IN THE UNITED STATES DISTRICT COURT 

FOR THE NORTHERN DISTRICT OF ILLINOIS 

 

 

UNITED STATES OF AMERICA, ) 

STATE OF ILLINOIS, ) 

STATE OF LOUISIANA, and the ) 

STATE OF MONTANA ) 

 ) 

 Plaintiffs, ) 

 ) 

 v. ) 

 ) 

EXXON MOBIL CORPORATION and ) 

EXXONMOBIL OIL CORPORATION ) 

 ) 

 Defendants. ) 

 )

 

Case No. 05 C 5809 

The Honorable Rebecca R. Pallmeyer 

 

 

 

 

 

THIRD AMENDMENT MAKING MATERIAL MODIFICATIONS TO 

CONSENT DECREE

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 1 of 38
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WHEREAS, the Plaintiffs filed a complaint in this matter on October 11, 2005, alleging 

violations of the Clean Air Act, 42 U.S.C. §§ 7401-7671q, and other environmental laws at six 

petroleum refineries owned and operated by Defendants Exxon Mobil Corporation and 

ExxonMobil Oil Corporation (collectively referred to herein as “ExxonMobil”), and the United 

States thereafter lodged a proposed Consent Decree between the Plaintiffs and the Defendants. 

 WHEREAS, the Court approved and entered the Consent Decree on December 13, 2005 

(hereinafter the “2005 Consent Decree”). 

 WHEREAS, the 2005 Consent Decree specified that the Court would retain continuing 

jurisdiction for the purpose of enforcing and modifying the Decree. 

 WHEREAS, Paragraph 269 of the 2005 Consent Decree provides that any material 

modifications to the Decree shall be in writing, shall be signed by the U.S. Environmental 

Protection Agency (“EPA”), the Applicable Co-Plaintiff, and ExxonMobil, and shall be effective 

upon approval by the Court. In contrast, non-material modifications do not require Court 

approval, although Paragraph 269 of the 2005 Consent Decree specifies that non-material 

modifications shall be filed with the Court after being executed by EPA and ExxonMobil. 

 WHEREAS, EPA and ExxonMobil previously agreed to two stipulated non-material 

modifications to the 2005 Consent Decree, which were filed with the Court on June 1, 2006 and 

November 13, 2007. 

 WHEREAS, the parties to this Third Amendment Making Material Modifications to 

Consent Decree (the “Third Decree Amendment”) have agreed to certain material modifications 

to the 2005 Consent Decree, as set forth herein. Unlike the two prior non-material modifications, 

Court approval is required for these material modifications. The modifications address certain 

injunctive obligations relating to ExxonMobil’s refineries in Billings, Montana, Beaumont, 

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Texas, and Joliet, Illinois, so the State of Montana and the State of Illinois are parties to this 

agreement, as Applicable Co-Plaintiffs, along with the United States and ExxonMobil 

(collectively, the “Parties”). 

 WHEREAS, as specified herein, this Third Decree Amendment affords ExxonMobil 

additional time to install certain air pollution control equipment that is required by the 2005 

Consent Decree in exchange for ExxonMobil’s commitment to implement additional injunctive 

relief, including accelerating installation of other air pollution control equipment and taking 

certain other steps to reduce air pollutant emissions from its refineries. The additional injunctive 

relief under this Third Decree Amendment will yield emissions reductions that will more than 

offset any excess emissions during the time extensions afforded by this Third Decree 

Amendment. 

 WHEREAS, for the sake of clarity, this Third Decree Amendment restates and 

incorporates the changes made by the two prior non-material modifications to the 2005 Consent 

Decree. This Third Decree Amendment also makes certain other minor and conforming changes 

to the 2005 Consent Decree. 

 WHEREAS, the Parties recognize, and the Court by entering this Third Decree 

Amendment finds, that this Third Decree Amendment has been negotiated at arms-length and in 

good faith and that this Third Decree Amendment is fair, reasonable, and in the public interest. 

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

issue of fact or law, and upon the consent and agreement of the Parties, it is hereby ORDERED, 

ADJUDGED and DECREED as follows:

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AMENDED AND RESTATED CONSENT DECREE PROVISIONS

 The 2005 Consent Decree shall remain in full force and effect in accordance with its 

terms, except that Paragraphs 14, 15, 17, 18, 20, 29, 30, 72, 143, 145, 166, 167, 237, 250, and 

266, and Appendices C, D, and G are revised as set forth below and shall become effective no 

later than December 31, 2008, if entered by this Court. 

* * * * 

 14. NOx Emissions Control for the Beaumont FCCU. 

 a. NOx Control System. By no later than April 1, 2008, ExxonMobil shall 

control NOx emissions from the Beaumont FCCU by installing and operating a SCR system for 

the FCCU. ExxonMobil presently intends to control NOx emissions from the Beaumont FCCU 

by: (i) installing and operating a Thermal DeNOx system; (ii) installing and operating CO boiler 

low-NOx burners; and/or (iii) shifting the FCCU to a lower CO operation mode. ExxonMobil 

shall use best efforts to design the NOx control system to attain 50 ppmvd NOx or less (at 0% O2

on a 365-day rolling average basis) and 100 ppmvd NOx or less (at 0% O2 on a 7-day rolling 

average basis); provided, however, that ExxonMobil shall not be required to design the control 

system in a manner that creates a safety problem or impairs unit feed rate, conversion, feed slate 

or yield selectivity. Nothing in this Subparagraph 14.a shall be deemed to limit ExxonMobil’s 

ability to implement or use additional NOx reducing measures.

 b. Final NOx Limits. By no later than July 1, 2009, ExxonMobil shall 

comply with NOx emission limits of 50 ppmvd at 0% O2 on a 365-day rolling average basis and 

100 ppmvd at 0% O2 on a 7-day rolling average basis at the Beaumont FCCU. 

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(1) The long-term Final NOx Limit for the Beaumont FCCU shall be 

set based on application of the provisions in Subparagraph 15.c., and shall be: (i) in the 

range of 50-60 ppmvd NOx (at 0% O2 on a 365-day rolling average basis); and (ii) as 

close to 50 ppmvd as practicable. ExxonMobil shall comply with the long-term Final 

NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 

15.c.

(2) The short-term Final NOx Limit for the Beaumont FCCU shall be 

set based on application of the provisions in Subparagraph 15.c., and shall be: (i) in the 

range of 100-120 ppmvd NOx (at 0% O2 on a 7-day rolling average basis); and (ii) as 

close to 100 ppmvd as practicable. ExxonMobil shall comply with the short-term Final 

NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 

15.c.

 c. Interim NOx Control Measures. Beginning April 1, 2008, ExxonMobil 

shall use best efforts to minimize NOx emissions from the Beaumont FCCU by minimizing 

supplemental firing to the CO Boiler and/or by minimizing FCCU regenerator outlet CO to the 

full extent without adversely impacting FCCU feed rate, conversion, feed slate, or yield 

selectivity, unless reasonable steps can be taken to compensate for such impairment. The 

requirement to perform these Interim NOx Control Measures will remain in effect until the Final 

NOx Limits specified in Subparagraph 14.b become applicable. 

