, •

IN THE UNITED STATES DISTRICT COURT

FOR THE SOUTHERN DISTRICT OF TEXAS

United State, Couru

SOuthDrn O1~trir.t of Texas I: FILED

OCT ll(l 20M

Defendants.

UNITED STATES OF AMERICA,

STATE OF GEORGIA,

STATE OF ILLINOIS,

STATE OF LOUISIANA, and

STATE OF NEW JERSEY

No.

Plaintiffs,

v.

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CITGO PETROLEUM CORPORATION, )

CITGO REFINING AND CHEMICALS )

COMPANY, L.P., PDV MIDWEST )

REFINING, L.L.C., and CITGO ASPHALT )

REFlNINGCOMPANY, )

)

)

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CONSENT DECREE
TABLE OF CONTENTS

I. Jurisdiction and Venue (paragraphs 1-3) 7

II. Applicability and Binding Effect (paragraphs 4-8) 7

m. Objectives (Paragraph 9) 9

IV. Definitions (Paragraph 10) 10

V. Affirmative Reliefi'EnvironmentalProjects (paragraphs 11-134) 20

A. NOx Emissions Reductions from FCCDs (Paragraphs 11-31) 20

B. S02 Emissions Reductions from FCCDs (Paragraphs 32-42) 39

C. PM Emissions Reductions. from FCCDs (Paragraphs 43-47) 48

D. CO Emissions Reductions. from FCCUs(paragraphs 48-50) 50

E. NSPS Applicability to FCCD Regenerators (paragraph 51)...................• 51.

F. NOx Emissions Reductions from Heaters and Boilers (Paragraphs 52-62) .51

G. S02 Emissions Reductions from and NSPS Applicability ofHeaters, Boilers and

Other Fuel Gas Combustion Devices (paragraphs 63-65) .58

H. Sulfur Recovery Plants (paragraphs 66-73) 60

I. Hydrocarbon Flaring (Paragraphs 74-76) __ 67

J. Control ofAcid Gas. Flaring and Tail Gas Incidents (Paragraphs 77-93) 69

K. Control ofHydrocarbon Flaring Incidents (Paragraph 94) 79

L. Benzene Waste NESHAPProgram Enhancements (Paragraphs 95-112) 79

M. Leak Detection and Repair ("LDAR') Program Enhancements (Paragraphs 113-

130) 96

N. Incorporation ofConsent Decree Requirements into Federally Enforceable Pennits

(Paragraphs 131-134) .1 08

1
VI. Emission Credit Generation (paragraphs 135-138) " 109

Vll. Modifications to Implementation Schedules (Paragraphs 139-140) .112

Vm. Environmentally Beneficial Projects (paragraphs 141-143) .lIS

IX. Recordkeeping and Reporting (Paragraph 144) 117

X. Civil Penalty (Paragraphs 145-148) , .118

XI. Stipulated Penalties (Paragraphs 149-226) , , .. 120

A. Requirements for NOx Emission Reductions from FCCDs (Paragraphs 150-156) , 121

B. Requirements for S02 Emission Reductions from FCCDs (paragraphs 157-160) ..122

C. Requirements for PM Emission Reductions from FCCDs (Paragraphs 161-163) .. 124

D. Requirements for CO Emission Reductions from FCCDs (Paragraphs 164-165). , 124

E. Requirements Related to NSPS Applicability to FCCD Regenerators

(Paragraph 166) , ; , 125

F. Requireinents for NOx Emission Reductions. from HeatersIBoilers

(Paragraphs 167-170) '" , .125

G. Requirements for S02 Emission Reductions from HeaterslBoilers

(Paragraphs 171-17Ia) , 126

H. Requirements for Sulfur Recovery Plants (Paragraphs 172-178) .127

I. Requirements for Flaring Devices (paragraphs 179-180) .129

J. Requirements for Control ofAG Flaring and Tail Gas Incidents

(paragraphs 181-184) , , 130

K. Requirements for Control ofHydrocarbon Flaring Incidents (Paragraph 185) .....132

L. Requirements for BenzeneWaste NESHAP Enhancements (Paragraphs 186-203) .132

M. Requirements for Leak Detection and Repair Program Enhancements

(paragraphs 204-220) , " , , 135

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N. Requirements to Incorporate Consent Decree Requirements into FederallyEnforceable Permits (paragraph 221) , ..137

O. Requirements for Reporting and Recordkeeping (Paragraph 222) 138

P. Requirements for Environmentally Beneficial Projects and Civil Penalties

(paragraph 223) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . 138

Q. Requirement to Pay Stipulated Penalties (Paragraph 224) 138

R. Payment ofStipulated Penalties (Paragraph225) 138

S. Stipulated Penalties Dispute (Paragraph 226) 139

XII. Interest (paragraph 227) 140

XIII. Right ofEntry (paragraph 228) , .140

XIv. Force Majeure (Paragraphs 229-237) : 141

XV. Retention ofJurisdictionlDispute Resolution (paragraphs 238-246) 144

XVI. Effect ofSettlement (paragraphs 247-261) , 146

XVII. General Provisions (Paragraphs 262-273) 154

xvm. Termination (paragraph 274-276) 161

XIX. Signatories (paragraph 277) 165

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TABLE OF APPENDICES

Appendix A:

State and Federal Compliance Orders and Notices

AppendixB:

List ofHydrocarbon Flaring Devices

Appendix B-1 :

List ofNSPS Hydrocarbon Flaring Devices

Appendix B-2:

List ofNSPS Acid Gas Flaring Devices

AppendixC:

List ofHeaters and Boilers

AppendixD:

Determining the Optimized Addition Rates ofLow NOx Combustion Promoters and

NOx Reducing Catalyst Additives

AppendixE:

NSPS Subpart J Compliance Schedule for Heaters and Boilers and Streams in Fuel Gas

AppendixF:

Fuel Gas Combustion Devices Compliance Schedule

Appendix G:

NSPS Subpart J Compliance Schedule·for NSPS Flaring-Devices

Appendix H:

Predictive Emissions Monitoring Systems for Heaters and Boilers with Capacities

Between 100 and 150 MMBTU!HR

IV
Appendix I:

Koch Guidance

v
CONSENT DECREE

WHEREAS, plaintiffthe United States ofAmerica ("Plaintiff" or "the United States"), by

the authority ofthe Attorney General ofthe United States and through its undersigned counsel, .

acting at the request and on behalf ofthe United States Environmental Protection Agency

("EPA"), alleges upon infonnation and beliefthat defendants CITGO Pettolerun Corporation,

CITGO Refining and Chemicals Company, L.P., PDV Midwest Refrning, L.L.C., and CITGO

Asphalt Refining Company (collectively "CITGO") have violated and/or continue to violate the

requirements ofthe Clean Air Act, and the regulations and permits promulgated thereunder at

CITGO's petroleum refineries in Lemont, minois, Lake Charles, Louisiana, and Corpus Christi,

Texas, and at CITGO's asphalt refmeries in Savannah, Georgia and Paulsboro, New Jersey

(collectively "Covered Refineries'~;

WHEREAS, the United States specifically alleges that ClTGO has violated and/or

continues to violate the following statutory and regulatory provisions:

1) Prevention ofSignificant Deterioration ("PSD") requirements found at Part C of

Subchapter 1ofthe Clean Air Act (the "Act"), 42 U.s.C. §§ 7475, and the regulations

promulgated thereunder at 40 C.F.R. § 52.21 (the "PSD Rules"); and "Plan Requirements

for Non-Attainment Areas" at Part D ofSubchapter I ofthe Act, 42 U.S.C. §§ 7502-7503,

and the regulations promulgated thereunder at 40 C.F.R. § 51.165(a) and (b) and at

Title 40, Part 51, Appendix S, and at 40 C.F.R. § 52.24 .("PSDfNSR Regulations"), for

fuel gas combustion devices, fluid catalytic cracking unit catalyst regenerators for NOx,

S02' CO and PM and for sulfuric acid plants;

2) New Source Perfonnance Standards ("NSPS") found at 40 C.F.R. Part 60, Subparts A

and J ("Refinery NSPS Regulations'~ and Subpart H, promulgated under Section III of
· the Act, 42 U.S.C. § 7411, for sulfur recovery plants, fuel gas combustion devices, and

fluid catalytic cracking unit catalyst regenerators and for sulfuric acid plants;

3) Leak Detection and Repair ("LDAR") requirements promulgated pursuant to

Sections III and 112 ofthe Act, and found at 40 C.F.R. Part 60 Subparts VV and GGG;

40 C.F.R. Part 61, Subparts J and V; and 40 C.F.R. Part 63, Subparts F, H, and CC

("LDAR Regulations"); and

4) National Emission Standards for Hazardous Air Pollutants. ("NESHAP") for BenzeI\e

Waste Operations promulgated pursuant to Section 112(e) ofthe Act, and found at

40 C.F.R. Part 61, Subpart FF ("Benzene Waste NESHAP Regulations'').

WHEREAS, the United States also specifically alleges witli respect to the Covered

Refineries that, upon information and belief, CITGO has been and/or continues to be in violation

ofthe state implementation plans ("SIPs") and other state rules adopted by the states in which the

Covered Refineries are located to the extent that such plans or rules implement, adopt or

incorporate the above-described Federal requirements;

WHEREAS, the State ofGeorgia ("Georgia"), the State of Illinois ("minois"), the State

ofLouisiana ("Louisiana''), and the State ofNew Jersey ("New Jersey") (collectively "CoPlaintiffs") have alleged violations. oftheir respective applicable SIP provisions and other state

and local rules, regulations, and permits incorporating and/orimplementing the foregoing federal

requirements;

WHEREAS, with respect to the provisions of Section V.I. ("Control ofAcid Gas Flaring

Incidents and Tail Gas Incidents'') ofthis Consent Decree, EPA maintains that "[i]t is the intent

ofthe proposed standard [40 C.F.R. § 60.104] that hydrogen-sulfide.rich gases exiting the amine

2
regenerator [or sour water stripper gases] be directed to an appropriate recovery facility, such as a

Claus sulfur plant," Information for Proposed New Source Performance Standards: Asphalt

Concrete Plants, Petroleum Refineries, Storage Vessels, Secondary Lead Smelters and

Refineries, Brass orBronze Ingot Production Plants, Iron and Steel Plants, Sewage Treatment

Plants, Vol. I, Main Text at 28;

WHEREAS, EPA further maintains that the failure to direct hydrogen-sulfide-rich gases

to an appropriate recovery facility -- and instead to flare such gases under circumstances that are

not sudden or infrequent or that are reasonably preventable -- circumvents the purposes and

intentions ofthe standards at 40 C.F.R. Part 60, Subpart J;

WHEREAS, EPA recognizes that "Malfunctions," as. defmed in Paragraph 10 ofthis

Consent Decree and 40 C.F.R § 60.2, ofthe "Claus Sulfur Recovery Plants" or of"Upstream

Process Units" may result in flaring of "Acid Gas" or "Sour Water Stripper Gas" on occasion, as

those terms are defined herein, and that such flaring does not violate 40 C.F.R § 60.1 I(d) ifthe

owner or operator, to the extent practicable, maintains and operates such units in a manner

consistent with good air pollution control practice for minimizing emissions during these

periods;

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

.statutory, regulatory, SIP provisions and other state and local rules, regulations and permits

incorporating and implementing the foregoing federal requirements, and maintains that it has

been and remains in compliance with all applicable statutes, regulations and perinits and is not

liable for civil penalties and injunctive reliefas alleged in the Complaint;

3
WHEREAS, the United States is engaged in a federal strategy for achieving cooperative

agreements with U.S. petroleum refineries to achieve across-the-board reductions in emissions in

a manner that achieves compliance with existing statutory and regulatory standards ("Global

Settlement Strategy");

WHEREAS, CrrGO consents to the simultaneous filing ofthe Complaint and lodging of

this Consent Decree so as to accomplish its objective of cooperatively reconciling the goals of

the United States, CrrGO and the Co-Plaintiffs under the Clean Air Act and the corollary state

statutes, and therefore. agrees to undertake the. installation of air pollution control equipment and

enhancements to its air pollution management practices set forth in this Consent Decree at the

Covered Refineries to reduce air emissions through participation in the Global Settlement

Strategy;

WHEREAS, by entering into this Consent Decree CrrGO is committed to reducing air

pollutant emissions from its operations;

WHEREAS, the United States, Georgia, Illinois, Louisiana, New Jersey, and CITGO

agree that the affirmative relief and environmental projects identified in Sections V and VIII of

this Consent Decree will reduce annual emissions from the Covered Refineries by the following

amounts: 1) nitrogen oxide by approximately 7,162 tons; 2) sulfur dioxide by approximately

23,250 tons; and 3) particulate matter ("PM") by approximately 915 tons;

WHEREAS, EPA recently issued PSD Rules and PSDINSR Regulations, see. 67 Fed.

Reg. 80186-80289 (2002), that identity and address "Pollution Control Projects" and "Clean

Units" and the applicability ofPSDINSR permitting requirements to such Projects or Units;

4
WHEREAS, EPA previously issued guidance ("Pollution Control Projects and New

Source Review (NSR) Applicability", July 1,1994) identifying and addressing "Pollution

Control Projects" and the applicability ofPSDJNSR pennitting requirements to such Projects;

WHEREAS, EPA agrees that under the recently issued PSD Rules and PSDJNSR

Regulations that identify and address "Clean Units", see 67 Fed. Reg. 80186 ~., units that

accept the following emission limits under this Consent Decree may be considered "Clean

Units" with respect to the identified pollutants:

For FCCUs:

- 20 ppmvd NOx at 0% 02 on a 365-day rolling average basis

- 25 ppmvd S02 at 0% 02 on a 365-day rolling average basis

- 100 ppmvd CO at 0% 02 on a 365-day rolling average basis

- 0.5 pounds ofPM per 1,000 pounds of coke burned on a3-hour average basis

For Heaters and Boilers: .

5
rules, regulations, and guidance, provided that CITGO complies with the requirements for

"Pollution Control Projects" under applicable federal, state, and local regulations and policies.

WHEREAS, projects undertaken pursuant to this Consent Decree are for the purposes of

abating or controlling atmospheric pollution or contamination by removing, reducing or

preventing the emission ofpollutants and, as such, may be considered for certification as

PolIution Control Facilities by federal, state or local authorities.

WHEREAS, CITGO has waived any applicable federal or state requirements ofstatutory

notice ofthe alleged Violations;

WHEREAS, the Parties agree that: (a) settlement ofthe matters set forth in the Complaint

(filed herewith), and those orders and notices identified in Appendix A, is in the best interests of

the Parties, and the public; and (b) entry ofthis Consent Decree without litigation is the most

appropriate. means ofresolving this matter;

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

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

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

NOWTHEREFORE, with respect to the matters set forth in the complaint, and those

orders and notices identified in Appendix A, and in Section XVI ofthe Consent Decree ("Effect

of Settlement"), and before the takiug ofany testimony, without adjudication of any issue offact

or law, and upon the consent and agreement ofthe Parties to the Consent Decree, it is hereby

ORDERED, ADJUDGED and DECREED as follows:

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I. JURISDICTION AND VENUE

1. This Court has jurisdiction over the subject matter ofthis action and over the Parties

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

subject matter ofthis action pursuant to Sections 113(b) and 167 ofthe CM, 42 U.S.C.

§ 7413(b) and 7477. The Complaint states a claim upon which reliefmaybe granted for

injooctive relief and civil penalties against CITGO under the Clean Air Act Authority to bring

this suit is vested in the United States Department ofJusticeby 28 U.S.C. §§ 516 and 519,

Section 305 ofthe. CM, 42 U.S.C. § 7605.

2. Venue is proper in the Southern District ofTexas pursuant to Section 113(b) ofthe

CM, 42 U.S.C. § 7413(b), and 28 U.S.C. §§ 1391(b) and (c), and 1395(a).. CITGO consents to

the personal jurisdiction ofthis Court, waives any objections to venue in this District, and does

not object to the participation ofthe States ofGeorgia, Illinois, Louisiana, and New Jersey as

parties or intervenors in this action.

3. Notice ofthe commencement ofthis action has been given to theStatesofGeorgia,

lllinois, Louisiana, New Jersey and Texas in accordance with Section 113(a)(I) ofthe Clean Air

Act, 42 U.S.c. § 7413(a)(l), and as required by Section 113(b) ofthe CAA, 42 U.S.C. § 7413(b).

II. APPLICABILITY AND BINDING EFFECT

4. The provisions ofthe Consent Decree shaH apply to the Savannah Refinery, the

Lemont Refinery, the LakeCharlesRefinery, the Paulsboro Refinery, the Corpus Christi East

Refinery and the Corpus Christi West Refinery ("Covered Refineries"). The provisions ofthe

Consent Decree shall be binding upon the United States, the Co-Plaintiffs, and CITGO, its

successors and assigns.

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5. CITGO, the United States and the Co-Plaintiffs agree not to contest the validity ofthe

.Consent Decree in any subsequent proceeding to implement or enforce its terms.

6. ClTGO shall give written notice. ofthe Consent Decree to any successors. in interest

prior to the transfer of ownership or operation of any portion of any Covered Refinery and shall

provide a copy ofthe Consent Decree to any successor in interest. ClTGO shall notify the United

States, and the ~ppropriate Co-Plaintiff, in accordance with the notice provisions set forth in

Paragraph 270 (Notice), of any successor in interest at least thirty (30) days prior to any such

transfer.

7. CITGO 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 any

.Covered Refinery, upon the execution by the transferee of a modification to the ConsentDecree,

which modification shall make the terms and conditions ofthe Consent Decree that apply to such

Covered Refmery or portion of a Covered Refinery applicable to the transferee. In the event of

such transfer, CITGO shall notify the United States and the applicable Co-Plaintiff, but ifsuch

transfer occurs before CITGO achieves all ofthe NOx reductions required by Paragraph 54,

CITGO shall then submit an allocation to EPA for that Covered Refmery's share ofNOx

reduction requirements ofParagraph 54 that will apply individually to the transferred Covered

Refinery after such transfer (such allocation may be zero). By no earlier than thirty (30) days

after such notice, CITGO may file a motion to modify the Consent Decree to make the terms and

conditions ofthe Consent Decree applicable to the transferee. CITGO shall be released from the

obligations and liabilities ofthis Consent Decree UIlIess the United States opposes the motion

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and the Court fmds that the transferee does not have the financial and technical ability to assume

the obligations and liabilities under the Consent Decree.

8. Subject only to. Paragraph 7, above, and Sections vn and XIV, below, CITGO shall be

solely responsible for ensuring that performance ofthe work contemplated under this Consent

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

Consent Decree and any attachments hereto. CITGO shall provide a copy ofthis Consent Decree

(or an extract ofrelevant, applicable provisions ofthis Consent Decree) to each consulting or

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

execution of any contract relating to such work. No later than thirty (30) days after the Date of

Lodging ofthe Consent Decree, CITGO also shall provide a copy ofthis. Consent Decree. (or an

.extract ofrelevant, applicable provisions. ofthis Consent Decree) to each consnlting or

contracting finn that CITGO already has retained to perform the work required under this

Consent Decree. Copies ofthe Consent Decree (or an extract ofrelevant, applicable provisions

ofthis Consent Decree) may be provided by electronic means but do not need to be supplied to

firms who are retained to supply materials or equipment to satisfy requirements ofthis Consent

Decree.

III. OBJECTIVES

9. It is the purpose ofthe.Parties in this Consent Decree to further the objectives ofthe .

federal Clean Air Act, the Georgia Air Quality Act, OCGA 12-9-1; the Illinois Environmental

Protection Act, 415lLCS 5/8: Title II Air Pollution; Louisiana Air Control Law, LSA-R.S.

30:2051-2065; the New Jersey Air Pollution Act, 26:2C-l to 252; and the Texas Air Act, Acts

1989,71" Leg., ch. 382.

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IV. DEFINITIONS

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

meaning given to those tenns in the Clean Air Act, and the implementing regulations

promulgated thereunder. The following tenns used in this Consent Decree shall be defmed, for

purposes ofthe Consent Decree and the reports and documents submitted pursuant hereto, as

follows:

A.. "Acid Gas" or "AG" shall mean any gas that contains hydrogen sulfide and is

generated at a refinery by the regeneration of an amine scrubber solution but does not mean Tail

Gas.

B. "Acid Gas Flaring" or "AG Flaring" shall mean the combustion ofAcid Gas and/or

Sour Water Stripper Gas in a AGFlaring Device. Nothing in this definition shall be construed to

modifY, limit, or affect EPA's authority to regulate the flaring ofgases that do not fall within the

definitions ofAcid Gas or Sour Water Stripper Gas contained in this Decree.

C. "Acid Gas Flaring Device" or "AG Flaring Device" shall mean the devices listed in

Appendix B-2 that are used by the Covered Refineries to combust Acid Gas. and/or Sour Water

Stripper Gas. The tenn "Acid Gas Flaring Device" does not include facilities in which gases are

combusted to produce snlfur or sulfuric acid. To the. extent that, during the duration ofthe

Consent Decree, any Covered Refinery utilizes any Flaring Devices other than those specified in

Appendix B-2 for the purpose of combusting Acid Gas and/or Sour Water Stripper Gas, those

Flaring Devices shall be AG Flaring Devices and shall be subject to the requirements ofthis

Consent Decree.

10
D. "Acid Gas Flaring Incident" or "AG Flaring Incident" shall mean the continuous or

intermittent combustion ofAcid Gas and/or Sour Water Stripper Gas from one or more AG

Flaring Devices at a Covered Refinery that results in the emission ofsulfurdioxide equal to, or in

excess of, five-hundred (500) pounds in any twenty-four (24) hour period. Where such

continuous or intermittent combustion from one or more AG Flaring Devices continues into

subsequent, contiguous, non-overlapping twenty-four (24) hourperiod(s), and sulfur dioxide

equal to, or in excess of, five.-hundred (500) pounds is emitted in each subsequent, contiguous,

non-overlapping twenty-four (24) hour period(s), then only one AG Flaring Incident shall have

occurred. Subsequent, contiguous, non"overlapping twenty-four (24) hour periods are measured

from the initial commencement ofAG Flaring within the AG Flaring Incident.

E. "ApplicableFederal and State Agencies" shall mean, with respect to the Savannah

Refinery, EPA's Office ofRegulatory Enforcement, EPA's Region 4, and the Georgia

Department ofNatural Resources; with respect to the Lemont Refinery, EPA's Office of

Regulatory Enforcement, EPA's Region 5, and the Illinois Environmental Protection Agency;

with respect to the Lake Charles Refinery, EPA's Office ofRegulatory Enforcement; EPA's

Region 6 and the Louisiana Department ofEnvironmental Quality; with respect to the Paulsboro

Refinery, EPA's Office ofRegulatory Enforcement, EPA's Region 2, and the New Jersey

Department ofEnvironmental Protection; and with respect to the Corpus Christi East and Corpus

Christi West Refineries, EPA's Office. ofRegulatory Enforcement, and EPA's Region 6.

F. "Applicable State Agency" shall mean, with respect to the Savarmah'Refinery, the

Georgia Department ofNatural Resources; with.respect to the Lemont Refinery, the Illinois

Environmental Protection Agency; with respect to the Paulsboro Refinery, the New Jersey

11
Department ofEnvironmental Protection; and with respect to the Corpus Christi East and Corpus

Christi West Refineries, as used in Paragraphs 131, 132 and 134 ofthis Consent Decree only, the

Texas Commission on Environmental Quality. As used in Paragraphs 131~ 132 and 134 ofthis

Consent Decree only, "Applicable State Agency" shall also include any regional or local air

quality board that issues pennits referred to in those Paragraphs.

G. "Calendar quarter" shall mean the three month period ending on March 31", June 30th,

Septeinber 30th, and December 31st.

H. "CEMS" shaH mean continuous emissions monitoring system.

I. "CITGO" shall mean CITGO Petroleum Corporation, CITGO Refming and Chemicals

Company, L.P., PDV Midwest Refining, L.L.C., and CITGO AsphaltRefining Company, their

successors and assigns.

J. "Consent Decree" or "Decree" shall mean this Consent Decree, including any and all

appendices attached to the Consent Decree.

K. "Corpus Christi East Refinery" shall mean the refinery owned and operated by

CITGO and located at 180I Nueces Bay Boulevard, Corpus Christi, Texas.

L. "Corpus Christi West Refmery" shall mean the refinery owned and operated by

CITGO and located at 7350 Interstate Hwy. 37, Corpus Christi, Texas.

M. "Covered FCCUs" shall mean the following six FCCUs that CITGO owns and

operates:

• Corpus Christi FCCU # I at the Corpus Christi East Refinery

• Corpus Christi FCCU # 2 at the Corpus Christi East Refinery

• Lake Charles FCCUs # A, B, and C at the Lake Charles Refinery

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• Lemont FCCU at the Lemont Refinery

N, "Covered Refineries" shall mean the following refineries that are subject to the

requirements ofthis Consent Decree: the Corpus Christi East and Corpus Christi West Refinery,

the Lake Charles Refinery, the Lemont Refinery, the Paulsboro Refinery, and the Savannah

Refinery.

O. "CO" shall mean carbon monoxide.

P. "Current Generation Ultra-Low NOx Burners" shall mean those burners that are

designed to achieve a NOx emission rate of 0.020 to 0.040 Ib/mmBTU HHV when firing natural

gas at 3% stack oxygen at full design load without air preheat, regardless ofwhether upon

installation actual emissions exceed 0.040 Ib/mroBTUHHV.

Q.. "Date ofLodging" or "Date ofLodging ofthe Consent Decree" shall mean the date

the Consent Decree is lodged with the Clerk ofthe Court for the United States District Court for

the Southern District ofTexas.

R "Date ofEntry" or "Date ofEntry ofthe Consent Decree" shall mean the date the

Consent Decree is entered by the United States District Court for the Southern District ofTexas.

S. "Day" or "Days" shall mean a calendar day or days.

T. ''FCCU'' shall mean a fluidized catalytic cracking unit, its regenerator and associated

CO boiler(s) where present.

U. "Flaring Device" shall mean an AG and/or an HC Flaring Device,

V. "Fuel Oil" shall mean any liquid fossil fuel with sulfur content of greater than 0.05%

by weight.

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W. "Full Burn Operation" shall mean when essentially all ofthe CO produced in the

FCCU regenerator is converted to CO, inside the regenerator and there is excess 0, present in the

regenerator flue gas. Specifically, for the Lemont FCCU, Full Burn Operation shall occur when

.less than. 500 ppm CO and greater than 0.2% 0, by volume is present in the regenerator flue gas,

and for COlpus Christi FCCU #1, Full Bum Operation shall occur when greater than 0.2% O2 by

volume is present in the regenerator flue gas.

X. "GDNR" shall mean the Georgia Department ofNatural Resources and any successor

departments or agencies ofthe State of Georgia.

Y. "Hydrocarbon Flaring" Or "HC Flaring" shall mean the combustion of

refmery-generated gases, except for Acid Gas and/or Sour Water Stripper Gas and/or Tail Gas, in

a Hydrocarbon Flaring Device. Nothing in this definition shall be construed to modifY, limit, or

affect EPA's authority to regulate the flaring of gases that do not fall within the definitions

contained in this Consent Decree.

Z. "Hydrocarbon Flaring Device" or "HC Flaring Device" shall mean the devices listed

in Appendix Bthat are used by the. Covered Refmeries to control (through combustion) any

excess. volume of a refmery-generated gas other than Acid Gas and/or Sour Water Stripper Gas

and/or Tail Gas. To the extent that any Covered Refinery utilizes Flaring Devices other than

those specified in Appendix B for the purpose of combusting any excess of a refmery-generated

gas other than Acid Gas and/or Sour Water Stripper Gas, those Flaring Devices shall be He

Flaring Devices and shall be subject to the provisions ofthis Consent Decree.

AA. "Hydrocarbon Flaring lncident" or "HC Flaring lncident" shall mean the continuous

or intermittent flaring ofrefinery-generated gases, except for Acid Gas or Sour Water Stripper

14
Gas or Tail Gas, at a Hydrocarbon Flaring Device that results in the emission ofsulfur dioxide

equal to, or greater than five hundred (500) pounds in a 24-hour period. Where such continuous

or intennittent flaring from a Hydrocarbon Flaring Device continues into subsequent, contiguous,

non-overlapping twenty-four (24) hour period(s), and sulfur dioxide. equal to, or in excess of,

five-hundred (500) pounds is emitted in each subsequent, contiguous, non-overlapping twentyfour (24) hourperiod(s), then only one HC Flaring Incident shall have occurred. Subsequent,

contiguous, non-overlapping twenty-four (24) hour periods are measured from the in.itial

commencement offlaring within the HC Flaring Incident.

BB. "Hydrotreater Outage" shall mean the period oftime during which the FCCD

operation is affected as a result ofcatalyst change-out operations, shutdowns required by ASME

pressure vessel requirements or state boiler codes, or as a result ofMalfunction, that prevents the

hydrotreater from effectively producing the quantity and quality offeed necessary to achieve

established FCCD emission perfonnance.

CC. "IEPA" shall mean the Illinois Envirorunental Protection Agency and any successor

departments or agencies ofthe State ofIllinois.

DD. "Incremental NOx Reduction Factor" and "Incremental S02 Pick-up Factor" shall

mean:

PE.. - PE..I

CAR;-CAR;l

where:

PR;

=Pollutant (NOx or S02 ) reduction rate at increment i in pounds per day from the

baseline

15
PR;-l

=Pollutant (NOx or S02 )reduction rate at the increment prior to increment i inpounds'

per day from the baseline

CAR;

=Pollutant (NOx or S02 ) Reducing Catalyst Additive Rate at increment i in pounds per

day from the baseline

CAR;_1

=Pollutant (NOx or S02) Reducing Catalyst Additive Rate at the increment prior to

increment i in pounds per day from the baseline

EE. "Lake Charles Refinery" shall mean the refmery owned and operated by CITGO and

located in Lake Charles, Louisiana;

FF. "LDEQ" shall mean the Louisiana Department ofEnvironmental Quality and any

successor departments or agencies ofthe State ofLouisiana.

GG. "Lemont Refinery" shall mean the refinery owned and operated by CITGO and

located in Lemont, lllinois;

. HH. "Low NOx Combustion Promoter" shall mean a catalyst that contains no platinum

that is added to an FCCD, consistent with Appendix D, or such other technology as may be

approved by EPA,. that minimizes NOx formation while maintaining its effectiveness as a

combustion promoter.

II. "Malfunction" shall mean, as specified in 40 C.F.R. Part 60.2, "any sudden,

infrequent, and not reasonably preventable failure of air pollution control equipment, process

equipment, or a process to operate in a normal or usual manner. Failures that are caused in part

by poor maintenance or careless operation are not malfunctions."

JJ. "Natural Gas Curtailment" shall mean a restriction imposed by a natural gas supplier,

, which limits CITGO's ability to obtain natural gas.

16
KK. "Next Generation Ultra-Low NOx. Burners" or ''Next Generation ULNBs" shall

mean those burners that are designed to achieve a NOx emission rate ofless than or equal to

0.020 Ibl mmBTU HHV when firing natural gas at 3% stack oxygen at full design load without

air preheat, regardless ofwhether upon installation.actual emissions exceed 0:020 Ib/mmBTU

HHV.

LL. "NJDEP" shall mean the New Jersey Department ofEnviroIlIIlental Protection and

any successor departments or agencies ofthe State ofNew Jersey.

MM. "NOx" shall mean nitrogen oxides.

NN. "NOx Additives" shall mean Low NOx Combustion Promoters and NOx Reducing·

Catalyst Additives.

00. "NOx Reducing Catalyst Additive" shall mean a catalyst additive that is introduced

to an FCCU to reduce NOx emissions through reduction or controlled oxidation ofintermediates.

PP. "NSPS. Hydrocarbon Flaring Device" or "NSPS HC Flaring Device" shall mean the

Hydrocarbon Flaring Devices listed in Appendix B-1 which are, or will be, regUlated as fuel gas

combustion devices underNSPS Subparts A and J.

QQ. "Paragraph" shall mean a portion ofthis Consent Decree identified by an arabic

numeral.

RR. "PM" shall mean particulate matter.

SS. "Parties" shall mean the Uriited States, the Co-Plaintiffs, and CITGO.

TT. "Paulsboro Refinery" shall mean the asphalt refinery owned and operated by CITGO

and located in Paulsboro, New Jersey.

17
UU. "Co-Plaintiffs" shall mean the States ofGeorgia, Illinois, Louisiana, and New

Jersey.

VV. "Pollutant Reducing Catalyst Additive" shall mean either a NOx Reducing Catalyst

Additive or a S02 Reducing Catalyst Additive.

WW. "Root Cause" shall mean the primary cause(s) ofAG Flaring fucident(s),

Hydrocarbon Flaring fucident(s), or Tail Gas Incident(s), as determined through a process of

investigation.

XX. "Savannah Refinery" shall mean the asphalt refinery owned and operated by CITGO

and located in Savannah, Georgia.

YY. "Scheduled Maintenance" shall mean any shutdown ofany emission unit or control

equipment that CITGO schedules at least fourteen (14) days in advance. ofthe shutdown for the

.purpose ofundertaking maintenance ofsuch unit or control equipment.

ZZ. "Shutdown" shall mean the cessation of operation of an llffected facility for any

purpose.

AAA. "Sour Water Stripper Gas" or "SWS Gas" shall mean the gas produced by the

process ofstripping or scrubbing refinery sour water.

. BBB. "S02 Reducing Catalyst Additive" shall mean a catalyst additive that is introduced

to an FCCD to reduce S02 emissions by reduction and adsorption.

CCC. "Startup", as specified in 40 C.F.R.Section 60.2, shall mean the. setting in

operation of an affected facility for any purpose.

DDD. "SOt shall mean sulfur dioxide.

18
EEE. "SRP" or "Claus Sulfur Recovery Plant" shall mean a process unit that recovers

sulfur from hydrogen sulfide by a vapor phase catalytic reaction ofsulfur dioxide and hydrogen

sulfide.

FFF. "Tail Gas" or "TG" shall mean exhaust gas from the Claus trains andJor the tail gas

unit ("TOU") section ofthe SRP.

GGG. "Tail Gas Unit" or "TGU" shall mean a control system utilizing a technology for

reducing emissions ofsulfur compounds from a Claus SulfurRecovery Plant.

HHH. "Tail Gas Incident" shall mean combustion ofTail Gas that either is:

1. combusted in a flare and results in 500 pounds or more of S02 emissions in any 24

hour period; or

ii. combusted in a thennalincinerator and results in excess emissions of 500 pounds or

more ofS02 in any 24-hour period. Only those time periods which are in excess of a S02

concentration of250 ppm(rolling 12-hollr average) shall be used to detennine the amount

of excess S02 emissions from the incinerator.

CITGO shall use engineering judgment andJor other monitoring data to estimate emissions

during periods in which the S02 continuous. emission analyzer has exceeded the. range ofthe

instrument or is out ofservice.

m. "Total Catalyst" shall mean all fonus of catalyst added to the FCCU, including but

not limited to base catalyst and equilibrium catalyst, but excluding PollutantReducing Catalyst

Additive.

JJJ. "Upstream Process Units" shall mean all amine contactors, amine scrubbers, and

sour water strippers at the Covered Refineries, as well as all process units at these refineries that

produce gaseous or aqueous waste streams that are processed at amine contactors, amine

scrubbers, or sour water strippers.

19
KKK. "Weight %Pollutant Reducing Catalyst Additive Rate" shall mean:

Amount ofPollutant Reducing CatalYSt Additive (Ib/day)

Amount ofTotal Catalyst added (Ib/day)

x 100%

V. AFFIRMATIVE RELIEF / ENVIRONMENTAL PROJECTS

A. NOx EMISSIONS REDUCTIONS FROM FCCUs.

11. General.. CITGO shall implement a program to reduce NOx emissions from the

Covered FCCUs. Pursuant to Section V.N ofthis Consent Decree, CITGO shall apply for

permits containing NO, emission limits established under this Consent Decree. CITGO will

monitor compliance with the emission limits through the use ofCEMS.

12. Continuous Emissions Monitoring Systems ("CEMS"). Beginning no later than

the dates listed below, CITGO shall, connnence operation of, calibrate and certifjr CEMS for

NOx,Oz, SOz, CO and Opacity at the following FCCUs:

Oz . SOz NOx CO Opacity

Corpus Christi Date of April 1, 2007 Date ofEntry April 1, 2007 Date ofEntry

East #1 .Entry

Corplls Christi Date of Date ofEntry Date ofEntry Date ofEntry Date ofEntry

East #2 Entry

Lake Charles October 1, OctoberI, October 1, October 1, October 1,

Unit A 2005 2005 2005 2005 2005

Lake Charles October 1, October 1, October 1, October 1, October 1,

UnitB 2005 2005 2005 2005 2005

Lake Charles October I, OctoberI, October I, October I, October 1,

UnitC 2005 2005 2005 2005 2005

Lemont Date of Date ofEntry Date ofEntry Date ofEntry Date ofEntry

Entry

20
The CEMS shall be installed, calibrated and certified in accordance with 40 C.F.R. § 60.13 and·

Part 60 Appendices A and F, and the applicable perfonnance specification test of40 C.F.R. Part

60 Appendix B. However, in lieu ofthe requirements of 40 C.F.R. Part 60, Appendix F §§ 5.1.1,

5T3, and 5.1.4, CITGO may conduct: (1) either aRelative Accuracy Audit ("RAA") or a

Relative AccuracyTest Audit ("RATA'') once every three (3) years; and (2) a Cylinder Gas

Audit ("CGA") each calendar quarter in which a RAA or RATA is not perfonned. The Parties

agree that the CEMS may need to be moved and reinstalled because ofthe installation ofcontrol

equipment, and that once moved will need to be re-calibrated and re-certified. If use of a

continuous opacity monitor ("COMS") is not feasible on an FCCU with a Wet Gas Scrubber,

CITGO shall submit to EPA an alternative monitoring plan no later than six (6) months prior to

the date CITGO intends to commence. operation of each Wet Gas Scrubber ("WGS").

13. NOx Emission Limit at Corpus Cbristi FCCD 2. Beginning no later than June I,

2005, CITGO shall comply with an interimNO, emission limitof23 ppmvd at 0%02 on a 365-

day rolling average basis and 60 ppmvd at 0% O2 on a 24-hour rolling average basis from FCCU

2 at the Corpus Christi East Refmery ("Corpus Christi FCCU 2").

14. [Intentionally left blank]

15. [Intentionallylefiblank]

16.. NOx Minimization Study at Corous Christi FCCD 2. By no later than June 1,

2005, CITGO shall begin a 2-month study ofthe Corpus Christi FCCU 2 regenerator in an effort

to minimize NOx emissions by minimizing regenerator oxygen and usage ofplatinum

combustion promoter to the extent practicable without creating a safety problem, interfering with

conversion or processing rates, yield selectivity or otherwise exceeding previously established

21
and complied with operating limits, provided such cannot be reasonably compensated for by

adjustment(s) to other operating parameters. ("NOx Minimization Study"). By no later than

August 31, 2005, CITGO shall submit the results ofsuch NOx Minimization Study to EPA. As

part ofthe NOx Minimization Study, CITGO shall provide ail ofthe parameters listed in

Paragraph 19 on a daily average basis during the NOx Minimization Study. Upon request by

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

evaluate the NOx Minimization Study.

17. NOx Minimization Protocol for Corpus Christi FCCD 2. By no later than

August 31, 2005, CITGO shall propose for EPA review and approval a protocol for operation of

Corpus Christi FCCU 2 in a way that minimizes NOx emissions to the extent practicable and

without creating a safety problem, interfering with conversion or processing rates, yield

selectivity or otherwise exceeding previously established and complied with operating limits,

provided such cannot be reasonably compensated for by adjustment(s) to other operating

parameters (UNOx Minimization Protocol").

18. NOx Minimizatiou Demoustration at the Corpus Christi FCCD 2. By no later

than November 30, 2005, CITGO shall begin an 18cmonth demonstration ("Demonstration

Period") ofCorpus Christi FCCU 2 to establish long term (I.e., 365-day rolling average) and

short term (e.g., 7-day or 24-hour rolling average) emission limits for NOx in ppmvd at 0% Oz.

During the Demonstration Period, CITGO shall operate Corpus Christi FCCU 2 in accordance

with the EPA-approved NOx Minimization Protocol.

19. NOxMinimization Demonstration Report for Corpns Christi FCCD 2. Byno

later than August 31, 2007, CITGO shall report the results ofthe demonstration (''NOx

22
Minimization Demonstration Report") to EPA. The NOx Minimization Demonstration Report

shall include, at a minimum, the NOx and O2 CEMS data recorded during the Demonstration

Period and the following data on a daily or daily average basis as measured directly (where

available) or as calculated (where necessary):

a. Regenerator bed, dilute phase, cyclone and flue gas, temperatures;

b. Coke burn rate in pounds per hour;

c. FCCD feed rate in barrels per day;

d. FCCD feed API gravity;

e. FCCD feed sulfur and basic nitrogen (where available) content as a weight %;

f. Estimated percentage, and where available, actual percentage of each type of

FCCD feed component (i.e. atmospheric gas oil, vacuum gas oil, atmospheric

tower bottoms, vacuum tower bottoms, etc.);

g. Estimated percentage, and where available, actual percentage by volume ofthe

FCCD feed that is hydrotreated;

h. FCCD feed hydrotreatyr reactor pressures and temperatures;

i. CO boiler firing rate and fuel type, if applicable;

J. CO boiler combustion temperature, if applicable;

k. Total Catalyst addition and catalyst circulation rates;

1. Conventional combustion promoter addition rates;

m, Hourly and daily volume percent oxygen in the regenerator fuel gas and at the

point ofCEMs measurement; and

n. Hourly and daily SOz, NOx, and CO mass emission rates in pounds per hour, tons

per year, and concentrations in ppmvd at 0% oxygen. .

Upon request by EPA, CITGO shall submit any additional, reasonably available data to EPA.

In the NOx Minimization Demonstration Report, CITGO shall propose a short term (i.e.,

7-day and 24-hour rolling average) and a 365-day rolling average concentration-based (ppmvd)

NOx emission limits, as measured at 0% Oz. CITGO shall comply with the emission limits it

proposes for Corpus Christi Fccu 2 beginning immediately upon submission ofthe NOx

Minimization Demonstration Report. CrrGO shall continue to comply with these limits unless

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

Paragraph 20.

23
20. Establishine NO:!; Emission Limits for Corpus Christi FCCU 2. EPA will use

the data collected about the Corpus Christi FCCU 2 during the NOx Minimization Study and the

Demonstration Period, as well as all other available and relevant information, to establish limits

which can be met with a reasonable certainty of compliance but which shall be no lower than 20

ppmvd at 0% oxygen on a 365-day rolling average basis and no higher than 23 ppmvd at 0%

oxygen on a 365-day rolling average basis for NOx emissions from Corpus Christi FCCU 2.

Upon request by EPA, CITGO shall submit any additional, readily available data that EPA

detemrines it needs to evaluate the demonstration. EPA will establish a short-term (e.g., 24-hour

or 7-day rolling average) and a 365-day rolling average concentration-based (ppmvd) NOx

emission limit corrected to 0% oxygen, provided, however, that ifEPA establishes a 365-day

rolling average concentration-based NOx limit of20 ppmvd at 0% oxygen, the short-term limit

will then be 40 ppmvd at 0% oxygen (7-day rolling average). EPA will determine the limits

based on:. (i) the level ofperformance during the baseline, Minimization Study and

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

relevant information. EPA will notify CITGO ofits determination ofthe concentration-based

NOx emissions limit and averaging times. EPA may establish alternative emissions limits to be

applicable during alternative operating scenarios (e.g., during HydrotreaterOutages). CITGO

shall immediately (or within thirty (30) days, ifEPA's limit is more stringent than the limit

proposed. by CITGO) 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 ofthis Decree; provided however, that during the period of

24
dispute resolution, CITGO shal1 comply with the emission limits it proposed Wlder Paragraph 19.

CITGO shal1 demonstrate compliance with its emission limits pursuant to Paragraph 31.

21. Conversion ofCorpus Christi FCCD 1 and the Lemont FCCD to Full Burn

Operation. CITGO shal1 no later than December 31, 2006 either convert FCCD 1 at the Corpus

Christi East Refinery ("Corpus Christi FCCD I ") to Fu11Burn Operation, or accept and agree to

comply with concentration based emission limits of 20 ppmvd on a 365-day rolling average and

40 ppmvd on a 7-day roIling average basis, both at 0% oxygen, at the Corpus Christi FCCD 1.

CITGO shal1 no later than December 31, 2007 either convert the FCCD at the Lemont Refinery

("LerilOnt FCCU') to Ful1 Burn Operation, or accept and agree to comply with concentration

.based emission limits of 20 ppmvd on a 365-day rol1ing average and 40 ppmvd on a 7-day rol1ing

. average basis, both at 0% oxygen, at the Lemont FCCD. As part ofthe conversion to Ful1 Bum

.Operation, eITGO shall take into account changes that may be necessary to accommodateLow

NOx Combustion Promoter at the maximum operating rate of each FCeD while controIIing

afterburn adequately and maintaining CO emissions at compliant levels.

