__________________________________________ Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 1 of 121

IN THE UNITED STATES DISTRICT COURT

FOR THE SOUTHERN DISTRICT OF TEXAS

) UNITED STATES OF AMERICA, ) ) Plaintiff, ) )

v. ) No. 4:13- cv -2009 ) SHELL OIL COMPANY, DEER PARK )

REFINING LIMITED PAR TNERS HIP, and )

SHELL CHEMICAL LP

, ) )

Defendants. ) ) _________________________________________ )Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 2 of 121

TABLE OF CONTENTS

I. JURISDICTION AND VENUE

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

II. APPLICABILITY

..................................................................................................................... 6

III

. DEFINITIONS

......................................................................................................................... 8

IV. CIVIL PENALTY

................................................................................................................. 24

V. COMPLIANCE REQUIREMENTS

....................................................................................... 25

A. Instrumentation and Monitoring Systems

.......................................................................... 25

B. Determining Whether a Covered Flare that has a Water Seal

Is not Receiving Potentially Recoverable Gas Flow

.......................................................... 30

C. Waste Gas Minimization

.................................................................................................... 31

D. Flare Gas R ecovery Systems at the SDP Refinery

............................................................ 38

E. Flaring Limitations at the Refinery

.................................................................................... 41

F. Flare Gas Recovery System at the Olefins Flares of the SDP Chemical Plant

.................. 46

G. Limitations on Flari ng at the A&S and HIPA Flares of the SDP Chemical Plant

............. 51

H. Flare Combustion Efficiency

............................................................................................. 52

I. NSPS Subpart A, J, and Ja Applicability

............................................................................ 64

J. Eliminating Fuel Gas Flow from the SDP Refinery to the SDP Chemical Plant

Cover ed Flares

.................................................................................................................... 64

K. Incorporation of Consent Decree Requirements into Federally

Enforceable Permits

........................................................................................................... 65

VI. EMISSION CREDIT GENERATION

.................................................................................. 66

VII. MITIGATION PROJECTS

.................................................................................................. 68

VIII. SUPPLEMENTAL ENVIRONMENTAL PROJECTS

...................................................... 69

IX. REPORTING REQUIREMENTS

......................................................................................... 73

iiCase 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 3 of 121

X. STIPULATED PENALTIES

.................................................................................................. 77

XI. FORCE MAJEURE

............................................................................................................... 87

XII. DISPUTE RESOLUTION

................................................................................................... 90

A. For All Disputes Except those Arising Under Subparagraphs 43.c and 46.c

................... 90

B. For Disputes Arising Under Subparagraphs 43.c and 46.c

............................................... 92

XIII. INFORMATION COLLECTION AND RETENTION

..................................................... 92

XIV. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS

........................................... 94

XV. COSTS

............................................................................................................................... 102

XVI. NOTICES

.......................................................................................................................... 102

XVII. EFFECTIVE DATE

........................................................................................................ 104

XVIII. RETENTION OF JURISDICTION

............................................................................... 105

XIX. MODIFICATION

............................................................................................................. 105

XX. TERMINATION

................................................................................................................ 105

XX I

. PUBLIC PARTICIPATION

............................................................................................. 107

XXII. SIGNATORIES/SERVICE

............................................................................................. 108

XXIII. INTEGRATION

............................................................................................................. 108

XXIV. FINAL JUDGMENT

..................................................................................................... 109

iiiCase 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 4 of 121

TABLES OF APPENDICES

TABLE 1

NUMBER ABBREVIATION DESCRIPTION

1.1 S- Drwgs Drawings Illustrating Lower, Center, and Upper Steam Injection in Various Types of Flare Tips

1.2 Gen

- Eq General Equations

1.3 LFL Calculating NHV

cz

- limit and NHV

cz for Steam

- Assisted Flares

1.4 Malf -Pol EPA’s Policy on Excess Emissions during Malfunctions, Startup, and Shutdown

1.5 MFR

- Eq Calculating Momentum Flux Ratio

1.6 Tip

- Area

- Eq Calculating the Unobstructed Cross Sectional Area of Various Types of Flare Tips

1.7 G- Drwg Depiction of Gases Associated with Steam

- Assisted Flares

1.8 Flr

- Data -Rpt Outline of Requirements for the Flare Data and Initial Monitoring Systems Report

1.9 GC -Cmpnds List of Compounds a Gas Chromatograph must be Capable of Speciating

1.10 Tech

- Specs Equipment and Instrumentation Technical Specifications and Quality Assurance/Quality Control Requirements

1.11 WG

- Map Waste Gas Mapping: Level of Detail Needed to Show M ain

Headers and Process Unit Headers

1.12 DWDF

- Drwgs Representations of Discontinuous Wake Dominated Flow

1.13 Stips

- Calc Calculating the Amount of Stipulated Penalties Due for Violating Limitations on Flaring when the Stipulated

Penalties are Based on Excess VOC and SO 2 Emitted

1.14 Nlsn -Cmplxty Equations and Methodology to Calculate Refinery

- Specific Complexity and Industr y-Average Complexity using Nelson Complexity Index

ivCase 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 5 of 121

TABLE 2

NUMBER ABBREVIATION DESCRIPTION

2.1 SDP -Cmplnc- Sch Covered Flares and Applicability Dates for Certain Consent Decree Requirements

2.2 Intentionally left

blank Intentionally left blank

2.3 FLR

- Limit

- Calc Methodology for Calculating Refinery Flaring Limitation (including SDP’s Form EIA

- 820 for Report Year 2012)

2.4 FGRS -%- Rcvy Calculation of Olefins FGRS Estimated Percent Recovery

2.5 HIPA

- Emssns Methodology for Calculating the 365

- day Rolling Sum Emissions of Volatile Organic Compounds from the HIPA

Flare

2.6 Mitig

- NET Mitigation Project at the North Effluent Treater

2.7 Mitig

- Tank Mitigation Project at Certain Tanks

2.8 Mitig

- ACU/BEU Mitigation Project at the ACU and BEU

2.9 SEP -Mntring Fence Line Monitoring Supplemental Environmental Project

2.10 SEP

- Diesel Diesel Retrofit Supplemental Environmental Project

vCase 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 6 of 121

CONSENT DECREE

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

United States Environmental Protection Agency (“EPA”), has filed a complaint against

Defendants Shell Oil Company (“Shell Oil”), Deer Park Refining Limited Partnership (“ Dee r

Park Refining”), and Shell Chemical LP ( “She ll Chemical ”) (collectively “SDP ”), concurrently

with the lodging of this Consent Decree, for alleged environmental violations at Shell Oil ’s and

Deer Park Refining’s petroleum refinery (“SDP Refinery”) and at Shell Chemical’s c hemical

p lant (“SDP Chemical Plant”) ( collectively “Covered Facilities”) , both located in Deer Park,

Texas;

WHEREAS, on information and belief, the United States alleges that SDP has violated

and/or continues to violate, at the Covered Fa cilities , one or more of the following statutory and

regulatory provisions:

a. The Prevention of Significant Deterioration (“PSD”) requirements found in 42 U.S.C. § 7475 and 40 C.F.R. §§ 52.21(a)(2)(iii) and 52.21(j)– 52.21(r)(5);

b. The Non- Attainment New Source Review (“NNSR”) requirements found in 42 U.S.C. §§ 7502(c)(5), 7503(a)–(c) and 40 C.F.R. Part 51, Appendix S, Part IV, Conditions 1–4;

c. The federally enforceable Minor New Source Review (“Minor NSR”) requirements adopted and implemented by the R elevant States in their State Implementation Plans (“SIPs”) pursuant to 42 U.S.C. § 7410(a)(2)(C) and 40 C.F.R. §§ 51.160–51.164;

d. The New Source Performance Standards (“NSPS”) promulgated at

40 C.F.R. Part 60, Subparts A, J, VV, VVa, GGG, and GGGa, pursuant to

Section 111 of the CAA, 42 U.S.C. § 7411;

e. The National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) promulgated at 40 C.F.R. Part 61, Subparts A and FF and 40 C.F.R. Part 63, Subparts A, G, CC, FF, and UUU, pursuant to

Section 112 of the CAA, 42 U.S.C. § 7412;Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 7 of 121

f. The requirements of Title V of the CAA found at 42 U.S.C. §§ 7661a(a), 7661b(c), 7661c(a); and 40 C.F.R. §§ 70.1(b), 70.5(a) and (b), 70.6(a) and (c), and 70.7(b);

g. The portions of the Title V permits for the Covered F acilities that adopt, incorporate, or implement the provisions cited in a– e and h

– i;

h. The federally enforceable Texas SIP provisions that incorporate, adopt, and/or implement the federal requirements listed in a –b and d– f; and

i. Additional, federally enforc eable Texas SIP regulations.

WHEREAS SDP denies that it has violated and/or continues to violate the foregoing

statutory and regulatory requirements and denies any liability to the United States arising out of

the transactions or occurrences alleged in the Complaint;

WHEREAS S DP previously agreed, under a prior Consent Decree, to comply with

40 C.F.R. Part 60, Subpart J, at certain Flares at the SDP Refinery and has installed , in

compliance with that requirement and the requirement s of this Decree, a Flare Gas Recovery

System (“FGRS”) at a n estimated total cost of approximately $90 million ;

WHEREAS , pursuant to this Decree, SDP has agreed to install a FGRS at the SDP

Chemical Plant and to install other equipment to reroute, recover, and minimize Waste Gas flows

at both the SDP Refinery and SDP Chemical Plant at an estimated total cost of approximately

$9 0 million;

WHEREAS, for purposes of complying with rules in the State of Texas for limiting

emissions of highly reactive Volatile Or ganic Compounds, SDP, prior to the commencement of

negotiations in this matter, installed Vent Gas flow meters and gas chromatographs on Flares

designated in this Consent Decree as “Regular

- Use” Flares, and, in addition, from 2008 through

the D ate of L odgi ng of this Consent Decree, spent more than $9.5 million to improve

2Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 8 of 121

combustion efficiency and reduce emissions from Flares, and projects that it will spend another

$.5 million on these efforts ;

WHEREAS SDP estimates that the mitigation projects required pursuant to Section VII

of this Decree will cost up to $60 million;

WHEREAS SDP estimates that the Supplemental Environmental Project s required

pursuant to Section VIII of this Decree will cost approximately $ 1.2 million;

WHEREAS, between 2008 and full im plementation of this Decree, EPA estimates that

emissions from the twelve flares covered by this Consent Decree (“Covered Flares”) will be

reduced by approximately the following amounts (in “tons per year” or “TPY”):

Pollutant 2008–through implementa tion

Volatile Organic Compounds (“VOCs”) 1,838 TPY Carbon Dioxide Equivalents (“CO 2 e”) 261,033 TPY Hazardous Air Pollutants (“HAPs”) 264 TPY Sulfur Dioxide (“SO 2 ”) 2,412 TPY

WHEREAS

, between 2008 and full implementation of this Consent Decree, emissions of

hydrogen sulfide (“H 2 S”) and carbon monoxide (“CO”) from the Covered Flares also will be

reduced ;

WHEREAS EPA estimates that emissions of VOCs will be reduced by approximately

300 TPY when the mitigation projects required in Section VII of this Consent Decree are fully

implemented;

WHEREAS SDP intends to convert the f lare known as the A&S Flare, which is located at

SDP’s Chemical Plant, into a Temporary

- Use Flare (as that term is defined in thi s Consent

Decree) and to redirect all gases from it to a f lare known as the HIPA Flare, also located at

SDP’s Chemical Plant;

3Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 9 of 121

WHEREAS SDP has demonstrated that even after the redirection of the gas flow from

the A&S F lare to the HIPA Flare, the HIPA Flare will primarily serve intermittent loading

operations and the gas directed to the HIPA Flare will contain high levels of inerts relative to

volatile organic compounds, thus making a mass limit of volatile organic compounds from the

HIPA Flare an appropriate emissions limit;

WHEREAS SDP has demonstrated that the A&S Flare (after conversion) and the Flares

known as the South Property Flare and the CCU Flare will be Temporary

- Use Flares ;

WHEREAS, prior to the Date of Lodging of this Consent Decree, SDP repres ented that it

completed a project to eliminate a connection between the Girbotol Flare ( located at the SD P

Refinery ) and the A&S and HIPA Flares ( located SD P Chemical Plant ), and, pursuant to

Subsection V. J of this Consent Decree, SDP has agreed to undertake other actions to discover

and eliminate all connections from the SDP Refinery to the SDP Chemical Plant Covered Flares

that potentially allow Fuel G as flow ;

WHEREAS, by entering into this Consent Decree, SDP has indicated that it is committed

to continuing to proactively reduce emissions from its F lares;

WHEREAS this Consent Decree is intended to represent a comprehensive resolution of

the claims alleged in the Complaint and the claims resolved through Section XI V (Effect of

Se ttlement) and to ensure that when the compliance measures required by this Decree have been

fully implemented, each Covered Flare will be operated and maintained to prevent a recurrence

of the violations alleged in the Complaint and the violations resolved through Section XIV

(Effect of Settlement);

WHEREAS the United States anticipates that the specific and comprehensive compliance

measures set forth in this Consent Decree, which are subject to a reasonable timetable for

4Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 10 of 121

implementation, will result in the cessation of the violations alleged in the Complaint and the

violations resolved through Section XIV (Effect of Settlement);

WHEREAS, the United States and SDP (the “Parties”) recognize, and this Court by

entering this Consent Decree finds, that this Con sent Decree has been negotiated by the Parties in

good faith and will avoid litigation between the Parties, and that this Consent Decree is fair,

reasonable, and in the public interest;

NOW, THEREFORE, before the taking of any testimony, without the adjudication or

admission of any issue of fact or law except as provided in Section I, and with the consent of the

Parties, IT IS HEREBY ADJUDGED, ORDERED, AND DECREED as follows:

I. JURISDICTION AND VENUE

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

28 U.S.C. §§ 1331, 1345, and 1355; Sections 113(b) and 167 of the CAA, 42 U.S.C. §§ 7413(b)

and 7477; and over the Parties. Venue lies in this District 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), because SDP resides

and is located in this judicial district and the violations alleged in the Complaint are alleged to

have occurred in this judicial district. For purposes of this Decree, or any action to enforce this

Decree, SDP consents to this Court’s jurisdiction over this Decree, over any action to enforce

this Decree, and over SDP. SDP also consents to venue in this judicial district.

2. For purposes of this Consent Decree, SDP does not contest that the Complaint

states cla ims upon which relief may be granted.

3. Notice of the commencement of this action has been given to Texas, under

Sections 113(a)(1) and 113(b) of the CAA, 42 U.S.C. §§ 7413(a)(1) and (b).

5Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 11 of 121

II. APPLICABILITY

4. The obligations of this Consent Decree apply to and are binding upon the United

States and upon SDP and any successors, assigns, and other entities or persons otherwise bound

by law.

5. SDP shall give written notice of, and shall provide a copy of, the Consent Decree

to any successors in interest at least sixty (60) days prior to the transfer of ownership or

operation of any portion of the Covered Facilities . SDP shall notify the United States in

accordance with the notice provisions in Section XV I (Notice) of any successor in interest at

least thirty days prior to any such transfer.

6. If SDP intends to request that the United States agree to a transferee’s assumption

of any obligations of the Consent Decree, SDP shall condition any transfer, in whole or in part,

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

shareholder interest) in the Covered Facilities upon the transferee’s written agreement to execute

a modification to the Consent Decree that shall make the terms and conditions of the Consent

Decree applicable to the transferee.

7. As soon as possible prior to the transfer : (i) SDP shall notify the United States of

the proposed transfer and of the specific Consent Decree provisions that SDP proposes the

transferee assume; ( ii ) SDP shall certify that the transferee is contractually bound to assume the

obligations and liabilities of this Consent Decree; and (iii) the transferee shall submit to the

United States a certification that the transferee has the financial and technical ability to assume

the obl igations and liabilities of this Consent Decree and a certification that the transferee is

contractually bound to assume the obligations and liabilities of this Consent Decree.

6Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 12 of 121

8. A fter the submission to the United States of the notice and certification requi red

by the previous Paragraph , either : (i) the United States

, shall notify SDP that the United States

does not agree to modify the Consent Decree to make the transferee responsible for complying

with the terms and conditions of the Consent Decree; or ( ii ) the United States , SDP , and the

transferee shall file with the Court a joint motion requesting the Court approve a modification

substituting the transferee for SDP as the Defendant s responsible for complying with the terms

and conditions of the Consent De cree.

9. If SDP does not secure the agreement of the United States to a joint motion within

a reasonable period of time, then SDP and the transferee may file, without the agreement of the

United States , a motion requesting the Court to approve a modification substituting the transferee

for SDP as the Defendant responsible for complying with some or all of the terms and conditions

of the Consent Decree. The United States may file an opposition to the motion. The motion to

modify shall be granted unless SDP and the transferee : (i) fail to show that the transferee has the

financial and technical ability to assume the obligations and liabilities of the Consent Decree;

( ii ) fail to show that the modification language effectively transfers the obligations and liabilities

to the transferee; or ( iii ) the Court finds other good cause for denying the motion.

10. Except as provided in Paragraphs 5–9 and Section X I (Force Majeure), SDP shall

be responsible for ensuring that performance of the work contemplated under this Con sent

Decree is undertaken in accordance with the deadlines and requirements contained in this

Consent Decree and any attachments hereto. SDP shall provide a copy of all applicable portions

of this Consent Decree to all officers and employees whose duties might reasonably include

compliance with any provision of this Decree. No later than the execution of any contract with a

consulting or contracting firm that is retained to perform work required by this Consent Decree,

7Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 13 of 121

SDP shall provide a copy of the applicable provisions of this Consent Decree to each such

consulting or contracting firm. SDP shall condition any such contract upon performance of the

work in conformity with the applicable terms of this Consent Decree. No later than thirty (30)

days after the Date of Lodging of the Consent Decree, SDP also shall provide a copy of the

applicable provisions of this Consent Decree to each consulting or contracting firm that SDP

already has retained to perform the work requi red by this Consent Decree. Copies of the

applicable provisions of the Consent Decree do not need to be supplied to firms who are retained

to supply materials or equipment to satisfy requir ements of this Consent Decree.

11. In any action to enforce this Conse nt Decree, SDP shall not raise as a defense the

failure by any of its officers, directors, employees, agents, or contractors to take any actions

necessary to comply with the provisions of this Consent Decree.

III. DEFINITIONS

12. Terms used in this Consent Decree that are defined in the CAA or in federal and

state regulations promulgated pursuant to the CAA, shall have the meaning assigned to them in

the CAA, or such regulations, unless otherwise provided in this Decree. Whenever the terms set

forth below are used in this Consent Decree, the following definitions shall apply:

a. “Ambient Air” or “ air ” shall mean that portion of the atmosphere, external

to buildings, to which persons have access.

b. “Automatic Control System” or “ACS” shall mean a system that utilizes

programming logic to automate the operation of the instrumentation and systems required in

Paragraphs 18–23 of this Decree so as to produce the operational results required in

Paragraphs 53, 56–59.

8Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 14 of 121

c. “Available for Operation” shall mean , w ith respect to a Compressor within

a Flare Gas Recovery System, that the Compressor is capable of commencing the recovery of

Potentially Recoverable Gas as soon as practicable but not more than one hour after the Need for

the Compressor to Operate arises ; the period of time, not to exceed one hour, allowed by this

definition for the startup of a Compressor shall be included in the amount of time that a

compressor is Available for Operation.

d. “Barrels per day” or “bpd” shall mean barrels per calendar day.

e. “Baseload Waste Gas Flow Rate” shall mean, for a particular Regular

- Use

Covered Flare , the daily average flow rate, in scfd, to the Flare, excluding all flows during

periods of Startup, Shutdown, and Malfunction. The flow rate data period that shall be used to

determine Baseload Waste Gas Flow Rate is set forth in Subparagraph 30.b.ii.

f. “BTU/scf” shall mean British Thermal Unit per standard cubic foo t.

g. “Calendar Quarter” shall mean a three -month period ending on March 31,

June 30, September 30, or December 31.

h. “Capable of Receiving Sweep, Supplemental, and/or Waste Gas” shall

mean
, for a F lare

, that the flow of Sweep, Supplemental, and/or Waste Gas is /are not prevented

from being directed to the F lare by means of closed valves and/or blinds.

i. “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 Vent Gas without

entraining air. Diagrams illustrating the meaning and location of Center, Lower, and Upper

Steam are set forth in Appendix 1.1 to this Consent Decree.

9Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 15 of 121

j. “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.

k. “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 judgment, on a 5-minute block average using Equation 2 in

Appendix 1.2.

l. “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 1.2.

m. “Combustion Efficiency Multipliers” or “ CE Multipli ers” shall mean

empirically derived factors that are used as multipliers of the Net Heating Value of the Vent Gas

at its Lower Flammability Limit to ensure an acceptable Combustion Efficiency. The CE

Multipliers are set forth in Table 2 of Appendix 1.3 of this Consent Decree.

n. “Combustion Zone” shall mean the area of the Flare flame where the

combustion of Combustion Zone Gas occurs.

o. “Combustion Zone Gas” shall mean the mixture of all gases and steam

found after the Flare tip. This gas includes all Ven t Gas, all Pilot Gas, and all Total Steam.

p. “Compressor” shall mean, with respect to a Flare Gas Recovery System, a

mechanical device designed and installed to recover gas from a flare header. Types of Flare Gas

Recovery System compressors include reciproc ating compressors, centrifugal compressors,

liquid ring compressors and liquid jet ejectors.

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q. “Consent Decree” or “Decree” shall mean this Consent Decree, including

any and all appendices attached hereto.

r. “ Covered Facilities ” shall mean the SDP Chemical P lant and the SDP

Refinery.

s. “Covered Flare” shall mean each of the following Flares :

At SDP Chemical Plant At SDP Refinery

A&S CCU

HIPA Coker

Olefins II East Property

Olefins III Ethylene (aka Girbotol)

Olefins Ground North Property South Property West Property

t. “Date of Lodging of this Consent Decree” or “Date of Lodging” or

“DOL” shall mean the date that this Consent Decree is filed for lodging , pending solicitation of

public comment, with the Clerk of the Court for the United States District Court for the Southern

District of Texas

.

u. “Date of Entry of this Consent Decree” or “Date of Entry” or “DOE” shall

mean the Effective Date of this Consent Decree.

v. “Discontinuous Wake Dominated Flow” shall mean gas f low exiting a

Flare tip that is identified visually by:

(i) The presence of a flame that is: (1) immediately adjacent to the exterior of the Flare tip body; and (2) below the exit plane of the Flare tip; and

(ii) A discontinuous flame, such that pockets of flame are detached from the portion of the flame that is immediately adjacent to the exterior of the Flare tip body. Representations of Discontinuous

Wake Dominated Flo w are set forth in A ppendix 1.12.

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w. “Duplicate Spare Compressor” shall mean, with respect to a Flare Gas

Recovery System, an installed compressor, designed to be identical or functionally equivalent to

the other compressor(s) of the FGRS. In order to qualify as a “Duplicate Spare Compressor ,” the

compressor must be functionally interchangeable with the other FGRS compressor(s) such that

the Operating Design Capacity of the FGRS is Available for Operation while any one

compressor of the FGRS is out of service. The capacity of a D uplicate Spa re Compressor

depends upon the number of compressors installed to meet the Operating Design Capacity of the

FGRS. For example, if one compressor is installed to provide an Operating Design Capacity of

270 kscfh, the D uplicate S pare Compressor shall have a capacity of 270 kscfh; if, instead

, three

,

90 kscfh compressors are installed, the D uplicate S pare Compressor shall have a capacity of 90

kscfh

.

x. “Effective Date” shall have the definition set forth in Section XVI I

(Effective Date) of this Consent Decree.

y. “Elevated Flare” shall mean a Flare that supports combustion at a tip that

is situated at the upper end of a vertical conveyance ( e.g., pipe, duct); the combustion zone is

elevated in order to separate the heat generated by combustion from people, equipment, or

structures at grade level.

z. “EPA” shall mean the United States Environmental Protection Agency

and any of its successor departments or agencies.

aa. “Exit Velocity” shall mean the velocity (“ v ”) , in feet per second, of the

Vent Gas and Center Steam as they exit the flare tip. Exit Velocity shall be calculated by adding

together the Vent Gas Volumetric Flow Rate and the Center Steam Volumetric Flow Rate, based

on standard conditions, and dividing by the Unobstructed Cross Sectional Area of the Flare Tip.

12Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 18 of 121

bb. “ External Utility Loss” shall mean a loss in the supply of electrical power

or other third- party utility to a Covered Facility that is caused by events occurring outside the

boundaries of a Covered Facility, excluding utility losses due to an interruptible utility service

agreement.

cc. “First Updated Waste Gas Minimization Plan” or “First Updated WGMP”

shall mean the document submitted pursuant to Paragraph 31 as the first update to the Initial

WGMP.

dd. “Flare” sh all mean a combustion device that uses an uncontrolled volume

of Ambient Air to burn gases.

ee. “Flare Gas Recovery System” or “FGRS” shall mean a system of one or

more compressors, piping, and associated water seal, rupture disk, or similar device used to

divert gas from a Flare and direct the gas to a fuel gas system, to a combustion device other than

the Flare, or to a product, co-product, by- product, or raw material recovery system

.

ff. “Fuel Gas” shall have the definition set forth in 40 C.F.R. § 60.101a.

gg. “Gro und Flare” shall mean a Flare or array of Flare tips that supports

combustion at or near grade level and uses some form of shielding or barrier to separate the heat

generated by combustion from people, equipment, and structures at grade level. Ground Flar es

include Flares that are partially enclosed.

hh. “Initial Waste Gas Minimization Plan” or “Initial WGMP” shall mean the

document submitted pursuant to Paragraph 30.

ii. “In Operation” or “Being In Operation” or “Operating, ” with respect to a

Flare

, shall mean a ny and all times that any gas ( e.g. , Wast e, Vent, Purge, Pilot, ) is or may be

vented to a Flare. A Flare that is In Operation is C apable of R eceiving Sweep, Supplemental,

13Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 19 of 121

and/or Waste Gas unless all Sweep, Supplemental, and Waste Gas flow is prevented by means of

closed valves and/or blinds.

jj. “KSCFH” or “kscfh” shall mean thousand standard cubic feet per hour.

kk. “Lower Flammability Limit” or “ LFL ” shall mean the lowest volumetric

concentration of a combustible gas in air that, at a given temperature and pressure, will still

combust.

ll. “Lower Flammability Limit of Vent Gas” or “ LFL vg ” shall mean the

weighted average of the LFLs of each of the individual compounds in Vent Gas, weighted by

their volume fraction in the Vent Gas. LFL vg is represented by and sha ll be calculated according

to Equation 1 in Appendix 1.3 of this Consent Decree.

mm. “Lower Heating Value” or “ LHV ” shall mean the theoretical total quantity

of heat liberated by the complete combustion of a unit volume or weight of a fuel initially at 25

degrees Centigrade and 760 mmHg, assuming that the produced water is vaporized and all

combustion products remain at, or are returned to, 25 degrees Centigrade; however, the standard

for determining the volume corresponding to one mole is 20 degrees Centigrade.

nn. “Lower Steam” shall mean steam piped to an exterior annular ring near the

lower part of a Flare tip, which entrains Ambient Air which flows through tubes to the Flare tip,

and ultimately exits the tubes at the top of the Flare tip. Diagrams illustrating the meaning and

location of Center, Lower, and Upper Steam are set forth in Appendix 1.1 to this Consent

Decree.

oo. “Malfunction” shall mean any sudden, infrequent, and not reasonably

preventable failure of air pollution control equipment, process equipment, or a process to operate

in a normal or usual manner. Failures that are caused in part by poor maintenance or careless

14Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 20 of 121

operation are not Malfunctions. In any action under this Consent Decree involving this

definition, SDP shall have the burden of proving a Malfunction and, in interpreting this

definition, the ten requirements for a “malfunction” set forth in Section II (“ Affirmative Defenses

for Malfunctions” ) of EPA’s Policy on Excess Emissions during Malfunctions, Startup, and

Shutdown shall apply. This Policy is attached as Appendix 1.4.

pp. 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 degr ee to which the Ambient Air

affects the trajectory of the Vent Gas and Center Steam just as it exits the Flare tip. MFR is

represented by Equation 1 in Appendix 1.5 and shall be calculated in accordance with the

equations, conversion factors, MFR constants, MFR measured variables, and MFR calculated

variables set forth in Appendix 1.5.

qq. “Need for a Compressor to Operate” shall mean:

i. For a situation in which no Compressor within the FGRS is recovering gas : When a Potentially Recoverable Gas flow rate (d etermined on a five-minute block average) to the Covered Flare(s) serviced by the Flare Gas Recovery System exists ; or

ii. For a situation in which one or more Compressors within the FGRS already are recovering gas : When the Potentially

Recoverable Gas flow rate (determined on a five-minute block average) exceeds the capacity of the operating C ompressor(s).

rr. “Net Heating Value” shall mean Lower Heating Value.

ss. “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.a or 5.b in Appendix 1.3 to this Consent Decree and shall be calculated in

accordance with Equations 5 –8 of Appendix 1.3.

15Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 21 of 121

tt. “Net He ating Value of Combustion Zone Gas Limit” or “ NHV cz

- limit ” shall

mean the minimum Net Heating Value that the Combustion Zone Gas must have to ensure an

acceptable Combustion Efficiency.

uu. “Net Heating Value of Hydrogen as Adjusted” or “ NHV H2

- adj ” shall mea n

1212 BTU/scf. NHV H2

- adj represents an adjustment to hydrogen’s actual Net Heating Value for

use, consistent with Step 3 of Appendix 1.3, in the calculation of the NHV vg .

vv. “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 of Appendix 1.3.

ww. “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 accordance with Equation 3 of

Appendix 1.3 of this Consent Decree.

xx. “Olefins

, ” for purposes of this Consent Decree, shall mean the following

compounds:

Ethene (a/k/a ethylene) Propene (a/k/a propylene) Acetylene

But -1- ene (a/k/a but e ne, alpha -butylene)

Z-but-2- ene (a/k/a beta

- butylene, cis -butene)

E-but-2- ene (a/k/a beta -butylene, trans-butene)

2- methylpropene (a/k/a iso -butylene, iso-butene) 1,3 butadiene

yy. “Olefins FGR S ” shall mean one or more Flare Gas Recovery Systems

designed and operated to recover gas that otherwise would be directed to the Olefins Flares.

zz. “Olefins Flares” shall mean each of the following Covered Flares: the

Olefins II Flare , Olefins III Flare , and the Olefins Ground Flare.

16Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 22 of 121

aaa. “Operating Design Capacity” shall mean, with respect to a Flare Gas

Recovery System, the sum of the capacities, in kscfh, of the installed flare gas recovery

Compressors, excluding the capacity of the one installed Duplicate Spare Compressor.

bbb. “Pilot Gas” shall mean all gas introduced through the pilot tip (s) of a

Flare t o maintain a flame.

ccc. “Portable Flare” shall mean a Flare that is not permanently installed that

receives Waste Gas that has been redirected to it from a Covered Flare for periods that are

anticipated to be 504 hours or less on a rolling 1095-day period.

ddd. “ Potentially Recoverable Gas” shall mean the Sweep Gas , Supplemental

Gas, and /or Waste Gas (including hydrogen, nitrogen, oxygen, carbon dioxide, carbon

monoxide, and/or water) directed to a Covered Flare’s or group of Covered Flares’ FGRS

.

Hydrogen produced by the Pressure Swing Absorption (“PSA”) units at the Covered Facilities

and introduced between a Covered Flare’s water seal and a Covered Flare’s tip is not Potentially

Recoverable Gas.

eee. “Prevention Measure” shall mean an instrument, device, piece of

equipment, system, process change, physical change to process equipment, procedure, or

program to minimize or eliminate flaring.

fff. “Purge Gas” shall mean the minimum amount of gas introduced between a

Flare header’s water seal and the Flare tip to prevent ox ygen infiltration (backflow) into the Flare

tip. For a Flare with no water seal, the function of Purge Gas is performed by Sweep Gas, and

therefore, by definition, such a Flare has no Purge Gas.

ggg. “Regular

- Use Flare” shall mean any flare that is not a Tem porary- Use or

Portable Flare.

17Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 23 of 121

hhh. “Regular

- Use Covered Flare” shall mean each of the following Covered

Flares:

At SDP Chemical Plant At SDP Refinery

HIPA Coker

Olefins II East Property

Olefins III Ethylene (aka G i rb o tol)

Olefins Ground North Property West Property

iii. “Reportable Flaring Incident” shall mean, for each of the following time

periods, when any one of the following quantities is flared within a 24-hour period at the

Covered Facilities :

From the submission of the Init ial WGMP until the submission of First Updated WGMP From the submission of the First Updated WGMP through all

times thereafter
≥ 500 lb SO 2 (Refinery Covered Flares Only) ≥ 500,000 scf Waste Gas (All Covered Flares)
≥ 500 lb SO 2 (Refinery Covered

Flares Only)

Events that have the same root cause(s) that last more than 24 hours shall be considered a single

incident. For purposes of calculating whether the triggering level of SO 2 emissions has been

met, when flaring occurs at more than one Covered Flare, the quantity of SO 2 from all Covered

Flares involved shall be added together unless the root cause(s) of the flaring at the respective

Covered Flares is(are) not related to each other. For purposes of calculating whether the

triggering level of Waste Gas flow has been met, 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

Reportable Flaring Incident); and (ii) if SDP has instrumentation capable of calculating the

volumetric flow rate of hydroge n, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or

water (steam ) in the Waste Gas, the contribution of all measured flows of any of these

18Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 24 of 121

elements/compounds. When flaring occurs at more than one Covered Flare, the volume of

non- excluded Waste Ga s flow at all Covered Flares involved shall be added together unless the

root cause(s) of the flaring at the respective Covered Flares is (are) not related to each other.

jjj. “SCFD” or “scfd” shall mean standard cubic feet per day

.

kkk. “SCFH” or “scfh” shall mean standard cubic feet per hour.

lll. “SCFM” or “scfm” shall mean standard cubic feet per minute.

mmm. “SDP” shall mean Shell Oil Company, Deer Park Refining Limited

Partnership, and Shell Chemical LP.

nnn. “ SDP Chemical Plant” shall mean the chemical plant owned and operated

by Shell Chemical LP located at 5900 Highway 225 East, Deer Park, TX 77536.

ooo. “SDP Chemical Plant Covered Flare” shall mean each of the following

Covered Flares:

A&S

HIPA

Olefins II

Olefi ns III

Olefins Ground

ppp. “ SDP Refinery” shall mean petroleum refinery owned by Deer Park

Refining Limited Partnership and operated by Shell Oil Company and located at 5900 Highway

225 East, Deer Park, TX 77536.

qqq. “SDP Refinery Covered Flare” shall mean each of the following Covered

Flares:

19Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 25 of 121

CCU

Coker East Property Ethylene (aka Girbotol) North Property South Property West Property

rrr. “Shell’s PRI Consent Decree” shall mean the Petroleum Refinery

Initiative Con s ent Decree, as amended and revised, entered in an action styled United States, et

al. v. Deer Park Refining Limited Partnership, CA No. H-01-0978 (S.D. Texas).

sss. “Shutdown” shall mean the cessation of operation for any purpose.

ttt. “Smoke Emissions” shall have the definition set forth in Section 3.5 of

Method 22 of 40 C.F.R. Part 60, Appendix A. Smoke Emissions may be documented either by a

person certified pursuant to Method 22 or by a video camera.

uuu. “Standard Conditions” shall mean a temperature of 68 degrees Fahrenheit

and a pressure of 1 atmosphere. Unless otherwise expressly set forth in this Consent Decree or

an Appendix, Standard Conditions shall apply.

vvv. “Startup” shall mean the setting in operation for any purpose.

www. “Steam

- Assisted Flare” shall mean a Fla re that utilizes steam piped to a

Flare tip to assist in combustion.

xxx. “Supplemental Gas” shall mean all gas introduced to a Flare to comply

with: (1) the net heating value requirements of 40 C.F.R. § 60.18(b), 40 C.F.R. § 63.11(b), and/or

Paragraph 56 of this Consent Decree ; and/or (2) the requirements of Paragraph s 57 and/or 58.

yyy. “ S/VG

mass ” 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.

20Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 26 of 121

zzz. “Sweep Gas” shall mean :

i. For a Flare with a Water Seal: The minimum amount of gas

introduced into a Flare header in order to: (a) prevent oxygen buildup, corrosion, and/or freezing in the Flare header; and (b) maintain a safe flow of gas through the Flare header , including a higher flow during hot taps. Sweep Gas in these Flares is introduced prior to and is intended to be recovered by the Flare Gas Recovery System; and

ii. For a Flare without a Water Seal: The minimum amount of gas

introduced into a Flare header in order to: (a) prevent oxygen buildup, corrosion, and/or freezing in the Flare header; (b) maintain a safe flow of gas through the Flare header, including a higher flow during hot taps; and (c) prevent oxygen infiltration (backflow) into the Flare tip.

aaaa. “Temporary- Use Flare” shall mean a permanently installed F lare that

receives Waste Gas that has been redirected to it from another flare for periods that are

anticipated to be 504 hours or less on a rolling 1095-day average period.

bbbb. “Temporary

- Use Cover ed Flare” shall mean each of the following

Covered Flares: A&S, South Property, and CCU.

cccc. “Total Capacity” shall mean, with respect to a Flare Gas Recovery

System, the sum of the capacities, in kscfh, of the installed flare gas recovery Compressors,

including the capacity of the one installed Duplicate Spare Compressor.

dddd. “Total Steam” or “ S ” shall mean the total of all steam that intentionally is

introduced into a Steam- Assisted Flare to assist in combustion. Total Steam includes, but is not

limited t o, Lower Steam, Center Steam, and Upper Steam.

eeee. “Total Steam Mass Flow Rate” or “ ṁ

s ” shall mean the mass flow rate of

Total Steam supplied to a Flare, in pounds per hour as calculated on a 5-minute block average.

Total Steam Mass Flow Rate shall be calcula ted as set forth in Equation 3 of Appendix 1.2.

21Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 27 of 121

ffff. “Total

- Steam

- Mass

- Flow

- Rate

- to

- Vent

- Gas

- Mass

- Flow

- Rate Ratio” or

“ S/VG

mass ” shall mean the ratio of the Total Steam Mass Flow Rate to the Vent Gas Mass Flow

Rate.

gggg. “Unobstructed Cross Sectional Area of the Flare Tip” or “ A tip

- unob ” shall

mean the open, unobstructed area of a Flare tip through which Vent Gas and Center Steam pass.

Diagrams of four common flare types are set forth in Appendix 1.6 together with the equations

for calculating the A tip

- unob of th ese four types.

hhhh. “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 1.1 to

this Consent Decree.

iiii. “Velocity of the Wind” or “Wind Speed” or “ v wind ” shall mean the velocity

of the Ambient Air, in ft/s on a five- minute block average, measured at the Meteorological

Station required pursuant to Paragraph 23 of this Consent Decree.

jjjj. “Vent Gas” shall mean the mixture of all gases found just 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.

kkkk. “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.

llll. “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-minute block average. Vent

Gas Mass Flow Rate shall be calculated as set forth in Equation 4 of Appendix 1.2.

22Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 28 of 121

mmmm. “Vent Gas Molecular Weight” or “ MW vg ” shall mean the

Molecular Weight, in pounds per pound-mole, of the Vent Gas, on a 5-minute block average.

nnnn. “Visible Emissions” shall mean five minutes or more of Smoke Emissions

during any two consecutive hours. For purposes of this Consent Decree, Visible Emissions may

be determined by a person certified pursuant to Method 22 or documented by a video camera.

oooo. “VOC” or “Volatile Organic Compounds” shall have the definition set

forth in 40 C.F.R. § 51.100(s).

pppp. “VOC Vent Gas Concentration” shall mean the volumetric concentration

of VOCs in the Vent Gas and shall be calculated as set forth in Equation 15 of Appendix 1.3.

qqqq. “Waste Gas” shall mean the mixture of all gases from facility operations

that is directed to a flare for the purpose of disposing of the gas. “Waste Gas” does not include

gas introduced to a flare exclusively to make it operate safely and as intended; therefore, “Waste

Gas” does not include Pilot Gas, Total Steam, Assist Air, or the minimum amount of Sweep Gas

and Purge Gas that is necessary to perform the functions of Sweep Gas and Purge Gas. “Waste

Gas” also does not include t he minimum amount of gas introduced to a flare to comply with

regulatory and/or enforceable permit requirements and/or the requirements of Paragraphs 56, 57,

or 5 8; therefore, “Waste Gas” does not include Supplemental Gas. Depending upon the

instrumentation that monitors Waste Gas, certain compounds (hydrogen, nitrogen, oxygen,

carbon dioxide, carbon monoxide, and/or water (steam)) that are directed to a Flare for the

purpose of disposing of these compounds may be excluded from calculations relating to Waste

Gas flow . In Section V of this Consent Decree, the circumstances in which such exclusions are

permitted are specifically identified. Appendix 1.7 to this Cons ent Decree depicts the meaning

of “Waste Gas,” together with its relation to other gases associated with Flares.

23Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 29 of 121

IV. CIVIL PENALTY

13. By no later than 30 days after the Effective Date of this Consent Decree , SDP

shall pay the sum of Two Million, Six -Hundred Thousand Dollars ($2,600,000 ) as a civil

penalty. SDP shall pay the civil penalty by FedWire Electronic Funds Transfer (“ EFT ”) to the

U.S. Department of Justice in accordance with written instructions to be provided to SDP,

following lodging of the Consen t Decree, by the Financial Litigation Unit of the U.S. Attorney = s

Office for the Southern District of Texas, 1000 Louisiana St., Suite 2300, Houston, TX 77002.

At the time of payment, SDP shall send a copy of the EFT authorization form, the EFT

transacti on record, and a transmittal letter: (i) to the United States in the manner set forth in

Section XV I of this Decree (Notices) ; (ii) by email to acctsreceivable.CINWD@epa.gov ; and

(iii) by mail to:

EPA Cincinnati Finance Office 26 Martin Luther King Drive Cincinnati, Ohio 45268

The transmittal letter shall state that the payment is for the civil penalty owed pursuant to the

Consent Decree in United States v. Shell Oil Company, et al. , and shall reference the civil action

number, USAO File Number 2012VO1637, and DOJ case number 90-5-2-1-09388/1.

14. If any portion of the civil penalty due to the United States is not paid when due,

SDP shall pay interest on the amount past due, accruing from the Effect ive Date through the date

of payment, at the rate specified in 28 U.S.C. § 1961. Interest payment under this Paragraph

shall be in addition to any stipulated penalty due.

15. SDP shall not deduct any penalties paid under this Decree pursuant to this Section

o r Section X (Stipulated Penalties) in calculating its federal income tax.

24Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 30 of 121

V. COMPLIANCE REQUIREMENTS

A. Instrumentation and Monitoring Systems

16. Flare Data and Monitoring Systems and Protocol Report (“Flare Data and

Monitoring Systems and Protocol Repor t”) . For the Covered Flares

, by no later than the dates

set forth in Column B of Appendix 2.1, SDP shall submit a report, consistent with the

requirements in Appendix 1.8, to EPA that includes the following:

a. The information, diagrams, and drawings sp ecified in Paragraphs 1 –7 of Appendix 1.8;

b. A detailed description of each instrument and piece of monitoring equipment, including the specific model and manufacturer, that SDP has installed or will install in compliance with Paragraphs 18 –23 of this Consent Decree (Paragraph s 8 –9 of Appendix 1.8);

c. A narrative description of the monitoring methods and calculations that SDP shall use to comply with the requirements of Paragraphs 56–58 (Paragraph 10 of Appendix 1.8); and

d. The identification of the calibration gases to be used to comply with Subparagraph V.B.1 of Appendix 1.10 (Paragraph 11 of Appendix 1.8).

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 requirements o f 40 C.F.R. § 60.7(a)(5).

17. Installation and Operation of Monitoring Systems

.

a. Regular

- Use Covered Flares. By no later than the dates set forth in

Column C of Appendix 2.1, for each Regular

- Use Covered Flare , SDP shall have completed the

installation and commenced the operation of the instrumentation, controls, and monitoring

systems set forth in Paragraphs 18–24.

b. Temporary

- Use Covered Flares. P rior to directing any Vent Gas to a ny

Temporary

- Use Covered Flare, SDP shall have completed the install ation of the instrumentation,

controls, and monitoring systems set forth in Paragraphs 18–24 . SDP shall operate the

25Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 31 of 121

instrumentation, controls, and monitoring systems for each Temporary

- Use Covered Flare at all

time s that the Flare is Capable of Receiving Sweep , Supplemental, and/or Waste Gas

. During

periods when a Temporary-Use Covered Flare is not C apable of Receiving Sweep,

Supplemental, and/or Waste Gas, the instrumentation, controls, and monitoring systems in

Paragraphs 18–24 may be removed and the co ntinuous operation, maintenance, and calibration

of those instruments, controls and monitoring systems is not required; provided however, that

prior to the Startup of a ny Temporary

- Use Covered Flare, SDP shall take all necessary steps to

ensure that the in struments, controls, and monitoring systems are calibrated properly and are

capable of continuous operation for the full duration of the use of the Temporary- Use Covered

Flare.

18. Vent Gas Flow Monitoring System

. This system shall:

a. Continuously measure and calculate the total flow, in scfm and pounds per hour, of all Vent Gas;

b. Continuously analyze pressure and temperature at each point of Vent Gas

flow measurement; and

c. Have retractable or removable sensors at each point of Vent Gas flow

measurement to ensure that the Vent Gas Flow Monitoring System is

maintainable online.

19. Vent Gas Average Molecular Weight Analyzer

. This instrument or system shall

continuously analyze the average molecular weight of all Vent Gas. This analysis may be

performed by an instrument that also serves as part of a Vent Gas Flow Monitoring System.

20. Total Steam Flow Monitoring System

. This system shall:

a. Continuously measure and calculate the flow, in scfm and pounds per hour, of the Total Steam to each Covered Flare ; and

b. Continuously analyze the pressure and temperature of s team at a representative point of s team flow measurement

.

26Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 32 of 121

21. Steam Control Equipment . This equipment, including, as necessary, main and

trim control valves and piping, shall enable SDP to control steam flow in a manner sufficient to

ensure compliance with this Decree.

22. Gas Chromatograph (“GC”) or Net Heating Value Analyzer

. Each Regular

- Use

Covered Flare shall be equipped with a GC . E ach Temporary

- Use Covered Flare shall be

equipped with either a GC or a Net Heating Value Analyzer . The GCs and, to the extent used,

Net Heating Value Analyzers, shall meet the following requirements :

a. Gas Chromat o graph

. This instrument shall be capable of speciating the Vent Gas constituents set forth in Appendix 1.9.on a mole percent (“mol/mol%”) basis

. The sample extraction point of the G as Chromatograph may be located upstream of the introduction of Supplemental and/or Sweep and/or Purge Gas if the composition and flow rate of any such Supplemental and/or Sweep and /or Purge Gas is a known

constant and if this constant then is used in the calculation of the volume percent of all gas constituents of the Vent Gas

.

b. Net Heating Value Analyzer . This instrument shall measure the Net Heating Value of the Vent Gas in BTU/s cf. The sample extraction point

of the Net Heating Value Analyzer may be located upstream of the introduction of Supplemental and/or Sweep and/or Purge Gas if the composition and flow rate of any such Supplemental and/or Sweep and/or Purge Gas is a known constant and if this constant then is used in the calculation of the Net Heating Value of the Vent Gas

.

23. Me teorologic al Station or “Met Station ” (one Met Station can to be used for both

Covered Facilities ; not one for each Covered Facility and not one for each Covered Flare ). This

station shall include meteorological data instruments capable of measuring wind speed. The

station shall be placed at a location where wind is representative of conditions at the Regular

- Use

Covered Flare with the largest estimated volume of Waste Gas after Waste Gas minimization is

complete. The Meteorological Station shall be located as high as reasonably practicable but doe s

not have to be as high as the Regular

- Use Covered Flare that its location is based on

.

27Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 33 of 121

24. Video Camera

. This instrument shall record, in digital format, the flame of

(including any resulting from Discontinuous Wake Dominated Flow), and any Smoke Emissions

from

, the Regular

- Use Covered Flares.