* * * * 

 15. Baton Rouge and Beaumont NOx Minimization StudyStudies. ExxonMobil 

shall complete a 12-month studyies of: (i) the Baton Rouge FCCUs’ NOx control system, by no 

later than 12 months after the Entry Date (the “Baton Rouge NOx Minimization Study”); and (ii) 

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the Beaumont FCCU NOx control system, by no later than July 1, 2009 (the “Beaumont NOx 

Minimization Study”). 

 a. During the each Study, ExxonMobil shall use best efforts to operate the 

FCCU and the NOx control system to achieve emissions as close as practicable to 50 ppmvd 

NOx (at 0% O2 on a 365-day rolling average basis) and 100 ppmvd NOx (at 0% O2 on a 7-day 

rolling average basis); provided, however, that ExxonMobil shall not be required to operate the 

FCCU(s) or the control system in a manner that creates a safety problem or impairs unit feed 

rate, conversion, feed slate or yield selectivity, unless reasonable steps can be taken to 

compensate for such impairment. 

 b. Within 90 days after the completion of the each Study, ExxonMobil shall 

submit a written report to EPA that shall summarize the results of the Study and shall provide 

relevant CEMS data and FCCU feed and operating data on a daily or daily average basis as 

measured directly (where available) or as calculated (where necessary). Upon request by EPA, 

ExxonMobil shall submit any additional, readily available data that EPA determines it needs to 

evaluate the Study. 

 c. Based on the results of the Study, the each Study report shall specify Final 

NOx Limits for the relevant FCCU(s) within the ranges set forth in Subparagraphs 13.b. and 

14.b. ExxonMobil shall specify limits which reflect best efforts to achieve emissions as close as 

practicable to 50 ppmvd NOx (at 0% O2 on a 365-day rolling average basis) and 100 ppmvd 

NOx (at 0% O2 on a 7-day rolling average basis); provided, however, that ExxonMobil shall not 

be required to specify a limit below the upper end of the range that would create a safety problem 

or impair unit feed rate, conversion, feed slate or yield selectivity. 

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 d. If the any limit specified pursuant to Subparagraph 15.c is higher than 

50 ppmvd NOx (at 0% O2 on a 365-day rolling average basis) or 100 ppmvd NOx (at 0% O2 on a 

7-day rolling average basis), then the relevant Study report shall include a plan for making 

supplemental NOx emission reductions from Combustion Units at the Baton Rouge relevant 

refinery, in accordance with the following table: 

Long-Term Limit or Short-Term Limit Additional Required Reductions

 50 ppmvd 100 ppmvd 0 TPY NOx 

 51 ppmvd 101-102 ppmvd 12 TPY NOx 

 52 ppmvd 103-104 ppmvd 26 TPY NOx 

 53 ppmvd 105-106 ppmvd 42 TPY NOx 

 54 ppmvd 107-108 ppmvd 60 TPY NOx 

 55 ppmvd 109-110 ppmvd 80 TPY NOx 

 56 ppmvd 111-112 ppmvd 102 TPY NOx 

 57 ppmvd 113-114 ppmvd 126 TPY NOx 

 58 ppmvd 115-116 ppmvd 152 TPY NOx 

 59 ppmvd 117-118 ppmvd 180 TPY NOx 

 60 ppmvd 119-120 ppmvd 210 TPY NOx 

Such supplemental NOx reductions: (i) shall be in addition to those NOx emission reductions 

from Combustion Units required by Subsection V.G of this Consent Decree, and shall not count 

toward the reductions required by that Subsection; and (ii) shall be quantified, made, and 

incorporated into federally-enforceable permits in a manner consistent with the approach 

outlined in Subsections V.G and V.Q of this Consent Decree. If supplemental NOx reductions 

are required under this Subparagraph, then ExxonMobil’s Study report shall include a definitive 

schedule for making the supplemental NOx reductions, and for submitting a completion report 

documenting the reductions. The schedule shall be subject to EPA approval, which shall not be 

unreasonably withheld. 

* * * * 

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 17. NOx Emissions Control for the Billings FCCU.

 a. NOx Control System. ExxonMobil shall control emissions from the 

Billings FCCU by installing and operating a SCR system for the FCCUpresently intends to 

control NOx emissions from the Billings FCCU by: (i) converting the FCCU to Full Burn 

Operation; and (ii) taking other steps to reduce NOx (which may include, but are not limited to, 

use of a Thermal DeNOx system and/or CO boiler low-NOx burners and/or use of NOx-reducing 

catalyst additive and/or low NOx combustion promoter). 

 b. Interim Final NOx Limits. By no later than June 30, 2009December 31, 

2008, ExxonMobil shall comply with interim NOx emission limits of 40 ppmvd at 0% O2 on a 

365-day rolling average basis and 80 ppmvd at 0% O2 on a 7-day rolling average basis at the 

Billings FCCU.

 c. NOx Reduction Study. 

 (1) By no later than December 31, 2010 ExxonMobil shall complete a 

12-month study of the Billings FCCU SCR system with the objective of establishing a 

final long-term NOx emission limit that is: (i) in the range of 30-40 ppmvd NOx (at 0% 

O2 on a 365-day rolling average basis); and (ii) as close to 30 ppmvd as practicable. 

During the Study, ExxonMobil shall use best efforts to operate the FCCU and the NOx 

control system to achieve emissions as close as practicable to 30 ppmvd NOx (at 0% O2

on a 365-day rolling average basis) or less; provided, however, that ExxonMobil shall not 

be required to operate the FCCU or the control system in a manner that creates a safety 

problem or impairs unit feed rate, conversion, feed slate or yield selectivity, unless 

reasonable steps can be taken to compensate for such impairment. 

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 (2) By February 28, 2011, ExxonMobil shall submit a Report which 

summarizes the results of the NOx Reduction Study and provides all relevant NOx and 

O2 CEMS data and any other data relevant to the Study. Based on the results of the 

Study, the Report shall propose a long-term NOx limit for the Billings FCCU that is 

consistent with the criteria described in Subparagraph 17.c.(1). 

 (3) ExxonMobil shall comply with the long-term emission limit it 

proposes for the Billings FCCU beginning immediately upon submission of the Report. 

ExxonMobil shall continue to comply with that proposed long-term limit unless and until 

ExxonMobil is required to comply with the long-term emission limit set by EPA pursuant 

to Subparagraph 17.d.

 d. Establishment of Final NOx Limits for the Billings FCCU. EPA will use 

the data collected during the Billings FCCU NOx Reduction Study, as well as all other available 

and relevant information, to establish a final long-term limit for NOx emissions from the Billings 

FCCU that is consistent with the criteria described in Subparagraph 17.c.(1). EPA will establish 

a 365-day rolling average concentration-based (ppmvd) NOx emission limit, corrected to 0% 

oxygen, which can be met with a reasonable certainty of compliance. This limit may be the 

same as the limit proposed by ExxonMobil in accordance with Subparagraph 17.c. The interim 

short-term (7-day rolling average) NOx emission limit of 80 ppmvd, corrected to 0% O2, shall 

remain unchanged and shall become the final short-term limit. ExxonMobil may propose, and 

EPA may establish, alternative emissions limits to be applicable during alternative operating 

scenarios. EPA will determine the limit based on: (i) the level of performance during the NOx 

Reduction Study period; (ii) a reasonable certainty of compliance; and (iii) any other available 

and relevant information. EPA will notify ExxonMobil of its determination of the long-term 

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concentration-based NOx emission limit. ExxonMobil shall immediately (or within thirty (30) 

days, if EPA’s limit is more stringent than the limit proposed by ExxonMobil) operate the FCCU 

so as to comply with the EPA-established emission limit. Disputes regarding the appropriate 

emission limit shall be resolved in accordance with the dispute resolution provisions of this 

Decree.

 e.c. Non-Routine Operations. FCCU NOx emissions during a period of 

natural gas curtailment will not be used in determining compliance with the short-term (7-day) 

Final NOx Limit established pursuant to Subparagraph 17.b if Fuel Oil is burned in a combustion 

unit serving the Billings FCCU CO boiler or CO furnace during the period of natural gas 

curtailment. During any such period of natural gas curtailment, ExxonMobil shall comply with 

an alternate short-term NOx emission limit of 120 ppmvd at 0% O2 on 24-hour rolling average 

basis at the Billings FCCU. 

