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 th an $400 million to install state-of-the-art pollution c ontrols 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 plati ng 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 agre ed 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, th e 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 ove rflows 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 Page 38 of 104 Civil Cases and Settlements | Enforcement | US EPA

12/29/2015 http://cfpub.epa.gov/enforcement/cases/Menu



## Enforcement 

# BP Whiting Settlement (Flaring)

(Washington, DC - May 23, 2012) The U.S. Environm ental 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 in stall state-of-the -art pollution cont rols and cut emissions from BP's petroleum refinery in Whiting, Ind. When fully implemented, the agreemen t is expected to reduce harmful air pollution that can cause respiratory problems such as asthma and are signifi cant 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 additi onally operates petroleum refineries in California, Indiana, Ohio, Texas and Was hington. 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. Page 1 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaring

## 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 constructi on 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 Standard s (NSPS), 40 C.F.R. Part 60, S ubparts 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 (NO x ) 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 ro lling average basis

◾ 20 ppm on a 7-day rolling average basis • Final FCCU sulfur dioxide (SO 2 ) 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 NO x and SO 2 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 mi crons or less (PM 10 ) per 1,000 pounds of coke burned

◾ 1.2 pounds of all particulate matter regardless of size (PM TOTAL ) 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 PM 10 per 1,000 pounds of coke burned

◾ 0.2 pounds of PM TOTAL 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 Cata lytic Reduction and Ultra Low NO x Burners on refinery heaters and boilers, and a sulfur limit of 70 ppm on any re finery fuel gas that is burned in heaters and boilers. NSPS and Flaring • Compliance with SO 2 standards of Subpart J and/or Ja for combustion devices burning refinery fuel

gas, including flaring devices. • Compliance with SO 2 standards of Subpart Ja at all sulfur recovery processes, including the sulfur

pit. Page 2 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaring• Installation of flare gas recovery systems. • Flare Minimization:

◦ Implementation of a waste gas mi nimization plan (a detailed pl an for reducing waste gas to flares).

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

lb/day SO 2 or 500,000 standard cubic feet pe r day (scf) waste gas flow.

◦ An overall limit on fl aring (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 pr ocedures 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 Ai r 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 re finery 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 repa ir at 200 ppm for valves • More frequent monitoring than required by regulation • Limitation on use of “Del ay of Repair” exception • Installation of “low-leaking” valve or va lve 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 conve yance 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 refi nery 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. Page 3 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaring

## Supplemental Environmental Project
As a supplemental environmental project, BP will inst all, operate and maintain a $2 million fence line monitoring system at the Whiting Re finery and will make the data collected available to the public by posting the information on a publicly-accessible website . Fenceline monitors wi ll continuously monitor benzene, toluene, pentane, hexane, SO 2 , hydrogen sulfide (H 2 S) and all “reduced sulfur compounds” (all compounds containing reduced sulfur). 

## Pollutant Reductions
When fully implemented, th e new controls and requirements under th e Consent Decree are estimated to reduce emissions by over 4,000 tons per year (tpy) of the following pollutants, as follows:
• NO x will be reduced by approximately 328 tpy • SO 2 by approximately 377 tpy • VOCs by approximately 3,224 tpy • Hazardous Air Pollutants by approximately 85 tpy • Additional reductions of PM, PM 10 , PM TOTAL , carbon monoxide (CO) and H 2 S 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 CO 2 e ). 

## Health and Environmental Effects
• Nitrogen Oxides – Nitrogen oxides can cause gr ound-level ozone, acid rai n, particulate matter,

global warming, water quality deterioration, and vi sual impairment. Nitrogen oxides play a major role, with volatile organic chemicals, in the at mospheric 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 SO 2 affect breathing and may aggr avate existing respiratory

and cardiovascular disease. Sensit ive 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 NO x , 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, a nd increased susceptibility to respiratory illnesses such as pneumonia and bronchitis. • Benzene - Acute (short-term) inhalation exposur e of humans to benzene may cause drowsiness,

dizziness, headaches, as well as eye, skin, and respiratory tr act 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 wo men exposed by inhalati on to high levels, and adverse effects on the developing fetus have been obser ved in animal tests. Increased incidences of Page 4 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaringleukemia have been observed in humans occupationa lly exposed to benzene. EPA has classified benzene as a Group A human carcinogen.
• Greenhouse Gases – The release of GHGs into the at mosphere traps heat. The continued release of

GHGs at or above the current rate will increase average temperatur es around the globe. Increases in global temperatures will most likel y change our planet’s climate in ways that will have significant long-term effects on peopl e and the environment. • Particulate Matter – PM, especially fine particles, cont ain 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 in creased respiratory symptoms such as irritation of the airways, coughing, or difficulty breathing, decreased lung f unction, 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 organi zations 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 Nort hern District of Indiana. The consent decree will be subject to a 30-day public comm ent 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. Page 5 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaringLast updated on March 2, 2015 Washington, DC 20460-0001 (202) 564-7978 foley.patrick@epa.gov Page 6 of 6 BP Whiting Settlement (Flarin g) | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/bp-whiting-settlement-flaringNewsroom 

### News Releases By Date

BP Agrees to Add More Than $400 Million in Pollution Controls at Indiana Refinery a nd Pay $8 Million Cl ean Air Act Penalty

Release Date: 05/23/2012 Contact Information: Stacy Kika, ki ka.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 t hat 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 I ndiana from harmful air pollution by requiring state-of-the-art pollution controls,” said Cynthia Giles, assistant adminis trator for EPA’s Office of Enforcement and Compliance Assurance."BP's agreement to inst all 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 re finery in Indiana,” said Ignacia S. Moreno, Assistant Attorney General for the Environment and Natural Re sources 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. W e 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) require ments 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 refi nery’s flaring devices. Flarin g devices are used to burn-off waste gases. The more waste gases sent to a flare, and the le ss efficient the flare is when bu rning 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 nati onal 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 syst em at the Whiting refinery and will make the data collected available to the public by posting the information on a publicly-accessible website. Fenceline m onitors 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 petro leum 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 6 th 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 pu blic comment period and final court approval.

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

- whiting.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 Amer ica Inc., Civil No. 2:12 CV 207 (PDF) (325 pp, 10 MB) Page 1 of 1 Consent Decree: BP Products Nort h America Inc., Civil No. 2:12 CV 207 | Enforcement | US EPA

12/29/2015 http://www.epa.gov/enforcement/c onsent-decree-bp- products-north -america-inc-civil-no-212-cv-207case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 1 of 325 document 7-1 filed 09/18/12 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 DECREEcase 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 2 of 325 document 7-1 filed 09/18/12 page 2 of 324

TABLE OF CONTENTS

I. JURISDICTION AND VENUE

.......................................................................................... 4

II. APPLICABILITY AND BINDING EFFECT

..................................................................... 5

III. OBJECTIVES

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

.............................................................................................................. ....... 6
V. AFFIRMATIVE RELIEF/E NVIRONMENTAL PROJECTS

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

.............................................................. 12 B. SO 2 Emissions Reductions from FCCUs.

.............................................................. 14 C. Particulate Matter Emissi ons 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. SO 2 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 H 2 S 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 Requ irements into Federally Enforceable Permits

................................................................................................................... 57

VI. EMISSION CREDIT GENERATION

.............................................................................. 58

VII. SUPPLEMENTAL ENVIRONM ENTAL 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 SO 2 Emissions Reductions from FCCUs.

................................. 71

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

C. Requirements for PM Emissi ons Reductions from FCCUs

................................... 72 D. Requirements for CO Emissi ons Reductions from FCCUs

................................... 72 E. Requirements for VOC Emissi ons Reductions from FCCUs

................................ 73 F. Requirements for NOx Emissions Re ductions from Heaters and Boilers

............. 73 G. Requirements for SO 2 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

..................................................................................................................... 7 6 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 C onsent Decree Requirements Into Permits

.. 94 Q. Requirements for Supplementa l 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 JURISD ICTION/DISPUTE RESOLUTION

....................................... 99

XV. EFFECT OF SETTLEMENT

.......................................................................................... 101

XVI. GENERAL PROVISIONS

.............................................................................................. 114

XVII. TERMINATION

.............................................................................................................. 120

XVIII. INTEGRATION

............................................................................................................... 125

XIX. SIGNATORIES

............................................................................................................. .. 125

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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

iiicase 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 5 of 325 document 7-1 filed 09/18/12 page 5 of 324

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 (“Indian a”) has joined in this matter alleging violations of its applicable State Implementation Plan provisi ons and/or other state rules, regulations, and permits inco rporating and implementing th e 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, Susa n Eleuterio and Tom Tsourlis (“CitizenIntervenors”) by their execution of and entry into this Cons ent Decree are hereby seeking to intervene in this action, w ith the consent of the United St ates, 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 St ates, Indiana and BPP are among the parties to a Consent Decree entered by th is Court in Civ. No. 2:96 CV 095 RL on August 29, 2001 (the “2001 Consent Decree”), which has b een 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 No tices of Violation and Findings of Violations to BPP relating to the Whiti ng Refinery’s compliance with various requirements of both the 2001 Consen t Decree and the Clean Air Act; WHEREAS, BPP is presently engaged in a capital improvement project, referred to by BPP as the Whiting Refinery Modern ization 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 ex isting crude slate; WHEREAS on May 1, 2008, the Indiana Department of Environmental Management (“IDEM”) issued a final Signi ficant Source Modification permit authorizing BPP to proceed with the construction need ed 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 Of fice of Environmental Adjudication (“OEA”) challenging both the WRMP Construction Pe rmit 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 Re sources Defense Council, Save the Dunes Council, Inc., Sierra Club, Inc., Susan Eleute rio 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 ne cessary to determine applicable Clean Air Act requirements and to estab lish appropriate emission limits, that the calculation to determine appropriate NSR requirements was do ne incorrectly and th at 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 a ppropriately address the following emissions: emissions from new and existing flaring devi ces resulting from start-up, shut-down and malfunction of refinery process units; emissi ons from vessel depressurization; emissions from increased coking and coke drum depressurization; and emissions of fugitive sulfur compounds. The EPA Order also granted the T itle V Petition on the i ssue that IDEM had not provided a sufficient rationa le 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 requir ed 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 regulat ions and permits issued thereunder and (ii) to substantially reduce emissions of pollutants from the Whiting Refinery; WHEREAS, the design cycle time for th e 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 D ecree beyond the minimum term specified in Appendix E; WHEREAS, in conjunction w ith the negotiation of this Consent Decree, BPP has applied to IDEM for a Significant Source Pe rmit 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 Cons ent Decree incorporates all remaining obligations and requirements of the 2001 C onsent 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 Cons ent 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 C onsent Decree that apply to the Whiting Refinery and otherwise amend the 2001 Cons ent Decree as needed to reflect the termination of the provisions appl icable to the Whiting Refinery; WHEREAS, by entering into this Consent Decree, BPP is committed to proactively resolving environmental con cerns related to its operations; WHEREAS, discussions between the Part ies have resulted in the settlement embodied in this Consent Decree; WHEREAS, BPP has waived any applicab le federal or state requirements of statutory notice of th e alleged violations; WHEREAS, notwithstanding the foregoing re servations, the Parties agree that: (a) settlement of the matters set forth in the Comp laint is in the best interests of the Parties and the public; and (b) entry of the Consen t Decree without litig ation is the most appropriate means of resolving this matter; and WHEREAS, the Parties r ecognize, and the Court by en tering the Consent Decree finds, that the Consent Decree has been negot iated at arms length and in good faith and that the Consent Decree is fair, reas onable, and in the public interest; NOW THEREFORE, with respect to the matte rs set forth in the Complaint, and in Part XV of the Consent Decree (“Effect of Settlement”), and before the taking of any testimony, without adjudi cation 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 act ion pursuant to Sections 113(b) and 167 of

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the CAA, 42 U.S.C. §§ 7413(b) and 7477. Th e United States’ Complaint states a claim upon which relief may be granted for injunctive relief a nd 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 Dist rict 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 th is Court, waives any objections to venue in this District, and does not object to the particip ation of the State of Indiana in this action. 3. Notice of the commencement of this ac tion has been given to the State of Indiana in accordance with Se ction 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, th e 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, employ ees, 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 acco rdance with the notice provision s set forth in Paragraph 210

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(“Notice”), of any successor in interest at le ast 30 days prior to any such transfer. 7. BPP shall condition any transfer, in w hole or in part, of ownership of, operation of, or other inte rest (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 C onsent Decree, which makes the terms and conditions of this Consent Decr ee applicable to the transfer ee. In the event of such transfer, BPP shall notify the United States a nd the State of Indian a in accordance with the notice provisions in Paragra ph 210 (“Notice”). By no earlie r 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 ap plicable to the transf eree. BPP shall be released from the obligations and liabilitie s of this Consent Decree unless the United States or the State of Indiana opposes the mo tion 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 requi red 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 perfo rm 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 there under. 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 pu rposes of clarity, the first day used in a 7-day rolling average complian ce period is the first day on which the emission limit is effective, and the first complete 7-day av erage 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 Ja nuary 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-da y average compliance period is 365 days later ( e.g., for a limit effective on January 1, the firs t 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 mont hs, divided by 12. A new 12-month rolling average shall be calculated for each new co mplete 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 effectiv e, 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 31 st

. 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 60.10 1a 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 pres sure 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 de vice or the opening at the base of the Coke Drum used to discharge coke. The New C oker 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 Ve nt 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 afte r cooling and cutting. N. “Consent Decree” or “Decree” shal l 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 manuf acturer’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 Dist rict of Indiana. Q. “Date of Lodging” shall mean the da te this Consent Decree is lodged with the United States District Court for the Northern District of Indiana. R. “Day” or “Days” shall mean a cale ndar 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, wh ere 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, preventi ve maintenance, unknown causes, etc.), but shall not include downtime associated with routine CEMS zero and span checks and QA/QC activities required by this Consen t Decree. CEMS data that meet the requirements of 40 C.F.R. § 60.13 shall be cons idered valid for purposes of determining downtime. T. “EPA” or “U.S. EPA” shall mean the United States Environmental Protection Agency and any successor departme nts or agencies of the United States. U. “ESP” shall mean electr ostatic precipitator. V. “Federal Financial Assistance Tran saction” shall mean a grant, cooperative agreement, loan, federally-guarant eed loan or other mechanism for providing federal financial assistance. An “open” Fe deral Financial Assistan ce 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 mean ing 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 st reams 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, in cinerators, gas turbines, and any other fuel gas combustion devices. AA. “Fuel Oil” shall mean any liquid fo ssil 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 m ean 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 de sign load without air preheat, even if upon installation actual emissions ex ceed 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 preven table failure of ai r 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 th is Consent Decree identified by a Roman numeral. II. “Parties” shall mean the United Stat es, the State of Indiana, CitizenIntervenors and BPP.

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JJ. “PM” shall mean particulate matte r as measured by EPA Methods 5B or 5F as specified in 40 C.F. R. Part 60, Subpart Ja. “PM 10 ” shall mean all filterable and condensable particulate matter ten microns or less in diameter, as measured by EPA Methods 201A and 202. “PM TOTAL ” 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 poi nt and atmospheric
pressure. LL. “Quench Water” shall mean the water, in liquid phase, used to cool coke after it is form ed 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 a nd (ii) the point at which th e coke bed has been covered with water and the water addition rate drops below 100 gallons per minute. NN. “Quench Water Soak Time” shall m ean the duration of time from the end of the Quench Water Fill Time a nd 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 comm encing 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 a ny 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 consistin g of ammonia injection and a catal yst bed to selectively catalyze the reduction of NOx with am monia to nitrogen and water. TT. “SO 2 ” 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 Federa l 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 m ean all sulfur containi ng compounds, measured in parts per million. ZZ. “Whiting Refinery” shall mean the re finery owned and operated by BPP and located at 2815 In dianapolis 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 eq ual to 0.020 lb/mmBTU HHV when firing natural gas at 3% stack oxygen at full design load without air preheat, even if upon installati on actual emissions exce ed 0.020 lb/mmBTU HHV. BBB. “United States” shall mean the United States of Amer ica, 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 emissi on limits into its operating permits and will demonstrate future compliance with the lowe r 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 sha ll 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 a nd 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 in itial performance test require ment 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% O 2 (365-day rolling average) and a short-term FCCU emission limit of 80 ppmvd NOx @ 0% O 2 (7-day rolling average). ii. FCU 600: BPP shall continue to comply with a long-term FCCU emission limit of 20 ppmvd NOx @ 0% O 2 (365-day rolling average) and a short-term FCCU emission limit of 40 ppmvd NOx @ 0% O 2 (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% O 2 (365-day rolling average) and a short-term FCCU emission limit of 80 ppmvd NOx @ 0% O 2 (7-day rolling average); and ii. FCU 600: BPP shall comply with a long-term FCCU emission limit of 10 ppmvd NOx @ 0% O 2 (365-day rolling average) and a short-term FCCU emission limit of 40 ppmvd NOx @ 0% O 2 (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 polluti on control practices as required by 40 C.F.R. § 60.11(d) to minimize NOx emissi ons. 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 O 2 CEMS to monitor performance of the Whiting Refinery FCCUs and to report co mpliance with the terms and conditions of this Consent Decree. CEMS will be used to demonstrate compliance with the NOx emission limits established pursuant to Pa ragraph 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 provisi ons applicable only to C ontinuous 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 (“RA TA”) is not performed.

B. SO 2 Emissions Reductions from FCCUs Summary : BPP is required to limit SO 2 emissions at the Whiting Refinery FCCUs. BPP is also required to incorporate the lower SO 2 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 sha ll 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 w ith the requirements of 40 C.F.R. Part 60, Subparts A and Ja, for SO 2 applicable to FCCUs, and by no later than September 1, 2013, FCU 600 shall be subject to and comply w ith the requirements of 40 C.F.R. Part 60, Subparts A and Ja, for SO 2 applicable to FCCUs. Entr y of this Consent Decree and

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compliance with the relevant monitoring requ irements 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 SO 2 Emission Limits

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a. Interim Limits . Beginning on the Date of Entry, BPP shall comply with the following SO 2 emission limits at the Whiting Refinery: i. FCU 500: BPP shall continue to comply with a FCCU emissions limit of 25 ppmvd SO 2 @ 0% O 2 (365-day rolling average) and 50 ppmvd SO 2 @ 0% O 2 (7-day rolling average). ii. FCU 600: BPP shall continue to comply with a long-term FCCU emission limit of 50 ppmvd SO 2 @ 0% O 2 (365-day rolling average) and a short-term FC CU emission limit of 125 ppmvd SO 2 @ 0% O 2 (7-day rolling average). b. Final Limits . BPP shall comply with the following SO 2 emission limits at the Whiting Refinery: i. FCU 500: By no later than December 31, 2012, BPP shall comply with a FCCU emi ssions limit of 10 ppmvd SO 2 @ 0% O 2 (365­ day rolling average) and 50 ppmvd SO 2 @ 0% O 2 (7-day rolling average). ii. FCU 600: By no later than September 1, 2013, BPP shall comply with a FCCU emi ssions limit of 10 ppmvd SO 2 @ 0% O 2 (365­ day rolling average) and 50 ppmvd SO 2 @ 0% O 2 (7-day rolling average).

c. SO 2 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 polluti on control practices as required by 40 C.F.R. § 60.11(d) to minimize SO 2 emissions. SO 2 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 SO 2 Emission Limits . By no later than Date of Entry, BPP shall use an SO 2 and O 2 CEMS to monitor the performance of the Whiting Refinery FCCUs and to repor t compliance with the terms and conditions

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of this Consent Decree. CEMS will be us ed to demonstrate compliance with the SO 2 emission limits established pursuant to Pa ragraph 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 provisi ons applicable only to C ontinuous Opacity Monitoring Systems) and Part 60 Appendices A and F, a nd 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 Emi ssions Reductions from FCCUs Summary : BPP is required to control and limit emissions of PM, PM 10 and PM TOTAL 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 sha ll 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 a nd 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 in itial performance test require ment of 40 C.F.R. § 60.8(a).

a. By no later than 180 Days after th e 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 te sts that the PM limit in 40 C.F.R. § 60.102a(b)(1) is not being exceeded, B PP may reduce the required testing frequency to an annual basis. BPP sha ll provide notice to EPA no later than 30 Days in advance of the performance te sting 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 th e PM limits during testing. BPP shall

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provide EPA with notice no later than 30 Da ys 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 PM 10 and PM TOTAL . By no later than December 31, 2013, BPP shall comply with the following PM 10 and PM TOTAL emission limits at the Whiting Refinery:

a. FCU 500 : i. BPP shall comply with an emissions limit of 0.9 pound of PM 10 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 PM TOTAL 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 PM 10 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 PM TOTAL 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 Decr ee and NSPS Subparts A and Ja applicable to FCCUs, by no later than the Date of En try, 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 SO 2 -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 PM 10 and PM TOTAL Emission Limits

.

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a. Compliance with the PM 10 and PM TOTAL 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 PM 10 and PM TOTAL emission limits in Paragraph 18.

c. For the purposes of this Paragr aph, BPP may use Method 201A in lieu of Method 5 to determine PM TOTAL emissions, provided that BPP follows the procedures in Method 201A for the collec tion and analysis of PM greater than 10 microns. 21. FCCU Performance Testing

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a. Testing Protocols for PM 10 and PM TOTAL Emissions : By no later than 180 Days after the Date of Entry, B PP shall implement a performance testing protocol as provided in this Paragraph: i. Testing Frequency : BPP shall conduct performance tests to measure emissions of PM 10 and PM TOTAL from FCU 500 and FCU 600 on at least a semi-annual basis, with ea ch 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 test s 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 PM 10 and PM TOTAL limits are not being exceeded, (ii) the average of all four valid se mi-annual tests is not more than 80% of the PM 10 and PM TOTAL limits, and (iii) the average result from any valid semi-annual test is not greater than 90% of the PM 10 and PM TOTAL 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 ot her 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 PM 10 or PM TOTAL limit, EPA may elect to reinstate the re quirement for semi-annual testing. EPA’s decision to reinstate semi-ann ual testing shall not be subject to Dispute Resolution. ii. Test Methods for PM 10 and PM TOTAL Emissions : BPP shall measure PM 10 emissions using Methods 201A and 202. BPP may use Method 5 in lieu of Method 201A for purposes of demonstrating compliance with the PM 10 emission limit provided that BPP considers all PM measured by Method 5 as PM 10 . BPP shall measure PM TOTAL emissions using Methods 5 and 202. BPP may use Method 201A in lieu of Method 5 for purposes of demonstrating compliance with the PM TOTAL 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 provi de all information necessary to document why the test run was not valid. iv. Valid Performance Tests : A PM 10 and PM TOTAL 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 PM 10 and PM TOTAL emission limits must not be less than the ac tual average coke burn rate over the time period since the previous performance test;

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(2) The average SO 2 concentration for all runs used in determining compliance with the PM 10 and PM TOTAL emission limits must not be greater than 10 ppmvd @ 0% O 2 ; and (3) The average total ammonia injection rate for all runs used in determining compliance with the PM 10 and PM TOTAL emission limits must not be le ss than average total ammonia injection rate over the time peri od 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 PM 10 and PM TOTAL emission limits must not be greater than 120% of the average ESP total primary power since the last stack test.

v. Additional Parametric M onitoring During the Tests : BPP shall monitor or calculate and record SO 2 concentration, NOx concentration, catalyst additive rates, ammonia addition prior to ESP, ammonia addition at the SCR, ammo nia slip, the coke burn-off rate, regenerator overhead temperatures, and F CCU 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 pr oduce a report with recommenda tions on how to optimize the performance of each ESP to enable each FCU to meet the PM, PM 10 and PM TOTAL 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 ta ken 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 sha ll 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 a nd 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 in itial performance test require ment 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% O 2 . 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% O 2 . 26. CO emissions during periods of Startup, Shutdown, or Malfunction shall not be used in determining complianc e with the 1-hour 500 ppmvd emissions limit, provided that during such peri ods BPP implements good air po llution 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 monito r the performance of each FCCU and to report compliance with the terms and conditions of this Consent Decree. CEMS will be used to demonstr ate 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 CE MS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60, Appendices A and F, and the applicable performance sp ecification 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

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a. BPP shall calculate VOC emissions using the following equations:
⎛ C × Q × MW × 60 ⎞ ⎛ 1000 ⎞ E = ⎜ ⎜ ⎟ ⎟ × ⎜ ⎟ ⎝ V m ⎠ ⎝ F ⎠

C = C

− C

− C total methane ethane
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 C total = fraction, as carbon, as m easured by EPA Method 25a Concentration of methane in volume fraction, as C methane = carbon, as measured by EPA Method 18 Concentration of ethane in volume fraction, as C ethane = 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 pu t emissions on a per 1000 1000 = bbl feed 385.3 dscf of gas per lb-mol at standard conditions V m = (68° F) FCCU feed rate in bbl/h our, averaged over period F = of source test 60 = conversion factor for 60 minutes per hour

b. BPP shall conduct the first stack te st at each FCCU no later than December 31, 2013, and shall thereafter c onduct 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 el ect to conduct stack tests at least once every three (3) years at that F CCU in lieu of annual stack testing. ii. If, after BPP exercises the opti on 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 annua l stack testing for that FCCU. F. NOx Emissions Reduction s from Heaters and Boilers Summary : BPP is required to undertake measures to reduce emissions of NOx from the Heaters and Boilers at the Whiting Refi nery, as provided in this Section.