25. Instrumentation and Monitoring Systems: Optional Equipment for any Covered

Flare . At its option, SDP may elect to install (if not already installed) an instrument to

continuously measure and calculate flow, in scfm and pounds per hour, of all Pilot Gas to a

Covered Flare. SDP may utilize the data generated by this instrument as part of the calculation

of the Net Heating Value of the Combustion Zone Gas.

26. Instrumentation and Monitoring Systems: Specifications . The instrumentation

and monitoring systems identified in Paragraphs 18–20 and 22–23 shall meet or exceed the

specifications set forth in Appendix 1.10.

27. Instrumentation and Monitoring Systems: Recording and Averaging Times . The

instrumentation and monitoring systems identified in Paragraph s 18–20 and 22–24 shall be able

to produce and record data measurements and calculations for each parameter at the following

time intervals.

28Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 34 of 121

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

Net Heating Value Analyzer Measure continuously and record 5 minute block averages

Wind Speed Measure continuously and record 5

minute block averages

Video Camera Record at a rate of no less than 4 frames per minute

Nothing in this Paragraph is intended to prohibit SDP from setting up process control logic that

uses different averaging times from those in this table provided that the recording and averaging

times in this table are available and used for determining compliance with this Consent Decree.

28. Instrumentation and Monitoring Systems: Operation and Maintenance. SDP

shall operate each of the instruments and monitoring systems re quired in Paragraphs 18–20 and

22–24 on a continuous basis when the Covered Flare that the instrument and/or monitoring

system is associated with is In Operation and C apable of Receiving Sweep, Supplemental, and/or

Waste Gas

, except for the following perio ds:

a. Malfunction of an instrument and/or monitoring system;

b. Maintenance following instrument and/or monitoring system Malfunction;

c. Scheduled maintenance of an instrument and/or monitoring system in accordance with the manufacturer’s recommended schedule; and/or

d. Quality Assurance/Quality Control activities

.

In no event, however, shall the excepted activities in Subparagraph 28.a–28.d for any instrument

monitoring a Regular- Use Covered Flare exceed 110 hours in any calendar quarter nor shall the

29Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 35 of 121

excepted activities in Subparagraph 28.a–28.d for any instrument monitoring a Temporary- Use

Covered Flare exceed 5% of the time that the Temporary

- Use Covered Flare is In Operation and

Capable of Recei ving Sweep, Supplemental, and/or Waste Gas during an uninterrupted time

period. The calculation of instrument downtime shall be made in accordance with 40 C.F.R.

§ 60.13(h)(2) and Paragraph VI of Appendix 1.10. If the excepted activities in

Subparagraphs 28.a–28.d for any instrument exceed their allowable amount, EPA shall be

entitled to seek stipulated penalties as set forth in Subp aragraph 93 .e or 93.f (as applicable) of

this Consent Decree and SDP shall be entitled to assert that the period of instrumentation and

monitoring system downtime was justified under the circumstances. Nothing in this Paragraph is

intended to prevent SDP from claiming a force majeure defense to any period of instrumentation

and/or monitoring system downtime. Nothing in this Paragraph supersedes or replaces the

monitoring requirements, including operation, maintenance, and quality assurance/quality

control requirements of 40 C.F.R. Part 60, Subparts J and Ja at such time as those requirements

become applicable pursuant to Paragraph 64. All such requirements shall apply in accordance

with the terms set forth in Subparts J and Ja.

B. Determining Whether a Covered Flare that has a Water Seal is Not Receiving

Pote ntially Recoverable Gas Flow

29. For a Covered Flare that has a water seal, if all of the following conditions are

met , then the Covered Flare is not receiving P otentially Recoverable G as flow:

a. For the water seal drum associated with the respective Covered Flare, the pressure difference between the inlet pressure and the outlet pressure is less than the water seal pressure as set by the static head of water between the opening of the dip tube in the drum and the level- setting weir in the drum;

b. For the water seal drum associated with the respective Covered Flare, the

water level in the drum is at the level of the weir ; and

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c. Downstream of the seal drum, t here is no flow of Supplemental Gas

directed to the Co vered Flare

.

C. Waste Gas Minimization

30. Initial Waste Gas Minimization Plan (“Initial WGMP”) . By no later than the

dates set forth in Column D of Appendix 2.1, for each Regular-Use Covered Flare, SDP shall

submit to EPA an Initial Waste Gas Minimization Plan that discusses and evaluates flaring

Prevention Measures both Facility-wide and on a Flare- specific basis. The Initial WGMP

submitted for the HIPA Flare shall include a discussion and evaluation of flaring Prevention

Measures that were implemented for gas that was directed to the A&S Flare before that gas was

rerout ed to the HIPA Flare. The Facility -wide evaluation shall include one evaluation for the

SDP Refinery and a separate evaluation for the SDP Chemical Plant; provided however, that

interconnections between the two Covered Facilities may be evaluated on a conso lidated basis.

The Initial WGMP shall include but not be limited to:

a. Updates . SDP shall submit updates, if and as necessary, to the

information, diagrams, and drawings provided in the Flare Data and Monitoring Systems and

Protocol Report required under Paragraph 16.

b. Waste Gas Characterization and Mapping . SDP shall undertake to

characterize the Waste Gas being disposed of at each Regular -Use Covered Flare and determine

its source as follows:

i. Volumetric (in scfm) and mass (in pounds ) flow rat e . SDP 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 Regular- Use Covered Flare

for the one- year period of time prior to 31 days before the submission of the Initial WGMP. To the extent that, for any particular Regular

- Use Covered Flare, SDP has instrumentation capable of measuring and/or calculating the volumetric and mass flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, carbon

31Case 4:13-cv-02009

ii.

iii.

iv. Document 2-1 Filed in TXSD on 07/10/13 Page 37 of 121

dioxide, and/or water (steam ) in the Waste Gas, SDP may break down the volumetric and mass flow as between: (i) All Waste Gas flows excluding hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam); and (ii) hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam)

flows in the Waste Gas. SDP may use either an engineering evaluation or measurements from monitoring or a combination to

determine flow rate. In determining flow rate, flows during a ll periods (including but not limited to normal operations and periods

of Startup, Shutdown, Malfunction, process upsets, relief valve leakages, utility losses due to an interruptible utility service agreement, and emergencies arising from events within the

boundaries of the Covered Facilities ), except those described in the

next sentence, shall be included. Flows that could not be prevented through reasonable planning and are in anticipation of or caused by a natural disaster

, act of war or terrorism, or E xternal Utility Loss are the only flows that shall be excluded from the calculation of flow rate. SDP shall specifically describe the date, time, and nature of the event that results in the exclusion of any

flows from the calculation.

Baseload Waste Gas Flow Rates

. SDP shall utilize flow rate data

for the one- year period of time prior to 31 days before the

submission of the Initial WGMP to determine the Baseload Waste Gas Flow Rate, in scfd, to each Regular- Use Covered Flare. The

Baseload Waste Gas Flow Rate shall not include flows during periods of Startup, Shutdown, and Malfunction.

Identification of Constituent G ases . SDP shall use best efforts to identify the constituent gases within each Regular- Use Covered Flare’s Waste Gas and the perc entage contribution of each such constituent during baseload conditions. SDP may use either an engineering evaluation or measurements from monitoring or a

combination to determine Waste Gas constituents.

Waste Gas Mapping

. Using instrumentation, isotopic tracing, and/or engineering calculations, SDP shall identify and estimate the flow from each process unit header (sometimes referred to as a “subheader”) to the main header(s) servicing the Regular

- Use Covered Flare. Using that information and all other available

information , SDP shall complete an identification of each Waste

Gas tie -in to the main header (s) and process unit header(s), as applicable, consistent with Appendix 1.11. Temporary connections to the main header(s) of a Regular

- Use Covered Flare and/or process unit header(s) are not required to be included in the mapping.

32Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 38 of 121

c. Reductions previously realized . SDP shall describe the equipment,

processes and procedures installed or implemented since 2008 to reduce flaring. The description

shall specify the date of installation or implementation and the amount of reductions realized.

d. Planned reductions . SDP shall describe the equipment, processes, or

procedures that SDP plans to install or implement to eliminate or reduce flaring. The description

shall specify a schedule for expeditious installation and commencement of operation and a

projection of the amount of reductions to be realized. Subsequent to the submission of the

WGMP, SDP may revise th e installation and operation dates provided that SDP does so in

writing to EPA within a reasonable time of determining that such a revision(s) is(are) necessary

and provides a reasonable explanation for the revised date(s). In formulating this plan, SDP

s pecifically shall review and evaluate the results of the Waste Gas Mapping required by

Subparagraph 30.b.iv.

e. Taking a Covered Flare Permanently O ut of Service . SDP shall identify

any Covered Flare that it intends to permanently take out of service, including the date for

completion of the decommissioning. Taking a Covered Flare “permanently out of service”

means physically removing piping in the Flare header or physically isolating the piping with a

welded blind so as to eliminate direct piping to th e Covered Flare and surrendering any permit to

operate such Covered Flare

.

f. Prevention Measures . SDP shall describe and evaluate all Prevention

Measures, including a schedule for the expeditious implementation and commencement of

operation of all Prevention Measures, to address the following:

i. Flaring that has occurred or may reasonab l y be expected to occur during planned maintenance activities, including Startup and

Shutdown . The evaluation shall include a review of flaring that

33Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 39 of 121

has occurred du ring these activities since January 2009 and shall consider the feasibility of performing these activities without flaring.

ii. Fl aring that may reasonably be expected to occur due to issues of gas quantity and quality . The evaluation shall include a gen eral audit of the existing flare gas recovery capacity of each Regular

- Use 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.

iii. Flaring caused by the recurrent failure of air pollution control equipment, process equipment, or a process to operate in a normal

or usual manner . The evaluation shall consider the adequacy of existing maintenance schedules a nd protocols for such equipment. A failure is “recurrent” if it occurs more than twice during any five year period as a result of the same cause.

31. First Updated Waste Gas Minimization Plan . By no later than the dates set forth

in Column E of Appendix 2.1 , SDP shall submit to EPA a First Updated WG MP which shall

update for the 12- month period after the period covered by the Initial Waste Gas Minimization

Plan, if and as necessary, the information required in Subp aragraph s 30 .a

– 30 .f and shall also

include the following:

a. Updated Waste Gas Mapping . SDP shall update the Waste Gas mapping as more information becomes available. SDP shall use this updated mapping to plan reductions;

b. Reductions Based on Root Cause Analysis . SDP shall review all of the Root Cause Analysis reports submitted under Paragraph 35 to determine if reductions in addition to the reductions achieved through any required corrective action under Paragraph 36 can be realized; and

c. Revised Schedule . To the extent that SDP proposes to extend any schedule set forth in the Initial WGMP, SDP may do so only with good

cause.

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32. Subsequent Updates to Waste Gas Minimization Plan

.

a. SDP Chemical Plant. In the first semi -annual report required under

Section IX of this Decree (Reporting Requirements) that is due no sooner than one year after the

submission of the First Updated WGMP, SDP shall submit a Second Updated WGMP for the

SDP Chemical Plant . On an annual basis thereafter until termination of the Decree, SDP shall

submit an updated WGMP for the SDP Chemical Plant as part of the semi -annual report. Each

update shall update, if and as necessary, the information required in Subparagraphs 30 .a –30.f,

31.a, and 31.b. To the extent that SDP proposes to extend any schedule set forth in a previous

WGMP for the SDP Chemical Plant , SDP may do so only with good cause.

b. SDP Refinery. For the SDP Refinery, in lieu of submitting any updates to

the Initial and First Updated WGMP under this Consent Decree, SDP shall comply with the Flare

Management Plan requirements of NSPS Subpart Ja, 40 C.F.R. § 60.103a(a)– (b) , by no later than

November 11, 2015.

33. Waste Gas Minimization Plan: Implementation . By no later than the dates

specified in a WGMP, SDP 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.

34. Enforceability of WGMPs . The terms of each WGMP (including Initial, First

Updated, and Subsequent Updated WGMPs) submitted under this Consent Decree are

specifically enforceable.

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35. Root Cause Analysis for Reportable Flaring Incident

.

a. Internal Reporting and Recordkeeping . Except as provided in

Paragraphs 37 and 38.a, commencing on the dates set forth in the definition of “Reportable

Flaring Incident” in Section III of this Decree (De finitions), by no later than forty- five days

following the end of a Reportable Flaring Incident, SDP 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:

i. The date and time that the Reportable Flaring Incident started and ended;

ii

. The volume of Waste Gas flared and an estimate of the quantity of

VOCs and SO 2 that was emitted and the calculations that were used to determine that quantity;

iii. The steps, if any, that SDP took to limit the duration of the Reportable Flaring Incident and quantity of VOC and/or SO 2 emissions associated therewith;

iv

. A detailed analysis that sets forth the root cause and all contributing causes of the Repo rtable Flaring Incident, to the extent determinable;

v. 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

futu re. The analysis shall discuss the alternatives, if any, that are available, the probable effectiveness and the cost of the alternatives, if an alternative is eliminated based on cost . Possible design and operation and maintenance changes shall be evalua ted.

If SDP concludes that corrective action(s) is (are) required under Paragraph 36 , the report shall include a description of the action(s) and, if not already completed, a schedule for its (their) implementation, including proposed commencement and

com pletion dates. If SDP concludes that corrective action is not required under Paragraph 36, the report shall explain the basis for that conclusion; and

vi. To the extent that investigations of the causes and/or possible

corrective actions still are underw ay 45 days after the Reportable

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Flaring Incident, a statement of the anticipated date by which a follow-up report fully conforming to the requirements of this Paragraph shall be completed.

b. Submitting Summary of Internal Flaring Incident Reports . In each

semi -annual report due under Section IX of this Decree (Reporting Requirements), SDP shall

include a summary of the following items for each Reportable Flaring Incident that occurred

during the six-month period that the semi-annual report covers:

i. Date;

ii. Duration;

iii. Amount of SO 2 and VOC released;

iv. Root Cause(s);

v. Corrective Action(s) completed;

vi. Corrective Action(s) still outstanding; and

vii. An analysis of any trends identified by SDP in terms of the number of Incidents, the Root Causes, or the types of Corrective Action.

36. Corrective Action Implementation . In response to any Reportable Flaring

Incident , SDP shall take, as expeditiously as practicable, such interim and/or long- term

corrective actions, if any, as are consistent with good engineering practice to minimize the

likelihood of a recurrence of the root cause and all contributing causes of that Reportable Flaring

Incident.

37. In lieu of preparing a new report under Paragraph 35 and analyzing and

implementing corr ective acti on under Paragraph 36 for a Reportable Flaring Incident that has as

its root cause the same root cause as a previously reported Reportable Flaring Incident, SDP may

cross -reference and utilize the prior report and analysis when preparing the report require d by

Paragraph 35.

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38. Overlapping Requirements

.

a. Root Cause Analysis and Corrective Action Requirements under SDP ’s

PRI Consent Decree

. To the extent that a Reportable Flaring Incident that is triggered solely by

the SO 2 threshold in the definition of “R eportable Flaring Incident” also constitutes an Acid Gas

or Hydrocarbon Flaring Incident under S hell ’s PRI Consent Decree, SDP shall follow the

provisions of S hell ’s PRI Consent Decree, and not the provisions of this Decree, for addressing

the incident, fo r as long as S hell’s PRI Consent Decree is in effect.

b. Root Cause Analysis and Corrective Action Provisions of NSPS

Subpart Ja

. With respect to the Covered Flares at the SDP Refinery, SDP no longer shall be

required to comply with the root cause analysis and corrective action provisions in

Paragraphs 35–36 of this Consent Decree on and after November 11, 2015. At that time, SDP

shall comply with the requirements of NSPS Subpart Ja, 40 C.F.R. § 60.103a(c)–(e ).

D. Flare Gas Recovery Systems at the SDP Refinery

39. Flare Gas Recovery Systems at the SDP Refinery: Capacity and Start

- Up Dates

.

By no later than the following dates for the following Regular

- Use Covered Flares at the SDP

Refinery , SDP shall complete installation and commence operation of the following Flare Gas

Recovery Systems at the SDP Refinery:

38Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 44 of 121

FGRS ID Covered

Flares FGRS Operating Design Capacity (kscfh) Total No. of Compressors (includes one Spare per FGRS) Capacity of

each Compressor (kscfh) FGRS

Total Capacity (kscfh) Date

CPU North and

West 350 2 350 700 DOE

Coker Coker 290 6 58 348 DOE

EP F /G i rb o tol East Property

and

G i rb o tol 500 2 500 1000 DO E

40. Flare Gas Recovery Systems at the SDP Refinery: Operation

.

a. General . SDP shall operate each FGRS in a manner to minimize Waste

Gas to the respective Covered Flares while ensuring safe refinery operations. SDP also shall

operate each FGRS consistent with good engineering and maintenance practices and in

accordance with its design and the manufacturer’s specifications.

b. Requirements Related to Compressors Being Available for Operation

and/or in Operation . By no later than December 31, 2014, SDP shall comply with the following

requirements when Potentially Recoverable Gas is being generated :

i. CPU and EPF/Gi rb o tol Flare Gas Recovery Systems . For the CPU and East Property/Gi rb o tol Flare Gas Recovery Systems, SDP shall have one Compressor Available for Operation and/or in operation 98% of the time and two Compressors Available for Operation and/or in operation 90% of the time . Periods of

maintenance and subsequent restart on the Compressors within the CPU and/or EPF/Girbotol Flare FGRSs may be included in the

amount of time that the Compressors are Available for Operation when determining compliance with the requirement to have two Compressors Available for Operation and/or in operation 90% of

the time , provided that these periods shall not exceed 1344 hours per Compressor in a five- year rolling sum period, rolled daily.

ii. Coker Flare Gas Recovery System . For the Cok er Flare Gas Recovery System, SDP shall have five C ompressors Available for Operation and/or in operation 95% of the time and four

39Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 45 of 121

iii

. Compressors Available for Operation and/or in operation at all

times. The following periods may be included in the amount of

time that a C ompressor is Available for Operation when determining compliance with the requirement to have four Compressors Available for Operation and/or in operation “at all

times” :

(1) Periods of maintenance on and subsequent restart of the equipment within the Coker FGRS that is shared by all Compressors (for example, the water seal, the knock-out drum, valves), such that the entire FGRS must be shut

down in order to undertake the maintenance ; provided however, that t hese periods shall not exceed 336 hours i n a five

- year rolling sum period, rolled daily. SDP shall use best efforts to schedule these maintenance activities dur ing

a turnaround of the process units venting to the Coker

Flare . To the extent it is not practicable to undertake these maintenance activities during a turnaround, SDP shall use

best efforts to minimize the generation of Waste Gas during such periods.

(2) Periods in which the four Compressors are shut down (including the subsequent restart) due to operating conditions (such as high temperatures or large quantities of entrained liquid in the Vent Gas) outside the design operating range of the Coker FGRS, including the

associated knock -out drum(s), such that the outage is necessary for safety and/or to preserve the mechanical integrity of the Coker FGRS. By no later than 45 days after any such period of outage, SDP shall investigate the root cause and all contributing causes of the outage and shall implement, as expeditiously as practicable, corrective action, if any, to prevent a recurrence of the cause(s). In the reports due under Section IX of this Decree, SDP shall

describe each outage that occurred under the conditions identified in this Subparagraph, including th e date, duration, cause(s), corrective action, and the status of the implementation of corrective action.

Period to be U sed for Computing P ercentage of T ime

. For purposes of calculating compliance with the 90%, the 95%, and the

98% of time that a Co mpressor or group of Compressors must be Available for Operation and/or in operation, as required by Subparagraphs 40.b.i and 40.b.ii, the period to be used shall be an 8760-hour rolling sum, rolled hourly, using only hours when Potentially Recoverable Gas was generated during all or part of the

40Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 46 of 121

hour but excluding hours for flows that could not have been prevented through reasonable planning and were in anticipation of or caused by a natural disaster, act of war or terrorism, or External Utility Loss . W hen no Potentially Recoverable Gas was generated during an entire hour, then that hour shall not be used in computing the 8760-hour rolling sum . The r olling sum shall include only the prior 8760 1-hour p eriods when Potentially Recoverable Gas was generated during all or part of the hour, provided that the Potentially Recoverable Gas was not generated by flows that could not have been prevented through reasonable planning and were in anticipation of or caused by a natural disaster, act of war or terrorism, or External Utility Loss

.

E. Flaring Limitations at the SDP Refinery

41. Limitations on Flaring at the SDP Refinery : Initial Limit s

.

a. On and after the following dates, SDP shall comply with the following

limitations on flaring from all SDP Refinery Covered Flares and Portable Flares (if any) :

i. Refinery -Wide 30-day Rolling Average

. By no later than December 31, 2017, SDP shall comply with the following Refinery -wide short- term limit: 2,455,944 scfd of Waste Gas on a 30-day rolling average basis, rolled daily.

ii

. Refinery -Wide 365- day Rolling Average. By no later than December 31, 2014, SDP shall comply with the following Refinery -wide long- term limit : 1,637,296 scfd of Waste Gas on 365-day rolling average basis, rolled daily.

iii. The rolling averag e period shall include only the prior 30 or 365 days, as applicable, when any Refinery Covered Flare or Portable

Flare was/were In Operation

.

Each exceedance of the 3 0- day rolling average limit or each exceedance of the 3 65- day rolling

average li mit shall constitute one day of violation. An exceedance of either or both of the limits

shall not prohibit ongoing refinery operations.

b. The limitations set forth in Subparagraph 41 .a were calculated using the

equations set forth in Subparagraph 43.a.i and ii. Appendix 2.3 sets forth the actual calculation.

The “ SDP Ref. Crude Capacity ” was taken from the “Total Operable” atmospheric crude oil

41Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 47 of 121

distillation capacity, in barrels per calendar day, found in Part 5, Code 401, of the Form EIA-820

that SD P submitted to the Energy Information Agency (“EIA”) for the 2012 report year. The

value reported was 327,000 barrels per calendar day. A copy of that Form is included in

Appendix 2.3. The “ SDP Complexity ” and “ Industry Avg Complexity ” were calculated p ursuant

to the methodology set forth in Appendix 1.14.

42. Intentionally left blank.

43. Limitations on Flaring at the SDP Refinery: Requesting an Increase in the

Limit(s)

.

a. SDP Request

. Once per calendar year commencing no sooner than

January 1, 2016, S DP may submit a request to EPA to increase the limitations in flaring set forth

in Subparagraphs 41 .a and/or 41.b. SDP may request an increase in the limit(s), and EPA will

approve such an increase, only if the request is based on post-Lodging changes in crude capacity

and/or complexity that are or will be permitted by the State of Texas and only if the changes in

crude capacity and /or co mplexity result in new limit( s) that are higher by at least 20% than the

limits set forth in Subparagraphs 41 .a and/or 41.b. In any such request, SDP shall propose

(a) new limit(s) ( hereafter referred to as “New Limit (s) Based on Projections”) based upon the

following equations:

i. For the Refinery-wide, 30- day rolling average limit:

Refinery Flaring ≤ 750,000 scfd x SDP Ref. Crude Cap

. x SDP Complexity

____ 100,000 bpd Industry Avg C omplexity

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ii. For the Refinery-wide, 365- day rolling average limit:

Refinery Flaring ≤ 500,000 scfd x SDP Ref. Crude Cap

. x SDP Complexity 100,000 bpd Industry Avg Complexity

Nothing in this Paragraph or Consent Decree shall be construed to relieve SDP of an obligation

to evaluate, under applicable Prevention of Significant Deterioration and Nonattainment New

Source Review requirements, any increase in a Refinery

- Wide limit on flaring.

b. For purposes of Subp aragraph s 43.a.i and 43 .a.ii, the following shall

apply:

i. The items in italics are variables that will change over time.

ii. The SDP Ref. Crude Capacity shall be determined as follows:

(1) If the post-Lodging modification does not affect the crude capacity, the Atmospheric Crude Oil Distillation Capacity, in barrels per calendar day, that the Refinery reported under “Total Operable” capacity on Part 5, Code 401, of the Applicable Form EIA -820 ; the defin ition of “Applicable

Form EIA -820” is found in the “Definitions” section of Appendix 1.14; to the extent that the “Parts” or “Codes” on

Form EIA -820 change in the future, the intent of the Parties

is that the “Parts” and “Codes” of future forms that

corres pond most closely to those found on the Form EIA820 for Report Year 2012 (see Attachment 2 to Appendix

1.14 ) will be used ; or

(2) If the post-Lodging modification does affect crude capacity, the projected, new capacity set forth in the air permit application(s) for the post Lodging modification

i ii

. SDP C omplexity shall be calculated in accordance with Equation 1 of Appendix 1.14. SDP shall certify the accuracy of the projected crude capacity and/or process unit capacities used to support the

c alculations.

iv. The Industry Average Complexity shall be calculated in accordance with Equation 2 of Appendix 1.14.

43Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 49 of 121

c. EPA Response to Request . EPA shall evaluate any request under

Subparagraph 43.a on the basis of consistency with Subparagraphs 43.a.i and 43.a.ii. If EPA

does not act on SDP’s request within 90 days of submission, SDP may invoke the accelerated

dispute resolution provisions of Subsection XII. B of this Decree.

d. The New Limit(s) Based on Projections shall take effect, if ever,

beginning on the later of the date that EPA approves the request or a dispute is resolved in SDP’s

favor or the date(s) specified in the modification permit(s).

e. In the event that SDP amends, modifies or withdraws the air permit

application(s) that is/ are the basis for the New Limit(s) Based on Projections requested pursuant

to Subparagraph 43 .a in a manner that affects the limit (s) calculation(s), SDP shall

, within 15

days of amending, modifying, or withdrawing its air per mit application(s), revise or withdraw its

request under Subparagraph 43.a. To the extent that SDP revises, rather than withdraws, its

request under Subparagraph 43.a, the 90-day deadline under Subparagraph 43.c for EPA’s

response to the revised request shall commence upon the date of EPA’s receipt of SDP’ s revised

request

.

f. Consequences of a Mistake in Project ed Capacities

.

i. By no later than 30 days after the Startup of the permitted modifications, SDP shall determine whether the projected “ SDP Ref. Crude Capacity ” or the projected capacities for new or

modified units that SDP relied upon pursuant to Subparagraphs 43.b .ii and/or b.iii , respectively, were or are different from the actual capacities that SDP has or will report to

the EIA or the Oil & Gas Journal after the Startup of the permitted modification. If there are differences, SDP shall re

- calculate the flaring limitation(s) using the actual capacities that SDP has or will report to the EIA or the Oil & Gas Journal ( hereafter referred to as “New Limit(s) Based on Actuals”)

.

ii. If the New Limit(s) Based on Actuals that SDP calculate s under Subparagraph 43. f.i is/ are greater than the New Limit(s) Based on

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Projections that SDP calculated under Subparagraph 43. a, then no further action shall be required and the New Limit(s) Based on Projections shall remain in effect

.

iii. If the New Limit(s) Based on Actuals that SDP calculate s under Subparagraph 43. f.i is/ are less than the New Limit(s) Based on Projections that SDP calculated under Subparag raph 43.a, then by no later than 30 days after the Startup of the permitted modifications, SDP shall: (1) commence complying with the New Limit(s) Based on Actuals; and (2) submit the revised, recalculated New Limit(s) Based on Actuals to EPA. After submission to EPA,

SDP shall consult with EPA about the New Limit(s) Based on

Actuals and secure EPA’s approval.

iv. Stipulated Penalties . If Subparagraph 43.f.iii applies, then by no later than 60 days after the Startup of the permitted modifications,

the New Limit(s) Based on Actuals identified in the submission to EPA under Subparagraph 43.f .iii (2) shall apply and form the basis for determining compliance for purposes of the stipulated penalty provisions of Subparagraphs 93.l and 93.m. If EPA disapproves

the New Limit(s) Based on Actuals, the New Limit(s) Based on

Actuals shall continue to apply for purposes of stipulated penalties until such time as other limitation(s) either is/are agreed upon between EPA and SDP or a dispute is resolved that sets forth revised limitation(s).

44. Limitations on Flaring at the SDP Refinery: 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 Subparagraphs 41.a.i and 41.a.ii,

and any revised limitations on flaring developed pursuant to Paragraph 43, the following shall

apply:

a. To the extent that SDP has instrumentation capable of calculating the volumetric flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam) in the Waste Gas, the contribution of all measured flows of any of these element s/compounds may be excluded

from the Waste Gas flow rate calculation

.

b. Flows during all periods (including but not limited to normal operations and periods of Startup, Shutdown, Malfunction, process upsets, relief valve leakages, utility losses due to an interruptible utility service agreement, and emergencies arising from events within the boundaries of

45Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 51 of 121

the Refinery), except those expressly described in the next sentence, shall be included. Flows that could not be prevented through reasonable planning and are in anticipation of or caused by a natural disaster, act of war or terrorism, or External Utility Loss may be excluded from the

calculation of flow rate.

c. Except for hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or water (steam ) contributions to the flow rate that are excluded by virtue of instrumentation measuring these flows, for any flow that SDP does not include in a computation, SDP shall submit the following

information in the semi -annual report due under Paragraph 85 of t his

Consent Decree: a description of the event that resulted in the exclusion; the date(s) and duration(s) of the flows caused by the event; the estimated

VOC and SO 2 emissions during the event; whether flows from the event are anticipated to persist afte r the notice, and if so, for how long; and the measures taken or to be taken to prevent or minimize the flows, including, for future anticipated flow, the schedule by which those measures will be implemented.

F. Flare Gas Recovery System at the Olefins Fl ares of the SDP Chemical Plant

45. Olefins FGRS: Capacity and Start

- Up Date

.

a. By no later than December 31, 2017, SDP shall complete installation and

commence operation of one or more Flare Gas Recovery System (s) for the Olefins Flares.

Except as provided in Paragraph 46 , the Operating Design Capacity of the Olefins FGRS (s) shall

be a minimum of 270 kscfh.

b. The design of each Olefins FGRS shall include one installed D uplicate

S pare Compressor.

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46. Process of Securing a Decrease in the Operating D esign Capacity of the Olefins

FGRS

.

a. SDP Request for an Operating Design Capacity of Less than 270 kscfh

.

Pursuant to the requirements of Subsection V.C of this Consent Decree (“Waste Gas

Minimization”), SDP shall undertake efforts to minimize Waste Gas flow to, inter alia , the

Olefins Flares. Because of those activities, by no later than SDP’s submission of its First

Updated WGMP, SDP may submit a request to EPA for approval of a decrease in the 270 kscfh

Operating Design Capacity of the Olefins FGRS. In any such request, SDP must:

i. Continue to commit to install (a) Duplicate Spare Compressor(s) consistent with the requirements of Paragraph 45.b; and

ii. Demonstrate that the newly requested Operating Design Capacity and number of compressors of the Olefins FGRS will result in an Estimated Percent Recovery of 80% or more as calculated in

accordance with the Paragraph 46.b.

b. Calculation of Estimate d Percent Recovery . In undertaking the

demonstration required in Subparagraph 46.a.ii, SDP shall use the hourly average Vent Gas

flow- adjusted data set (“ HFvg

- adjusted data set ”) , as defined below, to calculate the Estimated

Percent Recovery in accordance with the methodology specified in Appendix 2.4. In addition,

the following shall apply:

i. SDP shall submit, in editable spreadsheet form, the hourly average Vent Gas flow data set for each hour of the year that ends 30 days prior to the date of SDP ’s re quest for EPA approval of a decrease in the Operating Design Capacity of the Olefins FGRS (“HFvg

baseline data set”).

ii. To account for Vent Gas flow reductions that SDP will secure from specific sources of Vent Gas as a result of identified

modificati ons and/or identified revised operating practices that SDP, in its request for a decrease in the Olefins FGRS Operating Design Capacity, commits to complete between the date of its request and December 31, 2017, SDP shall adjust each hourly average Vent Ga s flow rate in the HFvg- baseline data set by

47Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 53 of 121

iii.

iv.

v. subtracting out the contribution to the flow from specific sources

of Vent Gas that SDP commits to eliminate

, i.e. , “Enforceable

Reductions.” SDP shall also submit an adjusted Hourly Average

Vent Gas flow data set (“HFvg

- adjusted data set”) that represents

the HFvg

- baseline data set as adjusted by the identified Enforceable Reductions. The HFvg- adjusted data set shall be submitted in editable spreadsheet form and shall include the hourly average Vent Gas flow d ata set as adjusted for each hour of the year that ends 30 days prior to the request for a decrease in the Olefins FGRS Operating Design Capacity.

SDP shall assume that the amount of time that the proposed size and number of Compressors will be “Avai lable for Operation” will equal the percentages specified in Subparagraph 47.b.

“Enforceable Reductions” shall mean reductions in the Vent Gas Flow that SDP shall secure from specific sources of Vent Gas as a

result of identified modifications and/or identified revised operating practices that SDP, in its request for a decrease in the Olefins FGRS Operating Design Capacity, commits to complete between the date of its request and December 31, 2017. To the extent that SDP commenced implementation of an y such modifications and/or revised operating practices prior to its request but the resulting Vent Gas Flow reductions were not yet realized and included in the Vent Gas Flow for the full one year period that is 30 days prior to the request, SDP may include them in the Enforceable Reductions. In its request, SDP shall include documentation supporting the scope and expected flow reduction(s) from the modifications and/or revised operating practices and a schedule for the implementation of these activities prior to December 31, 2017.

“Vent Gas Flow,” for all purposes in the equations used in this Paragraph, shall include flows during all periods (including but not limited to normal operations and periods of Startup, Shutdown, Malfunction, process upsets , relief valve leakages, External U tility Losses due to an interruptible utility service agreement, and emergencies arising from events within the boundaries of the Facilities), except those described in the next sentence. Vent Gas Flows that could not be prevented through reasonable planning and are in anticipation of or caused by a natural disaster, act of war or terrorism, or External Utility Loss are the only flows that shall be excluded from the calculation of flow. In making its request for a

smalle r Operating Design Capacity for the Olefins FGRS, SDP specifically shall describe the date, time, and nature of any event

48Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 54 of 121

that results in the exclusion of any Vent Gas Flows from its

calculation.

c. EPA Response to Request . EPA shall evaluate any reque st under

Subparagraphs 46 .a and b on the basis of its consistency with the requirements of those

Subparagraphs. If EPA does not act on SDP’s request within 90 days of submission, SDP may

invoke the accelerated dispute resolution provisions of Subsection X II. B of this Decree. The

new Design Operating Capacity shall take effect, if ever, on the date that EPA approves the

request or a dispute is resolved in SDP’s favor.

47. Olefins F GRS: Operation

.

a. General . After the December 31, 2017 deadline in Paragraph 45 .a, SDP

shall operate the Olefins FGRS (s) in a manner to minimize Waste Gas to the Olefins Flares while

ensuring safe chemical plant operations. SDP also shall operate the Olefins FGRS consistent

with good engineering and maintenance practices and in accordance with its design and the

manufacturer’s specifications.

b. Requirements Related to Compressors Being Available for Operation

. By

no later than June 30, 2018, SDP shall comply with the following requirements for the Olefins

FGRS when Po tentially Recoverable Gas is being generated :

i. An Olefins FGRS with two (2) Compressors (one of which is the required Duplicate Spare Compressor) shall have one compressor Available for Operation and/or in operation 98% of the time and two Compressors Available for Operation and/or in operation 90%

of the time . If these two Compressors are reciprocating Compressors, periods of maintenance on them and subsequent

restart may be included in the amount of time that the Compressors are Available for Operatio n when determining compliance with the requirement to have two Compressors Available for Operation and/or in operation 90% of the time; provided however, that these periods shall not exceed 1344 hours per Compressor in a five- year rolling sum period, rolled daily.

49Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 55 of 121

ii.

i ii

. An Olefins FGRS with more than two (2) Compressors (one of

which is the required Duplicate Spare Compressor ) where the total number of Compressors is represented by “n,” shall have n-1 Compressors Available for Operation and/or in operation 95% of

the time and n -2 Compressors Available for Operation and/or in operation at all times. The following periods may be included in

the amount of time that a Compressor is Available for Operation when determining compliance with the requirement to have “n

- 2” Compressors Available for Operation and/or in operation “at all

times” :

(1) Periods of maintenance on and subsequent restart of the equipment within the Olefins FGRS that is shared by all Compressors (for example, the water seal, the knock-out

dru m, valves), such that the entire FGRS must be shut down in order to undertake the maintenance; provided however, that these periods shall not exceed 336 hours i n a five

- year rolling sum period, rolled daily. SDP shall use

best efforts to schedule these ma intenance activities during

a turnaround of the Olefins unit. To the extent it is not practicable to undertake these maintenance activities during an Olefins turnaround, SDP shall use best efforts to minimize the generation of Waste Gas during such period s.

(2) Periods in which the “n -2” Compressors are shut down (including the subsequent restart) due to operating conditions (such as high temperatures or large quantities of entrained liquid in the Vent Gas) outside the design operating range of the Olefin s FGRS, including the

associated knock -out drum(s), such that the outage is necessary for safety and/or to preserve the mechanical integrity of the Compressors. By no later than 45 days after any such outage, SDP shall investigate the root cause and

all c ontributing causes of the outage and shall implement, as expeditiously as practicable, corrective action, if any, to prevent a recurrence of the cause(s). In the reports due

under Section IX of this Decree, SDP shall describe each outage that occurred under the conditions identified in this Subparagraph, including the date, duration, cause(s), corrective action, and the status of the implementation of

corrective action.

Period to be Used for Computing Percentage of Time

. For purposes of calculating compliance with the 90%, the 95%, and the 98% of time that a Compressor or group of Compressors must be Available for Operation and/or in operation, as required by

50Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 56 of 121

Subparagraphs 47.b.i and 47.b.ii, the period to be used shall be an 8760-hour rolling sum, rolled hourly, using only hours when Potentially Recoverable Gas was generated during all or part of the hour but excluding hours for flows that could not have been prevented through reasonable planning and were in anticipation of or caused by a natural d isaster, act of war or terrorism, or External Utility Loss . W hen no Potentially Recoverable Gas was generated during an entire hour, th en that hour shall not be used in computing the 8760-hour rolling sum . The r olling sum shall include only the prior 8760 1-hour p eriods when Potentially Recoverable Gas was generated during all or part of the hour, provided that the Potentially Recoverable Gas was not generated by flows that could not have been prevented through reasonable planning and were in anticipation of or caused by a natural disaster, act of war or terrorism, or External Utility Loss

.

G. Limitations on Flaring at the A&S and HIPA Flares of the SDP Chemical Plant

48. Conversion of A&S Flare to a Temporary

- Use Flare . By no later than June 30,

2013, SDP will convert the A&S Flare to a Temporary

- Use Flare by rerouting flow from the

A&S Flare to the HIPA Flare.

49. Limitation on VOC Emissions from the HIPA Flare . By no later than 24 months

after the Date of Entry, SDP shall not emit from the HIPA Flare more than 25 tons per year of

VOC s in a 365- day rolling sum period, rolled daily. SDP shall utilize the equations set forth in

Appendix 2.5 to calculate VOC emissions from the HIPA flare in any given 365- day r olling sum

p eriod

. After incorporation of the limit into a federally

- enforceable permit, nothing in this

Consent Decree shall prohibit SDP from seeking an increase in this limit (regardless of the

amount of the increase ) prior to termination of this Consent Decree if SDP undertake s a LAER

analysis through appropriate Texas state permitting authorities in order to secure the increase.

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H. Flare Combustion Efficiency

50. General Emission Standards Applicable to Covered Flares . By no later than the

dates set forth in Column F of Appendix 2.1, SDP shall comply with the requirements set forth in

this Paragraph at all times when the Covered Flare is In Operation.

a. Operation during Emissions Venting . SDP shall operate each Covered

Flare at all times when emissions may be vented to it.

b. No Visible Emissions . Except for periods of Startup, Shutdown, and/or

Malfunction, SDP shall operate each Covered Flare with no Visible Emissions. Method 22 in

40 C.F.R. Part 60, Appendix A, shall be used to determine compliance with this standard.

However, for purposes of this Consent Decree, Visible Emissions may be determined by a

person certified pursuant to Method 22 or documented by a video camera.

c. Flame Presence . SDP shall operate each Covered Flare with a flame

present at all times. SDP shall monitor the presence of the pilot flame using a thermocouple or

any other equivalent device to detect the presence of the pilot flame.

d. Monitoring According to Applicable Provisions . SDP 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.

e. Good Air Pollution Control Practices . At all times, including during

periods of Startup, Shutdown, and/or Malfunction, SDP shall implement good air pollution

control pra ctices to minimize emissions from each Covered Flare ; provided however, that SDP

shall not be in violation of this requirement for any practice that this Consent Decree requires

SDP 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.

52Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 58 of 121

51. Exit Velocity . Beginning no later than the dates set forth in Column C of

Appendix 2.1, except for periods of Startup, Shutdown, and/or Malfunction, SDP shall operate

each Covered Flare with an Exit Velocity less than 18.3 m/sec (60 ft/sec) on a one-hour block

average; provided however, that:

a. If the Covered Flare combusts Vent Gas with a Net Heating Value of greater than 1000 BTU/scf, SDP 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

b. If the Covered Flare has a maximum permitted velocity (V max ), SDP may operate the Cove red Flare with an Exit Velocity less than V max provided that it also operates the applicable Flare with an Exit Velocity of less than 122 m/sec (400 ft/sec) on a one-hour block average. 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 consistent with Appendix 1.6.

52. Revisions to 40 C.F.R. §§ 60.18(b)–(f) and/or 63.11(b) . To the extent that, from

the Date of Lodging of this Consent Decree until its termination, r evisions to 40 C.F.R.

§§ 60.18(b)–(f) and/or 63.11(b) are final and effective that are inconsistent with any of the

requirements in Paragraphs 50.a–d or 51, then SDP shall comply with the final, effective

regulations and any requirements in Paragraphs 50.a–d and/or 51 that are not inconsistent with

these final, effective regulations. As used in this Paragraph, “inconsistent” mean that compliance

with both provisions is not possible.

53. Work Practice Standards for each Covered Flare.

a. Regular

- Use Covered Flares

. By no later than the dates set forth in

Column G of Appendix 2.1, utilizing the instrumentation and controls required to be installed

pursuant to Paragraphs 18 –24, SDP shall install on each Regular

- Use Covered Flare an

Automatic Control System that shall:

53Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 59 of 121

i. Automate the control of the Supplemental Gas flow rate to the respective Flare; and

ii

. Automate the control of the Total Steam Mass Flow Rate to the respective Flare.

For the Regular- Use Covered Flares, SDP shall operate these Automated Cont rol Systems

immediately upon installation.

b. Temporary -Use Covered Flares

. After the dates set forth in Column G of

Appendix 2.1, SDP shall not direct any Sweep, Supplemental, and/or Waste Gas to any

Temporary

- Use Flare, until an Automatic Control Syst em that conforms to the requirements of

Subparagraph 53 .a is installed. SDP shall operate the Automated Control System whenever any

Sweep, Supplemental, and/or Waste Gas is directed to the Temporary

- Use Covered Flare.

During those periods after the installation of the ACS when the Temporary

- Use Covered Flare is

not C apable of Receiving Sweep, Supplemental and/or Waste Gas, the operation of the AC S is

not required; provided however, that prior to the Startup of a Temporary

- Use Covered Flare,

SDP shall take all necessary steps to ensure that the ACS is capable of continuous operation for

the full duration of the use of the Temporary- Use Covered Flare.

54. Exception to Work Practice Standard s in Subparagraph 53 . SDP manually may

override the operation of the Automatic Control System (s) required in Subparagraph 53 if the

exception in Paragraph 60 applies, and/or during Startup, Shutdown, or Malfunction of a

Covered Flare or a process unit that feeds a Covered Flare , and/or to achieve the following:

a. Stop Smoke Emissions that are occurring;

b. Meet the Net Heating Value requirements of Paragraph 56;

c. Prevent extinguishing the Flare;

d. Protect personnel and process safety;

54Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 60 of 121

e. Stop Discontinuous Wake Dominated Flow ; and/or

f. Stop acoustic disturbances that are occurring.

55. Operation According to Design . By no later than the dates set forth in Column H

of Appendix 2.1, SDP shall operate and maintain each Covered Flare in accordance with its

design, except if, and only to the extent that, operation and maintenance of the Covered Flare in

conformance with its design conflicts with compliance with one or more of the requirements of

this Consent Decree

56. Net Heating Value Standards

.

a. Net Heating Value of Vent Gas ( NHV vg ) . Beginning on the Date of

Lodging and continuing until the earlier of: (i) terminat ion 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, SDP shall operate each Covered Flare, except as provided in Paragraph 60, with an

NHV vg of greater than or equal to 300 BTU/scf at all times that the gas being combusted in the

Covered Flare is subject to the control requirements of 40 C.F.R. § 60.18(c)(3)(ii) and/or

§ 63.11(b)(6)(ii).

b. Net Heating Value of Combustion Zone Gas ( NHV cz ) for Regular

- Use

Covered Flares , excluding the Olefins Ground Flare . By no later than the dates set forth in

Column H of Appendix 2.1, and except as provided in Paragraph 60 .a , SDP shall calculate an

NHV cz

- limit at each Regular

- Use Covered Flare no less frequently than every fifteen min utes.

Except as provided in Paragraph 60 .a , SDP shall operate each Regular

- Use Covered Flare so as

to ensure that the Regular

- Use Covered Flare’s NHV cz , on a three-hour rolling average, rolled

every fifteen minutes, is greater than or equal to its NHV cz -l imit on a three-hour rolling average,

55Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 61 of 121

rolled every fifteen minutes. SDP shall utilize the equations and directives set forth in

Appendix 1.3 to meet the requirements of this Subparagraph 56.b.

c. Net Heating Value of Combustion Zone Gas ( NHV cz ) for the O lefins

Ground Flare. By no later than the date set forth in column H of Appendix 2.1, and except as

provided in Paragraph 60.a , SDP shall calculate the NHV cz at the Olefins Ground Flare no less

frequently than every 15 minutes . Except as provided in Paragraph 60.a , SDP shall operate the

Olefins Ground Flare so as to ensure that its NHV cz , on a three-hour rolling average basis, rolled

every fifteen minutes, is equal to or greater than 500 BTU/scf, using a Net Heating Value for

hydrogen of 1212 BTU/scf. SDP shall utilize Steps 3 and 6 in Appendix 1.3 to calculate NHV cz .

d. Net Heating Value of Combustion Zone Gas ( NHV cz ) for Temporary

- Use

Covered Flares

. After the dates set forth in Column H of Appendix 2.1, SDP shall not direct any

Sweep, Supplemental, and/or Waste Gas to any Temporary

- Use Flare unless SDP calculate s the

NHV cz at such Temporary

- Use Flare during its operation, except as provided in Paragraph 60.b.

SDP may use either a gas chromatograph or Net Heating Value Analyzer to calcu late/measure

the Net Heating Value of the Vent Gas. If SDP uses a gas chromatograph to calculate Net

Heating Value, SDP shall use a Net Heating Value for hydrogen of 1212 BTU /scf and shall

calculate the NHV cz no less frequently than every 15 minutes. If SDP uses a Net Heating Value

Analyzer to measure Net Heating Value of the Vent Gas

, SDP shall calculate the NHV cz no less

frequently than every five minutes. Except as provided in Paragraph 60.b , SDP shall operate

each Temporary

- Use Covered Flare so as to ensure that its NHV cz is greater than or equal to 355

BTU/scf : (i) on a three-hour rolling average basis, rolled every fifteen minutes if a gas

chromatograph is used; (ii) on a one-hour rolling average basis, rolled every five minutes

, if a

56Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 62 of 121

Net Heating Value Analyzer is used . SDP shall utilize Steps 3 and 6 in Appendix 1.3 to

calculate NHV cz .