* * * * 

 18. NOx Emissions Control for the Joliet FCCU.

 a. NOx Control System. ExxonMobil presently intends to control emissions 

from the Joliet FCCU by installing and operating a SCR system for the FCCU. 

 b. Final NOx Limits. By no later than December 31, 20102012, ExxonMobil 

shall comply with NOx emission limits of 20 ppmvd at 0% O2 on a 365-day rolling average basis 

and 40 ppmvd at 0% O2 on a 7-day rolling average basis at the Joliet FCCU. 

* * * * 

 20. Startup, Shutdown, and Malfunction. NOx emissions (i) caused by or 

attributable to the startup, shutdown, or Malfunction of an FCCU listed in Subsection V.A and/or 

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(ii) during periods of Malfunction of the relevant FCCU’s NOx Control System will not be used 

in determining compliance with the short-term (7-day) Interim NOx Limits or Final NOx Limits 

established pursuant to Subparagraphs 13.b.(2), 14.b.(2), 16.b, 16.c, 17.b, 17.d, 18.b, and 19.b, 

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

minimize NOx emissions. Nothing in this Paragraph shall be construed to relieve ExxonMobil 

of any obligation under any federal, state, or local law, regulation, or permit to report emissions 

during periods of startup, shutdown, or Malfunction, or to document the occurrence and/or cause 

of a startup, shutdown, or Malfunction event. Emissions during any such period of startup, 

shutdown, or Malfunction shall either be: (i) monitored with CEMS as provided by Paragraph 

21; or (ii) monitored in accordance with an alternative monitoring plan approved by EPA 

pursuant to this Consent Decree if it is necessary to bypass the FCCU’s main stack during the 

particular period of startup, shutdown, or Malfunction. 

* * * * 

 29. SO2 Emissions Control for the Billings FCCU. 

 a. SO2 Control System. ExxonMobil presently intends to control SO2

emissions from the Billings FCCU by: (i) converting the FCCU to Full Burn Operation; and 

(ii) implementing a special two-step protocol using SO2 Reducing Catalyst Additives, as 

summarized below. 

 (1) Step 1. Step 1 of the protocol will commence shortly after the 

Entry Date. Step 1 will require a performance of a short-term trial to identify the 

commercially-available catalyst additive that achieves the greatest SO2 reduction at the 

Required Addition Rate. Once the best-performing additive is identified, ExxonMobil 

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shall use that additive at the Required Addition Rate, except as otherwise required in 

Subparagraph 30.f, whenever the unit is operated, until Step 2 of the protocol. 

 (2) Step 2. Step 2 of the protocol will commence several years after 

the Entry Date. Step 2 will require a performance of another short-term trial to identify 

the future-generation commercially-available catalyst additive that achieves the greatest 

SO2 reduction at the Required Addition Rate. Once the best-performing additive is 

identified, ExxonMobil shall use that additive at the Required Addition Rate during a 

defined demonstration period. 

 (3) Required Addition Rate. For the purpose of this Paragraph 29 and 

Paragraph 30, the term “Required Addition Rate” shall mean addition of 20.0 Average 

Weight % of Total Catalyst Added, unless EPA agrees to a lesser weight % addition rate 

for a particular SO2 Reducing Catalyst Additive based on a demonstration by 

ExxonMobil that a lesser addition rate achieves an equal or greater total reduction in SO2

emissions from the Billings FCCU. The Average Weight % of Total Catalyst Added 

shall be calculated based on the Total Catalyst Addition Rate during the two year baseline 

period from November 2001 to October 2003. As required by this Paragraph 29 and 

Paragraph 30, ExxonMobil shall add SO2 Reducing Catalyst Additive at the Required 

Addition Rate in a manner that minimizes SO2 emissions; provided, however, that 

ExxonMobil shall not be required to use the Additive in a manner that creates a safety 

problem or impairs unit feed rate, conversion, feed slate or yield selectivity, unless 

reasonable steps can be taken to eliminate the problem or compensate for such 

impairment. 

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 b. Final SO2 Limits. The final long-term and short-term SO2 limits for the 

Billings FCCU shall be established by one of two methods, designated as “Option A” and 

“Option B” below. 

 (1) Option A. Under Option A, the final long-term and short-term SO2

limits for the Billings FCCU shall be set pursuant to Subparagraph 30.i based on the 

results achieved during the demonstration period in Step 2 of the SO2 Reducing Catalyst 

Additive protocol. ExxonMobil shall comply with any long-term and short-term Final 

SO2 Limits set under Subparagraph 30.i according to the schedule prescribed by 

Subparagraph 30.i. 

 (2) Option B. Under Option B, ExxonMobil may, at any time up to 

and including its proposing emission limits under Subparagraph 30.h, accept and agree to 

comply immediately with concentration-based SO2 emission limits of 25 ppmvd on a 

365-day rolling average and 50 ppmvd on a 7-day rolling average basis, both at 0% 

oxygen, for the Billings FCCU. In such circumstances, ExxonMobil shall be absolved of 

any remaining obligations for the Billings FCCU under Paragraph 30 of this Consent 

Decree. 

* * * * 

 30. Particular Requirements for the Billings FCCU: Conversion to Full Burn 

Operation and Two-Step SO2 Reducing Catalyst Additive Program. Unless and until 

ExxonMobil selects Option B under Subparagraph 29.b.(2), ExxonMobil shall implement an SO2

emissions control program for the Billings FCCU as specified by this Paragraph. The program 

shall include conversion of the Billings FCCU to Full Burn Operation and implementation of a 

special two-step protocol using SO2 Reducing Catalyst Additives, as described below. 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 13 of 38
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 a. Conversion of Billings FCCU to Full Burn Operation. By no later than 

30 days after the Entry Date, ExxonMobil shall convert the Billings FCCU to Full Burn 

Operation. 

 b. SO2 Baseline Data for the Billings FCCU. By no later than 210 days after 

the Entry Date, ExxonMobil shall submit to EPA and the Applicable Co-Plaintiff a report on the 

baseline period beginning 60 days after the Entry Date and ending 180 days after the Entry Date. 

During that baseline period, the FCCU shall be operated in Full Burn Operation mode, without 

use of SO2 Reducing Catalyst Additives. The Baseline Data Report shall include all relevant 

SO2 and O2 CEMS data and all other data set forth in Appendix H. 

 c. Identification and Selection of SO2 Reducing Catalyst Additives for Trial 

Use and Trial Procedures. By the following dates, ExxonMobil shall select and submit for EPA 

approval a written plan for use of at least three commercially available SO2 Reducing Catalyst 

Additives that ExxonMobil proposes to use for short-term trials at the Billings FCCU. 

