2 monitor shall be operated and maintained in 

accordance with all corresponding EPA equivalent method requirements. The 

SO2 monitors will be operated in the 0 to 0.50 ppm full scale measurement range 

with temperature and pressure compensation features activated. For Hydrogen 

Sulfide (H2S) and reduced sulfur compounds, the Teledyne API Model T101 or 

equivalent will be operated in switching mode to provide alternate 5-minute data 

for H2S, then reduced sulfur compounds. The monitors shall be operated and 

maintained in accordance with the manufacturer’s recommendations and shall be 

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capable of measuring reduced sulfur compounds and H2S, with a lower detection 

level of 1.0 ppb. 

b. Benzene, Toluene, Pentane, and Hexane. The continuous 

measurement of benzene, toluene, pentane, and hexane shall be accomplished 

using an SRI Model 8610 auto-GC or equivalent. The automated GC monitors 

shall be operated and maintained in accordance with the manufacturer’s 

recommendations and shall have a calibration range of 1.0 to 500 ppbV for all 

gases. The GC monitors shall operate with a one hour cycle time with ambient air 

samples collected over an approximate 40 minute period during each hourly 

cycle. 

Nothing in this Appendix E shall preclude the use of any other, additional fenceline 

monitoring equipment and/or monitoring of any other, additional pollutants at the 

fenceline of the Whiting Refinery. 

2. Instruments for Measuring and Recording Wind Speed, Wind Direction, Ambient 

Temperature, Humidity and Barometric Pressure. Specific meteorological 

parameters will be continuously monitored to obtain data representative of 

prevailing meteorological conditions for the Whiting refinery area. The data set 

produced shall be adequate to correlate prevailing conditions with pollutant 

measurements and transport. 

a. Continuously measured meteorological parameters shall include 

hourly-averaged (scalar or vector) measurements of horizontal wind speed and 

wind direction, the standard deviation of the horizontal wind direction (sigma 

theta), air temperature and relative humidity. Wind speed and direction shall be 

measured at a height of approximately 10 meters. Temperature, relative humidity, 

and barometric pressure shall be measured at a height of 2 to 3 meters. 

b. Wind direction and sigma theta measurement data shall be 

compiled and reported as hourly block averages in degrees (o

), rounded to the 

nearest whole degree. Wind speed data measurement data shall be compiled and 

reported as hourly block averages in miles per hour (mph), rounded to the nearest 

tenth of a mph. 

c. Air temperature measurement data will be compiled and reported 

as hourly block averages in degrees Fahrenheit (o F) or Celsius (o C), rounded to 

the nearest tenth of a degree. 

d. Relative humidity measurement data will be compiled and reported 

as hourly block averages in percent, rounded to the nearest whole percent. 

3. Monitoring Station. Monitoring equipment (except meteorological monitors and 

their support towers) shall be installed and operated inside a temperaturecontrolled equipment shelter. The temperature within each shelter shall be 

continuously monitored and recorded using a calibrated RTD and microprocessoror PC-based data acquisition system (DAS or data logger). The climate control 

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system for each monitoring shelter will be capable of maintaining a stable 

temperature within the range of 20° C to 30° C. 

Typically, the monitoring shelters will measure 8 feet wide by 12 feet long 

by 8 feet high. Each shelter will be anchored and secured to a concrete pad for 

safety. A padlocked exterior compartment attached to an outer wall of the shelter 

will safely house all compressed support gases. Shelters walls and roof will have a 

minimum insulation rating of R11. Each shelter will be equipped with electrical 

service panels, interior electrical distribution circuits, lighting, workbench and 

sufficient space for housing, operating and maintaining the monitoring 

instruments. All electrical wiring and appurtenances will conform to the National 

Electric Code (NEC). Each shelter electrical service and the shelter building itself 

will be grounded to earth in conformance with NEC and local code requirements. 

Monitoring shelters located within the refinery shall maintain a slight (e.g., 0.013 

to 0.026 Bar) internal positive air pressure with respect to atmospheric air 

pressure. 

B. Locations – The four monitoring stations shall be located on Whiting Refinery property 

near the Refinery fence line at up- and down-wind locations to be determined by BPP in 

consultations with EPA and interested members of Whiting’s Community Advisory 

Committee (CAC), and in consideration of the following siting criteria: 

a. The up- and down-wind locations should be determined by the last 

5 years of NOAA data from the most appropriate National Weather Service 

(NWS) or from the Indiana Department of Environment Management (IDEM) 

Gary, Indiana monitoring station. The meteorological data (resultant wind 

direction and wind speed hourly averages) will be used to construct wind roses for 

the site. 

b. Availability of land, accessibility to site, availability of utility 

services, and security of monitors and operating personnel. 

c. Geographic spacing of sites relative to the refinery for monitoring 

upwind and downwind concentrations. 

d. Probe or sampler inlet should be 2 to 5 meters above ground and 

have unrestricted airflow 270 degrees around the sample inlet probe or 180 

degrees if the probe is on the side of a building. 

e. Probe or sampler inlet should be >20 meters from the dripline of 

any tree(s). 

f. SO2, TRS, and VOC probes should be >1 meter away from 

supporting structures, walls and parapets. 

g. The distance from a sampler probe to an obstacle, such as a 

building, should be at least twice the height the obstacle protrudes above the 

sampler, probe, or monitoring path. 

h. All probes and samplers should be away from minor sources, such 

as incineration flues, to avoid undue influences from minor sources. The 

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separation distance is dependent on the height of the minor source’s emission 

point (such as a flue), the type of fuel or waste burned, and the quality of the fuel. 

C. Operation – BPP shall operate and maintain the monitors and equipment described 

herein in accordance with manufacturers’ recommendations for a period of no less than: 

(a) two years after installation and startup of the four monitoring stations, or (b) for a 

longer period, if necessary to meet the requirements of Paragraph 88 of the Consent 

Decree with respect to the total amount of money required to be expended. 

D. Quality Assurance/Quality Control (QA/QC) – BPP shall ensure that all data collected 

by the Fence Line Monitoring System is subjected to appropriate QA/QC procedures on a 

monthly basis. The QA/QC procedures for a given month’s data shall be completed by 

no later than the end of the month following the month within which the data were 

collected. 

E. Data Availability – On a weekly basis, BPP shall post the Fence Line Monitoring 

System data on a dedicated website or through BPP Whiting’s internet homepage 

(“Monitoring Data Website”), in a manner that shall be readily accessible, clearly 

labeled, and clearly presented to the public. BPP shall additionally post on the 

Monitoring Data Website, on a quarterly basis, CEMS emissions reports submitted to 

IDEM and/or USEPA pursuant to the Title V permit for all refinery units that are 

monitored by CEMS. BPP shall maintain data collected through the Fence Line 

Monitoring System on the Monitoring Data Website for at least five years from the date 

of its collection, and shall review the Fence Line Monitoring Data with the CAC 

members as they may request. 

F. General Provisions –As required by Paragraph 88, BPP shall expend not less than $2 

million in costs or expenditures to perform this SEP. For purposes of this SEP, “costs or 

expenditures” shall mean the costs or expenditures required to purchase, install, operate 

and maintain the monitoring equipment required by this SEP for a 2 year period, and at a 

cost of not less than $2 million. 

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APPENDIX F
 

FOVs and NOVs 

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