22. Installation ofLow NO}: Burners in Lemont CO Boiler. By no later than

December 31,2007, CITGO shal1 instal1 low NOx burners designed to achieve 0.060 Ib/mmBTU

HHV ofNOx in the FCCD CO Boiler at the Lemont Refinery (assuming no air preheat and the

use ofnatural gas) to reduce NOxemissions from combustion ofauxiliary fuel.

23. Dse of Low NOx Combustion Promoters and NOx Reducing Catalyst

Additives at the Corpus Christi 1, Lake Charles A, Lake Charles B, Lake Charles C and

Lemont FCCDs: In General. CITGO sha1l implement a program to reduce NOx emissions

from the Corpus Christi 1, Lake Charles A, Lake Charles S, Lake Charles C and Lemont FCCDs

25
.(collectively, "Corpus Christi I, Lake Charles, and Lemont FCCUs"). As required underSection

V.N. ofthis Consent Decree, CITGO shall apply for permits containing new NOx emission limits

and will use CEMS to monitor for compliance with the emission limits.

24. NO" Baseline Data for the Corpus Christi 1, Lake Charles, arid Lemont

FCCUs. CITGO shall for each FCCU listed in the following table, no later than the dates

specified in the table, submit to the Applicable Federal and State Agencies a report of at least

. twelve (12) months ofbaseline data, including baseline data for the baseline periods specified in

the table:

FCCD Baseline Start Baseline End . Report

Corpus Christi I April I, 2007 March 31, 2008 June 30, 2008

Lake Charles A October 1, 2005. September 30, 2006 December 31, 2006

Lake Charles B October 1, 2005 September 30, 2006 . December 31, 2006

Lake Charles C October 1, 2005 September 30, 2006 December 31, 2006

Lemont April 1, 2008 March 31, 2009 June 30, 2009

The. baseline data shall include at a minimum, the data set forth in Paragraph 19.

25. [Intentionally Left Blank]

26. Low-NOx Combustion Promoter - Short-Term Trials for the Corpus Christi 1,

Lake Charles, and Lemont FCeDs.

a. Identification and Selection ofLew NOx Combustion Promoters for Trial Use. By the

following dates, CITGO shall select and submit for EPA approval at least two commercially

available Lew NOx Combustion Promoters that CITGO proposes to use for later short-term trials

26
at the Corpus Christi 1, Lake Charles, and Lemont FCCDs and shall submit a protocol for

conducting the trials by the following dates:

Corpus Christi 1:

Lake Charles A:

Lake Charles B:

Lake Charles C:

Lemont:

December 31,. 2007

June 30, 2006

June 30, 2006

June 30, 2006

December 31, 2008

CITGO shall propose use. of at least two Low NOx Combustion Promoters that are likely to

perform the best at reducing NOx emissions in each FCCD. EPA will base its approval or

disapproval on its assessment ofthe performance ofthe proposed PrOmoters in other FCCDs and

the similarity ofthose FCCDs to ClTGO's FCCDs, with the. objective oftestingLow NOx

Combustion Promoters likely to have the best performance in reducing NOx emissions while

adequately combusting CO in the FCCD regenerator.. IfEPA objects to one or mote ofthe

proposed Low NOx Combustion Promoters, EPA will explain the basis ofits objectionsin

writing. In the event that CITGO submits less than two approvable Promoters, EPA shall

identifY and by that identification approve the use. of other Low NOx Combustion Promoters. by

CITGO.

27
b. Minimization ofUse. ofConventional Pt-Based Combustion Promoter. CITGO shall

commence and complete a program ofminiIirization ofuse of conventional Platinum-based

("Pt-based") combustion promoter to the amount necessary to adequately control afterburn.

CITGO shall complete this program in accordance with the protocol set forth in Appendix D by

the following dates for each ofthe following FeCUs:

FeeD Commence Date Complete Date

Corpus Christi I April 1,2008 June. 30, 2008

Lake Charles A October 1, 2006 December 31, 2006

Lake Charles B October 1, 2006 December 31, 2006

Lake. Charles C October 1, 2006 December 31·, 2006

Lemont April I, 2009 June 30, 2009

c. Short-Term Trials ofLow NOx Combustion Promoters.. CITGO shall conduct trials of

at least two. EPA-approved Low NOx Combustion Promoters that were selected and approved

under Subparagraph 26a, and such other Low NOx Combustion Promoters as CIIGO may elect,

for each ofthe following FCCUs in accordance with Appendix D by the following dates:

FCCD Cornrnence.Date

Corpus Christi 1 July 1, 2008

Lake Charles A January 1, 2007

Lake Charles B January 1, 2007

Lake Charles C January I, 2007

Lemont July 1, 2009

28
d. Report on Results of Short-Term Trials. and Minimization Program for Conventional

Pt-Based Combustion Promoters. CITGO shall submit a report to EPA that describes the results

ofthe minimization of use ofconventional Pt-based combustion promoter and the performance

of each Low NOx Combustion Promoter that was tested by the following dates for each ofthe

following FCCDs:

FceD Report Date

Corpus Christi 1 December 31, 2008

Lake Charles A June 30, 2007

Lake Charles B June 30, 2007

Lake Charles. C June 30, 2007

Lemont, December 31, 2009

ill the report, CITGO shall propose to use the best performing Combustion Promoter,as

demonstrated and explained by CITGO (e.g. by percentage. ofNOx emissions reduced and the

concentration to which NO. emissions were reduced in the trials without creating a safety

problem or limiting conversion rates, processing rates or yield selectivity).

e. EPA Approval ofCombustion Promoters. For each ofthe five FCCDs subject to this

Paragraph, EPA will either approve the Low NOx Combustion Promoter proposed by CITGO,

approve another Low NOx Combustion Promoter that was tested by CITGO, or approve the use

of a conventional Pt-based promoter based on the criteria in Appendix D. IfEPA objects to

CITGO's selection ofLow NOx Combustion Promoter or conventional Pt-based promoter, EPA

will explain the basis ofits objections in writing. Upon request by EPA, CITGO shall submit

any additional, reasonably available data that EPA determines it needs to evaluate the trials.

29
CITGO shall use the approved Low NOx Combustion Promoter, or if applicable, a conventional

Pt-based combustion promoter under the terms ofAppendix D.

f. Discontinuance ofLow NOx Combustion Promoters. CITGO may, upon EPA

approval, discontinue use of a Low NOx Combustion Promoter at a particular FeCU ifClTGO

demonstrates that, as to that particular FCCU, CITGO has adjusted other parameters and the

Promoter being used does not adequately control afterburn and/or causes. CO emissions to

approach or exceed applicable limits and/or exceeds safe operation limits. or equipment design

limits. Notwithstanding the foregoing, CITGO shall not be required to adjust operating

parameters in a way that would create a safety problem or limit conversion rates, processing rates

or yield selectivity.

g. Use ofConventional Pt-Based Combustion Promoter. CITGO may use conventional

Pt-based combustion promoter on an intermittent basis during the short-term trials under this

Paragraph, and the short-term trials, optimization studies and demonstration periods under

Paragraphs 27, 28, and 29, as needed to avoid unsafe operation ofthe FCCU regenerator and to

comply with CO emission limits. CITGO shall undertake all reasonable measures and/or adjust

operating parameters with a goal of eliminating such use. Notwithstanding the foregoing,

CITGO shall not be required to adjust operating parameters in a way that would create a safety

problem or limit conversion rates, processing rates or yield selectivity.

27. NOx Reducing Catalyst Additives - Short-Term Trials at the Corpus Christi 1,

Lake Charles and Lemont FCCUs.

a. Identification and Selection ofNOx Reducing Catalyst Additives for Trial Use.

CITGO shall select and submit for EPA approval at least two commercially available NOx

30
Reducing Catalyst Additives that CITGO proposes to use for later short-tenn trials at the Corpus

Christi 1, Lake Charles and Lemont FCCDs and shall submit a protocol for conducting the trials

by the following dates:

FCCD

Corpus Christi 1

Lake Charles A

Lake Charles B

Lake Charles C

Lemont

Report Date

December 31, 2009

June 30, 2008

December 31,2006

December 31,. 2006

June 30, 2009

CITGO shall propose use ofat least two NOx Reducing Catalyst Additives that are likely to

perform the best at reducingNOx emissions in each FCCD. EPA will base itsapproval or

disapproval on its assessment ofthe performance ofthe proposed Additives in other FCCDs and

the similarity ofthose FCCDs to CITGO's FCCDs, with the objective oftesting NOx Reducing

Catalyst Additives likely to have the best performance in reducing NOx emissions. IfEPA

objects to one. or more ofthe proposed NOx Reducing Catalyst Additives, EPA will explain the

basis ofits objections in writing. In the event that CITGO submits less than two approvable NOx

Reducing Catalyst Additives, EPA shall identifY and by that identification approve the use of

other NOx Reducing Catalyst Additives by CITGO.

31
b. Short-Tenn Trials. ofNOx Reducing Catalyst Additives. CITGO shall conduct trials

of at least two EPA-approved NOx Reducing Catalyst Additives, and such other NOx Reducing

Catalyst Additives as CITGO may elect, for each ofthe following FCCDs in accordance with the

protocol approved pursuant to Subparagraph 27.a as soon as. practicable, but by no later than the

following dates:

FCCU Commence Date Complete Date

Corpus Christi 1 July 1, 2010 December 31, 2010

Lake Charles A January 1, 2009 June 30, 2009

.Lake Charles B July 1, 2007 December 31, 2007

Lake Charles C July 1,2007 December 31, 2007

.

Lemont January 1, 2010 June 30, 2010

c. Report on the Performance ofNOx Reducing Catalyst Additives. CITGO shall submit

a report to EPA that describes the performance of each NOx Reducing Catalyst Additive that was

tested no later thanthe following dates for each ofthe following FCCDs:

FCCU

Corpus Christi 1

Lake Charles. A

Lake Charles B

Lake Charles C

Lemont

Report Date

February 28, 2011

August 31, 2009

February 28, 2008

. February 28, 2008

August 31, 2010

In the report, CITGO shaH propose to use the. best performing NOx Reducing Catalyst Additive,

as demonstrated and explained by CITGO (e.g. by percentage ofNOx emissions reduced and the

concentration to which NOx emissions were reduced in the trials without creating a safety

problem or limiting conversion rates, processing rates or yield selectivity, provided such cannot.

reasonably be compensated for by adjustment(s) to other operating parameters).

32
d. EPA Approval ofthe NOx Reducing Catalyst Additives. EPA will either approve the

NOx Reducing Catalyst Additive proposed by CITGO or approve another NOx Reducing

Catalyst Additive that was tested. Upon request by EPA, CITGO shall submit any additional,

reasonably available data that EPA determines it needs. to evaluate the trials.. IfEPA objects to

CITGO's selection of a NOx Reducing Catalyst Additive, EPA will explain the basis ofits

objections in writing. CITGO shall use the approved NOx Reducing Catalyst Additive selected

pursuant to this Paragraph in the Optimization Studies and Demonstration Periods required

. pursuant to Paragraphs 28 and 29.

28. NOx Reducing Catalyst Additives - Optimization Studies at the Corpus

Christi 1, Lake Charles and Lemont FCCDs.

a. Optimization Study Protocol. CITGO shall submit, for EPA approval, a proposed

protocol consistent with the requirements ofAppendix D for optimization studies to establish the

optimized NOx Reducing Catalyst Additive and combustion promoter addition rates by the

following dates for each ofthe following FCCDs:

FCCD

Corpus Christi I

Lake Charles A

Lake Charles B

Lake Charles C

Lemont

Deadline

February 28,. 2011

August 31, 2009

February 28, 2008

February 28,2008

August 31,2010

The protocol shall include identification ofthe NOx Reducing Catalyst Additive, methods to

calculate effectiveness, cost effectiveness, methods for base loading, and percent NOx Reducing

Catalyst Additive used at each increment tested.

33
. b. Optimization Studies. CITGO shall commence and complete the optimization study

of each NOx Reducing Catalyst Additive and combustion promoterselected under Paragraphs

27.d and 26.e in accordance with the approved protocol and with Appendix D by the following

dates for each ofthe following FCCUs:

FCCU

Corpus Christi 1

Lake Charles A

Lake Charles B

. Lake Charles C

Lemont

Commence Date

May I, 2011

November 1,2009

May 1,2008

May 1, 2008

November 1,2010

Complete Date

October 31,2011

April 31,2010

October 31, 2008

October 31, 2008

April 30, 2011

c. Optimization StudyRSlports. By the following dates for each ofthe FCCUs subject to

this Paragraph, CITGO shall report the results ofthe optimization studies and propose, for EPA

approval, optimized addition rates ofthe NOx Reducing Catalyst Additives. and combustion

promoters to be used for the demonstration period:

FCCU

Corpus Christi I

Lake Charles A

Lake Charles B

Lake Charles C

Lemont

Deadline

December 31, 2011

June 30, 2010 .

December 31, 2008

December 31,2008

June 30, 2011

Upon request by EPA, CITGO shall submit any additional, reasonably available data that EPA

determines it needs to evaluate the optimization study.

CITGO shall include in its report a description of any model CITGO used to predict

uncontrolled NOx concentration and mass emission rate unless CITGO agrees to add NOx

Reducing Catalyst Additive at 2.0 weight% as the optimized addition rate. Such description

shall describe how the model was developed, which parameters were considered, why parameters

34
were eliminated, efforts and results ofmodel validation, the statistical methods. used to arrive at

the equation to predict uncontrolled NOx concentration and mass emission rate and all data

considered in developing the model on a daily average basis. Upon request by E,PA, CITGO

shall submit any additional, reasonably available data that EPA determines it needs to evaluate

the model.

d. EPA Approval ofthe. Optimized Addition Rates. ofthe NOx Reducing Catalyst

Additives and Low NOx Combustion Promoters. EPA will either approve or disapprove each of

the optimized addition rates proposed by CITGO, CITGO will not berequired to add increasing

increments ofNOx Reducing Catalyst Additive beyond an additive rate. that results in any ofthe

following:

I. The FCCD meets 20 ppmvd NOx at 0% O2 on a 365-day rolling average, .

provided CITGO agrees to accept limits of20 ppmvd NOx at 0% O2 on a

365-day rolling average basis at the conclusion ofthe Demonstration

Period;

ii Incremental NOx Reducing Factor < 1.8. lb NOx/lb additive;

Ill. Total cost ofthe NOx Reducing Catalyst Additive> $10,000/ton NOx

removed;. or

iv. FCCU is operating at 2.0 Weight % NOx Reducing Catalyst Additive.

IfEPA disapproves the. proposed optimized addition rate for either the NOx Reducing Catalyst

Additives or Low NOx Combustion Promoters, EPA will explain the basis ofits disapproval in

writing, and will specifY the approved optimized addition rate.

35
29; NOx Reducing Catalyst Additives - Demonstration Periods fOT the Corpus

Christi I. Lake Charles and Lemont FCCUs.

a. Demonstration Period. CITGO shall commence and complete demonstration ofthe

NOx Reducing Catalyst Additive and the Low Nox Combustion Promoter at the final optimized

addition rates selected in Paragraph 28.d, or if applicable, a conventional Pt-based combustion

promoter under the terms ofAppendix D, by the following dates for each ofthe following

FCCUs;

FCCD

Corpus Christi 1

Lake Charles A

Lake Charles B

Lake Charles C

Lemont

Commence Date

January 1, 2012

July 1, 2010

January 1,2009

January 1,2009

July 1, 2011

Complete Date

June 30, 2013

December 31, 2011

June 30, 2010

. June 30, 2010

December3I,2012

For Corpus Christi FCCD I and Lake Charles FCCU A, the NOx Reducing Catalyst Additive,

Low NOx combustion Promoter and 802Reducing Catalyst Additive demonstrations. shall occur

simultaneously. During the demonstration period, CITGO shall add NOx Reducing Catalyst

Additive and operate the FCCUs, CO floilers (where they exist) and FCCU feed-hydrotreaters

(where they exist) in a manner that minimizes NOx emissions to the extent practicable without

creating a safety problem or limiting conversion rates, processing rates or yield selectivity,

provided such cannot be reasonably compensated for by adjustment(s) to other operating

parameters.

36
b. NOx Reducing Catalyst Additive Performance Demonstration Report (''NOx Additive

Demonstration Report"). CITGO will report the results ofthe demonstration ("NQx Additive

Demonstration Report") to EPA by the following dates for each ofthe following FCCUs:

FCCU

Corpus Christi I

Lake Charles A

Lake Charles B

Lake Charles C

Lemont

Report Date

September 30, 2013

March 31, 2012

September 30, 2010

September 30, 2010

March 31, 2013

Each NOx Additive Demonstration Report shall include, at a minimum, the NOx and O2 CEMS

data recorded during the Demonstration Period and all ofthe applicable parameters under

Paragraph 19 for the Demonstration Period.. In each NOx Additive Demonstration Report,

. CrrGO shall propose a short-term (Le., 24Chour and7-day rolling average) and a long-term (365-

day rolling average) concentration-based (ppmvd) NOx emission limit, both as measured at 0%

O2, for the Corpus Christi I, Lake Charles, and Lemont FCCUs. CrrGO shall comply with the

emission limits it proposes for each ofthese FCCUs beginning immediately upon submission of

the NOx Additive Demonstration Report for thatFCCU. CITOO shall continue to comply with

these limits unless and until CITGOis required to comply with the emissions. limits set by EPA

pursuant to. Paragraph 30. Upon request by EPA, CITOO shall submit any additional, reasonably

available data that EPA determines it needs to evaluate the demonstration.

30..Establishing NOx Emissions Limits at the Corpus Christi 1, Lake Charles and

Lemont FCCUs. EPA will use the data collected during the baseline period, the Optimization

Period, and the Demonstration Period, as well as all other available and relevant information, to

establish limits for NOx emissions from the Corpus Christi I, Lake Charles and Lemont FCCUs.

37
EPA will establish short,term (e.g., 24-hour or 7"day rolling average) and a 365-day rolling

average concentration-based (ppmvd) NOx emission limits, both corrected to 0% oxygen, which

limits. can be met by CITGOwith a reasonable certainty of compliance. EPA will determine the

limits based on:·(i) the level ofperformance during the baseline, Short-Term Trials, and

Optimization and Demonstration periods; (ii) a reasonable certainty of compliance; and (iii) any

other available and relevant information. EPA will notify CITGO ofits determination ofthe

concentration-based NOx emissions limit and averaging times for each FCCD. EPA may

establish altemative emissions limits to be applicable during altemativeoperating scenarios (e.g.,

during Hydrotreater Outages). CITGO shall immediately (or within thirty (30) days, ifEPA's

limit is more stringent than the. limit proposed by CITGO) operate the FCCD 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 ofthis Decree; provided

however, that during the period of dispute resolution, CITGO shall add additives in the manner

and amount applicable during the Demonstration Period (in lieu ofcomplying with the EPA

limits).

30A. Emission Limit Option. .CITGO may, at any time up to and including its

proposing emission limits under Paragraphs 19 and/or 29, accept and agree to comply

immediately with concentration based emission limits of20 ppmvd on a 365-day rolling average

and 40 ppmvd on a 7-day rolling average basis, both at 0% oxygen, for a particular FCCD. In

such circumstances, CITGO shall be absolved of any remaining obligations for that FCCU under

Paragraphs 13 through 30 ofthis Consent Decree.

38
31. Demonstrating Compliance with FCCU NOx Emission Limits for aU Covered

FCCUs. CITGO shall use NOx and O2CEMS to monitor performance and to report compliance

with the terms and conditions ofthis Consent Decree. CITao shall make. CEMS data available

to EPA as. soon as practicable following an EPA request for such data.

B. S02 EMISSIONS REDUCTIONS FROM FCCUs

32. .General. CITGO shall implement a program to reduce S02 emissions from the

Covered FCCDs. CITGO shall apply for permits containing new S02 emission limits established

under this Consent Decree, and CITGO will monitor compliance with the emission limits

through the use ofCEMS.

33. Installation of Wet Gas Scrubbers on the Lake Charles B, Lake Charles C, and

Lemont FCCUs. CITGO shall install and commence operation ofa Wet Gas Scrubber ("WaS")

and comply with a S02 emission limit of25 ppmvd at 0% O2on a 365-dayrolling average basis

and 50 ppmvd at 0% O2on a 7-dayrolling average basis for each ofthe following FCCDs by the

dates specified:

FCCU

Lake Charles FCCD B

Lake Charles FCCD C

Lemont FCCD

Deadline

December 31, 2006

December 31, 2007

December 31, 2007

34. Use of S02 Reducing Additives at the Corpus Christi }, Corpus Christi 2, and

Lake Charles A FCCUs: In General. As described below, CITGO shall implement a program

to reduce S02 emissions and establish lower FCCD S02 emission limits at the Corpus Christi 1,

Corpus Christi 2, and Lake Charles A FCCDs (collectively "Corpus Christi and Lake Charles A

FCCDs"), by using S02 Reducing Catalyst Additives.

39
35. SO, Baseline Data for the Corpus Christi andLake Charles A FCCDs. CITGO

shaIl for each FCCU listed in the following table, no later than the dates specified in the table,

submit to the Applicable Federal and State Agencies a report of at least twelve (12) months of

baseline data, including baseline data for the baseline periods specified in the table:

FCCU

Corpus Christi 1

Corpus Christi 2

Lake Charles A

Baseline. Start

April 1, 2007

October 1, 2005

October 1, 2005

Baseline. End

March31,2008

September 30, 2006

September 30, 2006

R6J1ort

June 30, 2008

December 31, 2006

December 31, 2006

The baseline data shall include at a minimum, the data set forth in Paragraph 19.

36. [Intentionally Left Blank].

37. SO, Reducing Catalyst Additives - Short-Term Trials for the Corpns Christi

and Lake Charles A FCCDs.

a Identification and Selection ofS02Reducing Catalyst Additives for Trial Use. By the

following dates, CITGO shall select and submit for EPA approval at least two commercially

available S02 Reducing Catalyst Additives that CITGO proposes to use for short-term trials at

the Corpus Christi and Lake Charles A FCCUs:

Corpus Christi 1

Corpus Christi 2

Lake Charles A

June 30, 2008

May31,2006

December 31, 2006

CITGO shall propose use of at least two S02 Reducing Catalyst Additives that are likely to

perfonn the best at reducing S02 emissions in each FCCU. EPA will base its approval or

disapproval. on its assessment ofthe performance ofthe proposed Additives in other FCCUs and·

the similarity ofthose FCCUs to CITGO's FCCUs, with the objective oftesting S02 Reducirtg

Catalyst Additives likely to have the best performance in reducing S02 emissions. IfEPA

40
objects to one or more ofthe proposed S02 Reducing Catalyst Additives, EPA will explain the

basis ofits objections in writing. In the event that CITGO submits less than two approvable

Additives, EPA shall identify and by that identification approve the use of other S02 Reducing

Catalyst Additives by ClTGO.

b. Short~Term Trials ofS02 Reducing Catalyst Additives. ClTGO shall conduct trials of

at least two EPA-approved S02 Reducing Catalyst Additives selected under Subparagraph 37a,

and such other S02 Reducing Catalyst Additives as ClTGO may elect, for each ofthe following

FCCUs in accordance with Appendix D by the following dates:

FCCU

Corpus Christi I

Corpus Christi 2

Lake Charles A

Commence Date

January I, 2009

January 1, 2007

July 1, 2007

Complete Date

June 30, 2009

June 30, 2007

December 31,2007

c. Report on the Performance ofthe S02 Reducing Catalyst Additiyes. ClTGO shall

. submit a report to EPA that describes the performance of each S02 Reducing Catalyst Additive

that was tested under Subparagraph 3Th by the following dates for each ofthe following FCCDs:

FCCU

Corpus Christi 1

Corpus Christi 2

Lake Charles A

Report Date

August 31, 2009

August 31, 2007

February 28,2008

In the report, CITGO shall propose to use the best performing additive as demonstrated and

explained by ClTGO (e.g., by percentage ofS02 emissions reduced and the conceotration to

which S02 emissions were reduced in the trials without creating a safety problem or limiting

conversion rates, processing rates or yield selectivity, provided such cannot reasonably be

compensated for by adjustment(s) to other operating parameters).

41
d. EPA Approval ofthe SO, Reducing Catalyst Additives. EPA will either approve the

S02 Reducing Catalyst Additive proposed by CITOO or approve another additive that was tested.

IfEPA objects to CITOO's selection of S02 Reducing Catalyst Additive, ~PA will explain the

basis ofits objections in writing. Upon request by EPA, CITOO shall submit any additional,

reasonably available data that EPA determines it needs to evaluate the trials. CITGO shall use

the S02 Reducing Catalyst Additive selected pursuant to this Paragraph in the. Optimization

Studies and Demonstration Periods required pursuant to Paragraphs 38 and 39.

38. SO, Reducing Catalyst Additives - Optimization Studies at the Corpus Christi

and Lake Charles A FCCUs.

a. Optimization Study Protocol. CITGO shall submit, for EPA approval, a proposed

protocol consistent with the requirements ofAppendix D for optimization studies to establish the

optimized S02 Reducing Catalyst Additive addition rates by the. following dates for each ofthe

following FCCUs:

Corpus Clrristi 1

Corpus Clrristi 2

Lake Charles A

August 31, 2009

August 31,2007

February 28, 2008

The protocol shall include identification ofthe S02 Reducing Catalyst Additive, methods to

calculate effectiveness, cost effectiveness, methods for base loading, and percent S02 Reducing.

Catalyst Additive used at each increment tested.

42
b. Optimization Studies. ClTOO shall commence and complete the optimization study

ofeach EPA-approved S02 Reducing Catalyst Additive in accordance with the approved

protocol and Appendix D by the following dates for each ofthe following FCCUs:

FCCU

Corpus Christi I

Corpus Christi 2'

Lake. Charles A

Commence Date

November I, 2009

November I, 2007

May 1,2008

Complete Date

April 30, 2010

Apri130, 2008

October 31, 2008

c. Optimization Study Reports. By the following dates for each ofthe FCCUs subject to

this Paragraph, ClTOO shall report the. results ofthe optimization study and propose, for EPA

approval, an optimized addition rate ofS02 Reducing Catalyst Additive to be used for the

demonstration period:

Corpus Christi. I

Corpus Christi 2

Lake Charles A

June 30, 2010

June 30, 2008

December 31, 2008

CITOO shall include in its report a description of any model CITOO used to predict uncontrolled

S02 concentration and mass emission rate unless ClTOO agrees to add S02 Reducing Catalyst

Additive at 10.0 weight % as the optimized addition rate. Such description shall describe how

the model was developed, which parameters were considered, why parameters were eliminated,

efforts and results ofmodel validation, the statistical methods used to· arrive at the equation to

predict uncontrolled S02 concentration and mass emission rate and all data considered in

developing the model on a daily average basis. Upon request by EPA, cITao shall submit any

additional, reasonably available data that EPA determines it needs to evaluate the model or the

optimization study. ClTaO shall use the approved S02 Reducing Catalyst Additive rate during

the Demonstration Periods required pursuant to Paragraph 39.

43
d. EPA Approval ofthe Optimized Addition Rate. ofthe SO, Reducing Catalyst

Additive. EPA will either approve or disapprove the optimized addition rate proposed by

CITGo. CITGO will not be required to add S02 Reducing Catalyst Additive beyond an additive

rate that results in any ofthe following;

I. The FCCD meets 25 ppmvd S02 at 0%02on a 365-day rolling average,

provided CITGO agrees to accept limits of25 ppmvd S02 at 0%02on a

365·day rolling average basis at the conclusion ofthe Demonstration

Period;

ii. Incremental S02 Pick-up Factor < 2.0 Ib SO,llb additive; or

111. FCCD is operating at 10.0 Weight % S02 reducing catalyst additive.

IfEPA disapproves the proposed optimized addition rate for the S02 Reducing Catalyst Additive,

EPA will explain the basis ofits. disapproval in writing, and will specifY the approved optimized

addition rate.

39. S02 Reducing Catalyst Additives - DemonstrationPeriods for tbe Corpus

Cbristi and Lake Charles A FCCUs:

a. Demonstration Period. CITGO shall commence and complete demonstration ofthe

final S02 Reducing Catalyst Additive at the optimized addition rates selected under Paragraph

38.d by the following dates. for each ofthe following FCCDs:

FCCD

Corpus Christi 1

Corpus Christi 2

Lake Charles A

Commence. Date

January 1, 2012

July 1, 2008

July 1,2010

Complete Date

June 30, 2013

December 31, 2009

December31,2011

For Corpus Christi FCeD 1 and Lake Charles FCCD A, the NOx Reducing Catalyst Additive,

Low NOx Combustion Promoter, and S02 Reducing Catalyst Additive demonstrations shall

occur simultaneously, During the demonstration for the Lake Charles FCCD A, CITGO shall

44
hydrotreat all ofthe FCCD feed to the Lake Charles FCCD A. During the demonstration period,

CIIGO shall add S02 Reducing Catalyst Additive and operate the FCCDs, CO Boilers (where

they exist) and FCCD feed hydrotreaters (where they exist) in amanner that millimizes S02

emissions to the extent practicable without creating a safety problem or limiting conversion rates,

processing rates or yield selectivity, provided such cannot be reasonably compensated for by

adjustrnent(s) to other operating parameters.

b. S02 Reducing Catalyst Additive Performance Demonstration Report ("S02 Additive

Demonstration Report"). CrrGO will report the results. ofthe demonstration ("S02 Additive

Demonstration Report") to EPA by the following dates. for each ofthe following FCCDs:

FCCD

Corpus Christi 1 .

Corpus Christi 2

Lake Charles A

Report Date

September 30, 2013

March 31, 2010

March 31, 2012

Each S02 Additive. Demonstration Report shall include, at a minimum, the S02 and O2 CEMS

data recorded. during the Demonstration Period and all ofthe applicable parameters under

Paragraph 19 for the Demonstration Period. In each S02 Additive Demonstration Report,

crrGO shall propose 7-day rolling average and 365-day rolling average concentration~based

(ppmvd) S02 emission limits as measured at 0% O2for the Corpus Christi and Lake. Charles A

FCCDs. CrrGO shall comply with the emission limits it proposes for each FCCD beginning

immediately upon submission ofthe S02 Additive Demonstration Report for that FCCD.

crrGO shall continue to comply with these limits unless and until it is required to comply with

the emissions limits set by EPA pursuant to Paragraph 40. Dpon request by EPA, CIIGO shall

45 .
submit any additional, reasonably available data that EPA determines it needs to evaluate the

demonstration.

40. Establishine S02 Emissions Limits (or the Corpus Christi and Lake Charles A

FCCDs. EPA will use the data collected during the baseline period, the Short-Term Trials, the'

Optimization Period, and the Demonstration Period, as well as all other available and relevant

information, to establish limits for S02 emissions from the Corpus Christi and Lake Charles A .

FCCDs. EPA will establish a 7-day rolling average and a 365-day rolling average concentrationbased (ppmvd) S02 emission limit corrected to 0% oxygen, which limits can be met with a

reasonable certainty of compliance. EPA will detennine the. limits.based on: (i) the level of

performance during the baseline, Optimization and Demonstration periods; (ii) a reasonable

certainty ofcompliance; and (iii) any other available and relevant information.. EPA will notify

CITGO ofits determination ofthe concentration-based S02 emissions limit and averaging times

for each FCCD. EPA may establish alternative emissions limits to be applicable during

alternative operating scenarios, including, for example, during Hydrotreater Outages. CITGO

shall immediately (or within thirty (30) days, ifEPA's limit is more stringent than the limit

proposed by CITGO) operate the FCCD 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 ofthis Decree; provided however, that during the period of

dispute resolution, CITGO shall add additives in the manner and amount applicable during the

Demonstration Period (in lieu ofmeeting the EPA limits).

40A. Emission Limit Option. CITGO may, at any time up to and including its

proposing emission limits under Paragraph 39, accept and agrce to comply immediately with

46·
47
C. PM EMISSIONS REDUCTIONS FROM FCCUs.

43. General. CITGO shall control and further reduc;e particulate matter ("PM")

emissions. from the Covered FCCUsby the installation and operation ofWGSs and/or third stage

separators ("TSS'') or continued operation of electrostatic precipitators ("ESPs").

44. PSD Emission Limits for Lake Charles and Lemont FCCDs

a. CITGO will install and commence operation of a WGS designed to achieve an

emission limit of0.5 pounds ofPM per 1000 pounds of coke burned on a 3-hour average basis

for the following FCCUs by no later than the dates set forth below for each FCCU:

Lake. Charles FCCD B

Lake Charles FCCU C

Lemont FCCU

December 31, 2006

December 31, 2007

December 31, 2007

b. Unless CITGO agrees to accept an emission limit of 0.5 pounds ofPM per 1000

pounds of coke burned on a 3-hour average basis, EPA will use the data collected under

Paragraph 47, as well as other, available and relevant informatiOn, to establish PM emission

limits for each FCCU which can be met with a reasonable certainty ofcompliance but which

shall be no lower than 0.5 pounds ofPM per 1000 pounds of coke burned on a 3-hour average

basis. EPA will determine the liinits based on : (i) the level ofperformahce during the

Performance Test(s); (ii) a reasonable certainty ofcompIiance; and (iii) any other available and

relevant information. EPA will notifY CITGO ofits determination of an appropriate emission

limit or limits. During any dispute under this Paragraph, CITGO shall continue to operate the

WGSs. required under this Paragraph in a manner consistent with good air pollution control

practices in lieu ofmeeting the EPA-established limit under this Paragraph.

48
45. PSD Emission Limits at the Corpus Christi 1, Corpus Christi 2, and Lake

Charles A FCCUs. At any time during the life ofthe Consent Decree, CITGO may accept a PM

emission limit of0.5 pounds ofPM per 1000 pounds of coke burned on a 3-hour average basis

for the Corpus Christi 1, Corpus Christi 2, and/or Lake Charles A FCCDs that is/are. then

reflected in a federally enforceable, non-Title V pennit.

46. NSPS PM Emission Limits for the Covered FCCUs. In accordance with NSPS

regulations at 40 CPR, Part 60, Subpart J, CITGO shall comply with an emission limit of 1.0

pounds ofPM per 1000 pounds of coke burned on a 3-hour average basis for all ofthe Covered

FCCUs by the foHowing dates:

Corpus Christi #1 December 31: 2006

Corpus Christi #2 April 30, 2005

Lake Charles A March 31, 2010

Lake Charles B December 31, 2006

Lake Charles C December 31, 2007

Lemont December 31, 2007

The deadlines imposed above shall not affect ClTGO's obligation to comply with the MACT 2

(40 C.F.R. § 63.640) in a timely manner.

47. PM Testine for the Covered FCCUs. CITGO shall follow the stack test protocol

specified in 40 C.F.R. § 60.1 06(b)(2) using EPA Reference Method SB or SF to measure PM·

emissions from the Covered FCCDs. ClTGO shall propose and submit the stack test protocol for

approval to EPA by no later than three (3) months after a PM limit becomes effective for a

particular Covered FCCD. ClTGO shall conduct the first stack test no later than three (3) months

after EPA approves.the stack test protocol. Dntil tennination ofthe Consent Decree, CITGO

49
shall conduct annual PM stack tests at each Covered FCCU. Upon demonstrating through at

least three (3) annual tests that the PM limits are not being exceeded at a particular Covered

FCCU, CITOO may request EPA approval to conduct tests less frequently than annually at that

Covered FCCU. Such approval will not be unreasonably withheld.

D. CO EMISSIONS REDUCTIONS FROM FCCUs

48. CO Emission LimitsJor the Corpus Christi 2, Lake Charles A, Lake

Charles D, Lake Charles C, and Lemont FCCDs. CITOO shall comply with emission limits

of 100 ppmvd CO corrected to. 0% O2 on a 365-day rolling average basis and 500 ppmvd CO

corrected to 0% O2 on a I-hour average basis for the Corpus Christi 2 and Lemont FCCUs by no

later than the Date ofEntry ofthe Consent Decree. CITOO shall comply with the emission limits

pursuant to this Paragraph for the Lake Charles A, Lake Charles Band Lake Charles C FCCUs

by no later than the date ofinstallation ofCO CEMS pursuant to Paragraph 12 ofthis Consent

Decree..

49. CO Emission Limits for the Corpus Christi 1 FCCU. CITOO shall comply with

an emission limit of 500 ppmvd CO corrected to 0% O2 on a 1- hour average basis for the Corpus

Christi 1 FCCU by no later than the date ofinstallation ofCO CEMs pursuant to Paragraph 12 of

the Consent Decree.

50. Demonstrating Compliance with CO Emissions Limits at the Covered FCCUs.

Beginning on the dates set forth in Paragraph 12, CITOO shall use CO and O2 CEMS to monitor

emissions and to report compliance with the terms and conditions ofthis Consent Decree.

CITGO shall make CEMS data available to EPA as soon as practicable following an EPA request

for such data.

50
E. NSPS APPLICABILITY TO FCCU REGENERATORS

51. Each ofCITGO'sFCCD regenerators at the Corpus Christi, Lake Charles, and

Lemont Refmeries shall be an "affected facility," as. that term is used in 40 C.F.R. Part 60,

Subparts A and J, and shall be subject to all ofthe requirements ofNSPS Subparts Aand J for

each pollutant. CITGO shall comply with the requirements ofNSPS Subparts A and J for its

FCCD regenerators for S02, PM and CO by the following dates:

.

S02 PM CO

Corpus Christi FCCD January 1, 2012 December 31, 2006 April 1, 2007

1

Corpus Christi FCCD July 1, 2008 April 30, 2005 Date ofEntry

·2

Lake Charles FCCD January 1,2010 March 31,2010 October 1, 2005

A

Lake Charles FCCD December 31, 2006 December. 31, 2006 October 1, 2005

B

Lake Charles FCCD December 31, 2007 December 31, 2007 October 1, 2005

C

Lemont December 31, 2007 December 31, 2007 Date ofEntry

F. NOx EMISSIONS REDUCTIONS FROM HEATERS AND BOILERS

52. General.. CITGO shall implement a program to reduce NOx emissions from the

heaters and boilers at the Covered Refineries through the installation ofNOx controls or the shut

down ofunits and by applying for and accepting emission limits in a permit for the units

controlled to meet the requirements ofParagraphs 54 and 58. CITGO will morutor compliance

51
with the emission limits through the use ofCEMS,.PEMS, or stack tests as described in more

detail below.

53. Identification of Qualifying Controls. CITGO shall select one or any combination of

the following "Qualifying Controls" to satisfy the requirements ofParagraphs 54 and 58:

a. SCR or SNCR;

-b. Current Generation or Next Generation Ultra-Low NOx Burners;

. c. other technologies which CITGO demonstrates to EPA's satisfaction should

reduce NOx emissions to 0.040 pounds ofNOx per mmBTU heat input or lower;

d. permanent shutdown of a heater or boiler with revocationofits operating permit;

e. IfCurrent Generation or Next Generation Ultra-Low NOx Burners are

technologically infeasible for a cylindrical heater and/or boiler, CITOO may

propose an alternative single burner technology which CITGO demonstrates to

EPA's satisfaction will reduce NOx emissions to 0.055 lbs per mmBTU or lower;

or

£ in the case ofthe compressor engines at the Corpus Christi East Refinery, catalytic

. converters that are designed to achieve 2 grams ofNOx per Brake Horsepowerl

Hour (BhplHr).

54. Installation of Qualifying Controls. On or before June 30, 2011, CITGO shall use

Qualifying Controls to reduce NOx emissions from the heaters and boilers listed in Appendix C

(excluding those at the Paulsboro and SavarmahRefineries) by at least 50% ofthe revised

52
n

baseline identified under Paragraph 55A..For example and based on the baseline identified in

Paragraph 55, this amount would be 4,949 tons per year. The emission reductions required by

this Paragraph 54 shall be demonstrated by satisfying the following inequality:

•

I [(Ea'tual)' - (Eallo""ble);];> XXXX

1=1

Where:

[(The permitted allowable pounds ofNOx per million BTU

for heater or boiler i)/(2000 pounds per ton)] X [(the lower

ofpermitted or maximum heat input rate capacity in million

BTU per hour for heater or boiler i) x (the lower of 8760 or

permitted hours per year)];

The tons ofNOx per year prior actual emissions as listed in

AppendixC for heater or boiler (unless prior actual

emissions exceed allowable emissions, then use allowable);

and

The number ofheaters and boilers with Qualifying Controls

from those listed in Appendix C that are selected by

CITGO to satisfy the requirements ofthe equation set forth

in this Paragraph 54.

CITGO shall have sole discretion to select the Qualifying Controls to be. applied on any particular

heater, boiler or compressor engine and shall choose which heaters, boilers or compressor

engines to control. Permit limits established to implement this Paragraph may use a 365-day

rolling average for heaters and boilers that use a CEMS or PEMS to monitor compliance:

CITGO shallinstall Qualifying Controls on two additional heaters or boilers with a heat input

capacity of 40 nunBtu/hr or more, one at the Paulsboro Refinery and the other at the Savannah

Refinery.

53
55. Baseline Heater and Boiler Information. Appendix C to this Consent Decree

provides the following information for each heater or boiler larger than 40 mmBtulbr that

operated during the baseline years listed in Appendix C at the Covered Refineries (excluding

those. at the Paulsboro and Savannah Refineries):

a. the maximum heat input capacity or, ifless, the allowable heat input capacity in

nunBtuJhr (HHV);

b.· the actual emission rate for baseline years in pounds ofNOx per mmBtu heat

input (HHV) and tons per year;

c. the type ofdata used to derive the emission estimate (i.e., emission factor, stack

test, or CEMS data); and,

. d. the utilization rate in annual average nunBtuJhr (HHV) for the baseline years.

55A. Revised Baseline Heater and Boiler Information.. By.no later than February 28,

2005, CITGO shall submit a revised Appendix C to EPA for review and comment. This revision

shall either (i) reflect that at least 75% ofCITGO's total estimated ton per year average NOx

emissions (derived from 1999 and 2000 data for the Lemont Refinery and 2001 and 2002 data for

the Corpus Christi and Lake Charles Refineries) were derived from stack tests, CEMs, or

portable analyzer or such other measurement device as maybe approved by EPA, or (ii) include

results ofstack tests (Method 7E or an alternative method as approved by EPA) on NOx

emissions for the five heaters and boilers designated for stack tests in Appendix C. Appendix C

(revised) will then be used to calculate the emission reductions required under this Section,

including Paragraphs 54 and 57. The required reductions as specified in the inequality shall be

50% ofthe updated average CITGO NOx emissions (derived from 1999 and 2000 data for the

. Lemont Refinery and 2001 and 2002data for the Corpus Christi and Lake Charles Refineries) in

tons per year in the revised Appendix C.

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56. NOxControl Plan. CITGO shall submit a detailed NOx control plan ("Control

Plan") to EPA for review and conunent by no later than March 31, 2005, with annual updates

(covering the prior calendar year) with the first report submitted pursuant to Section IX (Recordkeeping and Reporting) following the passage of each calendar year until termination ofthe

Consent Decree or until the. reductions required by Paragraph 54 are achieved, whichever occurs

first. The Control Plan and its. updates shall describe the achieved and anticipated progress ofthe

NOx emissions reductions program for heaters and boilers and shall contain the. following

information for each heater and boiler greater than 40 mmBtulhr that CITGOplans to use to

satisfy the requirements ofParagraphs 54, 57, 58, and, if applicable, 57A:

a. All ofthe information in Appendix C;

be Identification ofthe type ofQualifying Controls installed or planned with date

installed or planned (including identification ofthe heaters and boilers to be

permanently shut down);

c. To the extent limits exist, the allowable NOx emission rates'(in lbsfmmBtu

(HHV)), with averaging period) and allowable heat input rate. (in mmBtulhr

(HHV)) obtained or planned with dates obtained or planned;

d. The results of emissions tests and annual average CEMS data (in ppmvd at 0% 0z,

and lbs/mmBtu) conducted pursuant to Paragraph 59 and tons per year; and

e, The amount in tons per year applied or to be applied toward satisfying

Paragraph 54.

Appendix C, the Control Plan, and the updates required by this Paragraph shall be for

informational purposes only and shall not be used to develop permit requirements or other

operating restrictions. CITGO may change any projections, plans, or information (including, but

not limited to, which units CITGO plans to control) that is included in the Control Plan or

updates at any time.

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57. By September 30, 2008, CITGO shall install sufficient Qualifying Controls and

have applied for emission limits sufficient to reduce NOx emissions by two-thirds ofthe NOx

emissions.reductionsrequired by Paragraph 54. In the first semi-annual update to be submitted

to the Applicable Federal and State Agencies after September 30, 2008, CITGO shall include a

report showing how it satisfied the requirement ofthis Paragraph. Consistent with Paragraph 54,

CITGO shall install the remainder ofthe required Qualifying Controls by no later than June 30,

2011.

