TECHNICAL SUPPORT DOCUMENT

FOR

BEST AVAILABLE RETROFIT TECHNOLOGY

UNDER THE REGIONAL HAZE RULE

AQPSTR 09-06

April 29, 2011

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

1021 NORTH GRAND AVENUE EAST

P.O. BOX 19276

SPRINGFIELD, ILLINOIS 62794-9276
2

Table of Contents

List of Acronyms............................................................................ 4

Figures........................................................................................ 5

Tables......................................................................................... 6

Executive Summary....................................................................... 7

1.0 Introduction....................................................................... 9

2.0 BART-Eligible Sources in Illinois ............................................ 12

3.0 Visibility Modeling of BART-Eligible Sources ............................. 14

3.1 Modeling Methodology................................................. 15

3.2 Modeling Results ......................................................... 18

4.0 BART Controls in Illinois ...................................................... 23

4.1 BART Controls for Illinois EGUs .................................... 23

4.1.1 EGUs Under the MPS and CPS............................... 24

4.1.1.1 Dynegy ................................................... 25

4.1.1.2 Ameren ................................................... 28

4.1.1.3 Midwest Generation..................................... 30

4.1.2 Other Illinois EGUs .............................................. 31

4.1.2.1 CWLP ..................................................... 33

4.1.2.2 Dominion Kincaid ...................................... 35

4.2 BART Controls for Non-EGUs ........................................ 38

4.2.1 CITGO ............................................................ 38

4.2.2 ExxonMobil ....................................................... 39

5.0 Summary ............................................................................ 43

References .................................................................................... 45
3

Table of Contents (continued)

Appendix A Single Source Modeling to Support Regional Haze BART Modeling Protocol

Appendix B Regional Air Quality Analysis for Ozone, PM2.5, and Regional Haze: Final

 Technical Support Document

Appendix C Illinois Mercury Rule

Appendix D BART Analysis for the Kincaid Power Plant

Appendix E Consent Decree for ExxonMobil Oil Corporation

Appendix F Consent Decree for CITGO Petroleum Corporation
4

List of Acronyms

BART Best Available Retrofit Technology

CAA Clean Air Act

CD Consent Decree

CO Carbon Monoxide

CPS Combined Pollutant Standard

EGAS Economic Growth Analysis System

EGU Electrical Generating Unit

FCCU Fluid Catalytic Cracking Unit

FGD Flue Gas Desulfurization

IPM Integrated Planning Model

LADCO Lake Michigan Air Directors Consortium

LNB Low NOx Burner

MPS Multi-Pollutant Standards

MRPO Midwest Regional Planning Organization

NH3 Ammonia

NOx Oxides of Nitrogen

OFA Over-fire Air

PAMS Photochemical Assessment Monitoring Sites

PM Particulate Matter

PM2.5 Particulate Matter 2.5 microns in diameter

PM10 Particulate Matter 10 microns in diameter

NSPS New Source Performance Standards

SCR Selective Catalytic Reduction

SDA Spray Dryer Absorbers

SIP State Implementation Plan

SLAMS State and Local Air Monitoring Sites

SNCR Selective Non-catalytic Reduction

SO2 Sulfur Dioxide

SPM Special Purpose Monitors

USEPA United States Environmental Protection Agency

VOC Volatile Organic Compounds

VOM Volatile Organic Material
5

Figures

Figure 3.1 Model Domain with Class I Areas.................................... 16

Figure 3.2 Illinois Sources Subject to BART...................................... 21
6

Tables

Table 2.1 Initial List of BART-Eligible Sources........................................ 13

Table 3.1 CALPUFF Modeling System Versions....................................... 15

Table 3.2 Class I Receptor Areas and Total Discrete Receptors.................... 17

Table 3.3 CALPUFF Modeling Results - Number of Days with 

Impacts Greater Than 0.5 Deciviews at Nearby Class I Areas......... 19

Table 3.4 List of Units Subject to BART................................................. 22

Table 4.1 Presumptive BART Emission Limits for Coal-Fired EGUs............. 24

Table 4.2 NOx Reductions from Dynegy EGUs - BART vs. MPS .................. 27

Table 4.3 SO2 Reductions from Dynegy EGUs - BART vs. MPS ................... 27

Table 4.4 NOx Reductions from Ameren EGUs - BART vs. MPS................... 29

Table 4.5 SO2 Reductions from Ameren EGUs - BART vs. MPS .................. 30

Table 4.6 NOx Reductions from Midwest Generation EGUs - BART vs. CPS.... 32

Table 4.7 SO2 Reductions from Midwest Generation EGUs - BART vs. CPS.... 33

Table 4.8 NOx Reductions from CWLP - BART vs. MOU............................ 34

Table 4.9 SO2 Reductions from CWLP - BART vs. MOU............................ 34

Table 4.10 Comparison of Visibility Impacts from Dominion Kincaid 

Emissions Control Scenarios – Number of Days with Impacts 

Greater Than 0.5 Deciviews.................................................... 37

Table 4.11 NOx Reductions from Dominion - BART vs. MOU........................ 37

Table 4.12 SO2 Reductions from Dominion - BART vs. MOU......................... 38

Table 4.13 NOx Reductions from CITGO - BART vs. Consent Decree ............. 40

Table 4.14 SO2 Reductions from CITGO - BART vs. Consent Decree ............. 40

Table 4.15 NOX Reductions from ExxonMobil - BART vs. Consent Decree....... 41

Table 4.16 SO2 Reductions from ExxonMobil - BART vs. Consent Decree........ 42
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Executive Summary

In an effort to restore visibility in national parks and wilderness areas in the United States to 

pristine conditions, the United States Congress amended the Clean Air Act ("CAA") to remedy 

any existing visibility impairment and to prevent any future impairment. The federal Regional 

Haze Rule, finalized by the United States Environmental Protection Agency ("USEPA") in 

19991, is aimed at achieving pristine visibility conditions in the subject areas by 2064. This goal 

is to be achieved by addressing the combined effects of several pollutants from a number of 

sources over a wide geographic area that have been found to negatively impact visibility in the 

affected areas. As part of a strategy to reduce pollutants such as oxides of nitrogen (“NOx”), 

sulfur dioxide (“SO2”), and particulate matter (“PM”), USEPA has determined that certain 

stationary emission sources should be subject to a Best Available Retrofit Technology (“BART”) 

standard. The sources subject to a BART standard, according to "Guidelines for BART 

Determinations under the Regional Haze Rule" (“BART Guidelines”)2published by USEPA in 

July of 2005, must be one of 26 specified source categories; were in existence in August 1977;

began operating after August 1962; and have the potential to emit 250 tons per year or more of 

any air pollutant. 

The federal Regional Haze Rule requires consultation between the states, tribes, and Federal 

Land Managers (“FLMs”) responsible for managing Class I areas. This multi-state and multiagency consultation process has been facilitated by Regional Planning Organizations (“RPOs”) 

established specifically for this purpose. Illinois fully participated in the planning and technical 

development efforts of the Midwest Regional Planning Organization ("MRPO"), which also 

includes the States of Indiana, Michigan, Ohio, and Wisconsin. States in other parts of the 

country participated in similar RPOs. Illinois has also participated in consultations with other 

RPOs and states that have requested Illinois‟ participation in their planning process. 

The Illinois EPA, in conjunction with the MRPO, has made adequate plans to meet the 

requirements of the Regional Haze Rule by performing the necessary modeling to determine its 

impact on visibility in Class I areas. The modeling approach used by the Illinois EPA to address 

BART was developed in consultation with the MRPO, the other participating MRPO states, the 

USEPA, and participating FLMs.
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The purpose of this document is to describe Illinois‟ approach for meeting the BART 

requirements for emission sources in Illinois that have been shown to be BART-eligible. 

Technical analyses conducted by the Illinois EPA have shown that certain BART-eligible 

sources in Illinois are causing or contributing to visibility impairment in several Class I areas in 

the eastern United States, including Mammoth Cave National Park in Kentucky, the Mingo 

Wilderness Area in Missouri, Isle Royale National Park in Michigan, and others. Illinois is 

therefore required to submit revisions to its State Implementation Plan (“SIP”) to require that 

subject emission sources install cost effective retrofit control technologies or provide equivalent 

emission reductions.

Illinois has promulgated emission control requirements for most of the emission units in Illinois 

that are subject to BART that provide greater emission reductions, and greater environmental 

benefits, than would be provided by implementation of BART. Other emission units are subject 

to provisions contained in federally enforceable consent decrees or federally enforceable permits

that provide greater emission reductions than would be achieved by BART. All of these 

requirements provide significant emission reductions that the Illinois EPA considers to meet or 

exceed the reductions expected from the BART requirements contained in the Regional Haze 

Rule, and all requirements will be contained in federally enforceable permits.
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1.0 Introduction

In an effort to restore national parks and wilderness areas in the United States to pristine 

conditions with regard to man-made visibility impairment, the United States Congress amended 

the Clean Air Act ("CAA") in 1977 to remedy any existing visibility impairment, and to prevent 

any future impairment. These amendments led to measures specifically addressing plume blight 

caused by visible plumes from nearby emission sources, but did little to reduce regional haze in 

the United States. When Congress again amended the CAA in 1990, it directed further research 

into regional haze, and mandated periodic assessments of progress toward regional haze goals. 

The resulting research and mandates led to the adoption on July 1, 1999, of USEPA‟s Final 

Regional Haze Rule. The Regional Haze Rule set the goal of achieving pristine visibility 

conditions at federal Class I areas by 2064. The Rule also addressed the visibility effects of 

pollution sources over a wide geographic range, and included sources from states without any 

Class I areas located within them. 

USEPA has determined that as part of its strategy to reduce visibility impairing air pollutants, 

such as oxides of nitrogen (“NOx”), sulfur dioxide (“SO2”), and particulate matter (“PM”), that 

certain stationary emission sources should be subject to a Best Available Retrofit Technology 

(“BART”) standard. BART is defined as an “emission limitation based on the degree of 

reduction available through the application of the best system of continuous emission reduction 

for each pollutant which is emitted by an existing stationary facility.” 40 CFR §51.301. The 

sources subject to a BART standard, according to "Guidelines for BART Determinations under 

the Regional Haze Rule" (“BART Guidelines”)2published by USEPA in July of 2005, must be 

one of 26 specified source categories; were in existence in August 1977; began operating after 

August 1962; and have the potential to emit 250 tons per year or more of any air pollutant. 

In 2002, the Regional Haze Rule was challenged by the American Corn Growers Association in 

the United States Court of Appeals for the District of Columbia Circuit. American Corn 

Growers Ass’n v. EPA, 291 F.3d 1 (D.C. Cir. 2002). The court issued a ruling vacating the rule 

in part and sustaining it in part. The ruling denied the challenge to the Regional Haze Rule 

mandating goals of zero visibility impairment and no degradation in Class I areas, but remanded 

the BART requirements to the USEPA for revision. In response to the court‟s ruling, USEPA
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promulgated final amendments to its Regional Haze Rule that specifically apply to the BART 

provisions of the rule. 70 Fed. Reg. 39104 (July 6, 2005). 

As stated in the final BART Guidelines, “The process of establishing BART emission limitations 

can be logically broken down into three steps:

(1) States identify those sources which meet the definition of „BART-eligible source‟ set 

forth in 40 CFR 51.031. These sources are any which: (1) have the potential to emit 

250 tons per year (“TPY”) or more of a visibility impairing air pollutant; (2) were put 

in place between August 7, 1962 and August 7, 1977; and (3) whose operations fall 

within one or more of 26 specifically listed source categories. 

(2) States determine whether such sources „emit [] any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility [in a 

Class I area.]‟. A source which fits this description is „subject to BART.‟

(3) For each source subject to BART, states then identify the appropriate type and the 

level of control for reducing emissions.”

The BART Guidelines discuss how to determine whether a source “emits any pollutants which 

may reasonably be anticipated to cause or contribute to any visibility impairment.” For the 

purpose of this analysis, the Illinois EPA used CALPUFF for modeling visibility impacts, as 

recommended by USEPA.

2

 

The BART Guidelines identify the following visibility-impairing pollutants: SO2, NOx, and PM. 

In addition, USEPA recommends exercising judgment in deciding whether VOC and ammonia

and ammonia compounds should be considered as visibility-impairing pollutants. The guidelines

also allow states to exclude visibility-impairing pollutants from consideration if they are below 

de minimis levels (i.e., 40 TPY for SO2 and NOx, and 15 TPY for PM on a source-wide basis).
11

The Regional Haze Rule defines BART as: “... an emission limitation based on the degree of 

reduction achievable through application of the best system of continuous emission reduction for 

each pollutant which is emitted by a [BART-eligible source]. The emission limitation must be 

established on a case-by-case basis, taking into consideration the technology available, the cost 

of compliance, the energy and non air quality environmental impacts of compliance, any 

pollution control equipment in use or in existence at the source, the remaining useful life of the 

source, and the degree of improvement in visibility which may reasonably be anticipated to 

result from the use of such technology.” 40 CFR §51.301. Once it is determined that a source is 

subject to BART, these five factors must be considered to establish an emission limitation to 

meet the BART requirement.

The federal Regional Haze Rule requires consultation between the states, tribes, and Federal 

Land Managers (“FLMs”) responsible for managing Class I areas. This multi-state and multiagency consultation process has been facilitated by Regional Planning Organizations (“RPOs”) 

established specifically for this purpose. Illinois fully participated in the planning and technical 

development efforts of the Midwest Regional Planning Organization ("MRPO"), which also 

includes the States of Indiana, Michigan, Ohio, and Wisconsin. States in other parts of the 

country participated in similar RPOs. The modeling approach used by the Illinois EPA to 

address BART was developed in consultation with the MRPO, the other participating MRPO 

states, the USEPA, and participating FLMs.

The purpose of this document is to summarize the analyses that were conducted to determine 

which BART-eligible stationary sources in Illinois are subject to the BART standards pursuant to 

the Regional Haze Rule. In addition, this document details how these sources will comply with 

the rule, whether by meeting a BART standard or by an alternative strategy. 
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2.0 BART-Eligible Sources in Illinois

According to USEPA‟s BART Guidelines, a source is BART-eligible if it: (1) falls into one of 

26 specified source categories, (2) was “in existence” on August 7, 1977, and “in operation” on 

or after August 7, 1962, and (3) has potential emissions of 250 TPY or more of any visibilityimpairing pollutant (i.e., SO2, NOx, or PM).

The Illinois EPA identified potentially eligible BART sources using a multi-step process. First, 

Illinois EPA identified potential BART-eligible sources based upon data available from Title V 

operating permits, including information on dates of operation and maximum actual emissions

from a source (with a threshold of 100 TPY). Second, the Illinois EPA requested the dates of 

construction and potential to emit (“PTE”) for individual units from all Title V sources in Illinois 

that fell into one of the 26 specified source categories. Table 2.1 provides the initial list of 

sources that operate one or more potential BART-eligible emission units. Finally, those sources 

found to be potentially BART-eligible were modeled using CALPUFF to determine whether the 

source contributes to visibility impairment. The modeling methodology, developed in 

cooperation with the MRPO, is detailed in Section 3 of this document.

As summarized in Table 2.1, the Illinois EPA determined that there are 26 sources in Illinois that 

operate emission units that are BART-eligible. Eleven of those sources are coal-fired electric 

generating units (“EGUs”). Of the non-EGUs, there are four petroleum refineries, three 

chemical process plants, two Portland cement plants, two glass fiber processing plants, one lime 

plant and one iron and steel plant.
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Table 2.1 Initial List of BART-Eligible Sources

Source Name County Source ID

Big River Zinc Corp St. Clair 163121AAK

Carmeuse Lime Inc Cook 031600ADY

Chicago Carbon Co Will 197803AAK

CITGO Petroleum Corp Will 197090AAI

ConocoPhillips Co,Wood River Refinery Madison 119090AAA

Equistar Chemicals LP Grundy 063800AAC

ExxonMobil Oil Corp Will 197800AAA

Illinois Cement Co La Salle 099030AAZ

Lone Star Industries Inc La Salle 099816AAF

Marathon Petroleum Co LLC Crawford 033808AAB

US Steel Granite City Madison 119813AAI

Owens-Brockway Glass Container Inc La Salle 099490AAD

Pilkington North America Inc La Salle 099825AAG

Aventine Renewable Energy Inc Tazewell 179060ACR

Koppers Inc Cook 031300AAJ

Dynegy Midwest Generation Inc - Baldwin Randolph 157851AAA

Ameren Energy Generating Inc - Coffeen Montgomery 135803AAA

City Water Light and Power (CWLP) Sangamon 167120AAO

Ameren Energy Resources - Duck Creek Fulton 057801AAA

Ameren Energy Resources – Edwards Peoria 143805AAG

Midwest Generation LLC - Joliet Will 197809AAO

Dominion Kincaid Generation LLC Christian 021814AAB

Midwest Generation LLC - Powerton Tazewell 179801AAA

Soyland Power Coop Pike 149817AAB

Midwest Generation LLC - Will County Will 197810AAK

Dynegy Midwest Generation Inc - Wood River Madison 119020AAE
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3.0 Visibility Modeling of BART-Eligible Sources

The Illinois EPA used modeling to support its decision on which BART–eligible sources cause 

or contribute to visibility impairment and are therefore subject to BART. USEPA guidance for 

performance of visibility modeling is set forth in the Phase 2 Summary Report and 

Recommendations for Modeling Long Range Transport Impacts compiled by the Interagency 

Workgroup on Air Quality Modeling (“IWAQM”)

3

, as well as the BART Guidelines. Based on 

this guidance, the MRPO developed a modeling protocol to address BART in consultation with 

the participating MRPO states, including Illinois, the USEPA, and participating FLMs. The 

approach is described in detail in the document: “Single Source Modeling to Support Regional

Haze BART – Modeling Protocol,” prepared by the Lake Michigan Air Directors Consortium 

(“LADCO”) (March 21, 2006). This document is included as Appendix A. The Illinois EPA 

followed the MRPO Modeling Protocol, which was approved by USEPA, in the performance of 

the analyses described in this section. 

To assess the likelihood that particulate matter emissions in the MRPO states cause or contribute 

to visibility impairment, the MRPO performed a “cumulative modeling” assessment, as allowed 

by the BART Guidelines. Specifically, the MRPO used the Comprehensive Air Quality Model 

with Extensions (“CAMx”), with all point source particulate matter emissions domain-wide set 

to zero to determine the contribution of particulate matter emissions to visibility impairment in 

the eastern United States. The MRPO demonstrated that particulate matter emissions from all 

point sources in the domain do not contribute to visibility impairment (impact greater than 0.5 

deciviews) anywhere in the eastern United States. Since particulate matter emissions from just 

the BART-eligible sources represent a small fraction of the total particulate matter emissions 

from all point sources, the MRPO determined that the visibility impact of particulate matter

emissions from just the BART-eligible sources in the MRPO states will be much less than 0.5 

deciviews in any Class I area. Illinois EPA has nonetheless included PM2.5 emissions in the 

modeling of BART-eligible sources, where reliable emissions estimates were available, to 

determine if those sources caused adverse visibility impacts.
15

3.1 Modeling Methodology

The Illinois EPA modeled each BART-eligible source using the CALPUFF model on an 

individual unit basis. CALPUFF is a non-steady-state puff dispersion model that simulates the 

effects of time and space-varying meteorological conditions on pollution transport, 

transformation, and removal. CALPUFF consists of the plume transport model (CALPUFF), 

two meteorological data pre-processors (CALMM5, CALMET), an inorganic chemistry 

parameterization module (POSTUTIL), and the post-processor (CALPOST).

7,8 The specific 

versions of the CALPUFF modeling system used for this analysis are listed in Table 3.1.

Table 3.1 CALPUFF Modeling System Versions

Model Level Version

CALPUFF 5.771a 040716

CALPOST 5.51 030709

CALMET 5.53a 040716

CALMM5 2.0 021111

POSTUTIL 1.4 040818

The CALPUFF/CALMET modeling domain used in this analysis was a Lambert conformal grid 

projection centered at (97 W, 40 N) with true latitudes at 33 N and 45 N and origin at (-900 km, -

1620 km). The horizontal domain consists of 97 cells of 36-km in the east-west direction and 90 

cells of 36 km in the north-south direction (see Figure 3.1). 

The basis for meteorological files that were processed through CALMET consisted of three years 

of 36-km grid Fifth-Generation Mesoscale Model (“MM5”) simulations (2002-2004). The MM5 

data were processed using four-dimensional data assimilation (“FDDA”), which incorporates

surface and upper air observational data. The IWAQM guidance states that less than five years of 

meteorological data may be used if a meteorological model using FDDA is used to supply data.

The Illinois EPA used three years of meteorological data developed by the MRPO using FDDA. 

The Illinois EPA applied CALPUFF for NOx and SO2 emissions from all BART units at each 

BART-eligible source for calendar years 2002, 2003, and 2004.
16

CALPUFF was applied using discrete receptor points in each Class I area with an approximate 

receptor resolution of one kilometer. The receptor data used to determine visibility impacts were

taken from the National Park Service‟s (“NPS”) Class I Area Receptor Index.4 According to the 

Figure 3.1 Model Domain with Class I Areas

BART modeling guidance, receptors “...should be located in the nearest Class I area with 

sufficient density to identify likely visibility effects.”

2

 Table 3.2 shows the list of Class I areas 

and the total number of discrete receptors covering each Class I area used as the receptor field in 

CALPUFF. The Illinois EPA recognizes that not all Class I areas in the eastern United States are 

included in the modeling analysis, but the list is considered sufficient to identify maximum 

visibility impacts from BART sources located in Illinois and is therefore adequate for the 

purpose of identifying sources that are subject to BART requirements.
17

Table 3.2 Class I Receptor Areas and Total Discrete Receptors

The daily visibility metric for each receptor is expressed as the change in deciviews compared to 

natural visibility conditions as outlined in the IWAQM guidance.

3

 Natural visibility conditions, 

the 20% best days, for Class I areas used in this analysis are found in Appendix B of USEPA‟s 

visibility guidance document.

5 Annual background concentrations for the eastern United States 

are also given in Table 2-1 of USEPA‟s visibility guidance document.5

Having determined the natural background conditions for each Class I area, modeling was 

conducted to determine visibility degradation beyond natural conditions due to specific sources. 

The difference in visibility degradation due to a source compared with natural conditions, 

expressed in deciviews, is calculated for each Class I area and ranked over the length of the 

modeling simulation. 

Class I Area Abbreviation State Discrete Receptors

Boundary Waters Canoe Area BOWA MN 856

Brigantine National Wildlife Refuge NJ 16

Dolly Sods/Otter Creek Wilderness WV 187

Great Gulf Wilderness NH 38

Great Smoky Mountains National Park TN 736

Hercules-Glades HEGL MO 80

Isle Royale National Park ISLE MI 966

James River Face VA 52

Linville Gorge NC 66

Lye Brook Wilderness VT 103

Mammoth Cave National Park MACA KY 302

Mingo MING MO 47

Seney SENE MI 173

Shenandoah National Park VA 298

Sipsy Wilderness AL 148

Voyageurs National Park MN 366
18

The CALPOST post-processing software was used to depict the output from the CALPUFF 

model. These plots provided initial qualitative spatial information on visual impacts from each 

BART-eligible source. CALPOST was used to determine the number of days at each receptor 

that have at least 5% degradation in light extinction (1/Mm) over background conditions, which 

is equivalent to 0.5 deciviews degradation.

3.2 Modeling Results 

The Illinois EPA modeled each BART-eligible source listed previously in Table 2.1 using the 

CALPUFF model on an individual unit basis. Illinois EPA used either maximum daily or 

maximum hourly emission rates for SO2 and NOx, and specific stack parameters for each unit

identified as BART-eligible, based on data supplied by affected sources. The CALPUFF 

modeling results are summarized in Table 3.3. 

According to the BART Guidelines, a source “causes” visibility impairment if it imparts a 

change of visibility of at least 1.0 deciview at any Class I area, while a source “contributes” to 

visibility impairment if it imparts a change to visibility impairment of at least 0.5 deciviews. 

States are given the opportunity to enact more stringent de minimis thresholds if they choose. 

Illinois EPA believes that these thresholds are adequate and does not propose an alternative 

level. According to the BART Guidelines, the 98th percentile value should be compared to the 

contribution threshold to determine whether a BART-eligible source is subject to BART. If it is 

determined that for a given source there are more than 21 days in three years (the 98th percentile 

based on modeling three years) on which the source causes a 0.5 deciviews impact, or if there are 

more than 7 days in a single year (the 98th percentile based on modeling one year) with a 0.5 

deciviews impact, then the source is subject to BART. Table 3.3 contains the maximum number 

of exceedances attributed to each source for the highest year at any of the Class I areas modeled, 

the maximum number of exceedances over the three-year period at any Class I area modeled, and 

the three year exceedance total for the six nearest federal Class I areas. The six Class I areas 

listed in Table 3.3 are those most frequently impacted by sources in Illinois. To preserve clarity 

in the tabular results, only these six Class I areas are listed. All of the Class I areas listed 

previously in Table 3.2 were included in the modeling, however.
19

Table 3.3 CALPUFF Modeling Results - Number of Days

With Impacts Greater than 0.5 Deciviews at Nearby Class I Areas

Source Category Source Name

Max. Days Class I Areas

3 Yrs 1 Yr BOWA HEGL ISLE MACA MING SENE 

EGUs Dynegy - Baldwin 151 57 19 67 18 104 151 43

Dominion - Kincaid 118 50 26 48 30 118 109 59

Ameren - Coffeen 175 68 33 95 50 166 175 75

Ameren - Edwards 136 53 61 76 69 115 127 136

Midwest Gen. - Powerton 93 37 43 46 43 76 72 93

Midwest Gen. - Joliet 103 40 27 22 36 42 51 103

CWLP 103 44 33 45 35 87 103 68

Ameren - Duck Creek 39 17 17 16 17 31 28 39

Midwest Gen. - Will Cty 32 16 5 2 10 6 5 32

Dynegy - Wood River 16 6 1 4 2 7 16 4

Non-EGUs ExxonMobil 84 35 22 18 30 30 33 84

CITGO 52 22 8 4 14 10 14 52

Conoco 0 0 0 0 0 0 0 0

Aventine 0 0 0 0 0 0 0 0

US Steel 1 1 0 1 0 0 0 0

Marathon 0 0 0 0 0 0 0 0

Lone Star 3 2 1 0 2 0 0 3

Chicago Carbon 2 1 0 0 0 0 0 2

Pilkington 0 0 0 0 0 0 0 0

Big River 0 0 0 0 0 0 0 0

IL Cement 0 0 0 0 0 0 0 0

Owens Brockway 0 0 0 0 0 0 0 0

Koppers 0 0 0 0 0 0 0 0

Carmeuse Lime 0 0 0 0 0 0 0 0

Equistar 0 0 0 0 0 0 0 0

Based on the results of the modeling, eleven sources in Illinois exceed the 0.5 deciview visibility 

impact threshold on at least 22 days over the three-year modeling timeframe, or on at least eight 

days in any one of the three modeled years. These sources are highlighted in red in Table 3.3
20

and depicted graphically in Figure 3.2. Of the eleven sources, nine are electric generating unit 

(“EGU”) sources and two are non-EGU sources (petroleum refineries). 

As mentioned previously, the MRPO determined that the visibility impact of particulate matter

emissions from all BART-eligible sources in the MRPO states will be much less than 0.5 

deciviews in any Class I area. Clearly the visibility impact of particulate matter emissions from 

all BART-eligible sources in Illinois is therefore much less than 0.5 deciviews in any Class I 

area, since particulate matter emissions from BART-eligible sources in Illinois are just a fraction 

of those from all MRPO states. Illinois EPA has nonetheless included PM2.5 emissions in the 

modeling of BART-eligible sources, where reliable emissions estimates were available, to 

determine if those sources caused adverse visibility impacts. Some of the BART-eligible sources 

listed in Table 3.3 that were found to exceed the 0.5 deciview visibility impact threshold on 

fewer than 22 days over the three-year modeling timeframe, or on fewer than 8 days in any one 

of the three modeled years did not have reliable PM2.5 emission estimates at the time when the 

modeling was performed. To ensure that these sources would not cause a greater number of days 

exceeding the 0.5 deciview threshold if PM2.5 emissions had been included, Illinois EPA 

examined the impact of particulate matter emissions from the largest of those sources, the 

Dynegy – Wood River power plant. The modeling results reflected in Table 3.3 for this source 

properly considered particulate matter emissions, in combination with emissions of SO2 and 

NOx. To determine the visibility impacts of just the particulate matter emissions, the Illinois 

EPA ran the CALPUFF model for this source both with and without particulate matter emissions 

included. The modeling indicated that zeroing-out the particulate matter emissions from this 

source reduced by one the number of days exceeding 0.5 deciviews in two of the three years 

modeled. Since the Dynegy – Wood River power plant is the largest of the BART-eligible 

sources in Table 3.3 that has been demonstrated as not causing significant visibility impairment, 

and it is also closer to the nearest Class I area than the other sources (with the exception of 

ConocoPhillips and US Steel which are essentially the same distance), the Illinois EPA has 

concluded that particulate matter emissions do significantly affect the determination of sources 

that are subject-to-BART.
21

The Illinois EPA has determined that BART-eligible emission units at eleven sources in Illinois 

exceed the 0.5 deciview visibility impact threshold on at least 22 days over the three-year 

modeling timeframe, or on at least eight days in any one of the three modeled years, and are 

therefore subject to BART. The specific emission units at the sources that are subject to BART 

are listed in Table 3.4. 

Figure 3.2 Illinois Sources Subject to BART
22

Table 3.4 List of Units Subject to BART

Source Name Unit ID Source Name Unit ID

Dynegy Baldwin Boiler #1 CITGO Heater 115 B-2

Dynegy Baldwin Boiler #2 CITGO Heater 116 B-1

Dynegy Baldwin Boiler #3 CITGO Heater 116 B-2

Dominion Kincaid Boiler #1 CITGO Heater 116 B-3

Dominion Kincaid Boiler #2 CITGO Heater 116 B-4

Ameren Coffeen Boiler CB-1 CITGO Heater 118 B-1

Ameren Coffeen Boiler CB-2 CITGO Heater 118 B-51

Ameren Edwards Boiler #2 CITGO Heater 122 B-2

Ameren Edwards Boiler #3 CITGO Heater 123 B-5

Ameren Duck Creek Boiler #1 CITGO Heater 125 B-1

Midwest Gen. Powerton Boiler #51 CITGO Reboiler 125 B-2

Midwest Gen. Powerton Boiler #52 CITGO SRU 119 A train

Midwest Gen. Powerton Boiler #61 CITGO SRU 119 B train

Midwest Gen. Powerton Boiler #62 CITGO SRU 121 C train

Midwest Gen. Joliet Boiler #71 CITGO SRU 121 D train

Midwest Gen. Joliet Boiler #72 ExxonMobil South sulfur trains

Midwest Gen. Joliet Boiler #81 ExxonMobil FCCU

Midwest Gen. Joliet Boiler #82 ExxonMobil Heaters 1B1A & 1B1B

Midwest Gen. Will County Boiler #4 ExxonMobil Vacuum heater

CWLP Boiler Dallman 1 ExxonMobil Coker chg heaters (E & W)

CWLP Boiler Dallman 2 ExxonMobil Heater 7B1

CWLP Boiler Lakeside 8 ExxonMobil Aux boiler

CITGO Heater 111B-1A ExxonMobil Sat gas lean oil reboiler

CITGO Heater 111B-1B ExxonMobil Heater 2B3

CITGO Heater 111B-2 ExxonMobil Heater 2B5

CITGO FCCU ExxonMobil Heater 2B4

CITGO Heater 113 B-1 ExxonMobil Heater 2B6

CITGO Aux Boiler 430 B-1 ExxonMobil Heater 2B7

CITGO Heater 113 B-2 ExxonMobil Reboiler 17-B-2

CITGO Heater 114 B-1 ExxonMobil Heater 3B1

CITGO Heater 114 B-2 ExxonMobil Heater 3B2

CITGO Heater 114 B-3 ExxonMobil Blow down East flare

CITGO Heater 115 B-1 ExxonMobil Blow down South flare
23

4.0 BART Controls in Illinois

The Regional Haze Rule defines BART as: “... an emission limitation based on the degree of 

reduction achievable through application of the best system of continuous emission reduction for 

each pollutant which is emitted by a [BART-eligible source].” 40 CFR §51.301. Once it is 

determined that a source is subject to BART, the following five factors must be considered to 

establish an emission limitation to meet the BART requirement:

1. the cost of compliance;

2. the energy and non air quality environmental impacts of compliance;

3. any pollution control equipment in use or in existence at the source;

4. the remaining useful life of the source;

5. the degree of improvement in visibility which may reasonably be anticipated to result 

from the use of such technology. 

Illinois EPA has considered these factors to determine the level of control necessary for those 

units and sources to meet BART. 

4.1 BART Controls for Illinois EGUs

For coal-fired EGUs, the BART Guidelines provide presumptive emission limits or control 

levels for various boiler types and coal types. The presumptive emission limits for coal-fired 

EGUs are shown in Table 4.1. 

The Illinois EPA has compared these presumptive BART emission levels to existing emission 

reduction requirements and commitments for the subject-to-BART EGUs in Illinois. The 

existing emission reduction requirements and commitments for coal-fired EGUs in Illinois that 

are subject-to-BART include: 

the Multi-Pollutant Standards (“MPS”) and Combined Pollutant Standard (“CPS”) 

codified in the Illinois Mercury Rule, 35 Ill. Adm. Code Part 225, that apply to Ameren,

Dynegy, and Midwest Generation; 
24

a multi-pollutant agreement between the Illinois EPA and Dominion Energy Services, as 

operator, and Kincaid Generation, LLC, as owner, of the Kincaid Generating Station 

(collectively “Dominion Kincaid”), to achieve BART-control levels; and

a similar agreement between the Illinois EPA and the City of Springfield, Illinois d/b/a 

City, Water, Light and Power (CWLP), to achieve BART-control levels and to shut down 

one of its existing subject-to-BART units.

Table 4.1 Presumptive BART Emission Limits for Coal-Fired EGUs

Pollutant Boiler Type Coal Type Presumptive Limit 

(lbs/mmBTU)

SO2 All units All coal types 0.15 

(or 95% control)

NOx Dry-bottom wall-fired Bituminous 0.39

Sub-bituminous 0.23

Lignite 0.29

Tangential-fired Bituminous 0.28

Sub-bituminous 0.15

Lignite 0.17

Cell burners Bituminous 0.40

Sub-bituminous 0.45

Dry-turbo-fired Bituminous 0.32

Sub-bituminous 0.23

Wet-bottom tangentialfiredAll

0.62

Cyclone All 0.10

4.1.1 EGUs under the MPS and CPS

Three electric utilities operating in Illinois, Dynegy, Ameren, and Midwest Generation have 

committed to comply with the MPS and CPS under the Illinois Mercury Rule, requiring the 

installation of state-of-the-art pollution controls on many of their electric generating units in 
25

Illinois. These regulations were promulgated to allow coal-fired electric utilities more flexibility 

in meeting the Illinois Mercury Rule in exchange for significant NOx and SO2 reductions. 

Appendix C contains the relevant portions of the fully adopted Illinois Mercury Rule, with the 

requirements for NOx and SO2 emission reductions highlighted. Illinois intends to submit 

Appendix C to USEPA, the highlighted portions of which will become part of Illinois‟ SIP to 

satisfy BART obligations for affected units at these three utilities. In addition, the MPS and CPS 

requirements will ultimately be contained in federally enforceable permits. 

The MPS and CPS require affected utilities to meet fleet-wide average emission rates, which will 

require installation of controls on emission units regardless of whether or not they are subject to 

BART. The agreements between Illinois and the utilities are intended to allow the companies the 

flexibility to meet the fleet-wide emission limits in the most cost-effective manner. The 

agreements contain a range of compliance dates, beginning as early as 2012 and as late as 2019. 

The Illinois EPA recognizes that, in general, the compliance date for BART controls is within 5 

years of USEPA‟s approval of the State‟s SIP. Assuming USEPA approves Illinois‟ SIP in 2011 

or 2012, the compliance date for BART controls would be in 2016 or 2017. The Illinois EPA‟s 

analysis of emission reductions that will result from implementation of the MPS and CPS by the

year 2015 demonstrates conclusively that Illinois‟ approach will yield much larger reductions of 

NOx and SO2 than will implementation of BART controls on just subject to BART emission 

units. Emission reductions occurring after 2015 will improve visibility in Class I areas impacted 

by sources in Illinois, regardless of USEPA‟s decision of whether to approve those reductions as 

meeting BART requirements. The following subsections provide Illinois EPA‟s analysis of the 

emission reductions expected from the MPS and CPS and a description of the controls that will 

most likely be installed as a result of the MPS and CPS.

4.1.1.1 Dynegy 

Dynegy operates several electric generating stations in Illinois, all of which are affected by the 

requirements of the MPS. Only the three coal-fired boilers at Baldwin are subject to BART, 

however. Units 1 and 2 at Baldwin are cyclone-fired boilers burning sub-bituminous coal, while 

Unit 3 is a tangentially-fired unit burning sub-bituminous coal. Currently, Units 1 and 2 are 

controlled by over-fire air (“OFA”) and selective catalytic reduction (“SCR”) for NOx, while 
26

Unit 3 is controlled by low-NOx burners and OFA. All three units are also limited by a federal 

consent decree which requires that by December 31, 2012 NOx emissions cannot exceed 0.10 

pounds per million British thermal units (“lb/mmBTU”) of NOx on a 30-day rolling average. 

The presumptive BART emission limit for NOx for cyclone-fired boilers is 0.10 lb/mmBTU. 

For tangentially-fired EGU boilers burning sub-bituminous coal, the presumptive BART 

emission limit for NOx is 0.15 lb/mmBTU. Since all three units at Baldwin are required to meet 

0.10 lb/mmBTU, the presumptive BART limits for NOx will be met.

All three units at Baldwin currently use low-sulfur coal to reduce SO2 emissions. However, 

Dynegy is installing dry scrubbers on all three units at Baldwin by December 31, 2012, which 

will allow these units to achieve SO2 emissions levels well below the presumptive BART limit of 

0.15 lb/mmBTU. Dynegy has also committed to installing baghouses for particulate control on 

all three units by December 31, 2012. 

Tables 4.2 and 4.3 compare the emission reductions expected from Dynegy system wide from 

compliance with the MPS and the expected emission reductions from compliance with BART for 

NOx and SO2, respectively. USEPA requires that BART controls be installed within five years 

from the date the State‟s BART SIP is approved. Accordingly, Tables 4.2 and 4.3 compare 

expected emissions reductions from the MPS with the reductions that would be achieved from 

the subject to BART units meeting the presumptive BART emission limits for the year 2015. 

The Illinois EPA has estimated that compliance with the MPS will reduce NOx emissions from 

Dynegy system wide by 23,831 TPY compared to 2002 emissions levels, and will reduce SO2

emissions system wide by 47,347 TPY compared to 2002 emissions levels. Applying 

presumptive BART controls to just the units at Baldwin that are subject to BART will yield NOx 

reductions of 16,169 TPY, and SO2 reductions of 16,658 TPY. Compliance with the MPS on a 

system-wide basis will therefore yield much larger reductions of NOx and SO2 than will the 

application of BART.
27

Table 4.2 NOx reductions from Dynegy EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015* MPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Baldwin 1 43,884 0.55 12,119 0.10 9,925 0.10 9,925 0.10 9,925

Baldwin 2 37,135 0.4 7,405 0.10 5,548 0.10 5,548 0.10 5,548

Baldwin 3 46,403 0.12 2,850 0.15 -696 0.10 464 0.10 464

Havana 9 28,514 0.27 3,901 NA NA 0.10 2,424 0.10 2,424

Hennepin 1 4,684 0.32 760 NA NA 0.10 515 0.10 515

Hennepin 2 17,575 0.33 2,862 NA NA 0.10 2,021 0.10 2,021

Vermilion 1 5,311 0.37 986 NA NA 0.10 717 0.10 717

Vermilion 2 6,741 0.37 1,231 NA NA 0.10 910 0.10 910

Wood River 4 5,561 0.19 521 NA NA 0.10 250 0.10 250

Wood River 5 17,611 0.22 1,903 NA NA 0.10 1,057 0.10 1,057

0.324 16,169 23,831 23,831

*The MPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.

Table 4.3 SO2 reductions from Dynegy EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015* MPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Baldwin 1 43,884 0.41 9,053 0.15 5,705 0.19 4,827 0.19 4,827

Baldwin 2 37,135 0.39 7,283 0.15 4,456 0.19 3,714 0.19 3,714

Baldwin 3 46,403 0.43 9,931 0.15 6,496 0.19 5,568 0.19 5,568

Havana 9 28,514 0.9 12,815 NA NA 0.19 10,122 0.19 10,122

Hennepin 1 4,684 0.43 1,000 NA NA 0.19 562 0.19 562

Hennepin 2 17,575 0.43 3,792 NA NA 0.19 2,109 0.19 2,109

Vermilion 1 5,311 2.75 7,293 NA NA 0.19 6,798 0.19 6,798

Vermilion 2 6,741 2.74 9,224 NA NA 0.19 8,595 0.19 8,595

Wood River 4 5,561 0.55 1,536 NA NA 0.19 1,001 0.19 1,001

Wood River 5 17,611 0.65 5,726 NA NA 0.19 4,051 0.19 4,051

0.634 16,658 47,347 47,347

*The MPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.
28

4.1.1.2 Ameren

Ameren operates EGUs at six locations in Illinois: Hutsonville, Newton, Coffeen, Meredosia, 

Duck Creek, and Edwards. Three of these, Coffeen, Duck Creek, and Edwards have at least 

some BART-eligible units. 

Coffeen

There are two units at Coffeen, both of which are subject to BART. They are both cyclone-type 

units firing a blend of bituminous and sub-bituminous coals. NOx emissions from both units are 

already controlled using SCRs. Ameren installed wet scrubbers on both units in 2009. 

Duck Creek

The single unit at Duck Creek is subject to BART. It is a dry-bottom wall-fired unit burning 

bituminous coal. The unit is controlled by an SCR in addition to low-NOx burners for NOx

control. Ameren installed a wet scrubber in 2009.

Edwards

Ameren operates three units at the Edwards facility, two of which (Units 2 and 3) are subject to 

BART. Both units are dry-bottom wall-fired units that burn sub-bituminous coal. Unit 2 has 

low-NOx burners, which Ameren plans to upgrade with a new low-NOx burner/OFA system. 

NOx is currently being controlled at Unit 3 with an SCR and low-NOx burners. Ameren is 

expected to install a new scrubber, along with a baghouse for particulate control, on Unit 3 by 

January 2014. Ameren is relying on system-wide reductions required by the MPS to meet BART 

at Edwards. 

For Ameren system wide, the MPS will provide substantially greater source-wide reductions of 

NOx and SO2 by 2015 than would be achieved by just requiring subject-to-BART units to meet 

the presumptive BART emission limits. As shown in Tables 4.4 and 4.5, the MPS will lead to 

fleet-wide reductions of almost 28,000 TPY of NOx, and more than 131,000 TPY of SO2 by 

2015, which is much greater than would be achieved by subject-to-BART units meeting

presumptive BART emission limits. 
29

Table 4.4 NOx reductions from Ameren EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015* MPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Coffeen 1 18,570 0.53 4,918 0.10 3,990 0.11 3,900 0.11 3,900

Coffeen 2 37,545 0.5 9,422 0.10 7,545 0.11 7,321 0.11 7,321

Duck Creek 1 22,635 0.47 5,328 0.39 905 0.11 4,074 0.11 4,074

E D 

Edwards 1 6,417 0.41 1,306 NA NA 0.11 963 0.11 963

E D 

Edwards 2 17,222 0.45 3,901 0.23 1,894 0.11 2,928 0.11 2,928

E D 

Edwards 3 15,972 0.46 3,639 0.23 1,837 0.11 2,795 0.11 2,795

Hutsonville 5 3,161 0.57 897 NA NA 0.11 727 0.11 727

Hutsonville 6 3,443 0.52 902 NA NA 0.11 706 0.11 706

Joppa 1 13,548 0.13 876 NA NA 0.11 135 0.11 135

Joppa 2 16,258 0.13 1,048 NA NA 0.11 163 0.11 163

Joppa 3 15,396 0.13 1,030 NA NA 0.11 154 0.11 154

Joppa 4 13,402 0.13 904 NA NA 0.11 134 0.11 134

Joppa 5 15,094 0.12 939 NA NA 0.11 75 0.11 75

Joppa 6 16,063 0.12 999 NA NA 0.11 80 0.11 80

Meredosia 1 1,134 0.51 292 NA NA 0.11 227 0.11 227

Meredosia 2 1,337 0.5 336 NA NA 0.11 261 0.11 261

Meredosia 3 1,069 0.51 271 NA NA 0.11 214 0.11 214

Meredosia 4 1,406 0.51 357 NA NA 0.11 281 0.11 281

Meredosia 5 10,810 0.47 2,524 NA NA 0.11 1,946 0.11 1,946

Newton 1 40,631 0.15 3,037 NA NA 0.11 813 0.11 813

Newton 2 38,533 0.11 2,215 NA NA 0.11 0 0.11 0

0.292 16,171 27,896 27,896

*The MPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.
30

Table 4.5 SO2 reductions from Ameren EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015* MPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Coffeen 1 18,570 1.54 14,332 0.15 12,906 0.25 11,978 0.23 12,163

Coffeen 2 37,545 1.49 27,999 0.15 25,155 0.25 23,278 0.23 23,653

Duck Creek 1 22,635 0.97 11,026 0.15 9,280 0.25 8,149 0.23 8,375

E D 

Edwards 1 6,417 3.55 11,399 NA NA 0.25 10,588 0.23 10,652

E D 

Edwards 2 17,222 1.7 14,666 0.15 13,347 0.25 12,486 0.23 12,658

E D 

Edwards 3 15,972 1.21 9,683 0.15 8,465 0.25 7,667 0.23 7,826

Hutsonville 5 3,161 4.53 7,163 NA NA 0.25 6,765 0.23 6,796

Hutsonville 6 3,443 4.53 7,791 NA NA 0.25 7,368 0.23 7,402

Joppa 1 13,548 0.51 3,441 NA NA 0.25 1,761 0.23 1,897

Joppa 2 16,258 0.51 4,139 NA NA 0.25 2,114 0.23 2,276

Joppa 3 15,396 0.51 3,947 NA NA 0.25 2,001 0.23 2,155

Joppa 4 13,402 0.52 3,488 NA NA 0.25 1,809 0.23 1,943

Joppa 5 15,094 0.52 3,932 NA NA 0.25 2,038 0.23 2,189

Joppa 6 16,063 0.52 4,182 NA NA 0.25 2,169 0.23 2,329

Meredosia 1 1,134 5.02 2,844 NA NA 0.25 2,705 0.23 2,716

Meredosia 2 1,337 5.02 3,356 NA NA 0.25 3,189 0.23 3,202

Meredosia 3 1,069 5.04 2,694 NA NA 0.25 2,560 0.23 2,571

Meredosia 4 1,406 5 3,518 NA NA 0.25 3,339 0.23 3,353

Meredosia 5 10,810 2.34 12,639 NA NA 0.25 11,296 0.23 11,405

Newton 1 40,631 0.45 9,046 NA NA 0.25 4,063 0.23 4,469

Newton 2 38,533 0.46 8,823 NA NA 0.25 4,046 0.23 4,431

1.099 69,154 131,367 134,464

*The MPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.

4.1.1.3 Midwest Generation

Midwest Generation operates 19 coal-fired EGUs at six separate locations in Illinois. Nine of 

these units, located at Powerton, Joliet, and Will County, are subject to BART. 

Powerton

All four units at the Powerton station are subject to BART. All four units are cyclone-type

boilers firing sub-bituminous coal and vent to a common stack. Current NOx control for all units 
31

consists of low-NOx burners and OFA. Midwest Generation is expected to install selective noncatalytic reduction (SNCR) controls on all four units by 2012. The units currently burn lowsulfur coal to control for SO2, but Midwest Generation currently plans to install flue gas 

desulfurization (FGD) equipment by the end of 2013 on all four units. 

Joliet

Four of the five units (Units 71, 72, 81, and 82) at the Joliet facility are subject to BART. The 

four units of interest are all tangentially-fired boilers burning sub-bituminous coal. Current NOx

controls for Boilers 71, 72, 81, and 82 consist of low-NOx burners and OFA. Midwest 

Generation is expected to install SNCR controls on these four units by 2012. For SO2, Midwest 

Generation is expected to install FGD equipment on all four BART units at Joliet by 2019.

Will County

Of the four units at the Will County plant, only Unit 4 is subject to BART. Unit 4 is tangentially 

fired and burns sub-bituminous coal. NOx emissions from Unit 4 are currently controlled by 

low-NOx burners and OFA. Midwest Generation is expected to install an SNCR on this unit by 

2012. For SO2, Midwest Generation is expected to install FGD equipment by 2019.

It should be noted that under the CPS, Midwest Generation is not required to meet unit specific 

emission limits for NOx or SO2, and that the anticipated CPS emission estimates given in Tables 

4.6 and 4.7 reflect the fleet-wide average emissions for all units. Tables 4.6 and 4.7 show that

the CPS will lead to system-wide reductions of more than 38,000 TPY of NOx and more than 

35,000 TPY of SO2 by 2015, which are much greater than the reductions that would be achieved 

by meeting the presumptive BART emission levels at the subject-to-BART units. 

4.1.2 Other Illinois EGUs

The MPS and CPS requirements do not apply to Dominion Kincaid or to CWLP. The Illinois 

EPA has negotiated separate agreements with these companies to address the BART 

requirements. Consistent with these agreements, both plants have either installed controls or 

plan to install controls that will meet or exceed the presumptive BART limits. Unit-specific 

requirements for these sources are contained in federally-enforceable permits, which are included 
32

as part of Illinois‟ SIP submittal. The individual BART-eligible units at each source are

described in the following sections.

Table 4.6 NOx reductions from Midwest Generation EGUs BART vs. MPS

Base Year Presumptive BART CPS 2015* CPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Crawford 7 11,627 0.2 1,187 NA NA 0.11 523 0.11 523

Crawford 8 17,348 0.19 1,663 NA NA 0.11 694 0.11 694

Fisk 19 14,650 0.34 2,463 NA NA 0.11 1,685 0.11 1,685

Joliet 29 71 15,034 0.12 871 0.15 -226 0.11 75 0.11 75

Joliet 29 72 13,824 0.12 816 0.15 -207 0.11 69 0.11 69

Joliet 29 81 15,585 0.13 1,049 0.15 -156 0.11 156 0.11 156

Joliet 29 82 15,403 0.14 1,073 0.15 -77 0.11 231 0.11 231

Joliet 9 5 14,369 0.36 2,562 NA NA 0.11 1,796 0.11 1,796

Powerton 51 20,936 0.73 7,594 0.10 6,547 0.11 6,490 0.11 6,490

Powerton 52 21,137 0.73 7,695 0.10 6,638 0.11 6,552 0.11 6,552

Powerton 61 18,293 0.66 5,995 0.10 5,080 0.11 5,031 0.11 5,031

Powerton 62 18,088 0.66 5,936 0.10 5,031 0.11 4,974 0.11 4,974

Waukegan 17 7,502 0.63 2,365 NA NA 0.11 1,951 0.11 1,951

Waukegan 7 16,117 0.14 1,092 NA NA 0.11 242 0.11 242

Waukegan 8 21,950 0.14 1,488 NA NA 0.11 329 0.11 329

Will County 1 9,398 0.85 4,000 NA NA 0.11 3,477 0.11 3,477

Will County 2 8,293 0.8 3,310 NA NA 0.11 2,861 0.11 2,861

Will County 3 15,559 0.17 1,300 NA NA 0.11 467 0.11 467

Will County 4 27,585 0.15 2,009 0.15 0 0.11 552 0.11 552

0.360 22,630 38,155 38,155

*The CPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.
33

Table 4.7 SO2 reductions from Midwest Generation EGUs BART vs. MPS

Base Year Presumptive BART CPS 2015* CPS Final*

Plant Unit

1000 

mmBTU 

Lbs/ 

mmBTU Tons

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/ 

mmBTU

Tons/Year 

Reduction 

Crawford 7 11,627 0.54 3,142 NA NA 0.28 1,512 0.11 2,500

Crawford 8 17,348 0.51 4,453 NA NA 0.28 1,995 0.11 3,470

Fisk 19 14,650 0.52 3,843 NA NA 0.28 1,758 0.11 3,003

Joliet 29 71 15,034 0.7 5,276 0.15 4,134 0.28 3,157 0.11 4,435

Joliet 29 72 13,824 0.7 4,828 0.15 3,802 0.28 2,903 0.11 4,078

Joliet 29 81 15,585 0.68 5,300 0.15 4,130 0.28 3,117 0.11 4,442

Joliet 29 82 15,403 0.68 5,260 0.15 4,082 0.28 3,081 0.11 4,390

Joliet 9 5 14,369 0.63 4,559 NA NA 0.28 2,515 0.11 3,736

Powerton 51 20,936 0.42 4,444 0.15 2,826 0.28 1,466 0.11 3,245

Powerton 52 21,137 0.43 4,497 0.15 2,959 0.28 1,585 0.11 3,382

Powerton 61 18,293 0.43 3,964 0.15 2,561 0.28 1,372 0.11 2,927

Powerton 62 18,088 0.43 3,909 0.15 2,532 0.28 1,357 0.11 2,894

Waukegan 17 7,502 0.44 1,642 NA NA 0.28 600 0.11 1,238

Waukegan 7 16,117 0.47 3,754 NA NA 0.28 1,531 0.11 2,901

Waukegan 8 21,950 0.49 5,385 NA NA 0.28 2,305 0.11 4,171

Will County 1 9,398 0.42 1,969 NA NA 0.28 658 0.11 1,457

Will County 2 8,293 0.39 1,617 NA NA 0.28 456 0.11 1,161

Will County 3 15,559 0.47 3,636 NA NA 0.28 1,478 0.11 2,801

Will County 4 27,585 0.47 6,462 0.15 4,414 0.28 2,621 0.11 4,965

0.515 31,440 35,465 61,194

*The CPS emission limits are a system-wide average and are not intended to reflect unit-specific emission limits.

4.1.2.1 CWLP 

The subject-to-BART units at CWLP are Dallman 31, Dallman 32, and Lakeside 8. CWLP shut 

down the Lakeside unit in 2009. The Dallman 31 and 32 units are cyclone boilers and burn

bituminous coal. CWLP currently operates SCRs and scrubbers on both Dallman units. It 

should be noted that CWLP‟s generating capacity is less than 750 MW, so the presumptive 

BART emission limits shown in Table 4.1 do not apply. Rather, the BART rule requires that 

such units operate SCRs, or equivalent controls, to control NOx emissions on an annual basis. 

For SO2, the BART rule requires 95% emissions reduction. 
34

CWLP has agreed to operate SCRs on the two subject-to-BART units to meet an annual average 

emissions rate of 0.12 lb/mmBTU by 2015. CWLP also agreed to meet a NOx emission rate of 

0.11 lb/mmBTU by 2017. The Illinois EPA considers the operation of SCRs on the two subjectto-BART units at CWLP at the emission rates contained in the agreement between CWLP and 

the Illinois EPA to be sufficient to meet the BART requirement. For SO2, the scrubbers on the 

Dallman units will achieve greater than 95% emissions reductions, which will meet the 

presumptive BART requirement for boilers burning bituminous coal (historical average sulfur 

content of 6.0 lbs/mmBTU). Tables 4.8 and 4.9 reflect the reductions expected from operation 

of these controls by 2015, and demonstrate that CWLP will achieve emission reductions for NOx 

and SO2, respectively, which meet or exceed the presumptive BART control requirements.

Table 4.8 NOx Reductions from CWLP - BART vs. MOU

Base Year 2002 Presumptive BART MOU 2015* MOU Final*

Plant Unit 1000 

mmBTU 

Lbs/ 

mmBTU Tons Lbs/mmBTU

Tons/Year 

Reduction 

 Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/

mmBTU

Tons/Year 

Reduction 

Dallman 31 4,528 1.10 2,484 0.12 2,212 0.12 2,212 0.11 2,235

Dallman 32 4,787 1.11 2,654 0.12 2,366 0.12 2,366 0.11 2,391

Lakeside 8 1,593 0.94 749 0.12 653 0 749 0 749

5,231 5,327 5,375

*The emission limit is an average between Dallman Units 31 and 32. The emission limits shown here are not 

intended to reflect unit-specific emission limits.

Table 4.9 SO2 Reductions from CWLP - BART vs. MOU

Base Year 2002 Presumptive BART MOU 2015* MOU Final*

Plant Unit 1000 

mmBTU 

Lbs/ 

mmBTU Tons Lbs/mmBTU

Tons/Year 

Reduction 

 Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/

mmBTU

Tons/Year 

Reduction 

Dallman 31 4,528 0.33 753 0.30 74 0.25 187 0.23 232

Dallman 32 4,787 0.35 835 0.30 117 0.25 236 0.23 284

Lakeside 8 1,593 5.47 4,358 0.30 4,119 0 4,358 0 4,358

4,310 4,781 4,875

* The emission limit is an average between Dallman Units 31 and 32. The emission limits shown here are not 

intended to reflect unit-specific emission limits.
35

4.1.2.2 Dominion Kincaid 

Both boilers at Dominion‟s Kincaid facility are subject to BART. The two boilers are cyclones 

and both burn sub-bituminous coal. Dominion currently operates SCRs on both units at Kincaid 

to control NOx emissions, which, when operated on an annual basis, will meet the presumptive 

BART control requirement for cyclone boilers. There are currently no controls in place to 

reduce emissions of SO2. The original agreement between Dominion and the Illinois EPA 

required that SO2 emissions be reduced at Kincaid from the current rate of 0.46 lbs/mmBTU to a 

rate of 0.20 lbs/mmBTU by January 1, 2014, and to 0.18 lbs/mmBTU by January 1, 2017. This 

emission rate did not meet the presumptive BART emission limit of 0.15 lb/mmBTU. Rather, 

Dominion conducted a site-specific BART analysis for the Kincaid plant, including a control 

technology review and CALPUFF modeling to assess the visibility impacts of several control 

alternatives. Dominion‟s site-specific analysis for the Kincaid plant is included as Appendix D. 

In subsequent discussions, Dominion agreed to further reduce SO2 emissions at the Kincaid plant 

to a rate of 0.15 lbs/mmBTU, which meets the presumptive BART emissions limit. Dominion 

has also agreed to meet the NOx emission rate of 0.07 lbs/mmBTU, in accordance with the 

original agreement with Illinois EPA. This emission rate is considerably more stringent than the 

presumptive BART emission limit of 0.10 lbs/mmBTU. The final agreement between Dominion

and the Illinois EPA requires the two subject-to-BART units at Kincaid to meet a NOx emission 

rate of 0.07 lbs/mmBTU on a year-round basis beginning March 1, 2013, and that SO2 emissions 

be reduced from the current rate of 0.46 lbs/mmBTU to a rate of 0.20 lbs/mmBTU by January 1, 

2014, and to 0.15 lbs/mmBTU by January 1, 2017.

 

Dominion‟s site-specific analysis included a modeling analysis addressing the visibility impacts 

of the Kincaid plant at the two closest Class I areas, the Mingo National Wildlife Refuge in 

Missouri and at Mammoth Cave in Kentucky. The NOx and SO2 emission rates used in this 

modeling analysis reflected the original agreement between the Illinois EPA and Dominion. 

Dominion‟s modeling analysis also used a modeling methodology that was different from the 

methodology used by Illinois EPA in the CALPUFF modeling described in Section 3.0 of this 

report. The Illinois EPA has performed additional modeling, using the federally-approved 

modeling protocol, to assess the visibility improvements of both the original and the revised 
36

agreements, and on an expanded list of Class I areas potentially impacted by the Kincaid plant.

The list of Class I areas included in Illinois EPA‟s analysis is listed in Table 3.3. The results of 

this analysis are shown in Table 4.10. 

The results shown in Table 4.10 compare the number of days exceeding the 0.5 deciview 

threshold at Class I areas for the following scenarios: NOx and SO2 emissions at Kincaid 

meeting the presumptive BART emission limits of 0.10 and 0.15 lbs/mmBTU, respectively; NOx 

and SO2 emissions at Kincaid meeting the emission limits of 0.07 and 0.18 lbs/mmBTU, 

respectively per the original agreement; and NOx and SO2 emissions at Kincaid meeting the 

emission limits of 0.07 and 0.15 lbs/mmBTU, respectively per the final agreement. The 

maximum number of days exceeding the 0.5 deciview threshold in any single year and the total 

number of days in all three years modeled are shown in the table. Only those Class I areas with 

days exceeding the threshold are listed in the table, in other words, all other modeled Class I 

areas were predicted to have no days exceeding 0.5 deciviews in either scenario. Comparing the 

number of days exceeding 0.5 deciviews between presumptive BART controls and the two 

control scenarios, the results demonstrate that Dominion‟s original control plan resulted in 

generally equivalent visibility improvements than would be expected from controls meeting the 

presumptive BART emission limits. At Mammoth Cave and Isle Royale, Dominion‟s original 

control plan resulted in fewer days exceeding 0.5 deciviews, compared to presumptive BART, 

but the presumptive BART scenario resulted in fewer days exceeding 0.5 deciviews at Mingo 

and Hercules Glade. The modeling results for the final agreement demonstrate visibility 

improvements at Mammoth Cave, Mingo, Seney, Isle Royale, and Hercules Glade, compared to 

both the presumptive BART scenario and the original agreement. At all other Class I areas, there 

is no difference in the number of days exceeding the threshold between the scenarios modeled. 

The Illinois EPA concludes that the modeling results demonstrate that Dominion‟s final control 

plan for the Kincaid facility will provide greater visibility improvements than the presumptive 

BART emission limits.
37

Table 4.10 Comparison of Visibility Impacts from Dominion Kincaid Emissions Control 

Scenarios – Number of Days with Impacts Greater Than 0.5 Deciviews

Class I Area

Presumptive BART Original Agreement Final Agreement

1 year 3 years 1 year 3 years 1 year 3 years

Mammoth Cave 5 9 4 7 4 5

Mingo 1 3 2 5 1 2

Seney 2 3 2 3 1 2

Isle Royale 2 3 1 2 1 1

Hercules Glade 1 1 1 2 0 0

Boundary Waters 1 1 1 1 1 1

Great Gulf 1 1 1 1 1 1

 

Tables 4.11 and 4.12 compare the emission reductions expected from Dominion‟s final control 

plan and the emission reductions that would occur from compliance with the presumptive BART 

emission limits for NOx and SO2. As shown in the tables, expected NOx emission reductions 

from Dominion‟s final control plan exceed the reductions that would occur from implementation 

of presumptive BART by more than 900 TPY. Expected SO2 emission reductions from 

Dominion Kincaid‟s final control plan meet presumptive BART and greatly exceed the 

reductions expected in the original agreement with the Illinois EPA. Since air quality modeling

has adequately demonstrated that the final control plan will result in greater visibility 

improvements than will the presumptive BART emission limits, the Illinois EPA believes the 

final control plan meets the BART requirement for the Kincaid facility.

Table 4.11 NOx Reductions from Dominion - BART vs. MOU

Base Year 2002 Presumptive BART Final Agreement

Plant Unit 1000 

mmBTU 

Lbs/ 

mmBTU Tons Lbs/mmBTU

Tons/Year 

Reduction 

 Lbs/ 

mmBTU

Tons/Year 

Reduction 

Kincaid 1 32,265 0.64 10,300 0.10 8,686 0.07 9,171

Kincaid 2 32,238 0.66 10,605 0.10 8,993 0.07 9,476

17,679 18,648

* The emission limit is an average between Kincaid Units 1 and 2. The emission limits shown here are not intended 

to reflect unit-specific emission limits.
38

Table 4.12 SO2 Reductions from Dominion - BART vs. Final Agreement

Base Year 2002 Presumptive BART Final Agreement 

2015*

Final Agreement 

2017*

Plant Unit 1000 

mmBTU 

Lbs/ 

mmBTU Tons Lbs/mmBTU

Tons/Year 

Reduction 

 Lbs/ 

mmBTU

Tons/Year 

Reduction 

Lbs/

mmBTU

Tons/Year 

Reduction 

Kincaid 1 32,265 0.55 8,873 0.15 6,453 0.20 5,646 0.15 6,453

Kincaid 2 32,238 0.54 8,704 0.15 6,286 0.20 5,480 0.15 6,286

12,739 11,126 12,739

*The The emission limit is an average between Kincaid Units 1 and 2. The emission limits shown here are not 

intended to reflect unit-specific emission limits.

4.2 BART Controls for Non-EGUs

The two non-utility sources that have emission units that are subject to BART are both petroleum 

refineries located in the Chicago area. These sources are the CITGO refinery in Lemont and the 

ExxonMobil refinery south of Joliet. Both refineries have been the subject of litigation by 

USEPA that has resulted in legal settlements as set forth in consent decrees. The consent decrees 

establish federally-enforceable emission limits for these sources that have resulted, or will result,

in significant reductions in SO2 and NOx emissions. The Illinois EPA considers the requirements 

of these consent decrees to be sufficient to meet the requirements for BART. The consent 

decrees for ExxonMobil and CITGO are included in this document as Appendices E and F, 

respectively. The following subsections describe the requirements established by the consent 

decrees for these sources. 

4.2.1 CITGO

The burners and heaters that are subject to BART are required by the consent decree to burn fuel 

gas having no more than 0.1 grains per dry standard cubic foot of hydrogen sulfide, consistent 

with Standards of Performance for New Stationary Sources (NSPS) Subpart J limits. (40 CFR

§60.100) The Fluid Catalytic Cracking Unit (FCCU) has an SCR/wet gas scrubber system that 

began operation early in 2008. The FCCU controls will reduce SO2 by more than 85% and NOx

by at least 90%. In 2008, a tail gas recovery unit was installed to control SO2 emissions from the 

119A and 119B sulfur trains. Units 119A and 119B had previously been uncontrolled. These

controls have reduced SO2 from each train by about 98%, reducing the emissions to below the 

NSPS Subpart J limit of 250 parts per million of volume (“ppmv”) of SO2. Tables 4.13 and 4.14

compare expected emissions for NOx and SO2, respectively, from the application of controls on 
39

units that are subject to BART, and on units affected by the consent decree. On a source-wide 

basis, the consent decree will decrease NOx emissions by more than 1,200 TPY, and will 

decrease SO2 emissions by more than 15,000 TPY. The Illinois EPA considers the requirements 

of the consent decree to be sufficient to meet the requirements for BART for the CITGO 

refinery. 