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

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a. By no later than the Date of Lodging, BPP shall conduct NOx emission tests on heaters F-2 and F-3 in th e 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 ei ther EPA Method 19, or EPA Methods 1, 2, 3, and 4, or an EPA-approve d alternative test method. b. BPP shall install Ultra-Low NOx Bu rners 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 da tes 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

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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 comp ly with the applicable requirements of NSPS Subparts A and Ja for NOx em issions from process heaters.

c. Entry of this Consent Decree a nd compliance with the relevant monitoring requirements of Subpart Ja sh all satisfy the notice requirements of 40 C.F.R. § 60.7(a) and the initial perfor mance test requirement of 40 C.F.R. § 60.8(a) for each heater lis ted in this Paragraph. 34. Additional Requirements For New and Modified Heaters

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a. BPP shall comply with the em ission 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 Pa ragraph 34.a are t hose as of the Date of Lodging and are included solely for purposes of identification of the relevant control technology and emissi on 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 Capac ity 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 cap acity 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 performan ce 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 D ecember 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 requi red by Paragraph 83.a, BPP shall apply to remove the authority that is cu rrently contained in the existing permit to replace the existing burners in the ISOM Heater H-1 with larger burners. 36. CEMS Monitoring Requirements

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a. Performance Specifications . Beginning no later than one hundred and eighty (180) days after installing the applicable control te chnology on a heater or boiler that shall be monitored by us e of a NOx CEMS required by Paragraph 34, BPP shall install, cer tify, calibrate, maintain, a nd 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 RA TA on each CEMS at least once every three (3) years in lieu of the require ments of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3 and 5.1.4. BPP shall conduct a Cy linder 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 sh all be calculated using the following equation:

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

Where: E tpy = 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, stat e, 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 regulator y, 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 Decr ee until its termination pursuant to Part XVII (Termination). BPP shall make su ch records and all CEMS data and test results available to EPA and IDEM upon request.

G. SO 2 Emissions Reductions from Heaters and Boilers Summary : BPP is required by this Section to undertake measures to reduce SO 2 emissions from refinery heater s and boilers by restricting H 2 S in refinery fuel gas and not burning Fuel Oil, except as specifically pe rmitted under the provisions set forth in this Section.

39. NSPS Applicability to Heaters and Boilers

.
a. Subpart Ja Applicability to Ce rtain Existing Heaters and Boilers

. Upon the Date of Entry, each of the follo wing heaters and boilers shall be an “affected facility” for SO 2 as that term is used in 40 C.F.R. Part 60, Subparts A and Ja, and shall be subject to and comp ly with the applicable requirements of NSPS Subparts A and Ja for SO 2 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 star t-up, each of the following h eaters and boilers shall be

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an “affected facility” for SO 2 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 SO 2 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 a nd compliance with the relevant monitoring requirements of Subpart Ja sh all satisfy the notice requirements of 40 C.F.R. § 60.7(a) and the initial perfor mance test requirement of 40 C.F.R. § 60.8(a) for the heaters listed in Paragraph 39.a. 40. Elimination of Fuel Oil Burning

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a. Existing Heaters and Boilers . Effective on the Date of Entry, BPP shall not burn Fuel Oil in a ny heater or boiler at the Wh iting 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 heat er or boiler that burns Fuel Oil unless the air pollution control equipment contro lling the combustion device either: i. has an SO 2 control efficiency of 90% or greater; or ii. achieves an SO 2 concentration of 20 ppm or less at 0% O 2 or less on a 3-hour ro lling 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 H 2 S on a 12-month rolling average basis.

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42. Demonstrating Compliance with Total Sulfur Emission Limits

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a. By no later than December 31, 2013, BPP shall install three Total Sulfur Continuous Analyzers on the refine ry fuel gas systems to continuously monitor, measure and record the total sulf ur concentration in refinery fuel gas, and to report compliance with the terms and conditions of this Consent Decree. The Total Sulfur Continuous Analyzers wi ll 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 to tal sulfur concentra tion in the refinery fuel gas being burned in all heaters and boile rs 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 th e 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 an alyzers are placed into service and certified.

c. The Total Sulfur Continuous Analyz ers 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, excep t 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 Con tinuous Analyzer at least once every three (3) years. BPP must also condu ct 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 anal yzer 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 trai ning for all individuals (BPP employees and contractors) involved in CEMS operations and maintena nce to maintain necessary levels of monitoring competency. All newly-hired i ndividuals (BPP employees and contractors) involved in CEMS operations and maintenance shall be trained prio r to undertaking any CEMS-related responsibili ties. The CEMS O&M Plan sha ll 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 accord ance with the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excludi ng 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, A ppendix 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 procedur es may be based initially on the CEMS vendor’s recommendations. Routine prev entative 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 em ission monitoring data, including regular ( e.g., daily, weekly monthly) routine in ternal (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 main tenance and repair and non-routine maintenance and repair. BPP shall maintain a spare parts inventory adequate to meet the normal operating and CEMS preventative maintena nce 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 respons ibility for maintaining th e adequacy of the spare parts inventory. The on-site spare part s inventory may be based on the vendor's recommendations and shall be modified on an as-needed basis. 47. EPA Review and Comment on CE MS 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 comment s 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 su bmission, BPP shall implement the CEMS O&M Plan in acco rdance 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 devel op a corrective action plan to promptly address the findings of th e CEMS Root Cause Failure Analysis. The CEMS Root Cause Failure Analysis shall incl ude the following elements, at a minimum:

a. An identification and detailed an alysis 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 re asonably available to prevent the root cause(s) of the CEMS downtime from recurring. This analysis shall include an evaluation of possible design, operationa l, and maintenance measures. For any CEMS for which a Root Cause Failure An alysis 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 Failu re 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 requ ired by Part VIII of the Consent Decree following completion of the Root Cause Failure Analysis. 49. Corrective Action . The corrective action pl an shall require BPP to undertake as expeditiously as reasonably possible such reasonably available corrective actions as are necessary to correct the cau se of the CEMS monitor downtime and to prevent a recurrence of the root cause(s) id entified in the CEMS Root Cause Failure Analysis. The corrective action plan shall in clude a description of any corrective actions already completed or, if not complete, a sc hedule 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 find ings; and/or (2) any objections to the schedules of implementation of the corre ctive 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 schedul e 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 part y 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 En try of the Consent Decree. Nothing in

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this Section shall relieve BPP of its i ndependent obligation to comply with the requirements of the Benzene Waste Operations NESHAP.

50. Facility Compliance Status

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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 complia nce 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) m eet 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 abilit y of BPP to treat and manage Aqueous Benzene Wastes in accordance with the re quirements 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 therea fter on or before each April 1st, BPP shall submit its annual TAB report fo r 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 Re finery’s benzene wast e stream inventory, TAB calculation, all waste management units, an d entire wastewater treatment system in

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order to assess compliance with all app licable Benzene Waste Operation NESHAP requirements. BPP further certifies that, as reported in the January 25, 2010 report, it has completed implementation of all corrective ac tions necessary to re medy 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 curren tly installed and used as the co ntrol device for complying with the Benzene Waste Operations NESHAP, B PP 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 En try of the Consent Decree, BPP shall install primary and secondary carbon can isters and operate them in series (the “dual-canister” option). BPP ma y 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 fo r breakthrough monitoring between the primary and secondary beds in accordan ce with this sub-paragraph. ii. Breakthrough monitoring . BPP shall conduct breakthrough monitoring between the primary and s econdary 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-paragr aph 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 late r 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 al l canisters or beds which BPP has designated as unsafe to monito r 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 imme diately replace the primary carbon canister or bed when the design value for the primary canister or bed is exceeded (as monitored between th e primary and secondary carbon canister or carbon bed). Unless bot h the primary and secondary carbon canisters or beds are replaced with fresh ones, the original secondary carbon canister or bed shall become th e 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 havesufficient capacity to meet the breakthrough definition of this subparagraph. For purposes of this sub- paragraph 52.a, “immediately” means no later than within tw enty-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 wher e carbon canisters will be installed and used as the control device for complying with the Benzene Waste Operations NESHAP, BPP shall comp ly 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 desc ribed in this sub-paragraph at the following locations: (1) If BPP demonstrates that it is technologically infeasible or unsafe to comply with the dual-canis ter option under sub-paragraph 52.a, BPP may use a single carbon canister at that specific location. BPP shall subm it 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 technol ogically infeasible or unsafe to comply with the dual-canister option and shall provide a detailed explanation of the specific technica l and/or safety reasons for the request. This request shall be subject to EPA approval. (2) BPP may use a single car bon 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 ca rbon 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 m onths 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 singl e carbon canisters at the DAF and API Separator. ii. Breakthrough monitoring . By no later than the Date of Entry, BPP shall conduct breakthrou gh monitoring for each single carbon canister at the Whiting Refinery when ther e 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 basi s the applicable breakthrough definition specified in sub-paragraph 52.b.iii, but in no case less frequently than on a monthly ba sis. If a carbon canister or bed becomes unsafe to monitor because it is located within a temporary exclusion zone, BPP shall monitor th e 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 re port a list of all canisters or beds

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which BPP has designated as unsaf e to monitor during the reporting period. iii. Breakthrough definition . Single carbon canisters will be replaced immediately when breakth rough is detected as follows: (1) For canisters less than or equal to 55-gallon drum size, breakthrough is any readi ng 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 hist orical replacement interval is greater than two weeks.
(3) For purposes of this sub-paragraph 52.b, the term “immediately” shall mean: with in eight (8) hours for single canisters with representative hist orical replacement intervals of two weeks or less; or within tw enty-four (24) hours for single canisters with a representative hist orical replacement interval of more than two weeks. iv. Canister Replacement . Single carbon canisters may be replaced with a dual carbon caniste r 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 re quirements for dual-carbon canisters

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or dual-carbon beds provided in su b-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 technol ogy meets all applicable control and/or treatment requirements under the Benzen e Waste Operations NESHAP and the compliance monitoring point is unaffect ed by the use of such other control devices. If BPP elects to use anot her 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 t echnology 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 ensu re that all new benzene waste streams are included in the Whiting Refinery’s waste stream inventory a nd 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 de termine compliance with the Benzene Waste Operations NESHAP at the Wh iting Refinery. These audits shall review procedures and methods in order to ensure that proper an alytical and quality a ssurance practices are followed. BPP shall conduct such audits at each laboratory at least every two (2) calendar years from the date of the last au dit conducted by the Wh iting 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 Refi nery 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 gene rated through such spills that are not managed solely in controlled wa ste management units shall count toward the 6 Mg compliance limit. 56. Training . BPP shall:

a. Develop and implement annual trai ning for all employees at the Whiting Refinery with responsibility to sample benzene waste streams; b. Establish standard operating pro cedures 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 cont ractors hired to perform any requirement of this Section J of the Consent Decree have a proper training program to implement the provi sions 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 w ith the provisions of 40 C.F.R. Part 61, Subpart FF. 58. Sampling (6 Mg/yr) . BPP shall conduct qua rterly “end-of-line” (“EOL”) benzene determinations as follows:

a. If no changes will be made to th e 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 benz ene determinations for the Whiting Refinery, within 30 Days af ter 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 Sa mpling Plan shall be subject to EPA approval. BPP shall comply with a nd 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 whet her 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 co mpliance 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 esti mating the Whiting Refinery’s annual or quarterly EOL benzene quantity, then by no la ter 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 Refine ry 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 identifi ed 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 NE SHAP at the Whiting Refinery on all inspection schedules pertaining to Benzene Waste Operation NESHAP compliance, and shall conduct inspecti ons of each such drain system in accordance with such schedules set fort h in 40 C.F.R. Part 61, Subpart FF;

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d. BPP shall monitor the flow indi cators on all conservation vents on process sewers for detectable leaks on a weekly basis;

e. BPP shall conduct quarterly monitori ng 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 sta ndards 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 c onstruction and installation of a new Dissolved Air Flotation (DAF) unit at th e Whiting Refinery. By no later than December 31, 2015, BPP shall complete c onstruction and installation of new covers for the API Separator at the Whiti ng 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 car bon 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 fi rst TAB Report submitted for the refinery after October 29, 2012, a nd 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 qu antity under the 6 Mg Option. 62. Semi - Annual Benzene Waste NESHAP Report . By no later than February 15 and August 15 of each calendar y ear 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 Benzen e Waste NESHAP Report”). Each SemiAnnual Benzene Waste NESHAP Report shall include the following information for the two most recently completed Calendar Qu arters (the “repor ting 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 uncontrolle d benzene quantity (for any Calendar Quarter during th e reporting period) at the Whiting Refinery exceeds 1.5 Mg or the annual uncontr olled benzene quantity exceeds 6 Mg, then BPP shall, as specified below, conduct a Root Cause Failure Analysis and develop a corrective ac tion plan (including a schedule for completing the corrective actions) to pr omptly 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 sha ll be submitted to EPA in a written report within 30 Days following comp letion 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 th is 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 discre te 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 se tting 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 th e root cause(s) for the exceedance from recurring. This analysis shall include an ev aluation 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-paragra ph shall require BPP to undertake as expeditiously as possible any such interim and/or long-term corrective actions as are necessa ry and consistent with good air pollution control practices to pr event 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 collect ed at the Whiting Refinery pursuant to this Section J, and BPP shall provid e 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 Cons ent Decree, BPP shall submit a project completion report to EPA de tailing the actions performed to comply with the requirements of Para graph 52. BPP shall include a list of all locations within th e 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 si ngle carbon canisters are used, BPP shall identify each such location and provide the results of all breakthrough monitoring and carbon canister change-out s 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 carbon canister change-out o ccurred. BPP shall also include in each semi

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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 la bs 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 method s 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 pursuan t to the requirements of Paragraph 56, and shall describe the training these employees r eceived. BPP shall also describe the training scheduled to be performed during the next re porting period.

e. BPP shall certify each Semi-A nnual Benzene Waste NESHAP Report required in accordance with th e certification statement required under Paragraph 102 of the Consent Decree.

K. Leak Detection and Repair 63. NSPS Applicability . Upon the Date of Entr y, 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 late r than one year from the Date of Entry, except as specifically provide d 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 constructi on commenced prior to January 4, 1983, shall not be subject to the requi rements 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 Dilu ent, Oil Movements North, South Tank Field and Stieglitz Pa rk Tank Field. Nothing in this Paragraph or in Appendix B to this Consent Decree shall relieve BPP of its independent obligation to comply with th e requirements any other federal, state or local LDAR regulation that may be applicab le to Equipment at the Whiting Refinery. 64. Enhanced Leak Detection and Repair . BPP shall implement and comply with the requirements of the Enha nced Leak Detection and Repair Program (“ELP”) set forth in Appendix B to this C onsent Decree by the dates specified therein. The requirements of Appendix B are in additi on to the applicable requirements under 40 C.F.R. Part 60, Subpart GGGa; Part 61, Subpa rts J and V; and Part 63, Subparts H and CC. The terms “in light liquid service” a nd “in gas/vapor service” shall have the definitions set forth in the applicable provi sions 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 Subp art Ja applicability for its Sulfur Recovery Plant (“SRP”), and to route all emissions from its sulfur p its and sealed sulfur collection drums such that all emissions ar e 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 un it) serving as control devices. As a part of WRMP, two new Claus sulfur recovery uni ts 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 facili ty” as that term is used in 40 C.F.R. Part 60, Subparts A and Ja, for all pollutants applicab le to SRPs, and shall be subject to and comply with all applicable re quirements 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 star tup, whichever comes first. b. The Beavon Stretford and SBS units at the Whiting Refinery SRP shall be shut down and permanently rem oved 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 (COT 1 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 late r than the initial startup of the New Coker. Until the Beavon Stretford unit is shut dow n, 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 acco rdance 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 re quired to achieve compliance under Paragraph 65.a of this Section, the Whiting Refinery SRP shall comply with the following requirements:

a. An SO 2 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 to tal 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 × 10 6 ⎝ m ⎠

E = TGTU SO 2 Emissions in tons per month F = Measured total TGTU incinera tor stack flow rate, dscf at standard conditions (6 0o F), for the month

C = Average concentration of SO 2 in TGTU incinerator exhaust for the month, in ppmvd MW = Molecular weight of SO 2 = 64.06 Vm = 379.4 dscf of gas per lb-mol at standard conditions (60o F) 2000 = conversion factor for 2000 pound per ton 10 6 = 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, B PP shall, to the extent practicable, operate and maintain the SRP, including its TGU, its sulfur pits and sealed sulfur collection drums, any supplemental cont rol 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 afte r 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, sulf ur 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 coll ection 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 lim ited 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 unde r representative conditions to measure the sulfuric acid mist (“SAM”) emission rate. 69. Sulfur Pit and/or Sulfur Co llection 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 ma intain 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 emissi ons from Pits A, B, C and 2400 in the event that pit sweep em issions 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, ma intain and operate the newly redesigned

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degas system to minimi ze the entrainment of H 2 S vapor in the sulfur routed to Pit 2400 in a manner consistent with go od 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 af ter 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 P it 2400 with storage tanks, BPP shall route all sulfur emissions from the s ealed sulfur collection drums and the molten sulfur storage tanks such th at they are treated, monitored, and included as part of the SRP’s emissi ons subject to the NSPS Subpart Ja limit for SO 2 , 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 basi s 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 subpa ragraph 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 floati ng 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 e quipped 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 H 2 S concentration on the outlet of the iron sponge system and da ily 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 H 2 S emissions back to the sulfur recovery plant at all times except during periods when th e 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 no t 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 th e 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 emissi ons 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 leve l 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 sha ll be vented to an iron sponge control system except during periods when the iron sponge is offline for maintenance. b. Emissions of H 2 S from the TK-6254 shall not exceed 2.84 tons per rolling 12-month period. Emissions du ring periods when the iron sponge is offline for maintenance shall be included in determining compliance with this emission limit.

c. BPP shall monitor and reco rd the daily average H 2 S concentration at the outlet of the iron s ponge system and shall determine the daily average vapor flow based on the nitrogen pur ge rate to TK-6254. The H 2 S concentration and nitrogen purge flow will be used to calculate the H 2 S emissions rate. Process analyzers calibrated in accordance w ith 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 monthl y basis, BPP shall (a) monitor the VOC concentration at the outlet of the ir on sponge system in accordance with the methods used to comply with the requ irements for breakth rough 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 th e 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 treatmen t 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 underl ying Federal, State or local re gulations applicable to the tank(s). BPP will report the results of th ese 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 H 2 S Emission Reductions from the Whiting Refinery New Coker Summary : BPP will limit VOC, PM, TRS and H 2 S emissions by depressuring the Coke Drum to no more than 2.0 psig prior to ve nting, 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 leve l 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, PM TOTAL , PM 10 , TRS, and H 2 S Emissions from the Whiting New Coker . Upon initial startup of the Ne w 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 comp ly 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 th e water reaches the high leve l 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 H 2 S 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 w ithin 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 syst em that has no emissions points to the atmosphere. 80. Quench Water Operating Practices

.
a. Commencing upon the initial startu p 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 cont act 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 pp m and a total sulfide concentration of less than 35 ppm; or

v. Some combination of water from i-iv. b. Commencing upon the initial startu p 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 Fla res 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, constructi on, or operating permits, BPP shall submit timely and complete applications and take all other acti ons 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) sha ll 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 applica tion(s) shall also seek to incorporate all emissions limits and standards required by the fo llowing requirements of this Consent Decree that will survive terminati on 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 SO 2 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 ( SO 2 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 inco rporation of emission limits and standards into the Title V operating perm it 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 obtai n, or a delay in obtaining, any permit or approval required to fulfill such oblig ation, if BPP has submitted timely and complete applications and has taken all ot her actions necessary to obtain all such permits or approvals.

VI. EMISSION CREDIT GENERATION Summary : This Part addresses the use of certa in 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, SO 2 , H 2 S, TRS, reduced sulfur compounds, PM, PM 2.5 , PM 10 , PM TOTAL , VOC, or CO emissions reductions (“CD Emission Reduc tions”), or apply for and obtain any emission reduction credits, that result fr om 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 Reduc tions under 2001 Consent Decree

. BPP shall not generate or use any NO x 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 C onsent Decree as netting reductions or emissions offsets in any PSD, major nona ttainment, 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 PM 10, 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 constr ucted, 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 T itle V construction and operating permit

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program) that reflects the following requi rements 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 H 2 S per dry standard cubic foot of fuel gas or 20 ppmvd SO 2 corrected to 0% O 2 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% O 2 on a 365-day rolling average basis;

e. For FCCUs, a limit of 25 ppmvd SO 2 corrected to 0% O 2 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 SO 2 at 0% O 2 on a 24-hour rolling average basis.

86. Conditions Precedent to Utilizing Ex ception to General Prohibition

. Utilization of the exception set forth in Para graph 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 tim e that actual CD Emissions Reductions have occurred; b. CD Emissions Reductions may be used only at the Whiting Refinery;

c. The CD Emissions Reductions pr ovisions of this Consent Decree are for purposes of this Consent Decree on ly 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 credit s 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 thes e 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 limita tion pursuant to this Consent Decree; or

c. Utilize emissions reductions pursuant to this Consent Decree for the Whiting Refinery’s compliance with a ny rules or regulations designed to address regional haze or the non-attainment status of any area (excluding PSD and Non-Attainment New Source Review Rule s, but including, for example, RACT rules) that apply to the Whiting Refi nery. Notwithstanding the preceding sentence, BPP will not trade or sell any emissions reductions that result from any projects conducted or cont rols utilized pursuant to this Consent Decree.