57A. By no later than December 31,2005, CITGO shall infonn EPA and the CoPlaintiffs whether it will install a cogeneration system at the Lake Charles Refinery. IfCITGO

so infonns EPA and the Co-Plaintiffs and installs the cogeneration system, the emission

reduction required by Paragraph 54 shall be. raised by 525 tons per year, but the interim emission

reductiofl required byParagraph 57 shall be reduced to 1125 tons per year.

58. By no later than June. 30, 2011, CITGO shall have installed Qualifying Controls on

at least 30% ofthe total heat input capacity in mrnBtu per hour (at lllIV) ofheaters and boilers

with capacities greaterthan 40 mrnBtu/hr at each ofthe following refineries: Corpus Christi East,

Corpus Christi West, Lake. Charles. and Lemont. Any Qualifying Controls may be used to satisfY

this requirement, regardless ofwhen the QualifyingControls were installed.

59. For heaters. and boilers where Qualifying Controls are installed after the DatI'; of

Lodging and beginning no later than 180 days after installing Qualifying Controls on and

commencing operation of a heater and boiler that will be used to satisfY the requirements of

Paragraph 54, CIIGO shall monitor the heaters or boilers as follows:

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a. For heaters and boilers with a capacity greater than 150 mmBtuIhr (HHV), install

or continue to operate a NOx CEMS;

b. For heaters and boilers with a capacity greater than 100 mmBtuIhr (HHV) but less

than or equal to 150 mmBtulhr (HHV), install or continue. to operate a NOx

CEMS, or monitor NOx emissions. with a predictive emissions monitoring system

("PEMS") developed and operated pursuant to the requirements ofthe PEMS

Program prepared by CITGO under this Paragraph.

c. For heaters and boilers with a capacity ofless than or equal to 100 mmBtuIhr

(HHV), conduct an initial performance test and any periodic. teststhat may be

required by EPA or by the applicable State or local permitting authority under

other applicable regulatory authority. The results ofthe initial performance

testing shall be reported to EPA and Applicable Permitting Authority within 90

days of completing the stack test.

CITGO shall use Method 7E to conduct initial performance testing required by

Subparagraph 59c. Monitoring with a PEMS that is required by this Paragraph shall be

conducted in accordance with the requirements ofAppendix H. By no later than September 30,

2005, CITGO shall submit to EPA for review and commeut a PEMS Program in accordance with

Appendix H. By no later than September 30,.2005, CITGO shall implement the specified

monitoring requirements (CEMS, PEMS, stack test) based on the. capacity ofthe heater or boiler

as listed in Appendix C for units that utilize Qualifying Controls as ofthe Date ofLodging and

which CITGO intends to use to achieve the NOx reductions. required by Paragraph 54.·

60. Demonstrating Compliance through Use of a NOx CEMS. CITGO shall install,

certify, calibrate, maintain, and operate the CEMS required byParagraph 59 in accordance with

40 C.F.R. Part 60, Appendices A and F, and the applicable performance specification test of40

C.F.R. Part 60, Appendix B. However, in lieu ofthe requirements of 40 C.F.R.Part 60,

Appendix F §§ 5.1.1,5.1.3 and 5.1.4, CITGO may conduct either a Relative Accuracy Audit

("RAA") or a Relative Accuracy Test Audit ("RATA") once every three (3) years and shall

57
conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is

not perfOlmed.

61. The requirements ofthis Section V.F. do not exempt ClTGO from complying with

any and all Federal, state, regional, and local requirements that may require technology,

equipment, monitoring, or other upgrades based on actions or activities. occurring after the. Date

ofLodging ofthe Consent Decree, or based upon new or modified regulatory, statutory, or permit

requirements. However, nothing in this Section V.F. ismeant to prevent CrrGO from using the

NOx reductions achieved pursuant to this Section towards future NOx emission reduction

requirements except as prohibited under Section VI (Emission Credit Generation) ofthis Consent

Decree.

62. CITGO shall retain records demonstrating installation ofQualifYing Controls under

Paragraph 54 and monitoring/test data under Paragraph 59 until termination ofthe Consent

Decree. CrrGO shall submit such records to EPA upon request.

G. SO, EMISSIONS REDUCTIONS FROM AND NSPS APPLICABILITY OF

HEATERS, BOILERS AND OTHER FUEL GAS COMBUSTION DEVICES

63. General. CITGO shall undertake measures to limit SO, emissions from refinery

heaters and boilers and other fuel combustion devices by restricting H2S in refmery fuel gas and

by agreeing not to burn Fuel Oil except as specifically permitted under the provisions ofthis

Section V.G. Flaring Devices are not subject to the provisions ofSection V.G., but rather are

. subjectto the provisions ofSections V.I., V.I. and V.K.

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64. NSPS Applicability to Heaters. Boilers and Other Fuel Gas Combustion Devices

(Other than Flaring Devices).

a. Upon the Date ofEntry, each heater and boiler that combusts refinery fuel gas at the

Covered Refineries shall be an affected facilitY, as that term is used in 40 C.F.R. Part 60, ..

Subparts A and J, and shall be subject to, and comply with the requirements ofNSPS.Subparts A

and J for fuel gas combustion devices, except for those heaters and boilers listed in AppendixE,

each ofwhich shall be an affected facility and shall be subject to and comply with the

requirements ofNSPS Subparts A and J for fuel gas combustion devices by the dates listed in

AppendixE.

b.. By the date listed in Appendix F, each ofthe fuel gas combustion devices listed in

Appendix F shall be an affected facilitY, as that term is used in 40 C.F.R. Part 60, Subparts A and

J, and shall be subject to and comply with the requirements ofNSPS Subparts Aand J for fuel

gas combustion devices.

c. Where Appendix E or F specifies an alternative monitoring plan ("AMP') submittal

date (rather than a final NSPS Subpart J compliance date), CITGO shall submit to EPA a timely

and complete AMP application by the date(s) specified. To the extent that CITGO seeks

approval of an alternative monitoring method that is the same or substantially similar to the

method identified in the "Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas"

attached to EPA's December 7, 1999 letter to Koch Refining CompanyLP, which is attached

hereto in Appendix I, CITao may begin using such method immediately upon submitting its

application for approval to use such method. If an AMP is not approved, CITGO shall submit to

EPA for approval a plan for complying with the monitoring requirements ofNSPS Subpart J for

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the particular equipment within ninety (90) days ofreceiving notice ofthe disapproval. The

equipment will become an affected facility when the AMP has been approved or crrGO has

fully implemented its approved plan. Such plan may include a revised AMP application,

physical or operational changes to the. equipment, or additional or different monitoring.

d. FOr some heaters and boilers that combust low-flow VOC streams from vents,

pumpseals,and other sources, it is anticipated that some ofthe AMP applications will rely in part

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on calculating a weighted average H2S concentration of all VOC and fuel gas streams that are

burned in a single heater or boiler and demonstrating with alternative monitoring that either the

S02 emissions from the heater or boiler will not exceed 20 ppm or that the. weighted average H2S

concentration is not likely to exceed 0.1 grains H2S per dry standard cubic foot offuel gas. EPA

shall'not reject an AMP solely due to the AMP's use of one ofthese approaches to demonstrating

compliance with NSPS Subpart J.

65. EliminationlReduction of Fuel Oil Burning. Effective on the Date ofEntry,

crrGO Shall not bum Fuel Oil in any combustion unit at the Covered Refineries except during

periods ofNatural Gas Curtailment. Nothing herein isintended to limit, or shall be interPreted as

limiting, the. use oftorch oil during FCCU Startups.

H. SULFUR RECOVERY PLANTS

66. Description of Sulfur Recovery Plants. CrrGO owns and operates Claus Sulfur

Recovery Plants ("SRPs") at the Lemont, Lake Charles, Corpus Christi East and Corpus Christi

West Refineries.

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a. Lemont SRP: The SRP at the Lemont Refinery ("Lemont SRP") consists offour

Claus trains, Units 119 A, 119 B,.l21 C and121 D. There is a single Beavon Stretford Tail Gas

Unit ("TGU") which serves as the control device for the two 121 Claus trains.

b. Lake Charles SRP: The SRP at the Lake Charles Refinery consists offour Claus

trains, A, C, D and E. There are two amine solution TGUs that serve the above-listed Claus

trains.

c. Comus Christi (East) SRP: The SRP at the Corpus Christi (East) Refinery consists of

two Claus trains. There is a single SCOT TGU which serves as the control device for the two

Claus trains.

d.. Comus Christi (West) SRP: The SRP at the. Corpus Christi (West) Refmery consists of

two Claus trains.. There is a single SCOT TGU which serves as the control device for the. two

Claus trains.

67. Claus Sulfur Recovery Plant NSPS Applicability. Each ofthe. following Claus

SulfurRecovery Plants shall be an "affected facility," as that term is used in 40 C.F.R. Part 60, as

follows:

a. Effective on the Date ofEntry ofthe Consent Decree, each SRP at the Lake Charles,

Corpus Christi East and Corpus Christi West Refineries shall be an "affected facility" under

NSPS, 40 C.F.R. Part 60, Subparts A and J;

. b. Effective no later than 90 days after installation of one or more TGU(s) to control

the emissions from the Lemont Claus trains 119 A and B; as required under Paragraph 69, the

SRP at the Lemont Refinery shall be an "affected facility" under NSPS, 40 C.F.R. Part 60,

Subparts A and J;

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c. Notwithstanding Paragraph 67.b, above, effective on the Date ofEntry ofthe

Consent Decree until such time as the SRP at the Lemont Refinery is an "affected facility," the

Lemont Claus Trains 121 C and D ("Lemont Claus. Trains") shall be treated under this Consent

Decree as an SRP that is. an "affected facility" that must comply with all provisions applicable to

such an affected facility under 40 C.F.R. Part 60,. Subparts A and J.

68. Claus Sulfur Recovery Plant NSPS Compliance. By no later than the. effective

date ofNSPS applicability for each ofthe SRPs and the Lemont Claus Trains as set forth in

Paragraph 67, above, the SRPs and the Lemont Claus Trains shall comply with all applicable

provisions ofNSPS set forth at 40 C.F.R.Part 60, Subparts A and J, including, .but not limited to,

the. following:

a. Emission limit. CrrGO shall,. for all periods ofoperation ofthe SRPs, comply with

40 C.F.R. § 60.104(a)(2) at each SRP except during periods ofStartup, Shutdown or Malfunction

ofthe respective SRP, or during a Malfunction of a TGU serving as a control device for the SRP.

For the purpose of determining compliance with the Sulfur Recovery Plant emission limits. of40

C.F.R. § 60.1 04(a)(2), the "Startup/Shutdown" provisions set forth in NSPS Subpart A shall

apply to each SRP and not to the independent start-up or shutdown of a TGU serving as. a control

device for the SRP. However, the Malfunction exemption set forth in NSPS Subpart A shall

apply to each SRP and to the TGU serving as the control device for the SRP.

. b. Monitoring. CITGO shall monitor all emissions points (stacks) to the atmosphere

for tail gas emissions and shall monitor and report excess emissions from each ofthese SRPs as

required by 40 C.F.R. §§ 60.7(c), 60.13, and 60.I 05(a)(5), (6)or (7). During the life ofthis

Consent Decree, CITGO shall conduct emissions monitoring from these SRPs with CEMS at all

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ofthe emission points, unless an S02 alternative monitoring procedure has been approved by

EPA, per 40 C.F.R. § 60.13(i), for any ofthe. emission points. Tl;1e requirement for continuous

monitoring ofthe SRP emission points is not applicable to the Acid Gas Flaring Devices used to

flare the Acid Gas or Sour Water StripperGas diverted from the SRPs.

69. Lemont SRP Requirements.

a. CITGO shall install one or more TGU(s) to control the emissions from the. Lemont

Claus Trains 119 A and B by no later than December 31, 2008. Byno later than February 28,

2005, CITGO shall submit to EPA and IEPA a schedule for Lemont Claus trains 119 A and B

that will ensure complianc.e with SRP NSPS. requirements by no later than December 31, 2008.

b. CITGO shall also implement the following interim measures at the Lemont Claus

Trains. 119 A and B:

i. CITGO shall continue to operate and maintain an S02 CEMS for monitoring the

emissions from Lemont Claus Trains 119 A and B in accordance with 40 C.F.R. Part 60,

Subpart A, § 60.13.

ii.. By no later than February 28, 2005, CITGO shall complete an optimization study to

minimize emissions and maximize sulfurrecover efficiencies at Lemont Claus Trains. 119

A and B and shallsubmit a copy ofthat study toEPA and IEPA. This study shall meet

the requirements set forth in Paragraph 70. CITGO shall promptly implement the

physical improvements and operating parameters recommended in the study to optimize

performance of Lemont Claus Trains119 A and B.

iii. By no later than April 30, 2005, CITGO shall submit a report to EPA and IEPA that

proposes an appropriate interim performance standard (percent recovery efficiency and/or

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emission limitation) and, ifnecessary, a schedule for implementing related optimization

study recommendations that are necessary to comply with CITGO's proposed standard.

Beginning with the date ofsuch submission, CITGO shall comply with its proposed

interim performance standard or, ifnecessary, implement its proposed implementation

schedule.

iv. IfEPA determines. that a more stringent interim performance standard and/or a

different implementation schedule is appropriate and can be achieved with a reasonable

certainty of compliance, after an opportunity for consultation with IEPA, EPA shall so

notify CITGO. Unless CITGO disputes EPA's determination(s) within 90 days ofits 1\

receipt ofthat notice, it shall complywith such new standard within 90 days or, if

necessary, such other period as may be established by EPA based upon the approved

implementation schedule. CITGO shall continue to complywith the appropriate interim

performance standard until such time. as CITGO completes installation ofthe TGU(s) in

accord with the. schedule under Paragraph 69.a and operates the. Lemont SRP in

. compliance with NSPS Subpart J.

70. Optimization. The optimization studies required for the Lemont Claus Trajns 119

A and B shall meet the following requirements:

a. Detailed evaluation ofplant design and capacity, operating parameters and

efficiencies - including catalytic activity, and material balances;

b. An analysis ofthe composition ofthe acid gas and sour water stripper gas

resulting from the processing ofcrude slate actually used, or expected to be used,

in those Claus trains;

c. A review of each critical piece ofprocess equipment and instrumentation within

the Claus train that is designed to correct deficiencies or problems that prevent the

.Claus train from achieving its optimal sulfur recovery efficiency and expanded

periods of operation;

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d. Establishment ofbaseline data through testing and measurement ofkey

parameters throughoutthe Claus train;

e. Establishment of a thermodynamic process model ofthe Claus train;

f. For any key parameters that have been determined to be at less than optimal

levels, initiation of changes designed to move such parameters toward their

optimal values;

g. Verification through testing, analysis ofcontinuous emission monitoring data or

other means, ofincremental and cumulative improvements in sulfur recovery

efficiency, ifany;

h. Establishment of-new operating procedures for long-term efficient operation; and

I. Each study shall be. conducted to optimize the performance ofthe Claus trains in

light ofthe actual characteristics ofthe feeds to the trains.

71. Sulfur Pit Emissions. CITGO shall continue to route orre-route all sulfur pit

emissions at the Lemont, Lake Charles, and Corpus Christi East and West Refineries so that they

are eliminated, controlled, or included and monitored as part ofthe SRP's emissions subject to

the. NSPS Subpart J limit for S02' 40 C.F.R. § 60.104(a)(2), by no later than the earlier of: (i) the

first turnaround ofthe applicable Claus train that occurs on or after October 31, 2004; or

(ii) March 30, 2007, provided, however, that ifLemont Claus Trains Il9A and/or Il9Belect to

route such emissions to the TGU required under Paragraph 69.a, then by the date ofsuch TGU

installation.

72. Sulfuric Acid Plant. By no later than December 31,2006, the Lake Charles

Sulfuric Acid Plant shaH be an "affected facility," as that term is used in 40 C.F.R. Part60,

Subparts A and H, and shall comply with an emission limitation of 3.5 pounds ofsulfur dioxide

per ton of acid produced, three hour average, (production expressed as 100 percent sulfur acid);

the acid mist standards found in 40 C.F.R.§ 60.83; and the emissions monitoring and testing

requirements. in 40 C.F.R. Part 60, Subparts A and H. The Lake Charles Sulfuric Acid Plant

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shall comply~ithth~ 3.5 lb SO, per ton limit and the acid mist standards at all times except

during periods ofStartup, Shutdown or Malfunction ofthe Sulfuric Acid Plant.

73. Good Operation and Maintenance.

a. Byno later than February 28, 2005, CITGO shall submit to EPA and the appropriate

Co-Plaintiff a summary ofthe plans, implemented or to be implemented, at the Lemont, Lake

Charles, and Corpus Christi East and West Refineries for enhanced maintenance. and operation of

their SRPs, the Lake Charles Sulfuric Acid Plant and the appropriate Upstream Process Units.

'This plan shall be ternled a Preventive Maintenance and Operation Plan (''PMO Plan"). The

PMO Plan shall be a compilation ofCITGO's approaches for exercising good air pollution

control practices and for minimizing SO, emissions from sulfur processing and other production

processes at these refineries. PMO Plans shall have as their goals the elimination ofAcid Gas

Flaring and operation ofSRPs between Scheduled Maintenance turnarounds with minimization

ofemissions. The PMO Plan shall include, but not be limited to, sulfur shedding procedures,

startup and shutdown procedures of SRP's, control devices and Upstream Process Units,

emergency procedures and schedules to coordinate maintenance turnarounds ofthe SRP Claus

trains :and any control device to coincide with scheduled turnarounds ofmajor Upstream Process

Units. CITGO shall implement the PMO Plans at all times, including periods ofStartup,

Shutdown and Malfunction ofits SRPs. Changes to a PMO Plan related.to minimizing Acid Gas

Flaring and/or SO, emissions shall be summarized and reported by CITaO to EPA and the

appropriate Co-Plaintiffin the semi·annual report required under Paragraph 144.

b. EPA, IEPA, and LDEQ do not, by their review ofa PMO Plan and/or by their failure

to comment on a PMO Plan, warrant or aver in any manner that any ofthe actions that CITGO

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may take pursuant tosuch PMO Plan will result in compliance with the provisions ofthe Clean

Air Act or any other applicable federal, state, or local law or regulation. Notwithstanding the

review by EPA or any"state agency of a PMO Plan, CITGO shall remain solely responsible for

compliance with the Clean Air Act and such other laws and regulations.

I. HYDROCARBON FLARING

74. Good Air Pollution Control Practices. On and after the Date ofEntry, CITGO

shall at all times and to the extent practicable, including during periods ofstartup, shutdown,

.. upset and/or Malfunction, implement good air pollution control practices to minimize emissions

from its Hydrocarbon Flaring Devices consistent with 40 C.F.R. § 60.11 (d). CITGO shall

implement such good air pollution control practices to minimize Hydrocarbon Flaring Incidents

by investigating, reporting and correcting all Hydrocarbon Flaring Incidents in accordance with

the procedures in Paragraph 94.

75. NSPS Applicability of Hydrocarbon Flaring Devices: CITGO owns and operates

the NSPS Hydrocarbon Flaring Devices identified in Appendix B-1 to this Consent Decree. By·

no later than the dates identified in Appendix G,CITGO agrees that each such NSPS HC Flaring

Deviceis an "affected facility" (as that term is used in NSPS, 40 C.F.R. Part 60) subject to, and

required to comply with, the requirements of40 C.F.R. Part 60,Subparts A and J, for fuel gas.

combustion devices used as emergency control devices for quick and safe release of gases.

. a. CITGO shall meet the NSPS Subparts A and J requirements for each NSPS HC

Flaring Device by using one or any combination ofthe following methods:

1. Operating and maintaining a flare gas recovery system to prevent continuous or

routine combustion in the NSPS HC Flaring Device. Use of a flare gas recovery

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system on a flare obviates the need to continnously monitor emissions as

otherwise required by 40 C.F.R. § 60.105(a)(4);

n. Eliminating the routes of continuous or intennittent, routinely-generated refinery

fuel gases to an NSPS He Flaring Device and operating the Flaring Device such

that it only receives. non-routinely generated gases, process upset gases, fuel gas

released as a result ofreliefvalve leakage or gases released due to other

emergency malfunctions; or

lll. Operating the NSPS He FlaringDevice as. a fuel gas combustion device,

monitoring it for the continuous orintennittent, routinely-generated refinery fuel

gases streams put into the flare header, with a CEMS as required by 40 C.F.R.

§ 60.105(a)(4) or with a parametric monitoring system approved by EPA as an

alternative monitoring system under 40 C.F.R. § 60.13(i) and complying with

emission limits when and as required by Paragraph 76.a.

CITGO shall implement the compliance option chosen for each NSPS Hydrocarbon Flaring

Device according to the schedule in Appendix G and identify the. option that was implemented

for each NSPS Hydrocarbon Flaring Device. in the first Semi-Annual Report due under Paragraph

144 after such compliance is. achieved. The Parties recognize that periodic maintenance may be

required for properly designed and operated flare gas recovery systems. CITGO shall take all

reasonable measures to minimize emissions while such periodic maintenance is being perfonned.

b. Within 90 days after bringing an NSPS Hydrocarbon FlaringDevice into compliance

with NSPS Subparts A and J, CITGO shall conduct a flare perfonnance test pursuant to 40

C.F.R.§§ 60.8 and 60.18, or an EPA-approved equivalent method. In lieu of conducting the

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velocity test required in 40 C.F.R. §60.18, CITGO may submit velocity calculations which

demonstrate that the NSPS Hydrocarbon Flaring Device meets the performance specification

required by 40 C.F.R. §60.18.

76. Compliance with the Emission Limifat 40 C.F.R. &60.104(a)(1).

a. Continuous or Intermittent, Routinely-Generated Refinery Fuel Gases. For

continuous or intermittent, routinely-generated refinery gases that are combusted in any ofthe

NSPS Hydrocarbon Flaring Devices, CITGO shall comply with the emission limit at 40 C.F.R:

§ 60.1 04(a)(l) by the dates specified in Appendix G.

b. Non-Routinely Generated Gases. The combustion ofgases generated by the Startup,

Shutdown, or Malfunction of a refinery process unit or releasedto an NSPS Flaring Device as a

result ofreliefvalve leakage or other emergency Malfunction are exempt from the requirement to

comply with 40 C.F.R. § 60.104(a)(1).

J. CONTROL OF ACID GAS FLARING AND TAIL GAS INCIDENTS

77. Flaring History and Corrective Measures. CITGO has conducted a look-back

analysis ofAG Flaring Incidents that occurred at the Covered Refineries from October 1, 1998,

through September 30, 2003, and submitted a report on such incidents to EPA.

78. Future Acid Gas Flaring and Tail Gas Incidents:. CITGO shall investigate the.

cause offuture Acid Gas Flaring and Tail Gas Incidents, take reasonable steps to correct the

conditions. that have caused or contributed to such Acid Gas Flaring and Tail Gas Incidents, and

minimize Acid Gas Flaring and Tail Gas Incidents at the Corpus Christi East, Corpus Christi

West, Lemont and Lake Charles Refineries.

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79. Investigation and Reporting. No later than forty-five (45) days following the end

of an Acid Gas Flaring Incident occurring after the Date ofEntry, CITGO shall submit to EPA

and the appropriate Co-Plaintiff a report that sets forth the following:

a. The date and time that the Acid Gas Flaring Incident started and ended. To the

extent that the Acid Gas Flaring Incident involved multiple releases either within

a twenty-four (24) hour period or within subsequent, contiguous, non-overlapping

twenty-four (24) hour periods, ClrGO shall set forth the starting and ending dates

and times of each release;

b. An estimate ofthe quantity ofsulfur dioxide that was emitted and the calculations

. that were used to determine that quantity;

c. The steps, if any, that CITGO took to limit the duration and/or quantity ofsulfur

dioxide emissions. associated with the Acid Gas Flaring Incident;

d. A detailed analysis that sets forth the Root Cause. and all significant contributing

causes ofthat Acjd Gas Flaring Incident, to the extent determinable;

e. An analysis ofthe measures, if any, that are available to reduce the likelihood of a

recurrence of an Acid Gas Flaring Incident resulting from the same Root Cause or

significant contributing causes in the future. Iftwo or more reasonable

alternatives exist to address the Root Cause, the. analysis shall discuss the

alternatives, if any, that are available, the probable. effectiveness and cost ofthe

alternatives, and whether or not an outside consultant should be retained to assist

in the analysis. Possible design, operation and maintenance changes shall be

evaluated.. IfCITGO concludes that corrective action(s) is (are) required under

Paragraph 80, the report shall include a description ofthe action(s) and, ifnot

aIreadycompleted, a schedule for its (their) implementation, including proposed

commencement and completion dates. IfCITGO concludes that corrective action

is not required under Paragraph 80, the report shall explain the basis for that

conclusion;

f. A statement that: (a) specifically identifies each ofthe grounds for stipulated

penalties in Paragraphs 86 and 87 ofthis Decree and describes whether or not the

Acid Gas Flaring Incident falls under any ofthose grounds, provided, however,

that ClrOO may choose to submit with the Root Cause Failure Analysis a

payment ofstipulated penalties in the nature ofsettlement without the need to

specifically identifY the grounds for the penalty. Such payment ofstipulated

penalties shall not constitute an admission ofliability, nor shall itraise any

presumption whatsoever about the nature, existence or strength ofCITGO's

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potential defenses; (b) ifan Acid Gas Flaring Incident falls under Paragraph 88 of

this Decree,. describes which Subparagraph 88.a or 88.b applies and why; and (c)

if an Acid Gas Flaring Incident falls under either Paragraph 87 or 88.b, states

whether or not ClTGO asserts a defense to the Flaring Incident, and ifso, a

description ofthe. defense;

g. To the extent that investigations ofthe causes and/or possible corrective actions

still are underway ou the due date ofthe report, a statement ofthe anticipated date

by which a follow-up report fully conforming to the requirements of

Subparagraphs 79.d and 79.e shall be submitted; provided, however, that if

CITGO has uot submitted a report or a series ofreports containing the information

required to be submitted under this Paragraph within the 45 day time period set

forth in this Paragraph 79 (or such additional time as EPA may allow) after the

due date for the initial report for the Acid Gas Flaring Incident, the stipulated

penalty provisions ofSection XI shall apply, but CITGO shall retain the. right to

dispute, under the dispute resolution provision ofthis. Consent Decree, any

demand for stipulated penalties that was issued as a result ofClTGO's failure to

submit the. report required under this Paragraph within the time frame set forth.

Nothing in this Paragraph shaH be deemed to excuse CITGO from its

investigation, reporting, and corrective action obligations under this Section for

any Acid Gas Flaring Incident which occurs after an Acid Gas Flaring Incident for

which CITGO has requested an extension oftime under this Subparagraph 79.g;

and

h. To the extent that completion ofthe implementation of corrective action(s), if

any, is not finalized at the time ofthe submission ofthe report required under. this

Paragraph, then, by nei later than thirty (30) days after completion ofthe

implementation of corrective action(s), CITGO shall submit a report identifYing

the corrective action(s) taken and the dates ofcommencement and completion of

implementation.

80. Corrective Action.

a. In response to any AG Flaring Incident occurring after the Date ofEntry, CITGO 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 ofthe

Root Cause and all significant contributing causes ofthat AG Flaring Incident.

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b. IfEPA does not notify CITGO in Writing within forty-five (45) days ofreceipt ofthe

report(s) required by Paragraph 79 that it objects to one or more aspects ofthe proposed

corrective action(s) and schedule(s) ofimplementation, if any, then that (those) action(s) and

schedule(s) shall be deemed acceptablefor purposes of compliance with Paragraph 80.a ofthis

Decree. EPA does not, however, by its failure to object to any corrective action that CITGO may

take in the future, warrant or aver in any manner that any corrective actions in the future. shaH

result in compliance with the provisions ofthe Clean Air Act or its implementing regulations.

c. IfEPA objects, in whole or in part, to the proposed corrective action(s) andlor the

schedule(s) ofimplementation or, where applicable, to the absence ofsuch proposal(s) andlor

schedule(s), it shall notify CITGO and explain the basis fodts objection (s) in writing within

forty-five (45) days following receipt ofthe report(s) required by Paragraph 79, and CITGO shall

respond promptly to EPA's objection(s).-

d. Nothing in this Section V.L shall be construed to limit the right ofCITGO to take such

corrective. actions as it deems necessary and appropriate immediately following an Acid Gas

Flaring Incident or in the. period during preparation and review of any reports required under this

Paragraph.

8!. [Intentionally Left Blank]

82. [Intentionally Left Blank]

83. [Intentionally Left Blank]

·84. [Intentionally Left Blank]

85. Stipulated Penalties for Acid Gas Flaring Incidents. The provisions ofParagraphs

86 through 89 are to be used by EPA in assessing stipulated penalties for AG Flaring Incidents

72
occurring after the Date ofEntry ofthis Consent Decree and by the United States in demanding

stipulated penalties under this Section V.I. The provisions ofParagraphs 86-89 do not apply to

.HC Flaring Incidents.

86. The stipulated penalty provisions ofParagraph 181 shall apply to any Acid Gas

Flaring Incidel1t for which the RootCause was one or more or the following acts, omissions, or

events:

a Error resulting from careless operation by the persounel charged with the

responsibil~ty for the Sulfur Recovery Plant, Sulfuric Acid Plant, TGU, or

Upstream Process Units;

b. Failure to follow written procedures;

c. A failure of equipment that is due to a failure by CITGOto operate and maintain·

that equipment in a manner consistent with good engineering practice; or

87. Ifthe Acid Gas. Flaring Incident is not a result of one ofthe Root Causes identified

in Paragraph 86, then the stipulated penalty provisions ofParagraph 181 shall apply ifthe Acid

Gas Flaring Incident:

a. Results in emissions ofsulfur dioxide at a rate greater than twenty (20.0) pounds

per hour continuously for three (3) consecutiv<;hours or more and CITGO failed

to act in accordance with its PMO Plan .and/or to take any action during the Acid

Gas Flaring Incident to limit the duration and/or quantity ofSOz emissions

associated with such incident; or

b. Causes the total number ofAcid Gas Flaring Incidents in a rolling twelve (12)

month period to exceed five (5) per refinery.

88. With respect to any Acid Gas Flaring Incident not identified in Paragraphs 86 or 87,

the following provisions shall apply:

a. First Time: Ifthe Root Cause ofthe Acid Gas Flaring Incident was not a

recurrence ofthe same Root Cause that resulted in a previous Acid Gas Flaring

Incident that occurred since Date ofEntry, then:

73
(i) Ifthe Root Cause ofthe Acid Gas Flaring Incident was sudden, infrequent,

and not reasonably preventable through the exercise of good engineering

practice, then that cause shall be designated as an agreed-upon malfunction

for purposes ofreviewing subsequent Acid Gas Flaring Incidents;

(ii) Ifthe Root Cause ofthe. Acid Gas Flaring Incident was sudden and

infrequent, and was reasonably preventable through the exercise ofgood.

engineering practice, then CITGO shallimplement corrective action(s)

pursuant to Paragraph 80, and the stipulated penalty provisions ofSection

XI shall not apply.

b. Recurrence: Ifthe Root Cause isa recurrence ofthe same Root Cause that

resulted in a previous Acid Gas Flaring Incident that occurred since the Date of

Entry, then CITGO shall be liable for stipulated penalties under Section XI unless:

(i) the. Flaring !ricident resulted from a Malfunction; or

(H) the Root Cause previously was. designated as an agreed-upon malfunction

under Paragraph 88.a.i; or

(Hi) the AG Flaring !ricident had as its Root Cause. the recurrence ofaRoot

Cause for which CITGO had previously developed, or was in the process

of developing, a corrective action plan and for which CITGO had not yet

completed implementation.

89. Defenses. CITGO may raise the following affirmative defenses in response to a

demand by the United States for stipulated penalties:

a. Force majeure.

b. As to Paragraph 86, the Acid Gas Flaring !ricident does not meet the identified

criteria.

c. As to Paragraph 87, Malfunction

d. As to Paragraph 88, the !ricident does not meet the identified criteria and/or was

due to a Malfunction.

90. In the event a dispute under Paragraphs 85 through 89 is brought to the Court

pursuant to the Dispute Resolution provisions ofthis Consent Decree, CITGO may also assert a

74
Start up, Shutdown and/or upset defense (including of an individual sulfur recovery unit within

an SRP), but the United States shall be entitled to assert that such defenses are not. available; If

CITGO prevails in persuading the Court that the defenses ofStartup, Shutdown and/or upset are

available for AG Flaring Incidents under 40 C.F.R. 60.104(a)(I), CITGO shall not be liable for

stipulated penalties for emissions resulting from such Startup, Shutdown and/or upset. Ifthe

United States prevails in persuading the Court that the defenses or Startup, Shutdown and/or

upset are not available, CITGO shall be liable for such stipulated penalties.

91. Other than for a Malfunction or force majeure, ifno Acid Gas Flaring Incident occurs

at either the Corpus Christi East, Corpus Christi West, Lake Charles. or Lemont Refinery for a

rolling 36 month period, then the stipulated penalty provisions ofSection V.I.. shall no longer

apply to. that Refinery. EPA may elect to reinstate the stipulated penalty provision ifsuch

Refinery has. an Acid Gas Flaring Incident which would otherwise be subject to stipulated

penalties. EPA's decision shall not be subject to dispute. resolution. Once reinstated, the

stipulated penalty provision shall continue for the remaining life ofthis Consent Decree for that

Refmety.

92. Emission Calculations.

a. Calculation ofthe Ouantity of Sulfur Dioxide Emissions Resulting from AGFlaring.

For purposes ofthis Consent Decree, the quantity ofS02emissions resulting from anAG Flaring

Incident shall be calculated by the following formula:

Tons ofS02= [FR][TD][ConcH2S][8.44 x 10.5

].

The quantity ofS02 emitted shall be rounded to one decimal point. (Thus, for example, for a

calculation that results in a number equal to 10.050 tons, the quantity of S02 emitted shall be

75
rounded to 10.1 tons.) For purposes ofdetennining the occurrence of, or the total quantity of

S02 emissions resulting from, an AG Flaring Incident that is comprised ofintennittent AG

Flaring, the quantity ofS02emitted shall be equal to the sum ofthe quantities ofS02flared

during each 24-hour period starting when the Acid Gas was first flared.

b. Calculation ofthe Rate. ofS02Emissions During AG Flaring. For purposes ofthis

Consent Decree, the rate. of S02 emissions resulting from an AG Flaring Incident shall be

expressed in tenns ofpounds per hour and shall be calculated by the. following fonnula:

ER = [FR][ConcH2S][O.169].

The emission rate shall be rounded to one decimal point. (Thus, for exampie, for a calculation

that results. in an emission rate of 19.95 pounds of S02 per hour, the emission rate shall be

rounded to 20.0 pounds ofS02 per hour; for a calculation that results in an emission rate of20.05

pounds 0[S02 per hour, the emission rate shall be rounded to 20.1.)

c. Meaning ofVariables and Derivation ofMultipliers Used in the Equations in this

Paragraph 92:

ER=

FR=

TD=

8.44 X 1O,s =

0.169 =

Emission Rate in pounds of S02 per hour

Average Flow Rate to Flaring Device(s) during Flaring Incident in

standard cubic feet per hour

Total Duration ofFlaring Incident in hours

Average Concentration ofHydrogen Sulfide in gas during Flaring

Incident (or immediately prior to Flaring Incident if all gas is being

flared) expressed as a volume fraction (scfH2S/scf gas)

[lb mole H2S/379. scfH2S][64lbs SO/lb mole H2S][Ton/2000 lbs]

[lb mole H2S/379 scfH2S][1.0 Ib mole SO/lIb mole H2S][64Ib

SO,l1.0 lb mole S02]

76
The flow of gas to the AG Flaring Device(s) ("FR") shall be as measured by the relevant flow

. meter Or reliable flow estimation parameters. Hydrogen sulfide concentration ("ConcH,S") shall

be determined from the Sulfur Recovery Plant feed gas analyzer, from knowledge ofthe sulfur

content ofthe process gas being flared, by direct measurement by tutwiler or draeger tube

analysis or by any other method approved by EPA or the Co-Plaintiffs. In the event that any of

these data points is unavailable or inaccurate, the missing data pointes) shall be estimated

according to best engineering judgment. The report required under Paragraph 79 shall include

the data used in the calculation and an explanation ofthe basis for any estimates ofmissing data

points.

93. Tail Gas Incidents.

a. Investigation. Reporting. Corrective Action and Stipulated Penalties. For Tail Gas

Incidents, CITGO shall follow the same investigative, reporting, corrective action and assessment

ofstipulated penalty procedures as those set forth in Paragraphs 79 through 91 for Acid Gas

Flaring Incidents. Those procedures shall be applied to TGU shutdowns, bypasses of a TGU, or

other events which result in a Tail Gas Incident, including unscheduled Shutdowns of a Claus

Sulfur Recovery Plant. Notwithstanding the foregoing, stipulated penalties shall not apply to a

Tail Gas Incident attributable. to the scheduled startup or shutdown of an individual train at the

SRP located at the Lake Charles Refinery, provided that CITGO demonstrates that it has

implemented good air pollution control practices. This Paragraph 93 shall apply after the

effective date ofNSPS applicability at each ofthe Covered Refmeries' SRPs, as provided in

Paragraph 67 above.

b: Calculation ofthe Quantity ofSOl Emissions Resulting from a Tail Gas Incident.

For the purposes ofthis Consent Decree, the quantity of SOl emissions resulting from a Tail Gas

Incident shall be calculated by one ofthe following methods, based·on the type of event:

77
1.

ii.

Where:

IfTail Gas is combusted in a flare, the SO, emissions are calculated

using themethods outlined in Paragraph 92; or

IfTail Gas exceeding the 250 ppmvd (NSPS J limit)is emitted from a

monitored SRP incinerator, then the following formula applies:

20.9 - % O2

L [FRIo,]! [Cone. S02 - 250];[0.169 x 10.(;][ 20.9 1

i"'l

Emissions from Tail Gas Unit at the SRP incinerator, pounds ofSO, over

a 24 hour period

Hours when the incinerator CEM was exceeding 250 ppmvd S02 on a

rolling twelve hour average, corrected to 0% 02, in each 24 hour period of

the Incident .

1 '" Each hour within TDTGI

FRIn,. '" Incinerator Exhaust Gas Flow Rate (standard cubic feet per hour, dry

basis) (actual stack monitor data or engineering estimate based on the acid

gas feed rate to the SRP) for each hour ofthe Incident

Cone. S02 '" The average S02 concentration (CEMS data) that is greater than 250ppm

in the incinerator exhaust gas, ppmvd corrected to 0% 02' for each hour of

the Incident

% O2 0, concentration (CEMS data) in the incinerator exhaust gas in volume %

on dry basis for each hour ofthe Incident

0.169 X 10-6 = [lb mole ofS02.! 379 S02 ] [641bs S02/lb mole S02 ] [1 X 10-6 ]

Standard conditions = 60 degree F; 14.7Ibro"jsq.in. absolute

In the event the concentration S02 data point is inaccurate or not available or a flow meter for

FRIo" does not exist or is inoperable, then CITGO shall estimate emissions based on best

engineering judgment.

78
K. CONTROL OF HYDROCARBON FLARING INCIDENTS

94. For Hydrocarbon Flaring InCidents occurring after the Date ofEntry, CrrGO shall

follow the same investigative, reporting, and corrective action procedures as those set forth in

Section V.I. for Acid Gas Flaring Incidents; provided however, that in lieu of analyzing possible

corrective actions under Paragraph 79.e and taking interim and/or long-term corrective action

under Paragraph 80 for a Hydrocarbon Flaring Incident attributable to the startup or shutdown of

a unit that CrrGO has previously analyzed under this Paragraph, CITGO may identifY such prior

analysis when submitting the. report required under this. Paragraph. By no later than the dates

specified in Appendix G for identified coker flares, CrrGO will install equipment to minimize

HC Flaring from coker blowdown cycles. Prior to the completion ofthese projects, CrrGO shall

not be required to identifY or implement corrective action(s), as under Paragraph 80, for HC

Flaring Incidents from coker blowdown cycles, unless. more than 500 lbs. of S02 would have

been released ifsnch equipment had been installed and in use. crrGO shall submit the

Hydrocarbon Flaring Incident(s) reports as part ofthe Semi-annual Progress. Reports required

pursuant to Section IX. Stipulated penalties under Paragraphs 85 - 91 and Section XI shall not

apply to Hydrocarbon Flaring Incident(s). The formulas at Paragraph 92, used for calculating the

quantity and rate ofsulfur dioxide emissions during AG Flaring Incidents, shall be used to

calculate the quantity and rate ofsulfur dioxide emissions during HC Flaring Incidents. Neither

this Paragraph 94 nor Section V.J. ofthis Consent Decree shall apply to Hydrocarbon Flaring

Device 343 B-5 Flare Central at the Lake Charles Refinery..

L. BENZENE WASTE NESHAP PROGRAM ENHANCEMENTS

95. In addition to continuing to comply with all applicable requirements of40 C.F.R.

Part 61, Subpart FF ("Benzene Waste NESHAP" or "Subpart FF"), CrrGO agrees to undertake

79
the measures set forth in Section V.L. to ensure continuing compliance with Subpart FF and to

minimize or eliminate fugitive benzene waste. emissions at each Covered Refinery.

96. Current Subpart FF Status.

a. CITGO has determined that the Lake Charles, Lemont, and Corpus Christi East

Refineries each has a total annual benzene (TAB) ofgreater than 10 megagrarns (Mg) per year.

Commencing on the Date ofEntry ofthe Consent Decree,. each ofthe above referenced refineries

shall comply with the compliance option set forth at 40 C.F.R. § 61.342(e) (herein referred to as

the "6BQ Compliance Option"); and

b. CITGO has determined that the Corpus Christi West, Paulsboro and Savannah

Refmeries each has a TAB ofless than 10 Mglyr and that the Corpus Christi West Refmery has. a

TAB of greater than 1.0 Mglyr.

97. Refinery Compliance Status Changes.. Commencing on the Date ofEntry ofthe

Consent Decree and for the duration ofthe Consent Decree, CITGO shall not change the

compliance option ofthe Lake Charles, Lemont, or Corpus Christi East Refineries from the. 6BQ

Compliance Option to the compliance options set forth at 40 C.F.R. § 61.342(c) or (d). Ifat any

time. from the Date ofEntry ofthe Consent Decree. through its termination, the Paulsboro,

Savannah or Corpus Christi West Refineries are determined to have a TAB equal to or greater

than 10 Mglyr, each such refinery shall comply with the 6 BQ Compliance Option.

98. One-Time Review and Verification ofEach Refinery's TAB and Compliance

with the Benzene Waste NESl!AP, including the 6 BO Compliance Option.

a. Phase One ofthe Review and Verification Process. By no later than April 30, 2005,

CITOO shall complete a review and verification ofthe Lake Charles, Lemont, CorpusClrristi

East, Corpus Christi West, and Savannah Refineries TAB and its compliance with the Benzene

Waste NESHAP, including the 6 BQ Compliance Option (if applicable). elTOO shall complete

80
a review and verification ofthe Paulsboro Refinery TAB and compliance with the Benzene

Waste. NESHAP by no later than August 31, 2005. CITGO's review and verification process at

each Covered Refinery shall include, but not be limited to:

1. an identification of each waste stream that is required to be included

in the Refinery's TAB where these waste streams meet the definition

of a waste under 40 C.F.R. § 61.341 ~, slop oil, tank water draws,

spent caustic, spent caustic hydrocarbon layer, desalter rag layer

dumps, desalter vessel process sampling points, other sample wastes,

maintenance wastes, and turnaround wastes);

ii.. a review and identification ofthe calculations. and/or measurements

used to determine the flows of each waste stream for the purpose of

ensuring the accuracy offue annual waste. quantity for each waste

stream;

111. an identification ofthe benzene concentration in each waste stream,

including sampling for benzene concentration at no less than 10 waste

streams per Refinery for the Lake. Charles, Lemont, Corpus Christi

East and Corpus Christi West Refineries, and no less than 5 waste

streams per Refinery for the Paulsboro and SavanIIalI Refineries,

consistent with the requirements of40 C.F.R. § 61.355(c)(I) and(3);

provided however, that previous analytical data or documented

knowledge ofwaste streams maybe used, 40 C.F.R. § 61.355(c)(2),

for streams not sampled;

iv. an identification ofwhether or notthe stream is controlled consistent

with the requiremeuts of Subpart FF; and

v. an identification of any existing noncompliance with the requirements

of Subpart FF.

Byno later than thirty (30) days following the completion ofPhase One ofthe review and

verification process, CITGO shall submit a Benzene Waste NESHAP Compliance Review and

Verification report ("BON Compliance Review and Verification Report") that sets forth the

results ofPhase One, including but not limited to the items identified in Subparagraphs (i)

through (v) ofthis Paragraph.