 No later than 255 Days after the Entry Date for the Step 1 trials of current- 

 generation SO2 Reducing Catalyst 

 Additives 

 No later than January 15, 2010 for the Step 2 trials of future- 

 generation SO2 Reducing Catalyst 

 Additives 

In the plan for each set of short-term trials, ExxonMobil shall describe, in detail, the trial 

procedures to be used, including but not limited to: (i) the amount of additive to be baseloaded 

into the regenerator; (ii) the method of additive loading; and (iii) the expected timing and 

duration of the trial. Each such plan shall also propose use of at least three specific SO2

Reducing Catalyst Additives that are likely to perform the best at reducing SO2 emissions in the 

FCCU. EPA will base its approval or disapproval of the SO2 Reducing Catalyst Additives on its 

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assessment of the performance of the proposed Additives in other FCCUs and the similarity of 

those FCCUs to ExxonMobil’s Billings FCCU, with the objective of testing SO2 Reducing 

Catalyst Additives likely to have the best performance in reducing SO2 emissions. If EPA 

objects to one or more of the proposed SO2 Reducing Catalyst Additives, or if EPA objects to 

any other aspect of ExxonMobil’s plan, then EPA will explain the basis of its objections in 

writing. In the event that ExxonMobil submits less than three approvable Additives, EPA shall 

identify and by that identification approve the use of other SO2 Reducing Catalyst Additives by 

ExxonMobil. 

 d. Performance of the Short-Term Trials. In each Step of the protocol, 

ExxonMobil shall perform a set of short-term trials in accordance with the plan approved by 

EPA under Subparagraph 30.c. ExxonMobil shall commence and complete the short-term trials 

in accordance with the following schedule: 

 For the Step 1 trials of current-generation SO2 Reducing Catalyst Additives:

 Commencement Date No later than 300 days after the Entry Date 

 Completion Date No later than 480 days after the Entry Date 

 For the Step 2 trials of future-generation SO2 Reducing Catalyst Additives:

 Commencement Date No later than March 1, 2010 

 Completion Date No later than October 1, 2010 

 e. Reports on the Short-Term Trials. For each Step of the protocol, 

ExxonMobil shall submit a written report to EPA describing the performance of each SO2

Reducing Catalyst Additive that was tested in the short-term trials. 

 (1) In each Trials Report, ExxonMobil shall summarize the results of 

the trials and shall provide all relevant SO2 and O2 CEMS data and all other data set forth 

in Appendix H. Each Trials Report shall also summarize any safety problems or 

impairments of unit feed rate, conversion, feed slate, or yield selectivity observed in the 

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trials, and all steps that were taken to attempt to eliminate the problems or compensate for 

such impairments. 

 (2) In each Trials Report, ExxonMobil shall identify the Additive that 

achieved the lowest SO2 concentration, corrected to 0% O2, when averaged over the 

entire trial period and the additive that reduced emissions the most from a predicted 

uncontrolled baseline during the trials (the “Best-Performing Additive”). If EPA 

determines that another Additive tested in the trials was the Best-Performing Additive in 

the trials, then EPA, after consultation with the Applicable Co-Plaintiff, will so notify 

ExxonMobil and ExxonMobil shall treat that Additive as the Best-Performing Additive 

and use it at the specified addition rate in the Step 1 Interim Reduction Period (under 

Subparagraph 30.f) or the Step 2 Demonstration (under Subparagraph 30.g). 

 (3) ExxonMobil shall submit the Trials Reports in accordance with the 

following schedule: 

 For the Step 1 trials of current-generation SO2 Reducing Catalyst Additives:

 Report Due Date No later than 540 days after the Entry Date 

 For the Step 2 trials of future-generation SO2 Reducing Catalyst Additives:

 Report Due Date No later than December 1, 2010 

 f. Step 1 Interim Reduction Period. By no later than 585 days after the Entry 

Date, ExxonMobil shall commence and continue use of the Best-Performing Additive for Step 1 

at the Required Addition Rate, and beginning April 1, 2008 shall commence and continue use of 

the Best-Performing Additive for Step 1 at the Required Addition Rate plus 2.0%; provided, 

however, that ExxonMobil shall not be required to operate the FCCU or use the Additive in a 

manner that creates a safety problem or impairs unit feed rate, conversion, feed slate, or yield 

selectivity, unless reasonable steps can be taken to eliminate the problem or compensate for such 

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impairment. ExxonMobil shall continue using the Best-Performing Additive at the Required 

Addition Rate plus 2.0% until commencement of the Step 2 trials under Subparagraph 30.d. 

 g. Step 2 Demonstration. ExxonMobil shall commence and complete a 

demonstration of the Best-Performing Additive for Step 2 in accordance with the following 

schedule: 

 Commencement Date No later than January 15, 2011 

 Completion Date No later than January 15, 2012 

During the Step 2 demonstration, ExxonMobil shall use the Best-Performing Additive for Step 2 

at the Required Addition Rate and shall operate the FCCU and the CO boiler in a manner that 

minimizes SO2 emissions; provided, however, that ExxonMobil shall not be required to operate 

the FCCU or use the Additive in a manner that creates a safety problem or impairs unit feed rate, 

conversion, feed slate, or yield selectivity, unless reasonable steps can be taken to eliminate the 

problem or compensate for such impairment. Even after completion of the demonstration, 

ExxonMobil shall continue using the Best-Performing Additive at the Required Addition Rate 

until ExxonMobil begins complying with proposed and final SO2 emission limits under 

Subparagraphs 30.h and 30.i. 

 h. Step 2 Demonstration Report. By no later than March 15, 2012, 

ExxonMobil will submit a written report to EPA on the results of the Step 2 Demonstration. In 

the Step 2 Demonstration Report, ExxonMobil shall summarize the results of the demonstration 

and shall provide all relevant SO2 and O2 CEMS data and all other data set forth in Appendix H. 

In the Step 2 Demonstration Report, ExxonMobil shall propose a long-term (i.e., 365-day rolling 

average) and short-term (i.e., 7-day rolling average) concentration-based (ppmvd) SO2 emission 

limits, both as measured at 0% O2, for the Billings FCCU. ExxonMobil shall comply with the 

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emission limits it proposes for the Billings FCCU beginning immediately upon submission of the 

Step 2 Demonstration Report. ExxonMobil shall continue to comply with these limits unless and 

until ExxonMobil is required to comply with the emissions limits set by EPA pursuant to 

Subparagraph 30.i.

 i. Establishment of Final Limits for the Billings FCCU. EPA will use the 

data collected during the Step 2 Demonstration Period, as well as all other available and relevant 

information, to establish long-term and short-term final limits for SO2 emissions from the 

Billings FCCU. EPA will establish 365-day rolling average and 7-day rolling average 

concentration-based (ppmvd) SO2 emission limits, corrected to 0% oxygen, which limits can be 

met with a reasonable certainty of compliance. Such limits may be the same as the limits 

proposed by ExxonMobil in accordance with Subparagraph 30.h. ExxonMobil may propose, and 

EPA may establish, alternative emissions limits to be applicable during alternative operating 

scenarios. EPA will determine the limits based on: (i) the level of performance during the Step 

2 Demonstration Period; (ii) a reasonable certainty of compliance; and (iii) any other available 

and relevant information. EPA will notify ExxonMobil of its determination of the long-term and 

short-term concentration-based SO2 emissions limits. ExxonMobil shall immediately (or within 

thirty (30) days, if EPA’s limit is more stringent than the limit proposed by ExxonMobil) operate 

the FCCU so as to comply with the EPA-established emission limits. Disputes regarding the 

appropriate emission limits shall be resolved in accordance with the dispute resolution provisions 

of this Decree; provided, however, that during the period of dispute resolution, ExxonMobil shall 

use Additive in the manner and amount applicable during the Step 2 Demonstration Period (in 

lieu of meeting the EPA-established limits). 