VII. SUPPLEMENTAL ENVIRONM ENTAL 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 fence line 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 C onsent Decree. BPP sha ll 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 th an 18 months after the Date of Entry. 89. BPP is responsible for the satisf actory completion of the Fenceline Monitoring SEP as provided in this Consen t 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 e qual to the difference between the amount expended as demonstrated in the certified cost report and the amount specified in Paragraph 88. The stipulated penalty sh all 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 unexpende d 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 provide d to EPA in connection with the Fenceline Monitoring SEP is complete and accurate; b. that, as of the date of executi ng 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 us ed to fund the same activity as the SEP described in Appendix E; and
g. that based upon a r easonable inquiry:

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i. the activity covered by this SE P 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 wa s barred from funding as statutorily ineligible); and ii. BPP is not aware of any open Federal Financial Assistance Transaction that is funding or coul d 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 descri ption of its progress toward implementing the SEP required by this Section. In addi tion, the report required by Paragraph 98.c. for the period in which the SEP is completed sh all 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 en countered 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 environmen tal 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 Pa ragraph, 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 unde r 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 undertak en 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, B PP 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 Greenhous e 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 la ter than three (3) months after the Date of Entry of the C onsent Decree, BPP shall provide Citizen-Intervenors a report on the results of that st udy. 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, in cluding all associated heaters, boilers, and flares; and iv. A complete list of the po tential GHG reduction projects identified by the KBC Whiting En ergy 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 theDate of Entry of the Consent Decree, BPP shall submit a report to CitizenIntervenors identifying each of the GHG pr ojects 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 effo rts 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 otherwis e required by this Consent Decree, state, or federal regulation sha ll constitute a qualifying energy efficiency or GHG improvement for the purposes of this Paragraph.

e. Timeline . By no later than five (5) y ears 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 subpar agraph b of this Paragraph; and ii. Provide Citizen-Intervenors w ith 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 re ports or other submissions required by Paragraph 95 to EPA.

VIII. REPORTING AND RECORDKEEPING 97. BPP shall retain all r ecords required to be maintained in accordance with this Consent Decree for a period of five (5) years or until Te rmination, 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 provide d in this Part. Each semi-annual report shall contain the following informati on 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 repo rt, a summary of the emissions data for the Whiting Refinery that is specifically required by the reporting requirements of the Consent Decree for th e period covered by the report; b. A description of any problems that have occurred or are anticipated with respect to meeting the requirement s 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 Downti me; 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 A ugust 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. SO 2 , CO and PM emissions in tons pe r year as a sum for all heaters and boilers; d. SO 2 emissions from the Sulfur Recovery Plant in tons per year;

e. SO 2 emissions from all Acid Gas Flaring and Tail Gas Incidents by flare in tons per year; f. NOx, SO 2 , PM and CO emissions in tons per year as a sum for all other emissions units for which emissions information is requir ed to be included in the facilities’ annual emissions summa ries and that are not identified above; and
g. NOx, SO 2 , CO and PM emissions in tons per year for each FCCU; and h. Emissions from Covered Flares a nd 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 em issions 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 re ports and attached to the repo rt 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 th e 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 dow ntime (including maintenance or malfunction), and, if it was a malf unction, an explanation and any corrective action taken.

v. If a report filed pursuant to another applicable legal requirement contains all of the in formation required by Paragraph 100.a.iiv above in similar or the same fo rmat, 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 emissi ons limit required by this Consent Decree from an operating unit mon itored 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 R ecordkeeping Requirements

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a. BPP shall include in each semi-annua l report required by this Part VIII the results of all testing of FC U 500 and FCU 600 required by Paragraph 21 (“FCCU Performance Testing”). The perf ormance test reports shall include all relevant testing data and information, in cluding, but not limited to the following: PM, PM 10 , PM TOTAL , SO 2 concentration, NOx concen tration, 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 te mperature, 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 emi ssions 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, Subpa rt 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 th is 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 penalt y to the United States and the sum of $800,000 as a civil penalty to the State of I ndiana 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 Fi nancial Litigation Unit of the U.S. Attorney’s Office for the Northern Distri ct 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 th e 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 acco rdance 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 th e 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 Pena lties”), 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 deduc tible for purposes of federal or state law. 105. Upon the Date of Entry, this Cons ent Decree will constitute an enforceable judgment for purposes of post-judg ment 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 th is Consent Decree. In no event shall any stipulated pena lty assessed exceed $37,500 per day for any individual violation of this C onsent Decree. Stipulated penalti es shall be calculated in the amounts specified in this Part X. For thos e 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 exceed s the applicable limit. 108. For failure to install, certify, calib rate, maintain, and/or operate a NOx CEMS as required by Paragra ph 13, per unit, per day: Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h day after deadline $2000 or an amount equal to 1.2 times the economic benefit of delayed compliance, whichever is greater

B. Requirements for SO 2 Emissions Reductions from FCCUs. 109. For each failure to meet any SO 2 emission limit set forth in Paragraph 15, per unit, per day: $3000 for each calenda r 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 SO 2 CEMS as required by Paragr aph 16, per unit, per day: Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 Matt er 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 1 s t through 30 t h day after deadline $200 31 s t through 60 t h day after deadline $500 Beyond 60 t h 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 fo r each calendar day on which the specified 1

­ hour rolling average exceed s the applicable limit. 115. For failure to install, certify, calib rate, maintain, and/or operate a CO CEMS as required by Paragr aph 27, per unit, per day:

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Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 te sting, as required by Paragraph 30, per day, per test, per FCCU:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $200 31 s t through 60 t h day after deadline $500 Beyond 60 t h 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 1 s t through 30 t h day after deadline $1500 31 s t through 60 t h day after deadline $2000 Beyond 60 t h day after deadline $3000

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119. For failure to install, certify, calib rate, 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 1 s t through 30 t h day after deadline 31 s t through 60 t h day after deadline Beyond 60 t h 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 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 1 s t through 30 t h day after deadline 31 s t through 60 t h day after deadline Beyond 60 t h 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 SO 2 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 h eater or boiler as speci fied in Paragraph 39, per unit, per day:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 incons istent with the requirements of Paragraph 40, per unit, per day:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $1750 Beyond 30 t h 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 require d by Paragraph 41, per unit, per day:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 s ubmit the CEMS O&M Plan required by Paragraph 43, and for failure to include CE MS Testing and Calibration requirements in the CEMS O&M Plan as required by Paragraph 45: Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $200 31 s t through 60 t h day after deadline $500 Beyond 60 t h day after deadline $1000

127. For failure to develop or implemen t 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 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1500 Beyond 60 t h 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 act ions necessary to correct noncompliance as required by Paragraph 49:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $1250 31 s t through 60 t h day after deadline $3000 Beyond 60 t h 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 opera te carbon canisters as required by Paragraph 52: $1,000 per da y, per carbon canister. 134. For failure to establish an annua l review program to identify new benzene waste streams as require d by Paragraph 53: $2,500 per month. 135. For failure to perform laboratory au dits 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 a ny 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 segregat ed storm water drains as required in Paragraph 60.b: $1,000 per week, per drain. 140. For failure to monitor conservati on vents as required by Paragraph 60.d: $500 per vent not monitored. 141. If it is determined through federal, st ate, or local investigation that BPP has failed to include all benzene waste str eams 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 construc tion of a new DAF unit by the date specified in Paragraph 60.g, or to route em issions from the DAF unit and API Separator as required by Paragraph 60.g:

Period of Delay or Non-Compliance Penalty per Day 1 s t through 30 t h day after deadline $1250 31 s t through 60 t h day after deadline $3000 Beyond 60 t h 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 require ment 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 Detecti on and Repair Program Enhancements 144. The following stipulated penalties sh all 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 Consen t Decree (“Leak Detect ion 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 1 s t through 15 t h day after deadline $300 16 t h through 30 t h day after deadline $400 Beyond 30 t h 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 indicat ed 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 electroni cally record the Screening Value, date, time, identifica tion number of the monitoring equipment, or the identification of the technicia n, 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 Pa ragraph 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 pena lties of Paragraph 144.h do not apply): $150 per day for each day after deadlin e, 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 subpa ragraph, the term “rep air” includes the required repair verification monitoring in Paragraph 13 after the first repair attempt (in which case the stipulated pe nalties 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 Repa ir Verification Monitoring, as required by Paragraph 13, where the first a ttempt 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 1 s t

through 15 t h day after deadline $200 16 t h through 30 t h day after deadline $350 Beyond 30 t h 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 C overed 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 un it 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 P acking, as required by Paragraph 19: $1000 per valve required by Paragraph 19.c a nd $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 C overed Equipment from the LDAR program, as required by Paragraph 23: $150 per piece of Covered Equipment.
q. Failure to timely develop a tr aining 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 pers on, 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 re quirements of Paragraph 26: $1000 per missed requirement, per year.

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u. Failure to conduct an LDAR aud it in accordance with the schedule set forth in Paragraph 28: Period of Delay or Non-Compliance Penalty per Day 1 s t through 15 t h day after deadline $300 16 t h through 30 t h day after deadline $400 Beyond 30 t h 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 require ments in Paragraph 29 except for Paragraphs 29.a-c: $10,000 per missed re quirement, 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 1 s t through 15 t h day after deadline $100 16 t h through 30 t h day after deadline $250 Beyond 30 t h day after deadline $500, not to exceed $100,000 per audit

z. Failure to implement corrective act ion 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 1 s t through 15 t h day after deadline $500 16 t h through 30 t h day after deadline $750 Beyond 30 t h 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 1 s t through 15 t h day after deadline $100 16 t h through 30 t h day after deadline $250 Beyond 30 t h day after deadline $500, not to exceed $100,000 per audit

bb. Failure to secure and retain doc umentation 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 sulf ur 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 1 s t through 30 t h day after deadline $1000 31 s t through 60 t h day after deadline $2000 Beyond 60 t h 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 1 s t through 30 t h day after deadline $1000 31 s t through 60 t h day after deadline $2000 Beyond 60 t h 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 p it emissions in accordance with the requirements of Paragraph 69.c.i: Period of Delay or Non-Compliance 1 s t through 30 t h day after deadline 31 s t through 60 t h day after deadline Beyond 60 t h 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 op erate the control equipment in accordance with the requirements of Paragraphs 70 through 74, or to timely repair leaks identified through the Optical Gas Imaging Ca mera Monitoring as required by Paragraph 75, per day, per unit: Period of Delay or Non-Compliance 1 s t through 30 t h day after deadline 31 s t through 60 t h day after deadline Beyond 60 t h 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 H 2 S 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 pa rameters (as specified by Paragraph 78), the Quench Water System or Operating Practices (as specified by Para graphs 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 1 s t through 30 t h day after deadline $1000 31 s t through 60 t h day after deadline $2000 Beyond 60 t h 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 “(Emi ssion 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 requirement s 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, Pa ragraph 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 requir ements 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 requi rements 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 monitori ng 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 D owntime 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 R ecovery System that conforms to the requirements of Paragraph 24, or failure to timely equip, in accordance with Paragraph 25.a, automatic star tup 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 fo r 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 comp ressor 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 (o r 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 (o r 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 Pa ragraph 42.c (for the LPG Flare): Penalty per Flare per day: $500.
q. Violation of Paragraph 33.b – C overed Flares except DDU Flare

. For each Covered Flare except the DDU Flar e, failure to comply with the Net Heating Value in the Combustion Zone Gas (NHV cz )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 Paragr aph 33.b – DDU Flare . For the DDU Flare, failure to comply with the Net Heating Value in the Combustion Zone Gas (NHV cz ) 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 ṁ air-asst / ṁ air-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 ṁ

air-asst / ṁ air-stoich-vg standard, all five minute pe riods 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 viol ation 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 requir ements 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 Pa ragraphs 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 r eceipt of an objection by EPA pursuant to Paragraph 55.c; or (ii) is required to undertake following disput e 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 exclus ively 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 fo r corrective action agreed to by BPP (with any such extens ions 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 re quirements 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 H 2 S emission limit at a Covered Flare or the LP G Flare after that C overed 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 H 2 S limit, all one-hour periods of viol ation shall be added together to determine the total.

dd. Violation of Paragraph 71 . Failure to timely decommission the SRU Flare in conformance with th e 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 C onsent 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 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1500 Beyond 60 t h 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 1 s t through 30 t h day after deadline $500 31 s t through 60 t h day after deadline $1500 Beyond 60 t h 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 1 s t through 30 t h day after deadline $300 31 s t through 60 t h day after deadline $1000 Beyond 60 t h 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 penaltie s 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 Rela ted 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 paymen t of stipulated penalties will identify the particular violation(s) to wh ich 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 dema nd, and the grounds upon which the demand is based. The United States may, in its unrev iewable 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 St ates 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 Justi ce,” 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 s tipulated penalties owing to Indiana will be paid in the manner se t 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, whic hever is applicable, and will continue to accrue until performan ce 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 pet ition with the Court under Part XIV (“Retention of Jurisdiction/Di spute Resolution”) if BPP has placed the disputed amount demanded in a commercial escr ow account with interest. If the dispute thereafter is resolved in BPP’s favor, the es crowed amount plus accrue d 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 rese rve the right to pursue any other nonmonetary remedies to which they are legally entitled, including but not limited to, injunctive relief, for BPP’s viol ations of this Consent Decree . Where a violation of this Consent Decree is also a viola tion of the Clean Air Act, it s regulations, or a federallyenforceable state law, regulati on, or permit, the United States will not seek ci vil penalties where it already has demanded and secured stip ulated penalties from BPP for the same violations nor will the United States demand s tipulated 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 w ill not seek civil penalties where the United States already has demanded and/or secured stipulated penalties fr om 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 in terest 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 coup on 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 w ill be computed daily and comp ounded 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 s tipulated penalty payment made into an interest bearing escrow a ccount as contemplated by Pa ragraph 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 ri ght 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 Wh iting 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 sp ecifically are noted, the Whiting Refinery will retain such records for the period of th e Consent Decree. Nothing in this Consent Decree will limit the authority of EPA or IDEM to conduct te sts, inspections, or other activities under any statutor y or regulatory provision.

XIII. FORCE MAJEURE 164. “ Force majeure ,” for purposes of this Consen t 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 de lays or prevents the perfor mance 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 us ing 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 mi nimize any resulting delay to the greatest extent possible. “ Force Majeure” does not include BPP’s financial inability to perform any obligation unde r 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 s hould have known, that the event caused or may cause such delay. The notice shall include an explanat ion 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 implementati on 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 w ith any notice all available documentation supporting the claim that the delay was attributable to a force majeure

. Failure to comply with the above requirem ents 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 contro lled 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 anti cipated delay is attributable to a force majeure event, the time for performance of the obligations und er 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 pe rformance of the obliga tions 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 affect ed 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 anticipa ted 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 sh all 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 circumstance s, that best efforts were exercised to avoid and mitigate the effects of the delay, a nd that BPP complied with the requirements of Paragraphs 164 and 165, above. If BPP carries this burden, the dela y 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 th e Consent Decree and for the purpose of adjudicating all disputes of the Consent D ecree between the United States and BPP that may arise under the provisions of this C onsent Decree, until the Consent Decree terminates in accordance with Pa rt 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 th is 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 firs t be the subject of informal negotiations. The dispute shall be considered to have ar isen 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 peri od 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, w ithin 30 Days after the United States has notified BPP of the conclusion of the info rmal negotiation period, BPP invokes formal dispute resolution procedur es 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 incl ude, but need not be limited to, any factual data, analysis, or opinion supporting BPP’s position and a ny supporting document ation relied upon by BPP. 173. The United States shall serve its St atement 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 limite d to, any factual data, analys is, or opinion supporting that

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position and any supporting documentation relie d upon by the United States. The United States’ Statement of Positi on shall be binding on BPP, unl ess BPP files a motion for judicial resolution of the dispute in accordance w ith the following Paragraph. 174. BPP may seek judicial resolution of the dispute by filing with the Court and serving on the United States, in accord ance 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 mo tion shall contain a written statement of BPP’s position on the matter in dispute, incl uding any supporting fact ual data, analysis, opinion, or documentation, and shall set fort h 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 B PP’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 arisi ng under the Consent Decree, BPP shall bear the burden of demonstrating that its position complies with this Consent Decree and the CAA and that B PP is entitled to relief. Th e United States reserves the right to argue that its position is reviewable only on the ad ministrative record and must be upheld unless arbitrary and capricious or othe rwise 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 di sputed 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 di sputed issue, stipulated penalties shall be assessed and paid as provided in Part X (“ Stipulated Penalties”). As part of the resolution of any dispute under th is Part, the Parties, by agreement, or the Court, by order, may, in appropriate circum stances, extend or modify the schedule for completion of work under this Consent Decr ee to account for the delay in work that

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occurred as a result of the di spute 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” sh all have the meaning set forth in 42 U.S.C. § 7412(b)(1); b. “Whiting Refinery Modernization Proj ect” or “WRMP” shall mean: 1) the projects authorized to be constructe d and operated at the Whiting Refinery pursuant to Significant Source Modifi cation 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 incl uded 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 S ource 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 re gulation 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 provisi ons 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, Subpa rt Ja, that are currentl y stayed pursuant to 73 Fed. Reg. 78,549 (Dec. 22, 2008); i. SO 2 and H 2 S emissions limits applicable to flares (set forth in 40 C.F.R. § 60.102a(g)(1) (2010)); ii. SO 2 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 St ayed 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. , “SO 2 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 vi olations that occurre d through the Date of Lodging of the Consent Decree as alleged in the Complaints (filed by the United States and the State concurrently with th e 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 violati ons 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 attach ed hereto in Appendix F.

181. Resolution of Claims for Violat ing PSD/NNSR Requi rements at the Covered, LPG, and SRU Flares . With respect to emissions of SO 2, VOCs, CO and H 2 S from the following flares, entry of this Cons ent 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 Violati ng PSD/NNSR Require ments at Other Process Units . With respect to emissions of the following pollutants from the following process units, entry of this Consent Decree shall resolve th e civil claims of the United States and the State of Indiana agains t 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 SO 2 and NOx;

b. At the Whiting New Coker (also referred to as the #2 Coker) with respect to VOCs, H 2 S, PM TOTAL , and PM 10 ; 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 SO 2 :
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 U nder 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 cl aims 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 th e 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 re solved 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 SO 2 and H 2 S 40 C.F.R. Part 60, Subparts A and J

FCU 500 and FCU 600 SO 2 , CO, NOx and PM 40 C.F.R. Part 60 , Subparts A, J, and Ja

Heaters, boilers, and other units listed in P aragraph 1 8 5 .b SO 2 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 H 2 S 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 Conti nuing 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 Maintena nce 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 th e 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 th ese provisions: (a) relate to flares, and (b) requ ire 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) rela te 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 SO 2 at the following flares, entr y of this Consent Decree sha ll resolve the civil claims of the United States and the State of I ndiana 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 th e Stayed Subpart Ja Requirements, then entry of this Consent Decree sh all 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 th e following Stayed Subpart Ja Requirements, from the date that a final rule encompassing the Stayed Subpart Ja Requirements is effective th rough the following dates: Name of Flare SO 2 and H 2 S 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 ru le 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 SO 2 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 H eaters (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 C onsent 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, Su bpart 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 (a s 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 Consen t Decree shall resolve the ci vil claims of the United States and the State of Indian a 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 Secti ons 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 St ates against BPP for the following violations at the Whiting Refinery of the Cons ent Decree entered on August 29, 2001 in United States, et al. v. BP Expl oration 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 Repa ir on Valves), 20.H.i. (LDAR Monitoring Frequency), 20.L (Adding New Valves and Pumps), and 20.S (Quarterly Reports) that occurred prior to th e Date of Lodging; and

c. Violations of Paragraph 21.A (Sul fur 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: Resolu tion 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 betw een the Date of Lodging and the Post-Lodging Compliance Dates, those re solutions 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 Flari ng Events), and Section P (Incorporation of Consent Decree Requirements into Federally Enfo rceable Permits) of Part V, and Part VI (Emission Credit Generation). However, the re solutions 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 stip ulated 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 D ecree. This Consent Decree shall not be construed to limit the right s of the United States or IDEM to obtain penalties or injunctive relie f under the CAA or implementi ng regulations, or under other federal or state laws, regulations, or permit conditions, excep t 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 substa ntial endangerment to th e public health or welfare or the environment arising at, or posed by, BPP’s Whiting Refinery, whether related to the violations addressed in this Cons ent Decree or otherwise. 193. In any subsequent administrative or judicial proceedi ng initiated by the United States or IDEM for injunctive relief, civil penalties, othe r appropriate relief relating to the Whiting Refinery for viola tions of PSD/NSR, NSPS, NESHAP and/or LDAR requirements not iden tified in this Part:

a. BPP shall not assert, and may not ma intain, 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 th e instant case, except with respect to claims that have been specifically resolv ed pursuant to Paragr aphs 179-188 of this Part and for which the resolution of lia bility 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 re lated 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 re gulations. 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 Stat es and IDEM do not, by their consent to the entry of this Consent Decree, warrant or av er 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 cons trued to create rights in, or grant any cause of action to, any third part y 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 thecommitments 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 Citi zen-Intervenors have control) of any judicial or administrative objection(s), appeal(s), petitions(s) for review, petition to EPA pursuant to Sec tion 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 Perm it that is required by, contemplated by or necessary to implement this C onsent 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 sh all not apply if the terms and conditions of any such permit differ in material respects from th e terms and conditions of the draft terms and conditions that have been provided to Citizen-Intervenors prior to the date hereof and Citizen-Intervenor s 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 prio r to the date hereof or with such modifications as have been consented to by the Citizen-Inte rvenors, Save the Dunes, Sierra Club, the Hoosier Envir onmental Council, Tom Tsourlis and Susan Eleuterio shall dismiss with prejudice thei r 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 ci tizen suit or support the filing (byproviding legal representation or financial contributions over which CitizenIntervenors have control) of any third pa rty 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 obliga tions of BPP under this Decree, except for the obligations unde r Part IX (Civil Penalty) and Part X (Stipulated Penalties), by filing with th e Court a motion for appropriate relief. Such motion shall be governed by the Fe deral 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 perfor mance or injunction. In no event shall BPP be entitled to monetary damages for breach of this Agreement. In addition, no legal action for specific pe rformance or injunction shall be brought or maintained until: (a) BPP provides wr itten 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 breach ing Party fails to commence to cure the claimed breach within such (30) day peri od, 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 re gulations, including, but not limited to, more stringent standards. In addi tion, nothing in this C onsent Decree will be construed to prohibit or prevent the Un ited States or IDEM from developing, implementing, and enforcing more stringent st andards subsequent to the Date of Lodging of this Consent Decree through rulemaki ng, the permit process, or as otherwise authorized or required under fe deral, state, regional, or local laws, or as otherwise authorized or required under fe deral, 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 sa nctions 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 author ity 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 comp lying with any and all new or modified federal, state, regional, and/ or local statutory or regulatory requirement s that may require technology, equipment, monitoring, or other upg rades after the Date of Lodging of this Consent Decree. 200. Startup, Shutdown, and Malfunction . Notwithstanding the provisions of this Consent Decree regarding Start up, Shutdown, and Malfunction, this Consent Decree does not exempt BPP from the requirement s 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 Decr ee will be construed to prevent or limit the