81
b. Phase Two ofthe. Review and Verification Process. Based on EPA's review ofthe

BON Compliance Review and Verification Report(s), EPA may select up to 20 additional waste

streams. at each Covered Refinery for sampling for benzene concentration. ClTGO shall conduct

the required sampling under representative conditions and submit the results to EPA within sixty

(60) days ofreceipt ofEPA's request. CITGO shall use the results ofthis additional sampling to

recalculate the TAB and the uncontrolled benzene quantity, except where such results are not

accurate due. to identified laboratory or analytical error, and to amend the BON Compliance

Review and Verification Report, as needed. To the extent that EPA requires CITGO to

re-sample any waste stream sampled by CITGO on or after January 1, 2003, CITGO may average

the results ofsuch sampling events. CITGO shall submit an amended BON Compliance Review

and Verification Report within ninety (90).days following the. date ofthe completion ofthe

required Phase Two sampling, ifPhase Two sampling is required by EPA.

99. [Intentionally Left Blank]

100. Implementation ofActions Necessary to Correct Non-Compliance or to

Come Into Compliance.

a. Amended TAB. Reports. lfthe results ofthe BON Compliance Review and

Verification Report(s) indicate(s) that the reports submitted by CITGO pursuant to 40 C.F.R.

§ 61.357(c) or 6L357(d) for the Covered Refineries have not been filed or are inaccurate and/or

do not satisfy the requirements ofSubpart FF, CITGO shall submit, by no later than sixty (60)

days after completion ofthe BON Compliance Review and Verification Report(s), .an amended

TAB report to the Applicable Federal and State Agencies.

b. Submittal ofCompliance Plans for the Paulsboro, Savannah. and Comus Christi

West Refineries. Ifthe results ofthe BON Compliance Review and Verification Report indicate

that the TABs at the Paulsboro, Savannah, or Corpus Christi West Refineries exceed 10 Mglyr,

82
CITGO shallsubmit to EPA and the appropriate Co-Plaintiff; by no later than 180 days after

completion ofthe BON Compliance Review and Verification Report, a plan that identifies with

specificity the compliance strategy and schedule that CITGO will implement to ensure that the

subject Refmery complies with the 6 BQ Compliance Option as soon as practicable. Ifthe

results ofthe BON Compliance Review and Verification Report indicate that theTAB at the

Paulsboro, Savannah, or Corpus Christi West Refineries is: (i) below I Mg/yr; or (ii) less than 10

Mg/yr but equal to or greater than 1 Mg/yr, CITGO shall comply with the applicable Benzene

Waste NESHAP regulations for such categories ofrefineries.

c. Submittal ofCompliance Plans for the Lake Charles, Lemont, and Corpus Christi

East Refineries. Ifthe results ofthe BON Compliance Review and Verification Report indicate

that the uncontrolled benzene quantity at the Lake Charles, Lemont, or Corpus Christi East

Refineries exceeds 6 Mg/yr, CITGO shall submit to the Applicable Federal and State Agencies,

by no later than 180 days after completion ofthe BON Compliance Review and Verification

Report, a plan that identifies with specificity the compliance strategy and schedule that CITGO

will implement to ensure that the subject Refinery complies with the 6 BQCompliance Option as

soon as practicable.

d. Review and Approval ofPlans Submitted Pursuant to Paragraphs 100.b and 100.c..

Any plan submitted pursuant to Paragraphs 100.b or 100.c shall be subjectto approval or

disapproval by EPA, which shall act after an opportunity for consultation with the. appropriate

Co-Plaintiff. Within sixty (60) days after receiving any notification of disapproval from EPA,

CITGO shall submit to EPA and the appropriate Co-Plaintiff a revised plan that responds to all

83
identified or alleged deficiencies. Upon receipt of approval or approval with conditions, crroo

shall implement the plan according to the schedule provided in the approved plan.

e. Certification ofCompliance with the 6 BO Compliance. Option. By no later than

thirty (30) days after completion ofthe implementation of all actions, if any, required pursuant to

Paragraphs 100.b, t OO.c, orlOO.d to come into compliance with the 6 BQ Compliance Option,

crroo shall submit a report to EPA and the appropriate Co·Plaintiff certifying that, as to the

subject Refinery, the Refinery complies with the. Benzene Waste. NESHAP.

101. Carbon Canisters: crroo shall complywith the requirements ofthis

Paragraph at all locations at the Covered Refmeries where a carbon canister(s) is utilized as a

control device under the Benzene Waste NESHAP.

a. crroo shall continue to. use primary and secondary carbon canisters and operate

them in series at all Covered Refineries where such systems are. in use as ofthe Date ofEntry of

the Consent Decree and shall maintain a complete, accurate and up-to-date list at each such

Covered Refmery that identifies the location where each secondary carbon canister is installed

and whether VOC or benzene is used to monitor for breakthrough at each such canister.under

Paragraph tOI.d, including the date of any change to the constituent beirig monitored for

breakthrough.

b. Except as expressly permitted under Paragraph lO1.f, crroo shall not use single

carbon canisters for any new units or installations that require controls pursuant to the. Benzene

Waste NESHAP at any ofits Covered Refineries.

84
c. For dual carbon canister systems, "breakthrough" between the primary and secondary

canister is defined as any reading equal to or greater than 50 ppm volatile organic compounds,

excluding ethane and methane (hereinafter in Section V.L. only "VOC"), or 5 ppm benzene.

d. ClTGO shall monitor for breakthrough between the primary and secondary carbon

canisters monthly or in accordance with the frequency specified in 40 C.F.R. § 61.354(d),

whichever is more frequent. This requirementshall commence: (i) upon Date ofEntry where

dual carbon canisters currently are in service; and (ii) within seven days after installation of a

new, dual carbon canister system.

e. CITGO shall replace the original primary carbon canisters immediately when

breakthrough is detected between the primary and secondary canister. The original secondary

carbon canister will become the new primarycarbon canister and a fresh carbon canister will

become the secondary canister. For purposes ofthis Paragraph, "immediately" shall mean within

twelve (12) hours ofthe detection ofa breakthrough for canisters of55 gallons or less,. and

within twenty-four (24) hours. ofthe detection of a breakthrough for canisters greater than 55

gallons. In lieu ofreplacing the primary canister immediately, CITGO may elect to monitor the

outlet ofthe secondary canister the day breakthrough between the primary and secondary canister

is identified and each calendar day thereafter. This daily monitoring shall continue until the

primary canister is replaced. Ifthe constituent being monitored (either benzene or VOC) is

detected at the outlet ofthe secondary canister during this period of daily monitoring, the primary

canister must be replaced within twelve (12) hours ofthe detection of a breakthrough. The

original secondary carbon canister will become the new primary carbon canister and a fresh

carbon canister will become the secondary canister.

85
f. Temporary Applications. CITGO may utilize properly sized single canisters for

short-term operations such as with temporary storage tanks or as temporary control devices. For

canisters operated as. part of a single canister system, breakthrough is defined for purposes oftms

Decree as any reading ofVOC above background or benzene above Ipprn. Beginning no later

than October 31, 2004, CITGO shall monitorforbreakthrough from single carbon canisters each

day such canister is used. ClTGO shall replace the. single carbon canister with a fresh carbon

canister, discontinue flow, or route the stream to an alternate, appropriate device immediately

when breakthrough is detected.. For this Paragraph, "immediately" shall mean within twelve (12}

hours ofthe detection ofa breakthrough for canisters of55 gallons or less and within twenty-four

(24). hours ofthe detection of a breakthrough for canisters greater than 55 gallons. IfClTGO

discontinues flow to the single carbon canister or routesthe stream to an alternate, appropriate

control device, such canister must be replaced before it is returned to service.

g. ClTGO shall maintain a readily available supply offresh carbon canisters at each

Covered Refinery at all times or otherwise ensure that such canisters are readily available to

implement the requirements ofthis Paragraph 1Q1.

h. ClTGO shall maintain records associated with the requirements ofthis Paragraph,

including carbon canister monitoring readings and the constituents being monitored for at least

five (5) years after such readings occur.

,

102. Annual Program. By no later than May 31, 2005,. ClTGO shall establish or

modify its written management of change procedures to provide for an armual review ofprocess

information for each Covered Refinery, including but not limited to construction projects, to

86
ensure that all new benzene waste streams are included in the Covered Refinery's waste stream .

inventory. CITGO shall conduct such reviews on an annual basis.

103. Laboratory Audits. CITGO shall co~atidjts of all laboratories that perform

analyses ofCITGO's Benzene Waste NESHAP samples to ensure that proper analytical and

quality assurance/quality control procedures are followed for such samples.

a. By no later than September 30, 2005, CITGO shall complete initial audits of each

laboratory used by it. In addition, CITGO shall conduct a similar audit of any laboratory to be

used for analyses ofbenzene samples prior to such use. IfCITGO has completed an audit of any

laboratory on or after June 30, 2003, initial audits ofthose laboratories pursuant to this

subparagraph shall not be required.

b. If and to the extent that a Covered Refinery submits its. Benzene WasteNESHAP

samples to laboratories audited and certified by New Jersey for the testing method required by

the Benzene Waste NESHAP (as required for the Paulsboro Refinery under New Jersey law),

CITGO need not separately audit such laboratory(ies) under this Paragraph.

c. During the life ofthis Consent Decree, CITGO shall conduct subsequent laboratory

audits, such that each laboratory is audited every two (2) years.

d. CITGO may conduct audits itself; retain third parties to conduct these audits, or use

audits conducted by others as its own, but the responsibility and obligation to ensure compliance

with this Consent Decree and Subpart FF are solely ClTGO's.

104. Benzene Spills. For each spill at each Covered Refinery after the Date ofEntry of

this Consent Decree, CITGO shall review the spill to determine if any benzene waste, as defined

by Subpart FF, was generated. For each spill involving the release ofmore than 10 pounds of

87
benzene in a 24 hour period, CITGO shall: (i) include the benzene waste generated by the spill in

the relevant Covered Refinery's TAB, as required by 40 C.F.R. § 61.342;. and (ii) as appropriate,

account for such benzene waste in accordance with the. applicable compliance option.

105. Training.

a. By no later than May 31, 2005; CITGO shall develop and begin implementation of

annual (i.e., Once each calendar year) training for all employees who draw benzene waste

samples for Benzelle Waste NESHAP purposes.

b. For the Lake Charles, Corpus Christi East, and Lemont Refineries, by no later than

September 30, 2005, CITGO shall complete the development ofstandard operatiIlg procedures

for all control devices and treatment processes used to comply with the Benzene Waste

. NESHAP. By no later than December 31, 2005, CITGO shall complete an initial training

program regarding these procedures for all operators assigned to applicable control devices and

treatment processes. Comparable training shall also be provided to any persons who subsequently

become operators, prior to their assumption ofthis duty. "Refresher"training in these procedures

shall be perfonned on a three year cycle.

c. If and when the Paulsboro, Savannah, or Corpus Christi West Refineries' TAB

reaches 10 Mg/yr or more, CITGO shall complete the development ofstandard operating

procedures for all control devices and treatment processes used to compiy with the Benzene

Waste NESHAP. CITGO shall complete an initial training program regarding these procedures

for all operators assigned to the relevant equipment. Training shall be provided to any persons

who subsequently become operators, prior to their assumption ofthis duty. "Refresher" training

shall be perfonned on a periodic basis. CITGO shall propose a schedule for the initial and

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refresher training at the same time that CITGO proposes a plan pursuant to Paragraph 100.b that

. identifies the compliance strategy and schedule that CITGO will implement to come into

compliance with the 6 BQ Compliance Option.

d. CITGO shall assure that the employees of any contractors hired to perform any ofthe

requirements ofSection V.L ofthis Consent Decree are properly trained to implement such

requirements that they are hired to perform, as under Paragraph 105.a-c.

106. Waste/Slap/Off-Spec Oil Management. By no later than February 28,2005,. for

. each Covered Refinery, CITGO shall submit to EPA and the appropriate Co-Plaintiffschematics

that: (a) depictthe waste management units (including sewers) that handle, store, and transfer

waste/slop/off-spec oil streams; (b) identify the control status of each waste management unit;

and (c)show how such oil is transferred within each Refinery. Representatives from CITGO and

EPA thereafter may confer about the appropriate characterization of each Covered Refinery's

waste/slop/off-spec oil streams and the necessary controls, if any, for the waste management

,units handling such oil streams for purposes ofeach Covered Refinery's TAB calculationandlor

compliance with the 6BQ Compliance Option. Ifrequested by EPA, CITGO shall promptly

submit revised schematics that reflect the Parties' agreements regarding the characterization of

these oil streams and the appropriate control standards. CITGO shall use these schematicsin

preparing the end-of-line sampling plans required under Paragraph 107.

107. Ouarterly Sampling at Egd afLine and Point of Waste Generation for

Refineries nnder the 6 DO Compliance Option. eITOO shall conduct quarterly sampling at

the Lake Charles, Lemont, and Corpus Christi East Refineries under the terms ofthis Paragraph

for the purpose of calculating quarterly, uncontrolled benzene quantities.

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a. By no later than September 30, 2005, CITGO shall submit to EPA for approval, a

sampling plan designed to identify the quarterly benzene quantity in uncontrolled benzene waste

streams, including waste/slop/off-spec oil. The sampling plan ("EOL Plan") shall include, but

need not be limited to: (i) proposed sampling locations and methods for flow calculations at the

"end ofline" of uncontrolled benzene waste streams; (ii) a simplified flow diagram that identifies

significant, uncontrolled benzene waste streams that feed into. each proposed sampling location;

(iii) proposed sampling, at the "point ofwaste generation," of each waste stream that contributes

0.05 Mglyr or more to a Refinery's BQ; and (iv) quarterly sampling at all "end ofline" and point

ofwaste generation locations identified in Paragraph 107.a (i) and (iii).

b. If changes in processes, operations, or other factors. lead CITGO to conclude. that its

approved EOL Plan may no longer provide an accurate measure ofthe Refinery's quarterly

benzene quantity in uncontrolled benzene waste streams, CITGO shall submit a revised EOL

Plan to EPA for approval.

c. CITGO shall commence sampling under its EOL Plan during the fourth calendar

quarter 0[2005 (regardless ofwhether or not the Plan is approved at that time). CITGO shall

take, and have analyzed, at least three representative samples from each identified sampling

location. CITGO shall use the average of all samples taken and the identified flow calculations

to detennine its quarterly benzene quantity in uncontrolled waste streams and to estimate a

calendar year value for each Refmery.

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108. Quarterly Sampling at End of Line and Point of Waste Generation for the

Paulsboro, Savannah, and Corpus Christi West Refineries.

a. TAB. is under I Mglyr. Ifthe results ofthe BON Compliance and Review Report

indicate that the TAB for the Paulsboro. or Savannah Refineries is less than 1 Mgfyr, no quarterly

sampling shall be required.

b. TAB is less than 10 MgIyr but equal to or greater than 1 MgIyr. Ifthe. results ofthe

BON Compliance and Review Report indicate that the TAB for the Paulsboro, Savannah, or

Corpus Christi West Refineries is less than 10 Mgfyr but equal to or greater than 1 Mgfyr,

CITGO shall comply with.the provisions. ofParagraph 107 except that: (i) the EOL Plan shall be

dhe byno later than December 31, 2005;. (ii) the quarterly sampling shall commence during the

first month ofthe first full calendar quarter of2006 (regardless ofwhether or not the. Plan is

approved at the. time); and (iii) after eight (8) quarters of quarterly sampling, and based upon an

evaluation ofthe prior sampling results, CITGO may submit a request to EPA to modify the

frequency ofthe sampling. EPA,. after an opportunity for consultation'with the appropriate CoPlaintiff, shall not unreasonably withhold its consent to such modification.

c. TAB is 10 Mglyror greater. Ifthe results ofthe BON Compliance and Review

Report indicate that the TAB for the Paulsboro, Savannah, or Corpus Christi West Refineries is

10 Mgfyr or greater, CITGO shall comply with the provisions ofParagraph 107 except that: (i)

the EOL Plan shall be due by no later than ninety (90) days after the date ofthe submission ofthe

final BON Compliance and Review Report; and (ii) the quarterly sampling shall commence

during the first month ofthe first full calendar quarter immediately following CITGO's

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submission ofthe EOL Plan to EPA (regardless ofwhether or not the Plan is approved at the

time).

109. Calculation of Quarterly and Projected Calendar Year Uncontrolled Benzene

Quantities and TABs. For any Covered Refinery that is or becomes subject to the 6 BQ

Compliance Option at any time during the duration ofthis Consent Decree, at the end of each

.Calendar Quarter following commencement of quarterly sampling, CITGO shall calculate a

quarterly uncontrolled benzene quantity and shall estimate a projected calendar year uncontrolled

benzene quantity based on the quarterly EOL sampling results, noncEOL sampling results, and

the approved flow calculations. If, at any time during the duration ofthis Consent Decree, the

TAB at the Paulsboro, Savaunah, or Corpus Christi West Refmeries is less than 10 Mglyrbut

equal to or greater than 1 Mglyr, CITGO shall calculate, at the end of each Calendar Quarter

following commencement of quarterly sampling, a quarterly TAB and a projected calendar year

TAB. based on the quarterly EOL sampling results, non-EOL sampling results, and the. approved

flow calculations. CITGO shall submit the uncontrolled benzene quantity and, if applicable,

TAB. calculations in the progress reports due under Section IX ofthis Decree.

110. Corrective Measures.

a. Applicability, If, at any Covered Refinery that is or becomes subject to the 6 BQ

Compliance Option at any time during the duration ofthis Consent Decree, the calculations in

Paragraph 109 indicate that the quarterly uncontrolled benzene quantity exceeds 1.5 Megagrams

or the projected calendar year uncontrolled benzene quantity exceeds 6.0 Megagrams, CITGO

shall submit a written report to EPA and the appropriate Co-Plaintiffthat evaluates all relevant

information and identifies whether any action should be taken to reduce benzene quantities in its

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waste streams for the remainder ofthe calendar year. If additional actions are determined to be

necessary to ensure compliance with the 6 BQ Compliance Option, CITOO will include in its

written report a plan as specified in Paragraph IIO.b. If, at any time during the duration ofthis

Consent Decree, the TAB at the Paulsboro or Savannah Refmeries is equal to or greater than I

Mglyr, and the calculations in Paragraph 109 indicatedthat the quarterly TAB exceeds 2.5

Megagrams or the projected calendar year TAB exceeds 10.0 Megagrams, CITOO shall submit a

written report to EPA and the appropriate Co-Plaintiffthat evaluates all relevant information and

identifies whether any action should be taken toxeduce benzene quantities in its waste streams

for the remainder ofthe calendar year. If additional actions are determined to be necessary to

ensure that its TAB remains below 10 Mglyr, CITOOwill include in its written report a plan as

specified in Paragraph IIO.b.

b. Corrective Measures Plan. CITOO shall, in any such corrective measures plan

required by this Paragraph, identify: (i) the cause ofthe potentially elevated benzene quantities;

(ii) all corrective actions that CITOO has taken or plans to take to ensure. that the cause will not

recur; and (iii) a specific strategy and schedule that CITOO shall implement to ensure

that CITOO complies with the 6 BQ Compliance Option or generates less than 10 Mglyr, as

applicable. CITOO shall submit such plan and schedule, along with its report under Paragraph

11O.a, by no later than 60 days after the end ofthe Calendar Quarter in which one or more ofthe

conditions specified inthe Paragraph 110.a is satisfied. CITOO shall implement its plan in

accordance with the schedule provided therein.

c. Third-Party TAB Study and Compliance Review. After a second consecutive quarter

in which at least one ofthe conditions in Paragraph IIO.a· continues to exist and ClTGO is not

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then able to identifY the canse(s) and/or appropriate corrective measures to ensure compliance

with the 6 BQ option or that the refinery's TAB remains below 10 Mg/yr, CITOO shall retain a

third-party contractor to undertake a comprehensive TAB study and compliance review ("Thirdparty TAB Study and Compliance Review") at the subject Refinery. By no later than the hist day

ofthe next following quarter, CITOO shall submit a proposal toEPA that identifies the

contractor, the contractor's scope ofwork;. and the contractor's schedule for the Third-Party TAB

Study and Compliance Review. Unless EPA disapproves or seeks modifications ofthe. proposal

within 30 days after its receipt, CITOO shall authorize the contractor to commence work.

CrTOO shall ensure that the work is completed in accordance with the schedule provided therein.

No later than thirty (30) days after CITOO receives. the results ofthe Third-Party TAB Study and

Compliance Review, CITOO shall submit the results to EPA. After the report is subinitted to

EPA, CITOO and EPA shall discuss informally the results ofthe Third-Party TAB Study and

. Compliance Review. No later than ninety (90) days after CITOO receives the results ofthe

.Third-Party TAB Study and Compliance Review or at such other time as CITOO and EPA may

agree, CITOO shall submit to EPA a plan and schedule for remedying any deficiencies identified

in the Third-Party TAB Study and Compliance Review and any deficiencies that EPA identified

following the Third-Party TAB Study and Compliance Review. Unless EPA disapproves or

seeks. modifications ofthe proposal within thirty (30) days after its receipt, CITOO shall

implement the remedial plan in accordance with the schedule included in its plan.

Ill. Miscellaneous Measures. The provisions ofthis Paragraph shall apply: (i) to the

Lake Charles, Lemont, and Corpus Christi East Refineries, as ofthe Date ofEntry ofthis

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Consent Decree; and (ii) to the Paulsboro, Savarmah, and Corpus Christi West Refmeries only if

the TAB reaches or exceeds 10 Mg/yr. CITGO shall:

a. Conduct monthly visual inspections of and, if appropriate, refill all Subpart FF water

traps within each Refinery's individual drain systems;

b. IdentifY and mark at the drain all area drains that are segregated storrnwater drains by

no later than February 28,2005;

c. IfCITGO utilizes conservation vents, visually inspect all Subpart FF conservation

vents or indicators on process sewers for detectable leaks on a weekly basis, reset any vents

where leaks are detected, and record the results ofthe inspections. After two (2) years ofweekly

inspections, and based upon an evaluation ofthe recorded results, CITGO may submit a request

to the appropriate EPA Region to modifY the frequency ofthe inspections. EPA shall not

unreasonably withhold its consent to such modification. Nothing in this subparagraph shall

require CITGO to monitor conservation vents on fixed rooftanks; and

d..Conduct quarterly monitoring and repair ofthe oil-water separators consistent with

the "no detectable emissions" provision in 40 C.F.R. § 61.347.

112. Recordkeeping and Reporting Requirements. CITGO shall submit to EPA, as

and to the extent required, the following materials in the progress report(s) pursuant to Section

IX (Reporting and Recordkeeping) for the six month period covered by the report:

a. An identification of all laboratory audits, if any, completed during the six month

period, including a description ofthe methods used in the audit and the results ofthe audit;

b. A description ofthe measures taken, ifany, dllring the six month period to comply

with the training provisions ofParagraph 105; and

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c. A summary ofthe sampling results required under Paragraphs 107 and 108, including

the quarterly and projected annual uncontrolled benzene quantities or TABs, as applicable.

M. LEAK DETECTION AND REPAIR ("LDAR") PROGRAM

ENHANCEMENTS.

113. In order to minimize or eliminate fugitive emissions of volatile organic

compounds ("VOCs''), benzene, volatile hazardous air pollutants ("VHAPs"), and organic

hazardous air pollutants ("HAPs'') from equipmentin light liquid and/or in gas/vapor service,

. CITGO shall undertake the enhancements identified in this Section V.M. to its LDARprograms

for each Covered Refinery under 40 C.F.R. Part 60, Subpart GGG; Part 61, Subparts J and V;

Part 63, Subparts F, H, and CC;. and applicable state and local LDAR requirements. The terms

"equipment," "in light liquid service" and "in gas/vapor service" shall have the definitions set

.forth in the applicable provisions of40 C.F.R. Part 60, Subpart GGG;Part 61, Subparts J and V;

Part 63, Subparts F, Hand CC; and applicable state and local LDAR regulations. CITGOis not

requited to include in the enhanced program described herein any equipment or units not

otherwise subject to the applicable federal, state or local LDAR regulation, nor is any

requirement ofthis Section V.M. intended to change the criteria for identifying valves orpurnps

that are subject to the various LDAR programs.

114. [Intentionally Left Blank]

115. Written Refinery-Wide LOAR Program. By no later than April 30, 2005,

CITGO shall develop and maintain a written program for compliance with all applicable federal

and state LDAR regulations at each Covered Refinery. CITGO shall update the program as may

be necessary to ensure continuing compliance. Such program shall include, at a minimum:

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a. A leak rate goal for each Covered Refinery and a target for achievement on a

process-unit-by-process-unit basis;

b. A procedure to identify all equipment in light liquid and/or in gas/vapor service

that has the potential to leak VOCs, HAPs, VHAPs, and benzene within each

Covered Refinery's process units;

c. Procedures for identifying leaking equipment within each Covered Refinery's

process units;

d. Procedwes for repairing and keeping track ofleaking equipment;

e. Procedures for identifying and including in the LDAR program new

equipment;

f A process for evaluating new and replacement equipment to promote

consideration and instaIlation of equipment that wiII minimize leaks. and/or

eliminate chronic leakers;

g. A definition or designation of "LDARPersonnel" responsible for the day-today implementation ofthe LDAR program and the designation of an "LDAR

Coordinator" who has. the authority and responsibility for implementing the

enhanced LDAR program at each Covered Refmery (by name or position); and

h. A procedure for regularly communicating LDAR information to appropriate

CITOn personnel.

116. Trainfug. By no later than May 31,2005, CITOD shall begin to implement the

foIlowing training programs at each Covered Refinery:

a. For personnel newly-assigned to LDAR responsibilities, crroo shall require

LDAR training prior to each employee beginning such work;

b. For all personnel assigned LpAR responsibilities, CITGO shaIl provide and

require completion ofannual LDAR training. Initial armual LDAR training for

all such personnel wiII be completed no later than September 30, 2005.

c. For all other operations and maintenance personnel (including contract

personnel) at each Covered Refinery, C1TGO shall provide and require

completion of an initial training program that includes instruction on aspects of

LDAR that are relevant to the person's duties. Initial LDAR training for all

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such personnel will be completed no later than September 30, 2005.

"Refresher" training shall be perfonned annually; and

d. If contract employees are perfonning LDAR work, CITGO shall assure that its

contractor complies with the training requirements in Subparagraphs 116.a-c,·

as appropriate, for all such contractor employees and shall require the

contractor to provide its training infonnation and records to CITGO.

117. LDAR Audits. CITGO shall implement at each Covered Refinery the refinerywide audits set forth in this Paragraph to ensure each Covered Refmery's compliance with all

applicable LDAR requirements. The LDAR audits shall include, but not be limited to,

comparative monitoring, records review to ensure monitoring and repairs were completed in the

required periods, component identification procedures, tagging procedures, data management

procedures and observation ofthe LDAR technicians' calibration and monitoring techniques.

During the WAR audits, leak rates shall be calculated for each process unit where comparative

monitoring was perfonned.

a. Initial Compliance Audit. By no later than September 30, 2005, CITGO shall

complete a refinery-wide audit ofits compliance with the LDAR regulations at each Covered

Refinery, provided, however, that ifCITGO elects to conduct a third-party audit at the Paulsboro

and/or Savannah refineries under Paragraph 117.b, such audit must then be completed by no later

than March 31, 2006. Each audit shall include, at a minimum, the audit requirements set forth in

this Paragraph. Within 60 days ofcompletion of each audit, CITGO shall either certifY

compliance with all LDAR requirements or submit a report to EPA and the appropriate CoPlaintiff on areas oinon-compliance identified as a result ofits refinery-wide audit, including a

proposed compliance schedule for correcting such non-compliance.

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b. Third-Party Audits. CITGO shall retain a contractor(s) with expertise in the LDAR

program requirements to perform a third-party audit of each Covered Refinery's LDAR program.

The first third-party audit at Corpus Christi East, Corpus Christi West, Lake Charles and Lemont

shall be completed pursuant to Subparagraph 117.a ofthis Paragraph (lrritial Compliance Audit).

Subsequent third-party audits shall be held every four (4) years thereafter for the life ofthis

Consent Decree. CITGO is. required by this Consent Decree to perform only one third-party

audit at the Paulsboro and Savannah Refmeries during the term ofthis Consent Decree.

c. Internal Audits. CITGO shall conduct internal audits of each Covered Refinery's

LDAR Program by sending personnel familiar with the LDAR program and its requirements

from one or more ofCITGO's other Refineries or locations. to. audit another CITGO Refinery..

CITGO shall complete the first round ofthese internal LDAR audits no later than two (2) years

after the date ofthe completion ofthe Initial Compliance Audit required in Subparagraph 117.a.

Internal audits ofthe Lake Charles, Lemont, Corpus Christi East, and Corpus Christi West

Refineries shall be held every four years thereafter. Internal audits ofthe Paulsboro. and

Savannah Refineries shall be held every two (2) years thereafter.

d.. Audit Frequency. To. ensure that an audit at each Covered Refinery occurs at least

every two years, third-party and internal audits shall be separated by no more than two years.

e. Alternative. As an alternative to the internal audits required by Subparagraph 117.c,

CITGO may elect to retain third-parties to undertake these audits, provided that an audit ofeach

Covered Refinery occurs every two (2) years.

118. Implementation of Actions Necessary to Correct Non-Compliance. Ifthe

results of any ofthe audits conducted pursuant to Paragraph 117 identifY any areas of

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noncompliance, CITGO shall implement, as soon as practicable, all steps necessary to correct or

otherwise address such fjTea(s) of non-compliance and to prevent a recurrence ofthe cause ofthat

non-compliance, to the extent practicable. For the life ofthe Consent Decree, CITGO shall

retain the audit reports generated pursuant to Paragraph 117 and shall maintain a written record

of all corrective actions that CITGO takes in response to deficiencies identified in any audits. In

the first semi-annual report after the completion ofan audit, see Section IX ofthis Consent

Decree (Recordkeeping and Reporting), ClTGO shall submit a summary, including findings, of

each such audit report and a list of corrective actions taken during the reporting period. In each

subsequent semi-annual report under Section IX ofthis Corlsent Decree, ClTGO shall submit a

list of corrective actions taken during that reporting period and a notice, where appropriate, that

all corrective actions have. been completed in response to a particular audit at a Covered

Refinery.

119. Internal Leak Definition for Valves and Pumps. CITGO shall utilize the

following internal leak definitions for valves and pumps in light liquid and/or gas/vapor service,

unless other perroit(s), regulations, or laws require the use oflower leak definitions.

a. Leak Defmition for Valves. By no later than February 28, 2006, ClTGO shall utilize

an internal leak: definition of500 ppm VOCs for valves at the Lake Charles, Lemont, Corpus

Christi East, Corpus Christi West, and Paulsboro Refineries, excluding pressure relief devices.

By no later than December 31, 2006, CITGO shall utilize an intemalleak definition of 500 ppm

VOCs for valves at the SavannahRefinery, excluding pressure relief devices.

b. Leak Definition for Pumps. By no later than February 28, 2006, ClTGO shall utilize

an intemalleak definition of 2000 ppm for each Covered Refinery's pumps.

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120. Reporting, Recording, Tracking, Repairing and Remonitoring Leaks of'

Valves and Pumps Based on the Internal Leak Definitions.

a. Reporting. For regulatory reporting purposes, CITGO may continue to report leak

rates in valves. and pumps against the applicable regulatory leak definition, or may use the lower,

internal leak definitions specified in Paragraph 119.

b. Recording. Tracking. Repairing and Remonitoring Leaks. CITGO shall begin

recording, tracking, repairing and re-monitoring all leaks in excess ofthe internal leak definitions

ofParagraph 119 atsuch time. as those definitions become applicable. CITGO shall make a first

attempt to repair and re-monitor leaks within five (5) days. ofidentification. Within thirty (30)

days ofidentification, CITGO shall either complete repairs andre'monitoring ofleaks or place

..such component on the Covered Refinery's delay ofrepair list pursuant to Paragraph 128.

121. LDAR Monitoring Frequency.

a. Pumps. Unless more frequent monitoring is required by applicable federal, state

andlpr local requirements, CITGO shall monitor all pumps at all Covered Refineries at the

internal leak definition on a monthly basis.

b. Valves. Unless more frequent monitoring is required by applicable federal, state

andlorIocal requirements, CITGO shall monitor all valves at all Covered Refineries, other than

. difficult-to-morutor or unsafe-to-monitor valves, at the intemalleak definition on a quarterly

basis.

121A. Monitoring After Turnaround or Maintenance. CITGO shall have the option

ofmonitoring affected valves and pumps within process unit(s) after completing a documented

maintenance, startup, orshutdown activity without having the results ofthe monitoring count as

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a scheduled monitoring activity, provided that CITGO monitors according to the following

schedule:

. L For events. involving 1000 or fewer valves and pumps, monitor within one (1)

week ofthe documented maintenance, startup, or shutdown activity;

ii. For events involving greater than 1000 but fewer than 5000 valves and pumps,

monitor within two (2) weeks ofthe documented maintenance, startup, or

shutdown activity; and

iii. For events involving greater than 5000 pumps and valves, monitor within four

(4) weeks ofthe documented maintenance, startup, orshutdown activity.

122. Initial Attempt at Repair ofValves. Beginning no later than September 30,

2005, at the Lake Charles, Lemont, Corpus Christi East, Corpus Christi West and Paulsboro

Refineries and beginning no later than December 31, 2006, at the Savannah Refmery, CITGO

shall make an "initial attempt" to repair any valve at any Covered Refinery that has a reading

greater than 200 ppm ofVOCs, excluding pressure reliefdevices, control valves and components

that LDAR personnel are not authorized to repair. CITGO or its designated contractor shan

make this "initial attempt" at repair and remonitor the leak within five. (5) days ofidentification.

Ifthe re-monitored leak reading is. below the applicable leak definition, no. further action will be

necessary. Ifthe re-monitored leak reading is greater than the applicable leak definition, CITGO

shall repair the valve according to the requirements ofParagraph 128, except that no first repair

attempt requirement shall apply. IfCITGO can demonstrate with statistically significant

monitoring data over a period of at least two years that "initial attempts" to repair at 200 ppm

worsen or do not improve overall mass refinery emissions or emission rates from. emitting

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components in a reasonable, cost-effective manner, CITGO may request EPA to amend this

requirement.

123. Electronic Monitorine, Storing. and Reporting of LDAR Data.

. a. Electronic Storing and Reporting ofLDAR Data. Beginning on the Date ofEntry of

the Consent Decree, CITGO shall continue to maintain an electronic database for storing and

reporting LDAR data at all Covered Refineries.

b. Electronic. Data Collection During LDAR Monitoring and Transfer Thereafter. By

no later than December 31, 2004, CITGO shall use data loggers and/or electronic data collection

devices during all LDAR monitoring at the Lake Charles, Lemont,. Corpus Christi East, Corpus

Christi West and Paulsboro Refineries. CITGO, or its designated contractor, shall use its best

efforts to transfer on a daily basis the. electronic data from electronic data logging devices to the

electronic database. maintained pursuant to Paragraph 123.a. For all monitoring events in which

an electronic data collection device is. used, the collectedmonitoring data shall include a time and

date stamp, and identification ofthe instrument and operator. ClTGO may use. paper logs where

necessary or more feasible (e.g., small rounds, re-monitoring, or when data loggers are not

available or broken), and at all times at the Savannah Refinery. Ifpaper logs are used, CITGO

shall record, at a minimum, the identity ofthe technician, the date, the monitoring starting and

ending times, all monitoring readings, and an identification ofthemonitoring equipment.

CITGO shall transfer any manually recorded monitoring data to the electronic database

maintained pursuant to Paragraph l23.a within seven (7) days ofthe monitoring event.

124. DAfoe of LDAR Data. By no later than the Date ofEntry ofthe Consent

Decree, CITGO (or a third-party contractor retained by CITGO) shall have developed and begun

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implementing procedures for quality assurance/quality control ("QA/QC") reviews ofall data

generated by LDAR monitoring technicians such that: (a) monitoring data is reviewed for

QA/QC by the monitoring technicians daily after collection;. and (b) all monitoring data is subject

to a QA/QC review at least once per quarter, including but not limited to the number of

components monitored per technician, time between monitoring events, and abnormal data

patterns.

125. [Intentionally Left Blank]

126. [Intentionally Left Blank]

127. Calibration/Calibration .Drift Assessment.

a. Calibration. CITGO shall conduct all calibrations ofLDAR monitoring equipment at

all Covered Refineries in accordance with 40 C.F.R. Part 60, EPA Reference Test Method 21.

b. Calibration DriftAssessment. Beginning no later than the Date ofEntry ofthis

Decree, CITGO shall conduct calibration drift assessments ofLDAR monitoring equipment at

each Covered Refinery at the end of each monitoring shift, at a minimum. CITGO shall conduCt

the calibration drift assessment using, at a minimum, a 500 ppm calibration gas. Ifany

calibration drift assessment after the initial calibration shows a negative drift ofmore than 10%

from the previous calibration, CITGO shall re-monitor all valves that were monitored using that

instrument and that had a reading greater than 100 ppm since its last calibration and shall remonitor all pumps that were monitored using that instrument and that had a reading greater than

500 ppm since its last calibration.

c. CITGO shall maintain records of all instrument calibrations for a period of 1 year

following the date ofcalibration.

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128. Delay ofRepair. Beginning no later than February 28, 2006, CITGOshal1 take

the following actions for any equipment at any Covered Refinery that CITGO intends to place on

the "delay ofrepair" list, under applicable regulations:

a. Require sign-offby the unit supervisor (as identified in the Covered Refinery's

written LDAR program) within thirty (30) days ofidentifying that a piece of equipment is

leaking at a rate greater than the applicable leak definition that such equipment is teclmically

infeasible to repair without a process unit shutdown.

b. Include equipment that is placed on the "delay ofrepair" list in CITGO's regular

LDAR monitoring, as required in Paragraph 121.

c. Use the "drill and tap" method (or an equivalent), other than on a control or pressure

reJiefvalve, ifit is leaking at a rate of 10,000 ppm or greater, unless CITGO can demonstrate

that .there is a safety, mechanical, or major environmental concern posed by repairing the leak in

this manner. CITGO shall, ifnecessary, perform two "drill and taps" (or equivalents) within

thirty (30) days. ofdetecting the leak. For purposes ofthis Paragraph, the second attempt may be.

made through the same hole created during the first attempt.

d. Use best efforts to isolate and repair pumps identified as leaking at a rate of2000

ppm or greater.

e. If a new method develops that is similarly effective as the "drill and tap" method for

repairing non-control valves, CITGO will advise EPA and appropriate Co-Plaintiffs prior to

implementing such new method.

129. Chronic Leakers. CITGO shall replace, repack, or perform similarly effective

repairs on chronically leakiug, non-control valves during the next process unit turnaround after

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identification. A component shall be classified as a "chronic leaker" under this Paragraph ifit

leaks above 10,000 ppm twice in any consecutive four quarters, unless the component has not

leaked in the twelve (12) consecutive quarters prior to the relevant process unit turnaround.

130. Recordkeeping and Reporting Requirements for this Section

a. Consistent with the requirements of Section IX (Recordkeeping and Reporting),

CITGO shall include. the following information in each Covered Refinery's Semi-Annual

Progress Report in which the identified activity occurred or was required:

I.

n.

Ill.

IV.,

v.

VI.

VII.

VIII.

IX.

Notification that training has been implemented as required by

Paragraph 116;

Notification that the. lower leak definitions and increased monitoring

frequencies have been implemented according to Paragraphs 119 and

121',

Notification that the "initial attempt at repair" program under

Paragraph 122 has been implemented;

Notification that the QAlQC procedures for reviewing data generated

by LDAR technicians under Paragraph 124 have been implemented;

An identification ofeach Covered Refinery's LDAR Coordinator;

Notification that a tracking program for new valves and pumps added

during maintenance and construction has been developed and is being

implemented;

Notification that the calibration drift assessment procedures under

Paragraph 127 have been implemented;

Notification that the "delay ofrepair" procedures under Paragraph 128

have been implemented; and

A copy ofeach Covered Refinery's written refinery-wide LDAR

program under Paragraph 115.

106
b. In each Covered Refinery's Progress Report submitted pur~uant to Section IX,

CITGO shall also include the following information on LDAR monitoring:

i. a list ofthe process units monitored during the reporting period;

ii. the number ofvalves and pumps present in each process unit;

iii. the number ofvalves and pumps monitored in each process unit;

iv. the number ofvalves and pumps found leaking;

v. the nuniber of "difficult to monitor" pieces of equipment monitored;

VI. the projected month and year ofthe. next monitoring event for that

unit;

vii. a list of all equipment currently on the "delay ofrepair" list,. the date , . each component was determined to be leaking at a rate greater than

10,000 ppm, the date of each drill and tap or equivalent method of

repair, its associated monitoring results, and whether such activities

were completed in a timely manner under Paragraph 128;

viii. the number, date and results Of each initial attempt at repair, including

a list of all initial attempts/remonitoring that did not occur in a timely

manner under Paragraph 122; and

lX. all instances when CITGO failed to comply with the requirements in

Paragraph 120.b. (Recording, Tracking, Repairing and Remonitoring

Leaks).

To the extent other required reports to EPA and the appropriate Co-Plaintiffaddress the above.

information, CITGO may incorporate such other report(s) by reference in lieu ofseparately

submitting such information under this Paragraph 130.b.

107
N. INCORPORATION OF CONSENT DECREE REOUIREMENTS INTO

FEDERALLY ENFORCEABLE PERMITS

131. Currently Effective Limits and Standards. By no later than March 31,.2005,

CITGO shall submit applications to the Applicable State Agency to incorporate the emission'

limits and standards required by the Consent Decree that are effective as ofthe Date ofEntry of

the Consent Decree into air pennits (other than Title V permits) which are federally enforceable

unless such permits with such limits have already been issued or applied for. Following

submission ofthe permit application, CITGO shall cooperate with the Applicable State Agency

by promptly submitting to the Applicable State Agency all available information that the

Applicable State Agency seeks following its. receipt ofthe permit application. CITGO. shall file

any applications necessaryto incorporate the requirements ofthose permits into the Title V

permits ofthe Covered Refmeries.

132. Future Limits and Standards. Byno late~ than thirty (30) days after the

effective date or establishment of any emission limits and/or standards under Section V ofthis

Consent Decree, CITGO shall submit applications to the Applicable State Agency to incorporate

those emission limitations. and/or standards into air permits (other than Title V permits) which

are federally enforceable unless such permits with such limits have already been issued or

applied for. Following submission ofthe permit appliCation, CITGO shall cooperate with the

Applicable State Agency by promptly submitting to the Applicable. State Agency all available

information that the Applicable State Agency seeks following its receipt ofthe permit

application. CITGO shall file any applications necessary to incorporate the requirements ofthose

permitsinto the Title V pemlits ofthe Covered Refineries.

108
133. Mechanism for Title V Incorporation. The P<lrties agree that the incorporation

ofthe requirements ofthis Consent Decree into Title V permits shall be in accordance with state

Title V rules, including applicable administrative amendment provisions ofsuch rules.

134. Obtaining Construction Permits. CITGO agrees to use its best efforts to obtain

all required, federally enforceable permits for the construction ofthe pollution control technology

and/or the installation of equipment necessary to implement the affirmative reliefand

. environmental projects set forth in this Section V and in Section Vill. To the extent that CITGO

must submit permit applications for construction or installation to the Applicable State Agencies,

CITGO shall cooperate with the Applicable State Agency by promptly submitting to the

. Applicable State Agency all available. information that the Applicable State Agency seeks

following its. receipt ofthe permit application. This Paragraph 134 is not intended to prevent .

CITGO from applying to the Applicable State. Agency for a pollution control project exemption.

VI. EMISSION CREDIT GENERATION

135. Summary. This Section addresses the use of emissions reductions that will result

from the installation and operation ofthe controls required by this Consent Decree ("CD

Emissions Reductions") for the purpose of emissions netting or emissions offsets..It allows

CITGO to use a fraction ofthe. CD Emissions Reductions if: (1) the emissions units for which

CITGO seeks to use the CD Emissions Reductions are modified or constructed for purposes of

compliance with Tier II gasoline or low sulfurdiesel requirements; and (2) the emissions from

those modified or newly-constructed units are at or below the levels outlined in

Paragraph 137(2).

109
136. General Prohibition. CITOO shall not generate or use any NOx, SO" PM,

.VOC, or CO emissions reductions that result from any projects conducted or controls required

pursuant to this Consent Decree as netting reductions or emissions offsets in any PSD, major

non-attainment and/or syothetic minor New Source Review ("NSR") permit or pennit

proceeding.