57. S/VG Standard s (Total

- Steam

- to

- Vent

- Gas Ratio Standards)

.

a. Interim Period . Beginning on the Date of Lodging and continuing until

the date s set forth in Column H of Appendix 2.1, and except as provided in Subparagraph 57. c

and Paragraph 60, SDP shall use best efforts to operate each Covered Flare at less than or equal

to an S/VG mass of 3.0 on a one-hour rolling average, rolled every five minutes

.

b. After Interim Period . By no later than the dates set forth in Column H of

Appendix 2.1, and except as provided in Subparagraph 57.c and Paragraph 60 , SDP shall operate

each Covered Flare at less than or equal to an S/VG mass of 3.0 on a one-hour rolling average,

rolled every five minutes. For each Covered Flare, SDP shall record the S/VG mass

.

c. Exceptions . Notwithstanding the requirements of Subparagraphs 57 .a and

57.b, SDP is not subject to the emissions standards in those Subparagraphs if the exception in

Paragraph 60 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 56;

iii. Prevent extinguishing the Flare; and/or

iv. Protect personnel and process safety.

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58. Prohibition on Discontinuous Wake Dominated Flow or Requirement for

M inimum Momentum Flux Ratio (“ MFR ”) for Covered Flares

.

a. The requirements of this Paragraph have no applicability to Ground

Flares; therefore, the Olefins Ground Flare is not subject to this Paragraph. All references to

“Covered Flares” in this Paragraph exclude the Olefins Ground Flare.

b. By no later than the dates set forth in Column H of Appendix 2.1, for each

Covered Flare

, SDP shall comply with either Subparagraph 58.c. or 58.d. In the first

semi

- annual report due after the applicable compliance date, SDP shall identify which

compliance option it selects for each Covered Flare. SDP may select different alternatives for

different Covered Fl ares and may change its election for any given Covered Flare by providing

EPA with 30 days prior notice of the change. The notice shall include the reasons SDP is

changing its compliance option.

c. Prohibition on Discontinuous Wake Dominated Flow

.

i. SD P shall not operate the Covered Flares with Discontinuous Wake Dominated Flow (as defined above and in Appendix 1.12 of the Consent Decree) , except for periods not to exceed a total of five minutes during any two consecutive hours. SD P shall add Supple mental 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 58.c.i, for all operators and supervisors with responsibility and/or oversight for the operation of each Covered Flare, SD P shall complete training on the meaning and prevention of Discontinuous

Wake Dominated Flow. After this effective date, operators shall monitor the operation of each Covered Flare at intervals appropriate for the weather conditions and service of the Covered Flare in order to comply with the prohibition in Subparagraph 58.c.i.

58Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 64 of 121

d. MFR Requirements

. MFR shall be calculated in accordance with the

equations, conversion factors, MFR constants, MFR measured variab les, and MFR calculated

variables set forth in Appendix 1.5. SDP shall either:

i. Maintain a minimum MFR of 0.0010 for the Olefins II and

Olefins III Flares and a minimum MFR of 0.0030 for all other Covered Flares, each on a 60- minute rolling average , rolled every 5 minutes; or

ii. Propose a Flare- specific minimum MFR

. SD P shall submit such a proposal to EPA for approval. In any such proposal, SD P shall demonstrate, using , at a minimum, photographs correlated to MFR, that at the proposed minimum MFR , Discontinuous Wake

Dominated Flow will not occur for the Covered Flare that is the subject of the request.

iii. Calculation of MFR “on a 60-minute rolling average, rolled every 5 minutes,” when there are more than 5 but less than 12

consecutive 5 minute averages of MFR . During any period of

Vent Gas flow to the Covered Flare when there are more than 5 but less than 12 consecutive 5 minute averages of MFR, the MFR “on

a 60 -minute rolling average, rolled every 5 minutes” shall be calculated using the 5

- mi nute averages that are greater than “0” during the period and for which the exception in Paragraph 58.e does not apply ; the 5

- minute averages when MFR is “0” because

either there is no Vent Gas flow or the exception in Paragraph 58.e applies shall not be u sed in calculating the 60

- minute rolling average, rolled every 5 minutes.

e. Exceptions to the Prohibition on Discontinuous Wake Dominated Flow

and MFR Requirements. Notwithstanding Subparagraphs 58.c. and 58.d, SD P shall not be

required to add Supplemental Gas , and the requirements in those Subparagraphs are not

applicable

, at any time that Paragraph 60 applies and/or the wind speed at the Covered Facilities

is greater than or equal to 35 mph on a 60- minute rolling average , rolled every 5 minutes.

59. 98% Combustion Efficiency . By no later than the dates set forth in Column H of

Appendix 2.1, SDP shall operate each Covered Flare with a minimum of a 98% Combustion

Efficiency at all times when Waste Gases are vented to it. To demonstrate continuous

59Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 65 of 121

compliance with the 98% Combustion Efficiency, SDP s hall operate each Covered Flare in

compliance with the applicable requirements in Paragraphs 56–58.

60. Exception for Instrument Downtime

.

a. Regular

- Use Covered Flares . For Regular- Use Covered Flares, a failure to

comply with the work practices or standards in Subparagraphs 53.a, 56.a, 56.b, 56.c, 57.a, 57.b,

58.c, or 58.d shall not constitute a violation of such work practice or standard if the

noncompliance results from downtime of instruments or equipment due to the following:

i. Malfunction of an instrument, for an instrument needed to meet the requirement(s);

ii. Maintenance following instrument Malfunction, for an instrument needed to meet the requirement(s);

iii

. Scheduled maintenance of an instrument in accordance with the manufacturer’s recommended schedule, for an instrument needed to meet the requirement(s); and/or

iv

. Quality Assurance/Quality Control activities on an instrument needed to meet the requirement(s).

This exception shall no longer be applicable if the activities in Subparagraphs 60.a.i–60. a.iv

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 1.10.

b. Temporary

- Use Covered Flares and Portable Flares . For Temporary- Use

Covered Flares and Portable Flares , a failure to comply with the work practices or standards in

Subparagraphs 53.b, 56.a, 56.d, 57.a, 57.b, 58.c, or 58.d shall not constitute a violation of such

work practice or standard if the noncompliance results from downtime of instruments or

equipment due to the activities in Subparagraphs 60.a.i–iv; provided however, that this exception

shall no longer be applicable if the activities in Subparagraphs 60.a.i– iv exceed 5% of the time

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that the Temporary

- Use Covered Flare or Portable Flare is In Operation and c apable of r eceiving

Waste, Supplemental

, and/or Sweep Gas during a n uninterrupted time period. The calculation of

instrument downtime shall be made in accordance with 40 C.F.R. § 60.13(h)(2) and Paragraph

VI of Appendix 1.10.

61. Inapplicability of Paragraphs 56–59 . The requirements of Paragraphs 56–59 are

not applicable to any Covered Flare or Portable Flare when the only gas or gases being vented to

the Covered Flare or Portable Flare is/are Pilot Gas and/or Purge Gas.

62. Recordkeeping: Timing and Substance . SDP shall comply with the following

recordkeeping requirements:

a. By no later than three months after the dates set forth in Column C of

Appendix 2.1, SDP shall calculate and record each of the following parameters:

i. Total Steam Volumetric Flow Rate (in scfm) and Total Steam Mass Flow Rate (in lb/hr) (in accordance with the recording and averaging times required in Par agraph 27)

ii. Vent Gas Volumetric Flow Rate (in scfm) and Vent Gas Mass Flow Rate (in lb/hr) (in accordance with the recording and averaging times required in Paragraph 27)

iii. S/VG

mass (in lb steam/lb Vent Gas) (in accordance with the averaging times in Subparagraph 57.b)

iv. NHV vg (in BTU/scf) (on a one-hour block average)

v. NHV
cz (in BTU/scf) (in accordance with the averaging times in Subparagraphs 56.b, 56.c, and 56.d)

vi. NHV
cz

- limit (in BTU/scf) (in accordance with the averaging times in Subparagraphs 56.b)

b. By no later than six months after the first full calendar quarter starting on

or after the dates set forth in Column C of Appendix 2.1, commencing if and when the excepted

activities in Subparagraphs 28.a–28.d for any instrument subject to Paragraph 28 exceed 110

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hours in any calendar quarter for a Regular

- Use Covered Flare, or 5% of the time that a

Temporary

- Use Covered Flare is In Operation and C apable of R eceiving Sweep , Supplemental,

and/or Waste Gas during an uninterrupted time period, SDP shall record the duration of the

deviation, an explanation of the cause(s) of the deviation, and a description of the corrective

action(s) that SDP took.

c. By no later than the dates set forth i n Column G of Appendix 2.1 for

compliance with the work practice standards in Paragraph 53 : (i) SDP shall record eac h time it

manually overrides an Automatic Control System, including the date, time, duration, reason for

the override, and corrective actio ns that SDP took; and (ii) where the reason for the override was

to stop Smoke Emissions that were occurring and/or to stop Discontinuous Wake Dominated

Flow , SDP shall include a copy of the digital video record (with a time stamp) of the flare during

the period of the manual override.

d. By no later than the dates required in Column F of Appendix 2.1 for

compliance with the standards in Paragraph 50, and by no later than the dates required in

Column H of Appendix 2.1 for compliance with the emissions standards in Paragraphs 56–59 , at

any time that SDP deviates from those standards, SDP shall record the duration of the deviation,

an explanation of the cause(s) of the deviation, and a description of the corrective action(s) that

SDP took.

63. Portable Flares

.

a. Applicability . The provisions of this Paragraph shall apply to Portable

Flares.

b. Distinction between Planned and Unplanned Outages of Covered Flares.

For purposes of this Paragraph, a “planned” outage shall mean an outage of a Regular

- Use

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Cover ed Flare that is scheduled 30 days or more in advance of the outage. An “unplanned”

outage is an outage of a Covered Flare that either is scheduled less than 30 days in advance or is

unscheduled.

c. 504 hours or less . For any planned or unplanned outage of a Covered

Flare that SDP knows or reasonably anticipates will result in 504 hours or less of downtime on a

1095- day rolling sum period, rolled daily, SDP shall make good faith efforts to ensure that the

Portable Flare that replaces the Covered Flare c omplies with all of the requirements of this

Consent Decree that are applicable to the Covered Flare that the Portable Flare replaces.

d. More than 504 hours.

i. Planned . For any planned outage of a Regular

- Use Covered Flare

that SDP knows or reasonably can anticipate will last 504 hours or

more on a 1095- day rolling sum period, rolled daily, SDP shall

ensure that the Portable F lare complies with all of the requirements

of this Consent Decree related to the Regular

- Use Covered Flare

t hat it replaces as of the date that the Portable F lare is In Operation

and C apable of R eceiving Waste, Supplemental, and/or Sweep
Gas, except that, in lieu of having to comply with the applicable dynamically

- calculated NHV cz

- limit under Subparagraph 56.b or the

355 BTU/scf static NHV cz

- limit under Subparagraph 56.d, SDP shall operate the Portable Flare so that, except as provided in Paragraph 60.b , the Portable Flare’s NHV cz is greater than or equal to 325 BTU/scf: (i) on a three-hour rolling average, rol led every fifteen minutes if a gas chromatograph is used to calculate NHV cz ; (ii) on a one-hour rolling average, rolled every five minutes if a Net Heating Value Analyzer is used to calculate NHV cz . SDP shall utilize Steps 3 and 6 in Appendix 1.3 to calcu late NHV cz .

ii. Unplanned . For any unplanned outage of a Covered Flare that, in advance of the outage, SDP cannot reasonably anticipate will last longer than 504 hours, SDP shall ensure that the Portable F lare complies with all of the requirements of this Consent Decree related to the Covered Flare that it replaces by no later than 30 days after the date that SDP knows or reasonably should have known that the outage will last 504 hours or more , except that, in lieu of having to comply with the applicable dynamically

- calculated NHV cz

- limit under Subparagraph 56.b or the

355 BTU/scf static NHV cz

- limit under Subparagraph 56.d, SDP shall

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operate the Portable Flare so that, except as provided in Paragraph 60.b, the Portable Flare’s NHV cz is greater than or equal

to 325 BTU/scf: (i) on a three-hour rolling average, rolled every fifteen minutes if a gas chromatograph is used to calculate NHV cz ; (ii) on a one-hour rolling average, rolled every five minutes if a Net Heating Value Analyzer is used to calculate NHV cz . SDP shall utilize Steps 3 and 6 in Appendix 1.3 to calculate NHV cz .

iii. SDP shall calculate NHV cz using a Net Heating Value for hydrogen

of 1212 BTU /scf if the Portable Flare is equipped with a gas chrom atograph for calculating Net Heating Value

.

e. Recordkeeping . SDP shall keep records sufficient to document

compliance with the requirements of this Paragraph any time it uses a Portable F lare.

I. NSPS Subpart A, J, and Ja Applicability

64. NSPS Subpa rts A , J, and Ja.

a. NSPS Subparts A and J

. As of the Date of Lodging, each SDP Refinery

Covered Flare shall continue to be an “affected facilit y” within the meaning of Subparts A and J

of 40 C.F.R. Part 60 and shall comply with all of the requirements of Subparts A and J, including

but not limited to 40 C.F.R. §§ 60.104(a)(1) and 60.105(a)(4), by no later than the Date of

Lodging and continuing until November 11, 2015.

b. NSPS Subparts A and Ja

. Each SDP Refinery Covered Flare shall be an

“affected facility” within the meaning of Subparts A and Ja of 40 C.F.R. Part 60, and shall

comply with all of the requirements of Subparts A and Ja on and after November 11, 2015. After

November 11, 2015, Subpart J shall not apply to the SDP Refinery Covered Flares.

J. Eliminating Fuel Gas Flow from the SDP Refinery to the SDP Chemical Plant

Covered Flares

65. SDP shall take all steps necessary to locate and eliminate all connections and/or

operations which could allow Fuel G as from the SDP Refinery to be routed to the SDP Chemical

Plant Covered Flares in accordance with these requirements:

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a. By no later than December 31, 2014, SDP shall physically remov e piping

and/ or physically isolat e piping with a welded blind where such piping potentially allow s Fuel Gas to be routed to the Olefins II and Olefins III

Flares during emergency situations ;

b. By no later than December 31, 2016, SDP shall permanently cease using

the Butane Butylene Hydrotreater Unit to process any refinery streams and

shall eliminate the possibility that Fuel Gas from such operations may be

routed from the Butane Butylene Hydrotreater Unit to the Olefins Flares;

and

c. By no later than December 31, 2016, SDP shall discover and permanently eliminate all other potential connec tions and/or operations which could

allow Fuel Gas to be routed to the SDP Chemical Plant Covered Flares

.

K. Incorporation of Consent Decree Requirements into Federally Enforceable Permits

66. Permits Needed to Meet Compliance Obligations . If any compliance obligation

under this Section V requires SDP to obtain a federal, state, or local permit or approval, SDP

shall submit timely and complete applications and take all other actions necessary to obtain all

such permits or approvals. SDP may seek relief under the provisions of Section XI of this

Decree (Force Majeure) for any delay in the performance of any such obligation resulting from a

failure to obtain, or a delay in obtaining, any permit or approval required to fulfill such

obligation, if SDP has submitted timely and complete applications and has taken all other actions

necessary to obtain all such permits or approvals.

67. Permits to Ensure Survival of Consent Decree Limits and Standards after

Termination of Consent Decree

.

a. Prior to termination of this Consent Decree, SDP shall submit complete

applications to the appropriate permitting authorities in the State of Texas to incorporate the

limits and standards listed in Subparagraph 67.b into non- Title V, federally enforceable permits

that will survive te rmination of this Consent Decree. Prior to termination of this Consent

Decree, SDP shall submit to the appropriate permitting authorities in the State of Texas,

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appropriate applications, amendments and/or supplements to incorporate as “applicable

requirem ents” the limits and standards listed in Subparagraph 67.b to ensure that these limits and

standards survive termination of this Consent Decree.

b. The limits and standards imposed by the following Paragraphs of this

Consent Decree shall survive terminat ion: 17–24, 26–29, 40, 47, 49, 50–51, 53–55, 56.b–d,

57.b–c, 58.c–e, 59–62, 64–65. Nothing in this Paragraph shall prohibit SDP from seeking to

incorporate Paragraph 25 in a permit that survives termination of this Decree.

68. Modifications to Title V Operating Permits . Prior to termination of this Consent

Decree, SDP shall submit complete applications to the appropriate permitting authorities in the

State of Texas to modify, amend, or revise the Title V permit of each Covered Facility to

incorporate the limits and standards identified in the preceding Paragraph in to the Title V

permits. The Parties agree that the incorporation of these emission limits and standards into

Title V Permits shall be done in accordance with applicable state or local Title V rules. The

Parties agree that the incorporation may be by “amendment” under 40 C.F.R. § 70.7(d) and

analogous state Title V rules, where allowed by state law.

VI. EMISSION CREDIT GENERATION

69. Prohibitions

.

a. Definition . “CD Emissions Reductions” shall mean any NO

x , SO 2 , H 2 S,

PM, PM TOTAL , PM 10 , PM 2.5 , VOC, or CO emissions reductions that result from any projects

conducted or controls used to comply with this Consent Decree.

b. Prohibitions

.

i. SDP shall neither generate nor use any CD Emissions R eductions: as netting reductions; as emissions offsets; to apply for, obtain, trade, or sell any emission reduction credits; or in determining whether a project would result in a significant emissions increase

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or significant net emissions increase in any P SD, major nonattainment, and/or minor New Source Review permit or permit proceeding. Baseline actual emissions during any 24 -month period selected by SDP shall be adjusted downward to exclude any portion of the baseline emissions that would have been eli minated

as CD Emissions Reductions had SDP been complying with this Consent Decree during that 24-month period;

ii. Any CD Emissions Reductions that result from the Waste Gas minimization requirements of Paragraphs 30–37 may not be used as netting reduct ions, as emissions offsets, or in determining whether a project is “major” in any PSD, major non

- attainment and/or minor New Source Review permit or permit proceeding

even if those Reductions result in emissions lower than the

allowable level under the fla ring limitations in Paragraph 41. Baseline actual emissions during any 24 -month period selected by

SDP shall be adjusted downward to exclude any portion of the

baseline emissions that would have been eliminated as Waste Gas

minimization related CD Emission s Reductions as if SDP previously achieved the reductions during that 24-month period;

iii. Except as provided in Subparagraph 70.b, SDP shall not apply for, obtain, trade, or sell any emission reduction credits that result from

CD Emissions Reductions.

70. Outside the Scope of the Prohibition . Nothing in this Section is intended to

prohibit SDP from seeking to nor prohibit the State of Texas from denying SDP’s ability to:

a. Use or generate netting reductions or emission reduction credits for refinery units that are not subject to an emission limitation pursuant to this
Consent Decree;

b. U se CD Emission s Reductions for the Covered Facil it ies’ compliance with any rules or regulations designed to address regional haze or the

non- attainment status of any area (excluding PSD and Non- Attainment

New Source Review rules , but including, for example, RACT rules ) that apply to the Covered Facilit ies ; provided, however, that SDP shall not be

allowed to trade or s ell any CD Emissions Reductions.

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VII. MITIGATION PROJE CT S

71. SDP shall undertake the “Mitigation Project: North Effluent Treater Controls” set

forth in Appendix 2.6 of this Decree in accordance with the requirements of Appendix 2.6

.

72. SDP shall undertake the “Mitigation Project: T ank Controls” set forth in

Appendix 2.7 of this Decree in accordance with the requirements of Appendix 2.7.

73. SDP shall undertake the “Mitigation Project: ACU and BEU Controls” set forth

in Appendix 2.8 of this Decree in accordance with the requirements of Appendix 2.8.

74. By signin g this Consent Decree, SDP certifies that it is not required to perform or

develop th ese Mitigation Project s by any federal, state, or local law or regulation and is not

required to perform or develop th ese Project s by agreement, grant, or as injunctive re lief awarded

in any other action in any forum; that th ese Project s are not ones that SDP was planning or

intending to construct, perform, or implement other than in settlement of the claims resolved by

this Decree; and that SDP will not receive any reimbur sement for any portion of the costs of

th ese Project s from any other person.

75. Mitigation Project Progress and Completion Reports

. SDP shall include in each

report required under Paragraph 85, a status update on each Mitigation Project required by this

Sect ion. In addition, the report required by Paragraph 85 for the period in which the Project is

completed shall contain the following information:

a. A detailed description of the Project as implemented;

b. A description of any problems encountered in comp leting the Project and the solutions thereto;

c. A description of the environmental and public health benefits resulting from implementation of the Project (with a quantification of the benefits and an estimate of the pollutant reductions); and

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d. A certification that the Project has been fully implemented pursuant to the provisions of this Decree.

VIII

. SUPPLEMENTAL ENVIRO N MENTAL PROJECTS

76. SDP shall implement as a Supplemental Environmental Project (“SEP”) a project

to install and operate a n open path air monitor on the fenceline of the Covered Facilities (“Fence

Line Open Path Monitoring SEP”), in accordance with this Paragraph and the criteria, terms, and

procedures in Appendix 2.9 of this Consent Decree. SDP shall spend not less than $1 million to

implement this SEP

. SDP shall undertake the tasks required for implementing the Fence L ine

Open Path Monitoring SEP in accordance with the schedule required by Appendix 2.9.

77. SDP shall implement a SEP designed to reduce diesel emissions from school

bus es and /or non-school bus publicly owned vehicles in the vicinity of the Covered Facilities

(“Diesel Retrofit SEP”) in accordance with this Paragraph and the criteria, terms and procedures

in Appendix 2.10. SDP shall spend no less than $200,000 to implement this SEP. No SEP funds

shall be used for testing or demonstration. SDP shall complete the implementation of the Diesel

Retrofit SEP by no later than 24 months after the Date of Entry

.

78. With respect to the Diesel Retrofit SEP, SDP certifies under penalty of law that it

would have agreed to perform a comparably valued, alternative project other than a diesel

emissions reduction Supplemental Environmental Project if EPA were precluded by law from

accepting a diesel emissions reduction Supplemental Environme ntal Project

.

79. SDP is responsible for the satisfactory completion of the Fence Line Monitoring

SEP and the Diesel Retrofit SEP as provided in this Consent Decree. SDP may use contractors

or consultants in planning and implementing the SEPs.

a. If SDP completes the SEPs in accordance with all applicable requirement s but does not expend the entire amount specified in Paragraph s 7 6 or 77,

SDP shall pay the difference between the amount expended as

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demonstrated in the certified cost report and the amount specified in Paragraph s 76 or 77 (as applicable). The difference shall be paid as provided in Section X of this Consent Decree.

b. As an alternative to payment of such amount, SDP may request, and EPA may, in its sole discretion, approve use of the unexpended SEP funds for

an alternative SEP.

80. With regard to the Fence Line Open Path Monitoring and Diesel Retrofit SEP s,

SDP certifies the truth and accuracy of each of the following:

a. That all cost information provided to EPA in connection with EPA’s approval of these SEPs is complete and accurate and that SDP in good faith estimates that the cost to implement the Fence Line Open Path Monitoring SEP is $1 million and the cost to implement the Diesel Retrofit SEP is $200,000;

b. That, as of the date of executing this Consent Decree, SDP is not required to perform or develop the se SEP s by any federal, state, or local law or regulation and is not required to perform or develop the se SEP s by agreement, grant, or as injunctive relief awarded in any other action in any forum;

c. That the se SEP s are not project s that SDP was planning or intending to construct, perform, or implement other than in settlement of the claims

resolved in this Consent Decree;

d. T hat SDP has not received and will not receive credit for the SEPs in any other enforcement action;

e. T hat SDP will not receive any reimbursement for any portion of the SEPs from any other person;

f. T hat SDP is not a party to any Open F ederal Fina ncial As sistance Transaction that is or could be used to fund the same activity as the SEP s; and

g. That, to the best of SDP ’s knowledge and belief based upon reasonable inquiry:

i. There is no open F ederal F inancial As sistance T ransaction that is funding or could fund the same activity as the SEPs; and

ii. T he activity covered by these SEP s has not been described in an unsuccessful Federal Financial Assistance Transaction proposal

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submitted by SDP to EPA w ithin two years of the date of executing this Consent Decree (unless the project was barred from funding as statutorily ineligible ).

81. SDP shall include in each report required by Paragraph 85 of Part IX (Reporting)

a description of its progress toward implementing the SEP required by this Section. In addition,

the report required by Paragraph 85 for the period in which the SEP is completed will contain the

following information with respect to the SEP (“SEP Completion Report”):

a. A detailed description of the SEP as implemented. For the Diesel Retrofit
SEP, t he description shall include, with respect to each retrofit, the following information:

i. Vehicle owner with contact name and phone number;

ii. Vehicle type (e.g., mass transit bus, school bus);

iii. Model year;

iv. Engine Manufacturer;

v. Actual, or if not known, estimated or projected, annual miles or hours of operation;

vi. Retrofit type (e.g., oxidation catalyst, particulate filter);

vii. Retrofit cost per vehicle (separate out installation costs);

viii. Actual, or if not known, estimated or projected, annual fuel usage (gal/yr);

ix. Actual, or if not known, estimated or projected, annual emissions reductions (PM, HC, CO);

x. Copy of invoices for purchase of control technology;

xi. Name of the technology installed as identified on the EPA or CARB webpages:

http://www.epa.gov/otaq/retrofit/verif

- list.htm

http://www.epa.gov/otaq/smartway/transport/whatsmartway/verified -technologies.htm#idle

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http://www.arb.ca.gov/diesel/verdev/vt/cvt.htm

b. A description of any problems encountered in completing the SEP and the solutions thereto;

c. A n itemized list of all eligible SEP costs expended;

d. Certification that the SEP has been fully implemented pursuant to the provisions of this Decree; and

e. A description of the environmental and public health benefits re sulting from implementation of the SEP (with a quantification of the benefits and pollutant reductions, if feasible).

EPA may require information in addition to that described in this Paragraph, in order to evaluate

SDP ’s SEP Completion Report.

82. Disputes concerning the satisfactory performance of th e Fence Line Monitoring

and Diesel Retrofit SEP s and the amount of eligible SEP costs may be resolved under

Section XII of this Decree (“Dispute Resolution”). No other disputes arising under this Section

shall be subject to Dispute Resolution.

83. Any public statement, oral or written, in print, film, or other media, made by SDP

and referring to one and/or both of the SEPs under this Decree shall include the following

language: “This project was undertaken in conne ction with the settlement of an enforcement

action, United States v. Shell Oil Co., et al. , taken on behalf of the EPA under the Clean Air

Act.”

84. For federal income tax purposes, SDP agrees that it will neither capitalize into

inventory or basis nor deduct any costs or expenditures incurred in performing either the Fence

Line Monitoring SEP or the Diesel Retrofit SEP

.

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IX

. REPORTING REQUIREMENTS

85. Semi -Annual Reports . On the dates and for the time periods set forth in

Paragraph 88, SDP shall submit to EPA in the manner set forth in Section XV I (Notices) the

following information:

a. A progress report on the implementation of the requirements in Section V of this Decree (Complian ce Requirements) at the Covered Facilities ;

b. A description of any problems anticipated with respect to meeting the requireme nts of Section V at the Covered Facilities ;

c. A description of the status of the Mitigation Project s in Section VII of this Decree (Mitigation Project);

d. A description of the status of the SEPs in Section VIII of this Decree;

e. Monitoring equipment/instrument downtime; override of Automatic Control System (“ASC”) ; exceedances of emission standards ; and compliance with compressor availability requirements ; as described in Paragraph 86;

f. For the semi -annual report due on July 31 of each year, annual emissions data, as described in Paragraph 87;

g. Any additional matters required by any other Paragraph of this Consent

Decree to be submitted in the semi -annual report; and

h. Any additional matters tha t SDP believes should be brought to the

attention of EPA.

86. Monitoring Instrument/Equipment Downtime; Override of ACS; and Emissions

Exceedances . On and after the date of applicability of any work practice or standard, SDP shall

provide a summary of the following, per Covered Flare per calendar quarter (hours shall be

rounded to the nearest tenth):

a. Monitoring Instrument/Equipment Downtime

. The total number of hours of downtime of each monitoring instrument/ equipment required pursuant

to Paragraphs 18–20 and 22–24 expressed as both an absolute number and a percentage of time the Covered Flare that the instrument /equipment

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monitors is In O peration and C apable of R eceiving Sweep, Supplemental, and/or Waste Gas;

b. Monitoring Instrument/Equipment Down time . If the total number of hours of downtime of any monitoring instrument/equipment required pursuant to Paragraphs 18–20 and 22–24 exceeds 110 hours in any calendar quarter (for a Regular -Use Covered Flare) or 5% of the operating time (for a Temporary

- Use Covered Flare or Portable Flare), 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 Contro l System . The total number of hours in

which SDP manually overrode the ACS required in Paragraph 53, expressed both as an absolute number of hours and a percentage of time

the Covered Flare was I n O peration and Capable of Receiving Sweep, Supplemental, an d/or Waste Gas ; provided however, that for any hour identified, the report shall describe either or both of the following: (i) if the reason for the override was one of the exceptions identified in Paragraph 54, a statement of which exception; or (ii) if the total number of hours in which the ACS was overridden was less than 110 hours (for a Regular -Use Covered Flare) or less than 5% of the operating time (for a Temporary -Use Covered Flare) and was caused by one or more of the exceptions identified in Para graph 60, 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 Paragraph 54 or if the total number of hours in which the ACS was overriden exceeds 110 hours in any calendar quarter (for a Regular -Use Covered Flare) or 5% of the operating time (for a Temporary -Use Covered Flare), an identification of the periods of override by the date, time, duration, reason for the override, and corrective actions taken;

e. Inappli cability of Emissions Standards

. The total number of hours, expressed as both an absolute number of hours and a percentage of time that the Covered Flare was In Operation, in which the requirements of Paragraphs 56–59 were not applicable because the only gas or gases being vented was/were Pilot Gas and/or Purge Gas; for purposes of Subparagraphs 86.f. and 86.g, all remaining hours shall be termed “Hours of Applicability”;

f. Exceedances of Emissions Standards . During the Hours of Applicability,

the total number of hours, expressed as both an absolute number of hours and a percentage of time the Covered Flare was In Operation, of exceedances of the emissions standards in Subparagraphs 56.b–d, 57.b, 58.c–d, and 59; provided however, that if the exceedance o f these

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standards was less than 110 hours in the calendar quarter (for Regular- Use Covered Flares) or 5% of the total Hours of Applicability (for Temporary -Use Covered Flares) and was due to one or more of the exceptions set forth in Paragraph 60, the report shall so note;

g. Exceedances of Emissions Standards . During the Hours of Applicability, if the exceedance of the emissions standards in Subparagraphs 56.b–d, 57.b, 58.c–d, and 59 was not due to one of the exceptions in Paragraph 60,

or if the exceed ance was due to one or more of the exceptions in Paragraph 60 but the total number of hours caused by the exceptions in Paragraph 60 was greater than 110 (for Regular- Use Covered Flares) or 5% of the total Hours of Applicability (for Temporary- Use Covered and Portable Flares), an identification of each block p eriod 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;

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 Subparag raph 44.b, the information required in Subparagraph 44.c;

ii. An identification of each calendar day in which the limitations on flaring set forth in Paragraph 41 were exceeded ;

iii. The cause of the exceedance; and

iv. If the cause is asserted to be a Malfunction, an explanation and any

corrective actions taken ;

i. Intentionally Left Blank; and

j. Compliance with Compressor Availability Requirements . In each

semi -annual report starting on and after July 31, 2015 (for the compressors

within the FGRS s ystems at the SDP Refinery)

, and in each semi -annual report starting on and after January 31, 2019 (for the compressors within the Olefins FGRS), SDP shall provide sufficient information to document compliance with the Compressor availability requirements of Subparagraph 40.b ( for the SDP Refinery FGRS Compressors ) and Subparagraph 47.b ( for SDP Olefins FGRS Compressors). For any period

of non- compliance, SDP shall identify the date, cause, and corrective

action taken.

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87. Emissions Data . In the semi-annual report that is submitted on July 31 of each

year, SDP shall provide, for each Covered Flare, for the 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.

88. Due Dates . The firs t compliance status report shall be due thirty

- one days after

the first full half

- year after the Effective Date of this Consent Decree ( i.e., either: (i) January 31

of the year after the Effective Date, if the Effective Date is between January 1 and June 3 0 of the

preceding year; or (ii) July 31 of the year after the Effective Date, if the Effective Date is

between July 1 and December 31). The initial report shall cover the period between the

Effective Date and the first full half year after the Effective Date (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 January 31 and July 31 and shall cover the prior half year

( i.e. , January 1 to June 30 or July 1 to December 31 ). Whenever this Consent Decree requires

compliance within a certain number of “months” after a triggering event, the compliance

obligation commences on the anniversary of the numerical date that triggers the obligation. For

example, if compliance is required by no later than three months after the submission of a

particular document, and if the document is submitted on March 23, 2012, the compliance

obligation commences on June 23, 2012.

89. Each report submitted under this Consent Decree shall be signed by the Covered

Facilit ies’ Manager (or his/her designee), the person responsible for environmental management

at the Covered Facilities , or by a person responsible for overseeing implementation of this

Consent Decree across SDP, and shall include the following certification:

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed

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to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete.

90. The reporting requirements of this Consent Decree do not relieve SDP of any

reporting obligations required by the CAA or implementing regulations, or by any other federal,

state, or local law, regula tion, permit, or other requirement.

91. Any information provided pursuant to this Consent Decree may be used by the

United States in any proceeding to enforce the provisions of this Consent Decree and as

otherwise permitted by law.

X. STIPULATED PENALTIES

92. Failure to Pay Civil Penalty . If SDP fails to pay any portion of the civil penalty

required to be paid under Section IV of this Decree (Civil Penalty) when due, SDP shal l pay a

stipulated penalty of $2500 per day for each day that the payment is late. L ate payment of the

civil penalty and any accrued stipulated penalties shall be made in accordance with

Paragraph 13.

93. Failure to Meet all Other Consent Decree Obligations . SDP shall be liable for

stipulated penalties to the United States for violations of this Consent Decree as specified below

unless excused under Section XI of this Decree (Force Majeure). For those provisions where a

stipulated penalty of either a fixed amount or 1.2 times the economic benefit of delayed

compliance is available, the deci sion of which alternative to seek rests exclusively within the

discretion of the United States. For a given calendar day, where a failure to comply with the

30-day and/or the 365- day rolling average limit on Waste Gas flaring at the SDP Refinery

required by Subparagraph 41.a of this Decree ( and potentially subject to the stipulated penalty

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provisions of Subparagraphs 93.l and /or 93.m ) is the result of a failure to have the requisite

number of Compressors Available for Operation as required by Subparagraph 40.b of this Decree

(and potentially subject to the stipulated penalty provisions of Subparagraphs 93.j and/or 93.k),

only the stipulated penalty provision that results in the higher penalty shall be applicable for that

calendar da y ( i.e. , stipulated penalties under both Subparagraph 93.l and/or 93.m and

Subparagraph 93.j and/or 93.k shall not be assessed). Nothing in the previous sentence shall be

construed to result in only one penalty being applicable on any given calendar day for violations

of both the 30-day and the 365- day rolling average limit s on Waste Gas flaring ( i.e. , for any

given calendar day in which both the 30-day and 365- day rolling average limits are violated,

stipulated penalties under both Subparagraph 93.l . and 93.m may be assessed).

Violation Stipulated Penalty

93.a. Violation of Paragraph 16. Failure to timely submit a report (¶ 16) that conforms to the requirements of that Paragraph Period of delay or noncompliance

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day

$ 300 $ 400 $ 500

93.b. Violation of Paragraph 30, 31, or 32. Failure to timely submit a plan (¶¶ 30, 31, or 3 2) that conforms to the requirements of the respective Paragraph Period of delay or noncompliance

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day

$ 500 $ 750 $ 1000

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9 3 .c. Violation of Paragraph 17, 18, 19, 20, 21, 22, 23, 24, 26, or 27. Failure to timely install the equipment and monitoring systems required by Paragraphs 18– 24 in accordance with the respective, applicable technical specifications in those Paragraphs, Paragraph s 26–27, and Appendix 1.10 (except for the requirements of Appendix 1.10 found in Subparagraphs I.g, III.e, IV, V.B, or VII.a: those are QA/QC requirements covered in Subparagraph 9 3 .d below) Period of delay or noncompliance, per monitoring system

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day per monitoring

system

$ 750 $ 1250 $ 2000 or an amount equal to 1.2 times

the economic benefit of delayed compliance, whichever is greater

9 3 .d. Vi olation of the QA/QC requirements in Appendix 1.10 . Failure to comply with the QA/QC requirements in Appendix 1.10 at Subparagraphs I.g, III.e, IV, V.B, and

VII.a Violation of a :

Daily requirement Quarterly requirement Annual requirement Penalty

$ 100 $ 200 per day late $ 500 per day late

9 3 .e Violation of Paragraph 28 : Per monitoring system, Penalty per hour Regular

- Use Covered Flares . After the number of hours per per monitoring dates in Column H of Appendix 2.1, calendar quarter of system except for 110 hours per calendar downtime over 110 quarter, failure to operate the monitoring systems in Paragraphs 18–20 and 22– 0.25–50.0 $ 250 24; provided however, that SDP shall 50.25–100.0 $ 500 not be liable for a stipulated penalty for Over 100.0 $ 1000 violation of Paragraph 28 if, during the period of instrument downtime, the only gas(es) being sent to the Regular

- Use Covered Flare in question is/are Purge

Gas and/or Pilot Gas . For any monitoring system that serves a dual

purpose, this stipulated penalty applies per instrument only.

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93. f

. Violation of Paragraph 28: Temporary

- Use Covered Flares . After the dates in Column H of Appendix 2.1, except for 5% per uninterrupted period of time that a Temporary

- Use Covered

Flare i s In Operation and Capable of Receiving Sweep, Supplemental, and/or Waste Gas, failure to operate the monitoring systems in Paragraphs 18–20 and 22–24; provided however, that SDP shall not be liable for a stipulated penalty for violation of Paragraph 28 if, during the period of instrument downtime, the only gas(es) being sent to the Temporary -Use Covered Flare in question is/are Purge Gas and/or Pilot Gas. For any monitoring system that serves a dual purpose, this stipulated penalty applies per instrument only. Per monitoring system, number of hours per uninterrupted period

of time

0.25–50.0

50.25–100.0

Over 100.0 Penalty per hour per monitoring

system

$ 250 $ 500 $ 1000

93. g

. Violation of Paragraph 35

. Period of delay or Penalty per day Failure to timely develop a report that noncompliance conforms to the requirements in Subparagraph 35.a; or failure to keep it Days 1 – 30 $ 800 as an internal record; or failure to timely Days 31 – 60 $ 1,600 submit a summary of the flaring incident Days 6 1 and later $ 3,000 reports that conforms to the requirements in Subparagraph 35.b

93. h

. Violation of Paragraph 36

. Period of del ay or Penalty per day Failure to complete any corrective noncompliance

action under Paragraph 36 in accordance

with the schedule for corrective action Days 1 – 30 $ 1,000 agreed to by SDP or imposed on SDP Days 31 – 60 $ 2,000 pursuant to the dispute resolution Days 6 1 and later $ 5,000 provisions of this Decree (with any such

extensions thereto as to which EPA and SDP may agree in writing)

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93.i. Violation of Paragraph 39 or Paragraph 45 . Failure to timely install, in accordance with Paragraph 39 or Paragraph 45 (as applicable), a Flare Gas Recovery System that conforms to the requirements of Paragraph 39 or Paragraph 45(as applicable) Period of delay or Penalty per day per FGRS noncompliance, per FGRS

Days 1–30 $ 1250 Days 31 –60 $ 3000 Days 6 1 and later $ 5000 or an amount equal to 1.2 times

the economic benefit of delayed compliance, whichever is greater

93.j

. Violation of Certain Subparagraph 40.b.ii or Subparagraph 47.b.ii requirements. For each failure to comply with the Subparagraph 40.b.ii requirement to have four Compressors Available for Operation and/or in operation “at all times

, ” or for each failure to comply with the Subparagraph 47.b.ii requ irement to have “n

- 2” Compressors Available for Operation and/or in operation “at all times” Per FGRS, per hour or fraction thereof : $750 ; provided however, that stipulated penalties shall not apply for any hour in which a Compressor’s unavailability did not result in flaring

93.k. Violation of Certain Subparagraph 40.b or Subparagraph 47.b Requirements (excluding those identified in Subparagraph 93.j). For each failure to comply with the following requirements in Subparagraph 40.b. or Subparagraph 47.b: (1) Subparagraph 40.b.i or Subparagraph 47.b.i requirement to have one Compressor Available for Operation and/or in operation 98% of the time; (2) Subparagraph 40.b.i or Subparagraph 47.b.i requirement to have two Compressors Available for Operation and/or in operation 90% of the time; (3) Subparagraph 40.b.ii or Subparagraph 47.b.ii requirement to have five Compressors or “n

- 1” Compressors, respectively, Available for Operation and/or in operation 95% of

the time Per FGRS, the number of hours or frac tion thereof

– over the allowed percentage —in a rolling 8760-hour period that a Compressor required to be Available for Operation is not: $750; provided however, that stipulated penalties shall not apply for any hour or fraction thereof in which a Compressor’s unavailability did not result in flaring.

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93.l. Violation of Paragraph 41.a. i Failure to comply with the 30

- day rolling average limit on Waste Gas flaring at the SDP Refinery Pollutant Penalty per Day per ton

SO 2 $ 100

VOC $ 300

The amount of excess emissions during the event(s) which precipitate(s) the exceedance(s) of the 30

- day rolling average limit is not the sole basis for calculating the stipulated penalty due. Instead, each day on which

the 30- day rolling average limit is violated —which violations most likely continue even though the precipitating event and the excess emissions do not — counts as a separate day. SDP shal l comply with Appendix 1.13 to calculate the stipulated penalties resulting from violating the flaring limitation in Paragraph 41.a.i.

93.m. Violation of Paragraph 41.a.ii. Failure to comply with the refinery

- wide

365- day rolling average limit on Waste Gas flaring at the SDP Refinery Pollutant Penalty per Day per ton

SO 2 $ 40 VOC $ 120

The amount of excess emissions during the event(s) which precipitate(s) the exceedance(s) of the 365

- day rolling average limit is not the sole basis for calculating the stipulated penalty due. Instead, each day on which

the 365- day rolling average limit is violated —which violations most likely continue even though the precipitating event and the excess emissions do not— counts as a separate day. SDP shall comply with Appendix 1.13 to calculate the stipulated penalties resulting from violating the flaring limitation in Parag raph 41.a. ii.

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93.n. Violation of Paragraph 48. Failure to timely convert the A&S Flare to Temporary-Use in conformance with the requirements of Paragraph 48. Period of delay or Penalty per day noncompliance

Days 1–30 $ 1000 Days 31 –60 $ 2500 Days 6 1 and later $ 5000

93. o

. Violation of Paragraph 4 9

. Failure to comply with the 365- day rolling sum emission limit on VOCs

from the HIPA Flare $2500 per ca lendar day on which the limit is exceeded

93. p

. Violation of Paragraph 53

. Failure to timely install and operate, by the dates in Column G of Appendix 2.1, the Automatic Control System requirements of Paragraph 53 Penalty per Covered Flare per day: $50 0

93.q. Violation of Subparagraph 56.b, 56.c, or 56.d. For each Covered Flare, failure to comply with the Net Heating

Value in the Combustion Zone Gas (“NHV

cz ”) standard in Subparagraph 56.b, 56.c, or 56.d. On a per Covered Flare Penalty per hour, basis, hours per calendar or fraction there of quarter i n noncompliance per flare

Hours 0.25–50.0 $ 25 Hours 50.25–100.0 $ 75 Hours over 100.0 $ 150

For purposes of calculating the number of hours of noncompliance with the NHV

cz standard, all 15- minute periods of violation shall be added together to determine

the total.

93

. r

. Violation of Subparagraph 57.a. Penalty per Covered Flare per day or fraction thereof: Between the Date of Lodging and the $1500 compliance dates in Column H of Appendix 2.1, f ailure to use best efforts

to maintain the S/VG ratio at each Covered Flare below 3.0; provided, however, that SDP shall not be liable for a stipulated penalty for violation of Subparagraph 57.a if, at the Covered Flare in question, SDP can demon strate that it is complying with the requirements of Subparagraphs 56.b, 56.c, or 56.d (as applicable) during the period of applicability of this stipulated penalty.

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93.s. Violation of Subparagraph 58.c. 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

93.t. Violation of Subparagraph 58.d. Failure to comply with the applicable

MFR standard Flare Tip Size (inches) Penalty per hour or

fraction thereof

1.0–24.0 $ 50

24.1–48.0 $ 75 Over 48.0 $ 175

For purposes of calculating the number of hours of noncompliance with the MFR limit, all 5- minute periods of violation shall be added together to determine the total

. 93. u

. Violation of Paragraph 62

. $100 per day Failure to record any information required to be recorded pursuant to Subparagraphs 62.a, b, c, or d

93.v. Violation of Subp aragraph s 63.d.i

or 63.d.ii. Failure to ensure that a

Portable Flare that falls under the conditions of Subparagraph 63.d.i or 63.d.ii complies with the requirements of those Subparagraphs Number of days Penalty per day

Portable Flare did not comply

Days 1 –7 $ 1000 Days 8 –15 $ 2000 Days 16 and later $ 5000

93.w. Violation of Paragraph 64. Failure to comply with the H 2 S emission limit at a Refinery Covered Flare after that Refinery Covered Flare is required to comply with 40 C.F.R. Part 60, Subpart J, or 40 C.F.R. Part 60, Subpart

Ja On a per Covered Flare Penalty per hour per basis, hours (on a three- Covered Flare hour rolling average basis) per c alendar quarter in noncompliance

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 violation shall be added together to determine the total. The averaging period for this standard is a three-hour rolling average.

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93.x. Violation of Paragraph 65. Failure to timely comply with the requirements of Paragrap h 65 Period of delay

Days 1 – 30 Days 31 – 60 Days 6 1 and later Penalty per day

$ 1,000 $ 2,000 $ 5,000

93.y. Violation of Paragraphs 71–73, and Appendices 2.6–2.8. For fa ilure to comply with any requirement of Paragraphs 71–73 or Appendices 2.6–

2.8 Period of delay or noncompliance

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day

$ 500 $ 1500 $ 3000

93.z. Violation of Paragraphs 76–77 and Appendices 2.9–2.10. For failure to comply with any requirement of Paragraphs 76–77 and Appendices 2.9–

2.10 Period of delay or noncompliance

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day

$ 500 $ 1500 $ 3000

93. aa . Violation of Section IX (Reports) . For each failure to submit reports as required by Section IX Period of delay or noncompliance

per report

Days 1–30 Days 31 –60 Days 6 1 and later Penalty per day

per report

$ 300 $ 1000 $ 2000

94. Waiver of Payment . The United States may, in its unreviewable discretion,

reduce or waive payment of stipulated penalties otherwise due to it under this Consent Decree.

95. Demand for Stipulated Penalties . A written demand by the United States for the

payment of stipu lated penalties will identify the particular violation(s) to which the stipulated

penalty relates; the stipulated penalty amount (as can be best estimated) that the United States is

demanding for each violation; the calculation method underlying the demand; and the grounds

upon which the demand is based. Prior to issuing a written demand for stipulated penalties, the

United States may, in its unreviewable discretion, contact SDP for informal discussion of matters

that the United States believes may merit stipulated penalties.

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96. Stipulated Penaltie s Accrua l . Stipulated penalties will begin to accrue on the day

after performance is due or the day a violation occurs, whichever is applicable, and, except as

provided in Paragraph 99, shall continue to accrue unti l performance is satisfactorily completed

or the violation ceases. Stipulated penalties shall accrue simultaneously for separate violations

of this Consent Decree.

97. Stipulated Penalties Payment Due Date . Stipulated penalties shall be paid no later

than si xty (60) days after receipt of a written demand by the United States unless the demand is

disputed through compliance with the requirements of the dispute resolution provisions of this

Decree.

98. Manner of Payment of Stipulated Penalties . Stipulated penalties owing to the

United States of under $10,000 shall be paid by check and made payable to the “U.S.

Department of Justice, ” referencing DOJ Number 90-5-2-1-09388/1 and USAO File Number

2012VO1637, and delivered to the U.S. Attorney’ s Office in the Southern District of Texas,

1000 Louisiana St., Suite 2300, Houston, TX 77002. Stipulated penalties owing to the United

States of $10,000 or more shall be paid in the manner set forth in Section IV of this Decree (Civil

Penalty). All transmittal correspondence shall state that the payment is for stipulated penalties,

shall identify the violations to which the payment relates, and shall include the same identifying

information required by Paragraph 13.