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right of the United States or IDEM to seek in junctive or monetary relief for violations of permits; provided, however, that with respect to monetary relief, the United States and IDEM must elect between f iling a new action for such monetary relief or seeking stipulated penalties under this Consent Decree, if stipulated penaltie s also are available for the alleged violation(s). 202. Failure of Compliance . The United States a nd 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 D ecree will result in compliance with the provisions of the CAA or the corollary stat e and local statutes. Notwithstanding the review or approval by EPA or IDEM of a ny 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 applicab le permits, and all applicable federal, state, re gional, and local laws and regul ations, 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 ma y 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 ri ght to seek to void all or part of the Resolution of Liability refl ected in Part XVII (“Eff ect of Settlement”). Nothing in this Paragraph is intended to en large the Parties’ rights under Fed. R. Civ. P. 60, nor is this Paragraph intended to confer on any Party any indepe ndent 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 su bmits an AMP to EPA for approval, then BPP shall comply with the proposed AMP pe nding 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 applicab le 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 ac cept service of process by mail with respect to all matte rs arising under or relating to this Consent Decree and to waive the formal service requirements set fort h 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 th e Date of Entry. Liability for stipulated penalties, if applicable, shall accrue for vi olations 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 Da te 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 subj ect to public inspecti on in accordance with applicable federal law, unless subject to lega l 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 entere d 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 w ithdraw or withhold its consent to this Consent Decree at any time prior to the Date of En try if public comments disclose facts or considerations indicating that this Consent Decree is inappropriat e, improper, or inadequate. 210. Notice . Unless otherwise provided he rein, notifications to or communications between the Parties shall be deemed submitted on the date they are postmarked and sent by U.S. Mail or overnig ht 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/Di spute Resolution”), which shall be sent by overnight mail or by certified or registered ma il, 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 el ectronic version sent to the addressees set forth in this Paragraph. E ach report, study, notification, or other communication of BPP shall be submitted as specified in this Consen t 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 ot her 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 requ ired or allowed under this Consent Decree shall be addressed as follows: As to the United States :
Chief Environmental Enforcement Section Environment and Natura l 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 necessa ry, 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 elec tronically 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 submissi ons 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 Cent er 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 w ith a notice setting forth such new notice recipient or address. In a ddition, the nature and frequency of reports required by this Consent Decree may be modified by mutual cons ent 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 contai ns 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 willbe 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 modifica tions include, but are not lim ited to, modifications to the

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frequency of reporting obligati ons and modifications to sche dules that do not extend the date for compliance with emissions limitations following the installation of control equipment, provided that such changes ar e 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 appr oval by the Court. Specific provisions in this Consent Decree that govern specific types of modifications shall be effective as set forth in the specific provisi on governing the modification. 214. Effect of Shutdown . The permanent Shutdown of an emissions unit or equipment and the surrender of all permits fo r 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 perm anent 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 D ecree applicable to the Refine ry 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 - Flui d 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 – NO x Emissions Reductions from Heaters and Boilers (including operation of the re levant units for one (1) year after installation of required emission controls and complia nce with applicable emission limits established pursuant to this Consent Decree);

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c. Part V, Section G – SO 2 Emissions Reductions from Heaters and Boilers (including operation of the relevant units for one (1) year after completion in compliance with the emission limits establis hed 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 Recove ry 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 fl ow 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 ha ve been completed, BPP may submit a written report to EPA and IDEM de scribing the activities undertaken and certifying that the applicable Se ction(s) or Part(s) have been completed in full satisfaction of the requirements of this C onsent 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 responsib le 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 perso nnel qualified to properly gather and evaluate the information submitted. Based on my directions and after reasonable inquiry of the person(s) di rectly 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 requi rements have not been fully complied with, EPA will notify BPP as to th e activities that must be undertaken to complete the applicable Section. BPP w ill perform all activities described in the notice, subject to its right to invoke the dispute resoluti on procedures set forth in Part XVI (“Dispute Reso lution”); and/or b. If EPA concludes that the require ments of the applicable Section or Part have been completed in accordan ce with this Consent Decree, EPA will so certify in writing to BPP. This certificat ion 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, traini ng, 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 w ill preclude the United States from seeking stipulated penalties for a violation of any of the requirements of the Consent Decree regardless of whether a Certifica tion 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 C onsent 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 Paragra ph. Prior to seeking termination, BPP must have completed and satisfied all of the followi ng requirements of this Consent Decree:

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a. Installation of control technology systems as speci fied in this Consent Decree; b. Compliance with all provisions contai ned 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 a ll penalties and/or other monetary obligations owed to the United States or th e State of Indiana ar e fully paid as of the time of the motion; d. Satisfaction of Part VII (“Supplem ental Environmental Projects and Additional Injunctive Relief”);

e. Application for and receipt of perm its 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 w ith 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 complianc e 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 Paragrap h 219, BPP will certify such compliance and completion to the Unite d 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 writ ing with specific reasons within 120 days of receipt of BPP certificati on 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, th en 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 installati on of all controls required by, and operation for one (1) year in compliance with the emission limits established pursuant to,

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Part V, Sections F and G, BPP may move for te rmination of Part V, Sections F and G, as provided in this Paragraph:

a. BPP shall prepare and submit to EP A 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 requireme nt 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 (“S tipulated Penalties”). ii. With respect to the requireme nt in Paragraph 219.e for the application and receipt of permits incorporating the emission limits and standards established unde r this Consent Decree, BPP shall include copies of the relevant portions of all applic able 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 vi olation 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.

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222. Each of the undersigned representative s certifies that she or he is fully authorized to enter into this Consent Decr ee on behalf of the applicable Party, and to execute and to bind such Part y 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 pr ior agreements and understandings, whether oral or written, concerning the settlement em bodied herein. No ot her document, nor any representation, inducement, agr eement, understanding, or promise, constitutes any part of this Consent Decree or the set tlement 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 representative s certifies that she or he is fully authorized to enter into this Consent Decr ee on behalf of the applicable Party, and to execute and to bind such Part y to this Consent Decree.

Dated and entered this _______ day of ________________, 2012.

UNITED STATES DISTRICT JUDGE

125Subject 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 page 130 of 325 document 7-1 filed 09/18/12 page 130 of 324Subject 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 page 131 of 325 document 7-1 filed 09/18/12 page 131 of 324Subject 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 page 132 of 325 document 7-1 filed 09/18/12 page 132 of 324Subject 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 case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 133 of 325 document 7-1 filed 09/18/12 page 133 of 324Subject 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 case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 134 of 325 document 7-1 filed 09/18/12 page 134 of 324Subject 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 page 135 of 325 document 7-1 filed 09/18/12 page 135 of 324case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 136 of 325 document 7-1 filed 09/18/12 page 136 of 324

Subject to the notice and comment provi sions 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 CouncilSubject 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 page 137 of 325 document 7-1 filed 09/18/12 page 137 of 324Subject 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 page 138 of 325 document 7-1 filed 09/18/12 page 138 of 324Subject 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 page 139 of 325 document 7-1 filed 09/18/12 page 139 of 324Subject 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:



### !~3

- -- l c_. 12 Date: ~ /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 page 140 of 325 document 7-1 filed 09/18/12 page 140 of 324Subject 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: ~./~ ~ ~ ~"1~ctr~~~j ~~S ZC f Z :~~`~ C= l li 1 Y WILLIAM L. PATBERG, E Shumaker, Loop &Kendrick, L

ATTORNEYS FOR BP PRODUCTS NORTH AMERICA INC. case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 141 of 325 document 7-1 filed 09/18/12 page 141 of 324case 2:12-cv-00207-PPS-APR document 7-1 filed 09/18/12 page 142 of 325case 2:12-cv-00207-PPS-APRcase 2:12-cv-00207-PPS-APRdocument 3-1 filed 05/23/12page 143 of 325document 7-1 filed 09/18/12page 142 of 324APPENDIX ALOCATION OF FUEL GAS SULFUR MONITORS1case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 144 of 325 document 7-1 filed 09/18/12 page 143 of 324

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 th is 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 l eaking at no greater than 100 ppm.

b. “Certified Low-Leaking Valve Pack ing Technology” shall mean valve packing technology for which a manufact urer has issued either: (i) a written guarantee that the valve packing technology will not leak above 100 ppm for five year s; or (ii) a written gu arantee, certification or equivalent documentation that the valve packin g technology has been tested pursuant to generally -accepted good engineering practices and has been found to be leak ing at no greater than 100 ppm.

c. “Covered Equipment” shall mean all pumps and valves, in light liquid, heavy liquid, or gas/vapor servi ce in all Covered Process Units.

d. “Covered Process Units” shall mean any process unit that is, or under the terms of this Consent Decree be comes, 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 L eak 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 “C ompletion 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 in dicates the relative size of the leak) by no later than the end of th e next calendar day of each attempt at repair of a leaking piece of C overed 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 appl y 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 appl y to all Equipment at the Whiting Refinery that is regulated under a ny 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 afte r the Date of Entry, BPP shall develop a written facility-wide LDAR Program th at 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 a nd that pieces of Equipment that are taken out of service are removed from the LDAR program; (iii) the roles and responsibilities of all employee a nd contractor personnel assigned to LDAR functions at the Whiting Re finery; (iv) how the number of personnel dedicated to LDAR functi ons 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 w ith 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 subparagra ph 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 dir ectly electronically records the Screening Value detected at each piece of Covered Equipment, the date and time that each Screening Va lue 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 meet s 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 Covere d 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, temperatur e, 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 pro cess 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 be fore 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 monito ring shift and prior to each time LDAR monitoring equipment is turned off during each monitoring shift, except when LDAR monitoring equipmen t 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 in strument if the instrument can be immediately re-ignited. The calib ration drift assessment shall be conducted using calibration gas as pr ovided in 40 C.F.R. § 60.485a(b)(1) with a concentration approximately equal to the applicable internal leak definition. If any calibration drift as sessment after the initial calibration shows a negative drift of more than 10% from the previous calibration, BPP shall re-monitor all components th at 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 En try, 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, fo r all Covered Equipment, at any time, including outside of periodic monitori ng, that a leak is detected through audio, visual, or olfactory sensing, B PP 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 pp m of VOCs, excluding control valves and other valves that LDAR personnel are no t authorized to repair.

12. For each leak subject to Paragra ph 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 (1 5) 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 Repa ir 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 Repa ir 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 repairi ng 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 issu e with repairing the valve using the drill-and-tap method, in which case, BPP shall document the reason(s) why any drill-and-tap at tempt was not performed prior to placing any valve on the DOR list.

15. For each leak, BPP shall record the fo llowing information: the date of all repair attempts; the repair methods used during each repair attempt; the date, time and Screening Values fo r 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 inte nded 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 re pair 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 Entr y, 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 co mpliance, 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 withou t a process unit shutdown;

b. Periodic monitoring, at the frequenc y 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 re packed 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 th e process unit for two successive monitoring periods without detecting a leak gr eater 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 Replac ement/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 repl ace 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 modifi ed purchasing procedures that evaluate the availability of valv es and valve packing that meet the requirements for a Certified Low-Leaking Valve or Certified Low-Leaking Valve P acking Technology at the time that the valves and/or va lve packing is acquired.
(ii) Except as provided in Para graph 20, BPP sha ll install valve packing material that meets the requirements for Certified Low-Leaking Valve Packing Technology whenever repacking any valve in gas/vapor or lig ht liquid VOC service in a Covered Process Unit.

b. By no later than 90 days after the Da te 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 pu rchases for use in any Covered Process Unit either is a Certified Lo w-Leaking Valve or is fitted with Certified Low-Leaking Va lve 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 inst alls in any Covered Process Unit

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either is a Certified Low-Leaking Va lve 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 Va lves 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 Va lve with a Certified Low-Leaking Valve or with Certified Low-L eaking Valve Packing Technology. BPP shall undertake this replacement or repacking by no later than 30 days after the monitoring event th at triggers the replacement or repacking requirement, unless the replacement or repacking requires a process unit shutdown. If the replac ement or repacking requires a process unit shutdown, BPP shall undertake the replacement or repacking during the Maintenance Shutdown that follows the monitoring event that tri ggers the requirement to replace or repack the valve. If BPP completes the replace ment or repacking within 30 days of detecting the leak, B PP 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 mi ght 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 Cer tified Low-Leaking Valve or Certified Low-Leaking Valve Packing Technology

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a. BPP shall not be required to utiliz e a Certified Low-Leaking Valve or Certified Low-Leaking Valve Pack ing Technology to replace orrepack a valve if a Certified Low-Leaking Valve or Certified LowLeaking Valve Packing Technology is commercially unavailable in accordance with the provisions in Pa rt 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 docum entation from each vendor that the particular valve that BPP needs is commercially unavailable either as a Certified Low-Leaking Valve or wi th 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 Valv e or Certified Low-Leaking Valve Packing Technology; (ii) identify th e vendors it contacted to determine the unavailability of such a Va lve or Packing Technology; and (iii) include the written represen tations 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 a nd Part O of this Appendix for a subsequent Commercial Unavailabil ity 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 ava ilability of a valve or valvepacking meeting Certified Low-Leaking Valve or Certified LowLeaking Valve Packing Technology requirements.

21. Records of Certified Low-Leaki ng Valves and Certified Low-Leaking Valve Packing Technology . Prior to installing any Certified LowLeaking Valves or Certified Lo w-Leaking Valve Packing Technology, BPP shall secure from each manufacturer documentation that demonstrates that the proposed va lve or packing technology meets the definition of “Certified Low-Leaki ng Valve” and/or “Certified LowLeaking Valve Packing Technology.” B PP shall retain that documentation for the duration of this Consen t Decree and make it available upon request.

22. Valve Replacement/Improvement Report . In each Compliance Status Report due under Part N of this Appe ndix, BPP shall include a separate section in the Report that: (i) descri bes the actions it t ook to comply with this Part G, including identifying each valve that was replaced or upgraded; and (ii) identifies the sche dule 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 th e 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 in tegrated 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 c ontractors responsible for LDAR monitoring, maintenance of LDAR mon itoring equipment, LDAR repairs, and/or any other duties generated by the LDAR program have completed training on all aspects of LDAR that ar e relevant to the person’s duties. By that same time, BPP shall develop a training protocol to ensure that refresher training is performed on ce per calendar year and that new personnel are sufficiently trained prio r 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 pr actical but in no case later than the next work day for the monitoring tec hnician, 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 technici an for each day of monitoring, a log sheet may be created that includes the certification that the monitoring technicians would date and sign each da y that the technician collects data.

26. Commencing by no later than the first full calendar quarter after the Date of Entry, during each calendar quart er, at unannounced times, an LDARtrained employee or contractor of BP P, who does not serve as an LDAR monitoring technician on a routine ba sis, shall undertake the following:

a. review Management of Cha nge documentation for the previous calendar quarter, and co nduct process unit walk-throughs to determine whether all pieces of Equipment id entified in the previous calendar quarter’s Management of Change do cumentation as being subject to the LDAR program are included in the LDAR database and are properly tagged;

b. during the process unit walk-thr oughs required by subparagraph 26.a., and during such additional walk-throughs as may be necessary to assure that all Covered Process Un its are reviewed at least once per year, conduct spot checks of Equipm ent to verify that the Equipment checked is included in the LDAR da tabase 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 documentati on 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 E quipment monitored per Day) for feasibility and unusual trends;
(v) verify that proper calibra tion records and monitoring instrument maintenance information are stored and maintained;

d. conduct spot checks of LDAR progr am records to verify that those records are maintained as required; and

e. observe each LDAR monitoring te chnician in the field to ensure monitoring is being cond ucted 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 ob servations required by this Paragraph were undertaken; and (ii) describes th e nature and timing of any corrective actions taken.

Part K: LDAR Audits and Corrective Action

27. BPP shall conduct LDAR audits pursuan t to the schedule in Paragraph 28 and the requirements of Paragraph 29 of this Appendix. BPP shall retain a third-party with experience in conduc ting 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 reta in a third-party auditor, BPP may conduct the audit internally by using its own personnel, provided that the personnel BPP us es are not employed at the Whiting Refinery but rather are employed at a f acility that currently uses Certified Low-Leaking Valve and/or Certif ied Low-Leaking Valve Packing Technology. All such internal audi ts 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) m onths 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. Fo r 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 regula tions, reviewing and/or verifying the same items that are required to be re viewed and/or verified in Paragraph 26 of this Appendix, and performing the following activities for Covered Equipment:

a. Calculating a Comparative M onitoring Audit Le ak Percentage

. Covered Equipment, excluding pumps and valves in heavy liquid service, shall be monitored to ca lculate 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 sha ll conduct a comparative monitoring audit pursuant to this Paragraph during each LDAR audit. Each Covered Process Unit at the Whiting Refi nery 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 Le ak 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 Paragrap h 29.a to the historic average leak percentage from Paragraph 29.b shall be calculated. If a calculated ratio yields an infinite result, B PP 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 Refine ry’s compliance with this ELP.

30. When More Frequent Periodic Monitoring is Required . If a comparative monitoring audit leak percentage ca lculated pursuant to Paragraph 29.a triggers a more frequent monitoring sc hedule 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 fo r the equipment type in that Covered Process Unit, BPP shall monitor the a ffected 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

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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 result s of an LDAR audit identify any deficiencies or if the Comparativ e 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 possibl e 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 ex pected 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 certificati on of the completion of corrective action(s). For any corrective actions requiring more than 90 days to complete, BPP shall include an expl anation 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 afte r receipt of BPP’s CAP, EPA may disapprove any or all aspects of th e CAP. Each item that is not specifically disapproved shall be deemed approved. Except for good cause, EPA may not disappr ove any action within the CAP that already has been completed. Within 45 days of receipt of any disapproval fr om 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 EP A 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 th e dispute resolution provisions of this Decree. Part L: Certification of Compliance

32. Within 180 days after th e 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 i nquiry: (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 th at 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 reco rds, including copies of all LDAR audits, to document compliance with the requirem ents of this ELP in accordance with Section VIII (Reporting and Recor dkeeping) 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 orig inal electronic format, all LDAR monitoring data generated during th e 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 Prov isions) 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 assigne d 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 descrip tion of any non-compliance with the requirements of this Appendix;

c. An identification of any problem s 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 trai ning required in accordance with Part I of this Appendix;

f. Any deviations identified in th e QA/QC performed under Part J of this Appendix B, as well as any correc tive actions taken under that Part;

g. A summary of LDAR audit resu lts 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 pr eceding 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 sh all cover the period between the Date of Entry and the first full half year af ter 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 submitte d 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 in clude 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 encl osed document(s), including all attachments. Based on my inqui ry of those individuals with primary responsibility for obtaini ng 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 possibi lity 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 “Co mmercial 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 th an those identified in this Part may also be utilized to establish th at a Certified Low-Leaking Va lve or Certified Low-Leaking Valve Packing Technology is not commercially available.

37. Factors . The following factors sha ll be taken in to account for determining the availability of safe and suitable Certified Low-Leaking Valve or Certified Low-Leaki ng 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 re levant for consideration, depending on the process unit or equipmen t 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 an d/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 num ber 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 thr ee vendors of valves and three vendors of valve pack ing technologies;

ii. If fewer than three vendor s of valve or valve packing technologies are contacted, the de termination 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 fo r 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 th e 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 documentati on 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 Repor t required by Section VIII of the Consent Decree, for the period in wh ich the valve or valve packing is replaced.

39. EPA Review of Claim of Commercial Unavailability . Upon discretionary review by EPA of any claim of co mmercial unavailability, if EPA disagrees that a valve or valve-p acking technology is commercially unavailable, EPA shall notify BPP in writing, specifying the valve or valve packing EPA believes to be comme rcially 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 no tice, the following shall apply:

a. BPP is not required to retrofit th e valve or valve packing for which the unavailability claim was asserted (unless otherwise required to do so pursuant to some other provis ion of this Consent Decree).

b. EPA’s notification shall serve as no tice to BPP of EPA’s intent that a future claim of commercial unavaila bility 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 fact ors identified in th is Appendix. If BPP disagrees with EPA’s notificat ion, BPP and EPA may informally discuss the basis for the claim of commercial unavaila bility. EPA may thereafter revise its not ification, if necessary.

c. If BPP makes a subsequent comm ercial unavailability claim for the same valve or valve packing (or va lve or valve packing in the same or similar service) that was the subject of a prior unavailability claim which was not accepted by EP A, and such subsequent claim is also denied by EPA on the same basis as provided in EPA’s prior notification, BPP shall re trofit 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 Resolu tion 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 Ne t Heating Value of the Vent Gas directed to each Covered Flare. The response time of a GC require s the use of an aver aging 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 th e South Flare or to an alternative flare when the South Flare is out of service. BPP does not have staged flar es at the Whiting Refinery.

DEFINITIONS “Acid Gas” shall mean any gas that contai ns hydrogen sulfide and is generated at a refinery by the regeneration of an amine scrubb er solution, but does not include Tail Gas. “Acid Gas Flaring” or “AG Flaring” shall m ean 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 Stripp er Gas, except facilities in which gases are combusted to produce sulfur or sulfuric acid. B PP 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 Flari ng 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 SO 2 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 SO 2 , then only one AG Flaring Incident shall ha ve occurred. Subsequent, con tiguous, non-overlapping periods

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are measured from the initial commencement of flaring within the AG Flar ing Incident. If, at any time during the term of this Consent Decr ee, 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 whet her there is one AG Flar ing 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 utiliz es 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 “ ṁ air-stoich-vg ” shall mean the mass of air needed to reach a stoichiometric ratio based on the actual Vent Gas Mass Flow Rate. The ṁ air-stoich-vg is represented by and shall be calculated according to Equation 4 in Appendix FLR-15 of this Consent Decree.

“Assist Air” or “ Air asst ” shall mean all air that intentionally is introduced into an Air-Assisted Flare to assist in combustion. Assist Air does not incl ude ambient air, air introduced through in a Minimum Steam Reduction System, or air entrained in Vent Gas.

“Assist Air Mass Flow Rate” or “ ṁ air-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 ṁ air-asst ” is represented by and shall be calculate d 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 in strumentation and systems requi red in Paragraphs 7 – 13, 42.a and 42.b of this Decree so as to produce the ope rational results required in Paragraphs 30, 33 – 35, 37, and 45.
“Baseload Waste Gas Flow Rate” shall mean, for a particular Cove red Flare, the daily average flow rate, in scfd, to the Flare, excl uding all flows during peri ods of startup, shutdown, and Malfunction. The flow rate da ta 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 In itial Waste Gas Minimization Plan due under Subparagraph 18.b.ii and may be updated in subs equent Waste Gas Minimization Plans due under Paragraphs 19 and 20.

“BTU/scf” shall mean British Ther mal Unit per standard cubic feet.
“Calendar Quarter” shall mean a thre e-month period ending on March 31, June 30, September 30, or December 31.

“Center Steam” or “ S cen ” 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 Ve nt Gas without entraining air.

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Diagrams illustrating the meani ng 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 “ Q s-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 “ ṁ s-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 judg ment, on a 5-minute block average using Equation 2 in Appendix FLR-2. “Cold Startup of the Refinery ” shall mean the setting into ope ration 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 Ne t 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 mixtur e of all gases and st eam 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 (i f 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 Dominate d 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 ex terior of the Flare tip body. Representations of Discontinuous Wake Domina ted Flow are set fort h 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 zo ne is elevated in order to separate the heat generated by combustion from peopl e, 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 Vo lumetric Flow Rate and dividing by the Unobstructed Cross Sectional Area of the Flare Tip.