137. Exception to General Prohibition. Notwithstanding the general prohibition set

forth in Paragraph 136, CITGO may use 300 tons per year ofNOX, 300 tons per year ofS02 and

20 tons per year 6fPM from the CD Emissions Reductions. as credits or offsets in any PSD,

major non-attainment and/or syothetic minor NSR permit or pe~it proceeding occurring after

the Date ofLodging ofthe Consent Decree, provided that the new or modified emissions unit: (I)

is. being constructed or modified for purposes ofcompliance with Tier 2 gasoline or low sulfur

diesel requirements; and (2) has. a federally enforceable, non-Title V Pennit with tht: following

limits, as applicable:

1. For heaters and boilers, a limit of 0.020 lbs NOx per million BTU or less on a

3-hour rolling average basis;

11. For heaters and boilers, a limit of 0.1 0 grains ofhydrogen sulfide per dry

standard cubic. foot offuel gas or 20 ppmvd S02 corrected to 0% O2both on a

3-hour rolling average;

111. For heaters and boilers, no Fuel Oil blUIiing or solid fuel firing capability;

iv. For FCCUs, a limit of 20 ppmvd NOx corrected to 0% O2or less. on a 365-day

roIling average basis;

v. For FCCDs, a limit of25 ppmvd S02 corrected to 0% O2or less on a 365-day

roIling average basis; and

VI. For SRPs, NSPS Subpart J emission limits.

110
Utilization ofthe exception set forth above is subject to each ofthe following conditions:

I. Under no circumstances shall CITGO use CD Emissions Reductions

for netting and/or offsets prior to the time that actual CD Emissions

Reductions have occurred;

ii. CD Emissions Reductions may be used only at the Covered Refinery

that generated them;

Ill. The CD Emissions Reductions provisions ofthis Consent Decree are

for purposes. ofthis Consent Decree only and neither CITGO, nor any

other entity may use CD Emissions Reductions for any purpose,

including in any subsequent pennitting or enforcement PFoceeding,

except as provided herein; and

iv. CITGO still shall be subject to all federal and state regulations

applicable to the PSD, major non-attainment and/or minor NSR

pennitting process.

137A. Notwithstanding the general prohibition set forth in Paragraph 136 and for

purposes ofNOx "offsets" under LAC 33:III.510.C.l.b.vii only, the parties agree that 50% ofthe

NOx emissions reduction made. at the Lake Charles Refinery to demonstrate compliance with

Paragraphs 54, 57 and 57A [heater and boiler NOx reductions] are not "otherwise required by the

Act or by state regulations," provided that such new major stationary source ormajor

modification, as defined in LAC 33:III.509.B. is either located at the Lake Charles Refinery or is

a cogeneration project in which CITGO is a participant; has or will have a federally enforceable,

non-Title V pennit; and that such pennit contains limits which are either no less stringent than .

those specified in Paragraph 137(2), or determined by LDEQ (after an opportunity for

consultation with EPA) under LAC 33:III.510 or other, similar authority (e.g., LAC 33:11I.509).

138. Outside the Scope ofthe General Prohibition. Nothing in this Section VI is

intended to prohibit CITGO from seeking to: (1) utilize or generate emissions credits or

111
reductions from Covered Refinery units to the extent that the proposed credits or reductions

represent the difference between the emissions limitations set forth in this Consent Decree for

these refinery units and the more stringent emissions limitations that CITGO may elect to accept

. for these refinery units in a permitting process; or (2) utilize or generate emissions credits or

reductions on refmery units that are not subject to an emission limitation pursuant to this Consent

Decree.

VII. MODIFICATIONS TO IMPLEMENTATION SCHEDULES

139. Securing Permits or Approvals.

a. For any work under Sections V or VIII ofthis Consent Decree that requires a federal,

state and/or local permit or EPA approval (e.g., EPA approval of catalyst additives in Section V),

CITGO shall be responsible for submitting in 11 timely fashion applications for federal, state and

local permits and request for EPA approval for work and activities required so that permit or

approval decisions can be made in a timely fashion. CITGO shall use its best efforts to secure

EPA approvals and/or to: (i) submit permit applications (i.e., applications for permits to

construct, operate, or their equivalent) that comply with all applicable requirements; and

(ii) secure approval ofpermits after filing the applications, including timely supplying additional

information, ifrequested. Ifit appears that the failure ofEPA or any other govenunental entity to

act upon a timely-submitted permit application or request for EPA approval may delay CITGO's

performance of work according to an applicable implementation schedule, CITGO shall notifY

the EPA and the Applicable Federal and State Agencies of any such delays as soon as practicable

after CITGO reasonably concludes that the delay could affect its ability to complywith the

iinplementation schedule set forth in this Consent Decree.

112
b. CITGO shall propose for approval by EPA a modification to the applicable schedule

ofimplementation setting out the time necessary to comply after the permit or approval has been'

received by CITGO. EPA, after an opportunity for consultation with the appropriate CoPlaintiff, shall not unreasonably withhold its consent to requests for modifications ofschedules

ofimplementation ifthe requirements ofthis. Paragraph are met. All modifications to any dates

initially set forth in this Decree or in any approved schedule ofimplementation shall be signed in

· writing by EPA and CITGO, and neither the United States nor ClTGO shall be required to file

such modifications with the Court in order for the modifications to be effective. The procedures

of this Paragraph may be used more than once, ifnecessary. Stipulated penalties shall not accrue

nor be due and owing during any period between an originally-scheduled implementation date

· and an approved modification to such date. The failure ofEPA or an other govenunental entity

to act upon a timely-submitted permit or approval application shall not constitute a force majeure

event triggering the requirements of Section XIV; this Paragraph shall apply.

140. Commercial Unavailability ofControlEquipment and/or Additives.

a.ClTGO shall be solely responsible for compliance with any deadline or the

· performance of any work described in Sections V and vm ofthis Consent Decree that requires

·.the acquisition and instal1ation ofcontrol equipment and/or catalyst additive.. Ifit appears that

the commercial unavailability of any control equipment and/or catalyst additive may delay

CITGO's performance ofwork according to an applicable implementation schedule,ClTGO

shaH notify the Applicable Federal and State Agencies of any such delays as soon as practicable

after CITGO reasonably concludes that the delay could affect its ability to comply with the

implementation schedule set forth in this Consent Decree. CITGOshall then contact a

113
reasonable munber o(vendors ofsuch equipment or additive and obtain (or request) a written

representation (or equivalent communication to EPA) from the vendor thattlie equipment or

additive is commercially unavailable.

b. CITGO shall propose for approval by EPA a modification to the applicable schedule

ofimplementation, refer to. this Paragraph 140 ofthis Consent Decree, identifY the milestone date

it contends it will not be able to meet, provide the Applicable Federal and State Agencies with

written correspondence to the vendor identifYing efforts made to. secure the control equipment or

.catalyst additive; and describe the specific efforts CITGO has taken and will continue to take to

find such equipment or additive. CITOO may propose a modified schedule or modification of

otlier.requirements ofthis Consent Decree to .address such conimercial unavailability.

c.. Section XV ("Retention ofJurisdictionlDispute Resolution") shall govern the

resolution of any claim of commercial unavailability. EPA, after an opportunity for consultation

with the appropriate Co·Plaintiff, shall not unreasonably withhold its consent to requests for

modifications ofschedules ofimplementation ifthe requirements ofthis Paragraph are met. All

modifications to any dates initially set forth in this Consent Decree or in any approved schedule

ofimplementation shall be signed in writing by EPA and ClTOO, and neither the United States.

nor ClTOO shall be required to file such modifications with the Court in order for the

modifications to be effective. The procedures ofthis Paragraph may be used more than once, if

necessary. Stipulated penalties shall notaccrue nor be due and owing during any period between

an originally-scheduled implementation date and an approved modification to such date. The

failure by CITOO to secure control equipment and/or catalyst additive shall not constitute a force

majeure event triggering the tequirementsofSection XIV; this Paragraph shall apply.

114
VIII. ENVIRONMENTALLY BENEFICIAL PROJECTS

141. In accordance with the requirements and schedule set forth in this Section VlII,

crrGO shall spend no less than $5,000,000 to implement the Supplemental Environmental

Project ("SEP") described in Paragraph 142 below. CrrGO may carry out its responsibilities for

the SEP identified below directly or through contractors selected by CITGO.

142. The Compressor Replacement/Emissions Reduction SEP: CrrGO shall no. later

than December 31, 2007, replace three. (3) existing natural gas-fired, wet gas compressors at the

Corpus Christi 1 FCCU with a single electric driven compressor, thereby eliminating emissions

from the existing compressors ofNOx, CO and other. products generated by the combustion of

natural gas.

143A. crrGO is responsible for the satisfactory completion ofthe SEP(s) required

under this Consent Decree in accordance with this Section VlII. Upon completion of a specific

SEP, crrGO shall submit to EPA and the appropriate Co-Plaintiff a cost report certified as

accurate under penalty ofperjury by a responsible corporate official. IfCrrGO doesnotexpend

the entire projected $ 5,000,000 cost ofthe SEP described in Paragraph 142, CrrGO shall pay a

stipulated penalty equal to the difference between the amount expended as demonstrated in the

certified cost report(s) and the projected cost. The stipulated penalty shall be paid as provided in

Paragraph 225 (payment of Stipulated Penalties) ofthe Consent Decree. As an alternative to

payment ofthe above penalty, CrrGO may request approval from EPA and the appropriate CoPlaintiffto use unexpended SEP monies for other SEPs, after an opportunity for consultation

with the appropriate Co-Plaintiff.

115
l43B. By signing this Consent Decree, CITGO certifies that it is not required, and has

no liability under any federal, state or local law or regulation or pursuant to any agreements or

orders of any court, to perform or develop the SEP described in Paragraph 142. CITGO further

certifies that it has not applied for or received, and will not in the future apply for or receive:. (1) .

credit as a Supplemental Environmental Project or other penalty offset in any other enforcement

action for the SEP described in Paragraph 142; (2) credit for any emissions reductions resulting

from the SEP described in Paragraph 142 in any federal, state or local emissions trading or early

reduction program; or (3) a deduction from any federal, state, or local tax based on its

participation in, performance of, or incurrence. of costs related to SEP described in Paragraph

142.

l43C: CITGO shall include in each Report required byParagraph l43A, a progress

report for each SEP being performed under this Section VllI ofthis Consent Decree. In addition,

the final Report required by Paragraph 143 submitted after all SEPs identified in this. Section V11I

is completed, shall contain the following information withrespect to each SEP:

a. A detailed description of each project as implemented;

b. A briefdescription of any significant operating problems encountered,

including any that had an impacton the environment, and the solutions for

each problem;

c. Certification that each project has been fully implemented pursuant to the

provisionsofthis Consent Decree; and

116
d. A description ofthe environmental and public health benefits resulting from

implementation of each project (including quantification ofthe benefits and

pollutant reductions, iffeasible).

1430. CITGO agrees that in any public statements regarding these SEPs, CITGO

must clearly indicate that these projects are being undertaken as part ofthe settlement of an

errforcel1,lent action for alleged violations ofthe Clean Air Act and corollary state statutes..

IX. RECORDKEEPING AND REPORTING

144. CITGO shall submit semi-annual reports to the Applicable Federal and State

Agencies that contain the following information;

a. a progress report on the implementation ofthe requirements ofSection V

(Affirmative Relief/Environmental Projects) at each Covered Refinery;

b. . a summary ofthe emissions data, including a separate identification of any

exceedence(s), for each Covered Refinery as. required by Section V ofthis

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

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

requirements ofSection V ofthis Consent Decree at each Covered Refinery;

d. any such additional matters as CITGO believes should be brought to the

attention ofthe Applicable Federal and State Agencies.

e. additional items required by another Paragraph ofthis 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), with the first such report

due on February 28, 2005. Each portion ofthe semi-annual report which relates to a particular

Covered Refinery shallbe certified by either the person responsible for environmental

117
management and compliance for that Covered Refinery, or by a person responsible for

overseeing implementation ofthis Decree across CITGO, as follows:

I certify under penalty oflaw that this information 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 ofthe person(s) who manage the system, or the person(s) directly responsible for

gathering the information, the information submitted is, to the best ofmy knowledge

and belief, true, accurate, and complete.

X. CIVIL PENALTY

145. Within thirty (30) days ofthe Date ofEntry ofthe Consent Decree, CITGO shall

pay a civil penalty of$3,600,000 as. follows: (1) $. 2,300,000 to the United States; (2) $ 100,000

to the State of Georgia; (3) $ 350,000 to the State oflllinois; (4) $ 750,000 to the State of

Louisiana; and (5) $. 100,000 to the State ofNew Jersey.

a Payment ofmonies to the United States shall be made by Electronic Funds Transfer

("EFT") to the United States Department ofJustice, in accordance with current EFT procedures,

referencing USAO File Number 2004V01515, DOJ Case Number 90-5-2-1-07277, and the civil

action case name and case number ofthis action in the Southern District ofTexas. The costs of

such EFT shall be the responsibility of CITGO. Payment shall be made in accordance with

instructions provided to CITGO by the Financial Litigation Unit ofthe U.S. Attorney's Office for

the Southern District ofTexas. Any funds received after 11 :00 a.m. (EST) shall be credited on

the next business day. CITGO shall provide notice ofpayment, referencing USAO File Number

2004V01515, DOJ Case Number 90-5-2-1-07277, and the civil action case name and case

number to the Department ofJustice and to EPA, as provided in Paragraph 270 (Notice).

118
b. Payment ofthe civil penalty owedto the State ofGeorgia under this Paragraph shall

be made by certified or corporate check made payable to the Georgia Department ofNatural

Resources and sent to the following address:

Chief

Air Protection Division

4244 International Parkway

Suite 120

Atlanta, Ga. 30354

c. Payment ofthe civil penalty owed to the State ofIllinois under this Paragraph shall

be made. by certified check made payable to the Illinois Attorney General State Projects and

Court Ordered Distribution Fund to be used at the discretion ofthe Illinois Attorney General's

Office for the advancement of enviromnental protection activities in Illinois and sent to the

following address:

Phyl1is Dunton

Enviromnental Bureau

Illinois Attorney General's Office

188 West Randolph Street, 20tb Floor

Chicago, Illinois 60601

. d.. Payment ofthe civil penalty owed to the State ofLouisiana under this Paragraph

shall be made by certified check made payable to the Louisiana Department ofEnviromnental

Quality and sent to Darryl Serio, Fiscal Director; Office ofManagement and Finance, LDEQ,

P.O. Box 4303, Baton Rouge, LA 708214303.

119
e. Payment ofthe civil penalty owed to the State ofNewJersey under this Paragraph

shaIl be made by certified check made payable to the State ofNew Jerseyand sent to the

foIlowing address:

Administrator, Air Compliance & Enforcement

New Jersey Department ofEnvironmental Protection

P.O. Box 422

Trenton, New Jersey 08625-0422

146. [IntentionaIly Left Blank}

147. The cost ofthe SEPs. and the civil penalty set forth herein together constitute the

sole penalty imposed for the violations alleged hereunder within the meaning ofSection I 62(f) of

the Internal Revenue Code, 26 U.S.C. § 162(f), and, therefore, CITGO shaIl not treat these

penalty payments astax deductiblefor purposes ofnet income taxes imposed under federal, state,

or local law.

148.. Upon the Date ofEntry ofthe Consent Decree, the Consent Decree shall

constitute an enforceablejudgment for purposes ofpost-judgment coIlection in accordance with

Federal Rule ofCivil Procedure 69, the Federal Debt CoIlection Procedure Act, 28 U.S.C. §§

3001-3308, and other applicable federal authority.

XI. STIPULATED PENALTIES

149. CITGO. shaIl pay stipulated penalties to the United States and the appropriate

Co-Plaintiffs for each failure by ClTGO to comply with the terms ofthis. Consent Decree as

provided herein. Stipulated penalties shall be calculated in the amounts specified in Paragraphs

150 through 224. Stipulated penalties for failure to comply with the concentration-based, rolling

average emission limits referenced in Section V shaIl not start to accrue until there is

120·
noncompliance for 5% or more ofthe applicable unit's operating time during any calendar

quarter. For those provisions where a stipulated penalty of either a fixed amount or 1.2 times the

economic benefit ofdelayed compliance is available, the decision ofwhich alternative to seek

shall rest exclusively within the discretion ofthe EPA and the appropriate Co-Plaintiff.

A. Requirements for NOx Emission Reductions from .FCCUs.

150. For failure to meet the Interim NO, Emission limits set forth in Paragraph 13, or

any emissions limit proposed by CITGO or established by EPA (final or interim) for NOx

pursuant to Paragraph 19, 20,21,29,30 or 30A, per day, per unit: $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-OOy roning average

exceeds the applicable limit.

151. For failure to prepare and/or submit written deliverables required by Paragraphs

17, 19,20 if applicable, or 24, per day:

Period ofNon-Compliance

1Sl through 30th day after deadline

31 Sl through 60th day after deadline

Beyond 60th day after deadline

Penalty per day

$200

$500

$1000

152. For failure to timely commence, complete or substantially comply with the

requirements of any minimization studies, demonstration periods, trials or studies required by

Paragraphs 16, 18, and 26-29, per unit, per day:

Period ofNon-Compliance

1Sl through 30th day after deadline

31 Sl through 60'h day after deadline

Beyond 60th day after deadline

121

Penalty per day

$200

$500

$1000
153. For failure to install, certifY, calibrate, maintain, and/or operate all CEMS

required by Paragraph 31, per day, per CEMS:

Period ofNon-Compliance

1" tmough 30th day after deadline

31" through 60'h day after deadline

Beyond 60th day after deadline

Penalty per day

$500

$1,000

$2,000 or an amount equal to 1.2 times the

economic benefit ofdelayed compliance,

whichever is greater.

154. For failure to convert Corpus Christi FCCD 1 or Lemont FCCD to Full Bum

Operation, as required by Paragraph 21, per unit:

Period ofNon-Compliance

1st through 30th day after deadline

31" throllgh 60'h day after deadline

Beyond 60th day after deadline

Penalty per day

$2,500

$6,000

$10,000, or an amount equal to 1.2 times

the economic benefit ofdelayed

compliance, whichever is greater.

155. For failure to install Low NO, Burners at the Lemont Refinery, as required by

Paragraph 22:

Period ofNon-Compliance

1" through 30th day after deadline

31 ,t through 60th day after deadline

Beyond 60th day after deadline

156. [IntentionallyLeft Blank]

Penalty per day.

$2,500

$6,000

$10,000, or an amount equal to 1.2 times

the economic benefit ofdelayed

compliance, whichever is greater.

B. Requirements for SO, Emission Reductions from FCCUs.

157. For each failure to meet S02 emission limits set forth in Paragraph 33, or any

emission limit proposed by CITGO or established by EPA (interim or final) for 302pursuant to

Paragraphs 39, 40 or 40A, per day, per unit: $750 for each calendar day in a calendar quarter on

122
which the specified 7-day rolling average exceeds the applicable limit; $2,500 for each calendar

day in a calendar quarter on which the specified 365-day rolling average exceeds the applicable

limit.

158. For failure to prepare and/or submit written deliverables required by Paragraphs

35-42, per day:

Period ofNon-Compliance

I" through 30'h day after deadline

31" through 60th day after deadline

Beyond 60th day after deadline

Penalty per day

$200

$500

$1000

159. For failure to timely commence, complete or substantially comply with the

. requirements regarding the use ofS02 Reducing Catalyst Additives, including the requirements

regarding demonstration periods, short-term trials, or optimization studies, as set forth in

Paragraphs 37-39, per unit, per day:

Period ofNon-Compliance

1" through 30th day after deadline

31" through 60th day after deadline

Beyond 60th day after deadline

Penalty per day

$750

$1,500

$2,000, or an amount equal to 1.2 times the

economic benefit ofthe delayed

compliance whichever is greater

160. For failure to install, certify, calibrate, maintain, and/or operate a S02 CEMS, as

required by Paragraph 41, per unit, per day:

Period ofNon-Compliance

I" through 30'h day after deadline

31" through 60'h day after deadline

Beyond 60th day after deadline

123

Penalty per day

$500

$1,000.

$2,000 or an amount equal to 1.2 times the

economic benefit ofdelayed compliance,

whichever is greater.
160A. For failure to comply with the plan required by Paragraph 42 for operating

FCCUs in the event ofa hydro1reater outage, per-unit, per-day:

Period ofNon-Compliance

I" through 30th day after deadline

31st through 60th day after deadline

Beyond.60th day after deadline

Penalty per day

$250 .

$1,000

$2,000 or an amount equal to 1.2 times the

economic benefit ofdelayed compliance,

whichever is. greater.

C. Requirements for PM Emissions Reductions from FCCDs.

161. For each failure to meet any PM emission limit, as. required by Paragraphs 44, 46,

or, if applicable, Paragraph 45: $500 for the first day ofnon-compliance in which the specified

short-term rolling average exceeds the applicable limit, and $1,500 for each day thereafter until

CITGO demonstrates compliance. with the applicable limit.

162. For failure to submit written de1iverables, or to. conduct required stack tests, as

required by Paragraph 47:

Period ofNon-Compliance

1" through 3Othday after deadline

31" through 60th day after deadline

Beyond 60th day after deadline

163. [Intentionally Left Blank]

Penalty per day

$200

$500

$1000

D. Requirements for CO Emissions Reductions from FCCDs.

164. For each failure to meet the CO emission limits, as required in Paragraphs 48 and

49: $750 for each calendar day in a calendar quarter on which the specified I-hour 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.

124
165. For failUre to install, certify, calibrate, maintain, and/or operate a CO CEMS, as

required by Paragraph 50, per unit, per day:

Period ofNon-Compliance

I't through 30th day after deadline

31" through 60th day after deadline

Beyond 60th day after deadline

Penalty per day

$500

$1,000

$2,000, or, an amount equal to 1.2 times

the economic benefit of d¢layed

compliance, whichever is greater.

E. Requirements Related to NSPS Applicability to FCCD Re2enerators.

166. For failure to comply with NSPS Subparts A and J limits for S02 or COat each

ofClTGO's FCCD regenerators at the Corpus Christi, Lake Charles, and Lemont Refineries, as

required by Paragraph 51, per urnt, per day in a calendar quarter:

Period ofNon-Compliance

I" through 30th day

31" through 60th day

Over 60 days

Penalty per day·

$1,000

$2,000

$3,000 or an amount equal to 1.2 times the

of delayed compliance, whichever is

greater.

F. Requirements for NOx Emission Reductions from Heaters and Boilers~

167. For failure. to install selected Qualifying Controls on heaters and boilers or to

reduce NOx emissions as required by Paragraphs 53, 54, 57, 57A or 58,per day:

Period ofNon-Compliance .

I" through 30th day after deadline

31" through 60" day after deadline

Beyond 60th day after deadline

125

Penalty per day

$2,500

$6,000

$10,000, or an amount equal to 1.2 times

the economic benefit of delayed

compliance, whichever is greater.
168. For failure to comply with the applicable monitoring requirements. as set forth in

Paragraphs 59, pet unit, per day:

Period ofNon-Compliance

1" through 30th day after deadline

31" through 60th day after deadline

Beyond 60'h day after deadline

Penalty per day

$500

$1,000

$2,000, or an amount equal to 1.2 times. the

econonllc benefit ofdelayed compliance, .

whichever is greater.

169. For failure to install, certify, calibrate, maintain, and/or operate a NOx CEMS, as

reql,lired by Paragraph 60, per unit, per?ay:

Period ofNon-Compliance

1st through 30th day after deadline

31st through 601h day after deadline

Beyond 60th day after deadline

Penalty per day

$450

$1,000

$2,000, or an amount equal to 1.2 times the

economic benefit of delayed compliance,

whichever is greater.

per day:

170. Forfailure to submit the written deliverables required by Paragraphs 55A or 56,

Period ofNon-Compliance

I" through 30th day after deadline

31 st through 60th day after deadline

Beyond 60th day

Penalty per day

$200

$500

$1,000 .

G. Requirements for SO, Emission Reductions from Heaters and Boilers.

171. For burning in any heater or boiler or in any other identified equipment listed in

Appendix E any refinery fuel gas in violation ofthe applicable requirements ofNSPS Subparts A

and J after the date ofEntry ofthe Consent Decree or, ifthe heater or boiler is listed in Appendix

E, after the date set forth in Appendix E on which the respective unit becomes an "affected

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facility" subjectto NSPS Subparts A & J, as set forth in Section V.G., per unit, per day in a

calendar quarter: '

Period ofNon-Compliance

Ist through 30th day

Beyond 31 st day

Penalty per day

$2,500

$5,000 or an amount equal to 1.2 times the

economic benefit of delayed compliance,

whichever is greater.

171a. ForburningFuel Oil in a manner inconsistent with the requirements of

Paragraph 65, per day:

Period ofNon-Compliance

1st through 30th day

Beyond 31st day

Penalty per day

$1,750

$5,000

H. Requirements for Sulfur Recovery Plants.

172. For failure to route all sulfur pit emissions in accordance with the requirements•

ofParagraph 71, per day:

Period ofNon-Compliance

1st through 30th day

31 st through 60fu day

Beyond 601h day

Penalty per day

$1,000

$1,750

$4,000 or an amount equal to 1.2 times the amount

ofdelayed compliance whichever is. greater.

173. For failure to comply with the NSPS Subparts A and J emission limits at the

Lemont, Lake Charles, and Corpus. Christi East and West Refineries, as specified in Paragraphs

67, 68 and 69, per day:

Period ofNon-Compliance

1st through 30th day

31st through 601h day

Over 60 days

Penalty per day

$1,000

$2,000

$3,000 or an amount equal to 1.2 times the of

delayed compliance, whichever is greater.

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174. For failure to comply with the NSPS Subparts A and H emission limits at the

Lake Charles Sulfuric Acid Plant, as specified in Paragraph 72, per day:

Period ofNon-Compliance

1st through 30th day

31" through 601h day

Qver 60 days

Penalty per day

$1,000

$2,000

$3,000 or an amount equal to 1.2 times the of

delayed compliance, whichever is greater.

175. For failure to comply with the monitoring requirements set forth in Paragraph 68b,

per unit, per day:

Period ofNon-Compliance

1st through 301h day after deadline

Beyond 31" day after deadline

Beyond 60'h day after deadline

Penalty per day

$500

$1,500

$2,000

176, Forfailure to develop Preventive Maintenance and Operation Plans as specified in

Paragraph 73,. per unit, per day:

Period ofDelay or Non-Compliance

1st through 30th day after deadline

Beyond 31,t day after deadline

Beyond 60th day after deadline

Penalty per day

$500

$1,500

$2,000

177. For fuilure to timely commence and complete the optimization study or to

substantially comply with any ofthe other requirements other than installation of TGU at the

Lemont Claus Trains 119 A and B, required by Paragraphs 69 and 70, per day, per requirement:

Period ofNon-Compliance

1,t through 30th day after deadline

Beyond 31 st day after deadline

Beyond 60th day after deadline

128

Penalty per day

$500

$1,500

$2,000
178. For failure to install TGUs at the Lemont Claus trains 119 A and B in compliance

with Paragraph 69:

Period ofNon-Compliance

1" through 30th day after deadline

31sl through 60th day after deadline

Beyond 60th day after deadline

I. Requirements for Flarine; Devices.

Penalty per day

$2,500

$6,000

$10,000, or an amount equal to 1.2 times

the economic benefit of delayed

compliance, whichever is greater.

179. For failure to comply with NSPS Subparts A and J, including emission limits, for

the Flaring Devices identified in Appendix B-1 and B-2 after the compliance dates specified in

Appendix G, per device:

Period ofNon-Compliance

Ist through 301h day after deadline

Beyond 31st day after deadline

Beyond 60th day after deadline

Penalty per day

$500

$1,500

$2,000

Provided, however, that ifstipulated penalties could be assessed under both Paragraphs 179 and

181, the provisions ofParagraph 181 shall control.

180. [Intentionally Left Blank]

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J. Requirements for Control ofAcid Gas Flaring and Tail Gas Incidents.

181.. For AG Flaring Incidents andiorTail Gas Incidents for which CITGO is liable

under Section VJ.:

Tons Emitted in Length ofTime from Length ofTime from Length ofTime

Flaring Incident or Commencement of Commencement of ofFlaring within

Tail Gas Incident Flaring within the Flaring within the Flaring the Flaring

Flaring Incident to Incident to Tennination of Incident is

Tennination ofFlaring Flaring within the Flaring greater than 24

within the Flaring Incident is greater than 3 hours; Length of

Incident is. 3 hours. or hours but less than or Time. ofthe Tail

less; Length ofTime of equal to 24 hours; Length Gas. Incident is

the Tail Gas Incident is ofTime ofthe Tail Gas greater than 24

3 hours or less Incident is greater than 3 hours

hours but less than or

equal to 24 hours

·5 Tons or less $500. per Ton $750 per Ton $1,000 per Ton

Greater than 5 $1,200 per Ton $1,800 per Ton $2,300 per Ton,

Tons, but less. than up to, but not

or equal to 15 exceeding,

Tons $27,500 in any

one calendar day

Greater than 15 $1,800 per Ton, up to, $2,300 per Ton, up to, but $27,500 per

Tons but not exceeding, not exceeding, $27,500 in calendar day for

$27,500 in anyone . anyone calendar day each calendar

calendar day day over which

the Flaring

Incident lasts

For purposes of calculating stipulated penalties pursuant to this Paragraph, only one cell

within the matrix shall apply. Thus, for example, for a Flaring Incident in which the Flaring

starts at 1:00 p;m. and ends at 3:00 p.m., and for which 14.5 tons ofsulfur dioxide are emitted,

the penalty would be $17,400 (14.5 x $1,200); the penalty would not be $13,900 [(5 x $500) +

(9.5 x $1200)]. For purposes ofdetermining which column in the table set forth in this

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Paragraph applies under circumstances in which Flaring occurs intermittently during a Flaring

Incident, the Flaring shall be deemed to commence at the time that the Flaring that triggers the

initiation ofa Flaring Incident commences, and shall be deemed to terminate at the time ofthe

termination ofthe last episode ofFlaring within the Flaring Incident. Thus, for example, for

Flaring within a Flaring Incident that (i) starts at I :00 p.m. on Day I and ends at I:30 p.m. on

Day I; (ii) recommences at 4:00 p.m. on Day I and ends at 4:30 p.m. on Day I;

(iii) recoriunences at 1:00 a.m. on Day 2 and ends at 1:30 a.m. on Day 2; and (iv) for which no

further Flaring occurs within the. Flaring Incident, the Flaring within the Flaring Incident shall be

deemed to last 12.5 hours -- not 1.5 hours -- and the column for Flaring of "greater than 3. hours

but less than or equal tQ 24 hours". shall apply.

182. For failure to timely submit any report required by Section V.I., or for submitting

any report that does not substantially conform to its requirements:

Period ofNon-Compliance

Days 1-30

Days 31-60

Over 60 days

Penalty per diw

$750

$1,500

$3,000

183. For those corrective action(s) which CITGO: (i) agrees to undertake following

receipt ofan objection byEPA pursuant to Paragraph 80; or (ii) is required to undertake

following dispute resolution, then, from the date ofEPA'sreceipt ofCITGO's report under

Paragraph 79 ofthis Consent Decree until the date that either: (i) a fmal agreement is reached

131
between EPA and CITOO regarding the corrective action; or (ii) a court order regarding the

corrective action is entered, CITOO shall be liable for stipulated penalties as follows:

a. Period ofNon-Compliance

Days 1-120

Days 121-180

Days 181 - 365

Over 365 Days

Penalty per day

$50

$100

$300

$3,000

or

b. 1.2 times the economic benefit resulting from CITOO's failure to implement

the corrective action(s).

184. For failure to complete anycorrective action under Paragraph 80 ofthis Decree

in accordance with the schedule for such corrective action agreed to by CITOO or imposed on

CITGO pursuant to the dispute resolution provisions oftbis Decree (with any such extensions

thereto as to which EPA and CITGO may agree in writing):

Period ofNon-Compliance

Days 1-30

Days 31-60

Over 60

Penalty per day

$1,000

$2,000

$5,000

K. Requirements for Control of Hydrocarbon Flaring Incidents.

185. For each failure to perform a Root Cause analysis or submit a written report or

perform corrective actions for a Hydrocarbon Flaring Incident, as required by Paragraph 94:

Period ofDelay or Non-Compliance

Ist through 30th day

31 st through 60th day

Beyond 60th day,

Penalty per day per Incident

$500

$1,500

$3,000

L. Requirements for Benzene Waste NESHAP Program Enhancements. For each

violation in which a frequency is specified in Section V.L., the amounts identified below shall

apply on the first day of violation, shall be calculated for each incremental period ofviolation (or

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portion thereof); and shaH be doubled beginning on the fourth consecutive, continuing period of

violation. For requirements where no frequency is specified, penalties will not be doubled.

186. For failure to complete the BON Compliance Review and Verification Reports as

required by Paragraph 98:

$7,500 per month, per refinery.

187. For failure to submit a plan that provides for actions necessary to correct noncompliance as required by Paragraph 100(b) or (c), or for failure toimplement the actions

necessary to correct non-compliance and to certify compliance as required by Paragraph l00(d)

and 1OO(e), per refinery:

Period ofNon-Compliance

Ist through 301h day after deadline

31,t through 60th day after deadline

Beyond 60th day

188. [Intentionally Left Blank1

189. [Intentionally Left Blank]

Penalty per day

$1,250

$3,000

$5,000, or an arnount equal to 1.2 times the

economic benefit ofdelayed compliance,

whichever is greater.

190. For failure to comply with the requirements set forth in Paragraph 101 related to

the use, monitoring, and replacement ofcarbon canisters: $1,000 per incident ofnon-compliance,

per day.

191. For failure to implement the training requirements ofParagraph 105: $10,000 per

quarter.

192. For failure to establish an annual review program to identify new benzene waste

streams as required by Paragraph 102: $2,500 per month, per refinery.

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193. For failure to perform laboratory audits as required by Paragraph 103: $5,000 per

month, per audit.

194. For failure to submit or maintain any plans or other deliverables required by

Paragraph 106 (Waste/Slop/OffSpec Oil Management): $2,000 per deliverable.

195. [Intentionally Left Blank]

196. For failure to conduct sampling in accordance with the sampling plans required

by Paragraph 107 and 108: $30,000 per quarter, per stream, whichever is greater, but not to

exceed $150,000 per quarter, per refinery.

197. For failure to submit the plans or retain the third-party contractor required by

Paragraph 110: $10,000 per month.

198. For failure to conduct monthly visual inspections of all Subpart FF water traps as

required by Paragraph 111(a): $500 per drain not inspected;

199. For failure to identify/mark segregated stormwater drains as required in Paragraph

111(b): $1,000 per week per drain;

200. For failure to monitor Subpart FF conservation vents as required by Paragraph

111(c): $500 per vent not monitored;

201. For failure to conduct monitoring ofoil-water separators as required by Paragraph

111(d): $1,000 per month, per unit.

202. For failure to submit any ofthe written deliverables required by Section V.L.

(except for those deliverables for which stipulated penalties are specified in Paragraphs 186, 187,

194 or 197) - $1,000 per week, per deliverable.

134
203. Ifit is detennined through a federal, state, or local investigation that any Covered

Refmery has failed to include all benzene-containing waste streams in its TAB calculation

submitted pursuant to Paragraph 98, crrao shall pay the following, per waste stream:

Waste Stream

for waste streams < 0.03 Mglyr

for waste streams. between 0.03 and 0.1 Mglyr

for waste streams between 0.1 and 0.5 Mglyr

for waste streams> 0.5 Mglyr

Penalty

$250

$1,000

$5,000

$10,000

M. Requirements for Leak Detection and Repair Program Enhancements. For

each violation in which a frequency is specified in Section V.M., the amoWlts identified below

shall apply on the first day ofviolation, shall be calculated for each incremental period of

violation (or portion thereof), and shall be doubled beginning on the fourth consecutive,

continuing period ofviolation.. For requirements where no frequency is specified, penalties will

not be. doubled.

204. [Intentionally Left Blank]

205. For failure to develop an LDAR Program as required by Paragraph 115: $3,500

per week, per refinery.

206. For failure to implement the training programs specified inParagraph 116:

$10,000 per month, per program, per refinery.

207. For failure. to conduct any ofthe audits described in Paragraph 117: $5,000 per

month, per audit, per refinery.

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208. For failure to implement any actions necessary to correct non-compliance as

required in Paragraph 118:

Period ofNon-Compliance

1" through 30th day after deadline

31st through 60th day after deadline

Beyond 60th day

Penalty per day

$1,250

$3,000

$5,000, or an amount equal to 1.2 times the

economic benefit ofdelayed compliance,

whichever is. greater

209. For failure to perform monitoring utilizing the lower intemalleak rate. definitions

as specified in Paragraph 119: $100 per component, but not greater than $10,000 per month, per

process unit.

210. For failure to.make first repair attempts within 5 days and/or take other actions

required by Paragraph 120: $100 per component but not greater than $10,000 per month, per

refinery (except that Paragraph 211 shall apply in lieu ofthis Paragraph 210 where both

paragraphs are potentially applicable).

211. For failure to implement the "initial attempt" repair program set forth in Paragraph

122: $100 per component, but notto exceed $10,000 per month,.per process unit.

212.. For failure to implement the QAlQC procedures described in Paragraph 124:

$1,000 per incident, but not greater than $10,000 per month per process unit.

213. For failure to implement the LDAR monitoring program as required by

Paragraph 121 :$1 00 per component, but not greater than $10,000 per month, per process unit.

214. For failure to designate an individual as accountable for LDAR performance as

required by Paragraph 115g, or for failure to implement the maintenance tracking program

required by Paragraph 115d: $3,500 per week per refinery.

136
215. For failure to use dataloggers or maintain electronic data as required by

Paragraph 123: $5,000 per month.

216. For failure to conduct and record the calibrations and the calibration drift

assessments or remonitor valves and pumps based on calibration drift assessments in Paragraph

127: $100 per missed event.

217. For failure to comply with the requirements for delay ofrepair set forth at

Paragraph 128: $5,000 per valve or pump, per incident ofnon-compliance.

218. For failure to submit the written deliverables required by Section V.M.: $500per

week per deliverable.

219. For each valve or pump that CITGO failed to include in its LDARprogram within

ninety (90) days ofthe date ofcompletion ofthe initial audit under Paragraph 117, CITGO shall

pay $175. Ifit is determined through a federal, state, or local investigation that CITGO has failed

to include all valves or pumps in its LDAR program, CITGO shall pay $225 per component that

it failed to include.

220. For failure to comply with the requirements for chronic leakers set forth at

Paragraph 129: $5,000 per valve.

N. Requirements to Incorporate Consent Decree Requirements into

Federally-Enforceable Permits.

221. For each failure to submit an application as required by Paragraphs 131 and 132:

Period ofNon-Compliance

Days 1-30

Days 31-60

Over 60 Days

137

Penalty per day

$800

$1,500

$3,000
O. Requirements for Reporting and Recordkeeping.

222. For failure to submit reports as required by Section IX, per report, per day:

Period ofNon-Compliance

Ist through 30th day after deadline

3Ist through 60th day after deadline

Beyond 60th day

Penalty per day

$300

$1,000

$2,000

P. Requirements for Environmentally Beneficial Projects and Civil Penalties.

223. For failure to timely complete implementation ofthe SEPs required under Section

VID, per project, per day:

Period ofDelay or Non-Compliance

1st through 30th day after deadline

31" through 60tl• day after deadline

Beyond 60th day

Q. Requirement to Pay StipUlated Penalties.

Penalty per day

$1,000

$1,500

$2,000

224. For failure to. pay stipulated penalties as required by Paragraph 225 ofthis

Consent Decree, CITGO shall be liable for $2,500 per day, and interest on the amount overdue at

the rate specified in 28 U.S.C. § 1961(a).

R. Pavment of Stipulated Penalties.

225. GITGO shall pay stipulated penalties upon written demand by the United States or

the appropriate Co-Plaintiffs, no later than sixty (60) days after CITGO receives such demand.

Demand from either the United States or the appropriate Co-Plaintiffs shall be deemed a demand

.from both, but the United States and the appropriate Co-Plaintiffs shall consult with each other

prior to making a demand. Stipulated penalties owed by CITGO shall be paid 50 percent to the

United States and 50 percent to the appropriate Co-Plaintiffs. Stipulated penalties shall be paid

to the United States and the appropriate Co-Plaintiffs in the maImer set forth in Section X (Civil

138
Penalty) ofthis Consent Decree. A demand for the payment ofstipulated penalties will identify

the particular violation(s) to which the stipulated penalty relates, the. stipulated penalty amount

the United States or the appropriate Co-Plaintiffis demanding for each violation (as can be best

estimated), the calculation method underlying the demand, and the grounds upon which the

demand is based. After consultation with each other, the United States and the appropriate CoPlaintiffmay, in their umeviewable discretion, waive payment of any portion ofstipulated

penalties that may accrue under this Consent Decree. Payment ofstipulated penalties shall

relieve ClTGO from liability to EPA and appropriate Co-Plaintifffrom civil penalties under its

permits for the same violation.

S, Stipulated Penalties Dispute.

226. Should ClTGO dispute the United States' and/or the appropriate Co-Plaintiffs'

demand for all or part of a stipulated penalty, it may avoid the imposition of a stipulated penalty for

failure to pay a stipulated penalty under Paragraph 224 by placing the disputed amount demanded in

a commercial escro;.v account pending resolution ofthe matter and by invoking the dispute resolution

provisions of Section XV within the time. provided in Paragraph 225 for payment ofstipulated

penalties. Ifthe dispute is thereafter resolved in ClTGO's favor, the escrowed amount plus accrued

interest shall be returned to CITGO; otherwise, the United States and the appropriate Co-Plaintiff

shall be entitled to the amount that was determined to be due by the Court, plus the interest that has

accrued in the. escrow account on such amount. The United States and the appropriate Co-Plaintiffs

139
reserve the right to pursue any other non-monetary remedies to which they are legally entitled,

including but not limited to, injunctive relieffor CITGO's violations ofthis Consent Decree.

XII. INTEREST

227. After the date on which a payment is due under this. Consent Decree, CrrGO shall

be liable for interest on the unpaid balance ofthe civil penalty specified in Section X, and for

interest on any unpaid balance ofstipulated penalties to be paid in accordance with Section XI.

All such interest shall accrue at the rate established pursuant to 28. U.S.C. § 1961(a) --i.e., a rate

equal to the. coupon issue yield equivalent (as determinedby the Secretary ofTreasury) ofthe

average accepted auction price for the last auction of52-week U.S. Treasury bills settled prior to

the Date ofLodging ofthe Consent Decree. Interest shall be computed daily and compounded

annually. Interest shall be calculated from the date payment is due under the Consent Decree

through the date of actual payment. For purposes ofthis Paragraph 227, interest pursuant to this

Paragraph will cease to accrue onthe amount ofany stipulated penalty payment made into an

interest bearing escrow account as contemplated by Paragraph 226 ofthe Consent Decree.

Monies timely paid into escrow shall notbe considered to be an unpaid balance underthis

Section.

XIII. RIGHT OF ENTRY

228. Any authorized representative of an Applicable Fedenil or State Agency,

including independent contractors, upon presentation of credentials, shall have a right of entry

upon the premises ofthe facilities ofthe Covered Refineries, at any reasonable time for the

purpose ofmonitoring compliance with the provisions ofthis Consent Decree, including

inspecting plant equipment, and inspecting and copying all records maintained by CITGO

140
pursuant to the requirements ofthis Consent Decree or in the ordinary course ofCITGO's

business that are deemed necessary by EPA or the applicable Co-Plaintiffto verifY compliance

with this Consent Decree. CITGO shall retain records required under this Consent Decree for the

period ofthe Consent Decree. Nothing in this Consent Decree shall limit the authority of an

Applicable Federal or State. Agency to conduct tests, inspections, or other activities under any

statutory or regulatory provision.

XIV. FORCE MAJEURE

229. Ifany event occurs which causes or may cause a delay or impediment to

performance in complying with any provision ofthis Consent Decree, CITGO shall nOtifY the

Applicable Federal and State Agencies in writing as soon as practicable, but in any event within

ten (10) business days ofthe date when CITGO first knew ofthe event or should have known of

the event by the exercise. ofdue diligence. In this notice, CITGO shall specifically reference this

Paragraph 229 ofthis Consent Decree and describe the anticipated length oftime. the delay may

persist, the cause or causes ofthe delay, and the measures taken or to be taken by CITGO to

prevent or minimize the delay and the schedule by which those measures shall be implemented.

CITGO shall take all reasonable steps to avoid or minimize such delays. The notice required by

this Section shall be effective upon the mailing ofthe same by certified mail, return receipt

requested, to the Applicable EPA Regional Office as specified in Paragraph 270 (Notice).

230. Failure by CITGO to substantially comply with the notice requirements of

Paragraph 229 as specified above shall render this Section XN (Force Majeure) voidable by the

United States, in consultation with the Applicable State Agency, as to the specific event for

141
which CITGO has failed to comply with such notice requirement, and, ifvoided, is ofno effect

as to the particular event involved.