4.2.2 ExxonMobil

As with CITGO, the combustion units at ExxonMobil are required by the consent decree to fire 

fuel gas that complies with NSPS Subpart J. The FCCU and the south sulfur recovery unit are 

the largest remaining emission units that are subject to BART. The FCCU is controlled by a wet 

gas scrubber installed in 2008. ExxonMobil is required under the consent decree to install and 

operate an SCR to control NOx emissions from the FCCU by 2011. The south sulfur recovery 

unit now operates with a tail gas recovery unit installed in 2008, which reduces emissions of SO2

to below the NSPS Subpart J limit of 250 ppmv of SO2. Tables 4.15 and 4.16 compare expected 

emissions reductions for NOx and SO2, respectively, from the application of controls on units 

that are subject to BART, and on units affected by the consent decree. On a source-wide basis,

the consent decree will decrease NOx emissions by more than 1,600 TPY, and will decrease SO2

emissions by more than 18,000 TPY. The Illinois EPA considers the requirements of the consent 

decree to be sufficient to meet the requirements for BART for the ExxonMobil refinery. 
40

Table 4.13 NOx Reductions from CITGO - BART vs. Consent Decree

2002 

Base BART Controls Consent Decree 2013

Point Unit # Tons Tons Tons/Year 

Reduction Tons Tons/Year Reduction 

3

ATMOSPHERIC HEATER 111B-1A 92.84 56.16 36.68 56.16 36.68

4

ATMOSPHERIC HEATER 111B-1B 74.55 56.16 18.39 56.16 18.39

5 CRUDE VACUUM HEATER 111B-2 9.36 9.36 0 9.36 0

7

FCCU CATALYST REGENERATION 112D-1 1065.67 106.57 959.10 106.57 959.10

11 COKER CHARGE HEATER 113B-1 12.74 12.74 0 12.74 0

19 CHARGE HEATER & STABILIZER REBOILER 116B-1 107.67 28.7 79.0 28.7 79.0

21 HOT OIL HEATER 118B-1 10.36 10.36 0 10.36 0

31 FEED HEATER 125B-1 6.45 6.45 0 6.45 0

37 AUXILIARY BOILER 430B-1 167.11 35.35 131.76 35.35 131.76

64 COKER CHARGE HEATER 113B-2 12.44 12.44 0 12.44 0

66

INTERHEATER & NAPTHA STRIPPER REBOILER 

116B-2

58.75 15.67 43.08 15.67 43.08

74 STRIPPER REBOILER 125B-2 18.21 18.21 0 18.21 0

215 CLAUS SULFUR RECOVERY UNITS 119A & B 9.56 9.56 0 9.56 0

216 CLAUS SULFUR RECOVERY UNITS 121C & D 10.38 10.38 0 10.38 0

1268.01 1268.01

Table 4.14 SO2 Reductions from CITGO - BART vs. Consent Decree

2002 

Base BART controls Consent Decree 2013

Point Unit # Tons Tons Tons/Year 

Reduction Tons Tons/Year Reduction 

3 ATMOSPHERIC HEATER 111B-1A 4.93 4.93 0 4.93 0

4 ATMOSPHERIC HEATER 111B-1B 4.27 4.27 0 4.27 0

5 CRUDE VACUUM HEATER 111B-2

2.83 2.83 0 2.83 0

7 FCCU CATALYST REGENERATION 112D-1

10982.50 107.91 10874.59 107.91 10874.59

11 COKER CHARGE HEATER 113B-1

2.10 2.1 0 2.1 0

19

CHARGE HEATER & STABILIZER REBOILER 

116B-1

3.76 3.76 0 3.76 0

21 HOT OIL HEATER 118B-1

1.16 1.16 0 1.16 0

31 FEED HEATER 125B-1

1.14 1.14 0 1.14 0

37 AUXILIARY BOILER 430B-1

5.68 5.68 0 5.68 0

38 BOILER #19 1.93 NA NA 0 1.93

64 COKER CHARGE HEATER 113B-2

2.09 2.09 0 2.09 0

66

INTERHEATER & NAPTHA STRIPPER REBOILER 

116B-2

2.06 2.06 0 2.06 0

74 STRIPPER REBOILER 125B-2

2.97 2.97 0 2.97 0

215 CLAUS SULFUR RECOVERY UNITS 119A & B 4339.96 91.2 4248.76 91.2 4248.76

216 CLAUS SULFUR RECOVERY UNITS 121C & D 2.52 2.52 0 2.52 0

15123.35 15125.28
41

Table 4.15 NOX Reductions from ExxonMobil - BART vs. Consent Decree

2002 

Base BART controls Consent Decree 2011

Point Unit # Tons Tons Tons/Year 

Reduction Tons Tons/Year Reduction 

2

AUX BOILER 19.61 19.61 0 19.61 0

4

REFINERY WASTE GAS BLOWDOWN SYSTEM 

AND 2 FLARES 810.3 810.3 * 810.3 *

12 SAT GAS LEAN OIL REBOILER 24.4 24.4 0 24.4 0

13

SULFUR TRAINS INCLUDING SULFUR PIT AND 

LOADING RACK 12.49 12.49 0 12.49 0

15 FLUID CATALYTIC CRACKING UNIT 1818.02 181.80 1636.22 181.80 1636.22

18 CRUDE UNIT HEATERS (#1B1A AND #1B1B) 288.72 288.72 0 288.72 0

19 CRUDE UNIT VACUUM HEATER 114.61 114.61 0 114.61 0

21 COKER CHARGE HEATERS (EAST AND WEST) 133.78 133.78 0 133.78 0

25

REFORMER CHARGE HEATERS (2B3, 2B4, 2B5, 

AND 2B6) 124.62 124.62 0 124.62 0

26 PT REFORMATE DEBUT REBOILER 2B7 23.07 23.07 0 23.07 0

27 PRETREAT REACTOR CHARGE HEATER 17-B-1 23.07 23.07 0 23.07 0

28 PRETREAT DEBUT REBOIL 17-B-2 32.91 32.91 0 32.91 0

33 CHD REACT CHARGE HEATER 3B1 35.87 35.87 0 35.87 0

34 CHD STRIP REBOILER 3B2 41.72 41.72 0 41.72 0

37

CHD REACTOR REGENERATION, 40 HR TWICE/YR 

M AND B 36.63 14.65 21.98 14.65 21.98

38 ALKY ISOSTRIP REBOILER HEATER 7B1 36.63 14.65 21.98 14.65 21.98

38 ALKY ISOSTRIP REBOILER HEATER 7B1 23.94 9.58 14.36 9.58 14.36

90 CCR REGENERATOR 0.41 0.41 0 0.41 0

113 CRUDE UNIT FEED PREHEATER 1-B3/13-B-4 31.27 31.27 0 31.27 0

1694.54 1694.54

* Emission reductions are uncertain but the ExxonMobil Consent Decree requires that the facility have a flare 

minimization plan and to construct and operate flare gas recovery.
42

Table 4.16 SO2 Reductions from ExxonMobil - BART vs. Consent Decree

2002 

Base BART controls Consent Decree 2009

Point Unit # Tons Tons Tons/Year 

Reduction Tons Tons/Year Reduction 

2 AUX BOILER 0.89 0.89 0 0.89 0

4

REFINERY WASTE GAS BLOWDOWN SYSTEM 

AND 2 FLARES

1156.32 1156.32 * 1156.32 *

12 SAT GAS LEAN OIL REBOILER 1.42 1.42 0 1.42 0

13

SULFUR TRAINS INCLUDING SULFUR PIT AND 

LOADING RACK

9340.6 186.81 9153.79 186.81 9153.79

15 FLUID CATALYTIC CRACKING UNIT 9865 197.3 9667.7 197.3 9667.7

18 CRUDE UNIT HEATERS (#1B1A AND #1B1B) 14.84 14.84 0 14.84 0

19 CRUDE UNIT VACUUM HEATER 4.36 4.36 0 4.36 0

21 COKER CHARGE HEATERS (EAST AND WEST) 8.9 8.9 0 8.9 0

25

REFORMER CHARGE HEATERS (2B3, 2B4, 2B5, 

AND 2B6)

10.8 10.8 0 10.8 0

26 PT REFORMATE DEBUT REBOILER 2B7 1.16 1.16 0 1.16 0

27 PRETREAT REACTOR CHARGE HEATER 17-B-1

0.09 0.09 0 0.09 0

28 PRETREAT DEBUT REBOIL 17-B-2

1.67 1.67 0 1.67 0

33 CHD REACT CHARGE HEATER 3B1 1.36 1.36 0 1.36 0

34 CHD STRIP REBOILER 3B2 2.14 2.14 0 2.14 0

37

CHD REACTOR REGENERATION, 40 HR TWICE/YR 

M AND B

0 0 0 0 0

38 ALKY ISOSTRIP REBOILER HEATER 7B1 1.89 1.89 0 1.89 0

38 ALKY ISOSTRIP REBOILER HEATER 7B1 0 0 0 0 0

90 CCR REGENERATOR 4.92 4.92 0 4.92 0

113 CRUDE UNIT FEED PREHEATER 1-B3/13-B-4

1.84 1.84 0 1.84 0

18820.79 18820.79

* Emission reductions are uncertain but the ExxonMobil Consent Decree requires that the facility have a flare 

minimization plan and to construct and operate flare gas recovery.
43

5.0 Summary

USEPA has determined that, as part of a strategy to reduce pollutants found to negatively impact 

visibility in national parks and wilderness areas in the United States, certain stationary emission 

sources should be subject to a Best Available Retrofit Technology (“BART”) standard. The 

sources subject to a BART standard, according to "Guidelines for BART Determinations under 

the Regional Haze Rule" published by USEPA in July of 2005, must be one of 26 specified 

source categories; in existence in August 1977; began operating after August 1962; and have the 

potential to emit 250 tons per year or more of any air pollutant. 

USEPA‟s Regional Haze Rule requires consultation between the states, tribes, and Federal Land 

Managers (“FLMs”) responsible for managing Class I areas. This multi-state and multi-agency 

consultation process has been facilitated by Regional Planning Organizations (“RPOs”) 

established specifically for this purpose. Illinois fully participated in the planning and technical 

development efforts of the Midwest Regional Planning Organization ("MRPO"), which also 

includes the States of Indiana, Michigan, Ohio, and Wisconsin. States in other parts of the 

country participated in similar RPOs. Illinois has also participated in consultations with other 

RPO‟s and states that have requested Illinois‟ participation in their planning process. 

The Illinois EPA, in conjunction with the MRPO, has made adequate plans to meet the 

requirements of the Regional Haze Rule by performing the necessary modeling to determine its 

impact on visibility in Class I areas. The modeling approach used by the Illinois EPA to address 

BART was developed in consultation with the MRPO, the other participating MRPO states, the 

USEPA, and participating FLMs.

This document describes Illinois‟ approach for meeting the BART requirements for emission 

sources in Illinois that have been shown to be BART-eligible. Technical analyses conducted by 

the Illinois EPA have shown that certain BART-eligible sources in Illinois are causing or 

contributing to visibility impairment in several Class I areas in the eastern United States, 

including Mammoth Cave National Park in Kentucky, the Mingo Wilderness Area in Missouri, 

and Isle Royale National Park in Michigan. Illinois is therefore required to submit revisions to 
44

its State Implementation Plan to require that subject emission sources install cost-effective 

retrofit control technologies, or provide equivalent emission reductions.

Illinois has promulgated emission control requirements for most of the emission units in Illinois 

that are subject to BART that provide greater emission reductions, and greater environmental 

benefits, than would be provided by implementation of BART. Other emission units are subject 

to provisions contained in federally-enforceable consent decrees which meet or exceed the 

emission reductions than would be achieved by BART. The remaining emission units in Illinois 

that are subject to BART have committed to meet the BART requirements, as formalized in 

federally enforceable permits issued by the Illinois EPA and submitted to USEPA as SIP 

revisions to meet the BART requirements. These requirements, which were developed 

considering the technology available, the cost of controls, the non-air quality environmental 

impacts, the remaining useful life of the source, and the expected visibility improvement, will 

result in emission reductions that meet or exceed the reductions that would be achieved by the 

meeting the BART requirements contained in the Regional Haze Rule.

Illinois EPA has attempted in this document and its appendices to provide a complete record of 

the efforts made by it and by other entities on its behalf in order to: determine the Illinois sources 

that are subject to the BART requirements; detail the current emission controls and planned 

controls for those sources; and compare the current and planned controls and emission rates at 

affected sources to those required by the BART Guidelines. 
45

References

1. Regional Haze Regulations; Final Rule, 64 Fed. Reg. 35714-35774 (July 1, 1999).

2. Regional Haze Regulations and Guidelines for Best Available Retrofit Technology 

(BART) Determinations; Final Rule, 70 Fed. Reg. 39104-39172 (July 6, 2005).

3. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary 

Report and Recommendations for Modeling Long Range Transport Impacts, 

USEPA, EPA-454/R-98-019, December 1998.

www.epa.gov/scram001/7thconf/calpuff/phase2.pdf

4. National Park Service Class I Area Receptor Index is a database that can be 

accessed online at: http://www.nature.nps.gov/air/Maps/Receptors/index.cfm

5. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze

Rule, USEPA, EPA-454/B-03-005, September 2003.

www.epa.gov/ttn/amtic/files/ambient/visible/natural.pdf

6. Federal Land Managers Air Quality Related Values Workgroup (FLAG) Phase I 

Report, U.S. Forest Service -- Air Quality Program, National Park Service -- Air 

Resources Division, U.S. Fish and Wildlife Service – Air Quality Branch, December 

2000. www.nature.nps.gov/air/pubs/pdf/flag/flagfinal.pdf

7. Scire, J.S., D.G. Strimaitis, R.J. Yamartino, 2000. A User’s Guide for the CALPUFF 

Dispersion Model (Version 5). Earth Tech, Inc., Concord, MA 

http://src.com/calpuff/download/CALPUFF_UsersGuide.pdf

8. Scire, J.S., F.R. Robe, M.E. Fernau, and R.J. Yamartino, 2000b: A User’s Guide for 

the CALMET Meteorological Model (Version 5). Earth Tech, Inc., Concord, MA
Modeling Protocol: Page 1 of 8 

Single Source Modeling to Support Regional Haze BART 

Modeling Protocol 

March 21, 2006 

Lake Michigan Air Directors Consortium 

Des Plaines, IL 

Modeling may be necessary to support a decision by the States about which BART 

eligible sources “cause or contribute” to visibility impairment and are subject to 

BART. The threshold used to determine whether a source “contributes” to visibility 

impairment is 0.5 deciviews, or lower, which is suggested in U.S. Environmental 

Protection Agency (EPA) guidance (EPA, 2005). For the purposes of this analysis, the 

threshold used to determine whether a source “contributes” to visibility impairment 

is 0.5 deciviews. EPA guidance recommends CALPUFF for modeling single source 

visibility impacts at Class I areas (EPA, 2005). 

POLLUTANTS 

EPA guidance lists SO2, NOX, and primary particulate matter (PM) as visibility 

impairing pollutants (EPA, 2005). Emissions of SO2, NOX, and PM must be examined 

for source contribution to visibility impairment. EPA recommends using the CALPUFF 

modeling system. EPA guidance recommends the use of judgment to determine 

whether VOC, ammonia, or primary PM emissions contribute to visibility impairment 

(EPA, 2005). An additional modeling analysis will be performed to determine whether 

VOC, ammonia, and primary PM emissions need to be considered. 

VISIBILITY IMPAIRMENT MODELING: SUBJECT TO BART 

The list of BART-eligible sources in each state will include all 26 applicable source 

categories (i.e., both EGUs and non-EGUs). For EGUs, EPA states the CAIR rule will 

result in controls for electric generating units (EGUs) better than those achievable by 

the BART provision of the Regional Haze rule. Each State will need to make a policy 

decision to either accept this position or to impose BART controls on their EGUs. 

Since the CAIR rule regulates SOX and NOX emissions, some consideration for other 

EGU emissions including primary PM, VOC, and ammonia is necessary. An additional 

modeling analysis will be performed to determine whether VOC, ammonia, and 

primary PM emissions from all elevated point sources in the Midwest RPO States 

contribute to visibility impairment at Class I areas. 

For non-EGUs, the options in the BART guideline for determining which sources need 

not be subject to BART will be considered. The three options are individual source 

attribution approach (i.e., CALPUFF modeling), use of model plants to exempt 

individual sources, and cumulative modeling to show that certain elevated point 

source emissions species do not contribute to visibility degradation at nearby Class I 

areas. All three options will be used here. Specifically, the following approach will 

be taken: 

(1) Calculate the Q/d value for all sources based on actual emissions and 

minimum distance to a Class I area. (Note, the Q/d metric was 
Modeling Protocol: Page 2 of 8 

identified in EPA’s proposed rule and is similar to the emissionsdistance criteria suggested in the final rule.) 

(2) Conduct individual source CALPUFF modeling for those sources with a 

Q/d value > 5. (Note, the CALPUFF modeling conducted in response to 

EPA’s proposed BART rule showed that the emissions-distance criteria 

associated with less than 0.5 dv visibility impacts on nearby Class I 

areas was consistent with a Q/d value of < 5.) 

(3) Review the results of the new CALPUFF modeling to determine which 

sources have less than a 0.5 dv impact on nearby Class I areas and 

which can, therefore, be assumed to be exempt from the BART 

process. 

(4) Also review the results of the new CALPUFF modeling for sources with 

a Q/d value between 5 and 20 to determine if 5 is an appropriate cutoff for exempting sources from the BART process. 

(5) Cumulative modeling will also be performed with CAMx to determine if 

ammonia, VOC, and direct PM (fine and coarse mass) emissions can be 

exempt from the BART process. 

CUMULATIVE VISBILITY IMPAIRMENT MODELING 

A photochemical model (CAMx4) will be applied with the VOC, ammonia, and PM fine 

and coarse mass emissions “zeroed-out” from all point sources in the Midwest RPO 

States, both BART-eligible and non-BART-eligible. The “zero-out” run will include 

EGU and non-EGU point sources. The results of this run will be compared to a base 

run with these emissions included to determine if these emissions species impair 

visibility. This type of cumulative modeling is consistent with option 3 under the 

section on determining which sources are subject to BART (EPA, 2005). The CAMx4 

modeling system is applied with the same inputs and parameters as used for the 

PM2.5 and regional haze SIP. CAMx4 will be applied for the 2002 calendar year at 36 

km grid resolution. 

SINGLE SOURCE VISIBILITY IMPAIRMENT MODELING: SUBJECT TO BART 

The CALPUFF modeling system is used to estimate visibility impairment from single 

sources. CALPUFF consists of the plume transport model (CALPUFF), meteorological 

data pre-processors (CALMM5, CALMET), inorganic chemistry parameterization 

module (POSTUTIL), and post-processor (CALPOST) (Scire et al, 2000a; Scire et al, 

2000b). The versions of the CALPUFF modeling system code used for this analysis 

are shown in Table 1. 

Table 1. CALPUFF Modeling System Versions

 Version Level 

CALPUFF 5.771a 040716 

CALPOST 5.51 030709 

CALMET 5.53a 040716 

CALMM5 2.0 021111 

POSTUTIL 1.4 040818 

The modeling system is applied consistently with the EPA guidance recommendation 

of following the guidelines set forth in EPA’s Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling 

Long Range Transport Impacts (EPA, 2005; EPA, 1998). None of the BART eligible 

sources in the Midwest Regional Planning Organization are less than 50 km from a 
Modeling Protocol: Page 3 of 8 

Class I area so modeling analysis in addition to CALPUFF is not applicable. The 

IWAQM guidance states that less than 5 years of meteorological data may be used if 

a meteorological model using FDDA is used to supply data. 

CALPUFF will be applied to each source for a 3 annual simulations, covering calendar 

years 2002 to 2004. CALPUFF will be applied using discrete receptor points covering 

the Class I areas with an approximate resolution of 1 km. POSTUTIL is used to repartition nitrate into the gas or particulate phase depending on the estimated 

ammonia availability. This option has been shown to improve model performance 

(Scire et al, 2001). CALPOST is then applied to the POSTUTIL output for each group 

of Class I area receptors (shown in Figure 1 and in Table 3). CALPUFF, POSUTIL, and 

CALPOST are also run for 3 consecutive years for each source for gridded receptors 

that match the CALMET/CALPUFF domain shown in Figure 1. These runs allow for 

quality assurance and quality control by plotting the results for visual inspection. The 

results are checked for reasonableness of stack location, stack parameters, and 

emission rates. Each source is applied in CALPUFF for 3 years in a discrete receptor 

mode to meet regulatory requirements and for 3 years in a gridded receptor mode as 

a quality assurance and control measure. 

The CALPUFF/CALMET modeling domain is a Lambert conformal grid projection 

centered at (97 W, 40 N) with true latitudes at 33 N and 45 N and origin at (-900 

km, -1620 km). The horizontal domain consists of 97 36 km cells in the east-west 

direction and 90 36 km cells in the north-south direction (see Figure 1). The vertical 

atmosphere up to approximately 15 km is resolved with 16 vertical layers, most of 

which are in the boundary layer to appropriately resolve the diurnal fluctuations in 

boundary layer mixing depths. 

Figure 1. Model Domain 

Landuse and terrain data are extracted from the global datasets, USGS Composite 

Theme Grid landuse and USGS Digital Elevation Model terrain height, distributed with 

CALPUFF and match the horizontal grid specifications. Meteorological inputs to 

CALPUFF are output from a prognostic meteorological model using four-dimensional 

data assimilation. MM5v3.6 output is used to supply hourly meteorological data to 

CALPUFF. 
Modeling Protocol: Page 4 of 8 

Observation data is included in the ETA analysis fields used to initialize MM5 so 

additional assimilation of observational data in CALMET is redundant to the specific 

purpose of a prognostic meteorological model, which is to appropriately fill in the 

data around the surface monitoring network and sparse upper air monitoring 

network. The MM5 output used to support the BART CALPUFF modeling has extensive 

model performance evaluation and is used to support regional photochemical 

modeling applications for the ozone, PM2.5, and regional haze State Implementation 

Plans (Baker, 2004; Baker, 2005; Johnson, 2003). 

Modeling options are set to be consistent with the IWAQM guidance. A few 

modifications to the suggested parameter settings are discussed in this section. For 

CALMET, several options were selected to use the MM5 output as input to CALMET 

rather than observation data; ICLOUD=3, IPROG=14, ITPROG=2, and IEXTRP=-1. 

Several options are selected in CALPUFF that differ from the IWAQM 

recommendations: the IDRY and IWET variables are set to 0 since dry and wet 

deposition flux output is not applicable for this analysis. The IPRTU variable is set to 

3 to output specie concentrations in units of ug/m3

 to be consistent with measured 

regional concentrations. 

CALPUFF requires the input of ozone (O3) and ammonia (NH3) concentrations as a 

monthly background value applicable for the entire modeling domain. Seasonal 

domain averaged concentrations of each will be obtained from an annual 2002 

calendar year CAMx4 simulation. These values are shown in Table 2. 

Table 2. Domain Seasonal Average Concentrations (ppb) 

 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

O3 (ppb) 31 31 31 37 37 37 33 33 33 27 27 27 

NH3 (ppb) .3 .3 .3 .5 .5 .5 .5 .5 .5 .5 .5 .5 

CAMx4 prediction of ammonia at the rural Illinois site in Bondville shows good 

agreement between model predictions and ambient observations. A scatter plot 

showing the prediction-observation pairs over the entire calendar year of 2004 is 

shown in Figure 2. 

Figure 2. CAMx4 model and ambient ammonia

Predictions at Bondville, Illinois 
Modeling Protocol: Page 5 of 8 

SOURCE SPECIFIC INPUTS: EMISSIONS and STACK PARAMETERS 

States will use the 24-hr maximum emissions rate between 2002 and 2004. If this 

data is not available, then a short term “allowable” or “potential” emission rate of 

emissions between 2002-2004 will be used. If neither of these types of emission 

rates is available, then the highest actual annual emissions divided by hours of 

operation of NOX, SOX, and primary PM between 2002 and 2004 will be applied in 

CALPUFF. 

EPA recommends the States should determine the specific stacks that BART process 

emissions will exit and use stack information specific to those stacks (EPA, 2005b). 

CLASS I AREA RECEPTORS 

The receptors used to determine visibility impacts are taken from the National Park 

Service’s Class I area receptor index (NPS, 2005). The receptors “should be located 

in the nearest Class I area with sufficient density to identify likely visibility effects” 

according to the BART modeling guidance (EPA, 2005). The spatial resolution of the 

discrete receptors is not changed in any way from the NPS files. Table 3 shows the 

list of Class I areas and the total number of discrete receptors covering the Class I 

area used as the receptor field in CALPUFF. 

Table 3. Class I Receptor areas and total discrete rectors 

Boundary Waters Canoe Area MN 856

Brigantine National Wildlife Refuge NJ 16

Dolly Sods /Otter Creek Wilderness WV 187

Great Gulf Wilderness NH 38

Great Smoky Mountains National Park TN 736

Hercules-Glades MO 80

Isle Royale National Park MI 966

James River Face VA 52

Linville Gorge NC 66

Lye Brook Wilderness VT 103

Mammoth Cave National Park KY 302

Mingo MO 47

Seney MI 173

Shenandoah National Park VA 298

Sipsy Wilderness AL 148

Voyageurs National Park MN 366

CALPUFF OUTPUT: POST PROCESSING and INTERPRETATION 

The light extinction equation will use the monthly average relative humidity (RH) 

rather than the daily average humidity as detailed in the BART modeling guidance 

(EPA, 1998; FLAG, 2000). This necessitates using the CALPOST background light 

extinction option 6, which computes light extinction from speciated PM 

measurements with a monthly RH adjustment factor. These Class I area centroid 

specific monthly RH adjustment factors are taken from Table A-3 of the EPA’s 

“Regional Haze: Estimating Natural Visibility Conditions under the Regional Haze 

Rule: Guidance Document.” (EPA, 2003). 
Modeling Protocol: Page 6 of 8 

The daily visibility metric for each receptor is expressed as the change in deciviews 

compared to natural visibility conditions as outlined in the IWAQM guidance (EPA, 

1998). Natural visibility conditions, the 20% best days, for Class I areas used in this 

analysis are found in Appendix B of EPA’s Guidance for Estimating Natural Visibility 

Conditions under the Regional Haze Rule (EPA, 2003). The 20% best days for each 

Class I area are listed in Appendix B in deciviews and not as chemically speciated 

constituents of the light extinction equation, which are needed for CALPOST option 6. 

Annual background concentrations for the eastern United States are given in the 

Guidance for Estimating Natural Visibility Conditions in Table 2-1 (EPA, 2003). These 

values are scaled back to lower concentrations until the Class I area specific natural 

visibility metric is produced (North Dakota Department of Health, 2005). This scaling 

procedure is done for each Class I area and uses an annual average fRH calculated 

from the 12 monthly site specific fRH values mentioned in the first paragraph of this 

section (EPA, 2003). 

The annual average Class I area specific natural conditions are given in deciviews, so 

they must be converted to light extinction. 

Natural conditions (1/Mm) = 10*exp(natural conditions in deciviews/10) 

Second, the chemically speciated natural background concentrations for the eastern 

United States are scaled to equal the site specific natural background light extinction 

value. 

Natural conditions in 1/Mm = 3*fRH*[ammonium sulfate]*X + 3*fRH*[ammonium 

nitrate]*X + 4*[OC]*X + 10*[EC]*X + 1*[SOIL]*X + 0.6*[CM]*X + [β(Raleigh)] 

The bracketed concentrations are expressed as ug/m3. The fRH values represent 

annual average fRH calculated from the 12 monthly site specific fRH values 

mentioned in the first paragraph of this section (EPA, 2003). Solving for X gives the 

dimensionless scaling factor which is applied to each of the chemically speciated 

natural background concentrations given for the eastern United States. The natural 

background values and scaling factors used for each Class I area are shown in Table 

4. 

Table 4. Scaled natural background values by Class I area 

Class I 

Area

Nat. 

Back. 

deciview

Nat. 

Back. 

1/Mm

Scaling 

Factor

Annual 

average 

fRH

Amm. 

Sulfate

Amm. 

Nitrate

Organic 

Carbon

Elemental 

Carbon Soil

Coarse 

Mass

BOWA 3.53 14.233 0.39 2.93 0.089 0.038 0.539 0.008 0.192 1.155

BRIG 3.60 14.333 0.39 3.05 0.090 0.039 0.546 0.008 0.195 1.169

DOSO 3.64 14.391 0.39 3.20 0.090 0.039 0.546 0.008 0.195 1.169

GRGU 3.63 14.376 0.39 3.13 0.090 0.039 0.547 0.008 0.195 1.172

GRSM 3.76 14.564 0.40 3.46 0.091 0.040 0.555 0.008 0.198 1.188

HEGL 3.59 14.319 0.39 3.13 0.089 0.039 0.540 0.008 0.193 1.157

ISLE 3.54 14.248 0.39 2.90 0.089 0.039 0.542 0.008 0.194 1.161

JARI 3.56 14.276 0.39 3.04 0.089 0.038 0.539 0.008 0.192 1.155

LIGO 3.75 14.550 0.39 3.54 0.090 0.039 0.549 0.008 0.196 1.176

LYBR 3.57 14.290 0.39 2.99 0.089 0.039 0.543 0.008 0.194 1.164

MACA 3.85 14.696 0.41 3.36 0.095 0.041 0.575 0.008 0.206 1.233

MING 3.59 14.319 0.39 3.14 0.089 0.039 0.539 0.008 0.193 1.156

SENE 3.69 14.463 0.39 3.30 0.090 0.039 0.550 0.008 0.196 1.178

SHEN 3.57 14.290 0.38 3.19 0.088 0.038 0.533 0.008 0.191 1.143

SIPS 3.71 14.492 0.39 3.43 0.090 0.039 0.547 0.008 0.195 1.172

VOYA 3.41 14.064 0.38 2.71 0.087 0.038 0.528 0.008 0.188 1.131
Modeling Protocol: Page 7 of 8 

The visibility degradation beyond natural conditions expressed in deciviews is kept 

for each Class I area and ranked over the length of the modeling simulation. The 

criteria used to determine if a source is “contributing” to visibility impairment is the 

98th percentile that is equal to .5 deciviews for MRPO States using a maximum 24-

hour emission rate and the peak value that is equal to .5 deciviews for MRPO States 

using an actual 24-hour emission rate. The 98th percentile is interpreted as any 

source with more than 21 days of visibility impairment over the 3 year modeling 

period or 7 days of visibility impairment in any one of the 3 years modeled is 

“contributing” to visibility impairment. The peak value is interpreted as any source 

with more than 1 day of visibility impairment over the 3 year modeling period is 

“contributing” to visibility impairment. 

The gridded receptor run will be post processed through CALPOST for plotting 

purposes. The plots show the number of days at each receptor that have 24-hr 

average 1% degradation in light extinction (1/Mm) over background conditions. This 

is approximate, but not equal, to 0.5 deciview degradation over background 

conditions. These plots allow for a qualitative visual inspection of the extent impact 

over the region. 

VISIBILITY IMPROVEMENT DETERMINATION 

Once a source is considered subject to BART the visibility improvement 

determination requires additional single source modeling. CALPUFF will be used to 

determine the visibility improvement at Class I area receptors from the potential 

BART control technology applied to the source. Post-control emission rates are 

calculated as a percentage of the pre-control emission rates (EPA, 2005). 

The post-control CALPUFF simulation will be compared to the pre-control CALPUFF 

simulation by the change in the value of the highest degradation in visibility over 

natural conditions between the pre-control and post-control simulations (EPA, 2005). 

Further information on the sources and control levels to be used in this additional 

modeling will be provided later. 

REFERENCES 

Baker, K. Meteorological Modeling Protocol for Application to PM2.5/Haze/Ozone Modeling Projects, 2004. 

See http://www.ladco.org/tech/photo/photochemical.html (accessed March 1, 2005). 

Baker, K. MM5 Performance for 3 Annual Simulations (2002-2004); Relating meteorological model 

performance to PM2.5 performance, 2005. 2005 Ad-Hoc Meteorological Modeling Meeting, Denver, 

Colorado. See http://www.ladco.org/tech/photo/adhocmet (accessed September 2, 2005). 

FLAG, 2000. Federal Land Managers Air Quality Related Values Workgroup (FLAG) Phase I Report. 

December 2000. 

Johnson, M. Meteorological Modeling Protocol: IDNR 2002 Annual MM5 Application, 2003. See 

http://www.iowacleanair.com/prof/progdev/files/protocol.pdf (accessed March 1, 2005). 

LADCO, 2005. Conceptual Model of PM2.5, Regional Haze, and Ozone. Des Plaines, IL. 

National Park Service. 2005. http://www2.nature.nps.gov/air/Maps/Receptors/index.cfm

North Dakota Department of Health. 2005. Draft Protocol for BART Related Visibility Impairment Modeling 

Analysis in North Dakota. 

Scire, J., Strimaitis, D., Yamartino, R. A Users’ Guide for the CALPUFF Dispersion Model (version 5). Earth 

Tech. 2000a. http://src.com/calpuff/calpuff1.htm
Modeling Protocol: Page 8 of 8 

Scire, J.S., F.R. Robe, M.E. Fernau, and R.J. Yamartino, 2000b: A User’s Guide for the CALMET 

Meteorological Model (Version 5). Earth Tech, Inc., Concord, Massachusetts. 

Scire, J.S., Z-X Wu, D.G. Strimaitis and G.E. Moore, 2001: The Southwest Wyoming Regional CALPUFF Air 

Quality Modeling Study – Volume I. Prepared for the Wyoming Dept of Environmental Quality. Available 

from Earth Tech, Inc., 196 Baker Avenue, Concord, MA. 

US EPA, 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long Range Transport Impacts. EPA Document Number: EPA-454/R-98-

019 

US EPA, 2003. Regional Haze: Estimating Natural Visibility Conditions Under the Regional Haze Rule: 

Guidance Document. EPA Document Number: EPA-454/B-03-005. 

US EPA, 2005. BART guidelines, Federal Register update: June 24, 2005. 

US EPA 2005b. Personal communication from John Summerhays, Randall Robinson, Todd Hawes. July 14, 

2005. 
Regional Air Quality Analyses for

Ozone, PM2.5, and Regional Haze: 

Final Technical Support Document

April 25, 2008

States of Illinois, Indiana, Michigan, Ohio, and Wisconsin
Appendix C

Illinois Mereury Rule

The Illinois EPA is seeking approval from the United States Environmental Protection Agency ofthe

following holdedprovisions ofthe Illinois Mercury Rule, 35 Ill. Adm. Code Part 225, Subpart B:

Control ofMercury Emissionsfrom Coal-Fired Electric Generating Units, under this submission.

Please note that the non-boldedprovisions are includedfor context.

Section 225.233 Multi-Pollutant Standards (MPS)

a) General.

1) As an alternative to compliance with the emissions standards of Section

225.230(a), the owner of eligihle EGUs may elect for those EGUs to

demonstrate compliance pursuant to this Section, which establishes control

requirements and standards for emissions of NOx and S02' as well as for

emissions of mercury.

2) For the purpose of this Section, the following requirements apply:

A) An eligible EGU is an EGU that is located in Illinois and which

commenced commercial operation on or before Deeember 31,2004;

and

B) Ownership of an eligible EGU is determined based on direct

ownership, by the holding of a majority interest in a company that

owns the EGU or EGUs, or by the common ownership of the company

that owns the EGU, whether through a parent-subsidiary

relationship, as a sister corporation, or as an affiliated corporation

with the same parent corporation, provided that the owner has the

right or authority to submit a CAAPP application on behalf of the

EGU.

3) The owner of one or more EGUs electing to demonstrate compliance with

this Subpart B pursuant to this Section must submit an application for a

CAAPP permit modification to the Agency, as provided in Section 225.220,

that includes the information specified in subsection (b) of this Section and

which clearly states the owner's election to demonstrate compliauce pursuant

to this Section 225.233.

A) Ifthe owner of one or more EGUs elects to demonstrate compliance

with this Subpart pursuant to this Section, then all EGUs it owns in

Illinois as of July 1,2006, as defined in subsection (a)(2)(B) of this

Section, must be thereafter subject to the standards and control

1
requirements of this Section, except as provided in suhsection

(a)(3)(B). Such EGUs must be referred to as a Multi-Pollutant

Standard (NIPS) Group.

B) Notwithstanding the foregoing, the owner may exclude from an MPS

Group any EGU scheduled for permanent shutdown that the owner

so designates in its CAAPP application required to be submitted

pursuant to subsection (a)(3) of this Section, with compliance for such

units to be achieved by means of Section 225.235.

4) When an EGU is subject to the requirements of this Section, the

requirements apply to all owners or operators of the EGU.

b) Notice ofIntent.

The owner of one or more EGUs that intends to comply with this Subpart B by

means of this Section must notify the Agency ofits intention by December 31, 2007.

The following information must accompany the notification:

I) The identification of each EGU that will be complying with this Subpart B by

means of the multi-pollutant standards contained in this Section, with

evidence that the owner has identified all EGUs that it owned in Illinois as of

July 1,2006 and which commenced commercial operation on or before

December 31, 2004;

2) lfan EGU identified in subsection (b)(I) of this Section is also owned or

operated by a person different than the owner submitting the notice of intent,

a demonstration that the submitter has the right to commit the EGU or

authorization from the responsible official for the EGU accepting the

application;

3) The Base Emission Rates for the EGUs, with copies ofsupporting data and

calculations;

4) A summary of the current control devices installed and operating on cach

EGU and identification of the additional control devices that will likely be

needed for the each EGU to comply with emission control requirements of

this Scction, including identification of each EGU in the MPS group that will

be addressed by subsection (c)(I)(B) ofthis Section, with information

showing that the eligibility criteria for this subsection (b) are satisfied; and

5) Identification of each EGU that is schcduled for permanent shut down, as

provided by Section 225.235, which will not be part of the MPS Group and

which will not be demonstrating compliance with this Subpart B pursuant to

this Section.

2
c) Control Technology Requirements for Emissions ofMercury.

1) Requirements for EGUs in an MPS Group.

A) For each EGU in an MPS Group other than an EGU that is addressed by

subsection (c)(1 )(B) ofthis Section for the period beginning July 1, 2009

(or December 31,2009 for an EGU for which an S02 scrubber or fabric

filter is being installed to be in operation by December 31, 2009), and

ending on December 31, 20 14 (or such earlier date that the EGU is subject

to the mercury emission standard in subsection (d)(1) ofthis Scction), the

owncr or operator ofthe EGU must install, to the extent not already

installed, and properly operate and maintain one ofthe following emission

control devices:

i) A Halogenated Activated Carbon Injection System, complying

with the sorbent injection requirements ofsubsection (c)(2) ofthis

Section, except as may be otherwise provided by subsection (c)(4)

ofthis Section, and followed by a Cold-Side Electrostatic

Precipitator or Fabric Filter; or

ii) Ifthe boiler fires bituminous coal, a Selective Catalytic Reduction

(SCR) System and an S02 Scrubber.

B) An owner of an EGU in an MPS Group has two options under this

subsection (c). For an MPS Group that contains EGUs smaller than 90

gross MW in capacity, the owner may designate any such EGUs to be not

subject to subsection (c)(1 )(A) ofthis Section. Or, for an MPS Group that

contains EGUs with gross MW capacity of less than 115 MW, the owner

may designate any such EGUs to be not subject to subsection (c)(l)(A) of

this Section, provided that the aggregate gross MW capacity ofthe

designated EGUs does not exceed 4% ofthe total gross MW capacity of

the MPS Group. For any EGU subject to one ofthese two options, unless

the EGU is subject to the emission standards in subsection (d)(2) ofthis

Section, beginning on January l, 2013, and continuing until such date that

the owner or operator ofthe EGU commits to comply with the mercury

emission standard in subsection (d)(2) ofthis Section, the owner or

operator ofthe EGU must install and properly operate and maintain a

Halogenated Activated Carbon Injection System that complies with the

sorbent injection requirements ofsubsection (c)(2) ofthis Section, except

as may be otherwise provided by subsection (c)(4) ofthis Section, and

followed by either a Cold-Side Electrostatic Precipitator or Fabric EiteL

The use of a properly installed, operated, and maintained Halogenated

Activated Carbon Injection System that meets the sorbent injection

requirements ofsubsection (c)(2) ofthis Section is defined as the

"principal control technique."

3
2) For each EGU for which injection of halogenated activated carbon is required by

subsection (c)(l) ofthis Section, the owner or operator ofthe EGU must inject

halogenated activated carbon in an optimum manner, which, except as provided in

subsection (c)(4) ofthis Section, is defined as all ofthe following:

A) The use of an injection system designed for effective absorption of

mercury, considering the configuration ofthe EGU and its ductwork;

B) The injection of halogenated activated carbon manufactured by Alstom,

Norit, or Sorbent Technologies, Calgon Carbon's FLUEPAC CF Plus, or

Calgon Carbon's FLUEPAC MC Plus, or the injection of any other

halogenated activated carbon or sorbent that the owner or operator ofthe

EGU has demonstrated to have similar or better effectiveness for control

of mercury emissions; and

C) The injection ofsorbent at the following minimum rates, as applicable:

i) For an EGU firing subbituminous coal, 5.0 Ibs per million actual

cubic feet or, for any cyclone-fired EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 Ibs mercury/GWh gross electrical output or

at least 75 percent reduction ofinput mercury, 2.5 Ibs per million

actual cubic feet;

ii) For an EGU firing bituminous coal, 10.0 Ibs per million actual

cubic feet for any cyclone-fircd EGU that will install a scrubber

and baghouse by December 31, 2012, and which already meets an

emission rate of 0.020 Ib mercury/GWh gross electrical output or

at least 75 percent reduction ofinput mercury, 5.0 Ibs per million

actual cubic feet;

iii) For an EGU firing a blend ofsubbituminous and bituminous coal,

a rate that is the weighted average ofthe above rates, based on the

blend of coal being fired; or

iv) A rate or rates set lower by the Agency, in writing, than the rate

specified in any ofsubsections (c)(2)(C)(i), (c)(2)(C)(ii), or

(c)(2)(C)(iii) ofthis Section on a unit-specific basis, provided that

the owner or operator ofthe EGU has demonstrated that such rate

or rates are needed so that carbon injection will not increase

particulate matter emissions or opacity so as to threaten

noncompliance with applicable requirements for particulate mattcr

or opacity.

D) For the purposes ofsubsection (c)(2)(C) ofthis Scction, the flue gas flow

shall be the gas flow rate in the stack for all units except for those

4
equipped with activated carbon injection prior to a hot-side electrostatic

precipitator; for units equipped with activated carbon injection prior to a

hot-side electrostatic precipitator, the flue gas flow rate shall be the gas

flow rate at the inlet to the hot-side electrostatic precipitator, whieh shall

be determined as the stack flow rate adjusted through the use ofCharles'

Law for the differences in gas temperatures in the stack and at the inlet to

the electrostatic precipitator (Vesp = Vstack X Tesp/Tstacb where V = gas flow

rate in aef and T =gas temperature in Kelvin or Rankine

3) The owner or operator of an EGU that seeks to operate an EGU with an activated

carbon injection rate or rates that are set on a unit-specific basis pursuant to

subsection (c)(2)(C)(iv) ofthis Section must submit an application to the Agency

proposing such rate or rates, and must meet the requirements ofsubsections

(c)(3)(A) and (c)(3)(B) ofthis Section, subject to the limitations ofsubsections

(c)(3)(C) and (c)(3)(D) ofthis Section:

A) The application must be submitted as an application for a new or revised

federally enforceable operating pcrmit for the EGO, and it must include a

summary ofrelevant mercury emission data for the EGO, the unit-specific

injection rate or rates that are proposed, and detailed information to

support the proposed injection rate or rates; and

B) This application must be submitted no later than the date that activated

carbon must first be injectcd. For example, the owner or operator of an

EGU that must inject activated carbon pursuant to subsection (c)(l)(A) of

this subsection must apply for unit-specific injection rate or rates by July

1, 2009. Thereafter, the owner or operator ofthe EGU may supplement its

application; and

C) Any decision ofthe Agency denying a permit or granting a permit with conditi

that set a lower injection rate or rates may be appealed to the Board pursuant tc

Section 39 ofthe Act; and

D) The owner or operator of an EGU may operate at the injection rate or rates

proposed in its application until a final decision is made on the application,

including a final decision on any appeal to the Board.

4) During any evaluation ofthe effectiveness of a listed sorbent, an alternative

sorbent, or other technique to control mercury emissions, the owner or operator of

an EGU need not comply with the requirements ofsubsection (c)(2) ofthis

Section for any system needed to carry out the evaluation, as further provided as

follows:

A) The owner or operator ofthe EGU must conduct the evaluation in

accordance with a formal evaluation program submitted to the Agency at

least 30 days prior to commencement ofthe evaluation;

5
B) The duration and scope ofthe evaluation may not exceed the duration and

scope reasonably needed to complete the desired evaluation ofthe

alternative control technique, as initially addressed by the owner or

operator in a support document submitted with the evaluation program;

C) The owner or operator ofthe EGU must submit a report to the Agency no

later than 30 days after the conclusion ofthe evaluation that describes the

evaluation conducted and which provides the results ofthe evaluation; and

D) Ifthe evaluation ofthe alternative control technique shows less effective

control ofmercury emissions from the EGU than was achieved with the

principal control technique, the owner or operator ofthe EGU must

resume use ofthe principal control technique. Ifthe evaluation ofthe

alternative control technique shows comparable effectiveness to the

principal control technique, the owner or operator ofthe EGU may either

continue to use the alternative control technique in a manner that is at least

as effective as the principal control technique, or it may resume use ofthe

principal control technique. Ifthe evaluation ofthe alternative control

technique shows more effective control of mercury emissions than'the

control technique, the owner or operator ofthe EGU must continue to use

the alternative control tcchnique in a manner that is more effective than

the principal control technique, so long as it continues to be subject to this

subsection (c).

5) In addition to complying with the applicablc recordkeeping and monitoring

requirements in Sections 225.240 through 225.290, the owner or operator of an

EGU that elects to comply with this Subpart B by means ofthis Section must

also comply with thc following additional requirements:

A) For the first 36 months that injection ofsorbent is required, it must

maintain records ofthe usage ofsorbent, the fluegas flow rate from the

EGU (and, ifthe unit is equipped with activated carbon injection prior to a

hot-side electrostatic precipitator, flue gas temperature at the inlet ofthe

hot-side electrostatic precipitator and in the stack), and the sorbent feed

rate, in pounds per million actual cubic feet offlue, on a weekly average;

B) After the first 36 months that injection ofsorbent is required, it must

monitor activated sorbent feed rate to the EGU, gas flow rate in the stack,

and, ifthe unit is equipped with activated carbon injection prior to a hotside electrostatic precipitator, flue gas temperature at the inlet ofthe hotside electrostatic precipitator and in the stack. It must automatically

record this data and the sorbent carbon feed rate, in pounds per million

actual cubic feet offlue gas, on an hourly average; and

6
C) If a blend ofbitwninous and subbituminous coal is fired in the EGD, it

must keep rccords ofthe amount of each type of coal burned and the

required injection rate for injection of activated carbon, on a weekly basis.

6) DntilJune 30, 2012, as an alternative to the CEMS or excepted monitoring system

(sorbent trap system) monitoring, recordkeeping, and reporting requirements in

Sections 225.240 through 225.290, the owner or operator of an EGD may elect to

comply with the emissions testing, monitoring, recordkeeping, and reporting

requirements in Section 225.239(c), (d), (e), (£)(1) and (2), (h)(2), (i)(3) and (4),

and (j)(I).

7) In addition to complying with the applicable reporting requirements in Sections

225.240 through 225.290, the owner or operator of an EGD that elects to comply

with this Subpart B by means ofthis Section must also submit quarterly reports

for the recordkeeping and monitoring conducted pursuant to subsection (c)(5) of

this Section.

d) Emission Standards for Mercury.

1) For each EGD in an MPS Group that is not addressed by subsection (c)(I)(B) of

this Section, beginning January I, 20 15 (or such earlier date when the owner or

operator ofthe EGD notifies the Agency that it will comply with these standards)

and continuing thereafter, the owner or operator ofthe EGU must comply with

one ofthe following standards on a rolling 12-month basis:

A) An emission standard of 0.0080 lb mercury/GWh gross electrical output;

or

B) A minimwn 90-percent reduction ofinput mercury.

2) For each EGD in an MPS Group that has been addressed under subsection

(c)(I)(B) ofthis Section, beginning on the date when the owner or operator ofthe

EGD notifies the Agency that it will comply with these standards and continuing

thereafter, the owner or operator ofthe EGD must comply with one ofthe

following standards on a rolling 12-month basis:

A) An emission standard of 0.0080 lb mercury/GWh gross electrical output;

or

B) A minimum 90-percent reduction ofinput mercury.

3) Compliance with the mercury emission standard or reduction requirement ofthis

subsection (d) must be calculated in accordance with Section 225.230(a) or (d), or

Section 225.232 until December 31, 2013.

7
4) Until June 30, 2012, as an alternative to demonstrating compliance with the

emissions standards in this subsection (d), the owner or operator of an EGU may

eleet to eomply with the emissions testing requirements in Section 225.239(a)(4),

(b), (c), (d), (e), (t), (g), (h), (i), and GJ ofthis Subpart.

e) Emission Standards for NOx and S02.

1) NOx Emission Standards.

A) Beginning in calendar year 2012 and continuing in each calendar

thereafter, for the EGUs in each MPS Group, the owner and operator

of the EGUs must comply with an overall NOx annual emission rate of

no more than O.l1lb/million Btu or an emission rate equivalent to 52

percent of the Base Annual Rate of NO, emissions, whichever is more

stringent.

B) Beginning in the 2012 ozone season and continuing in each ozone

season thereafter, for the EGUs in each MPS Group, the owner and

operator of the EGUs must comply with an overall NO, seasonal

emission rate of no more than O.l1lb/million Btu or an emission rate

equivalent to 80 percent of the Base Seasonal Rate of NOx emissions,

whichever is more stringent.

2) S02 Emission Standards.

A) Beginning in calendar year 2013 and continuing in calendar year

2014, for the EGUs in each MPS Group, the owner and operator of

the EGUs must comply with an overall S02 annual emission rate of

0.33 Ib/million Btu or a rate equivalent to 44 percent ofthe Base Rate

of S02 emissions, whichever is more stringent.

B) Beginning in calendar year 2015 and continuing in each calendar year

thereafter, for the EGUs in each MPS Grouping, the owner and

operator of the EGUs must comply with an overall annual emission

ratc for S02 of 0.25 Ibs/million Btu or a rate equivalent to 35 percent

of the Base Rate of S02 emissions, whichever is more stringent.

3) Ameren MPS Group Multi-Pollutant Standard

A) Notwithstanding the provisions of subsections (e)(I) and (2) of this

Section, this subsection (e)(3) applies to the Ameren MPS Group as

described in the notice of intent submitted by Ameren Energy

Resources in accordance with subsection (b) of this Section.

B) NOx Emission Standards.

8
f)

4)

i) Beginning in the 2010 ozone season and continuing in each

ozone season thereafter, for the .EGUs in the Ameren MPS

Group, the owner and operator of the .EGUs must comply with

an overall NOx seasonal emission rate of no more than 0.11

lb/million Btu.

ii) Beginning in calendar year 2010 and continuing in calendar

year 2011, for the .EGUs in the Ameren MPS Group, the owner

and operator of the .EGUs must comply with an overall NOx

annual emission rate of no more than 0.14 lb/million Btu.

iii) Beginning in calendar year 2012 and continuing in each

calendar year thereafter, for the .EGUs in the Ameren MPS

Group, the owner and operator of the .EGUs must comply with

an overall NOx annual emission ratc of no morc than 0.11

lb/million Btu.

C) S02 Emission Standards

i) Beginning in calendar year 2010 and continuing in each

calendar year through 2013, for the EGUs in the Amcren MPS

Group, the owner and operator of the EGUs must comply with

an overall S02 annual emission rate of 0.50 lb/million Btu.

ii) In calcndar year 2014, for the EGUs in the Ameren MPS

Group, the owner and operator of the .EGUs must comply with

an overall SOz annual emission rate of 0.43 lb/million Btu.

iii) Beginning in calendar year 2015 and continuing in calendar

ycar 2016, for the .EGUs in the Ameren MPS Group, the owner

and operator of the EGUs must comply with an overall SOz

annual emission rate of 0.25 lb/million Btu.

iv) Beginning in calendar year 2017 and continuing in each

calendar ycar thereafter, for the .EGUs in the Ameren MPS

Group, the owner and operator of the .EGUs must comply with

an overall S02 annual emission rate of 0.23 lb /million Btu.

Compliance with the NOx and S02 emission standards must be demonstrated

in accordance with Sections 225.310, 225.410, and 225.510. The owner or

operator of .EGUs must complete the demonstration of compliance before

March 1 of the following year for annual standards and before November 1

for seasonal standards, by which date a compliance report must be submitted

to the Agency.

Requirements for NOx and S02 Allowances.

9
I) The owner or operator ofEGUs in an MPS Group must not sell or trade to any

person or otherwise exchange with or give to any person NOx aJlowances

allocated to the EGUs in the MPS Group for vintage years 2012 and beyond that

would otherwise be available for sale, trade, or exchange as a result of actions

taken to comply with the standards in subsection (e) ofthis Section. Such

allowances that are not retired for compliance must be surrendered to the Agency

on an annual basis, beginning in calendar year 2013. This provision does not

apply to the use, sale, exchange, gift, or trade of allowances among the EGUs in

an MPS Group.

2) The owners or operators ofEGUs in an MPS Group must not sell or trade to any

person or otherwise exchange with or give to any person S02 allowances

allocated to the EGUs in the MPS Group for vintage years 2013 and beyond that

would otherwise be available for sale or trade as a result of actions taken to

comply with the standards in subsection (c) ofthis Section. Such allowances that

are not retired for compliance, or otherwise surrendered pursuant to a consent

decree to which the State ofIllinois is a pmiy, must be surrendered to the Agency

on an annual basis, beginning in calendar year 2014. This provision does not

apply to the use, sale, exchange, gift, or trade of allowances among the EGUs in

an MPS Group.

3) The provisions ofthis subsection (f) do not restrict or inhibit the sale or trading of

allowances that become available from one or more EGUs in a MPS Group as a

result of holding allowances that represent over-compliance with the NOx or S02

standard in subsection (e) ofthis Section, once such a standard becomes effective,

whether such over-compliance results from control equipment, fuel changes,

chm1ges in the method of operation, unit shut downs, or other reasons.

4) For purposes ofthis subsection (f), NOx and S02 allowances mean allowances

necessary for complim1ce with Sections 225.310, 225.410, or 225.510,40 CFR

72, or Subparts AA and AAAA of 40 CFR 96, or any future federal NOx or S02

emissions trading programs that modify or replace these programs. This Section

does not prohibit the owner or operator ofEGUs in an MPS Group from

purchasing or otherwise obtaining allowances from other sources as allowed by

law for purposes of complying with federal or state requirements, except as

specifically set forth in this Section.

5) By March 1, 2010, and continuing each year thereafter, the owner or operator of

EGUs in an MPS Group must submit a report to the Agency that demonstrates

compliance with the requirements ofthis subsection (f) for the previous calendar

year, and which includes identification of al1y allowances that have been

surrendered to the USEPA or to the Agency and al1y allowances that were sold,

gifted, used, exchal1ged, or traded because they became available due to overcompliance. All allowances that are required to be surrendered must be

surrendered by August 31, unless USEPA has not yet deducted the allowal1ces

10
from the previous year. A final report must be submitted to the Agency by

August 31 of each year, verifying that the actions described in the initial report

have taken place or, ifsuch actions have not taken place, an explanation of all

changes that have occurred and the reasons for such changes. 1fUSEPA has not

deducted the allowances from the previous year by August 31, the final report will

be due, and all allowances required to be surrendered must be surrendered, within

30 days after such deduction occurs.

g) Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with

the applicable emission standards ofsubseetions (d) and (e) of this Section for 12

months, the owner or operator of the EGU must obtain a construction permit for

any new or modified air pollution control equipment that it proposes to construet

for control of emissions of mercury, NO" or S02.

(Source: Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

Section 225.291 Combined Pollutant Standard: Purpose

The purpose of Sections 225.291 through 225.299 (hereinafter referred to as the Combined

Pollutant Standard ("CPS")) is to allow an alternate means of compliance with the emissions

standards for mercury in Section 225.230(a) for specified EGUs through permanent shut-down,

installation of ACI, and the application of pollution control technology for NO" PM, and S02

emissions that also reduce mercury emissions as a co-benefit and to establish permanent emissions

standards for those specified EGUs. Unless otherwise provided for in the CPS, owners and

operators of those specified EGUs are not excused from compliance with other applicable

requirements of Subparts B, C, D, and E.

(Source: Added at 33 Ill. Reg. 10427, effective June 26, 2009)

Section 225.292 Applicability of the Combined Pollutant Standard

a) As an alternative to compliance with the emissions standards of Section 225.230(a),

the owner or operator of specified EGUs in the CPS located at Fisk, Crawford,

Joliet, Powerton, Waukegan, and Will County power plants may elect for all of

those EGUs as a group to demonstrate compliance pursuant to the CPS, which

establishes control requirements and emissions standards for NO" PM, S02' and

mercury. For this purpose, ownership of a specified EGU is determined based on

direct ownership, by holding a majority interest in a company that owns the EGU or

EGUs, or by the common ownership of the company that owns the EGU, whether

through a parent-subsidiary relationship, as a sister corporation, or as lUI affiliated

corporation with the same parent corporation, provided that the owner or operator

has the right or authority to submit a CAAPP application on behalf ofthe EGU.

11
b) A specified EGU is a coal-fired EGU listed in Appendix A, irrespective of any

subsequent changes in ownership of the EGU or power plant, the operator, unit

designation, or name of unit.

c) The owner or operator of each of the specified EGUs electing to demonstrate

compliance with Section 225.230(a) pursuant to the CPS must submit an application

for a CAAPP permit modification to the Agency, as provided for in Section 225.220,

that includes the information specified in Section 225.293 that clearly states the

owner's or operator's election to demonstrate compliance with Section 225.230(a)

pursuant to the CPS.

d) If an owner or operator of one or more specified EGUs elects to demonstrate

compliance with Section 225.230(a) pursuant to the CPS, then all specified EGUs

owned or operated in Illinois by the owner or operator as of December 31, 2006, as

defined in subsection (a) of this Section, are thereafter subject to the standards and

control requirements of the CPS. Such EGUs are referred to as a Combined

Pollutant Standard (CPS) group.

e) If an EGU is subject to the requirements of this Section, then the requirements

apply to all owners and operators of the EGU.

(Source: Added at 33 Ill. Reg. 10427, effective June 26, 2009)

Section 225.293 Combined Pollutant Standard: Notice of Intent

The owner or operator of one or more specified EGUs that intends to comply with Section

225.230(a) by means of the CPS must notify the Agency of its intention on or before

December 31,2007. The following information must accompany the notification:

a) The identification of each EGU that will be complying with Section 225.230(a)

pursuant to the CPS, with evidence that the owner or operator has identified all

specified EGUs that it owned or operated in Illinois as of December 31,2006, and

which commenced commercial operation on or before December 31, 2004;

b) If an EGU identified in subsection (a) ofthis Section is also owned or operated by a

person different than the owner or operator submitting the notice of intent, a

demonstration that the submitter has the right to commit the EGU or authorization

from the responsible official for the EGU submitting the application; and

c) A summary of the current control devices installed and operating on each EGU and

identification of the additional control devices that will likely be needed for each

EGU to comply with emission control requirements of the CPS.

(Source: Added at 33 Ill. Reg. 10427, effective June 26, 2009)

12
Section 225.295 Combined Pollutant Standard: Emissions Standards for NOx and S02

a) Emissions Standards for NOx and Reporting Requirements.

1) Beginning with calendar year 2012 and continuing in each calendar year

thereafter, the CPS group, which includes all specified EGUs that have not

been permanently shut down by December 31 before the applicable calendar

year, must comply with a CPS group average annual NO, emissions rate of

no more than 0.11 lbs/mmBtu.

2) Beginning with ozone season control period 2012 and continuing in each

ozone season control period (May 1 through September 30) thereafter, the

CPS group, which includes all specified EGUs that have not been

permanently shut down by December 31 before the applicable ozone season,

must comply with a CPS group average ozone season NO, emissions rate of

no more than 0.11 lbs/mmBtu.

3) The owner or operator of the specified EGUs in the CPS group must file, not

later than one year after startup of any sclective SNCR on such EGU, a

report with the Agency describing the NOx emissions reductions that the

SNCR has been able to achieve.

b) Emissions Standards for S02. Beginning in calendar year 2013 and continuing in

each calendar year thereafter, the CPS group must comply with the applicable CPS

group average annual S02 emissions rate listed as follows:

year lbs/mmBtu

2013 0.44

2014 0.41

2015 0.28

2016 0.195

2017 0.15

2018 0.13

2019 0.11

c) Compliance with the NO, and S02 emissions standards must be demonstrated in

accordance with Sections 225.310,225.410, and 225.510. The owner or operator of

the specified EGUs must complete the demonstration of compliance pursuant to

Section 225.298(c) before March 1 of the following year for annual standards and

before November 30 of the particular year for ozone season control periods (May 1

through September 30) standards, by which date a compliance report must be

submitted to the Agency. [NOTE: This subsection is relying on the compliance requirements

ofthe Clean Air Interstate Rule Trading Program under Subparts C, D, and E of Part 225 and will

need to be amended accordingly when the Transport Rule is promulgated.]

13
d) The CPS group average annual S02 emission rate, annual NOxemission rate and

ozone season NOx emission rates shall be determined as follows:

n n

ERavg =:E (S02i or NOxi tonsy:E (HI;)

i=1 i=1

Where:

ERavg =

HIi , =

S02i = NOxi =

N = I =

average annual or ozone season emission rate in

Ibs/mmBbtu of all EGUs in the CPS group.

heat input for the annual or ozone control period of each

EGU, in mmBtu.

actual annual S02 tons of each EGU in the CPS group.

actual annual or ozone season NOx tons of each EGU in the

CPS group.

number ofEGUs that are in the CPS group.

each EGU in the CPS group.

(Source: Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

Section 225.296 Combined Pollutant Standard: Control Technology Requirements for NO" S02,

and PM Emissions

a) Control Technology Requirements for NOxand S02.

1) On or before December 31, 2013, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 7;

2) On or before December 31, 2014, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Waukegan 8;

3) On or before December 31, 2015, the owner or operator must either

permanently shut down or install and have operational FGD equipment on

Fisk 19;

4) IfCrawford 7 will be operated after December 31, 2018, and not

permanently shut down by this date, the owner or operator must:

A) On or before December 31, 2015, install and have operational SNCR

or equipment capable of delivering essentially equivalent NO,

reductions on Crawford 7; and

14
B) On or before December 31, 2018, install and have operational FGD

equipment on Crawford 7;

5) IfCrawford 8 will be operated after December 31,2017 and not permanently

shut down by this date, the owner or operator mnst:

A) On or before December 31,2015, install and have operational SNCR

or equipment capable of delivering essentially equivalent NO,

emissions reductions on Crawford 8; and

B) On or before December 31,2017, install and have operational FGD

equipment on Crawford 8.

b) Other Control Technology Requirements for S02. Owners or operators ofspecified

EGUs must either permanently shut down or install FGD equipment on each

specified EGU (except Joliet 5), on or before December 31, 2018, unless an carlier

date is specified in subsection (a) of this Section.

c) Control Technology Requirements for PM. The owner or operator of the two

specified EGUs listed in this subsection that are equipped with a hot-side ESP must

replace the hot-side ESP with a cold-side ESP, install an appropriately designed

fabric filter, or permanently shut down the EGU by the dates specified. Hot-side

ESP means an ESP on a coal-fired boiler that is installed before the boiler's airpreheater where the operating temperature is typically at least 5500 F, as

distinguished from a cold-side ESP that is installed after the air pre-heater where

the operating temperature is typically no more than 3500 F.

I) Waukegan 7 on or before December 31,2013; and

2) Will County 3 on or before December 31,2015.

d) Beginning on December 31, 2008, and annually thereafter up to and including December

31, 2015, the owner or operator ofthe Fisk power plant must submit in writing to the

Agency a report on any technology or equipment designed to affect air quality that has

been considered or explored for the Fisk power plant in the preceding 12 months. This

report will not obligate the owner or operator to install any equipment described in the

report.

e) Notwithstanding 35 Ill. Adm. Code 201.146(hhh), until an EGU has complied with

the applicable requirements ofsubsections 225.296(a), (b), and (c), the owner or

operator of the EGU must obtain a construction permit for any new or modified air

pollution control equipment that it proposes to construct for control of emissions of

mercury, NO" PM, or S02.

(Source: Added at 33 Ill. Reg. 10427, effective Junc 26, 2009)

15
225.APPENDIX A Specified EGUs for Purposes of the CPS (Midwest Generation's Coal-Fired

Boilers as of July 1,2006)

Plant Permit Boiler Permit designation CPS

Number Designation

Crawford 031600AIN 7 Unit 7 Boiler BLRI Crawford 7

8 Unit 8 Boiler BLR2 Crawford 8

Fisk 031600AMI 19 Unit 19 Boiler BLR19 Fisk 19

Joliet 197809AAO 71 Unit 7 Boiler BLR71 Joliet 7

72 Unit 7 Boiler BLR72 Joliet 7

81 Unit 8 Boiler BLR81 Joliet 8

82 Unit 8 Boiler BLR82 Joliet 8

5 Unit 6 Boiler BLR5 Joliet 6

Powerton 179801AAA 51 Unit 5 Boiler BLR 51 Powerton 5

52 Unit 5 Boiler BLR 52 Powerton 5

61 Unit 6 Boiler BLR 61 Powerton 6

62 Unit 6 Boiler BLR 62 Powerton 6

Waukegan 097190AAC 17 Unit 6 Boiler BLR17 Waukegan 6

7 Unit 7 Boiler BLR7 Waukegan 7

8 Unit 8 Boiler BLR8 Waukegan 8

Will County 197810AAK 1 Unit 1 Boiler BLRI Will County 1

2 Unit 2 Boiler BLR2 Will County 2

3 Unit 3 Boiler BLR3 Will County 3

4 Unit 4 Boiler BLR4 Will County 4

(Source: Amended at 33 Ill. Reg. 10427, effective June 26, 2009)

16
Prepared for: 

Dominion Energy, Inc. 

BART Analysis for the Kincaid 

Power Plant 

ENSR Corporation 

January 2009 

Document No.: 02285-076-400 
Prepared for: 

Dominion Energy, Inc. 

BART Analysis for the Kincaid 

Power Plant 

__________________________________________________________ 

Prepared By: Olga Kostrova and Ian Thomson 

_________________________________ 

Reviewed By: Robert Paine 

ENSR Corporation 

January 2009 

Document No.: 02285-076-400 
i January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Contents 

Executive Summary ...........................................................................................................................................1

1.0 Introduction ............................................................................................................................................ 1-1

2.0 Background Data ................................................................................................................................... 2-1

2.1 Overview of BART Emission Units.................................................................................................. 2-1

2.2 Existing Control Technologies......................................................................................................... 2-1

2.3 Baseline Emissions ......................................................................................................................... 2-1

3.0 Emission Control Alternatives............................................................................................................. 3-1

3.1 SO2 Control...................................................................................................................................... 3-1

3.1.1 Technical Feasibility of Alternative SO2 Controls ............................................................. 3-1

3.1.2 Impacts of Alternative SO2 Controls.................................................................................. 3-4

3.1.3 Discussion of Candidate SO2 Control Technologies ........................................................ 3-5

3.2 NOX Emission Controls.................................................................................................................... 3-6

3.2.1 Technical Feasibility of Alternative NOx Controls ............................................................. 3-6

3.2.2 Discussion of Candidate NOx Control Technologies........................................................ 3-7

3.3 PM Emission Control....................................................................................................................... 3-7

3.4 Control Scenarios ............................................................................................................................ 3-8

4.0 Meteorological Data used in Visibility Improvement Modeling....................................................... 4-1

4.1 Elements of the Refined Analysis ................................................................................................... 4-1

4.2 CALMET Processing ....................................................................................................................... 4-1

5.0 CALPUFF Modeling Procedures.......................................................................................................... 5-1

5.1 CALPUFF Modeling Domain and Receptors.................................................................................. 5-1

5.2 Technical Options Used in the Modeling ........................................................................................ 5-1

5.3 Natural Conditions and Monthly f(RH) at Class I Areas................................................................. 5-1

5.4 Light Extinction and Haze Impact Calculations .............................................................................. 5-2

6.0 CALPUFF Modeling and BART Determination Results.................................................................... 6-1

6.1 Modeled Control Scenarios............................................................................................................. 6-1

6.2 Modeling Results for Baseline Emissions....................................................................................... 6-1

6.3 Modeling Results for the Alternative Control Cases....................................................................... 6-1

6.4 Cost of BART Control Cases .......................................................................................................... 6-4

6.5 Conclusions ..................................................................................................................................... 6-6
ii January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

7.0 References.............................................................................................................................................. 7-1

List of Appendices 

Appendix A Meteorological Stations used in CALMET Processing 

List of Tables 

Table ES- 1 Regional Haze Impacts Due to Baseline and BART Control Emissions..............................ES-2 

Table ES- 2 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Option Emissions....................................................................................................................ES-3 

Table ES-3 Visibility Improvement and Annual Costs for Each Control Option at Mammoth Cave .......ES-3 

Table 2-1 Kincaid Baseline Emissions ..................................................................................................... 2-3

Table 2-2 Kincaid Baseline Stack Parameters......................................................................................... 2-3

Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO2 Control Technologies 

Applied to Kincaid Units 1 and 2.............................................................................................. 3-4

Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1).............................................................. 3-10

Table 5-1 MRPO Ozone and Ammonia Seasonal Concentrations......................................................... 5-1

Table 5-2 Annual Average Natural Background Concentrations ............................................................ 5-2

Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emissions ................................ 6-2

Table 6-2 Visibility Improvement and Annual Costs for Each Control Case at Mingo ........................... 6-4

Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave ........... 6-5
iii January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

List of Figures 

Figure ES- 1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Option Emissions....................................................................................................................ES-2 

Figure ES-2 Annual Costs vs. Visibility Improvements..............................................................................ES-4 

Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain............................................................... 4-3

Figure 4-2 Location of Meteorological Stations used in CALMET Processing ........................................ 4-4

Figure 6-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control 

Emissions.................................................................................................................................. 6-2

Figure 6-2 Regional Haze Impacts For Top 8 Days Averaged Over 3 Years: Cases 1, 1a, and 2........ 6-3

Figure 6-3 Annual Costs vs. Visibility Improvements................................................................................ 6-6
ES-1 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Executive Summary 

Federal regulations under Title 40 of the Code of Federal Regulations (CFR) Part 51 Appendix Y provide 

guidance and regulatory authority for the application of Best Available Retrofit Technology (BART) to those 

existing eligible sources in order to help meet the targets for visibility improvement at designated Class I areas. 

The IEPA has identified the two coal-fired boilers, Units 1 and 2, at Dominion’s Kincaid Power Plant as BARTeligible emission units. This BART analysis will be reviewed and used by the Illinois Environmental Protection 

Agency (IEPA) for development of the state’s Regional Haze State Implementation Plan (SIP). 

The BART rules require that sources that are subject to BART perform a site-specific BART analysis including 

a control technology review and CALPUFF modeling to assess the visibility impact of the emission units. 