* * * * 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 18 of 38
18 

 72. Construction and Operation of Upgraded Flare Gas Recovery Systems. 

 a. ExxonMobil currently operates existing flare gas recovery systems at the Baton 

Rouge, Baytown, Beaumont, Billings, and Torrance Refineries. 

 b. By no later than September 30, 201042 months after the Entry Date, 

ExxonMobil will construct and commence operation of enhancements to its existing flare gas 

recovery systems at the Beaumont Refinery. Those enhanced flare gas recovery systems will 

serve certain NSPS Flaring Devices at the Beaumont Refinery, as specified in Appendix G. 

 c. By no later than September 30, 201048 months after the Entry Date, 

ExxonMobil will construct and commence operation of enhancements to its existing flare gas 

recovery system at the Billings Refinery. That enhanced flare gas recovery system will serve 

both the NSPS Flaring Devices at the Billings Refinery that are identified in Appendix G. 

 d. By no later then the Entry Date, ExxonMobil shall construct and 

commence operation of flare gas recovery facilities at the Joliet Refinery pursuant to the IEPA 

Construction Permit for the Joliet Coker Blowdown Recovery Project (Application Number 

03060091). 

* * * * 

 143. Emission Limits and Standards. The following Consent Decree requirements 

shall constitute the emission limits and standards that are required to be incorporated into permits 

under Paragraphs 141 and 142: 

 i. the interim emission limits and standards imposed by Subparagraphs 16.b, 17.b, 

29.a, 30.f, 30.g, and 68.b, for so long as each such interim emission limit or 

standard applies under this Consent Decree; and 

 ii. the requirements specified in Subparagraphs 145.a.(1) through 145.a.(9), that shall 

survive termination of the Consent Decree. 

* * * * 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 19 of 38
19 

 145. Obligations that Shall Survive Consent Decree Termination. The 

requirements imposed by the following provisions of this Consent Decree that shall survive 

termination of the Consent Decree under Section XVIII: 

 a. Emission Limits and Standards. The following Consent Decree 

requirements shall constitute emission limits and standards that shall survive termination of the 

Consent Decree by virtue of being incorporated into federally-enforceable permits: 

 (1) Subparagraphs 13.b, 14.b, 15.d, 16.c, 17.b17.d, 18.b, 19.b, and 

Paragraph 21 in Subsection V.B; 

 (2) Subparagraphs 23.b, 24.b, 25.b, 26.b, 27.b, 28.b, 29.b, and 

Paragraph 32 in Subsection V.C; 

 (3) Paragraphs 34 and 35 (if applicable as of the date of termination) 

in Subsection V.D; 

 (4) Paragraphs 39, 40 (if applicable as of the date of termination), and 

42 in Subsection V.E; 

 (5) Paragraph 43 and 44 in Subsection V.F; 

 (6) Paragraphs 52, 53 and 54 in Subsection V.G; 

 (7) Subparagraphs 59.a and 59.b and Paragraph 60 in Subsection V.H; 

 (8) Paragraphs 63 and 64, Subparagraph 67.e, and Paragraph 69 in 

Subsection V.I; and 

 (9) Paragraphs 70, 71, and 73 in Subsection V.J. 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 20 of 38
20 

 b. Certain Other Requirements

 (1) Subparagraph 65.a (as specified therein) in Subsection V.I; 

 (2) Paragraph 79 (as specified therein) and Subparagraph 91.a (as 

specified therein) in Subsection V.K; 

 (3) Paragraph 92 (as specified therein) in Subsection V.L; 

 (4) All of this Subsection V.Q; and 

 (5) All of Section VI. 

 c. Agreement Required for Changes to Surviving Requirements. In the event 

ExxonMobil should ever seek, after termination of this Consent Decree, to delete or modify an 

emission limit or standard surviving termination by virtue of Subparagraph 145.a, such emission 

limit or standard shall not be deleted or modified unless EPA and the Applicable Co-Plaintiff 

shall have first agreed in writing to the deletion or modification. In the event that ExxonMobil 

should ever seek to delete or modify any of the certain other requirements surviving termination 

pursuant to Subparagraph 145.b, such requirement shall not be deleted or modified unless EPA 

and the Applicable Co-Plaintiff shall have first agreed in writing to the deletion or modification. 

* * * * 

 161. ExxonMobil shall submit Semi-Annual Reports to EPA and the Applicable CoPlaintiff that contain the following information: 

 i. a progress report on the implementation of the requirements of Section V 

(Affirmative Relief) at the Covered Refineries; 

 ii. a summary of the emissions data, including a separate identification of any 

exceedance(s) of Consent Decree emission limitations or standards for the 

Covered Refineries set forth in or established pursuant to Section V of this 

Consent Decree, for the six (6) month period covered by the report; 

 iii. a description of any problems anticipated with respect to meeting the 

requirements of Section V of this Consent Decree at the Covered Refineries; 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 21 of 38
21 

 iv. a progress report on the implementation of the requirements of Section VIII 

(Environmentally Beneficial Projects); 

 v. any such additional matters as ExxonMobil believes should be brought to the 

attention of EPA and the Applicable Co-Plaintiff; and 

 vi. additional items required by another Paragraph of this Consent Decree to be 

submitted with a Semi-Annual Report. 

Semi-Annual Reports shall be submitted by August 31 (covering the period from January 1 to 

June 30) and February 28 (covering the period from July 1 to December 31), provided, however, 

that the first such Report shall be due on August 31, 2006 (covering the period from December 

31, 2005 to June 2006)with the first such Report due on the first reporting date after the Entry 

Date. The Semi-Annual Report shall be certified by: (i) the person responsible for 

environmental management and compliance for each of the Covered Refineries; or (ii) a person 

responsible for overseeing implementation of this Decree for ExxonMobil, as follows: 

I certify under penalty of law that this information [related to _______ refiner(y)(ies)] 

was prepared under my direction or supervision in accordance with a system designed to 

assure that qualified personnel properly gather and evaluate the information submitted. 

Based on my directions and my inquiry of the person(s) who manage the system, or the 

person(s) directly responsible for gathering the information, the information submitted is, 

to the best of my knowledge and belief, true, accurate, and complete. 

* * * * 

166. For failure to meet any FCCU Interim NOx Limit or Final NOx Limit set forth in 

or established pursuant to Subparagraphs 13.b, 14.b, 16.b, 16.c, 17.b, 17.d, 18.b, or 19.b, per 

FCCU: $750 for each calendar day in a calendar quarter in which the short-term rolling average 

exceeds the applicable limit; and $2,500 for each calendar day in a calendar quarter on which the 

specified 365-day rolling average exceeds the applicable limit. 