231. The United States, after consultation with the Applicable State Agency, shall

notifY CITGO in writing regarding its claim ofa delay or impediment to performance within

thirty (30) days ofreceipt ofthe force majeure notice providedunder Paragrapb 229.

232. Ifthe United States, after consultation with the Applicable State Agency, agrees

that the delay or impediment to performance has been or will be caused by circumstances beyond

the control ofCITGO, inclUding any entity controlled by CITGO, and that CITGO co.u1d not have

prevented the delay by the exercise ofdue diligence, the Parties shall stipulate to an extension of

tbe required deadline(s) for. all requirement(s) affected by the delay by a period equivalent to the

delay actually caused by such circumstances or such other period as may be appropriate under the

circumstances. Such stipulation shall be filed as a modification·to the Consent Decree pursuant

to the modification procedures established in this Consent Decree.. CITGO shall not be liable for

stipulated penalties for the period of any such delay.

233. Ifthe United States, after consultation with the Applicable State Agency, does. not

accept CITGO's claim of a delay or impediment to performance, CITGO must submit the matter

to the Court for resolutionto avoid payment ofstipulated penalties, by. filing a petition for

determination with the Court. In the event the United States and the appropriate Co-Plaintiff do

not agree, the position ofthe United States on the force majeure claim shall become the final

Plaintiffs' position. Once CITGO has submitted this matter to the Court, the United States and

the Applicable State Agency shall have twenty (20) business days to file their responses to the

petition. Ifthe Court determines that the delay or impediment to performance has been or will be

142
caused by circumstances beyond the control ofClTGO, including any entity controlled by

CITGO, and that the delay could not have been prevented by ClTGO by the exercise. ofdue

diligence, CITGO shall be excused as to that event(s) and delay (including stipulated penalties),

for allrequirements affected by the delay for a period oftime equivalent to the delay caused by

such circumstances or such other period as may be determined by the Court.

234. CITGO shall bear the burden ofproving that any delay of any requirement(s) of

this Consent Decree was caused by or will be cansed by circumstances beyond its control,

including any entity controlled by it, and that it could not have prevented the delay by the

exercise of due diligence. ClTGO shall also. bear the burden ofproving the duration and extent

of any delay(s) attributable to such circumstances. An extension ofone compliance date based

on a particular event may, but will not necessarily, result in an extension of a subsequent

compliance date or dates.

235. Unanticipated or increased costs or expenses associated with the performance of

CITGO's obligations under this Consent Decree shall not constitute circumstances beyond its

control, or serve as the basis. for an extension oftime. under this Section XN.

236. Notwithstanding any other provision ofthis Consent Decree, this Court shall not

draw any inferences nor establish any presumptions adverse to either Party as a result ofCITGO

serving a force majeure notice or the Parties' inability to reach agreement.

237. As part ofthe resolution of any matter submitted to this Court under this

Section XN, the Parties by agreement, or the Court, by order, may in appropriate circumstances

extend or modify the schedule for completion ofwork under the Consent Decree to account for

the delay in the work that occurred or will occur as a result of any delay or impediment to

143
perfonnance agreed to by the United States or approved by this Court. CITGO shall be liable for

stipulated penalties for its failure thereafter to complete the work in accordance with the

extended or modified schedule.

XV. RETENTION OF JURISDICTIONJDISPUTE RESOLUTION

238. This Court shall retain jurisdiction ofthis matter for the purposes of

implementing and enforcing the tenns and conditions ofthe Consent Decree and for the purpose

ofadjudicating all disputes (including, but not limited to, detenninations under Section V

(Affinnative RelieflEnvironmental Projects) ofthe Consent Decree) among the. Parties that may

arise under the provisions ofthe Consent Decree, until the Consent Decree terminates in

.accordance with Section XVIII ofthis Consent Decree (Tennination).

239. The dispute resolution procedure set forth in this Section XV shall be available to

resolve all disputes arising under this Consent Decree, except only as otherwise. provided in .

Section XIV regarding Force Majeure, provided that the Partymaking such application has made

a good faith attempt to resolve the matter with the other Party.

240. Dispute resolution shall be commenced by one ofthe Parties under the Consent

Decree by giving written notice to another Party advising of a dispute pursuant to this Section

XV. The notice shall describe the nature. ofthe dispute, and shaH state the noticing Party's

position with regard to such dispute. The Party receiving such a notice shall acknowledge receipt

ofthe notice and the Parties shall expeditiously schedule a meeting to discuss the dispute

informally not later than fourteen (14) days after the receipt ofsuch notice.

241. Disputessubmitted to dispute resolu\ion shall, in the first instance, be the subject

ofinformal negotiations between the Parties. Such period ofinfonnal negotiations shall not

144
extend beyond thirty (30) calendar days from the date ofthe first meeting between

representatives ofthe Parties, unless the Parties agree that this period should be extended.

242. In the event that the Parties are unable to reach agreement during such informal

negotiation period, the United States or the Applicable State Agency, as applicable, shall provide

CITGO with a written summary ofits position regarding the dispute. The position advanced by

the United States or the Applicable State Agency, as. applicable, shall be. considered binding

unless, within forty-five (45) calendar days ofCITGO's receipt ofthe written summary ofthe

United States' or the Applicable State Agency's position,. CITGO files with the Court a petition

which describes the nature ofthe dispute. The United States or the Applicable State Agency

shall respond to the petition within forty-five (45) calendar days offiling.

243. In the event that the. United States and the Applicable State Agency make

differing determinations or take differing actions that affect CITGO's rights or obligations under

this Consent Decree, the determination or action ofthe United States shall control.

244. Where the nature ofthe dispute is such that a more timely resolution ofthe issue

is required, the time periods set forth in this Section XV may be shortened upon motion of one of

the Parties to the dispute.

245. The Parties do not intend that the invocation ofthis Section XV by a Party cause

the Court to draw any inferences nor establish any presumptions adverse to either Party as a

result ofinvocation ofthis Section or their inability to reach agreement.

246. As part ofthe resolution of any dispute submitted to dispute resolution, the

Parties, by agreement, or this Court, by order, may, in appropriate circumstances, extend or ; . .

modify the schedule for completion ofwork under this Consent Decree to account for the delay

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in the work that occurred as a result ofdispute resolution. CITGO shall be liable for stipulated

penalties for its failure thereafter to complete the work in accordance with the extended or

modified schedule.

XVI. EFFECT OF SETTLEMENT

247. Definitions. For purposes ofSection XVI, the following definitions apply:

a. "Applicable NSRlPSD Requirements" shall mean:

(i) PSD requirements at Part C ofSubchapter I ofthe Act, 42 U.S.C.

§ 7475, and the regulations promulgated thereunder at 40 C.F.R.

§ 52.21, all as amended from time to time;

(ii) "Plan Requirements for Non-Attainment Areas" at Part D of

SubchapterI ofthe Act, 42 U.S.C. §§. 7502-7503, and the regulations

promulgated thereunder at 40 GF.R. §§ 51.165 (a) and (b); Title 40,

Part 51, Appendix S; and 40 C.F.R. § 52.24, all as amended from time

to time; and

(iii) Any applicable state laws or regulations that implement, adopt, or

incorporate the specific federal regulatory requirements identified

above regardless ofwhether such state or local laws orregulations

have been formally approved by EPA as being a part ofthe applicable

state implementation plan.

b. "Applicable NSPS Subparts. A and J Requirements" shall mean the standards,

monitoring, testing, reporting and recordkeeping requirements, found at 40 C.F.R. §§ 60.100

through 60.109 (Subpart J), relating to a particular pollutant and a particular affected facility, and

the corollary general requirements found at 40 C.F.R. §§ 60.1 through 60.19 (Subpart A) that are

applicable to any affected facility covered by Subpart J.

c. "Post-Lodging Compliance Dates" shall mean any dates in this Section XVI after the

Date ofLodging. Post-Lodging Compliance Dates include dates certain ~.g., "December 31,

2005"), dates after Lodging represented in terms of "months after Lodging" (J<.g., "Twelve

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Months after theDate ofLodging"), and dates after Lodging represented by actions taken (S;.g.,

"Date ofCertification''). The Post-Lodging Compliance Dates represent the dates by which work

is required to be completed or an emission limit is required to be met under the applicable

provisions ofthis Consent Decree.

248. . Liabili1y Resolution regarding the Applicable NSRlPSD Requirements,

With respect to emissions ofthe following pollutants. from the following units, entry ofthis

Consent Decree shall resolve. all civil liability ofCITGO to the United States and the CoPhiintiffs for violations ofthe Applicable NSRJPSD Requirements. resulting from construction or

modification from the date ofthe pre-Lodging construction or modification (including

reconstruction) up to the following dates:

Unit

Lemont FCCU

Lake Charles FCCU A

Lake Charles FCCU B

Lake Charles FCCU C

Pollutant

S02

NOx

fM

CO

S02

NOx

CO

PM

S02

NOx

PM

CO

S02

NOx

PM

CO

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Date

December 31, 2007

March 31, 2013

December 31, 2007

Date ofEntry

March 31, 2012

March 31, 2012

October 1, 2005

March 31, 2010

December. 31, 2006

September 30, 2010

December 31, 2006

October 31, 2005

December 31, 2007

September 30, 20I 0

December 31,2007

October 31, 2005
Corpus Christi FCCU # 1 S02 September 30, 2013

NOx September 30, 2013

PM December 31, 2006

CO Date ofEntry

Corpus Christi FCCU #:2 S02 March 31, 2010

NOx August 31,2007

CO Date ofEntry

PM April 30, 2005

All Heaters and Boilers listed

in Appendix C NOx June 30, 2011

All Heaters and Boilers other

than those. in. Appendix C NOx Date ofLodging

All Heaters and Boilers listed

in Appendix E S02 Dates listed in Appendix E

All Heaters and Boilers other

than those listed in Appendix E S02 Date ofLodging

All Fuel Gas Combustion

Devices listed in Appendix F S02 Dates listed in Appendix F

All Flaring Devices

lisfed in Appendices B-1 or B-2,

andG S02 Date. listed in Appendix G

Lake Charles. Sulfuric Acid Plant S02 December 31, 2006

249. Reservation ofRi2hts regardin2 Applicable NSRlPSD Requirements:

Release for Violations Continuin2 Uter the Date of Lodging Can be Rendered Void.

Notwithstanding the resolution ofliability in Paragraph 248, the release ofliability by the.

United States and the Co-Plaintiffs to CITOO for violations ofthe Applicable NSRJPSD

Requirements during the period between the Date ofLodging ofthe Consent Decree and the

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Post-Lodging Compliance Dates shall be rendered void for a particular emissions unit ifCITGO

materially fails to comply with the obligations and requirements of Sections V.A. - VD. and

V.F. for that unit; provided however, that the release in Paragraph 248 shall not be rendered void

ifCITGO remedies such material failure and pays any stipulated penalties due as a result ofsuch

material failure.

250. Exclusions from Release Coverage reearding Applicable NSRlPSD

Requirements: Construction aud/or Modification Not Covered by Paraeraph .

Notwithstanding the resolution ofliability in Paragraph 248, nothing in this Consent Decree

precludes the United States and/or the Co-Plaintiffs from seeking from CITGO, injunctive relief,

penalties, or other appropriate relieffor violations. by CITGO ofthe Applicable NSRJPSD

Requirements resulting from construction or modification that: (I) commenced prior to or

coinIllences after the Date. ofLodging ofthe Consent Decree for pollutants or units not covered

by the Consent Decree; or (2) commences after the Date ofLodging ofthe Consent Decree for

units covered by this Consent Decree.

251. Increases in emissions from units covered by this Consent Decree, where the

increases result from the Post-Lodging construction or modification of any units within the

Covered Refineries, are beyond the scope ofthe release in Paragraph 248.

252. Resolution of Liability Regarding Applicable NSPS Requirements. With

respect to emissions ofthe following pollutants from the following units, entry ofthis Consent

Decree shall resolve all civil liability ofCITGO to the United States and the Co-Plaintiffs for

violations ofthe Applicable NSPS Subparts A and J Requirements from the date that the claim(s)

ofthe United States and the Co-Plaintiffs accrued up to the follOWing dates:

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Unit Pollutant Date

All Covered FCCUs S02 Dates listed in Paragraph 248

PM (including

opacity) Dates listed in Paragraph 248

CO Dates listed in Paragraph 248

All Heaters and Boilers listed

in Appendix E S02 Dates listed in Appendix E

All Heaters and Boilers other

than those listed in Appendix E S02 Date ofLodging

All Fuel Gas Combustion

Devices listed in Appendix F S02 Dates listed in Appendix F

Corpus Christi East and S02 Date ofEntry

Corpus Christi West SRPs

Lake Charles SRP Total Reduced

Sulfur Date ofEntry

LemontSRP S02 December 31, 2008

Flaring Devices listed

in Appendices B·! or G S02 Date listed in Appendix G

In addition and with respect to the Lake Charles Refmery sulfuric acid plant, entry ofthis

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

Louisiana for violations ofthe Applicable NSPS Subparts A and H requirements from the date

the.claim(s) ofthe United States and the State ofLouisiana accrued up to December 31,2006.

253. Reservation ofRights regarding Applicable NSPS Subparts A andJ

Requirements: Release for NSPS Violations Occurring After the Date of Lodging Can be

Rendered Void. Notwithstanding the resolution ofliability in Paragraph 252, the release

ofliability by the United States a~d the Co-Plaintiffs to ClTGO for violations of any

ISO
Applicable NSPS Subparts A and JRequirement that occurred between the Date ofLodging and

the Post-Lodging Compliance Dates shall be rendered void for a particular emissions unit if

CITGO materially fails to complywith the obligations and requirements ofSections V.E., V.G.,

V.H., V.I., VJ.and V.K., and Paragraphs 44-46 and 48-49 for that unit; provided however, that

the release in Paragraph 252 shall not be rendered void ifCITGO remedies such material failure

and pays any stipulated penalties due as. a result ofsuch material failure,

254. Prior NSPS Applicability Determinations. Nothing in this. Consent Decree

shall affect the status of any FCeD, fuel gas combustion device, or sulfUr recovery plant

currently subject to NSPS as previously determined by any federal, state, or local authority or any

applicable permit

255,. Resolution of Liability Regarding Benzene Waste NESHAP Requirements.

With respect to the National Emission Standard for Benzene Waste Operations, 40 e,F.R.

Part 61, Subpart FF ("Benzene Waste NESHAP"), and any applicable state, regional, or local

regulations that implement, adopt or incorporate the Benzene. Waste NESHAP, entry ofthis

Consent Decree shall resolve all civil liability ofCITGO to the United States and the CoPlaintiffs for violations that: (1) commenced and ceased prior to the Date ofEntry ofthe. Consent

Decree; and/or (2) are based on events identified in the BON Compliance Review and

Verification Report required under Paragraph 98 and are corrected pursuant to the requirements

ofParagraph 100.

256. Resolution of Liability Regarding LDAR Requirements. With respect to the

Leak Detection and Repair requirements relating to equipment in light liquid service and gas

and/or vapor service set forth at 40 C.F.R. Part 60, Subparts VV and GGG; 40 C.F.R. Part 61,

151
Subparts J and V; and 40 C.F.R. Part 63; Subparts F, H, and CC (collectively "LDAR

Requirements"), and any applicable state. regional, or local regulations or State Implementation

Plan requirements that implement, adopt or incorporate the LDAR Requirements or set similar

standards, entry ofthis Consent Decree shall resolve the civil liability ofCITGO to the United

States and the. Co-Plaintiffs for violations that:. (I) commenced and ceased prior to the Date of

Entry ofthe Consent Decree; and/or (2) are based on events identified in the initial audit required

under Paragraph 117(a) and are corrected pursuant to the requirements ofParagraph 118.

.257. Reservation ofRiehts Regardine the Benzene Waste NESHAP and LDAR

Requirements. Notwithstanding the resolution ofliability in Paragraphs 255 and 256, nothing in

this Consent Decree precludes the United States and/or the Co-Plaintiffs from seeking from

CITGO civil penalties and/or injunctive relief and/or other equitable relieffor violations by

.CITGO ofBenzene Waste NESHAP and/or LDAR requirements that: (I) commenced prior to

the. Date ofEntry ofthis Consent Decree and continued after the Date ofEntry ifCITao fails to

identifY in its Paragraph 98 report or its Paragraph 117(a) audit, as applicable, such violations,

and/or fails to correct such violations pursuant to Paragraphs 100 or 118, as applicable; or

(2) commenced after the Date ofEntry ofthe Consent Decree but are not identified in CITGO's

Paragraph 98 report or its Paragraph 117(a) audit,. as. applicable and/or are not corrected pursuant

to Paragraphs 100 or 118, as applicable. .

258. With respect to the claims which formed the basis ofthe notices and orders

identified in Appendix A, the United States and the Co-Plaintiffs release CITGO from any and

152
all civil liability under the Clean Air Act and any corresponding state or local laws or regulations

arising out of any acts or omissions by CITGO which formed the .basis for such claims.

258A. With respect to any claims for a stipulated penalty under this Consent Decree,

assessment of and payment ofsuch stipulated penalty by CITGO shall resolve all civil liability of

CITGO to the United States and the Co-Plaintiffs under the Clean Air Act and any similar state

or local laws or regulations, for any and all violations based on the facts. or circumstances giving

rise to the claim for and assessment ofthe stipulated penalty.

259. Audit Policy. Nothing in this Consent Decree is intended to limit or disqualify

CITOO, on the grounds that information was not discovered and supplied voluntarily, from

seeking to apply EPA's Audit Policy or any state audit policy to any violations or

.non~compliance that CITGO discovers during the. course of any investigation, audit, or enhanced

monitoring that CITGO is reqnired to undertake pursuant to this Consent Decree.

260.ClaimlIssue Preclusion. In any subsequent administrative orjudicial

proceeding initiated by the United States or the Co-Plaintiffs for injunctive relief, penalties, or

other appropriate. reliefrelating to CITGO for violations. ofthe PSDINSR, NSPS, NESHAP,

and/or LDAR requirements, not identified in this Section XVI ofthe Consent Decree and/or the

Complaint:

a. CITGO shall not assert, and may not maintain, any defense or claim based upon the

principles ofwaiver, res jUdicata, collateral estoppel, issue preclusion, or claim-splitting. Nor

may CITGO assert, or maintain, any other defenses based upon any contention that the claims

raised by the United States or the Co-Plaintiffs in the subsequent proceeding were or should have

been brought in the instant case. Nothing in the preceding sentences is intended to affect the

153
ability ofCITGOto assert that the claims are deemed resolved by virtue ofthis Section XVI of

the Consent Decree.

b. The United States and Co-Plaintiffs. may not assert or maintain that this Consent

Decree constitutes a waiver or determination of, or otherwise obviates, any claim or defense

whatsoever, or that this Consent Decree constitutes acceptance by CrrGO of any interpretation or

guidance issued by EPA related to. the matters addressed in this Consent Decree.

261. Imminent and Substantial Endangerment. Nothing in this Consent Decree

shall be construed to limit the authority ofthe United States, Georgia, Illinois, louisiana, or New

Jersey to undertake any action against any person, including CITGO, to abate. or correct

conditions which may present an imminent and substantial endangerment to the public health,

welfare, or the environment.

XVII. GENERAL PROVISIONS

262. Other Laws. Except as specificallyprovided by thi~ Consent Decree, nothing in

this Consent Decree shall relieve CITOO ofits obligations to complywith all applicable federal,

state and local laws and regulations. Subject to Section XVI, nothing contained in this Consent

Decree shall be construed to prevent or limit the rights ofthe United States, Georgia, Illinois,

Louisiana, or New Jersey to seek or obtain other remedies or sanctions available under other

federal, state mlocal statutes or regulations, by virtue ofClTOO's violation ofthe Consent

Decree or ofthe statutes and regulations upon which the Consent Decree is based, or for

CITGO's violations of any applicable provision oflaw, other than the specific matters resolved

herein. This shall include the right ofthe United States, Georgia, TIlinois, Louisiana, or New

154
Jersey to invoke the authority ofthe Court to order CITGO's compliance with this Consent

Decree in a subsequent contempt action.

263. Post-Permit Violations. Nothing in this Consent Decree shall be construed to

prevent or limit the right ofthe United States, Georgia, Illinois, Louisiana, or New Jersey to seek

injunctive or monetary relieffor violations ofpermits issued as a result ofthe procedure required

under Section V.N. ofthis Decree; provided however, that with respect to monetary relief, the

United States, Georgia, Illinois, Louisiana, or New Jerseymust elect between filing a new action

for such monetary relief or seeking stipulated penalties under this Consent Decree, ifstipulated

penalties also are available for the allegedviolation(s).

264. Failure ofCowpliance. The United States, Georgia, Illinois, Louisiana, or New

Jersey do not, by their consent to the entry ofthis Consent Decree, warrant or aver in any manner

that CITGO's complete compliance with the Consent Decree will result in future compliance

with the provisions ofthe CAA, the Georgia Air Quality Act, OCGA 12-9-1; the Illinois

Environmental Protection Act, 415 !LCS 5/8: Title II Air Pollution; Louisiana Air Control Law,

LSA - R.8. 30:2051-2065; the New Jersey Air Pollution Control Act, 26:2C-l to 25.2; and the

Texas Clean Air Act, Acts 1989, 71" Leg., ch. 382. Notwithstanding the. review or approval by

EPA or the. Co-Plaintiffs, including their applicable state agencies, of any plans; reports, policies

or procedures formulated pursuant to the Consent Decree, CITGO shall remain solely responsible

for compliance with the terms ofthe Consent Decree, all applicable permits, and all applicable

federal, state and local laws and regulations, except as provided in Section XIV (Force Majeure).

265. Service of Process. CITGO hereby agrees to accept service ofprocess by mail

with respect to all matters arising under or relating to the Consent Decree and to waive the formal

155
service requirements set forth in Rule 4 ofthe Federal·Rules ofCivil Procedure and any

applicable local rules ofthis Court, including but not limited to, service of a summons. The

persons identified by CITGO at Paragraph 270 (Notice) are authorized to accept service of

process with respect to all matters arising under or relating to the Consent Decree.

266. Post-LodginglPre-Entry Obligations. Obligations ofCITGO under this

Consent Decree to perform duties scheduled to. occur after the Date ofLodging ofthe Consent

Decree, but prior to the Date ofEntry ofthe Consent Decree, shall be legally enforceable on and

after the Date ofEntry ofthe Consent Decree. Liability for stipulated penalties, if applicable,

shall accrue for violation ofsuch obligations and payment ofsuch stipulated penalties may be

demanded by the United States, Georgia, Illinois, Louisiana, and/or New Jersey as provided in

this. Consent Decree, provided that stipulated penalties that may have accrued between the Date

ofLodging ofthe Consent Decree and the. Date ofEntry ofthe Consent Decree may not be

collected unless and until this Consent Decree is entered by the Court.

267. Costs. Each Party to this action shall bear its own costs and attorneys' fees.

268. Public Documents. All information and documents submitted by CITao to the

Applicable Federal and State Agencies pursuant to this Consent Decree shall be subject to public

.inspection in accordance with the respective statutes and regulations that are applicable, unless

subject to legal.privileges or protection or identified and supported as business confidential in

accordance with the respective state or federal statutes or regulations.

269. Public Notice and Comment. The Parties agree that the Consent Decree maybe

entered upon compliance with the public notice procedures set forth at 28 C.F.R. § 50.7, and

upon notice to this Court from the United States Department ofJustice requesting entry ofthe

156
Consent Decree. The United States reserves the right to withdraw or withhold its consentto the

Consent Decree ifpublic comments disclose facts or considerations indicating that the Consent

Decree is inappropriate, improper, or inadequate. Further, the Parties acknowledge and agree

that final approval by CocPlaintiff, the State. ofLouisiana, through the Department of

Enviromnental Quality, and entry ofthis Consent Decree is SUbject to the requirements ofLa.

R.S. 30:2050.7, which provides for public notice ofthis Consent Decree in newspapers of

general circulation and the official journals ofparishes in which CITGO facilities are. located, an

opportunity for public comment, consideration ofany comments, and concurrence by the State

Attorney General.

270. 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 XN (Force Majeure) and Section XV (Retention

JurisdictionlDispute Resolution) which shall be sent by overnight mail or by certified or

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

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

Headquarters and the Applicable EPA Region and the Applicable State Agency. Ifthe 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 Co-Plaintiffs and/or

CITGO shall be addressed as follows:

157
As to the United States:

Chief

Environmental Enforcement Section

Environment and Natural Resources Division

U.S. Department ofJustice

P.O. Box 7611, Ben Franklin Station

Washington, DC 20044-7611

Reference Case. No. 90-5-2-1-07277

As to EPA:

U.S. Environmental Protection Agency

Director, Air Enforcement Division

Office ofRegulatory Enforcement

Ariel Rios Building

1200 Pennsylvania Avenue, N.W.

Mail Code 2242-A

Washington, DC 20460

EPA Region 2:

Director, Division ofEnforcement and Compliance Assistance

U.S. Environmental Protection Agency, Region 2

21sl Floor

290 Broadway

New York, NY 10007

Chief, Air Compliance Branch

Division ofEnforcement and Compliance Assistance

21sl Floor

290 Broadway

New York, NY 10007

EPA Region 4:

Chief, Air Enforcement & EPCRA Branch

Air, Pesticides and Toxics Management Division

U.S. Environmental Protection Agency, Region 4

61 Forsyth Street, S.W.

Atlanta, Georgia 30303

158
-~.\.;"', ...

EPA Region 5:

Air and Radiation Division

U.S. EPA, Region 5

77 West Jackson Blvd. (AE-17J)

Chicago, Illinois 60604

ATTN: Compliance Tracker

Office ofRegional Counsel

U.s. EPA, Region 5

77 West Jackson Blvd.. (C-14J)

Chicago, Illinois 60604

EPA Region 6:

Chief

Air, Toxics, and Inspections Coordination Branch

Environmental Protection Agency, Region 6

1445 Ross Avenue

Dallas, Texas. 75202-2733

The State ofGeorgia:

Chief

Air Protection Branch

Environmental Protection Division

4244 International Parkway

Suite 120

Atlanta, Ga. 30354

The State oflllinois:

Chief, Environmental Bureau

Office ofthe lllinois. Attorney General

188 West Randolph Street, 20'h Floor

Chicago, lllinois 60601

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The State ofLouisiana:

PeggyM. Hatch

Administrator, Enforcement Division

Office ofEnvironmental Compliance

Louisiana Department ofEnvironmental Quality

P.O. Box 4312

Baton Rouge, La. 70821-4312

The State of New Jersey:

New Jersey Department ofEnvironmental Protection

Southern Regional Office

Air Compliance & Enforcement Manager

One Porl Center

2 Riverside Drive, Suite. 201

Camden, New Jersey 08103

As to CITGO:

Manager, Environmental Services

crroo

1293 Eldridge Parkway

Houston, Texas 77077

General Counsel

CITGO

1293 Eldridge Parkway

Houston, Texas 77077

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.. In

addition, the nature and frequency ofreports required by the Consent Decree may be modified by

mutual consent ofthe Farties. The consent ofthe United States to such modification must be in

. the form of a written notification ofconsent from the Department ofJustice, but need not be filed

with the Court to be effective.

160
271. Approvals. All EPA approvals shall be made in writing. All PlaintiffIntervener approvals shall be sent from the offices identified in Paragraph 270.

272. Paperwork Reduction Act. The information required to be maintained or

submitted pursuant to this Consent Decree is not subject to the Paperwork Reduction Act of

1980,44 U.S.C. §§ 3501 et~.

273. Modification. The Consent Decree contains the entire agreement ofthe Parties

and shall not be modified by any prior oral or written agreement, representation or understanding.

Prior drafts ofthe Consent Decree shall not be. used in any action involving the interpretation or

enforcement ofthe Consent Decree. Non-material modifications to this Consent Decree,

including modifications to. the schedules for catalyst additive programs under Sections. V.A and

v.n and to the frequency ofreporting obligations, shall be in writing, signed by the Parties, but

need not be filed with the Court. Material modifications to this Consent Decree shall be in

writing, signed by the Parties, and shall be effective upon filing with the Court.

XVIII. TERMINATION

274. This Consent Decree shall be subject to termination upon motion by the United

States, in consultation .with the Co-Plaintiffs, or CITGO (under the procedure identified in

Paragraph 276). Prior to either party seeking termination, CITao shall have. completed and

satisfied all ofthe following requirements ofthis Consent Decree:

a. installation of control technology systems as specified in this Consent Decree;

b. compliance with all provisions contained in this Consent Decree, which

compliance may be established for specific parts ofthe Consent Decree in

accordance with Paragraph 275, below;

161
c. payment of all penalties and other monetary obligations due under the terms of

the Consent Decree; no penalties or other monetary obligations due hereunder

can be outstanding or owed to the United States or the Co-Plaintiffs;

d. completion ofthe "environmentally beneficial" projects set forth in Section

VIII;

e. application for and receipt ofpermits incorporating the surviving emission

limits and standards established under Section V.N.; and

f. operation for at least one year ofeach unit in compliance with the emission

limits established herein, and certification ofsuch compliance for each unit

within the first six. (6) month period progress report following the conclusion

ofthe. compliance period.

275. Certification ofCompletion.

a. Prior to moving for termination, CITGO may certifycompletion ofone or more. of

the following subsections ofthe Consent Decree, provided that all ofthe related requirements

have been satisfied:

i. Subsection V.A. - V.E.; relating to FCCUs;

ii. Subsections V.F. - V. G., relating to Heaters, Boilers and Other Fuel

Gas Combustion Devices;

Ill. Subsections. V.H - V.K, relating to SRPs and Flaring;

IV. Subsections V.L and V.M, relating to Benzene Waste NESHAP and

LDAR; and

v. Section VIII, relating to Environmentally Beneficial Projects.

162
b, Within 90 days after CITGO concludes that'any ofthe parts ofthe Consent Decree

identified in this Paragraph 275 have been completed, CITGO may submit a written report to the

Parties listed in Paragraph 270 (Notice) describing the activities. undertaken and certifying that

. the applicable Paragraphs have been completed in full satisfaction ofthe requirements ofthis

Consent Decree, and that CITGO is in substantial and material compliance with all ofthe other

requirements ofthe Consent Decree, The report shall contain the. following statemeht, signed by

aresponsible corporate official ofCITGO:

To the best ofmy knowledge, after thorough investigation, I certify that the

information contained in or accompanying this submission is true, accurate and

complete, I am aware that there are significant penalties for submitting false

information, including the possibility offine and imprisonment for knowing

violations,

c. Upon receipt ofCITGO's certification, EPA, after reasonable opportunity for review

and comment by the Applicable State AgencieS,shall notify CITGO whether the requirements set

forth in the applicable Paragraphs have been completed in accordance with this Consent Decree,

The parties recognize that ongoing obligations under such Paragraphs remain and necessarily

continue (e,g, reporting, record keeping, training, auditing requirements), and that CITGO's

certification is that it is in current compliance with all such obligations,

I, IfEPA concludes. that the requirements have not been fully complied

with, EPA shall notify CITGO as to the activities that must be

undertaken to complete the applicable Paragraphs ofthe Consent

Decree, CITGO shall perform all activities described in the notice,

subject to its right to invoke the dispute resolution procedures set

forth in Section XV (Dispute Resolution),

IL IfEPA concludes that the requirements ofthe applicable Paragraphs

have been completed in accordance with this Consent Decree, EPA

will so certify in writing to CITGO, This certification shall constitute

163
the certification ofcompletion ofthe applicable Paragraphs for

purposes ofthis Consent Decree.

d. Nothing in Paragraph 275(c) shall preclude the United States orthe Co-Plaintiffs

:trom seeking stipulated penalties for a violation of any ofthe requirements ofthe Consent Decree

regardless ofwhether a Certification ofCompletion has been issued under Paragraph 275 ofthe

Consent Decree. In addition, nothing in Paragraph 275(c) shall permit CIrGO to fail to

implement any ongoing obligations under the Consent Decree regardless ofwhether a

Certification ofCompletion has been issued with respect to Paragraph 275 ofthe Consent

Decree.

276. Atsuch time as CIrGO believes that it has satisfied the requirements for

termination set forth in Paragraph 274, CIrGO shall certify such compliance. and completion to

the United States and the Co-Plaintiffs in writing as provided in Paragraph 270 (Notice). Unless,

within 120 days ofreceipt ofCITGO's certification under this Paragraph, either the United States

or the Co-Plaintiffs. objects in writing with specific. reasons, CIrGO may move this Court for an

order that this. Consent Decree be terminated. Ifeither the United States or the Co-Plaintiffs

objects to the certification by CITGO under this. Paragraph, then the matter shall be. submitted to

the Court for resolution under Section XV (Retention ofJurisdictionlDispute. Resolution) ofthis

Consent Decree. In such case, CIrGO shall bear the burden ofproving that this Consent Decree

should be terminated.

164
XIX. SIGNATORIES

277. .Each ofthe undersigned representatives certifies that he orshe is fully authorized

to enter into the Consent Decree on behalfofsuch Parties,. and to execute and to bind such

Partiesto the Consent Decree. This Consent Decree may be signed in counterparts.

Dated and entered this _. day of ".2004

UNITED STATES DISTRICT JUDGE

165
•

PLANTIFF UNITED STATES OF AMERICA

THOMAS L. SANSONETTI

. Assistant Attorney General

Environment and Natural Resources Division

U.S. Department ofJustice

Washington, DC 20530

NICHOLAS

~TL~~. F. PERSAMPIERI -,

Trial Attorney

Environmental Enforcement Section

Environment and Natural Resources Division

U.S. Department ofJustice·

P.O. Box 7611

Washington, DC 20044·7611

fl&w...V,

·:rnotAS V. SKINNER

. Acting Assistant Administrator for Enforcement

and Compliance Assurance

United States Environmental Protection Agency

1200 Pennsylvania Avenue, Mail Code: 220lA

Washington, DC 20460

166

9..22· (/1

DATE·

DATE
.. PLAnmFF TIIE STATE OF GEORGIA

CAROL A: COUCH, PHD.

.Director

Environmental Protection Division

.DepartIn~t ofNatural Resources

. .State ofGeOrgia·

167
·PLAINTlFF tHE STATEOF ILLINOIS

Ro

Chief

Environmental Bureau

Assistant AttomeyGeneral

188 West Randolph St. 20th Floor

. Chicago, llIinois 60601 .

. .J"

168

Date:.-U¥"=-f--=-1-_-,-_
. .

. UISIANA, THROUGH THEDEPARTMENT OF

Date: ~~?/6Y OLDLEG9 T,P

ASsistant Secretary

. Office ofEnVironmental Compliance

Louisiana Departtnent ofEnViron:rnerital Quality

TED ... S

SeniorA mey (LA .Bar No: 20456)

Legal Division

Louisiana Department ofEnviromnental Quality

:(225)219-3985

169
,

PLAINTIFF THE STATE OF NEW JERSEY'

PETER C. HARVEY

.Attorney General ofNew Jerney

'By'~~(3~ SCOTT B. DUBIN .

Deputy Attorney General

Department ofLaw and Public Safety

Division ofLaw

RJ Hughes Justice Complex

25 Market St. 7th FloorWest

P.O. Box 093

Trenton,

EDWARD M. CHOROMANSKI

Administrator, Air Compliance &. Enforcement .

New Jersey Department ofEnviromnental Protection

P.O. Box 422

401 East State Street, Floor 4

Trenton, New Jersey 08625

170

Date:.~_·--,<tI_V_'7_ir-/-=-o-l-1__

Date:·~_'?7Ac..::2-,--3:::"If-h=-O.Ltf_·_
ITt· .

:...._....

DEFENDANT CITGO PElROLEUM CORPORATION

By (j"lt~
JERRY E. rnOMPSoN

ChiefOperating Officer

H'Iol,,,yr~D CHEMICALS COMPANY, L.P.

Date: ./Iv"!

I

DEFENDANT PDV MIDWEST REFINING, L.L.C.

ByJE~rn ~e~ MPSO~ ~c

President

DEFENDANT CITGO ASPHALT REFINING COMPANY

.._.- ," ' .. "." ,

',:' President

,172

Date: t(

,

/Z}[O'Y ..
APPENDIX A

STATE AND. FEDERAL COMPLIANCE ORDERS AND NOTICES

EPA FOV 5-99-IL-28 (dated 6.8·99)

EPA NOV 5-01-IL-04 (dated 1·19-01)

EPA FOV 5-01-IL-II (dated 7-13-01)

IEPA Violation Notice. A-2002-00346 (dated 11/13/02)

IEPA Violation Notice E-2003-00004 (dated 1-13-03)

LDEQ Notice. ofViolation and Potential Penalty AE-NP-99-0226 (dated 10-29-99)

LDEQ Compliance Order and Notice. ofPotential PenaltY AE-CN-OI-0304 (dated 6-6-02)

LDEQ Compliance Order and Notice ofPotential Penalty AE-CN-02-0191 (dated 3-10-.03)

TCEQ Agreed Order Docket No. 2001-1469-AIR-E (dated February 2004)

TNRCC Agreed Order Docket No. 1999-0057-AIR-E (dated June 2002)
APPENDIXB

LIST OF. HYDROCARBON FLARING DEVICES

COJllus Christi East Refinery

Fluor Flare .

Cumene Flare

Comus Christi West Refmery

Flare

Lemont Refinery

844C-I North Plant Flare

844C-2 South Plant Block2Flare

844C-3 South Plant Block 3. Flare

. 844C-4 Needle Coker Flare

844C-5 Alky Flare·

Lake Charles. Refinery

328B-! Flare Alky

330B-4 Flare NGL/Girbitol

343B-5 Flare Central

343B-6 Flare Central

343B·7 Flare Central

3!9B-8 Flare C4 Recovery .

3I 5B-9 Flare Benzene

327B-II Flare C-Re£'CKll

320B-j2 Flare Unicracker

399B-16 Flare CFH

360CB-701 (CB-II) PFU

CAIOOI.CLAW

B-I04 COP!fIER II
· PaulsbClro Refinery

Flare
APPENDIX B-1

LIST OF NSPS HYDROCARBON FLARING DEVICES

Comus Christi EastRefinery

Fluor Flare

Cumene Flare

Comus Christi West Refinery

Flare

Lemont Refinery

844C·l North Plant Flare

844C-2 South Plant Block 2 Flare

844C-3 South Plant Block 3 Flare

844C-4 Needle. Coker Flare

844C-5 AlkyFlare

Lake. Charles. Refmety

327B-ll Flare C-Ref/CKIJ

320B-12 Flare Unicracker

399B-16 Flare CFH

360CB-701 (CB-ll) PFU

CAIOOI CLAW

B-104 COPrrIEIUI

Paulsboro Refinery

Flare
APPENDIX B-2

LIST OF. NSPS ACID. GAS FLARING DEVICES

Comus. Christi East Refinery

Acid Gas Flare

SWSFlare

Comus Christi West Refinery

Acid Gas Flare

SWSFlare

Lemont Refinery

844C-2 South Plant Block 2 Flare

844C-3 South Plant Block 3 Flare

Lake Charles Refmery

327B-II Flare C-Refi'CK II

320B-12 Flare Unicracker
APPENOIXC

LIST OF CITGO HEATERS AND: BOILERS

INFORMATION REDACTED AS CONFIDemAL BUSINESS INFORMATION

79 BoilerB-l,B-IA 890_6 146UI ~493,3 80).0 813,2 Rctbctcd R",""" F&TS Tc:n'

145 Furnace B-So3-,504j05 700.0 172,9 191.7 41:>.6 475.1 ....,'" RedGtcd Sta<:k Test Pmnit· 261 M·' 77 BoUer B-IC 616.7 474.9 505.5 349.8 372.3 Redacted Redacted FIlTS Tt~

j 18 Boiler B-IB 53].6 450.3 . 47LO 314.5 391.7 ....,'" Rcdm:tcd AP.42

j 25 FumaceB-4 456.6 242.6 218.9 403.5 364.2

"""""'''' Redacted AP-42

2' fUrnace B_I04 456.6 28<ll 189.9 456.S 472.8 Redaeted R.edacted . F&TS Te~

'35 Boiler :B-5A 1~7.6 81.) 76.5 185.6 174.1

""""'''' R"""'" Stack Tl"lIt PSI).LA.51

136 BOllerB-5 331.6 92.9 89.6 212.1 204.6 R"""'" N.edacted Stack fest PSD-LA-57

" FI,I11'JfleC n-403,404,405 330.0 46_1 SU 183_8: 21S.3 R~led """''''' .F&'rST~in..!O B0l1el':B-2 267.1 193.4 ta1.2 160.9 150.7 """"'" R ,'" AP-4'

" Bol!erB-2A 267.1 132.6 117.8 1611.2 149.4 l!.e(iacled Redacted JI&'l'S'festln

..i~. Fumnec:..--p-1 "345 245.0 Ilg.!! 136.1 134.1 153.1 Red~ed """"'''' Stack Tesl =ni1_2EiI5 ., 82 ~~B-3,1i':?!L_., .• 229.:1 303.9 309.5 252.8 257.4 R~ed R.ted AP-4'

83 Bl;li1er B-3A,B-3C 229_5 155.0 153,7 128:9- 127.8 Redacted Redao;ted AP_42

'44 f\ll'I;&Ce B-SOI,502,506 19a.5 73.3 69.8 88".2 83.9 R"""'" Redacr:oo. StlIckTM Sl)..LA-21i

, 107 FI.lJlllltI:BcIOZ-B-I06 185.0

"'"' 65.6 76.7 54.6 R"""" """"'" AP-4'

" BoilerBF-4 \67.0 45.0 '"' 31.4

'"' Redacted ""-, AP-4'

'" FlrmU:<:t B-20 I .158.8 1l0.1 93.3 158.0 133_2 Rr.m;u;ted ""-'" fl&"tS'testin , 140 FUJ1'NIt;I: 8-202 158.8 90.5 87.1 150.6 144.8 R""''''' ""''''''' AP-4'

;

" A~t"f~B-6 156_2 too.4 94.4 83.5 78.5 R"""'" ",- AP-42

" C eat F'w't1a.:e 8-6 156.2 24.5 29.1 68.3 80.9 """"'" Redacloo. F&TSTesdn

" Tkliler BF-I 139.0 II4.3 138.8 95_1 115.4 """"'" RedaCled AP-4'

" Boil<::r 51'-2 139.0 124.6 140.9 l03.7 117.2 R~W:led """"'''' M_42

33 lklilerBF-3 139.0 1j6.4 134.5 113.4 111.9 RedacUld """','" Al"-42

177 Furnace 8_101 116_9 18_0 130 97.6 10.6 :Redacled ktdacted StaekTClIt mnli -2308 ., 14 F'!Jrllace BA-I.2A&.2B 115.6 102.2 110:5 85.0 91.9

""""'" """""'" Ai'_42

2001 -»-421

2002 ' Stm:k Tcrt (Permit _

_'2 Fllfl'ill(;e D-IOI· 112.9 70.0 92.4" 85.1 101.3 Redacted Red;u,:ted 2714 VO

2001-AP-421

2002 Sw.:1; Test (Pmnil-

_lQ.._- Fl,lffiiI~B-:lOI 109.7 74.6 ''"I 91.3 101.0 Rcdllt-I-ec) R"""'''' '" 0

94 FumIlCC 8--IC 10·0 134".5 143_7 111.8 119.5 R"""" R"""od AP-42

" FUI1IaCe B-2C

'" 47.0 46.4 109.4 108.1 R""''''' Redacted AP-4'

118 FIU1lIP;B-JO~ 88.0 14.4 10.7 78.4· 58.4 R,"'"" R"""'" SlaCk Te$I; Permil- 2308 M-2

" B CIl.t ,FlIm&{;~ 8-6 81.4 16.6 15.2 38,6 35.5 Redacted RedclCied AP-4' __L_ t::'!'!1~.C; Bb..-_'____ 77.5 33-4 37.4 77,8 67.1 Redacted RcdM:ted AP-42

2001- AP-42 , Fllrnace SA-IOI 17_5 33.5 23.1 78.0 10.3 Re-latt¢d RcdllC!ed i002~ AP'-42 - LowNox burner

65 F\lrtI!lCe Il-201 75.6 41.7 44"' 97.1 103.2 Redatt=d .....,'" Al'-4l

n Fllm&o:o!:Il-IOI 74.8 22.0

""' 51.2 54.3 Redact="d R~ed AP-42

73 FU111l1l:e B-10 I #2 74.8 22_0 23.3 51.2 .54.3 R"""" """"" AJ'"-4;2

" Flll'\4lCe BA_I &2 .., 11.3 II.3 26.4 U;;2 """"'" Red/ll;t:ed AI'-4Z.,._l:!~._. f.Wlla¢e B-20 I 1\'"5 22.;Z ;l.4..9 5l.S 58-0 Redoolcd Redlll:ted AP-4'

---§.--" FvmkcN-2.A 1\4,' 20,Z 10.3 47-1 47.2 RedlM:ted Redacled AP-4' , I:mn_~.N.:~_ .. 1\4"' 23.2 21.1 54.0 49_2 Rcdac.led RedlM:ted AP·42 , FlIJlII\I;:~J:4:~c;:'",- ____ 1\4"' 21.1 2(l,9 .<19,2 48.7 Rroamd Redacted AP.42

17 Fumacp~A-1 & 2 1\4,' 19,9 20,1 41$.3 46.8 Redaeted Redacted AP·42

84 FllJ1'IaceJl-401 60' 17.5 15_7 40"' JQ.,:i Redac.ted R.cdiIeled AP-4'

74 Fllrnace 8-'5 58.4 14.0 14.2 32.5 33_1 Red\\l:led Redacted AP-42

85 ~B-406 573 10.6 11.5 24.8 ;':6.7 R~ted Redacted AP-42

86 fumace 8-402 55.9 14.3 16.2 33.3 31.:11 Redlltted R~w;:ted AP-42

1\4 Furnace B-2()2 53.0 1~.3 16.6 42.7 ,>7 Il:cdaeLed Re~ted Ar'-42

" FUmaceB-2A 44"' 19.6 21.1 458 49.1 Reuacled ""","" :AP-42

" FumaceB-l02 43-3 27.7 23.3 40.1 JJ.7 Re4;u:Ied Redacted Stack Test Permil_ 74 M~3

" Furnace D·I #1--- 39.0 24,' 22.4 56.3 52.1 Redar;led Redaclild »-42

" FumliCeB·j #2 39.0 24,' 22,4 56.3 52.1 Redacled Redacted AP-42

".",.<,,~:. ":!.:~,;;">,-;.,:. -, .. ';"\:"";'

,

'I1KI:ie Imits id=rtlfic:d wilh this ..hc:l:ktnBri; tu'e: to be lested rorNO~ l:JI"Iimons. With prior consrni from EPA. CITGO may substitute any other heater or boiler with 1I d=rign firing nile;:> 100

MMBI,.Ihr fUld for which AJ'-42 fm::tt;:rll are el\JTen\1y being Il$OO to (l$limm the baseli...e NO. ~ions_ '
APPENDIXC

LIST OF CITGO HEATERS AND BOILERS

INFORMATION REDACTED AS CONFlDENTlAL BUSINESS INFORMATiON

. Prc:rio\IS1y used A~-42, Sth ed.