Additionally, for large Electric Generating Units (EGU) affected by the rule, the source should meet 

presumptive control levels for nitrogen oxide (NOX) and sulfur dioxide (SO2) unless it is determined that 

alternative control levels are justified or equivalent in effectiveness. The presumptive BART limits for these 

units are continuous year-round operation of the existing SCR systems at 0.10 pound per million British 

thermal unit (lb/MMBtu) for NOX and 0.15 lb/MMBtu or 95 percent control for SO2. 

This report documents the case-by-case BART analysis conducted for NOx, SO2, and PM10 emissions from 

Kincaid Units 1 and 2. The following BART control scenarios were evaluated: 

• Case 1. Firing 0.3%-sulfur PRB sub-bituminous coal, Dry Sorbent Injection (DSI) with Trona capable 

of achieving an SO2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR 

at a NOx emission level of 0.07 lb/MMBtu. 

• Case 1a. Firing 0.3%-sulfur PRB sub-bituminous coal, enhanced DSI with Trona capable of achieving 

an SO2 emissions level of 0.18 lb/MMBtu (if achievable), enhanced year-round operation of the SCR 

at a NOx emission level of 0.07 lb/MMBtu, and replacement of the existing Electrostatic Precipitators 

(ESP) with Fabric Filters (FF). 

• Case 2. Firing 0.5%-sulfur PRB sub-bituminous coal, Dry Scrubber/Fabric Filter (DS/FF) capable of 

achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NOx

emission level of 0.10 lb/MMBtu. 

• Case 3. Firing 1.62%-sulfur Illinois Basin bituminous coal, Wet Flue Gas Desulfurization (WFGD) 

capable of achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR 

at a NOx emission level of 0.10 lb/MMBtu. 

Kincaid Units 1 and 2 currently employ high-efficiency Electrostatic Precipitators (ESP) to control Particulate 

Matter (PM) emissions. Based upon peak stack test measurements in 1999, the baseline PM emission rates 

for Units No. 1 and 2 are 0.011 and 0.008 lb/MMBtu, respectively. These emissions are significantly below the 

permitted PM emission limit of 0.10 lb/MMBtu. The new FF, DS/FF or WFGD systems are capable of 

achieving a vendor-guaranteed filterable PM emission level of 0.015 lb/MMBtu. The DSI with Trona system 

has the potential for significant reductions in PM emissions1

. However, for conservatism, Dominion has 

assumed that there will not be any appreciable effect on filterable PM emission levels, and they are assumed 

to remain at the baseline levels. However, we do account for an estimated 50% reduction in H2SO4 removal 

due to Trona injection. 

 

1

 PM10 filterable and condensable emissions were reduced by approximately 47% during the demonstration testing at the 

Mirant Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
ES-2 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

CALPUFF modeling results for meteorological database years 2002-2004 were obtained for the two PSD 

Class I areas within 300 km of the Kincaid Generating Station: Mingo Wilderness Area in Missouri and 

Mammoth Cave National Park in Kentucky. The results of the baseline emissions indicate that the 8th highest 

visibility impacts at Mingo and Mammoth Cave are above the 0.5 delta deciview significance threshold. 

Therefore, a BART determination analysis was conducted. 

CALPUFF modeling results for visibility improvements due to application of the four SO2 control cases at the 

two Class I areas are tabulated in Table ES-1 and graphically plotted in Figure ES-1. The table indicates that 

substantial visibility improvements occur with the implementation of the Case 1 or 1a (dry sorbent injection with 

Trona) and Case 2 (dry scrubber/fabric filter) controls, with lesser improvement for the Case 3 (WFGD) 

controls. In fact, no perceptible visibility impacts (defined by a 98th percentile change of at least 0.5 deltadeciview) occur at either Class I area in any modeled year with the implementation of emission controls 

associated with Cases 1/1a or 2. 

Table ES-1 Regional Haze Impacts Due to Baseline and BART Control 
ES-3 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Figure ES-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART 

Control Case 

Dominion Kincaid

Regional Haze Impacts Due to Units 1&2 Baseline and BART Control Emissions

3-Year Average 8th Highest Impacts

1.37

1.22

0.30

0.25 0.27

0.23 0.25

0.46

0.40

0.26

0.0

0.5

1.0

1.5

Mingo Wilderness Mammoth Cave National Park

Class I Area

8th Highest delta-deciview

Baseline: 0.3% S PRB Coal, Seasonal

SCR, ESP

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR,

FF

Case 2: 0.5% S PRB Coal, year-round

SCR, DS, FF

Case 3: 1.62% S Illinois Coal, 

year-round SCR, ESP, WFGD
ES-4 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Tables ES-2 and ES-3 list the projected annualized control cost that is a function of the capital and annual 

operating costs, as well as fixed capital charges estimated by Dominion Energy. The table also presents a 

computation of each control case’s visibility improvement effectiveness and cost relative to the baseline 

conditions, since each control case is independent of the others. The visibility results in Tables ES-2 and ES-3 

are based on the 8th highest regional haze impacts at Mingo and Mammoth Cave, respectively, averaged over 

the three years. Figure ES-2 presents a graph of visibility improvements as a function of the cost for each 

control case. It is evident from the figure that BART Case 1/1a (DSI with Trona) is clearly the most costeffective case for the visibility improvement attained (although the incremental improvement from Case 1 to 1a 

has a markedly steeper cost slope than from the baseline to Case 1, almost as steep as the slope for the Case 

2 and 3 options). Therefore, we conclude that the recommended BART control case is Case 1: the use of 

Trona injection and enhanced SCR performance operation. The ability for an SO2 emission rate lower than 

0.20 lb/MMBtu to be achieved in practice with the use of DSI with Trona will be determined from operational 

experience. 

Table ES- 2 Visibility Improvement and Annual Costs for Each Control Case at Mingo WA 

Control Casea

8th Highest at 

Mingo 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal 

SCR, ESP 1.37 $0 $0 

Case 1: 0.3% S PRB Coal, DSI/Trona, 

Enhanced year-round SCR, ESP 0.30 $24,820,000b

 $23,100,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000c

 $29,210,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.26 $94,700,000d

 $85,060,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.46 $125,370,000e

 $137,220,000 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost becomes 

$30,660,000 and the incremental cost effectiveness from the baseline becomes $28,530,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $37,470,000. 

d

 When Case 2 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized cost becomes 

$156,110,000 and the incremental cost effectiveness from the baseline becomes $140,220,000. 

e

 When Case 3 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized cost becomes 

$200,430,000 and the incremental cost effectiveness from the baseline becomes $219,370,000. 
ES-5 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Table ES-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are escalated to 2014 dollars (based upon 2014 installation date) the Annualized Cost becomes 

$30,660,000 and the Incremental Cost Effectiveness from the baseline becomes $31,770,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $41,960,000. 

d

 When Case 2 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$156,110,000 and the Incremental Cost Effectiveness from the baseline becomes $161,880,000 

e

 When Case 3 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$200,430,000 and the Incremental Cost Effectiveness from the baseline becomes $244,530,000. 

Control Casea

8th Highest at 

Mammoth 

Cave 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal SCR, 

ESP 1.22 $0 $0 

Case 1: 0.3% S PRB Coal, DSI with Trona, 

Enhanced year-round SCR, ESP 0.25 $24,820,000b

 $25,720,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000c $32,710,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.25 $94,700,000d

 $98,200,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.40 $125,370,000e

 $152,950,000 
ES-6 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Figure ES-2 Annual Costs vs. Visibility Improvements 

$0

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$140,000,000

1.5 1.4 1.11.21.3 1.0 0.70.80.9 0.6 0.30.40.5 0.2 0.00.1

8th Highest delta-dv (Average of 3-Years)

Cost ($/year)

Mingo

Mammoth

Baseline

Case 2

Case 3

Case 1

Case 1A
1-1 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

1.0 Introduction 

Federal regulations under Title 40 of the Code of Federal Regulations (CFR) Part 51 Appendix Y provide 

guidance and regulatory authority for conducting a visibility impairment analysis for designated eligible 

sources. The program requires the application of Best Available Retrofit Technology (BART) to those existing 

eligible sources in order to help meet the targets for visibility improvement at designated Class I areas. The 

BART analysis will be reviewed and used by the Illinois Environmental Protection Agency (IEPA) for 

development of the state’s Regional Haze State Implementation Plan (SIP). The IEPA has identified the two 

coal-fired boilers, Units 1 and 2, at Dominion’s Kincaid Power Plant as BART-eligible emission units. 

The BART rules require that sources that are subject to BART perform a site-specific BART analysis including 

a control technology review and CALPUFF modeling to assess the visibility impact of the emission units. 

Additionally, for large Electric Generating Units (EGU) affected by the rule, the source should meet 

presumptive control levels for nitrogen oxide (NOX) and sulfur dioxide (SO2) unless it is determined that 

alternative control levels are justified or equivalent in effectiveness. The presumptive BART limits for these 

units are continuous year-round operation of the existing SCR systems at 0.10 pound per million British 

thermal unit (lb/MMBtu) for NOX and 0.15 lb/MMBtu or 95 percent control for SO2. 

The BART analysis was conducted in accordance with the procedures contained in the Final BART Guidelines 

published by the USEPA on July 6, 2005. Consistent with the BART Guidelines, the five steps for a case-bycase BART analysis were followed. 

1. Step 1 – Identify all available control technologies for the unit including improvements to existing 

control equipment or installation of new add-on control equipment. 

2. Step 2 – Eliminate technically infeasible options considering the commercial availability of the 

technology, space constraints, operating problems and reliability, and adverse side effects on the rest 

of the facility. 

3. Step 3 – Evaluate the control effectiveness of the remaining technologies based on current pollutant 

concentrations, flue gas properties and composition, control technology performance, and other 

factors. 

4. Step 4 – Evaluate the annual and incremental costs of each feasible option in accordance with 

approved EPA methods, as well as the associated energy and non-air quality environmental impacts. 

5. Step 5 – Determine the visibility impairment associated with baseline emissions and the visibility 

improvements provided by the control technologies considered in the engineering analysis. 

The regulation further requires a formal choice of BART based on the above data, plus the degree of 

improvement in visibility (impacts), which may be reasonably anticipated to result from the installation or 

implementation of the proposed BART. Economic analysis, remaining useful life of the plant, and impacts on 

facility operation that are a cost consequence of air pollution control equipment may be considered in the final 

BART decision-making process. 

This report documents the case-by-case BART analysis conducted for SO2, NOx and PM emissions from 

Units 1 and 2 at the Kincaid Power Station. Section 2.0 provides a description of Kincaid Units 1 and 2 and 

their baseline emissions. Section 3.0 provides a discussion of SO2, NOx and PM control technologies. The 

available meteorological data and the CALPUFF modeling procedures are described in Sections 4.0 and 5.0, 

respectively. The results of the visibility improvement modeling using CALPUFF are presented in Section 6.0, 

along with the BART recommendation. References are listed in Section 7.0.
2-1 January 2009

BART Analysis for Kincaid Power Station 

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2.0 Background Data 

2.1 Overview of BART Emission Units 

The BART-affected emission units at the Kincaid Power Plant are Units 1 and 2. Units 1 and 2 commenced 

commercial operation in 1967 and 1968, respectively. The two units began operation during the time period 

(1962-1977) targeted by the Regional Haze BART Rule. Units 1 and 2 are cyclone-fired boilers manufactured 

Babcock & Wilcox. These two units each have a rated capacity of 4,200,000 lb/hr of superheated steam at 

2,620 psig and 1,005°F. The steam is directed to dedicated turbine-generators each with a rated capacity of 

660 MW. Because the plant has a total rated capacity in excess of 750 MW, Units 1 and 2 are subject to 

presumptive BART controls in accordance with the Regional Haze BART Rule. 

2.2 Existing Control Technologies 

Kincaid Units 1 and 2 are both equipped with over fire air (OFA) systems and selective catalytic reduction 

(SCR) to control NOx emissions. Kincaid’s permit requires the SCR system need only be operated during the 

ozone season (May 1st through September 30th) and must achieve a NOx emission level of 0.15 lb/MMBtu 

during that period. Units 1 and 2 are also equipped with electrostatic precipitators (ESPs) to control PM 

emissions. The ESPs must achieve a filterable PM emission level of at least 0.10 lb/MMBtu according to the 

station’s permits. Units 1 and 2 currently burn low-sulfur Powder River Basin (PRB) sub-bituminous coal to 

control SO2 emissions. Based on historical emissions, the sulfur content of the PRB coal generally does not 

exceed 0.3% by weight. 

2.3 Baseline Emissions 

For the purposes of determining BART eligibility, the SO2 and NOx baseline emissions were determined using 

measurement data collected by the continuous emissions monitoring system (CEMS) during the years 2002 

through 2006. Filterable PM baseline emissions were determined using the highest results of the latest stack 

tests conducted in November 1999. 

The SO2 and NOx baseline emission rates were derived from maximum daily emissions measured by the 

CEMS) during the years 2002 through 2006. The PM emissions were derived from the results of stack tests 

conducted in November 1999. Speciation of the particulate matter emissions into filterable and condensable 

PM10 components was determined using the following approach: 

• Filterable PM was subdivided by size category consistent with the default approach cited in AP-42, 

Table 1.1-8. For cyclone furnaces equipped with ESPs, 68% of the filterable PM emissions are 

filterable PM10 and 36% of the PM emissions are fine filterable PM10 emissions (less than 2.5 microns 

in size). 

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine filterable PM10 based on the 

best estimate for electric utility coal combustion in Table 6 of “Catalog of Global Emissions Inventories 

and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 

68-D-98-046, January 2002. 

• Condensable inorganic PM10 emissions, assumed to consist of H2SO4, are based on procedures 

presented in “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical 

Update, March 2007 (and reaffirmed in a March 2008 update). For coal-fired boilers, H2SO4

emissions are determined by the following relationship: 
2-2 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

E = (Q)(98.06/64.04)(F1)(F2) 

where: E is the H2SO4 emission rate (lb/hr), 

Q is the baseline SO2 emission rate (lb/hr), 

F1 is the fuel factor (0.0018 for PRB sub-bituminous coal), and 

F2 is the control factor (0.56 for an air pre-heater and 0.73 for a cold-side ESP). 

Note that, although Units 1 and 2 are equipped with SCR, the maximum daily NOx baseline emissions 

occur when the SCR system is off-line during the non-ozone season. 

• For pulverized coal-fired boilers burning coal with a sulfur content of 0.5% or less, total condensable 

organic PM10 emissions factor is 0.002 lb/MMBtu based on AP-42, Table 1.1-5. Because AP-does not 

have an emission factor for total condensable organic PM10 emissions from cyclone boilers, AP-42 

directs you to the use the pulverized coal emission factor for cyclone boilers. 

Table 2-1 provides a summary of the SO2, NOx, and PM emissions that were used in the modeling analysis for 

baseline conditions. Table 2-2 then provides the stack parameters that were used in the baseline conditions 

modeling analysis. 
2-3 

BART Analysis for Kincaid Power Station 02285-076-400

Table 2-1 Kincaid Baseline Emissions 

Table 2-2 Kincaid Baseline Stack Parameters 

Case UTM Northing (m) UTM Easting (m) Base Elevation (m) Stack Height (m) Stack Diameter (m) Flue Gas Temperature (°K) Flue Gas 

Rate (m

Baseline 4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.2
3-1 January 2009

BART Analysis for Kincaid Power Station 

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3.0 Emission Control Alternatives 

The visibility impairing pollutants discussed in this section include NOX, SO2, and PM. Information on control 

of these pollutants through application of a control device, combination of devices, and/or operational change 

is provided. 

3.1 SO2 Control 

Sulfur dioxide emissions are generated in fossil fuel-fired combustion units from the oxidation of sulfur present 

in the fuel. Approximately 98% of the sulfur in coal is emitted upon combustion as gaseous sulfur oxides, SO2

and SO3. Uncontrolled emissions of SO2 are directly related to the fuel sulfur content, and not by the firing 

mechanism, boiler size, or operation. Many coal-fired boilers in the U.S. limit emissions of SO2 through the 

use of low sulfur western coals, including Powder River Basin Coal. Compared with higher sulfur eastern 

bituminous coal that may contain as much as 4% sulfur, the practice of burning western coal can reduce SO2

emissions by approximately 70% to 90%. However, control equipment can generally remove a higher 

percentage of the SO2 from higher sulfur coal than lower sulfur coal. The selection of coal type and sulfur 

content, therefore, is an important aspect of the determination of BART and needs to be considered in 

conjunction with add-on control alternatives when performing the BART analysis. 

The Unit 1 and 2 boilers currently burn low-sulfur PRB coal to limit SO2 emissions. Alternative SO2 control 

technologies available to further reduce SO2 emission from the coal-fired boilers include Dry Scrubber/Fabric 

Filter (DS/FF), Wet Flue Gas Desulfurization (WFGD) and Dry Sorbent Injection (DSI) with Trona. This 

analysis is limited to these control technologies: 

• Lime or limestone based WFGD capable of achieving 90 to 95% control; 

• Lime DS/FF capable of achieving 80 to 90% control; 

• DSI with Trona capable of achieving approximately 60% control; 

The technical feasibility, performance, and economic, energy, and environmental impacts of the alternative 

SO2 control technologies are addressed in the remainder of this section. 

3.1.1 Technical Feasibility of Alternative SO2 Controls 

The technical feasibility and performance levels of the alternative SO2 control technologies are evaluated 

below in terms of their application to Kincaid Units 1 and 2. 

 Wet Flue Gas Desulfurization 

WFGD typically uses limestone or lime to react with SO2 from coal-fired boilers. The temperature of the flue 

gas is reduced to its adiabatic saturation temperature and the SO2 is removed from the flue gas by reaction 

with the alkaline medium. SO2 is absorbed into the scrubbing slurry, which falls into the lower section of the 

vessel known as the reaction tank. Finely ground limestone and make-up water are added to the reaction 

tank to neutralize and regenerate the scrubbing slurry. 

Limestone scrubbing introduces limestone slurry into the scrubber. The sulfur dioxide is absorbed, 

neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in 

the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 
3-2 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a more 

reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

Whether limestone or lime is used as the reagent for SO2 removal, additional equipment is needed for 

preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite 

sludge is difficult to mechanically dewater and is typically stabilized with fly ash for landfilling. Calcium sulfate 

sludge is stable and is readily mechanically dewatered. To produce calcium sulfate, an air injection blower is 

needed to supply the oxygen for the second reaction to occur (forced oxidation). 

WFGD is most effective in reducing SO2 emissions resulting from combustion of high-sulfur coals. In addition, 

the water consumption in a WFGD system is high due to water retained in the sludge and water losses to the 

atmosphere. Make-up water is added to the reaction tank and is recirculated through the gas stream. A 

WFGD will consume approximately 8 to 10% more water than a spray dryer system. In addition to higher 

water demand, a WFGD system has a number of environmental impacts including generating an additional 

solid waste stream and an additional liquid waste stream. 

WFGD has been applied on many coal-fired boilers in the United States. These installations have been 

demonstrated to consistently achieve SO2 removal efficiencies ranging from 90% to in excess of 95%. These 

high SO2 control efficiencies would provide Dominion with an opportunity to use higher sulfur Illinois 

bituminous coal and still meet the presumptive BART limit of 0.15 lb/MMBtu. Although the delivered price for 

PRB sub-bituminous coal currently is less than that for local Illinois bituminous coal, rail transportation costs 

have recently been increasing dramatically due to increases in the price of diesel fuel, so the price differential 

between PRB and local Illinois coal could narrow considerably or disappear in the future. Over the past two 

years alone, transportation costs have almost doubled and are expected to continue rising with the price of 

diesel fuel. There is also a concern about the reliability of the rail transportation from Wyoming, due to recent 

incidents of derailments and delays in PRB coal shipments. 

If Dominion were required to install WFGD for SO2 control, therefore, they would consider the use of mediumsulfur (<2.5%) sulfur Illinois coal to allay concerns about the rising costs of transporting PRB sub-bituminous 

coal to the site and to promote the use of locally mined coal to improve the Illinois economy. For the 

purposes of the visibility analysis, it is assumed that the WFGD system will be applied to Units 1 and 2 firing 

~1.62% sulfur Illinois-bituminous coal and will achieve an outlet SO2 emission level of 0.15 lb/MMBtu, 

consistent with the presumptive BART limit. 

 Dry Scrubber and Fabric Filter 

Use of a dry scrubber technology requires a dry scrubber to be located upstream of the particulate collection 

device. The flue gas passes through a spray dryer vessel, where it encounters a finely atomized alkaline lime 

slurry. The lime slurry is injected into the dry scrubber through either a rotary atomizer or fluid nozzles. 

Evaporation of the water produces a finely divided particle of mixed salt and un-reacted alkali and reduces 

flue gas temperatures. The flue gas is cooled to approximately 20 to 30°F above the adiabatic saturation 

temperature of the flue gas. A portion of the dry powder drops to the bottom of the scrubbing vessel, while 

the flue gases containing the remaining reacted salts and un-reacted lime are delivered to the particulate 

collection device. The calcium salts have a moisture content of approximately 2 to 3%, which drops to 1% 

before reaching the particulate control device. 

In the absorbing chamber, the water in the slurry droplets is rapidly evaporated by the hot flue gases. The 

SO2 are absorbed onto the hydrated lime particles and react to form calcium salts. The reduction in flue gas 

temperature provided by the evaporating water has been shown to be a major factor influencing the removal 

of acid gases. Studies have shown that SO2 removal efficiencies are significantly higher when the dry 
3-3 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

scrubber is operated at temperatures approaching the saturation temperature of the flue gas. As a result of 

the scrubbing process, a dry, free-flowing powder is produced consisting of un-reacted lime and reacted salts 

(most prevalent being CaSO3 and CaSO4). The largest of these particles are separated by gravity from the 

gas in the absorbing chamber by gravity and fall to the bottom. The smaller particles are carried to the PM 

control device for separation from the flue gas. 

When a fabric filter is used as the particulate control device, it allows for further reaction of the lime captured 

in the filter media with the SO2 in the flue gas. This is due to the layer of porous filter cake on the surface of 

the filter that contains the reagent that all flue gas must pass through. This allows for increased efficiency of 

control of SO2 and H2SO4 as compared to wet scrubbers. This filter cake is credited with controlling pressure 

drops, dampening surges or pollutant spikes, providing a site for increased reagent utilization, and increasing 

equipment reliability. 

Dry scrubbers have been applied primarily in combination with fabric filters (FFs) on many coal-fired boilers in 

the United States. These installations have been demonstrated to consistently achieve SO2 removal 

efficiencies of 80 to 90%. For the purposes of the visibility analysis, it is assumed that the DS/FF combination 

will be applied to Units 1 and 2 firing 0.5% sulfur PRB sub-bituminous coal and will achieve an outlet SO2

emission level of 0.15 lb/MMBtu consistent with the presumptive BART limit. 

 Dry Sorbent Injection (DSI) with Trona 

A variety of manufacturers have developed DSI systems for SO2 control on coal-fired boilers. This technology 

uses very standard process equipment, including carbon steel storage silos, material handling equipment, 

blowers, and pneumatic transport piping, all of which are commodity components available from multiple 

vendors at similar cost. In order to remove SO2 compounds from hot exhaust gases, finely ground Trona, 

sodium sesquicarbonate [Na3(HCO3)], can be injected into the hot gas stream to react with the SO2 and form 

sodium sulfite (Na2SO3). The reacted salt would then be removed from the flue gas stream by the existing 

downstream particulate control devices. The main chemical reaction is as follows: 

 2(Na3(HCO3)•(CO3)•2H2O) + 3SO2 → 3Na2SO3 + 5H2O + 4CO2

A plant’s operating conditions will ultimately affect the effectiveness of DSI with Trona in removing SO2. The 

most important variables for high removal efficiency are injection temperature, SO2 concentration, fine particle 

size (~10 microns), retention time (the time the acid gases are in contact with the sorbent) and the type of 

coal utilized. 

DSI with Trona has demonstrated the following SO2 removal rates during the short term demonstration tests 

discussed below. In 2005 the Mirant Potomac River Station2

 demonstrated a maximum SO2 control of ≈80% 

while burning Central Appalachian and Columbian coals. In 2008, We Energies Presque Isle Power Plant 

demonstrated a maximum SO2 control of ≈70% while burning Powder River Basin (PRB) coal. Dominion 

estimates that for the purposes of BART implementation, DSI with Trona injection will be able to achieve an 

average SO2 control of ≈60% and an SO2 emission rate of 0.20 lb/MMBtu based upon a 30-day rolling 

average. Dominion has assumed 60% SO2 removal for PRB coal at Kincaid for several reasons, related to 

differences in the units, the limited testing scope at Presque Isle and the impact on mercury removal. Higher 

Trona injection rates during the Presque Isle tests contributed to reduced rates of mercury removal from 

Activated Carbon Injection, an issue which must be evaluated for Kincaid. Further, the Presque Isle tests 

consisted of only 8-hour injections of Trona in a 90 MW unit. Effective utilization of Trona will be more difficult 

for Kincaid's much larger 660 MW units and a 30-day rolling average presents a much greater challenge than 

an 8-hour test under optimum conditions. For example, during normal operations Kincaid operates at 

reduced loads and lower temperatures at night, which typically which reduces the reactivity of Trona. The 

 

2

 http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
3-4 January 2009

BART Analysis for Kincaid Power Station 

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Presque Isle units were tested with Trona injection upstream of a bag house while Kincaid utilizes an 

electrostatic precipitator for particulate removal. 

One advantage of the DSI with Trona injection process is that the stack temperature is not diminished 

compared to the WFGD processes that involve the use of significant amounts of water. Aside from the 

environmental benefits that result from avoiding the use of the water spray, the increased stack gas 

temperature will tend to avoid the local impacts of increased H2SO4 emissions associated with oxidation of 

SO2 to SO3 by the SCR catalyst and the subsequent formation of H2SO4 in the control equipment. 

DSI with Trona requires much lower capital investment, less physical space, and less modification to existing 

ductwork compared to a spray dryer absorber or wet scrubber. Trona is a very reactive reagent that can be 

used to achieve a range of efficiencies depending upon the amount of sorbent injected into the ductwork. 

Two cases are presented for Trona injection for SO2 control (Cases 1 and 1a), with slightly different SO2

emission rates (0.20 lb/MMBtu for Case 1 and 0.18 lb/MMBtu for Case 1a). Although the lower SO2 emission 

rate is preferred, it may not be achievable, depending upon the coal sulfur content and the effectiveness of 

the Trona removal for this specific application. 

3.1.2 Impacts of Alternative SO2 Controls 

The alternative control technologies available to control SO2 emissions from Units 1 and 2 are DSI with Trona, 

DS/FF and WFGD. This section documents the economic, non-air environmental, and energy impacts 

associated with applying alternative control technologies to Units 1 and 2. 

 Economic Impacts 

Table 3-1 presents the first-year annual capital and annual costs associated with DSI with Trona, DS/FF and 

WFGD applied to Kincaid Units 1 and 2. The capital costs for the technically feasible SO2 control 

technologies were provided by Dominion Energy. The annual fixed capital charges and annual operating 

costs were also provided by Dominion. An interest rate of 9.8% and an amortization period of 20 years were 

assumed in the calculation of the annualized costs for the BART control cases. 

Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO2 Control 

Technologies Applied to Kincaid Units 1 and 2 

Control 

Case c Control Technology 

Total Capital 

Cost 

($)a

 Fixed Capital 

Costs 

($/yr)b

Annual O&M 

Costs 

($/yr) 

Total Annual 

Costs 

($/yr) 

1 Dry Sorbent Injection (PRB Coal) $60,000,000 $7,000,000 $17,820,000 $24,820,000 

1a Enhanced DSI/FF (PRB Coal) $163,000,000 $19,000,000 $13,210,000 $32,210,000 

2 Dry Scrubber/FF (PRB Coal) $732,580,000 $85,000,000 $9,700,000 $94,700,000 

3 WFGD (Bituminous Coal) $840,710,000 $97,000,000 $28,370,000 $125,370,000 

a

 Total capital costs for Cases 2 and 3 include $17,900,000 for removal of existing equipment; this cost for Case 1a is 

$6,000,000. In addition, total capital costs for Cases 1a and 2 include expenses associated with the fabric filter. 

b

 Fixed capital charges are based on a capital recovery factor of 0.1159, assuming an interest rate of 9.8% and an 

amortization period of 20 years. 

c

 All costs are based on 2008 dollars. 
3-5 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

 Non-Air Quality Environmental Impacts 

The preceding technology evaluation identified DSI with Trona, DS/FF and WFGD as the available SO2

control technologies providing the highest removal efficiencies relative to other technologies. Of the two 

scrubber options, the DS/FF combination is considered the preferred control technology. The disadvantages 

of WFGD compared to DS/FF system include: 

• higher water consumption or wastewater treatment requirement resulting in increased energy and 

utility operating costs; 

• liquid effluent from the wet scrubber requires pretreatment to meet regulatory requirements before 

discharge to a municipal sewer; 

• problems associated with the disposal of wet sludge resulting from the process, requiring extensive 

sludge thickening and dewatering equipment; 

• a relatively low stack gas temperature resulting in reduced buoyancy and lower plume rise, and 

hence poorer dispersion of the residual pollutants; 

• visible steam plume under most meteorological conditions, especially during periods of high relative 

humidity; and 

• corrosion, scaling and fouling of scrubber internals, requiring costly acid corrosion resistant 

construction materials for scrubber and downstream equipment. 

Furthermore, available test data demonstrate the superior effectiveness of DS/FF systems for SO2 and other 

acid gas emissions, as well as the control of secondary pollutant (i.e., trace organics and trace metals). 

As noted above, the DSI with Trona option provides significant non-air quality benefits over both scrubbing 

options: 

• no use of additional water in the FGD treatment 

• a higher stack temperature, leading to improved local air quality due to increased buoyancy and 

higher plume rise, and hence greater dispersion of the residual pollutants and 

• a lower likelihood of visible plumes, as well as fogging and icing potential. 

 Energy Impacts 

The WFGD option would consume significantly more electrical energy than the DS/FF option, while the 

DSI with Trona option would consume the least energy of any of the options. For example, the higher 

electrical energy consumption for WFGD relative to DS/FF and DSI with Trona primarily is due to the power 

required for the increased fan static pressure required to overcome the pressure drop across the 

scrubber vessel, as well as for dewatering, re-circulating pumps and material handling. WFGD applied to 

both units would consume approximately 82,000 kWh, compared to 65,000 kWh for the DS/FF compared to 

13,000 kWh for the DSI with Trona. The increased emissions of criteria pollutants required to maintain the 

net electrical output have not been incorporated into the visibility modeling. 

3.1.3 Discussion of Candidate SO2 Control Technologies 

The SO2 control technologies identified for evaluation include DSI with Trona (two possible SO2 emission 

rates), DS/FF and WFGD. Of these technologies, WFGD is capable of higher SO2 control efficiencies ranging 

from 90 to 95%, providing Dominion with the flexibility of using medium-sulfur Illinois bituminous coal. The 

DS/FF, on the other hand, is capable of achieving SO2 control efficiencies ranging from 80 to 90%, limiting 

Dominion options to low-sulfur PRB sub-bituminous or eastern bituminous coals. The DSI with Trona option 

can achieve SO2 removal rates of up to 70% when firing low-sulfur PRB coals as demonstrated at the We 

Energies Presque Isle Power Plant. The WFGD system, however, has significant disadvantages compared 
3-6 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

with the other SO2 removal options. The WFGD system has substantially higher capital and annual operating 

costs than the other SO2 removal options. Compared with these other options, WFGD would result in 

significant environmental and energy impacts, including increased power requirements, increased water 

consumption, liquid effluent requiring pretreatment, wet sludge requiring dewatering, and cooler and less 

buoyant plume. 

3.2 NOX Emission Controls 

Nitrogen oxides formed during the combustion of coal are generally classified as either thermal NOx or fuelbound NOx. Thermal NOx is formed when elemental nitrogen in the combustion air is oxidized at the high 

temperatures in the primary combustion zone yielding nitrogen oxide (NO) and nitrogen dioxide (NO2). The 

rate of formation of thermal NOx is a function of residence time and free oxygen, and increases exponentially 

with peak flame temperatures. Thermal NOx from coal combustion can be effectively controlled by techniques 

that limit available oxygen or reduce peak flame temperatures in the primary combustion zone. Fuel-bound 

NOx is formed by the oxidation of chemically bound nitrogen in the fuel. The rate of formation of fuel-bound 

NOx is primarily a function of fuel bound nitrogen content, but is affected by fuel/air mixing. 

The technologies available to control NOX from coal-fired boilers include combustion controls, such as lowNOx burners (LNB), and post-combustion techniques, such as selective non-catalytic reduction (SNCR) and 

selective catalytic reduction (SCR). Because Units 1 and 2 already incorporate combustion controls, this 

analysis is limited to the following post-combustion control technologies: 

• Selective catalytic reduction capable of 80 to 90 percent control; and 

• Selective non-catalytic reduction capable of 30 to 50 percent control. 

The Unit 1 and 2 boilers currently incorporate SCR for the control of NOx emissions during the ozone season. 

As demonstrated below, this control technology is considered the most effective in reducing NOx emissions 

from coal-fired boilers. The SCR controls would need to be operated continuously to meet the presumptive 

BART requirements 

3.2.1 Technical Feasibility of Alternative NOx Controls 

The technical feasibility and performance levels of the alternative NOx control technologies are evaluated 

below in terms of their application to Kincaid Units 1 and 2. 

 Selective Catalytic Reduction 

Selective Catalytic Reduction (SCR) is a process that involves post-combustion removal of NOx from flue gas 

utilizing a catalytic reactor. In the SCR process, ammonia injected into the flue gas reacts with NOx and 

oxygen to form nitrogen and water vapor. The SCR process converts NOx to nitrogen and water by the 

following general reactions: 

4NO + 4NH3 + O2 → 4N2 + 6H2O 

 2NO2 + 4NH3 + O2 → 3N2 + 6H2O 

The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively lower the 

activation energy of the NOx decomposition reaction to about 375 to 750°F, depending on the specific catalyst 

and other contaminants in the flue gas. The factors affecting SCR performance are catalyst reactor design, 

optimum operating temperature, sulfur content of the fuel, catalyst deactivation due to aging or poisoning, 

ammonia slip emissions, and design of the ammonia injection system. 

The SCR system is comprised of a number of subsystems, including the SCR reactor, ammonia injection 

system, and ammonia storage and delivery system. Typically, the SCR reactor would be located downstream 

of the economizer and upstream of the air pre-heater and the particulate control system. From the 
3-7 January 2009

BART Analysis for Kincaid Power Station 

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economizer outlet, the flue gas would first pass through a low-pressure ammonia/air injection grid designed to 

provide optimal mixing of ammonia with flue gas. The ammonia treated flue gas would then flow through the 

catalyst bed and exit to the air pre-heater. The SCR system for a coal boiler typically uses a fixed bed 

catalyst in a vertical down-flow, multi-stage reactor. 

Reduction catalysts are divided into two groups: base metal, primarily vanadium, platinum or titanium, (lower 

temperature), and zeolite (higher temperature). Both groups exhibit advantages and disadvantages in terms 

of operating temperature, ammonia-NOx ratio, and optimum oxygen concentration. The optimum operating 

temperature for a vanadium-titanium catalyst system is in the range of 550° to 750°F, which is significantly 

higher than for platinum catalyst systems. However, the vanadium-titanium catalyst systems begin to break 

down when operating at temperatures above this range. Operation above the maximum temperature results 

in oxidation of ammonia to ammonia sulfate and NOx, thereby actually increasing NOx emissions. 

SCR with ammonia injection technology is a demonstrated, commercially available technology. SCR has 

been used with other coal-fired boilers; therefore, SCR is technically feasible for the control of NOX emissions 

from Units 1 and 2. Performance data from Units 1 and 2 indicate that the SCR systems are capable of NOx

removal efficiencies ranging from 85 to 90%. Based on these performance data, continuous operation of the 

SCR system will ensure that Units 1 and 2 will comply with the presumptive BART limit for cyclone furnaces of 

0.10 lb/MMBtu. 

 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction is a post-combustion control technology that involves ammonia or urea 

injection into the flue gases without the presence of a catalyst. SNCR, similar to SCR, involves the reaction of 

NOX with ammonia, where a portion of the NOX is converted to molecular nitrogen and water. Without the use 

of a catalyst or supplemental fuel injection, the NOX reduction reaction temperature must be tightly controlled 

between 1,600 and 2,200°F (between 1,600 and 1,800°F for optimum efficiency). Below 1,600°F ammonia 

will not fully react, resulting in un-reacted ammonia that is emitted into the atmosphere, (referred to as 

ammonia slip). If the temperature rises above 2,200°F, the ammonia added will be oxidized resulting in an 

increased level of NOX emissions. 

SNCR with ammonia injection technology is a demonstrated, commercially available technology. SNCR has 

been used with other coal-fired boilers; therefore, SNCR is indeed technically feasible for the control of NOX

emissions from Units 1 and 2. However, NOX removal efficiencies with SNCR are lower than SCR, typically 

ranging from 30 to 50% depending on the combustion process and inlet NOx concentrations. Based on such 

performance estimates, SNCR system is not capable of achieving the presumptive BART limit of 0.10 

lb/MMBtu. Because SNCR is less effective than SCR, this technology is not considered further in this 

analysis. 

3.2.2 Discussion of Candidate NOx Control Technologies 

The NOX post-combustion control technologies identified for evaluation are SCR and SNCR. Of these 

technologies, SCR has been demonstrated to be the most effective technology in minimizing NOx emissions 

from coal-fired boilers. Further, SCR is the only technology capable of achieving the presumptive BART limit 

for cyclone furnaces. Accordingly, continuous operation of the SCR systems with a rolling 30-day emission 

rate of 0.10 lb/MMBtu is recommended as BART for Kincaid Units 1 and 2. 

3.3 PM Emission Control 

Kincaid Units 1 and 2 currently employ high-efficiency Electro-Static Precipitators (ESP) to control Particulate 

Matter (PM) emissions. The baseline PM emission rates for Units No. 1 and 2 are 0.011 and 0.008 lb/MMBtu, 

respectively. These emissions are significantly below the permitted PM emission limit of 0.10 lb/MMBtu. A 

new FF, DS/FF or WFGD are capable of achieving a vendor-guaranteed filterable PM emission level of 0.015 
3-8 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

lb/MMBtu. The DSI with Trona system has been shown significant reductions in PM3. Dominion has 

conservatively assumed that there will not be any appreciable effect on PM emission levels and are assumed 

to remain at the baseline levels. Given the high performance levels of the existing ESPs, these PM control 

devices are considered BART for Unit 1 and 2 and no additional PM controls were considered in this analysis. 

3.4 Control Scenarios 

A number of different control scenarios are possible for reduction of visibility impairing pollutants from the 

Kincaid Power Plant. Based on the anticipated performance levels, the proposed NOx and particulate control 

technologies are considered BART for Units 1 and 2. Therefore, the following SO2 control scenarios are 

included in the modeling assessment: 

• Case 1. Firing 0.3%-sulfur PRB sub-bituminous coal, Dry Sorbent Injection (DSI) with Trona capable 

of achieving an SO2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the 

SCR at a NOx emission level of 0.07 lb/MMBtu. 

• Case 1a. Firing 0.3%-sulfur PRB sub-bituminous coal, enhanced DSI with Trona capable of 

achieving an SO2 emissions level of 0.18 lb/MMBtu (if achievable), enhanced year-round operation of 

the SCR at a NOx emission level of 0.07 lb/MMBtu, and replacement of the existing Electrostatic 

Precipitators (ESP) with Fabric Filters (FF). 

• Case 2. Firing 0.5%-sulfur PRB sub-bituminous coal, Dry Scrubber/Fabric Filter (DS/FF) capable of 

achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NOx

emission level of 0.10 lb/MMBtu. 

• Case 3. Firing 1.62%-sulfur Illinois Basin bituminous coal, Wet Flue Gas Desulfurization (WFGD) 

capable of achieving an SO2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR 

at a NOx emission level of 0.10 lb/MMBtu. 

A DS/FF or WFGD system is capable of achieving a filterable PM emission level of 0.015 lb/MMBtu. The DSI 

with Trona system has shown significant reductions in PM4

. Dominion has conservatively assumed that there 

will not be any appreciable effect on PM emission levels and are assumed to remain at the baseline. As 

noted previously, Units 1 and 2 already incorporate OFA and SCR for NOx control. The NOx controls have 

been demonstrated of being capable of achieving a NOx emission level of 0.10 lb/MMBtu. For the DSI with 

Trona options, Dominion would commit to a NOx emission rate of 0.070 lb/MMBtu. 

The alternative control technologies will not only affect SO2 and NOX emission levels from Units 1 and 2, but 

also will affect the emissions and speciation of PM10. The PM10 emissions and speciation for modeling 

purposes were determined using the following approach: 

• Filterable PM was subdivided by size category consistent with the default approach cited in AP-42, 

Table 1.1-6. For coal-fired boilers equipped with fabric filters, 92 percent of the filterable PM 

emissions are filterable PM10 and 53 percent of the PM emissions are fine filterable PM10 emissions 

(less than 2.5 microns in size). Although not as effective in controlling fine PM, WFGD was assumed 

to have the same particle size distribution for the purposes of the visibility analysis. 

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM10 based on the best 

estimate for electric utility coal combustion in Table 6 of “Catalog of Global Emissions Inventories and 

 

3

 PM10 filterable and condensable emissions were reduced by ≈47% during the demonstration testing at the Mirant 

Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf

4

 PM10 filterable and condensable emissions were reduced by ≈47% during the demonstration testing at the Mirant 

Potomac River Station. The test report can be found at: 

http://www.mirant.com/our_business/where_we_work/Unredacted_Trona_Test_Report_011706BC.pdf
3-9 January 2009

BART Analysis for Kincaid Power Station 

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Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-

D-98-046, January 2002. 

• Condensable inorganic PM10 emissions, assumed to consist of H2SO4, are based on “Estimating 

Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2007. 

For coal-fired boilers equipped with SCR, H2SO4 emissions are determined by the following 

relationship: 

E = (Q)(98.06/64.04)(F1+S2 F3)(F2) 

where: E is the H2SO2 emission rate (lb/hr), 

Q is the baseline SO2 emission rate (lb/hr), 

F1 is the fuel factor (0.00111 for PRB sub-bituminous coal and 0.016 for mediumsulfur eastern bituminous coal), 

S2 is the SCR catalyst SO2 oxidation rate (0.003 for PRB sub-bituminous coal and 

0.005 for eastern bituminous coal) 

F3 is the technology impact factor (0.17 for PRB sub-bituminous coal and 1.00 for 

eastern bituminous coal), 

F2 is the control factor (0.56 and 0.85 for an air heater PRB coal and bituminous 

coal, respectively, 0.73 and 0.77 for an ESP for PRB coal and bituminous coal, 

respectively, 0.5 for DSI, 0.47 for wet scrubbers, and 0.01 for a DS/FF). 

• For coal-fired boilers with FGD, the total condensable organic PM10 emission factor is 0.004 

lb/MMBtu based on AP-42, Table 1.1-5. 

Tables 3-2, 3-3, 3-4, and 3-5 provide summaries of the SO2, NOx, and PM emissions that were used in the 

modeling analysis for cases 1, 1a, 2, and 3 respectively. Table 3-6 provides the stack parameters that were 

used in the modeling for these cases. 
3-10 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1) 
3-11 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-3 Kincaid Future Enhanced DSI with Trona Emissions (Case 1a) 
3-12 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-4 Kincaid Future DS/FF Emissions (Case 2) 
3-13 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-5 Kincaid Future WFGD Emissions (Case 3) 
3-14 

BART Analysis for Kincaid Power Station 02285-076-400

Table 3-6 Kincaid Future DSI with Trona, DS/FF and WFGD Stack Parameters 

Case Description 

UTM 

Northing 

(m) 

UTM 

Easting 

(m) 

Base 

Elevation 

(m) 

Stack 

Height 

(m) 

Stack 

Diameter 

(m) 

Flue Gas 

Temperature 

(°K) 

Flu

Flo

(

1 DSI, Enhanced SCR, ESP 4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,6

1a 

Enhanced DSI, Enhanced SCR, FF, 

4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,6

2 SCR, Dry Scrubber, FF 4,385,605.6 284,850.0 182.87 186.69 9.03 352.59 1,43 SCR, ESP, WFGD 4,385,605.6 284,850.0 182.87 186.69 9.03 324.82 1,3
4-1 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

4.0 Meteorological Data used in Visibility Improvement Modeling 

This section discusses refinements to the Lake Michigan Air Directors Consortium (LADCO) and Midwest 

Regional Planning Organization (MRPO) meteorological database that was used for the Kincaid BART 

modeling. 

4.1 Elements of the Refined Analysis 

ENSR made several refinements to the CALMET meteorological database produced by LADCO/MRPO for 

BART CALPUFF analyses for Midwestern States. The CALMET database derived by LADCO/MRPO has a 

domain that covers approximately a 3,492 km (east-west) by 3,240 km (north-south) area with a 36-km grid 

resolution. This area covers the entire continental United States east of the Rocky Mountains, but its large 

size limits the horizontal resolution of each grid element to 36 km. This coarse grid resolution, without further 

refinement, can be deemed appropriate for a screening-level analysis, but it would not be considered 

appropriate for a more refined analysis. 

ENSR developed a refined meteorological database that included a modeling domain encompassing the two 

Class I areas (Mingo and Mammoth Cave), the Kincaid facility, and the appropriate buffers around the source 

and Class I areas for puffs recirculation. This domain covers approximately a 486 km (east-west) by 456 km 

(north-south) area, has a grid resolution of 6 km (6 times better than the LADCO/MRPO database in both eastwest and north-south directions), and contains 10 vertical levels. The refined database utilized the same MM5 

databases that were used to develop the LADCO/MRPO 36-km CALMET database. 

In addition to the use of consistent MM5 databases with the LADCO-developed meteorological data, ENSR 

utilized similar model switches/settings, when appropriate, that were used to develop the LADCO/MRPO 

CALMET database. To improve the database even further, ENSR introduced actual surface, precipitation, and 

twice-daily upper air sounding observations into the refined meteorological database. These improvements in 

the CALMET database provide more accurate plume trajectories from the Kincaid facility to the distant Class I 

areas. 

In addition, ENSR used the latest EPA-approved versions of CALMET (Version 5.8) and CALPUFF (Version 

5.8), rather than the “old” EPA-approved versions suggested in the MRPO BART common protocol (available 

at http://www.state.in.us/idem/programs/air/workgroups/regionalhaze/docs/BART_protocol.pdf). 

4.2 CALMET Processing 

ENSR used refined 6-km grid spacing for the CALMET and CALPUFF models. The modeling domain was 

based on a 100-km buffer around the source and at least a 50-km buffer around each of the two Class I areas 

to account for puffs recirculation. The modeling domain is shown in Figure 4-1. This design creates a 486 km 

(east-west) x 456 km (north-south) domain extent at a 6-km resolution. 

A Lambert Conformal Conic (LCC) coordinate system was used and is identical to the LADCO/MRPO 

coordinate system. The LCC projection for this analysis was based on the NAS-C datum and standard 

parallels of 33 and 45 degrees North, with an origin of 40 degrees North and 97 degrees West. 

ENSR used the latest EPA-approved version of CALMET (Version 5.8, Level 070623) to produce threedimensional wind fields for three years (2002-2004). Advanced meteorological data in the form of prognostic 

mesoscale meteorological data, such as the Fifth Generation Mesoscale Model (MM5), was used to provide a 

superior estimate of the initial wind fields. This application consisted of 3 years (2002-2004) of prognostic 

MM5 meteorological data supplied by the MRPO at a 36-km resolution. 
4-2 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

• 2002 MM5 data set at 36 km resolution provided by CENRAP; 

• 2003 MM5 data set at 36 km resolution provided by Midwest RPO; 

• 2004 MM5 data set at 36 km resolution provided by Midwest RPO. 

These databases are consistent with those used by LADCO/MRPO for their BART assessments. 

These prognostic meteorological data sets were initially combined with the 6-km grid resolution terrain and 

land use data to more accurately characterize the wind flow throughout the modeling domain. The gridded 

terrain data was derived using the U.S. Geological Survey (USGS) 90-meter grid spacing Digital Elevation 

Model (DEM) files. These files were processed in the TERREL pre-processor program. The gridded land use 

data was derived from USGS 1:250,000 Composite Theme Grid land use files. 

The Step 2 wind fields were produced using the input of all available National Weather Service (NWS) and 

CASTNET hourly surface and twice-daily upper air balloon sounding data within the modeling domain. Figure 

4-2 shows the meteorological stations that were included in the CALMET modeling and Appendix A provides 

their names and locations. 
4-3 January 2009 BART Analysis for Kincaid Power Station 

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Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain 
4-4 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Figure 4-2 Location of Meteorological Stations used in CALMET Processing 
5-1 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

5.0 CALPUFF Modeling Procedures 

This section provides a summary of the modeling procedures that were used for the refined CALPUFF 

analysis conducted for the Kincaid Power Plant. 

5.1 CALPUFF Modeling Domain and Receptors 

ENSR used the latest EPA-approved version of CALPUFF (Version 5.8, Level 070623) that has been posted 

at http://www.src.com/calpuff/download/download.htm#EPA_VERSION. 

The extents of the 6-km domain are shown in Figure 4-1. The modeling domain was based on a 100-km 

buffer around the source and at least a 50-km buffer around each of the two Class I areas plus an additional 

buffer to the east and to the west to account for puff re-circulations. The modeling domain is shown in Figure 

4-1. This design allows for a 486 km (east-west) x 456 km (north-south) domain extent, at a 6-km resolution. 

5.2 Technical Options Used in the Modeling 

For CALPUFF modeling technical options, inputs, and processing steps, the Kincaid modeling procedures 

followed the MRPO common BART protocol. 

For CALPUFF modeling, ENSR used seasonal ozone and ammonia ambient background concentrations that 

are identical to the MRPO common BART modeling protocol and are listed in Table 5-1. 

Table 5-1 MRPO Ozone and Ammonia Seasonal Concentrations 

Parameter Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

O3 (ppb) 31 31 31 37 37 37 33 33 33 27 27 27 

NH3 (ppb) 0.3 0.3 0.3 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 

Due to the large distance to the nearest Class I areas, building downwash effects were not included in the 

CALPUFF modeling. 

5.3 Natural Conditions and Monthly f(RH) at Class I Areas 

Two Class I areas were modeled for the Kincaid facility. For these Class I areas, natural background 

conditions were established in order to determine a change in natural conditions related to a source’s 

emissions. 

For BART analyses, EPA has allowed states to accept either the annual average or 20% best day’s natural 

background for BART exemption and determination modeling analyses. Regional Planning Organizations 

(RPOs) have provided guidance to states within their RPOs on what values to accept, which typically has 

varied based on the degree of the meteorological database refinement. For example, the VISTAS RPO has 

generally adopted the annual average background because it has provided member states with refined 

meteorological data sets. Since MRPO used the 36-km database with no observations, as a measure of 

conservatism, MRPO/LADCO recommended to states that the 20% best day’s background be incorporated 

into the analysis as opposed to the annual average. This measure of conservatism was taken due to concerns 

by EPA Region 5 and FLMs on the accuracy of the 36-km meteorological data in “NO-OBS” mode. However, 

Wisconsin and Indiana, both MRPO states, have stated that they would allow sources to use the annual 
5-2 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

average background with the 98th percentile day as opposed to the 20% best days if a site-specific 

meteorological database is developed. 

ENSR refined the meteorological database with a finer grid resolution (6-km) and by introducing surface 

observations. Having a refined meteorological database has provided ENSR with additional justification for 

using the annual average background, while evaluating visibility impacts based on the source’s impacts at the 

98th percentile day modeled results. This procedure is consistent with other eastern states and other states 

within the MRPO. 

For the modeling described in this document, ENSR used the annual average natural background 

concentrations shown in Table 5-2, modified as noted below with site-specific considerations, and 

corresponding to the annual average natural background concentrations (EPA 2003, Appendix B). 

To determine the input to CALPOST, it is first necessary to convert the deciviews to extinction using the 

equation: 

Extinction (Mm-1) = 10 exp(deciviews/10). 

For example, for Mingo, 7.43 deciviews is equivalent to an extinction of 21.02 inverse megameters (Mm-1); this 

extinction includes the default 10 Mm-1 for Rayleigh scattering. This remaining extinction is due to naturally 

occurring particles, and is held constant for the entire year’s simulation. Therefore, the data provided to 

CALPOST for Mingo would be the total natural background extinction minus 10 (expressed in Mm-1), or 11.02. 

This is most easily input as a fine soil concentration of 11.02 μg/m3

 in CALPOST, since the extinction 

efficiency of soil (PM-fine) is 1.0 and there is no f(RH) component. The concentration entries for all other 

particle constituents would be set to zero, and the fine soil concentration would be kept the same for each 

month of the year. The monthly values for f(RH) that CALPOST needs were taken from "Guidance for 

Tracking Progress Under the Regional Haze Rule" (EPA, 2003) Appendix A, Table A-3. 

Table 5-2 Annual Average Natural Background Concentrations 

Component Represented Mammoth Cave Mingo 

Soil (PM fine) (deciview) 7.69 7.43 

Soil (PM fine) (Mm-1 or μg/m3)* 21.58 21.02 

* Extinction values include Rayleigh scattering. 

5.4 Light Extinction and Haze Impact Calculations 

The CALPOST postprocessor was used for part of the calculation of the impact from the modeled source’s 

primary and secondary particulate matter concentrations on light extinction. The formula that is used in 

CALPOST is the existing IMPROVE/EPA formula, which is applied to determine a change in light extinction 

due to increases in the particulate matter component concentrations. Using the notation of CALPOST, the 

formula is the following: 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

The concentrations, in square brackets, are in μg/m3

 and bext is in units of Mm-1. The Rayleigh scattering term 

(bRay) has a default value of 10 Mm-1, as recommended in EPA guidance for tracking reasonable progress 

(EPA, 2003a). 
5-3 January 2009

BART Analysis for Kincaid Power Station 

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The assessment of visibility impacts at the Class I areas applied CALPOST Method 6 (as standard with all 

BART applications). Each hour’s source-caused extinction is calculated by first using the hygroscopic 

components of the source-caused concentrations, due to ammonium sulfate and nitrate, and monthly Class I 

area-specific f(RH) values. The contribution to the total source-caused extinction from ammonium sulfate and 

nitrate is then added to the other, non-hygroscopic components of the particulate concentration (from coarse 

and fine soil, secondary organic aerosols, and from elemental carbon) to yield the total hourly source-caused 

extinction. 
6-1 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

6.0 CALPUFF Modeling and BART Determination Results 

This section provides a summary of the modeled visibility improvement as a result of installing BART controls 

on Kincaid Units 1 and 2. It also presents the recommended BART determination. 

6.1 Modeled Control Scenarios 

The baseline emissions were modeled along with the four alternative control emission scenarios. Tables 3-2 

through 3-5 present contain the emissions associated with the alternative control scenarios for Units 1 and 

2.

6.2 Modeling Results for Baseline Emissions 

CALPUFF modeling results of the baseline emissions at the two Class I areas are presented in Table 6-1 and 

graphically plotted in Figure 6-1. Modeling was conducted for all three years of CALMET meteorological data 

(2002-2004). For each Class I area and year, Table 6-1 lists the number of days above 0.5 and 1.0 deltadeciview due to plant emissions as well as the maximum and the 8th highest delta-deciview. Figure 6-1 

indicates that the higher visibility impacts occur at Mingo Wilderness and they are due to that park’s proximity 

to Kincaid. 

The results of the baseline emissions indicate that the 8th highest visibility impacts at Mingo and Mammoth 

Cave are above the 0.5 delta deciview threshold. 

6.3 Modeling Results for the Alternative Control Cases 

CALPUFF modeling results of the four control cases at the two Class I areas are presented in Table 6-1 and 

graphically plotted in Figure 6-1. Modeling was conducted for all three years of CALMET meteorological data 

(2002-2004). For each Class I area and year, Table 6-1 lists the number of days above 0.5 and 1.0 deltadeciview due to plant BART emission controls. 

Figure 6-1 indicates that substantial visibility improvements occur with either Case 1/1a (DSI with Trona) and 

Case 2 (DS/FF) controls and that no perceptible visibility impacts (defined by a 98th percentile change of at 

least 0.5 delta-deciview) occur at any Class I area with these controls. 

The results show that the averaged regional haze impacts with dry scrubber/fabric filter controls are reduced 

by about 1.10 delta-dv at Mingo and by 0.96 delta-dv at Mammoth Cave (relative to the baseline case). 

Nearly the same visibility improvement occurs with the use of the BART Case 3 controls, and the modeling 

results provided here have not accounted for the larger energy requirements of these controls. Installation of 

WFGD results in less improvement at the Class I areas due to the higher H2SO4 emissions associated with 

WFGD. Addition of WFGD would reduce visibility impacts by about 0.96 delta-dv at Mingo and by 0.81 deltadv at Mammoth Cave from the baseline case. 

Figure 6-2 shows a comparison between the visibility improvement over the top 8 days on average for BART 

control cases 1 and 2. This is a more robust comparison because it uses a more stable statistical sample of 

peak impact days. The results indicate that the visibility improvements available from BART cases 1 and 2 are 

essentially equivalent. 
6-2 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emissions 

Figure 6-1 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART 

Control Emissions 

Dominion Kincaid

Regional Haze Impacts Due to Units 1&2 Baseline and BART Control Emissions

3-Year Average 8th Highest Impacts

1.37

1.22

0.30

0.25 0.27

0.23 0.25

0.46

0.40

0.26

0.0

0.5

1.0

1.5

Mingo Wilderness Mammoth Cave National Park

Class I Area

8th Highest delta-deciview

Baseline: 0.3% S PRB Coal, Seasonal

SCR, ESP

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR,

FF

Case 2: 0.5% S PRB Coal, year-round

SCR, DS, FF

Case 3: 1.62% S Illinois Coal, 

year-round SCR, ESP, WFGD
6-3 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

Figure 6-2 Regional Haze Impacts For Top 8 Days Averaged Over 3 Years: Cases 1, 1a, and 2 

3-Year Average of 8 Highest Days

0.355 0.350 0.357

0.385

0.326

0.371

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

Mingo Wilderness Mammoth Cave National Park

Class I Area

Average Delta-Deciview of 8 Highest Days

Case 1: 0.3% S PRB Coal, DSI/Trona,

Enhanced year-round SCR, ESP

Case 1a: 0.3% PRB Coal, Enhanced

DSI/Trona, Enhanced year-round SCR, FF

Case 2: 0.5% S PRB Coal, year-round SCR,

DS, FF
6-4 January 2009 BART Analysis for Kincaid Power Station 

02285-076-400

6.4 Cost of BART Control Cases 

Table 6-2 summarizes the annualized control cost that is a function of the capital and annual operating costs, 

as well as fixed capital charges estimated by Dominion Energy. The table also presents a computation of 

each control case’s visibility improvement effectiveness and cost relative to the baseline conditions, since each 

control case is independent of the others. The visibility results in Table 6-2 and Table 6-3 are based on the 8th

highest regional haze impacts at Mingo and Mammoth Cave, respectively, averaged over the three years. 

Figure 6-3 presents a graph of visibility improvements as a function of the cost for each control case. It is 

clear from the figure that BART Case 1 (DSI with Trona) is clearly the most cost-effective option for the 

visibility improvement attained. As Figure 6-3 indicates, the incremental cost effectiveness of proceeding to 

Case 1a from Case 1 is steep (very little visibility improvement for the additional cost), so this step is not 

recommended. 

Table 6-2 Visibility Improvement and Annual Costs for Each Control Case at Mingo 

Control Casea

8th Highest at 

Mingo 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal 

SCR, ESP 1.37 $0 $0 

Case 1: 0.3% S PRB Coal, DSI/Trona, 

Enhanced year-round SCR, ESP 0.30 $24,820,000b

 $23,100,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000c

 $29,210,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.26 $94,700,000d

 $85,060,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.46 $125,370,000e

 $137,220,000 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized 

cost becomes $30,660,000 and the incremental cost effectiveness from the baseline becomes $28,530,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized 

cost becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $37,470,000. 

d

 When Case 2 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized 

cost becomes $156,110,000 and the incremental cost effectiveness from the baseline becomes $140,220,000. 

e When Case 3 costs are projected to 2017 dollars (based upon a 2017 installation date), the annualized 

cost becomes $200,430,000 and the incremental cost effectiveness from the baseline becomes $219,370,000.
6-5 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave 

a These costs are based on 2008 dollars. 

b

 When Case 1 costs are escalated to 2014 dollars (based upon 2014 installation date) the Annualized Cost becomes 

$30,660,000 and the Incremental Cost Effectiveness from the baseline becomes $31,770,000. 

c

 When Case 1a costs are projected to 2014 dollars (based upon a 2014 installation date), the annualized cost 

becomes $41,320,000 and the incremental cost effectiveness from the baseline becomes $41,960,000. 

d

 When Case 2 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$156,110,000 and the Incremental Cost Effectiveness from the baseline becomes $161,880,000 

e

 When Case 3 costs are escalated to 2017 dollars (based upon 2017 installation date) the Annualized Cost becomes 

$200,430,000 and the Incremental Cost Effectiveness from the baseline becomes $244,530,000. 

Control Casea

8th Highest at 

Mammoth 

Cave 

3-Yr Ave 

(delta-dv) 

Annualized Cost for 

Unit 1 & 2 

($/Year) 

Incremental Cost 

Effectiveness from 

Baseline ($/dv) 

Baseline: 0.3%S PRB Coal, Seasonal SCR, 

ESP 1.22 $0 $0 

Case 1: 0.3% S PRB Coal, DSI with Trona, 

Enhanced year-round SCR, ESP 0.25 $24,820,000b

 $25,720,000 

Case 1a: 0.3% S PRB Coal, enhanced DSI 

with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000c $32,710,000 

Case 2: 0.5% S PRB Coal, year-round 

SCR, DS, FF 0.25 $94,700,000d

 $98,200,000 

Case 3: 1.62%S Illinois Coal, year-round 

SCR, ESP, WFGD 0.40 $125,370,000e

 $152,950,000 
6-6 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Figure 6-3 Annual Costs vs. Visibility Improvements 

$0

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

$120,000,000

$140,000,000

1.5 1.4 1.11.21.3 1.0 0.70.80.9 0.6 0.30.40.5 0.2 0.00.1

8th Highest delta-dv (Average of 3-Years)

Cost ($/year)

Mingo

Mammoth

Baseline

Case 2

Case 3

Case 1

Case 1A

6.5 Conclusions 

CALPUFF modeling of the baseline emissions and four BART control emission scenarios has been 

conducted. BART control cases included continuous operation of SCR and the installation of DSI with 

Trona, DS/FF and WFGD. Each control case was modeled to assess visibility improvements at the two 

Class I areas within 300 km of the plant. 

The CALPUFF modeling results indicate that the use of DSI with Trona with increased SCR performance 

results in a visibility improvement that is about equivalent to or better than the dry or wet scrubber options, at a 

much reduced cost. Therefore, we conclude that the recommended BART control case is Case 1, with the 

use of DSI with Trona and enhanced SCR performance operation. The difference in effectiveness for regional 

haze reduction between BART Control Cases 1 and 1a is very small and the associated cost is relatively high. 

The ability for an SO2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the use of DSI 

with Trona will be determined from operational experience.
7-1 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

7.0 References 

Environmental Protection Agency (EPA), AP 42, Fifth Edition, Compilation of Air Pollutant Emission Factors, 

Volume 1: Stationary Point and Area Sources, January, 1995 

Environmental Protection Agency (EPA), Guidance for Tracking Progress Under the Regional Haze Rule, 

EPA-454/B-03-003, Appendix A, Table A-3, September, 2003a 

Environmental Protection Agency (EPA), Guidance for Estimating Natural Visibility Conditions Under the 

Regional Haze Program, EPA 454/B-03-005, September 2003b 

Environmental Protection Agency (EPA), Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 

Summary Report and Recommendations for Modeling Long Range Transport Impacts, EPA-454/R-98-019, 

December, 1998 

EPRI. Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, EPRI, Palo Alto, CA: 2008. 

1016384. 

Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; 

Final Rule (FR Vol. 70, No. 128 published July 6, 2005) 

Regional Haze Regulations; Revisions to Provisions Governing Alternative to Source-Specific Best Available 

Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 71, NO. 198 published October 13, 2006) 

Single Source Modeling to Support Regional Haze BART Modeling Protocol November 17, 2005, Lake 

Michigan Air Directors Consortium, Des Plaines, IL 
 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Appendix A 

Meteorological Stations used in CALMET Processing 
 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Table A-1 NWS Surface Stations used in CALMET Processing 

ID Station Name State Latitude Longitude 

724395 ALTON/ST LOUIS RGNL IL 38.90 -90.05 

724338 BELLEVILLE SCOTT AF IL 38.55 -89.85 

724397 BLOOMINGTON/NORMAL IL 40.48 -88.91 

725314 CAHOKIA/ST. LOUIS IL 38.56 -90.15 

724336 CARBONDALE/MURPHYSB IL 37.78 -89.25 

725315 CHAMPAIGN/URBANA IL 40.03 -88.28 

725316 DECATUR AIRPORT IL 39.83 -88.86 

725342 LAWRENCEVILLE\VIN. IL 38.76 -87.60 

724339 MARION REGIONAL IL 37.75 -89.01 

725317 MATTOON/CHARLESTON IL 39.48 -88.28 

724335 MOUNT VERNON (AWOS) IL 38.31 -88.86 

725320 PEORIA GREATER PEOR IL 40.66 -89.68 

724330 SALEM-LECKRONE IL 38.65 -88.96 

724390 SPRINGFIELD CAPITAL IL 39.85 -89.68 

724385 ANDERSON MUNICIPAL IN 40.11 -85.61 

724375 BLOOMINGTON/MONROE IN 39.15 -86.61 

724363 COLUMBUS BAKALAR IN 39.26 -85.90 

724384 EAGLE CREEK IN 39.83 -86.30 

724320 EVANSVILLE REGIONAL IN 38.05 -87.53 

724365 HUNTINGBURG IN 38.25 -86.95 

724380 INDIANAPOLIS INTL A IN 39.71 -86.26 

724386 LAFAYETTE PURDUE UN IN 40.41 -86.93 

725336 MUNCIE/JOHNSON FLD IN 40.25 -85.40 

724356 SHELBYVILLE MUNI IN 39.58 -85.80 

724373 TERRE HAUTE HULMAN IN 39.45 -87.30 

746716 BOWLING GREEN WARRE KY 36.98 -86.43 

746710 FORT CAMPBELL (AAF) KY 36.66 -87.50 

724240 FORT KNOX GODMAN AA KY 37.90 -85.96 

724238 HENDERSON CITY KY 37.81 -87.68 

724235 LOUISVILLE BOWMAN F KY 38.23 -85.66 

724230 LOUISVILLE STANDIFO KY 38.18 -85.73 

724237 OWENSBORO/DAVIESS KY 37.73 -87.16 

724350 PADUCAH BARKLEY REG KY 37.05 -88.76 

723489 CAPE GIRARDEAU MUNI MO 37.23 -89.56 

724454 FARMINGTON MO 37.76 -90.40 

723300 POPLAR BLUFF(AMOS) MO 36.76 -90.46 

724347 ST CHARLES COUNTY A MO 38.91 -90.41 

724340 ST LOUIS LAMBERT IN MO 38.75 -90.36 

724345 ST LOUIS SPIRIT OF MO 38.65 -90.65 

723270 NASHVILLE INTERNATI TN 36.11 -86.68 
 January 2009

BART Analysis for Kincaid Power Station 

02285-076-400

Table A-2 CASTNET Surface Stations used in CALMET Processing 

ID Station Name State Latitude Longitude 

ALH157 Alhambra IL 38.87 -89.62 

CDZ171 Cadiz KY 36.78 -87.85 

MAC426 Mammoth Cave NP KY 37.28 -86.26 

MCK131 Mackville KY 37.70 -85.05 

Table A-3 Upper Air Stations used in CALMET Processing 

WBAN ID Station Name State Latitude Longitude 

4833 Lincoln-Logan IL 40.15 -89.33 

13897 Nashville TN 36.25 -86.57 
IN THE UNITED STATES DISTRICT COURT

FOR THE NORTHERN DISTRICT OF ILLINOIS

UNITED STATES OF AMERICA, 

STATE OF ILLINOIS,

STATE OF LOUISIANA, and the

STATE OF MONTANA

Plaintiffs, 

v. 

) 

) 

) 

) 

) 

) 

) 

) 

) 

EXXON MOBIL CORPORATION and ) No. 