99. Disputes over Stipulated Penalties . By no later than 60 days after receiving a

demand for stipulated penalties, SDP may dispute liability for any or all stipulated penalties

demanded by invoking the dispute resolution procedures of Section XII of this Decree (Dispute

Resolution). In the event of a dispute over stipulated penalties, stipulated penalties shall not

accrue commencing on the later of either: (i) the date that, during dispute resolution under

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Section XI I, the United States and SDP agree upon; or (ii) the date that SDP files a motion with

the Court under Paragraph 113; provided however, that in order for stipulated penalties to cease

accruing pursuant to either (i) or (ii), SDP must place the disputed amount in an interest- bearing

commercial escrow account. If the dispute thereafter is resolved in SDP’s favor, the escrowed

amount plus accrued interest will be returned to SDP; otherwise, the United States will be

entitled to the amount determined by the Court to be due, plus interest that has accrued on such

amount in the escrow account.

100. No amount of the stipulated penalties paid by SDP shall be used to reduce its

federal tax obligations.

101. Subject to the provisions of Section XIV of this Decree (Effect of

Settlement/Reservation of Rights), the stipulated penalties provided for in this Decree shall be in

addition to any other rights, remedies, or sanctions available to the United States for a violation

of this Consent Decree or app licable law. In addition to injunctive relief or stipulated penalties,

the United States may seek mitigating emissions reductions equal to or greater than the excess

amounts emitted if the violations result in excess emissions. SDP reserves the right to oppose

the United States’ request for mitigating emission reductions. SDP shall be allowed a credit, for

any stipulated penalties paid, against any statutory penalties imposed for such violation.

XI. FORCE MAJEURE

102. “Force Majeure,” for purposes of this Consent Decree, is defined as any event

beyond the control of SDP, its contractors, or any entity controlled by SDP that delays the

performance of any obligation under this Consent Decree despite SDP’s best efforts to fulfill the

obligation. The requirem ent that SDP exercise “best efforts to fulfill the obligation” includes

using best efforts to anticipate any potential Force Majeure event and best efforts to address the

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effects of any such event: (a) as it is occurring; and (b) after it has occurred, to prevent or

minimize any resulting delay.

103. “Force Majeure” does not include SDP’s financial inability to perform any

obligation under this Consent Decree. Unanticipated or increased costs or expenses associated

with the performance of SDP’s obligations und er this Consent Decree shall not constitute

circumstances beyond SDP’s control nor serve as the basis for an extension of time under this

Section X I.

104. If any event occurs or has occurred that may delay the performance of any

obligation under this Consent Decree, whether or not caused by a Force Majeure event, SDP

shall notify EPA in writing not later than fifteen calendar days after the time SDP first knew or

should have known by the exercise of due diligence that the event might cause a delay. In the

wri tten notice, SDP shall specifically reference this Paragraph 104 of the Consent Decree and

shall provide an explanation and description of the reasons for the delay; the anticipated duration

of the delay; all actions taken or to be taken to prevent or minimize the delay; a schedule for

implementation of any measures to be taken to prevent or mitigate the delay or the effect of the

delay; SDP’s rationale for attr ibuting such delay to a Force Majeure event if it intends to assert

such a claim; and a statement as to whether, in the opinion of SDP, such event may cause or

contribute to an endangerment to public health, welfare, or the environment. SDP shall be

deeme d to know of any circumstance of which SDP, any entity controlled by SDP, or SDP’s

contractors knew or should have known. SDP shall include with any notice all available

documentation supporting the claim that the delay was attributable to a Force Majeure . The

written notice required by this Paragraph shall be effective upon the mailing of the same by

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overnight mail or by certified mail, return receipt requested, to EPA in the manner set forth in

Section XV I of this Decree (Notices).

105. Failure by SDP to com ply with the requirements in Paragraph 104 shall preclude

SDP from asserting any claim of Force Majeure for the event for the period of time of such

failure to comp ly, and for any additional delay caused by such failure.

106. If EPA agrees that the delay or anticipated delay is attributable to a Force Majeure

event, the time for performance of the obligations under this Consent Decree that are affected by

the Force Majeure event will be extended by EPA for such time as is necessary to complete those

obligations. An extension of the time for performance of the obligations affected by the Force

Majeure event shall not, of itself, extend the time for performance of any other obligation. EPA

will notify SDP in writing of the length of the extension, if any, for performance of the

obligations affected by the Force Majeure event.

107. If EPA does not agree that the delay or anticipated delay has been or will be

caused by a Force Majeure event, or if the EPA and SDP fail to agree on the length of the delay

attributable to the Force Majeure event, EPA will notify SDP of its decision.

108. If SDP elects to invoke the dispute resolution procedures set forth in Section XI I

of this Decree (Di spute Resolution), it shall do so no later than 45 days after receipt of EPA’s

notice. In any such proceeding, SDP shall have the burden of demonstrating by a preponderance

of the evidence that the delay or anticipated delay has been or will be caused by a Force Majeure

event, that the duration of the delay or the extension sought was or will be warranted under the

circumstances, that best efforts were exercised to avoid and mitigate the effects of the delay, and

that SDP complied with the requirements of Paragraphs 102 and 104. If SDP carries this burden,

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the delay at issue shall be deemed not to be a violation by SDP of the affected obligation of this

Consent Decree identified to EPA and the Court.

XII. DISPUTE RESOLUTION

109. Unless otherwise expressly provided for in this Consent Decree, the dispute

resolution procedures of this Section shall be the exclusive mechanism to resolve disputes arising

under or with respect to this Consent Decree.

A. For All Disputes Except those Arising Under Subparagraphs 43.c and 46 .c

110. Informal Dispute Resolution . The first stage of dispute resolution shall consist of

in formal negotiations. The dispute shall be considered to have arisen when one Party sends the

other Party 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 after the Notice of

Dispute, unless that period is modified by written agreement. If the Parties cannot resolve the

dispute by informal negotiations, then the position advanced by the United States shall be

considered binding unless within 45 days after the conclusion of the informal negotiation period,

SDP invokes formal dispute resolution procedures set forth below.

111. Formal Dispute Resolution . SDP shall invoke formal dispute resolution

procedures, within the time period provided in the preceding Paragraph, by serving on the United

States a written Statement of Position regarding the matter in dispute. The Statement of Position

shall include, but need not be limited to, any factual data, analysis, or opinion supporting SDP’s

position and any supporting documentation relied upon by SDP.

112. The United States shall serve its Statement of Position within 45 days of receipt

of SDP’s Statement of Position. The United States’ Statement of Position shall include, but need

not be limited to, any factual dat a, analysis, or opinion supporting that position and any

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supporting documentation relied upon by the United States. The United States’ Statement of

Position shall be binding on SDP unless SDP files a motion for judicial review of the dispute in

accordance with the following Paragraph.

113. SDP may seek judicial review of the dispute by filing with the Court and serving,

in accordance with Section XV I of this Decree (Notices), on the United States a motion

requesting judicial resolution of the dispute. The motion must be filed within 45 days of receipt

of the United States’ Statement of Position pursuant to the preceding Paragraph. The motion

shall contain a written statement of SDP’s position on the matter in dispute, including any

supporting factual data, analysis, opinion, or documentation, and shall set forth the relief

requested and any schedule within which the dispute must be resolved for orderly

implementation of the Consent Decree.

114. The United States shall respond to SDP’s motion within the time period allowed

by the Local Rules of this Court for responses to dispositive motions. SDP may file a reply

memorandum, to the extent permitted by the Local Rules.

115. In a formal dispute resolution proceeding under this Section, SDP shall bear the

burden of demonstrating that its position complies with this Consent Decree and the CAA and

that it is entitled to relief under applicable principles of law. The United States reserves the right

to argue that its position is reviewable only on the administrative record and must be upheld

unless arbitrary and capricious or otherwise not in accordance with law, and SDP reserves the

right to argue to the contrary.

116. The invocation of dispute resolution procedures under this Section shall not, by

itself, extend, postpone, or affect in any way any obligation of SDP under this Consent Decree,

unless and until final resolution of the dispute so provides. Stipulated penalties with respect to

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the disputed matter shall accrue in accordance with Paragraph 99, but payment shall be stayed

pending resolution of the dispute.

B. For Disputes Arising Under Subparagraphs 43.c and 46.c

117. For disputes arising under Subparagraphs 43 .c and /or 46.c, the provisions of this

Subsection XII.B shall apply if SDP invokes the accelerated dispute resolutio n as allowed by

Subparagraphs 43 .c or 46.c. Paragraphs 110-116 are incorporated herein by reference except for

the following changes:

Reference Instead Of Use

Para. 110 ; 4 th Sentence 60 days 15 days

Para. 110 ; 5 th Sentence 45 days 10 days

Para. 112 ; 1 st Sentence 45 days 15 days

Para. 113 ; 2 nd Sentence 45 days 15 days

Para. 114 ; 1 st Sentence “within the time period allowed by the

Local Rules of this Court for responses to dispositive motions” “within 21 days”

118. If a dispute under Subparagraphs 43 .c or 4 6 .c comes before this Court for

disposition, both Parties jointly shall advise the Court that time is of the essence.

XI II. INFORMATION COLLECTION AND RETENTION

119. The United States and its representatives, employees, contractors, and consultants

shall have the right of entry into the Covered Facilities , at all reasonable times, upon

presentation of credentials and any other documentation required by law, to:

a. monitor the progress of activities required under this Consent Decree;

b. verify any data or information submitted to the United States in accordance with the terms of this Consent Decree;

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c. obtain documentary evidence, including photographs and similar data, relevant to compliance with the terms of this Consent Decree; and

d. assess SDP’s compliance with this Consent Decree.

120. Except for data recorded by any video camera that may be required pursuant to

Paragraph 24 , until one year after termination of this Consent Decree, SDP shall retain all

documents, records, or other information, regardless of storage medium ( e.g. , paper or

electronic) in its possession or control that directly relate to SDP’s performance of its obligations

under this Consent Decree. Except for data recorded by any video camera that may be required

pursuant to Paragraph 24, until one year after termination of this Consent Decree, SDP shall

instruct its contractors and agents to preserve all documents, records, or other information,

regardless of storage medium ( e.g. , paper or electronic) in its contractors’ or agents’ possession

or control, or that come into its or its contractors’ or agents’ possession or control, that

demonstrate or document SDP’s compliance or non- compliance with the obligations of this

Consent Decree. This information

- ret ention requirement shall apply regardless of any contrary

corporate or institutional policies or procedures. At any time during this information-retention

period, the United States may request copies of any documents, records, or other information

require d to be maintained under this Paragraph. SDP shall retain the data recorded by any video

camera required pursuant to Paragraph 24 for six months from the date of r ecording except that

SDP shall keep any such video record until one year after termination if SDP was required to

keep the record pursuant to Subparagraph 62 .c.

121. Except for emissions data, SDP may assert that information required to be

provided under this Section is protected as Confidential Business Information (“CBI”) under

40 C.F.R. Part 2. As to any information that SDP seeks to protect as CBI, SDP shall follow the

procedures set forth in 40 C.F.R. Part 2, where applicable.

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122. This Consent Decree in no way limits or affects any right of entry and inspection,

or any right to obtain information, held by the United States pursuant to applicable federal laws,

regul ations, or permits, nor does it limit or affect any duty or obligation of SDP to maintain

documents, records, or other information imposed by applicable federal or state laws,

regulations, or permits.

XI V. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS

123. Defini tions . For purposes of this Section XIV, the following definitions apply:

a. “BTU/scf Flared Gas Requirements” shall mean the requirements found in the following regulations:

i. 40 C.F.R. § 60.18(c)(3)(ii);

ii. 40 C.F.R. § 63.11(b)(6)(ii);

iii. 40 C.F. R. §§ 60.482-10(d), 60.482-10a(d), but only to the extent that these provisions require compliance with 40 C.F.R. § 60.18(c)(3)(ii);

iv. 40 C.F.R. §§ 60.592(a), 60.592a(a), but only to the extent that these provisions: (1) relate to flares; and (2) require compliance with 40 C.F.R. § 60.18(c)(3)(ii);

v. 40 C.F.R. § 63.643(a)(1), but only to the extent that this provision requires compliance with 40 C.F.R. § 63.11(b)(6)(ii);

vi. 40 C.F.R. § 63.648(a), but only to the extent that this provision: ( 1) relates to flares; and (2) requires compliance with 40 C.F.R. § 60.18(c)(3)(ii);

vii. 40 C.F.R. § 61.349(a)(2)(iii), but only to the extent that this provision require s compl iance with 40 C.F.R. § 60.18(c) (3)(ii);

viii. 40 C.F.R. § 63.1566(a)(1)(i) and Table 15, but only to the extent that these provisions: (1) relate to flares; and (2) require compliance with 40 C.F.R. § 63.11(b)(6)(ii) ; and

ix. 40 C.F.R. § 63.113(a)(1)(i), but only to the extent that this provision require s co mpliance with 40 C.F.R. § 63.11(b)(6)(ii).

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b. “General Flare Requirements” shall mean the requirements found in the following regulations:

i. 40 C.F.R. § 60.18(c)(1) and 40 C.F.R. § 63.11(b)(4) (both relate to a prohibition on visible emissions);

ii

. 40 C.F.R. § 60.18(c)(2) and 40 C.F.R. § 63.11(b)(5) (both relate to flame presence);

iii. 40 C.F.R. § 60.18(c)(4) and 40 C.F.R. § 63.11(b)(7) (both relate to exit velocity requirements for steam

- assisted flares);

and

iv. 40 C.F.R. § 60.18(e) and 40 C.F.R. § 63.11(b)(3) (both relate to operation during emissions venting).

c. “Good Air Pollution Control Practice Requirements” shall mean the requirements found in the following regulations:

i. 40 C.F.R. § 60.11(d);

ii. 40 C.F.R. § 61.12(c);

i ii. 40 C.F.R. § 63.6(e)(1)(i);

iv. 40 C.F.R. Part 63, Subpart CC, Table 6, but only to the extent that Table 6 requires compliance with 40 C.F.R. § 63.6(e)(1)(i); and

v. 40 C.F.R. Part 63, Subpart UUU, Table 44, but only to the extent

that Table 44 requires compliance with 40 C.F.R. § 63.6(e)(1).

d. “Post

- Lodging Compliance Dates” shall mean any dates in this

Section XI V after the Date of Lodging;

e. “PSD/NNSR Requirements” shall mean the Prevention of Significant

Deterioration and Non- Attainment New Source Review requirements found in the following:

i. 42 U.S.C. § 7475;

ii. 40 C.F.R. §§ 52.21(a)(2)(iii) and 52.21(j)–52.21(r)(5);

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iii. 42 U.S.C. §§ 7502(c)(5), 7503(a)

– (c);

iv. 40 C.F.R. Part 51, Appendix S, Part IV, Conditions 1–4;

v. any applicable, federally enforceable state or local regulation that implements, adopts, or incorporates the federal provisions cited in Subparagraphs 123 .e.i –iv; and

vi. Title V permit requirement that implements, adopts, or incorporates the federal, or federally enforceable state, provisions cited in Subparagraphs 123.e.i–v;

f. “Requirements Related to Monitoring, Operation, and Maintenance According to Flare Design” shall mean the requirements found in the following regulations:

i. 40 C.F.R. § 60.18(d);

ii. 40 C.F.R. § 63.11(b)(1);

iii. 40 C.F.R. §§ 60.482-10(d), 60.482-10a(d), but only to the extent that these provisions require compliance with 40 C.F.R. § 60.18(d);

iv. 40 C.F.R. §§ 60.482-10(e), 60.482- 10a(e), but only to the extent that these provisions relate to flares;

v. 40 C.F.R. §§ 60.592(a), 60.592a(a), but only to the extent that these provisions: (1) relate to flares; and (2) require compliance with 40 C.F.R. § 60.18(d);

vi. 40 C.F.R. § 63.643(a)(1), but only to the extent that this provision requires compliance with 40 C.F.R. § 63.11(b)(1);

vii. 40 C.F.R. § 63.648(a), but only to the extent that this provision: (1) relates to flares; and (2) requires compliance with 40 C.F.R. § 60.18(d); and

viii. 40 C.F.R. § 63.1566(a)(1)(i) and Table 15 but only to the extent that this provision: (1) relates to flares; and (2) requires compliance with 40 C.F.R. § 63.11(b)(1).

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g. “Subpart Ja Requirements” shall mean the following requirements of

40 C.F.R. Part 60, Subpart Ja (in effect as of November 13, 2012):

i. H 2 S emission limit applicable to flares (set forth in 40 C.F.R. § 60.103 a( h));

ii. H 2 S monitoring for flares (set forth in 40 C.F.R. § 60.107a(a)(2));

i ii. Sulfur monitoring for flares (set forth in 40 C.F.R. § 60.107a(e));

and

iv. Flow monitoring for flares (set forth in 40 C.F.R. § 60.107a(f)) .

124. Entry of this Consent Decree shall resolve the civil claims of the United States for

the violations alleged in the Complaint filed in this action through the Date of Lodging.

125. Resolution of Claims for Violating PSD/NNSR Requirements at the Covered

Flares

. With respect to emissions of H 2 S, SO 2 , VOCs, and CO from the Covered Flares , entry of

this Consent Decree shall resolve the civil claims of the United St ates against SDP for violations

of the PSD/NNSR Requirements resulting from construction or modification from the date of the

pre -Lodging construction or modification through: (i) for the SDP Refinery Covered Flare s,

December 31, 2017 ; (ii) for the Olefins Flares, December 31, 2017; and (iii) for the HIPA Flare,

24 months after the Date of Entry.

126. Resolution of Pre

- Lodging Claims at the Covered Flares for Failing to Comply

with: (a) BTU/scf Flared Gas Requirements; (b) General Flare Requirements; (c) Good Air

Pollution Control Practice Requirements; and (d) Requirements Related to Monitoring,

Operation, and Maintenance According to Flare Design . With respect to emissions of the

following pollutants from the Covered Flares, entry of this Consent Decre e shall resolve the civil

claims of the United States against SDP for violations of the following requirements from the

date those claims accrued through the Date of Lodging:

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Pollutant(s) Requirement/Regulation

VOCs and HAPs BTU/scf Flared Gas Requirements

VOCs and HAPs General Flare Requirements

VOCs and HAPs Good Air Pollution Control Practice Requirements

VOCs and HAPs Requirements Related to Monitoring, Operation, and Maintenance According to Flare Design

127. Resolution of Pre- Lodging Claims for Failing to Comply with 40 C.F.R. Part 60,

Subpart J.

a. SDP Refinery Covered Flares . With respect to emissions of SO 2 and H 2 S

from the SDP Refinery Covered Flares, entry of this Consent Decree shall resolve the civil

claims of the United Stat es against SDP for violations of 40 C.F.R. Part 60, Subpart J, from the

date those claims accrued through the Date of Lodging.

b. SDP Chemical Plant Covered Flares. With respect to emissions of SO 2

and H 2 S from the SDP Chemical Plant Covered Flares (as specifically identified in

Subparagraphs 127.b.i– iii), entry of this Consent Decree shall resolve the civil claims of the

United States against SDP for violations of 40 C.F.R. Part 60, Subpart J, from the date those

claims accrued through the Date of Lodging, provided that the claims arose due to one the

following:

i. Fuel Gas flowing from the SDP Refinery to the Olefins II and III Flares during emergency situations; or

ii

. G as flowing to the Olefins Flares as a result of refinery streams being processed at the Butane Butylene Hydrotreater Unit ; or

iii. Gas redirected from the Girbotol Flare at the SDP Refinery to the

A&S and HIPA Flares

.

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128. Resolution of Claims Continuing Post- Lodging for Failing to Comply with:

(a) Requirements Related to Monitoring, Operation, and Maintenance According to Flare

Design; and (b) 40 C.F.R. Part 60, Subpart J at Olefins Flares

.

a. Requirements Related to Monitoring, Operation, and Maintenance

According to Flare Design for all Covered Flares

. With respect to emissions of VOCs and HAPs

from the Covered Flares, entry of this Consent Decree shall resolve the civil claims of the United

States against SDP for the violations set forth in Subparagraph 128 .a.i, for the time frame set

forth in Subparagraph 128.a.ii:

i. Violations of Requirements Related to Monitoring, Operation, and Maintenance According to Flare Design, but only to the extent that

the claims are based on SDP’s use of too much steam in relation to Vent Gas flow;

ii. The resolution of liability in Subparagraph 128 .a.i extends from the Date of Lodging through, for each Covered Flare, the date in Column C of Appendix 2.1 that is associated with that Covered

Flare.

b. 40 C.F.R. Part 60, Subpart J at the Olefins Flares . With respect to

emissi ons of SO 2 and H 2 S from the Olefins Flares , entry of this Consent Decree shall resolve

the civil claims of the United States against SDP for violations of 40 C.F.R. Part 60, Subpart J,

from the Date of Lodging through, for the Olefins Flares, the following date s, for claims that are

based on the following circumstances:

i. December 31, 2014, for claims based on Fuel Gas flowing from the SDP Refinery to the Olefins II and III Flares during emergency situations; and

ii

. December 31, 2016, for claims based on gas flowing to the Olefins Flares as a result of refinery streams being processed at the Butane Butylene Hydrotreater Unit

.

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129. Resolution of Claims under Subpart Ja Requirements. Entry of this Consent

Decree shall resolve the civil claims of the United States against SDP for violations of the

following Subpart Ja Requirements from November 13, 2012, through, for each SDP Refinery

Covered Flare, the following:

H 2 S Emission Limits (40 C.F.R. § 60.103a(h )) Sulfur and Flow Monitoring (40 C.F.R. §§ 60.107a(e ),( f ))

November 11, 2015 November 11, 2015

130. Resolution of Title V Violations . Entry of this Consent Decree shall resolve the

civil claims of the United States against SDP for the violations of Sections 502(a), 503(c), and

504(a) of the CAA, 42 U.S.C. §§ 7661a(a), 7661b(c), 7661c(a), and of 40 C.F.R. §§ 70.1(b),

70.5(a) and (b), 70.6(a) and (c), and 70.7(b), that are based upon the violations resolved by

Paragraphs 125–129 for the time frames set forth in those Paragraphs.

131. Reservation of Rights: Resolution of Liability in Paragraphs 125 and 128–130

can be Rendered Void

. Notwithstanding the resolution of liability in Paragraphs 125 and 128–

130 for the period of time between the Date of Lodging and the Post-Lodging Compliance Dates,

those resolutions of liability shall be rendered void if SDP materially fails to comply with any of

the obligations and requirements of Sections V and VI of this Decree (Compliance Requirements

and Emission Credit Generation). However:

a. To the extent that a material failure involves a partic ular Covered

Facility (ies), the resolution of liability shall be rendered void only with respect to claims

involving that particular Covered Facility (ies);

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b. The resolutions of liability in Paragraphs 125 and 128–130 shall not be

rendered void if SDP, as expeditiously as practicable, remedies such material failure and pays all

stipulated penalties due as a result of such material failure.

132. The United States reserves all legal and equitable remedies available to enforce

the provisions of this Consent Decree, except as expressly s tated in Paragraphs 125–130. This

Consent Decree shall not be construed to limit the rights of the United States to obtain penalties

or injunctive relief under the CAA or implementing regulations, or under other federal or state

laws, regulations, or permit conditions, except as expressly specified in Paragraphs 125–130.

The United States further reserves all legal and equitable remedies to address any imminent and

substantial endangerment to the public health or welfare or the environment arising at, or posed

by the Covered Facilities

, whether related to the violations addressed in th is Consent Decree or

otherwise.

133. In any subsequent administrative or judicial proceeding initiated by the United

States for injunctive relief, civil penalties, other appropriate relief relating to the Covered

Facilit ies or SDP ’s CAA violations, SDP shall not assert, and may not maintain, any defense or

claim based upon the principles of waiver, res judicata, collateral estoppel, issue preclusion,

claim preclusion, claim -splitting, or other defenses based upon any cont ention that the claims

raised by the United States in the subsequent proceeding were or should have been brought in the

instant case, except with respect to claims that have been specifically resolved pursuant to

Paragraphs 125–130 of this Section and for which the resolution of liability has not been voided

pursuant to Parag raph 131.

134. This Consent Decree is not a permit, or a modification of any permit, under any

federal, state, or local laws or regulations. SDP is responsible for achieving and maintaining

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complete compliance with all applicable federal, state, and local laws, regulations, and permits;

and SDP’ s compliance with this Consent Decree shall be no defense to any action commenced

pursuant to any such laws, regulations, or permits, except as set forth herein. The United States

does not, by its consent to the entry of this Consent Decree, warrant or aver in any manner that

SDP’ 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, s tate, or

local laws, regulations, or permits.

135. This Consent Decree does not limit or affect the rights of SDP or the United

States against any third parties that are not party to this Consent Decree, nor does it li mit the

rights of third parties that are not party to this Consent Decree against SDP , except as otherwise

provided by law.

136. This Consent Decree shall not be construed to create rights in, or grant any ca use

of action to, any third party not party to this Consent Decree.

XV. COSTS

137. The Parties shall bear their own costs of this action, including attorneys fees,

except that the United States shall be entitled to collect the costs (including attorneys fees)

incurred in any action necessary to enforce this Consent Decree or to collect any portion of the

civil penalty or any stipulated penalties due but not paid by SDP.

XV I. NOTICES

138. Unless otherwise specified herein, whenever notifications, submissions, or

co mmunications are required by this Consent Decree, they shall be made in writing and

addressed to the persons set forth below. Submission by U.S. mail or courier is required and

shall be sufficient to comply with the notice requirements of this Consent Dec ree; however, for

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the submission of technical information or data, SDP shall submit the data in electronic form

( e.g. , a disk or hard drive). The email addresses listed below are to permit the submission of

courtesy copies.

Notice or submission to the Uni ted States :

Chief, Environmental Enforcement Section

Environment and Natural Resources Division

U.S. Department of Justice

Box 7611 Ben Franklin Station Washington, DC 20044-7611

Re: DOJ No. 90 -5-2-1-09388/1

Notice or submission to EPA :

Director, Air Enforcement Division

Office of Civil Enforcement

U.S. Environmental Protection Agency

Mail Code 2242-A Regular Mail: 1200 Pennsylvania Ave, N.W. Ariel Rios Building South

Room 1119 Washington, DC 20460-0001 Express Mail: Use same address but use 20004 as the zip code

and

Associate Director Air, Toxics, and Inspections Coordination Branch (6 EN- A)

U.S. EPA, Region 6

1445 Ross Avenue Dallas, Texas 75202

For courtesy purposes, electronic copies to:

parrish.robert@epa.gov foley.patrick@epa.gov crawford.dorothy@epa.gov

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Notice or submission to SDP :

Kimberly Z. Lesniak Senior Legal Counsel Shell Oil Company

One Shell Plaza

910 Louisiana Street
Houston, TX 77002 For courtesy purposes: kim.lesniak@shell.com

Shari Keller Sr. Staff Environmental Specialist

- Air Compliance

Shell Oil Products Environmental Affairs (OSP 2804B) 910 Louisiana Houston, TX 77002 For courtesy purposes: shari.keller@shell.com

Richard Bourns Environmental Manager

Shell Deer Park Site Shell Oil Products Company, LLC Shell Deer Park, 5900 Highway 225 East, Deer Park, TX 77536 For courtesy purposes: richard.bourns@shell.com

Any Party may, by written notice to the other Party, change its designated notice recipient(s) or

notice address(es) provided above. Notices submitted pursuant to this Section shall be deemed

submitted upon mailing, unless otherwise provided in this Consent Decree or by mutual

agreement of the Parties in writing.

XVI I. EFFECTIVE DATE

139. The Effective Date of this Consent Decree shall be the date upon which this

Consent Decree is entered by the Court or a motion to enter the Consent Decree is granted,

whichever occurs first, as recorded on the Court’s docket; provided however, that SDP hereby

agrees that it shall be bound to perform duties scheduled to occur prior to the Effective Date. In

the event the United States wit hdraws or withholds consent to this Consent Decree before entry,

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or the Court declines to enter this Consent Decree, then the preceding requirement to perform

duties scheduled to occur before the Effective Date shall terminate.

XV II I. RETENTION OF JURISDI CTION

140. The Court shall retain jurisdiction over this case until termination of this Consent

Decree for the purposes of resolving disputes arising under this Decree, entering orders

modifying this Decree, or effectuating or enforcing compliance with the terms of this Decree.

XIX. MODIFICATION

141. Except as provided in Paragraph 9 , the terms of this Consent Decree may be

modified only by a subsequent written agreement signed by the United States and SDP. Where

the modification constitutes a material change to any term of this Consent Decree, it shall be

effective only upon approval by the Court.

142. Except as provided in Paragraphs 5–9, any disputes concerning modification of

this Decree shall be resolved pursuant to Section XII of this Decree (Dispute Resolution);

provided, however, that instead of the burden of proof as provided by Paragraph 115 , the Party

seeking the modification bears the burden of demonstrating that it is entitled to the requested

modification in accordance with Federal Rule of Ci vil Procedure 60(b).

XX. TERMINATION

143. Termination for the SDP Chemical Plant, the SDP Refinery or Entire Consent

Decree

. If the conditions precedent to termination set forth in Paragraph 144 are satisfied, the

requirements of this Consent Decree that are applicable to either the SDP Chemical Plant or the

SDP Refinery may be subject to termination or all of the requirements in thi s Consent Decree

may be subject to termination.

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144. Termination: Conditions Precedent . Prior to termination, SDP must have

completed all of the following requirements of this Consent Decree:

a. Payment of all civil penalties, stipulated penalties and other monetary obligations;

b. Satisfactory c ompliance with all provisions of Section V of this Decree (Compliance Requirements) with respect to all of the Covered Flaresat the Facility(ies) that is(are) subject to the termination request;

c. Operation for at least one year in satisfactory compliance with the limitations and standards set forth in Paragraphs 41 , 40.b, 47.b, 49, 56.b, 56.c, 57.b, 58.c (if and as applicable) , 58.d (if and as applicable) , and 59

for all of the Covered Flares at the Facility(ies) that is(are) subject to the termination request;

d. Compl etion of the Mitigation Projects in Section VII;

e. Completion of the Supplemental Environmental Project in Section VIII;

f. Application for and receipt of all non- Title V air permits necessary to

ensure survival of the Consent Decree limits and standards after

termination of this Consent Decree (the Paragraph 67 requirement) for all

of the f lares at the Facility(ies) that is(are) subject to the termination

request;

g. Application for a modification or amendment to the Title V permit to incorporate the limits and standards in Paragraph 67 into the Title V permit of the Facility(ies) that is(are) subject to the termination request;

and

h. Applicat ion for such modification s, amendment s, or revisions to the Covered Facilities’ NPDES permit as may be necessary as a result of the Mitigation Project required in Paragraph 71 of this Consent Decree (“Mitigation Project: North Effluent Treater Controls”).

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145. Termination: Procedure

.

a. At such time as SDP believes that it has satisfied the conditions for

termination set forth in Paragraph 144 for either the SDP Chemical Plant or the SDP Refinery or

for the entire Consent Decree, SDP may submit a request for termination to the United States by

certifying such compliance in accordance with the certification language in Paragraph 89. In the

Request for Termination, SDP must demonstrate that it has satisfied the conditions for

termination set forth in Paragraph 144

. The Request for Termination shall include all necessary

supporting documentation.

b. Following receipt by the United States of SDP’s Request for Termination,

the Parties shall confer informally concerning the Request. If the United States agrees that the

Decree may be terminated, the Parties shall submit, for the Court's approval, a joint stipulation

terminating the Decree.

c. If the United States does not agree that the Consent Decree may be

terminated, or if SDP does not receive a written response from the United States within 60 days

of SDP’s submission of the Request for Termination, SDP may invoke dispute resolution under

Section XI I of this Decree (Dispute Resolution).

XXI. PUBLIC PARTICIPATION

146. This Consent Decree shall be lodged with the Court for a period of not less than

30 days for public notice and comment in accordance with 28 C.F.R. § 50.7. The United States

reserves the right to withdraw or withhold its consent if the comments regarding the Consent

Decree d isclose facts or considerations indicating that the Consent Decree is inappropriate,

improper, or inadequate. SDP consents to entry of this Consent Decree without further notice

and agrees not to withdraw from or oppose entry of this Consent Decree by the Court or to

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challenge any provision of the Decree unless the United States has notified SDP in writing that it

no longer supports entry of the Decree.

XXI I. SIGNATORIES/SERVICE

147. Each undersigned representative of SDP and the Assistant Attorney General for

the Environment and Natural Resources Division of the Department of Justice (or his or her

designee), certify that he or she is fully authorized to enter into the terms and conditions of this

Consent Decree and to execute and legally bind the Party he or she represents to this document.

148. This Consent Decree may be signed in counterparts, and its validity shall not be

challenged on that basis. SDP agrees to accept service of process by mail with respect to all

matters arising under or relating to this Co nsent Decree and to waive the formal service

requirements set forth in Rules 4 and 5 of the Federal Rules of Civil Procedure and any

applicable Local Rules of this Court including, but not limited to, service of a summons.

XXII I. INTEGRATION

149. This Consent Decree and its Appendices constitute the final, complete, and

exclusive agreement and understanding among the Parties with respect to the settlement

embodied in this Consent Decree and its Appendixes and supersede all prior agreements and

understandings, whether oral or written, concerning the settlement embodied herein. No other

document, except for any plans or other deliverables that are submitted pursuant to this Decree,

nor any representation, inducement, agreement, understanding, or promise, constit utes any part

of this Decree or the settlement it represents, and no such extrinsic document or statement of any

kind shall be used in construing the terms of this Decree.

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XXI V. FINAL JUDGMENT

150. Upon approval and entry of this Consent Decree by the Court, this Consent

Decree shall constitute a final judgment of the Court in this action as to the United States and

SDP. The Court finds that there is no just reason for delay and therefore enters this judgment as

a final judgment under Fed. R. Civ. P. 54 and 58.

DATED this day of 2013.

UNITED STATES DISTRICT JUDGE

SOUTHERN DISTRICT OF TEXAS

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We hereby consent to the entry of the Consent Decree in the matter of United States, v . Shell Oil
Company, et al. , subject to public notice and comment.

FOR THE UNITED STATES OF AMERICA

s/ Robert G. Dreher

ROBERT G. DREHER Acting Assistant Attorney General

Environment and Natural Resources Division United States Department of Justice

s/ Robert D. Parrish

ROBERT D . PARRISH

DOJ Attorney by Special Appointment

Environmental Enforcement Section

Environment and Natural Resources Division Department of Justice 1200 Pennsylvania Ave., NW Washington, DC 20460 (202) 564-6946 (phone) parrish.robert@epa.gov

s/ Annette M. Lang

ANNETTE M. LANG

Senior Counsel

Environmental Enforcement Section

Environment and Natural Resources Division Department of Justice

P.O. Box 7611 Washington, D.C. 20044-7611 (202) 514-4213 (phone) (202) 616-6584 (fax) annette.lang@usdoj.govCase 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 116 of 121

KENNETH MAGIDSON United States Attorney

Southern District of Texas

By: s/ Keith Edward Wyatt

KEITH EDWARD WYATT

Assistant United States Attorney

Texas Bar No. 22092900

Federal Bar No. 3480 1000 Louisiana St., Suite 2300
Houston, TX 77002 Telephone: (713) 567-9713 Fax: (713) 718-3303Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 117 of 121

We hereby consent to the entry of the Consent Decree in the matter of United States v . Shell Oil Company, et al. , subject to public notice and comment.

FOR THE UNITED STATES ENVIRONMENTAL

PROTECTION AGENCY

s/ Cynthia Giles***

CYNTHIA GILES

Assistant Administrator Office of Enforcement and Compliance Assurance United States Environmental Protection Agency Washington, DC

s/ Susan Shinkman***

Susan Shinkman Director, Office of Civil Enforcement Office of Enforcement and Compliance Assurance United States Environmental Protection Agency Washington, DC

s/ Phillip A. Brooks***

PHILLIP A. BROOKS Director, Air Enforcement Division Office of Enforcement and Compliance Assurance United States Environmental Protection Agency Washington, DC

*** Signed with permission.Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 118 of 121

We hereby consent to the entry of the Consent Decree in the matter of United States v . Shell Oil Company, et al. , subject to public notice and comment.

FOR THE UNITED STATES ENVIRONMENTAL

PROTECTION AGENCY

REGION 6

s/ John Blevins***

JOHN BLEVINS

Director Compliance Assurance and Enforcement Division EPA Region 6 Dallas, TX

*** Signed with permission.Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 119 of 121

We hereby consent to the entry of the Consent Decree in the matter United States v. Shell Oil Company, et al.

FOR SHELL OIL COMPANY

By: s/ Barry J. Klein***

BARRY J. KLEIN General Manager

Deer Park Site 5900 Highway 225 East Deer Park, TX 77536 Shell Oil Products Company LLC, as Agent for Shell Oil Company

*** Signed with permission.Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 120 of 121

We hereby consent to the entry of the Consent Decree in the matter of United States v . Shell Oil Company, et al.

FOR DEER PARK REFINING LIMITED PARTNERS HIP

By: s/ Barry J. Klein***

BARRY J. KLEIN General Manager

Deer Park Site 5900 Highway 225 East Deer Park, TX 77536 Shell Oil Products Company LLC, as Agent for Shell Oil Company, General Partner

*** Signed with permission.Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 121 of 121

We hereby consent to the entry of the Consent Decree in the matter of United States v . Shell Oil Company, et al.

FOR SHELL CHEMICAL LP

By: s/ Barry J. Klein***

BARRY J. KLEIN General Manager

Deer Park Site 5900 Highway 225 East Deer Park, TX 77536 Shell Oil Products Company LLC, as Agent for Shell

Chemical LP

*** Signed with permission.Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 1 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.1

DRAWINGS ILLUSTRATING LOWER, CENTER, AND UPPER STEAM

INJECTION IN VARIOUS TYPES OF FLARE TIPS

## Appendix 1.1 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 2 of 75



### Type II

Exit Lower

Steam/Air

Mixture

Pilot Steam/Air

Tubes

Stability Ring 

### Type I

Upper

Steam

Center

Steam Pilot Stability Tab

Upper

Steam

B A

Center

Steam

Pilot Stability Tab

Upper

Steam Lower

Steam

Key:

Yellow = Vent Gas

Red = Fire Light Blue = Steam / Air

Dark Blue = SteamCase 4:13-cv-02009 Filed in TXSD on 07/10/13 Page 3 of 75 Document 2-2



### Type IV

Pilot 

### Type III

Pilot Stability Tabs

Modules

Upper

Steam

Lower

Steam Key:

Yellow = Vent Gas

Red = Fire Light Blue = Steam / Air

Dark Blue = SteamCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 4 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.2

GENERAL EQUATIONSCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 5 of 75



### APPENDIX 1.2

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 th e combusted gas immediately above the Combustion Zone, counting each carbon molecule separately where the co ncentration of each individual compound is multiplied by the number of carbon atoms it contains before summing ( e.g. , 0.1 volume percent ethane shall count as 0.2 percent OC because ethane has two carbon atoms)

For purposes of using the CE equation, the unit of measurement for CO 2 , CO, and OC must be the same; that is, if “volume percent” is used for one compound, it must be used for all compounds. “Volume percent” cannot be used for one or more compounds and “ppm-meters” for the remainder.

Equation 2: “Center Steam Mass Flow Rate” or “ 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 Rate

1 of 2Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 6 of 75



### APPENDIX 1.2

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

ṁ vg = Q vg x ( MW vg

/3 85.5 )

where:

Q vg = Vent Gas Volumetric Flow Rate

MW vg = Molecular Weight, in pounds pe r pound-mole, of the Vent Gas, as measured by the Vent Gas Averag e Molecular Weight Analyzer described in Paragraph 19 of this Consent Decree

[End of Appendix 1.2]

2 of 2Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 7 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.3

CALCULATING NHV CZ-LIMIT 

# AND NHV CZ 

# FOR

STREAM-ASSISTED FLARESCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 8 of 75



### APPENDIX 1.3

CALCULATING NHV cz-limit AND NHV
cz FOR STEAM-ASSISTED FLARES

All abbreviations, constants, and variables are defined in the Key on Page 6 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 fraction of the vent gas. All inerts, including nitrogen, are assumed to have an infi nite lower flammability limit (e.g. LFL N2 = ∞ ).

1 ൬ ݔ

ܮܨܮ ൌ ݃ݒ ܮܨܮ

݅ൌ1 ݊ ∑ ݅ Equation 1 ൰

݅

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 at the conclusion of each an alytical cycle (~10-15 minutes). Equation 2 is used by the GC to calculate the vent gas ne t heating value from each individual compound net heating value. Individual com pound volume fractions, except for water, are measured directly by the GC. A company is not required to measure water in Vent Gas. If a company chooses to measure water, then: (i) if th e water measurement is taken upstream of a knock-out drum, then

water does not have to be incl uded in the calculation of NHV vg ; (ii) if no knock-out drum exists

or if the water measurement is taken after th e knock-out drum, then the company must include

water in the calculation of NHV vg and adjust the concentration of the compounds measured by the GC to a wet basis. Individual compound net heating values, including water, are listed in Table 1 of this Appendix.

݊
ܰ ·ܪܸ ݅ ݔ ሺ ෍

ൌ ݃ݒ ܸܪܰ

݅ൌ1 Equation 2 ሻ ݅

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).

1 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 9 of 75



### APPENDIX 1.3

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 .

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.

݃ݒ ܮ ·ܨܮ ݃ݒ ܪܸ ܰ ൌ ܮ–݃ݒܮܨ ܸܪܰ 3 Equation

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:

ܮܨ ܮെ݃ݒ ܰ ·ܪܸ ൯ ݈݁݊݁ݕ݌݋ݎ݌ ݔ·ܤ൅ ܣ ൫
ൌ ݐ݈݅݉݅െݖܿ ܸܪܰ 4 Equation

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 Ap pendix. The NHV of steam is assumed to be ) are measured by on-line
௦ ܳ ݎ݋ m ) and steam flow rate ( ௩௚ ܳ ݎ݋ vg ሶ zero. Vent Gas flow rate ( m ሶ

s (is constant for each flare and set by an orifice. ௚௣ ܳ ݎ݋ pg ሶ The pilot gas flow rate ( flow meters. m

௔௜௥ ௩௚ ܸܪ ·ܰ ௩௚ ݉ ሶ ൬

௩௚ ܯܹ

ሶ ݉ ൰൅൬

௚௣ ܯܹ ௚௣ ܸܪ ·ܰ ௣௚ ሶ ݉ ൰൅൬

௚௣ ܯܹ

ሶ ݉ ൰ ൅ ቀ

௥௜௔ ܹܯ

൰

ൌ ௖௭ ܰܪܸ

ሶ ሶ ݉ ൰൅൬ ௣௚ ௩௚ ݉ ൬

ை మ ு ௦ ܹܯ ௚௩ ܹܯ

ሻ ௚௣ ܸכܪ ܰ ௣௚ ܳ ൯ ൅ ሺ ௩௚ ܸכܪ ܰ ௩௚ ൫ܳ

ൌ ௖௭ ܰܪܸ

௔௜௥ ൅ ܳ
௦ ൅ ܳ ௣௚ ൅ ܳ ௩௚ ܳ ቁ Equation 5a

OR

Equation 5b

2 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 10 of 75



### APPENDIX 1.3

The values for
௦ ݉

ሶ

, are determined as follows based on the type of flare: Q

s and Q air , ௥ ௔௜ ݉

ሶ

Steam-Assisted Flare without a Minimum Steam Reduction System (“MSRS”)

݁ ݑ ݈ ܽ ݒ ݎ ݁ ݀ ݑ ݁ ܽ ݏ ݉ ൌ ௦ ܳ ݎ݋ ݉

ሶ

ൌ 0 ௥௜௔ ݎ݋ ܳ ௔௜௥ ݉

ሶ ௦

Steam-Assisted Flare with MSRS

݈ ൌ ݉ ௦ ݎ݋ ܳ
௦ ݉

ሶ ܳݎ݋ ݉

ሶ ݁ ݑ ݊݋݅ݐܽݑݍܧ ܽ ݒ ݎ ݁ ݀ ݑ ݁ ܽ ݏ

ݎݐ݈ݑݏ݉݁݋ݎ݂ ൌ ௔௜௥ 13 ݅݊݌݁ݐ6ܽ ܵ ௔௜௥

OR

ൌ 0 with vendor certification that the MSRS equipment installed ௥௜௔ ݎ݋ ܳ ݉

ሶ

on the flare is not capable ሺeven at minimum vent gas flowሻ of inspirating more than twice the stoichiometric volume of air in to the vent gas.

The molecular weight of the vent gas (MW vg ) is calculated by the GC using Equation 6. An on-line ultrasonic flow meter may also be used to calculate MW vg . Individual compound molecular weights are listed in Table 1 of this Appendix. ௔௜௥

ܹܯ ݃ݒ ݊

݅ ݔ ሺ ෍

ൌ

݅ൌ1 · ܯܹ ݅ 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.

݊ ෍൫

݅ൌ1 ܸܪܰ ൌ ݅ ܪܰ · ܸ ݅ ݃݌ ൯ 7 Equation ݃݌

݊ ෍൫

݅ൌ1 ܹܯ ൌ ܹܯ · ݅ ݃݌ ݅ ൯ 8 Equation ݃݌

3 of 10ሶ

ሶ ሶ

ሶ Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 11 of 75



### APPENDIX 1.3

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:

ܱ ଶ ܪ ቁ ݕ

2 ൅ ቀ

ଶ ܱܥ ՜ ݔ ଶ ቁ ܱ

4 ݕ ݔቀ ൅ ൅ ௬ ܪ
௫ ܥ 9 Equation

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

Therefore, the stoichiometric oxygen molar flow rate (moles/hr) for any given combustible compound flow is defined by Equation 10a (mass basis) or Equation 10b (volumetric basis):

ሶ ೡ೒

ெௐ ೡ೒ ൰ ቀݔ ൅ ௬ Equation 10a ቁ

ସ ௠ ൬

௝ ൌ ݔ ைଶି௦௧௢௜௖௛ ݊

OR

௩௚ ܳ ൬
௝ ൌ ݔ ைଶି௦௧௢௜௖௛ ݊ ሶ

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). 385.5 ቀ ൰ ൅ ݔ ݕ

4 ቁ Equation 10b

௡

ೕ ைଶି௦௧௢௜௖௛ ݊ כ෍

మ ை ܹ ൌ ܯ ைଶି௦௧௢௜௖௛ି௩௚ ݉

௝ୀଵ

OR

௡

ೕ ைଶି௦௧௢௜௖௛ ݊ ෍

כ ൌ 385.5 ைଶି௦௧௢௜௖௛ି௩௚ ܳ

௝ୀଵ Equation 11a

Equation 11b

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).

ሶ ܱ2െ݋ݐݏ݄݅ܿെݒ݃ כ ݉ ൌ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ݉

ሶ ܽ݅ݎ ܯܹ

2 ܱ ܹܯ 0.21

· Equation 12a

OR

݃ݒെ݄݅ܿ݋ݐݏെܱ2 ܳ

ൌ ௔௜௥ି௦௧௢௜௖௛ି௩௚ ܳ 0.21 Equation 12b

4 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 12 of 75



### APPENDIX 1.3

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 from the total air provided by the MSRS. This is shown in Equation 13a and 13.b.

ሶ ݉

ሶ ௔௜௥ ൌ ݉ ݉ ሶ 2 כ െ ሺ ௔௜௥ିெௌோௌ

OR ܽ݅ݎെ݋ݐݏ݄݅ܿെݒ݃ ሻ Equation 13a

ሻ ܽ݅ݎെ݋ݐݏ݄݅ܿെݒ݃ ܳ כ െ ሺ2 ௔௜௥ିெௌோௌ ൌ ܳ ௥௜௔ ܳ Equation 13b

݉

ሶ The equation for 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.