* * * * 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 22 of 38
22 

 167. For failure to comply with any of the Beaumont Interim NOx Control Measures 

specified by Subparagraph 14.c, any of the Baton Rouge and Beaumont NOx Minimization 

Studyies requirements specified by Paragraph 15, or any of the Billings NOx Reduction Study 

requirements specified by Paragraph 17, including submission of required reports, per day: 

 Period of Non-Compliance Penalty per day

 1st through 30th day after deadline $1,000 

 31st through 60th day after deadline $1,500 

 Beyond 60th day after deadline $2,000, or an amount equal to 1.2 times the 

 economic benefit of non-compliance 

 whichever is greater 

* * * * 

 237. Liability Resolution Regarding the Applicable NSR/PSD Requirements. 

With respect to emissions of the following pollutants from the following units, entry of this 

Consent Decree shall resolve all civil liability of ExxonMobil to the United States and the 

Applicable Co-Plaintiffs for alleged violations of the Applicable NSR/PSD 

Requirements resulting from construction or modification from the date of the pre-Lodging 

construction or modification up to the following dates: 

 Unit Pollutant Date

 Baton Rouge PCLA 2 SO2 January 1, 2006 

 NOx 455 days after the Entry Date 

 Baton Rouge PCLA 3 SO2 January 1, 2006 

 NOx 455 days after the Entry Date 

 Baytown FCCU 2 SO2 December 31, 2009 

 NOx June 30, 2010 

 Baytown FCCU 3 SO2 Entry Date 

 NOx June 30, 2010 

 Beaumont FCCU SO2 Entry Date 

 NOx July 1, 2009October 1, 2009

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 23 of 38
23 

 Billings FCCU SO2 Either: (i) March 15, 2012, if the 

 Final SO2 Limit is established by 

 election of Option A under 

 Subparagraph 29.b.(1); or (ii) the 

 date on which a Final SO2 Limit is 

 established by election of Option B 

 under Subparagraph 29.b.(2) 

 NOx June 30, 2009December 31, 2008

 Joliet FCCU SO2 December 31, 2008 

 NOx December 31, 20102012

 Torrance FCCU SO2 Entry Date 

 NOx Entry Date 

 All Combustion Devices listed 

 in Appendix A NOx September 30, 2010 

 All heaters and boilers other 

 than those in Appendix A NOx Entry Date 

 All heaters and boilers listed 

 in Appendix C SO2 Dates listed in or derived from 

 Appendix C 

 All heaters and boilers other 

 than those listed in Appendix C SO2 Entry Date 

 All Other Fuel Gas Combustion 

Devices listed in Appendix D SO2 Dates listed in or derived from 

 Appendix D 

* * * * 

250. Resolution of Liability Regarding LDAR Requirements. Entry of this Consent 

Decree shall resolve the civil liability of ExxonMobil to the United States and the Applicable 

Co-Plaintiffs for alleged violations of LDAR Requirements at the Covered Refineries that either: 

(i) commenced and ceased prior to the Consent Decree Entry Date; or (ii) commenced prior to 

the Entry Date and continued past the Entry Date, provided that the events giving rise to such 

post-Entry violations are based on events that are identified in the LDAR Initial Audit Report 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 24 of 38
24 

required under Subparagraph 120.b and are corrected pursuant to the requirements of Paragraph 

121. 

* * * * 

 266. Notice. Unless otherwise provided herein, notifications to or communications 

between the Parties shall be deemed submitted on the date they are postmarked. Notifications 

and communications shall be sent by U.S. Mail, postage pre-paid, or private courier service, 

except for notices under Section XIV (Force Majeure) and Section XV (Retention of 

Jurisdiction/Dispute Resolution) which shall be sent by overnight mail or by certified or 

registered mail, return receipt requested. Each report, study, notification or other communication 

of ExxonMobil shall be submitted as specified in this Consent Decree, with copies to EPA 

Headquarters, the applicable EPA Region, and the Applicable Co-Plaintiff. If the date on which 

a notification or other communication is due falls on a Saturday, Sunday or legal holiday, the 

deadline for such submission shall be enlarged to the next business day. Except as otherwise 

provided herein, all reports, notifications, certifications, or other communications required under 

this Consent Decree to be submitted or sent to the United States, EPA, the Applicable CoPlaintiffs, and/or ExxonMobil shall be addressed as follows: 

As to the United States:

Chief 

Environmental Enforcement Section 

Environment and Natural Resources Division 

U.S. Department of Justice 

P.O. Box 7611, Ben Franklin Station 

Washington, DC 20044-7611 

 Reference Case No. 90-5-2-1-07030 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 25 of 38
25 

As to EPA: 

EPA Headquarters:

U.S. Environmental Protection Agency 

Director, Air Enforcement Division 

 Office of Regulatory Enforcement 

Ariel Rios Building 

1200 Pennsylvania Avenue, N.W. 

Mail Code 2242-A 

Washington, DC 20460 

 

 with a hard copy to 

 Director, Air Enforcement Division 

 Office of Regulatory Enforcement 

 c/o Matrix New World Engineering, Inc.Environmental & Geotechnical Services

120 Eagle Rock Avenue, Suite 207215 Ridgedale Avenue

East Hanover, NJ 07936-3159Florham Park, NJ 07932

 and an electronic copy to 

jmack@matrixneworld.comneichlin@matrixengineering.com

 foley.patrick@epa.gov 

EPA Region 5:

 Air and Radiation Division 

 U.S. EPA, Region 5 

 77 West Jackson Blvd. (AE-17J) 

 Chicago, IL 60604 

 Attn: Compliance Tracker 

 and 

 Office of Regional Counsel 

 U.S. EPA, Region 5 

 77 West Jackson Blvd. (C-14J) 

 Chicago, IL 60604 

EPA Region 6:

Chief 

 Air, Toxics, and Inspections Coordination Branch 

Environmental Protection Agency, Region 6 

1445 Ross Avenue 

Dallas, Texas 75202-2733 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 26 of 38
26 

 

EPA Region 8:

 Air Program Coordinator 

 U.S. Environmental Protection Agency, Region 8 

 Montana Office 

 10 W. 15th St., Suite 3200 

 Helena, MT 59626 

 

EPA Region 9:

 Director 

 Air Division 

 Mail Code AIR-1 

 USEPA Region 9 

 75 Hawthorne Street 

 San Francisco, CA 94105 

As to the State of Illinois:

 Manager Compliance and Enforcement Section 

 Illinois Environmental Protection Agency 

 1021 North Grand Avenue, East 

 P.O. Box 19276 

 Springfield, IL 62794 

 and 

 Field Operations Section 

 Illinois Environmental Protection Agency 

 9511 West Harrison 

 Des Plaines, IL 60016 

 and 

 Maureen Wozniak 

 Assistant Counsel 

 Illinois Environmental Protection Agency 

 1021 North Grand Avenue, East 

 P.O. Box 19276 

 Springfield, IL 62794 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 27 of 38
27 

As to the State of Louisiana:

 Peggy M. Hatch 

 Administrator, Enforcement Division 

 Office of Environmental Compliance 

 Louisiana Department of Environmental Quality 

 P.O. Box 4312 

 Baton Rouge, LA 70821-4312 

As to the State of Montana:

 Enforcement Division Administrator 

 Montana Department of Environmental Quality 

 P.O. Box 200901 

 Helena, MT 59620-0901 

 and 

 Bureau Chief 

 Air Resources Management Bureau 

 Montana Department of Environmental Quality 

 P.O. Box 200901 

 Helena, MT 59620-0901 

As to ExxonMobil: 

Assistant General Counsel, Litigation 

 Law Department 

 Exxon Mobil Corporation 

 800 Bell Street 

 ExxonMobil Building, Room 1503B 

 Houston, TX 77022 

 Tel. 713-656-3431 

 Fax 713-656-7719 

and 

 Downstream Environment and Global Compliance Manager 

 Exxon Mobil Corporation 

 3225 Gallows Road 

 Room 8B 0233 

 Fairfax, VA 22037-0001 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 28 of 38
28 

With a copy to each applicable refinery as shown below:

As to Baton Rouge:

 Refinery Manager 

 ExxonMobil Baton Rouge Refinery 

 P.O. Box 551 

 Baton Rouge, LA 70821-0551 

As to Baytown:

 

 Refinery Manager 

 ExxonMobil Baytown Refinery 

 P.O. Box 3950 

 Baytown, TX 77522-3950 

As to Beaumont:

 