EXXONMOBIL OIL CORPORATION )

)

Defendants. ) 

)

CONSENT DECREE 
TABLE OF CONTENTS

I. JURISDICTION AND VENUE ............................................6

II. APPLICABILITY AND BINDING EFFECT ..................................7

III. OBJECTIVES ..........................................................9

IV. DEFINITIONS ..........................................................9

V. AFFIRMATIVE RELIEF ................................................17

A. Fluid Catalytic Cracking Units ......................................17

B. NOx Emissions Reductions from the FCCUs ...........................18

C. SO2 Emissions Reductions from the FCCUs ............................28

D. Particulate Matter Emissions Reductions from the FCCUs .................39

E. Carbon Monoxide Emissions Reductions from the FCCUs ................41

F. NSPS Applicability to the FCCU Catalyst Regenerators ..................44

G. NOx Emissions Reductions from Combustion Units .....................49

H. SO2 Emissions Reductions from and NSPS Applicability of Heaters, Boilers

and Other Fuel Gas Combustion Devices ..............................56

I. Sulfur Recovery Plant Operations ....................................58

J. Flaring Devices ..................................................67

K. Control of Acid Gas Flaring and Tail Gas Incidents ......................71

L. Control of Hydrocarbon Flaring Incidents ..............................81

M. CERCLA/EPCRA Reporting ........................................82

N. Benzene Waste NESHAP Program Enhancements .......................83

O. Leak Detection and Repair Program Enhancements .....................100

P. Other Compliance Program Requirements Applicable to the Billings and

Joliet Refineries .................................................114

Q. Incorporation of Consent Decree Requirements into Federally

Enforceable Permits ..............................................120

VI. EMISSION CREDIT GENERATION .....................................124

VII. MODIFICATIONS TO IMPLEMENTATION SCHEDULES ...................126

VIII. ENVIRONMENTALLY BENEFICIAL PROJECTS ..........................131

IX. RECORDKEEPING AND REPORTING ...................................138

-i-
X. CIVIL PENALTY .....................................................139

XI. STIPULATED PENALTIES .............................................143

XII. INTEREST ...........................................................167

XIII. RIGHT OF ENTRY ....................................................167

XIV. FORCE MAJEURE ....................................................168

XV. RETENTION OF JURISDICTION / DISPUTE RESOLUTION .................171

XVI. EFFECT OF SETTLEMENT ............................................173

XVII. GENERAL PROVISIONS ..............................................187

XVIII. TERMINATION ......................................................198

XIX. SIGNATORIES .......................................................202

-ii-
TABLE OF APPENDICES

Appendix A: Combustion Unit Information 

Appendix B: PEMS Program Requirements 

Appendix C: NSPS Subpart J Compliance Schedule for Certain Heaters and Boilers 

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

Devices 

Appendix E: “Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas” 

Appendix F: List of Existing Flaring Devices Operated by Covered Refineries 

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

by Covered Refineries 

Appendix H: Data Relevant to Billings FCCU Baseline Emissions, Trials, 

Demonstrations, and Final Limits 

Appendix I: Additional Claims Concerning the Billings Refinery Referenced in 

Consent Decree Subparagraph 252.b 

Appendix J: Table of Alleged CWA Violations at the Joliet Refinery Referenced in 

Consent Decree Subparagraph 252.c.(1) 

Appendix K: Table of Alleged CERCLA Section 103 and EPCRA Section 304 

Reporting Violations at the Joliet Refinery Referenced in Consent Decree 

Subparagraph 252.c.(1) 

Appendix L: Additional Claims Concerning the Joliet Refinery Referenced in Consent 

Decree Subparagraph 252.c.(2) 

Appendix M: Additional Claims Concerning the Baton Rouge Refinery Referenced in 

Consent Decree Subparagraph 252.d 

Appendix N: Schedule for Use of CEMS at ExxonMobil’s FCCUs 

Appendix O: Summary of the Understanding Between LDEQ and the Louisiana 

Wildlife and Fisheries Foundation Relating to ExxonMobil’s Payment for 

Beneficial Environmental Projects Under Consent Decree Paragraph 159 

Appendix P: Joliet Wastewater Treatment Plant Area Program 

Appendix Q: Federal Diesel Emission Reduction SEPs 

Appendix R: Drawing of Real Estate Referenced in Consent Decree Subparagraph 

156.d(1) 

Appendix S: Drawing of Billings Refinery Scrap Yard and Laydown Areas and Land 

Treatment Unit as Referenced in Consent Decree Paragraphs 137 and 138 

Appendix T: Drawing of Joliet Material Staging Area Referenced in Consent Decree 

Subparagraph 135.a 

-iii-
CONSENT DECREE 

WHEREAS, defendant Exxon Mobil Corporation currently owns and operates petroleum 

refineries located in Baton Rouge, Louisiana; Baytown, Texas; and Billings, Montana. 

Defendant ExxonMobil Oil Corporation (formerly known as Mobil Oil Corporation) currently 

owns and operates petroleum refineries located in Beaumont, Texas; Joliet, Illinois; and 

Torrance, California. As specified by Section IV of this Consent Decree: (i) Exxon Mobil 

Corporation and ExxonMobil Oil Corporation are referred to herein as “ExxonMobil;” and 

(ii) the six petroleum refineries identified above are referred to herein as the “Covered 

Refineries.” 

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

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

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

Agency (“EPA”), alleges upon information and belief that defendant ExxonMobil has violated 

and/or continues to violate certain requirements of the Clean Air Act, and the regulations and 

permits promulgated thereunder at the Covered Refineries. 

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

continues to violate the following statutory and regulatory provisions: 

1) Prevention of Significant Deterioration (“PSD”) requirements found at Part C of 

Subchapter I of the 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 of Subchapter I of the Act, 42 U.S.C. §§ 7502-

7503, and the regulations promulgated thereunder at 40 C.F.R. § 51.165(a) and (b), 40 

C.F.R. Part 51, Appendix S, and 40 C.F.R. § 52.24 (“PSD/NSR Regulations”), for fuel 

1
gas combustion devices and fluid catalytic cracking unit catalyst regenerators for NOx, 

SO2, CO and PM; 

2) New Source Performance Standards (“NSPS”) found at 40 C.F.R. Part 60, Subparts A

and J (“Refinery NSPS Regulations”), promulgated under Section 111 of the Act, 42

U.S.C. § 7411, for sulfur recovery plants, fuel gas combustion devices, and fluid catalytic

cracking unit catalyst regenerators; 

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

Sections 111 and 112 of the Act, and found at 40 C.F.R. Part 60 Subpart 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 Benzene

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

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

WHEREAS, the United States also alleges upon information and belief that ExxonMobil

has violated and/or continues to violate certain other legal requirements applicable to the 

Covered Refineries, including requirements imposed by the following statutes and the 

regulations promulgated thereunder: (i) the Clean Water Act (the “CWA”), 33 U.S.C. § 1251 et 

seq.; (ii) the Resource Conservation and Recovery Act (“RCRA”), 42 U.S.C. § 6901 et seq.; and 

(iii) the release reporting requirements found at Section 103(a) of the Comprehensive 

Environmental Response, Compensation, and Liability Act (“CERCLA”), 42 U.S.C. § 9603(a), 

and Section 304 of the Emergency Planning and Community Right-to-Know Act (“EPCRA”), 

42 U.S.C. § 11004. 

2
WHEREAS, the United States also specifically alleges with respect to the Covered 

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

violation of the state implementation plans (“SIPs”) and other state rules adopted by the states 

and/or local air quality districts in which the Covered Refineries are located to the extent that 

such plan or rules implement, adopt or incorporate the above-described Federal requirements. 

WHEREAS, the State of Illinois (on behalf of the Illinois Environmental Protection 

Agency), the State of Louisiana (on behalf of the Louisiana Department of Environmental 

Quality), and the State of Montana (on behalf of the Montana Department of Environmental 

Quality) (referred to herein as the “Co-Plaintiffs”) have joined in this matter to allege violations 

of their respective applicable SIP provisions and other state and local rules, regulations, and 

permits incorporating and/or implementing the foregoing federal requirements. 

WHEREAS, with respect to the provisions of Subsection V.K (“Control of Acid Gas 

Flaring and Tail Gas Incidents”) of this Consent Decree, EPA maintains that "[i]t is the intent of 

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

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

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

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

Refineries, Brass or Bronze Ingot Production Plants, Iron and Steel Plants, Sewage Treatment 

Plants, Vol. 1, 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 of the standards at 40 C.F.R. Part 60, Subpart J. 

3
WHEREAS, EPA recognizes that “Malfunctions,” as defined in Section IV (Definitions) 

of this Consent Decree and 40 C.F.R. § 60.2, of the “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. 

§ 60.11(d) if the 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, ExxonMobil 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 permits and is 

not liable for civil penalties and injunctive relief as alleged in the Complaint. 

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, ExxonMobil consents to the simultaneous filing of the Complaint and 

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

goals of the United States, the Co-Plaintiffs, and ExxonMobil under the Clean Air Act and the 

corollary state statutes, and ExxonMobil 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. 

4
WHEREAS, even before entry into the settlement negotiations that resulted in this 

Consent Decree, ExxonMobil had taken significant steps to reduce air pollutant emissions from 

the Covered Refineries, including by: 1) installing the first selective catalytic reduction (“SCR”) 

NOx control system on any fluid catalytic cracking unit (“FCCU”) in the United States, at its 

Torrance Refinery in 2000; and 2) installing wet gas scrubber (“WGS”) SO2 and PM control 

systems on its Baton Rouge Refinery FCCUs (which commenced operation in 1976) and 

Baytown Refinery FCCUs (which commenced operation in 1974 and 1975). 

WHEREAS, by entering into this Consent Decree, ExxonMobil is committed to making 

further reductions in air pollutant emissions from its operations. 

WHEREAS, the United States, the Co-Plaintiffs, and ExxonMobil estimate that, when 

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

Consent Decree are fully implemented, annual emissions from the Covered Refineries will be 

reduced by the following amounts, as compared to historical baseline emissions: 1) nitrogen 

oxide by approximately 10,200 tons; and 2) sulfur dioxide by approximately 40,700 tons. 

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

statutory notice of the alleged violations. 

WHEREAS, coordinated negotiations between the United States and ExxonMobil and 

Chalmette Refining, L.L.C. – addressing multiple petroleum refineries owned and/or operated by 

those entities – resulted in two complementary Consent Decrees, namely: (i) this Consent 

Decree with ExxonMobil (relating to the Covered Refineries); and (ii) a separate Consent Decree 

with Chalmette Refining, L.L.C. that has been lodged with the United States District Court for 

the Eastern District of Louisiana (relating to a refinery in Chalmette, Louisiana that is owned by 

5
Chalmette Refining, L.L.C. and operated for and on behalf of Chalmette Refining, L.L.C. by 

ExxonMobil Oil Corporation). 

WHEREAS, the Parties agree that: (i) settlement of the matters set forth in the Complaint 

(filed herewith) and in Section XVI (Effect of Settlement) of this Consent Decree is in the best 

interests of the Parties, and the public; and (ii) entry of this Consent Decree without litigation is 

the most appropriate means of resolving 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. 

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

Section XVI of the Consent Decree, and before the taking of any testimony, without adjudication 

of any issue of fact or law, and upon the consent and agreement of the Parties to the Consent 

Decree, it is hereby ORDERED, ADJUDGED and DECREED as follows: 

I. JURISDICTION AND VENUE 

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

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

over the subject matter of this action pursuant to Sections 113(b) and 167 of the Clean Air Act, 

42 U.S.C. §§ 7413(b) and 7477, Section 309(b) of the CWA, 33 U.S.C. § 1319(b), Section 

3008(a) of RCRA, 42 U.S.C. § 6928(a), Section 109(c) of CERCLA, 42 U.S.C. § 9609(c), and 

Section 325(b) of EPCRA, 42 U.S.C. § 11045(b). The Complaint states a claim upon which 

relief may be granted for injunctive relief and civil penalties against ExxonMobil under the 

Clean Air Act, the CWA, RCRA, CERCLA Section 103, and EPCRA Section 304. Authority to 

bring this suit is vested in the United States Department of Justice by 28 U.S.C. §§ 516 and 519. 

6
2. Venue is proper in the Northern District of Illinois pursuant to Section 113(b) of 

the Clean Air Act, 42 U.S.C. § 7413(b), CWA Section 309(b), 33 U.S.C. § 1319(b), RCRA 

Section 3008(a), 42 U.S.C. § 6928(a), CERCLA Section 113(b), 42 U.S.C. § 9613(b), EPCRA 

Section 325(b)(3), 42 U.S.C. § 11045(b)(3), and 28 U.S.C. §§ 1391(b) and (c), and 1395(a). 

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

in this District, and does not object to the participation of the Co-Plaintiffs as parties or 

intervenors in this action. 

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

the State of Louisiana, the State of Montana, the State of Texas, the California Air Resources 

Board, and the South Coast Air Quality Management District, in accordance with Section 

113(a)(1) of the Clean Air Act, 42 U.S.C. § 7413(a)(1), and as required by Section 113(b) of the 

Clean Air Act, 42 U.S.C. § 7413(b). 

II. APPLICABILITY AND BINDING EFFECT 

4. The provisions of the Consent Decree shall apply to the Covered Refineries. The 

provisions of the Consent Decree shall be binding upon the United States, the Co-Plaintiffs, and 

ExxonMobil, (acting through its officers, agents, servants, employees, and members acting in 

their capacities as such), and upon ExxonMobil’s successors and assigns; provided, however, 

that all obligations of ExxonMobil herein related to the Baton Rouge, Baytown, or Billings 

Refineries shall be borne by Exxon Mobil Corporation, and all obligations of ExxonMobil herein 

related to the Beaumont, Joliet or Torrance Refineries shall be borne by ExxonMobil Oil 

Corporation. 

5. ExxonMobil, the United States, and the Co-Plaintiffs agree not to contest the 

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

7
6. ExxonMobil shall give written notice of the Consent Decree to any successors in 

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

(to the extent such portion is subject to one or more requirements of this Consent Decree) and 

shall provide a copy of the Consent Decree to any successor in interest. ExxonMobil shall notify 

the United States, and the Applicable Co-Plaintiff, in accordance with the notice provisions set 

forth in Paragraph 266 (Notice), of any successor in interest at least thirty (30) days prior to any 

such transfer. 

7. ExxonMobil 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 

Consent Decree, which modification shall make the terms and conditions of the Consent Decree 

that apply to the Covered Refinery or portion of the Covered Refinery applicable to the 

transferee. In the event of such transfer, ExxonMobil shall notify the United States and the 

Applicable Co-Plaintiff. By no earlier than thirty (30) days after such notice, ExxonMobil may 

file a motion to modify the Consent Decree to make the terms and conditions of the Consent 

Decree applicable to the transferee. ExxonMobil shall be released from the obligations and 

liabilities of this Consent Decree unless the United States opposes the motion and the Court finds 

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

liabilities under the Consent Decree. 

8. Subject only to Paragraph 7, above, and Sections VII (Modifications to 

Implementation Schedules) and XIV (Force Majeure), below, ExxonMobil shall be solely 

responsible for ensuring that performance of the work contemplated under this Consent Decree is 

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

8
and any attachments hereto. ExxonMobil shall provide a copy of this Consent Decree (or an 

extract of applicable provisions of this Consent Decree) to each consulting or contracting firm 

that is retained to perform work required under Subsections V.N or V.O of this Consent Decree, 

upon execution of any contract relating to such work. Copies of the Consent Decree (or an 

extract of applicable provisions of this 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 under this Consent Decree. 

III. OBJECTIVES 

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

the federal Clean Air Act, the CWA, RCRA, CERCLA Section 103, EPCRA Section 304, the 

Illinois Environmental Protection Act, 415 Ill. Comp. Stat. 5/1 - 58.17, the Louisiana 

Environmental Quality Act, La. Rev. Stat. Ann. § 30:2001 et seq., and the Clean Air Act of 

Montana, Mont. Code Ann. §§ 75-2-101 - 75-2-429. 

IV. DEFINITIONS 

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

meaning given to those terms in the Clean Air Act, the CWA, RCRA, CERCLA Section 103, 

EPCRA Section 304, and the implementing regulations promulgated thereunder. The following 

terms used in this Consent Decree shall be defined, for purposes of the 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. 

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b. “Acid Gas Flaring” or “AG Flaring” shall mean the combustion of Acid 

Gas and/or Sour Water Stripper Gas in an AG 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 of Acid Gas or Sour Water Stripper Gas contained in this Decree. 

c. “Acid Gas Flaring Device” or “AG Flaring Device” shall mean the 

devices identified in Appendix F that are used at the Covered Refineries to combust Acid Gas 

and/or Sour Water Stripper Gas. The term “Acid Gas Flaring Device” does not include facilities 

in which gases are combusted to produce sulfur or sulfuric acid. To the extent that, during the 

duration of the Consent Decree, any Covered Refinery utilizes any Flaring Devices other than 

those specified above 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 of 

this Consent Decree. 

d. “Acid Gas Flaring Incident” or “AG Flaring Incident” shall mean the 

continuous or intermittent combustion of Acid Gas and/or Sour Water Stripper Gas from one or 

more AG Flaring Devices at a Covered Refinery that results in the emission of sulfur dioxide 

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) hour period(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 of AG Flaring within the AG Flaring Incident. 

10
e. “Applicable Co-Plaintiff” shall mean the following states with respect to 

the following refineries: 

Baton Rouge Refinery State of Louisiana through the LDEQ 

Billings Refinery State of Montana through the MDEQ 

Joliet Refinery State of Illinois on behalf of IEPA 

f. “Average Weight % of Total Catalyst Added” (as determined on a 7-day 

rolling average basis) shall mean: 

Amount of SO2 Reducing Catalyst Added (in pounds per day as received) x 100 percent 

Total Catalyst Addition Rate (in pounds per day as received). 

g. “CEMS” shall mean continuous emissions monitoring system. 

h. “Combustion Units” shall mean the heaters, boilers, and gas turbines with 

a capacity of greater than 40 mmBtu/hr (at HHV) at the Covered Refineries that are listed in 

Appendix A. 

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

any and all appendices attached to the Consent Decree. 

j. “Covered Refineries” shall mean the following petroleum refineries: 

(1) the Baton Rouge Refinery, owned and operated by Exxon Mobil Corporation and located at 

4045 Scenic Highway in Baton Rouge, Louisiana; (2) the Baytown Refinery, owned and 

operated by Exxon Mobil corporation and located at 2800 Decker Drive in Baytown, Texas; (3) 

the Beaumont Refinery, owned and operated by ExxonMobil Oil Corporation and located at End 

of Burt Street in Beaumont, Texas; (4) the Billings Refinery, owned and operated by Exxon 

Mobil Corporation and located at 700 Exxon Refinery Road in Billings, Montana; (5) the Joliet 

Refinery, owned and operated by ExxonMobil Oil Corporation and located at I-55 and Arsenal 

11
Road in Channahon, Illinois; and (6) the Torrance Refinery, owned and operated by ExxonMobil 

Oil Corporation and located at 3700 West 190th Street in Torrance, California. 

k. “CO” shall mean carbon monoxide. 

l. “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 lb/mmBTU HHV when firing 

natural gas at 3% stack oxygen at full design load without air preheat, regardless of whether 

upon installation actual emissions exceed 0.040 lb/mmBTU HHV. 

m. “Date of Lodging” or “Date of Lodging of the Consent Decree" shall 

mean the date the Consent Decree is lodged with the Clerk of the Court for the United States 

District Court for the Northern District of Illinois. 

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

o. “Entry Date” shall mean the date the Consent Decree is entered by the 

United States District Court for the Northern District of Illinois. 

p. “ExxonMobil” shall mean Exxon Mobil Corporation and ExxonMobil Oil 

Corporation and their successors and assigns. For matters under this Consent Decree relating to 

the Baton Rouge Refinery, the Baytown Refinery, and/or the Billings Refinery, the term 

“ExxonMobil” shall mean Exxon Mobil Corporation and its successor and assigns. For matters 

under this Consent Decree relating to the Beaumont Refinery, the Joliet Refinery, and/or the 

Torrance Refinery, the term “ExxonMobil” shall mean ExxonMobil Oil Corporation and its 

successors and assigns. For matters relating to all of the Covered Refineries or to general rights 

and obligations under this Consent Decree, the term “ExxonMobil” shall mean both Exxon 

Mobil Corporation and ExxonMobil Oil Corporation, and their successors and assigns. 

12
q. “FCCU” shall mean a fluidized catalytic cracking unit, its regenerator and 

associated CO boiler(s) and CO furnace(s) where present. 

r. “Flaring Device” shall mean an AG Flaring Device and/or an HC Flaring 

Device. 

s. “Flaring Incident” shall mean an AG Flaring Incident, a Tail Gas Incident, 

and/or an HC Flaring Incident. 

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

than 0.05% by weight. 

u. “Full Burn Operation,” when used with respect to the Billings Refinery 

FCCU, shall mean when essentially all of the CO produced in the FCCU regenerator is 

converted to CO2 inside the regenerator and there is O2 (greater than 0.5% by volume as 

measured on a daily basis) present in the regenerator flue gas. 

v. “Hydrocarbon Flaring” or “HC Flaring” shall mean the combustion of 

refinery-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. 

w. “Hydrocarbon Flaring Device” or “HC Flaring Device” shall mean the 

devices listed in Appendix F that are used by the Covered Refineries to control (through 

combustion) any excess volume of a refinery-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 F for the purpose of combusting any excess of a 

refinery-generated gas other than Acid Gas and/or Sour Water Stripper Gas, those Flaring 

13
Devices shall be HC Flaring Devices and shall be subject to the provisions of this Consent 

Decree. 

x. “Hydrocarbon Flaring Incident” or “HC Flaring Incident” shall mean the 

continuous or intermittent flaring of refinery-generated gases, except for Acid Gas or Sour Water 

Stripper Gas or Tail Gas, in a Hydrocarbon Flaring Device that results in the emission of sulfur 

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

continuous or intermittent 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 

twenty-four (24) hour period(s), then only one HC Flaring Incident shall have occurred. 

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

initial commencement of flaring within the HC Flaring Incident. 

y. “IEPA” shall mean the Illinois Environmental Protection Agency and any 

successor department or agency of the State of Illinois. 

z. “LDEQ” shall mean the Louisiana Department of Environmental Quality 

and any successor departments or agencies of the State of Louisiana. 

aa. “Low NOx Combustion Promoter” shall mean a catalyst that is added to a 

FCCU that minimizes NOx emissions while maintaining its effectiveness as a combustion 

promoter. 

ab. “Malfunction,” as specified by 40 C.F.R. § 60.2, shall mean: “[A]ny 

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.” 

14
ac. “MDEQ” shall mean the Montana Department of Environmental Quality 

and any successor department or agency of the State of Montana. 

ad. “Natural Gas Curtailment” shall mean a restriction imposed by a natural 

gas supplier, which limits ExxonMobil’s ability to obtain natural gas. 

ae. “Next Generation Ultra-Low NOx Burners” or “Next Generation ULNBs” 

shall mean those burners that are designed to achieve a NOx emission rate of less than or equal 

to 0.020 lb/ mmBTU HHV when firing natural gas at 3% stack oxygen at full design load 

without air preheat, regardless of whether upon installation actual emissions exceed 0.020 

lb/mmBTU HHV. 

af. “NOx” shall mean nitrogen oxides. 

ag. “NOx Additives” shall mean Low NOx Combustion Promoters and NOx 

Reducing Catalyst Additives. 

ah. “NOx Reducing Catalyst Additive” shall mean a catalyst additive that is 

introduced to an FCCU to reduce NOx emissions through reduction or controlled oxidation of 

intermediates. 

ai. “NSPS Flaring Device” shall mean a Flaring Device listed in Appendix G. 

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

arabic numeral. 

ak. “PM” shall mean particulate matter. 

al. “Parties” shall mean the United States, the Co-Plaintiffs, and ExxonMobil. 

am. “Root Cause” shall mean the primary cause(s) of AG Flaring Incident(s), 

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

investigation. 

15
an. “Sour Water Stripper Gas” or “SWS Gas” shall mean the gas produced by 

the process of stripping or scrubbing refinery sour water. 

ao. “SO2 Reducing Catalyst Additive” shall mean a catalyst additive that is 

introduced to an FCCU to reduce SO2 emissions by reduction and adsorption. 

ap. “SO2” shall mean sulfur dioxide. 

aq. “Sulfur Recovery Plant” or “SRP” shall mean a process unit that recovers 

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

sulfide. For the purposes of this Consent Decree, the SRPs at the refineries identified below 

shall be defined as follows: 

(1) Baytown SRP: The SRP at the Baytown Refinery (the “Baytown SRP”) consists 

of four Claus trains: Claus A, Claus B, Claus C, and Claus D. 

(2) Beaumont SRP: The SRP at the Beaumont Refinery (the “Beaumont SRP”) 

consists of three Claus trains: Claus 1, Claus 2, Claus 3. 

(3) Joliet SRP: The SRP at the Joliet refinery (the “Joliet SRP”) consists of three 

Claus trains: North Train, East Train, and West Train. 

(4) Torrance SRP: The SRP at the Torrance Refinery (the “Torrance SRP”) consists 

of two trains: Train A and Train B. 

ar. “Tail Gas” or “TG” shall mean exhaust gas from the Claus trains and/or 

the tail gas cleanup unit (“TGU”) section of the SRP. 

as. “Tail Gas Unit” or “TGU” shall mean a control system utilizing a 

technology for reducing emissions of sulfur compounds from a Claus Sulfur Recovery Plant. 

at. “Tail Gas Incident” shall mean combustion of Tail Gas that either is: 

(1) combusted in a flare and results in 500 pounds or more of SO2 emissions in any 

24 hour period ; or 

(2) combusted in a thermal incinerator and results in excess emissions of 500 pounds 

or more of SO2 in any 24-hour period. Only those time periods which are in 

16
excess of a SO2 concentration of 250 ppm (rolling 12-hour average) shall be used 

to determine the amount of excess SO2 emissions from the incinerator. 

ExxonMobil shall use engineering judgment and/or other monitoring data to estimate emissions 

during periods in which the SO2 continuous emission analyzer has exceeded the range of the 

instrument or is out of service. 

au. “Total Catalyst Addition Rate” shall mean the amount as an average 

(in pounds per day as received) of all forms of catalyst added to an FCCU during the two year 

baseline period from November 2001 to October 2003 (which amount was 3,607 pounds per day 

as received) including, but not limited to, base catalyst, equilibrium catalyst, and pollutant 

reducing catalyst. 

av. “Upstream Process Units” shall mean all amine contactors, amine 

scrubbers, and sour water strippers at a Covered Refinery, 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. 

V. AFFIRMATIVE RELIEF 

A. FLUID CATALYTIC CRACKING UNITS. 

11. Description of FCCUs. ExxonMobil owns and/or operates the FCCUs identified 

below at the Covered Refineries. 

a. Baton Rouge FCCUs: The Baton Rouge Refinery has two FCCUs, 

designated PCLA 2 and PCLA 3 (collectively the “Baton Rouge FCCUs”). A single Wet Gas 

Scrubber (“WGS”) that commenced operation in 1976 serves as an SO2 and PM control device 

for the Baton Rouge FCCUs. 

17
b. Baytown FCCU 2 and Baytown FCCU 3: The Baytown Refinery has two 

FCCUs, designated FCCU 2 and FCCU 3. A WGS that commenced operation in 1974 serves as 

an SO2 and PM control device for FCCU 2, and a WGS that commenced operation in 1975 

serves as an SO2 and PM control device for FCCU 3. A high-pressure hydrotreater also exists 

which lowers the sulfur in a portion of the FCCU feed. 

c. Beaumont FCCU: The Beaumont Refinery has one FCCU. A WGS that 

commenced operation in 2004 serves as an SO2 and PM control device for the FCCU. The 

Beaumont FCCU also has third-stage cyclones. 

d. Billings FCCU: The Billings Refinery has one FCCU. 

e. Joliet FCCU: The Joliet Refinery has one FCCU. The Joliet FCCU also 

has third-stage cyclones. 

f. Torrance FCCU: The Torrance Refinery has one FCCU. A selective 

catalytic reduction (“SCR”) system installed in 2000 serves as a NOx control device for the 

FCCU. An electrostatic precipitator that commenced operation in 1972 and was upgraded in 

1985 serves as a PM control device for the FCCU. A high-pressure hydrotreater also exists 

which lowers the sulfur in a portion of the FCCU feed. 

B. NOx EMISSIONS REDUCTIONS FROM THE FCCUs. 

12. General. ExxonMobil shall implement a program to reduce NOx emissions from 

the FCCUs at the refineries listed in Subsection V.A, as specified below. Pursuant to Subsection 

V.Q of this Consent Decree, ExxonMobil shall apply for federally-enforceable permits that 

incorporate the lower NOx emission limits established by this Subsection. ExxonMobil will 

monitor compliance with the emission limits through the use of CEMS, as specified by this 

Subsection V.B. 

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13. NOx Emissions Control for the Baton Rouge FCCUs. 

a. NOx Control System. By no later than the Entry Date, ExxonMobil shall 

control NOx emissions from the Baton Rouge FCCUs. ExxonMobil presently intends to control 

NOx emissions from the Baton Rouge FCCUs by: (i) operating a Thermal DeNOx system; and 

(ii) shifting the FCCUs to a lower CO operation mode. ExxonMobil has used best efforts to 

design the NOx control system to attain, under optimum conditions, 50 ppmvd NOx or less (at 

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

rolling average basis). Nothing in this Subparagraph 13.a shall be deemed to limit 

ExxonMobil’s ability to implement or use additional NOx reducing measures. 

b. Final NOx Limits. 

(1) The long-term Final NOx Limit for the Baton Rouge FCCUs shall 

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

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

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

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

15.c. 

(2) The short-term Final NOx Limit for the Baton Rouge FCCUs shall 

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

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

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

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

15.c. 

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14. NOx Emissions Control for the Beaumont FCCU. 

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

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

NOx emissions from the Beaumont FCCU by: (i) installing and operating a Thermal DeNOx 

system; (ii) installing and operating CO boiler low-NOx burners; and/or (iii) shifting the FCCU 

to a lower CO operation mode. ExxonMobil shall use best efforts to design the NOx control 

system to attain 50 ppmvd NOx or less (at 0% O2 on a 365-day rolling average basis) and 

100 ppmvd NOx or less (at 0% O2 on a 7-day rolling average basis); provided, however, that 

ExxonMobil shall not be required to design the control system in a manner that creates a safety 

problem or impairs unit feed rate, conversion, feed slate or yield selectivity. Nothing in this 

Subparagraph 14.a shall be deemed to limit ExxonMobil’s ability to implement or use additional 

NOx reducing measures. 

b. Final NOx Limits. 

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

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

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

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

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

15.c. 

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

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

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

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

20
NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 

15.c. 

15. Baton Rouge and Beaumont NOx Minimization Studies. ExxonMobil shall 

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

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

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

Minimization Study”). 

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

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

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

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

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

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

compensate for such impairment. 

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

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

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

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

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

evaluate the Study. 

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

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

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

21
practicable to 50 ppmvd NOx (at 0% O2 on a 365-day rolling average basis) and 100 ppmvd 

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

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

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

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

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

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

supplemental NOx emission reductions from Combustion Units at the relevant refinery, in 

accordance with the following table: 

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

50 ppmvd 100 ppmvd 0 TPY NOx 

51 ppmvd 101-102 ppmvd 12 TPY NOx 

52 ppmvd 103-104 ppmvd 26 TPY NOx 

53 ppmvd 105-106 ppmvd 42 TPY NOx 

54 ppmvd 107-108 ppmvd 60 TPY NOx 

55 ppmvd 109-110 ppmvd 80 TPY NOx 

56 ppmvd 111-112 ppmvd 102 TPY NOx 

57 ppmvd 113-114 ppmvd 126 TPY NOx 

58 ppmvd 115-116 ppmvd 152 TPY NOx 

59 ppmvd 117-118 ppmvd 180 TPY NOx 

60 ppmvd 119-120 ppmvd 210 TPY NOx 

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

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

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

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

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

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

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

22
documenting the reductions. The schedule shall be subject to EPA approval, which shall not be 

unreasonably withheld. 

16. NOx Emissions Control for the Baytown FCCUs. 

a. NOx Control Systems. 

(1) ExxonMobil presently intends to control NOx emissions from 

Baytown FCCU 2 by: (i) continuing to operate the FCCU in full burn mode; and 

(ii) taking other steps to reduce NOx (which may include, but are not limited to, use of a 

Thermal DeNOx system and/or use of NOx-reducing catalyst additive and/or low NOx 

combustion promoter). 

(2) ExxonMobil presently intends to control NOx emissions from 

Baytown FCCU 3 by installing and operating a scrubber-based NOx emission reduction 

technology. 

b. Interim NOx Limits. 

(1) By no later than December 31, 2006, ExxonMobil shall specify 

and comply with separate long-term and short-term interim NOx emission limits for 

Baytown FCCU 2 and Baytown FCCU 3. Those Interim NOx Limits shall apply until 

Final NOx Limits are established under Subparagraph 16.c. The weighted average of the 

two sets of unit-specific interim limits shall not exceed: 

Long-term limit: 65 ppmvd NOx on a 365-day rolling average basis at 0% O2 

Short-term limit: 95 ppmvd NOx on a 7-day rolling average basis at 0% O2 

In computing the average, the individual limits will be weighted based on each unit’s flue 

gas flow rate. In addition, the unit-specific interim limits shall not exceed: 

Long-term limit: 70 ppmvd NOx on a 365-day rolling average basis at 0% O2 

23
Short-term limit: 105 ppmvd NOx on a 7-day rolling average basis at 0% O2 

(2) In the Semi-Annual Report due on February 28, 2007 under 

Section IX, ExxonMobil shall specify the Interim NOx limits applicable to Baytown 

FCCU 2 and Baytown FCCU 3, which shall be consistent with the limitations imposed by 

Subparagraph 16.b.(1). 

c. Final NOx Limits. 

(1) By no later than June 30, 2010, ExxonMobil shall specify and 

comply with separate long-term and short-term final NOx emission limits for Baytown 

FCCU 2 and Baytown FCCU 3. The weighted average of the two sets of unit-specific 

final limits shall not exceed: 

Long-term limit: 35 ppmvd NOx on a 365-day rolling average basis at 0% O2 

Short-term limit: 70 ppmvd NOx on a 7-day rolling average basis at 0% O2 

In computing the average, the individual limits will be weighted based on each unit’s flue 

gas flow rate. In addition, the unit-specific final limits shall not exceed: 

Long-term limit: 45 ppmvd NOx on a 365-day rolling average basis at 0% O2 

Short-term limit: 90 ppmvd NOx on a 7-day rolling average basis at 0% O2 

(2) In the Semi-Annual Report due on August 31, 2010 under Section 

IX, ExxonMobil shall specify the Final NOx limits applicable to Baytown FCCU 2 and 

Baytown FCCU 3, which shall be consistent with the limitations imposed by 

Subparagraph 16.c.(1). 

17. NOx Emissions Control for the Billings FCCU. 

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

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

24
(ii) taking other steps to reduce NOx (which may include, but are not limited to, use of a 

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

additive and/or low NOx combustion promoter). 

b. Final NOx Limits. By no later than December 31, 2008, ExxonMobil 

shall comply with NOx emission limits of 40 ppmvd at 0% O2 on a 365-day rolling average basis 

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

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

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

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

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

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

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

basis at the Billings FCCU. 

18. NOx Emissions Control for the Joliet FCCU. 

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

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

b. Final NOx Limits. By no later than December 31, 2012, ExxonMobil 

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

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

19. NOx Emissions Control for the Torrance FCCU. 

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

from the Torrance FCCU by operating its existing SCR system for the FCCU. 

25
b. Final NOx Limits. By no later than the Entry Date, ExxonMobil shall 

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

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

c. Non-Routine Operations. For any period, not to exceed fourteen (14) days 

per occurrence, when the Torrance SCR is not operating because waste heat boiler 2F-7 is shut 

down for an internal boiler inspection required by Cal. Code Regs. Tit. 8, Section 770(b), NOx 

emissions from the Torrance FCCU will not be used in determining compliance with the shortterm (7-day) Final NOx Limit established pursuant to Subparagraph 19.b. During any such 

period when waste heat boiler 2F-7 is shut down, ExxonMobil shall comply with a short-term 

NOx emission limit of 140 ppmvd at 0% O2 on 24-hour rolling average basis at the Torrance 

FCCU. Emissions during any such period shall either be: (i) monitored with CEMS as provided 

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

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

during the particular period. In the first Semi-Annual Report that is due under Section IX after 

any such period, ExxonMobil shall identify the period during which waste heat boiler 2F-7 was 

shut down and shall describe why an internal boiler inspection was required by Cal. Code Regs. 

Tit. 8, Section 770(b). 

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

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

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

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

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

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

26
to minimize NOx emissions. Nothing in this Paragraph shall be construed to relieve 

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

report emissions during periods of startup, shutdown, or Malfunction, or to document the 

occurrence and/or cause of a startup, shutdown, or Malfunction event. Emissions during any 

such period of startup, shutdown, or Malfunction shall either be: (i) monitored with CEMS as 

provided by Paragraph 21; or (ii) monitored in accordance with an alternative monitoring plan 

approved by EPA pursuant to this Consent Decree if it is necessary to bypass the FCCU’s main 

stack during the particular period of startup, shutdown, or Malfunction. 

21. Demonstrating Compliance with FCCU NOx Emission Limits for the 

FCCUs. By no later than the dates set out in Appendix N, ExxonMobil shall use NOx and O2 

CEMS at each of the FCCUs at the refineries listed in Subsection V.A to monitor performance 

and to report compliance with the terms and conditions of this Subsection V.B relating to NOx 

emissions from the FCCUs. As permitted by Subparagraph 19.c and Paragraph 20, emissions 

during certain periods may be monitored in accordance with an alternative monitoring plan 

approved by EPA. ExxonMobil shall make emissions monitoring data available to EPA as soon 

as practicable following an EPA request for such data. 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 performance specification test of 40 C.F.R. Part 60 Appendix B. For the Baton Rouge 

FCCUs, the Baytown FCCUs, the Beaumont FCCU, and the Torrance FCCU, unless Appendix F 

is otherwise required by the NSPS, state law or regulation, or a permit or approval, in lieu of the 

requirements of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil may 

conduct: (1) either a Relative Accuracy Audit (“RAA”) or a Relative Accuracy Test Audit 

(“RATA”) once every three (3) years; and (2) a Cylinder Gas Audit (“CGA”) each calendar 

27
quarter in which a RAA or RATA is not performed. The Parties agree that the CEMS may need 

to be moved and reinstalled because of the installation of control equipment, and that once 

moved it will need to be re-calibrated and re-certified. 

C. SO2 EMISSIONS REDUCTIONS FROM THE FCCUs. 

22. General. ExxonMobil shall implement a program to reduce SO2 emissions from 

the FCCUs at the refineries listed in Subsection V.A, as specified below. Pursuant to Subsection 

V.Q of this Consent Decree, ExxonMobil shall apply for federally-enforceable permits that 

incorporate the lower SO2 emission limits established by this Subsection. ExxonMobil will 

monitor compliance with the emission limits through the use of CEMS, as specified by this 

Subsection V.C. 

23. SO2 Emissions Control for Baytown FCCU 2. 

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

emissions from Baytown FCCU 2 by upgrading and operating its existing WGS. 

b. Final SO2 Limits. By no later than December 31, 2009, ExxonMobil shall 

comply with SO2 emission limits of 25 ppmvd at 0% O2 on a 365-day rolling average basis and 

50 ppmvd at 0% O2 on a 7-day rolling average basis at Baytown FCCU 2. 

24. SO2 Emissions Control for Baytown FCCU 3. 

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

emissions from Baytown FCCU 3 by operating its existing WGS. 

b. Final SO2 Limits. By no later than the Entry Date, ExxonMobil shall 

comply with SO2 emission limits of 25 ppmvd at 0% O2 on a 365-day rolling average basis and 

50 ppmvd at 0% O2 on a 7-day rolling average basis at Baytown FCCU 3. 

28
25. SO2 Emissions Control for the Baton Rouge FCCUs. 

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

emissions from the Baton Rouge FCCUs by: (i) operating its existing WGS; and (ii) taking other 

steps to reduce SO2 (which may include, but are not limited to, use of SO2 Reducing Catalyst 

Additive) during planned routine maintenance on the Baton Rouge WGS. 

b. Final SO2 Limits. By no later than the January 1, 2006, ExxonMobil shall 

comply with SO2 emission limits of 35 ppmvd at 0% O2 on a 365-day rolling average basis and 

70 ppmvd at 0% O2 on a 7-day rolling average basis at the Baton Rouge FCCUs. 

26. SO2 Emissions Control for the Beaumont FCCU. 

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

emissions from the Beaumont FCCU by operating its existing WGS. 

b. Final SO2 Limits. By no later than the Entry Date, ExxonMobil shall 

comply with SO2 emission limits of 25 ppmvd at 0% O2 on a 365-day rolling average basis and 

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

27. SO2 Emissions Control for the Joliet FCCU. 

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

emissions from the Joliet FCCU by installing and operating a WGS. 

b. Final SO2 Limits. By no later than December 31, 2008, ExxonMobil shall 

comply with SO2 emission limits of 25 ppmvd at 0% O2 on a 365-day rolling average basis and 

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

28. SO2 Emissions Control for the Torrance FCCU. 

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

emissions from the Torrance FCCU by using low sulfur feed in the FCCU. 

29
b. Final SO2 Limits. By no later than the Entry Date, ExxonMobil shall 

comply with SO2 emission limits of 25 ppmvd at 0% O2 on a 365-day rolling average basis and 

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

29. SO2 Emissions Control for the Billings FCCU. 

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

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

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

summarized below. 

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

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

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

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

shall use that additive at the Required Addition Rate whenever the unit is operated, until 

Step 2 of the protocol. 

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

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

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

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

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

defined demonstration period. 

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

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

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

30
for a particular SO2 Reducing Catalyst Additive based on a demonstration by 

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

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

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

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

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

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

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

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

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

impairment. 

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

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

“Option B” below. 

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

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

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

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

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

Subparagraph 30.i. 

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

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

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

31
365-day rolling average and 50 ppmvd on a 7-day rolling average basis, both at 0% 

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

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

Decree. 

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

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

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

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

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

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

a. Conversion of Billings FCCU to Full Burn Operation. By no later than 

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

Operation. 

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

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

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

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

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

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

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

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

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

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

32
No later than 255 Days after the Entry Date for the Step 1 trials of currentgeneration SO2 Reducing Catalyst 

Additives 

No later than January 15, 2010 for the Step 2 trials of futuregeneration SO2 Reducing Catalyst 

Additives 

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

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

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

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

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

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

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

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

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

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

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

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

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

ExxonMobil. 

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

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

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

in accordance with the following schedule: 

33
For the Step 1 trials of current-generation SO2 Reducing Catalyst Additives: 

Commencement Date No later than 300 days after the Entry Date 

Completion Date No later than 480 days after the Entry Date 

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

Commencement Date No later than March 1, 2010 

Completion Date No later than October 1, 2010 

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

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

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

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

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

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

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

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

for such impairments. 

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

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

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

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

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

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

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

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

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

34
(3) ExxonMobil shall submit the Trials Reports in accordance with the 

following schedule: 

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

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

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

Report Due Date No later than December 1, 2010 

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

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

at the Required Addition Rate; provided, however, that ExxonMobil shall not be required to 

operate the FCCU or use the Additive in a manner that creates a safety problem or impairs unit 

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

eliminate the problem or compensate for such impairment. ExxonMobil shall continue using the 

Best-Performing Additive at the Required Addition Rate until commencement of the Step 2 trials 

under Subparagraph 30.d. 

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

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

schedule: 

Commencement Date No later than January 15, 2011 

Completion Date No later than January 15, 2012 

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

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

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

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

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

35
problem or compensate for such impairment. Even after completion of the demonstration, 

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

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

Subparagraphs 30.h and 30.i. 

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

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

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

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

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

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

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

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

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

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

Subparagraph 30.i. 

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

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

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

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

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

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

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

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

36
scenarios. EPA will determine the limits based on: (i) the level of performance during the Step 

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

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

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

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

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

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

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

ExxonMobil shall use Additive in the manner and amount applicable during the Step 2 

Demonstration Period (in lieu of meeting the EPA-established limits). 

31. Startup, Shutdown, and Malfunction. SO2 emissions (i) caused by or 

attributable to the startup or shutdown of an FCCU that is not controlled by a WGS and/or 

(ii) during periods of Malfunction of the FCCU or Malfunction of the relevant FCCU’s WGS or 

SO2 Reducing Catalyst Additive system will not be used in determining compliance with the 

short-term (7-day) SO2 emission limits established pursuant to Subparagraphs 23.b, 24.b, 25.b, 

26.b, 27.b, 28.b, and 29.b, provided that during such periods ExxonMobil implements good air 

pollution control practices to minimize SO2 emissions. Nothing in this Paragraph shall be 

construed to relieve ExxonMobil of any obligation under any federal, state, or local law, 

regulation, or permit to report emissions during periods of startup, shutdown, or Malfunction, or 

to document the occurrence and/or cause of a startup, shutdown, or Malfunction event. 

Emissions during any such period of startup, shutdown, or Malfunction shall either be: 

(i) monitored with CEMS as provided by Paragraph 32; or (ii) monitored in accordance with an 

37
Alternative Monitoring Plan approved by EPA if it is necessary to bypass the FCCU’s main 

stack during the particular period of startup, shutdown, or Malfunction. 

32. Demonstrating Compliance with FCCU SO2 Emission Limits for the FCCUs. 

By no later than the dates set out in Appendix N, ExxonMobil shall use SO2 and O2 CEMS at 

each of the FCCUs at the refineries listed in Subsection V.A to monitor performance and to 

report compliance with the terms and conditions of this Subsection V.C relating to SO2 

emissions from the FCCUs. As permitted by Paragraph 31, emissions during certain periods 

may be monitored in accordance with an Alternative Monitoring Plan approved by EPA. 

ExxonMobil shall make emissions monitoring data available to EPA as soon as practicable 

following an EPA request for such data. For the Baton Rouge FCCUs, the Baytown FCCUs, the 

Beaumont FCCU, and the Torrance FCCU, unless compliance 40 C.F.R. Part 60, Appendix F is 

otherwise required by the NSPS, state law or regulation, or a permit or approval, in lieu of the 

requirements of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil may 

conduct: (1) either a Relative Accuracy Audit (“RAA”) or a Relative Accuracy Test 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 performed. The Parties agree that the CEMS may need 

to be moved and reinstalled because of the installation of control equipment, and that once 

moved it will need to be re-calibrated and re-certified. 

38
D. PARTICULATE MATTER EMISSIONS REDUCTIONS FROM THE 

FCCUs. 

33. General. ExxonMobil shall implement a program to reduce PM emissions from 

the FCCUs at the refineries listed in Subsection V.A, as specified below. Pursuant to Subsection 

V.Q of this Consent Decree, ExxonMobil shall apply for federally-enforceable permits that 

incorporate the lower PM emission limits established by this Subsection. ExxonMobil will 

monitor compliance with the emission limits as specified by this Subsection V.D. 

34. Emission Limits for PM. 

a. Consistent with the NSPS regulations at 40 C.F.R., Part 60, Subpart J, 

ExxonMobil shall comply with an emission limit of 1.0 pounds of PM per 1000 pounds of coke 

burned for the FCCUs listed below by the dates listed below: 

FCCU PM Emission Limit Compliance Date 

Baytown FCCU 2 December 31, 2009 

Baytown FCCU 3 Consent Decree Entry Date 

Beaumont FCCU Consent Decree Entry Date 

Joliet FCCU Consent Decree Entry Date 

Torrance FCCU Consent Decree Entry Date 

b. By no later than December 31, 2006, ExxonMobil shall: (i) install and 

commence operation of new third-stage cyclones on the Billings FCCU; and, thereafter 

(ii) complete a performance test to assess PM emissions from the Billings FCCU under “turn 

down” conditions based on the average of three runs in a test performed in accordance with 

Method 5B or 5F. If PM emissions during that performance test are less than 1.0 pound of PM 

per 1000 pounds of coke burned, then the Billings FCCU shall comply with an emission limit of 

1.0 pounds of PM per 1000 pounds of coke burned as of December 31, 2006, consistent with the 

NSPS regulations at 40 C.F.R., Part 60, Subpart J. If PM emissions during that performance test 

are greater than or equal to 1.0 pound of PM per 1000 pounds of coke burned, then ExxonMobil 

39
shall take additional steps to reduce PM emissions from the Billings FCCU and shall comply 

with an emission limit of 1.0 pounds of PM per 1000 pounds of coke burned as of December 31, 

2008, consistent with the NSPS regulations at 40 C.F.R., Part 60, Subpart J. By no later than 

December 31, 2006, ExxonMobil shall provide EPA and the Applicable Co-Plaintiff a written 

report that summarizes the results of the performance test and either: (i) indicates that 

ExxonMobil will comply with the emission limit by December 31, 2006 under this Paragraph; or 

(ii) indicates that ExxonMobil will comply with the emission limit by December 31, 2008 and 

summarizes the additional steps that ExxonMobil intends to take to comply with the emission 

limit under this Paragraph. 

35. NSR Emission Limits for PM. At any time during the term of the Consent 

Decree, ExxonMobil may accept a Final PM Limit of 0.5 pounds of PM per 1000 pounds of coke 

burned based on the average of three runs in a test performed in accordance with Method 5B or 

5F. Upon accepting such limit: (i) ExxonMobil’s liability for certain potential NSR violations 

for PM emissions from the relevant FCCU shall be resolved pursuant to Paragraph 238 of this 

Consent Decree; and (ii) ExxonMobil, in accordance with Paragraph 142, shall apply for a 

federally-enforceable permit that shall incorporate this Final PM Limit. 

36. Startup, Shutdown, and Malfunction. PM emissions (i) caused by or 

attributable to the startup or shutdown of an FCCU that is not controlled by a WGS and/or 

(ii) during periods of Malfunction of the FCCU or Malfunction of the relevant FCCU’s WGS, 

third-stage cyclones or electrostatic precipitator will not be used in determining compliance with 

any PM emission limits established by Paragraphs 34 and 35, provided that during such periods 

ExxonMobil implements good air pollution control practices to minimize PM emissions. 

Nothing in this Paragraph shall be construed to relieve ExxonMobil of any obligation under any 

40
federal, state, or local law, regulation, or permit to report emissions during periods of startup, 

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

Malfunction event. 

37. PM Testing. ExxonMobil shall follow the test protocol specified in 40 C.F.R. 

§ 60.106(b)(2) using EPA Reference Method 5B or 5F to measure PM emissions from each of 

the FCCUs identified in Paragraph 34. ExxonMobil shall propose and submit the test protocol to 

EPA for approval, with a copy to the Applicable Co-Plaintiff, by no later than three (3) months 

after a PM limit becomes effective. ExxonMobil shall conduct the first test no later than three 

(3) months after EPA approves the test protocol. ExxonMobil shall conduct annual PM tests on 

each of the FCCUs identified in Paragraph 34 and shall submit the results in the first 

Semi-Annual Report due under Section IX that is at least three (3) months after the test. Upon 

demonstrating through at least three (3) annual tests that the PM limits are not being exceeded at 

a particular FCCU, ExxonMobil may request EPA approval to conduct tests less frequently than 

annually. Such approval will not be unreasonably withheld. Nothing in this Consent Decree 

shall limit the authority of EPA or an Applicable Co-Plaintiff to require additional tests under 

any statutory or regulatory provision or under any permit. 

E. CARBON MONOXIDE EMISSIONS REDUCTIONS FROM THE FCCUs. 

38. General. ExxonMobil shall implement a program to reduce CO emissions from 

the FCCUs at the refineries listed in Subsection V.A, as specified below. Pursuant to Subsection 

V.Q of this Consent Decree, ExxonMobil shall apply for federally-enforceable permits that 

incorporate the lower CO emission limits. ExxonMobil will monitor compliance with the 

emission limits with CEMS, as specified by this Subsection V.E. 

41
39. Emission Limits for CO. Consistent with the NSPS regulations at 40 C.F.R., 

Part 60, Subpart J, ExxonMobil shall comply with an emission limit of 500 ppmvd CO corrected 

to 0% O2 on a 1-hour average basis for the FCCUs listed below by the dates listed below: 

FCCU CO Emission Limit Compliance Date 

Baytown FCCU 2 Consent Decree Entry Date 

Baytown FCCU 3 Consent Decree Entry Date 

Beaumont FCCU Consent Decree Entry Date 

Billings FCCU Consent Decree Entry Date 

Joliet FCCU Consent Decree Entry Date 

Torrance FCCU Consent Decree Entry Date 

40. NSR Emission Limits for CO. At any time during the term of the Consent 

Decree, ExxonMobil may accept the following Final CO Limits for a FCCU: 

Long-term limit: 150 ppmvd CO on a 365-day rolling average basis at 0% O2 

Short-term limit: 250 ppmvd CO on a 24-hour rolling average basis at 0% O2 

Upon accepting such Final CO Limits for a FCCU: (i) ExxonMobil’s liability for certain

potential NSR violations for CO emissions from the relevant FCCU shall be resolved pursuant to

Paragraph 239 of this Consent Decree; and (ii) ExxonMobil shall, in accordance with

Paragraph 142, apply for a federally-enforceable permit that incorporates such limits.

41. Startup, Shutdown, and Malfunction. CO emissions (i) caused by or 

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

(ii) during periods of Malfunction of the relevant FCCU’s CO control system will not be used in 

determining compliance with any short-term (i.e., 1-hour and/or 24-hour) CO emission limit 

established pursuant to Paragraph 39 or 40, provided that during such periods ExxonMobil 

implements good air pollution control practices to minimize CO emissions. Nothing in this 

Paragraph shall be construed to relieve ExxonMobil of any obligation under any federal, state, or 

local law, regulation, or permit to report emissions during periods of startup, shutdown, or 

42
Malfunction, or to document the occurrence and/or cause of a startup, shutdown, or Malfunction 

event. Emissions during any such period of startup, shutdown, or Malfunction shall either be: 

(i) monitored with CEMS as provided by Paragraph 42; or (ii) monitored in accordance with an 

Alternative Monitoring Plan approved by EPA if it is necessary to bypass the FCCU’s main 

stack during the particular period of startup, shutdown, or Malfunction. 

42. Demonstrating Compliance with CO Emissions Limits. By no later than the 

dates set out in Appendix N, ExxonMobil shall use CO and O2 CEMS at each of the FCCUs at 

the refineries listed in Paragraph 39 to monitor emissions and to report compliance with the 

terms and conditions of this Subsection V.E relating to CO emissions from the FCCUs. As 

permitted by Paragraph 41, emissions during certain periods may be monitored in accordance 

with an Alternative Monitoring Plan approved by EPA. ExxonMobil shall make emissions 

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

For the Baton Rouge FCCUs, the Baytown FCCUs, the Beaumont FCCU, the Billings FCCU, 

and the Torrance FCCU, unless compliance with 40 C.F.R. Part 60, Appendix F is otherwise 

required by the NSPS, state law or regulation, or a permit or approval, in lieu of the requirements 

of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil may conduct: (1) either 

a Relative Accuracy Audit (“RAA”) or a Relative Accuracy Test 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 performed. The Parties agree that the CEMS may need to be moved and reinstalled 

because of the installation of control equipment, and that once moved it will need to be recalibrated and re-certified. 

43
F. NSPS APPLICABILITY TO THE FCCU CATALYST REGENERATORS. 

43. NSPS Applicability and Compliance. Each of the FCCU catalyst regenerators 

for the FCCUs at the refineries listed in Subsection V.A shall be an “affected facility,” as that 

term is used in 40 C.F.R. Part 60, Subparts A and J, with respect to the pollutants specified for 

such FCCU catalyst regenerators in the following Subparagraphs, and shall be subject to all of 

the applicable requirements of NSPS Subparts A and J, by the dates set forth below. 

a. Sulfur Oxides. ExxonMobil shall comply with the requirements of NSPS 

Subparts A and J for the following FCCU catalyst regenerators for SO2 by the following dates: 

FCCU 

Baton Rouge PCLA 2 

Baton Rouge PCLA 3 

Baytown FCCU 2 

Baytown FCCU 3 

Beaumont FCCU 

Joliet FCCU 

Torrance FCCU 

NSPS Effective Date for SO2

January 1, 2006

January 1, 2006

December 31, 2006

Consent Decree Entry Date

Consent Decree Entry Date

December 31, 2008

Consent Decree Entry Date

b. Particulate Matter. 

(1) ExxonMobil shall comply with the requirements of NSPS Subparts 

A and J for the following FCCU catalyst regenerators for PM by the following dates: 

FCCU 

Baytown FCCU 2 

Baytown FCCU 3 

Beaumont FCCU 

Joliet FCCU 

Torrance FCCU 

NSPS Effective Date for PM 

December 31, 2009 

Consent Decree Entry Date 

Consent Decree Entry Date 

Consent Decree Entry Date 

Consent Decree Entry Date 

(2) ExxonMobil shall comply with the requirements of NSPS Subparts 

A and J for the Billings FCCU catalyst regenerator for PM: (i) by no later than 

December 31, 2006, if the results of performance tests conducted pursuant to 

Subparagraph 34.b are such that compliance with an emission limit of 1.0 pounds PM per 

44
1000 pounds of coke burned is required by that date; or (ii) by no later than December 

31, 2008, if the results of performance tests conducted pursuant to Subparagraph 34.b are 

such that compliance with an emission limit of 1.0 pounds PM per 1000 pounds of coke 

burned is required by that date. 

c. Carbon Monoxide. ExxonMobil shall comply with the requirements of 

NSPS Subparts A and J for the following FCCU catalyst regenerators for CO by the following 

dates: 

FCCU 

Baytown FCCU 2 

Baytown FCCU 3 

Beaumont FCCU 

Billings FCCU 

Joliet FCCU 

Torrance FCCU 

NSPS Effective Date for CO 

Consent Decree Entry Date

Consent Decree Entry Date

Consent Decree Entry Date

18 months after Consent Decree Entry Date

18 months after Consent Decree Entry Date

Consent Decree Entry Date

d. Opacity. ExxonMobil shall comply with the requirements of NSPS 

Subparts A and J for the following FCCU catalyst regenerators for opacity by the following 

dates: 

FCCU 

Baytown FCCU 2 

Baytown FCCU 3 

Beaumont FCCU 

Billings FCCU 

Joliet FCCU 

Torrance FCCU 

NSPS Effective Date for Opacity 

Submit AMP six months after Entry Date

Submit AMP six months after Entry Date

AMP pending

December 31, 2006

Consent Decree Entry Date

Consent Decree Entry Date

Where this Subparagraph specifies an alternative monitoring plan (“AMP”) submittal date 

(rather than a final NSPS Subpart A and J compliance date), ExxonMobil shall submit to EPA a 

timely and complete AMP application by the date(s) specified. Where this Subparagraph 

indicates that an AMP is pending, ExxonMobil has already submitted an AMP application to 

EPA. If an AMP is not approved, ExxonMobil shall submit to EPA for approval a plan for 

45
complying with the monitoring requirements of NSPS Subparts A and J for the particular 

equipment within ninety (90) days of receiving notice of the disapproval. The equipment will 

become an affected facility when ExxonMobil receives EPA’s approval of the relevant AMP. A 

plan for complying with the monitoring requirements of NSPS Subparts A and J may include a 

revised AMP application, physical or operational changes to the equipment, or additional or 

different monitoring. 

e. For all periods of operation, ExxonMobil shall ensure that each FCCU 

catalyst regenerator complies with the applicable emissions limitations imposed by NSPS 

Subpart J, as specified by the preceding Subparagraphs, except during periods of startup, 

shutdown, or Malfunction, as defined by 40 C.F.R. § 60.2. At all times, including periods of 

startup, shutdown, and Malfunction, ExxonMobil shall, to the extent practicable, maintain and 

operate each FCCU catalyst regenerator and any associated air pollution control equipment in a 

manner consistent with good air pollution control practice for minimizing emissions. 

f. For FCCU catalyst regenerators that become affected facilities under 

NSPS Subparts A and J pursuant to this Paragraph 43. Entry of this Consent Decree and 

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

satisfy the notice requirements of 40 C.F.R. 60.7(a) and the initial performance test requirements 

of 40 C.F.R. § 60.8(a). 

44. Particular Requirements Applicable to the Baton Rouge FCCUs. 

a. Compliance with NSPS SO2 Emission Limitations. By no later than 

January 1, 2006, ExxonMobil shall ensure that the Baton Rouge FCCUs’ catalyst regenerators 

comply with the applicable NSPS SO2 emission limitations at all times, except during periods of 

startup, shutdown or Malfunction as defined by 40 C.F.R. § 60.2. Specifically, ExxonMobil 

46
shall: (i) comply with the emission limitation established by 40 C.F.R. 60.104(b)(1), except 

during any period of planned routine maintenance on the Baton Rouge WGS approved in 

accordance with 40 C.F.R. 63.1575(j); and (ii) comply with one of the alternative emission 

limitations established by 40 C.F.R. 60.104(b)(2) or (b)(3) during any period of planned routine 

maintenance on the Baton Rouge WGS approved in accordance with 40 C.F.R. 63.1575(j). 

Compliance with the provisions of this Subparagraph 44.a shall constitute compliance with the 

emission limitations requirements of 40 C.F.R. § 60.104(b). 

b. MACT Standard Compliance. ExxonMobil shall ensure that each of the 

Baton Rouge FCCUs complies with all applicable requirements of the Maximum Achievable 

Control Technology standard for catalytic cracking units, as set forth at 40 C.F.R. Part 63, 

Subparts A and UUU (the “MACT Standard”) including, but not limited to: (i) the emission 

limitations imposed by 40 C.F.R. §§ 63.1564(a) and 63.1565(a); (ii) the requirement to prepare 

and operate at all times in compliance with an operation, maintenance, and monitoring plan 

(an “OMM Plan”), as defined in 40 C.F.R. § 63.1574(f), and a startup, shutdown, and 

malfunction plan (an “SSM Plan”), as defined in 40 C.F.R. § 63.6(e)(3); and (iii) the provisions 

of 40 C.F.R. § 63.1575(j) relating to planned routine maintenance on the Baton Rouge WGS. 

c. OMM Plan Requirements. The OMM Plan(s) for the Baton Rouge 

FCCUs shall include a schedule and procedures for planned routine maintenance on the Baton 

Rouge WGS. The schedule and procedures shall be consistent with good air pollution control 

practices for minimizing emissions to the extent practicable, and shall incorporate the 

requirements specified by the following Subparagraphs. 

(1) The OMM Plan(s) shall establish schedules and procedures for 

minimizing criteria pollutant and hazardous air pollutant emissions associated with 

47
planned routine maintenance on the Baton Rouge WGS, to the extent practicable. The 

OMM Plan shall specifically require that ExxonMobil: (i) minimize the duration of each 

planned routine maintenance period; (ii) maximize WGS run length between planned 

routine maintenance periods; (iii) coordinate planned routine maintenance on the WGS 

with scheduled turnarounds of at least one of the Baton Rouge FCCUs; and (iv) seek and 

obtain the applicable permitting authority’s advance approval of each planned routine 

maintenance period under the requirements imposed by 40 C.F.R. § 63.1575(j). 

(2) The OMM Plan requirements specified by Subparagraph 44.c.(1) 

shall apply only to planned routine maintenance on the Baton Rouge WGS, and shall not 

apply to any unplanned shutdown or malfunction. Among other things, as required by 

Subparagraph 44.b, the SSM Plan for the Baton Rouge FCCUs shall separately address 

periods of unplanned shutdown or malfunction, including ExxonMobil’s duty to operate 

and maintain the affected source (including associated air pollution control equipment 

and monitoring equipment) in a manner consistent with good air pollution control 

practices for minimizing emissions to the extent practicable. 

d. Emissions of NOx and SO2 from the Baton Rouge FCCUs during periods 

of planned routine maintenance on the Baton Rouge WGS shall not be used in determining 

compliance with the short-term NOx and SO2 emission limits established for the Baton Rouge 

FCCUs under Subparagraphs 13.b.(2) and 25.b of this Consent Decree, provided that 

ExxonMobil operates the units in a manner consistent with good air pollution control practices 

during such periods. Emissions during such periods of planned routine maintenance on the 

Baton Rouge WGS shall either be: (i) monitored with CEMS as provided by Paragraphs 21 and 

32; or (ii) monitored in accordance with an Alternative Monitoring Plan approved by EPA. 

48
G. NOx EMISSIONS REDUCTIONS FROM COMBUSTION UNITS. 

45. General. ExxonMobil shall implement a program to reduce NOx emissions from 

Combustion Units identified in Appendix A through the installation of NOx controls or the 

shutdown of certain units and by the acceptance of permit limits on the units controlled to meet 

the requirements of Paragraphs 47 and 51. ExxonMobil will monitor compliance with the 

emission limits through the use of CEMS, a predictive emissions monitoring system (“PEMS”), 

or stack tests as described in more detail below. 

46. Identification of Qualifying Controls. ExxonMobil shall select one or any 

combination of the following “Qualifying Controls” to satisfy the requirements of Paragraphs 47 

and 51: 

i. selective catalytic reduction or selective non-catalytic reduction; 

ii. Current Generation or Next Generation Ultra-Low NOx Burners; 

iii. other technologies which ExxonMobil demonstrates to EPA’s satisfaction should 

reduce NOx emissions to 0.040 pounds of NOx per mmBTU heat input or lower; 

or 

iv. permanent shutdown of a Combustion Unit with surrender of its operating permit; 

provided, however, that to the extent that the emissions reductions resulting from 

the permanent shutdown are used to satisfy the requirements of Paragraphs 47, 

50, and 51, those reductions may not be used as reductions for the construction of 

new units or the modification of existing units permitted collectively as a single 

project with the shutdown, notwithstanding the provisions of 

Subparagraph 150.iv. 

47. Installation of Qualifying Controls. 

a. On or before September 30, 2010, ExxonMobil shall use Qualifying 

Controls to reduce NOx emissions from the Combustion Units listed in Appendix A by at least 

4750 tons per year, so as to satisfy the following inequality: 

49
n 

∑ [(Eactual)i − (Eallowable)i] ≥ 4750 tons per year 

i =1 

Where: 

(Eallowable)i = [(The permitted allowable pounds of NOx per million BTU 

for Combustion Unit i)/(2000 pounds per ton)] x [(the 

lower of permitted or maximum heat input rate capacity in 

million BTU per hour for Combustion Unit i) x (the lower 

of 8760 or permitted hours per year)]; 

(EActual)i = The tons of NOx per year prior actual emissions as listed in 

Appendix A for Combustion Unit i (unless prior actual 

emissions exceed allowable emissions, then use allowable); 

and 

n = The number of Combustion Units with Qualifying Controls 

from those listed in Appendix A that are selected by 

ExxonMobil to satisfy the requirements of the equation set 

forth in this Paragraph 47. 

Permit limits established to implement this Paragraph may use a 365-day rolling average for 

Combustion Units that use a CEMS or PEMS to monitor compliance, and for Combustion Units 

that do not use a CEMS or PEMS, the permit limits averaging period must be no longer than the 

averaging period of the reference test method. 

b. For the following four sets of Combustion Units: 

i. Baton Rouge Refinery Combustion Units F-2 and F-3 (at Refinery Units PCLA-2 

and PCLA-3); 

ii. Baytown Refinery Combustion Units GTG-38, GTG-41, GTG-42, GTG-43, 

GTG-44, and GTG-45 (all at Refinery Units BH-6 and BH-7); 

iii. Baytown Refinery Combustion Units F-801 and F-802 (at Refinery Unit PS-8); 

and 

iv. Beaumont Refinery Boiler 33 and Boiler 34 (at Power Plant 3). 

50
ExxonMobil may use the combined permitted heat input capacity for the set of Combustion 

Units in the inequality in Subparagraph 47.a, provided that each Combustion Unit in the set has 

an identical emission limit (in lbs/mmBTU). The emission limit and combined permitted heat 

input capacity for the set may be used in the inequality as if the set of Combustion Units were 

one unit. 

48. Baseline Information. Appendix A to this Consent Decree provides the 

following information for each Combustion Unit: 

i. the maximum physical heat input capacity or, if less, the allowable heat input 

capacity in mmBtu/hr (HHV); 

ii. the baseline emission rate for the agreed-upon baseline years in pounds of NOx 

per mmBtu heat input (HHV) and tons per year of actual emissions; 

iii. the type of data used to derive the emission estimate (i.e., emission factor, stack 

test, or CEMS data); and, 

iv. the utilization rate in annual average mmBtu/hr (HHV) for the baseline years. 

49. NOx Control Plan. ExxonMobil shall submit a detailed NOx control plan (the 

“NOx Control Plan”) to EPA for review and comment by no later than 90 days after the Entry 

Date, with annual updates (covering the prior calendar year as determined at calendar year end) 

with the first report submitted pursuant to Section IX (Recordkeeping and Reporting) following 

the passage of each calendar year until termination of the Consent Decree or until the reductions 

required by Paragraph 47 are achieved, whichever occurs first. The NOx Control Plan and its 

annual updates shall describe the achieved (as determined at calendar year end) and anticipated 

progress of the NOx emissions reductions program for Combustion Units and shall contain the 

following information for each Combustion Unit greater than 40 mmBtu/hr that ExxonMobil 

plans to use to satisfy the requirements of Paragraphs 47, 50, and 51: 

51
i. All of the information in Appendix A; 

ii. Identification of the type of Qualifying Controls installed or planned with date 

installed or planned (including identification of the Combustion Unit to be 

permanently shut down); 

iii. To the extent limits exist, the allowable NOx emission rates (in lbs/mmBtu 

(HHV)), with averaging period) and allowable heat input rate (in mmBtu/hr 

(HHV)) obtained or planned with dates obtained or planned; 

iv. The results of emissions tests and annual average CEMS data (reported in ppmvd 

corrected to 3% O2, and in lbs/mmBtu) conducted pursuant to Paragraph 53 and 

tons per year; and 

v. The amount in tons per year applied or to be applied toward satisfying 

Paragraph 47. 