݉

ሶ then ൏ 0 ௔௜௥ ݉

ሶ If

OR

ൌ 0 ௥௜௔ ܳ ݄݊݁ ൏ 0 ݐ ௔௜௥ ܳ If is specific to the MSRS inst alled and must be provided ௔௜௥ିெௌோௌ ܳ or ௔௜௥ିெௌோௌ

௔௜௥ ൌ 0

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 acceptable combustion efficiency. E quation 14 shows this relationship.

ݐ݈݅݉݅െݖܿ ܪܸ ܰ ൒
ݖܿ ܸܪܰ 14 Equation

5 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 13 of 75



### APPENDIX 1.3

Key to the Abbreviations:

ሻ ሻ ݉– ݋݈݅ܽݎ ݈ܾ ⁄ ଶ ܱ ݈݉݋

– 0.21 ݈ܾ ሺ ݂݋݃݁݊ ݕݔ݋ ݅݊ ݎܽ݅ ݊݋݅ݐܽܿݎ ݂ ݈݁݉݋ 0.21 ൌ ݈݈݋݉‐ܾ ⁄ ݂ܿݏ 385.5 ሺ ܾ݅ܿݑ ܿݐ ݂݁݁ ݀ݎܽ݊݀ܽݐݏ ݏ݈݁݋ ݉݋ݐ ݊݀ݑ݋݌ ݉݋ݎ ݂ ݊݋݅ݏݎ݁ݒ݊݋ܿ 385.5 ൌ ሻ ݏݏ݈݁ݐ݊݅ݑ ሺ ௅ ி௅ି௚௩ ܸܪܰ ݂ݎ݋ ݈݌݁݅݅ݎ ݐ ݈ݑ݉ ݂݂݅ܿ݅݁݁ݕ݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݁ݒ݋ݎ݈݈ܽ ൌ ܣ ሻݏݏ݈݁ݐ݊݅ݑሺ ௅ி௅ି௚௩ ݎ݋ܸ ݂ܪܰ ݎ݈݅݁݌݅ݐ݈ݑ ݉ ݕܿ݅݁݊ܿ ݂݂݁݅ ݊݋݅ݐݏݑܾ݉݋ ܿ ݈݁݊݁ݕ݌݋ݎ݌ ൌ ܤ ሻ % ݈݋ݒ ሺ ݂݋ ܥ݄݁ ݅݊ ܸܱݐ ݐ݁݊ݒ ݏ ݃ܽ ݊݋݅ݐܽݎݐ݊ܿ݁݊݋ܿ ൌ ௚௩ ܥ ሻ ݏݏ ݈݁ݐ݊݅ݑሺ1 ܾ݈ܶܽ݁ ݅݊ ݉݊ݑ݈݋݅ ܿ ݉݋ݎ ݂ ݊݀ݑ݋݌݉݋ ܿ ݁݀ݎܾ݉݁ݑ ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݅ ሻ ݏݏ ݈݁ݐ݊݅ݑሺ1 ݉݊ݑ݈݋ ܾ݈ܶܽ݁ ݅݊ ݆ ܿ ݉݋ݎ ݊݀ ݂ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ ݊ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݆ ݏݏ݈݁ݐ݊݅ݑሺ ሻ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ ܿ ݄݁ݐ ݋݂ ݐ݊݁݊݋݌݉݋ ܿ ݏݑ݋݁ݏ ݃ܽ ݈ܽݑ݅݀ݒ݅݊݀݅ ൌ ݇

݈ ൌ ܮܨܮ ௜ ሻ % ݈݋ݒ ሺ ݊݀ݑ݋݌݉݋ ܿ ݈ܽݑ݅݀ݒ݅݊݀݅ ݐ݂ ݈݅݉݅݋ ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݎ݁ݓ݋ ሻ % ݈݋ݒ ሺ ݏ ݃ܽ ݐ݂ ݈݅݉݅݋ ݐ݁݊ݒ ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݈ݎ݁ݓ݋ ൌ ௚௩ ܮܨܮ ሻ ݎ/݄ ݈ܾሺ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ ݎ ܽ݅ ݉ݏݏܽ ൌ ௔௜௥ ݉ ሶ

ݎܽ݅ ݁ݐܽݎ݂ ݋ ݏݏ ݉ܽݓ݋݂݈ ݈ܽݐ݋ ൌ ݐ ெௌோௌି ௔௜௥ ݉ ሶ

݉ ሶ

݉ ሶ

݉ ሶ

݉ ሶ

݉ ሶ

݉ ሶ

݊ ሶ ሻ ݎ/݄ ݈ܾሺ ݕܴܵܵ ܽ݊ ܾܯ ܿ݁݀ݑ݀݋ݎݐ݊ ݅ ሻ ݎ݄ ݈ܾ/ሺ ݎ ܽ݅ݏݏ ݉ܽݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ݃ܽ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௚௩ି ௖௛ ሻ ݎ/݄ ݈ܾሺ ݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉ ݋ܿ ݂ ݉ݏݏܽ ൌ ௞ ሻ ݄ݎ ⁄ ݈ܾሺ ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݓ݋݂݈ ݏݏ ݉ܽ ݃݁݊ݕݔ݋ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௚௩ି௢௜௖௛௦௧ିைଶ ௔௜௥ି௦௧௢௜ ݒܽ݅݊݀݅ݑ݈݅݀ ݂݋ ݎ݁ݐܽ ݈ݓ݋

( ݎ/݄ ݈ܾሺ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݉ݏݏܽ ൌ ௣௚ ݈݂ ݉ݏݏܽ ൌ ௦ ሻ ܾݎ/݄ ݈ሺ ݈ܽݐ݋ݐ݁ ݐݏܽ݉ ݂݋ ݎ݁ݐܽ ݓ݋ ሻ ݎ݄ / ܾ ݈ሺ ݏ݃ܽ ݐ ݁ݒ݊ ݂݋ ݎ݁ݐܽ ݈݂ݓ݋ ݉ݏݏܽ ൌ ௚ ௩ ሻ ݎ݄ ⁄ ݈݋ ݉ሺ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ܽ݊ ݎ݋݂ ݓ ݎ݈ܽ݋ ݉݋݂݈ ݃݁݊ݕݔ݋ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௢௜௖௛ ௦௧ିைଶ ሻ ݈݋݉

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

– /݈ܾ ݈ܾሺ ݊݀ݑ݋݌݉݋ ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ݐ݄݁݅݃ݓ݂ ݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௜ ܹܯ ሺ ݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ݐ݄݁݅݃ݓ݂ ݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௞ ܹܯ ሻ ݉݋݈

– ܾ݈ܾ/ ݈ ሻ ݈݋݉

– /݈ܾ32.0 ݈ܾ ሺ ݐ݄݁݅݃ݓ݂ ݋݃݁݊ ݕݔ݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ మ ை ܹܯ ሻ ݈݋݉

– /݈ܾ 28.9 ݈ܾሺ ݐ݄݁݅݃ݓ݂ ݋ ݎ ܽ݅ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௔௜௥ ܹܯ ሻ ݈݋݉

– /݈ܾ ݈ܾሺ ݐ݄݁݅݃ݓ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ௣௚ ܹܯ ሻ ݈݉݋

– ݈ܾ / ܾ݈ ሺ ݃ܽݏ ݐ݁݊ ݒ ݂݋ ݁݅ݓݐ݄݃ ݈ܽ݉ݑ݈݁ܿ݋ݎ ൌ ௚ ௩ ܹܯ ሻ ݏݏ݈݁ݐ݊݅ݑ ሺ 1 ܾ݈ܶܽ݁ ݉݋ݎ݂ ݏ݊݀ݑ݋݌݉݋ ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ݂݋ ݐݏ݈݅ ൌ ݊ ݂ܿݏ ⁄ ܷܶܤሺ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ ܿ ݁ݑ݈ܽݒ݂ ݋݄݁ ݐ ݅݊݃ݐ ݄݁ܽ ݐ݊݁ ൌ ௭௖ ܸܪܰ ݏ݂ܿ ⁄ ܷܶܤሺ ݊݀ݑ݋݌݉݋ ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ݁ݑ݈ܽݒ݂ ݋ ݅݊݃ݐ ݄݁ܽ ݊ݐ݁ ൌ ܸܪܰ ݏ݂ܿ ⁄ ܷܶܤሺ ݐ ݈݅݉݅ ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݎ݁ݓ݋ ݁ݑ݈ܽݒ ݐ݁݊ݒ ݏ ݈ ݃ܽݐܽ ݅݊݃ݐ ݄݁ܽ ݐ݊݁ ൌ ௅ ி௅ି௚௩ ௜ ܸܪܰ ݂ܿݏ ⁄ ܤܷܶ ሺ ݊݁݋ݖ ݊݋݅ݐݏݑܾ݉݋ ܿ ݁ݑ݈ܽݒ݂ ݋݄݁ ݐ ݅݊݃ݐ ݄݁ܽ ݐ ݊݁ ݐ݅݉݅ ሻ ሻ ሻ ሻ

݈ ൌ ௖௭ି௟௜௠௜௧ ܰܪܸ ሻ ݂ܿݏ ⁄ ܷܶܤሺ ݁ݑ݈ܽݒ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݅݊݃ݐ ݄݁ܽ ݐ݊݁ ൌ ௣௚ ܸܪܰ ሻ ݏ݂ܿ ⁄ ܷܶܤ ሺ ݁ݑ݈ܽݒ݂ ݋ ݐ݁݊ݒ ݏ ݃ܽ ݅݊݃ݐ ݄݁ܽ ݐ݊݁ ൌ ௚ ௩ ܸܪܰ ሻ݅ܽݏ݌ሺ ݏ ݃ܽ ݊݁݋ ݖ ݊݋݅ݐݏݑܾ݉݋ ܿ ݂݋ ݌݁ݎݑݏݏ݁ݎ ൌ ௭௖ ܲ

݅ ሻ݅ݏ݌14.696 ሺ ݏ݊݋݅ݐ݊݀݋ ܿ ݀ݎܽ݊݀ܽݐݏ ݐ ܽ ݁ݎݑݏݏ݁ݎ݌ ܽݐܾ݉݁݊ ൌ ௦௧ௗ ܲ ሻ ݂ݎ݊݋݅ݐܽܿ ݈݋ݒ ሺ ݏ݃ܽ ݅݊ݐ݋݈݅݌ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݊݀݅ ൌ ௜ ݃݌ ሻ݂݄ܿݏሺ ݕܴܵܵ ܽ݊ ܾܯ ܿ݁݀ݑ݀݋ݎݐ ݅݊ ݎ݅ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ܽ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݈ܽݐ݋ ൌ ݐ ௔௜௥ ெௌோௌି ܳ ሻ݂݄ܿݏሺ ݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎ ܽ݅ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐ ݏ ൌ ௚ ௩ି௖௛ ௜௔௜௥ ௢௦௧ି ܳ ሻ݂݄ܿݏሺ ݓ݋݁ ݂݈ݐܽݎ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݐ݊݁݊݋݌݉݋ ܿ ݐ݁݊ݒ ݏ ݃ܽ ݈݅݀ܽ݅ݒ݊݀݅ ൌ ௞ ܳ ሻ ݎ/݄ ଷ ݐ݂ሺ ݎ݁ܽݐ ݓ ݈݂݋ ݉݁ݎݐ݅ܿ ݑ ݈݋ݒ ݐ ݊݁݋݌݉݋݊ܿ ݏ݃ܽ ݐ ݅ݒ݈݁݅݀ܽ݊݀݅ݒ݊ ൌ ௔௖௙ ,௞ ܳ ሻ ݂݄ܿݏ ሺ ݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݅ܿ ݉݁ݎݐ ݑ ݈݋ݒ ݃݁ݕݔ݋݊ ݎݐ݅ܿ ݉݁݋݄݅ܿ݅݋ݐݏ ൌ ௚ ௩ି௢௜௖௛௦௧ିைଶ ܳ ሻ ݂݄ܿݏ ሺ ݓ݋ܽ ݂݈ݎ݁ݐ ݋݅ݎݐ݉݁ݑ݈ܿ ݒ ݃ܽݏ ݐ݁݊ ൌ ݒ ௚ ௩ ܳ ሻ ݂݄ܿݏ ሺ ݓ݋݁ ݂݈ݐܽݎ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݏ ݃ܽ ݌ݐ݋݈݅ ൌ ௚௣ ܳ ሻ ݂݄ܿݏ ሺ ݓ݋݁ ݂݈ݐܽݎ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݏ݁ܽ݉ݐ ൌ ௦ ܳ ሻ݂݄ܿݏሺ ݓ݋݁ ݂݈ݐܽݎ ݅ܿݎݐ݉݁ݑ݈݋ݒ ܽݎ݅ ൌ ௔௜௥ ܳ ) ݋ܴ݈ · ݉ െ ܾ݈ ⁄ ݌ ·ݏ݅ ଷ ݐ10.73 ݂ሺ ݐܽ݊ݐݏ݊݋ ܿ ݏ݃ܽ ൌ ܴ ሻ°ܴሺ ݊݁݋ݖ ݏ ݃ܽ ݊݋݅ݐݏݑܾ݉݋ ܿ ݂݋ ݁ݎݑݐܽݎ݁݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௭௖ ܶ ሻ528°ܴሺ ݏ݊݋݅ݐ݊݀݅݋ܿ ݀ݎܽ݊݀ܽݐ ݐ ܽݏ ݁ݎݑݐܽݎ݁݌݁݉ݐ ݁ܽݐݑ݈݋ݏܾ ൌ ௦௧ௗ ܶ ሻ ݈݋݉ ݈/݋݉ሺ ௬ ܪ ௫ ݎ݁݌݈݁ ݋݂ ݉݋ ܥ ݂݋݊ ݋ܾݎ ܿܽ ݏ݈݁݋݉ ݔ ൌ ሻ ݊݋݅ ݐܽܿݎ݂ ݈݋ݒሺ ݏ ݃ܽ ݐ݁݊ݒ ݄݁ ݅݊ݐ ݊݋݅ݐ ܽܿݎ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ ܿ ݈ܽ݅ݑ݅݀ݒ݊݀݅ ൌ ௜ ݔ ሻ݊ ݅݋ ݐ ݋݂݈ݎܿܽ ݒሺ ݏ ݄݁ ݅݊ݐ ݐ݁݊ݒ݃ܽ ݊݋݅ݐܽܿݎ ݂ ݉݁ݑ݈݋ݒ ݊݀ݑ݋݌݉݋ܿ ܾ݈݅݁ݐݏݑܾ݉݋ܿ ݈ܽ݅ݑ݅݀ݒ݊݀݅ ൌ ௝ ݔ ሻ ݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݄݁ݐ ݐ݁݊ݒ ݏ݃ܽ ݅݊ ݈݁݊݁ݕ݌݋ݎ݌ ݂݋ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ ൌ ݒ ௟௘௡௘ ௬௣௥௢௣ ݔ ሻ ݈݋݉ ݈/݋݉ሺ ௬ ܪ ௫ ݎ݁݌݈݁ ݋݂ ݉݋ ܥ ݃݁݊݋ݎ݀ݕ ݄ ݂݋ ݏ݈݁݋݉ ݕ ൌ

6 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 14 of 75



### APPENDIX 1.3

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 ∞ n/a n/a

3

- Nitrogen 0 28.01 ∞ n/a n/a

4

- CO 2 0 44.01 ∞ n/a n/a

5

- CO 316 28.01 0.125 n/a n/a

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 2928 56.11 0.018 4 8

15 11 trans-Butene 2826 56.11 0.017 4 8

16 12 cis-Butene 2830 56.11 0.016 4 8

17 13 1,3-Butadiene 2690 54.09 0.020 4 6

18 14 Pentane+ (C 5 +) 3655 72.15 0.014 5 12

19

- Water (3) 0 18.02 ∞ n/a n/a

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.

3 A GC does not measure water. If water is measured by means of another instrument, the properties of water listed in this row shall be used.

Note: Benzene is not required to be sp eciated by the Gas Chromatograph for this refinery settlement ( see Appendix 1.9) because benzene is present in the Vent Gas only in de minimis quantities. Because benzene speci ation is not required, it is not listed in Table 1of this Appendix. The Vent Gas composition involved in other

future settlements should be evaluated on a case-by-cas e basis to determine if benzene speciation should be required.

7 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 15 of 75



### APPENDIX 1.3

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 X Condition Y

≤ 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 X: 3 ≤ H 2 % ≤ 8 and Propylene% ≥ H 2 % (all percentages are volume or mole percentages) Condition Y: Any condition not meeting the requirements for Condition X.

Note: The specifications for Condition X 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:

௡

௝ ෍ ൌ

ݔ ௚ ௩ ܥ

௝ୀସ 100 15 Equation כ

Note: The summation does not include methane or ethane.

8 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 16 of 75



### APPENDIX 1.3

Addendum A 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 ௚௣ ܸכܪ ܰ ௣௚ ܳ ൯൅ሺ
௩௚ ܸכܪ ܰ ௩௚ ൫ܳ

ൌ ௖௭ ܰܪܸ

௔௜௥ ൅ ܳ ௦ ൅ ܳ ௣௚ ൅ ܳ ௩௚ ܳ Equation 5b

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 ௞,௔௖௙ ൌ ܳ ௞ ܳ

௖௭ ܶ ௦௧ௗ ܲ Equation A1

݉ ሶ

ൌ ௞,௔௖௙ ܳ

௖௭ ܴܶ ௞ ݉ ሶ

ൌ ௞ ܳ

௖௭ ܲ ௞ ܯܹ ௖௭ ܴܶ ௞

௭௖ ܲ ௞ ܹܯ Equation A2

௦௧ௗ ܶ

כ ௖௭ ܲ

כ

௖௭ ܶ ௦௧ௗ ܲ ௦௧ௗ ܴܶ ௞ ݉ ሶ

ൌ

௦௧ௗ ܲ ௞ ܯܹ Equation A3

ሶ 528 כ 10.73 כ ௞ ሶ ݉

ൌ 385.5 14.696 כ ௞ ܹܯ ݉

ൌ ௞ ܳ

௞ ܹܯ ௞

Substitution of this expression into Equation 5b gives NHV

cz in terms of mass flow:

௩௚ ௣௚ ݉ ሶ ൰ ൅ ൬385.5

௩௚ ܸכܪ ܰ ݉ ሶ ൬385.5

௚௣ ܯܹ ௩௚ ܯܹ

ሶ ݉ ሶ ሶ ሶ ௩௚ ௣௚ ௔௜௥ ݉ ൅ 385.5 ݉ ൅ 385.5 ݉ 385.5

௥௜௔ ܹܯ ை మ ு ௦ ܹܯ ௚௣ ܹܯ ௚௩ ܹܯ Equation A4

൰

௣௚ ܰ כܪܸ

ൌ ௖௭ ܰܪܸ 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:

9 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 17 of 75



### APPENDIX 1.3

௔௜௥ ௩௚ ܸܪ ·ܰ ௩௚ ݉ ሶ ൬

௩௚ ܯܹ

ሶ ݉ ൰൅൬

௚௣ ܯܹ ௚௣ ܸܪ ·ܰ ௣௚ ሶ ݉ ൰൅൬

௚௣ ܯܹ

ሶ ݉ ൰ ൅ ቀ

௥௜௔ ܹܯ

൰

ൌ ௖௭ ܰܪܸ Equation 5a

݉ ሶ ൰൅൬ ௣௚ ௩௚ ݉ ሶ ൬

ை మ ு ௦ ܹܯ ௚௩ ܹܯ

This demonstrates the equiva lence of Equations 5a and 5b. ቁ

10 of 10Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 18 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.4

EPA’S POLICY ON EXCESS EMISSIONS DURING

MALFUNCTIONS, STARTUP, AND SHUTDOWN

## APPENDIX 1.4

POLICY ON EXCESS EMISSIONS DURING MALFUNCTIONS, STARTUP, AND

SHUTDOWN

Introduction

This policy specifies when and in what manner state implementation plans (SIPS) may provide for defenses to

violations caused by periods of excess emissions due to malfunctions,l startup, or shutdown. Generally, since SIPS must provide for attainment and maintenance of the national ambient

air quality standards and the achievement of PSD increments, all
periods of excess emissions must be considered violations.
Accordingly, any provision that allows for an automatic
exemptioh2 for excess emissions is prohibited.

However, the imposition of a penalty for excess emissions during malfunctions caused by circumstances entirely beyond the

control of the owner or operator may not be appropriate. States

may, therefore, as an exercise of their inherent enforcement
discretion, choose nod to penalize a source that has produced

excess emissions under such circumstances.

This policy provides an alternative approach to enforcement

discretion for areas and pollutants where the respective

contributions of individual sources to pollutant concentrations

in ambient air are such that no single source or small group of

sources has the potential to cause an exceedance of the NAAQS or

PSD increments. Where a single source or small group of sources

has the potential to cause an exceedance of the NAAQS or PSD
increments, as is often the case for sulfur dioxide and lead,'

EPA believes approaches other than enforcement discretion are not appropriate. In such cases, any excess emissions may have a significant chance of causing an exceedance or violation of the
applicable standard or PSD increment.

1The term excess emission means an air emission level which

exceeds any applicable emission limitation. Ma3function means a

sudden and unavoidable breakdown of process or control equipment.

2The term automatic exemption means a generally applicable
provision in a SIP that would provide that if certain conditions

existed during a period of excess emissions, then those

exceedances would not be considered violations.

3This policy also does not apply for purposes of PM2.5

NAAQS. In American Trucking Association v. EPA, 175 F. 3d 1027

(D.C. Circ., 1999), the court remanded the PM2.5 NAAQS to the

EPA. The Agency has not determined whether tha.s policy is
appropriate for PM2.5 NAAQS. Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 19 of 75

## APPENDIX 1.4

- 2

-

Except where a single source or small group of sources has

the potential to cause an exceedance of the NAAQS or PSD
increments, states may include in their SIPS affirmative

defensesg for excess emissions, as long as the SIP establishes

limitations consistent with those set out below. If approved

into a SIP, an affirmative defense would be available to sources
in an enforcement action seeking penalties brought by the state,

EPA, or citizens. However, a determination by the state not to

take an enforcement action would not bar EPA or citizen action s

In addition, in certain limited circumstances, it may be
appropriate for the State to build into a source

- specific or

source

- category- specific emission standard a provision stating

that the otherwise applicable emission limitations do not apply
during narrowly defined startup and shutdown periods.

I. AUTOMATIC EXEMPTIONS AND ENFORCEMENT DISCRETION

If a SIP contains a provision addressing excess emissions,

i~ cannot be the type that provides for automatic exemptions.

Automatic exemptions might aggravate amba.ent air quality by
excusing excess emissions that cause or contribute to a violation

of an ambient air quality standard. Additional grounds for
disapproving a SIP that includes the automatic exemption approach

are discussed in more detail at 42 Fed. Reg. 58171 (November 8,

1977) and 42 Fed. Reg. 21372 (April 27, 1977). As a result, EPA

will not approve any SIP revisions that provide automatic

exemptions for periods of excess emissions.

The best assurance that excess emissions will not interfere

with NAAQS attainment, maintenance, or increments is to address

excess emissions through enforcement discretion. This policy

provides alternative means for addressing excess emissions of

criteria pollutants. However, this policy does not apply where a single source or small group of sources has the potential to

cause an exceedance of the NAAQS or PSD increments. Moreover,

'The term affirmative defense means, in the context of an

enforcement proceeding, a response or defense put forward by a
defendant, regarding which the defendant has the burden of proof,

and the merits of which are independently and objectively

evaluated in a judicial or administrative proceeding.

SBecause all periods of excess emissions are violations and

because affirmative defense provisions may not apply in actions

fox injunctive relief, under no circumstances would EPA consa. der
periods of excess emissions, even if covered by an affirmative

defense, to be "federally permiCted releases" under EPCRA or

CERCLA. Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 20 of 75

## APPENDIX 1.4

- 3

-

nothing in this guidance should be construed as requiring States

to include affirmative defense provisions in their SIPS.

II. AFFIRMATIVE DEFENSES FOR MALFUNCTIONS

The EPA can approve a STP revision that creates an

affirmative defense to claims for penalties in enforcement

actions regarding excess emissions caused by malfunctions as long

as the defense does not apply ~o SIP provisions that derive from

federally promulgated performance standards or emission limits,

such a9 new source performance standards (NSPS) and national

emissions standards for hazardous air pollutants (NESHAPS).6 In

addition, affirmative defenses are not appropriate for areas and

pollutants where a single source or small group of sources has

the potential to cause an exceedance of the NAAQS or PSD

increments. Furthermore, affirmative defenses to claims for

injunctive relief are not allowed. To be approved, an

affirmative defense provision must provide that the defendant has

the burden of proof of demonstrating ghat:

1. The excess emissions were caused by a sudden,

unavoidable breakdown of technology, beyond the control of the

owner or operator;

2. The excess emissions (a) did not stem from any activity

or event that could have been foreseen and avoided, or planned

for, and (b) could not have been avoided by better operation and

maintenance practices;

3. To the maximum extent practicable the air pollution

control equipment or processes were maintained and operated in a

manner consistent with good practice for minimizing emissions;

4. Repairs were made in an expeditious fashion when the

operator knew or should have known that applicable emission

limitations were being exceeded. Off -shift labor and overtime

must have been utilized, to the extent practicable, to ensure

that such repairs were made as expeditiously as practicable;

5. The amount and duration of the excess emissions

(including any bypass) were minimized to the maximum extent
practicable during periods of such emissions;

6To the extent a State includes NSPS ox NESHAPS in its SIP,

the standards should not deviate from those that were federally

promulgated. Because EPA set these standards taking into account
technological limitations, additional exemptions would be

inappropriate. Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 21 of 75

## APPENDIX 1.4

-~-

6. All possible steps were taken to minimize the impact of

the excess emissions on ambient air quality;

7. All emission monitoring systems were kept in operation

if at all possible;

8. The owner or operator's actions in response to the

excess emissions were documented by properly signed,

contemporaneous operating logs, or other relevant evidence;

9. The excess emissions were n.ot part of a recurring

pattern indicative of inadequate design, operation, or maintenance; and

10. The owner or operator properly and promptly notified

the appropriate regulatory authority.

The EPA interprets these criteria narrowly. Only those

malfunctions that are sudden, unavoidable, and unpredictable in

nature quality for the defense. For example, a single instance

of a burst pipe that meets the above criteria may qualify under

an affirmative defense. The defense would not be available,

however, if the facility had a history oP similar failures

because of improper design, improper maintenance, or poor operating practices. Furthermore, a source must have taken all

available measures ~o compensate for and resolve the malfunc~ian.

If a facility has a baghouse fire ghat leads to excess emissions,

the affirmative defense would be appropriate only for the period

of time necessary to modify or curtail operations to come into
compliance. The fire should not be used to excuse excess
emissions generated during an extended period of time while the

operator orders and installs new bags, and relevant SIP language

must limit applicability of the affirmative defense accordingly.

III. EXCESS EMISSIONS DURING STARTUP AND SHTJTDOWN

Tn general, startup and shutdown of process equipment are
part of the normal operation of a source and should be accounted

for in the planning, design, and implementation of operating
procedures for the process and control equipment. Accordingly,

it is reasonable to expect that careful and prudent planning and design will eliminate violations of emission limitations during

such periods.

A. SOURCE CATEGORY SPECIFIC RULES FOR STARTUP AND SHUTDOWN

For some source categories, given the types of control
technologies available, there may exist short periods of

emissions during startup and shutdown when, despite best efforts regarding planning, design, and operating procedures, the Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 22 of 75

## APPENDIX 1.4

- 5

-

otherwise applicable emission limitation cannot be met. Accordingly, except in the case where a single source or small

group of sources has the potential to cause an exceedance of the

~` NAAQS or P5D increments, it may be appropriate, in consultation

with EPA, to create narrowly

- tailored SIP revisions that take

these technological limitations into account and state that the

otherwise applicable emissions limitations do not apply during narrowly defined startup and shutdown periods. To be approved,

these revisions should meet the following requirements:

1. The revision must be limited to specific, narrowlydefined source categories using specific control strategies
(e.g., cogeneration facilities burning natural gas and using

selective catalytic reduction);

2. Use of the control strategy for this source category

must be technically infeasible during startup or shutdown periods;

3. The Frequency and duration of operation in startup or
shutdown mode must be minimized to the maximum extent practicable;

4. As part of its justification of the STP revision, the

state should analyze the potential worst -case emissions that

could occur during startup and shutdown;

5. All possible steps must be taken to minimize the impact

of emissions during startup and shutdown on ambient air quality;

6. At all dimes, the facility must be operated in a manner
consistent with good practice for minimizing emissions, and the

source must have used best efforts regarding planning, design,

and operating procedures to meet the otherwise applicable

emission limitation; and

7. The owner or operator s actions during startup and

shutdown periods must be documented by properly signed,

contemporaneous operating 7.ogs, or other relevant evidence.

B. GENERAL, AFFIRMATIVE DEFENSE PROVISIONS RELATING TO

STARTUP AND SHUTDOWN

In addition to the approach outlined in Section II(A) above,

States may address the problem of excess emissions occurring
during startup and shutdown periods through an enforcement

discretion approach. Further, except in the case where a single

source or small group of sources has the potential to cause an

exceedance of the NAAQS or PSD increments, States may also adopt

for their SIPS an affirmative defense approach. Using this Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 23 of 75

## ~~ APPENDIX 1.4

- 6

-

approach, all periods of excess emissions arising during startup

and shutdown must be treated as violations, and the affirmative

defense provision must not be available for claims for injunctive

relief.. Furthermore, to be approved, such a provision must
provide that the defendant has the burden of proof of

demonstrating that:

1. The periods of excess emissions that occurred during

startup and shutdown were short and infrequent and could not have

been prevented through careful planning and design;

2. The excess emissions were not part of a recurring

pattern indicative of inadequate design, operation, or

maintenance;

3. If the excess emissions were caused'by a bypass (an

intentional diversion of control equipment), then the bypass was

unavoidable to prevent loss of life, personal injury, or severe

property damage;

4. At all times, the facility was operated in a manner

consistent with good practice for minimizing emissions;

5. The frequency and duration of operation in startup or

shutdown mode was minimized to the maximum extent practicable;

6. All possible steps were taken to minimize the impact of

the excess emissions on ambient air quality;

7. A11 emission monitoring systems were kept in operata.on

if at all possible;

8. The owner or operator's actions during the period of

excess emissions were documented by properly signed,

contemporaneous operating logs, or other relevant evidence; and

9. The owner or operator properly and promptly notified the

appropriate regulatory authority.

If excess emissions occur during routine startup or shutdown

periods due to a malfunction, then those instances should be

treated as o~har malfunctions that are subject to the malfunction

provisions of this policy. (Reference Part I above).

bennett899a.wpolAugust 11, 1999 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 24 of 75Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 25 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.5

CALCULATING MOMENTUM FLUX RATIOCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 26 of 75



### APPENDIX 1.5

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.

ଶ ௩௚ା௦,௖௘௡௧ · ݒ ௩௚ା௦,௖௘௡௧ ߩ

ൌ ܴܨܯ ߩ ௥௜௔ ݒ · ௥௜௔ ଶ Equation 1

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 th e density of any given component ( ρ i ) at standard temperature and pressure (68 °F, 1 atm) is shown in Equation 2.

ܹܯ

ൌ ܹܯ ܹܯ

ൌ ௜ ௜ ௜ 385.5 ߩ ௜ ൌ 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.

௥௜௔ ܹܯ

ൌ ௥௜௔ ߩ 385.5 ൌ 28.96

௩௚ ܯܹ

ൌ ௩௚ ߩ 385.5

385.5 ൌ 18.02 ை మ ு ܯܹ

ൌ ௦,௖௘௡௧ ߩ Equation 3

Equation 4

Equation 5 ݅ݏ݌

· 14.696 ܲ ·

௔௕௦ ܶ ܴ · ଷ ݐ ݂

· ݅ݏ݌ 10.73 ሻ 68°ܴ ൅ 460°ܴ ሺ

· °ܴ

· ݈݋݈ܾ݉

ଷ ݈ܾ

ݐ ݂ ൌ 0.075 385.5

݈ܾ

ଷ ݐ ݂

ଷ ݈ܾ

ݐ ݂ ൌ 0.047 385.5

1 of 3ሶ ሶ ሶ ሶ

ሶ ሶ

ሶ ሶ Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 27 of 75



### APPENDIX 1.5

The density of the Vent Gas plus Center Steam ( ρ vg+s,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.

௦,௖௘௡௧ ൅ ݉ ௩௚ ݉

ൌ ௦,௖௘௡௧ ൅ ݉ ௩௚ ݉

ൌ ௩௚ା௦,௖௘௡௧ ߩ

௦,௖௘௡௧

௦,௖௘௡௧ ݉

ߩ ൅ ௚௩

௩௚ ݉

ߩ ௦,௖௘௡௧ ൅ ܳ ௩௚ ܳ Equation 6

Calculating Velocity

The velocity of the Vent Gas plus Center Steam ( v vg+s,cent ) is calculated by Equation 7.

௦,௖௘௡௧

௦,௖௘௡௧ ݉

ߩ ൅ ௚௩

௩௚ ݉

ߩ

A ௧௜௣ି௨௡௢௕ ௦,௖௘௡௧ ൅ ܳ ௩௚ ܳ

ൌ ௩௚ା௦,௖௘௡௧ ݒ ௧௜௣ି௨௡௢௕ ܣ ൌ Equation 7

The wind velocity is measured directly.

Constants:

݈ܾ 28.96൬ ݎ ܽ݅ ݐ݄݁݅݃ݓ݂ ݋ ݎ݈ܽݑ݈݁ܿ݋݉ ൌ ௔௜௥ ܹܯ ൰

݈݋݈ܾ݉ ݈ܾ 18.02൬ ݎ݁ݐܽݓ ݐ݄݁݅݃ݓ݂ ݋ ݑ݈݁ܿ݋݈݉ݎܽ ൌ ை మ ு ܹܯ ൰

݈݋݈ܾ݉

௜ ܹܯ

ሻ ݅ܽݏ݌.73 14 ሺ ݁ݎݑݏݏ݁ݎ݌ ݐ ܾܽ݉݅݁݊ ݁ݐݑ݈݋ݏܾܽ ൌ ܲ

ଷ ݈ܾ
݂ݐ ൰

ൌ 0.075 ଷ ݈ܾ
ݐ݂ ൬ ݅ܽݎ ݋݂ ݕݐ ݊݁ݏ݅ ݀ ൌ ௔௜௥ ߩ

ଷ ݈ܾ
݂ݐ ൰

ൌ 0.047 ଷ ݈ܾ
ݐ݂ ൬ ݁ܽ݉ݐ ܵ ݂݋݁ ܥݎ݁ݐ݊ ݀ݕݐ݅ݏ݁݊ ൌ ௧௖௘௡,௦ ߩ

ݐ ଷ ݈ܾ ൬ ݊݋݌݉݋݁ܿݐ ݅݊ ݐ݄݁݅݃ݓ݂ ݋ ݈݁ܿ݋݉ݎ݈ܽݑ ൌ ݋݈݈ܾ݉ ൰

݂

· ݅ݏ݌ 10.73ቆ

ݐܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ ቇ

ܴ °

· ݈݋݈ܾ݉

ܴ ° ൌ 528 ܴ ° ൅ ܴ 68 ° ൌ 460 ሻ ܴ ° ሺ ݁ݎݑݐܽݎ݁݌݁݉ݐ ݐݑ݈݋ݏܾ݁ܽ ൌ ௦௔௕ ܶ

2 of 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 28 of 75



### APPENDIX 1.5

Measured variables:

݈ܾ ൬ ݐ ܸ݁݊ݏܽܩ ݐ݄݁݅݃ݓ݂ ݋ ݑ݈݁ܿ݋݈݉ݎܽ ൌ ௚ ௩ ܹܯ ൰

݈݈ܾ݋݉ ݈ܾ ൬ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݏݏ݉ܽ ൌ ௧௖௘௡,௦ ݉ ሶ ൰

ݎ݄ ݈ܾ ൬ ݐ ܸ݁݊ݏܽܩ ݁ݐܽݎ݂ ݋ ݓ ݋݂݈ ݏݏ݉ܽ ൌ ௚ ௩ ݉ ሶ ൰

ݎ݄

ሻ ݂݄ܿݏ ሺ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥݎ ݁ݐܽݎ݂ ݋ ݓ ݋݂݈ ݑ݈݋݅ܿ݉ݎݐ݁ ൌ ݒ ௧௖௘௡,௦ ܳ

ሻ ݂݄ܿݏ ሺ ݐ ܸ݁݊ݏܽܩ ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݐ݉݁ݑ݈݋݅ܿݎ ൌ ݒ ௚௩ ܳ

ݐ݂ ൬ ݅݊݀ݓ ݂݋ ݕ ݐܿ݅݋݈݁ݒ ൌ ௔௜௥ ݒ ൰

ݎ݄

Calculated variables:

ሻ ଶ ݐ݂ ሺ ݁ݎ ݂݈ܽ݌݅ݐ ݁ܽݎ݂ ܽ݋ ݏ݋݅ݐ݈ܽ݊݁ܿ

െ ݏݏ݋ݎ ܿ ݐݏܾ݋݊ݑݎ݁ݐܿݑ݀ ൌ ௕௢௡௨ି௜௣௧ ܣ

ሻ ݊݅ݑݏݏ݈݁ݐ ሺ ݔݑ ݂݈݋݅ݐܽݎ ݉ݑݐ݉݁݊݋݉ ൌ ܴܨܯ

݈ܾ ൬ ݏܽܩ ݂݋ ݐܸ݁݊ ݕ ݀ݐ݅ݏ݁݊ ൌ ௚ ௩ ߩ ൰

ଷ ݐ݂

݈ܾ ൬ ݊݋݌݉݋ܿݐ݅݁݊ ݂݋ ݕݐ ݅݀ݏ݁݊ ൌ ൰

ଷ ݐ݂ ߩ ௜

ݐ݂ ൬ ݐ ܸ݁݊ݏܽܩ ݂݋ ܿ݋݈݁ݕݐ݅ ൌ ݒ ௚ ௩ ݒ ൰

ݎ݄ ݐ݂ ൬ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥݎ ݂݋ ݕ ݐܿ݅݋݈݁ݒ ൌ ௧௖௘௡,௦ ݒ ൰

ݎ݄

3 of 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 29 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.6

CALCULATING THE UNOBSTRUCTED CROSS

SECTIONAL AREA OF VARIOUS TYPES OF

FLARE TIPS

### APPENDIX 1.6 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 30 of 75



### Type II

Exit Lower

Steam/Air

Tubes

Pilot

Steam/Air

Tubes O.D. T

Stability Ring I.D. T I.D. T

A tip

- unob = (I.D. T ) 2 /4 – A ST – N T * *(O.D. T ) 2 /4 

## ~

Example: Where: A tip

- unob = Unobstructed Cross Sectional Area of Flare Tip

I.D. T = Inside Diameter Flare Tip

X T = Number of Stability Tabs

A ST = Area of a Stability Tab

I.D. T = 41.5 inches

X T = 3

A ST = 3 Sq. inches

A tip

- unob = (41.5) 2 /4

- (3 * 3) 

## ~ Example: Where: A tip

- unob = Unobstructed Cross Sectional Area of Flare Tip

I.D. T = Inside Diameter Flare Tip

A ST = Area of Stability Ring

O.D. T = Outside Diameter of

........... Steam/Air Tubes

N T = Number of Steam/Air Tubes

I.D. T = 47.5 inches

A ST = 100 Sq. inches

O.D. T = 6.5 inches

N T = 8

A tip

- unob = (47.5) 2 /4

- 100

- 8* *(6.5) 2 /4 

## ~ ~

A tip

- unob = 1322 Sq. inches A tip

- unob = 1344 Sq. inches 

### Type I

Pilot Stability Tab I.D. T I.D. T

A tip

- unob = (I.D. T ) 2 /4

- (X T *A ST ) 

## ~ ~

### APPENDIX 1.6 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 31 of 75

Example: Where:

Example: Where: A tip

- unob = Unobstructed Cross Sectional Area of Flare Tip

I.D. M = Inside Diameter of One Tip Module

N M = Number of Modules

X T = Number of Stability Tabs per Module

A ST = Area of a Stability Tab

I.D. M = 17 inches

N M = 6 X T = 3

A ST = 3 Sq. inches

A tip

- unob = 6 * ( *(17) 2 /4 – 3 * 3) 

## ~

A tip

- unob = 1308 Sq. inches A tip

- unob = Unobstructed Cross Sectional Area of Flare Tip

I.D. T = Inside Diameter of Flare Tip

I.D. T = 41.5 inches

A tip

- unob = (41.5) 2 /4

A tip

- unob = 1353 Sq. inches 

## ~ Type IV

I.D. T

I.D. T

Pilot

A tip

- unob = (I.D. T ) 2 /4 

## ~ Type III

Pilot I.D. M

A tip

- unob = N M * ( *(I.D. M ) 2 /4 – X T * A ST ) 

## ~ I.D. M Stability Tabs

ModulesCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 32 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.7

DEPICTION OF GASES ASSOCIATED WITH

STEAM-ASSISTED FLARESCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 33 of 75 

# DEPICTION OF GASES ASSOCIATED

WITH STEAM-ASSISTED FLARES

OPERATIONAL WASTE REGULATORY GASES GASES GASES AND STEAM

VOC-CREATING METHANE NON - SUPPLEMENTAL SWEEP PURGE PILOT STEAM ALL HYDROCARBONS AND HYDROCARBON OTHER GAS GAS GAS GAS (HCs) ETHANE HAPs

GASES THAT

MAY AFFECT

COMBUSTION

EFFICIENCY NON-HC,
NON-HAP,

CARBONS (eg, CO

2 , CO) ALL OTHER (Including Steam

(water) in the Waste Gas)

HYDROGEN (H

2 ) NITROGEN (N

2 ) 

## CONSENT DECREE

DEFINITIONS

WASTE GAS
“The mixture of all gases from facility operations that is directed to a flare for the purpose of disposing of the gases.”

However, if a facility has instrumentation capable of calculating the flow rate of H

2 , N
2 , O

2 , CO, CO

2 , and/or H

2 O in the Waste Gas, the contribution of all calculated flows of these elements/compounds may be excluded from Waste Gas flow rate calculations.


## VENT GAS
“The mixture of all gases found prior to the flare tip. This includes all Waste Gas, Supplemental Gas, Sweep Gas, and Purge Gas.”



# APPENDIX 1.7 COMBUSTION ZONE GAS
“The mixture of all gases and steam found just after the flare tip. This includes all Vent Gas, Pilot Gas,

and Total Steam.”Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 34 of 75

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.8

OUTLINE OF REQUIREMENTS FOR THE FLARE

DATA AND INITIAL MONITORING SYSTEMS

REPORTCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 35 of 75



### APPENDIX 1.8

OUTLINE OF REQUIREMENTS FOR THE

FLARE DATA AND INITIAL MONITORING SYSTEMS REPORT

1. Facility-Wide

1.1 Facility plot plan showing the location of each flare in relation to the general plant layout

2. General Description of Flare

2.1 Ground or elevated

2.2 Type of assist system

2.3 Simple or integrated ( e.g. , sequential, staged)

2.4 Date first installed

2.5 History of any physical changes to the Flare

2.6 Whether the Flare is a Temporary-Use Flare, and if so, the duration and time periods of use

2.7 Flare Gas Recovery System (“FGRS”), if any, and date first installed

3. Flare Components: Complete description of each major component of the Flare, except the Flare Gas Recovery System ( see Part 5), including but not limited to:

3.1 Flare stack (for elevated flares)

3.2 Flare tip

3.1.2.1 Date installed

3.1.2.2 Manufacturer

3.1.2.3 Tip Size

3.1.2.4 Tip Drawing

3.3 Knockout or surge drum(s) or pot(s), including dimensions and design capacities

3.4 Water seal(s), including dimensions and design parameters

3.5 Flare header(s)

3.6 Sweep Gas system

3.7 Purge gas system

3.8 Pilot gas system

3.9 Supplemental gas system

3.10 Assist system

3.11 Ignition system

4. Simplified process diagram(s) showing the configuration of the components listed in Paragraph 3

1 of 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 36 of 75



### APPENDIX 1.8

5. Existing Flare Gas Recovery System (“FGRS”)

5.1 Complete description of each major component, including but not limited to:

5.1.1 Compressor(s), including design capacities

5.1.2 Water seal(s), rupture disk, or similar device to divert the flow

5.2 Maximum actual past flow on an scfm basis and the annual average flow in scfm for the five years preceding Date of Lodging

5.3 Simplified schematic showing the FGRS

5.4 Process Flow Diagram that adds the FGRS to the PDF(s) in Part 4

6. Flare Design Parameters

6.1 Maximum Vent Gas Flow Rate and/or Mass Rate

6.2 Maximum Sweep Gas Flow Rate and/or Mass Rate

6.3 Maximum Purge Gas Flow and/or Mass Rate, if applicable

6.4 Maximum Pilot Gas Flow and/or Mass Rate

6.5 Maximum Supplemental Gas Flow Rate and/or Mass Rate

6.6 If steam-assisted, Minimum Total Steam Rate, including all available information

on how that Rate was derived

7. Gases Venting to Flare

7.1. Sweep Gas

7.1.1 Type of gas used

7.1.2 Actual set operating flow rate (in scfm)

7.1.3 Average lower heating value expected for each type of gas used

7.2 Purge Gas, if applicable

7.2.1 Type of gas used

7.2.2 Actual set operating flow rate (in scfm)

7.2.3 Average lower heating value expected for each type of gas used

7.3 Pilot Gas

7.3.1 Type of gas used

7.3.2 Actual set operating flow rate (in scfm)

7.3.3 Average lower heating value expected for each type of gas used

7.4 Supplemental Gas

7.4.1 Type of gas used

7.4.2 Average lower heating value expected for each type of gas used

7.5 Steam (if applicable)

7.5.1 Drawing showing points of introducti on of Lower, Center, Upper, and any

other steam

7.6 Simplified flow diagram that depicts the points of introduction of all gases, including Waste Gases, at the Flare (in this diagram, the detailed drawings of

7.5.1 may be simplified; in addition, detailed Waste Gas mapping is not required; a simple identification of the header(s) that carries(y) the Waste Gas to the Flare and show(s) its(their) location in relation to the location of the introduction of the other gases is all that is required)

2 of 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 37 of 75



### APPENDIX 1.8

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:

8.1.1 Waste Gas and/or Vent Gas flow monitoring

8.1.2 Waste Gas and/or Vent Gas heat content analyzer

81.3 Sweep Gas flow monitoring

8.1.4 Purge Gas flow monitoring

8.1.5 Supplemental Gas flow monitoring

8.1.6 Steam flow monitoring

8.1.7 Waste Gas or Vent Gas molecular weight analyzer

8.1.8 Gas Chromatograph

8.1.9 Sulfur analyzer(s)

8.1.10 Video camera

8.1.11 Thermocouple

8.2 Drawing(s) showing locations of all existing monitoring systems

9. Monitoring Equipment to be 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 MFR Requirements in the Consent Decree

11. Identification of Calibration Gases to be used to comply with Appendix 1.10

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## APPENDICES TO CONSENT DECREE



# APPENDIX 1.9

LIST OF COMPOUNDS A GAS

CHROMATOGRAPH MUST BE CAPABLE OF

SPECIATINGCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 39 of 75



### APPENDIX 1.9

LIST OF COMPOUNDS A GAS CHROMATOGRAPH

MUST BE CAPABLE OF SPECIATING

The Gas Chromatograph must be capable of speciating the Vent 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-butyl ene) and 2-methylpropene (aka: iso-butylene, iso-butene) (these two constituents will be measured on the same column and the reported result will be one value: the sum of the two constituents)

15. E-but-2-ene (aka: beta-b utylene, trans-butene)

16. Z-but-2-ene (aka: beta-b utylene, cis-butene)

17. 1,3 butadiene

18. Pentane plus (aka: C 5 plus) ( i.e. , all HCs with five Cs or more)

19. Hydrogen Sulfide

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.