(31911).Tw1e 1.4-2 ([adar

=O.214351·lb.lMMBm). 10110101

mack Icstill& by ARl resulted In

4308-1 325.0 181_7 1.98.9 183.9 201.3 Ikdaeled

'''''''''' cumnt r~or.

Based on 101912000 nack test by

1Illl-IA 3.22.0 250.0 261.1 m.2 2119.6 """""" RedActed AI"

Dued·01\ 101912000 ~tack test by

lIIB-IB 322.0 234.2- 2S0,Z 259.8 217.'.5 Redacted Redacted ARJ

Previl;)\l!;Jy used AP-42. 5th at

(3f5l1l). Tableo 1.4--2 (tal:tar=

O.274511b./MMBtu), 9f6l0t !>(flC:k

terting by AJU resul~ irl C\ltI"dll

431B-19 149,<t 3n 39.0 11&.8 122-6 Ri:dacteod ."""'.. factOr.

43IB-Repl;u;:=lllRI Rep!nee(\'ll';llt b 431B-19 in 2002..

Des!~ed fur O.061b_ NOitMMBtu.

249_0 0.0 0.0 0.0 0.0 Redal:ted Redacted

41Z2198 'laCk test .. 0.161

1b/MMBtl:l. ULNB imtlIIIed MaJ-ch

'00. EF '" O.06lb1MMBtu (C!it).

10/1912000 MllCk (¢Sf 'by ARI

Il1B,2 219_8 104.& 38_5 148.6 14",9 """'too ."""'.. showed EF= 0.036 lb./MMBtu.

116B·l 125.6 103.il 104.] 863 86.6

''''''''' '"",too AP-' Sthcd 3/98 TDbleo 1.4-2

1238-.2 121.2 91.9 104.4 76.4 86.8 ''''''''' ."""" AP"42 5th cd. 3/98) rltble 1.4-2

112B·I; 021 0.0 0.0 0.0 0.0 Redllct.ed . Redacted AP-42 5th cd. ]{!l Table 1,4-2-

116B-2 106.9 129.2 104.0 107.5 86.5 Redae~'" Rt:dacted AP-42 5th cd_ 3198 Tabk: IA-2

PennitBuisisO.16JJ:>,IMMDtll- AP

42, 5th cd, (31911), Table 1.4-2 if

109:B~62 103.0 37.6 649 5n 92,6 Redac!ed """"",, 0.098039.

118:8-1 93.11 18.9 '" 440 5t.7 ~8Cled ReWed AP-42 5th ed. 3/98 Tabk 1.4.2

113B-1 . 88,8 16.38 16.1 7L9 70.8 ....... Redilcto:d " ;"d SEP. 9/97 staclc. ~I

1l3B-2 lrl!.8 15.11 15,6 69.5 68.5 "'''''''.. R~dact~d Ponci 9f97 5taeJ.; l~ ()f 1136-1

113B-3 88.8 26.8 27.4 71.7 73.2 .."""'" Redacted P=nit. 10/85 sw:k tef;.t results

125Bn-2· S:l.J 40.4 37,0 94".0 8<5.2 :R~dacted Redacted AP-42 5th ed. 3/98 •nble L4_2

125B-1 69.3 31.6 13,2 73.5 30,8 Ralaeted ,"""'.. AP·42 5th.,;'l. 31!j.8 TlIble 1.4-2

1238-3, 55.3 9.9 10,2 23.2 23.8 Redacted Redacted AP-42 5th ed_ 3f98 Table 1.4-2

-123J:J-1 45_6 79 9.9 18,3 23,0- ."""', """"".. AP·42 SIb~. 3198 •Table 1.4-2

I23B~5 . 42.0 12,8 12,2 29.9 1-IIA ."""'.. Redal:tcd Al'·42 Sth cd. 31911 Table 1.4-2 ......:.,
ArPENDIXC

LIST Of CITGQ HEATERS AND, BOILERS

.INFORMATION REDACTED AS CONFIDENTIAL BUSiNESS I~FORMAnON

."t_ '''' 59.' 47.3 173.\1 111,4 .","'.. """"'" NOxCEM

BMtPbmt 311.8 94.' IOH 154.1 111.9 .,"""" """"'" AP-42

EletPlanl 120 ~9.3 ~1I.6 Il8 116J """',.. .""''''' StB(;k Test 5199

East Plant '" 82.6 99.4 99_2 119.5 .""".. Rcdaete<l AP·42 EM'''' \21.7 80_9 88.9 97.2 IOU .""".. Rodactcd AP·42

&sf. P[;ml 222 16.1 H.S !ilS.9 108.3

.""".. .""".. NOx IOOdel

Plant II. 403

4.... n.l lOlA """"'" ._.. AJ>·42

I!au:Planl 200.6 41.9 43.5 79.S 78.2 ."""'" ."""'" NOxJmdcl

EastPl;mt 252.4 120.7 ;',32.] J96.a ."""'" .""".. AP-42 NlIi~l

EMt»liUlt 4B 19.4 19.2 44.2 43.9 ........ Rod""'" AP-42

EllStplltllt 41.6 U.2 12.1 30.1 29 RedBC1ed ."""'" AP-42

flllllt 164.3 0.0 0.0 0,.0- 0.0

""""'" Redacted AP-42 ""'- 400 130.4 U2.2 391.6 397.1 Rlida.cted ."""'" Stack TI.'.lII 5199

li1l!ltPllint 52,' to.S ,., 23.9 15.8 ."""'" """'t'" AP-42

Basi Plant 5-2.8 10.1 ...

" 16.3 ...,,,,,,, Redac~ed AP-42

WatPlIlllt 2906 45.0 47.s 205.4m.• ."""', ."""', NOxmodel

Westrhlnf 144.8 101,4 71.6 121.4 116,11: R"","" ~, AP-42

Westp\ant. 132.7 511:.2 62.1 94.9 10L2 Redacted' Redacted AP-42

Westplanl 76.6 32.6 31.8 74.4 72.7 RcdaCl.cd ~da.l:t.ed AP-42

We.rtPlam 82.3 27.9 2!'J.4 67.7 71.::i R"""'" "''''''''' Swelt Te$t 1/15198'

westplatlt 98'.9 25.7 21.8 ::i0.2 42_:5 Redacted Redacr.ed Slack Tll$l 3126/84 W ..." 98.9 21.6 20.3 46 4M, hdiil:ted Redacted Stack 'fest 3/22184

Wm: Plant 411.2 19.4 20.9 ...4 41.7 """''''' """"'" AP-42

Wen l1ant 98.9 l1,2- ".4 39.3 39,R """",' Redack:d AP-42

Wes.t Plant 49_9 1~.9 13.7 ".2 31.3 "'''''''' ~Ied AP-42

WmPl:mt 62 7.5

- 7.7 2.~ 27.1 R""'Iod Redacted SllICkTCllt 1'16I9~

'x,..",,',: I.~'

."""'" AP-42 Nat.t

"""'"" AP-<2

Rtdal:tcd AP-42
APPENDIXD

/ DETERMINING THE OPTIMIZED ADDITION RATES OF

CATALYST ADDITIVES AT THE FCCUs

I. PURPOSE

This Appendix defines a process by which CITGO shall determine for the FeCDs the

Optimized Addition Rates for Low NOX Combustion Promoters, NOX Reducing Catalyst

Additives and S02 Reducing"Additivesduring the Optimization Periods.

II. ESTABLISHING AN OPTIMIZED LOW NOX COMBUSTION PROMOtER

ADDITION RATE

A. Overview. Establishing an Optimized Low NOX Combustion Promoter Addition . .

Rate for the FCCDs is a three-step process: (1) establishing a minimum addition rate for the

conventional combustion promoter that CITGO currently uses such that the effectiveness ofthe

conventional combustion promoter is maintained (the "Minimum Conventional Combustion

Promoter Addition Rate"); (2) replacing the conventional combustion promoter with a particular

Low NOX Combustion Promoter at an addition rate that is the functional equivalent ofthe

Minimum Conventional Combustion Promoter Addition Rate (the "Initial Low NOX

Combustion Promoter Addition Rate"); and (3) increasing the addition rate up to two times the

Initial Low NOX Combustion Promoter Addition Rate ifthe Initial Low NOX Combustion

Addition Rate is not effective (the "Optimized Low NOX Combustion Promoter Addition

Rate").

B•. "Effectiveness" Determinations. The effectiveness of conventional combustion

promoter shall be detennined by the following criteria: (1) afterburn is controlled adequately

and regenerator temperature and combustion levels are adequately maintained; and

I
(2) temperature excursions are brought under control adequately. The effectiveness ofLow

NOX Combustion Promoter shall be determined by those two criteria and by whether a

measurable reduction in NOX emissions occurs.

C. Establishing the Minimum Conventional Combustion Promoter Addition Rate,

CITGO shall reduce its historical usage of conventional combustion promoters to the point that

the addition rate is the minimum necessary to retain the effectiveness ofthe conventional

combustion promoter that CITGO is using ("Minimum Conventional Combustion Promoter

Addition Rate").

D. Establishing the Initial Low NOX Combustion Promoter Addition Rate. Based

on the activity of conventional combustion promoter historically used and the activity ofthe Low

NOX combustion. promoter, CITGO shall replace conventional combustion promoter with Low

NOX Combustion Promoter at a rate that is the functional equivalent in promotion activity ofthe

Minimum Conventional Combustion Promoter Addition Rate. This functionally equivalent rate

shall be called the Initial Low NOX Combustion Promoter AdditionRate.

E. Establishing the Optimized Low NUX Combustion Promoter Addition Rate. If

the Low NOX Combustion Promoter is not effective at the Initial Low NOX Combustion

Promoter Addition Rate, CITGO shall increase, by up to two times, the Initial Low NOX

Combustion Promoter Addition Rate. If, at two times the Initial Low NOX Combustion

Promoter Addition Rate, the Low NOX Combustion Promoter is not effective, CITGO may

discontinue the use ofLow NOX Combustion Promoter.

2
III. ESTABLISHING AN OPTIMIZED NOXREDUCING CATALYST ADDITIVE

ADDITION RATE

A.· Overview. The Optimized NOXReducing Catalyst Additive Addition Rate shall be

determined by evaluating NOX emissions reductions and annualized costs at three different

addition rates.

B. The Increments. The three addition rates or "increments" shall be:

1.0 Weight % NOX Reducing Catalyst Additive

1.5 Weight % NOX Reducing Catalyst Additive

2.0 Weight % NOX Reducing Catalyst Additive

Where Weight % is ofthe total catalyst added to the FCCU.

C. The Procedure.. CITGO shall successively add NOX Reducing Catalyst Additive at

each increment set forth above. Once a steady state has been achieved at each increment,

CITGO shall evaluate the performance ofthe NOX Reducing Catalyst Additive in terms ofNOX

emissions reductions and projected annualized costs. The final Optimized NOX Reducing

Catalyst Additive Addition Rate shall occur at the addition rate where either:

(1) the FCCU meets 20 ppmvd NOX (corrected to 0% 02) on a 365-day tolling

average, in which case CITGO shall agree to accept limits of20 ppmvd NOX

(corrected to 0% 02) on a 365-day rolling average basis at the conclusion ofthe

Demonstration Period; or

(2) the total annualized cost-effectiveness ofthe NOX Reducing Catalyst Additive

used exceeds $10,000 per ton ofNOX removed as measured from an uncontrolled

baseline (as estimated based on current operating pammeters as compared to

operating parameters during the baseline period); or

(3) the Incremental NOX Reduction Factor is less than 1.8, where the Incremental

NOX Reduction Factor is defmed as:

FE, c PE,'I

CAR; - CAR;.1

PR,

where:

Pollutant (NOX) reduction rate at increment i in pounds per

day from the baseline model
PR,-t

CAR,

=

=

Pollutant (NOX) reduction rate at the increment prior to

increment i in pounds per day from the baseline model

NOX Reducing Catalyst Additive Rate at increment i in

pounds per day

NOX Reducing Catalyst Additive Rate at the increment

prior to increment i in pounds per day

Ifthe conditions of either (1), (2), or (3) above are not met at any addition rate less than 2.0

Weight % NOX Reducing Catalyst Additive, then the Optimized Addition Rate shall be 2.0

Weight % NOX Reducing Catalyst Additive.

If an additive limits the FCCU's ability to control CO emissions to below 500 ppmvd CO

at 0% 02 on an I-hour basis or 100 ppmvd CO at 0% Ox on a 365-day basis, and cannot be

reasonably compensated for by adjusting other parameters without adversely impacting

conversion (yield selectivity) or processing rales, then the additive rate shall be reduced to a

level at which the additive no longer causes such effects.

IV. ESTABLISHING AN OPTIMIZED S02 REDUCING CATALYST ADDITIVE

ADDITION RATE

A. Overview. The Optimized S02 Reducing Catalyst Additive Addition Rate shall be

determined by evaluating S02 emissions reductions and annualized costs at three different

addition rates.

B. The Increments. The three addition rates or "increments" shall be:

5.0 Weight % S02 Reducing Catalyst Additive

7.5 Weight % S02 Reducing Catalyst Additive

10.0 Weight % S02 Reducing Catalyst Additive

Where Weight % is ofthe totill catalyst added to the FCCU.

C. The Procedure. CITGO shall successively add S02 Reducing Catalyst Additive at
each increment ~et forth above. Once a steady ~tate ha~ been achieved at each increment,

CITGO shall evaluate the performance ofthe 802 Reducing Cataly~t Additive in term~ of 802

emi~~ions reduction~. The final Optimized 802 Reducing Cataly~t Additive Addition Rate ~hall

occur at the addition rate where either:

(1) the FCCD meet~ 25 ppmvd 802 (corrected to 0% 02) on a 365-day rolling

average and 50 ppmvd 802 (corrected to 0% 02) on a 7-day rolling average, in

which ca~e CITGO ~hall agree to accept limit~ of 25 ppmvd 802 (corrected to 0%

02) on a 365-day rolling average and 50 ppmvd 802 (corrected to 0% 02) on a

7-dayrolling average at the conc1u~ion ofthe Demon~trationPeriod;

(2) the addition of 802 Reducing Cata1y~t Additive litnit~ the FCCD feed~tock

proc~~ingrate cir convemion (yield ~electivity) capability in a manner that cannot

be rea~onably compen~atedfor by the adju~tment of other parameter~, then the

maximum addition rate ~han be reduced to a level at which the additive no longer

interfere~ with the FCCD proces~ingor conver~ionrate; provided, however, that

inno ca~e, ~ha11 the maximum addition rate be le~~ than 5.0 weight %; or

(3) the Incremental 802 Pick-up Factor i~ le~~than 2.0, where the Incremental 802

Pick-up Factor i~ defined a~:

PR, - PRi.,

CAR; - CAR;.,

PR;

PR;.,

CAR;

CAR;.,

=

=

=

where:

Pollutant (802) reduction rate at increment i in ponnd~ per

day from the ba~eline model

Pollutant (802) reduction rate at the increment prior to

increment i in ponnd~ per day from thc ba~eline model

Pollutant (802) Reducing Cataly~t Additive Rate at

increment i in ponnd~ per day

Pollutant (802) Reducing Cataly~t Additive Rate at the

increment prior to increment i in pound~ per day

Ifthe condition~ of either (1), (2), or (3) above are not met at any addition rate le~~ than 10.0

weight % 802 Reducing Cataly~t Additive, then the Optimized Addition Rate ~hall be 10.0

weight % 802 Reducing Cata1y~t Additive. In no C$e ~hall the Optimized Addition Rate ~hall

5
be less than 5.0 weight % 802 Reducing Catalyst Additive.

6
APPENDIXE

NSPS SUBPART J COMPLIANCE SCHEDULE

FOR HEATERS AND BOILERS AND...STREAMS IN FUEL GAS

Plant· Unit Completion/Submittal Date

Corpus Christi East Refinery Cumene Depropanizer Off·Gas AMP 6. months after Date. ofEntry

Corpus Christi East Refmery Hydrar Stabilizer OH OffGas AMP. 6. months. after Date. ofEntry

Corpus Christi East Refinery Hydrar Stripper OffGas AMP. 6. months. after Date. ofEntry

Corpus Christi East Refmery Hydrar Hydrogen AMP 6. months after Date ofEntry

Corpus Christi East Refmery Hydrar Degassing Drum OffGaS AMP 6. months. after Date ofEntry

Corpus Christi East Refinery C4SHP DME Stripper Off Gas AMP 6. months after Date. ofEntry

Corpus Christi East Refmery Tanks. 140 and 141 Vents AMP. 6. months after Date. ofEntry

Corpus Christi East Refinery C5 Merox DisulfideSeparator AMP 6. months after Date. ofEntry

Spent Air Vent

Corpus Christi East Refinery Unibon Recycle Hydrogen Purge AMP 6. months after Date. of Entry

Corpus Christi West Refinery Merox Disulfide. Separator Spent AMP 6. months after Date. ofEntry

Air Vent

Lemont Refinery 114B-l July 2005

Lemont Refinery 114B-2 July 2005

Lemont Refinery 114B-3 July 2005

Lemont Refinery U5B-I July 2005

. Lemont Refinery 115B-2 July 2005

Lemont Refmery 116.B-I July 2005

Lemont Refinery 116.B-2 July 2005 . .

Lemont Refmery 116.B-3 July 2005

Lemont Refinery 116.B-4 July 2005

Lemont Refinery 1I8B-l July 2005
Plant . Unit Completion/Submittal Date

Lemont Refinery 118B-5l July 2005

Lemont Refinery l22B-l July 2005

Lemont Refinery l22B-2 July 2005

Lemont Refinery 123B-I October 2005

Lemont Refinery 123B-2 October 2005

Lemont Refinery 123B-3 . October 2005

Lemont Refinery l23B-4 October 2005

Lemont Refinery 123B-5 October 2005

Lemont Refmery 125B-I. July 2005 ..

LerilOnl Refinery 125B-2 July 2005

Lake. Charles Refmery C-Refonner B-501 March 2005

Lake Charles Refinery C-Reformer B-502 March 2005

Lake Charles Refinery C-Refonner B-503 March 2005

Lake Charles Refinery C-Refonner B-504 March 2005

Lake Charles Refmery C-Refonner B-505 March 2005

Lake Charles. Refinery C-Reformer B-506 . March2005

Lake Charles Refinery Boilet BF-l September 2005

Lake Charles Refinery Boiler BF-2 September 2005

Lake Charles Refinery Boiler BF-3 September 2005

LakeCharles Refinery Boiler BF-4 September 2005

Lake Charles Refmery Boilcr BF-5 September 2005

Lake Charles Refinery Duo-Sol Furnace N-2A September 2005

Lake Charles Refmery Duo-Sol Furnace N-2B September 2005

Lake. Charles Refinery Duo-Sol Furnace. N-2C September 2005

Lake. Charles Refmery Duo-Sol Furnace S-I September 2005

Lake Charles Refincry Duo-:';ol Furnace S-2 September 2005

Lake Charles Refinery Duo-Sol Furnace P-2 September 2005

Lake Charles Refinery Furfural Furnace BA-I,2A&2B September 2005

Lake Charles. Refinery Furfural Furnace BA-3 September 2005

Lake Charles Refinery MEK-I FurnaceBAcl &2 September 2005

.Lake Charles Refincry MEK-2 Furnace BA-l & 2 September 2005

Lake Charles Refinery MEK-2 Furnace. BA-3 September 2005

Lake Charles Refinery Lube Vaeeum BA-I AMP by February 2010

Lake Charles Refinery Lube Vacuum BA-lOI AMP by September 20 II

Lake Charles Refinery TAME Hydrogen Unit Shutdown.. Ifrestarted, AMP

by startup date.
Plant Unit Completion/Submittal Date

Lake Charles Refinery

C Dock Butane. Unloading·

AMP by December 2005
APPENDIXF

FUEL GAS COMBUSTION DEVICES COMPLIANCE. SCHEDULE

Plant Unit Stream AMP. Submittal Date

Corpus Christi East Refinery Marine. EmissionControl 6. months. after Date ofEntry

Corpus Christi East Refinery NESHAP FF Incinerator . 6. months. after Date ofEntry

Corpus. Christi East Refinery CPl Vapor Combustor 6. months. after Date ofEntry

Lemont Refinery 333B-401. Barge Dock Benzene 6. months. after Date ofEntry

Vapor Combustor .

Lemont Refinery 335B-l Fuels Rack Emission 6. months after Date. ofEntry

Control

Lake Charles Refinery B-700 WWT Combustor June 2007 .

Lake Charles Refinery B-13 A-Dock Vapor Combustor December 2005

Lake Charles Refinery B-14 B&C Dock Vapor Combustor December 2005

Lake Charles Refinery B-15 D Dock Vapor Combustor December 2005

Lake Charles Refinery VCU-OI Fuel Loading Rack December 2005

Combustor

PaUlsboro Refinery Marine Emission Combustor August200S
APPENDIXG

NSPS SUBPART 1. COMPLIANCE. SCHEDULE FOR

NSPS FLARING DEVICES

Plant Flare Completion

/Submittal Date

Corpus Christi East Refinerv Cumene.Flare December 2007

Comus Christi East Refmerv Fluor Flare December 2007

Corpus Christi East Refinery Acid Gas Flare

AMP by 6. months

after Date ofEntry

Corpus Christi East Refmery SWSFlare

AMP by 6. months

after Date ofEntry

Corpus Christi West Refmery Flare (*) December 2006.

Corpus Christi West Refmery Acid Gas Flare AMP by 6. months

after Date of Entry

Corpus Christi West Refinery SWS Flare AMP by 6. months

after Date. ofEntrv

Lemont Refmerv 844C-I. North Plant Flare Date.ofEntrv

Lemont Refmery 844C-2 South Plant Block 2 Date ofEntry

Flare (*)

. Lemont Refmery 844C-3 South Plant Block 3 Date ofEntry

Flare (*)

Lemont Refinerv 844C-4 Needle Coker Flare(*) Date ofEntrv

Lemont Refinery 844C-5 Alky Flare AMP by 6. months

after Date. ofEntrv

Lake. Charles Refmery 327B-ll Flare C-Ref/CK 11(*) September 2010

Lake Charles Refinery 320B-12 Flare Unicracker February 2010

Lake Charles Refinery 399B-I6. Flare. CFH December 2008

Lake Charles Refmery 36.0CB-70I. (CB-1I) PFU .AMP by December

2005

- Lake Charles. Refmery CAIOOI CLAW AMP by June 2007

Lake Charles Refinery B-I04 COPITIERII December 2011

Paulsboro Refmery Flare AMP by August

2006.
(*) Identifies flares for which CITGO will install equipment to minimize

hydrocarbon flaring from coker blowdown cycles under Paragraph 94.
APPENDIXH

PREDICTIVE EMISSIONS MONITORING SYSTEMS FOR HEATERS

AND BOILERS WITH CAPACITIES BETWEEN 150 AND 100 mmBTUIHR

A Predictive Emissions Monitoring Systems ("PEMS") is a mathematical model that

predicts the gas concentration ofNOx in the stack based on a set of operating data. Consistent

with the CEMS data frequency requirements of40 C.F.R. Part 60, the PEMS shall calculate a

pound per million BTU value at least once every 15 minutes, and all ofthe data produced in a

calendar hour shall be averaged to produce a calendar hourly average value in pounds per million

BTU.

The types of information needed for a PEMS are described below. The list of

instruments and data sources shown below represent an ideal case. However at a minimum, each

PEMS shall include continuous monitoring for at least items 3-5 below. COPC will identify and

use existing instruments and refinery data sources to provide sufficient data for the development

and implementation ofthe PEMS.

Instrumentation:

1. Absolute Humidity reading (one instrument per refmery, if available)

2. Fuel Density, Composition and/or specific gravity - On line readings (it may be

possible ifthe fuel gas does not vary widely, that a grab sample and analysis may

be substituted)

3. Fuel flow rate

4. Firebox temperature

5. Percent excess oxygen

I
6. Airflow to the firebox (ifknown or possibly estimated)

7. Process variable data c steam flow rate, temperature and pressure - process stream

flow rate, temperature & pressure, etc.

Computers & Software:

Relevant data will be collected and stored electronically, using computers and software.

The hardware and software specifications will be specified in the source-specific PEMS.

Calibration and Setup:

I. Data will be collected for a period of7 to 10 days of all the data that is to be used

to construct the mathematical model. The data will be collected over an operating

range that represents 80% to 100% ofthe normal operating range ofthe

heater/boiler;

2. A "Validation" analysis shall be conducted to make sure the system is collecting

data properly;

3. Stack Testing to develop the actual emissions data for comparison to the collected

parameter data; and

4. Development ofthe mathematical models and installation ofthe model into the

computer.

The elements of a monitorine protocol for a PEMS will include:

I. Applicability

a. IdentifY source name, location, and emission unit number(s);

b. Provide expected dates ofmonitor compliance demonstration testing.

2. Source Description

2
a. Provide a simplified block flow diagram with parameter monitoring points

and emission sampling points identified (e.g., sampling ports in the stack);

b. Provide a discussion ofprocess or equipment operations that are known to

significantly affect emissions or monitoring procedures (e.g., batch

operations, plant schedules, product changes).

3. Control Equipment Description

a. Provide a simplified block flow diagram with parameter monitoring points

and emission sampling points identified (e.g., sampling ports in the stack);

b. List monitored operating parameters and normal operating ranges;

c. Provide a discussion of operating procedures that are known to

significantly affect emissions (e.g., catalytic bed replacement schedules).·

4. . Monitoring System Design

a. Install, calibrate, operate, and maintain a continuous PEMS;

b. Provide a general description ofthe software and hardware components of

the PEMS; including manufacturer, type of computer, name(s) ofsoftware

product(s), monitoring technique (e.g., method of emission correlation),

Manufacturer literature and other similar information shall also be

submitted, as appropriate;

c. List all elements used in the PEMS to be measured (e.g., pollutant(s), other

exhaust constituent(s) such as O2 for correction purposes, process

parameter(s), and/or emission control device parameter(s»);

3
d. List all measurement orsampling locations (e.g., vent or stack location,

process parameter measurement location, fuel sampling location, work

stations);

e. Provide a simplified block flow diagram ofthe monitoring system

overlaying process or control device diagram (could be included in Source·

Description and Control Equipment Description);

f. Provide a description ofsensors and analytical devices (e.g., thermocouple

for temperature, pressure diaphragm for flow rate);

g; . Provide a description ofthe data acquisition and handling system

operation including sample calculations (e.g., parameters to be recorded;

frequency ofmeasurement, data averaging time, reporting units, recording .

process);

h. Provide checklists, data sheets, and report format as necessary for

compliance determination (e.g., forms for record keeping).

5. Support Testing and Data for Protocol Design

a. Provide a description offield and/or laboratory testing conducted in

developing the correlation (e.g., measurement interference check,

parameter/emission correlation test plan, instrument range calibrations);

b. .Provide graphs showing the correlation, and supporting data (e.g.,

correlation test results, predicted versus measured plots, sensitivity plots,

computer modeling development data).

6. Initial Verification Test Procedures

4
a. Perfonn an initial relative accuracy test (RA test) to verify the perfonnance

ofthe PEMS for the equipment's operating range. The PEMS must meet

the relative accuracy requirement ofthe applicable Perfonnance

Specification in 40 C.F.R. Part 60, AppendixB. The test shall utilize the

test methods of 40 CFR Part 60, Appendix A;

. b. Identify the most significant independently modifiable parameter affecting

the emissions. Within the limits ofsafe unit operation, and typical ofthe

anticipated range ofoperation, test the selected parameter for three RA test

data sets at the low range, three at the nonnal operating range and three at

the high operating range ofthat parameter, for a total ofnine RA test data

sets: .Each RA test dataset should be between 21 and 60 minutes in

duration;

c. Maintain a log or sampling report for each required stack test listing the

emission rate;

d. Demonstrate the ability ofthe PEMS to detect excessive sensor failure

modes that would adversely affect PEMS emission detennination. These

failure modes include gross sensor failure or sensor drift;

.e. Demonstrate the ability to detect sensor failures that would cause the

.PEMS emissions determination to drift s\gnificantly from the original

PEMSvalue;

f. The PEMS may use calculated sensor values based upon the mathematical

relationships established with the other sensors used in the PEMS.

5
Establish and demonstrate the number and combination of calculated

sensor values which would cause PEMS emission determination to drift

significantly from the original PEMS value.

7. Quality Assurance Plan

a. Provide a list ofthe input parameters to the PEMS (e.g., transducers, sensors,

gas chromatograph, periodic laboratory analysis), and a description ofthe

sensor validation procedure (e.g., manual or automatic check);

b. Provide a description ofroutine control checks to be performed during

operating periods (e.g., preventive maintenance schedule, daily manual or

automatic sensor drift determinations, periodic instrument calibrations);

c. Provide minimum data availability requirements and procedures for supplying

missing data (including specifications for equipment outages for QAlQC

checks);

d. List corrective action triggers (e.g., response time deterioration limit on

pressure sensor, use ofstatistical process control (SPC) determinations of

problems, sensor validation alarms);

e. List trouble-shooting procedures and potential corrective actions;

f. Provide an inventory ofreplacement and repair supplies for the sensors;

g. SpecifY, for each input parameter to the PEMS, the drift criteria for excessive

error (e.g., the drift limit of each input sensorthat would cause the pEMS to

exceed relative accuracy requirements);

h. Conduct a quarterly electronic data accuracy assessment tests ofthe PEMS;

6
1. Conduct semiannual RA tests ofthe PEMS. Annual RA tests may be

conducted ifthe most recent RAtest result is less than or equal to 7.5%.

Identify the most significant independently modifiable parameter affecting the

emissions. Within the limits ofsafe unit operation and typical ofthe

anticipated range ofoperation, test the selected parameter for three RA test

data pairs at the low range, three at the nonnal operating range, and three at

the high operating range ofthat parameter for a total ofnine RA test data sets.

Each RA test data set should be between 21 and 60 minutes in duration.

8. PEMS Tuning

a. Perfonn tuning ofthe PEMS provided that the fundamental mathematical

relationships in the PEMS model are not changed.

b. Perform tuning ofthe PEMS in case ofsensor recaJibration or sensor

replacement provided that the fimdamental mathematical relationships in the

PEMS model are not changed.

7
DATED; DECEMBER 7, i999; SIGNED; JOHN B. RASNIC

Phillip E. Guillemette .

Director ofEnviton:irie:ntaIMfairs .

KochRefining C9IhPllllY LP . . P.O. Box' 64596

Saint Paul, Minnesota 55164-0596.

DearMr. Guillemette: .

This is in response to your August 14,1998, and January 6, 1999,letteis to Administrator

CarolBrowner, and your July 9, 1999, supplemental submittal. Please find enclosed, our December 2,

1999, response addressing applicability issues ofllie New Source Performance Standards NSPS Subpart

.J to refinery fuelgasesand fuel gas combustion devices. Also enclosed is our genirra1 "Alternative

Monitoring Plan for NSPS Subpart J Refinery Fuel Gases': addressing your request for approval of an

alternative plan to continuous monitoring ofrefinery fuel gases..

while yourJuly 9, 1999, supplemental submittal and the September 3.,1999, letter from

Mr. James Mahoney; your Senior Vice President ofOperations, request that we approve a proposed flare

management policy, we are unable to do so at this time. We continue to.review the issue. We appreciate

your willingness to meet with us to answetquestionson these difficult issues, and hope we can work out

a resolution that provides cl:uification for what the Ertvironmental Protection Ag~cyconsiders to be

."good air pollution control practice for minimizing emissions" un.der NSPS SubpartJ for flate systems;

· As we continue to work on an agreement for a flaring policy, based on oUr past discussions with .

representatives from Koch, we believe that many ofyont current and planned practices to minimize ..

· flaring events (assuming proper documentation ofthose practices) are elements of"good air pollution

control" and provide adequate protection ofhmnan health and the environment. . .

I trust that the enclosed information will be useful to you. Jfyou have any questions, please feel

free to contact Tom Rippofmy staff at (202) 564-7003..

Sincerely,

s/JOHN B. RASNIC

'. John B. Rasnic, Director

Manufacturing, Energy and Transportation Division

. Office ofCompliance

Enclosures .

· cc: James Mahoney, Koch

Preparedby:t.ripp:mlw:12/3/99:2:30 PM:2pp:564--7003:2223A:kochco-Lwpd
DATED: DECEMBER 2,1999; SIGNED: KEN GIGUELLO for

Phillip E. Guillemette

Director ofEnviromnental Affairs

·Koch Reflniilg Company. LP

P.O. Box 64596 .

. . Saint Pflul, MinneSot;l. 55164-0596

Dear Mr. Guillemette: .

Thisis in response to your August 14. i998, and January 6, 1999, letters. to Administrator

Browner. Koch Refining Company LP.. (Koch) seeks. clarification from the. Enviromnental

Protection Agency (EPA)regarding the· applicability ofNew SourCl: Performance Standard

Subpart J (NSPS. SubpartJ) to: fuel gas. combustion deviceii (FGCDs): and fuel gases; "process

upset" conditions; and to'certain ideIitifiedgas streams.at itS RosemouiIt, Minnesota refinery..

. Although you requested thatEPA review and revise NSPS Subpart J in your. August 14, 1998,

.. letter, it is ow: current understanding that you are not requesting that NSPS. SUbpart He

reviewed/revised as. part of a response. to yow: letters. .

.You write that NSPS. Subpart J is, in part, intended to neduce sulfur.emissions from gases

generated as a byproduct ofthe. refining processthat are. used as. fuel in a re01ulery's heaters and

boilers••To accomplish this, NSPS Subpart J imposes monitoring requirements and limits. for

certain fuel gas. streams. that are. combusted in relmery FGCDs.. You assert that "fuel gas", and.

"FGCD" are. vaguely defined, and it is. often unclear as to what types ofunits.. and streams are

covered under the. standard.. Wedisagfee with yoUr characterization that "fuel gas" and

"FGCD" are. not clearly defined. The. definitions are purposeliilly broad, and the. exemptions are

spedfic.· We also disagree with your characterizations that the rule is limited to only refinery

generated.gases burned as fuel in relmeiy process. heaters and boilers. The rule. clearly inciudes

routine. combustion ofrefinery. gases in flares and other waste. gas dispos<tl devices.

In youdetter, you develop a position on exemptions from NSPS. Subpart J baSed 'onthe

conunendable use ofa flare gas recovery system. You describe. your refinery flare. gasrecovery

system, and state that:

.•• [a]s designed, the flare gas recovery systemhassuffident

capacity to recover gases that are routed to. the. system under

n<innal operating conditions.. •• '. Under process upset

conditions. the flare gas recovery system's capacity may be

exceeded and excess gases are routed to the flare for combustion

·Preparedby:tnpp:miw:9/20/99:2:14 PM:pp:564-7003:2223A:kochS.wpd
2 . .

Because you believe that yourrefinery gases areroured to the flare only as a result ofprocess

upsets, you believe that the flaring ofthose gases are not subject to NSPS Subpart J; We do:not .

, agree that all ofthe events. you describe as "process upset conditions" ID€;etthe. regulatciiy .

definition ofmalfunction or the interpretation of''upset'', and, therefore, may not be qualifiedfor

exemption from NSPS Subpart J. In addition, we note that any. malfunction or upset involving

combustion ofprocess upset gas in an NSPS-affected FGCD would stillbe.subject to NSPS

Subpart A (General Provisions) §60.11(jl) obligations.

Your August 14, 1998, letter focuses, on three areas:

How NSPS Subpart J appliesto FGCDs andJuelgases;

• How the. process upset gas exemption applies;

• How NSPSSubpart J applies to the. 26miscellaneous'gas.streaJl1s.

. Our respons~ addresses. those issues in order.

How NSPS SubpartJ Appliesto FGCDs. and Fuel Gases

The. provisions ofNSPS SUbpart J are, in part, applicable to affected FGCDs. To control'

stilfuroxide(SOJ emissions. to the..atmosphere .fromaffected FGCDs, NSPS Subpart J

§60.l 04(a)(l) limits. the. amount ofhydrogen sulfide (H2S) allowed in the fuel gas burned in those

devices. Except for fuel gas. released to. a flare, as a result ofreliefvalve leakage or other

emergency malfunctions, you must not bum fuel gas containing greater than 230 mgldscm ofH2S

in any affected FGCD. Additionally, the combustion ofa process upset gasin a FGCD is. exempt

from the HiS limit... The combustion/flaring ofthose exempted gases in an NSPS-affected FGCD

isstill subjectto §60.11(d) ofthe. General Provisions'as described later. .

NSPS Subpart J§60.l 04(a)(1) applies to gas combustion deVices, uthe following are. true: .'

1).The gas is a "fuel gas" [§60.101(d)]: .

• • • any gas which is. generated at a petroleum refinery and which .

is combusted. ' Fuel gas also includes natural gas when the. natural

gasis combined and combusted in any proportion with a gas

generated at a refinery. Fuel gas.does. not include gases generated

'by catalytic. cracking unit catalyst regenerators and fluid coking

burners. . . .

2) The fuel gas is combusted in a "FGCD" [§60.101(g)]:
3

any equipment, such as. procesS heaters, boilers. and flares. used to

combust fuel gas, except facilities in'whichgases are~ombustedto , .

produce sulfur orsulfuric, acid.

3) .The FGCD is an "affected FGCD". An affectedFGCD is any FGCD for which

construction or modification coinmenced after June 11, 1973.§60.1OO(b)

, ' '

Additionally, when deteImining the. applicability ofNSPS, SubpartJ to anyparticular

, combination of combustion device and gas stream, the following general concepts apply:

• Unl.ike the definition ofprocess upset gas, the definition offuel.gas does not requiTe, that

the gas be generated by a, "refinery procesS unit", it must·merely be generated at the

refinery; ,

• There. is no general exemption for gas streams with low sulfur content;

• There is no general exemption for low volume or intermittent gas streams;

• A FGCD need not genemte a product to, be regulated. Flares. do not generate. products or

energy that are, recovered for use, but they are clearly FGCDs since they are specifically

named in the definition. "

Your refinery flares (constructed after June 11, 1973) are affected FGCDs as defined by,

NSPS SubpartJ. When the capacity ofyour refinery flare, gas recovery system is exceeded as

the result of normal operations'(not malfunctioIiS), NSPS Subpart J for FGCDs applies, to those

NSPS refinery flares.

For any fuel gasstream sUbject to NSPSSubpart J;' youmay petition for alternative

monitoring underthe General Provisions at §60.13(i). For EPA to approve alternative

rnonitoring, you mnst submit sufficient information to show that your alternativemonitoring plan

,wIll yield similarI:esultsto the required moiritoring under NSPS Subpart J. .

How the Process Upset Gas Exemption Applies

As. mentioned above, §60.104(a)(I) exempts the combustion ina FGCDofprocess upset'

,gases and exempts the, combustion in a flare, offuel gas that is released to the flare as a result of

reliefvalve leakage or other emergency malfunction. Not all ofthe events you describe as "

"process upset conditions". meet the. qualifications for, exemption from NSPS SubpartJ.

Therefore; the 26 gas streams do notreceive a blanket exemption from the. regulation. Some, of ,

the gases generated underKoch's described events are. not gases generated as. a result ofupsets,

but are generated as a result ofnormal operations.. Additionally, not all ofyoUI: process upsets
4

result in flaring.

Process upset gas is defmed at §60.l01(e) as:

.•.• imy gas generated by a petroleum refmery process unit as a

result ofstart-up, shut-down,.upset or malfunctioh.

.Malfunction is. defined in the. General Provisions at §60.2as:

•. ' ; any sudden, infrequent, and not reasonably preventable

f;1i1ure ofair pollution control equipment, process equipment, or. a

process to operate hi a normal or usual manner. Failures 1hatare .

caused in part by poor mainten<U!ce. or careleSS. operation are not

malfunctions.

Upset is. nQt defined in NSPS Subpart J orin the. Generai Provisions. 'However, hi EPA's

1973 Backgrol'ind IDformation for Proposed NeW: Sourcel'erformanceStaildards for Petroleum

Refineries,PI~~22I 736. (1973. BID), page 25,. EPA writes. that the. proposed standard doe& not

apply to extraordinary situiitions, such as emergency gas. releases. In EPA's 1974Background

Information for New Source PerformanceStandard& for Petroleum Refineries, PB·23 1601 .'

'(1974BID), page 20, EPA further explained the.statement futhe1973.BlD that:

Becaus~ the. frequencY ofproces& upsets and thevolumes of gase&

which must be. disposedofare highly unpredictable, it is. not

feasible to. design or operate a gas treating facility that would

preventsulfur dioxide emiliSions from flare systemS in these

situations... A facility designed to. remove hydrogen sulfide. from all

ptoces&upset gases prior to combustionwollld have to be designed

to. handle. the ilDmediate release ofgases from all proCl~Ss writs if

each unit experienced the worst possible upset or malfunction at

the same. time.. The cost ofsuch a large gastreatment facility '.,

would impose. a severe and'unreasonable. economic: bUrdenupon a.

.refmery;

From the language hi the I974 BID, it is. clear th~t a facility .does not have. to be. designed

to.-treat and dispose of gases produced in a woist Cllse sceriario at a facility. However, it i& clear

.that more frequent and predicable process events (which Koch would describe as ''upsets'', but

which do not meet the interpretation for llpsets) are.subject to. the. standard, and that it is not·

=reasonable. for the. faciIityto bave. sUffiCient capacitY tohandIe these routine process. events.

. In a similar issue, EPA successfully argued i~ a cas~ before an Administrative Law Judge .

(ALJ);.thatthe term "syStem bre~down" (which is used in 40 CFR §60.13(e), but is Undefined)

was akin to a malfunction as defined in the Gerienil Provisions at §60.2..In the March 9, 1995,

decision (see Enclosure. I), the ALl wrote that: .
5

While the actual words. "system breakdown" do not appear here

[in the. defInition ofmalfunctionJ, this. definition incorponites

analogous phrases.. • • • Thus using the defmitioiwfmal:!iiD.ction

. as a guide, a system breakdown would constitute somethingsudden

and unforeseen •. , , • Accordingly, it is. found that a system

breakdown requires there to be. an occurrence. which is umorseen, .

sudden and unavoidable.

The same logic. that went into the. ALl's. decision applies here; the exemption was

intended for infrequent and unpredictable. events, thus, ''upset'' is analogous to malfunctiOli.

. Therefore, the malfunction/upset exemption under NSPS Subpart J applies only to .

extraordinary, infrequent, and not reasonably preventable upsets. Additionally, the

.malfunctiortlupset·callllot be the. result ofpoor maintenance or careless operations.. Once you

determine the cause ofa malfunction/upset, you should workto correct the root cause in order to

prevent it from occurring again. Each time that is done,nlalfunctionslupsets should become less

frequent.. . .