Appendix A, the NOx Control Plan, and the annual updates required by this Paragraph shall be 

for informational purposes only and shall not be used to develop permit requirements or other 

operating restrictions. ExxonMobil may change any projections, plans, or information 

(including, but not limited to, which units ExxonMobil plans to control) that is included in the 

NOx Control Plan or updates by including such changes or updates in its annual reports. 

50. Milestones. 

a. By December 31, 2008, ExxonMobil shall install sufficient Qualifying 

Controls and have applied for emission limits sufficient to reduce NOx emissions by two-thirds 

of the NOx emissions reductions required by Paragraph 47. In the first Semi-Annual Report to 

be submitted under Section IX after December 31, 2008, ExxonMobil shall include a report 

showing how it satisfied the requirement of this Subparagraph. 

b. By December 31, 2009, ExxonMobil shall install sufficient Qualifying 

Controls and have applied for emission limits sufficient to reduce NOx emissions by 95% of the 

NOx emissions reductions required by Paragraph 47. In the first Semi-Annual Report to be 

52
submitted under Section IX after December 31, 2009, ExxonMobil shall include a report 

showing how it satisfied the requirement of this Paragraph. 

c. Consistent with Paragraph 47, ExxonMobil shall install the remainder of 

the required Qualifying Controls by no later than September 30, 2010. 

51. By no later than September 30, 2010, Combustion Units with Qualifying Controls 

shall represent at least 30% of the total maximum heat input capacity of all Combustion Units 

greater than 40 mmBtu/hr (at HHV) located at each of the Covered Refineries. Any Qualifying 

Controls may be used to satisfy this requirement, regardless of when the Qualifying Controls 

were installed. 

52. Pursuant to Subsection V.Q of this Consent Decree, ExxonMobil shall apply for 

federally-enforceable permits that incorporate emission limits (in lbs/mmBTU) for Combustion 

Units required under Paragraph 47, to ensure that the NOx emission reduction requirements 

imposed by this Subsection V.G shall survive the termination of this Consent Decree. 

53. For Combustion Units where Qualifying Controls are installed after the Entry 

Date, beginning no later than 180 days after installing Qualifying Controls on and commencing 

operation of a Combustion Unit that will be used to satisfy the requirements of Paragraph 47, 

ExxonMobil shall monitor such Combustion Unit as follows: 

i. For each Combustion Unit with a maximum physical capacity greater than 150 

mmBtu/hr (HHV), install or continue to operate a NOx and O2 CEMS. 

ii. For each Combustion Unit with a maximum physical capacity greater than 100 

mmBtu/hr (HHV) but less than or equal to 150 mmBtu/hr (HHV), install or 

continue to operate a NOx and O2 CEMS, or monitor NOx emissions with a 

PEMS developed and operated pursuant to the requirements of Appendix B of 

this Consent Decree. 

iii. For each Combustion Unit with a maximum physical capacity of less than or 

equal to 100 mmBtu/hr (HHV), (a) conduct an initial performance test and any 

53
periodic tests that may be required by EPA or by an Applicable Co-Plaintiff under 

other applicable regulatory authority; or (b) comply with the monitoring 

requirements described in Subparagraphs 53.i. or 53.ii above. The results of the 

initial performance testing shall be reported to the EPA and the Applicable 

Co-Plaintiff within 90 days of completing the test. 

ExxonMobil shall use Method 7E to conduct initial performance testing required by 

Subparagraph 53.iii. Monitoring with a PEMS that is required by this Paragraph shall be 

conducted in accordance with the requirements of Appendix B. By no later than 90 days after 

the Entry Date, ExxonMobil shall submit to EPA for review and comment a PEMS Program in 

accordance with Appendix B. For units that utilize Qualifying Controls as of the Entry Date and 

which ExxonMobil intends to use to achieve the NOx reductions required by Paragraphs 47 

and/or 51, ExxonMobil shall implement the specified monitoring requirements (CEMS, PEMS, 

stack test) based on the capacity of the Combustion Unit as listed in Appendix A by no later than 

eighteen (18) months after the Entry Date. For any such unit with a maximum physical capacity 

of less than or equal to 100 mmBtu/hr (HHV), an additional performance test is not required 

under this Paragraph if an initial performance test using Method 7E was performed after January 

1, 2004 and after the Combustion Unit was equipped with Qualifying Controls. 

54. Demonstrating Compliance through Use of a NOx CEMS. ExxonMobil shall 

install, certify, calibrate, maintain, and operate the CEMS required by Paragraph 53 in 

accordance with 40 C.F.R. Part 60, Appendices A and F, and the applicable performance 

specification test of 40 C.F.R. Part 60, Appendix B. For the Baton Rouge Refinery, the Baytown 

Refinery, the Beaumont Refinery, and the Torrance Refinery, unless Appendix F is otherwise 

required by the NSPS, state law or regulation, or a permit or approval, in lieu of the requirements 

of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3 and 5.1.4, ExxonMobil may conduct either a 

Relative Accuracy Audit (“RAA”) or a Relative Accuracy Test Audit (“RATA”) once every 

54
three (3) years and shall conduct Cylinder Gas Audits (“CGA”) each calendar quarter during 

which a RAA or a RATA is not performed. 

55. The requirements of this Subsection V.G do not exempt ExxonMobil 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 of Lodging of the Consent Decree, or based upon new or modified regulatory, 

statutory, or permit requirements. However, nothing in this Subsection V.G is meant to prevent 

ExxonMobil 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) of this Consent Decree. ExxonMobil is not prohibited from using additional 

emission reductions from Combustion Units that are not required by this Consent Decree for any 

other purpose as allowed by Paragraph 150. 

56. ExxonMobil shall retain records demonstrating installation of Qualifying Controls 

under Paragraph 47 and monitoring/test data under Paragraph 53 until termination of the Consent 

Decree. ExxonMobil shall submit such records to EPA upon request. 

57. If ExxonMobil transfers ownership of any Covered Refinery before achieving all 

of the NOx reductions required by Paragraph 47, ExxonMobil shall notify EPA and the 

Applicable Co-Plaintiff of that transfer and shall submit an allocation to EPA and the Applicable 

Co-Plaintiff for that Covered Refinery’s share of NOx reduction requirements of Paragraph 47 

that will apply individually to the transferred refinery after such transfer. If ExxonMobil 

chooses, such allocation may be zero. Any such allocation shall be memorialized in a Consent 

Decree modification in accordance with Paragraphs 7 and 269. 

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H. SO2 EMISSIONS REDUCTIONS FROM AND NSPS APPLICABILITY OF 

HEATERS, BOILERS AND OTHER FUEL GAS COMBUSTION 

DEVICES. 

58. General. ExxonMobil shall undertake measures to limit SO2 emissions from 

refinery heaters and boilers and other fuel combustion devices by restricting H2S in refinery fuel 

gas and by agreeing not to burn Fuel Oil except as specifically permitted under the provisions of 

this Subsection V.H. Flaring Devices are not subject to the provisions of this Subsection V.H, 

but rather are subject to the provisions of Subsections V.J, V.K, and V.L. 

59. NSPS Applicability to Heaters, Boilers and Other Fuel Gas Combustion 

Devices (Other than Flaring Devices). 

a. Upon the Entry Date, each heater and boiler that is used to combust 

refinery fuel gas at any of 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 of NSPS Subparts A and J for fuel gas combustion devices, except for those heaters 

and boilers listed in Appendix C, each of which shall be an affected facility and shall be subject 

to and comply with the requirements of NSPS Subparts A and J for fuel gas combustion devices 

by the dates listed in Appendix C. 

b. By the dates listed in Appendix D, each of the other fuel gas combustion 

devices that is used to combust refinery fuel gas at any of the Covered Refineries, as listed in 

Appendix D, 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 of NSPS Subparts A and J for 

fuel gas combustion devices. 

c. Where Appendix C or D specifies an alternative monitoring plan (“AMP”) 

submittal date (rather than a final NSPS Subpart A and J compliance date), ExxonMobil shall 

56
submit to EPA a timely and complete AMP application by the date(s) specified. To the extent 

that ExxonMobil 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,” which is attached hereto in Appendix E, ExxonMobil may begin 

using such method immediately upon submitting its application for approval to use such method. 

If an AMP is not approved, ExxonMobil shall submit to EPA for approval a plan for complying 

with the monitoring requirements of NSPS Subparts A and J for the particular equipment within 

ninety (90) days of receiving notice of the disapproval. The equipment will become an affected 

facility when ExxonMobil receives EPA’s approval of the relevant AMP. A plan for complying 

with the monitoring requirements of NSPS Subparts A and J 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 of the AMP applications will rely 

in part 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 SO2 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 of fuel gas. 

EPA shall not reject an AMP solely due to the AMP’s use of one of these approaches to 

demonstrating compliance with NSPS Subpart J. 

60. Elimination/Reduction of Fuel Oil Burning. Effective on the Entry Date, 

ExxonMobil shall not burn Fuel Oil in any combustion unit at any of the Covered Refineries 

except during periods of Natural Gas Curtailment. Nothing herein is intended to limit, or shall 

57
be interpreted as limiting: (i) the use of torch oil in an FCCU regenerator to assist in starting, 

restarting, maintaining hot standby, or maintaining regenerator heat balance; or (ii) combustion 

of acid soluble oil in a combustion device. 

61. Compliance with Consent Decree Constitutes Compliance with Certain 

NSPS Subpart A Requirements. For each fuel gas combustion device that becomes an 

“affected facility,” as that term is used in 40 C.F.R. Part 60, Subparts A and J, pursuant to this 

Subsection V.H, entry of this Consent Decree and compliance with the relevant monitoring 

requirements of this Consent Decree for such fuel gas combustion device will satisfy the notice 

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

§ 60.8(a). 

I. SULFUR RECOVERY PLANT OPERATIONS. 

62. General. ExxonMobil shall comply with the requirements specified below for 

the Sulfur Recovery Plants (“SRPs”) at the Baton Rouge, Baytown, Beaumont, Joliet, and 

Torrance Refineries. 

63. Sulfur Recovery Plant NSPS Applicability. Each of the following SRPs shall 

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

SRP NSPS Effective Date 

Baytown SRP Consent Decree Entry Date 

Beaumont SRP Consent Decree Entry Date 

Joliet SRP December 31, 2008 

Torrance SRP Consent Decree Entry Date 

64. Sulfur Recovery Plant NSPS Compliance. By no later than the NSPS Effective 

Dates specified by Paragraph 63, ExxonMobil shall ensure that the SRPs listed in Paragraph 63 

comply with all applicable provisions of NSPS set forth at 40 C.F.R. Part 60, Subparts A and J, 

including, but not limited to, the following: 

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a. Emission Limit. ExxonMobil shall, for all periods of operation of these 

SRPs, comply with 40 C.F.R. § 60.104(a)(2) at each SRP except during periods of startup, 

shutdown or Malfunction. The startup/shutdown provisions set forth in NSPS Subpart A shall 

not apply to the independent startup or shutdown of a TGU serving as a control device for the 

SRP. 

b. Monitoring. ExxonMobil shall monitor all emissions points (stacks) to the 

atmosphere for Tail Gas emissions and shall monitor and report excess emissions from each of 

these SRPs as required by 40 C.F.R. §§ 60.7(c), 60.13, and 60.105(a)(5), (6) or (7). During the 

term of this Consent Decree, ExxonMobil shall conduct emissions monitoring from these SRPs 

with CEMS that are compliant with NSPS requirements at all of the emission points, unless an 

SO2 alternative monitoring procedure has been approved by EPA, pursuant to 40 C.F.R. 

§ 60.13(i), for any of the emission points. The requirement for continuous monitoring of the 

SRP emission points is not applicable to the Acid Gas Flaring Devices used to flare the Acid Gas 

or Sour Water Stripper Gas diverted from the SRPs. 

c. Notice and Initial Performance Test Requirements. For each SRP listed in 

Paragraph 63, entry of this Consent Decree and compliance with the relevant monitoring 

requirements of this Consent Decree for such SRP will satisfy the notice requirements of 40 

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

65. Good Operation and Maintenance and PMO Plans. 

a. By no later than 90 days after the Entry Date, ExxonMobil shall submit to 

EPA and the Applicable Co-Plaintiffs a summary of the plans, implemented or to be 

implemented, at each of the Covered Refineries for enhanced maintenance and operation of the 

SRPs, the control devices, and the appropriate Upstream Process Units. Those plans shall be 

59
termed the Preventative Maintenance and Operations Plans (“PMO Plans”). The PMO Plans 

shall be a compilation of ExxonMobil’s approaches for exercising good air pollution control 

practices and for minimizing SO2 emissions from sulfur processing and Upstream Process Units 

at the Covered Refineries. The PMO Plans shall have as its goals the elimination of Acid Gas 

Flaring and operation of the SRPs between scheduled maintenance turnarounds with 

minimization of emissions. The PMO Plans shall include, but shall not be limited to, sulfur 

shedding procedures, startup and shutdown procedures of the SRPs, control devices and 

Upstream Process Units, emergency procedures and schedules to coordinate maintenance 

turnarounds of the SRP Claus trains and any control device to coincide with scheduled 

turnarounds of major Upstream Process Units. Through and after termination of this Consent 

Decree, ExxonMobil shall implement the PMO Plans at all times, including periods of startup, 

shutdown and Malfunction, consistent with the requirements imposed by 40 C.F.R. § 60.11(d). 

Changes to the PMO Plan related to minimizing Acid Gas Flaring and/or SO2 emissions shall be 

summarized and reported by ExxonMobil to EPA and the Applicable Co-Plaintiffs in the SemiAnnual Report required under Section IX. 

b. EPA and the Applicable Co-Plaintiffs do not, by their review of the PMO 

Plans and/or by their failure to comment on the PMO Plans, warrant or aver in any manner that 

any of the actions that ExxonMobil may take pursuant to such PMO Plans will result in 

compliance with the provisions of the Clean Air Act or any other applicable federal, state, or 

local law or regulation. Notwithstanding review of the PMO Plans by EPA or the Applicable 

Co-Plaintiffs, ExxonMobil shall remain solely responsible for compliance with the Clean Air 

Act and such other laws and regulations. 

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66. Baton Rouge and Joliet Optimization Studies and Interim Performance 

Standards. ExxonMobil shall complete an optimization study for the Joliet East Claus Train 

and West Claus Train and an optimization study for the Baton Rouge 100 Claus Train and 200 

Claus Train, for the purpose of determining optimal sulfur recovery rates for the aforementioned 

Claus Trains (the “Optimization Studies”). The Optimization Studies will be used to establish 

Interim Performance Standards for each of those Claus trains. The Interim Performance 

Standards for the Baton Rouge 100 Claus Train and 200 Claus Train would apply only during 

planned routine maintenance on the Baton Rouge TGU, if the relevant Claus train is being 

operated during the maintenance period, as provided by Paragraph 67. The Interim Performance 

Standards for the Joliet East Claus Train and West Claus Train would only apply until the Joliet 

SRP complies with NSPS Subpart J requirements, as provided by Paragraph 68. 

a. The Optimization Studies shall be completed by no later than ten (10) 

months after the Entry Date, and shall include: (i) a detailed evaluation of plant design and 

capacity, operating parameters and efficiencies - including catalytic activity, and material 

balances; (ii) an analysis of the composition of the acid gas and sour water stripper gas resulting 

from the processing of crude slate actually used, or expected to be used; (iii) a thorough review 

of each critical piece of process 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; (iv) establishment of 

baseline data through testing and measurement of key parameters throughout the Claus train; 

(v) establishment of a thermodynamic process model of the Claus train; (vi) for any key 

parameters that have been determined to be at less than optimal levels, initiation of logical, 

sequential, or stepwise changes designed to move such parameters toward their optimal values; 

61
(vii) verification through testing, analysis of continuous emission monitoring data or other 

means, of incremental and cumulative improvements in sulfur recovery efficiency, if any; 

(viii) establishment of new operating procedures for long term efficient operation; and (ix) each 

study shall be conducted to optimize the performance of the Claus train in light of the actual 

characteristics of the feeds to the Claus train. 

b. Within sixty (60) days after completion of each Optimization Study, 

ExxonMobil shall submit an Optimization Study Report. Each Optimization Study Report shall: 

(i) describe the results of the study on the Claus train; (ii) identify recommended physical and 

operational improvements, if any, that would enhance Claus train efficiency; (iii) propose an 

Interim Performance Standard (expressed as percent recovery efficiency and/or an emission 

limitation) for the Claus train; and, if necessary, (iv) propose a schedule for implementing 

recommended physical or operational improvements required to achieve the proposed Interim 

Performance Standard. 

c. Upon submitting an Optimization Study Report, ExxonMobil shall comply 

with its proposed Interim Performance Standard in accordance with this Paragraph 66 or, if 

necessary, shall begin implementing recommended physical or operational improvements 

required to achieve the proposed Interim Performance Standard. 

d. If EPA 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, then EPA, after consultation with the Applicable Co-Plaintiff, shall so 

notify ExxonMobil. Unless ExxonMobil disputes EPA’s determination(s) within 90 days of its 

receipt of that notice, ExxonMobil shall, in accordance with this Paragraph 66, comply with such 

62
new standard within 90 days or, if necessary, such other period as may be established by EPA 

based upon the approved implementation schedule. 

67. Particular Requirements for Baton Rouge. 

a. Good Air Pollution Control Practices. Commencing on the Entry Date, 

ExxonMobil shall at all times, including periods of startup, shutdown, and malfunction, to the 

extent practicable, maintain and operate the Baton Rouge Claus trains, the Baton Rouge TGU, 

and the Baton Rouge Sulfur Recovery incinerator, in a manner consistent with good air pollution 

control practices for minimizing emissions. 

b. Tail Gas Treatment. Commencing on the Entry Date, ExxonMobil shall 

route all Tail Gas from all Baton Rouge Claus trains to the Baton Rouge TGU, except: (i) during 

periods of a scheduled Claus train startup, a scheduled Claus train shutdown, or a Claus train or 

TGU malfunction; or (ii) during planned routine maintenance on the Baton Rouge TGU, as 

provided by Subparagraph 67.d. 

c. Emissions Limits for Normal Operations. Commencing on the Entry 

Date, emissions from the Baton Rouge Claus trains shall not exceed the following, except during 

periods of a scheduled Claus train startup, a scheduled Claus train shutdown, or a Malfunction: 

(1) For an oxidation control system or a reduction control system 

followed by incineration, 250 ppm by volume (dry basis) of sulfur dioxide (SO2) at zero 

percent excess air, on a 12-hour rolling average basis; or 

(2) For a reduction control system not followed by incineration, 

300 ppm by volume of reduced sulfur compounds and 10 ppm by volume hydrogen 

sulfide (H2S), calculated as ppm SO2 by volume (dry basis) at zero percent excess air, on 

a 12-hour rolling average basis. 

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d. Particular Requirements Regarding Planned Routine Maintenance on the 

Baton Rouge TGU. The requirements of this Subparagraph 67.d shall apply to periods of 

planned routine maintenance on the Baton Rouge TGU after the Entry Date. 

(1) ExxonMobil shall minimize emissions associated with planned 

routine maintenance on the Baton Rouge TGU, to the extent practicable. More 

specifically, ExxonMobil shall: (i) minimize the duration of each planned routine 

maintenance period, and specifically limit each such period to no more than 30 calendar 

days in duration; (ii) maximize TGU run length between planned routine maintenance 

periods, and specifically limit their frequency to no more than once every five (5) years; 

(iii) implement appropriate sulfur shedding procedures during any planned routine 

maintenance period; (iv) cease operation of the 400 Claus Train during planned routine 

maintenance on the TGU and coordinate planned routine maintenance on the TGU with 

scheduled turnarounds of the 400 Claus Train and major Upstream Process Units; 

(v) operate the 100 Claus Train and the 200 Claus Train in compliance with the relevant 

Baton Rouge Interim Performance Standards, as described above in Paragraph 66, during 

the planned routine maintenance period; and (vi) seek and obtain LDEQ’s advance 

written approval for the planned routine maintenance period (such as by seeking and 

obtaining a variance pursuant to La. Admin. Code tit. 33, III § 1505). 

(2) The requirements specified by Subparagraph 67.d.(1) shall only 

apply to planned routine maintenance on the Baton Rouge TGU, and shall not apply to 

any unplanned shutdown or malfunction. 

(3) On a case-by-case basis, EPA will consider any advance written 

request by ExxonMobil demonstrating that a particular planned routine maintenance 

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period for the Baton Rouge TGU should be scheduled less than five (5) years after the 

prior planned maintenance period so that the planned maintenance will coincide with a 

scheduled turnaround of one or more major Upstream Process Units. If the request is 

approved in writing by EPA, then ExxonMobil may conduct the planned routine 

maintenance during the period approved by EPA. During any such planned routine 

maintenance period approved under this Subparagraph 67.d.(3), ExxonMobil shall 

comply with all requirements imposed by Subparagraph 67.d.(1) other than the 

30 calendar day/5 year restrictions specified by that Subparagraph. 

e. Incorporation of Certain Requirements Into Federally-Enforceable 

Permits. Pursuant to Subsection V.Q of this Consent Decree, ExxonMobil shall apply for a 

federally-enforceable permit that incorporates the following requirements, to ensure that the 

requirements shall survive the termination of this Consent Decree: (i) the Interim Performance 

Standards for the Baton Rouge 100 Claus Train and 200 Claus Train, established pursuant to 

Subparagraph 66.a; and (ii) the Particular Requirements for Baton Rouge specified by 

Subparagraphs 67.a - 67.d. 

68. Particular Requirements Applicable to the Joliet SRP. 

a. By no later than December 31, 2008, ExxonMobil shall ensure that the 

Joliet SRP complies at all times with NSPS Subpart A and J requirements by taking actions that 

will include either: (i) expanding the Tail Gas handling capacity of the existing TGU, routing all 

Tail Gas from the East Claus Train and West Claus Train to the expanded TGU, and taking a 

refinery-wide shutdown during any period of planned routine maintenance on the TGU; or 

(ii) constructing one or more additional TGU(s) to control the emissions from the East Claus 

Train and West Claus Train. 

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b. Until the Joliet SRP complies with NSPS Subpart A and J requirements, 

ExxonMobil shall operate the East Claus Train and the West Claus Train in compliance with the 

relevant Joliet Interim Performance Standards, as set out above in Paragraph 66. 

69. Sulfur Pit Emissions. ExxonMobil shall route all sulfur pit emissions at the 

Covered Refineries as follows: 

a. ExxonMobil shall route or re-route all sulfur pit emissions at the Baytown 

Refinery and the Beaumont Refinery so that they are eliminated, controlled, or included and 

monitored as part of the emissions subject to the relevant NSPS Subpart J limit, 40 C.F.R. 

§ 60.104(a)(2), by no later than the Entry Date. 

b. ExxonMobil shall route or re-route all sulfur pit emissions at the Joliet 

Refinery so that they are eliminated, controlled, or included and monitored as part of the 

emissions subject to the relevant NSPS Subpart J limit, 40 C.F.R. § 60.104(a)(2), by no later than 

December 31, 2008. 

c. ExxonMobil shall route or re-route all sulfur pit emissions at the Torrance 

Refinery so that they are eliminated, controlled, or included and monitored as part of the 

emissions subject to the relevant NSPS Subpart J limit, 40 C.F.R. § 60.104(a)(2), by no later than 

July 1, 2009. 

d. ExxonMobil shall, by July 1, 2005, route or re-route all sulfur pit 

emissions at the Baton Rouge Refinery so that they are eliminated, controlled, or included and 

monitored as part of the relevant emissions limitations set forth in Paragraph 67. 

e. The Parties recognize that periodic maintenance may be required for 

properly designed and operated sulfur pit emission control systems and/or equipment. 

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ExxonMobil will take all reasonable measures to minimize emissions while such periodic 

maintenance is being performed. 

J. FLARING DEVICES. 

70. Good Air Pollution Control Practices. ExxonMobil currently owns and/or 

operates the Flaring Devices identified in Appendix F to this Consent Decree. On and after the 

Entry Date, ExxonMobil shall at all times and to the extent practicable, including during periods 

of startup, shutdown, upset and/or Malfunction, implement good air pollution control practices to 

minimize emissions from its Flaring Devices, in a manner consistent with the requirements 

imposed by 40 C.F.R. § 60.11(d). 

71. NSPS Applicability to Flaring Devices. By no later than the dates identified in 

Appendix G, ExxonMobil agrees that each NSPS Flaring Device listed in Appendix G of this 

Consent Decree is an “affected facility” (as that term is used in NSPS, 40 C.F.R. Part 60, 

Subparts A and J) subject to, and required to comply with, the requirements of 40 C.F.R. Part 60, 

Subparts A and J, for fuel gas combustion devices. Where two or more dates are set forth in 

Appendix G with respect to one NSPS Flaring Device, the later of the two dates shall be the date 

on which the NSPS Flaring Device becomes an “affected facility.” 

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

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

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

b. By no later than 42 months after the Entry Date, ExxonMobil will 

construct and commence operation of enhancements to its existing flare gas recovery systems at 

the Beaumont Refinery. Those enhanced flare gas recovery systems will serve certain NSPS 

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

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c. By no later than 48 months after the Entry Date, ExxonMobil will 

construct and commence operation of enhancements to its existing flare gas recovery system at 

the Billings Refinery. That enhanced flare gas recovery system will serve both the NSPS Flaring 

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

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

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

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

03060091). 

73. Compliance Methods for NSPS Flaring Devices. 

a. ExxonMobil shall comply with the NSPS Subparts A and J requirements 

for each NSPS Flaring Device by using one or any combination of the following methods 

i. Operate and maintain a flare gas recovery system to prevent continuous or routine 

combustion in the NSPS Flaring Device. Use of a flare gas recovery system on a 

flare obviates the need to continuously monitor and maintain records of hydrogen 

sulfide in the gas as otherwise required by 40 C.F.R. §§ 60.105(a)(4) and 60.7; 

ii. Eliminate the routes of continuous or intermittent, routinely-generated refinery 

fuel gases to a NSPS Flaring Device and operate the NSPS Flaring Device such 

that it receives only process upset gases (as defined in 40 C.F.R. § 60.101(e)), 

fuel gas released as a result of relief valve leakage or gases released due to other 

emergency malfunctions; 

iii. Operate the NSPS Flaring Device as a fuel gas combustion device and comply 

with NSPS monitoring requirements by use of a continuous monitor pursuant to 

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); or 

iv. Eliminate all routes of continuous or intermittent, routinely-generated fuel gases 

to the NSPS Flaring Device – other than the low-volume/low-pressure gas 

streams specified by Appendix G – and monitor the NSPS Flaring Device by use 

of a CEMS (in accordance with 40 C.F.R. § 60.105(a)(4)) and a flow meter; 

provided, however, that this compliance method: (a) may only be used for the 

three (3) NSPS Flaring Devices at the Baytown Refinery identified in Appendix 

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G; and (b) may not be used unless each of those NSPS Flaring Devices will emit 

less than 500 pounds of SO2 per day under normal conditions. 

b. For its existing NSPS Flaring Devices, ExxonMobil shall utilize the 

compliance method set forth in Appendix G by the dates specified in Appendix G. Where 

Appendix G specifies an AMP submittal date (rather than a final NSPS Subpart A and J 

compliance date), ExxonMobil shall submit to EPA a timely and complete AMP application by 

the date(s) specified. To the extent that ExxonMobil 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,” which is attached hereto in Appendix 

E, ExxonMobil may begin using such method immediately upon submitting its application for 

approval to use such method. If an AMP is not approved, ExxonMobil shall submit to EPA for 

approval a plan for complying with the monitoring requirements of NSPS Subparts A and J for 

the particular equipment within ninety (90) days of receiving notice of the disapproval. The 

equipment will become an affected facility when ExxonMobil receives EPA’s approval of the 

relevant AMP. A plan for complying with the monitoring requirements of NSPS Subparts A and 

J may include a revised AMP application, physical or operational changes to the equipment, or 

additional or different monitoring. 

74. Non-Routinely Generated Gases. The combustion of gases generated by the 

startup, shutdown, upset, or Malfunction of a refinery process unit or released to a Flaring 

Device as a result of relief valve leakage or other emergency Malfunction is exempt from the 

requirement to comply with 40 C.F.R. § 60.104(a)(1). 

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75. Compliance with Consent Decree Constitutes Compliance with Certain 

NSPS Subpart A Requirements. 

a. Notice Requirements. For each NSPS Flaring Device listed in 

Appendix G, entry of this Consent Decree will satisfy the notice requirements of 40 C.F.R. 

§ 60.7(a). 

b. Performance Test Requirements. 

(1) For each NSPS Flaring Device listed in Appendix G that becomes 

an affected facility under NSPS Subparts A and J pursuant to this Subsection V.J, entry 

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

Consent Decree for the NSPS Flaring Device shall satisfy the notice requirements of 40 

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

(2) Within 180 days of the Entry Date, for the NSPS Flaring Devices 

identified in Appendix G: (i) ExxonMobil shall conduct a velocity test on the NSPS 

Flaring Device pursuant to 40 C.F.R. § 60.18; or (ii) in lieu of conducting the velocity 

test required by 40 C.F.R. § 60.18, ExxonMobil may submit velocity calculations which 

demonstrate that the NSPS Flaring Device meets the performance specification required 

by 40 C.F.R. § 60.18. 

76. Periodic Maintenance of Flare Gas Recovery Systems. The Parties recognize 

that periodic maintenance may be required for properly designed and operated flare gas recovery 

systems. ExxonMobil will take all reasonable measures to minimize emissions while such 

periodic maintenance is being performed. 

77. Safe Operation of Refining Processes. The Parties recognize that under certain 

conditions, a flare gas recovery system may need to be bypassed in the event of an emergency or 

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in order to ensure safe operation of refinery processes. Nothing in this Consent Decree precludes 

ExxonMobil from temporarily bypassing a flare gas recovery system under such circumstances. 

K. CONTROL OF ACID GAS FLARING AND TAIL GAS INCIDENTS. 

78. AG Flaring History and Corrective Measures. ExxonMobil has conducted a 

review of past AG Flaring Incidents that occurred at the Covered Refineries between January 1, 

1998 and December 1, 2004, and has provided EPA a summary identifying the AG Flaring 

Incidents that occurred during that period, their probable causes, and the estimated emissions. 

ExxonMobil has implemented (or is in the process of implementing) corrective measures to 

address the root causes of the prior incidents and to minimize the number and duration of Acid 

Gas Flaring Incidents. 

79. Future AG Flaring Incidents and Tail Gas Incidents. As specified by this 

Subsection V.K, and consistent with the requirements of 40 C.F.R. § 60.11(d), ExxonMobil shall 

investigate the cause of future AG Flaring Incidents and Tail Gas Incidents, take reasonable 

steps to correct the conditions that have caused or contributed to such AG Flaring Incidents and 

Tail Gas Incidents, and minimize AG Flaring Incidents and Tail Gas Incidents at the Covered 

Refineries. ExxonMobil shall continue to follow the AG Flaring Incident investigation and 

corrective action procedures outlined in this Subsection V.K after termination of the Consent 

Decree, but the reporting and stipulated penalty provisions of this Subsection shall not apply 

after termination. 

80. Investigation and Reporting. No later than forty-five (45) days following the 

end of an AG Flaring Incident occurring after the Entry Date, ExxonMobil shall submit to EPA 

and the Applicable Co-Plaintiff a report that sets forth the following: 

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i. The date and time that the AG Flaring Incident started and ended. To the extent 

that the AG Flaring Incident involved multiple releases either within a twentyfour (24) hour period or within subsequent, contiguous, non-overlapping twentyfour (24) hour periods, ExxonMobil shall set forth the starting and ending dates 

and times of each release; 

ii. An estimate of the quantity of sulfur dioxide that was emitted and the calculations 

that were used to determine that quantity; 

iii. The steps, if any, that ExxonMobil took to limit the duration and/or quantity of 

sulfur dioxide emissions associated with the AG Flaring Incident; 

iv. A detailed analysis that sets forth the Root Cause and all significant contributing 

causes of that AG Flaring Incident, to the extent determinable; 

v. An analysis of the measures, if any, that are available to reduce the likelihood of a 

recurrence of an AG Flaring Incident resulting from the same Root Cause or 

significant contributing causes in the future. If two 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 of the 

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. If ExxonMobil concludes that corrective action(s) is (are) required 

under Paragraph 81, the report shall include a description of the action(s) and, if 

not already completed, a schedule for its (their) implementation, including 

proposed commencement and completion dates. If ExxonMobil concludes that 

corrective action is not required under Paragraph 81, the report shall explain the 

basis for that conclusion; 

vi. A statement that: (a) specifically identifies each of the grounds for stipulated 

penalties in Paragraphs 83 and 84 of this Decree and describes whether or not the 

AG Flaring Incident falls under any of those grounds, provided, however, that 

ExxonMobil may choose to submit with the Root Cause Failure Analysis a 

payment of stipulated penalties in the nature of settlement without the need to 

specifically identify the grounds for the penalty. Such payment of stipulated 

penalties shall not constitute an admission of liability, nor shall it raise any 

presumption whatsoever about the nature, existence or strength of ExxonMobil’s 

potential defenses; (b) if an AG Flaring Incident falls under Paragraph 85 of this 

Decree, describes which Subparagraph (i.e., 85.a or 85.b) applies and why; and 

(c) if an AG Flaring Incident falls under either Paragraph 84 or Subparagraph 

85.b, states whether or not ExxonMobil asserts a defense to the AG Flaring 

Incident, and if so, a description of the defense; 

vii. To the extent that investigations of the causes and/or possible corrective actions 

still are underway on the due date of the report, a statement of the anticipated date 

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by which a follow-up report fully conforming to the requirements of 

Subparagraphs 80.iv and 80.v shall be submitted; provided, however, that if 

ExxonMobil has not submitted a report or a series of reports containing the 

information required to be submitted under this Paragraph within the 45 day time 

period set forth in this Paragraph 80 (or such additional time as EPA may allow) 

after the due date for the initial report for the AG Flaring Incident, the stipulated 

penalty provisions of Section XI shall apply, but ExxonMobil shall retain the 

right to dispute, under the dispute resolution provision of this Consent Decree, 

any demand for stipulated penalties that was issued as a result of ExxonMobil’s 

failure to submit the report required under this Paragraph within the time frame 

set forth. Nothing in this Paragraph shall be deemed to excuse ExxonMobil from 

its investigation, reporting, and corrective action obligations under this Section 

for any AG Flaring Incident which occurs after an AG Flaring Incident for which 

ExxonMobil has requested an extension of time under this Subparagraph 80.vii; 

and 

viii. To the extent that completion of the implementation of corrective action(s), if 

any, is not finalized at the time of the submission of the report required under this 

Paragraph, then, by no later than thirty (30) days after completion of the 

implementation of corrective action(s), ExxonMobil shall submit a report 

identifying the corrective action(s) taken and the dates of commencement and 

completion of implementation. 

81. Corrective Action. 

a. In response to any AG Flaring Incident occurring after the Entry Date, 

ExxonMobil shall take, as expeditiously as practicable, such interim and/or long-term corrective 

actions, if any, as are consistent with good engineering practice to minimize the likelihood of a 

recurrence of the Root Cause and all significant contributing causes of that AG Flaring Incident. 

b. If EPA does not notify ExxonMobil in writing within forty-five (45) days 

of receipt of the report(s) required by Paragraph 80 that it objects to one or more aspects of the 

proposed corrective action(s) and schedule(s) of implementation, if any, then that (those) 

action(s) and schedule(s) shall be deemed acceptable for purposes of compliance with 

Subparagraph 81.a of this Decree. EPA does not, however, by its failure to object to any 

corrective action that ExxonMobil may take in the future, warrant or aver in any manner that any 

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corrective actions in the future shall result in compliance with the provisions of the Clean Air 

Act or its implementing regulations. 

c. If EPA objects, in whole or in part, to the proposed corrective action(s) 

and/or the schedule(s) of implementation or, where applicable, to the absence of such proposal(s) 

and/or schedule(s), it shall notify ExxonMobil and explain the basis for its objection (s) in 

writing within forty-five (45) days following receipt of the report(s) required by Paragraph 80, 

and ExxonMobil shall respond promptly to EPA’s objection(s). 

d. Nothing in this Subsection V.K shall be construed to limit the right of 

ExxonMobil to take such corrective actions as it deems necessary and appropriate immediately 

following an AG Flaring Incident or in the period during preparation and review of any reports 

required under this Paragraph. 

82. Stipulated Penalties for AG Flaring Incidents. The provisions of Paragraphs 

83-85 are to be used by EPA in assessing stipulated penalties for AG Flaring Incidents occurring 

after the Entry Date and by the United States in demanding stipulated penalties under this 

Section V.K. The provisions of Paragraphs 83-85 do not apply to HC Flaring Incidents. 

83. The stipulated penalty provisions of Paragraph 192 shall apply to any AG Flaring 

Incident for which the Root Cause was one or more of the following acts, omissions, or events: 

i. Error resulting from careless operation by the personnel charged with the 

responsibility for the Sulfur Recovery Plant, TGU, or Upstream Process Units; 

ii. Failure to follow written procedures; 

iii. A failure of equipment that is due to a failure by ExxonMobil to operate and 

maintain that equipment in a manner consistent with good engineering practice; 

iv. North Claus Train furnace power supply interlock system failures at the Joliet 

Refinery; or 

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v. Problems with SRP Unit 29B steam drum level controllers at the Torrance 

Refinery. 

84. If the AG Flaring Incident is not a result of one of the Root Causes identified in 

Paragraph 83, then the stipulated penalty provisions of Paragraph 192 shall apply if the AG 

Flaring Incident: 

i. Results in emissions of sulfur dioxide at a rate greater than twenty (20.0) pounds 

per hour continuously for three (3) consecutive hours or more and ExxonMobil 

failed to act in accordance with its PMO Plan and/or to take any action during the 

AG Flaring Incident to limit the duration and/or quantity of SO2 emissions 

associated with such incident; or 

ii. Causes the total number of AG Flaring Incidents in a rolling twelve (12) month 

period to exceed five (5) for a particular Covered Refinery. 

85. With respect to any AG Flaring Incident not identified in Paragraphs 83 or 84, the 

following provisions shall apply: 

a. First Time: If the Root Cause of the AG Flaring Incident was not a 

recurrence of the same Root Cause that resulted in a previous AG Flaring Incident that occurred 

since the Entry Date, then: 

(1) If the Root Cause of the AG 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 

of reviewing subsequent AG Flaring Incidents; 

(2) If the Root Cause of the AG Flaring Incident was sudden and 

infrequent, and was reasonably preventable through the exercise of good engineering 

practice, then ExxonMobil shall implement corrective action(s) pursuant to Paragraph 81, 

and the stipulated penalty provisions of Paragraph 192 shall not apply. 

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b. Recurrence: If the Root Cause is a recurrence of the same Root Cause that 

resulted in a previous AG Flaring Incident that occurred since the Entry Date, then ExxonMobil 

shall be liable for stipulated penalties under Paragraph 192 unless: 

(1) the AG Flaring Incident resulted from a Malfunction; or 

(2) the Root Cause previously was designated as an agreed-upon 

Malfunction under Subparagraph 85.a.(1); or 

(3) the AG Flaring Incident had as its Root Cause the recurrence of a 

Root Cause for which ExxonMobil had previously developed, or was in the process of 

developing, a corrective action plan for which ExxonMobil had not yet completed 

implementation. 

86. Defenses. ExxonMobil may raise the following affirmative defenses in response 

to a demand by the United States for stipulated penalties: 

i. Force majeure. 

ii. As to Paragraph 83, the AG Flaring Incident does not meet the identified criteria. 

iii. As to Paragraph 84, Malfunction. 

iv. As to Paragraph 85, the AG Flaring Incident does not meet the identified criteria 

and/or was due to a Malfunction. 

87. In the event a dispute under Paragraphs 82-86 is brought to the Court pursuant to 

the Dispute Resolution provisions of this Consent Decree, ExxonMobil may also assert a startup, 

shutdown and/or Malfunction defense, but the United States shall be entitled to assert that such 

defenses are not available. If ExxonMobil prevails in persuading the Court that the defenses of 

startup, shutdown and/or Malfunction are available for AG Flaring Incidents under 40 C.F.R. 

60.104(a)(1), ExxonMobil shall not be liable for stipulated penalties for emissions resulting from 

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such startup, shutdown and/or Malfunction. If the United States prevails in persuading the Court 

that the defenses of startup, shutdown and/or Malfunction are not available, ExxonMobil shall be 

liable for such stipulated penalties. 

88. Other than for a Malfunction or force majeure, if no AG Flaring Incident occurs at 

a Covered Refinery for a rolling 36 month period, then the stipulated penalty provisions of 

Subsection V.K. shall no longer apply to that Covered Refinery. EPA may elect to reinstate the 

stipulated penalty provision if ExxonMobil has an AG 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 term of this 

Consent Decree. 

89. Billings AG Flaring Incidents. With respect to AG Flaring Incidents occurring 

within the Billings Refinery, ExxonMobil shall not be entitled to assert failures, at Montana 

Sulfur and Chemicals Company’s contiguous facility, of air pollution control equipment, process 

equipment, or a process to operate in a normal or usual manner as a Malfunction defense. 

Nothing in this Consent Decree shall be construed as to impose any liability on the part of 

ExxonMobil for Acid Gas Flaring occurring within Montana Sulfur and Chemical Company's 

contiguous facility. 

90. Emission Calculations. 

a. Calculation of the Quantity of Sulfur Dioxide Emissions Resulting from 

AG Flaring. For purposes of this Consent Decree, the quantity of SO2 emissions resulting from 

an AG Flaring Incident shall be calculated by the following formula: 

Tons of SO2 = [FR][TD][ConcH2S][8.44 x 10-5]. 

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The quantity of SO2 emitted shall be rounded to one decimal point. (Thus, for example, for a 

calculation that results in a number equal to 10.050 tons, the quantity of SO2 emitted shall be 

rounded to 10.1 tons.) For purposes of determining the occurrence of, or the total quantity of 

SO2 emissions resulting from, an AG Flaring Incident that is comprised of intermittent AG 

Flaring, the quantity of SO2 emitted shall be equal to the sum of the quantities of SO2 flared 

during each 24-hour period starting when the Acid Gas was first flared. 

b. Calculation of the Rate of SO2 Emissions During AG Flaring. For 

purposes of this Consent Decree, the rate of SO2 emissions resulting from an AG Flaring 

Incident shall be expressed in terms of pounds per hour and shall be calculated by the following 

formula: 

ER = [FR][ConcH2S][0.169]. 

The emission rate shall be rounded to one decimal point. (Thus, for example, for a calculation 

that results in an emission rate of 19.95 pounds of SO2 per hour, the emission rate shall be 

rounded to 20.0 pounds of SO2 per hour; for a calculation that results in an emission rate of 20.05 

pounds of SO2 per hour, the emission rate shall be rounded to 20.1.) 

c. Meaning of Variables and Derivation of Multipliers Used in the Equations 

in this Paragraph 90: 

ER = Emission Rate in pounds of SO2 per hour 

FR = Average Flow Rate to Flaring Device(s) during Flaring Incident in 

standard cubic feet per hour 

TD = Total Duration of Flaring Incident in hours 

ConcH2S = Average Concentration of Hydrogen Sulfide in gas during Flaring 

Incident (or immediately prior to Flaring Incident if all gas is being 

flared) expressed as a volume fraction (scf H2S/scf gas) 

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8.44 x 10-5 = [lb mole H2S/379 scf H2S][64 lbs SO2/lb mole H2S][Ton/2000 lbs] 

0.169 = [lb mole H2S/379 scf H2S][1.0 lb mole SO2/1 lb mole H2S][64 lb 

SO2/1.0 lb mole SO2] 

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 (“ConcH2S”) shall 

be determined from the Sulfur Recovery Plant feed gas analyzer, from knowledge of the sulfur 

content of the process gas being flared, by direct measurement by Tutwiler or Draeger (or other 

colorimetric) tube analysis or by any other method approved by EPA or an Applicable 

Co-Plaintiff. In the event that any of these data points is unavailable or inaccurate, the missing 

data point(s) shall be estimated according to best engineering judgment. The report required 

under Paragraph 80 shall include the data used in the calculation and an explanation of the basis 

for any estimates of missing data points. 

91. Tail Gas Incidents. 

a. Investigation, Reporting, Corrective Action and Stipulated Penalties. For 

Tail Gas Incidents, ExxonMobil shall follow the same investigative, reporting, corrective action 

and assessment of stipulated penalty procedures and schedules as those set forth in Paragraphs 

80-88 for AG 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 an SRP. Commencing on the Entry Date, this Paragraph 91 shall apply to Tail Gas Incidents 

involving combustion of Tail Gas from: (i) the Baytown SRP; (ii) the Beaumont SRP; (iii) the 

Torrance SRP; (iv) the Joliet North Claus Train; and (v) the Baton Rouge Claus trains, except 

during periods of planned routine maintenance on the Baton Rouge TGU performed in 

compliance with Subparagraph 67.d. After December 31, 2008, this Paragraph 91 shall also 

apply to Tail Gas Incidents involving combustion of Tail Gas from the Joliet SRP’s East Claus 

Train and West Claus Train. ExxonMobil shall continue to follow the Tail Gas Incident 

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investigation and corrective action procedures after termination of the Consent Decree, but the 

reporting and stipulated penalty provisions of this Subsection shall not apply after termination. 

b. Calculation of the Quantity of SO2 Emissions Resulting from a Tail Gas 

Incident. For the purposes of this Consent Decree, the quantity of SO2 emissions resulting from 

a Tail Gas Incident shall be calculated by one of the following methods, based on the type of 

event: 

i. If Tail Gas is combusted in a flare, the SO2 emissions are calculated using 

the methods outlined in Paragraph 90; or 

ii. If Tail Gas exceeding the 250 ppmvd NSPS J limit is emitted from a 

monitored SRP incinerator, then the following formula applies: 

TDTGI 

ERTGI = 3 [ FRInc.]i

 [Conc. SO2 – 250]i [0.169 x 10-6] [[20.9 - % O2]/[20.9]]i 

i = 1 

Where: 

ERTGI = Emissions from Tail Gas Unit at the SRP incinerator, pounds of SO2 over 

a 24 hour period 

TDTGI = Hours when the incinerator CEM was exceeding 250 ppmvd SO2 on a 

rolling twelve hour average, corrected to 0% O2, in each 24 hour period of 

the Incident 

i = Each hour within TDTGI 

FRInc. = Incinerator Exhaust Gas Flow Rate (standard cubic feet per hour, dry 

basis) (actual stack monitor data or engineering estimate based on the acid 

gas feed rate to the SRP) for each hour of the Incident 

Conc. SO2 = The average SO2 concentration (CEMS data) that is greater than 250 ppm 

in the incinerator exhaust gas, ppmvd corrected to 0% O2, for each hour of 

the Incident 

% O2 = O2 concentration (CEMS data) in the incinerator exhaust gas in volume % 

on dry basis for each hour of the Incident 

0.169 x 10-6 = [lb mole of SO2 / 379 scf SO2 ] [64 lbs SO2 / lb mole SO2 ] [1 x 10-6 ] 

Standard conditions = 60 degree F; 14.7 lbforce/sq.in. absolute 

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In the event the concentration SO2 data point is inaccurate or not available or a flow meter for 

FRInc, does not exist or is inoperable, then ExxonMobil shall estimate emissions based on best 

engineering judgment. 

L. CONTROL OF HYDROCARBON FLARING INCIDENTS. 

92. HC Flaring Incidents. For HC Flaring Incidents occurring after the Entry Date, 

ExxonMobil shall follow the same investigative, reporting, and corrective action procedures as 

those set forth in Subsection V.K for AG Flaring Incidents. However: 

i. ExxonMobil shall submit the HC Flaring Incident(s) reports as part of the 

Semi-Annual Reports required pursuant to Section IX, rather than on an incidentby-incident basis. 

ii. For each of the Flaring Devices identified in Appendix F, ExxonMobil may 

prepare and submit a single Root Cause Analysis for one or more Root Causes 

found by that analysis to routinely recur. ExxonMobil will inform EPA and the 

Applicable Co-Plaintiff that it is electing to report only once on that Root 

Cause(s). Unless EPA or the Applicable Co-Plaintiff objects within thirty (30) 

days of receipt of the Root Cause Analysis, such election will be effective. 

iii. For the six (6) month period after the installation of a flare gas recovery system 

(that is, during the time in which the flare gas recovery system is being 

commissioned), ExxonMobil will not be required to undertake HC Flaring 

Incident investigations if the Root Cause of the HC Flaring Incident is directly 

related to the commissioning of the flare gas recovery system. 

iv. In lieu of analyzing possible corrective actions under Subparagraph 80.v and 

taking interim and/or long-term corrective action under Paragraph 81 for a 

HC Flaring Incident attributable to the startup or shutdown of a process unit that 

ExxonMobil has previously analyzed under this Paragraph, ExxonMobil may 

identify such prior analysis when submitting the report required under this 

Paragraph. 

v. To the extent that a HC Flaring Incident at a Covered Refinery has as its Root 

Cause the bypass of a flare gas recovery system for safety or maintenance reasons 

as set forth in Paragraphs 76 - 77, ExxonMobil will be required to describe only 

the HC Flaring Incident and to list the date, time, and duration of such Incident in 

the Semi-Annual Reports due under Section IX. 

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ExxonMobil shall continue to follow the HC Flaring Incident investigation and corrective action 

procedures after termination of the Consent Decree, but the reporting provisions of this 

Subsection shall not apply after termination. 

93. Stipulated penalties under Paragraphs 82-85 and Paragraph 192 shall not apply to 

HC Flaring Incident(s). 

94. The formulas at Paragraph 90, used for calculating the quantity and rate of SO2 

emissions during AG Flaring Incidents, shall be used to calculate the quantity and rate of SO2 

emissions during HC Flaring Incidents. 

M. CERCLA/EPCRA REPORTING. 

95. CERCLA/EPCRA Compliance Review for Acid Gas Flaring Incidents. 

ExxonMobil shall conduct a review of past AG Flaring Incidents that occurred at the Baton 

Rouge, Baytown, Beaumont, Billings, and Joliet Refineries between January 1, 1998 and the 

Date of Lodging to determine its compliance with applicable requirements of Section 103(a) of 

CERCLA, 42 U.S.C. § 9603(a), and Section 304 of EPCRA, 42 U.S.C. § 11004, with respect to 

reporting SO2 and H2S releases resulting from those AG Flaring Incidents. Upon completion of 

this review, ExxonMobil shall complete the following activities by no later than ninety (90) days 

after the Entry Date: 

a. correct any identified violations by submitting reports to the appropriate 

agencies consistent with the requirements of Section 103(a) of CERCLA and Section 304 of 

EPCRA; and 

b. submit a CERCLA/EPCRA Compliance Review Report to EPA and the 

Applicable Co-Plaintiff that: (i) identifies all AG Flaring Incidents; (ii) if associated violations 

of Section 103(a) of CERCLA and Section 304 of EPCRA related to SO2 and H2S were 

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identified with respect to any such AG Flaring Incidents, contains a list of such violations for 

which ExxonMobil seeks a resolution of liability; and (iii) attaches to such report copies of any 

corrective reports filed by ExxonMobil pursuant to Subparagraph 95.a., above. 

96. CERCLA/EPCRA Reporting for the Joliet Refinery. For any release at the 

Joliet Refinery after the Entry Date that is reportable under CERCLA Section 103(a) and/or 

EPCRA Section 304: 

i. ExxonMobil shall report any such release that is reportable under CERCLA 

Section 103(a) to the National Response Center , the State Emergency Response 

Center, and the Local Emergency Planning Committee as soon as ExxonMobil 

has knowledge that a Reportable Quantity has been released; 

ii. ExxonMobil shall report any such release that is reportable under EPCRA Section 

304 to the State Emergency Response Center and the Local Emergency Planning 

Committee immediately after ExxonMobil knows that a Reportable Quantity has 

been released, and shall submit required followup reports within 7 days of that 

time; and 

iii. ExxonMobil shall be liable for payment of stipulated penalties under Paragraph 

198 for failure to report a release as required by the preceding Subparagraphs 96.i 

and/or 96.ii. 

N. BENZENE WASTE NESHAP PROGRAM ENHANCEMENTS. 

97. In addition to continuing to comply with all applicable requirements of 40 C.F.R. 

Part 61, Subpart FF (“Benzene Waste NESHAP,” “BWON,” or “Subpart FF”), ExxonMobil 

agrees to undertake the measures set forth in this Subsection V.N to ensure continuing 

compliance with Subpart FF and to minimize or eliminate fugitive benzene waste emissions at 

the Covered Refineries. 

98. Subpart FF Compliance Status. 

a. Commencing on the Date of Entry, ExxonMobil’s Baton Rouge Refinery 

and Beaumont Refinery shall comply with the compliance option set forth at 40 C.F.R. 

83
§ 61.342(c), utilizing the exemptions set forth in 40 C.F.R. § 61.342(c)(2) and (c)(3)(ii) 

(hereinafter referred to as the “2 Mg Compliance Option”). 

b. Commencing on the Date of Entry, ExxonMobil’s Baytown Refinery, 

Billings Refinery, Joliet Refinery, and Torrance Refinery shall comply with the compliance 

option set forth at 40 C.F.R. § 61.342(e) (hereinafter referred to as the “6 BQ Compliance 

Option”). 

99. Refinery Compliance Status Changes. During the term of this Consent Decree, 

ExxonMobil shall not change the compliance status of any Covered Refinery from the 

6 BQ Compliance Option to the 2 Mg Compliance Option. 

100. One-Time Review and Verification of Each Covered Refinery’s TAB and 

Compliance Status. 

a. Phase One of the Review and Verification Process. By no later than 180 

days after the Entry Date, ExxonMobil shall complete a review and verification of each Covered 

Refinery’s Total Annual Benzene (“TAB”) and its compliance with the applicable compliance 

option. ExxonMobil’s review and verification process shall include, but not be limited to: 

i. an identification of each waste stream that is required to be included in the 

Refinery’s TAB (e.g., slop oil, tank water draws, spent caustic, desalter rag layer 

dumps, desalter vessel process sampling points, other sample wastes, maintenance 

wastes, and turnaround wastes); 

ii. a review and identification of the calculations and/or measurements used to 

determine the flows of each waste stream for the purpose of ensuring the accuracy 

of the annual waste quantity for each waste stream; 

iii. an identification of the benzene concentration in each waste stream, including 

sampling for benzene concentration at no less than 10 waste streams per Covered 

Refinery, consistent with the requirements of 40 C.F.R. § 61.355(c)(1) and (3); 

provided, however, that previous analytical data or documented knowledge of 

waste streams may be used, 40 C.F.R. § 61.355(c)(2), for streams not sampled. 

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Streams sampled after January 1, 2004 may be applied toward the waste streams 

requiring sampling; 

iv. an identification of whether or not the stream is controlled consistent with the 

requirements of Subpart FF; and 

v. an identification of any existing noncompliance with the requirements of Subpart 

FF. 

By no later than 30 days following the completion of Phase One of the review and verification 

process, ExxonMobil shall submit to EPA and the Applicable Co-Plaintiff a BWON Compliance 

Review and Verification Report for each Covered Refinery that sets forth the results of Phase 

One, including but not limited to the items identified in Subparagraphs a.i through a.v of this 

Paragraph. 

b. Phase Two of the Review and Verification Process. Based on EPA’s 

review of the BWON Compliance Review and Verification Reports, EPA may select up to 20 

additional waste streams at each Covered Refinery for additional sampling or re-sampling for 

benzene concentration. ExxonMobil shall conduct the required sampling under representative 

conditions and submit the results to EPA within 60 days of receipt of EPA’s request. 

ExxonMobil shall use the results of this additional sampling to reevaluate the TAB and the 

uncontrolled benzene quantity and to amend the BWON Compliance Review and Verification 

Report, as needed. To the extent that EPA requires ExxonMobil to re-sample a waste stream as 

part of the Phase Two review that ExxonMobil chose to sample as part of the Phase One review, 

ExxonMobil may average the results of the two sampling events. ExxonMobil shall submit an 

amended BWON Compliance Review and Verification Report within 90 days following the date 

of the completion of the required Phase Two sampling, if Phase Two sampling is required by 

EPA. 

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101. Implementation of Actions Necessary to Correct Non-Compliance or to 

Come Into Compliance. 

a. Amended TAB Reports. If the results of the BWON Compliance Review 

and Verification Report indicate that the reports required by 40 C.F.R. § 61.357(c) or 61.357(d) 

have not been filed or are inaccurate and/or do not satisfy the requirements of Subpart FF, 

ExxonMobil shall submit, by no later than sixty (60) days after completion of the BWON 

Compliance Review and Verification Report(s), an amended TAB report to EPA and the 

Applicable Co-Plaintiff. 

b. BWON Corrective Measures Plan. 

(1) Baton Rouge and Beaumont Refineries. If the results of the 

BWON Compliance Review and Verification Report indicate that ExxonMobil is not in 

compliance with the 2 Mg Compliance Option at the Baton Rouge Refinery or the 

Beaumont Refinery, ExxonMobil shall submit to EPA and the Applicable Co-Plaintiff, 

by no later than ninety (90) days after completion of the BWON Compliance Review and 

Verification Report, a BWON Corrective Measures Plan that identifies with specificity 

the compliance strategy and schedule that ExxonMobil shall implement to ensure that the 

Refinery complies with the 2 Mg Compliance Option as soon as practicable. 

(2) Baytown, Billings, Joliet, and Torrance Refineries. If the results of 

the BWON Compliance Review and Verification Report indicate that ExxonMobil is not 

in compliance with the 6 BQ Compliance Option at the Baytown Refinery, the Billings 

Refinery, the Joliet Refinery, or the Torrance Refinery, ExxonMobil shall submit to the 

EPA and the Applicable Co-Plaintiff, by no later than ninety (90) days after completion 

of the BWON Compliance Review and Verification Report, a BWON Corrective 

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Measures Plan that identifies with specificity the compliance strategy and schedule that 

ExxonMobil shall implement to ensure that the Refinery complies with the 6 BQ 

Compliance Option as soon as practicable. 

c. Review and Approval of Plans Submitted Pursuant to Subparagraph 101.b. 

Any plan submitted pursuant to Subparagraph 101.b shall be subject to approval or disapproval 

by EPA, which shall act after an opportunity for consultation with the Applicable Co-Plaintiff. 

Within sixty (60) days after receiving any notification of disapproval from EPA, ExxonMobil 

shall submit to the EPA and the Applicable Co-Plaintiff a revised plan that responds to all 

identified or alleged deficiencies. Upon receipt of approval or approval with conditions, 

ExxonMobil shall implement the plan according to the schedule provided in the approved plan. 

d. Certification of Compliance with the 2 Mg Compliance Option or the 

6 BQ Compliance Option, as Applicable. By no later than 30 days after completion of the 

implementation of all actions, if any, required pursuant to Subparagraphs 101.b or 101.c to come 

into compliance with the 2 Mg Compliance Option or the 6 BQ Compliance Option, as 

applicable, ExxonMobil shall submit a report to EPA and the Applicable Co-Plaintiff certifying 

that, as to the subject Refinery, the Refinery complies with the Benzene Waste NESHAP. 

102. Carbon Canisters. ExxonMobil shall comply with the requirements of this 

Paragraph 102 at all locations at the Covered Refineries where a carbon canister(s) is utilized as 

a control device under the Benzene Waste NESHAP. 

a. By no later than 180 days after the Entry Date, ExxonMobil shall 

complete installation of primary and secondary carbon canisters at locations currently utilizing 

single canisters and shall operate them in series. By no later than 30 days following completion 

of the installation of the dual canisters, ExxonMobil shall submit a report certifying the 

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completion of the installation. The report shall include: (i) a list of all locations at each Covered 

Refinery where carbon canister systems are used as a control device under Subpart FF; (ii) an 

indication, for each location, whether there was a pre-existing secondary carbon canister or 

whether a secondary carbon canister was installed under this Paragraph; (iii) the installation date 

of each such secondary canister installed under this Paragraph and the date that each secondary 

canister was put into operation; and (iv) an indication, for each location, whether volatile organic 

compounds (“VOC”) or benzene will be used to monitor for breakthrough under and as required 

by Subparagraph 102.d. 

b. Except as expressly permitted under Paragraph 102.g, ExxonMobil shall 

not use single carbon canisters for any new units or installations at the Covered Refineries that 

require controls pursuant to the Benzene Waste NESHAP. 

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 VOC or 5 ppm 

benzene (depending upon the constituent that ExxonMobil decides to monitor). 

d. ExxonMobil 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 requirement shall commence: (i) upon the Entry 

Date where dual carbon canisters currently are in service; and (ii) within seven days after 

installation of a new dual carbon canister system. 

e. If ExxonMobil monitors a canister system for benzene and detects 

between 1 ppm and 5 ppm benzene between the primary and secondary canisters, then 

ExxonMobil shall begin monitoring for breakthrough (at 5 ppm benzene) between the primary 

88
and secondary carbon canisters weekly, or in accordance with the frequency specified in 40 

C.F.R. § 61.354(d), whichever is more frequent. 

f. ExxonMobil shall replace the original primary carbon canister (or route 

the flow to an appropriate alternative control device) immediately when breakthrough is detected 

between the primary and secondary canister. The original secondary carbon canister (or a fresh 

canister) will become the new primary carbon canister and a fresh carbon canister will become 

the secondary canister. For purposes of this Subparagraph, “immediately” shall mean within 

eight (8) hours of the detection of a breakthrough for canisters of 55 gallons or less, and within 

twenty-four (24) hours of the detection of a breakthrough for canisters greater than 55 gallons. 

In lieu of replacing the primary canister immediately, ExxonMobil may elect to monitor the 

outlet of the secondary canister beginning on the day the 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. If the constituent being monitored (either 

benzene or VOC) is detected at the outlet of the secondary canister during this period of daily 

monitoring, both canisters must be replaced within eight (8) hours of the detection of a 

breakthrough. 

g. Temporary Applications. ExxonMobil 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 of this Consent Decree as any reading of VOC above background or benzene above 

1 ppm (whichever is monitored). Beginning no later than the Entry Date, ExxonMobil shall 

monitor for breakthrough from a single carbon canister system once every calendar day that 

there is actual flow to the carbon canister. ExxonMobil shall replace the single carbon canister 

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with a fresh carbon canister, discontinue flow, or route the stream to an alternate, appropriate 

device immediately when breakthrough is detected. For purpose of this Subparagraph, 

“immediately” shall mean within eight (8) hours for canisters of 55 gallons or less and twentyfour (24) hours for canisters greater than 55 gallons. If a single canister has been found to 

exceed the applicable breakthrough concentration, flow must be discontinued to that canister 

immediately. Such a spent canister may not be placed back into Benzene Waste NESHAP vapor 

control service until it has been appropriately regenerated. 

h. ExxonMobil shall maintain a readily-available supply of fresh carbon 

canisters at all times at each Covered Refinery where canisters are used as a control device or 

shall otherwise ensure that such canisters are readily available to implement the requirements of 

this Paragraph 102. 

i. ExxonMobil shall maintain records associated with the requirements of 

this Paragraph, including carbon canister monitoring readings and the constituents being 

monitored for at least five (5) years after such readings occur. 

103. Annual Review. By no later than 120 days after the Entry Date, ExxonMobil 

shall modify, as necessary, its existing written management of change procedures to provide for 

an annual review of process information for each Covered Refinery, including but not limited to 

construction projects, to ensure that all new benzene waste streams are included in the Refinery’s 

waste stream inventory. ExxonMobil shall conduct such reviews on an annual basis. 

104. Laboratory Audits. ExxonMobil shall conduct audits of all laboratories that 

perform analyses of ExxonMobil’s Benzene Waste NESHAP samples to ensure that proper 

analytical and quality assurance/quality control procedures are followed for such samples. 

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a. By no later than 180 days after the Entry Date, ExxonMobil shall 

complete initial audits of at least half of the laboratories used by the Covered Refineries within 

180 days after the Entry Date, and shall complete initial audits of the remaining laboratories 

within 365 days of the Entry Date. In addition, ExxonMobil shall audit any new laboratory to be 

used for analyses of benzene samples from the Covered Refineries prior use of the new 

laboratory. If ExxonMobil has completed an audit of any laboratory on or after January 1, 2004, 

initial audits of those laboratories pursuant to this Subparagraph shall not be required. 

b. During the term of this Consent Decree, ExxonMobil shall conduct 

subsequent laboratory audits, such that each laboratory is audited once every two (2) calendar 

years. 

c. ExxonMobil 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 ExxonMobil’s. 

105. Benzene Spills. For each spill at each Covered Refinery after the Entry Date, 

ExxonMobil shall review the spill to determine if any benzene waste, as defined by Subpart FF, 

was generated. For each spill involving the release of more than 10 pounds of benzene in a 

24 hour period, ExxonMobil shall: (i) include the benzene waste generated by the spill in the 

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. 

106. Training. 

a. By no later than 90 days after the Entry Date, ExxonMobil shall develop 

and implement a program for annual (i.e., once each calendar year) training for all employees 

who draw benzene waste samples for Benzene Waste NESHAP purposes. 

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b. By no later than 120 days after the Entry Date, ExxonMobil shall 

complete the development of standard operating procedures (where they do not already exist) for 

all control devices and treatment processes used to comply with the Benzene Waste NESHAP at 

each Covered Refinery. By no later than 180 days after the Entry Date, ExxonMobil shall 

complete an initial training program regarding these procedures for all operators assigned to the 

relevant equipment. Comparable training shall also be provided to any persons who 

subsequently become operators, prior to their assumption of this duty. “Refresher” training in 

these procedures shall be performed on a three-year cycle (i.e., once every three calendar years). 

c. ExxonMobil shall assure that the employees of any contractors hired to 

perform any of the requirements of this Subsection V.N are properly trained to implement such 

requirements that they are hired to perform, as under Subparagraphs 106.a-106.c. 

107. Waste/Slop/Off-Spec Oil Management. 

a. Schematics. By no later than 120 days after the Entry Date, ExxonMobil 

shall submit to the EPA and the Applicable Co-Plaintiff schematics for each Covered Refinery 

that: (i) depict the waste management units (including sewers) that handle, store, and transfer 

waste/slop/off-spec oil streams; (ii) identify the control status of each waste management unit; 

and (iii) show how such oil is transferred within the Refinery. Representatives from 

ExxonMobil and EPA thereafter may confer about the appropriate characterization of each 

waste/slop/off-spec oil streams and the necessary controls, if any, for the waste management 

units handling such oil streams, for purposes of the Covered Refinery’s TAB calculation and 

compliance with the applicable compliance option. If requested by EPA, ExxonMobil shall 

promptly submit revised schematics that reflect the Parties’ agreements regarding the 

characterization of these oil streams and the appropriate control standards. ExxonMobil shall 

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use these schematics in preparing the BWON Sampling Plans required under Paragraphs 108 and 

109. 

b. Non-Aqueous Benzene Waste Streams. All waste management units 

handling non-exempt, non-aqueous benzene wastes, as defined in Subpart FF, shall meet the 

applicable control standards of Subpart FF. 

c. Aqueous Benzene Waste Streams. For purposes of calculating each 

Covered Refinery’s TAB pursuant to the requirements of 40 C.F.R. § 61.342(a), ExxonMobil 

shall include all waste/slop/off-spec oil streams that become “aqueous” until such streams are 

recycled to a process or put into a process feed tank (unless the tank is used primarily for the 

storage of wastes). Appropriate adjustments will be made to such calculations to avoid the 

double-counting of benzene. For purposes of complying with the applicable compliance option, 

all waste management units handling benzene waste streams will either meet the applicable 

control standards of Subpart FF or will have their uncontrolled benzene quantity count toward 

the applicable limit under the 2 Mg Compliance Option or the 6 BQ Compliance Option. 