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## APPENDICES TO CONSENT DECREE



# APPENDIX 1.10

EQUIPMENT AND INSTRUMENTATION TECHNICAL SPECIFICATIONS AND QUALITY ASSURANCE/QUALITY CONTROL REQUIREMENTSCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 41 of 75


### APPENDIX 1.10

EQUIPMENT AND INSTRUMENTATIO N TECHICAL SPECIFICATIONS

AND QUALITY ASSURANCE/QUAL ITY CONTROL REQUIREMENTS

I. VENT GAS FLOW METER

a. Velocity Range: 0.1–250 ft/sec

b. Repeatability: ± 1% of r eading over the velocity range

c. Design Accuracy: ± 5% initially to 40% , 60%, and 90% of monitor full scale as certified by the manufacturer

d. Operational Accuracy: ± 20% of readi ng over the velocity range of 0.1–1 ft/s and ± 5% of reading over the ve locity range of 1–250 ft/s

e. Installation: Applicable AGA, ANS I, 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.

h. Pressure and Temperature Sensors: See Part IV below.

II. VENT GAS AVERAGE MOLECULAR WEIGHT ANALYZER (may be part of the Vent Gas Flow Meter)

a. Molecular Weight Range and Accuracy:

i. Range: 0 to 60 gr/grmol

ii. Accuracy: ± 1.2 gr/grmol if a Vent Gas Flow Meter or BTU analyzer that monitors the flare is capable of continuously analyzing Molecular Weight; ± 3.0 gr/grmol if and only if: (i ) the Vent Gas Flow Meter that monitors the flare is not capab le of continuously analyzing Molecular Weight; (ii) there is no BTU Analyzer that monitors the flare or the BTU Analyzer is not capable of conti nuously analyzing Molecular Weight; and (iii) a Gas Chromatograph is used for the purpose of continuously analyzing Molecular Weight

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### APPENDIX 1.10

III. STEAM FLOW METER

a. Repeatability: ± 1% of reading over the range of the instrument

b. Accuracy: ± 1% full scale on a volumetric basis

± 2.5% full scale on a mass basis

c. Installation: Applicable AGA, ANS I, API, or equivalent standard

d. Flow Rate Determination: Must be co rrected to one atmosphere pressure and

68 °F

e. QA/QC: Annual calibration shall be conducted.

f. Pressure and Temperature Sensors: See Part IV below.

IV. VENT GAS AND STEAM FLOW METER S: PRESSURE AND TEMPERATURE

SENSORS

a. Temperature monitor must be calibrated annually to ± 5%.

b. Pressure monitor must be calib rated 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: ± 1.0% of full scale on a volumetric basis over the full range

c. The minimum sampling frequency sh all be one sample every 15 minutes.

d. The GC shall be capable of speci ating all gas constituents listed in Appendix 1.9.

e. The sampling system sample line shall be heat traced and maintained at no lower than 135 degrees Fahrenheit wi th no cold spots. The sampling cabinet shall be maintained at no lower than 125 degrees Fahrenheit. All system components shall be heated, including the probe external to the flare piping, calibration valve, samp le lines, sampling loop (or sample introduction system), and GC oven.

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### APPENDIX 1.10

f. Where technically feasible, the sa mpling location should be at least two equivalent duct diameters downstrea m from the nearest control device, point of pollutant generation, or othe r point at which a change in the pollutant concentration or emission ra te occurs. The location should not be close to air in-leakages. Where technically feasible , the location should also be at least 0.5 diameters upstream from the exhaust or control device.

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. Daily Validation Procedure . Instead of the daily mid-level validation procedure in Secti on 10.2 of PS9, a daily low-level validation procedure shall be conducted on the calculated Net Heating Value of a certified calibration gas mixture that is developed using the concentration of each analyte specified in Column 1 of Table 1 below. The average instrument response shall not vary by more than 10 pe rcent from the Net Heating Value of the certified calibration gas mixture.

b. Quarterly Validation Procedure . The multi-point calibration error check procedure in Section 10.1 of PS9 shall be conducted quarterly for the analytes listed in Subparagraph V.B.1.c below. No calibrations will be required afte r routine maintenance or repair

where such activities do not have th e potential to alter the sampling or analysis of the gas. The GC must meet the calibration performance criteria in Sections 13.1 and 13.2 of PS9 for the listed analytes, such that: (i) the aver age instrument response must not differ by more than 10 percent of each analyte calibration gas value; and (ii) the precision and linearity check of each analyte listed below shall not deviate by 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

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### APPENDIX 1.10

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

Low-Level

Gas (Col. 1) Quarterly

Low-Level Gas (Col. 2) Quarterly

Mid-Level

Gas (Col. 3) Quarterly High-Level Gas (Col. 4)

Hydrogen 8 8 30 12 Nitrogen 65 65 8 5

Methane 22 22 48 30

Ethane 2 2 3 30 Propane 1 1 2 15
Propylene 1 1 8 5 Ethylene 1 1 1 3 NHV (Btu/scf) Unadjusted for

H2 310 310 793 1273

(1) The individual analytes 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 300 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 Paragra phs 28 and 60.a for SDP’s Regular-Use Flares and for purposes of calculating th e 5% of instrument downtime allowed pursuant to Paragraphs 28 and 60.b for SDP’s Temporary-Use Flares, the time

used for GC calibration and validation activities required by Subparagraph V.B.1 of this Appendix may be excluded.

2. Any hour that meets the requirements of 40 C.F.R. § 60.13(h)(2) shall not be counted toward instrument downtime. Specifically:

(i) For a full operating hour (any clock hour where the flare is In Operation ( i.e. , Capable of Receiving Sweep, Supplemental, and/or Waste Gas) for 60 minutes), if there are at least four valid data points to calculate the

4 of 5Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 45 of 75


### APPENDIX 1.10

hourly average (that is, one data poin t in each of the 15-minute quadrants of the hour), then there is no period of instrument downtime;

(ii) For a partial operating hour (a ny clock hour where the flare is In Operation ( i.e. , Capable of Receiving Sweep, Supplemental, and/or Waste Gas) for less than 60 minutes), if ther e is at least one valid data point in each 15-minute quadrant of the hour in which the flare is In Operation ( i.e. , Capable of Receiving Sweep, Supplemental, and/or Waste Gas) to calculate the hourly average, then there is no period of instrument downtime; and

(iii) For any operating hour in which required maintenance or quality-assurance activities on the instruments or monitoring systems associated with the flare are performed:

(A) If the flare is In Operation ( i.e. , Capable of Receiving Sweep, Supplemental, and/or Waste Gas) in two or more quadrants of the

hour and if there are at least two valid data points separated by at

least 15 minutes to calculate the hourly average, then there is no period of instrument downtime; or

(B) If the flare is In Operation ( i.e. , Capable of Receiving Sweep, Supplemental, and/or Waste Gas) 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 pe riod of instrument downtime.

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.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.11

WASTE GAS MAPPING: LEVEL OF DETAIL

NEEDED TO SHOW MAIN HEADERS AND

PROCESS UNIT HEADERSCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 47 of 75



### APPENDIX 1.11

WASTE GAS MAPPING:
LEVEL OF DETAIL NEEDED TO SHOW MAIN 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 s ources under normal operations). This
Appendix outlines what needs to be included as the Wast e 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 def ined 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 consistent with t he 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 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 48 of 752 of 3Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 49 of 75Table 1: Example of Flare Source Description TableProcess UnitHeaderSourcesDetailed Source DescriptionQPH1(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 PumpQPH2(Ex: Gas Oil Treater)Continue same as PH1Continue same as PH1QPH3Continue same as PH1Continue same as PH1QPH4Continue same as PH1Continue same as PH1A-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 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 50 of 75

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v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.12

REPRESENTATIONS OF DISCONTINUOUS

WAKE DOMINATED FLOWCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 51 of 75



### APPENDIX 1.12

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 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 52 of 75



### APPENDIX 1.12FlareTip

Flare Tip

Images take from: Practical Implications of Prior Research on Today’s Outstanding Flare Emissions Questions and a Resear ch Program to Answer Them James Seebold, ChevronTexaco (Retired) Peter Gogolek, Natural Resources Canada John Pohl, Virginia Polytechnic Institute and State University Robert Schwartz, John Zink Company LLC

As a wake dominated flame becomes less stable, it becomes segmented, or discontinuous. The
following is a representation of “Discontinuous Wake Dominated Flow.” The red area is an

artist’s rendition of a flame.

2 of 4Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 53 of 75



### APPENDIX 1.12

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 pl ane of the exit of the flare tip and attached
to the tip. However, since the flame is not discontinuous, this imag e would not represent

Discontinuous Wake Dominated Flow.

3 of 4Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 54 of 75



### APPENDIX 1.12

In order for the flame to be deemed discont inuous, it should be segmented, and not merely
possess small pockets of flame at the outer bound ary of a single large cohesive flame.
Furthermore, a discontinuous flame will normally a ppear thin relative to its length, and lack a
single bulbous core. The following image represen ts a flame with a small pocket of flame only
at the outer edges of the broad main flame. Th is would not represent a discontinuous flame, and

therefore would not be Discontinuous Wake Dominated Flow.

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.



## APPENDICES TO CONSENT DECREE



# APPENDIX 1.13

CALCULATING THE AMOUNT OF STIPULATED

PENALTIES DUE FOR VIOLATING

LIMITATIONS OF FLARING WHEN THE

STIPULATED PENALTIES ARE BASED ON

EXCESS VOCS AND SO 2 

# EMITTEDCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 56 of 75



### APPENDIX 1.13

CALCULATING THE AMOUNT OF STIPULATED PENALTIES DUE

FOR VIOLATING LIMITATIONS ON FLARING

WHEN THE STIPULATED PENALTIES ARE BASED ON

EXCESS VOCs AND SO 2 EMITTED

I. Stipulated Penalties for Violatin g the 30-Day Rolling Average Limit

. The following

equation shall be used to calculate the amount of stipulated penalties due for violating the 30-day

rolling average limit on flaring:

n Penalty due = ∑ [$$ 30d,VOC x EE 30d,VOC ] + [$$ 30d,SO2 x EE 30d,SO2 ] (Eq. 1)

i=1

Where:

n = Each day the 30-day roll ing average limit is exceeded
$$ 30d,VOC = Dollars per ton of VO C for violating the 30-day limit ($300/ton because SDP Refinery is in an ozone nonattainment area)

EE 30d,VOC = 30-day average VOC emissions above the flow limit on day limit is violated; see Equation 3.a
$$ 30d,SO2 = Dollars per ton of SO 2 for violating 30-day limit ($100/ton)

EE 30d,SO2 = 30-day average SO 2 emissions above the flow limit on day limit is violated; see Equation 4.a

II. Stipulated Penalties for Violat ing the 365-day Rolling Average Limit . The following

equation shall be used to calcu late the amount of stipulated penalties due for violating the

365-day rolling average limit on flaring:

n Penalty due = ∑ [$$ 365d,VOC x EE 365d,VOC ] + [$$ 365d,SO2 x EE 365d,SO2 ] (Eq. 2)

i=1

Where:

n = Each day the 365-day rolling average limit is exceeded
$$ 365d,VOC = Dollars per ton of VOC for violating 365-day limit ($120/ton because SDP Refinery is in an ozone nonattainment area)

EE 365d,VOC = 365-day average VOC emissions above the flow limit on day limit is violated; see Equation 3.b
$$ 365d,SO2 = Dollars per ton of SO 2 for violating 30 day cap ($40/ton)

EE 365d,SO2 = 365-day average SO 2 emissions above the fl ow limit on day limit is violated; see Equation 4.b

1 of 4Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 57 of 75



### APPENDIX 1.13

III. Calculating Average Emissions of VOCs Above the Flow Limit When Violating the 30-Day and 365-Day Rolling Average Limit

A. Violating the 30-day rolling average limit

. The following equation shall be

used to calculate the 30-day av erage VOC emissions above the fl ow limit for the day that the

30-day rolling average limit is violated:

EE 30d,VOC = [Q 30d,actual – Q 30d,allowable ][VOC 30d,vol fraction ] [.0026] [MW 30d,VOC ] [.0005][1 - CE 30d,as

fraction ] (Eq. 3.a)

Where:

EE 30d,VOC = 30-day average VOC emissions above the flow limit on the day that the 30-day rolling average limit is violated, in tons per day

Q 30d,actual = Actual 30-day rolling average Waste Gas Flow Rate on the day that the 30-day rolling av erage limit is violated, in scfd

Q 30d,allowable = Allowable 30-day rolling average Waste Gas Flow Rate taken from the Consent Decree, in scfd

VOC 30d,vol fraction = 30-day flow weighted rolling average VOC volume fraction in the Waste Gas on the day that the 30-day rolling average limit is violated. [NOTE: This is the VOC fraction in the Waste Gas, not the Vent Gas.] The daily fl ow weighted average VOC volume

fraction shall be determined from an average of the hourly average VOC concentration weighted by waste gas flow. The 30-day flow weighted rolling average VOC volume fraction shall be determined from daily flow weighted CE and daily flow of waste gas.

.0026 = 1 lb-mole VOC/385.5 scf

MW 30d,VOC = 30-day flow weighted rolling av erage Molecular Weight of VOCs on the day that the 30-day rolli ng average limit is violated, in lb/lbmole. The daily flow weighted average molecular weight (MW)

shall be determined from an average of the hour ly average MW weighted by waste gas flow. The 30-day flow weighted rolling average MW shall be determined from daily flow weighted MW and daily flow of waste gas.

.0005 = 1 ton/2000 lb

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### APPENDIX 1.13

CE 30d,as fraction = 30-day rolling average Combustion Efficiency (“CE”) determined

from the NHV
cz of the Combustion Zone Gas as follows:

NHV
cz (BTU/scf) CE as fraction

NHV
cz < 95 0.0

95<= NHV

cz <300 [0.16*(-95+ NHV

cz )]/[1+0.16*(-95+ NHV

cz )]

300<= NHV

cz <350 0.98

350<= NHV

cz <425 0.985

425<= NHV

cz <500 0.9875

500<= NHV

cz <600 0.99

600<= NHV

cz 0.995

Combustion Efficiency shall be determined hourly from the hourly average NHV
cz using the table above. The daily flow weighted average CE shall be determined from an average of the hourly average CE values weighted by wa ste gas flow. The 30-day flow weighted rolling average CE shall be determined from daily flow weighted CE and daily flow of waste gas.

B. Violating the 365-day rolling average limit . To calculate the 365-day average

VOC emissions above the flow limit for the da y that the 365-day rolling average limit is

violated:

Substitute “365” everywhere “30” a ppears in Equation 3.a (Eq. 3.b)

[Appendix continued on next page]

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### APPENDIX 1.13

IV. Calculating the Average Emissions of SO 2 Above the Flow Limit when Violating the 30-Day and 365-Day Rolling Average Limit

A. Violating the 30-day rolling average limit

. The following equation shall be

used to calculate the 30-day average SO 2 emissions above the flow limit for the day that the

30-day rolling average limit is violated:

EE 30d,SO2 = [Q 30d,actual – Q 30d,allowable ] [C 30d,H2S /1,000,000] [8.30 x 10 -5 ] (Eq. 4.a)

Where:

EE 30d,SO2 = 30-day average SO 2 emissions above the flow limit on the day that the 30-day rolling average limit is violated, in tons per day

Q 30d,actual = Actual 30-day rolling average Waste Gas Flow Rate on the day that the 30-day rolling av erage limit is violated, in scfd

Q 30d,allowable = Allowable 30-day rolling average Waste Gas Flow Rate taken from the Consent Decree, in scfd

C 30d,H2S = 30-day rolling average concentration of H 2 S in Waste Gas on the day that the that the 30-day ro lling average limit is violated, in

ppmv

8.30 x 10 -5 = [1 lb-mole H 2 S/385.5 scf] [64 lb SO 2 /lb-mole H 2 S] [Ton/2000 lb]

B. Violating the 365-day rolling average limit . To calculate the 365-day average

emissions of SO 2 above the flow limit for the day the 365-day rolling average limit is violated:

Substitute “365” everywhere “30” a ppears in Equation 4.a (Eq. 4.b)

[End of Appendix]

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## APPENDICES TO CONSENT DECREE



# APPENDIX 1.14

EQUATIONS AND METHODOLOGY TO

CALCULATE REFINERY-SPECIFIC

COMPLEXITY AND INDUSTRY-AVERAGE

COMPLEXITY USING NELSON COMPLEXITY

INDEX

### APPENDIX 1.14

DETERMINING REFINERY- SPECIFIC AND INDUSTRY

- AVERAGE COMPLEXITY

THROUGH USE OF THE NELSON COMPLEXITY INDEX

DEFINITIONS:

"Applicable EIA Annual Refinery Publication" shall mean the Annual EIA Refinery Publication that was

the most recent one posted on EIA's website prior to a refinery's request for an increase in flaring caps.

"Applicable Form EIA -820" shall mean the Form EIA -820 that forms the source for the requesting

refinery's capacity information that is summarized and compiled in the Applicable Annual EIA Refinery

Publication.

For.example, if a Nefinery Nequests an increase in flaring caps in March of 201 S, the
"Applicable FoNm EIA -820, " is the FoNm EIA -820 that the Refinery submitted prior to
February 1 S, 2014, for its capacities as of January 1, 2014, (and not the Form EIA -820

that the Refinery submitted prior to FebNUary I5, 201 S, for its capacities as of January 1,

2015). This is because the Applicable EIA Annual Refinery Publication is the one published in June of 2014 (i. e., the last one published prior to March of 201 S).

"Applicable O &GJ Refining Survey" shall mean the survey that is published in December of the year prior to the year of the Applicable EIA Annual Refinery Publication.

For example, if the Applicable EIA Annual Refinery Publication is the one published in

June of 2014, then the Applicable O &GJRefinery Survey is the one published in Decefnber

of 2013 foN capacities as of January 1, 2014.

"EIA" shall mean the United States Energy Information Agency.

"EIA Annual Publication of the Number and Capacity of Petroleum Refineries" or "EIA Annual Refinery

Publication" shall mean the information posted on EIA's website on approximately June 21 of each year

that compiles and summarizes the data submitted on the Form EIA -820s that each refinery submits prior

to February 15 of that year. As of Apri12013, the most recent Annual EIA Refinery Publication (i.e.,the

one from June of 2012) is found at http: / /www.eia.gov /dnav /pet /pet~np capl dcu nus a.htm. A
printout of this publication is Attachment 1 to this Appendix 1.14.

"Form EIA -820" shall mean the annual report that each refinery is required to submit to the EIA prior to
February 15 of each year. The "Report Year" of a Form EIA -820 refers to the capacities that exist as of

January 1 of the "Report Year." A copy of a typical Form EIA -820 is Attachment 2 to this Appendix 1.14.

"Oil &Gas Journal Worldwide Refining Survey" or "O &GJ Refining Survey" shall mean the survey that

the Oil &Gas Journal publishes in December of each year that lists refining capacities as of January 1 of

the following year. A copy of the national refining capacities listed in the December 5, 2011 O &GJ
Refining Survey for January 1, 2012 is Attachment 3 to this Appendix 1.14. The relevant United States
capacities are highlighted in yellow on the third page of Attachment 3.

1 of 4 (excluding Attachments) Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 61 of 75

### APPENDIX 1.14

REFINERY COMPLEXITY. The complexity of the Refinery is to be calculated using the following

formula:

Equation 1

Complexity = ~ NCI= x CAP

n_, CAP~,st

Where:

NCI; = The 2011 Nelson Complexity Index Coefficient shown in Table 1 below for Process

Unit i

The throughput capacity for the Refinery's Process Unit i, in barrels per calendar day,

which shall be determined as follows:

(a) for a Process Unit that is not new or modified and for which the Applicable EIA

Annual Refinery Publication lists total US throughput for that process, the capacity, in

barrels per calendar day, that the Refinery reported for Procession Part 6~1 of the
Applicable Form EIA -820. If the Refinery did not report the capacity of Process i in

"barrels per calendar day," but instead reported it in "barrels per stream day," then

"barrels per stream day" will be converted to "barrels per calendar day" by multiplying

"barrels per stream day" by the following factors: 0.95 for a vacuum distillation unit

CAP; = and 0.9 for all other units; or

(b) for a process unit that is not new or modified, if and only if the Applicable EIA

Annual Refinery Publication does not list total US throughput capacity for that

process unit, then the Refinery's capacity for that process unit, in barrels per calendar

day, listed in the Applicable O &GJ Refining Survey.

(c) for a Process Unit that is new or modified, where the new or modified capacity was

not reported on the Applicable Form EIA -820, the'projected new or modified unit

capacity that is set forth in the air permit applications) for the post

- Lodging

modification.

The Refinery's Atmospheric Crude Oil Distillation Capacity, in barrels per calendar

day, which shall be determined as follows:

(a) if the post

- Lodging modification does not affect the crude capacity, the

CAPDIST = Atmospheric Crude Oil Distillation Capacity, in barrels per calendar day, that the
Refinery reported under Total Operable capacity on Part 5, Code 401 - of the
Applicable Form EIA -820; or

(b) if the post

- Lodging modification does affect crude capacity, the projected, new capacity set forth in the air permit applications) for the post

- Lodging modification.

~1 The references to particular "Parts" or "Codes" of Form EIA -820 are to the Parts and Codes as they exist for the

Form EIA -820 that was used for Report Year 2012. See Attachment 2. To that extent that the "Parts" or "Codes"

on Form EIA -820 are changed in the future, the intent of the Parties is that the "Parts" and "Codes" of future forms

that correspond most closely to those found on the Form EIA -820 for Report Year 2012 will be used.

2 of 4 (excluding Attachments) Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 62 of 75

### APPENDIX 1.14

INDUSTRY AVERAGE COMPLEXITY: The Industry Average Complexity is to be calculated using

the following formula:

Equation 2

Industry_Average_Complexity = ~ NCI! x ICAP

n -1 ICAPD,St

Where:

NCI; = The 2011 Nelson Complexity Index Coefficient shown in Table 1 below for Process

Unit i

Total US throughput capacity, in barrels per calendar day, for Process Unit i which

shall be determined as follows:

(a) from the Applicable EIA Annual Refinery Publication, the total US capacity of

Process Unit i in barrels per calendar day. For the total US capacity of those process

units that the EIA lists only in "barrels per stream day" and not in "barrels per calendar

day," the "barrels per stream day" shall be converted to "barrels per calendar day" by

ICAP; = multiplying "barrels per stream day" by the following factors: 0.95 for a vacuum

distillation unit and 0.9 for all other units.~2

(b) if and only if the Applicable EIA Annual Refinery Publication does not list a total

US throughput capacity for a process unit that the Refinery operates, then the total US

throughput capacity for that process unit listed in the Applicable O &GJ Refining

Survey.

From the Applicable EIA Annual Refinery Publication, the total "Operable" US ICAPDIST = Atmospheric Crude Oil Distillation Capacity, in barrels per calendar day.3

~2 For example, for catalytic reforming, the total US capacity as of January 1, 2012, is 3,246,874 barrels per

calendar day. See Attachment 1 at page 2 (green highlight). Note that the capacity for catalytic reforming on

page 1 of Attachment 1 should not be used because that is listed in "barrels per stream day," not bpcd. For vacuum distillation, the total US capacity for 2012 is 8,679,643 barrels per stream day. See id. at page 1 (orange highlight).

This figure would be converted to 8,245,660 barrels per calendar day (8,679,643 x .95).

~3 Total Operable US Atmospheric Crude Oil Distillation Capacity (total ICAPDIST) of a January 1, 2012, is

17,322,178 barrels per calendar day. See Attachment 1 at page 1 (yellow highlight).

3 of 4 (excluding Attachments) Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 63 of 75

### APPENDIX 1.14

Table 1: 201.1 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
Polymerization 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

of 4 (excluding Attachments) Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 64 of 75

# APPENDIX 1.14

ATTACHMENT 1 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 65 of 75U.S. Number and Capacity of Petroleum Refineries



# eiaU S. Energy Information
Administration



### PETROLEUM &OTHER LIQUIDS Page 1 of 2

OVERVIEW DATA ANALYSIS &PROJECTIONS GLOSSARY> FAQS>

Number and Capacity of Petroleum Refineries

Area: U.S. ~ Perfod: Annual (as of January 1)

Show ~a[a By: GraOh

~ Data Sena (~ Area ~ Gear 2007 2008 2009 2010 2011 View

2012 History

!~~~tf.~F»t11b1~ R}flSle[iea

Total Number of Operable
R~neries ~_! 149 150 150 148 148 144 ~ -2ot2

Operating

... 145 148 141 137 137 134 1982 -2012

Idle 4 4 9 11 11 10 ~982"20~2

~.,. „~jC

Operable (Barrels per Calendar Day) ....: 17,443,492 17,593,847 17,671,550 17,583,790 17,736,370 17,322,178 1982.2012

Operating 16,997.792 17,225,797 17,313,550 16,850,194 16,937,024 16,744,291 te82 -2012

Idle i.: 445,700 368,050 358,000 733,596 799,346 577,887 1982 -2012

Operable (Barrels per Stream Day)

~

.. ~.. _~__ ~g,gz5,322 18,558,022 18,661,308 18,581,089 18,953,189 18,560,350 1982 -2012

Operating i 17.926.522 18.174,072 18.300.358 17,808,082 18.109,882 17,945,443 1982 -2012

~~e ~ 496,800 383,950 360,950 773,007 843,307 614,907 198 - 1

i a

~ ~ Vacuum Distlllaiion 8,251,451

.. 8,420,501 8,542,287 8,542,643 8,650,243 ~675i;813; 7,582"2012

Thermal Cracking 2,564,080 2,606,260 2,639,090 2,631,676 2,672,376 2,763,356 1 ~2

Total Coking 2,537,480 2,579,660 2,612,490 2,605,076 2,645,776 2,736,756 ~987.20i2

Delayed Coking 2,331,580 2,374,280 2,454,590 2,500,676 2,486,876 2,577,856 ~ s9 7 -202

Fluid Coking 205,900 205,400 157,900 104,400 158,900 158,900 1 89 7.2072

Visbreaking 16,000 16,000 16,000 16,000 16,000 16,000 X987 -2012

Other (Including Gas Oil) 10,600 10,800 10,600 10,600 10,600 10,600 1987 -2012

Catalytic Cracking -Fresh Feed 6,216,957 6,265,697 6.291,871 6,140,121 6,219,721 6,032,512 1982 -212

Catalytic Cracking

- Recycle Feed

~ 82,040 78,740 78,740 91,840 95,640 84,880 19 2- 1

Catalytic Hydro- Cracking 1,790,682 1,770,325 7,743,300 1,819,700 1,855,600 1,879,600 1982 -20t2

Distillate 602,800 558,900 593,100 585.200 540,100 596,500 02 04 -2012

Gas Oil gg7,482 1,004,425 1,010,200 1,079,500 1,170,500 1,161,100 2oD4.2o72

Residual 200,400 209,000 140,000 145,000 145,000 122,000 2D04 -202

CatalyficReforming 3,907,510 3,891,938 3,829,338 3.700,483 3,720,613 3,641,813 1982 -202

Low Pressure

~ 2,354,950 2.402,350 2,397,750 2,322,700 2,390,950 2,347,650 1987 -202

High Pressure '~ 1,552,560 1,489,588 1,431,588 1,377,763 1,329,863 1,293,963 1987.2012

Catalytic Hydrotrealing/DesulTurization 15,447,136 15,807,476 16,130,823 16,023,206 16,682,897 18,565,262 1982 -2012

NaphthalReformerFeed 4,453,890 4.348,590 4,334,297 3,281,046 4,441,323 4,360,593 19872012

Gasoline 2,221,568 2,420,968 2,415,282 2,394,882 2,578,782 2,519,082 2004"2012

Heavy Gas Oil

~ 2,578,840 2,672.440 2.735,538 2.796,798 2.809.298 2.877,138 X987.2012

Distillate Fuel Oil 5,212,387 5,462,649 5,622,252 5,676,032 6.113,846 6,063,001 j~97.20~2

Kerosene /Jet Fuel 1,009,450 1,137,010 1,160,110 1,339,150 1,484,850 1,489,750 X0042012

Diesel Fuel 3,332,671 3,468,471 3,551,211 3,647,211 3,917,611 3,981,411 20082012

OEher Distillate I 870,266 857,166 910,931 689,671 771,385 591,840 ZOW.2012

Residual Fuel Oil /Other 980,451 902,831 1,023,454 874,448 739,648 745,446 1987.2012

Residual Fuel Oil 331,420 251,200 316,400 246,200 241,000 246,000 20 - 1

Other 649,031 651,631 707,054 628,248 498,648 499,448 2004"202

http:// www. eia. gov/ dnav /pet/pet~np_capl_dcu_nus_a.htm 4/25/2013 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 66 of 75U.S. Number and Capacity of Petroleum Refineries

Fuels Solvent Deasphalting I ~`

e ~ ~ ~ _. ~ a

Catalytic Reforming (' °,

Total Colang

Catalytic Cracking -Fresh Feed i ',

Catalytic Hydro- Cradclnp i i_ 379,290 378,3501 380,950 383,250 382.750' 374.650] - 12

3,378,841 3,346,457 3,246,874;20~0.20~2

2,359.3181 2,390.223, 2,428,9811 2.387,898 2.396.787 2,499,293~1s87.2612

5,830,486 5,853,656 5,847,130 5,675,830 5,794,214 5,611,191' 1887.2012

1,620,705 1,602,431 1,592,973 '1,663,115 1,687.745 1,706,540 1987.2012

-= No Data RepoAed;

- - =Not Applicable; NA =Not Available; W = Nhthheld to avoid disclosure of ind~vitlual company data.

NoMS: Idle rcfinaries represent refineries where distillation units were completely idle but not permanently shutdovm as of January 1 of the year. See Dafinifions, Sources, and Notea Iink above for more information on this table.

Release Date: 8/22/2012 Ne# RBlease Date: 6/2120 3

http:// www. eia .gov /dnav /pet/pet~np_capl_dcu nus_a.htm Page 2 of 2

4/25/2013 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 67 of 75

# APPENDIX 1.14

ATTACHMENT 2 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 68 of 75~_A.

U.S. Energy Information 

# e 1

a Administrarion OMB No. 1905 -0165
Expiration Date: 1/31/2013

Version No.:2010.02

FORM EIA -820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

--
report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93 -275). Fa +lure to comply may result in criminal fines, civil penalties and

sanctions as provided by law. For further information concerning sanctions and data protections see the provision on sanctions and the provision concerning the

dentiality of information in the instructions. Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly makes to any Agency or

irtment of Ute United States any false, fictitious, or fraudulent statements as to any matter within its jurisdiction.

;T 1. RESPONDENT IDENTIFICATION DATA PART 2. 3UBMISSIONlRESUBMlSSION INFORMATION

ID NUMBER: r 133957010

If any Respondent Identification Data has changed since the last report,

enter an "X" in the box:

Company Name: Shell Oil Co.

Doing Business As:

Name: DEER PAi2K REFG LTD PTNRSHP

Final Control Number (TCN):

iysical Address (e.g., Street Address, Building Number, Floor, Suite):

HWY 225

City DEER PARK State: TX Z~p~ 77536 - 0100

Mailing Address of Contact (e.g., PO Box, RR): If the physical and
mailing addresses are the same, only complete the physical address.

P.O. BOX 100

City DEER PARK State: TX Z~P~ 77535 - 0100

Contact Name:

Phone No.: ~ Ext:
~

- .._. Fax No.: ~

__ Email address: If this is a resubmission, enter an "X" in the box:

A completed form must be received by February 15th of the
designated report year.

Forms may be submitted using one of the following methods:

Email: 00 U~YS~eia.gov

Fax: (202}586 -1076

Secure File Transfer:

httos: /lsiq non. eia. doe.govlu ploa dJn oticeooa.is a

Questions? Cail: 202- 386 -6281

~S: Explain any unusual or substantially different aspects of your current year's operations that affect the data reported. For example, note new ig units, major modifications or retirement of processing unib, sale of refinery, etc. (To separate one comment from another, press ALT +ENTER) Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 69 of 75.:..,,:.:, ,; _; :..~ :,:,: OMB No. 1905 -0165

~' l U.S. Energy Information Expiration Date: 1/31/2013 

# ela

Administration Version No.:2010.02 

### Fo~nn Eia -sza

ANNUAL REFINERY REPORT

REPORT YEAR 2012

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 3. FUEL. ELECTRICI'T'Y. AND STEAM PURC1iASED &CONSUMED AT THE REFINERY DURING 2Q11

PART 5. ATMOSPHERIC CRUDE OIL DISTILLATION CAPACITY AS O~ JANUARY 1

Atmos heric Crude OiP Distillation Capacity Code Barrel per Calendar Day2 Barrels er Stream Da

2012: O eratin 399 327000 327000

Idle 400 0 0

Total O erable 401 327000 327000

2013: O erable 50~ 327000

Z Barrels per Calendar Day Operating, Idle and Total Operable Capacity (Codes 399, 400 and 401) must match the comparable capacity numbers reported on the Form

EIA

-810, "Monthly Refinery Report," filed for January 2012. Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 70 of 75,,, ;

, , ,, ,,,,, ,~ ~..:,,

.. OMB No. 1905 -016

U.S. Energy Information Expiration Date: 1/31/201

~1~ Administration Version No.:2010.02

FORM EIA -820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 6. DOWNSTREAM CHARGE CAPACITY AS OF JANUARY 1

Downstream Charge Capacity Code 2012

Barrels per

Calendar Day 2012

Barrels per

Stream Day 2013

Barrels per

Stream Day

Vacuum Distillation 402 180000 180000

Thermal Cracking:

Visbreaking 403

~ 0

Fluid Coking (incl. Flexicokin) 404 0 0 0

Dela ed Coking 405 83600 89300 89000

Other incl. Gas Oil) 406

~ 0

CatalyticCrackin .~ ,

-~~ ~~ ° 'r

Fresh Feed 407 63600 70000 70000

Rec cied 408 5000 5000

Catal tic Hydrocracking: .,'~ ~~~~ ~ '`

Distillate 439 0 0 0

Gas Oil 440 55000 60000 60000

Residual 441 0 0 p

Desulfurization (including Catalytic Hydrotreating): x ~ ' >:,~ ~ ~° ~;s

Na htha /Reformer Feed 426 75000 75000

Gasoline 420 42000 42000

Kerosene and Jet 421 40000 40000

Diesel Fuel 422

~ 0

Other Distillate 423 45000 45000

Residual 424 49500 49500

Heavy Gas Oil 413 80000 86000

Other 425 43fl00 43000

Catal tic Reformin

Low Pressure 430 42900 45000 45000

High Pressure 431 22700 24500 24500

Fuels Solvent Deas haltin 432

PART 7. PRODUCTION CAPACITY AS OF JANUARY 1 Barrels er Stream Da

, Exce t Where Noted

Production Ca aci Code 2012 2013

Aik lates 415 18500 18500

Aromatics 437 0 0

As halt and Road Oil 931 o ~

Isobutane C4 644 o ~

Iso entane C5

, Isohexane C6 438

~ 0

Isooctane C8) 635

~ 0

Lubricants 854 0 0

Petroleum Coke

- Marketable 027 38701 38701

H dro en million cubic ft. er da) 091 ~ ~8 100

Sulfur short tons er da J 435 1085 1085 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 71 of 75

# APPENDIX 1.14

ATTACHMENT 3 Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 72 of 752011WorldwideRefiningSurveYLeenaKoottungalSurveyEditor/r1►ewsWriterAllfiguresareA!Ifiguresinbarrelspercalendarday{blcd}asofJanuary1,2012LEGENDNumbersidenfrfyprocessesinta61eCokingCatalyticreformingCatalytichydrotreatingAblationIsomerizationHydrogen1.Fluid_coking1.Semiregenerative1.Pretreatmentofcatreformerfeeds1,ulfuricacid1.C4feedProduction:2.Delayedcoking2.Cyclic~2.Ofhernaphthadesulfurization~2.Hydrofluoricacid2.C5feed1.Steammethanereforming3.Other3.Continuousregen.3.Naphthaaromaticssaturation3.C5andCgfeed2.Steamnaphthareforming4.Other4.Kerosine/jetdesuffurizationPolymerization/Qimerization3.PartialoxidationThermalprocess5.Dieseldesulfurizationi.PolymerizationOxygenatesa.Third-partyplant1.ThermalcrackingCatalytichydrocrackin`6.Distillatearomaticssaturation2.Dimerization1.MTBERecovery:2.Visbreaking1.Distillateupgrading7.Otherdistillates2.ETBE4.Pressureswingadsorption2.Residualupgrading8.PretreatmentofcatcrackerfeedsAromatics3.TAME5.CryogenicCatalypccracking3.Lubeoilmanufacturing9.Otherheavygasoilhydrotreating1.BTX4.Other6.Membrane1,Fluid4.Other10.Residhydrotreating2.Hydrodeal.kylation7.Other2.Otherc.Conventional(highpressure)11.Lubeoilpolishing3.Cyclohexanehydrocracking:(>lOdbargor12.PosthydrotreatingofFCCnaphtha4.Cumene1,450psig)13.Otherm.Mildtomoderatehydrocracking(<I00hargor1,450psig)NOTESANewIPrevioustylistedasSKCorp.QPlanstosellBPrevio~GsleAasCUevronCmp.JPrevioustylistedasHyundaiOilReliperyCaRPreviouslylistedasSunocoInc.CPrerioast~k~e9asSheNU.K.Ltd.KPrevioustylistedasNollyCorp.SPlanstoconverttoastorage(aciiryDPrevroaarylistedasA6ERefleia~&ManuFaduringLNewtosurveyTFarsaleEPrtviousylistsasNmrplry0~USAIne.MShutdownUPreviouslylistedasValeraEnergyCorp.FNaycanroRiMoakeiinponternioalNPreuioustylistedasFrontierOilCap.UPtevinusiylistedasMaraihanPetroleumCo.LP6Idled0PreviouslylistsasFrontierRefiningIne.WPreviouslylistedasShelloeutsch4andOilGMBHHkeriasly(sledxDilRefiietksltd.PPreviouslylistedasCanocoPhillipsCapacitqidinition~Hydro;en:Catalyticreforming:Capacityexpressedinbarrelspercalendarday(b/ed)isthemaximum1.Semiregenerativereformingischaracterizedbyshutdownofthenumberofbarrelsofinputthatcanbeprocessedduringa24-hourperiod,Hydrogenvolumespresentedhererepresenteithergenerationorreformingunitatspecifiedintervals,orattheoperators'sconvenience,aftermakingalbwancesforthefallowing(a)Typesandgradesofinputsupgradingto90+%purity.forinsitucat2lystregeneration.tobeprocessed,(b}Typesandgradesofproductstobemanufactured,(c)2.CyclicregenerationreformingischaracterizedbycontinuousaconEnvironmentalconstraintsassociatedwithrefineryoperations,(d)Schedutedtinualregenerationofcatalystinsituinanyoneofseveralreactorsdowntimesuchasmechanicalproblems,repairs,andslowdown.Capacitythatcanbeisolatedfromandreturnedtothereformingoperation.expressedinbarrelsperstreamday(b/sd)istheamountaunitcanprocessThisfsaccomplishedwithoutchangingfeedrateoroctane.whenrunningatfullcapacityunderoptimalfeedstockandproductslate3.Continuousregenerationre#ormingischaracterizedbythecontinuousconditions.Anasterisk(*)besidearefineryLocationindicatesthatthenumberadditionofthisregeneratedcatalysttothereactor.hasbeenconvertedfromblsdtob/cdusingtheconversionfactor0.95for4."Other"includesnonregenerativereforming(catalystisreplacedbyOcrudeandvacuumdistillationunitsand0.9foralldownstreamcrackingandfreshcata{yst)andmoving-bedcatalystsystems.conversionunits.moREFINERYREMQVALScwNameLocationCnu~rCrudeWcdReason~WesternR~ioingYorldown,VirginiaUS70,000Shutdownc~~uSurromk~c.WaNille,NJUS150,000ShutdownAbnUSABakersfield,Calif.US70,000IntegratedwAhParamountrefinerycnNdlyCap.Tufsa,Okla.US85,OIX1Integratedw~hotherTulsarefineryTotalSADunkirkFraixe137,028ShutdownPak-ArabReficeryCo.MahmoodKot,P~jabPakistan1(p,000Shutdown~..PeUoplusHaldmgsAGCressierSxitrerlarrd60,000ShutdormCase 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 73 of 750WorldwideRefineries-CapacitiesasofJan.1,2012~yNo.oCuuMryofrefineriesRudeYacuumdistillationEotiaaThermaloperationsChargecapacity,McdCatalyticCatalyticcracFingreformingCatalytichydroeracNing----CatalytichydrotreatingAlkylatinnPoIJIYim.AromaticsIsomerizationProductioncapac'~ry,NcdlobesOxygenatesNydtoyen(MACid)CokeSWfur(iannesperday)AsphaRc~Albania.............226,30010,50012,000--3,500-17,400600-700-6.570060-vAlgeria.............4450,000IQ,894-- -88,900"-81,950-- - -- - -- - -~M~la.............139,0002,500- - -1,900-6,600- -- --- ---950~Argentina...........10630,575248,36591,23338,420141,1805fi,630I7,~00175,5004,300520-12,7007,2902,60019.03,81010612,700~Aruba..............1235,000166,25068,40Q30,600---214,200- --- - -93.04,500810-~Australia.,..........7760,148192,865--235,043172,05318,407543,53124,73410,6091,00039,606- -72.3-14410,017~Austria.............1208,60065,W0-16,87526,25632,725-134,400- - -14,4Q0-t,600--18(!1,470pAzerbaijan..:.......:2398,4781'37,20038,529-57,75024,466-b7,492930- --16,206--1,400-5,000~Bahrain.,.,,.,,....1253,650198,170-21,60035,10013,50054,00076,5Q0-3,330- - --164.0-3408,730Bar~ladesh..........133,0004,000-10,000-1,8W1,2002,000---- --2.0-- -Belann.............2493,323105,806-60,00044,00092,00030,000262,100--2,7854,5003,760-22.8-859,fi30Belgium............4739,821250,630-30,016133,553105,589-687,75517,630--0-3,76498.5097126,500Bolivia.............241,2002,200- --12,100-6,899- -----14.0- - -Bruil..............131,917,333810,140115,3199,800505,28724,386-284,4466,290-- -20,0096,460126.06,47477127,100Brurrei.............18,600-- - -5,700--- - - -- -- - - -8ulgaria,...........1115,24049,900-2Q,60023,3004,060-64,2002,600-2,000--79010.3-631,500Cameroon...........137,000-- --6,500-16,140-- - - - ---- -Canada.............171,91$,455645,05659,100121,430482,468354,930210,3741,383,53670,40319,24062,68962,4903,000-461.02,6352,17466,OIX1Chile..............3226,80085,05013,86013,86050,54026,46050,400-910--8,51Q-1,580-6569Q-China..............546,856,000240,000156,0-588,OW178,000185,(H10541,00015,500-21,000-18,0009~-4,0201,362-China,Tanran........41,310,002A8,50651,~o-217,900115,IX1025,0[10672,50014,200-14,00025,00015,30011,266341.04,5223,74515,270Cobmhia...........5240,850141,006-52,00090,OW--19,8002,100 2,1002,200-1,400-18.0---Cor~o(BrazuvilW....121,0008,066---2,IX102,0003,500- --- -- - ---CostaRica......,...124,000600-6,500-1,200-2,000- --- ---- --Craatia.............3250,31787,0405,00023,52651,00249,36812,26468,256--9,4385,431470--200]23-Cuba..............4301,40475,700- -14,7D020,000-55,850- --- - -5.0- -1,080CzechRepublic.......3183,00078,870-17,000-27,47034,430103,180--fi607,2102,180 2,160112.0-14410,880Denmark...........:2174,40022,000-64,55Q-21,990-42,760---6,400- -- --8,000DaninicanRepudic...250,000-- - -8,200-20,913--- - --0.6- ---Ecuador............3176,00045,300-31,50018,0012,800-24,500----- -----Egypt..............9726,25095,2f1034,276- -62,24033,506207,8029,000-1,58414,7004,441-62.5I,b012904,623EiSaivada......,...122,0004,OW---3,000-15,500--- -------Eritrea.............11A,5642,219- --1.465-2,742- ---------Finiand.............2260,57514b,085-34,42056,69050,06090,110298,3257,750640--5,2805,73D160.0-5406,8WFrance.............121,718,803715,200-146,872347,052256,66911,8451,233,04$26,7Q22,9682,88748,49236,3904,711132.fl-1,38343,502Gabon.............124,(100- -9,220-1,400-9,430Germany............152,417,1621,496,231105,809247,445349,171404,8222Q3,4672,011,78230,8858,30171,94444,22614,22013,172772.03,8132,91460,630Ghana.............145,000- --14,00065,000--- - - - ------Greece.............4423,000152,000-49,00075,55049,20043,900361,6352,4001,7209,10023,6503,5003,94023.5-519ifi,950Hungary............11fi1,00077,5016,90014,0024,6029,66-120,7003,300-12,0003,50fi,1001,20076.2600226b,300India..............214,042,761811,986169,62543,180531,30551,673165,6fl~250,74285,000-9,742-6,2401,396]32.96,48045237,768Inda~sia...........S1,011,825265,98032,58058,9fi0101,45092,97099,72023,43016,200- --- -----Iran...............91,451,000559,400-290,80035,000164,7W136,500 183,160- - --19,60Q-286.0-47036,5WIraq...............9637,500145,000---88,00074,241292,000---2.5009,420-64.0- -38,738Ireland.............171,006-- --11,E-44,600-- -7,600--10.3-4-lsrael..............2220,000(18,000-66,00044,526,5-96,000-2,20---750- --2,700Ita{y...............172,337,229&14,23745,OIX}448,204 321,500287,06930.3,2101,250,75340,33Q1,50013,400112,26024,00011,720305.42,0461,77b15,706lvayCwst..........163,99023,990---12,330 14,48027,310-- -------4,330Jamaica............136,OOD1,800- --3,700-23,800- --------$50Japan..............3D4,729,8901,764,195I23,40(f20,00098fi,980829,225181,6905,416,16074,6905,760207,46731,35038,0132,9781,459.41,8639,544&4,370Jordan.............190,40021,500--4,00010,95,22017,300-- ----16.0--4,250Kankhstan..........3345,093121,03724,49752,07138,35651,586-ll7,890- -----21.51,0001248,550Kenya..............190,0001,700-- -8,260-36,000- -- - -- ---1~~Kuttait.............3936,000327,75072,000-36,00046,624115,650588,7805,61fi----6,561741.62,8004,200-Kyrgyntan..........110,000- - -- --- -Li6~ia.............115,0001,000---2,000-3,300- ----- ---2D0Libya..............5378,0003,775---20,250-A3,330- ---635- ---3.432Lithuania...........~1190,00089,300-28,80043,200 45,A00-153,400--7,200-I8,900-2,7IXI25.0-320-Macedonia..........150,000-- --10,860-22.050- --4,390- --- --Malaysia...........,7538,58294,33524,040-42,70075,07036,000216,800---14,8U~--147.22,245d6024,700Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 74 of 750y0aOnO~~..WorldwideRefineries--CapacitiesasofJan.1,2012~pp~~ry,h~~dProdectiancapacity,WcdNo.ofYacwinTlcermalCatalyticCatatydcCata{ylic CatalyticHydrogenCokeBallotCountryrofineriaGededisGllaliaiCoYin~oQerationscrackingrelominghytlroerackinghydmtreatingAlkyla6anPoIJDim.AramaGcsIsomerizMionLuhesOrygenates(MAAcfd)(ronnesperday)ilsphaltMartinique..........117,329- - --?,gSZ-14,269-Mexico. ............61,540,000754,W0191,000-380,5U0279,300-926,054128,456Morocco............2154,90124,921--5,04024,359-35,534-Myanmar...........357,6004,0005,200-- -- - -Netherlaads.........61,196,571711,09541,50091,4Q4101,983148,616198,0711,016,23415,450NetherlandsMtitles..,1320,000195,000-80,00050,Ood20,000-119,5IXt4,W0NewZealand.........1107,OOq38,270---25,84930,000.104,490-Nicardgua...,.,',....120,0001,500--=3,000-14,506-Nigeria.............4445,000124,490- -82,74070,070-109,2319,870NorthKaea.........271,000-- --7,300-7,400-Nanvay.............2319,W0-24,78D32,00049,00034,900-126,000-Oman..............185,000- -- -16,000-21,000-Pakistan............6186,30619,815-- -11,650-54,870-PapuaNewGuinea....132,500- -- -- - - -Paraguay............17,500- --- -- --Peru...............6198,95094,00-25,70033,5002,100-2,8~-Philippines..........3273,00061,000-33,E19,00051,000-184,990-Poland.............4492,950265,123--32,48567,514145,9259,5073,372Portugal...........,2304,17287,785-36,54040,50050,1829,180201,5375,400PuertoRico..........173,00034,000---21,00020,00021,OW-Qatar..............2338,700- - -60,0029,400 20,D0039,350Ranania............10531,277273,22568,24037,5171D9,47861,7631,534237,6252,300Russia.............405,430,91182,028,57084,999382,593330,817745,73557,0562,17,96610,006SaudiArahia.........72,112,000445,950-138,21Q3,600 193,160133,824493,46031,500Senegal......,..,..125,03Q7,160- - -1,540-1,930-Serbia&Monter~o...2214,8265D,583-20,34Q18,95018,822-50,9103,070Sierraleane.........1t0~IN10- ---- ---Singapore...........31,357,000346,000-203,7T680,000146,A70129,360706,50Q9,000Slovakia,...,.......1115,00055,000--.,18,00021,00042,00087,8004,500Slovenia............113,500---- - - --SarthAfica.,.......4484,547201,37526,80060,006108,64477,14211,774227,7129,395SouthKorea.........62,759,500515,65019,00-314,000 342,000326,5001,450,38048,70QSpain..............91,271,500414,24561,100149,200 191,300196,750131,500ffi5,38016,916SriLanka...........150,00024,000-12,500-5,300-19,295-Sudan.............3121,700-- --1,900-8,100-Suriname...........17,0(107,000-2,800- ----Sweden............5437,W0135,600-66,829,70070,66048,60268,540-Switrerlantl..........172,000- --20,40012,000-33,200-Syria..............2239,86563,13518,222,689-31,24226,41080,886-Tanzania............114,900--2,5IX}-2,5IX1-4,400-Thailand............4584,250202,50P-16,9$391,99097,77043,073428,630-Trinidad&Tob~o.....1168,000119206-Z4,00024,00018,00045,00041,0041,200Tunisia.............134~OW----3300-- -Turkey.............6714,275201,767-23,59028,93565,66253,820265,005-Turkmenist~........2236,97091,64528,568-15,15152,540-63,50D1,028Ukraine............6879,759336,29722,14917,29170,100144,7117,200315,013-UnitedArahEmirates...5773,25042,81Q- -34,35025,87531,050158,6271,140UnitedKi~dan......101,767,168866,31464,6W106,958444,723339,77136,0001,271,54192,202UnitedStates........12517,187,X47,909,8652,543,29834,0205,649,6593,492,2881,726,03014,067,5151,142,127Uruguay............150,QI1025,000.-7,OIX112.OIX312,000-23,000-Uz6~Cisfan..........322427145,67117,6679,585-23,487-30,804-Venezuela...........51,282,1OQ585,780144,9-231,84444,500-389,70065,8fl0dietnam............1140,000- -------VirginIslands.,......1500,00205,00055,00037,000140,000 105,000-435,00018,O~QYemen.............2140,00610,500- - -14,500- --Zambia.............123,7502,280---5,320-8.550-iot~l................65586,055,55229,062,1304,681,0233,8U1,12914,693,32811,468,1475,488,69445,730,0722,x,102-17,000-16,&0015,49Q183,0--58,000---2,460----5,630---50Q- -120- -68,9688,73011,6002,715358.9-1,72616,5002,000- -12,000-54,6-30026,000-.- --.-60.0-1115,4902,2742913,6103,878- -- -14,850-1,OIX3--1,000--- -11,000-3,840-- -b1020--1,400-3,800--- -4,200- - -- -- - -3,800- -1D,00~3,700-37.0-701,200-16,26223,14417,7962,514167.0-56U33,371-17,276---85.3-252--- - - -20.0-34-- -25,~D0-------7;8013,84610,3661,33018.02,55514313,7611,72954,33721,86982,8427,17593,33,72072&210,545-6,50033,0(10-3,700190.7- - --200-300-0.5-592,400-48,IX10-45,51101,4(~275.0-84539,500-9,2506,0002,OW1,50089.5-27Q2,fi004,9406,90012,2238,000-5022406077,100-140,300-66,64010,5001,385.51,2004,73081,327-25,80036,0009,fi009,600300.13,5651,76226,600------1.0003,420-2$,530--53.8-33427,4603,800-6,400--2&.0- - ---11,493--27.05001502,223-9,50019,546- -33.5-4202,5001,580- --1,00030.Q-1(10-- -14,0555,870-217.518031520,2161,223--2,000--1,04Q-415-3,464-50012521.570517612,7851,9IX1-- - -58.8-5770013,59614,590120,42323,8993,967127.02,40079228,43074,816464,fi39678,777193,10032,2504,044.9131,07332,284490,817- -6,000- --------9,341--650-4,151-2,00020,70012,020 12,830147.85,2(]01,47136,0007,00618,OIX117,000- --3,500500--- - --3,000-- ------5,527195,3201,311,9751;x,901802,516193,0741'4,160209,12383,21,794,824Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 75 of 75Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 1 of 54