 Refinery Manager 

 ExxonMobil Beaumont Refinery 

 P.O. Box 3311 

 Beaumont, TX 77704 

As to Billings:

 Refinery Manager 

 ExxonMobil Billings Refinery 

 P.O. Box 1163 

 Billings, MT 59103 

As to Joliet:

 Refinery Manager 

 ExxonMobil Joliet Refinery 

 P.O. Box 874 

 Joliet, IL 60434 

As to Torrance:

 Refinery Manager 

 ExxonMobil Torrance Refinery 

 3700 W. 190th Street 

 Torrance, CA 90509-2929 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 29 of 38
29 

Any Party may change either the notice recipient or the address for providing notices to it by 

serving all other parties with a notice setting forth such new notice recipient or address. 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 30 of 38
30 

Appendix C: NSPS Subpart J Compliance Schedule for Certain 

Heaters and Boilers

 

Refinery Combustion Device Compliance Date 1/

Baton Rouge PHLA-2-F-1 

PHLA-2-F-2 

PHLA-2-F-3 

PHLA-2-F-4 

PHLA-2-F-5 

PHLA-2-F-6

December 31, 2008

Baton Rouge FEED PREP F-30 

FEED PREP F-31

December 31, 2008

Baton Rouge 4LEU-E F-1 

4LEU-W F-1 

4LEU-W F-2

December 31, 2008

Baton Rouge LELA-E F-1 

LELA-S F-4

December 31, 2008

Baton Rouge KDLA- F-425 

KDLA F-451

December 31, 2008

Baytown LE Unit Heater F-601 

LE Unit Heater F-804

Submit AMP six months after Entry Date 

for NSPS vent stream

Billings Pipestill Heater F-1 October 31, 2009December 31, 2008 2/

 1/ As provided by Consent Decree Subparagraph 59.c, where this Appendix C refers to an AMP submittal 

date rather than a final compliance date, ExxonMobil will submit an AMP application for the listed device 

by the date specified, and the device shall become an affected facility on the date that ExxonMobil receives 

EPA’s approval of the relevant AMP. 

2/ Between the Entry Date and October 31, 2009December 31, 2008, Billings Pipestill Heater F-1 shall 

comply with the emission limitation specified by 40 C.F.R. § 60.104(a)(1) at all times, except when SWS 

T-23 ammonia overhead gas is combusted in the unit as permitted by pertinent provisions of the Montana 

State Implementation Plan. 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 31 of 38
31 

Appendix D: NSPS Subpart J Compliance Schedule for Certain Other Fuel Gas 

Combustion Devices

Refinery Combustion Device Compliance Date 4/

Baton Rouge MVR Combustor/Flare No. 1 AMP pending

Baton Rouge MVR Combustor/Flare No. 2 AMP pending

Baytown MVR Thermal Oxidizer VCU-440 Submit AMP six months after Entry Date

Baytown MVR Thermal Oxidizer VCU-470 Submit AMP six months after Entry Date

Baytown Thermal Oxidizer for Loading Racks 

22 & 3

Submit AMP six months after Entry Date

Baytown Caustic Oxidation Unit Incinerator Submit AMP six months after Entry Date

Beaumont MVR - John Zink Combustor Submit AMP six months after Entry Date

Billings FCCU CO Boiler Treat or re-route SWS T-23 ammonia 

overhead gas by no later than October 31, 

2009December 31, 2008; 

Submit AMP six months after Entry Date for 

Unsaturated Light Ends Merox Vent stream 

(DSO Offgas stream)

Joliet NBRU Thermal Vapor Incinerator - 

38B-1

Shutdown, treat, or re-route stream by no 

later than December 31, 2008

Joliet SBRU Thermal Vapor Incinerator - 

38B-2

Shutdown, treat, or re-route stream by no 

later than December 31, 2008

Torrance API Thermal Oxidizer 72F2 Submit AMP six months after Entry Date

Torrance API Thermal Oxidizer 72F4 Submit AMP six months after Entry Date

Torrance Resid Loading Rack Incinerator 

50J-30

Submit AMP six months after Entry Date

Torrance Sulfur Pit Vapor Incinerator 28F-11 Shutdown, treat, or re-route stream by July 1, 

2009

 4/ As provided by Consent Decree Subparagraph 59.c, where this Appendix D refers to an AMP submittal 

date rather than a final compliance date, ExxonMobil will submit an AMP application for the listed device 

by the date specified, and the device shall become an affected facility on the date that ExxonMobil receives 

EPA’s approval of the relevant AMP.

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 32 of 38
32 

Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries 

Refinery Flaring Device Compliance Date 6/ Compliance Method

Baton Rouge Flare 5 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 8 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 9 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 17 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 19 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 20 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 21 Entry Date Subparagraph 73.a.ii 

Baton Rouge Flare 23 Entry Date Subparagraph 73.a.i 

Baton Rouge Flare 24 Entry Date Subparagraph 73.a.i 

Baytown Flare 3 Entry Date Subparagraph 73.a.i 

Baytown Flare 4 Submit AMP six months after Entry Date for HF3 

vent stream routed to flare downstream from flare 

gas recovery system 

All other streams routed to Flare 4, through flare 

gas recovery system 

Subparagraph 73.a.iii 

Subparagraph 73.a.i 

Baytown Flare 5 Entry Date Subparagraph 73.a.i 

Baytown Flare 6 Entry Date for emergency service

All other streams routed to Flare 6, through flare 

gas recovery system

Subparagraph 73.a.ii

Subparagraph 73.a.i

Baytown Flare 11 Monitor with CEMS as required by 40 C.F.R. 

§ 60.105(a)(3) or (a)(4) by no later than 12 

months after Entry Date 

Subparagraph 73.a.iv 

Baytown Flare 14 Monitor with CEMS as required by 40 C.F.R. 

§ 60.105(a)(3) or (a)(4) by no later than 12 

months after Entry Date 

Subparagraph 73.a.iv 

Baytown Flare 15 Entry Date Subparagraph 73.a.i 

Baytown Flare 16 Entry Date Subparagraph 73.a.i 

 6/ As provided by Consent Decree Subparagraph 73.b, where this Appendix G refers to an AMP submittal 

date rather than a final compliance date, ExxonMobil will submit an AMP application for the listed device 

by the date specified, and the device shall become an affected facility on the date that ExxonMobil receives 

EPA’s approval of the relevant AMP.

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 33 of 38
33 

Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

 Operated by Covered Refineries (continued) 

Refinery Flaring Device Compliance Date Compliance Method

Baytown Flare 17 24 months after Entry Date (so that certain streams 

can be re-routed by that Compliance Date) 

Subparagraph 73.a.i 

Baytown Flare 18 Entry Date Subparagraph 73.a.i 

Baytown Flare 19 Entry Date for emergency service 

Submit AMP six months after entry for 

intermittent low mass sweet streams 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

Baytown Flare 20 24 months after Entry Date for streams other than 

HF4 stream (so that certain streams can be rerouted by that Compliance Date) 

Submit AMP six months after Entry Date for 

monitoring HF4 stream when Flare 17 is on 

turnaround

Subparagraph 73.a.i 

Subparagraph 73.a.iii 

Baytown Flare 21 Entry Date Subparagraph 73.a.i 

Baytown Flare 22 Entry Date for emergency service 

Submit AMP six months after Entry Date for 

monitoring intermittent low mass sweet streams 

when Flare 19 is on turnaround 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

Baytown Flare 25 Entry Date for emergency service 

Submit AMP six months after Entry Date for 

monitoring intermittent refinery fuel gas streams 

and natural gas streams 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

Baytown Flare 26 Submit AMP six months after Entry Date for 

monitoring certain sweet streams and nitrogencontaining streams 

Subparagraph 73.a.iii 

Baytown Flare 27 Monitor with CEMS as required by 40 C.F.R. 