108. Sampling Under the 6 BQ Compliance Option. ExxonMobil shall conduct 

quarterly sampling as described by this Paragraph at the Baytown, Billings, Joliet and Torrance 

Refineries for the purpose of calculating quarterly, uncontrolled benzene quantities. 

a. By no later than 180 days after the Entry Date, ExxonMobil shall submit 

to EPA for approval a sampling plan for each such Refinery designed to identify the quarterly 

benzene quantity in uncontrolled benzene waste streams, including waste/slop/off-spec oil. That 

sampling plan (the “BWON Sampling Plan”) shall include, but need not be limited to: 

(i) proposed sampling locations and methods for flow calculations at the “end of line” of 

uncontrolled benzene waste streams; (ii) a simplified flow diagram that identifies significant, 

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uncontrolled benzene waste streams that feed into each proposed sampling location; 

(iii) proposed quarterly sampling, at the “point of waste generation,” of each waste stream that 

contributes 0.05 Mg/yr or more to the Refinery’s benzene quantity; and (iv) quarterly sampling 

at all “end of line” and point of waste generation locations identified in Subparagraphs 108.a.(i) 

and 108.a.(iii). The BWON Sampling Plans may identify commingled, exempt waste streams 

for sampling, provided ExxonMobil demonstrates that the benzene quantity of those commingled 

streams will not be underestimated. Additionally, waste streams that are non-aqueous at their 

point of generation and do not become aqueous thereafter shall not be included in the BWON 

Sampling Plans. 

b. If changes in processes, operations, or other factors lead ExxonMobil to 

conclude that its approved BWON Sampling Plan no longer provides an accurate measure of the 

Refinery’s quarterly benzene quantity in uncontrolled benzene waste streams, ExxonMobil shall 

submit a revised BWON Sampling Plan to EPA for approval. 

c. ExxonMobil shall commence sampling under its BWON Sampling Plan 

during the first full calendar quarter following submittal of the Plan, regardless of whether or not 

the Plan is approved at that time. ExxonMobil shall take, and have analyzed, at least three 

representative samples from each identified sampling location. ExxonMobil shall use the 

average of all samples taken and the identified flow calculations to determine its quarterly 

benzene quantity in uncontrolled waste streams and to estimate a calendar year value for the 

Refinery. 

109. Sampling Under the 2 Mg Compliance Option. ExxonMobil shall conduct 

quarterly sampling as described by this Paragraph at the Baton Rouge and Beaumont Refineries 

for the purpose of calculating quarterly, uncontrolled benzene quantities 

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a. By no later than 180 days after the Entry Date, ExxonMobil shall submit 

to EPA for approval a sampling plan for each such Refinery designed to identify the quarterly 

benzene quantity in uncontrolled benzene waste streams, including waste/slop/off-spec oil. That 

sampling plan (the “BWON Sampling Plan”) shall include, but need not be limited to: 

(i) proposed sampling locations and methods for flow calculations at the “end of line” of 

uncontrolled benzene waste streams; (ii) quarterly sampling of all uncontrolled waste streams 

that count toward the 2 Mg/yr calculation an contain greater than 0.05 Mg/yr of benzene; 

(iii) monthly sampling of all uncontrolled waste streams that qualify for the 10 ppmw exemption 

(40 C.F.R. § 61.342(c)(2)) and that contain greater than 0.1 Mg/yr of benzene. The BWON 

Sampling Plans may identify commingled, exempt waste streams for sampling, provided 

ExxonMobil demonstrates that the benzene quantity of those commingled streams will not be 

underestimated. 

b. If changes in processes, operations, or other factors lead ExxonMobil to 

conclude that its approved BWON Sampling Plan may no longer provide an accurate measure of 

the Refinery’s quarterly benzene quantity in uncontrolled benzene waste streams, ExxonMobil 

shall submit a revised BWON Sampling Plan to EPA for approval. 

c. ExxonMobil shall commence sampling under its BWON Sampling Plan 

during the first full calendar quarter following submittal of the Plan, regardless of whether or not 

the Plan is approved at that time. ExxonMobil shall take, and have analyzed, at least three 

representative samples from each identified sampling location. ExxonMobil shall use the 

average of all samples taken and the identified flow calculations to determine its quarterly 

benzene quantity in uncontrolled waste streams and to estimate a calendar year value for the 

Refinery. 

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d. After at least 8 quarters of sampling under an approved BWON Sampling 

Plan under this Paragraph 109, ExxonMobil may submit a report to EPA and the Applicable 

Co-Plaintiff that requests a change in the monitoring frequency specified by Subparagraph 109.a 

for one or more of the Covered Refineries. If EPA determines, after an opportunity for 

consultation with ExxonMobil and the Applicable Co-Plaintiff, that the information presented in 

the report supports a change in the monitoring frequency for one or more of the Covered 

Refineries, then the monitoring frequency requirement under Subparagraph 109.a will be 

modified in accordance with Paragraph 269 (Modifications). 

110. Quarterly and Annual Estimations of Uncontrolled Benzene Quantity. At the 

end of each calendar quarter following commencement of quarterly sampling, ExxonMobil shall 

calculate a quarterly uncontrolled benzene quantity and shall estimate a projected calendar year 

uncontrolled benzene quantity based on the quarterly end of line sampling results, non-end of 

line sampling results, and the approved flow calculations. ExxonMobil shall submit the 

uncontrolled benzene quantity in the Semi-Annual Reports due under Section IX of this Decree. 

111. Corrective Measures. 

a. Applicability 

(1) For 6 BQ Compliance Option Refineries . If the calculations in 

Paragraph 110 indicate that the quarterly uncontrolled benzene quantity at the Baytown, 

Billings, Joliet, or Torrance Refineries exceeds 1.5 Megagrams or the projected calendar 

year uncontrolled benzene quantity exceeds 6.0 Megagrams, ExxonMobil shall submit a 

written report to EPA and the Applicable Co-Plaintiff that evaluates all relevant 

information and identifies whether any action should be taken to reduce benzene 

quantities in its waste streams for the remainder of the calendar year. If additional 

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actions are determined to be necessary to ensure compliance with the 6 BQ Compliance 

Option, ExxonMobil will include in its written report a BWON Corrective Measures Plan 

as specified in Subparagraph 111.b 

(2) For 2 Mg Compliance Option Refineries . If the calculations in 

Paragraph 110 indicate that the quarterly uncontrolled benzene quantity exceeds 

0.5 Megagrams or the projected calendar year uncontrolled benzene quantity exceeds 

2.0 Megagrams, ExxonMobil shall submit a written report to EPA and the Applicable 

Co-Plaintiff that evaluates all relevant information and identifies whether any action 

should be taken to reduce benzene quantities in its waste streams for the remainder of the 

calendar year. If additional actions are determined to be necessary to ensure compliance 

with the 2 Mg Compliance Option, ExxonMobil will include in its written report a 

BWON Corrective Measures Plan as specified in Subparagraph 111.b 

b. BWON Corrective Measures Plan. ExxonMobil shall, in any BWON 

Corrective Measures Plan required by this Paragraph, identify: (i) the cause of the potentially 

elevated benzene quantities; (ii) all corrective actions that ExxonMobil has taken or plans to take 

to ensure that the cause will not recur; and (iii) an appropriate strategy and schedule that 

ExxonMobil shall implement to ensure that ExxonMobil complies with the 6 BQ Compliance 

Option or the 2 Mg Compliance Option, as applicable. If a spill event is the main cause of the 

potentially elevated benzene quantities, the BWON Corrective Measures Plan will focus on the 

spill event and on future measures to minimize and address spills. ExxonMobil shall submit 

such plan and schedule, along with its report under Subparagraph 111.a, by no later than 60 days 

after the end of the Calendar Quarter in which one or more of the conditions specified in 

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Subparagraph 111.a is satisfied. ExxonMobil shall implement its BWON Corrective Measures 

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 of the conditions in Subparagraph 111.a continues to 

exist at a Covered Refinery and ExxonMobil is not then able to identify the cause(s) and/or 

appropriate corrective measures to ensure compliance with the applicable compliance option, 

ExxonMobil shall retain a third-party contractor to undertake a comprehensive TAB study and 

compliance review (“Third-Party TAB Study and Compliance Review”) at the relevant Refinery. 

By no later than the last day of the next following quarter, ExxonMobil shall submit a proposal 

to EPA that identifies the contractor, the contractor’s scope of work, and the contractor’s 

schedule for the Third-Party TAB Study and Compliance Review. Unless EPA disapproves or 

seeks modifications of the proposal within 30 days after its receipt, ExxonMobil shall authorize 

the contractor to commence work. ExxonMobil shall ensure that the work is completed in 

accordance with the schedule provided therein. No later than thirty (30) days after ExxonMobil 

receives the results of the Third-Party TAB Study and Compliance Review, ExxonMobil shall 

submit the results to EPA. After the report is submitted to EPA, ExxonMobil and EPA shall 

discuss informally the results of the Third-Party TAB Study and Compliance Review. No later 

than ninety (90) days after ExxonMobil receives the results of the Third-Party TAB Study and 

Compliance Review or at such other time as ExxonMobil and EPA may agree, ExxonMobil 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 

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modifications of the proposal within thirty (30) days after its receipt, ExxonMobil shall 

implement the remedial plan in accordance with the schedule included in its plan. 

112. Miscellaneous Measures. 

a. By no later than 60 days after the Entry Date, ExxonMobil shall: 

i. Conduct monthly visual inspections of and, if appropriate, refill all Subpart FF 

water traps within the Covered Refineries’ individual drain systems; 

ii. If ExxonMobil 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 of 

the inspections. After two (2) years of weekly inspections, and based upon an 

evaluation of the recorded results, ExxonMobil may submit a request to the 

appropriate EPA Region to modify the frequency of the inspections. EPA shall 

not unreasonably withhold its consent to such modification. Alternatively, for 

conservation vents with indicators that identify whether flow has occurred, 

ExxonMobil may elect to visually inspect such indicators on a monthly basis and, 

if flow is then detected, ExxonMobil shall then visually inspect that indicator on a 

weekly basis for four weeks. If flow is detected during any two of those four 

weeks, ExxonMobil shall install a carbon canister on that vent until appropriate 

corrective action(s) can be implemented to prevent such flow. Nothing in this 

Subparagraph shall require ExxonMobil to monitor conservation vents on fixed 

roof tanks; and 

iii. Conduct quarterly monitoring and repair of the oil-water separators consistent 

with the “no detectable emissions” provision in 40 C.F.R. § 61.347. 

b. By no later than 150 days after the Entry Date, ExxonMobil shall identify 

and mark at the drain all area drains that are segregated stormwater drains. 

113. Recordkeeping and Reporting Requirements for this Subsection V.N: 

Outside of the Reports Required under 40 C.F.R. § 61.357 and the Semi-Annual Reports 

Required by Section IX (Recordkeeping and Reporting). At the times specified in the 

applicable provisions of this Section V.N, ExxonMobil will submit, as and to the extent required, 

the following reports to EPA and the Applicable Co-Plaintiff: 

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i. BWON Compliance Review and Verification Reports (under Subparagraph 

100.a), as amended, if necessary (under Subparagraph 100.b); 

ii. Amended TAB Reports, if necessary (under Subparagraph 101.a); 

iii. BWON Corrective Measures Plans, if necessary (under Subparagraph 101.b 

and/or Paragraph 111); 

iv. Certifications of Compliance, if necessary (under Subparagraph 101.d); 

v. Reports certifying the completion of installation of dual carbon canisters (under 

Subparagraph 102.a); 

vi. Schematics of waste/slop/off-spec oil movements, as revised, if necessary (under 

Subparagraph 107.a); and 

vii. BWON Sampling Plans (under Subparagraphs 108.a and 109.a), and revised 

BWON Sampling Plans, if necessary (under Subparagraphs 108.b and 109.b). 

114. Recordkeeping and Reporting Requirements for this Subsection V.N: 

As Part of the Semi-Annual Reports Required by Section IX (Recordkeeping and 

Reporting). ExxonMobil shall submit the following information in the Semi-Annual Reports 

submitted pursuant to Section IX (Reporting and Recordkeeping) for the six month period 

covered by the Report: 

i. An identification of all laboratory audits, if any, completed during the six month 

period, including a description of the methods used in the audit and the results of 

the audit; 

ii. A description of the measures taken, if any, during the six month period to 

comply with the training provisions of Paragraph 106; and 

iii. A summary of the sampling results required under Paragraph 108, including the 

quarterly and projected annual uncontrolled benzene quantities or TAB, as 

applicable. 

O. LEAK DETECTION AND REPAIR PROGRAM ENHANCEMENTS. 

115. In order to minimize or eliminate fugitive emissions of volatile organic 

compounds (“VOCs”), benzene, volatile hazardous air pollutants (“VHAPs”), and organic 

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hazardous air pollutants (“HAPs”) from equipment in light liquid and/or in gas/vapor service, 

ExxonMobil shall undertake the enhancements identified in this Subsection V.O to its leak 

detection and repair (“LDAR”) programs for each of the Covered Refineries 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 of 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 regulations. 

116. Applicability of NSPS Subpart GGG to Process Units at the Covered 

Refineries. 

a. Covered Refineries Other than the Billings Refinery. As of the Entry Date 

for each of the Covered Refineries other than the Billings Refinery each existing “process unit” 

(as defined by 40 C.F.R. § 60.591) at each of those Covered Refineries shall become an 

“affected facility” for purposes of 40 C.F.R. Part 60, Subpart GGG, and shall become subject to 

and comply with the requirements of 40 C.F.R. Part 60, Subpart GGG, and the requirements of 

this Subsection V.O. 

b. Billings Refinery. 

(1) ExxonMobil shall comply with the requirements of 40 C.F.R. Part 

60, Subpart GGG, and the requirements of this Subsection V.O at each existing “process 

unit” (as defined by 40 C.F.R. § 60.591) at the Billings Refinery by no later than 180 

days after the Entry Date; provided, however, that ExxonMobil shall have two years from 

the Entry Date to comply with the standards for sampling connection systems set forth at 

40 C.F.R. § 60.482-5. 

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(2) Two years after the Entry Date, each existing process unit at the 

Billings Refinery shall become an affected facility for purposes of Subpart GGG, and 

shall become subject to and comply with the requirements of 40 C.F.R. Part 60, Subpart 

GGG, and the requirements of this Subsection V.O, including the standards for sampling 

connection systems set forth at 40 C.F.R. § 60.482-5. 

c. For the purposes of this Consent Decree, each process unit covered under 

this Paragraph shall be deemed to have become an affected facility for purposes of Subpart GGG 

under the provisions of 40 C.F.R. § 60.14 or § 60.15. These provisions specifically apply for the 

purposes of qualifying such affected facilities for any exemptions provided under 40 C.F.R. 

§§ 60.482-3(j), 60.482-7(h)(2), 60.482-10(k)(2), and 60.593(c). 

d. For process units that become affected facilities for purposes of Subpart 

GGG pursuant to this Paragraph 116 , entry of this Consent Decree shall satisfy applicable 

notification requirements of 40 C.F.R. § 60.7(a). 

117. Written Refinery-Wide LDAR Program Descriptions. By no later than 180 

days after the Entry Date, ExxonMobil shall develop and maintain a set of written LDAR 

Program Descriptions for a program for compliance with all federal, state, and local LDAR 

regulations applicable to each of the Covered Refineries. ExxonMobil shall update the LDAR 

Program Descriptions as may be necessary to ensure continuing compliance. The LDAR 

Program Descriptions shall include, at a minimum: 

i. A set of leak rate goals for each Covered Refinery that will be a target for 

achievement on a process-unit-by-process-unit basis. Such targets shall have the 

purpose of facilitating lower leak rates and are not intended to be enforceable 

requirements; 

ii. An identification of all equipment in light liquid and/or in gas/vapor service that 

is subject to periodic monitoring requirements via Method 21 under any 

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applicable federal, state, or local LDAR regulation and that has the potential to 

leak VOCs, HAPs, VHAPs, and benzene within each Covered Refinery’s process 

units; 

iii. Procedures for identifying leaking equipment within each Covered Refinery’s 

process units; 

iv. Procedures for repairing and keeping track of leaking equipment; 

v. Procedures for identifying and including new equipment to be added to the 

LDAR program; 

vi. A process for evaluating new and replacement equipment to promote 

consideration and installation of equipment that will minimize leaks and/or 

eliminate chronic leakers; 

vii. A description of each Covered Refinery’s LDAR monitoring organization and a 

designation of the person or position responsible for LDAR management and has 

the authority to implement LDAR improvements at the Refinery, as required by 

Paragraph 119; and 

viii. A procedure for regularly communicating LDAR information to appropriate 

ExxonMobil personnel. 

118. Training. By no later than 180 days after the Entry Date, ExxonMobil shall 

begin to implement a training program at each Covered Refinery which includes the following 

features: 

i. For personnel newly-assigned to LDAR responsibilities, ExxonMobil shall 

require LDAR training prior to each employee beginning such work; 

ii. For all personnel assigned LDAR responsibilities, ExxonMobil shall provide and 

require completion of annual LDAR training or require its LDAR contractor to 

provide such training (initial annual LDAR training for all such personnel will be 

completed not later than one year after the Entry Date); 

iii. For all other Refinery operations and maintenance personnel (including contract 

personnel) who have duties relevant to LDAR, ExxonMobil 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 such personnel will be completed not later than one year after the Entry 

Date); and 

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iv. For the individuals covered by this Paragraph, “refresher” training in LDAR shall 

be performed on a cycle of no longer than three years. 

119. LDAR Personnel. By no later than 180 days after the Entry Date, ExxonMobil 

shall establish a program that holds each person assigned LDAR responsibilities accountable for 

LDAR performance. By no later than 180 days after the Entry Date, ExxonMobil shall establish 

and maintain a person or position at each Covered Refinery with responsibility for LDAR 

management and authority to implement LDAR improvements at the Refinery. 

120. LDAR Audits. ExxonMobil shall implement Refinery-wide LDAR Audits – 

including an Initial LDAR Audit and Regular LDAR Audits – as set forth in this Paragraph to 

ensure each Covered Refinery’s compliance with all applicable LDAR requirements. Each 

LDAR Audit shall include, but shall not be limited to: (i) performing comparative monitoring; 

(ii) reviewing records to ensure monitoring and repairs were completed in the required periods; 

(iii) reviewing component identification procedures, tagging procedures, and data management 

procedures; and (iv) observing LDAR technicians’ calibration and monitoring techniques. 

During each LDAR Audit, leak rates shall be calculated for each process unit where comparative 

monitoring was performed. 

a. Initial LDAR Audit. ExxonMobil shall retain a third-party contractor to 

complete an Initial LDAR Audit for each Covered Refinery by no later than 365 days after the 

Entry Date. 

b. Initial Audit Report. Within 90 days of completion of the Initial Audit, 

ExxonMobil shall submit an Initial Audit Report to the EPA and the Applicable Co-Plaintiff. 

The Report shall describe the results of the Initial Audit, disclose all areas of identified noncompliance, and certify ExxonMobil’s compliance, except for the identified deficiencies. The 

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Report shall also include a schedule for correcting any identified deficiencies as soon as 

practicable. 

c. Regular LDAR Audits. 

(1) Third-Party Audits. ExxonMobil shall retain a contractor to 

perform a Third-Party LDAR Audit of each Covered Refinery’s LDAR program at least 

once every four (4) calendar years after the Initial LDAR Audit is completed under 

Subparagraph 120.a (with approximately 48 months between the Audits). 

(2) Internal Audits. ExxonMobil shall conduct Internal LDAR 

Audits of each Covered Refinery’s LDAR program by sending personnel familiar with 

the LDAR program and its requirements from one or more of ExxonMobil’s other 

Covered Refineries or locations to audit another Covered Refinery. ExxonMobil shall 

complete an Internal LDAR Audit by no later than two (2) years from the date of the 

completion of the third-party audits required in Subparagraphs 120.a and 120.c.(1). 

ExxonMobil will perform an Internal Audit of each Covered Refinery’s LDAR program 

at least once every four (4) calendar years (with approximately 48 months between the 

Audits). ExxonMobil may elect to retain third-parties to undertake an Internal Audit, 

provided that a Regular LDAR Audit at each Covered Refinery occurs every two (2) 

years. 

(3) Timing. To ensure that an LDAR Audit occurs every two (2) years 

at each Covered Refinery, once a Refinery’s Initial Audit is completed, the remaining 

Third-Party Audits and Internal Audits at that Refinery shall be separated by not more 

than two (2) calendar years (with approximately 24 months between the Audits). 

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121. Implementation of Actions Necessary to Correct Non-Compliance. If the 

results of any of the LDAR Audits conducted pursuant to Paragraph 120 identify any areas of 

noncompliance, ExxonMobil shall implement, as soon as practicable, all steps necessary to 

correct or otherwise address such area(s) of non-compliance and to prevent, to the extent 

practicable, a recurrence of the cause of such non-compliance. ExxonMobil shall, during the 

term of this Consent Decree, retain the Initial Audit Report and all other LDAR Audit reports 

generated pursuant to Paragraph 120, and shall maintain a written record of all corrective actions 

that ExxonMobil takes in response to deficiencies identified in any LDAR Audits. After the 

completion of any LDAR Audit other than the Initial Audit, ExxonMobil shall include the 

following information in the next Semi-Annual Report due under Section IX of this Consent 

Decree: (i) a summary, including findings, of each such LDAR Audit; and (ii) a list of corrective 

actions taken during the reporting period, and any schedule for implementing future corrective 

actions. 

122. Internal Leak Definition for Valves and Pumps. ExxonMobil shall utilize the 

following internal leak definitions for valves and pumps in light liquid and/or gas/vapor service, 

unless other permit(s), regulations, or laws require the use of lower leak definitions. 

a. Leak Definition for Valves. By no later than 365 days after the Entry Date 

for each Covered Refinery other than the Billings Refinery, and by no later than two (2) years 

after the Entry Date for the Billings Refinery, ExxonMobil shall utilize an internal leak 

definition of 500 ppm VOCs for valves in light liquid and/or gas/vapor service at Covered 

Refineries, excluding pressure relief devices. 

b. Leak Definition for Pumps. By no later than 365 days after the Entry Date 

for each Covered Refinery other than the Billings Refinery, and by no later than two (2) years 

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after the Entry Date for the Billings Refinery, ExxonMobil shall utilize an internal leak 

definition of 2000 ppm for centrifugal pumps at the Covered Refineries. Reciprocating pumps, 

connectors, compressors, and other components shall retain their applicable regulatory leak 

definition. 

123. LDAR Monitoring Frequency. 

a. Pumps. When the lower internal leak definition for pumps becomes 

applicable under Paragraph 122, and unless more frequent monitoring is required by applicable 

federal, state and/or local requirements, ExxonMobil shall monitor pumps at the internal leak 

definition on a monthly basis. 

b. Valves. When the lower internal leak definition for valves becomes 

applicable under Paragraph 122, and unless more frequent monitoring is required by applicable 

federal, state and/or local requirements, ExxonMobil shall monitor valves (other than difficult to 

monitor or unsafe to monitor valves) at the internal leak definition on a quarterly basis, with no 

ability to skip periods on a process-unit-by-process-unit basis. 

124. Reporting, Recording, Tracking, Repairing and Remonitoring Leaks of 

Valves and Pumps Based on the Internal Leak Definitions. 

a. Reporting. For regulatory reporting purposes, ExxonMobil 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 122. 

b. Recording, Tracking, Repairing and Remonitoring Leaks. ExxonMobil 

shall record, track, repair, and re-monitor all leaks in excess of the internal leak definitions of 

Paragraph 122 (at such time as those definitions become applicable). Except as provided 

otherwise in this Subsection V.O, ExxonMobil shall make a first attempt at repair and remonitor 

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the component within five (5) calendar days after a leak is detected and either complete repairs 

and re-monitor leaks or place such component on the Covered Refinery’s delay of repair list 

according to Paragraph 130 within thirty (30) days after a leak is detected. 

125. Monitoring After Turnaround or Maintenance. ExxonMobil shall have the 

option of monitoring affected valves and pumps within process unit(s) after completing a 

documented maintenance, startup, or shutdown activity, and that monitoring activity shall not 

count as a scheduled monitoring activity for any components found to be leaking at a level 

between the internal leak definition and the applicable regulatory definition, provided that 

ExxonMobil monitors according to the following schedule: 

i. For events involving 1000 or fewer valves and pumps, monitor within one (1) 

week of the 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 of the documented maintenance, startup, or 

shutdown activity; and 

iii. For events involving greater than 5000 pumps and valves, monitor within four (4) 

weeks of the documented maintenance, startup, or shutdown activity. 

126. Initial Attempt at Repair on Certain Valves. Beginning no later than 180 days 

after the Entry Date for each Covered Refinery other than the Billings Refinery, and beginning 

no later than two (2) years after the Entry Date for the Billings Refinery, ExxonMobil shall 

promptly make a “initial attempt” at repair after detecting a leak at a reading greater than 200 

ppm of VOCs at any valve, excluding pressure relief devices, control valves, valves that are on 

the delay of repair list, and components that LDAR personnel are not authorized to repair. 

ExxonMobil or its designated contractor shall re-monitor the valve in question within five (5) 

calendar days after the “initial attempt” to repair. If the re-monitored leak reading is below the 

applicable leak definition, no further action will be necessary. If the re-monitored leak reading is 

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greater than the applicable leak definition, ExxonMobil shall repair the valve according to the 

requirements of Subparagraph 124.b, except that no first repair attempt requirement shall apply. 

If ExxonMobil can demonstrate with sufficient, 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 

refinery leak rates, ExxonMobil may request EPA to reconsider or amend this requirement. 

127. Electronic Monitoring, Storing, and Reporting of LDAR Data. 

a. Electronic Storing and Reporting of LDAR Data. ExxonMobil has and 

shall continue to maintain an electronic database for storing and reporting LDAR data at each of 

the Covered Refineries. 

b. Electronic Data Collection During LDAR Monitoring and Transfer 

Thereafter. By no later than 90 days after the Entry Date for each Covered Refinery other than 

the Billings Refinery, and by no later than 150 days after the Entry Date for the Billings 

Refinery, ExxonMobil shall use data loggers and/or electronic data collection devices during all 

LDAR monitoring at the Covered Refineries. ExxonMobil, or its designated contractor, shall 

use its best efforts to transfer, by the end of the next business day, the electronic data from 

electronic data logging devices to the electronic database maintained pursuant to 

Subparagraph 127.a. For all monitoring events in which an electronic data collection device is 

used, the collected monitoring data shall include a time and date stamp, and identification of the 

instrument and operator. ExxonMobil may only use paper logs where necessary or more feasible 

(e.g., small rounds, re-monitoring, or when data loggers are unavailable or broken), and shall 

record, at a minimum, the identity of the technician, the date, the monitoring starting and ending 

times, all monitoring readings, and an identification of the monitoring equipment. ExxonMobil 

shall use its best efforts to transfer any manually recorded monitoring data to the electronic 

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database maintained pursuant to Subparagraph 127.a within seven (7) days of the monitoring 

event. 

128. QA/QC of LDAR Data. By no later than 90 days after the Entry Date for each 

Covered Refinery other than the Billings Refinery, and by no later than 150 days after the Entry 

Date for the Billings Refinery, ExxonMobil (or a third-party contractor retained by ExxonMobil) 

shall develop and implement procedures for quality assurance/quality control (“QA/QC”) 

reviews of all data generated by LDAR monitoring technicians. ExxonMobil shall ensure that 

monitoring data provided by monitoring technicians is reviewed daily for QA/QC. At least once 

per calendar quarter, ExxonMobil shall perform a QA/QC review of each contractor’s 

monitoring data which shall include, but not be limited to, a review of: (i) the number of 

components monitored per technician; (ii) the time between monitoring events; and 

(iii) abnormal data patterns. 

129. Calibration/Calibration Drift Assessment. 

a. Calibration. ExxonMobil shall conduct all calibrations of LDAR 

monitoring equipment at each of the Covered Refineries using methane as the calibration gas, 

and in accordance with 40 C.F.R. Part 60, EPA Reference Test Method 21. 

b. Calibration Drift Assessment. By no later than 365 days after the Entry 

Date, ExxonMobil shall conduct calibration drift assessment re-checks of the LDAR monitoring 

equipment at least twice during each monitoring shift, with one such re-check being at the end of 

the monitoring shift. ExxonMobil shall conduct the calibration drift assessment re-check using 

a calibration gas with a concentration approximately equal to the applicable internal leak 

definition. If any calibration drift assessment after the initial calibration shows a negative drift 

of more than 10% from the previous calibration, ExxonMobil shall remonitor all valves that 

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were monitored since the last calibration or calibration drift assessment that had a reading 

greater than 100 ppm and shall remonitor all pumps that were monitored since the last 

calibration or calibration drift assessment that had a reading greater than 500 ppm. 

130. Delay of Repair. 

a. By no later than 90 days after the Entry Date, ExxonMobil shall take the 

following actions for any equipment at any Covered Refinery that ExxonMobil intends to place 

on the “delay of repair” list, under applicable regulations: 

i. ExxonMobil shall require sign-off by the unit supervisor, within thirty (30) days 

of identifying that a piece of equipment is leaking at a rate greater than the 

applicable leak definition, that such equipment qualifies for delayed repair under 

applicable regulations; 

ii. ExxonMobil shall include equipment that is placed on the “delay of repair” list in 

ExxonMobil’s regular LDAR monitoring; 

iii. ExxonMobil shall use its best efforts to isolate and repair centrifugal pumps 

identified as leaking at a rate of 2000 ppm or greater; and 

iv. For valves (other than control valves and pressure relief devices) leaking at 

10,000 ppm or greater and which cannot be repaired using traditional techniques, 

ExxonMobil shall use the “drill and tap” repair method (or an equivalent repair 

method) for the leaking valve (unless the valve is isolated from the process and 

does not remain in VOC service), prior to placing the valve on the delay of repair 

list, unless ExxonMobil can demonstrate that there is a safety, mechanical, or 

major environmental concern posed by repairing the leak in that manner. If not 

repaired within 15 days by other means, ExxonMobil shall perform the first “drill 

and tap” (or equivalent repair method) within 15 days, and a second attempt (if 

necessary) within 30 days after the leak is detected. After two unsuccessful 

attempts to repair a leaking valve through the “drill and tap” (or equivalent) 

method, ExxonMobil may place the leaking valve on its “delay of repair” list. 

The requirement to make two attempts to repair a leaking component by the drill 

and tap method may be satisfied by making two sealant injection attempts rather 

than by making multiple taps into the valve body. 

b. If a new valve repair method not currently in use by the refining industry 

is planned to be used by ExxonMobil in lieu of the “drill and tap” method referenced in the 

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preceding Subparagraph, ExxonMobil shall advise EPA prior to implementing such a method or, 

if prior notice is not practicable, as soon as practicable after implementation. 

131. Chronic Leakers. A valve shall be classified as a “chronic leaker” under this 

Paragraph if it leaks above 5,000 ppm twice in any consecutive four quarters after the Entry 

Date, unless the valve has not leaked in the twelve (12) consecutive quarters prior to the relevant 

process unit turnaround. Following the identification of a “chronic leaker” non-control valve, 

ExxonMobil shall replace, repack, or perform similarly effective repairs on the chronic leaker 

during the next process unit turnaround occurring 180 days after the after the Entry Date. 

132. Alternate Leak Detection Method. With EPA’s prior written approval, 

ExxonMobil may begin using an alternate leak detection method – such as a method employing 

“Smart LDAR” technology – based on a showing that the alternate leak detection method is 

equivalent to traditional monitoring methods and is allowable under the applicable LDAR 

regulations. If necessary to implement this Paragraph, the Parties shall make appropriate 

modifications to this Consent Decree in accordance with Paragraph 269. 

133. Recordkeeping and Reporting Requirements for this Section. 

a. In the Semi-Annual Reports submitted by ExxonMobil pursuant to 

Section IX (Recordkeeping and Reporting), ExxonMobil shall include the following information 

in the Report for the period in which the identified activity occurred or was required: 

i. A copy of each Covered Refinery’s LDAR Program Description under Paragraph 

117; 

ii. A certification that each Covered Refinery’s training program has been 

implemented as required by Paragraph 118; 

iii. An identification of the person or position at each Covered Refinery responsible 

for LDAR performance as required by Paragraph 119; 

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iv. A certification that the lower leak definitions and increased monitoring 

frequencies have been implemented according to Paragraphs 122 and 123; 

v. A certification of the implementation of the “initial attempt” to repair program 

under Paragraph 126; 

vi. A certification of the implementation of QA/QC procedures for review of data 

generated by LDAR technicians as required by Paragraph 128; 

vii. A certification of the implementation of the calibration drift assessment 

procedures of Paragraph 129; and 

viii. A certification of the implementation of the “delay of repair” procedures of 

Paragraph 130. 

b. Special Requirement for Initial Semi-Annual Report Each Year. As part 

of the first Semi-Annual Report submitted each year pursuant to Section IX (Recordkeeping and 

Reporting), ExxonMobil shall identify each LDAR Audit that was conducted at each Covered 

Refinery under Paragraph 120 in the previous calendar year, including an identification of the 

auditors, a summary of the audit results, and the actions that ExxonMobil took or intends to take 

to correct identified deficiencies. 

c. Reports Due Under 40 C.F.R. § 63.654. In each report due under 40 

C.F.R. § 63.654, ExxonMobil shall include the following information on LDAR monitoring at 

the relevant Covered Refinery: 

i. a list of the process units monitored during the reporting period; 

ii. the number of valves and pumps present in each process unit; 

iii. the number of valves and pumps monitored in each process unit; 

iv. the number of valves and pumps found leaking for each process unit; 

v. the number of “difficult to monitor” pieces of equipment monitored; 

vi. the projected month and year of the next monitoring event for that unit; 

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vii. a list of all equipment currently on the “delay of repair” list and the date each 

component was placed on the list; 

viii. the number of repairs not attempted within five (5) days and thirty (30) days 

pursuant to Subparagraph 124.b; 

ix. the number of initial attempts at repair not made promptly and remonitored within 

five (5) days pursuant to Paragraph 126; 

x. the number of repairs not completed at the next process unit turnaround pursuant 

to Paragraph 131; and 

xi. the number of repairs not completed within fifteen (15) days and thirty (30) days 

under Subparagraph 130.a.iv. 

P. OTHER COMPLIANCE PROGRAM REQUIREMENTS APPLICABLE 

TO THE BILLINGS AND JOLIET REFINERIES. 

134. Joliet Wastewater Treatment Plant Area Program Requirements. ExxonMobil 

shall comply with the Joliet Wastewater Treatment Plant Area Program requirements specified in 

Appendix P to this Consent Decree. 

135. Joliet Material Staging Area. 

a. By no later than the Entry Date, ExxonMobil shall use the Material 

Staging Area (also known as the BRU Decant Pad) at the Joliet Refinery primarily for 

management of oil-bearing hazardous secondary materials subject to 40 C.F.R. § 261.4(a)(12) 

and Ill. Admin. Code tit. 35, § 721.104(a)(12)(A) , and shall not use the Material Staging Area 

for treatment, storage or disposal of materials that meet the definition of hazardous waste under 

40 C.F.R. § 261.3 and Ill. Admin Code tit. 35, § 721.103. The location of the Material Staging 

Area is identified on the drawing attached as Appendix T to this Consent Decree. 

b. As provided by 40 C.F.R. § 261.4(a)(12) and Ill. Admin. Code tit. 35, 

§ 721.104(a)(12)(A), oil-bearing hazardous secondary materials transferred to the Material 

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Staging Area shall not be placed on the land and shall not be accumulated speculatively before 

being recycled. 

c. ExxonMobil shall clean the Material Staging Area bays to remove 

hydrocarbon residue as required by usage, but no less than once every 90 days. Whenever the 

bays are cleaned, ExxonMobil shall inspect the areas around the Material Staging Area to 

confirm that oil-bearing hazardous secondary materials have not been released from the Material 

Staging Area. 

d. As provided by 40 C.F.R. § 261.4(a)(12) and Ill. Admin. Code tit. 35, 

§ 721.104(a)(12)(A), any residuals generated from processing or recycling oil-bearing hazardous 

secondary materials at the Material Staging Area that are disposed of or intended for disposal 

shall be designated and managed as F037 listed wastes when they are removed from the Material 

Staging Area. If any oil-bearing hazardous secondary materials are released from the Material 

Staging Area and not immediately recovered for use in a refining process, then ExxonMobil 

shall designate and manage such released materials as F037 listed wastes. 

e. If ExxonMobil uses the Material Staging Area for management of waste 

materials that do not meet the definition of hazardous waste under 40 C.F.R. § 261.3 and Ill. 

Admin Code tit. 35, § 721.103, then ExxonMobil shall segregate such waste materials and shall 

not commingle such waste materials with any oil-bearing hazardous secondary materials. 

f. ExxonMobil shall establish and implement written procedures designed to 

ensure that the Material Staging Area is used only for management of materials described in 

Subparagraphs 135.a and 135.e. The procedures shall include use of a written form to document 

all material transfers to the Material Staging Area, including an indication of the material type, 

the material quantity, the source of the material, the request and authorization dates, and the 

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names of the requester and the individual authorizing the transfer at the Joliet Refinery 

(“Material Staging Area Transfer Forms”). With each WWTP Area Wastewater Monitoring 

Plan Quarterly Report required under Paragraph 4 of Consent Decree Appendix P, ExxonMobil 

shall include a copy of each Material Staging Area Transfer Form completed and used for the 

transfer of material to the Material Staging Area during that quarterly period. With the WWTP 

Area Wastewater Monitoring Plan Final Report, ExxonMobil shall include a copy of each 

Material Staging Area Transfer Form completed and used for the transfer of material to the 

Material Staging Area for the final quarter of the Monitoring Period. 

g. As required by 40 C.F.R. § 261.2(f) and Ill. Admin. Code tit. 35, 

§ 721.102(f), ExxonMobil shall maintain appropriate documentation demonstrating that oilbearing hazardous secondary materials are being managed in the Material Staging Area in 

accordance with all requirements imposed by 40 C.F.R. § 261.4(a)(12) and Ill. Admin. Code tit. 

35, § 721.104(a)(12)(A). 

136. Joliet RCRA Training Requirements. By no later than the Entry Date, 

ExxonMobil shall provide to EPA for review and comment a copy of the following: 

i. The syllabus for the Joliet Refinery’s current RCRA training program given to all 

Refinery employees involved in hazardous waste management at the Joliet 

Refinery; 

ii. Completion records from employee RCRA training sessions held at the Joliet 

Refinery during calendar years 2003 and 2004; and 

iii. The procedure that will be used at the Joliet Refinery to ensure that contractors 

who perform work at the Joliet Refinery that involves the management of 

hazardous waste have had RCRA training. 

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137. Billings Refinery Scrap Yard and Laydown Areas. 

a. Within 90 days of the Entry Date, ExxonMobil shall designate both the 

Scrap Yard and the Laydown Areas (the precise location and area of the Scrap Yard and the 

Laydown Areas is defined in the drawing attached to this Consent Decree as Appendix S) as 

Solid Waste Management Units and/or Areas of Concern under the current Billings Refinery 

RCRA permit (Montana Hazardous Waste Permit, MTHWP-99-02). Pursuant to the Montana 

administered RCRA program ExxonMobil shall complete a RCRA Corrective Action process for 

the Scrap Yard and Laydown Areas, including investigating the nature and extent of all releases 

(including, but not limited to, releases from heat exchanger bundles), and performing necessary 

remediation, if any. 

b. ExxonMobil shall submit to EPA all documentation related to: (1) the 

designation of the Scrap Yard and the Laydown Areas as Solid Waste Management Units and/or 

Areas of Concern; and (2) any subsequent corrective action at the Scrap Yard and the Laydown 

Areas. The information shall be submitted to EPA at the same time the information is submitted 

to the Applicable Co-Plaintiff. 

c. Within 90 days of the Entry Date, ExxonMobil shall propose to EPA for 

review and approval modifications to its Billings Stormwater Pollution Prevention Plan 

(“SWPPP”) including: 

i. Standard operating procedures to assure that no hazardous wastes, as defined by 

RCRA, are placed in the Scrap Yard and the Laydown Areas; 

ii. A comprehensive list of the types of material that may be placed in Scrap Yard 

and Laydown Areas; and 

iii. Assigning direct responsibility for compliance with the new standard operating 

procedures regarding the Scrap Yard and the Laydown Areas and for all other 

SWPPP elements to an ExxonMobil employee. 

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Within 60 days of EPA’s approval of the modification of the Billings SWPPP, ExxonMobil shall 

revise its SWPPP to incorporate the approved provisions. 

138. Billings Refinery Land Treatment Unit. Within 90 days of the Entry Date, 

ExxonMobil shall submit to EPA for review and approval proposed amendments to its Billings 

Refinery RCRA permit (Montana Hazardous Waste Permit, MTHWP-99-02) related to waste 

application at the Land Treatment Unit (the precise location and area of the Land Treatment Unit 

is defined in the drawing attached to the Consent Decree as Appendix S). The proposed 

revisions shall include: 

i. A prohibition against waste application at the Land Treatment Unit when either: 

(1) the average hourly wind speed exceeds 10 mph for any 15 consecutive minute 

period, or (2) when maximum daily gusts exceed 20 mph for a 5 consecutive 

minute period; provided, however that waste application may be resumed if the 

conditions in (1) and (2) have not occurred for a period of 60 consecutive minutes 

prior to the time of resumption of waste application; 

ii. A requirement to maintain a system capable of measuring and transmitting wind 

conditions at the Refinery to ExxonMobil personnel necessary for compliance 

with the prohibition set forth in Subparagraph 138.i; and 

iii. Standard operating procedures to assure compliance with the soil moisture 

requirements applicable to the Land Treatment Unit (Montana Hazardous Waste 

Permit, MTHWP-99-02, Section III.a.E.7). 

139. Billings Refinery Outfall 002. 

a. Within 90 days of the Entry Date, ExxonMobil shall propose to EPA for 

review and approval draft amendments to the oil sheen provisions for Outfall 002 of its Billings 

Refinery Montana Pollutant Discharge Elimination System Permit ((MPDES)(MT-0000477)), 

including: 

i. A detailed procedure for the monitoring and detection of oil sheen events, 

including but not limited to, the use of an infrared monitoring system or 

equivalent; 

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ii. Requirements for maintaining proper calibration of sheen detection equipment, 

including, but not limited to, the infrared monitoring system or equivalent; and 

iii. Formal procedures for investigating the cause of oil sheen exceedances that reach 

the river. 

b. Upon EPA approval of the proposed MPDES Outfall 002 oil sheen permit 

modifications, ExxonMobil shall within 60 days submit an application to the Applicable CoPlaintiff to include the modifications in the Billings Refinery MPDES permit. 

140. Billings Refinery Tank 350. 

a. By no later than 90 days after the Entry Date, ExxonMobil shall 

discontinue placement of wastewater and/or other material in Billings Refinery Tank 350 using 

trucks or other non-piped methods (“Non-Piped Tank 350 Inflow”). 

b. Within 90 days of the Entry Date, ExxonMobil shall propose to EPA for 

review and approval a draft amendment to its Billings Refinery Montana Pollutant Discharge 

Elimination System Permit ((MPDES)(MT-0000477)) that is designed to prohibit Non-Piped 

Tank 350 Inflow. The proposed permit amendment will specify that Tank 350 shall receive only 

effluent that is piped from the API Separator outlet. 

c. Upon EPA approval of the proposed permit modification relating to Tank 

350, ExxonMobil shall within 60 days submit an application to the Applicable Co-Plaintiff to 

include the amendment to the Billings Refinery MPDES permit. 

d. Within 90 days of the Entry Date, ExxonMobil shall submit to EPA a 

description of how wastewaters and/or other material that currently are Non-Piped Tank 350 

Inflow will be managed at the Billings Refinery. 

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Q. INCORPORATION OF CONSENT DECREE REQUIREMENTS INTO 

FEDERALLY ENFORCEABLE PERMITS. 

141. Emission Limits and Standards Effective on the Entry Date. By no later than 

120 days after the Entry Date, ExxonMobil shall submit administratively complete applications 

to the applicable federal, state or local agency to incorporate the emission limits and standards, 

including NSPS applicability, required by this Consent Decree that are effective as of the Entry 

Date into federally-enforceable minor or major new source review permits or other permits that 

will ensure that the underlying emission limits and standards survive the termination of this 

Consent Decree in accordance with Paragraph 145. In light of the permitting program in the 

State of Louisiana, ExxonMobil shall submit to LDEQ’s consolidated permitting program, under 

the time frame specified by the previous sentence, appropriate applications, amendments and/or 

supplements to ensure that the emission limits and standards that are effective as of the Entry 

Date under this Consent Decree shall survive the termination of this Consent Decree in 

accordance with Paragraph 145. Following submission of the complete permit applications (or, 

for the Baton Rouge Refinery, following submission of appropriate applications, amendments, or 

supplements), ExxonMobil shall cooperate with the applicable federal, state or local agency by 

promptly submitting to the applicable agency all available information that the applicable agency 

seeks following its receipt of the permit materials. Promptly upon issuance of such permits or in 

conjunction with such permitting, ExxonMobil shall file any applications necessary to 

incorporate the requirements of those permits into the Title V permit for the relevant Covered 

Refinery. 

142. Future Emission Limits and Standards. As soon as practicable, but in no event 

later than ninety (90) days after the effective date or establishment of any emission limit or 

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standard under Section V that become effective after the Entry Date, ExxonMobil shall submit 

administratively complete applications to the applicable federal, state or local agency to 

incorporate that emission limit or standard into federally-enforceable minor or major new source 

review permits or other permits that will ensure that the underlying emission limit or standard 

survives the termination of this Consent Decree in accordance with Paragraph 145. In light of 

the permitting program in the State of Louisiana, ExxonMobil shall submit to LDEQ’s 

consolidated permitting program, under the time frame specified by the previous sentence, 

appropriate applications, amendments and/or supplements to ensure that the emission limits and 

standards that become effective after the Entry Date shall survive the termination of this Consent 

Decree in accordance with Paragraph 145. Following submission of the complete permit 

applications (or, for the Baton Rouge Refinery, following submission of appropriate 

applications, amendments, or supplements), ExxonMobil shall cooperate with the applicable 

federal, state or local agency by promptly submitting to the applicable agency all available 

information that the applicable agency seeks following its receipt of the permit materials. 

Promptly upon issuance of such permits or in conjunction with such permitting, ExxonMobil 

shall file any applications necessary to incorporate the requirements of those permits into the 

Title V permit for the relevant Covered Refinery. 

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

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

permits under Paragraphs 141 and 142: 

i. the interim emission limits and standards imposed by Subparagraphs 16.b, 29.a, 

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

applies under this Consent Decree; and 

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

shall survive termination of the Consent Decree. 

144. Mechanism for Title V Incorporation. The Parties agree that the incorporation 

of the requirements of this Consent Decree into Title V permits shall be in accordance with state 

Title V rules, including applicable administrative amendment provisions of such rules. 

145. Obligations that Shall Survive Consent Decree Termination. The 

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

termination of the Consent Decree under Section XVIII: 

a. Emission Limits and Standards. The following Consent Decree 

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

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

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

Paragraph 21in Subsection V.B; 

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

Paragraph 32 in Subsection V.C; 

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

in Subsection V.D; 

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

42 in Subsection V.E; 

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

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

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

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

Subsection V.I; and 

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

b. Certain Other Requirements 

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

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

specified therein) in Subsection V.K; 

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

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

(5) All of Section VI. 

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

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

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

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

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

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

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

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

146. Obtaining Construction Permits. ExxonMobil agrees to use its best efforts to 

obtain all required, federally-enforceable permits for the construction of the pollution control 

technology and/or the installation of equipment necessary to implement the affirmative relief and 

environmental projects set forth in Section V and in Section VIII. To the extent that 

ExxonMobil must submit permit applications for construction or installation to an applicable 

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state or local agency, ExxonMobil shall cooperate with the applicable state or local agency by 

promptly submitting to the applicable state or local agency all available information that the 

applicable state or local agency seeks following its receipt of the permit application. This 

Paragraph 146 is not intended to prevent ExxonMobil from applying to the applicable state or 

local agency for a pollution control project exemption. 

VI. EMISSION CREDIT GENERATION 

147. Summary. This Section addresses the use of emissions reductions that will result 

from the installation and operation of the controls required by this Consent Decree (“CD 

Emissions Reductions”) for the purpose of emissions netting or emissions offsets. It allows 

ExxonMobil to use a fraction of the CD Emissions Reductions if: (1) the emissions units for 

which ExxonMobil seeks to use the CD Emissions Reductions are modified or constructed for 

purposes of compliance with Tier II gasoline or low sulfur diesel requirements; and (2) the 

emissions from those modified or newly-constructed units are at or below the levels outlined in 

Paragraph 149(2). 

148. General Prohibition. ExxonMobil shall not generate or use any NOx, SO2, PM, 

VOC, or CO emissions reductions, or apply for and obtain any emission reduction credits, 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 synthetic minor 

New Source Review (“NSR”) permit or permit proceeding. 

149. Exception to General Prohibition. Notwithstanding the general prohibition set 

forth in Paragraph 148, ExxonMobil may use 186 tons per year of NOx, 240 tons per year of 

SO2, 38 tons per year of PM, 44 tons per year of CO, and 5 tons per year of H2SO4, from the CD 

Emissions Reductions as credits or offsets in any PSD, major non-attainment and/or synthetic 

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minor NSR permit or permit proceeding occurring after the Date of Lodging of the Consent 

Decree, provided that the new or modified emissions unit: (1) is being constructed or modified 

for purposes of compliance with Tier II gasoline or low sulfur diesel requirements; and (2) has a 

federally enforceable, non-Title V Permit with the following limits, as applicable: 

i. For heaters and boilers, a limit of 0.020 lbs NOx per million BTU or less on a 

3-hour rolling average basis; 

ii. For heaters and boilers, a limit of 0.10 grains of hydrogen sulfide per dry standard 

cubic foot of fuel gas or 20 ppmvd SO2 corrected to 0% O2 both on a 3-hour 

rolling average; 

iii. For heaters and boilers, no Fuel Oil burning or solid fuel firing capability; 

iv. For FCCUs, a limit of 20 ppmvd NOx corrected to 0% O2 or less on a 365-day 

rolling average basis; 

v. For FCCUs, a limit of 25 ppmvd SO2 corrected to 0% O2 or less on a 365-day 

rolling average basis; and 

vi. For SRPs, NSPS Subpart J emission limits. 

Utilization of the exception set forth above is subject to each of the following conditions: 

i. Under no circumstances shall ExxonMobil 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; 

iii. The CD Emissions Reductions provisions of this Consent Decree are for purposes 

of this Consent Decree only and neither ExxonMobil nor any other entity may use 

CD Emissions Reductions for any purpose, including in any subsequent 

permitting or enforcement proceeding, except as provided herein; and 

iv. ExxonMobil still shall be subject to all federal and state regulations applicable to 

the PSD, major non-attainment and/or minor NSR permitting process. 

150. Outside the Scope of the General Prohibition. Nothing in this Consent Decree 

is intended to prohibit ExxonMobil from seeking to: 

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i. utilize or generate netting reductions or emission offset credits from refinery units 

that are covered by this Consent Decree to the extent that the proposed netting 

reductions or emission offset credits represent the difference between the 

emissions limitations set forth in or established pursuant to this Consent Decree 

for these refinery units and the more stringent emissions limitations that 

ExxonMobil may elect to accept for these refinery units in a permitting process; 

ii. utilize or generate netting reductions or emission offset credits for refinery units 

that are not subject to an emission limitation pursuant to this Consent Decree; 

iii. utilize or generate netting reductions or emission offset credits for Combustion 

Units on which Qualifying Controls, as defined in Paragraph 46, have been 

installed, provided that such reductions are not included in ExxonMobil’s 

demonstration of compliance with the requirements of Paragraphs 15.c, 47, or 50 

of this Consent Decree; 

iv. utilize emissions reductions from the installation of controls required by this 

Consent Decree in determining whether a project that includes both the 

installation of controls under this Consent Decree and other construction that 

occurs at the same time and is permitted as a single project triggers major New 

Source Review requirements; 

v. utilize CD Emission Reductions for a Covered Refinery’s compliance with any 

rules or regulations designed to address regional haze or the non-attainment status 

of any area (excluding PSD and Non-Attainment New Source Review rules, but 

including, for example, RECLAIM and the Houston/Galveston Area NOx SIP) 

that apply to the particular Covered Refinery; provided, however, that 

ExxonMobil shall not be allowed to trade or sell any CD Emissions Reductions; 

or 

vi. utilize any emission reduction credits recognized under two permits previously 

issued to ExxonMobil, namely: (1) the Baton Rouge Refining Clean Air 

Commitment PSD-LA-667(M-1) and Catalytic Cracking Permit Number 

2385-V1; and (2) the IEPA Construction Permit for the Joliet Coker Blowdown 

Recovery Project (Application Number 03060091). 

VII. MODIFICATIONS TO IMPLEMENTATION SCHEDULES 

151. Modifications Relating to Securing Permits or Approvals (in States Where 

Permits are Characterized as “Approvals”). 

a. Timely Submitting Complete Permit Applications and Exercising Best 

Efforts. For any work under Sections V or VIII of this Consent Decree that requires a federal, 

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state and/or local permit or approval (including but not limited to air or wastewater permits or 

approvals), ExxonMobil shall be responsible for submitting in a timely fashion applications for 

federal, state and local permits and approvals for work and activities required so that permit or 

approval decisions can be made in a timely fashion. ExxonMobil shall use its best efforts 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 of permits 

after filing the applications, including timely supplying additional information, if requested. 

b. Notification. If it appears that the failure of a governmental entity to act 

upon a timely-submitted, complete permit application may delay ExxonMobil’s performance of 

work according to an applicable implementation schedule, ExxonMobil will notify the EPA and 

the Applicable Co-Plaintiff of any such delays as soon as ExxonMobil reasonably concludes that 

the delay could affect its ability to comply with the implementation schedule set forth in this 

Consent Decree. ExxonMobil shall propose for approval by EPA a modification to the 

applicable schedule of implementation setting out the time necessary to comply after the permit 

or approval has been received by ExxonMobil. EPA, after an opportunity for consultation with 

the Applicable Co-Plaintiff, shall not unreasonably withhold its consent to requests for 

modifications of schedules of implementation if the requirements of this Paragraph 151 are met. 

c. Stipulated Penalties Inapplicable. 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; provided, however, that if EPA does not approve a 

modification to a date or dates then: (i) EPA and the Applicable Co-Plaintiff will retain the right 

to seek stipulated penalties; and (ii) ExxonMobil will retain the right to dispute any demand for 

stipulated penalties, pursuant to Paragraph 215. 

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d. Force Majeure Inapplicable. The failure of a governmental entity to act 

upon a timely-submitted permit or approval application shall not constitute a force majeure event 

triggering the requirements of Section XIV; instead, this Paragraph 151 shall apply. 

152. Modifications Relating to Securing EPA Approval under this Consent 

Decree. 

a. For requirements of this Decree where ExxonMobil is prohibited from 

commencing an action prior to receiving EPA approval, ExxonMobil will use its best efforts to 

submit materials that comply with all applicable requirements of this Consent Decree and to 

ensure EPA’s timely response to the applicable submission. If it appears that the failure by EPA 

to timely provide an approval that is a condition precedent to subsequent action(s) will delay 

ExxonMobil’s performance of subsequent action(s), ExxonMobil and EPA will modify all 

relevant deadlines as appropriate in light of the delay. If EPA fails to timely act on a 

modification(s) required by this Subparagraph, stipulated penalties will not accrue for the period 

up to and including the earlier of: (i) the modified date(s) that EPA eventually determines; or 

(ii) the modified date(s) that this Court establishes if ExxonMobil pursues dispute resolution 

under Section XV. 

b. For requirements of this Consent Decree that are subject to EPA approval 

but for which ExxonMobil’s subsequent actions are not expressly conditioned upon receipt of 

EPA approval, ExxonMobil will commence and continue with such subsequent actions even 

without receipt of EPA approval. If, during the course of such continuing ExxonMobil actions, 

EPA disapproves in whole or in part of the manner in which ExxonMobil has proceeded, 

extensions of all relevant deadlines may result by agreement of the parties. Stipulated penalties 

will not accrue nor be due and owing during any period between a scheduled implementation 

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date and an approved modification to such date; provided, however, that if EPA does not 

approve a modification to a date or dates then: (i) EPA and the Applicable Co-Plaintiff will 

retain the right to seek stipulated penalties; and (ii) ExxonMobil will retain the right to dispute 

any demand for stipulated penalties, pursuant to Paragraph 215. 

c. Force Majeure Inapplicable. The failure of EPA to provide a required 

approval in a timely manner will not constitute a force majeure event triggering the requirements 

of Section XIV; instead, this Paragraph 152 shall apply. 

153. Modifications Relating to Commercial Unavailability of Control Equipment 

and/or Additives. 

a. ExxonMobil’s General Obligation. ExxonMobil shall be solely 

responsible for compliance with any deadline or the performance of any work described in 

Sections V and VIII of this Consent Decree that requires the acquisition and installation of 

control equipment, including SO2 Reducing Catalyst Additive or NOx Additives. 

b. Notification. If it appears that the commercial unavailability of any 

control equipment may delay ExxonMobil’s performance of work according to an applicable 

implementation schedule, ExxonMobil shall notify EPA and the Applicable Co-Plaintiff of any 

such delays as soon as practicable after ExxonMobil reasonably concludes that the delay could 

affect its ability to comply with the implementation schedule set forth in this Consent Decree. 

ExxonMobil shall then contact a reasonable number of vendors of such equipment or additive 

and obtain (or request) a written representation (or equivalent communication to EPA) from the 

vendor that the equipment or additive is commercially unavailable. 

c. Additional Notice Requirements and Requirements Relating to Contacting 

Vendors. ExxonMobil shall propose for approval by EPA a modification to the applicable 

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schedule of implementation, refer to this Paragraph 153 of this Consent Decree, identify the 

milestone date it contends it will not be able to meet, provide EPA and the Applicable CoPlaintiff with written correspondence to the vendor identifying efforts made to secure the control 

equipment or catalyst additive, and describe the specific efforts ExxonMobil has taken and will 

continue to take to find such equipment or additive. ExxonMobil may propose a modified 

schedule or modification of other requirements of this Consent Decree to address such 

commercial unavailability. 

d. Dispute Resolution. Section XV (Retention of Jurisdiction/Dispute 

Resolution) shall govern the resolution of any claim of commercial unavailability. EPA, after an 

opportunity for consultation with the Applicable Co-Plaintiff, shall not unreasonably withhold its 

consent to requests for modifications of schedules of implementation if the requirements of this 

Paragraph are met. 

e. Stipulated Penalties Inapplicable. 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; provided, however, that if EPA does not approve a 

modification to a date or dates then: (i) EPA and the Applicable Co-Plaintiff will retain the right 

to seek stipulated penalties; and (ii) ExxonMobil will retain the right to dispute any demand for 

stipulated penalties, pursuant to Paragraph 215. 

f. Force Majeure Inapplicable. The failure of ExxonMobil to secure control 

equipment or additives will not constitute a force majeure event triggering the requirements of 

Section XIV; instead, this Paragraph shall apply. 

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154. Procedures for Modifying Implementation Schedules under this Section VII. 

Any modifications to implementation schedules under this Section VII shall be made in 

accordance with Paragraph 269. 

VIII. ENVIRONMENTALLY BENEFICIAL PROJECTS 

155. In accordance with the requirements and schedule set forth in this Section VIII, 

ExxonMobil shall pay $6,700,000 to implement Supplemental Environmental Projects (“SEPs”) 

and Beneficial Environmental Projects (“BEPs”), as described below. 

156. Supplemental Environmental Projects. 

a. Performance of SEPs. ExxonMobil may carry out its responsibilities for 

the SEPs required by this Paragraph directly or through contractors or other third-parties selected 

by ExxonMobil. 

b. The Smart LDAR Project. By no later than December 31, 2007, 

ExxonMobil shall perform a SEP designed to demonstrate and evaluate the use of Smart LDAR 

imaging equipment in identifying and quantifying emissions from leaking components and other 

sources of fugitive VOC emissions at the Baytown Refinery, at a cost of no less than $250,000 

(the “Smart LDAR Project”). 

(1) Within 90 days of the Entry Date, ExxonMobil shall submit a plan 

for the Smart LDAR Project, which shall be subject to EPA review and approval. The 

plan shall include a proposal for: (i) comparative monitoring, to compare the results 

achieved with at least one Smart LDAR imaging camera against the results achieved 

through traditional Method 21 monitoring; and/or (ii) “bag” testing, to quantify the mass 

of VOC emissions from one or more leaking components monitored with a Smart LDAR 

imaging camera. The plan shall also include a description of the project’s overall 

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objective(s), the procedures to be followed, a project budget (detailing expected 

equipment costs, laboratory costs, and contractor costs), and a schedule for performing 

and completing the project. 

(2) Upon receipt of EPA approval, ExxonMobil shall implement the 

plan for the Smart LDAR Project according to the schedule provided in the approved 

plan. 

c. Diesel Emissions Reduction Projects. By no later than December 31, 

2009, ExxonMobil shall spend no less than $1,300,000 in performing diesel emissions reduction 

SEPs in accordance with the criteria, terms, and procedures specified in Appendix Q of this 

Consent Decree. 

d. Midewin National Tallgrass Prairie Restoration Project. By no later than 

December 31, 2009, ExxonMobil shall perform one or more prairie habitat restoration projects at 

the Midewin National Tallgrass Prairie that will require in-kind contributions and expenditures 

of $1,050,000 or more, as described by this Subparagraph 156.d. 

(1) By no later than December 31, 2007, ExxonMobil shall take all 

actions required to donate the parcel of property identified on the drawing attached as 

Appendix R (comprising approximately 39 acres, and referred to in this Subparagraph as 

the “Property”) to the United States, so that the parcel can be added to the Midewin 

National Tallgrass Prairie managed by the U.S. Department of Agriculture, Forest 

Service. ExxonMobil may condition the donation upon the United States’ acceptance of 

the Property subject to the following deed restrictions: 

“The land shall only be used and managed to conserve and enhance the 

native populations and habitats of fish, wildlife, and plants as part of the 

Midewin National Tallgrass Prairie, and to provide opportunities for 

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associated research, in accordance with the Illinois Land Conservation Act 

of 1995 (Public Law 104–106, Title XXIX, section 2901, et seq.) and shall 

not be used for residential or commercial development.” 

(2) The Property shall be conveyed by ExxonMobil by general 

warranty deed to the “United States of America and its assigns,” and title thereto shall be 

acceptable to the Secretary of Agriculture in accordance with title standards of the 

Attorney General of the United States. 

(3) Within 120 days prior to the proposed date of closing, ExxonMobil 

will provide the Forest Service with all available environmental studies and remediation 

reports relating to the Property; all available title, survey, and other land records relating 

to the Property; and any other available documentation pertaining to the title, upkeep, 

maintenance or similar records relating to the Property. 

(4) The United States, through the Forest Service, has the option to 

either accept or decline the conveyance of the Property for reasons of its environmental 

condition, title, or other reason in the discretion of the Forest Service. 

(5) If the United States accepts the property donation and the 

associated deed restrictions, ExxonMobil will be credited with providing an $800,000 

in-kind contribution (hereinafter the “In-Kind Contribution Amount”). If the United 

States notifies ExxonMobil that it will not accept the property donation and the 

associated deed restrictions, then the In-Kind Contribution Amount under this 

Subparagraph 156.d.(5) shall be $0. 

(6) ExxonMobil shall enter into a separate written agreement with the 

U.S. Department of Agriculture, Forest Service or its contractors or assignees, pursuant 

to 16 U.S.C. § 579(c) or other available authorities, for performance of prairie habitat 

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restoration, protection, preservation, or acquisition work at the Midewin National 

Tallgrass Prairie by no later than December 31, 2009. ExxonMobil shall spend at least 

$250,000 for performance of that prairie habitat restoration, protection, preservation 

and/or acquisition work, as determined by the following formula: 

$1,050,000 

– In-Kind Contribution Amount Under Subparagraph 156.d.(5) 

= Required Expenditure Under this Subparagraph 156.d.(6) 

If any portion of the Required Expenditure under this Subparagraph 156.d.(6) is to be 

used for acquisition of additional property, then the acquired property shall be managed 

to conserve and enhance the native populations and habitats of fish, wildlife, and plants 

as part of the Midewin National Tallgrass Prairie, and to provide opportunities for 

associated research, in accordance with the Illinois Land Conservation Act of 1995 

(Public Law 104–106, Title XXIX, section 2901, et seq.) and shall not be used for 

residential or commercial development. 

e. Will County Emergency Management Agency Equipment Purchase 

Project. By no later than December 31, 2007, ExxonMobil will spend at least $100,000 to 

purchase and/or upgrade emergency response equipment (such as mobile computer data 

terminals, hazardous materials vehicles, radio equipment, and protective suits) for the Will 

County Emergency Management Agency. The Will County Emergency Management Agency 

serves as the Local Emergency Planning Committee for the area near ExxonMobil’s Joliet 

Refinery. 

f. Billings Refinery Pressure Relief Valve Control Project. By no later than 

the dates set forth below, ExxonMobil shall perform a SEP designed to control hydrogen sulfide 

emissions from episodic releases from atmospheric pressure release valves (“PRVs”) at the 

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Billings Refinery, at a cost of no less than $1,500,000 (the “PRV Project”). ExxonMobil shall 

develop and satisfactorily complete the PRV Project as described by the following 

Subparagraphs. 

(1) By no later than 365 days after the Entry Date, ExxonMobil shall 

complete an engineering evaluation for the PRV Project. The engineering evaluation 

shall assess the relative costs and benefits of various PRV control options at the Billings 

Refinery, and shall: (i) identify PRVs in hydrogen sulfide service, (ii) estimate the 

amount of hydrogen sulfide that might be emitted during a release incident at each such 

PRV, (iii) assess the recent history of releases (if any) from the particular PRV, and 

(iv) estimate the cost of routing each such PRV or particular sets of PRVs to the Billings 

Refinery’s amine treatment systems, flare gas recovery systems, and/or flares. 

(2) By no later than 365 days after the Entry Date, ExxonMobil shall 

prepare a proposed plan for spending the $1,500,000 PRV Project budget (the “PRV 

Project Plan”), based on the results of the engineering evaluation required by 

Subparagraph 156.f.(1), and ExxonMobil shall submit the PRV Project Plan for review 

and approval by EPA and MDEQ. The PRV Project Plan shall: (i) summarize the results 

of ExxonMobil’s engineering evaluation, and (ii) propose a specific plan and schedule 

for spending the $1,500,000 PRV Project budget on cost effective measures to control 

hydrogen sulfide emissions from episodic releases from PRVs at the Billings Refinery. 

The schedule for implementing such measures shall not extend beyond December 31, 

2009, unless EPA and MDEQ agree to a request from ExxonMobil for an extension of 

time pursuant to Paragraph 269 (Consent Decree Modifications). 

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(3) ExxonMobil shall implement the PRV Project Plan as approved by 

EPA and MDEQ, and shall operate and maintain the hydrogen sulfide emission controls 

installed as part of the PRV Project . 

g. Joliet Refinery Heater Firing Reduction Project. 

(1) By no later than December 31, 2009, ExxonMobil shall install air 

control technology (including burner management and analyzer technology) on 1-B-3, 

13-B-4, and 2-B-3/4/5/6 heaters at the Joliet Refinery to reduce annually at least 2000 

tons of carbon dioxide (“CO2”) emissions from those heaters. Any associated NOx 

emission reductions from 1-B-3, 13-B-4, and 2-B-3/4/5/6 heaters shall not be used to 

achieve the NOx emission reductions for heaters and boilers required by Subsection V.G 

of this Decree, and all CO2 and NOx emission reductions resulting from this SEP shall be 

permanently retired (i.e., not used as emission reduction credits). ExxonMobil shall 

spend no less than $800,000 on this SEP. 

(2) ExxonMobil may request that EPA and IEPA approve the 

substitution of another heater or boiler located at the Joliet Refinery for heaters 1-B-3, 

13-B-4, and 2-B-3/4/5/6. EPA and IEPA will approve ExxonMobil’s request if 

ExxonMobil demonstrates that its actions will result in a reduction in CO2 emissions of at 

least 2000 tons. If EPA and IEPA approve a substitution, ExxonMobil shall not use 

emission reductions from the substitute heater or boiler to comply with Subsection V.G 

of this Decree. 

157. ExxonMobil shall include in each Semi-Annual Report required by Section IX, a 

progress report for SEPs specified by Paragraph 156. In addition, the first Semi-Annual Report 

that is submitted after December 31, 2009 (or after any extended deadline for the performance of 

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the SEPs) shall contain the following information with respect to the SEPs specified by 

Paragraph 156: 

i. A detailed description of each such SEP as implemented; 

ii. A brief description of any significant operating problems encountered, including 

any that had an impact on the environment, and the solutions for each problem; 

iii. A summary of the costs ExxonMobil incurred in performing the SEPs specified 

by Paragraph 156; 

iv. Certification that the project has been fully implemented pursuant to the 

provisions of this Consent Decree; and 

v. A description of the environmental and public health benefits resulting from 

implementation of the project (including quantification of the benefits and 

pollutant reductions, if feasible). 

158. If ExxonMobil completes a SEP described in Paragraph 156, but does not expend 

all of the project-specific amount specified in Paragraph 156, then ExxonMobil shall, with 

respect to the difference between the project-specific amount and the amount actually expended, 

either: 

i. pay the difference as a stipulated penalty under Paragraph 214, if a written 

demand for payment is made at any time by EPA; 

ii. use the difference to fund an increase in the scope and/or budget of one or more 

of the other SEPs specified by Paragraph 156, with the advance written approval 

of EPA and the Applicable Co-Plaintiff(s) as set forth in a non-material 

modification to the Consent Decree under Paragraph 269; or 

iii. use the difference to fund another appropriate SEP, with the advance written 

approval of EPA and the Applicable Co-Plaintiff(s) as set forth in a material 

modification to the Consent Decree under Paragraph 269. 