“External Power Loss” shall mean a loss in th e 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 sim ilar device used to divert gas from a Flare and direct the gas to a fuel gas sy stem, to a combustion device other than the Flare, or to a product, co-product, by produc t, or raw material recovery system. “Hydrocarbon Flaring” or “HC Flaring” shall mean the com bustion 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” sha ll mean a Flare used to combust any refinery-generated gas other than Acid Gas and/or Sour Water St ripper Gas and/or Tail Gas. The Hydrocarbon Flares that BPP operates at the Refi nery 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-gen erated 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 Appe ndix; or (ii) Air-Assisted shall be covered by Sections E, G-H, and J-K of this Appendix. Co mpliance with the applicable requirements shall commence on the first date of that any such ne w 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 gase s, except for Acid Gas, Sour Water Stripper Gas, or Tail Gas, at a H ydrocarbon Flare that results in the emission of sulfur dioxide equal to or greater than five-hundred (500) pounds in any 24-hour period; provide d, however, that if 500 pounds or more of sulfur dioxide has been emitted in any 24-hour period and flaring continues into subsequent, contiguo us, non-overlapping 24-hour period(s), each period of which results in emissi ons equal to, or in excess of, 500 pounds of sulfur dioxide, then only on e HC Flaring Incident shall have occurred. Subsequent, contiguous, n on-overlapping periods are measured from the initial commencement of Flari ng 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 Inci dent, unless the root causes of the flaring at the various HC Flaring Devices are not rela ted 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 calculati ng 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 m easuring the volumetric flow rate of hydrogen, nitrogen, oxygen, carbon monoxi de, carbon dioxide, and/or steam in the Waste Gas, the contributi on 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 Flari ng 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 sh all 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 vol umetric concentration of a combustible gas in air that, at a given te mperature and pressure, will still combust. “Lower Flammability Limit Table” shall m ean Table 1 of Appendix FLR-3. Table 1 lists, inter alia , the LFLs of individual co mpounds found in Vent Gas. “Lower Flammability Limit of Vent Gas” or “ LFL vg ” shall mean the weighted average of the LFLs of each of the individual compounds in Ve nt Gas, weighted by their volume percent in the Vent Gas. LFL vg is represented by and shall be cal culated 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 vo lume or weight of a fuel initially at 25 ̊ Centigrade and 760 mmHg, assuming that the pr oduced water is vapori zed and all combustion products remain at, or are returned to, 25 ̊ Centigrade; however, the standard for determining the volume corresponding to one mole is 20 ̊ Centigrade. “Lower Steam” shall mean steam piped to an exterior annula r ring near the lower part of a Flare tip, which entrains Air wh ich flows through tubes to the Flar e tip, and ultimately exits the tubes at the Flare tip. Diagrams illustrating th e 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, Ai r-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 e quipment, 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 interp reting 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 Ma lfunctions, 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 upo n re-examination of the tip’s requirements. “Minimum Steam Reduction System” or “MSR S” shall mean a system that utilizes a mixed stream of air and steam to reduce the minimum steam requirement s 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 wh ich 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 “ NHV cz ” shall mean the Lower Heating Value, in BTU/scf, of the Combustion Zone Gas in a Flare. NHV cz is represented by Equation 5 in Appendix FLR-3 to this Consent Decree a nd shall be calculated in accordance with Equations 5 - 8 of Appendix FLR-3. To the exte nt a Covered Flare ever is equipped with a Minimum Steam Reduction System, BPP also shall use Equations 9 – 13 to calculate NHV cz . “Net Heating Value of the Combustion Zone Gas Limit” or “ NHV cz-limit ” shall mean the minimum Net Heating Value that the Combustion Z one Gas must have to ensure an acceptable Combustion Efficiency. NHV cz-limit shall be calculated no less than one time every 15 minutes through the use of Equation 4 in Appe ndix FLR-3 of this Consent Decree. “Net Heating Value of Hydrogen as Adjusted” or “NHV H2-adj ” shall mean 1212 BTU/scf. NHV H2-adj represents an adjustment to hydrogen’s actua l 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 “ NHV vg ” shall mean the Lower Heating Value, in BTU/scf, of the Vent Gas directed to a Flare. NHV vg is calculated as set forth in Equation 2 in Appendix FLR-3. “Net Heating Value of Vent Gas at its Lower Flammability Limit” or “ NHV vg-LFL ” shall mean the Lower Heating Value, in BTU/scf, of the Vent Gas at its LFL. NHV vg-LFL is represented by and shall be calculated in accordan ce with Equation 3 of Appendix FLR-3 of this Consent Decree.

“Passive FTIR” shall mean a Fourier Transf orm Infrared System that collects thermal (infrared) radiation emitted by a hot gas plum e, and through the analysis of the resulting emission spectrum, identifies a nd quantifies the compounds produci ng values proportional to the path-integrated gas concentrations. “Pilot Gas” shall mean all gas introduced th rough the pilot tip of a Flare to maintain a flame.

“Prevention Measure” shall mean an instru ment, 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 infi ltration (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; a nd Hydrocarbon Flaring Incident. “Root Cause Analysis” shall mean the primary and any contributing causes of a Reportable Flaring Incident as determin ed 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 cessa tion of operation for any purpose. “Sour Water Stripper Gas” or “SWS Gas” sh all 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 ma y be documented by either a person certified pursuant to Method 22 or by a video camera.

“SRU Flare” shall mean the Elevated Flare asso ciated with the sulfur recovery unit at the Refinery that BPP designates with ID No. 162-03. “Standard Conditions” shall mean a temperat ure of 68 degrees Fahrenheit and a pressure of 1 atmosphere. Unless otherw ise expressly set forth in this Consent Decree or an Appendix, Standard Conditions shall apply. “Startup” shall mean the setti ng 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 Minimu m 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 buil dup, 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 ga s through the Flare heater; and (c) prevent oxygen infiltration (b ackflow) into the Flare tip. “Tail Gas” shall mean the exhaust gas from th e 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 SO 2 in any 24-hour period; or

ii. “Tail Gas Incident – Trigger 2”: Ta il Gas that is combusted in a thermal incinerator and results in excess emissions of 500 pounds or more of SO 2 emissions in any twenty-four (24) ho ur period. Only emissions which are in excess of a SO 2 concentration of 250 ppm (ro lling twelve-hour average) shall be used to determine the amount of excess SO 2 emissions from the incinerator. Tail Gas Incidents may include, but are not limite d to, any of the following: a TGU shutdown, a TGU bypass, and a scheduled or unscheduled shutdow n of a sulfur recovery plant. For Tail Gas Incidents – Trigger 2, BPP shall use good engineer ing judgment and/or other monitoring data to calculate emissions during periods in which the SO 2 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 flar e that receives Waste Gas that has been redirected to it from another flare for 504 hour s 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 in cludes, but is not limited to, Lower Steam, Center Steam, and Upper Steam.

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“Total Steam Volumetric Flow Rate” or “ Q s ” 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 “ ṁ s ” shall mean the mass flow rate of Total Steam supplied to a Flare, in pounds pe r hour as calculated on a 5-minut e block average. Total Steam Mass Flow Rate shall be calculated as se t forth in Equation 3 in Appendix FLR-2.

“Unobstructed Cross Sectional Ar ea of the Flare Tip” or “ A tip-unob ” shall mean the open, unobstructed area of a Flare tip th rough which Vent Gas and Center Steam pass. Diagrams of four common flare types are set forth in A ppendix FLR-6 together with the equations for calculating the A tip-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 th at operates at continuous ly variable speeds between a minimum and maximum as regul ated 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 vari able 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 “ ݒ ୵୧୬ୢ ” 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 ga ses 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 “ Q vg ” 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 “ ṁ vg ” shall mean the mass flow rate of Vent Gas directed to a Covered Flare, in pounds per hour on a 5-mi nute 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 “ MW vg ” shall mean the Molecu lar 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 A ppendix, 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” shal l 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 fort h 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 ga s. “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 th e 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. De pending upon the instrumentation that measures Waste Gas, certain compounds (hydrogen, nitr ogen, 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 rela ting to Waste Gas flow; in the substantive provisions of this Appendix, the circumstances in which such exclusions are permitted are specifically identified. Appendi x 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 th e Date of Entry, based on the monitoring systems and instrumentation existing at each Cove red Flare as of the Date of Entry, BPP shall complete the installation of a system that depict s, 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 th e 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 possibl e 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 Fl are, BPP shall operate each Covered Flare to minimize the S/VG ratio to the extent practical with th e existing monitoring and instrumentation systems.

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2. Evaluating and Upgrading or Replaci ng, as Necessary, Mete rs 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 sha ll upgrade or replace, as necessar y, 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 be ing directed to each Covered Flare. If the implementation of any such measur e takes longer than one ye ar 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-a nnual report under Sectio n VIII of this Decree that is due after one year afte r 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 sha ll conduct and complete a survey (“ Initial PRV Leak Survey”) of the large, high-pressure hydrocarbon pressure relief valves (“PR Vs”) 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 Main tenance 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 ar e not identified in Appendi x FLR-8) that are tied into Flare headers and subheaders, BPP shall co nduct acoustic monitoring pursuant to a plan and schedule that BPP shall include in the In itial Waste Gas Minimization Plan due under Paragraph 18.

B. Instrumentation and Monitoring Systems for Covered Flares

5. Flare Data and Monitoring Systems a nd 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 dr awings specified in Parts 1 – 8 of Appendix FLR-9;

b. A detailed description of each instrument and piece of monitoring equipment, including the specific m odel 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 m onitoring methods and calculations that BPP shall use to comply with the requ irements 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 H 2 S CEMS required pursuant to 40 C.F.R. Part 60, Subpart J or Subpart Ja, this report shall satisfy the notification require ments of 40 C.F.R. § 60.7(a)(5).

6. Installation and Operation of Monitoring Systems

.

a. By no later than startup of the Sout h Flare, and December 31, 2013 for all other Covered Flares, BPP shall have completed the installation and commenced the operation of the instru mentation, 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 UI U Flares in order to meet the accuracy requirement in Appendix FLR- 11. BPP shall complete any such upgrades or re-positioning by December 31 st 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 a nd temperature at each point of flow measurement;

c. Have dual channel measurement at each point of flow measurement for flow meters using an ultrasoni c flow measurement method; and

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d. Have retractable or removable sens ors at each point of flow measurement to ensure that the flow meter is maintainable online. Prior to any necessary relocati on 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 he ader prior to the flare stack (after all addition of Waste Gas from process units) or in the flare stack; (2) a flow mete r 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 th e ultrasonic flow meter pursuant to Paragraph 6, the Vent Gas Flow Moni toring System shall consis t 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 Supplementa l Gas that may be supplied to the flare stack and that is not already measured by the ultrasoni c 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 th e Vent Gas at each Covered Flare. BPP shall utilize the molecular weight analyzer in the u ltrasonic 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 ex cept Hydrogen Sulfide (“H 2 S”), the GC shall measure the concentration on a mole percent (“mol/mol%”) basis; for H 2 S, 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 meteor ologic data instruments capable of measuring wind speed. The station shall be lo cated in the refine ry 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 Domi nated 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 inst alled) and continuously measure the flow, in scfm or pounds per hour (if the instru ment automatically converts flow from scfm to lb/hr), of all Pilot Gas to a Cove red Flare. BPP may utilize the da ta generated by this system as part of the calculation of the Net Hea ting Value of the Combustion Zone Gas.

15. Instrumentation and Monitoring Systems: Specifications

. The instrumentation and monitoring systems identified in Paragra phs 7 – 9 and 11 - 12 shall meet or exceed the specifications set forth in Appendix FLR-11.

16. Instrumentation and Monitoring System s: 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 ex cepted activities in Subparagraphs 17.a—17.c for any instrument exceed 110 hours in any calenda r 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 pe nalties under Paragraph 150.j of Part X (“Stipulated Penalties”) and BPP sha ll be entitled to assert that the period of instrumentation and monitoring system downtim e was justified under the circumstances. Nothing in this Paragraph is inte nded 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 require ments, including operation, maintenance, and quality assurance/quality control requirements, of 40 C.F.R. Pa rt 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 e ffective after the Date of Lodging) at such time as those requirements become applicable pu rsuant 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. Th e 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 requir ed 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 be tween: (i) All Waste Gas flows excluding hydrogen, nitrogen, oxygen, carbon monoxide, carbon diox ide, and/or water (steam); and (ii) hydrogen, nitrogen, oxygen, carbon monoxi de, carbon dioxide, and/or wa ter (steam) flows in the

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Waste Gas. BPP may use either an engineering evaluation or measuremen ts from monitoring or a combination to determine flow rate. In de termining 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 lo sses 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 natu ral 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 even t 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 Ga s 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 C overed Flare’s Waste Gas and the percentage contribution of each such constituent during baseload conditions. BPP may use either an engineering evaluation or measur ements from monitoring or a co mbination 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 identificatio n of each Waste Gas tie-in to the main Flare header(s) and process unit flare header(s), as appli cable, consistent with Appendix FLR-12. Temporary connections to a Flare’s header(s) and/or subheader(s) ar e 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 ye ars to reduce flaring. The description shall specify the date of inst allation 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 e xpeditious installation and commencement of operation and a projection of the amount of reductions to be realiz ed. 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 servi ce, 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 a nd evaluate all Prevention Measures, including a schedule for the expedi tious implementation and commencement of operation of all prevention meas ures, to address the following:

i. Flaring that has occurred or may reasonably be expected to occur during planned maintenance activitie s, including startup and shutdown . The evaluation shall include a review of flaring that has occurred during these activiti es in the past three years and shall consider the feasibility of perf orming 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 audi t 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 cons ider the feasibility of reducing flaring through the recovery, treatment, a nd use of the Waste Gas.

iii. Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a proce ss to operate in a normal or usual manner . The evaluation shall consider the adequacy of existin g maintenance schedules and protocols for such equipment. A failure is “recurrent” if it occurs more than twice during an y 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, whic h shall update for the preceding calendar year, if and as necessary, th e 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 availa ble. 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 prep ared pursuant to Paragraph 54 to determine if reductions in addition to the reductions ac hieved through any corrective action under Paragra ph 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 thereafte r 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 a ppropriate 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 Ga s to the Flares while ensuring safe refinery operations. BPP shall operate the equipment c onsistent 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 cap able of automatic startup shall be considered to be available for operation. On ce 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 availabl e 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 st artup 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 operatio n. Prior to the installation of automatic startup at FGRS 1 and FGRS 2, BPP shall start compre ssors 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, ex cept 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 e quipment 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 generati on of Waste Gas during such periods.

iv. The requirements of subpar agraph i and ii shall not apply during periods when compressors are shut down consiste nt with the manufacture r’s specifications or good engineering practices to preserve the mechani cal 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 lim itations 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 rol ling 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 rol ling average basis, rolled daily.

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Each exceedance of the 30-day rolling average li mit 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: Reque sting 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 lim itations 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 lim it(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 variab les 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. Th e 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 li mit will be in effect. BPP shall certify the accuracy of the pro cess 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 su bmission, 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 resolv ed in BPP’s favor. Nothing in this Consent

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Decree shall be construed to relieve BPP of an obligation to evalua te, under applicable Prevention of Significant Deteri oration 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 hydr ogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam) in the Waste Gas, the contribution of all measured flows of any of thes e 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 du e to an interruptible power service agreement, and emergencies arising fr om events within the boundaries of the Refinery), except those expres sly 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 Star tup Waste Gas Minimization Plan”). If BPP submits a Cold Startup Waste Ga s 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 ex clude any such flows from the refinery-wide 365-day rolling average limit.

d. Except for hydrogen, nitrogen, oxyge n, 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 EP A 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 th e steps BPP took in compliance with the Cold Startup Waste Gas Minimizati on 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 th e event are anticipated to persist

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after the notice, and if so, for how l ong; and the measures taken or to be taken to prevent or minimize the flow s, 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 emi ssions may be vented to it.

b. No Visible Emissions . Except for periods of Startup, Shutdown, and/or Malfunction, BPP shall operate each Covered Flar e with no Visible Emissions. Method 22 in 40 C.F.R. Part 60, Appendix A, shall be used to dete rmine compliance with this standard. However, for purposes of this Appendix, Visible Emissions ma y be determined by either a person certified pursuant to Method 22 or by a video camera.

c. Flame Presence . Except for periods of Malfunc tion of the Flare, BPP shall operate each Covered Flare with a flame present at all times. BPP shall m onitor the presence of the pilot flame using a thermocouple or any other e quivalent 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 Flar e with an Exit Velocity less than 18.3 m/sec (60 ft/sec) on a one-hour block av erage; provided however, that:

i. If any Covered Flare combusts Vent Gas with a Net Heating Value of greater than 1000 BTU/scf, BP P 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 (V max ), BPP may operate the Covered Flare w ith an Exit Velocity less than V max provided that it also operates th e applicable Flare with an Exit Velocity of less than 122 m/s ec (400 ft/sec) on a one-hour block average.
V max 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 cons istent 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 sha ll implement good air pollution control practices to minimize emissions from each Covered Flare; provided however, that BPP shall not be in violation of th is 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 utiliz ing the instrumentation and cont rols 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 Supplem ental 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 Pr actice 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 re quirements 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 Malfunc tion 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, ope ration and maintenance of the Covered Flare in conformance with its design conflicts with complia nce with one or more of the requirements of this Appendix.

33. Net Heating Value Standards for each Covered Flare

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a. NHV vg . Beginning on the Date of Entry a nd 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 NHV vg are modified, BPP shall opera te each Covered Flare with
an NHV vg of greater than or equal to 300 BTU/scf on a three-hour ro lling average basis, rolled every fifteen minutes, except as provided in Paragraph 51.

b. NHV cz-limit . By no later than December 31, 2014, for all Covered Flares, and except as provided in Paragr aph 51, BPP shall calculate an NHV cz-limit at each Covered Flare no less than every fifteen minutes. Except as pr ovided in Paragraph 51, BPP shall operate each Covered Flare so as to ensu re that the Covered Flare’s NHV cz , on a three-hour rolling average basis, rolled every fifteen minutes, is greater than or equal to its NHV cz-limit on a three-hour rolling average basis, rolled every fifteen minutes. B PP 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 requireme nts of Subparagraph 34.a, BPP is not subject to the emissions standard in th at 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 Do minated 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-annua l report due after the applicable compliance date, BPP shall identif y which compliance option it selects for each Covered Flare. BPP may select different alternatives for di fferent 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 Disconti nuous Wake Dominated Flow

. i. BPP shall not operate the C overed Flares with Discontinuous Wake Dominated Flow, except for periods not to exceed a total of

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five minutes during any two cons ecutive 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 opera tors 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 Fl ow. After the effective date, operators shall monitor the operation of each Covered Flare at intervals appropriate fo r the weather conditions and service of the Covered Flare in order to co mply 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 co rrelated 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 a nd c., BPP shall not be required to add Supplemental Gas at any time that the wind speed at the Refinery is gr eater 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 Covere d Flare with a minimum of a 98% Combustion Efficiency at all times when Waste Gases ar e 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 Covere d Flare when the only gas or gase s 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 asso ciated 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 a nd Flare Combustion Efficiency, BPP shall conduct Passive FTIR testing on the DDU and th e 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 Prot ocol in accordance with the ge neral 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 mo nths 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 te sting 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 NHV cz , affects Combustion Efficiency;

c. A detailed description of the range of the NHV cz 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 NHV cz-limit at which BPP proposes to operate the Covered Flare in order to achieve a Combusti on 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 th e report impact the “A” Combustion Efficiency Multiplier for calculating the NHV cz-limit at the six Covered Flares that will not be subjectto 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 NHV cz-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 lim its 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” Com bustion Efficiency Multiplier for calculating the NHV cz-limit at the six Covered Flares that will not be subject to Passive FTIR testing. Disputes arising under this Paragraph sh all 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 reco rding 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. NHV vg (in BTU/scf)

v. NHV cz (in BTU/scf)

vi. NHV cz-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 operat es 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 correc tive 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, incl uding the date, time, duration, reason for the override, and corrective actions th at BPP took; and (ii) where th e reason for the override was to stop Smoke Emissions that were occurring, BPP sha ll include a copy of the digital video record (with a time stamp) of the Covered Flar e 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 reco rd the duration of the deviation, an explanation of the cause(s) of the deviation, and a description of the corrective acti on(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 sh all 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: Inst rumentation 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. Th e 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 on e 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 fi rst semi-annual report due af ter the installation of the flow meter required pursuant to Subpara graph 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 volume tric flow of Waste Gas, in scfm, on a 30-day rolling average, and the mass flow rate, in pound s per hour, on a 30-day rolling average, vented to the LPG Flare; (ii) the Prevention Measures implemented for the repor ting period; and (iii) the Prevention Measures expected to be implemented in the future, together with a schedule for prompt implementation.

44. Emission Standards Appli cable 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 Velocit y, 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 ṁ air-asst / ṁ air-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 th at EPA sets a new limit

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pursuant to either Subparagraph 48.d or 49.b; or (ii) the termin ation of this Consent Decree, whichever is applicable, BPP shall operate the LPG Flare so as to ensure that ṁ air-asst < 10 x ṁ

air-stoich-vg , on a one-hour rolling average, rolled ev ery five minutes. BPP shall utilize the equations and directives set forth in Appendi x 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 exceptio n in Paragraph 51 applies a nd/or in order to (1) stop Smoke Emissions that are occurring, (2) pr event extinguishing the Flare, (3) protect personnel safety, and /or (4) prev ent 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 complia nce 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 sha ll 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 20 15, BPP shall use the Vent Gas Flow Rate data gathered in 2015. All fl ows shall be included.

48. Testing Depending on Annual Average Vent Gas Volumetric Flow Rate to the LPG Flare: Consequences if the Annual Aver age 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 oz one standard at the en d 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 th e end of calendar year 2015), the n, 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 Efficien cy Test Protocol in accordance with the general requi rements in Appendix FLR-16. BPP shall complete the testing on the LPG Flare within 30 da ys 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 te sting that include minute by minute electronic data in Excel format for all measurements and process data and is consistent with th e 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 ṁ air-asst / ṁ air-stoich-vg affects Combustion Efficiency;

iii. A detailed description of the range of the ṁ air-asst / ṁ air-stoich-vg , that the Covered Flares must be opera ted at to ensure 98% Combustion Efficiency or as high an efficien cy as reliably obtainable, taking into consideration variability in Vent Gas flow rate.

iv. The maximum ṁ air-asst / ṁ air-stoich-vg at which BPP proposes to operate the LPG Flare in order to achieve a Combustion Efficiency as high as reliabl y obtainable; and

v. A proposed Combustion Efficiency applicable to the LPG Flare that is as high as reliably obtainable.

c. Compliance with Proposed Operat ing Limits in Passive FTIR Report

. Unless and until EPA establishes different lim its under Subparagraph 48.d, BPP shall comply with the operating limits that it propo ses pursuant to Subparagraph 48.b.iv.

d. EPA-Established Operating Limits and Combustion Efficiency . Based on all of the available information from the testi ng conducted pursuant to Subparagraph 48.a and the report submitted pursuant to Subparagraph 48.b, EPA shall establish a ṁ air-asst / ṁ air-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 receivi ng written notice establishing such limits, BPP shall comply with the ṁ air-asst / ṁ air-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-attain ment for the eight-hour ozone

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standard at the end of calendar year 2015) or 70 scfm (if the Whiti ng Refinery is located in an area designated as a ttainment for the eight-hour ozone standa rd at the end of calendar year 2015), then for the duration of the Cons ent 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 annu al 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 requirem ents set forth in Subparagraphs 48.a – 48.c by no later than September 30 of the applicable year. EPA thereafter will establish a ṁ

air-asst / ṁ air-stoich-vg and Combustion Efficiency pursuant to Subparagraph 48.d

c. Reporting . If as a result of an annual re view 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 a nnual review in the first semi-annua l 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 la ter 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 Paragr aph, BPP is require d to undertake Passive FTIR Testing, then commencing within 90 days after submitting its Passive FTIR Report, BPP shall comply with all applicable recordkeeping re quirements of Paragraph 41, but “Assist Air” or “ ṁ air-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 pr actices 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 re sults from downtime of instrume nts or equipment due to the following:

a. Malfunction of an instrument, fo r 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 re quirements of Subsection I.