§ 60.105(a)(3) or (a)(4) by no later than 12 months 

after Entry Date 

Subparagraph 73.a.iv 

Beaumont High Pressure 

(HP) Flare 

September 30, 201042 months after Entry Date (so 

that flare gas recovery system upgrades can be 

completed by that Compliance Date) 

Subparagraph 73.a.i 

Beaumont Low Pressure 

(LP) Flare 

September 30, 201042 months after Entry Date (so 

that flare gas recovery system upgrades can be 

completed by that Compliance Date) 

Subparagraph 73.a.i 

Beaumont FCC Flare September 30, 201042 months after Entry Date (so 

that flare gas recovery system upgrades can be 

completed by that Compliance Date) 

Subparagraph 73.a.i 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 34 of 38
34 

Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries (continued)

Refinery Flaring Device Compliance Date Compliance Method

Beaumont CHD 1 Flare September 30, 201042 months after Entry Date Subparagraph 73.a.i, 

73.a.ii, or 73.a.iii 

Beaumont CHD 2 Flare September 30, 201042 months after Entry Date Subparagraph 73.a.i, 

73.a.ii, or 73.a.iii 

Beaumont Coker Flare 7/ September 30, 201042 months after Entry Date Subparagraph 73.a.i, 

73.a.ii, or 73.a.iii 

Billings Main Flare September 30, 201048 months after Entry Date (so 

that flare gas recovery system upgrades and other 

improvements can be completed by that 

Compliance Date) 

Subparagraph 73.a.iii

Billings Turnaround 

Flare 

September 30, 201048 months after Entry Date (so 

that flare gas recovery system upgrades and other 

improvements can be completed by that 

Compliance Date) 

Subparagraph 73.a.iii

Torrance Flare 55F-1 Submit AMP six months after Entry Date Subparagraph 73.a.iii 

Torrance Flare 65F-3 Entry Date Subparagraph 73.a.i 

Torrance Flare 65F-4 Entry Date Subparagraph 73.a.i 

Torrance Enclosed 

Ground Flare 

65F-8 8/

Entry Date Subparagraph 73.a.i 

 7/ With respect to the Beaumont Refinery’s CHD 1 Flare, CHD 2 Flare, and Coker Flare, by no later than 

September 30, 201042 months after the Entry Date, ExxonMobil shall either: (i) complete flare gas 

recovery system upgrades to bring the particular flare into compliance with Subparagraph 73.a.i; or (ii) reroute streams as required to bring the particular flare into compliance with Subparagraph 73.a.ii or 73.a.iii. 

In the first Semi-Annual Report that is due under Section IX after September 30, 2010that 42 month 

period, ExxonMobil shall identify and certify compliance with a specific compliance method (i.e., either 

Subparagraph 73.a.i, 73.a.ii, or 73.a.iii ) for each of those three Beaumont Refinery flares. 

8/ Enclosed Ground Flare 65F-8 is an enclosed combustion device that: (i) is not subject to the velocity test 

requirement referenced in Subparagraph .b.(2) of this Consent Decree; and (ii) is subject to the 

requirements imposed by SCAQMD Rule 1118 and 40 C.F.R. §§ 60.482-10 and 60.486(d).

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 35 of 38
35 

Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries (continued)

Identification of Particular Low Volume/Low Pressure Streams to be Routinely Combusted in 

Certain Baytown Refinery Flaring Devices 

1. Low Volume/Low Pressure Streams to be Routinely Combusted in Baytown Flare 11 and/or 

Baytown Flare 14 

 a. Hydrocracker Unit 1 (HCU-1) 

 • S-702 (C-708 suction knock out drum) drain 

 • D-713 (C-708 1st stage discharge knock-out drum) drain 

 • D-714 (C-708 2nd stage discharge knock-out drum) drain 

 • D-770 (C-770 1st stage suction knock-out drum) drain 

 • D-771 (C-770 2nd stage suction knock-out drum) drain 

 • D-772 (C-770 3rd stage suction knock-out drum) drain 

 • D-780 (C-780 1st stage suction knock-out drum) drain 

 • D-781 (C-780 2nd stage suction knock-out drum) drain 

 • D-782 (C-780 3rd stage suction knock-out drum) drain D-780 

 • Low-point piping seal pot drains from C-770 & C-780

 • D-773 (C-770 filter knock-out drum) drain

 • D-783 (C-780 filter knock-out drum) drain

 • D-771, D-772, D-781, D-782 (knock-out liquid) vents

 • C-780 suction drain

 • C-770 suction drain

 • S870 hydrogen comp. coalescer drain

• D-901 (water drain)

• T-810 (sample point vents)

• R-701 (sample point vent)

• D-717A (C-701 sour seal oil drain)

• D-717B (C-701 sour seal oil drain)

• S-704C (C-708 peco filter)

• D-703 (sour water sample)

• D-715 (skim line)

• D-905 (blend gas knock out)

• D-906 (blowdown header low point drain) 

 b. FCCU 3 

 • C-302 (FCCU 3 wet gas compressor) seal oil liquid collection pot drain 

 • C-303 (FCCU 3 wet gas compressor) seal oil liquid collection pot drain

 • C-301 (FCCU 3 wet gas compressor) seal oil filtration system vent 

• D-504 C (boiler pilot gas knock out)

• D-303 (slop drum vent)

• D-302 (sample point vent)

• Dopak sample points 

• D-30A F-103 (fuel gas knock out)

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 36 of 38
36 

• D-406 F-105 (fuel gas knock out)

• D-1502 A, B, C (boiler fuel gas knock outs)

 c. Hydrofining Unit 9 (HU-9) 

 • D-390 (DCU flare knock-out drum) overhead vent

• C-361 / 362 (hydrogen recycle and make-up compressors) buffer gas (N2)

vent and drains off compressor lube pots [through D-390]

• RGB / LBG fuel gas knock-out drum liquid drain [through D-390]

d. Equipment leaks and purges from components such as pumps, compressors, valves, etc.

2. Low Volume/Low Pressure Streams to be Routinely Combusted in Baytown Flare 27 

 a. DCU 

 • D-617 (residual flow from DCU flare knock-out drum) 

 • D-612 vent (DCU blowdown settling drum) 

 • 2 - C-601 suction lines condensible drains (during winter months)

b. PS-3/7

• D-421 (hydrocarbon containment drum) 

• D-422 (hydrocarbon containment drum)

c. Equipment leaks and purges from components such as pumps, compressors, valves, etc

 

If ExxonMobil identifies any other low volume/low pressure stream that is routinely combusted in 

Baytown Flare 11, Flare 14, or Flare 27, EPA may approve addition of that stream to this Appendix 

through a non-material modification under Consent Decree Paragraph 269, so long as the other conditions 

of Subparagraph 73.a.iv are met. 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 37 of 38
37 

 SIGNATORIES

 Each of the undersigned representatives certifies that he or she is fully authorized to enter 

into the Third Decree Amendment on behalf of such Parties, and to execute and to bind such 

Parties to this Third Decree Amendment. This Third Decree Amendment may be signed in 

counterparts. 

 Dated and entered this _______ day of __________, 200___ 

_______________________________ 

 UNITED STATES DISTRICT JUDGE 

Case 1:05-cv-05809 Document 14-2 Filed 12/17/2008 Page 38 of 38