159. State of Louisiana Beneficial Environmental Projects. As a term and condition of 

the settlement between ExxonMobil and LDEQ that is reflected in this Consent Decree, 

ExxonMobil shall pay $1,700,000 to the Louisiana Wildlife and Fisheries Foundation within 

137
thirty (30) days of the Entry Date in order to fund performance of one or more BEPs under La. 

Admin. Code tit. 33, I Chapter 25. In the first Semi-Annual Report that is required by Section 

IX, ExxonMobil shall confirm whether that payment was made as required by this Paragraph 

159. LDEQ has agreed that the Louisiana Wildlife and Fisheries Foundation will perform the 

BEPs that are to be funded with that payment, as described in Appendix O to this Consent 

Decree. 

160. Public Statements. ExxonMobil agrees that in any public statements it makes or 

causes to be made regarding the SEPs or BEPs, ExxonMobil must clearly indicate that these 

projects are being undertaken as part of the settlement of an enforcement action for alleged 

violations of the Clean Air Act and corollary state statutes. 

IX. RECORDKEEPING AND REPORTING 

161. ExxonMobil shall submit Semi-Annual Reports to EPA and the Applicable 

Co-Plaintiff that contain the following information: 

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

(Affirmative Relief) at the Covered Refineries; 

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

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

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

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

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

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

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

(Environmentally Beneficial Projects); 

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

attention of EPA and the Applicable Co-Plaintiff; and 

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

submitted with a Semi-Annual Report. 

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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 the first reporting date after the Entry Date. The Semi-Annual Report shall be 

certified by: (i) the person responsible for environmental management and compliance for each 

of the Covered Refineries; or (ii) a person responsible for overseeing implementation of this 

Decree for ExxonMobil, as follows: 

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

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

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

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

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

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

X. CIVIL PENALTY 

162. Civil Penalty. 

a. Within thirty (30) days of the Entry Date, ExxonMobil shall pay a civil 

penalty of $7,700,000 as follows: (i) $6,000,000 to the United States; (ii) $650,000 to the State 

of Illinois; (iii) $900,000 to the State of Louisiana; and (iv) $150,000 to the State of Montana. 

Of the $6,000,000 to be paid to the United States, $500,000 of that amount will be a civil penalty 

paid to the EPA Hazardous Substances Superfund. 

b. Payment of monies to the United States shall be made by Electronic Funds 

Transfer ("EFT") to the United States Department of Justice, in accordance with current EFT 

procedures, referencing DOJ Case Number 90-5-2-1-07030 and the civil action case name and 

case number of this action in the Northern District of Illinois. The costs of such EFT shall be the 

responsibility of ExxonMobil. Payment shall be made in accordance with instructions provided 

to ExxonMobil by the Financial Litigation Unit of the U.S. Attorney's Office for the Northern 

139
District of Illinois. Any funds received after 11:00 a.m. (EST) shall be credited on the next 

business day. ExxonMobil shall provide notice of payment, referencing DOJ Case Number 

90-5-2-1-07030 and the civil action case name and case number to the Department of Justice and 

to EPA, as provided in Paragraph 266 (Notice). 

c. Payment of the civil penalty owed to the State of Illinois under this 

Paragraph shall be made as follows: 

(1) $100,000 shall be paid by certified or corporate check payable to 

the Illinois Environmental Protection Agency, or by an electronic funds transfer, for 

deposit into the Illinois Environmental Protection Trust Fund, and shall be sent by firstclass mail (unless submitted by electronic funds transfer) and delivered to the following 

address: 

Illinois Environmental Protection Agency

Fiscal Services Section

1021 North Grand Avenue East

P.O. Box 19276

Springfield, IL 62794-9276

The name and number of the case and ExxonMobil Oil Corporation’s Federal Employer 

Identification Number (FEIN) 13-5401570 shall appear on the check. A copy of the 

certified or corporate check or record of electronic funds transfer and any transmittal 

letter shall be sent to: 

Environmental Bureau

Office of the Illinois Attorney General

188 West Randolph Street, 20th Floor

Chicago, IL 60601

and

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Maureen Wozniak

Assistant Counsel

Illinois EPA

1021 North Grand Avenue East

Springfield, IL 62794-9276

(2) The Illinois Environmental Protection Agency directs that 

$275,000 of the civil penalty shall be paid by certified or corporate check payable to the 

Illinois Environmental Protection Agency, designated to the Special State Projects Trust 

Fund, and submitted to: 

Illinois Environmental Protection Agency

Fiscal Services Section

1021 North Grand Avenue East

P.O. Box 19276

Springfield, IL 62794-9276

The name and number of the case and ExxonMobil Oil Corporation=s Federal Employer 

Identification Number (FEIN) 13-5401570 shall appear on the check. A copy of the certified or 

corporate check and any transmittal letter shall be sent to: 

Environmental Bureau 

Office of the Illinois Attorney General

188 West Randolph Street, 20th Floor

Chicago, IL 60601

and

Maureen Wozniak

Assistant Counsel

Illinois EPA

1021 North Grand Avenue East

Springfield, IL 62794-9276 

(3) $275,000 shall be paid by certified or corporate check payable to 

the "Attorney General State Projects and Court Ordered Distribution Fund" to be used at 

the discretion of the Illinois Attorney General's Office for the advancement of 

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environmental protection, enhancement and education activities in Illinois. The check 

shall be delivered to the following address: 

Environmental Bureau

Office of the Illinois Attorney General

188 West Randolph Street, 20th Floor

Chicago, IL 60601

The name and number of the case and ExxonMobil Oil Corporation’s Federal Employer 

Identification Number (FEIN) 13-5401570 shall appear on the check. 

d. Payment of the civil penalty owed to the State of Louisiana under this 

Paragraph shall be made by certified check made payable to the Louisiana Department of 

Environmental Quality and sent to Darryl Serio, Fiscal Director, Office of Management and 

Finance, LDEQ, P.O. Box 4303, Baton Rouge, LA 70821-4303. 

e. Payment of the civil penalty owed to the State of Montana under this 

Paragraph shall be made by certified or corporate check made payable to the State of Montana 

and sent to the following address: 

John L. Arrigo

Administrator, Enforcement Division

Montana Department of Environmental Quality

P.O. Box 200901

Helena, MT 59620-0901

163. The amount set forth in Paragraph 155 for SEPs and BEPs and the civil penalty 

set forth in Subparagraph 162.a together constitute the sole penalty imposed for the violations 

alleged hereunder within the meaning of Section 162(f) of the Internal Revenue Code, 26 U.S.C. 

§ 162(f), and, therefore, ExxonMobil shall not treat these penalty payments as tax deductible for 

purposes of net income taxes imposed under federal, state, or local law. 

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164. Upon the Entry Date, the Consent Decree shall constitute an enforceable 

judgment for purposes of post-judgment collection in accordance with Federal Rule of Civil 

Procedure 69, the Federal Debt Collection Procedure Act, 28 U.S.C. §§ 3001-3308, and other 

applicable federal authority. 

XI. STIPULATED PENALTIES 

165. Generally. 

a. ExxonMobil shall pay stipulated penalties to the United States and to the 

Applicable Co-Plaintiff for each failure by ExxonMobil to comply with the terms of this Consent 

Decree as provided herein. Stipulated penalties shall be calculated in the amounts specified in 

this Section XI. Stipulated penalties for failure to comply with the concentration-based, rolling 

average emission limits referenced in Section V shall not start to accrue until there is 

noncompliance for 5% or more of the applicable unit’s operating time during any calendar 

quarter. 

b. For those provisions where a stipulated penalty of either a fixed amount or 

1.2 times the economic benefit of non-compliance is available, the decision of which alternative 

to seek shall rest exclusively within the discretion of the EPA and the Applicable Co-Plaintiff. 

For the purposes of this Section XI, the term “economic benefit of non-compliance” means the 

economic benefit accrued from delaying a capital investment, delaying a one-time expenditure, 

and avoiding recurring costs (such as operation and maintenance costs) over the period of 

non-compliance. The overall “economic benefit of non-compliance” will be calculated based on 

the total number of days of non-compliance, and will be multiplied by 1.2 to compute the total 

stipulated penalty amount under a particular provision of this Section XI. That total stipulated 

penalty amount will be assessed for the full period of non-compliance, and will not be assessed 

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“per day.” In no event shall any stipulated penalty assessed against ExxonMobil exceed $32,500 

(or any inflation-adjusted increase in that maximum penalty amount set pursuant to the Federal 

Civil Penalties Inflation Adjustment Act of 1990, as amended by the Debt Collection 

Improvement Act of 1996) per day for any individual violation of this Consent Decree. 

c. Where a single event triggers more than one stipulated penalties provision 

in this Consent Decree, only the provision providing for the higher stipulated penalty shall apply. 

In cases where a violation of this Consent Decree is also a violation that provides a basis for 

potential recovery of civil penalties under of the Clean Air Act, another federal environmental 

law, and/or an applicable state or local environmental law, the United States and the Applicable 

Co-Plaintiff will each elect between seeking stipulated penalties under this Consent Decree and 

commencing a new action for civil penalties under such laws. Notwithstanding the foregoing, 

the United States and the Applicable Co-Plaintiffs reserve the right to pursue any other 

non-monetary remedies to which they are legally entitled, including but not limited to injunctive 

relief for violations of the Consent Decree. 

d. For the purposes of this Section XI, terms such as “per refinery,” “per 

unit,” “per valve,” “per drain” and the like shall mean only each refinery, each unit, each valve, 

or each drain that is in non-compliance with a specific Consent Decree requirement. 

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A. Requirements for NOX Emission Reductions from the FCCUs. 

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

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

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

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

specified 365-day rolling average exceeds the applicable limit. 

167. For failure to comply with any of the Baton Rouge and Beaumont NOx 

Minimization Studies requirements specified by Paragraph 15, including submission of required 

reports, per day: 

Period of Non-Compliance Penalty per day

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

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

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

economic benefit of non-compliance 

whichever is greater 

168. For failure to specify Interim NOx Limits or Final NOx Limits for Baytown 

FCCU 2 and/or Baytown FCCU 3, as required by Subparagraph 16.b or 16.c, per day: 

Period of Non-Compliance Penalty per day

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

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

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

economic benefit of non-compliance 

whichever is greater 

169. For failure to install, certify, calibrate, maintain, and/or operate a CEMS, as 

required by Paragraph 21, per day, per CEMS: 

145
Period of Non-Compliance Penalty per day

1st through 30th day after deadline $500

31st through 60th day after deadline $1,000

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

economic benefit of non-compliance, 

whichever is greater. 

B. Requirements for SO2 Emission Reductions from the FCCUs. 

170. For each failure to meet any FCCU Final SO2 Limit set forth in or established 

pursuant to Subparagraphs 23.b, 24.b, 25.b, 26.b, 27.b, 28.b, or 29.b, per FCCU: $750 for each 

calendar day in a calendar quarter on 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. 

171. For failure to comply with any of the Particular Requirements for the Billings 

FCCU: Conversion to Full Burn Operation and Two-Step SO2 Reducing Catalyst Additive 

Program, as set forth in Paragraph 30, including submission of required reports, per day: 

Period of Non-Compliance Penalty per day

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

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

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

economic benefit of non-compliance 

whichever is greater 

172. For failure to install, certify, calibrate, maintain, and/or operate a CEMS, as 

required by Paragraph 32, per day, per CEMS: 

Period of Non-Compliance 

1st through 30th day after deadline 

31st 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 non-compliance,

whichever is greater.

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C. Requirements for PM Emissions Reductions from the FCCUs. 

173. For each failure to meet any FCCU Final PM Limit that ExxonMobil accepts 

pursuant to Paragraph 35 (if applicable), per day, per FCCU: $500 for the first day of noncompliance in which the specified short-term rolling average exceeds the applicable limit, and 

$1,500 for each day thereafter until ExxonMobil demonstrates compliance with the applicable 

limit. 

174. For failure to conduct PM testing, as required by Paragraph 37, per day, per 

FCCU: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $200 

31st through 60th day after deadline $500 

Beyond 60th day after deadline $1000 

D. Requirements for CO Emissions Reductions from the FCCUs. 

175. For each failure to meet any FCCU Final CO Limit that ExxonMobil accepts 

pursuant to Paragraph 40 (if applicable), per day, per FCCU: $750 for each calendar day in a 

calendar quarter in which the short-term rolling average exceeds the applicable limit; and $2,500 

for each calendar day in a calendar quarter on which the specified 365-day rolling average 

exceeds the applicable limit. 

176. For failure to install, certify, calibrate, maintain, and/or operate a CEMS, as 

required by Paragraph 42, per day, per CEMS: 

Period of Non-Compliance 

1st through 30th day after deadline 

31st 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 non-compliance,

whichever is greater.

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E. Requirements Related to NSPS Applicability to FCCU Regenerators. 

177. For failure to comply with NSPS Subparts A and J limits applicable to a particular 

FCCU’s catalyst regenerator, as required by Paragraphs 34, 39, and 43, per pollutant, per unit, 

per day in a calendar quarter: 

Period of Non-Compliance Penalty per day

1st through 30th day $1,000

31st through 60th day $2,000

Over 60 days $3,000 or an amount equal to 1.2 times the

economic benefit of non-compliance, whichever is 

greater. 

178. For failure to comply with any of the Particular Requirements Applicable to the 

Baton Rouge FCCUs specified by Subparagraphs 44.b and 44.c: $3,000 per day of 

non-compliance, or an amount equal to 1.2 times the economic benefit of non-compliance, 

whichever is greater. 

F. Requirements for NOx Emission Reductions from Combustion Units. 

179. For failure to install selected Qualifying Controls on Combustion Units or to 

reduce NOx emissions from Combustion Units as required by Paragraphs 47, 50, or 51, per day: 

Period of Non-Compliance Penalty per day

1st through 30th day after deadline $2,500

31st through 60th day after deadline $6,000

Beyond 60th day after deadline $10,000, or an amount equal to 1.2 times the

economic benefit of non-compliance, 

whichever is greater. 

180. For failure to comply with the applicable monitoring requirements as set forth in 

Paragraphs 53 and 54, per Combustion Unit, per day: 

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Period of Non-Compliance Penalty per day

1st through 30th day after deadline $500

31st through 60th day after deadline $1,000

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

economic benefit of non-compliance, 

whichever is greater. 

181. For failure to submit the written deliverables required by Paragraph 49, per day: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $200 

31st through 60th day after deadline $500 

Beyond 60th day after deadline $1,000 

G. Requirements for SO2 Emission Reductions from Heaters, Boilers, and Other 

Fuel Gas Combustion Devices. 

182. For burning in any heater or boiler (including but not limited to those listed in 

Appendix C) or in any Other Fuel Gas Combustion Device (listed in Appendix D) any refinery 

fuel gas in violation of the applicable requirements of NSPS Subparts A and J after the Entry 

Date or, if the device is listed in Appendix C or D, after the date set forth in Appendix C or D on 

which the respective device becomes an “affected facility” subject to NSPS Subparts A and J, as 

set forth in Subsection V.H., per device, per day in a calendar quarter: 

Period of Non-Compliance Penalty per day

1st through 30th day $2,500

Beyond 31st day $5,000 or an amount equal to 1.2 times the

economic benefit of non-compliance, whichever is 

greater. 

183. For burning Fuel Oil in a manner inconsistent with the requirements of 

Paragraph 60, per device, per day: 

Period of Non-Compliance Penalty per day 

1st through 30th day $1,750 

Beyond 31st day $5,000 

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H. Requirements for Sulfur Recovery Plants. 

184. For failure to comply with the NSPS Subparts A and J emission limits at a Sulfur 

Recovery Plant listed in Paragraph 63, as specified in Subparagraph 64.a, per day, per SRP: 

Period of Non-Compliance Penalty per day

1st through 30th day $1,000

31st through 60th day $2,000

Over 60 days $3,000 or an amount equal to 1.2 times the

economic benefit of non-compliance, whichever is 

greater. 

185. For failure to comply with NSPS Subparts A and J monitoring requirements at a 

Sulfur Recovery Plant listed in Paragraph 63, as specified in Subparagraph 64.b, per day, per 

SRP: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $500 

Beyond 31st day after deadline $1,500 

Beyond 60th day after deadline $2,000 

186. For failure to develop a Preventive Maintenance and Operation Plan as specified 

in Paragraph 65, per day, per Plan: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $500 

Beyond 31st day after deadline $1,500 

Beyond 60th day after deadline $2,000 

187. For failure to complete the Baton Rouge and Joliet optimization studies and 

reports as required by Paragraph 66, per Refinery, per day: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $500 

Beyond 31st day after deadline $1,500 

Beyond 60th day after deadline $2,000 

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188. For failure to comply with any of the Particular Requirements for Baton Rouge 

FCCUs specified by Subparagraphs 67.a - 67.d: $3,000 per day of non-compliance, or an 

amount equal to 1.2 times the economic benefit of non-compliance, whichever is greater. 

189. For failure to comply with an Interim Performance Standard applicable to the 

Joliet East Claus Train or the Joliet West Claus Train under Subparagraph 68.b, per day: 

Period of Non-Compliance Penalty per day

1st through 30th day $1,000

31st through 60th day $2,000

Over 60 days $3,000 or an amount equal to 1.2 times the

economic benefit of non-compliance, whichever is 

greater. 

190. For failure to manage all sulfur pit emissions in accordance with the requirements 

of Paragraph 69, per day, per Refinery: 

Period of Non-Compliance Penalty per day

1st through 30th day $1,000

31st through 60th day $1,750

Beyond 60th day $4,000 or an amount equal to 1.2 times the

economic benefit of non-compliance whichever is 

greater. 

I. Requirements for Flaring Devices. 

191. For failure to comply with the requirement in Paragraphs 71 and 73 that an NSPS 

Flaring Device comply with the compliance method specified in Appendix G, by the date 

specified in Appendix G, per day, per device: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $500 

Beyond 31st day after deadline $1,500 

Beyond 60th day after deadline $2,000 

Provided, however, that if stipulated penalties could be assessed under both Paragraphs 191 and 

192, the provisions of Paragraph 192 shall control. 

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J. Requirements for Control of AG Flaring Incidents and Tail Gas Incidents. 

192. For AG Flaring Incidents and/or Tail Gas Incidents for which ExxonMobil is 

liable under Subsection V.K: 

Tons Emitted in 

Flaring Incident or 

Tail Gas Incident 

Length of Time from 

Commencement of 

Flaring within the 

Flaring Incident to 

Termination of Flaring 

within the Flaring 

Incident is 3 hours or 

less; Length of Time of 

the Tail Gas Incident is 

3 hours or less 

5 Tons or less $500 per Ton 

Greater than 5 

Tons, but less than 

or equal to 15 

Tons 

$1,200 per Ton 

Greater than 15 

Tons 

$1,800 per Ton, up to, 

but not exceeding, 

$27,500 in any one 

calendar day 

Length of Time from 

Commencement of 

Flaring within the Flaring 

Incident to Termination of 

Flaring within the Flaring 

Incident is greater than 3 

hours but less than or 

equal to 24 hours; Length 

of Time of the Tail Gas 

Incident is greater than 3 

hours but less than or 

equal to 24 hours 

Length of Time 

of Flaring within 

the Flaring 

Incident is 

greater than 24 

hours; Length of 

Time of the Tail 

Gas Incident is 

greater than 24 

hours 

$750 per Ton $1,000 per Ton 

$1,800 per Ton $2,300 per Ton, 

up to, but not 

exceeding, 

$27,500 in any 

one calendar day 

$2,300 per Ton, up to, but 

not exceeding, $27,500 in 

any one calendar day 

$27,500 per 

calendar day for 

each calendar 

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 an AG 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 of sulfur 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 of determining which column in the table set forth in this 

Paragraph applies under circumstances in which flaring occurs intermittently during an 

152
AG Flaring Incident, the flaring shall be deemed to commence at the time that the flaring that 

triggers the initiation of an AG Flaring Incident commences, and shall be deemed to terminate at 

the time of the termination of the last episode of flaring within the AG Flaring Incident. Thus, 

for example, for flaring within an AG Flaring Incident that (i) starts at 1:00 p.m. on Day 1 and 

ends at 1:30 p.m. on Day 1; (ii) recommences at 4:00 p.m. on Day 1 and ends at 4:30 p.m. on 

Day 1; (iii) recommences at 1:00 a.m. on Day 2 and ends at 1:30 a.m. on Day 2; and (iv) for 

which no further Flaring occurs within the Flaring Incident, the flaring within the AG 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 to 24 hours” shall apply. 

193. For failure to timely submit any report required by Subsection V.K, or for 

submitting any report that does not substantially conform to its requirements: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

194. For those corrective action(s) which ExxonMobil: (i) agrees to undertake

following receipt of an objection by EPA pursuant to Paragraph 81; or (ii) is required to 

undertake following dispute resolution, then, from the date of EPA’s receipt of ExxonMobil’s 

report under Paragraph 80 of this Consent Decree until the date that either: (i) a final agreement 

is reached between EPA and ExxonMobil regarding the corrective action; or (ii) a court order 

regarding the corrective action is entered, ExxonMobil shall be liable for stipulated penalties as 

follows: 

153
i. Period of Non-Compliance Penalty per day 

Days 1-120 $50 

Days 121-180 $100 

Days 181 - 365 $300 

Over 365 Days $3,000 

or 

ii. 1.2 times the economic benefit resulting from ExxonMobil’s failure to implement 

the corrective action(s). 

195. For failure to complete any corrective action under Paragraph 81 of this Decree in 

accordance with the schedule for such corrective action agreed to by ExxonMobil or imposed on 

ExxonMobil pursuant to the dispute resolution provisions of this Decree (with any such 

extensions thereto as to which EPA and ExxonMobil may agree in writing): 

Period of Non-Compliance Penalty per day

Days 1-30 $1,000

Days 31-60 $2,000

Over 60 $5,000

K. Requirements for Control of Hydrocarbon Flaring Incidents. 

196. For each failure to perform a Root Cause analysis or submit a written report or 

perform corrective actions for an HC Flaring Incident, as required by Paragraph 92: 

Period of Non-Compliance Penalty per day per Incident 

1st through 30th day $500 

31st through 60th day $1,500 

Beyond 60th day $3,000 

L. Requirements for CERCLA/EPCRA Reporting. 

197. For failure to perform a CERCLA/EPCRA Compliance Review, submit a 

CERCLA/EPCRA Compliance Review Report, or perform corrective actions, as required by 

Paragraph 95, per refinery: 

154
Period of Non-Compliance Penalty per day per Incident

1st through 30th day $500

31st through 60th day $1,500

Beyond 60th day $3,000

198. For each failure to submit a CERCLA/EPCRA report on a release at the Joliet

Refinery, as required by Paragraph 96: 

Period of Non-Compliance Penalty per day per violation 

1st through 7th day $750 

8th through 14th day $1,500 

Beyond 14th day $5,000 

ExxonMobil’s obligation to pay stipulated penalties under this Paragraph 198 shall cease if: 

(i) at least thirty-six months have elapsed since the Entry Date; and (ii) stipulated penalties have 

not been assessed under this Paragraph 198 during the most recent thirty-six months. 

M. Requirements for Benzene Waste NESHAP Program Enhancements. 

199. For each violation in which a frequency is specified in Subsection V.N., the 

amounts identified below shall apply on the first day of violation, and shall be calculated for 

each incremental period of violation (or portion thereof): 

a. For failure to complete a BWON Compliance Review and Verification 

Report as required by Paragraph 100: $7,500 per month, per refinery. 

b. For failure to submit a BWON Corrective Measures Plan as required by 

Subparagraph 101.b, or for failure to implement Plan and to certify compliance as required by 

Subparagraphs 101.c and 101.d, per refinery: 

Period of Non-Compliance 

1st 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 of non-compliance,

whichever is greater.

155
c. For failure to comply with the requirements set forth in Paragraph 102 

related to the use, monitoring, and replacement of carbon canisters: $1,000 per incident of 

non-compliance, per day. 

d. For failure to implement the training requirements of Paragraph 106: 

$10,000 per quarter. 

e. For failure to establish an annual review program to identify new benzene 

waste streams as required by Paragraph 103: $2,500 per month, per refinery. 

f. For failure to perform laboratory audits as required by Paragraph 104: 

$5,000 per month, per audit. 

g. For failure to submit or maintain any plans or other deliverables required 

by Paragraph 107: $2,000 per deliverable. 

h. For failure to conduct sampling in accordance with the sampling plans 

required by Paragraphs 108 or 109: $30,000 per quarter, per stream, whichever is greater, but 

not to exceed $150,000 per quarter, per refinery. 

i. For failure to submit a BWON Corrective Measures Plan or retain the 

third-party contractor required by Paragraph 111: $10,000 per month. 

j. For failure to conduct monthly visual inspections of all Subpart FF water 

traps as required by Subparagraph 112.a.i: $500 per drain not inspected; 

k. For failure to monitor Subpart FF conservation vents as required by 

Subparagraph 112.a.ii: $500 per vent not monitored; 

l. For failure to conduct monitoring of oil-water separators as required by 

Subparagraph 112.a.iii: $1,000 per month, per unit not monitored; 

156
m. For failure to identify/mark segregated stormwater drains as required in 

Subparagraph 112.b: $1,000 per week per drain not identified/marked as required; 

n. For failure to submit any of the written deliverables required by 

Subsection V.N (except for those deliverables for which stipulated penalties are specified in 

Subparagraphs 199.a, 199.b, 199.g, or 199.i): $1,000 per week, per deliverable not submitted. 

N. Requirements for Leak Detection and Repair Program Enhancements. 

200. For each violation in which a frequency is specified in Subsection V.O the 

amounts identified below shall apply on the first day of violation, and shall be calculated for 

each incremental period of violation (or portion thereof): 

a. For failure to develop an LDAR Program Description as required by 

Paragraph 117: $3,500 per week, per refinery. 

b. For failure to implement the training program specified in Paragraph 118: 

$10,000 per month, per refinery. 

c. For failure to conduct any of the LDAR Audits described in Paragraph 

120: $5,000 per month, per audit, per refinery. 

d. For failure to implement any actions necessary to correct non-compliance 

as required in Paragraph 121: 

Period of Non-Compliance 

1st 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 of non-compliance,

whichever is greater

157
e. For failure to perform monitoring utilizing the lower internal leak rate 

definitions as specified in Paragraph 122: $100 per component, but not greater than $10,000 per 

month, per process unit. 

f. For failure to perform LDAR monitoring at the frequency required by 

Paragraph 123: $100 per component, but not greater than $10,000 per month, per refinery. 

g. For failure to make first repair attempts within 5 days and/or take other 

actions required by Paragraph 124: $100 per component but not greater than $10,000 per month, 

per refinery (except that Subparagraph 200.h shall apply in lieu of this Subparagraph 200.g 

where both Subparagraphs are potentially applicable). 

h. For failure to implement the “initial attempt” repair program set forth in 

Paragraph 126: $100 per component, but not to exceed $10,000 per month, per refinery. 

i. For failure to implement the QA/QC procedures described in Paragraph 

128: $1,000 per incident, but not greater than $10,000 per month, per refinery. 

j. For failure to designate a person or position responsible for LDAR 

management as required by Paragraph 119, or for failure to implement the maintenance tracking 

program required by Subparagraph 117.iv: $3,500 per week, per refinery. 

k. For failure to use dataloggers or maintain electronic data as required by 

Paragraph 127: $5,000 per month, per refinery. 

l. 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 129: $100 per missed event. 

m. For failure to comply with the requirements for delay of repair set forth at 

Paragraph 130: $5,000 per valve or pump, per incident of non-compliance. 

158
n. For failure to submit a written submission to EPA and/or an Applicable 

Co-Plaintiff as required by Subsection V.O (except where a more specific stipulated penalty 

provision applies to a submission under this Subsection XI.N): $500 per week, per submission. 

o. If it is determined through a federal, state, or local investigation that 

ExxonMobil has failed to include any valves or pumps in its LDAR program, ExxonMobil shall 

pay $175 per component that it failed to include. 

p. For failure to comply with the requirements for chronic leakers set forth at 

Paragraph 131: $5,000 per valve. 

O. Other Compliance Program Requirements for the Billings and Joliet 

Refineries. 

201. For failure to comply with the following Joliet Wastewater Treatment Area 

Program Requirements under Paragraph 134 and Appendix P: 

a. For failure to timely submit the WWTP Area Wastewater Monitoring Plan 

required by Paragraph 2 of Appendix P, or for submitting a WWTP Area Wastewater Monitoring 

Plan that does not substantially conform to the requirements of this Consent Decree: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

b. For failure to meet the scheduling milestones of the EPA-approved 

WWTP Area Wastewater Monitoring Plan: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

159
c. For failure to timely submit a WWTP Area Wastewater Monitoring Plan 

Quarterly Report required by Paragraph 4 of Appendix P, or for submitting a WWTP Area 

Wastewater Monitoring Plan Quarterly Report that does not substantially conform to the 

requirements of Appendix P: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

d. For failure to timely submit the WWTP Area Wastewater Monitoring Plan 

Final Report required by Paragraph 5 of Appendix P, or for submitting a WWTP Area 

Wastewater Monitoring Plan Final Report that does not substantially conform to the 

requirements of Appendix P: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

e. For failure to meet the scheduling milestones contained in the EPAapproved WWTP Area Wastewater Monitoring Plan Final Report: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

f. For failure to timely submit the Sludge Characterization and Removal 

Plan required by Paragraph 6 of Appendix P, or for submitting a Sludge Characterization and 

Removal Plan that does not substantially conform to the requirements of Appendix P: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

160
g. For failure to meet the scheduling milestones contained in the EPAapproved Sludge Characterization and Removal Plan: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

h. For failure to comply with any requirement of Paragraph 7 of Appendix P 

relating to Aggressive Biological Treatment at the Joliet Refinery EBTU: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

i. For failure to timely submit the Groundwater and Soil Characterization 

Plan required by Paragraph 8 of Appendix P, or for submitting a Groundwater and Soil 

Characterization Plan that does not substantially conform to the requirements of Appendix P: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

j. For failure to meet the scheduling milestones contained in the EPAapproved Groundwater and Soil Characterization Plan: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

k. For failure to comply with an effluent limitation specified by the Joliet 

Refinery NPDES Permit, as required by Subparagraph 3.a of Appendix P: 

(1) For a violation of a daily maximum limit: 

$2,000 for the first exceedance of a specified effluent limitation at a particular monitoring 

point; 

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$4,000 for the second exceedance of the same specified effluent limitation at a particular 

monitoring point; and 

$5,000 for the third exceedance and each subsequent exceedance of the same specified 

effluent limitation at a particular monitoring point. 

(2) For a violation of a 30-day average limit: 

$5,000 for the first exceedance of a specified effluent limitation at a particular monitoring 

point; 

$8,000 for the second exceedance of the same specified effluent limitation at a particular 

monitoring point; and 

$10,000 for the third exceedance and each subsequent exceedance of the same specified 

effluent limitation at a particular monitoring point. 

(3) Time Period for Accrual of Stipulated Penalties under this 

Subparagraph 201.k. Stipulated penalties for any noncompliance with the effluent 

limitations of the Joliet Refinery NPDES Permit covered by this Subparagraph 201.k 

shall accrue for at least thirty-six (36) months after the Entry Date, provided that after the 

initial twenty-four (24) month period, ExxonMobil’s obligation to pay stipulated 

penalties under this Subparagraph 201.k shall cease with respect to a specific effluent 

limitation at a particular monitoring point at such time that ExxonMobil demonstrates 

continuous compliance with that effluent limitation at that particular monitoring point as 

reported in its Discharge Monitoring Reports over a rolling consecutive twelve (12) 

month period. 

202. For failure to comply with any requirement of Paragraph 135 relating to the Joliet 

Material Staging Area: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

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203. For failure to timely submit the materials related to the Joliet RCRA Training 

Requirements required by Paragraph 136, or for submitting such materials required by Paragraph 

136 that do not substantially conform to the requirements of this Consent Decree: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

204. For failure to designate both the Billings Scrap Yard and the Laydown Areas as

Solid Waste Management Units and/or Areas of Concern as required under Paragraph 137: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

205. For failure to timely submit modifications to the Billings Stormwater Pollution

Prevention Plan required by Subparagraph 137.c, or for submitting such materials required by 

Paragraph 137.c that do not substantially conform to the requirements of this Consent Decree: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

206. For failure to timely seek amendments to the Billings Refinery RCRA permit

related to waste application at the Land Treatment Unit required by Paragraph 138, or for 

submitting such materials required by Paragraph 138 that do not substantially conform to the 

requirements of this Consent Decree: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

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207. For failure to timely submit proposed amendments to the Billings Refinery 

Montana Pollutant Discharge Elimination System Permit related to oil sheen required by 

Paragraph 139, or for submitting such materials required by Paragraph 139 that do not 

substantially conform to the requirements of this Consent Decree: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

208. For failure to comply with any requirement of Paragraph 140 relating to Billings

Refinery Tank 350: 

Period of Non-Compliance Penalty per day

Days 1-30 $750

Days 31-60 $1,500

Over 60 days $3,000

P. Requirements to Incorporate Consent Decree Requirements into 

Federally-Enforceable Permits. 

209. For each failure to submit an application as required by Paragraphs 141 and 142:

Period of Non-Compliance Penalty per day

Days 1-30 $800

Days 31-60 $1,500

Over 60 Days $3,000

Q. Requirements for Reporting and Recordkeeping. 

210. For failure to submit reports as required by Section IX, per report, per day: 

Period of Non-Compliance Penalty per day 

1st through 30th day after deadline $300 

31st through 60th day after deadline $1,000 

Beyond 60th day $2,000 

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R. Requirements for Environmentally Beneficial Projects and Civil Penalties. 

211. For failure to timely complete implementation of a SEP required under Section 

VIII, per day: 

Period of Non-Compliance Penalty per day 

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

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

Beyond 60th day $2,000 

212. For failure to make any civil penalty payment required by Paragraph 162 of this 

Consent Decree, ExxonMobil shall be liable for $15,000 per day, and interest on the amount 

overdue at the rate specified in 28 U.S.C. § 1961(a). 

S. Requirement to Pay Stipulated Penalties. 

213. ExxonMobil 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), for failure to do either of the following 

within sixty (60) days after receipt of a written demand pursuant to Paragraph 214: (i) pay 

stipulated penalties as required by Paragraph 165 of this Consent Decree; or (ii) place the 

amount of stipulated penalties demanded in escrow pursuant to Paragraph 215. 

T. Payment of Stipulated Penalties. 

214. ExxonMobil shall pay stipulated penalties (as required under Paragraph 165) 

upon written demand by the United States or the Applicable Co-Plaintiff no later than sixty (60) 

days after ExxonMobil receives such demand. Demand from either the United States or an 

Applicable Co-Plaintiff shall be deemed a demand from both, but the United States and the 

Applicable Co-Plaintiff shall consult with each other prior to making a demand. If there is no 

Applicable Co-Plaintiff, stipulated penalties owed by ExxonMobil shall be paid 100 percent to 

the United States. If there is an Applicable Co-Plaintiff, stipulated penalties owed by 

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ExxonMobil shall be paid 50 percent to the United States and 50 percent to the Applicable CoPlaintiff. Stipulated penalties shall be paid to the United States and to the Applicable CoPlaintiff in the manner set forth in Section X (Civil Penalty) of this Consent Decree. A demand 

for the payment of stipulated penalties will identify the particular violation(s) to which the 

stipulated penalty relates, the stipulated penalty amount the United States or the Applicable CoPlaintiff is demanding for each violation (as can be best estimated), the calculation method 

underlying the demand, and the grounds upon which the demand is based. After consultation 

with each other, the United States and the Applicable Co-Plaintiff may, in their unreviewable 

discretion, waive payment of any portion of stipulated penalties that may accrue under this 

Consent Decree. 

U. Stipulated Penalties Dispute. 

215. Should ExxonMobil dispute the United States’ and/or an Applicable 

Co-Plaintiff’s 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 213 by placing the 

disputed amount demanded in a commercial escrow account pending resolution of the matter and 

by invoking the dispute resolution provisions of Section XV within the time provided in 

Paragraph 214 for payment of stipulated penalties. If the dispute is thereafter resolved in 

ExxonMobil’s favor, the escrowed amount plus accrued interest shall be returned to 

ExxonMobil; otherwise, the United States and the Applicable 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 Applicable Co-Plaintiff reserve the 

right to pursue any other non-monetary remedies to which they are legally entitled, including but 

not limited to, injunctive relief for ExxonMobil’s violations of this Consent Decree. 

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XII. INTEREST 

216. After the date on which a payment is due under this Consent Decree, ExxonMobil 

shall be liable for interest on the unpaid balance of the civil penalty specified in Section X, and 

for interest on any unpaid balance of stipulated 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 determined by the Secretary of Treasury) of 

the average accepted auction price for the last auction of 52-week U.S. Treasury bills settled 

prior to the Date of Lodging of the Consent Decree. Interest 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 of this Section XII, interest 

pursuant to this Paragraph will cease to accrue on the amount of any stipulated penalty payment 

made into an interest bearing escrow account as contemplated by Paragraph 215 of the Consent 

Decree. Monies timely paid into escrow shall not be considered to be an unpaid balance under 

this Section. 

XIII. RIGHT OF ENTRY 

217. Any authorized representative of EPA or an Applicable Co-Plaintiff, including 

independent contractors, upon presentation of credentials, shall have a right of entry upon the 

premises of the facilities of any Covered Refinery, at any reasonable time for the purpose of 

monitoring compliance with the provisions of this Consent Decree, including inspecting plant 

equipment, and inspecting and copying all records maintained by ExxonMobil pursuant to the 

requirements of this Consent Decree or in the ordinary course of ExxonMobil’s business that are 

deemed necessary by EPA or the Applicable Co-Plaintiff to verify compliance with this Consent 

Decree. ExxonMobil shall retain records required under this Consent Decree for the period of 

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the Consent Decree. Nothing in this Consent Decree shall limit the authority of EPA or an 

Applicable Co-Plaintiff to conduct tests, inspections, or other activities under any statutory or 

regulatory provision. 

XIV. FORCE MAJEURE 

218. If any event occurs which causes or may cause a delay or impediment to 

performance in complying with any provision of this Consent Decree, ExxonMobil shall notify 

EPA and the Applicable Co-Plaintiff in writing as soon as practicable, but in any event within 

ten (10) business days of the date when ExxonMobil first knew of the event or should have 

known of the event by the exercise of due diligence. In this notice, ExxonMobil shall 

specifically reference this Paragraph 218 of this Consent Decree and describe the anticipated 

length of time the delay may persist, the cause or causes of the delay, and the measures taken or 

to be taken by ExxonMobil to prevent or minimize the delay and the schedule by which those 

measures shall be implemented. ExxonMobil shall take all reasonable steps to avoid or 

minimize such delays. The notice required by this Section shall be effective upon the mailing of 

the same by certified mail, return receipt requested, to EPA and the Applicable Co-Plaintiff as 

specified in Paragraph 266 (Notice). 

219. Failure by ExxonMobil to substantially comply with the notice requirements of 

Paragraph 218 as specified above shall render this Section XIV (Force Majeure) voidable by the 

United States, in consultation with the Applicable Co-Plaintiff, as to the specific event for which 

ExxonMobil has failed to comply with such notice requirement, and, if voided, is of no effect as 

to the particular event involved. 

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220. The United States, after consultation with the Applicable Co-Plaintiff, shall notify 

ExxonMobil in writing regarding its claim of a delay or impediment to performance within thirty 

(30) days of receipt of the force majeure notice provided under Paragraph 218. 

221. If the United States, after consultation with the Applicable Co-Plaintiff, agrees 

that the delay or impediment to performance has been or will be caused by circumstances beyond 

the control of ExxonMobil, including any entity controlled by ExxonMobil, and that 

ExxonMobil could not have prevented the delay by the exercise of due diligence, the Parties 

shall stipulate to an extension of the 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. ExxonMobil shall not be liable for stipulated penalties for the period of any 

such delay. 

222. If the United States, after consultation with the Applicable Co-Plaintiff, does not 

accept ExxonMobil’s claim of a delay or impediment to performance, ExxonMobil must submit 

the matter to the Court for resolution to avoid payment of stipulated penalties, by filing a petition 

for determination with the Court. In the event the United States and the Applicable Co-Plaintiff 

do not agree, the position of the United States on the force majeure claim shall become the final 

Plaintiffs’ position. Once ExxonMobil has submitted this matter to the Court, the United States 

and the Applicable Co-Plaintiff shall have twenty (20) business days to file their responses to the 

petition. If the Court determines that the delay or impediment to performance has been or will 

be caused by circumstances beyond the control of ExxonMobil, including any entity controlled 

by ExxonMobil, and that the delay could not have been prevented by ExxonMobil by the 

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exercise of due diligence, ExxonMobil shall be excused as to that event(s) and delay (including 

stipulated penalties), for all requirements affected by the delay for a period of time equivalent to 

the delay caused by such circumstances or such other period as may be determined by the Court. 

223. ExxonMobil shall bear the burden of proving that any delay in meeting any 

requirement(s) of this Consent Decree was caused by or will be caused 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. ExxonMobil shall also bear the burden of proving the duration and 

extent of any delay(s) attributable to such circumstances. An extension of one compliance date 

based on a particular event may, but will not necessarily, result in an extension of a subsequent 

compliance date or dates. 

224. Unanticipated or increased costs or expenses associated with the performance of 

ExxonMobil’s obligations under this Consent Decree shall not constitute circumstances beyond 

its control, or serve as the basis for an extension of time under this Section XIV. 

225. Notwithstanding any other provision of this Consent Decree, this Court shall not 

draw any inferences nor establish any presumptions adverse to either Party as a result of 

ExxonMobil serving a force majeure notice or the Parties' inability to reach agreement. 

226. As part of the resolution of any matter submitted to this Court under this 

Section XIV, the Parties by agreement, or the Court, by order, may in appropriate circumstances 

extend or modify the schedule for completion of work 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 

performance agreed to by the United States or approved by this Court. ExxonMobil shall be 

liable for stipulated penalties for its failure thereafter to complete the work in accordance with 

the extended or modified schedule. 

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XV. RETENTION OF JURISDICTION / DISPUTE RESOLUTION 

227. This Court shall retain jurisdiction of this matter for the purposes of implementing 

and enforcing the terms and conditions of the Consent Decree and for the purpose of 

adjudicating all disputes – including, but not limited to, determinations under Section V 

(Affirmative Relief) of the Consent Decree – among the Parties that may arise under the 

provisions of the Consent Decree, until the Consent Decree terminates in accordance with 

Section XVIII (Termination). 

228. 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 Party making such application has made 

a good faith attempt to resolve the matter with the other Party. 

229. Dispute resolution shall be commenced by one of the 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 of the dispute, and shall state the noticing Party's 

position with regard to such dispute. The Party receiving such a notice shall acknowledge 

receipt of the notice and the Parties shall expeditiously schedule a meeting to discuss the dispute 

informally not later than fourteen (14) days after the receipt of such notice. 

230. Disputes submitted to dispute resolution shall, in the first instance, be the subject 

of informal negotiations between the Parties. Such period of informal negotiations shall not 

extend beyond thirty (30) calendar days from the date of the first meeting between 

representatives of the Parties, unless the Parties agree that this period should be extended. 

231. In the event that the Parties are unable to reach agreement during such informal 

negotiation period, the United States or the Applicable Co-Plaintiff, as applicable, shall provide 

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ExxonMobil with a written summary of its position regarding the dispute. The position 

advanced by the United States or the Applicable Co-Plaintiff, as applicable, shall be considered 

binding unless, within forty-five (45) calendar days of ExxonMobil’s receipt of the written 

summary of the United States’ or the Applicable Co-Plaintiff’s position, ExxonMobil files with 

the Court a petition which describes the nature of the dispute. The United States and/or the 

Applicable Co-Plaintiff shall respond to the petition within forty-five (45) calendar days of 

filing. 

232. In the event that the United States and an Applicable Co-Plaintiff make differing 

determinations or take differing actions that affect ExxonMobil’s rights or obligations under this 

Consent Decree, the determination or action of the United States shall control. 

233. Where the nature of the dispute is such that a more timely resolution of the 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. 

234. The Parties do not intend that the invocation of this Section XV by a Party cause 

the Court to draw any inferences nor establish any presumptions adverse to either Party as a 

result of invocation of this Section or their inability to reach agreement. 

235. As part of the 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 of work under this Consent Decree to account for the delay 

in the work that occurred as a result of dispute resolution. ExxonMobil shall be liable for 

stipulated penalties for its failure thereafter to complete the work in accordance with the 

extended or modified schedule. 

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XVI. EFFECT OF SETTLEMENT 

236. Definitions. For purposes of this Section XVI, the following definitions apply: 

a. “Applicable NSR/PSD Requirements” shall mean: 

(i) PSD requirements at Part C of Subchapter I of the Act, 42 U.S.C. § 7475, 

and the regulations promulgated thereunder at 40 C.F.R. §§ 52.21 and 

51.166, as amended from time to time; 

(ii) “Plan Requirements for Non-Attainment Areas” at Part D of Subchapter I 

of the Act, 42 U.S.C. §§ 7502-7503, and the regulations promulgated 

thereunder at 40 C.F.R. §§ 51.165 (a) and (b); 40 C.F.R. Part 51, 

Appendix S; and 40 C.F.R. § 52.24, as amended from time to time; 

(iii) Any Title V regulations that implement, adopt, or incorporate the specific 

regulatory requirements identified above, as amended from time to time; 

and 

(iv) Any applicable state or local laws or regulations that implement, adopt, or 

incorporate the specific federal regulatory requirements identified above 

regardless of whether such state or local laws or regulations have been 

formally approved by EPA as being a part of the 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. “Benzene Waste NESHAP Requirements” shall mean the requirements 

imposed by the National Emission Standard for Benzene Waste Operations, 40 C.F.R. Part 61, 

Subpart FF, and any applicable state, regional, or local regulations that implement, adopt or 

incorporate the Benzene Waste NESHAP. 

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d. “CERCLA/EPCRA Requirements” shall mean the reporting requirements 

for a given release of a hazardous substance imposed by Section 103(a) of CERCLA, 42 U.S.C. 

§ 9603(a), and Section 304 of EPCRA, 42 U.S.C. § 11004. 

e. “LDAR Requirements” shall mean the requirements relating to equipment 

in light liquid service and gas and/or vapor service set forth at 40 C.F.R. Part 60, Subpart GGG; 

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

applicable state, regional, or local regulations or State Implementation Plan requirements that 

implement, adopt or incorporate those federal regulations. 

f. “Post-Lodging Compliance Dates” shall mean any dates in this Section 

XVI after the Date of Lodging (and/or after the Entry Date). Post-Lodging Compliance Dates 

include dates certain (e.g., “December 31, 2005”), dates after Lodging represented in terms of 

time after the Date of Lodging or the Entry Date (e.g., “180 days after the Date of Lodging” or 

“180 days after the Entry Date”), and dates after Lodging represented by actions taken (e.g., 

“Date of Certification”). 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 of this Consent Decree. 

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

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

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

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

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

construction or modification up to the following dates: 

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Unit Pollutant Date 

Baton Rouge PCLA 2 SO2 January 1, 2006 

NOx 455 days after the Entry Date 

Baton Rouge PCLA 3 SO2 January 1, 2006 

NOx 455 days after the Entry Date 

Baytown FCCU 2 SO2 December 31, 2009 

NOx June 30, 2010 

Baytown FCCU 3 SO2 Entry Date 

NOx June 30, 2010 

Beaumont FCCU SO2 Entry Date 

NOx October 1, 2009 

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

Final SO2 Limit is established by 

election of Option A under 

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

date on which a Final SO2 Limit is 

established by election of Option B 

under Subparagraph 29.b.(2) 

NOx December 31, 2008 

Joliet FCCU SO2 December 31, 2008 

NOx December 31, 2012 

Torrance FCCU SO2 Entry Date 

NOx Entry Date 

All Combustion Devices listed 

in Appendix A NOx September 30, 2010 

All heaters and boilers other 

than those in Appendix A NOx Entry Date 

All heaters and boilers listed 

in Appendix C SO2 Dates listed in or derived from 

Appendix C 

All heaters and boilers other 

than those listed in Appendix C SO2 Entry Date 

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All Other Fuel Gas Combustion 

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

Appendix D 

238. Conditional Resolution of Liability for PM Emissions Under the Applicable 

NSR/PSD Requirements. With respect to emissions of PM from an FCCU at a Covered 

Refinery, if and when ExxonMobil accepts an emission limit of 0.5 pound PM per 1000 pounds 

of coke burned for the particular FCCU pursuant to Paragraph 35 and demonstrates compliance 

by conducting a performance test representative of normal operating conditions for the particular 

FCCU, then all civil liability of ExxonMobil to the United States and to the Applicable 

Co-Plaintiffs shall be resolved for alleged violations of the Applicable NSR/PSD Requirements 

relating to PM emissions at the particular FCCU resulting from pre-Lodging construction or 

modification of the particular FCCU. 

239. Conditional Resolution of Liability for CO Emissions Under the Applicable 

NSR/PSD Requirements. With respect to emissions of CO from an FCCU at a Covered 

Refinery, if and when ExxonMobil accepts the following long-term and short-term emission 

limits at the particular FCCU pursuant to Paragraph 40 and demonstrates compliance using 

CEMS or, where applicable, an AMP at the particular FCCU, then all civil liability of 

ExxonMobil to the United States and to the Applicable Co-Plaintiffs shall be resolved for alleged 

violations of the Applicable NSR/PSD Requirements relating to CO emissions at the particular 

FCCU resulting from pre-Lodging construction or modification of the particular FCCU: 

Long-term limit: 150 ppmvd CO on a 365-day rolling average basis at 0% O2 

Short-term limit: 250 ppmvd CO on a 24-hour rolling average basis at 0% O2 

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240. Reservation of Rights regarding Applicable NSR/PSD Requirements: 

Release for Violations Continuing After the Date of Lodging Can be Rendered Void. 

Notwithstanding the resolution of liability in Paragraphs 237, 238, and 239, the release of 

liability by the United States and the Applicable Co-Plaintiffs to ExxonMobil for alleged 

violations of the Applicable NSR/PSD Requirements during the period between the Date of 

Lodging of the Consent Decree and the Post-Lodging Compliance Dates shall be rendered void 

for a particular emissions unit if ExxonMobil materially fails to comply with the obligations and 

requirements of Subsections V.B - V.E and V.G for that unit; provided, however, that the release 

in Paragraphs 237, 238, and 239, shall not be rendered void if ExxonMobil remedies such 

material failure and pays any stipulated penalties due as a result of such material failure. 

241. Exclusions from Release Coverage Regarding Applicable NSR/PSD 

Requirements: Construction and/or Modification Not Covered by Paragraphs 237, 238, 

and 239. Notwithstanding the resolution of liability in Paragraphs 237, 238, and 239, nothing in 

this Consent Decree precludes the United States and/or the Applicable Co-Plaintiffs from 

seeking from ExxonMobil, injunctive relief, penalties, or other appropriate relief for violations 

by ExxonMobil of the Applicable NSR/PSD Requirements resulting from construction or 

modification that: (i) commenced prior to or commences after the Date of Lodging of the 

Consent Decree for pollutants or units not covered by the Consent Decree; or (ii) commences 

after the Date of Lodging of the Consent Decree for units covered by this Consent Decree. 

242. Evaluation of Applicable PSD/NSR Requirements Must Occur. 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 any Covered Refinery, are beyond 

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the scope of the release in Paragraphs 237, 238, and 239, and ExxonMobil must evaluate any 

such increases in accordance with the Applicable PSD/NSR Requirements. 

243. Resolution of Liability Regarding Applicable NSPS Subparts A and J 

Requirements. With respect to emissions of the following pollutants from the following units, 

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

and the Applicable Co-Plaintiffs for alleged violations of the Applicable NSPS Subparts A and J 

Requirements from the date that claims of the United States and the Applicable Co-Plaintiffs 

resulting from pre-Lodging construction or modification (including reconstruction) accrued up to 

the following dates: 

Unit 

Baton Rouge PCLA 2 

Baton Rouge PCLA 3 

Baytown FCCU 2 

Baytown FCCU 3 

Beaumont FCCU 

Billings FCCU 

Pollutant 

SO2 

SO2 

SO2 

PM 

CO 

Opacity 

SO2 

PM 

CO 

Opacity 

SO2 

PM 

CO 

Opacity 

PM 

CO 

Opacity 

Date 

January 1, 2006 

January 1, 2006 

December 31, 2006

December 31, 2009

Entry Date

Date of AMP Approval Receipt

Entry Date

Entry Date

Entry Date

Date of AMP Approval Receipt

Entry Date

Entry Date

Entry Date

Date of AMP Approval Receipt

December 31, 2006 or December 31,

2008 (depending on the deadline

ultimately required by Subparagraph

34.b)

18 months after Entry Date

December 31, 2006

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Joliet FCCU SO2 December 31, 2008 

PM Entry Date 

CO 18 months after Entry Date 

Opacity Entry Date 

Torrance FCCU SO2 Entry Date 

PM Entry Date 

CO Entry Date 

Opacity Entry Date 

All heaters and boilers listed 

in Appendix C SO2 Dates listed in or derived from 

Appendix C 

All heaters and boilers other 

than those listed in Appendix C SO2 Entry Date 

All Other Fuel Gas Combustion 

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

Appendix D 

Baytown SRP SO2 Entry Date 

Beaumont SRP SO2 Entry Date 

Joliet SRP SO2 December 31, 2008 

Torrance SRP SO2 Entry Date 

NSPS Flaring Devices 

Listed in Appendix G SO2 Dates listed in or derived from 

Appendix G 

244. Reservation of Rights regarding Applicable NSPS Subparts A and J 

Requirements: Release for NSPS Violations Occurring After the Date of Lodging Can be 

Rendered Void. Notwithstanding the resolution of liability in Paragraphs 243, the release of 

liability by the United States and the Applicable Co-Plaintiffs to ExxonMobil for alleged 

violations of any Applicable NSPS Subparts A and J Requirements that occurred between the 

Date of Lodging and the Post-Lodging Compliance Dates shall be rendered void for a particular 

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emissions unit if ExxonMobil materially fails to comply with the obligations and requirements of 

Subsections V.F, V.H, V.I, V.J, V.K, and V.L, and Paragraphs 44-46 and 48-49 for that unit; 

provided, however, that the release in Paragraph 243 shall not be rendered void if ExxonMobil 

remedies such material failure and pays any stipulated penalties due as a result of such material 

failure. 

245. Conditional Resolution of Liability for the Applicable NSPS Subparts A and 

J Requirements for SO2 for the Billings FCCU. With respect to emissions of SO2 from the 

Billings FCCU, if and when ExxonMobil elects to classify the Billings FCCU catalyst 

regenerator as an “affected facility,” as that term is used in the Applicable NSPS Subparts A and 

J Requirements for SO2, and demonstrates compliance as required by the Applicable NSPS 

Subparts A and J Requirements for SO2, then all civil liability of ExxonMobil to the United 

States and to the Applicable Co-Plaintiff shall be resolved for alleged violations of the 

Applicable NSPS Subparts A and J Requirements for SO2 at the Billings FCCU catalyst 

regenerator resulting from pre-Lodging construction or modification (including reconstruction) 

of the Billings FCCU catalyst regenerator. 

246. Resolution of Liability for Certain Potential NSPS Violations Relating to the 

Baton Rouge Refinery. 

a. A single TGU serves as the control device for the 100 Claus Train, the 200 

Claus Train, and the 400 Claus Train at the Baton Rouge Refinery. 

b. The Baton Rouge 100 Claus Train and 200 Claus Train were constructed 

in 1972. 

c. Between 1976 and 1979, ExxonMobil: (i) began operating the Baton 

Rouge TGU; (ii) constructed the 400 Claus Train; and (iii) began routing Tail Gas from the 100 

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Claus Train, the 200 Claus Train, and the 400 Claus Train to the TGU. Those physical changes 

in, and/or changes in the method of operation of, and/or replacement of components are referred 

to collectively in this Paragraph as the “Specified Baton Rouge Sulfur Recovery Project.” 

d. Entry of this Consent Decree shall resolve all civil liability of ExxonMobil 

to the United States and the Applicable Co-Plaintiffs for potential violations of the Applicable 

NSPS Subparts A and J Requirements resulting from the Specified Baton Rouge Sulfur 

Recovery Project. 

246A. Conditional Resolution of Liability for the Applicable NSPS Subparts A and 

J Requirements for CO for the Baton Rouge FCCUs. With respect to emissions of CO from 

the Baton Rouge FCCUs, if at any time prior to termination ExxonMobil elects to classify each 

of the Baton Rouge FCCUs’ catalyst regenerators as an “affected facility,” as that term is used in 

the Applicable NSPS Subparts A and J Requirements for CO, and demonstrates initial 

compliance as required by the Applicable NSPS Subparts A and J Requirements for CO, then all 

civil liability of ExxonMobil to the United States and to the Applicable Co-Plaintiff shall be 

resolved for alleged violations of the Applicable NSPS Subparts A and J Requirements for CO at 

the Baton Rouge FCCUs resulting from Pre-Lodging construction or modification (including 

reconstruction) of the Baton Rouge FCCU catalyst regenerators. 

246B. Conditional Resolution of Liability for the Applicable NSPS Subparts A and 

J Requirements for PM for the Baton Rouge FCCUs. With respect to emissions of PM from 

the Baton Rouge FCCUs, if at any time prior to termination ExxonMobil elects to classify each 

of the Baton Rouge FCCUs’ catalyst regenerators as an “affected facility,” as that term is used in 

the Applicable NSPS Subparts A and J Requirements for PM, and demonstrates initial 

compliance as required by the Applicable NSPS Subparts A and J Requirements for PM, then all 

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civil liability of ExxonMobil to the United States and to the Applicable Co-Plaintiff shall be 

resolved for alleged violations of the Applicable NSPS Subparts A and J Requirements for PM at 

the Baton Rouge FCCUs resulting from Pre-Lodging construction or modification (including 

reconstruction) of the Baton Rouge FCCU catalyst regenerators. 

246C. Conditional Resolution of Liability for the Applicable NSPS Subparts A and 

J Requirements for Opacity for the Baton Rouge FCCUs. With respect to emissions of 

opacity from the Baton Rouge FCCUs, if at any time prior to termination ExxonMobil elects to 

classify each of the Baton Rouge FCCUs’ catalyst regenerators as an “affected facility,” as that 

term is used in the Applicable NSPS Subparts A and J Requirements for opacity, and 

demonstrates initial compliance with the Applicable NSPS Subparts A and J Requirements for 

opacity using an approved AMP, then all civil liability of ExxonMobil to the United States and 

to the Applicable Co-Plaintiff shall be resolved for alleged violations of the Applicable NSPS 

Subparts A and J Requirements for opacity at the Baton Rouge FCCUs resulting from PreLodging construction or modification (including reconstruction) of the Baton Rouge FCCU 

catalyst regenerators. 

247. Prior NSPS Applicability Determinations. Nothing in this Consent Decree 

shall affect the status of any FCCU, 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. 

248. Resolution of Liability Regarding CERCLA/EPCRA Requirements for 

Certain Pre-Lodging Acid Gas Flaring Incidents. Upon receipt by EPA of ExxonMobil’s 

CERCLA/EPCRA Compliance Review Report submitted pursuant to Paragraph 95, this Consent 

Decree shall resolve all civil liability of ExxonMobil to the United States and the Applicable Co182
Plaintiffs for alleged violations of CERCLA/EPCRA Requirements associated with SO2 and H2S 

releases resulting from pre-Lodging Acid Gas Flaring Incidents at the Baton Rouge, Baytown, 

Beaumont, Billings, and Joliet Refineries to the extent that ExxonMobil has identified such 

violations in its CERCLA/EPCRA Compliance Review Report and corrected the violations as 

required by Paragraph 95. 

249. Resolution of Liability Regarding Benzene Waste NESHAP Requirements. 

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

and the Applicable Co-Plaintiffs for alleged violations of Benzene Waste NESHAP 

Requirements at the Covered Refineries that either: (i) commenced and ceased prior to the 

Consent Decree Entry Date; or (ii) are based on events identified in the BWON Compliance 

Review and Verification Report required under Paragraph 100 and are corrected pursuant to the 

requirements of Paragraph 101. 

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

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

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

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

that are identified in the LDAR Initial Audit Report required under Subparagraph 120.b and are 

corrected pursuant to the requirements of Paragraph 121. 

251. Reservation of Rights Regarding CERCLA/EPCRA Requirements, Benzene 

Waste NESHAP Requirements, and LDAR Requirements. Notwithstanding the resolution of 

liability in Paragraphs 248, 249, and 250, nothing in this Consent Decree precludes the United 

States and/or the Applicable Co-Plaintiffs from seeking from ExxonMobil civil penalties and/or 

injunctive relief and/or other equitable relief for violations by ExxonMobil of CERCLA/EPCRA 

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Requirements, Benzene Waste NESHAP Requirements, or LDAR Requirements that either 

(i) commenced prior to the Consent Decree Entry Date and continued after the Entry Date; or 

(ii) commenced after the Consent Decree Entry Date: 

i. if ExxonMobil fails to identify any such violation of CERCLA/EPCRA 

Requirements in its CERCLA/EPCRA Compliance Review Report and correct 

such violation as required by Paragraph 95; 

ii. if ExxonMobil fails to identify any such violation of Benzene Waste NESHAP 

Requirements in its BWON Compliance Review and Verification Report under 

Paragraph 100 and correct such violation as required by Paragraph 101; or 

iii. if ExxonMobil fails to identify any such violation of LDAR Requirements in its 

LDAR Initial Audit Report required under Subparagraph 120.b and correct such 

violation as required by Paragraph 121. 

252. Resolution of Liability for Certain Other Alleged Violations. 

a. Claims Alleged in Certain EPA Notices of Violation and Findings of 

Violation. Entry of this Consent Decree shall resolve all civil liability of ExxonMobil to the 

United States and to the Applicable Co-Plaintiffs for the alleged past violations set forth in: 

(i) Notice of Violation EPA-5-00-IL-26 (dated August 29, 2000); (ii) Finding of Violation 

EPA-5-00-IL-27 (dated August 29, 2000); (iii) Finding of Violation EPA-5-00-IL-28 (dated 

August 29, 2000); (iv) EPA’s Notice of Violation relating to the Baytown Refinery (dated 

January 19, 2001); (v) EPA’s Notice of Violation relating to the Beaumont Refinery (dated 

December 20, 2001); and (vi) EPA’s Notice of Violation and Finding of Violation relating to the 

Baton Rouge, Baytown, Beaumont, and Joliet Refineries (dated August 20, 2002). 

b. Additional Claims Concerning the Billings Refinery. Entry of this 

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

Applicable Co-Plaintiff for the following alleged past violations: (i) alleged violations of the 

CWA, 33 U.S.C. § 1251 et seq., identified during the June 2002 and/or July 2002 EPA 

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inspections at the Billings Refinery, as listed in Appendix I; (ii) alleged violations of RCRA, 

42 U.S.C. § 6901 et seq., identified during the June 2002 and/or July 2002 EPA inspections at 

the Billings Refinery, as listed in Appendix I; (iii) alleged violations of release reporting 

requirements under CERCLA Section 103, 42 U.S.C. § 9603, and EPCRA Section 304, 

42 U.S.C. § 11004, identified during the June 2002 and/or July 2002 EPA inspections at the 

Billings Refinery; and (iv) violations of any corresponding state or local laws or regulations 

arising out of any acts or omissions by ExxonMobil which formed the basis for such alleged 

CWA, RCRA, and CERCLA and EPCRA violations. 

c. Additional Claims Concerning the Joliet Refinery. 

(1) Entry of this Consent Decree shall resolve all civil liability of 

ExxonMobil to the United States and the Applicable Co-Plaintiff for the following 

alleged past violations: (i) alleged violations of RCRA, 42 U.S.C. § 6901 et seq., based 

on alleged past unauthorized treatment, storage, and/or disposal of hazardous waste in the 

diversion basin and/or the equalization/biological treatment unit at Joliet Refinery; 

(ii) alleged violations of RCRA, 42 U.S.C. § 6901 et seq., based on alleged past 

unauthorized treatment, storage, and/or disposal of certain hazardous paint wastes and/or 

certain hazardous sludge wastes on the Joliet Refinery’s Material Staging Area; 

(iii) alleged violations of the CWA, 33 U.S.C. § 1251 et seq., based on alleged past 

unauthorized discharge of pollutants from the Joliet Refinery’s coke pile to navigable 

waters of the United States; (iv) alleged violations of the CWA, 33 U.S.C. § 1251 et seq., 

based on alleged past unpermitted discharge of pollutants or discharge of pollutants in 

excess of the allowable permit limits to navigable waters of the United States, as listed in 

the table of alleged violations attached as Appendix J; (v) alleged violations of the CWA, 

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33 U.S.C. § 1251 et seq., based on any alleged past exceedance of combined outfall 

temperature limits imposed by Special Condition 2 of the Joliet Refinery’s NPDES 

Permit between May 1996 and October 2004; (vi) alleged violations of reporting 

requirements under CERCLA Section 103, 42 U.S.C. § 9603, and EPCRA Section 304, 

42 U.S.C. § 11004, listed in the table of alleged violations attached as Appendix K; and 

(vii) violations of any corresponding state or local laws or regulations arising out of any 

acts or omissions by ExxonMobil which formed the basis for such alleged RCRA, CWA, 

and CERCLA and EPCRA violations. 

(2) Entry of this Consent Decree shall resolve all civil liability of 

ExxonMobil to the Applicable Co-Plaintiff for the alleged past violations at the Joliet 

Refinery specified in Appendix L. 

d. Additional Claims Concerning the Baton Rouge Refinery. Entry of this 

Consent Decree shall resolve all civil liability of ExxonMobil to the Applicable Co-Plaintiff for 

the alleged past violations at the Baton Rouge Refinery specified in Appendix M. 

253. Audit Policy. Nothing in this Consent Decree is intended to limit or disqualify 

ExxonMobil, 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 ExxonMobil discovers during the course of any investigation, audit, or 

enhanced monitoring that ExxonMobil is required to undertake pursuant to this Consent Decree. 

254. Claim/Issue Preclusion. In any subsequent administrative or judicial 

proceeding initiated by the United States or any Applicable Co-Plaintiff for injunctive relief, 

penalties, or other appropriate relief relating to ExxonMobil for alleged violations of the 

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PSD/NSR, NSPS, NESHAP, and/or LDAR requirements, not identified in this Section XVI of 

the Consent Decree and/or the Complaint: 

a. ExxonMobil shall not assert, and may not maintain, any defense or claim 

based upon the principles of waiver, res judicata, collateral estoppel, issue preclusion, or 

claim-splitting. Nor may ExxonMobil assert, or maintain, any other defenses based upon any 

contention that the claims raised by the United States or the Applicable 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 ability of ExxonMobil to assert that the claims are 

deemed resolved by virtue of this Section XVI of the Consent Decree. 

b. The United States and Applicable 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 ExxonMobil 

of any interpretation or guidance issued by EPA related to the matters addressed in this Consent 

Decree. 

255. Imminent and Substantial Endangerment. Nothing in this Consent Decree 

shall be construed to limit the authority of the United States or of the Applicable Co-Plaintiffs to 

undertake any action against any person, including ExxonMobil, to abate or correct conditions 

which may present an imminent and substantial endangerment to the public health, welfare, or 

the environment. 

XVII. GENERAL PROVISIONS 

256. Other Laws. Except as specifically provided by this Consent Decree, nothing in 

this Consent Decree shall relieve ExxonMobil of its obligation to comply with all applicable 

federal, state and local laws and regulations, permits, and administrative orders, including, but 

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not limited to, more stringent standards. In addition, nothing in this Consent Decree shall be 

construed to prohibit or prevent the United States or the Co-Plaintiffs from developing, 

implementing, and enforcing more stringent standards subsequent to the Date of Lodging of this 

Consent Decree through rulemaking, the permit process, or as otherwise authorized or required 

under federal, state, regional, or local laws and regulations. In addition, except as otherwise 

expressly provided in this Consent Decree, nothing in this Consent Decree is intended to 

eliminate, limit or otherwise restrict any compliance options, exceptions, exclusions, waivers, 

variances, or other right otherwise provided or available to ExxonMobil under any applicable 

statute, regulation, ordinance, regulatory or statutory determination, or permitting process. 

Subject to Section XVI (Effect of Settlement) and except as provided under Section XI 

(Stipulated Penalties), nothing contained in this Consent Decree shall be construed to prevent, 

alter or limit the United States’ and the Applicable Co-Plaintiff’s rights to seek or obtain other 

remedies or sanctions against ExxonMobil available under other federal, state or local statutes or 

regulations, in the event that ExxonMobil violates this Consent Decree or the statutes and 

regulations applicable to violations of this Consent Decree. This shall include the United States’ 

and the Applicable Co-Plaintiff’s right to invoke the authority of the Court to order 

ExxonMobil’s compliance with this Consent Decree in a subsequent contempt action. 