53. Dates of Applicability of the Requirements in Subsection I. The requirements of Subsection I shall apply to Repor table 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 Reportabl e Flaring Incident st arted and ended. To the extent that the Reportable Flaring Incident involved multiple releases either within a twenty-four (24) hour period or within subseque nt, contiguous, non-overla pping twenty-four (24) hour periods, BPP shall set forth the starting and ending dates and tim es of each release;

b. An estimate of the volume of gase s flared (or combusted, for Tail Gas Incidents – Trigger 2) , the quantity of SO 2 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 flar ed or combusted, and the quantity of SO 2 and VOC

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emissions associated therewith;

d. A detailed analysis that sets forth the Root Caus e, including all contributing causes, of the Reportable Flari ng 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 reasonab le alternatives, if any, that are available, and the proba ble effectiveness and cost of th e 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 acti on(s) and, if not already completed, a schedule for its (their) implement ation, including proposed commencement and completion dates. If BPP concludes that correctiv e 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 Fl aring 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 th e end of a Reportable Flaring Incident and if BPP has not sought by that time an extens ion of time to complete the investigation, stipulated penalties for failing to timely complete the investigati on shall apply but BPP shall retain the right to dispute, under the dispute resolu tion provisions of this Consent Decree, any demand for stipulated pe nalties that was issued as a result of BPP’s failure to timely complete the investigation. Nothing in this S ubparagraph shall be deemed to excuse BPP from its investigation, reporting, record keeping, and corrective action oblig ations of this Subsection H for any Reportable Flaring Incident that occurs af ter 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 afte r the end of a Reportable Flaring Incident, then BPP will include in each semi-annual report due unde r Part VIII of this De cree, 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 s tipulated 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 Subparagr aph -- 63.a or 63.b -- applies and w hy; 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 th e 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 natu re of settlement at the time that it submits the semi-annual report,
see Paragraph 57, that includes th e report completed under this Pa ragraph. 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, existe nce or strength of B PP’s potential defenses

55. Corrective Action Implementation

.

a. In response to any Reportable Flaring Incident, BPP shall take, as expeditiously as practicable, su ch interim and/or long-term co rrective actions, if any, as are consistent with good engineering practice to mini mize the likelihood of a r ecurrence of the Root Cause, including all contributing causes, of that Reportabl e 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 implemen ting regulations. Notwithstanding EPA’s review of any plans, reports, corrective actions or pro cedures 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 viola tions 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 correctiv e action or implementation sche dule 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 pr ovided 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 corr ective action and has purchased or entered into a binding contractual obligation (with adverse conseque nces from its breach) to purchase equipment necessary to implement the corrective action. Ho wever, BPP will be put on notice that such corrective action is deficient and not acceptabl e for remedying any subsequent, similar Root Cause(s) of any Reportable Flar ing Incident. If EPA and BP P cannot agree on the appropriate corrective action(s) or implement ation 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 nece ssary 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 Para graphs 54 and 55 for Certain HC Flaring Incidents . The requirements of Paragraphs 54 an d 55 shall not apply to the following Hydrocarbon Flar ing 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 commi ssioned), 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 su ch cases, BPP may rely upon and cross-reference the prior analysis.

57. Submitting the Internal Flaring In cident Reports to EPA and IDEM . In each semi-annual report due under Part VIII of this Co nsent Decree, BPP shall include copies of each Reportable Flaring Incident re port that BPP was required to prepare in compliance with Paragraph 54 during the six mont h period that the semi-annual repo rt covers. Each semi-annual report also shall include summary of each of the Incidents including the following:

a. Date;

b. Duration;

c. Amount of SO 2 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 identifi ed by BPP in terms of the number of Incidents, the Root Causes, or the types of Corrective Action

58. Calculating SO 2 Emissions . The equations for calculating sulfur dioxide emissions from Reportable Flaring Incide nts are set forth in Appendix FLR-18.

59. Reserved.

J. Stipulated Penalties for Acid Gas Fl aring 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 prov isions of Subsection I, includi ng Root Cause Analysis, internal reporting, recordkeeping, and corrective action, may subject BPP to stipulated penalties regardless of whether the type of Reportable Fl aring Incident was an Acid Gas, Tail Gas or Hydrocarbon Flaring Incident. Stipulated penalties for those othe r potential viol ations 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 sulf ur 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 du e 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 pr ovided 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 SO 2 at a rate greater than twenty (20.0) pounds per hour continuously for three (3) consec utive hours or more and BPP failed to take any action during the Acid Gas Flaring Incident to limit the duration and/or quantity of SO 2 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 Incide nt that occurred since the Date of Entry, then:

i. If the Root Cause of the Acid Ga s Flaring or Tail Gas Incident was sudden, infrequent, and not reason ably preventable through the exercise of good engineering practi ce, then that cause shall be designated as an agreed-upon Malfunction for purposes of

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reviewing subsequent Acid Gas Flar ing 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 prev entable through the exercise of good engineering practice, then BPP shall implement corrective action(s) pursuant to Paragra ph 55, but the stipulated penalty provisions of Paragraph 66 shall not apply.

b. Recurrence : If the Root Cause is a recurre nce 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 Inci dent resulted from a Malfunction or other defense that BPP successively asserts; or

ii. The Root Cause previously wa s 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 ev ents, 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 Incident s under Paragraphs 62 - 63, BPP may assert a Malfunction or Force Majeure defense. In a ddition, in any dispute under Paragraphs 62 and 63, BPP may also assert a Startup an d/or Shutdown defense, but the Un ited States shall be entitled to assert that such defens es 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 pr ovisions 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 wh ich would otherwise be subject to stipulated penalties. EPA’s decision shall not be subject to dispute resolution. Once rein stated, 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 calcu late stipulated penalti es that become due under Paragraphs 61 - 64:

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Tons of SO 2 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 sh all 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 SO 2 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 occu rs 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 exampl e, for Acid Gas Flaring within an Acid Gas Flaring Incident that (i) starts at 1:00 p.m. on Day 1 and e nds 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, th e AG Flaring within the AG Flaring Incident shall be deemed to last 12.5 hours – not 1.5 hours – and the column fo r Acid Gas Flaring of “greater than 3 hours but less than or equal to 24 hours” shall apply.

K. Miscellaneous

67. Temporary-Use Flares

.

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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 sha ll 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 da ys in advance or is unscheduled.

c. 504 hours or less . For any planned or unpl anned 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 ma ke good faith efforts to ensure that the Temporary-Use Flare that replaces the Covered Fl are complies with all of the requirements of this Consent Decree that are applicable to th e 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 w ith all of the requirements of this Appendix related to the Cove red 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 anti cipate will last longer than 504 hours, BPP shall ensure that the Temporary-Use flare complies with all of the requirem ents 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 Para graph any time it uses a Temporary-Use flare.

68. Miscellaneous . Whenever this Appendix requir es 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 exam ple, if compliance is required by no later than three mont hs after the submission of a pa rticular 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 “a ffected facility” within the m eaning of Subparts A and J of 40

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C.F.R. Part 60, will be subject to Subparts A an d J, and will comply with the requirements of Subparts A and J, including all monito ring, 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. Pa rt 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, recordk eeping, reporting, and ope rating 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 requ irements of Subparts A and J, including all monitoring, recordkeeping, reporti ng, 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 al l monitoring, recordkeepi ng, 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 eff ect. 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 operati ng requirements, by the later of: (i) the date by which that Flare is required to be tied into a FGRS unde r 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 fac ility” as set forth in Subpara graph 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 in itial 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 Downti me, Override of Automatic Control System, and Emissions Exceedances . On and after the date of a pplicability of any work practice or standard, BPP shall provide a summary of th e 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/equi pment 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 th e instrument/equipment monitors is available for operation;

b. Monitoring Instrument/Equipment Downtime . If the total number of hours of downtime of any monitori ng instrument/equipment required pu rsuant to Paragraphs 7-9, 11-13 (and, if applicable, Paragraph 42), ex ceeds 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 Pa ragraph 30 (and, if applicable, Paragraph 42), expressed as both an absolute nu mber 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 Pa ragraph 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 a ny 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 Fl are 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 st andards 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 ava ilable 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 Paragr aph 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 identificat ion of each averaging pe riod 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 D ecree by August 15 of each year, BPP shall provide, for each Covered Flare and the LPG Flare, for th e prior calendar year, the amount of emissions of the following compounds (in tons per year): VOCs, SO 2 , H 2 S, CO 2 , methane, and ethane.

44

## App end ix 

## FL R
- 1
T

y

pe I Type ][

Up per S team

C enter S t eam S tabi l ity R "'Il E xit Lowe r S tea m / Ai r M " tu r e



### = V e nt G as



### = 

### F ire

= St eam l Air



### = Ste am K ey Y ellow R ed Light Blue D ark Blu e Lo wer St eam Cent er S team • Upper St eam Sta bi l ity T a b

Sta bi lity T a b 

### T yp e 1:: B Pilo t

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APPENDIX FLR-2

GENERAL EQUATIONS Equation 1: “ Combustion Efficiency ” or “ CE ”:
CE = [CO 2 ]/([CO 2 ] + [CO] + [OC])

where:
[CO 2 ] = Concentration in volume percen t or ppm-meters of carbon dioxide in the combusted gas immediat ely above the Combustion Zone
[CO] = Concentration in volume pe rcent 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 immediatel y above the Combustion Zone, counting each carbon molecule separately where the concentration of ea ch 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 CO 2 , CO, and OC must be the same; that is, if “volume percent” is us ed 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 “ ṁ s-cen ” :
ṁ

s-cen = Q s-cen x (18/385.5)

where:
Q s-cen = Center Steam Volumetric Flow Rate

Equation 3: “Total Steam Mass Flow Rate” or “ ṁ s ”:
ṁ

s = Q s x (18/385.5)

where:
Q s Total Steam Volumetric Flow Ratecase 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 215 of 325 document 7-1 filed 09/18/12 page 214 of 324

Equation 4: “Vent Gas Mass Flow Rate” or “ ṁ vg ”:
ṁ

vg = Q vg x ( MW vg /385.5)

where:
Q vg = Vent Gas Volumetric Flow Rate

MW vg = 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)case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 216 of 325 document 7-1 filed 09/18/12 page 215 of 324

APPENDIX FLR-3

CALCULATING NHV cz-limit AND NHV cz 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 Abbrev iations”) of this Appendix. Steps in the Calculations
Step 1: Determine the Low er 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 us es 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 infi nite lower flammability limit (e.g. LFL N2 = ∞ ).

1

ൌ ௩௚ ܮܨܮ ௡ ݔ ௜ Equation 1 ∑ ቀ ቁ ௜ ܨܮܮ ௜ ୀଵ

Step 3: Determine the Net Heat ing Value of the Vent Gas (NHV vg ) 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 hea ting 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 NHV vg and adjust the concentration of the compounds measured by the GC to a wet basis. Indivi dual compound net heating va lues, including water, are listed in Table 1 of this Appendix.

௡ ܸܪ ·ܰ ݔ ሺ ൌ ෍ ௩௚ ܰܪܸ ௜ ௜ 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/sc f) and an “adjusted” NHV of hydrogen (1212 BTU/scf). Companies have the option of us ing either in calculating NHV vg ; however, whichever option is selected also must be used in calculating NHV cz .

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Step 4: Calculate the NHV vg at its LFL (NHV vg-LFL ) Using LFL vg from Equation 1 and NHV vg from Equation 2, the NHV vg-LFL is calculated by Equation 3.

௩௚– ܰܪܸ ௅ ܨܮ ·ܮ ௩௚ ܸܪ ൌ ܰ ி௅ ௩௚ Equation 3

Step 5: Multiply NHV vg-LFL by the Combustion Efficiency Multipliers to calculate the NHV cz-limit The Net Heating Value of the Gases in the Combustion Zone (NHV cz ) of a Flare that is needed to ensure an acceptable Combustion Efficien cy is determined by multiplying NHV vg-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:

௩௚ି௅ி௅ ܸܪ ൯·ܰ ௣௢௥௣௬௟௘௡௘ ൅ ܤ·ݔ ܣ ൌ ൫ ௖௭ି௟௜௠௜௧ ܰܪܸ Equation 4

Step 6: Calculate the Net Heating Va lue of the Combustion Zone Gas (NHV cz )
The NHV in the combustion zone (NHV cz ) 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 e quations 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 ݎ݋ ܳ m vg zero. Vent Gas flow rate ( ሶ ( are calculated from on-line ݏ ݎ݋ ܳ m s ሶ ) is constant for each flare and set by an ݌݃ ݎ݋ ܳ flow meters. The pilot gas mass flow rate ( mሶ pg orifice.

௣௚ ௩௚ ݉

ሶ ܯܹ ൬ ൅ ൰ ܯܹ ൬

௩௚ ௣௚ ௩௚ ܸܪ ·ܰ ௩௚ ݉

ሶ

௚௩ ܹܯ
݉

ሶ ௚௣ ܰ ·ܪܸ ௚௣ ݉

ሶ

௚௣ ܯܹ ൬ ൰ ൅ ൬ ൰

݉

ሶ ൌ ௖௭ ܰܪܸ Equation 5a ௔௜௥ ܯܹ ቀ ൅ ൰
௔௜௥

ሻ Equation 5b ൰ ൅ ൬ ቁ ௦ ݉

ሶ
ை

మ ு ܹܯ

OR

௚௣ ܸכܪ ܰ ௣௚ ܳ ൯൅ሺ ௩௚ ܸܪܰ כ ௩௚ ൫ܳ

ൌ ௖௭ ܰܪܸ ௔௜௥ ൅ ܳ ௦ ൅ ܳ ௣௚ ൅ ܳ ௩௚ ܳ

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The values for ሶ , Q s , and Q air are determined as follows based on the type of flare: ௔௜௥ ݉ , ௦ ݉

ሶ Steam-Assisted Flare without a Minimum Steam Reduction System (“MSRS”)
݁ ݑ ݈ܽ ݒ ݎ݀݁ ݑ ܽ݁ݏ ݉ ൌ ܳ ݎ݋ ௦ ݉

ሶ ݏ ܳ ݎ݋ ௥௜௔ ݉

ሶ
Steam-Assisted Flare with MSRS

௦ ݉

ሶ

௔௜௥ ݉

ሶ 0 ൌ ݎܽ݅
ܳ ݎ݋ ݎ ݑ ܽ݁ݏ ݉ ൌ ݁ ݑ ݈ܽ ݒ ݀݁ ݏ ܳ ݎ݋ ݎܽ݅ 6ܽ ݌݁ݐܵ ݅݊ 13 ݊݋݅ݐܽݑݍܧ ݉݋ݎ݂ ݐ݈ݑݏ݁ ݎ ൌ
OR

௔௜௥ ݉

ሶ not capable ሺeven at minimum ven t gas flowሻ of inspirating more than twice the stoichiometric volume of air into the vent gas. The molecular weight of the vent gas (MW vg ) is calculated from the GC data using Equation 6. An on-line ultrasonic flow meter ma y also be used to calculate MW vg . molecular weights are listed in Table 1 of this Appendix. Individual compound

௡

௩௚ ܯܹ ൌ ෍

௜ୀ ଵ ሺ ݔ ௜ ௜ ܹ · ܯ ሻ Equation 6

The NHV of the pilot gas (NHV pg ) and MW of the pilot gas (MW pg ) are calculated using Equations 7 and 8, respectively. These calculations are similar to the vent gas calculations, except the individual com pound 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 s upplier’s laboratory certif icate of analysis.

௡

௚௣ ܸܪܰ ݎ݋ ܳ ܽ݅ݎ ൌ 0 with vendor certification that t he MSRS equipment installed on the flare is

Equation 7 ሻ ௜ ܸܪ · ܰ ௜ ݌݃ ሺ ൌ ෍

௜ୀଵ

௡
௜ ݃݌ ሺ
௜ୀଵ

Step 6a: Calculation of air mass flow rate for flares equipped with MSRS. The complete combustion of an organic com pound comprised of a combination of carbon and hydrogen atoms is shown in Equation 9: ൌ ෍ ௚௣ ܯܹ ௜ ܹ · ܯ ሻ Equation 8

ݕ ݕ Equation 9 ܱ ଶ ܪ ቁቀ ൅ ଶ ܱ ܥ ՜ ݔ ଶ ܱ ቁ ݔ ൅ ቀ ൅ ௬ ܪ 4 2 ௫ ܥ

Note: x and y values for each compound are f ound in Table 1 of this Appendix.

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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):

௩௚ ݉

ሶ ݊ ሶ ቀ ݔ ൅ ݕ 4 ቁ Equation 10a ைଶି௦௧௢௜௖௛ ൌ ݔ ௝ ቆ

௚ ௩ ܯܹ ቇ

ܱܴ

௩௚ ܳ ൰ ቀݔ ൅ ݕ 4 ቁ Equation 10b ൬ ௝ ൌ ݔ ைଶି௦௧௢௜௖௛ ݊ 385.5 The stoichiometric oxygen mass flow rate for th e 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).

௡ כ෍

మ ை ܹ ൌ ܯ ைଶି௦௧௢௜௖௛ି௩௚ ݉

ሶ ௝ୀଵ

௡ Equation 11a ೕ ைଶି௦௧௢௜௖௛ ݊ ሶ

ܱܴ

כ ൌ 385.5 ைଶି௦௧௢௜௖௛ି௩௚ ܳ ೕ ைଶି௦௧௢௜௖௛ ݊ ሶ ௝ୀଵ
The stoichiometric air mass flow ra te (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 ൌ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ݉

ሶ ሶ ைଶି௦௧௢௜௖௛ି௩௚ כ ݉
మ ை ܹܯ ·

ܱܴ
ܳ ݃ݒ݃ݒ

െ݄݅ܿ݋ݐݏെܱ2 Equation 12a

Equation 12b ൌ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ܳ 0.21
The air mass flow (lb/hour) or ai r volumetric flow (scfh) used in Equation 5a or 5b is given by subtracting two times the stoichiometric air fr om the total air provided by the MSRS. This is shown in Equation 13.

ሶ ݉

ሶ ௔௜௥ି௦௧௢௜௖௛ି௩௚ 2כ݉ െ ሺ ௔௜௥ିெௌோௌ ௔௜௥ ൌ ݉ ሶ ሻ Equation 13a

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ܱܴ

௥௜௔ି௦௧௢௜௖௛ି௩௚ 2כܳ െ ሺ ௔௜௥ିெௌோௌ ൌ ܳ ௔௜௥ ܳ ሻ Equation 13b

The equation for is specific to the MSRS inst alled and must be provided ௔௜௥ିெௌோௌ ܳ or ௔௜௥ିெௌோௌ ݉

ሶ by the MSRS vendor. The factor of 2 used in Equation 13 is based on the best information available as of the Date of L odging. If new information becomes available thereafte r, the parties may modify that factor; any such modification does not constitute a material modification to the Consent Decree.

ൌ 0 ௔௜௥ ݉

ሶ then ൏ 0 ௔௜௥ ݉

ሶ

ൌ 0 ௥௜௔ ݄ܳ݊݁ ݐ ൏0 ௔௜௥ ܳ If If OR

Step 7: Ensure that during flare operation, NHV cz ≥ NHV cz-limit The flare must be operated to ensure that NHV cz is equal to or above NHV cz-limit to ensure an acceptable combustion efficiency. E quation 14 shows this relationship.

௖ ௭ି௟௜௠௜௧ ܸܪ ൒ ܰ ௖௭ ܰܪܸ Equation 14

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Key to the Abbreviations:

ݎܽ݅ ݊݅ ݕݔ݋݁݊݃ ݋݂ ݊݋݅ݐܽܿݎ݂ ݈݁݉݋ 0.21 ሻ ݎܽ݅ ݈݉݋

– ݈ܾ ⁄ ଶ ݈݉݋ܱ

– ݈ܾ ሺ0.21 ݈݋݉‐݈ܾ ⁄ ݂ܿ ݏ 385.5 ሺ ܾ݅ܿݑܿ ݐ݂݁݁ ݀ݎܽ݊݀ܽݐݏ ݏ݈݁݋݉ ݋ݐ ݊݀ݑ݋݌ ݉݋ݎ݂ ݊ܿ݋݊݋݅ݏݎ݁ݒ ൌ 385.5 ሻ ݏݏ݈݁ݐ݊݅ݑሺ ௅ி௅ି௚௩ ܸܪܰ ݎ݋݂ ݌݅ݐ݈ݑ݉ ݎ݅݁ ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݈݈ܽݎ݁ݒ݋ ൌ ܣ ሻ ݈ ݈ ሻ ݏݏ݈݁ݐ݊݅ݑሺ ௅ி௅ି௚௩ ܸܪܰ ݎ݋݂ ݌݅ݐ݈ݑ݉ ݎ݅݁ ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݈݁݊݁ݕ݌݋ݎ݌ ൌ ܤ ሻ% ݈ ݋ݒሺ ݐ݁݊ݒ ݏ݃ܽ ݄݁ ݐ ݅݊ ܱܸܥ ݋݂ ݊݋݅ݐܽݎݐܿ݁݊ ܿ݋݊ ൌ ௚௩ ܥ ሻ ݏݏ ݈݁ݐ݊݅ݑሺ 1 ݅݊ ܾ݈ܶܽ݁ ݅ ݉݊ݑ݈݋ܿ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݅ ሻ ݏݏ ݈݁ݐ݊݅ݑ ሺ 1 ܾ݈ܶܽ݁ ݅݊ ݆ ݉݊ݑ݈݋ܿ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݆ ሻ ݏݏ݈݁ݐ݊݅ݑሺ ݊݁݋ݖ ݊݋ ݅ݐݏݑܾ݉݋ܿ ݄݁ݐ ݋݂ ݐ݊݁݊݋݌݉݋ܿ ݏݑ݋݁ݏ݃ܽ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݇ % ݋ݒ݈ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݂݋ ݐ݈݅݉݅ ݕݐ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݈ݎ݁ݓ݋ ൌ ௜ ܮܨܮ ሻ ሺ ሻ % ݋ݒ݈ ሺ ݏ݃ܽ ݐ݈݅݉݅ ݂݋ ݐ݁݊ݒ ݕݐ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݎ݁ݓ݋ ݈ ൌ ௚௩ ܮܨܮ ሻ ݎ/݄ ݈ܾሺ ݎܽ݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௔௜௥ ݉ ݁ݐܽݎ ݂݋ ݏݏ݉ܽ ݓ݋݂݈ ݈ܽݐ݋ ൌݐ ெௌோௌି ௔௜௥ ݉

ሶ ݏ݄݅ܿ݋ݐ݉݅݋݅ݎݐܿ݁ ൌ ௚ ௩ି௢௜௖௛௦௧ି௔௜௥ ሶ ݈ܾݎ/݄ ܽ݊ ܴܵܵܯ ݀݁ݕܾ ሺ ܿݑ݀݋ݎݐ݅݊ ܽݎ݅ ሻ ݄ݎ ݈ܾሺ/ ݏ݃ܽ ݐ݁݊ ݒ ݄݁ ݐ ݎ݋݂ ݓ݋݂݈ ݎܽ݅ ሻ
݉