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.1

COVERED FLARES AND APPLICABILITY DATES

FOR CERTAIN CONSENT DECREE REQUIREMENTSCase 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 2 of 54

APPENDIX 2.1 ‐‐ Covered Flares and Applicability Dates for Certain Consent Decree Requirements

FLARE FLARE DATA

AND

MONITORING SYSTEMS

AND

PROTOCOL

REPORT INSTALLATION

AND

OPERATION

OF

MONITORING SYSTEMS

AND

EXIT VELOCITY

REQUIREMENTS INITIAL

WASTE GAS

MINIMIZATION PLAN FIRST

UPDATED

WASTE GAS

MINIMIZATION PLAN GENERAL

EMISSION

STANDARDS

FOR

COVERED FLARES WORK PRACTICE

STANDARDS

FOR

COVERED FLARES SPECIFIC

EMISSION

STANDARDS

FOR

COVERED FLARES

\

A B C D E F G H

‐‐ REFERENCED PARAGRAPHS ‐ ‐

12.s 16 17, 51 30 31 50 53 55, 56.b

‐ 59

East Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

Coker DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE 6/30/2014

Girbotol DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

North Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

West Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE 6/30/2014

Olefins Ground DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

Olefins II DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE PARA. 53.a.i
06/30/2016

DOE + 365 days

PARA. 53.a.ii

DOE

Olefins III DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE PARA. 53.a.i
06/30/2018

DOE + 365 days

PARA. 53.a.ii

DOE

HIPA DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

South Property

(Temporary

‐ Use) Prior to receipt of Vent

Gas after DOE Upon receipt of

Vent Gas

after DOE N/A N/A DOE Upon receipt of

Vent Gas

after DOE Upon receipt of

Vent Gas

after DOE

CCU

(Temporary

‐ Use) Prior to receipt of Vent

Gas after DOE Upon receipt of

Vent Gas

after DOE N/A N/A DOE Upon receipt of

Vent Gas

after DOE Upon receipt of

Vent Gas

after DOE

A&S

(Temporary

‐ Use) Prior to receipt of Vent

Gas after 6/30/2013 Upon receipt of Vent Gas

after 6/30/2013 N/A N/A DOE Upon receipt of Vent Gas

after 6/30/2013 Upon receipt of Vent Gas

after 6/30/2013

Legend:

DOE = Date of Entr yCase 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 3 of 54

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.2

INTENTIONALLY LEFT BLANKCase 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 4 of 54

UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.3

METHODOLOGY FOR CALCULATING REFINERY FLARING LIMITATION (INCLUDING

SDP’S FORM EIA-820 FOR REPORT YEAR 2012)APPENDIX

2.3 Refinery

Calculation

Basis Refinery
Crude Capacity

(b /cd)
Refinery ComplexityZ

US Complexity2

Refinery

/US Complexity

30 -Day Rolling Average

SCFD

365 -Day Rolling Average

SCFD Shell Deer Park

EIA /O &GJ

(b /cd)1

327,000

11.33

11.32

1.001

2,455,944

1,637,296 Notes: 1) Data

in barrels

per calendar

day

(b /cd)
are shown

on the next page.

US capacities

as of 1/1/2012

as taken from

US EIA report "U.S. Number

and Capacity

of Petroleum Refineries" (published 6/22/2012)

were used preferentially,

see Attachment

1, along
with
the corresponding

Shell Deer Park capacities

as of 1/1/2012 submitted

by Shell Deer Park

on Form

EIA -820 Annual Refinery Report
Parts

5 and

6. See Attachment

2. For processes

where

US capacities

were

not included

on the

US EIA report,

Oil &Gas Journal Worldwide
Refining Survey (published 12/5/2011) calendar

day capacities

were used

for both

the
US and Shell Deer Park.

See Attachment 3. Where

b /cd data was not available

in the EIA report, barrels

per stream

day

(b /sd) data from

EIA report were converted

to

b /cd for some processes

using

O &GJ factors
(0.95

for vacuum distillation

and 0.9 for any other processes)

where noted. 2) Nelson Complexity

factors

are shown

on the next page,

and are specified

in CD Appendix

1.14 Page

1Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 5 of 54APPENDIX

2.3 Process

Nelson Complexity Factors

SDP Capacity

as of 1/1/2012

(b /cd, except

H2 and

S) SDP Capacity

as of 1/1/2012
Source (Notes

1,

2 & 3)

US Capacity

as of 1/1/2012

(b /cd, except H2 and

S)

US Capacity

as of 1/1/2012
Source (Notes

1,

2 & 4) Atmospheric Distillation

1

327,000

Part

5, SDP's 2012

EIA -820,

b /cd

17,322,178

EIA Website

2012 Data,

b /cd Vacuum Distillation

1.3

171,000

Part

6, SDP's 2012

EIA -820,

b /sd *0.95

8,245,661

EIA Website

2012 Data,

b /sd *0.95 Coking

7.5

83,600

Part

6, SDP's 2012

EIA -820,.

b /cd

2,499,293

EIA Website

2012 Data,

b /cd Catalytic Cracking -Fresh

Feed

6

63,600

Part

6, SDP's 2012

EIA -820,

b /cd

5,611,191

EIA Website

2012 Data,

b /cd Catalytic Cracking

- Recycle

Feed

6

4,500

Part

6, SDP's 2012

EIA -820,

b /sd *0.9

76,401

EIA Website

2012 Data,

b /sd *0.9 Reforming

5

65,600

Part

6, SDP's 2012

EIA -820,

b /cd

3,246,874

EIA Website

2012 Data,

b /cd Hydrocracking

8

55,000

Part

6, SDP's 2012

EIA -820,

b /cd

1,706,540

EIA Website

2012 Data,

b /cd Hydrotreating

2.5

337,050

Part

6, SDP's 2012

EIA -820,

b /sd *0.9

14,908,736

EIA Website

2012 Data,

b /sd *0.9 Alkylates

10

17,600

0 &GJ (12/5/2011),

b /cd

1,142,127

O &GJ (12/5/2011),

b /cd Hydrogen (mmcfd)

1000

92

O &GJ (12/5/2011),

mmscf

/cd

4,045

O &GJ (12/5/2011),

mmscf

/cd Sulfur (short
tons /day)

240

1,011

O &GJ (12/5/2011),

t /cd

32,284

O &GJ (12/5/2011),

t /cd Thermal Processes (Visbreaking)

2.75

0 Part

6, SDP's 2012

EIA -820,

b /sd *0.9

14,400

EIA Website

2012 Data,

b /sd *0.9 Polymerization

10

0
0 &GJ (12/5/2011),

b /cd

74,810

O &GJ (12/5/2011),

b /cd Aromatics

20

0

O &G1 (12/5/2011),

b /cd

464,639

O &GJ (12/5/2011),

b /cd Isomerization

3

0

O &GJ (12/5/2011),

b /cd

678,777

O &GJ (12/5/2011),

b /cd Oxygenates

10

0

O &GJ (12/5/2011),

b /cd

32,250

O &GJ (12/5/2011),

b /cd Lubec

60

0

O &GJ X12/5/2011),

b /cd

193,100

O &GJ (12/5/2011),

b /cd Asphalt

1.5

0
O &GJ (12/5/2011),

b /cd

490,817

O &GJ (12/5/2011),

b /cd Refinery

/ US Complexity

11.33

1132 Note

1: Capacities

in barrels

per calendar

day

(b /cd)
are shown.

US capacities

as of 1/1/2012

from

US EIA report "U.S. Number

and Capacity

of Petroleum Refineries" (published 6/22/2012

and available

at www.eia.gov)

were used preferentially,

see Attachment

1, along
with the corresponding

Shell Deer Park capacities

as of 1/1/2012 submitted

by Shell Deer Park

on Form

EIA -820 Annual Refinery Report
Parts

5 and

6, see Attachment

2. For processes

where

US capacities

were

not included

on the
US EIA report

(i.e. those reported

in Part

7 of EIA -820 rather
than Part

6), Oil &Gas Journal Worldwide
Refining Survey (published 12/5/2011) calendar

day capacities

were used

for both
the
US and Shell Deer Park,

see Attachment

3. Where

b /cd data was not available

in the EIA report, barrels

per stream

day

(b /sd) data from

EIA report were converted to

b /cd for some processes

using

O &GJ factors
(0.95

for vacuum distillation

and 0.9 for any other processes)

where noted. Note

2:

O &GJ (12/5/2011)

=Oil &Gas Journal Worldwide
Refining Survey (published 12/5/2011)

of petroleum
refinery capacities

as of 1/1/2012.

See Attachment

3. Note

3: Part

5 or 6, SDP 2012

EIA -820

= U.S. Energy Information Administration

Form

EIA -820 submitted

by Shell Deer Park.

See Attachment

2. Note

4: EIA Website

2012 Data

= US Energy Information Administration

Website (www.eia.gov),

Number

and Capacity

of Petroleum Refineries

data

for the year 2012.

See Attachment

1. Page

2Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 6 of 54

# APPENDIX 2.3

ATTACHMENT 1 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 7 of 54U.S. Number and Capacity of Petroleum Refineries



# elaU S. Energy Information

Administration



## PETROLEUM &OTHER LIQUIDS Page 1 of 2

OVERVIEW DATA ANALYSISBPROJECTIONS GLOSSARY> FAQS>

Number and Capacity of Petroleum Refineries

Area: U.S. Period: Mnual (as of January 1)

F D U~Series C' Arcs I ~ ~cbar ' 200 2000 I 2009 I 2010 2011 2012 I H sit ry

Total Number of Operable
Refineries ~_ 149 150 150 148 148 144 tse2 -2ot2

Operating

_ 145 146 141 137 137 134 tse2 -2012

Idle 4 4 9 11 11 10 1 - 0~

tmoap er P. t~

3 Operable (Barrels per Calendar Day)

.... 17,443,492 17,593,847 17,671,550 17,583,790 17,736,370 17,322,178 19820012

Operatin8 16,997,792 17,225,797 17,313,550 16,850,194 16,937,024 16,744,291 ~sa2 -202

Idle ~_' 445,700 368,050 358,000 733,596 799,346 577,887 1982 -202

Operable (Barrels per Stream Day) ~.:_ 18,425,322 18,558,022 18,681,308 16,581,089 18,953,189 18,560,350 1982 -202

Operating

__ I ~_, 17,928,522 18,174,072 18,300,358 17,808,082 16,109,882 17,945,443 1982 -2012

Idle ~ ; 496,800 383,950 380,950 773,007 843,307 614,907 1982 -2012

..~

( 5, may

..

_
Vacuum Distillation ~] 8,251,451

.. 8,0.20,501 8,542,261 8,542,643 8,650,243 8,679,643 1 8 - 1

Thermal Cracking ~~'• 2,564,080 2,606,260 2,639,090 2,631,676 2,672,376 2,763,356 1982.2012

Total Coking ~__I 2,537,480 2,579,660 2,612,490 2.605,076 2,645,776 2,736,756 taa74o~2

Delayed Coking J 2,331,580 2,374,280 2,454,590 2,500,676 2,486,876 2,577,856 7 e9 7 -202

Fluid Coking

,_, 205,900 205,400 157,900 104,400 158,900 158,900 1987 -zot2

Visbreaking ~..1 16,000 16,000 16,000 16,000 16,000 18,000 X987 -2ot2

Other (Including Gas Oil) ` ~i 1D,600 10,800 10,600 10,600 10,600 10,600 1987.2072

Catalytic Cracking -Fresh Feed 8,216,957 6,265,697 6,291,871 6,140,121 6,219,721 6,032,512 ~se2 -2oi2

Catalytic Cracking

- Recycle Fead g2,04D 78,74D 78,740 91,840 95,640 84,890 1a 2 -2 7

Catalytic Flydro- Cracking 1,790,682 1,770,325 1,743,300 1,819,700 1,855,600 1,879,600 ~9e2 -2012

Distillate 602,800 556,900 593,100 595.200 540,100 596,500 2004.2072

Gas Oil 967,482 1,004,425 1,010,200 1,079,500 1,170,500 1,161,100 20W -2012

Residual 200,400 209,000 140,000 145,000 145,000 122,D00 2004.2012

Catalytic Reforming 3,907,310 3,891,938 3,629,338 3,700,483 3,720,613 3,641,813 198 - 012

Low Pressure 2,354,950 2,402,350 2,397,750 2,322,700 2,390,950 2,347,850 1987 -2012

High Pressure 1,552,560 1,489,588 1,431,588 1,377,763 1,329,663 1,293,963 1987.2012

Catalytic HydrotreaGng/Desulfurization 15.447,136 15,807,478 16,130,823 16,023,206 16,682,897 16,565,262 1982 -2012

Naphtha/ReformerFeed 4,453,890 4,348,590 4,334297 4,281,446 4,441,323 4,360,593 19874012

Gasoline 2,221,568 2,420,968 2.415,282 2,394,882 2,578,782 2,519,082 2004202

Heavy Gas Oil __~ 2,578,840 2,672.440 2.735,538 2.796.798 2.809,298 2.877.138 1987.2012

Dlstiilate Fuel Oil 5,212,367 5,462,849 5,622,252 5,676,032 8.113,646 6,063,001 ]987.2012

Kerosene /Jet Fuel 1,009,450 1,137,010 1,160,110 1,339,150 1,484,850 1,489,750 2004 -2012

piesel Fuel 3,332,671 3,466,471 3,551,211 3,647,211 3,917,611 3,961,411 2004.2012

OtherDislillate

~ 970,266 857,166 910,931 689,671 711,385 591,840 zoa•so~s

Residual Fuel OilJOther 980,451 902,831 1,023,454 874,448 739,648 745,448 1867.2012

Residual Fuel Oil ( 331,420 251,200 316,400 246,200 241,000 246,000 20042012

Other 649,031 651,631 707,054 628,248 498,648 498,448 ZOPa"20~2

http:// www. eia. gov/ dnav /pet/pet~np_capl_dcu_nus_a.htm 4/25/2013 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 8 of 54U.S. Number and Capacity of Petroleum Refineries

Fuels Solvent Deasphalting ~ 7 379,290' 378,3501 380,950 383,250 382,750 374,550 1987 -2072

~,
Catalytic Reforming (~ i 3,378,641 3,348,457 3,246,67412oaa2o~2

Toted Coking

~ 2,359,318, 2,390.223; 2,428,981 2.387,886. 2.396,787 2,499,293, s1 87.2012

Catalytic Cracking -Fresh Feed ` ' 5,830,486 5.853,656 5,847,130 5,675,830 5,794,214 5,611,191 1987 -2012

CatalyticHydro-Crackln8 ~. J 1,620,705] 1,602,431 1,592,973 1,663,115 1,687,745 1,706,540 1987 -2012

-= No Data Reported;

— =Not Applicable; NA =Not Available; W = Withheld to avoid disdosure of in~vitlual company daha.

Notes: Idle refineries represent refineries where disfilla6on uni4s were wmpleiely idle but not permanently shuMam as of January 1 of the year. See

Definitions, Sources, and Nofes link above for more iMortnation on this table.

RBIBaSe Dffie: 6/22/2012

Next Release Date: 8/21/2013 Page 2 of 2

http: / /www.eia.gov /dnav /pet /pet_pnp_capl_dcu

_

nus

_

a.htm 4/25/2013 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 9 of 54

# APPENDIX 2.3

ATTACHMENT 2 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 10 of 54U.S. Energy Information 

# ela

Administration OMB No. 1905 -0165
Expiration Date: 1/31/20131

Version No.2010.02

FORM EIA -820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93 -275). Failure to comply may result in criminal fines, civil penalties and

- sanctions as provided by law. For further information concerning sanctions and data protections see the provision on sanctions and the provision concerning the

9entiality of information in the instructions. Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly makes to any Agency or

irtment of the United States any false, fictitious, or fraudulent statements as to any matter within its jurisdiction.

- - - - - _.. ;T 1. RESPONDENT IDENTIFICATION DATA PART 2. SUBMIS510NIRESUBMlSSION INFORMATION

~EIA ID NUMBER: ~ 1339570101

~~

If any Respondent Identification Data has changed since the last report,

enter an "X" in the box:

Company Name: Shell Oil Co.

Doing Business As:

Site Name: DEER PARK REFG LTD P7NRSHP

Terminal Control Number (TCN):

Physical Address (e.g., Street Address, Building Number, Floor, Suite)

HWY 225

City DEER PARK State: TX - Z~p~ 77536 - 0100

(Mailing Address of Contact (e.g., PO Box, RR): If the physical and

malting addresses are the same, only complete the physical address.

P.O. BOX 100

City DEER PARK State: TX Zip: 77536 - 0100 If this is a resubmission, enter an "X" in the box:

A completed form must be received by February 15 ~n of the

designated report year.

Forms may be submitted using one of the following methods:

Email: OOG.SURVEYS~eia.gov

Fax: (202)586 -1076

Secure File Transfer:
https: /lsignon. eia. doe.gov /upload /n oticeooa. i s q

Questions? Call: 202- 588 -6281

Contact Name:

Phone No.: ~ Ext:

~

Fax No.:

Email address:

Comments: Explain any unusual or substantially different aspects of your current year's operations that affect the data reported. For example, note new

processing units, major modifications or retirement of processing unib, sale of refinery, etc. (To separate one comment from another, press ALT +ENTER) Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 11 of 54~~

_ :.....:...

. ... :.. ~ ,;. OMB No. 1905 -0165 

# ~~U.S.

F.nergy Information Expiration Date: 1/31/2013
Administration Version No.:2010.02

FORM EIA -820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

~EIA ID NUMBER: 7339570101 RESUBMISSION:

3. FUEL. ELECTRICITY. AND STEAM PURCHASED ~ CONSUMED AT THE REFINERY DURING 2011

PART 5. ATIIMOSPHERIC CRUDE OIL OISTtLLATION CAPACITY AS ~F JANUARY 1

Atmos heric Crude Oif Distillation Ca aci Code Barrel per Calendar Day2 Barrels per Stream Da

2012: O eratin 399 327000 327000

idle 400 0 0

Total O erable 401 327000 327000

2013: 0 erable 5o1 327000

z Barrels per Calentlar Day Operating, Idle and Total Operable Capacity (Codes 399, 400 and 401) must match the comparable capacity numbers reported on the Forth

EIA -810, "Monthly Refinery Report "filed for January 2012. Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 12 of 54,. ,:,..,:., ~,;.,,

,,.,, ,~ ~,.,..

LJ.S. Energy Iiiformacion 

# ela

administration

FORM EIA -820

ANNUAL REFINERY REPORT

REPORT YEAR 2012 OMB No. 1905 -016 Expiration Date: 1/31/201

Version No.:2010.02

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 6. DOWNSTREAM CHARGE CAPACITY AS OF JANUARY 1

Dovimstream Charge Capacity Code 2012

Barrels per

Calendar Day 2012

Barrels per

Stream Day 2013

Barrels per

Stream Day

Vacuum Distillation 402 180000 180000

Thermal Cracking:

Visbreaking 403

~ 0

Fluid Coking (incl. Flexicokin) 404 0 0 0

Delayed Coking 405 83600 89300 89000

Other (incl. Gas Oil) 406 a 0

CatalyticCrackin ~'` j~~*'2- '' $

Fresh Feed 407 63600 70000 70000

Recycled 408 5000 5000

Catal tic Hydrocracking: ~`' ~' y~~ ` `''

Distillate 439 0 0 0

Gas Oil 440 55000 60000 60000

Residual 441 0 0 0

Desulfurization (including Catalytic HydrotreaYing): c ~ •.:~ .~ ,~ ^~~ ~~~s;

Na htha /Reformer Feed 426 75000 75000

Gasoline 420 42000 42000

Kerosene and Jet 421 40000 40000

Diesel Fuel 422

~ 0

Other Distillate 423 45000 45000

Residual 424 49500 49500

Heavy Gas Oil 413 80400 80000

Other 425 43000 43000

Catal tic Reforming:

_ ~

Low Pressure 430 42900 45000 45000

High Pressure 431 22700 24500 24500

Fuels Solvent Deasphaltin 432

PART 7. PRODUCTION CAPACITY AS OF JANUARY 1 Barrels er Stream Da

, Exce Whet~e Noted

Rroduction Ca aci Code 2012 2013

Alk later q~5 18500 18500

Aromatics 437

~ 0

As halt and Road Oil 931

~ ~ {sobutane C4) 644

~ ~

Isa entane (C5

, Isohexane C6 438

~ ~

Isooctane C8} 635

~ ~

Lubricants 85a

~ ~

Petroleum Coke

- Marketable 02~ 38701 38701

H dro en million cubic ft. per day) 091 ~~$ goo

Sulfur (short tons per da) 435 1085 1085 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 13 of 54

# APPENDIX 2.3

ATTACHMENT 3 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 14 of 54.~.~+G7y01m~OnO2011WorldwideRefininSurveLeenaKoottungalgYSurveyEditorJNewsWriterAllfiguresinbarrelspercalendarday(b/cd)LEGENDNumbersidentify+procassesintableCokingCatalyticreforming1.Fluid.coking1.Semiregenerative2.Delayedcoking2.Cyclic3.Other3.Continuousregen.4.OtherThermalprocess1.ThermalcrackingCatalytichydrocracking2.Visbreaking1.Distillateupgrading2.ResidualupgradingCaffilyticcracking3.Lubeoilmanufacturing1.Fluid4.Other2.Otherc.Conventional(highpressure)hydrocracking:(>100Bargor1,450psig)m.Mildtomoderatehydrocracking(<100bargor1,450psig)Catalytichydrotreating1.Pretreatmentofcatreformerfeeds2.Othernaphthadesulfurization3.Naphthaaroma#icssaturation4.Kerosine/jetdes~ifurization5.Dieseldesulfurization6.Distillatearomaticssaturation7.Otherdistillates8.Pretreatmentofcatcrackerfeeds9.Otherheavygasoilhydrotreating10.Residhydrotreating11.Lubeoilpolishing12.PosthydrotreatingofFCCnaphtha13.OtherAllfiguresareasofJanuary1,2012AblationIsomerizationHydrogen1,ulfuricacid1.C4feedProduction:2.Hydrofluoricacid2.C~feed1.Steammethanereforming3.C5andC6feed2.SteamnaphthareformingPolymerization/Dimerization3.Partialoxidation1.PolymerizationOxygenatesa.Third-partyplant2.Dimerization1.MTBERecovery:2.ETBE4.PressureswingadsorptionAromatics3.TAME5.Cryogenic1.BTX4.Other6.Membrane2.Hydrodealkylation7.Other3.Cyclohexane4.CumeneNOTESANawIPreviouslylistedasSKCorp.QPlanstosellBPreviorslyNateiasOerrmlCap.1PreriouslylistedasHyundaiOilRelineryCo.RPreviouslylistedasSunocoInc.CPreciouslylinedUJLLtd.KPrevioustylistedasHallyCorp.5PlansioconverttoastoragefacifryDPrerionarylutedn116ERd~8Mandxlnri~LNewtosurveyTPo~saleEPrevioudylists~Mxpay8AUSAMc.MShuidownUPreviouslylistedasValeroEnergyCarp.FMayconvertintoakd'u~patkrnio~NPrevioustylistedasFrontierOilCary.VPteviousfylistedasMarathonPetroleumCa.tPiWhd0PreriouslylistedasfrontierRefiningMc.WPreviouslylistedasSheltoeuisch4andOiiGMBNHPreria~slqIaEndxOil145aetialdl.PPrevioustylistedasConacoPhillipsCapacityd~inilioasCapacityexpressedinbagelspercalendarday(b/cd)isthemaximumnumberofbarrelsofinputthatcanbeprocessedduringa24-hourperiod,aftermakingapowancesforthefolbwing:(a)Typesandgradesofinputstobeprocessed,(b)Typesandgradesofproductstobemanufactured,(c)Environmentalconstraintsassociatedwithrefineryoperations,(d)Scheduleddowntimesuchasmechanicalproblems,repairs,andslowdown.Capacityexpressedinbarrelsperstreamday(blsd)istheamountaunitcanpTncesswhen'runningatfullcapacityunderoptimalfeedstxkandproductslateconditions.Anasterisk(')besidearefinerylocationindicatesthatthenumberhasbeenconvertedfromWsdtob/cdusingtheconversionfactor0.95forcrudeandvacuumdistillationunitsand0.9foralldownstreamcrackingandconversionunits.REFINERYREMOVALSHydroQan:Hydrogenvolumespresentedhererepresenteithergenerationorupgradingto9Q+%purity.NameLocationCountryCordshkdReasonWesternRefiringYorktown,VirginiaUS70,000Shu[downSuracoInc.Westville,NJUS15,000Shu[downAbnUSABakersfield,CaliLUS70,000IntegratedwAhParamountrefineryHillyCap.Tulsa,Okla.US85,OIX1IMegtffiedwdhotherTulsarefineryi~aiSADunkirkFrance137,028ShutdwmPak-ArchRdineryCo.MahmaadKot,PunjabPakistan1{)0,000ShutcamPeVoplusHok3ir~sAGCressierSwitrarlar~6D,000ShutdawiCatalyticreformi~:1.Semiregenerativereformingischaracterizedbyshutdownofthereformingunitatspeckedintervals,orattheoperaYors'sconvenience,forinsihicatalystregeneration.2.CyclicregeneraUottreformingischaracterizedbycontinuousacontinualregenerationofcatalystinsituinanyoneofseveralreactorsthatcanbeisolatedfromandreturnedtothereformingoperation.Thisisaccomplishedwithoutchangingfeedrateoroctane.3.Continuousregeneratbnreformingischaracterizedbythecontinuousadditionofthisregeneratedcata{ysttothereactor.4."Other"includesnonregenerativereforming(catalystisreplacedbyfreshcatalyst)andmoving-bedcatatystsystems.Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 15 of 540WorldwideRefineries-CapacitiesasofJan.1,2012~Chargecapacih~~d---Productioncapacity,Wcdm~'No.ofVaeuunThermalCatalyticCatalyticCatalyticCatalytic~(MMcC(tonnesCountry0~oaiespMedistillalin~CotinaoperationscrackingrefaminghydrocrachinghydrolreatingAlkylatianPoIJDim.NomaticsIsoraerizadontubesOxygenMesd)pe$day)Aspl~pcAlbania.............226,30010,50012,000--3,500-17,400--600-700-6.570060-~Algeria.............4450,OW10,894- --88,900'-81,950----- - -- - --~Angola.............139,0002,500- --1,900-6,600-- - ------950~Argentina...........10630,575248,36591,233 38,420141,18056,530IJ,~00175,6004,300520-12,7007,2902,60D19.Q3,81010812,700~Aruba..............1235,000166,25068,40630,600---214,200- - - ---93,04,500810-Australia............7760,1A8192,865--235,043172,05318,407543,53124,73410,6091,00039,606--72.3-194ID,017~Austria.............1208,60065,000-16,87526,25032,725-139,400---14,400-1,6~--1801,470pAzerbaijan..:.......;2398,978237,20038,524-57,75624,466-fi7,492-930- - -16,200- -1,4fl0-5,000~Bahrain............1253,650198,170-21,60035,10013,50054,00076,500-3,330----164.4-3408,730Bangladesh..........133,0004,000-10,000-1,800 1,2002,000--- - --2.p-- -Belariu.............2A93,323105,800-60,00044,00692,00030,000262,100--2,7854,5003,766-22.8-859,630Belgium............4739,821250,630-30,016133,553105,589-687,75517,630--0-3,75498.5697126,500Bolivia.............241,2002200- --12,100-6,899------14.0---Brazil..............131,917,333810,140115,3199,800545,28724,386-284,446b,290-- -20,0096,460126.05,97477127,100Brurrei.............I8,600- ---5,700--- ---- ---Bulgaria.,..........I115,24049,900-20,60023,3004,060-64,2(102,600-2,000--79010.3-531,500Cameroon...........I37,000----6,500-16,140- - --- - - - --Canada.............171,918,455645,05659,100121,430482,468354,930210,3741,383,53670,40319,24062,68962,4903,000-461.02,6352,17466,000Chile..............3226,80085,05013,86013,86050,54026,46050,400-910--8,510-1,580-65690-China............ . .546,866,000240,WQ156,000-588,000178,000185,000541,00015,500-21,000-18,000900-4,0201,362-China,Taiwan........A1,310,000248,5Q651,000-217,900115,00025,000672,5001A,200-14,40026,00015,311,266341.04,5223,74515,270Calanbia.....,.....5290,850141,000-52,OOD90.000- -19,02,100 2,100 2,200-1,400-18.0---Cor~o(&aznaille)....121,0008,000- --2,0002,0003,500-- -- - -- - - -CostaRica..........124,000600-6.500-1~2t}0-2.000-- - - -- - - --Croatia....... ......3250,31787,0405,00023,52651,00249,36812264b8,256--9,4385,431470---200123-Caba..............4301,40075,700- -14,7W20,000-55.850-- - - --5.Q- -1,080CzechRepublk.......3183,00078,870-17,000-27,47034,430143,78a--6607,2102,18112,164I12.0-14410,880Denmark...,.......:2174,40022,000-64,550-21,990-42,760-- -6,400- - - - -8,~0DominicanRepudic...250,000--- -8,200-20,813--- -- -0.6- --Ecuada,...........3176,00045,300-31,50018,00012,800-24,500---- --- - - -Egypt..............9726,25095,20039,270- -62,24033,50Q207,8029,000-1,58410,7004,441-62.51,60129Q4,623EISalvador..........1Y1,0004,000-- -3,000-15,50D--- - - -----Eritrea.............114,5642,219---1,465-2,742- ------- - -Finland.............22fi0,57514fi,085-34,42456,69050,06090,110298,3257,75064Q- -5,2805,730160.0-5406,500France.............121,718,803715,200-146,872347,052256,66971,8451,233,04826,7Q22,9682,88748,43236,3904,711132.0-1,38343,502Gabon.............124,000---9,220-1,40-9,430Germany............152,417,1621,09fi,231105,809247,445349,171404,822263,0672,011,78230,8858,30171,94494,22614,22013,172772.03,8132,91460,630Ghana.............145,00---14,00065~W0---- - - -- ----Greece.............4423,000152,D00-49,00075,55049,24043,900361,6352,4W1,7209,1Q023,6503,500 3,94023.5-51916,950Hungary............1161,0077,50016,90014,Ob024,000 29,600-120,7003,300-12,0003,5006,1001,20076.26002266,300India..............2i4,042,761811,986169,62593,180531,30551,673165,640250,74285,000-9,742-8,2401,346]32.96,48045237,768Inda~esia...........81,011,925265,98032,58058,860101,45092,970 99,72023,43016,200-- - - - - - - -Iran...............91,451,000559,400-240,80035,00164,70013b,500183,160- - --19,60-286.0-47036,5D0Iraq...............9637,500145,000---88,00J4,241292,000---2,5009.426-64.0--38,738Ireland.............171,400-- --11,000-44,6i~-- -7,600--10.3-4-lsrael..............2220,400115,000-66,00049,50426,500-96,0(30-2,200---750---2,700Itaty...............172,337,229814,23745,000448,204321,506287,Q69 303,2101,250,75348,3341,50013,40D112,26024,00011,720305.42,0461,77b15,706lvayCoast..........163,99023,990-- -12,330 14,48027,310---- - ----4,330Jamaica............136,0001,800-- -3,700-23,8W-- - --- ---850Japan..............304,729,8901,764,195123,40020,00986,980829,225181,6405,016,16074,6905,760207,46731,35038,0132,9781,459.41,8639,54484,370Jordan.............190,40021,500--4,00010,9005,22017,300-- ----16.0--4,250Karakhs#an..........3345,D93121,03724,997 52,07138,35651,586-117,890-- - - --21.5I,00~1248,550Kenya..............190,D001,700---8,260-36,000- -- ------1~~K~wdit.............3936,000327,75072,000-36,06046,620115,650588,7805,filb-- --6,561741.62,8004,200-Kyrgyzstan..........110,000- --- ----Li6eria.............115,0001,000---2.000-3,300- - - -- - - --200Libpa..............3378,D003,715---2Q,250-43,330-- --b35- ---3,432Lithuania...........~119i1,IX1089,300-28,80043,200 45,A00-153,900--7,200-I8,9U0-2,70025.0-32U-Macedon~..........150,0- - - -10,860-22,050- --4,390- ---- -Malaysia............7538,58294,33524,0(10-42,70075,07036,000216,801)---10,800--147.2 2,24546024,700Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 16 of 540H0wOnOtiWorldwideRefineries-Capacitiesasoflan.1,2012~«P~h~~Protl~ctioncapacity,WcdNo.MVacuumThermalCatalyticCatah►licCatatyGcCatatyticHydrogenCokeSuiiurCouMtyMine~iaCededistlllationCoNinaoperationscrackingrehminghytlracrackinghydrotreatingAlkylatianPolJDim.AromaticsIsomerizalionLu6esOxygenates(MMCfd)(tonnesperday)AsphaltMartinique..........117,329- - --2,862-14,269-Mezico.............fi1,5d0,000754,000191,000-380,500279,300-926,050128,456Morocco............2154,90124,921- -5,04624,359-35,539-Myanmar...........357,0004,4005,200- -- ---Netherlands.........61,196,571711,04541,50041,4U4101,983148,616198,0711,016,23415,450NetherlandsAntilles...1320,000195,000-80,00050,00020,000-119,5009,OWNewZealand.........1107,00038,274- --25,84030,0,104,490-Nicaragua...........L24,0001,500--=3,000-14,5-Nigeria.............4445,000124,490- -82,7oQ70,070-1D9,2319,870NorthKorea.........271,W0-- --7,300-7,400-Naway.............2314,IXI0-24,78D32,00049,OOQ34,900-126,OIJQ-Oman..............165,000- -- -16,000-21,000-Pakistan............b186,30619,815- - -11,650-54,870-PapuaNewGaines....132,500- -- -- - - -Paraguay............17.500---- ----PBN...............G198,95094,000-25,70033,5002,100-2,800~-Philippirres...,......3273,00061,000-33,00019,D0051,000-184,990-Paland.............4492,950265,123- -32,48567,514145,908259,5W3,372Portugal........,,..2304,17287,785-36,54040,50Q50,1829,180201,5375,400PuertoRico..........173,00034,000- - -21,00020,00021,0-Qatar..............2338,700-- -60,0029,400 20,D0039,350Romania............10537,277273,22568,24037,577109,47861,7631,534237,6252,300Russia.............Atl5,430,9082,028,57084,999382,593330,817745,73557,0562,170,96610,006SaudiArahia.........72,112,000445,950-138,200 1Q3,600193,160133,820493,46031,5{10Senegal........,,..125,0307,160- - -1,590-1,930-S~bia&Montenegm...2214,82650,583-20,34018,95Q18,822-5D,9103,070SierraLeone.........110.000--- -- -- -Singapore...........31,357,000346,000-203,71080,000146,47Q129,36076,5009,00Slovakia............1115,00055,000--18,021,00042,00087,8004,500Slovenia............113,500--- - ----SauthAfica..,,.....44&4,5472U1,37526,80066,000108,64477,14211,774227,7729,595SouthKorea.........62,759,500515,65019,000-314,000 342,000326,5001,450,38048,700Spain..............91,271,500A14,2A561,100149,200141,300196,750131,500825,38016,916SriLanka...........150,00024,000-12,506-5,300-19,295-Sudan.............3121,700----1,906-8,100-Suriname...........17,000 7,000-2,8Q0- ----Sweden............5437,000135,60D-66,829,770,66D48,600268,540-Switeerland..........172,000---2~,4~12,400-33,200-Syria..............2239,86563,13518,20022,689-31,2422b,0.1080,866-Tanzania............114,900--2.500-2,5D0-4,A00-Thailand............4584,250202,500-16,98391,99047,77043,073428,634-Trinidad&Tobago.....1168,D00114,2D0-24,W024,00018,00045,00041,0041,200Tunisia.............134~OD0-- --3300- --Turkey.............6714,275201,767-23,59028,93565,66253,820265,5-Turkmenistan........2236,97091,64528,568-15,15152,540-63,5001,028Ukraine............6874,759336,29722,14917,2417Q,100144,7117,200315,013-UnitedRrabEmirates...5773,25092,870--34,35025,87531,050158,6271,140UnitedKingdom...,..1D1,767,168866,31464,600106,958444,723339,77136,0001,271,54192,202UniledStates........12517,787,7147,909,8652,543,24834,0205,649,&543,492,2881,726,03014,061,5151,142,127Uruguay............I50,00025,000.-7,OIX112,OW12,000-23.000-Uzbekisfan..........3224,27145,67117,6679,585-23,487-30,804-Yenezuela...........51,282,100585,78U144,90Q-231,80049,500-389,70065,8fl0dietnam............1140,000-- ---- --VirginIslas.,......1500,00205,00055,00037,006140,000105,OW-435,00018,000Yemen.............2140,00010,500- - -14,5~d- - -Zambia.............Z23,7502,280---5,320-8,550-Tof~l................65588,055,55229,062,1344,681,0133,801,12914,693,32811,468,1475,488,69445,73Q,0722,090,102-17,000-16,600 15,490183.0--58,000---2,460- ---5,630-- -50D--120---68,968 8,73011,6002,715358.9-1,72616,5002,OW--12,000-54,6-30026,000-- - -.-fi0.0-,Ill5,4902,2742913,6103,878- - --14,850-1,000- -1,000----11,~00-3,840---b1020--1,400-3,800- - - -4,200- - - - ----3,800- -1~,00~3,7~-37.0-701,200-10,26223,19417,7962,514167.0-56033,371-17,216-- -85.3-252-- - - --20.0-34---25,000----- --7,8013,84610,3661,33018.02,55514313,7611,72954,33721,86982,8427,17593,33,720726210,545-6,50033,000-3,lOQ198.7----200-300-0.5-592,400-48,000-45,5001,400275.0-84539,500-9,2506,0002,W61,50089.6-2702,6004,9406,90012,2238,000-5022406017,100-140,300-66,64010,5D01,385.51,2004,73061,327-25,80036,0009,6044,fi003~.13,5651,76226,600- -----1.0003,420-28,530-53.8-33427,4603,8W-6,40Q--28.0- - ---11,493--27.05001302,223-9,50019,596--33.5-4202,50fl1,580---1,00030.0-1~-- -14,0555,870-217.518031520,2151,223--2.000--1,044-4153,464-50012521.570517612,7851,900- -- -58.8-577IX113,59614,590120,42323,8943,967127.02,40079228,43074,8104b4,639678,777193,10032,2504,044.9131,07332,284490,817--6~000----- ----9,347--650-4,151-2,00020,70012,02012,830147.85,2001,47136,0007,Op018,00017,000- --3,500500-- -- - --3~a00--- - --- -5,527195,3201,371,8751,~i,901802,516193,0741'4,160209,12383,2561,194,824Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 17 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.4

CALCULATION OF OLEFINS FGRS ESTIMATED

PERCENT RECOVERY Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 18 of 54

### APPENDIX 2.4

CALCULATION OF OLEFINS FGRS ESTIMATED PERCENT RECOVERY

1. Calculation of F unrecovered for each hour : Using each hourly average Adjusted Vent Gas Flow Rate (“AVGFR”) from the HF vg

‐ adjusted data set submitted pursuant to paragraph 46.b., calculate hourly

unrecovered gas flow (“F unrecovered ” in KSCFH) due to the AVGFR exceeding operating compressor capacity using the following assumptions:

a. At least one compressor is assumed to be running at all times.

b. When the hourly average AVGFR exceeds the capacity of the currently operating compressor(s) (“Cap op ” in KSCFH), an additional compressor(s) up to the AVGFR begin(s)
operating the next hour. This accounts for the one

‐ hour lag in compressor start up time

allowed after the need for the compressor arises for those compressors required to be

Available for Operation.

c. As soon as the hourly reported flow rate does not necessitate one or more of the

compressor s, that compressor(s) shuts off.

d. Each compressor and the overall FGRS recovers flow up to its design capacity during periods

when the flow exceeds such capacity. Flow above currently operating compressor capacity

for each hour is considered unrecovered flow (F unrecovered ) for that hour and, when AVGFR is

greater than Cap op for an hour, is calculated as follows for that hour:

F unrecovered = AVGFR ‐ Cap op

2. Calculation of V downtime : The total volume of gas not recovered due to compressor downtime allowed

per the CD (V downtime , in KSCF), is calculated using the following assumptions:

a. Assume that the percentage of downtime for a specific compressor that will result in

unrecovered flow is the same as the percentage of overall allowed downtime for that

compressor (e.g., if a compressor is allowed to be down 2% of all tim e, and the compressor

is only ever needed for 100 hours over two years, then unrecovered flow due to downtime

will occur during 2% of 100 hours, or 2 hours). In other words, assume compressor down

time is even distributed over time and does not all occur at times the compressor is needed.

b. For the compressor in each scenario that is allowed downtime per the CD, calculate the

average gas volume over th e one year period, not the maximum gas volume, that would be

recovered by that specific compressor when needed (i.e., when flow exceeds capacity of

upstream compressors and the specific compressor is recovering flo w).

c. Multiply the average gas volume recovered (“V avg

‐ rec “) by the compressor when needed by

the total number of hours of allowed downtime (“H d ”) that occur when the compressor is

needed and sum for each hour of downtime:



### V

downtime 

###  H d

h =1 H d 

#  x V avg - rec Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 19 of 54

### APPENDIX 2.4

3. Calculate overall percent recovery over the one year time period (i.e., 8760 hours), according to the
equation (where “h” in the summation represents each incremental hour).



### 100%

AVGFR F V
1 Recovery Percent Estimated
8760

1h 8760

1h dunrecovere downtime



###     

 

   

 



 

#  

 

A spreadsheet containing hypothetical examples/applications of the above methodology is set forth at the

following: http://www2.epa.gov/enforcement/shell-deer-park-spreedsheet Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 20 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.5

METHODOLOGY FOR CALCULATING THE

365-DAY ROLLING SUM EMISSIONS OF

VOLATILE ORGANIC COMPOUNDS FROM

THE HIPA FLARE Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 21 of 54

## APPENDIX 2.5

1 Equations for Calculating the 365

­ day Rolling Sum Emissions of Volatile Organic Compounds from the HIPA Flare

For the purpose of demonstrating compliance with the Volatile Organic Compound (“VOC”) emissions limit for the HIPA flare in Paragraph 49 of this Consent Decree, the

block sum of HIPA Flare VOC emissions sha ll be calculated each day in accordance with the steps prescribed below, and the 365-day ro lling sum, rolled daily shall be calculated using data from the prior 365 calendar days. All abbreviations, constants, and variables are defined in the “Key to the Abbreviations ” on page 3 of this Appendix. An example calculation spreadsheet can be found at the following: www.epa.gov/enforcement/air/documents/sdp‐appendix2‐5.xlsx

Step 1: Determine the Molecular Weight (“MW i ”) of each Volatile Organic Compound (“VOC“) in the Vent Gas.

Take the MW i values for i = 8 through i =18 of each individual Vent Gas VOC from

column i of Table 1 in Appendix 1.3.

Step 2: Determine Compliance with the Net Heating Value of the Combustion Zone (“NHV
cz ”) standard for each calendar day.

Determine for the 365-day rolling sum period the calendar days “ r ” during which the 3-hour rolling average standa rd in paragraph 56.b was me t, and the calendar days

“ s ” during which the standard was not met.