Process ilpset gases exempted under NSPS SubpartJ are. still required to comply>Vith the

good air pollution control practices as. required under §60.ll(d).

At all times, including periods. ofstart-up, shut-down, and

malfunction, owners and operators.shall, to the extent practicable,

maintain and operate any affected facility mcluding associated air

pollution control equipmentin a manner consistentwith good air .

.pollution control practice for minimizing emissions. . ., .•.

. How NSPS Subpart J Applies to the 26 Specific Gas Streams •.

(Unless stated otherwise, itis assumed that all ofthe following gas. streams.are generated .

"af' the refInery and are combtisted.. The. general coricepts:identified on page 2 ofthisletter

should be incorporated into. EPA's.responses when those concepts address the positioil(s)

presented by Koch fOf a particul~ gas stream.)
6

A. Commercial Grade Natural Gas

Kqch's position:

NSPS Subpart J Is inapplicable because. tJUs stream is inher~nt1y low in sulfur and has no • .

po.tential for signIficant sulfur dioxide emissions. '

.EPA's.responSe:

Refinery generated, commercial grade; natural gas is subject to. NSPSSubpart J ifit is

combustedin an .affectedFGCD.· .

.R:efmery generated, commercial grade, natural gas meets. the definition offuel gas..

Note:.. Commercial grade natural gas purchased from an outside.source iSnot generated

"at" the. refmerya6d is. riot, itself, a fuel gas.. EPA has previously detertnined that an '

NSPS 3ffected gas combustion device is not required to, haye an instailed SO.or H.S

CEMifthat device has been confirnied to not burnrefinery fuel gas, in any mixtUre. and

at anytime (e.g:, To. be. exempt frc;mi NSPSSubpartJ, a combustion device. must.i>ei1red

only with purchased gas from a dedicated line, andmust be, isolated fromthe.refin~'s

fuelgas system)... See the December 4, 1991, memorandum from Jolm B. Ramie..'

(Enclosure, 2) .

B. Hydrogen Plant PSA Purge Gas

.Ko~'s position:

. . NSPS Sl,lbpart J is inapplil;able because, this stream is inherently loW: in sulfur,and haS no

potentialforsignificant sulfur dioxide emissions, '

EPA'sresponse:

. ~. . . . ., , . .

The COinbustiouofHydrogen PlautPSAPurge gas'hi the #2 HydrilgenPlant process

"heater is. subject to NSPS Subpart J, . .

1)Hydrogen Plaut PSA Purge. Gas ~eetsthe definitio.\l offuelgas...

2)The Hydrogen purge gas is burned in the #2 Hydrogen Pillrit process heater. The.#2

.HydrogenPIant process heatermeets th.e definition ofFGCD. : .

3) The #2 Hydrogen Plant process heateris an "affected'.' FGCD.

C. Commercial Grade Propane.(LPG)
7

Koch's position:

NSPS Subpart J isinapplicable. because. this·stream is. inherently low in sulfur and has: no

potential for significant sulfur dioxide emissions.

EPA'sresponse:

Refinery generated, commercial grade, propane gasissubject to NSPS Subpart J ifitis

combustedin.an affected FGCD.

Refinery. generated, commercial grade, propane. gas meetsthe. de.finition offuel gas..

Note: COnunercial grade propane gas purchased from an outside. source is not generated

"at" the refinery 3I!d is not, itself, a fuel gas. To be exempt fromNSPS. SubpartJ, a .

combustion device. must be. fired onlywith purchased gas from a dedicated line, and must

be. isolated from the refinery's fuel gas system. .

D. Commercial:GradeHydrogen .

Koch's position:

NSPS Subpart Jisinapplicable because this. stream iii inherently low in sulfur and has no .

potential for sigllificant sulfur dioxide emissions, .

EPA's. response:

Refinery generated,conunercial grade, hydrogen issubject to NSPS. Subpart J ifit is

combusted in an affected FGCD.

Refinery generated, commercial grade, hydrogen meets the. definition offuel gas.

C~mmerciai grade hydrogen purchased from an outside souree is not generated "at" the

refinery and is not, itSelf, a fuel gas. To be exempt from NSPS. Subpart], a combustion

device must be fired only with purchased.gas from a dedicated linll, and must be. isolated

from the refinery's fuel gas system: . , . . .
8

E. .D¢layed Coker BlowdoWli

Koch's Position:

NSPS SubpartJ is inapplicablebecause this. stream falls under the Subpart J exemption··

for prOcess upset gas..

.EPA's position:

Any coker blowdown gas generated as a normal part of operations that is. directed to the

refinery flares; issilbject to NSPS Subpart J.

1) Vapor from the delayed coker blowdownprocess meets the definition offuel gas.

.Coker blowdown vapor is generated as a normal part ofoperations, and not the:

result of a process upset or malfunction. Nor is. it exempt because it is genetttted during a

"shutdown" since the. cokiog process has. not shutdown.. Rather, the streamto the cokers

is merely shifted from one cokiog drum to. another to. maintain continuous operation of

the coker imit. . .

2) .The. hydrocarbon vapors.from the. blQwdown process are. directed to your flare. gas

recovery system: When the. refinery flare. gas recovery system's capacity is exceeded,

the excess gas flared.

3) As described earlier, the refinery flares. are. affected FGCPs.

F. Rail Loading Rack Thermal Ondizer

. Koch's Position:

NSPS Subpart J is.inapplicable because. the. thermal oxidizer is not a "FGCD" su]jject to

SnbpartJ, and vapors routedlo. the. thermaloxidizer are low in sulfur and are. not a"fuel

gas" gerierated by a refinery. process.

EPA's response:

Vapor from loading rack operations is subject to NSPS Subpart Jifit is combusted in an

affected FGCD. . .

1)·Vapors from loading racks located at the.iefinery meet the definition offuel gas.

2) Although the oxidizer may be added as a control device. under the refinery MACT, it

still meets the definition ofFGCD under NSPS SubpartJ and is. subject to NSPS

Subpart J. The refinery MACT (40 CFRPart 63 Subpart CC) is designed to limit the
,

9

release. of hazardous air pollutants (HAPs) and not SO. from petroleum refineries.

· .Combustion ofthose HAPs is not the. only control option available for compliance with

the.refinery MACI. Other compliance alternatives under the refinery MACI that do not

·involve combustion will not trigger the. NSPS Subpart J requirements.

G. Soil VaporExtraction Thermal Oxidizer

.Koch's Position:

NSPS SubpartJ is. inapplicable. to this stream because. vapors. recovered from soil

remediation are. not a"fue1 gas", and thetherma) oxidizer is. not a "FGCD",

.EPA's response:

Extracted soil vapor is subject to NSPS. Subpart J ifit is combusted iuan affected FGCD.

1) VaporS extracted from the. soil within the. refinery meet the. definition offuel gas. . . .

2) The. thermal oxidizer isa FGCD since itcombustsa fuel gas.

H.Wastewater Treatment Plant Thermal Oxidizer

Koch's');'osition:

NSPS Subpart J is inapplicable because. vapors from the wastewater'treatment plant are

not a "fuel gas", andthe.then:ilal oxidizer is not a "FGCD".

EPA'Hesponse:

Vapor from the refinery's WWfP. is subject to NSPS Subpa,rt Jifit is combtisted iIi an

affected FGCD.

· '1) The refinery is operating a wastewater treatment plant (WWTP) at the refinery, The.

vapors collected from theWWTP. meet.the definition dEfue} gas.' other regulations (i.e.,

NSl'S QQQ) that may cover vapors from the WWTP do not specifically exempt the

WWTP vapors from applicability under NSPS Subpart J.

2) Although athennaloxidizermay be a control device for otherregulations (i.e" NSPS .

· QQQ), it meets the definition bfFGCD for NSPS Subpart J,
10

. .Note~ Ymit: claim that EPA's. approval ofthe State ImplementationPlan (SIP) order for

· theDakota CountylPine Bend Area ofAir Quality Control Region 131 is evidence of

· EPA's determination that NSPS Subpart J is. inapplicable to this gas stream iii not correct

In approving the SIP order, the gas strealll wasnot characterized as being combusted in

· an NSPSSubpart Japplicable fuel gas combustion deviee, and EPA was notasked to

make a detenniruition ofthe applicability ofNSPS Subpart J to, aily. gas. streams or

affected fuel gas combustion devices. Itmerely. represerits EPA's. approval ofthe State's

requirements... Additionally, EPA included language. in Amendment Three to the Findings

and Order by. Stip1.llation in paragraphsD and H indicating that the. order does notrelieve

.Koch ofthe obligatiori to. comply with all applicable laws. and regulations, and that thQse

requirements may. be.lrtore stringent The relevant pages ofAmendment Thee are .

included as Enclosure 3. . .

.I.. Merox Off~G..s (34-U~3 Thennal Oxidizer)

.. Koch's Position:

NSP$. Subpart J is inapplicable to this streain becanse the. thermal oxidizer was .

constructed prior to June 11, 1973, and has not been modified orreconstrticted.

EPA's.response:

Any fuel gas combusted in the 34-H-3 thermal oxidizeris not subject to. NSPS Subpart J

§60.1()4(a)(l) as iong as the thermal oxidizeris not modified or reconstructed. .

1) Merox caustic regenerator vent gas, vapors from spent caustic storage tanks, sour

· water flash drums, and fresh amine storage tanks. meet the definition offuel gas. .

1) .The 34-H-ltbermal oxidiz~meetsthe, definition ofFGCD:

3). Based on your statement that the. 34-H-l thermal oxidizer ~as constructed before

June I I, 1973, it.is not an "affected"I:GCn uniess it has since been.modified or

· reconstructed.

J.. CansticNelltraJizer Off-Gas

Koch's Position:.

NSPSSubpartJ is inapplicable to, the stream because. the. Co boiler was cbrurtructed prior

toJune. iI, 1971imd'has not beenmodified orreconstructed. .
11

EPA's response:.. . .

· Any gas conibustedin the. CO boileris. not subjecttQ NSPSSubpart 1 §60,1O4(a)(l) as.

long as the COboiler is not modified or reconstructed.

I) The off-gas from the spent caustic neutralizers meets the. defiirition offuel gas.

· 2). The.spent caustic off-gasis routed to the. CO boiler.. The COboiler meets. the

defiirition ofFGCD. .

.. ·3) Based on yourstatement that the. CO boiler was constructed before june!l, 1973,

and has not been modified or reconstructed, it is not an "affected" FGOD. . . '. .

K. Reformer Catalyst Regeneration Streams

Koch's-Position:

NSPS Subpart 1 is. iriapplicable because these. streams. are. inherently low in sulfur,. and

they fall under the. Subpart J exemption.for pro~ess upset gas... .

EPA's resPonse:

Any regeneration gas generated as a normalpm:t ofoperations that is directed to the .

· refinerY; flares, is subject toNSPS Subpart J.. Additionally,Jockhopper gas that is not·

directed to the refinery. flare. gas recovery systembut is. directed to. a refmery heater is .

subjectto NSPS Subpart Hffue refinery heateds anaffected FGCD, .. .

:1). Reformer catalyst regerieration gas.streams meet fue. defiirition offuel.gas.

.. Gas. produced dUring fue routine switching 0;1'reformer reactors, as described by

Koch; does normeet fue process upset gas definition because the gas is. generated as a

normalpart ofciperations~.Nor is it exempt because it is generated during a "shutdown"·.

sincefuerefon:O.er process has. notshutdown... Rather, operations merely shift from one

reactorto anofuer so that spent catalyst may be regenerated while .fue.reformer unit

~ontinuesoperation. .

· 2) Reformercatalystregeneratioll gas produced during fui: switching process is. directed

to yout flare gas recovery system or, for final lock hopper depressurization, to a refmery

· heater~ When the. refinery flare. gas recovery system's capacity is exceeded, the excess gasflared~ . .. ..

3) As. described earlier; fue refinery .flares an: affected FGCDs.

. L. Vacuum Unit Off-Gas
12

Koch's Position:

NSPSSubpllrt J ii; inapplicable because this. stream fallS. underthe Subpart J exemption

for process upset gas.' , .

. .

According to your description, equipment leaks may allow airto enter tlie process

· creating a potentialfor the.formation of combustible mixtures... Un~er noimal operation,

vacumn gasesa:re routed to. the fuel gas·system.·. The. onlytime vapuum unit off-gas· ."

potentially may be. combusted in a fuel gas' combustion device. is wh6nthere has. been a

"pr(lcess upset as defined undeI' NSPS SubpartJ §60.lOl(e). .

EPA'sresponse: .

Vacuurnunit off-gasthat meets the. definition ofprQcess upset gas is. subject to NSPS . . .

Subpart A §60.11(d).•

I) VacuUm unit off-gasmeetS the defInition offuel gas.

· 2). Any gas generated by a petroleum refinery process Unit as aresult ofstart-up, shutdown, upset ormalfunction is a process upset gas.

3). Vacumn unitoff-gas generaiedduring periods ofa malfunction ofthe. vac~Um .

.distillation colurnJ: meetsthe. definition ofproclis upset gas.

. Additionally, ill. our August 10; 1999, meeting, we discussed the: effect ofshutdowns ofKoch's low pressure off-gasrecovery compressor and flare gas. recovery

compressor. .K~chhas a compressOI: system designed to recover discharges (off-gas)

from the vacuum generating equipment. The recovered off-gasis. nonnally routed to tho::

refinerY fudgas recovery system for H,Sremoval. inthe event ofan off-gas recovery

compressor shut-down, the. off-gas is routed to therefuiery flare. gas recovery system and.'

.IS. nolsent to. the flare. On]ywhen both compressors malfunction wotildthe. gas be routed

to. the flare..Ifboth compressors are. down at the same time due to'malfunctions as .

· defined under NSPS Subpart A §60:2, then the vacultDiunit off-gas would meet the •

exemption under NSPS Subpart J §1O4(a)(I) fOT other emergency malfunctions, (iff-

. gases exempted from the. eroissionrequiremeilts linderNSPS Subpart:T §60.104(a)(I) are .

. still subject toN8PS Subpart A §60.ll(d). .'
13

M. Slop Oil FlashDrum

Koch's Position:

· NSPS Subpart J is inapplicable. because this. stream falls under the SUbpart J exemption

for process upset gas;

EPA's. response:

Any. vapor from the slop oil process which is generated as a normal part ofoperations that

is. directed to the. refinery flares; is. subject to NSPS SubpartJ. .

I) In general, vapors. generated by the. slop oil process at Koch meet the definition offuel

gas.. Sending off-specification products. to the slop oil system does not qualify as. a

· process.upset.

2) When the. refinery's flare gas. recovery's system is exceeded, excess gas is. sent to. the

refim:ry's flares..Process tipsets/malfun~ons are not the onJy reasonsthat Koch'sflare

gas recovery system's capacity may be, exceeded~. The refinery'sflare gas recovery

system may he exceeded as. a result ofnormal operations (e.g:, delayed coker j)lowdown).

3) As described earlier, the refinery flares. are affected FGCDs.

N. Alkylation Unit Acid Neutralization Pit Off-Gas·

Koch's Position:

NSPS SubpartJis. inapplicable. tothis streambecause. the sulfuric acid alkylation units.is

not a "FGCD", and this. stream falls. under the SubpartJ exemption for process. upset gas.

EPA'S response:

Ifthe off-gas from the alkylation unit acid neutralization is not combusted, NSPS

SubpartI is. not applicable•. Only gases gen~ated a)ld combusted atthe refinery .

· (including purchased gas that is..mixed with fuel gas) meet the definition offuel gas.

0.· . Flare Pilot and Pnrge

Koch's. Position:

NSPS Subpart Jisinapplicable because pilot and purge gas. is not a "fuel gas", and this

stream is. inherently low in ,sulfur and has no. potential for significant sulfur dioxide .

.emissions. . .
14

EPA'sreSponse:

As. identified in your letter, EPA issued a deternlination (March 22, 1977)regarding

refinery pilot lights. We reaffirm our earlier position that NSPS. Subpart J is inapplicable

to refinery pilot lights. ',' Since a pilot light ensures that a combustien device will operate

properly, the pilot light, by itse1f,is not the combustion device.

P. Miscellaneous Process Streams Routed. to. Flare Gas, Recovery System

Koch's Position:

NSPS Subpart J is inapplicable because this. stream fulls under the. Subpart J exemption

for process upset gas. '

EPA's. response:

Any vapors from the. refinery's. miscellaneous process.,streams generated as. a normal part

of operations that is, .directed to the. refinery flares, is. subject to NSPS. Subpart J.

I) Vapors from miscellaneous processstrearnsmeet the, definition offuel gas because

they are not specifically exempted from the definition offuel gas..

2) When the.,refinery's flare gas recovery system is. exceeded, excessgas is sent to the

refinery's.flares.. Process. upsets/malfunctions are not the. only reasonsthat Koch's flare .

gas recovery system's capacity. maybe exceeded; The refinery's. flare gas recovery .

system may be exceeded as a result ofnormal operations. '

3) As described earlier, the refinery. flares are affected FGCDs.

Q. . Butane Storage Tank 517. Thermal Oxidizer

Koch's PoSitiOli:

NSPS. Subpart Jis. 4tapplicable. because this stream is not generated by a Refinery ,

process, it is inhereJitly low in sulfur,and itis subject to the. Subpart J exemption for

processupsets. To date, thethennal oxidizer has never been used.

,EPA's reSJlonse: ' .

Butanevapors generated as a resUlt ofa refrigerator system malfunction are'not subject

to NSPS Subpart J control requirements, but are subject to NSPS Subpart A §60J I(d).
15

I) Butane vapors meet the d~finmon offuel gas.

2) Ifbutane. vapors 3wfonned as. a result ofrefrigeiation system malfunction, the. vapors

are routed to tank5l7. thennal oxidizer. . .

3). NSPS Subpart J §6I.l04(a)(I) exemptsthe. combustion in a flare ofprocess upset

.gases. or fuel gas that is. released to the flare. as a. result ofreliefvalve. leakage or other

emergency malfunction.

R.. FCC CatalystRegeneratotOff-Gas

Koch's Position.: . .

NSPS Subpart J is inapplicable because this stream is subject to the express exemption for

catalytic cracking unit catalyst regenerators. .

. EPA's. response:

FCC catalyst regenerator offcgas.does. not meet the definition ~ffuel gas and, therefore,. is .

.exempt from NSPS Subpart J §60.104(a)(I)..

S. MEA 3ndMDEA Regenerator. Off-Gas

Koch's Position:

NSPS Subpart J fuel gas n;quirement& are. inapplicable because.this stream falls under the

exemption for facilities that are. part of):he sulfur produetion process. .

•EPA's. response;

Sendingthese streams. to. the. sulfur recovery uoit (SRU) does not SUbject them to the

NSPS Subpart J'Standardfor the combustiollofa fuel gas in aFGCD.

I) MEA and MDEA regenerator off-gas streams. meet the. definition offuel gas.' . .' . . .' .

2) Because these r~cycled strearnsaresentto the front oflhe SR.U, and the SRU is a

facility'in which gases are. cornbusted to: produce.sulfur orsulfuric acid, these streams. are

not being combusted in a FGCD..
16

T. Sour WaterT:mk Purge Gas .

Koch's Position:

This streamfalls wider the Subpart J exemption for sulfur production facilities and has

previously been detennined by USEPAto. b\lnot subject toNSPS Subpli!t J fuel gas

requirements.

EPA'sresponse:

. .

Ifthe:st:uldby incinerator: was. constructed ormodified afterJune. H, 1973, it is an

affectedFGCDand the. combustion ofsout \Vater tank purge. gas issubjectto NSPS . . .

Subpart 1.

I}. Sourwater tank purge gas. meets the defmition offuel gas.

·2) SoUr watertanks store. process wat~ from vario~ refinery. process units... These tanks

are not part ofthe. SRU since.they are not part ofthe unit thfit recovers sulfur from HzS

by a vapor-phase catalytic reaction ofS02 and H"S. .

3) At Koch's.facility, the sour water tank purge. gas is sent to directly to aSRU standby

incinerator (affected FGCD) for thermal oxidationwithout going through the. SRU. , , .. .

Note: Again,Y0l1 claim that EPA's approval ofthe State.Implementation Plan (SIP)

.order for the Dakota County/Pine Bend Area ofAir Quality Control Region 131 is

evidence ofEPA's detennination that NSPS. Subpart J is inapplicable to this gas. stream.

For the reasons.stated in. our response to stream H, your beliefis not correct. .

U. Sour. Water Stripper Overhead Gas

Koch's Plisition:

.NSPS SubpartJ. fuel gas requirements arc. inapplicable. b~ause. this stream is.part ofthe ..

sulfur produCtion process andfalls ~der the Subpart J exemption for proC\lss. upset gas. ..

EPA'sresponse: .

Introducing these. streams into the SRU does not subject themto NSPS: Subpart J

requirements applicable to the combustion ofafud gas in a FGCD.

1) Sour water stripper overhead gas meets the. definition offuel gas.

. .

2) Sour water strippers are not part ofthe. SRU since. they are. not part ofthe. unit that

recovers sulfur from Hzs by a vapor-phase catalytic reaction of802and HzS. . .
17

3J Koch sends the sour water strippeuwerhead gas to the. SRU. The SRU is. not a FGCD

because. it is a facility in which gases are combusted to produce sulfur or sulfuric acid.

Note:.. Koch indicates that this gas may be routed to a FGeD (bypassing the. SRU) during

periods ofstartcup, shut.down or malfunction ofthi:SRU•. Itmaintainsthat such·

combustion is not subject to Subpart 1's.sulfur oxide standard because. these. gases are

exempt process upset gases. . .

. Exemptions from rules of general applicability are to. be. coristrued narrowly.

Nonetheless,EFA. recogirizesthat there. are certain limited circumstances un.der which

normal processesmay be. bypassed because. upset conditions.·exist in some, upstreariJ.· .

process unit (e.g;; ifilpstream gas quillity will cause a malfunction in a downsiJ:eam unit, .

the gas is. diverted to a flare iustead). . ,

• It is the refinery's. burden to demonstrate.that a malfunction has. occurred each time. a

. downstream unit is. bypassed (or otherwise.demonstrate that its: actions are. exempt from

regulation). EPA notes. that a.malfunction must beinfrequent,ndt reasonably .'

. preventable and not attributable. to poor maintenance or careless operation:. For example,

a "malfuilCtion" caused by the same or similar conditions as had occUrred previously will

lose. its exempt character and be subject to all applicable standards. and requirements.

.Periods ofroutine. or periodic mairitenance. to downstream units. are not malfunctions at .

either the. upstream m: the downstream unit~ Gases. generated in the upstream 1,Inits. are

not then process upset gases, theii:combustion is subject fully to applicable. NSrS Subpart

J standards and the bypassing(without properconti:01s)ofa downstream unitthatis..'

undergoing routine. or periodic maintenance. would not be permitted.

Ifthe capacity ofthe SRU is exceeded due to. process upset gas~s, such gases may be .

flared (but only to the. extent attributable to such upsetgas)~.Such instances. are also

subject to §60JI(d). See discussionabove. .

V. Ammonia Acid Gas. Flare

Koch's. Position: _.. , . .- . : .

NSPS Subpart J is inapplicable because. this stream fallsunder the Subpart J exemption

for process upset gas.. The acid gas flare is. used only for ammOl)ia acid gasthat cannot be

processed in the sRU due to start'up, shut-down or malfunction.. .

EPA'sresponse:

Process upset gases. are. those.gases generated by a refinery process. unit during periods of

start-up, shut-doWn, upset or malfunction. Such gases are subject to 60.11(d).. See

discussion above.
18

I) Anunonia acid gas meets. the defmition Qffuel gas...

. .

2) Combustion of a fuel gas ina flare constructedor modified afterJune II, 1973, is·

subject to SubpartJstandards for sulfur oxides, but combustion ofprocess. upset gases is

. exempt from those standards. . .

Note~ Exemptions from rules ofgeueral applicability are to be construed narrowly.

Nonetheless, EPA recognizesfuat there. are ce)1ain limited circumstances uilder which

normal processes may be bypassed because upset comlitions exist in.some upstream

process unit (e.g., ifupstream gas quality win cause a malfunction in a downstre:iIii unit,

the gas is diverted to. a flare iristead). . .. .

It is the. refinery's. burden to demonstrate that a malfunction has. occurred each time a

. downstream unit is bypassed (or otherwise demonstrate. that its actions are exempt from

regulation).. EPA notes that a:rnalfUllction must be infrequent, not reasonably

preventable and not attributable to poor maintenance. or careless operation•.'For example,

a "malfunction" caused by the same or similar conditions. as. had occurred previous.ly will.

los.e iis. exempt character and be. subject to all applicable standards. and requirements.

.. Periods ofroutine. or periodic maintenance to downstream umtsare not malfunctions. at .

either the upstream or the downstream unit.. Gases generated in upstream units are not

then process. upset gases, their combusiion is subject fully to. applicable NSPS SubpartJ

standards. and the. bypassing of a downstream 1lllit that is. undergoing routine or periodic.

maintenance would not be permitted: . ...

Based on information EPA has, numerous episodes o{ combustion of amm()nia acid gaS: in

a flare subject to NSPS SubpartJ suggests thilt there are operation and maintenance

problems with those. refinery. units generating and/or processing that gas..

w. SUlfur Degassing OfJ.-Gas

. Koch~s Pos.ition:

This stream falls. under theSubpart Jexemption forsuifur production facilities and has

previously been determined by USEPA tobe not subject to SubpartJfuel gas ..

requirements. . . .

EPA's responSe:

Ti).e. sulfur degassing off-gas is generated within the SRU, .it is SUbject to·therequitements .

OfNSPS Subpart J §60.l04(a)(2) and is. exempt from §60.l04(a)(I). Please note that

some other sulfur pit degasification processes would not be considered asintegral.parts of

aClaus sulfur recovery' plant; asdefined,.and consequently, their exhaust gases could be

s\)bject to. §60:104(a)(I). . . .

/
.19

It is our understanding that Koch uses the Shellsulfur degasification process.• This

process involves a vapor phase reaction that converts'much ofthe dissolved H28 into'

elemental sulfur within the. stripping column oftlie. sulfur pit. For purposes. ofthe

regulation, this. conversion process. is. equivalentto the, Claus. process.

It appears, from your May 14,1999, Generic Tail Gas. Treatment Unit (TGTU}Flow

Chart, that the. sulfur degassing off-gas is generated within the sulfur pit ofeach SRU and

then routed to the emergencybypas.s. incinerator to, be combusted., It is. combusted along

with sour water tank off-gas, fuel gas. andany tail gas. from the SRU that bypassedJhe

TGW. That combustion results. iii an exhaust that is. a combination oigases, some .

subject to §60.l04(a)(I) and others to §60.104(a)(2).. Accordingly, each stream going to

the. emergency bypass. incinerator. must be. monitored separately, or the, more, stringent of '

the two, limits. applies (in this. case, theFGCb liInit). Streamssubject to the same

.. standaros may be. eombined and 01MY the. combined stream need then be monitored.

Note:. Again, yot! cIaiIn that EPA's, approval ofthe State. Implementation Plan (SIP)

order for the.Dakota CouritylPine Bend Area ofAir Quality Control Region 131 is

evidence ofEPA's. detenrtinlition thatNSP8Subpart lisinapplicable. to this gas stream.

For the reasons stated in oui: response to stream H, yOm beliefis. not correct. .

X. SRU TGTU Process Heater.

Koch's Position:

NSPS St!bpart J fuel gas requirements are. inapplicable because this stream falls under the

exemption for facilities in which gases are combustedto p.roduce sulfur. . . .

'EPA's response:

NSPS. Subpart 1§60.l04(a)(2). prolubits. the. discharge ofany gases. into the atmosphere

from any ClauS sulfur reeovery. plant containing excess amQunts ofSO,. According to

your diagrams, the exh,!ust from the heater/reactor goes into a liqilld-gas. H2S.recoverY .

system. The. recovered H2S is. then recycled back to the feed line ofthe SRU. Since the

S02 is. converted into H2S and is. not discharged into the atmosphere, NSPS Subpart J

requirements are not applicable to the direct-fired heater on the reducinggas. reactor

within the TGTU.· .

Although WI; agree that this. direct fired heater. is.not subject to NSPS Subpart J

§60.104(a)(1). [as discussed above], we do not agreewith Koch's.interpretation ofthe .

heater being exempt because itis part ofthe. s.u1fur recovery plarit. .Koch argues that the

exemption for sulfurrecovery plants. applies to this.heater..It does. not.. The heater and

reducing gas generator are not inthe SRU; the. H,S stream that they generate. is. desired

for iIripro1ling the efficiency ofthe SRU, but is. not essential for the operation ofthe SRU; .

and the recycled H2S stream would be "fuel gas" ifcorobusted anywhere, other than in the

SRU or a sulfuric acid plant at the refmery (the. two combustion devices exempted from
20

· being "FGCDs").

Y. SRU TGTU Incinerator

Koch;s Position:

This. urut is. subject to, and complieswith Subpart J requirements for sulfur plants.

EPA's response:

Based on yo'iJrMay 14, 1999, Generic Tail GasTreatment Urut Flow Chart, Koch's.

TGtus meet the definition of "reduction control systems"... Each TGTU has attached to it

an incinerator. Koch is. burrung refinery fuel gaS and gas from the. tail gas absorber in the

tGTUincinerator. The. exha:ust from Koch'.s TGTU incinerators isa combination of

exhausts from two different types. ofNSPS affe.cted facilities (i.e., an SRU and an FGCD).

Therefore, the TGTU. incinerator is subject to both the H2S limitfor the. fuel gaS

(§60.104(a)(I)) and theS021irrlit for the exhaust from a reduetion control system :.

followed byincimiration(§60.104(a)(2)(i)). The more. stiingent ofthe. two limits. applies

· (in this case, the. FGCD limit) unless. compliance can be. determined independently for'

each requirement... Koch monitors. the. refinery fuel gas fot H2S prior to combllstion and

monitors. the. S02leveis in the. exhaust from the. TGTU. inCinerator. Since. compliance. for

el\ch requirement can be. determined separately, Koch does not have tomaintain the

TGTU incinerator's combined emissions below the.FGCD S02 emission level, but the

S02, level (adjusted for the. combustion ofthe fuel gas) must meet the limits Under

§60'.l04(a)(2)(i). This. detertniJ1\ltion has already been established by EPA in an

April?, 1992letter. (Enclosure.4)

Z. Propane Flare. atKoch Pipeline Company. Pipeline Terminal

Koch's. Position:

NSPS Subpart J is inapplicable becaus!,: this stream falls. under the Subpart J exemption

for process upset gas.

EPA's response:

Based OJi. the description provided, EPA understands that the only time any vapors. are

generated and combusted at this terminal is during periods ofshtit-down or malfuriction.

·As such, and ifa Pllrt ofthe refinery, these gases are process. upset gases excluded from

SubpartJ, but would stiUbe. sJlbjectto §60.Il(d).

EPA also understands. that this pipeline terininal:is a separate source and is. different from

/.he refinery, and the only physical connection to. the,refinery is via a product pipeline.

Since it does not appear to be part ofthe refinery, these vapors would not be a fuel gas

because theY'are not generated at a refinery..
21

In ytmrJuly 9,1999, Supplemental Submittal, you requested thaIEPA Headquartersaet

on yoUrproposed Alternative. Monitoring Plan (AMP) and proposed Flare Gas Recovery. .

Performance Policy at the'same. time as isSUing this. applicability determination.·You state that if

EPA does not act onthose requestS at the same. time, you will assume that your requests would

ultimately be denied. In our August 10, 1999, meeting,we made itcleat that we ate willing to

work with you on those tworequests, but they do not affect the applicability ofthe regulation:

We are. confident that we. can resolve the issues. relating to those. two requests, and that your

requests will be approved in some form, but it will take. time. to. work out the. remaining details.

Therefore, we. have. deCided notto del;t.y our response to your original letter. from

August 14, 1998, while. we. continue. to work together on the AMP. and flaring policy. ,. '.

· This determination hasbeen·c09rdinated with EPA's. Office. ofRegulatoryEJ1forcement,

the Emission SUmdards. DiVision ofthe Office ofAir Quality Planning and8tandards,the Office

of Geileral Counsel; and Several ofEPA's Regional offices..Ifyou have any questions, please

contactTomRipp ofmy staff at (202) 564-7003.

Sincerely,

.SI KEN.GIGLffiJ:,LO for

John B.. Rasnic, Director

Manufacturing, Energy and Transportation Division

Office ofCompliance

cc: Jim Jackson,. ORE

· DianeMcCorikey;OQC

Jim.Durlmm,Oi\QPS

Annette Lang,nOJ

Patrick Foley,.Regiol)ill

Patrie McCoy, Region V

Jonathan York, Region VI

· Bill Peterson, Region VII

Lee Hanley, Region VIn

PaulBoys, Region X

Glenna Emanuel,OC
ALTERNATIVE MONITORING PLAN

for NSPS Subpart J Refmery Fuel Gas

Conditionsfor Approval ofthe AltemativeMonitoring Phm for Miscellaneous. Refinery Fuel Gas

Streams" .. .

. .

. '. Refinery fuel gas streams/systems. eligible for the Alternative Monitoring Plan (AMP)

should be inherently low: in H2S content, and suCh H2S content should be relatively stable•. The

refinerrequestirigati AMP. should provide sufficient informationto allow for a detennination of

appropriateness ofthe AMP. for each gas stream/system requested.. Such information should

. include, but need not be.l#nited to:

••

•

•

A descriptionoithe gas stream/system to be consideredincIuding submission of a portion

ofthe. appropriate piping diagrams indicating the boundaries. ofthe. gas stream/system,

and the affected fuel gas combustion device(s) to be considered and an identification of

. the. proposed sampling point for the alternative monitoring;

A statement that there are no crossover or entry points. for sour. gas (high H2S content) to

be introduced into the. gas stream/system.. (This should be shown inthepiping diagrams);

An e:,c.planation ofthe conditions that ensures low: amounts. ofsulfur in the gas stream

.(i.e., control equipment or product specifications) at all times;

• . , . .

The supponingtest results. from sampling the requested gas stream/system using

appropriate. H2Snionitoring (i.e., detector tube. monitoring following the Gas Processor

Association's: TesHorHydrogen Sulfide and Carbon Dioxide. in Natural Gas. Using.

Length ofStain TUbes, 1986Revision), at minimum:

• forfrequently operated gas streams/systems - two weeks of daily monitoring (14 samples); . . .

• . .for infrequently operated gas streams/systems, 7 samples shall be collected unless

,other additional information would support reduced sampling.

Note:. All samples are. grab samples.

• A description ofhow: thetwQ weeks. (or seven samplesfor infrequently operated gas

streams/systems) ofmonitoring results. compares to the typical rangeofH2S. concentration

(fuel quality) expected for the gas stream/system going to. the. affected fuel gas

combustion device... (e.g., The two weeks ofdaily detector tube resultsfor a frequently

operated loading rack included the. entire range ofproducts loaded out, and, therefore,

.should be representative oftypical operating conditions affectingH2S content in thegas

stream going to the loading rack flare);'

• Identification ofa representative process parameterthat can function as an indicator of a

, stable and low H2S concentration for each fuel gas streanVsystem, (e.g., reviewof .

gasoline sulfur content as an indicator ofsulfur content in the. vapors directed to a loading . rack flare); . .

• Suggested process parameter limit for each streamlsystem, the rationale.for the parameter

limit and the schedule. forthe acquisition and review ofthe process parameter data.. The

refiner will collect the proposed piocessparameter data in conjunction with the. testing of

the fuel gas stream's stable and low H2S concentration. .

1
The. following shall be. used for measuring HzS in fuel gas. within these types ofAMPs

unless the refIner requests, in writing, for approval ofan alternative. methodology:

• Conduct HzS testing using deteCtor tubes. ("length-of-stain tube" type measurement);

• Detector tube ranges O-lOIO-l(jO ppm (N =1011) shall be used forroutine testing~ and

• Detector tube ranges 0-500 ppm shall be. used for testing ifmeasured concentration

exceeds 100 ppm HzS. .

DataRalige and Variability Calculation and Acceptance Criteria

.For each step ofthe monitoring schedule, sample range and variability will be determined

by calculating the average. plus 3. standard deviations for.that test data set.

• Ifthe. average plus 3. standard deviations for the. test data set is. less. than 81 ppm H2S; the

sample range and variability are. acceptable and the. refIner can proceed to the. next stepQf

the monitoring schedule. .

Note: 81. ppm is one-halfthe. maximum allowable. fuel gas standard under NSPS

SubpartJ, and the Agency believes. that using 81 ppin acceptance criteria provides

a sufficientmargin for ensuring that the. emission limit is. not exceeded under

nonnal operating conditions. . .

• Ifthe data shows an unacceptable range and variability at any step (the average plus. 3

standard deviations is equal to or greater than 81 ppm H2S), then move. to Step 7. Agency

. approval is required to proceed to the next step. ifthe. average plus 3. standard. deviations is

betwe.en 81 ppm and 162 ppm H2S. As an example, lIpproval may be granted based on a

review ofthe testdata and any pertinentinformation which demonstrates that sample

variability during the test periodwas due. to.unusual circumstances.. Supplemental t:est·

data may be taken to demons.trate that process variability is within the plan requirements..

. Data may be. removed from the variability calculations for cause after agency approval.

• For Steps 3. and 4, ifthe data shows. an unacceptable range and variability (the average

plus. 3. standard deviations is equal to or greater than 81 ppm HzS), the. source will drop

backto the previous step's monitoring schedule.

• If at any time, one detector tube sample va!ue.is equal to or greater than 81 ppm H2S,

then begin sampling as specifIed in Step 6..Note: Standard deviation cannot be.

calculated for a data set containing one. point. . .

Monitoring Schedule for Approved AMPs

For gas streams.·which must meet product specifIcationsfor sulfur content, one time ouly

detection tube sampling along with a certifIcation that the gas stream is subject to product or

. pipeline specifIcations is.suffIcient for the AMP. Ifthe gas stream composition changes (i.e.,

Dew gas sources are added), or ifthe gas stream will no longer be required to meet product or

pipeline specifications, then the gas. stream must be resubmitted for approval under the AMP.. . .

The following are examples ofstreams. needing one. time only monitoring:

2
• Certified commercial grade naturnl gas;

• Certified commercial grade LPG;

• Certifiedcoinmercial grade hydrogen;

• Gasoline vapors from a loading rack that only loads.gasoline meeting a product

specification for: sulfur content.

. . .

.For other gas streams, the. HzS content ofeach refinery fuel gas streanlisystem with an

approved AMP shallbe. monitored per the following schedule: . .

Step 1:

. The refmer wil1conductrandomH28 sampling once. per quartet fora period ofsix

quarters (6 samples)witha minimum onmonth between samples. A minimum 0:f9. samples

. arerequired for infrequently generated and combusted fuel gas streams before proceeding to

Step4.. Continueto monitor and record the. selected process parameterin accordance. with the. ..

established schedule, and at times. when conducting H2S testing.. Move to. Step 4 ifthe calculated

range: and variability ofthe data meets. the established acceptance criteria.. Submit test data (raw

.. measurements plUS calculated average and variability) to the. agency quarterly..

Step 4:

. Th~ refiner will conduct random H2S sampling twice per year for a period oftwo years (4

samples); sample randomly in the. 1st and 3rd quarters with a minimum or 3 months between

samples.. Continue tomonitor and recordthe selected process parameter in accordance with the

established schedule; and at times. when conducting H2S testing. Move. to Step 5. ifthe calculated

range andvariability ofthe datameets the. established criteria. Submit test data (raw .

measurements plus calculated aveiage and variability) to the agency semiannually..

. Step.5:

3
The refiner will continue to conduct testing onserrri-annualbasis. Testing isto occur

randomly once every semiannual period with a minimum of 3. months between samples. . .

Continue to monitor and record the selected process parameter in accordance. with the established .

schedule, and at times. whenconductingHzS testing. Ifanyone. sample is. equal to or greater than

81 ppin H2S, then proceed to the sampling specified in Step 7. Note: Standard deviation cannot

be calculated for a data set containing one point. .

Step 6:

If, at any time, the selected process pariuneter. data indicates a potential change in H2S

concentration, Of a single detectortube sample valueis equal to. otgreater thail 81 ppm H2S, then.

·the fuel gas stream shall be sampled with detector tubes on a daily basis for 7 days (odor .

infrequently generated gas streams. - 7 samples during the same period of an indicated change. in

HzS concentration, or as otherwise apptovedby the agency). Ifthe average. detector tube result

plus 3. standard deviations for those seven samples. is. less. than 81 ppm H2S, the. date and value. of .

change iIi the selected process parameter indicator and the sample results shall be included in the

next quarterly report, and the. refiner shall resume moiritoringin accordance. with the. schedule. of

the current step. Ifthe. average plus J standard deviations. for those seven samples is. equal to or

greater than 81 ppm H2S,.sampling shall follow the requirements ofStep 7. .

Step. 7:

Ifsample detector tube. data indicates a potential for the. emission limit to be. exceeded

·(the average plus 3. standard de.viationsis. equal to or greater than 8r PPm.. HzS), as determined in

the Data Range andYariability Calculation and Acceptance Criteria orin Step 6, the. refmer. shall

notify the. agency ofthose results. before the end ofthe next business day following the last

sample day. The fuel gas stream shall subsequently be tested daily for a two week period (or 14

samples during the same event or as otherwise approved by the agency for infrequently generated

•gas streams). After the two week period is complete,sampling will continue once. per.week, \ffitil

the agency approves.a.revised sampling schedule. or makes a determination to withdraw approval.

ofthe gas stream/system from the. AMP..Note: .At any time, a detector tube value. in excess of

·the 162 ppm limit is. evidence. that the emission standard has been exceeded.

· General Provisions ofApproved AMPs

Upon agency tequest~ the refiner shall conduct a test audit for any gas. stream with an

approved AMP. The. audit Sball consist ofdaily detector tube. samples collected over a oneweek

period (7 samples). For fuel gas streams infrequently generated and combusted in affected fuel

. ... gas combustion devices, an audit shall consiSt of3 consecutive sampling events.. (e.g., Rail

loading may occur once. per moIith, ail audit would consist of 3. consecutiveIoading events.) The

United States Environmental ProtectionAgency, with due. notice, reserves the. right to withdraw

approval ofthe AMP. for any gas stream/system. ..

Thll source. shallkeep records ofthe. Hz8 detector tube test data and the. representative

process parameter data and fuel source for at least two Years. .

Ifanew fuel gas. stream is introduced into a fuel gas stream with an approved AMP; the

refiner shall again apply for·an AMP and repeat Steps. 1 5.

Example:

4
An AMP Application for a HydrOgenPlant PSA Off-Gas. Stream COlIlbusted Exclusiveiy in the

. Hydrogen Plant ProQess Heater:

Process Description

Hydrogen production for the. refinery by the steam methane reforming process. COzis. the

.primary impurity in the hydrogen produced; small amounts ofCO and methane.. are also present..

Unpurified hydrogen is passed over molecular sieve absorbent beds.to. remove these impurities.

The off gas from regeneration ofthe. absorbent beds is. called PSA off-gas. It is sent to the

hydrogen plant heater to recover heat and control CO emissions.

Piping Diagrams·

Piping diagrams should be supplied to show monitoring location and to demonstrate. that there. is

no potential for eross over or entry poirits for sour gas.

Basis for PSA Off-Gas Low H.S Content .' '. . .

. Since PSA off-gas is a byproduct ofhydrogen purification, anYHzS in the PSA purge gas must

come from the hydrogen unit feed. Levels ofHzS in the PSA gas are. negligible because. HzS

must be controlled to prevent .

deactivation ofthe. unit's catalyst . . .

. H2Sis a pernianeilt catalystpoison. The hydrogen unit has 2 scrubbers to remove H2S fromthe

feed gas to. protect the. unit's catalyst from HzS poisoning. The scrubbers. are. operated in series.

The lead scrubber must exhibit at least a 70% reduction inH2S content.. Ifnot, the. scrubber is

taken offline. and the absorbent is replaced. After the. absorbent is replaced, the scrubber is

placed on line. as. the second scrubber in series... This. maximizes. the amount ofH2Sremovaland

assures maximum scrubbing potential when one. scrubber is. offline for absorbent replacement.

Process. Parameter Monitoring andSuggested Process. Parameter Limit

Operation ofthe scrubbers is checked on a monthly basis with detector tubes. The feed gas. H2S

content is. measured at the inlet and outlet ofthe. lead scrubber... If natural gas is. used as. hydrogen

plant feed; bothrea<lings are below the 1 ppm detection limit. Ifrefinery fuel gas. isthe feed gas,

.30 ppm to 40. ppm H2S is normally detected at the inlet... A lead scrubber outletreading of 10. -12

ppm H2S would trigger.absorbent replacement.. The suggested process parameterlimit is 20 ppm

H2S at the lead HzS absorber outlet. Absorber outlet HtS measurements will be taken in

cOrUunction with the PSA gas measurements during Steps 2 and 3. . .

5