ሶ
݁ ݊݋ݖ ݏݑ݊݋݅ݐ ܾ݉ ݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௞ ݉

ሶ ݎ/݄ ݈ܾሺ ݉݋ܿ݋݌ݐ݊݁݊ ݏ݃ܽ ሻ ݎ݄ ݈ܾ ሺ ݎ݋݂ ݄݁ݐ ݐ݁݊ݒ ݏ݃ܽ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݅ܿݎ ݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௚ ௩ି௢௜௖௛௦௧ିைଶ ⁄ ሻ
݉

ሶ

ሶ ሻ ݎ/݄ ݈ܾሺ ݐ݋݈݅݌ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௣௚ ݉ ݎ/݄ ݈ܾሺ ݁ܽ݉ݐݏ ݈ܽݐ݋ݐ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௦ ݉

ሶ ሻ ݎ/݄ ݈ܾሺ ݐ݁݊ݒ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௚௩ ݉

ሶ ݄ ݈ ܿ݅ ݎݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௢௜௖௛ ௦௧ିைଶ ݊ ሶ ݎ ⁄ ݋݉ሺ ݌݉݋ܿݑ݋݊݀ ݈ܽݑ݅݀ݒ݅݊݀݅ ݎ݋݂ ܽ݊ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ሻ ݈݋݉

– /݈ܾ ݈ܾ 18.02ሺ ݎ݁ݐܽݓ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ை మ ு ܹܯ ሻ ሻ ሻ ݈݋݉

– /݈ܾ ݈ܾሺ ݌݉݋ܿݑ݋݊݀ ݈ܽݑ݅݀ݒ݅݊݀݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௜ ܹܯ ݉݋݈

– ܾ݈ ܾ/ ݈ሺ ݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ ௞ ܹܯ ሻ ݈݋݉

– /݈ܾ ݈ܾ 32.0ሺ ݃݁݊ݕݔ݋ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ మ ை ܹܯ 28.9ሺ/ ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݈݁ܿ݉݋ݎ݈ܽݑ ൌ ௔௜௥ ܹܯ ݈ܾሺ ݏ݃ܽ ݐ ݋݈݅݌ ሻ

ܾ݈ ሻ ݈݉݋

– ݈ܾ ݋݂ ݐ݄݁݅݃ݓ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௣௚ ܹܯ ሻ ݈ ݉
– /݈ܾ ݋ ሻ ݈݋݉

– /݈ܾ ݈ܾሺ ݐ݁݊ݒ ݏ݃ܽ ݐ݄݁݅݃ݓ ݂݋ ݈ݎܽ ݉ݑ݈݁ܿ݋ ൌ ௚ ௩ ܹܯ ሻ ݏݏ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݂݋ ݐݏ݈݅ ݏ ൌ ݊ ⁄ ݁ ݊݋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 ൌ ௅ ி௅ି௚௩ ܸܪܰ ݊ ܷܶܤሺ ሻ ݂ܿݏ
ݏ ⁄ ܷܶܤሺ ሻ ݂ܿ
݊ ⁄ ሻ ݂ܿ ⁄ ܷܶܤሺ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݁ݑ݈ܽݒ ݂݋ ݄݁ݐ ݅݊݃ݐ݄݁ܽ ݐ݊݁ ݈ݐ݅݉݅ ൌ ௧௟௜௠௜ି௭௖ ܸܪܰ ሻ ݂ܿ ݏ ⁄ ܷܶܤሺ ݏ݃ܽ ݐ݋݈݅݌ ݋݂ ݁ݑ݈ܽݒ ݅݊݃ݐ݄݁ܽ ݊ݐ݁ ൌ ௣௚ ܸܪܰ ሻ ݂ܿݏ ሻ ݂ܿ ݏ ⁄ ܷܶܤሺ ݂݋ ݑܾ݉݋ܿ ݁ݎݑݏݏ݁ݎ݌ ൌ ௭௖ ܲ ሻ ݅ݏ݌ 14.696ሺ ݏ݊݋݅ݐ݀ ݋ܿ ݀ݎܽ݊݀ܽݐݏ ݐܽ ݁ݎݑݏݏ݁ݎ݌ ݐܾ݉݁݊ ܽ ൌ ௦௧ௗ ܲ ݊ ݏ݃ܽ ݁ݑ݈ܽݒ ݂݋ ݐ݁݊ݒ ݅݊݃ݐ݄݁ܽ ݊ݐ݁ ൌ ௚ ௩ ܸܪܰ ሻ ݅ܽݏ݌ሺ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐ ݏ ሻ ݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݏ݃ܽ ݅݊ ݐ݋݈݅݌ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ௜ ݃݌ ሻ ݂݄ ܿ ݏሺ ܽ݊ ܴܵܵܯ ݕܾ ܿ݁݀ ݑ ݎܽ݅ ݀݋ݎݐ݅݊ ݂݋ ݎ݁ݐܽ ݓ݋݂݈ ݎݐ݉݁ݑ݈݋ܿ݅ ݒ ݐ݋݈ܽ ൌݐ ெௌோௌି௔௜௥ ܳ ݂݄ܿݏሻሺ ݏ݃ܽ ݐ݁݊ݒ ݄݁ݐ ݋݂ ݓ ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎܽ݅ ݅ܿݎ ݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௚ ௩ି௢௜௖௛௦௧ି௔௜௥ ܳ ݎ ሻ ݂݄ܿ ݏሺ ݁ݐܽݎ ݓ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ݒ ݐ݊݁݊݋݌݉݋ܿ ݐ݁݊ݒ ݏ݃ܽ ݈݅݀ܽݒ݅݊݀݅ ൌ ௞ ܳ ݎ/݄ ଷ ݐ݂ሺ ݁ݐܽݎ ݓ݋݂݈ ܿ݅ ݎݐ݉݁ݑ݈݋ݒ ݐ݊ ݁ ݊݋݌݉݋ܿ ݐ݁݊ݒ ݏ݃ܽ ݈݅݀ܽݒ݅݊݀݅ ൌ ௙௖ ௔ ,௞ ܳ ைଶି௦௧௢௜௖௛ି௩௚ ܳ ሻ ݂݄ܿݏሺ ݏ݃ܽ ݐ݁݊ݒ ݄݁ݐ ݓ݋݂݈ ݎ݋݂ ݅ܿ ݎݐ݉݁ݑ݈݋ݒ ݃݁݊ݕݔ݋ ݅ܿ ݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ ሻ ݂݄ܿݏሻሺ ݁ݐܽݎ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݏ݃ܽ ݐ݁݊ ൌݒ ௚௩ ܳ ሻ ݂݄ܿݏ ሺ ݎ݁ݐܽ ݓ݋݂݈ ݎݐ݉݁ݑ݈݋ܿ݅ ݒ ݏ݃ܽ ݐ݋݈݅ ݌ ൌ ௚௣ ܳ ݂݄ܿݏ ݁ݐܽݎ ݓ݋݂݈ ݐ݉݁ݑ݈݋݅ܿݎ ݒ ݁ܽ݉ݐ ݏ ൌ ௦ ܳ ሻ ሺ

ൌ ௔௜௥ ܳ ݂݄ܿݏሺ ݁ݐܽݎ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎ݅ ܽ ሻ

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ݐݐ݂ 10.73ሺ ܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ ଷ ⁄ ݌ ·ݏ݅ ݏ݃ܽ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ܿ ݂݋ ܾ݈ ݉ െ ݋݈ ( ܴ · ݎݑݐܽݎ݁ ݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௭௖ ܶ ݑݐܽݎ݁݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௦௧ௗ ܶ ݂݋ ݈݁݋݉ ݎ݁݌ ݊݋ܾݎܿܽ ݂݋ ݈݁݋݉ ݁ ሺ°ܴ ሻ 528°ܴሺ ሻ ݏ݊݋݅ݐ݊݀݅݋ܿ ݀ݎܽ݊݀ܽݐݏ ݐܽ ݎ݁ ൌ ݔ ሻ ݈݋݉ ݈݋݉ / ݊݋݅ ݐܽܿݎ݂ ݈݋ݒሺ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݒሺ ሺ ௬ ܪ ௫ ܥ
ݔ ௜ ൌ ݀ ݌݉݋݊ܿݑ݋ ݈ܽݑ݅݀ݒ݅݊݀݅ ሻ
ݔ

௝ ൌ ݏ ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ܾ݈݅݁ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ሻ݊ ݅ ݐ ݋ ݂ݎܿܽ ݋݈
ݔ ௟௘௡௘ ௬௣௥௢௣ ൌ ݊݋݅ݐܽܿݎ݂ ݈݋ݒ ሺ ݏ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݈݁݊݁ݕ݌݋ݎ݌ ݂݋ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ ݒ ݈݋݉ / ݈݋݉ሺ ௬ ܪ ௫ ܥ ሻ ݎ݁݌ ݈݁݋݉ ݂݋ ݃݁݊݋ݎ݀ݕ ݄ ݂݋ ݏ݈݁݋݉ ൌ ݕ ሻ

FLR-3-7case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 223 of 325 document 7-1 filed 09/18/12 page 222 of 324

Table 1 Individual Compound Properties

I (1) j Compound NHV i (Btu/scf) MW i (lb/lbmol) LFL i (vol fraction) C x H y

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 CO 2 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+ (C 5 +) 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=orga nic compounds and hydrogen

2 If using an H 2 -adjusted NHV vg and NHV cz , 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 be nzene and 1,3 butadiene are present in the Vent Gas only in de minimis quantities. Because be nzene and 1,3 butadiene speciation are not required, they are not listed in Table 1of this Appendix. The Vent Gas co mposition 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-3-8case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 224 of 325 document 7-1 filed 09/18/12 page 223 of 324

Table 2 Combustion Efficiency Multipli ers 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 ≤ H 2 % ≤ 8 and Propylene% ≥ H 2 % (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 ava ilable thereafter, the parties may modify these conditions; any such modification does not consti tute a material modification to the Consent Decree.

The “VOC Vent Gas Concentration” shall be ca lculated on an annual average basis as follows:

௡ 100 16 Equation כ ௝ ෍ ൌݔ ௚௩ ܥ ௝ୀସ Note: The summation does not include methane or ethane.

FLR-3-9case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 225 of 325 document 7-1 filed 09/18/12 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 demo nstrates the equivalence of the two methods for calculating NHVcz. Equation 5b uses volumetric flow rates for the calculation of NHV cz :

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: ௚௣ ܸכܪ ܰ ௣௚ ܳ ൯൅ሺ ௩௚ ܸכܪ ܰ ௩௚ ൫ܳ

ൌ ௖௭ ܰܪܸ ௔௜௥ ൅ ܳ ௦ ൅ ܳ ௣௚ ൅ ܳ ௩௚ ܳ

௖௭ ܲ The ideal gas law provides a method for determin ing volumetric flow rate of a specific gas, k, in the combustion zone at standard conditions:

௦௧ௗ ܶ

, כ ௞ ௔௖௙ ൌ ܳ

௖௭ ܶ כ ௦௧ௗ ܲ ௞ ܳ

௖௭ ܴܶ ௞ ݉ ሶ

ൌ ௔௖௙ ௖௭ ܲ ௞ ܯܹ , ௞ ܳ

ൌ ௦௧ௗ ܶ ௖௭ ܲ ௖௭ ܴܶ

௖௭ ܶ כ ௦௧ௗ ܴܶ ௞ ݉

ሶ ௞ ݉ ሶ

௦௧ௗ ܲ

௞ ݉ ሶ ሶ

௞ ܹܯ 385.5

Substitution of this expression into Equation 5b gives NHV cz in terms of mass flow:

݉ ሶ ݉ ሶ ௩௚ ௣௚ ܹܯ 385.5 ൬ ܹܯ

௔௜௥ ݉ ሶ ௦ ݉ ሶ ௣௚ ሶ ௩௚ ݉ ሶ ௩௚ ௣௚
ܹܯ 385.5 ൅ ை మ ு ܹܯ ൅ 385.5 ݉ 385.5 ൅ ܹܯ ܹܯ ௚௩ ௚௣ ௥௜௔ כ ௞ ܹܯ ௦௧ௗ ܲ ൌ ௞ ܳ

௖௭ ܲ ௞ ܯܹ

528 כ 10. 73 כ ௞ ൌ 14 6 96

. ݉
ൌ ௞ ܳ כ ௞ ܹܯ

൰ ௚௣ ܸכܪ ܰ ൰ ൅ ൬385.5 ௩௚ ܸכܪ ܰ

ൌ ௖௭ ܰܪܸ

FLR-3-10case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 226 of 325 document 7-1 filed 09/18/12 page 225 of 324

௔௜௥ ݉ ௣௚ ௩௚ ݉ ൰൅൬ ܯܹ ቀ ൰ ൅

ைு ܯܹ ܯܹ ܯܹ ௩௚ ௚௣ మ ௔௜௥ ௚௣ ܰ ·ܪܸ ௚௣ ݉ ሶ

௚௣ ܹܯ

ሶ ௦ ൬ ൰

݉ ሶ ൰൅൬ ௩௚ ܸܪ ·ܰ ௩௚ ݉ ሶ

௚௩

ܹܯ

ሶ Equation 5a ൌ ௖௭ ܰܪܸ ݉ ሶ

Therefore demonstrating the equi valence of Equations 5a and 5b. ൬ ൰൅൬ ቁ

FLR-3-11APPENDIX FLR·4

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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 page 232 of 325 document 7-1 filed 09/18/12 page 231 of 324case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 233 of 325 document 7-1 filed 09/18/12 page 232 of 324

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 velo city of the wind. It is defined in Equation 1.

ߩ ௩௚ା௦,௖௘௡௧ · ݒ ௩௚ା௦,௖௘௡௧ ଶ 1 Equation ൌ ܴܨܯ ߩ ௥௜௔ ݒ · ௥௜௔ 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 th e air (wind). As the velocity of the wind increases, the MFR will decline for a gi ven 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 ( ρ i ) – Ambient Air, Vent Gas, and Center Steam -- is shown in Equation 2.

௜ ܹܯ

ൌ 10.73 · ௜ ܯܹ

ൌ ௔௕௦ ܶ ܴ · · ܲ · 14.73

ൌ 1.373 · 460 ൅ ௜ ܯܹ ߩ ௜ ሺ 460 ൅ ሻ ௜ ܶ ௜ ܶ Equation 2 From the final form of Equation 2, the density of Ambient Air ( ρ air ), Vent Gas ( ρ vg ), and Center Steam ( ρ s,cent ) can be calculated, shown in Equations 3, 4, and 5. The temperature of Center Steam and Ambient Air is measured. The temper ature of Ambient Air and Vent Gas is assumed to be equal.

ൌ 1.373 · ߩ ௜௔ ௥ 460 ൅ ௥௜௔ ܯܹ

௔௜௥ ܶ Equation 3
1.373 · ߩ ௩௚ ൌ ௩௚ ܹܯ 460 ൅ 1.373 · ௔௜௥ ܶ Equation 4

ை మ ு ܯܹ Equation 5 ௧ ௡௘௖௦, ܶ 460 ൅ ߩ ௦, ௖௘௡௧ ൌ

FLR-5-1ሶ 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 page 234 of 325 document 7-1 filed 09/18/12 page 233 of 324

The density of the Vent Gas plus Center Steam ( ρ vg+c,cent ) is calculated by combining the mass flow rates of the Vent Gas and Center Steam a nd dividing by the combined volumetric flow rates of the Vent Gas and Center Steam. This is shown in Equation 6.

ߩ ௩௚ା௦,௖௘௡ ൌ ௦, ൅ ݉ ௩௚ ݉ ௖௘௡௧

௖௦, ൅ ܳ ௩௚ ܳ ௘௡௧ ൌ ௦, ൅ ݉ ௩௚ ݉

௖௘௡௧ ௦, ݉ ൅ ௩௚ ݉ ߩ ,௦ ௖௘௡௧ Equation 6 ߩ ௩௚ ௖௘௡௧
Calculating Velocity The velocity of the Vent Gas plus Center Steam ( v vg+s,cent ) is calculated by Equation 7.

௧௡௘௖ ௦, ݉ ൅ ߩ ௦,௖௘௡௧ A ௧௜௣ି௨௡௢௕ ௩௚ ݉ ߩ ௦, ൅ ܳ ௩௚ ܳ ௖௘௡௧ ൌ ௩௚ ௧௜௣ି௨௡௢௕ ܣ ݒ ௩௚ା௦,௖௘௡௧ ൌ Equation 7

The wind velocity is measured directly.

Constants:

ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௔௜௥ ܹܯ ൬ 28.96 ݈ܾ ݈݋݈ܾ݉ ݈ܾ ൰

ݎ݁ݐܽݓ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ ை మ ு ܹܯ
݁ݎݑݏݏ݁ݎ݌ ݐܾܽ݉݅݁݊ ݁ݐݑ݈݋ݏܾܽ ൌ ܲ ൬ 18.02 ൰ ݈ܾ݉݋݈ ሻ ݏ݌݅ܽ 14.73 ሺ

ݐܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ ݅ݏ݌ 10.73 ቆ ݈݋݈ܾ݉ ݂ · ቇ °ܴ ଷ ݐ

·

Measured variables:

݈ܾ ൬ ݐܸ݁݊ ݏܽܩ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ ௚ ௩ ܹܯ ݈݈ܾ݋݉ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ,௦௡௘௖௧ ݉ ሶ ൰
݈ܾ ൬ ൰

݄ݎ ݈ܾ ൬ ݐܸ݁݊ ݏܽܩ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௚ ௩ ݉ ሶ ൰ ݎ݄ ሻ Ԭ ሺ ܶ Ԭ ሺ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ ݐ ݎ݅ܣ ݐܾ݉݅݁݊ܣ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉

௡௧௘ ௦,௖ ܶ

ݒ ௔௜௥ ൌ ௔௜௥ ൌ ݐ ൌ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉ ሻ ൬ ݐ݂

ݎ݄ ൰ ݅݊݀ݓ ݂݋ ܿ݋݈݁ݕݐ݅ ݒ

FLR-5-2case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 235 of 325 document 7-1 filed 09/18/12 page 234 of 324

Calculated variables:
ሺ ሻ ଶ ݐ݂ ݁ݎ݂݈ܽ ݌݅ݐ ݁ܽݎܽ ݂݋ ݏ݋݅ݐ݈ܽ݊݁ܿ

െ ݏݏ݋ݎܿ ݐݏܾ݋݊ݑݎ݁ݐܿݑ݀ ൌ ௕௢௡௨ି௜௣௧ ܣ ሻ ݊݅ݑݏݏ݈݁ݐ ሺ ݔݑ݂݈ ݋݅ݐܽݎ ݉ݑݐ݉݁݊݋݉ ൌ ܴܨܯ
ݐ ݈ܾ ݅ ݊݁ ݊݋݌݉݋ܿ ݐ݄݁݅݃ݓ ݂݋ ݈݁ܿ݉݋݈ܽݑݎ ൌ ௜ ܹܯ ൬ ൰ ݋݈ ݈ܾ݉ ݅ܽݎ ݋݂ ൬ ݈ܾ
ଷ ൰ ݐ݂ ߩ ௔௜௥ ݀ ൌ ݊݁ݏ݅ ݕݐ ݈ܾ ݐ݂ ൬ ܽܩݏ ݂݋ ݐܸ݁݊ ߩ ௚ ௩ ൌ ݀ݐ݅ݏ݁݊ ݕ ൰
ଷ ݈ܾ ݐ݂ ൬ ߩ ,௦ ൌ ݁ܽ݉ݐܵ ݂݋ ݁ݐ݁݊ܥݎ ݕ ݐ݅ݏ݁݊ ݀ ൰ ௧௖௘௡ ଷ ݈ܾ

ଷ ൰ ߩ ݀ ൌ

௜ ݊݁ݏ݅ ݕݐ ܿ݋݉݌݋݊݁݊ ݋݂ ݐ ݅ ൬ ݐ݂ ଷ ݐ݂ ݎ݄ ቇ

,௦ ܳ ௧௖௘௡ ݒ ൌ ቆ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥ ݁ݐܽݎ ݂݋ ݓ ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ݎ

ଷ ݐ݂ ݎ݄ ݐܸ݁݊ ݏܽܩ ݁ݐܽݎ ݂݋ ݓ ݋݂݈ ݉ݑ݈݋݅ܿݎݐ݁ ൌݒ ௚ ௩ ܳ ቆ ቇ
ሻ °ܴ ሺ ݁ݎݑݐܽݎ݁ ݌݁݉ݐ ܽݐݑ݈݋ݏܾ݁ ൌ ௦௔௕ ܶ

௜ ܶ ൌ ܨ°ሻሺ ݅ ݊݋݌݉݋ܿݐ݁݊ ݂݋ ݁ݎ ݑݐܽݎ݁݌݁݉ ݐ ݐ݂ ൬ ݐܸ݁݊ ݏܽܩ ݂݋ ܿ݋݈݁ݕݐ݅ ൰ ݎ݄ ݒ

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FLR-5-3App e nd ix F LR-6

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. "": rleS case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 237 of 325 document 7-1 filed 09/18/12 page 236 of 324

## DEPICTION OF GASES ASSOCIATED WITH STEAM-ASSISTED FLARES

WASTE GASES

PI LOT GA S

C Ol"S El\l DE CRE E DEFI NITIONS OPERATIO NAL GASES AND S TEA:\I

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## I APPENDIX FLR-7 1 thej/ore tip This includes all V ent Gas, Pilot Gas, and Total Steam

. " case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 238 of 325 document 7-1 filed 09/18/12 page 237 of 324case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 239 of 325 document 7-1 filed 09/18/12 page 238 of 324

Appendix FLR

‐ 8case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 240 of 325 document 7-1 filed 09/18/12 page 239 of 324

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 dime nsions 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 majo r component, including but not limited to: FLR-9 - 1case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 241 of 325 document 7-1 filed 09/18/12 page 240 of 324

5.1.1 Compressor(s), incl uding 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 expe cted 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 expe cted 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 e xpected for each type of gas used 7.4 Supplemental Gas 7.4.1 Type of gas used 7.4.2 Average lower heating value expe cted for each type of gas used 7.5 Steam (if applicable) 7.5.1 Drawing showing points of introducti on of Lower, Center, Upper, and any other steam 7.6 Simplified flow diagram that depicts the points of introduc tion 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 - 2case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 242 of 325 document 7-1 filed 09/18/12 page 241 of 324

8.1.1 Waste Gas and/or Ve nt 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 Ga s 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 NHV CZ , S/VG, and Prohibition on Disconti nuous Wake Dominated Flow or MFR Requirements in the Consent Decree

11. Identification of calibrati on gases to be used to comply with Appendix FLR-11

[End of FLR-9]

FLR-9 - 3case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 243 of 325 document 7-1 filed 09/18/12 page 242 of 324

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-but ylene), 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: C 5 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 but adiene 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)case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 244 of 325 document 7-1 filed 09/18/12 page 243 of 324

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-11-1case 2:12-cv-00207-PPS-APR document 7-1 filed 09/18/12 page 245 of 325

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-11-2case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 246 of 325 document 7-1 filed 09/18/12 page 245 of 324

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 concen tration 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 tha t: (i) the average inst rument response must not differ by more than 10 percent of the calibration gas value; and (ii) the precision and linearity ch eck 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 Tabl e 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

FLR-11-3case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 247 of 325 document 7-1 filed 09/18/12 page 246 of 324

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. H 2 S Measurement . For the H 2 S 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 sha ll be followed. The span shall be set at 320 ppmv H 2 S or as required by NSPS Subpart Ja, if different.