Step 3: Calculate the block sum mass of VOC emitted for each calendar day “ r ” (i.e., days during which the flare was operated in compliance with the Net Heating Value of the Combustion Zone standard (“ ”).

Step 3a : The mass of VOC in the Vent Gas (“ ”) for each calendar day “ r ”

shall be calculated as follows using daily block average values of and for

that day: 

# 

  

###  

 18

8 

### 5.385 i iivg
vgVOC 

### xMWQ

m

 Equation 1

Step 3b : The mass of VOC emitted for a calendar day “r” shall be calculated as follows using a 98% VOC Combustion Efficiency (“ ”) and the value for from Equation 1:

Equation 2 

### N

H V

cz



### (  ̇ M VO C

 E mi t 

### )

r



###  ̇ m VOC

 v g 

### Q

vg 

### x i



### C

E VOC



###  ̇ m VOC

 v g



### (  ̇

M VOC

 Emit 

### )

r 

###   ̇ m VOC

 vg 

###  (1

 CE VOC 

### /100)  24 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 22 of 54

## APPENDIX 2.5

2 Step 4: Calculate the block sum mass of VOC emitted for each calendar day “ s ” during which the Net Heating Value of the Combustion Zone standard was not met (“ ”)

Step 4a : The mass of VOC in the Vent Gas shall be calculated for each 1-hour block sum period “ j ” of the calendar day “ s ” as follows using each hourly block average value for and that day:



# 

  

###  

 18

8 

### 5.385 )(

i iivg
jvgVOC 

### xMWQ

m

 Equation 3

Step 4b : Calculate NHV

cz for each 1-hour block sum period “ j” of the calendar day “ s ” (“ ”) using the equations in Step 6 of Appendix 1.3.

Step 4c : Calculate the Combustion Efficiency of VOC for each 1-hour block sum period “ j” (“ ”) of calendar day “ s ”:

If < 95 BTU/scf:

= 0 Equation 4a

If

( CE VOC ) j  0.16   95  ( NHV

cz ) j 

#  

1  0.16   95  ( NHV

cz )

j 

#    100 Equation 4b

Step 4d : The block sum mass of VOC emi ssions from the HIPA Flare during calendar day “ s ” shall be calculated as shown be low in Equation 5 as the sum of the hourly block sum VOC emissions calculated for each hour “ j ” during that calendar day.

Equation 5

Step 5: Calculate the tons p er year of VOC emissions (“ ”).

The results of Equation 2 for each day “r” a nd Equation 5 for each day “s” of the 365-day rolling sum period are summed and converted to tons per y ear as per Equation 6 below. The result of Equation 6 is used to dem onstrate compliance with the HIPA Flare VOC

limit in the consent decree. 

### (  ̇

M VOC

 E mi t 

### )

s



### Q

vg 

### x i



### ( N H V

cz 

### ) j



### ( CE VOC 

### ) j



### ( N H V

cz 

### ) j 

### ( CE VOC 

### ) j



### NHV

cz 

##  

j 

###  95 BTU / scf :

(  ̇

M VOC

 Emit 

### )

s 

###  (  ̇ m VOC

 vg 

### ) j 

###  1

 ( CE VOC 

### ) j 

### /100 

#   

#  

j  1 24 

# 

TPY VO C

 E mi t Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 23 of 54

## APPENDIX 2.5

3 Equation 6

Key to the Abbreviations:

0.16 = CE VOC multiplier for NHV
cz (unitless)

24 = Number of hours in a calendar day (24 hr/d)

95 = NHV cz below which CE VOC empirically correlates to zero (BTU/scf)

385.5 = conversion from pound moles to st andard cubic feet (385.5 lb/scf)

2000 = conversion from pounds to tons (2000 lb/ton)

CE VOC = percent combustion efficiency of VOC in the Vent Gas (%)

i = individual numbered compound from column i in Table 1 of Appendix 1.3 (unitless) j = individually numbered hours in a calendar day with NHV
cz non-compliance (unitless) = mass of VOC emitted for calendar day in NHV
cz compliance (lb/d)

= mass of VOC emitted for calendar day with NHV
cz non-compliance (lb/d)

= calendar day average mass flow rate of VOC in the Vent Gas (lb/hr)

= average mass flow rate of VOC in th e Vent Gas during hour “j” (lb/hr)

MW i = molecular weight of individual compound (lb/lb-mole)

NHV
cz = net heating value of the combustion zone (BTU/scf) Q vg = vent gas volumetric flow rate (scfh)

r

= calendar day when no exceedences of the standard occurred (unitless)

s = calendar day during which exceedence(s) of the standard occurred (unitless)

= mass flow rate of VOC emissions (tons/yr)

VOC = volatile organic compound in the vent gas (unitless)

x i = individual compound volume fraction in the vent gas (volume fraction) 

### TPY VOC

 Emit 

###  (  ̇ M VOC

 Emit 

### )

r 

###  (  ̇ M VOC

 Emit 

### )

s

s 

# 

r 

# 

2000



### (  ̇

M VO C

 E mi t 

### )

r 

### (  ̇

M VOC

 E mi t 

### )

s



###  ̇ m VOC

 v g 

### (  ̇ m VOC

 vg 

### ) j



### N H V

cz 

### N H V

cz 

### TPY VO C

 E mi t Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 24 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.6

MITIGATION PROJECT AT THE NORTH

EFFLUENT TREATER Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 25 of 54

### APPENDIX 2.6

MITIGATION PROJECT: NORTH EFFLUENT TREATER CONTROLS

2.6.1. By the dates set forth herein, SDP shall implement the Environmental Mitigation
Project described in this Appendix 2.6 for the purpose of reducing emissions of hazardous air

pollutants ( "HAPs ") and volatile organic compounds ( "VOCs ") from the North Effluent Treater

at the Covered Facilities.

2.6.2. Definitions

a. "Breakthrough" shall mean, for purposes of monitoring a carbon canister,

any reading equal to or greater than SO ppm VOC or 1 ppm benzene (depending upon the

parameter that SDP decides to monitor).

b. "DAF" shall mean the Dissolved Air Flotation unit that is located at the

North Effluent Treater and marked as such on the schematic attached as Exhibit 1.

c. "Manhole 4 Suxnp" shall mean the manhole at the North Effluent Treater

that is marked as "Manhole 4 Sump" on E~ibit 1.

d. "North Effluent Treater" or "NET" shall mean the wastewater treatment
plant located centrally at the north end of the SDP Refinery and Chemical Plant Facilities. It

treats wastewater from the Covered Facilities using primary, secondary, and tertiary treatment.

Treated water is discharged into the Houston Ship Channel. A plot plan showing the location of

the North Effluent Treater is attached as Exhibit 2.

e. "Trickling Filter Sump" shall mean the sump that is located downstream

of the Trickling Filter at the NET and marked as "Trickling Filter Sump" on Exhibit 1.

f. "Trickling Filter" shall mean the fixed- growth biological treatment unit

that uses aslime- covered stone filter packing to treat effluent from the DAF prior to further
biological treatment in the aeration basins at the NET. The Trickling Filter is marked as such on
E~ibit 1.

2.6.3. Objective. The objective of this Appendix is to reduce VOC emissions from the

Manhole 4 Sump, the DAFs, the Trickling Filter, and the Trickling Filter Sump. SDP requires

further time to study some of the options available to achieve this objective, but this objective

would be thwarted

—and it would be a violation of the terms of this Appendix —if SDP merely

redirected the waste streams) from one or more of these four units to uncovered and/or

uncontrolled waste management unit(s).

2.6.4. Tricklin Fg filter. By no later than December 31, 2019, SDP shall permanently

take the Trickling Filter out of service by physically removing all connections that would allow

the Trickling Filter to be used. SDP shall complete taking the Trickling Filter out of service by
surrendering any permits to operate the Trickling Filter.

App. 2.6 page 1 of 4 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 26 of 54

### APPENDIX 2.6

2.6.5. Manhole 4 Sump and Trickling Filter Sump. By no later than December 31,

2015, SDP shall undertake all necessary modifications to the Manhole 4 Sump and the Trickling

Filter Sump such that each of them conforms to the requirements of 40 C.F.R. § 61.346(a). SDP

also shall install on each of these Sumps a closed vent system and control device that conforms

to the requirements of Paragraphs 2.6.6. and 2.6.7., respectively.

2.6.6. DAF. By no later than December 31, 2019, SDP shall undertake one of the

following actions at the DAF:

a. Undertake all necessary modifications to the DAF such that the DAF

conforms to the requirements of 40 C.F.R. § 61.347. Under this option,

SDP shall install on the DAF a closed vent system and control device that

conform to the requirements of Paragraphs 2.6.7. and 2.6.8., respectively.

b. Replace the DAF with a new dissolved air flotation unit that conforms to

the requirements of 40 C.F.R. § 61.347. Under this. option, SDP shall

install on the new dissolved air flotation unit a closed vent system and

control device that conform to the requirements of Paragraphs 2.6.7. and

2.6.8., respectively.

c. Remove the DAF permanently from service. If SDP elects to use this

option, SDP shall either:

Send the waste stream off -site, by means of a hard -piped

conveyance system, to afederally- permitted wastewater treatment

plant; or

ii. Ensure that the waste stream that no longer is directed to the DAF

is transferred to waste management unit that is covered and

controlled in conformance with 40 C.F.R. Part 61, Subpart FF.

2.6.7. Closed Vent System Requirements. For the Manhole 4 Sump, the Trickling Filter

Sump, and the DAF (to the extent it is either retrofitted with controls (¶ 2.6.6.a) or replaced with

a new DAF that is controlled ( ¶2.6.6.b)), SDP shall design, install, operate, and maintain a closed

vent system in conformance with 40 C.F.R. § 61.349(a)(1). The closed vent system shall

conform to all requirements of 40 C.F.R. § 61.349 related to closed vent systems.

2.6.8. Control Device Requirements.

a. General. SDP shall route all vapors from the closed vent systems required

pursuant to Paragraph 2.6.7. to one or more control devices, each of which is designed, installed,

operated, and maintained in conformance with 40 C.F.R. § 61.349(a)(2)(i) or (ii) or (iii). The

control devices) shall conform to all requirements of 40 C.F.R. § 61.349 related to control

devices.

App. 2.6 page 2 of 4 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 27 of 54

### APPENDIX 2.6

b. Carbon Adsorption System. To the extent that SDP installs a carbon

adsorption system as one or more control devices, SDP shall comply with the following

requirements:

i. Dual Canisters. SDP shall install primary and secondary carbon

absorption canisters and operate them in series (the "dual canister"

configuration). SDP may comply with the dual canister
configuration by using a single canister with a "dual carbon bed" if

the dual carbon bed configuration nonetheless allows SDP to be

able to monitor for breakthrough between the primary and

secondary beds consistent with Subparagraph 2.6.8.b.ii.

ii. Monitoring. After installation, SDP shall monitor for breakthrough

between the primary and secondary canisters/beds at times when

there is actual flow to the canisters/beds. Monitoring between the

primary and secondary canisters beds shall occur on a daily basis

or at intervals no greater than 20 percent of the design carbon

replacement interval, whichever is greater. SDP shall monitor the

outlet of the secondary canister/bed on a monthly basis or at its

design replacement interval (whichever is less) to verify the proper functioning of the system.

iii. Replacement. SDP shall replace the original primary carbon

canisterlbed (or route the flow to an appropriate alternative control

device) immediately when breakthrough is detected. The original

secondary carbon canister/bed (or a fresh carbon canister /bed) shall

become the new primary canister/bed and fresh carbon canister/bed

will become the secondary carbon canister/bed. For purposes of

this Subparagraph, "immediately" shall mean eight (8) hours for

canisters/beds of 55 gallons or less; twenty four (24) hours for

canisters/beds between 55 gallons up to 20,000 pounds; and

forty -eight (48) hours for canisters/beds 20,000 pounds or larger.

iv. Maintaining Canister Supplies. SDP will maintain a supply of

fresh canisters/beds at the Covered Facilities at all times.

v. Work Practice. For carbon canisters/beds that are 20,000 pounds

or greater, as soon as breakthrough is detected, SDP shall ensure

that all emissions are vented to the secondary canister/bed and

shall monitor the outlet to the secondary canister/bed on an hourly

basis until the replacement canister is in place.

vi. Notify EPA about Monitored Parameter. In the first report due

under Paragraph 86 after installation of the carbon adsorption

system, SDP shall notify EPA about whether it is monitoring for

breakthrough using 50 ppm VOC or 1 ppm benzene.

App. 2.6 page 3 of 4 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 28 of 54

### APPENDIX 2.6

c. Anv Control Device Other than a Carbon Adsorption System. To the

extent that SDP installs or uses any control device other than or in addition to a carbon

adsorption system to comply with Subparagraph 2.6.8.a (e.g. SDP may install a carbon

adsorption system to control some part of the closed vent emissions and install or use a different

system to control other parts), such device must conform to the requirements of 40 C:F.R.

§ 61.349(a)(2)(i) or (ii) or (iii). In the first report due under Paragraph 85 after SDP has selected

a control device other than a Carbon Absorption System, SDP shall include a detailed description

of the control devices) it has selected, including how and where the device shall be incorporated

into the closed vent system, and a schematic identifying the location(s).

App. 2.6 page 4 of 4 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 29 of 54Exhibit1toAppendix2.6SHELLDEERPARKSITENORTHEFFLUENTTREATERFLOWSCHEMATICOUTFACEHOUSTONSHIPCHANNELCase 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 30 of 54Exhibit2toAppendix2.6SHELLDEERPARKSITENORTHEFFLUENTTREATERAREA4APRIL2013NORTHEFFLUENTTREATERAREA~C~'_"~3~.j.~.O7~~~Ul~ou~'.,,~~:i.::...,:.v\x~,.~_~_~~~~00~~-J~~a..-,~.ao..10;,,~...\..'...,c~~J~,rIk~i~,%}~~0'~Y....~~~~~~a~....k('~tC..``_~[,,;i~>`'-ir.:>:~<>;NORTH~nn❑~:uo~~O~C~nD~~o,~~~~O~O~I~J[;----~~—--LaPort-HoustcHighvraY226Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 31 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.7

MITIGATION PROJECT AT CERTAIN TANKS Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 32 of 54

### APPENDIX 2.7

MITIGATION PROJECT: TANK CONTROLS

Tank Retirements, Retrofits, and Inspection

1. By no later than July 1, 2015, SDP shall take Tanks TOL -912 and TOL -913 permanently

out of service. Tanks TOL -912 and TOL -913 shall be replaced by existing Tanks

TOL -901 and TOL -91 1. Prior to July 1, 2015, Tanks TOL -901 and TOL -911 each shall

be retrofitted with aluminum geodesic domes to mitigate the effect of wind on emissions.

2. By no later than December 31, 2013, Shell shall take Tank TOL -920 temporarily out of

service for inspection. When out of service, SDP shall undertake a full internal inspection and make any repairs necessary to assure that the tank is in good working

order and complies with all applicable regulatory control requirements.

Infrared Gas

- Imaging Program for Tanks Associated with the ACUBEU

3. "ACU" shall mean the Aromatics Concentration Unit. "BEU" shall mean the Benzene
Extraction Unit. For the purpose of this Mitigation Project, "Tanks Associated with the

ACUBEU" or "Tanks" shall mean all tanks that receive or supply benzene or
benzene

- containing material from/to the ACU or BEU and are located within the tank

farm denoted by "Aromatics Tank Farm" on the plot plan attached as Exhibit 1 to Appendix 2.7. As of the Date of Lodging of this Consent Decree, the "Tanks Associated

with the ACU

/BEU" are as follows:

Tank Service

D370 Benzene Service

D380 Benzene Service

D381 Benzene Service

D371 Benzene Service

L306 Benzene Service

D351 Benzene /Toluene Service

D352 Benzene /Toluene Service

J313 Benzene- Containing Service

D353 Benzene

- Containing Service

D377 Reformate

D379 Refortnate

J312 Heavy Naphtha

J314 Benzene

- Containing Service

D350 Benzene /Toluene Service

L305 Benzene /Toluene Service

4. During the life of this Consent Decree, the Tanks Associated with the ACUBEU may change (e.g., tanks may be retired, taken out of ACUBEU service, or added to

ACUBEU service). Within 30 days of any such change, SDP shall send a notice to EPA

Page 1 of 5 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 33 of 54

### APPENDIX 2.7

updating the list of Tanks Associated with the ACUBEU. Such a change is not a

material modification of this Consent Decree.

5. Except as provided in the last sentence of this Paragraph, by no later than one month after

the Date of Entry of this Consent Decree, SDP shall commence a

once

- every

- two

- calendar -weeks (i.e., bi- weekly) Infrared Gas

- Imaging Program of the

Tanks Associated with the ACUBEU that are in- service (i.e., when hydrocarbons are in a

tank) using infrared gas

- imaging cameras such as FLIR cameras or their equivalent. The

cameras used in this Program shall be capable of imaging organic gases that absorb

infrared light in approximately the 3.2 to 3.4 micron range, and have an automatic mode

(for thermal contrast and brightness) of gas imaging. For any specific tank, SDP shall not

be required to undertake the infrared gas

- imaging required by this Paragraph during any

time period in which, pursuant to Subparagraph 9.b and the notice required in

Subparagraph 9.e, the tank is being repaired, is being removed from service, or is

removed from service.

6. The Infrared Gas

- Imaging Program will be conducted by trained personnel who maintain

proficiency through regular use of the infrared gas

- imaging camera. Prior to
implementation of the Program, personnel shall receive training in infrared gas

- imaging

camera fundamentals and operation.

7. For the purpose of this Mitigation Project, the concept of "observing emissions" or

"emissions being observed" means any visual indication of organic gases on the screen of

an infrared gas

- imaging camera.

8. Tank Ima~in~.

a. All imaging shall be done with the camera in automatic mode and shall be of all

vents of each tank. Imaging shall be done from the ground and conducted as

close as possible to the vent but at a distance of no more than 50 feet from a vent.

b. During each bi- weekly monitoring period, an initial imaging of each tank shall

take place regardless of whether the tank is filling, drawing down, or static.

i. If the imaging operator does not observe emissions during the initial

imaging, no further imaging of the tank is required in the monitoring

period.

ii. If the imaging operator observes emissions during the initial imaging, SDP

will idle the tank so its contents are static and then reimage the tank. If no

emissions are observed during the static imaging, no further actions are required in the monitoring period.

iii. If emissions are observed during the static imaging, then SDP will proceed

with the requirements under Paragraph 9 of this Mitigation Project.

Page 2 of 5 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 34 of 54

### APPENDIX 2.7

9. Tank Inspection, Repair, and Notification. If emissions are observed during the static

tank imaging, SDP shall:

a. Conduct a visual inspection through manholes and roof hatches of the internal
floating roof, the primary seal, and secondary seals) (if one (or more) is in

service) within 48 hours of the static tank imaging that resulted in emissions being

observed.

b. If, during the inspection required by Subparagraph 9.a., the internal floating roof

is not resting on the surface of the liquid inside the.tank and is not resting on the
leg supports; or there is liquid on the floating roof; or the seals) is(are) detached;

or there are holes or tears in the seal fabric; or there are visible gaps between the

seals) and the wall of the tank, SDP shall repair all the items, or, if one or more repairs cannot be made, shall empty and remove the tank from service within 45

calendar days. If the failures cannot be repaired or the tank cannot be emptied

within 45 calendar days, SDP may utilize no more than 2 extensions of no more

than 30 calendax days each. SDP may utilize an extension of time only if

alternate storage capacity is unavailable.

c. If, during the visual inspection required pursuant to Subparagraph 9.a, none of the

failures described in Subparagraph 9.b are observed, then no further action is
required unless and until the requirements of Subparagraph 9.d are met.

d. Tank Replacement/Dispute Resolution Invocation Requirements.

i. Applicability. The requirements of this Subparagraph apply only when:

(1) SDP has undertaken four static imaging events within a 26 -week
period after the tank returns to service following a repair made

pursuant to Subparagraph 9.b;

(2) During each of those four events, emissions are observed
(Subparagraph 8.b.iii applies); and

(3) During each of the follow -up visual inspections to those four

events, no repairs are made pursuant to the timeframes in
Subparagraph 9.b.

ii. Tank Replacement/Dispute Resolution Invocation. If the applicability
requirements in Subparagraph 9.d.i are met, SDP must either:

(1) Replace the tank, in which case, SDP shall replace the tank by no
later than two years after the inspection triggering the replacement
requirement occurs; or

Page 3 of 5 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 35 of 54

### APPENDIX 2.7

(2) Invoke dispute resolution. Prior to invoking the dispute resolution
provisions of Section XII.A, SDP informally shall consult with

EPA for a period not to exceed 60 days. Thereafter, if the dispute

remains, SDP shall invoke the dispute resolution provisions of

Section XII.A. In any such dispute, SDP shall bear the burden of
demonstrating by substantial evidence that new, changed, or previously unknown circumstances or information render it very likely that if the tank were returned to service without being

replaced, emissions would not be observed from the tank for at

least 13 bi- weekly imaging events. For the duration of this

Consent Decree, SDP shall be entitled to invoke dispute resolution

on any tank only one time.

iii. Interim Period. Within 105 days after the inspection that triggers this

Subparagraph occurs: (1) SDP shall use best efforts to identify alternate

tank capacity that can be used continuously until the replacement tank is

available; or (2) if alternate tank capacity cannot be identified, SDP shall

submit a plan to EPA to minimize, to the extent practicable, the use of the

tank until the replacement tank is available. If (1) applies, SDP shall use

the alternate capacity until the replacement tank is available. If

(2) applies, SDP shall implement the plan.

e. SDP shall notify EPA in writing of the discovery of a tank failures) (as described

in paragraph 9.c.) within 30 days. Such notice shall describe in detail the tank

failure and SDP's detailed plans regarding repair of the tank and/or emptying of

the tank.

f. Within 10 days of the end of the origina145 day repair period and within 7 days

of the end of the first 30 day extension, SDP shall notify EPA in writing of a
decision to utilize an extension of time. Documentation of a decision to utilize an
extension shall include the reasons for the extension, an explanation about the
unavailability of alternate storage capacity, and a schedule of actions that will

ensure that the tank will be repaired or the tank will be emptied as soon as practical.

g. After completion of the repairs done pursuant to subparagraph 9.b., SDP shall reimage the tank as verification that the tank is in good working order and complies

with all applicable regulatory control requirements.

10. In each Semi

- Annual Report required pursuant to Section IX of this Consent Decree,

SDP shall include a narrative description of the infrared gas- imaging done pursuant to

this Mitigation Project, including but not limited to:

a. A certification that all Tanks Associated with the ACUBEU that were in- service

(i.e., that had hydrocarbons in the tank) at the time of the monitoring were
monitored in compliance with the terms of this Mitigation Project; an

Page 4 of 5 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 36 of 54

### APPENDIX 2.7

identification of each Tank Associated with the ACUBEU that was not monitored, including an identification of how many bi- weekly monitoring

events) were not undertaken for the tank; and a certification that the Tanks

Associated with the ACUBEU that were not monitored during any monitoring

event were not in- service (i.e., did not have hydrocarbons in the tank)

.

b. A record of the camera operator, date, time, weather conditions, tanks imaged,

and a written summary of the results (including identification of individual vent

and /or emission point locations). A notation should be made if a planned imaging

was not completed due to inclement weather, worker safety, or Force Majeure.

c. The infrared recordings (10 to 30 seconds) of any emissions observed during an infrared gas imaging conducted pursuant to this Mitigation Project.

d. A record of what was done in response to the observation of emissions, including inspection results and repairs.

Page5of5 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 37 of 54Exhibit1toAppendix2.?SHELLDEERPARKSITEAROMATICSTANKFARM4APRIL2013v~~~—..~~..,....,,,;,,_:..~w:;,....,.,,.,..:.,,~„~~;•.(~~~..LJ'`::,:;~~~uuuui:'S'.~..-.,,.~rn...._._~~v,.C_.-=o~`0_.:.~s-~~o-:~~a,..,,~\~oo...,.,._..~:...~'•I~~~~..........................:u::,....za:<,..,~..AROMATICSTANKFARMCase 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 38 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.8

MITIGATION PROJECT AT THE ACU AND BEU Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 39 of 54

### APPENDIX 2.8

1 of 4 MITIGATION PROJECT: ACU AND BEU CONTROLS

2.8.1. By the dates set forth herein, SDP sh all implement the Environmental Mitigation Project described in this Appendix 2.8 for the purpose of reducing emissions of hazardous air pollutants (“HAPs”) and volatile organic compounds (“VOCs”) from the Aromatic Concentration Unit (“ACU”) and the Benzene Extraction Unit (“BEU”).

2.8.2. PRV Review

a. By no later than six months after th e Date of Entry of this Consent Decree, SDP shall retain a third-party to undertake a review of the pressure relief valves (“PRVs”) in the ACU and BEU. Using the leak de tection and repair (“LDAR”) data base that is the most current

one for the SDP Chemical Plant at the time th is action is undertaken, as well as any other necessary documents ( e.g. , piping and instrumentation draw ings, HON semi-annual reports), the third-party shall identify each pressure relief valve (“PRV”) in the ACU and BEU and shall review the operational parameters of, and applicable regulatory requirements for, each PRV. The third-party shall make at least the following determinations:

(1) Location of the PRV

(2) Size of the PRV

(3) “State” of the process fluid in contact with the PRV ( e.g. , gas/vapor, light liquid, heavy liquid)

(4) Whether the PRV is in vacuum service

(5) Whether the PRV vents to the atmosphere

(6) Appropriate monitoring frequency for the PRV

(7) Appropriate monitoring method(s) for the PRV ( e.g. , Method 21, audio/visual/olfactory)

(8) Each regulatory requirement applicable to the PRV

b. After completing its review, the thir d-party shall meet w ith SDP to discuss its determinations. The third-party and SDP shall make final decisions regarding each applicable regulatory requirement for each PRV. By no later than twelve months af ter the Date of Entry, SDP shall update its LDAR database as necessary to accurately reflect the final decisions made.

2.8.3. DTM and UTM Review

a. By no later than six months after th e Date of Entry of this Consent Decree, SDP shall retain a third-party to underta ke a review of SDP’s designations of “difficult-to-monitor” (“DTM”) and “unsafe-to-m onitor” (“UTM”) pieces of equipment in the Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 40 of 54

### APPENDIX 2.8

2 of 4 ACU and BEU. Using the LDAR database that is the most current one for the SDP Chemical Plant at the time this action is undertaken, as well as any other necessary documents ( e.g. , piping and instrumentation drawings, HON semi-annual re ports), the third-party shall identify each component that SDP lists as DTM and UTM in the ACU and BEU and shall review whether each such DTM and UTM designation is appropriate based on the applicable regulations for the

component.

b. After completing its review, the thir d-party shall meet w ith SDP to discuss its determinations. The third-party and SDP sha ll make final decisions regarding each DTM and UTM designation. By no later than twelve months after the Date of En try, SDP shall update its LDAR database as necessary to accurat ely reflect the final decisions made.

2.8.4. Comparative Monitoring

a. In a time period that is sufficient to enable SDP to meet the reporting requirements in Subparagraph 2.8.4.d and to try to meet the goal in the last sentence of Subparagraph 2.8.4.c, SDP shall retain a third-part y to undertake comparative monitoring of the ACU and BEU. In undertaking the requi red monitoring, the third-party shall:

i. Calculate a Comparative Monitoring Leak Percentage . The third-party shall calculate a leak percentage for the ACU and a leak percentage for the BEU, broken down by component type ( e.g. , valves, pumps, connectors, etc. ).

ii. Calculate the Historic, Average Leak Percentage from Prior Periodic Monitoring Events . The third-party shall calculate the historic, average leak percentage from prior periodic monitoring events in the ACU and BEU, broken down by component type ( e.g. , valves, pumps, connectors, etc. ) but excluding pieces of equipment that were DTM and UTM during the monitoring periods used. The following number of complete monitoring periods immediately preceding the third-party’s comparative monitoring shall be used for this purpose:

Valves (including pressure relief valves) 4 periods Pumps and Agitators 12 periods Connectors 2 periods

iii. Calculate the Comparative Monitoring Leak Ratio . For the ACU and the BEU, the third-party sh all calculate the ratio of the Comparative Monitoring Leak Pe rcentage (from Paragraph 2.8.5.a) to the Historic, Average Leak Pe rcentage (from Paragraph 2.8.5.b).

This ratio shall be called the “Comparative Monitoring Leak Ratio.” If, in calculating this ratio, the denominator is “zero,” it

shall be assumed that one leak ing piece of equipment was found Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 41 of 54

### APPENDIX 2.8

3 of 4 through routine monitoring during the period before the comparative monitoring took place.

b. Comparative Monitoring Leak Ratio Report . In a time period that is sufficient to enable SDP to meet the reporting requirements in Subparagraph 2.8.4.d and to try to meet the goal in the last sentence of Subparagr aph 2.8.4.c, the third-party shall submit a report to SDP that identifies the Comparative Monitori ng Leak Ratios, broken down by component type, in the ACU and in the BEU. For any Comparativ e Monitoring Leak Ratio that is 3.0 or higher

and where the Comparative Monitoring Leak Percentage is greater than or equal to 0.5, the third-party shall provide its opinion about possible cau ses and corrective actions.

c. Preliminary Corrective Action Plan (“Preliminary CAP”) . In a time period that is sufficient to enable SD P to meet the reporting requirements in Subparagraph 2.8.4.d and to try to m eet the goal in the last sent ence of this Subparagraph 2.8.4.c, SDP shall develop a preliminary correction actio n plan for any Comparative Monitoring Leak Ratio that is 3.0 or higher and where the Comparative Monitori ng Leak Percentage is greater than or equal to 0.5. The preliminary CAP shall de scribe the actions that SDP has taken or shall take to identify and address the causes of the high Comparative Monitoring Leak Ratio(s). SDP shall include a schedule by which corrective actions that have not yet been completed shall be completed. SDP shall complete each corrective ac tion as expeditiously as practicable with the goal of completing each action by no later than twelve months after the Date of Entry.

d. Submission of Final CAP to EPA . In the first semi-annual report under

Section XI of this Decree that is due no sooner than twelve months afte r the Date of Entry, SDP shall submit a final CAP to EPA, together with a certification of comp letion of each item of corrective action. If any item of corrective action is not completed at the time of the submission of this Final CAP, SDP shall explain the re asons, together with a schedule for prompt completion. SDP shall then submit a supplementa l certification of comp letion those items of corrective action in the semi-annual report that is due for the period in which the action(s) was(were) completed.

2.8.5. Qualifications of Third-Party . For any actions in this Appendix 2.8 that must be undertaken by a “third-party,” SD P shall retain a company/cons ultant that has significant experience conducting LDAR compliance eval uations and Method 21 monitoring. The company/consultant must be a company different than the SDP Chemical Plant’s regular LDAR

contractor.

2.8.6. Dual Mechanical Seals on Pumps . By no later than two years after the Date of Entry of this Consent Decree, SDP shall upgrade the following two pumps in the BEU with a dual mechanical seal system that meets all of the requirements of 40 C.F.R. § 63.163(e)(1)-(3): (1) G/0 PMP DP-2206 (E Sde of Ves V-900) (LDAR tag P0071); and (2) G/0 PMP DP-2207 (E Sde of Ves V-900) (LDAR tag P0070). Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 42 of 54

### APPENDIX 2.8

4 of 4 2.8.7. FLIR Camera Protocol

.

a. By no later than one month after the Da te of Entry of this Consent Decree, SDP shall commence an Infrared Gas-Imaging Progr am of the ACU and BEU using infrared gasimaging cameras such as FLIR cameras or their equivalent. The cameras used in this Program shall be capable of imaging organic gases that ab sorb infrared light in approximately the 3.2 to 3.4 micron range, and have at leas t a high-sensitivity mode (enhan ced detection) and automatic mode (for thermal contrast a nd brightness) of gas imaging.

b. The Infrared Gas-Imaging Program sha ll be conducted by trained personnel who maintain proficiency through re gular use of the infrared ga s-imaging camera. Prior to implementation of the Program, personnel shall recei ve training in infrared gas-imaging camera use and operation.

c. All ground level imaging shall be conducte d at a distance of no more than 50 feet from the imaging target.

d. For the purpose of this Appendix, the c oncept of “observing excess emissions” or “excess emissions being observed” means any visual indication of organic gases on the screen of

an infrared camera.

e. Observed excess emissions will mon itored using Method 21. Components that exceed regulatory requirements will be repair ed consistent with existing regulations.

f. Infrared Gas-Imaging monitoring fre quency for equipment that contains VOCs greater than 5% shall be as follows:

i. Pumps – every two weeks ii. Atmospheric PRV’s – every two weeks iii. Valves – once per month iv. Connectors – once per quarter Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 43 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.9

FENCE LINE MONITORING SUPPLEMENTAL

ENVIRONMENTAL PROJECT Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 44 of 54

### APPENDIX 2.9

SCOPE OF WORK FOR THE SUPPLEMENTAL ENVIRONMENTAL

PROJECT: FENCE LINE OPEN -PATH MONITORING

( "AIR MONITORING SOW ")

Objectives

This Supplemental Environmental Project ( "SEP ") entails: (i) using an open -path

ambient air monitor to measure and record benzene concentrations in the ambient

air at the Covered Facilities' southeast fence line; (ii) using a Meteorological

Station to record weather variables simultaneously with pollutant measurements;

and (iii) responding with corrective actions to abate emissions.

Definitions

2. The following terms shall be defined as follows for the purposes of this Air Monitoring SOW:

"Air Monitoring System" or "AMS" shall mean a system consisting of one iJV DOAS Analyzer, one optical fiber multiplexer, two emitter telescopes,

and two receiver telescopes on the Covered Facilities' southeast fence
line, and a co- located Meteorological Station. These instruments shall be configured so that the emitter and receiver telescopes create two 300 meter paths in an east

-west orientation; the Analyzer shall alternate

measurements between the two paths on an hourly basis by means of an optical fiber multiplexer.

"Data Acquisition System" or "DAS" shall mean acomputer -based data

collection system that collects, organizes, and presents the data collected by the AMS.

"Field Investigation" shall mean the investigatory process by which Shell

Deer Park ( "SDP ") attempts to determine all potential causes) of a Screening Condition.

"Infrared Camera" shall mean an organic gas

- imaging camera.

"Investigation Team" shall mean one or more SDP employees or

contractors that conduct Field Investigations in response to a Screening

Condition. SDP shall ensure that members of the Investigation Team,

before conducting a Field Investigation, have received appropriate training

necessary to enable the team members to tarty out their responsibilities on
the Investigation Team.

"Meteorological Station" shall mean a station that includes: (i) a 2 -axis

sonic anemometer for measuring wind speed and direction; and (ii) temperature and barometric pressure sensors for standardizing gas

Page 1 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 45 of 54APPENDIX 2.9

concentration data to volumetric (ppbV) concentrations. The Meteorological Station shall be connected to the DAS. The data averaging

for the wind speed, wind direction, temperature, and barometric pressure
shall be timed to be contemporaneous with the 5- minute average gas concentration measurements taken by the UV DOAS Analyzer. The Meteorological Station shall be located away from structures so that wind
speed and direction measurements are representative of the measurement
site.

"Multiplexer" shall mean a device used to connect two optical paths to a single UV DOAS Analyzer and to switch the measurements between one path and the other.

"Portable PIDs" shall mean portable photo

- ionization detectors. For

purposes of this SOW,

Portable PIDs shall have a minimum sensitivity of

10 ppbV for organic gases measured as isobutylene.

"ppbV" shall mean parts per billion by volume normalized to standard

temperature and pressure.

"Screening Condition" shall mean SDP Relevant Data that consists of

either: (i) three or more 5- minute benzene concentration data points as
measured by the AMS within any one -hour period that are each 15 ppbV

or greater, provided that the five

- minute average wind direction

measurements, taken contemporaneously with the three benzene

concentrations of 15 ppbV or greater within any one -hour period, are all

within a range of no more than 40 degrees azimuth when concentration is
plotted against the wind direction; or (ii) any one 5- minute benzene data point as measured by the AMS that is greater than 50 ppbV.

"SDP Relevant Data" shall mean: (a) the 5- minute average benzene data. points collected during periods when the wind direction was from 270 to

360 degrees; and (b) all wind speed and direction data.

"Toxic Vapor Analyzer" or "TVA" shall mean a portable flame

- ionization

detector suitable for use in performing EPA Method 21.

"UV DOAS Analyzer" shall mean an open -path ultraviolet differential optical absorption spectrometer that uses the unique absorption by

chemicals of specific wave lengths in the ultraviolet spectrum to identify

and quantify individual chemicals in the ambient air. For the purposes of

this SOW, the LTV DOAS Analyzer shall be capable of achieving a detection limit of 3 ppbV for benzene and shall generate a data point for

average benzene concentration every 5- minutes. The 5- minute data point

for benzene shall represent an average of discreet data points collected during the 5- minute averaging period.

Page 2 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 46 of 54APPENDIX 2.9

Minimum Equipment Requirements

3. In order to implement this SEP, SDP shall maintain in good working, order at the

Covered Facilities at least all of the following systems and equipment for the

duration of this SEP:

a. The A~VIS;

b. The DAS; and

c. Two Infrared Cameras, two Portable PIDs, and two TVAs.

AMS Equipment Configuration and Data Collection Requirements

4. The UV DOAS Analyzer shall be installed such that the optical paths it measures

have a generally east -west orientation as per the location identified in Exhibit 1 to

this Appendix.

5. The UV DOAS Analyzer shall be connected to a DAS that shall integrate the gas
concentration and meteorological data in order to show the gas- concentrationwind- direction correlations during any hour in which a Screening Condition

occurs.

6. The Meteorological Station shall be located neax the optical paths measured by

the AMS. The wind sensors (i) shall be located on a 10 meter mast unless
adjustments are required due to obstructions from the overpass located next to the

fence line, and (ii) shall, to the extent practicable, be positioned away from, or
above, obstructions such as buildings and process units that may interfere with

wind direction measurements.

7. All numerical data. collected for the duration of this SEP shall be stored and

maintained in a format that can be used in common spreadsheet programs.

Field Investigation

— Minimum Requirements

8. Upon the occurrence of a Screening Condition, SDP shall begin a Field
Investigation as soon as possible but no later than 24 hours after the Screening

Condition. At a minimum, the Field Investigation shall include a review of the

data from the AMS and relevant operational data. from the Facility to locate the
potential sources) from which the emissions originated.

9. Upon identifying the general areas) from which the emissions originated, SDP

shall deploy an Investigation Team to the area(s). The Investigation Team shall

survey potential sources of the emissions by conducting a monitoring survey using Portable PIDs and Infrared Cameras. Infrared Cameras shall be used in
high sensitivity mode Leve12. Method 21 monitoring will be conducted on leaks

identified by the Portable PIDs and Infrared Cameras. Confirmed emissions

Page 3 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 47 of 54APPENDIX 2.9

sources that exceed regulatory requirements shall be repaired as soon as practicable. First attempt at repair of the confirmed emissions sources shall occur

no later than 5 days from the date of source identification by the Investigation

Team. Assessment of tanks shall be consistent with the protocols for tank
monitoring in Appendix 2.7 of this Consent Decree.

Compliance Status Determination and Corrective Action

10. By no later than 14 days after identifying, through a Field Investigation, a

benzene- emitting sources) that caused or contributed to a Screening Condition,

SDP shall determine whether the source is or was in violation of any applicable

federal, state, or local regulations or permit requirements. SDP shall implement,

as soon as practicable, corrective action to address any past or present noncompliance.

11. If the compliance status determination in Paragraph 10 reveals that an identified

sources) of benzene is not in violation of any applicable regulation or permit
requirement, SDP shall evaluate the feasibility of reducing the emissions of

benzene from that source in order to minimize the potential recurrence of a future
Screening Condition from that source. In the Semi

- Annual Reports required

pursuant to this SOW, SDP shall describe in detail the evaluation that it took and
identify any reduction measures considered, taken, and/or rejected.

Plans, Reports, and Schedule

12. No later than 120 days after the entry of this Consent Decree, SDP shall submit in
writing to EPA for review and approval an Air Monitoring Response Plan for the
Facility. This Plan shall include, but not be limited to:

a. A detailed description of the systems and equipment to be installed and
operated to implement this SOW. The systems and equipment shall be

consistent with the requirements set forth in Paragraphs 3 through 6 of this

SOW.

b. A QAPP that SDP shall implement to ensure the accuracy, validity,
representativeness, and usability of the data obtained by all monitoring
equipment, including the AMS, portable PIDs, TVAs, and Infrared

Cameras. The QAPP shall comply with the guidelines available in the
following publication: "EPA Requirements for Quality Assurance Project

Plans, EPA QA/R -5, March 2001."

Detailed standard operating procedures to be used during Field
Investigations.

d. A schedule —with a start date contingent upon approval of the Air
Monitoring Response Plan —for expeditiously purchasing, installing and

Page 4 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 48 of 54APPENDIX 2.9

commencing operation of the AMS, the DAS, the two Infrared Cameras,

the two Portable PIDs, and the two TVAs

.

13. After EPA has completed its review and approval of the Air Monitoring Response
Plan, EPA shall send notice of its approval by certified mail, return receipt
requested, to the individuals listed for SDP in the Notice Section of this Consent

Decree. The "date of approval" of SDP's Air Monitoring Response Plan shall be

three days after the date of EPA's mailing.

14. SDP shall purchase or lease the equipment specified in the approved plan in

accordance with the schedule in the approved plan.

15. SDP shall complete the installation of all equipment specified in the Air Monitoring Response Plan in accordance with the schedule in the approved. plan.

SDP shall promptly notify EPA when all of the specified equipment has been

installed. SDP shall not move the AMS to a new location without prior written
approval by EPA. Movement of AMS components for maintenance shall not be

restricted by this paragraph.

16. SDP shall commence operation of all monitoring equipment specified in the Air Monitoring Response Plan in accordance with the schedule in the approved plan.

17. No later than 180 days after the AMS is operational, SDP shall begin conducting

Field Investigations into all Screening Conditions.

18. SDP may seek EPA approval to modify the Air Monitoring Response Plan at any time during the effective period of this Consent Decree.

19. SDP shall submit Air Monitoring Semi

- Annual Reports to EPA that contain the following information:

a. In spreadsheet format, all data collected by the AMS. Data. shall include

time

- synchronized concentration data and meteorological data which shall

be presented in contiguous columns on the spreadsheet. The first two

columns of each sheet shall be the date and time.

b. A detailed summary of each Field Investigation including:

i. The pertinent data collected during the Field Investigation, including but not limited to: (a) measurement data collected by the

AMS, (b) recorded emissions imaged by the Infrared Cameras,
(c) portable PID data.; (d) TVA data; and (e) process data related to

the Investigation.

Page 5 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 49 of 54APPENDIX 2.9

ii. A detailed description of any actions taken by SDP to bring

sources into compliance and/or to reduce emissions in response to

the findings of a Field Investigation.

c. The calibration, maintenance, and other QA/QC results prepared pursuant

to the QAPP for all monitoring equipment required under this SEP.

d. In the period before the AMS is fully operational, SDP shall report on the

progress toward implementing this SEP.

20. The Air Monitoring Semi

- Annual Reports shall be submitted contemporaneously

with the Semi

- Annual Reports due under Paragraph 85 of the Decree with the first

Air Monitoring Semi

- Annual Report due on the first reporting date that occurs

more than three months after the approved date for commencement of the
operation of the AMS. The Air Monitoring Semi

- Annual Report shall be certified

in accordance with Paragraph 89 of the Consent Decree.

21. SDP shall post the Air Monitoring Semi

- Annual Reports on the Internet, with any

confidential information redacted, at that same time as submission to EPA.

22. On a calendar week basis, SDP shall post to a publicly available Internet site the

SDP Relevant Data for the prior week. SDP shall post the SDP Relevant Data for

each calendar week no later than the last day of the following calendar week. The

data shall be presented in form that allows the benzene, wind speed, and wind

direction data to be viewed concurrently, i.e., in a tabular format.

23. On a calendar week basis, SDP shall e -mail the AMS and Meteorological Station

data that does not meet the definition "SDP Relevant Data" for that week to Cary

Secrest of EPA HQ (secrest.carvna,e~a.gov) and Dorothy Crawford of EPA
Region 6 (crawford.dorothy(u~epa. o~v). SDP shall e -mail the data for a calendar

week no later than the last day of the following calendar week. The data shall be

presented in form that allows the benzene, wind speed, and wind direction data. to

be viewed concurrently, i.e., in a tabular format.

24. SDP shall be required to correct deficient performance with the terms of this

SOW. Any disputes related to this SOW shall be resolved pursuant to the

procedures set forth in Section XII of this Consent Decree.

25. SDP shall comply with all terms of this Air Monitoring SOW and terms of the Air

Monitoring Response Plan for a period of two years starting with the date that

Field Investigations are required pursuant to Paragraph 17 above.

26. SDP shall submit to EPA a completion report on this SEP ( "SEP Completion

Report ") at the time specified in Paragraph 81 of the Consent Decree. In addition

to the information required in Paragraph 81, the SEP Completion Report for this

SEP shall include: (i) the same information required in an Air Monitoring

Page6of7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 50 of 54APPENDIX 2.9

Semi

- Annual Report; (ii) a summary of violations identified in the process of
implementing this SEP; and (iii) a summary of physical, process, and/or
operational changes made as a result of implementing this SEP.

Page 7 of 7 Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 51 of 54Exhibit1toAppendix2.9SHELLDEERPARKSITEFENCELINEMONITORING12APRIL2013/~;-~~UNORTH1,:,,.>,~~~~D~~~~~~D~~~li~.`'.~~~~`C,.~~,,-~~f~o,,~~C~~,....o~C~C~oo~0~o~.DD00..S,;,~000~,~°~°~,,.~~a~_~~~00...,z....D°oa~~~\._.~,,.....,..,.:-t'.i::...c..~i.:...:s_::,.:,rl~ri::...;,:::~z~.~l_~__'C_._r~~~~~I~~IC;:kti1RANSMITTER'~~~ULr's225T1iAN5MITTER~Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 52 of 54UNITED STATES

v. SHELL OIL COMPANY, ET AL

.



## APPENDICES TO CONSENT DECREE



# APPENDIX 2.10

DIESEL RETROFIT SUPPLEMENTAL

ENVIRONMENTAL PROJECT Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 53 of 54

### APPENDIX 2.10

Supplemental Environmental Project: Diesel Retrofit

1. SDP shall implement a supplemental environmental project (“SEP”) in accordance with the criteria, terms and procedures specified in this Appendix 2.10 and in Section VIII (Supplemental Environmental Projects).

2. SDP may carry out its SEP responsibilities directly or through contractors selected by SDP. SDP shall ensure that all contractor costs related to the SEP are reasonable and necessary for completion of the SEP.

3. SDP shall spend no less than Two-Hundred Thousand Dollars ($200,000) to implement this SEP, which is to reduce emissions generated by diesel-powered school buses and non-school bus publicly-owned vehicles in the area of SDP’s refinery and chemical plant (“Covered Facilities”) in Deer Park, Texas.

4. All SEP funds shall be spent on the purchase and installation of United States Environmental Protection Agency (“EPA”) and/or California Air Resources Board (“CARB”) verified retrofit and idle reduction technologies. SEP funds creditable toward meeting the minimum $200,000 expenditure shall cover only the hardware and installation cost of retrofit and idle reduction technologies.

5. All SEP funds shall be spent for technologies to be installed on school buses or publicly owned vehicles located within 50 miles of the Covered Facilities and, limited to, and in the order of, the following priorities:

(1) School buses in Harris County (2) Non-school bus publicly owned vehicles in Harris County (3) School buses in Brazoria, Chambers, Fort Bend, Galveston, Liberty, and Montgomery counties (4) Non-school bus publicly owned vehicles in Brazoria, Chambers, Fort Bend, Galveston, Liberty, and Montgomery counties

6. Implementation of this SEP project shall be completed within twenty-four (24) months after the Date of Entry of this Consent Decree.

7. SDP shall seek to coordinate the selection of projects and the funding of projects with relevant and applicable state and local officials where possible, but SDP retains responsibility for performance of the SEP. Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 54 of 54