VI. Calculation of Instrument Downtime

1. For purposes of calculating the 110 hour s 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 cl ock hour with 60 minutes of unit operation), if there are at least four valid data point s 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 cl ock hour with less th an 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 un it operates to calculate the hourly average, then there is no peri od 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-11-4case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 248 of 325 document 7-1 filed 09/18/12 page 247 of 324

minutes to calculate the hourly aver age, 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-11-5case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 249 of 325 document 7-1 filed 09/18/12 page 248 of 324 

### 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 i dentify the source(s) of waste gas entering each Covered Flare. Waste Gas Mapping c an be done using instrumentation, isotopic tracing, acoustic monitoring, and/or engineer ing 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 de fined as pipes from inside the battery limits of each proc ess unit that connect to the ma in header. For process unit headers that are greater than or e qual to six (6) inches in di ameter, flow (“Q”) must be identified and quantifi ed if it is technically feasible to do so. In addition, all sources feeding each process unit header must be ident ified and listed in a table, but not necessarily individually quantified. For pr ocess unit headers that are less than six (6) inches in diameter, sources must be ident ified, but they do not need to be quantified.



### Waste Gas Mapping Submission Requirements: For each Covered Flare, the following sha ll be included within the Waste Gas Mapping section of the Initial WGMP:

1. Simplified Schematic consis tent 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 3APPENDIX FLR-12case 2:12-cv-00207-PPS-APRcase 2:12-cv-00207-PPS-APRdocument 3-1 filed 05/23/12page 250 of 325document 7-1 filed 09/18/12page 249 of 3242 of 3APPENDIX FLR-12case 2:12-cv-00207-PPS-APRcase 2:12-cv-00207-PPS-APRdocument 3-1 filed 05/23/12page 251 of 325document 7-1 filed 09/18/12page 250 of 324Table 1: Example of Flare Source Description TableProcess UnitHeaderSourcesDetailed Source DescriptionQS1(Ex: FCCU Gas ConUnit)3 PSVsPSV-14 on 110-D-5 Gas Con AbsorberPSV-12 on 110-D-1 Amine ScrubberPSV-7 on 110-F-1 Batch Caustic Vessel2 Pump Seal Purges110-G-1 LPG Pump110-G-2 Rich Amine Pump1 Sample Station110-S-1 LPG1 PSVPSV 17 on 112-D-1 Main Column1 Pressure ControlValvePCV 21 – Emergency Wet Gas Compressor1 PSVPSV-21 on Flush Oil Drum1 Pump Seal Purge110-G-23 Slurry Oil PumpQS2(Ex: Gas Oil Treater)Continue same as QS1Continue same as QS1QS3Continue same as QS1Continue same as QS1QS4Continue same as QS1Continue same as QS1A-H1 PSVsPSV-17 on 109-E-42 Slurry Heat ExchangerB-H2 Pump Seal Purges110-G-3 Gas Oil Feed110-G-4 Main Column Reflux3 of 3case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 252 of 325 document 7-1 filed 09/18/12 page 251 of 324 

### APPENDIX FLR-13

REPRESENTATIONS OF DISCONTI NUOUS WAKE DOMINATED FLOW

Definition
“Discontinuous Wake Dominated Fl ow” 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) belo w 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 ad jacent to the exterior of the Flare tip body. Background The gases present just outside of the flare tip ar e influenced by several factors. All of these factors are present all of the time, but as pr ocess 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 di rection 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 th e 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 buoya ncy due to temperature, and the inertia due to the gas’s momentum.case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 253 of 325 document 7-1 filed 09/18/12 page 252 of 324FlareTip

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 F low.‖ The red area is an artist’s rendition of a flame.

FLR-13-2case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 254 of 325 document 7-1 filed 09/18/12 page 253 of 324

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-13-3case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 255 of 325 document 7-1 filed 09/18/12 page 254 of 324

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-13-4case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 256 of 325 document 7-1 filed 09/18/12 page 255 of 324 

### 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 

# ∑

= NCI i CAP Dist ⎞ ⎟ ⎟ ⎠ CAP i ×

Where:

NCI i = The 2011 Nelson Complexity Index Coefficient shown in Table 1 below for Process i The throughput capacity for Process i in barrels per CAP i = calendar day as identified by the most recent Oil & Gas Journal survey The Refinery’s Crude Distillation Capacity in barrels CAP DIST = 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 ⎛ ⎜ ⎜ ⎝ NCI i × ICAP i ⎞

⎟ ⎟ ⎠ 

# ∑

= n 1 Where: The 2011 Nelson Complexity Index Coefficient shown NCI i = in Table 1 below for Process i Total US throughput capacity for Process i in barrels ICAP i = per calendar day as identified by the most recent Oil & Gas Journal survey Total US Crude Distillation Capacity in barrels per ICAP DIST = calendar day as identified by the most recent Oil & Gas Journal survey Industry Average

_ Complexity =
_ ICAP Dist

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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

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APPENDIX FLR-15

LIMITING AIR FLOW TO ENSURE ADE QUATE COMBUSTION EFFICIENCY FOR AIR-ASSISTED FLARES
All abbreviations, cons tants, 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 com pound comprised of a combination of carbon and hydrogen atoms is shown in Equation 1. In the ev ent the Vent Gas contains hydrogen, the value for x is zero and for y is two.

௫ ܥ ݕ ݕ Equation 1 ܱ ଶ ܪ ቀ ቁ ൅ ଶ ܱ ܥ ՜ ݔ ଶ ܱ ቁ ݔ ൅ ቀ ൅ ௬ ܪ 4 2 Therefore, the stoichiometric oxygen molar flow rate (moles/hr) for any given combustible compound flow is defined by Equation 2:

ݕ ௩௚ ݉

ሶ ቁ ቆ ௝ ൌ ݔ ைଶି௦௧௢௜௖௛ ݊ ሶ ቇ ቀ ݔ ൅ Equation 2 4 ௚ ௩ ܯܹ

Step 3: Calculate oxygen demand at stoichiometric conditions The stoichiometric oxygen mass flow rate for th e vent gas (lb/hr) is given by Equation 3.

௡ כ ෍

మ ை ܹ ൌ ܯ ைଶି௦௧௢௜௖௛ି௩௚ ݉

ሶ Equation 3 ೕ ைଶି௦௧௢௜௖௛ ݊ ሶ ௝ୀଵ

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Step 4: Calculate air mass flow rate at stoichiometric conditions

The mass of air needed to reach a stoichiometric ra tio based on the actual Vent Gas flow rate is given by Equation 4.

ሶ ሶ ைଶି௦௧௢௜௖௛ି௩௚ כ ݉ ൌ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ݉ ௥௜௔ ܹܯ

మ ை ܹܯ ·10.2 Equation 4

Step 5: Calculate actual Assist Air mass fl ow 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):

௥ ௔௜ ݉

ሶ ௥௜௔ ܹܯ

ൌ ି௔௦௦௜௦௧ כ ܸ 385.5 ሶ ௔௜௥ି௔௦௦௜௦௧ Equation 5

Step 6: Ensure that during flare opera tion, the following is met:

௔௜௥ି௦௧௢௜௖௛ି௩௚ ݉

ሶ ௥௔௜ ݉

ሶ ି௔௦௦௜௦௧ ൏ 106 · Equation 6

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Key to the Abbreviations:
ሻ ݅ܽݎ ݉ –݋݈ ݈ܾ ⁄ ଶ ܱ ݈݋݉

– ݈ܾ 0.21 ሺ ݅݊ ݎܽ݅ ݂݋ ݃݁݊ݕݔ݋ ݊݋݅ݐܽܿݎ݂ ݈݁݉݋ ൌ 0.21 ሻ ݈݁݋/݉ ݂ܿݏሺ ݉ݐܽ 1 ܽ݊݀ ܨ68° @ ݏ݃ܽ ܽ݊ ݈݅݀݁ܽ ݉݁ݑ݈݋ݒ ݂݋ ݉ݎ݈ܽ݋ ൌ 385.5
ݏݏ ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݅݊ ݅ ݉ݑ݈݋݊ܿ ݉݋ݎ݂ ݉݋ܿ݌݊ݑ݋݀ ݉ݑ݁݀݊ݎܾ݁ ݈ܽ ݑ ݅݀ݒ݅݊݀݅ ൌ ݅ ሻ
ݏݏ ݈݁ ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݅݊ ݆ ݑ݈݋݉݊ܿ ݉݋ݎ݂ ݑ݋݌݉݋݊݀ܿ ܾ݉݁ݑ݁݀݊ݎ ݑ݈ܽ݀ ݒ݅݅݊݀݅ ൌ ݆ ሻ ሻ ݎ/݄ ݈ܾሺ ݐݏ݅ݏݏܽ ݎܽ݅ ݁ݐܽݎ ݂݋ ݓ݋݂݈ ݉ݏݏܽ ൌ ௦௧௜௦௦௔ି ௔௜௥ ݉ ሶ
݁ ൌ ௢ ௦௧ି௚௜௔௜௥௩ି ௖௛ ݉ ሶ ݈ܾ ሺ ݏ݃ܽ ݐ ݎ݋݂ ݄ݐ ݁݊ݒ ݎܽ݅ ݓ݋݂݈ ݁ݐܽݎ ݏݏ݉ܽ ݉݋݅ܿݎݐ݁ ݏ݄݅ܿ݋ݐ݅ ݎ/݄ ሻ ݄ݎ ⁄ ሻ ݈ܾሺ ݏ݃ܽ ݐ ݎ݋݂ ݄݁ݐ ݁݊ݒ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݏ݄݅ܿ݅݋ݐݐ݉݁݋݅ܿݎ ൌ ௦ି௧ைଶ௚௢௩ି ௜௖௛ ݉ ሶ ݈ܾሺ/ሻ ݐ݁݊ݒ ݏ݃ܽ ݁ݐܽݎ ݂݋ ݓ ݋݂݈ ݉ݏݏܽ ൌ ௚ ௩ ݉ ሶ ݎ݄

మ ை ܹܯ ݈݋݉

– /݈ܾ ݈ܾ 32.0ሺ ݃݁݊ݕݔ݋ ݐ݄݁݅݃ݓ ݂݋ ݎܽ ݉ݑ݈݁ܿ݋ ൌ ݈ ሻ ሻ ݈݋݉

– /݈ܾ ݈ܾ 28.9ሺ ݎܽ݅ ݐ݄݁݅݃ݓ ݂݋ ݉ݑ݈݁ܿ݋݈ݎܽ ൌ ௔௜௥ ܹܯ ሻ ݈݉݋

– ݈ܾ / ݈ܾሺ ݐ݁݊ݒ ݏ݃ܽ ݐ݄݁݅݃ݓ ݂݋ ݎܽ ݉ݑ݈݁ܿ݋ ൌ ௚ ௩ ܹܯ ݈
ݏݏ ݈݁ݐ݊݅ݑሺ 1 ܾ݈ܶܽ݁ ݉݋ݎ݂ ݑ݋݌݉݋݀݊ܿݏ ݈ܽ ݑ ݂݋ ݅݀݅݊݀݅ݒ ݐݏ݈݅ ൌ ݊ ሻ
݊ ሶ ሻ ݎ݄ ݂ܿݏሺ/ ݎܽ݅ ݂݋ ݐݏ݅ݏݏܽ ݓ݋݂݈ ݅ܿݎݐ݉݁ݑ݈݋ ൌݒ ௟௔௧௨௔௖ି௔௜௥ ܸ ሶ ሻ ݈݋݉ / ݈݋݉ሺ ௬ ܪ ௫ ݂݋ ܥ ݈݁݋݉ ݎ݁݌ ݊݋ܾݎܿܽ ݂݋ ݏ݈݁݋݉ ݔൌ ݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ ݌݉݋ܿ ݑܾ݉݋ܾ݈݅ܿݐݏ݁ ݑ݈ܽ݅݀ ݒ ݊݀݅݅ ሻ ݈݋݉ / ݈݋݉ሺ ௬ ܥܪ ݂݋ ௫ ݌݉݋ܿ݋ ݈ܽ ݑ ݅݀ݒ ݎ݋݂ ܽ݊ ݅݊݀ ݏݏ݉ܽ ݓ݋݂݈ ݃݁݊ݕݔ݋ ݋݄݅ܿ݅݋ݐ݉ݐ݅ܿ݁ݎ ݏ ൌ ି௧௦ைଶ௜௖௛௢ ݅ ݎ ⁄ ݄ ݈ ݋݉ሺ ݊݀ݑ ሻ

ݔ

௝ ൌ ݋ ݏ ݃ܽ ݐ݁݊ݒ ݅݊ ݄݁ݐ ݊ ݒሺ ሻ݊ ݅݋ ݐ ܿܽ ݂ݎ ݋݈ ݕ ݎ݁݌ ݈݋݁݉ ݃݁݊݋ݎ݀ݕ݄ ݂݋ ݏ݈݁݋݉ ൌ

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Table 1 Individual Compound Properties

I (1) j Compound MW i (lb/lbmol) x + y/4
1 1 Hydrogen 2.02 0.5 2 Oxygen 32.00 0 3 Nitrogen 28.01 0 4 CO 2 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+ (C 5 +) 72.15 8 16 Water 18.02 0

1 i=all compounds, j=orga nic 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 be nzene and 1,3 butadiene are present in the Vent Gas only in de minimis quantities. Because be nzene and 1,3 butadiene speciation is not required, it is not listed in Table 1of this Appendix. The Vent Gas compositi on involved in other future settlements should be evaluated on a case-by-case basis to determine if ben zene or 1,3 butadiene speciation should be required.

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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 fl are 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 anal yzers will remotely analyze the combustion gases in the flare plume to determine combusti on 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 re gion, and therefore, th is test plan does not include evaluating combustion efficiency on pl umes having visible emissions. Each Test series will begin at e ither 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 flar e vent gas composition has been achieved and to ensure it is reasonably stable. Once th e 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

† T o be completed by BPP when submitting the protocol. Page 1 of 11case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 263 of 325 document 7-1 filed 09/18/12 page 262 of 324

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. Th e 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 wi nd, 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 requirement s). 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 ga s which is present at all times during testing may vary significantly in both flow and com position. During the Test, both flare gas and steam flow rates will be measured conti nuously 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 th e flare vent gas will not be required at the Whiting Refinery LPG flare for PFTIR testi ng. 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 experi ence short periods of over-steaming due to potential limitations in the in strumentation and control l ogic response times. Smoking, however, must be avoided (even for short durations) due to th e proximity of the surrounding community. The frequency and dur ation 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 th e 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 rega rdless of wind speed or direction.

[ADD PLOT PLAN WITH FLARE LOCATION] †
Figure 1: Map of equipment locations in relation to flare

† T o be completed by BPP when submitting the protocol. Page 3 of 11case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 265 of 325 document 7-1 filed 09/18/12 page 264 of 324



## 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 fr om the several sources, especially PFTIR measurements, may change after the test prog ram 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 ha ve a description of the conditions at which the run was performed. The entry will also not e the visible emissions rating of the flare and any ambient factors that could affect th e 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. Tabl e 2 lists the parameters and time interval that will be recorded and delivered by pl ant operations. The gas chromatograph (GC) used for measuring flare gas composition wi ll 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 He ating 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 instrume nts 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 w ith 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 CO 2, and shall compare and discuss 765 and 2000 wave number data. Compound Unit Carbon Dioxide (CO 2 ) ppm x m Carbon Monoxide (CO) ppm x m Methane (CH 4 ) ppm x m Ethylene (C 2 H 4 ) ppm x m Propane (C 3 H 8 ) ppm x m Page 6 of 11case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 268 of 325 document 7-1 filed 09/18/12 page 267 of 324

Compound Unit Propylene (C 3 H 6 ) ppm x m Butane (C 4 H 10 ) ppm x m 1,3 Butadiene (C 4 H 6 ) 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 w ill 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 camer a 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. Speci fications on the video cameras are located in Appendix B.



## 6.0 Stability of Flare
It should be understood that because this te st program is being conducted on a working refinery flare, it might not always be possi ble 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 defi ne conditions under which the variability of flare gas flow or compositi on occurring during the te st period is large enough to warrant concern over data quality. Ther efore, at the end of each test period, we will calculate whether the variab ility 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 ra te and composition can be maintained. During test runs calling for the S/VG ratio, th e 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 radiatio n 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 representati ve 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 repr esentative sample by either PFTIR, the test program will be paused to allow those ambient conditions to subside. Examples of such conditions may include coo ling tower plume interfer ence, rain or fog, and abrupt changes in wind direction.
[ADD WIND ROSE MAP] †
Figure 2: Restricted wind directio ns for PFTIR locations

† T o be completed by BPP when submitting the protocol. Page 8 of 11case 2:12-cv-00207-PPS-APR case 2:12-cv-00207-PPS-APR document 3-1 filed 05/23/12 page 270 of 325 document 7-1 filed 09/18/12 page 269 of 324



## 8.0 Calibration Radiance calibrations will be conducted at least once each day with a blackbody IR source located at roughly the same distance fr om 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 a nd 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 fl are 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 CO 2 , CO, and methane are metered by mass flow cont rollers into a heated cell. This cell is placed at the focal point of the collimator us ed 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 produ ce a concentration result. This result is then compared to the known value of the calibration gas concentr ation. 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 meas urement 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 temperatur es and outputs a false color image of the camera’s field of view. A scale of temperatur es 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 radi ance 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 wave lengths 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 defin ition 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 Ag ema 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 Tr ends by Varied Parameter

3.2 Summary and Key Data Tr ends 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
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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 Radi ance and Transmission Calibrations 3.3.5.3 Hot Cell Calibrations 3.3.6 PFTIR Detectors 3.3.6.1 Spectral Regions for CO 2
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 Princi ples 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

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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 SO 2 emissions resulting from an AG and HC Flaring Incidents shall be calculate d by the following equation:

Tons of SO 2 = [FR][TD][Conc S][8.44 x 10-5] (Equation 1)

b. The meaning of the variables is set forth in Paragraph 3.

c. The quantity of SO 2 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 SO 2 emitted shall be rounded to 10.1 tons.)

d. For purposes of determining the occurre nce of, or the tota l quantity of SO 2 emissions resulting from, an Acid Ga s or Hydrocarbon Flaring Incident that is comprised of intermitte nt Flaring, the quantity of SO 2 emitted shall be equal to the sum of the quantities of SO 2 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 SO 2 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 resu lts in an emission rate of 19.95 pounds of SO2 per hour, the emission rate sh all be rounded to 20.0 pounds of SO2 per hour; for a calculation that result s in an emission rate of 20.05 pounds of SO2 per hour, the emission ra te 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 SO 2 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 Incide nt if all gas is being flared) expressed as a volume frac tion (scf S/scf gas).

8.44 x 10-5 = [lb mole S/379 scf S][64 lb SO 2 /lb mole S][Ton/2000 lb]

0.169 = [lb mole S/379 scf S][1.0 lb mole SO 2 /lb mole S] [64 lb SO 2 /1.0 lb mole SO 2 ] The flow of gas to the Flaring De vice(s) (“FR”) shall be as meas ured 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 tu be 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 da ta used in the calculat ion and an explanation of the basis for any estimate s 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 emissi ons 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 quantit y of SO2 emissions is calculat ed using the following equation:

ER TGI

(Equation 3) = TD TGI ÿ [ FR Inc. ] i [Conc. SO 2 -250] i [0.169 x 10 -6 ] i [(20.9 - % O 2 )/20.9] i i = 1

Where:

ER TGI = Emissions from Tail Gas at the incinerator, SO 2 lb per 24-hour p erio d

TD TGI = Total Duration (number of hours) when the incinerator CEMS exceeded 250 ppmvd SO 2 corrected to 0% O 2 on a rolling twelve hour average, in each 24 hour period of the Incident

i = Each hourly average

FR Inc. = Incinerator Exhaust Gas Flow Rate (standard cubic feet per hour, dry basis) (actual stack monitor da ta or engineering estimate based on the acid gas feed rate to the SRP) for each hour of the Incident

Conc. SO 2 = Each actual 12 hour rolling average SO 2 concentration (CEMS data) that is greater than 250 ppm in the incinerator exhaust gas, p pmvd corrected to 0% O 2 , for each hour of the Incident.

% O 2 = O 2 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 SO 2 / 379 SO 2 ] [64 lbs SO 2 / lb mole SO 2 ] [1 x 10 -6 ] Standard conditions = 68 degree F; 14.7 lb force /sq.in . absolute

In the event the concentration SO 2 data point is inaccurate or not available or a flow meter for FR Inc does not exist or is inoperable, then BP shall use estimates based on best engineering judgment.

[End of Appendix FLR-18]

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APPENDIX E FENCE LINE MONITORING SYSTEM SU PPLEMENTAL ENVIRONMENTAL PROJECT
BPP will install, operate and maintain a fen ce line monitoring system and make the data collected available to the public pursuant to th e 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 capabl e 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 techni cal activities to be implemented to ensure that the results of the Fe nceline Monitoring SEP meets project specifications; and implementation of the data availability requirements of this Appendix.

a. SO 2 , Reduced Sulfur Compounds and H 2 S . Ambient concentrations of sulfur dioxide (SO 2 ) 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 SO 2 monitor shall be operated and maintained in accordance with all corresponding EPA equivalent method requirements. The SO 2 monitors will be operated in the 0 to 0.50 ppm full scale measurement range with temperature and pressure compensa tion features activated. For Hydrogen Sulfide (H 2 S) and reduced sulfur compounds, the Teledyne API Model T101 or equivalent will be operated in switching m ode to provide alternate 5-minute data for H 2 S, then reduced sulfur compounds. The monitors shall be operated and maintained in accordance with the manuf acturer’s recommendations and shall be

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capable of measuring reduced sulfur compounds and H 2 S, with a lower detection level of 1.0 ppb.
b. Benzene, Toluene, Pentane, and Hexane . The continuous measurement of benzene, toluene, pent ane, 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 calib ration range of 1.0 to 500 ppbV for all gases. The GC monitors shall operate w ith 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 Record ing 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 th e Whiting refinery area. The data set produced shall be adequate to correlat e prevailing conditions with pollutant measurements and transport.

a. Continuously measured meteorol ogical 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 measur ed 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 aver ages 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 installe d and operated inside a temperaturecontrolled equipment shelter. The temp erature within each shelter shall be continuously monitored and recorded usi ng 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 ra nge 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 anc hored 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 dist ribution circuits, li ghting, 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 a nd 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 pressu re with respect to atmospheric air pressure. B. Locations – The four monitoring sta tions 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 considerati on 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) wi ll be used to construct wind roses for the site. b. Availability of land, accessibility to site, availability of utility services, and securi ty of monitors an d operating personnel.

c. Geographic spacing of sites relativ e 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 airflo w 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. SO 2 , TRS, and VOC probes should be >1 meter away from supporting structures, wa lls and parapets.
g. The distance from a sampler probe to an obstacle, such as a building, should be at least twice the height the obst acle 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 t ype 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 st ations, or (b) for a longer period, if necessary to meet the re quirements 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 followi ng the month within which the data were collected. E

. Data Availability – On a weekly basis, BPP sha ll post the Fence Line Monitoring System data on a dedicated website or through BPP Whiting’s internet homepage (“Monitoring Data Website”), in a manner th at shall be readily accessible, clearly labeled, and clearly presented to the pub lic. 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 Fe nce 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 expend itures required to purchas e, 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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