256A. Changes to Law. In the event that during the term of this Consent Decree there 

is a change in the statutes or regulations that provide the underlying basis for the Consent Decree 

such that ExxonMobil would not otherwise be required to perform any of the obligations herein 

or would have the option to undertake or demonstrate compliance in an alternative or different 

manner, ExxonMobil may petition the Court for relief from any such requirements, in 

accordance with Rule 60 of the Federal Rules of Civil Procedure. However, if ExxonMobil 

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applies to the Court for relief under this Paragraph, the United States and the Applicable CoPlaintiff reserve the right to seek to void all or part of the resolution of liability reflected in 

Section XVI (Effect of Settlement). Nothing in this Paragraph is intended to enlarge the Parties’ 

rights under Rule 60, nor is this Paragraph intended to confer on any Party any independent 

basis, outside of Rule 60, for seeking such relief. This Paragraph 256A does not apply to 

ExxonMobil’s obligation to complete the environmentally beneficial projects referred to in 

Section VIII of this Consent Decree. 

257. Post-Permit Violations. Nothing in this Consent Decree shall be construed to 

prevent or limit the right of the United States or the Applicable Co-Plaintiffs to seek injunctive 

or monetary relief for violations of permits issued as a result of the procedure required under 

Subsection V.Q of this Decree; provided, however, that with respect to civil monetary relief, the 

United States or the Applicable Co-Plaintiff must elect between filing a new action for such 

monetary relief or seeking stipulated penalties under this Consent Decree, if stipulated penalties 

also are available for the alleged violation(s). 

258. Compliance with Certain Emission Limits. 

a. For the purposes of determining compliance with rolling average limits 

required under this Consent Decree: (i) at least 365 days is required after the initial compliance 

date for an applicable 365-day rolling average limit in order to have sufficient data to evaluate 

compliance with such 365-day rolling average limit; and (ii) at least 7 days is required after the 

initial compliance date for an applicable 7-day rolling average limit in order to have sufficient 

data to evaluate compliance with a 7-day rolling average limit. Accordingly: (i) each applicable 

365-day rolling average limit shall become enforceable commencing 365 days after the date set 

forth in this Consent Decree as the date by which ExxonMobil shall begin complying with such 

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limit; and (ii) each applicable 7-day rolling average limit set out above shall become enforceable 

commencing 7 days after the date set forth in this Consent Decree as the date by which 

ExxonMobil shall begin complying with such limit. 

b. If ExxonMobil proposes to use an alternative monitoring plan to monitor 

an FCCU’s compliance with an applicable emission limit during certain specified periods – as 

provided by Subparagraph 19.c, Paragraph 20 , 31, or 41, or Subparagraph 44.d – then 

ExxonMobil shall use its best efforts to submit a timely and complete application for approval of 

the proposed alternative monitoring plan, so that EPA can act on the application in a timely 

fashion. ExxonMobil shall use the proposed alternative monitoring plan to monitor compliance, 

if necessary, to meet the requirement to use an alternative monitoring plan while EPA is 

considering ExxonMobil’s application (such as if there is a period of Malfunction while the 

application remains under EPA review). If EPA approves any such proposed alternative 

monitoring plan, ExxonMobil shall use the EPA-approved alternative monitoring plan to monitor 

compliance during the specified periods, as provided by Subparagraph 19.c, Paragraph 20 , 31, 

or 41, or Subparagraph 44.d. If EPA disapproves a proposed alternative monitoring plan, 

ExxonMobil shall submit to EPA for approval a substitute plan for compliance monitoring 

within ninety (90) days of receiving notice of the disapproval. Such substitute plan may include 

a revised alternative monitoring plan application, physical or operational changes to the 

equipment, or additional or different monitoring. 

259. Startup, Shutdown, Malfunction. Notwithstanding the provisions of this 

Consent Decree regarding startup, shutdown, and Malfunction, this Consent Decree does not 

exempt ExxonMobil from the requirements of state laws and regulations or from the 

requirements of any permits or plan approvals issued to ExxonMobil, as these laws, regulations, 

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permits, and/or plan approvals may apply to startups, shutdowns, and Malfunctions at the 

Covered Refineries. 

260. Failure of Compliance. The United States and the Applicable Co-Plaintiffs do 

not, by their consent to the entry of this Consent Decree, warrant or aver in any manner that 

ExxonMobil’s complete compliance with the Consent Decree will result in future compliance 

with the provisions of the Clean Air Act and/or corresponding state or local laws. 

Notwithstanding the review or approval by the United States or the Applicable Co-Plaintiff, 

including their applicable state agencies, of any plans, reports, policies or procedures formulated 

pursuant to the Consent Decree, ExxonMobil shall remain solely responsible for compliance 

with the terms of the Consent Decree, all applicable permits, and all applicable federal, state and 

local laws and regulations, except as provided in Section XIV (Force Majeure). 

261. Service of Process. ExxonMobil hereby agrees to accept service of process by 

mail with respect to all matters arising under or relating to the Consent Decree and to waive the 

formal service requirements set forth in Rule 4 of the Federal Rules of Civil Procedure and any 

applicable local rules of this Court, including but not limited to, service of a summons. The 

persons identified by ExxonMobil at Paragraph 266 (Notice) are authorized to accept service of 

process with respect to all matters arising under or relating to the Consent Decree. 

262. Post-Lodging/Pre-Entry Obligations. Obligations of ExxonMobil under this 

Consent Decree to perform duties scheduled to occur after the Date of Lodging of the Consent 

Decree, but prior to the Entry Date, shall be legally enforceable on and after the Entry Date. 

Liability for stipulated penalties, if applicable, shall accrue for violation of such obligations and 

payment of such stipulated penalties may be demanded by the United States and/or the 

Applicable Co-Plaintiffs as provided in this Consent Decree, provided that stipulated penalties 

191
that may have accrued between the Date of Lodging of the Consent Decree and the Entry Date 

may not be collected unless and until this Consent Decree is entered by the Court. 

263. Costs. The United States, the Co-Plaintiffs, and ExxonMobil shall each bear their 

own costs and attorneys’ fees. 

264. Public Documents. All information and documents submitted by ExxonMobil to 

EPA and the Applicable Co-Plaintiffs 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. 

265. Public Notice and Comment. The Parties agree that the Consent Decree may be 

entered upon compliance with the public notice procedures set forth at 28 C.F.R. § 50.7, and 

upon notice to this Court from the United States Department of Justice requesting entry of the 

Consent Decree. The United States reserves the right to withdraw or withhold its consent to the 

Consent Decree if public 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 the State of Louisiana, through the LDEQ, and entry of this Consent 

Decree is subject to the requirements of La. Rev. Stat. Ann. § 30:2050.7, which provides for 

public notice of this Consent Decree in newspapers of general circulation and the official 

journals of parishes in which ExxonMobil facilities are located, an opportunity for public 

comment, consideration of any comments, and concurrence by the Louisiana Attorney General. 

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

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

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

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

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

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

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

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

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

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

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

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

As to the United States: 

Chief 

Environmental Enforcement Section 

Environment and Natural Resources Division 

U.S. Department of Justice 

P.O. Box 7611, Ben Franklin Station 

Washington, DC 20044-7611

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

As to EPA: 

EPA Headquarters: 

U.S. Environmental Protection Agency

Director, Air Enforcement Division

Office of Regulatory Enforcement

Ariel Rios Building

1200 Pennsylvania Avenue, N.W.

Mail Code 2242-A

Washington, DC 20460

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with a hard copy to

Director, Air Enforcement Division

Office of Regulatory Enforcement

c/o Matrix Environmental & Geotechnical Services

215 Ridgedale Avenue

Florham Park, NJ 07932

and an electronic copy to

neichlin@matrixengineering.com

foley.patrick@epa.gov

EPA Region 5: 

Air and Radiation Division

U.S. EPA, Region 5

77 West Jackson Blvd. (AE-17J)

Chicago, IL 60604

Attn: Compliance Tracker

and

Office of Regional Counsel

U.S. EPA, Region 5

77 West Jackson Blvd. (C-14J)

Chicago, IL 60604

EPA Region 6: 

Chief

Air, Toxics, and Inspections Coordination Branch

Environmental Protection Agency, Region 6

1445 Ross Avenue

Dallas, Texas 75202-2733

EPA Region 8: 

Air Program Coordinator

U.S. Environmental Protection Agency, Region 8

Montana Office

10 W. 15th St., Suite 3200

Helena, MT 59626

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EPA Region 9: 

Director

Air Division

Mail Code AIR-1

USEPA Region 9

75 Hawthorne Street

San Francisco, CA 94105

As to the State of Illinois: 

Manager Compliance and Enforcement Section

Illinois Environmental Protection Agency

1021 North Grand Avenue, East

P.O. Box 19276

Springfield, IL 62794

and

Field Operations Section

Illinois Environmental Protection Agency

9511 West Harrison

Des Plaines, IL 60016

and 

Maureen Wozniak

Assistant Counsel

Illinois Environmental Protection Agency

1021 North Grand Avenue, East

P.O. Box 19276

Springfield, IL 62794

As to the State of Louisiana: 

Peggy M. Hatch

Administrator, Enforcement Division

Office of Environmental Compliance

Louisiana Department of Environmental Quality

P.O. Box 4312

Baton Rouge, LA 70821-4312

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As to the State of Montana: 

Enforcement Division Administrator

Montana Department of Environmental Quality

P.O. Box 200901

Helena, MT 59620-0901

and

Bureau Chief

Air Resources Management Bureau

Montana Department of Environmental Quality

P.O. Box 200901

Helena, MT 59620-0901

As to ExxonMobil: 

Assistant General Counsel, Litigation

Law Department

Exxon Mobil Corporation

800 Bell Street

ExxonMobil Building, Room 1503B

Houston, TX 77022

Tel. 713-656-3431

Fax 713-656-7719

and

Downstream Environment and Global Compliance Manager

Exxon Mobil Corporation

3225 Gallows Road

Room 8B 0233

Fairfax, VA 22037-0001

With a copy to each applicable refinery as shown below: 

As to Baton Rouge: 

Refinery Manager

ExxonMobil Baton Rouge Refinery

P.O. Box 551

Baton Rouge, LA 70821-0551

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As to Baytown: 

Refinery Manager

ExxonMobil Baytown Refinery

P.O. Box 3950

Baytown, TX 77522-3950

As to Beaumont: 

Refinery Manager

ExxonMobil Beaumont Refinery

P.O. Box 3311

Beaumont, TX 77704

As to Billings: 

Refinery Manager

ExxonMobil Billings Refinery

P.O. Box 1163

Billings, MT 59103

As to Joliet: 

Refinery Manager

ExxonMobil Joliet Refinery

P.O. Box 874

Joliet, IL 60434

As to Torrance: 

Refinery Manager

ExxonMobil Torrance Refinery

3700 W. 190th Street

Torrance, CA 90509-2929

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. 

267. Approvals. All EPA approvals or comments required under this Consent Decree 

shall be made in writing. All approvals by an Applicable Co-Plaintiff shall be sent from the 

offices identified in Paragraph 266 (Notice). 

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268. Paperwork Reduction Act. The United States has determined that the 

information required to be maintained or submitted pursuant to this Consent Decree is not 

subject to the Paperwork Reduction Act of 1980, 44 U.S.C. §§ 3501 et seq. 

269. Consent Decree Modifications. The Consent Decree contains the entire 

agreement of the Parties and shall not be modified by any prior oral or written agreement, 

representation or understanding. Prior drafts of the Consent Decree shall not be used in any 

action involving the interpretation or enforcement of the Consent Decree. Non-material 

modifications to this Consent Decree shall be in writing and shall be effective when signed by 

EPA and ExxonMobil. For the purpose of this Paragraph, non-material modifications include, 

but are not be limited to: (i) any modifications to the frequency of reporting obligations; and 

(ii) any modifications to schedules that do not extend the ultimate date for compliance with 

emissions limitations following the installation of control equipment or the completion of a 

catalyst additive program. The United States will file non-material modifications with the Court 

on a periodic basis. Material modifications to this Consent Decree shall be in writing, signed by 

EPA, the Applicable Co-Plaintiff, and ExxonMobil, and shall be effective upon approval by the 

Court. 

XVIII. TERMINATION 

270. Prerequisites to Termination. This Consent Decree shall be subject to 

termination upon motion by the United States, in consultation with the Applicable Co-Plaintiffs, 

or ExxonMobil (under the procedure identified in Paragraph 272). Prior to either party seeking 

termination, ExxonMobil shall have completed and satisfied all of the following requirements 

with respect to this Consent Decree: 

i. installation of control technology systems as specified in this Consent Decree; 

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ii. compliance with all provisions contained in this Consent Decree, which 

compliance may be established for specific parts of the Consent Decree in 

accordance with Paragraph 271, below; 

iii. 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 Applicable Co-Plaintiffs; 

iv. completion of the SEPs and the payment for BEPs required by Section VIII; 

v. application for and receipt of permits incorporating the surviving emission limits 

and standards established under Subsection V.Q; and 

vi. operation for at least one year of each unit in compliance with the emission limits 

established herein, and certification of such compliance for each unit within the 

first six (6) month period progress report following the conclusion of the 

compliance period. 

271. Certification of Completion. 

a. Prior to moving for termination, ExxonMobil may certify completion for 

one or more of the Covered Refineries of one or more of the following Subsections of the 

Consent Decree, provided that all of the related requirements have been satisfied: 

i. Subsections V.B - V.F, relating to FCCUs; 

ii. Subsection V.G, relating to Combustion Units; 

iii. Subsection V.H, relating to Heaters, Boilers and Other Fuel Gas Combustion 

Devices; 

iv. Subsection V.I, relating to SRPs; 

v. Subsections V.J - V.L, relating to Flaring; 

vi. Subsections V.N, relating to Benzene Waste NESHAP; 

vii. Subsection V.O, relating to LDAR; 

viii. the requirements of Subsection V.P relating to certain other compliance 

requirements at the Billings Refinery; 

199
ix. The requirements of Subsection V.P relating to certain other compliance 

requirements at the Joliet Refinery; and 

x. Section VIII, relating to Environmentally Beneficial Projects. 

b. Within 90 days after ExxonMobil concludes that any of the parts of the 

Consent Decree identified in this Paragraph 271 have been completed, ExxonMobil may submit 

a written report to the Parties listed in Paragraph 266 (Notice) describing the activities 

undertaken and certifying that the applicable Paragraphs have been completed in full satisfaction 

of the requirements of this Consent Decree, and that ExxonMobil is in substantial and material 

compliance with all of the other requirements of the Consent Decree. The report shall contain 

the following statement, signed by a responsible corporate official of ExxonMobil: 

To the best of my 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 of fine and imprisonment for knowing 

violations. 

c. Upon receipt of ExxonMobil’s certification, EPA, after reasonable 

opportunity for review and comment by the Applicable Co-Plaintiffs, shall notify ExxonMobil 

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 ExxonMobil’s certification is that it is in current compliance with all 

such obligations. 

i. If EPA concludes that the requirements have not been fully complied with, EPA 

shall notify ExxonMobil as to the activities that must be undertaken to complete 

the applicable Paragraphs of the Consent Decree. ExxonMobil 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). 

200
ii. If EPA concludes that the requirements of the applicable Paragraphs have been 

completed in accordance with this Consent Decree, EPA will so certify in writing 

to ExxonMobil. This certification shall constitute the certification of completion 

of the applicable Paragraphs for purposes of this Consent Decree. 

d. Nothing in Subparagraph 271.c shall preclude the United States or an 

Applicable Co-Plaintiff from seeking stipulated penalties for a violation of any of the 

requirements of the Consent Decree regardless of whether a Certification of Completion has 

been issued under Paragraph 271. In addition, nothing in Subparagraph 271.c shall permit 

ExxonMobil to fail to implement any ongoing obligations under the Consent Decree regardless 

of whether a Certification of Completion has been issued with respect to Paragraph 271 of the 

Consent Decree. 

272. Termination Procedure. At such time as ExxonMobil believes that it has 

satisfied the requirements for termination set forth in Paragraph 270, ExxonMobil shall certify 

such compliance and completion to the United States and the Applicable Co-Plaintiffs in writing 

as provided in Paragraph 266 (Notice). Unless, within 120 days of receipt of ExxonMobil’s 

certification under this Paragraph, either the United States or the Applicable Co-Plaintiff objects 

in writing with specific reasons, ExxonMobil may move this Court for an order that this Consent 

Decree be terminated. If either the United States or the Applicable Co-Plaintiff objects to the 

certification by ExxonMobil under this Paragraph, then the matter shall be submitted to the 

Court for resolution under Section XV (Retention of Jurisdiction/Dispute Resolution) of this 

Consent Decree. In such case, ExxonMobil shall bear the burden of proving that this Consent 

Decree should be terminated. 

273. Termination of this Consent Decree shall not terminate the obligations specified 

by Paragraph 145. 

201
XIX. SIGNATORIES 

274. Each of the undersigned representatives certifies that he or she is fully authorized 

to enter into the Consent Decree on behalf of such Parties, and to execute and to bind such 

Parties to the Consent Decree. This Consent Decree may be signed in counterparts. 

Dated and entered this _______ day of __________, 2005 

_______________________________ 

UNITED STATES DISTRICT JUDGE 

202
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

Date: ___________________ 

Date: ___________________ 

FOR THE UNITED STATES OF AMERICA

___________________________________

KELLY A. JOHNSON

Acting Assistant Attorney General

Environment and Natural Resources Division

U.S. Department of Justice

Washington, DC 20530

___________________________________

RANDALL M. STONE

Trial Attorney

Environmental Enforcement Section

Environment and Natural Resources Division

U.S. Department of Justice

P.O. Box 7611

Washington, DC 20044-7611

PATRICK J. FITZGERALD

United States Attorney

LINDA WAWZENSKI

Assistant United States Attorney

Northern District of Illinois

219 S. Dearborn Street – 5th Floor

Chicago, IL 60604
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

Date: ___________________ 

FOR THE U.S. ENVIRONMENTAL

PROTECTION AGENCY

___________________________________

GRANTA Y. NAKAYAMA

Assistant Administrator for 

Enforcement and Compliance Assurance

United States Environmental Protection Agency

1200 Pennsylvania Avenue, N.W.

Washington, DC 20460
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

Date: ___________________ 

Date: ___________________ 

FOR THE PEOPLE OF 

THE STATE OF ILLINOIS

ex rel. LISA MADIGAN, Attorney General

of the State of Illinois

MATTHEW J. DUNN, Chief

Environmental Enforcement/Asbestos Litigation

Division

___________________________________

ROSEMARIE CAZEAU, Chief

Environmental Bureau

Assistant Attorney General

188 West Randolph St. – 20th Floor

Chicago, IL 60601

FOR THE ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

___________________________________

ROBERT A. MESSINA

Chief Legal Counsel
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

Date: ___________________ 

Date: ___________________ 

Date: ___________________ 

FOR THE STATE OF LOUISIANA

CHARLES C. FOTI, JR.

Attorney General

___________________________________

Assistant Attorney General

Louisiana Department of Justice

P.O. Box 94005

Baton Rouge, LA 70804-9005

FOR THE LOUISIANA DEPARTMENT OF

ENVIRONMENTAL QUALITY 

___________________________________

HAROLD LEGGETT, Ph.D.

Assistant Secretary

Office of Environmental Compliance

Louisiana Department of Environmental Quality

P.O. Box 4312

Baton Rouge, LA 70821-4301

___________________________________

TED R. BROYLES, II 

Attorney III

Office of the Secretary

Legal Affairs Division

Louisiana Department of Environmental Quality

P.O. Box 4302

Baton Rouge, LA 70821-4302
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

FOR THE STATE OF MONTANA 

Date: ___________________ ___________________________________ 

RICHARD OPPER 

Director 

Montana Department of Environmental Quality 

P.O. Box 200901 

Helena, MT 59620-0901 

Date: ___________________ ___________________________________ 

DAVID RUSOFF 

Special Assistant Attorney General 

Montana Department of Environmental Quality 

P.O. Box 200901 

Helena, MT 59620-0901 
THE UNDERSIGNED PARTY enters into this Consent Decree in:

United States v. Exxon Mobil Corporation and ExxonMobil Oil Corporation (N.D. Ill.)

Date: ___________________ 

Date: ___________________ 

FOR DEFENDANT 

EXXON MOBIL CORPORATION

___________________________________

Donald H. Daigle

Vice President Refining

ExxonMobil Refining & Supply Company 

(a division of Exxon Mobil Corporation)

3225 Gallows Road

Fairfax, VA 22037

FOR DEFENDANT 

EXXONMOBIL OIL CORPORATION

___________________________________

Ian F. Scoble

Attorney-in-Fact

3225 Gallows Road

Fairfax, VA 22037
Appendix A: Information on Combustion Units Greater Than 40 mmBtu/hr 

A-1: Baytown Refinery 

Unit Source 

Maximum Heat 

Input Capacity, 

mmBtu/hr (HHV) 

2000/2001 

NOx Emission 

Rate, 

lb/mmBtu 

(HHV) 

Basis for NOx Factor 

2000/2001 

Average Annual 

Utilization Rate, 

mmBtu/hr (HHV) 

2000/2001 

Average 

NOx, TPY 

BH-6 B-64 380 0.114 January 7, 1994 Stack Test 104 52 

CLEU-1 B-2 132 0.111 August 25, 2000 Stack Test 50 24 

CLEU-2 F-1 66 0.280 December 30, 1993 Stack Test 39 48 

CLEU-2 F-2 86 0.136 April 14, 2000 Stack Test 60 36 

CLEU-2 F-3 168 0.018 CEMS 80 6 

DCU F-601 140 0.060 Manufacturer's Specification in 

lb/MBtu; John Zink model PXMR10. 

8 

DCU F-602 140 0.060 Manufacturer's Specification in 

lb/MBtu; John Zink model PXMR10. 

8 

FCCU-3 F-103 186 0.090 August 22, 2000 Stack Test 46 18 

FCCU-3 F-105 142 0.200 June 26, 1998 Stack Test 100 88 

FXK F-301 110 0.067 Manufacturer's Specification in 

lb/MBtu; John Zink model PSMR20M-FXG 

65 19 

GF-1 F-201 126 0.044 August 23, 2000 Stack Test 100 19 

GF-1 F-227 120 0.060 August 24, 2000 Stack Test 96 25 

HCU-1 F-701 195 0.107 August 21, 2000 Stack Test 130 61 

HCU-1 F-810 85 0.084 August 21, 2000 Stack Test 32 12 

HDU-1 F-701 75 0.160 December 6, 1993 Stack Test 29 20 

HDU-1 F-702 75 0.200 December 6, 1993 Stack Test 45 39 

HF-3 F-1 302 0.080 CEMS 189 66 

HF-3 F-2 331 0.070 CEMS 130 40 

HF-3 F-3 229 0.074 CEMS 94 30 

HF-3 F-4 157 0.069 April 14, 2000 Stack Test 70 21 

HF-3 F-7 85 0.140 TCEQ 16 

HF-4 F-401 399 0.031 CEMS 276 37 

HF-4 F-402 398 0.026 CEMS 167 19 

HF-4 F-403 294 0.074 CEMS; NG ULNB installed Nov-01 129 42 

HF-4 F-404/5 288 0.065 CEMS 132 38 

HGU-1 F-101 386 0.127 CEMS 318 177 

HGU-1 F-121 386 0.127 CEMS 7 4 

HU-5A F-501 89 0.180 January 18, 1994 Stack Test 40 32 

HU-5B F-551 53 0.190 January 18, 1994 Stack Test 21 17 

HU-6A F-101 47 0.120 January 18, 1994 Stack Test 32 17 

HU-6B F-201 82 0.133 January 19, 1994 Stack Test 38 22 

KHF F-901 72 0.065 Manufacturer's Specification in 

lb/MBtu; John Zink model PSMR-20 

57 16 

LEFU Col 14 F-804 83 0.080 March 23, 1994 Stack Test 0 0 

LEFU Col 15 F-601 93 0.130 March 22, 1994 Stack Test 58 33 

LEFU Col 15 F-602 93 0.140 March 22, 1994 Stack Test 56 34 

The Unit started up in Nov-01. 

2 

The Unit started up in Nov-01. 

2 

26 

Appendix A - Page 1
LEFU Col 15 F-603 93 0.120 March 22, 1994 Stack Test 56 29 

LEFU Col 16 F-506 57 0.100 March 22, 1994 Stack Test 8 4 

LHF F-926 45 0.101 January 12, 1994 Stack Test 29 13 

LHU-2 F-3 45 0.140 TCEQ 8 

LXU-1 B-5 180 0.050 January 9, 1992 Stack Test 110 24 

LXU-2 B-1 72 0.110 January 4, 1994 Stack Test 24 12 

LXU-2 B-2 195 0.270 January 4, 1994 Stack Test 127 150 

LXU-2 B-4 195 0.175 September 6, 2000 Stack Test 114 87 

NFU F-902 70 0.150 December 21, 1993 Stack Test 26 17 

NHF F-701 135 0.087 September 8, 1995 Stack Test 47 18 

PS-3 F-301 45 0.110 December 27, 1993 Stack Test 33 16 

PS-3 F-302 45 0.170 December 28, 1993 Stack Test 30 22 

PS-3 F-303 292 0.130 December 27, 1993 Stack Test; 

CEMS 3/20/00 through 12/31/01 

209 119 

PS-3 F-305 126 0.102 August 15, 2000 Stack Test 87 39 

PS-7 F-701A 183 0.112 August 18, 2000 stack test for 2000 

& 2001 through July 10; NG ULNB 

installed with new stack test July 

11, 2001 

101 50 

PS-7 F-701B 184 0.136 August 18, 2000 Stack Test 103 61 

PS-7 F-702A 151 0.091 August 16, 2000 Stack Test 83 33 

PS-7 F-702B 140 0.079 August 17, 2000 Stack Test 79 27 

PS-7 F-705 176 0.038 June 22, 1999 Stack Test; PEMS 

started January 1, 2001 

133 22 

PS-7 F-706 151 0.038 June 22, 1999 Stack Test; PEMS 

started January 1, 2001 

114 19 

PS-7 F-707 199 0.022 June 22, 1999 Stack Test; PEMS 

started January 1, 2001 

185 18 

PS-8 F-801 489 0.046 CEMS 397 80 

PS-8 F-802 489 0.036 CEMS 399 63 

PS-8 F-803 122 0.120 January 13, 1994 Stack Test 86 45 

PS-8 F-804 131 0.060 January 12, 1994 Stack Test 86 23 

RHC F-301 80 0.048 November 8, 2000 Stack Test 38 8 

SCU-2 F-703 43 0.040 Manufacturer's Specification (0.02 

lb/MBtu); Callidus model CUB10...using 0.04 lb/MBtu for 

emissions calculations 

4 

SFU F-751 53 0.140 TCEQ 15 

BH-6 GTG-35 289 0.142 December 1993 Stack Test 230 143 

BH-6 GTG-36 289 0.227 December 1993 Stack Test 233 232 

BH-6 GTG-37 289 0.170 May 1995 Stack Test 276 206 

BH-6 GTG-38 618 0.072 CEMS 464 146 

BH-7 GTG-41 397 0.143 October 1999 Stack Test 378 237 

BH-7 GTG-42 397 0.142 October 1999 Stack Test 366 228 

BH-7 GTG-43 397 0.142 October 1999 Stack Test 357 222 

BH-7 GTG-44 397 0.145 October 1999 Stack Test 323 205 

BH-7 GTG-45 618 0.050 CEMS 495 108 

MEK C-4VT 101 0.211 January 1994 Stack Test 100 92 

TOTALS 14071 3976 

13 

1 

25 

Appendix A - Page 2
A-2: Baton Rouge Refinery 

Unit Source 

Maximum Heat 

Input Capacity, 

mmBtu/hr 

(HHV) 

2000/2001 

NOx Emission 

Rate, 

lb/mmBtu 

(HHV) 

Basis for NOx Factor 

2000/2001 

Average Annual 

Utilization Rate, 

mmBtu/hr (HHV) 

2000/2001 

Average 

NOx, TPY 

2 LEU F- 501 227 0.077 January 28, 2002 Stack Test 150 51 

4 LEU F-1 49 0.111 Developed from Test Data from 

other furnaces in 1990 

34 17 

4 LEU-W F-1 96 0.099 January 29, 2002 Stack Test 71 31 

4 LEU-W F-101 182 0.025 January 29, 2002 Stack Test 138 15 

4 LEU-W F-2 96 0.060 January 29, 2002 Stack Test 37 10 

East Coker F-1 266 0.057 January 30, 2002 Stack Test 234 58 

Far East Coker F-501A 158 0.049 January 30, 2002 Stack Test 133 29 

Far East Coker F-501B 158 0.236 November 2002 Test Data 126 130 

Feed Prep F-30 123 0.140 April 2002 Test Data 51 31 

Feed Prep F-31 200 0.031 April 2002 Test Data 171 23 

HCLA F-101 143 0.087 January 31, 2002 Test Data 40 15 

HCN F-201 57 0.085 Developed from Test Data from 

other furnaces in 1990 

21 8 

HCN F-202 72 0.308 Developed from Test Data from 

other furnaces in 1990 

49 66 

HHLA-E F-501 72 0.040 Manufacturer's Specification in 

lb/MBtu; Callidus model LE-CSG10P 

9 

HHLA-S F-201 55 0.071 Developed from Test Data from 

other furnaces in 1990 

21 7 

KDLA F-425 92 0.090 April 2002 Test Data 50 20 

KDLA F-451 189 0.081 January 30, 2002 Stack Test 89 31 

LELA-E F-1 207 0.066 January 30, 2002 Stack Test 112 32 

LELA-S F-3 200 0.070 April 2002 Test Data 133 41 

PCLA-2 F-2 333 0.167 1990 Test Data 291 213 

PCLA-3 F-3 333 0.167 Developed from Test Data from 

other furnaces in 1990 

295 216 

PHLA-2 F-1 151 0.070 April 2002 Test Data 131 40 

PHLA-2 F-3 117 0.065 January 29, 2002 Test Data 101 29 

PHLA-2 F-4 184 0.052 April 2002 Test Data 111 25 

PHLA-2 F-5 55 0.111 Developed from Test Data from 

other furnaces in 1990 

10 5 

PHLA-2 F-7 47 0.083 Developed from Test Data from 

other furnaces in 1990 

26 9 

PHLA-2 F-2 151 0.090 April 2002 Test Data 137 54 

PSLA-10 F-1 290 0.052 January 31, 2002 Test Data 217 49 

PSLA-10 F-101 394 0.032 February 7, 2002 Test Data 327 46 

PSLA-10 F-102 142 0.037 January 31, 2002 Test Data 95 15 

PSLA-10 F-2 177 0.036 January 31, 2002 Test Data 94 15 

PSLA-7 F-1 229 0.224 May 23, 2002 Test Data 212 208 

PSLA-7 F-2 130 0.120 January 28, 2002 Test Data 63 33 

PSLA-8 F-1 180 0.179 April 2002 Test Data 165 129 

PSLA-8 F-2 95 0.082 April 2002 Test Data 57 20 

2 

Appendix A - Page 3
PSLA-9 F-1 290 0.041 January 31, 2002 Test Data 202 36 

PSLA-9 F-2 130 0.034 January 31, 2002 Test Data 80 12 

RHLA-1 F-700 110 0.157 Developed from Test Data from 

other furnaces in 1990 

0 

RHLA-2 F-600 76 0.157 Developed from Test Data from 

other furnaces in 1990 

51 35 

West Coker F-101 264 0.060 January 31, 2002 Test Data 136 36 

TOTAL 6520 1841 

0 

Appendix A - Page 4
A-3: Beaumont Refinery 

Unit Source 

Maximum 

Heat Input 

Capacity, 

mmBtu/hr 

(HHV) 

2000/2001 

NOx

Emission 

Rate, 

lb/mmBtu

(HHV) 

2000 Basis for 

NOx Factor

CHD-1 Charge B1 155 0.132 January 31, 1994 

Stack Test 

CHD2 Charge B1 96 0.096 November 16, 

1992 Stack Test 

CHD2 Reboiler B2 69 0.096 November 16, 

1992 Stack Test 

Coker East B101B 108 0.069 January 25, 1994 

Stack Test 

Coker Far West BA3000 124 0.082 September 14, 

1993 Stack Test 

Coker Mid B101A 108 0.075 September 21, 

1993 Stack Test 

Coker West B101C 108 0.085 April 6, 1993 Stack 

Test 

CUA Crude B1A 253 0.129 December 20, 

1993 Stack Test 

CUA Crude B1B 253 0.217 December 20, 

1993 Stack Test 

CUA Vacuum B2 125 0.055 February 2, 1994 

Stack Test 

CUA Vacuum B3 95 0.074 February 2, 1994 

Stack Test 

CUB Atmospheric H3101 865 0.102 CEMS 

CUB Vacuum N H2001 132 0.113 December 16, 

1992 Stack Test 

CUB Vacuum S H3102 164 0.078 February 1, 1994 

Stack Test 

FCC Feed 

Preheater 

4B2 336 0.089 Mobil Test Data 

Furfural 2 Extract BA1/BA2 61 0.064 February 2, 1994 

Stack Test 

2001 Basis for 

NOx Factor 

2000/2001 

Average 

Annual 

Utilization 

Rate, 

mmBtu/hr 

(HHV) 

2000/2001 

Average NOx, 

TPY 

August 29, 2001 

Stack Test 

62 36 

November 16, 

1992 Stack Test 

19 8 

November 16, 

1992 Stack Test 

37 16 

August 31, 2001 

Stack Test 

58 18 

August 22, 2001 

Stack Test 

59 21 

August 23, 2001 

Stack Test 

63 20 

April 6, 1993 

Stack Test 

53 20 

1993 Stack Test 

through 6/27/01; 

CEMS 6/28/01 

forward 

194 110 

1993 Stack Test 

through 9/28/01; 

CEMS 9/29/01 

forward 

205 194 

August 28, 2001 

Stack Test 

90 22 

February 2, 1994 

Stack Test 

65 21 

CEMS 542 241 

December 16, 

1992 Stack Test 

78 39 

August 24, 2001 

Stack Test 

99 34 

CEMS 1/1/01 

forward 

221 86 

February 2, 1994 

Stack Test 

42 12 

Appendix A - Page 5
HDC Splitter Reb H3305 83 0.090 June 25, 1998 

Stack Test 

1998 Stack Test 

through 3/14/01; 

Manufacturer's 

Specification 

(0.045 #/MBtu, 

LHV) 3/15/01 

forward; Callidus 

model LE-CSG8W (outside) and 

LE-CSG-18W 

(inside)...using 

0.05 lb/MBtu for 

emissions 

calculations. 

51 

HDC Stab Reb H3304 216 0.074 June 26, 1998 

Stack Test 

CEMS 1/1/01 

forward 

142 

Isom Pretreater B1 85 0.074 December 16, 

1993 Stack Test 

December 16, 

1993 Stack Test 

61 

Isom Stab. Reb B2 90 0.110 December 16, 

1993 Stack Test 

December 16, 

1993 Stack Test 

58 

Power Plant 2 Boiler 15 402 0.229 December 15, 

1993 Stack Test 

1993 Stack Test 

through 1/17/01; 

CEMS 1/18/01 

forward 

199 

Power Plant 2 Boiler 16 402 0.232 December 15, 

1993 Stack Test 

1993 Stack Test 

through 1/17/01; 

CEMS 1/18/01 

forward 

220 

Power Plant 2 Boiler 17 402 0.228 December 14, 

1993 Stack Test 

1993 Stack Test 

through 1/17/01; 

CEMS 1/18/01 

forward 

218 

Power Plant 2 Boiler 18 402 0.227 December 15, 

1993 Stack Test 

1993 Stack Test 

through 1/17/01; 

CEMS 1/18/01 

forward 

231 

Power Plant 2 Boiler 19 402 0.154 December 14, 

1993 Stack Test 

1993 Stack Test 

through 1/17/01; 

CEMS 1/18/01 

forward 

232 

Power Plant 2 Boiler 22 844 0.130 May 24, 1979 

Stack Test through 

5/11/00; CEMS 

5/12/00 forward 

CEMS 540 

Power Plant 3 Boiler 32 724 0.225 December 21, 

1993 Stack Test 

1993 Stack Test 

through 1/18/01; 

CEMS 1/19/01 

forward 

492 

Power Plant 3 Boiler 33 713 0.198 December 21, 

1993 Stack Test 

1993 Stack Test 

through 1/18/01; 

CEMS 1/19/01 

forward 

454 

20 

46 

20 

28 

199 

224 

218 

229 

156 

242 

485 

393 

Appendix A - Page 6
Power Plant 3 Boiler 34 713 0.159 December 21, 

1993 Stack Test 

1993 Stack Test 

through 1/18/01; 

CEMS 1/19/01 

forward 

508 354 

PtR3 Debut Reb H3408 99 0.055 Manufacturer's Specification of 0.04 

lb/MBtu (LHV); Callidus model LESCG-8WSP. 

authority required BACT of 0.06 

lb/MBtu...using 0.055 lb/MBtu (HHV) 

for emissions calculations. 

53 13 

PtR3 Pretreater H3401 101 0.115 June 28, 1989 

Stack Test 

June 28, 1989 

Stack Test 

53 27 

PtR3 Reformer H3403-6 660 0.073 CEMS CEMS 307 99 

PtR3 Stripper Reb H3402 84 0.059 December 7, 1994 

Stack Test 

December 7, 

1994 Stack Test 

55 14 

PtR4 Debut Reb B7201 45 0.066 CEMS CEMS 26 8 

PtR4 Depent Reb B7002 160 0.051 January 26, 1994 

Stack Test 

August 21, 2001 

Stack Test 

75 17 

PtR4 Pretreater B7001 132 0.062 January 26, 1994 

Stack Test 

August 30, 2001 

Stack Test 

67 18 

PtR4 Reformer B7101-

7104 

964 0.061 CEMS CEMS 501 135 

TOTALS 10773 3842 

State permitting 

Appendix A - Page 7
A-4: Billings Refinery 

Unit Source 

Maximum Heat 

Input Capacity, 

mmBtu/hr (HHV) 

2000/2001 NOx 

Emission Rate, 

lb/mmBtu 

(HHV) 

Basis for NOx Factor 

2000/2001 

Average Annual 

Utilization Rate, 

mmBtu/hr (HHV) 

2000/2001 

Average NOx, 

TPY 

BOHO B-8 133 0.13 Oct-96 Version of FIRE 

Database, Table 1.4-1 

10 6 

Coker KCOB 146 0.13 Oct-96 Version of FIRE 

Database, Table 1.4-1 

126 72 

Crude F1/401 280 0.13 Oct-96 Version of FIRE 

Database, Table 1.4-1 

228 130 

H2PLT F-551 130 0.13 Oct-96 Version of FIRE 

Database, Table 1.4-1 

91 52 

POFO F-700 107 0.13 Oct-96 Version of FIRE 

Database, Table 1.4-1 

62 35 

TOTALS 796 294 

Appendix A - Page 8
A-5: Joliet Refinery 

Unit Source 

Maximum 

Heat Input 

Capacity, 

mmBtu/hr 

(HHV) 

2000/2001 

NOx Emission 

Rate, 

lb/mmBtu 

(HHV) 

Basis for NOx 

Factor 

2000/2001 

Average Annual 

Utilization Rate 

(Gas), 

mmBtu/hr 

(HHV) 

2000/2001

Average Annual 

Utilization Rate 

(Oil), mmBtu/hr 

(HHV) 

2000/2001

Average 

NOx, TPY 

Alky 7-B-1 138 0.140 Gas / 

0.408 Oil 

FIRE Database, 

Version 5.0 

71 13 63 

Aux.Util. Boiler 55-B-100 340 0.082* October 7, 1982 

Stack Test 

197 0 79 

* Burners replaced in Fall 2002 with CG ULNB; NOx 

factor = 0.07 lb/MBtu (Manufacturer's Specification) 

CHD Charge 3-B-1 158 0.140 FIRE Database, 

Version 5.0 

62 0 39 

CHD Reboiler 3-B-2 129 0.140 FIRE Database, 

Version 5.0 

69 0 36 

Coker 16-B-1A 183 0.110 Manufacturer's 

Specification (0.06 

lb/MBtu); Callidus 

model LE-CFSG3W...using 0.11 

lb/Mbtu for 

emissions per state 

permit application 

130 0 63 

Coker 16-B-1B 183 0.110 Manufacturer's 

Specification (0.06 

lb/MBtu); Callidus 

model LE-CFSG3W...using 0.11 

lb/Mbtu for 

emissions per state 

permit application 

133 0 64 

Crude Preheat 1B3/13B4 240 0.033 Manufacturer's 

Specification in 

lb/MBtu; Callidus 

model LE-CSG8WSP 

212 0 31 

Crude Vac. 13-B-2 277 0.175 Gas / 

0.391 Oil 

Gas: April 24, 1992 

Stack Test; 

Oil: FIRE Database, 

Version 5.0 

156 19 152 

Crude-Atm 1-B-1A 389 0.140 Gas / 

0.391 Oil 

FIRE Database, 

Version 5.0 

220 12 319 

Crude-Atm. 1-B-1B 389 0.140 Gas / 

0.391 Oil 

FIRE Database, 

Version 5.0 

223 10 Included in 1-

B-1A Stack 

FCC Air 

Preheater 

4-B-1 196 0.150 0 0 used only for 

startup 

PreTreater 

Charge 

17-B-1 112 0.140 FIRE Database, 

Version 5.0 

40 0 24 

Appendix A - Page 9
PreTreater 

Reboiler 

17-B-2 164 0.140 FIRE Database, 

Version 5.0 

70 0 

Reformer 2-B-3/4/5/6 680 0.080 Manufacturer's 

Specification in 

lb/Mbtu; John Zink 

model PSFFG-30M 

(2-B-3), PSFFG-45M 

(2-B-4&6) and 

PSFFG-60M (2-B-5) 

336 0 

Reformer 2B-7 78 0.140 FIRE Database, 

Version 5.0 

31 0 

Sat Gas 8-B-1 61 0.140 FIRE Database, 

Version 5.0 

44 0 

TOTALS 3717 

42 

118 

19 

26 

1074 

Appendix A - Page 10
A-6: Torrance Refinery 

Unit Source 

Maximum 

Heat Input 

Capacity, 

mmBtu/hr 

(HHV) 

2000/2001 

NOx Emission 

Rate, 

lb/mmBtu 

(HHV) 

Basis for NOx 

Factor 

2000/2001 

Average Annual 

Utilization Rate, 

mmBtu/hr (HHV) 

2000/2001 Average NOx, TPY 

Cat Hyd - DSU 6F-2 64 0.015 CEMS 22 1 

Crude 1F-1 457 0.012 CEMS 403 22 

Crude 1F-2 161 0.012 CEMS 153 8 

FCC Aux Boiler 2F-4 309 0.165 CEMS 195 142 

FCC Feed Htrtr 25F-1A 60 0.005 CEMS 14 0.3 

FCC Feed Htrtr 25F-2A 60 0.004 CEMS 16 0.2 

FCC Feed Htrtr 25F-1B 60 0.007 CEMS 18 0.5 

FCC Feed 

Hydrotreater 

25F-2B 60 0.006 CEMS 35 1 

FCCU Charge 

Heater 

2F-2 108 0.046 CEMS 48 10 

H2 2 24F-1 931 0.006 CEMS 567 15 

Hydrogen Plant -

GTG 

24J-01 316 0.016 CEMS 277 19 

H21 4F-1E/W 527 0.095 CEMS 351 142 

Hydrocracker 3F-3 129 0.057 CEMS 96 24 

Hydrocracker 3F-4 73 0.060 CEMS 63 17 

N Coker 21F-6 67 0.060 CEMS 54 14 

N Coker 21F-7 67 0.063 CEMS 54 15 

N Coker 21F-8 74 0.056 CEMS 52 13 

Pretreater / 

Reformer No1 

20F-4 79 0.022 CEMS 51 5 

Pretreater / RF 

No1 

20F-1 94 0.175 CEMS 22 16 

Reformer No 2 19F-1 288 0.008 CEMS 218 7 

S Coker 22F-1 126 0.092 CEMS 92 37 

S Coker 22F-2 91 0.092 CEMS 68 27 

S Coker 22F-3 91 0.077 CEMS 61 21 

Utilities 30F-1 340 0.008 CEMS 154 6 

Utilities 30F-2 340 0.008 CEMS 136 5 

Utilities 75F-1 291 0.098 CEMS 160 69 

TOTALS 5263 637 

Appendix A - Page 11
Appendix B: PEMS Program Requirements 

PREDICTIVE EMISSIONS MONITORING SYSTEMS FOR HEATERS 

AND BOILERS WITH CAPACITIES BETWEEN 150 AND 100 mmBTU/HR 

A Predictive Emissions Monitoring Systems (“PEMS”) is a mathematical model that 

predicts the gas concentration of NOx in the stack based on a set of operating data. Consistent 

with the CEMS data frequency requirements of 40 C.F.R. Part 60, the PEMS shall calculate a 

pound per million BTU value at least once every 15 minutes, and all of the 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. ExxonMobil will 

identify and use existing instruments and refinery data sources to provide sufficient data for the 

development and implementation of the PEMS. 

Instrumentation: 

1. Absolute Humidity reading (one instrument per refinery, if available) 

2. Fuel Density, Composition and/or specific gravity - On line readings (it may be 

possible if the 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 

6. Airflow to the firebox (if known or possibly estimated) 

7. Process variable data - 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: 

1. Data will be collected for a period of 7 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 

Appendix B - Page 1 
range that represents 80% to 100% of the normal operating range of the 

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 of the mathematical models and installation of the model into the 

computer. 

The elements of a monitoring protocol for a PEMS will include: 

1. Applicability 

a. Identify source name, location, and emission unit number(s); 

b. Provide expected dates of monitor compliance demonstration testing. 

2. Source 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. Provide a discussion of process 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 of the software and hardware components of 

the PEMS, including manufacturer, type of computer, name(s) of software 

product(s), monitoring technique (e.g., method of emission correlation). 

Appendix B - Page 2 
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)); 

d. List all measurement or sampling locations (e.g., vent or stack location, 

process parameter measurement location, fuel sampling location, work 

stations); 

e. Provide a simplified block flow diagram of the monitoring system 

overlaying process or control device diagram (could be included in Source 

Description and Control Equipment Description); 

f. Provide a description of sensors and analytical devices (e.g., thermocouple 

for temperature, pressure diaphragm for flow rate); 

g. Provide a description of the data acquisition and handling system 

operation including sample calculations (e.g., parameters to be recorded, 

frequency of measurement, 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 of field 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 

a. Perform an initial relative accuracy test (RA test) to verify the 

performance of the PEMS for the equipment’s operating range. The 

PEMS must meet the relative accuracy requirement of the applicable 

Performance Specification in 40 C.F.R. Part 60, Appendix B. The test 

shall utilize the test methods of 40 C.F.R. Part 60, Appendix A; 

b. Identify the most significant independently modifiable parameter affecting 

the emissions. Within the limits of safe unit operation, and typical of the 

Appendix B - Page 3 
anticipated range of operation, test the selected parameter for three RA 

test data sets at the low range, three at the normal operating range and 

three at the high operating range of that parameter, for a total of nine RA 

test data sets. Each RA test data set 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 of the PEMS to detect excessive sensor failure 

modes that would adversely affect PEMS emission determination. 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 significantly from the original 

PEMS value; 

f. The PEMS may use calculated sensor values based upon the mathematical 

relationships established with the other sensors used in the PEMS. 

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 of the input parameters to the PEMS (e.g., transducers, 

sensors, gas chromatograph, periodic laboratory analysis), and a 

description of the sensor validation procedure (e.g., manual or automatic 

check); 

b. Provide a description of routine 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 

QA/QC checks); 

d. List corrective action triggers (e.g., response time deterioration limit on 

pressure sensor, use of statistical process control (SPC) determinations of 

problems, sensor validation alarms); 

e. List trouble-shooting procedures and potential corrective actions; 

f. Provide an inventory of replacement and repair supplies for the sensors; 

Appendix B - Page 4 
g. Specify, for each input parameter to the PEMS, the drift criteria for 

excessive error (e.g., the drift limit of each input sensor that would cause 

the PEMS to exceed relative accuracy requirements); 

h. Conduct a quarterly electronic data accuracy assessment tests of the 

PEMS; 

i. Conduct semiannual RA tests of the PEMS. Annual RA tests may be 

conducted if the most recent RA test result is less than or equal to 7.5%. 

Identify the most significant independently modifiable parameter affecting 

the emissions. Within the limits of safe unit operation and typical of the 

anticipated range of operation, test the selected parameter for three RA 

test data pairs at the low range, three at the normal operating range, and 

three at the high operating range of that parameter for a total of nine RA 

test data sets. Each RA test data set should be between 21 and 60 minutes 

in duration. 

8. PEMS Tuning 

a. Perform tuning of the PEMS provided that the fundamental mathematical 

relationships in the PEMS model are not changed. 

b. Perform tuning of the PEMS in case of sensor recalibration or sensor 

replacement provided that the fundamental mathematical relationships in 

the PEMS model are not changed. 

Appendix B - Page 5 
Appendix C: NSPS Subpart J Compliance Schedule for Certain 

Heaters and Boilers 

Refinery Combustion Device Compliance Date 1/ 

Baton Rouge PHLA-2-F-1 

PHLA-2-F-2 

PHLA-2-F-3 

PHLA-2-F-4 

PHLA-2-F-5 

PHLA-2-F-6 

December 31, 2008 

Baton Rouge FEED PREP F-30 

FEED PREP F-31 

December 31, 2008 

Baton Rouge 4LEU-E F-1 

4LEU-W F-1 

4LEU-W F-2 

December 31, 2008 

Baton Rouge LELA-E F-1 

LELA-S F-4 

December 31, 2008 

Baton Rouge KDLA- F-425 

KDLA F-451 

December 31, 2008 

Baytown LE Unit Heater F-601 

LE Unit Heater F-804 

Submit AMP six months after Entry 

Date for NSPS vent stream 

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

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

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

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

EPA’s approval of the relevant AMP. 

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

emission limitation specified by 40 C.F.R. § 60.104(a)(1) at all times, except when SWS T-23 ammonia 

overhead gas is combusted in the unit as permitted by pertinent provisions of the Montana State 

Implementation Plan. 

Appendix C - Page 1 
Appendix C: NSPS Subpart J Compliance Schedule for Certain

Heaters and Boilers

(continued)

Refinery Combustion Device Compliance Date 3/ 

Beaumont CHD 1 Heater B-1 Submit AMP six months after Entry 

Date for hydrogen vent stream 

Beaumont Continuous Regen Reformer PTR 3 

Heater Box B3403 through H3406 

Submit AMP six months after Entry 

Date for Reformer Regen lock hopper 

vents stream 

Beaumont Continuous Regen Reformer PTR 4 

Heater Box B7101 through B7104 

Submit AMP six months after Entry 

Date for Reformer Regen lock hopper 

vents stream 

Beaumont Crude A B-1A Heater Submit AMP six months after Entry 

Date for South Benzene 

Recovery/Carbon Unit vent stream 

Beaumont Crude A Vacuum Heater B-2 and B-3 Re-route vacuum tower overhead gas to 

fuel gas treatment by no later than 

December 31, 2005 

Joliet Reformer Heaters 2B3 and 2B4 Submit AMP six months after Entry 

Date for Reformer regen lock hopper 

vent stream 

Torrance Reformer Heater 19F-1 Submit AMP two months after next 

regeneration cycle for Reformer regen 

vent stream, but no later than December 

31, 2006 

Torrance Heaters 25F1-A and 25F1-B Submit AMP six months after Entry 

Date for kerosene/LGO dryers stream or 

reroute stream by 12 months after Entry 

Date 

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

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

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

EPA’s approval of the relevant AMP. 

Appendix C - Page 2 
Appendix D: NSPS Subpart J Compliance Schedule for Certain Other Fuel Gas 

Combustion Devices 

Refinery Combustion Device Compliance Date 4/ 

Baton Rouge MVR Combustor/Flare No. 1 AMP pending 

Baton Rouge MVR Combustor/Flare No. 2 AMP pending 

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

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

Baytown Thermal Oxidizer for Loading Racks 

2 & 3 

Submit AMP six months after Entry Date 

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

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

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

overhead gas by no later than December 31, 

2008; 

Submit AMP six months after Entry Date for 

Unsaturated Light Ends Merox Vent stream 

(DSO Offgas stream) 

Joliet NBRU Thermal Vapor Incinerator -

38B-1 

Shutdown, treat, or re-route stream by no 

later than ber 31, 2008 

Joliet SBRU Thermal Vapor Incinerator -

38B-2 

Shutdown, treat, or re-route stream by no 

later than December 31, 2008 

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

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

Torrance Resid Loading Rack Incinerator 

50J-30 

Submit AMP six months after Entry Date 

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

1, 2009 

Decem

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

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

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

EPA’s approval of the relevant AMP. 

Appendix D - Page 1 
Appendix E: 

Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas 

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 

refiner requesting an AMP should provide sufficient information to allow for a determination of 

appropriateness of the AMP for each gas stream/system requested. Such information should 

include, but need not be limited to: 

! A description of the gas stream/system to be considered including submission of a 

portion of the appropriate piping diagrams indicating the boundaries of the 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 in the piping diagrams); 

! An explanation of the conditions that ensures low amounts of sulfur in the gas stream 

(i.e., control equipment or product specifications) at all times; 

! The supporting test results from sampling the requested gas stream/system using 

appropriate H2S monitoring (i.e., detector tube monitoring following the Gas Processor 

Association's: Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using 

Length of Stain Tubes, 1986 Revision), at minimum: 

! for frequently 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 of how the two weeks (or seven samples for infrequently operated gas 

streams/systems) of monitoring results compares to the typical range of H2S 

concentration (fuel quality) expected for the gas stream/system going to the affected fuel 

gas combustion device. (e.g., The two weeks of daily detector tube results for a 

frequently operated loading rack included the entire range of products loaded out, and, 

therefore, should be representative of typical operating conditions affecting H2S content 

in the gas stream going to the loading rack flare); 

! Identification of a representative process parameter that can function as an indicator of a 

stable and low H2S concentration for each fuel gas stream/system, (e.g., review of 

gasoline sulfur content as an indicator of sulfur content in the vapors directed to a loading 

rack flare); 

Appendix E - Page 1 
! Suggested process parameter limit for each stream/system, the rationale for the parameter 

limit and the schedule for the acquisition and review of the process parameter data. The 

refiner will collect the proposed process parameter data in conjunction with the testing of 

the fuel gas stream's stable and low H2S concentration. 

The following shall be used for measuring H2S in fuel gas within these types of AMPs 

unless the refiner requests, in writing, approval of an alternative methodology: 

! Conduct H2S measurement using detector tubes (“length-of-stain tube” type 

measurement); 

! Detector tube ranges 0-10/0-100 ppm (N =10/1) shall be used for routine testing; and 

! Detector tube ranges 0-500 ppm shall be used for testing if measured concentration 

exceeds 100 ppm H2S. 

Data Range and Variability Calculation and Acceptance Criteria 

For each step of the monitoring schedule, sample range and variability will be determined 

by calculating the average plus 3 standard deviations for that test data set. 

! If the 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 step of 

the monitoring schedule. 

Note: 81 ppm is one-half the maximum allowable fuel gas standard under NSPS 

Subpart J, and the Agency believes that using 81 ppm acceptance criteria provides 

a sufficient margin for ensuring that the emission limit is not exceeded under 

normal operating conditions. 

! If the 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 if the average plus 3 standard deviations 

is between 81 ppm and 162 ppm H2S. As an example, approval may be granted based on 

a review of the test data and any pertinent information which demonstrates that sample 

variability during the test period was due to unusual circumstances. Supplemental test 

data may be taken to demonstrate 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, if the data shows an unacceptable range and variability (the average 

plus 3 standard deviations is equal to or greater than 81 ppm H2S), the source will drop 

back to the previous step's monitoring schedule. 

! If at any time, one detector tube sample value 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. 

Appendix E - Page 2 
Monitoring Schedule for Approved AMPs 

For gas streams which must meet product specifications for sulfur content, one time only 

detection tube sampling along with a certification that the gas stream is subject to product or 

pipeline specifications is sufficient for the AMP. If the gas stream composition changes (i.e., 

new gas sources are added), or if the 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 of streams needing one time only monitoring: 

! Certified commercial grade natural gas; 

! Certified commercial grade LPG; 

! Certified commercial grade hydrogen; 

! Gasoline vapors from a loading rack that only loads gasoline meeting a product 

specification for sulfur content. 

For other gas streams, the H2S content of each refinery fuel gas stream/system with an 

approved AMP shall be monitored per the following schedule: 

Step 1: 

The refiner will monitor the selected process parameter for each stream/system, 

according to the established process parameter monitoring or review schedule approved by the 

agency in the AMP, and at times when conducting H2S detector tube sampling. 

Step 2: 

The refiner will conduct random detector tube sampling twice per week for each 

stream/system for a period of six months (52 samples). For fuel gas streams infrequently 

generated and combusted in affected fuel gas combustion devices (i.e., less frequent than biweekly), detector tube samples shall be taken each time the fuel gas stream is generated and 

combusted. A total of at least 24 samples shall be collected for infrequently generated gas 

streams. Monitor and record the selected process parameter in accordance with the established 

schedule, and at times when conducting H2S testing. Move to Step 3 if the calculated range and 

variability of the data meets the established acceptance criteria. Submit test data (raw 

measurements plus calculated average and variability) to the agency quarterly. 

Step 3: 

The refiner will conduct random H2S sampling once per quarter for a period of six 

quarters (6 samples) with a minimum of 1 month between samples. A minimum of 9 samples are 

required for infrequently generated and combusted fuel gas streams before proceeding to Step 4. 

Continue to monitor and record the selected process parameter in accordance with the 

established schedule, and at times when conducting H2S testing. Move to Step 4 if the calculated 

Appendix E - Page 3 
range and variability of the data meets the established acceptance criteria. Submit test data (raw 

measurements plus calculated average and variability) to the agency quarterly. 

Step 4: 

The refiner will conduct random H2S sampling twice per year for a period of two years 

(4 samples); sample randomly in the 1st and 3rd quarters 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 when conducting H2S testing. Move to Step 5 if the calculated 

range and variability of the data meets the established criteria. Submit test data (raw 

measurements plus calculated average and variability) to the agency semiannually. 

Step 5: 

The refiner will continue to conduct testing on semi-annual basis. Testing is to 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 when conducting H2S testing. If any one sample is equal to or 

greater than 81 ppm 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 parameter data indicates a potential change in H2S 

concentration, or a single detector tube sample value is equal to or greater than 81 ppm H2S, then 

the fuel gas stream shall be sampled with detector tubes on a daily basis for 7 days (or for 

infrequently generated gas streams - 7 samples during the same period of an indicated change in 

H2S concentration, or as otherwise approved by the agency). If the average detector tube result 

plus 3 standard deviations for those seven samples is less than 81 ppm H2S, the date and value 

of change in the selected process parameter indicator and the sample results shall be included in 

the next quarterly report, and the refiner shall resume monitoring in accordance with the 

schedule of the current step. If the average plus 3 standard deviations for those seven samples is 

equal to or greater than 81 ppm H2S, sampling shall follow the requirements of Step 7. 

Step 7: 

If sample detector tube data indicates a potential for the emission limit to be exceeded 

(the average plus 3 standard deviations is equal to or greater than 81 ppm H2S), as determined in 

the Data Range and Variability Calculation and Acceptance Criteria or in Step 6, the refiner shall 

notify the agency of those results before the end of the 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, until the agency approves a revised sampling schedule or makes a determination to 

withdraw approval of the 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. 

Appendix E - Page 4 
General Provisions of Approved AMPs 

Upon agency request, the refiner shall conduct a test audit for any gas stream with an 

approved AMP. The audit shall consist of daily detector tube samples collected over a one week 

period (7 samples). For fuel gas streams infrequently generated and combusted in affected fuel 

gas combustion devices, an audit shall consist of 3 consecutive sampling events. (e.g., Rail 

loading may occur once per month, an audit would consist of 3 consecutive loading events.) The 

United States Environmental Protection Agency, with due notice, reserves the right to withdraw 

approval of the AMP for any gas stream/system. 

The source shall keep records of the H2S detector tube test data and the representative 

process parameter data and fuel source for at least two years. 

If a new 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: 

An AMP Application for a Hydrogen Plant PSA Off-Gas Stream Combusted Exclusively in the 

Hydrogen Plant Process Heater: 

Process Description 

Hydrogen production for the refinery by the steam methane reforming process. CO2 is the 

primary impurity in the hydrogen produced; small amounts of CO and methane are also present. 

Unpurified hydrogen is passed over molecular sieve absorbent beds to remove these impurities. 

The off gas from regeneration of the 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 cross over or entry points for sour gas. 

Basis for PSA Off-Gas Low H2S Content

Since PSA off-gas is a byproduct of hydrogen purification, any H2S in the PSA purge gas must 

come from the hydrogen unit feed. Levels of H2S in the PSA gas are negligible because H2S 

must be controlled to prevent deactivation of the unit's catalyst. H2S is a permanent catalyst 

poison. The hydrogen unit has 2 scrubbers to remove H2S poisoning. The scrubbers are operated 

in series. The lead scrubber must exhibit at least a 70% reduction in H2S content. If not, the 

scrubber is taken off line 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 of H2S 

removal and assures maximum scrubbing potential when one scrubber is off line for absorbent 

replacement. 

Appendix E - Page 5 
Process Parameter Monitoring and Suggested Process Parameter Limit 

Operation of the scrubbers is checked on a monthly basis with detector tubes. The feed gas H2S 

content is measured at the inlet and outlet of the lead scrubber. If natural gas is used as hydrogen 

plant feed; both readings are below the 1 ppm detection limit. If refinery fuel gas is the feed gas, 

30 ppm to 40 ppm H2S is normally detected at the inlet. A lead scrubber outlet reading of 10 -12 

ppm H2S would trigger absorbent replacement. The suggested process parameter limit is 20 ppm 

H2S at the lead H2S absorber outlet. Absorber outlet H2S measurements will be taken in 

conjunction with the PSA gas measurements during Steps 2 and 3. 

Appendix E - Page 6 
Appendix F: List of Existing Flaring Devices Operated by Covered Refineries 5/ 

Baton Rouge Refinery 

Flare 5 

Flare 8 

Flare 9 

Flare 17* 

Flare 19* 

Flare 20 

Flare 21 

Flare 23 

Flare 24 

Baytown Refinery 

Flare 3 

Flare 4* 

Flare 5 

Flare 6* 

Flare 11 

Flare 14 

Flare 15 

Flare 16 

Flare 17 

Flare 18 

Flare 19* 

Flare 20 

Flare 21 

Flare 22* 

Flare 25* 

Flare 26* 

Flare 27 

Beaumont Refinery 

High Pressure (HP) Flare

Low Pressure (LP) Flare

FCC Flare

CHD 1 Flare*

CHD 2 Flare*

Coker Flare

Flare 6

Flare 7

Flare 10

Billings Refinery 

Main Flare* 

Turnaround Flare* 

Joliet Refinery 

South Flare 49-B-305b* 

East Flare 49-B-305a* 

Torrance Refinery 

Flare 55F-1

Flare 65F-3*

Flare 65F-4*

Ground Flare 65F-8*

5/ Flaring Devices followed by an asterisk (*) currently are used as Acid Gas Flaring Devices or as dualservice Acid Gas/Hydrocarbon Flaring Devices. Flaring Devices that are not followed by an asterisk 

currently are used solely as Hydrocarbon Flaring Devices. 

Appendix F - Page 1 
Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries 

Refinery Flaring Device Compliance Date 6/ Compliance Method 

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

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

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

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

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

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

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

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

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

Baytown Flare 3 Entry Date Subparagraph 73.a.i 

Baytown Flare 4 Submit AMP six months after Entry Date for 

HF3 vent stream routed to flare downstream from 

flare gas recovery system 

All other streams routed to Flare 4, through flare 

gas recovery system 

Subparagraph 73.a.iii 

Subparagraph 73.a.i 

Baytown Flare 5 Entry Date Subparagraph 73.a.i 

Baytown Flare 6 Entry Date Subparagraph 73.a.i 

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

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

months after Entry Date 

Subparagraph 73.a.iv 

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

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

months after Entry Date 

Subparagraph 73.a.iv 

Baytown Flare 15 Entry Date Subparagraph 73.a.i 

Baytown Flare 16 Entry Date Subparagraph 73.a.i 

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

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

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

EPA’s approval of the relevant AMP. 

Appendix G - Page 1 
Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries (continued) 

Refinery Flaring Device Compliance Date Compliance Method 

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

can be re-routed by that Compliance Date) 

Subparagraph 73.a.i 

Baytown Flare 18 Entry Date Subparagraph 73.a.i 

Baytown Flare 19 Entry Date for emergency service 

Submit AMP six months after entry for 

intermittent low mass sweet streams 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

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

HF4 stream (so that certain streams can be 

re-routed by that Compliance Date) 

Submit AMP six months after Entry Date for 

monitoring HF4 stream when Flare 17 is on 

turnaround 

Subparagraph 73.a.i 

Subparagraph 73.a.iii 

Baytown Flare 21 Entry Date Subparagraph 73.a.i 

Baytown Flare 22 Entry Date for emergency service 

Submit AMP six months after Entry Date for 

monitoring intermittent low mass sweet streams 

when Flare 19 is on turnaround 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

Baytown Flare 25 Entry Date for emergency service 

Submit AMP six months after Entry Date for 

monitoring intermittent refinery fuel gas streams 

and natural gas streams 

Subparagraph 73.a.ii 

Subparagraph 73.a.iii 

Baytown Flare 26 Submit AMP six months after Entry Date for 

monitoring certain sweet streams and nitrogencontaining streams 

Subparagraph 73.a.iii 

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

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

after Entry Date 

Subparagraph 73.a.iv 

Beaumont High Pressure 

(HP) Flare 

42 months after Entry Date (so that flare gas 

recovery system upgrades can be completed by 

that Compliance Date) 

Subparagraph 73.a.i 

Beaumont Low Pressure 

(LP) Flare 

42 months after Entry Date (so that flare gas 

recovery system upgrades can be completed by 

that Compliance Date) 

Subparagraph 73.a.i 

Beaumont FCC Flare 42 months after Entry Date (so that flare gas 

recovery system upgrades can be completed by 

that Compliance Date) 

Subparagraph 73.a.i 

Appendix G - Page 2
Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries (continued) 

Refinery Flaring Device Compliance Date Compliance Method 

Beaumont CHD 1 Flare 42 months after Entry Date Subparagraph 73.a.i, 

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

Beaumont CHD 2 Flare 42 months after Entry Date Subparagraph 73.a.i, 

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

Beaumont Coker Flare 7/ 42 months after Entry Date Subparagraph 73.a.i, 

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

Billings Main Flare 48 months after Entry Date (so that flare gas 

recovery system upgrades can be completed by 

that Compliance Date) 

Subparagraph 73.a.i 

Billings 

Flare 

48 months after Entry Date (so that flare gas 

recovery system upgrades can be completed by 

that Compliance Date) 

Subparagraph 73.a.i 

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

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

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

Torrance Enclosed 

Ground Flare 

65F-8 8/ 

Entry Date Subparagraph 73.a.i 

Turnaround 

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

42 months after the Entry Date, ExxonMobil shall either: (i) complete flare gas recovery system upgrades to 

bring the particular flare into compliance with Subparagraph 73.a.i; or (ii) re-route streams as required to 

bring the particular flare into compliance with Subparagraph 73.a.ii or 73.a.iii. In the first Semi-Annual 

Report that is due under Section IX after that 42 month period, ExxonMobil shall identify and certify 

compliance with a specific compliance method (i.e., either Subparagraph 73.a.i, 73.a.ii, or 73.a.iii ) for each 

of those three Beaumont Refinery flares. 

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

requirement referenced in Subparagraph 75.b.(2) of this Consent Decree; and (ii) is subject to the 

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

Appendix G - Page 3 
Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices 

Operated by Covered Refineries (continued) 

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

Combusted in Certain Baytown Refinery Flaring Devices 

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

and/or Baytown Flare 14 

a. Hydrocracker Unit 1 (HCU-1) 

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

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

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

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

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

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

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

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

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

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

b. FCCU 3 

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

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

c. Hydrofining Unit 9 (HU-9) 

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

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

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

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

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

a. DCU 

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

• D-612 vent (DCU blowdown settling drum) 

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

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

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

Appendix through a non-material modification under Consent Decree Paragraph 269, so long as 

the other conditions of Subparagraph 73.a.iv are met. 

Appendix G - Page 4 
Appendix H: Data Relevant to Billings FCCU Baseline Emissions, Trials, 

Demonstrations, and Final Limits 

As required by Consent Decree Paragraph 30, ExxonMobil shall submit the following 

categories of Billings FCCU 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. FCCU feed rate in barrels per day; 

d. FCCU feed API gravity; 

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

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

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

tower bottoms, vacuum tower bottoms, etc.); 

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

h. CO boiler combustion temperature, if applicable; 

i. Total Catalyst addition and catalyst circulation rates; 

j. Conventional combustion promoter addition rates; 

k. Hourly and daily volume percent oxygen in the regenerator flue gas and at the 

point of CEMs measurement; 

l. Hourly and daily SO2, NOx, and CO mass emission rates in pounds per hour, tons 

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

m. Upon request by EPA, any additional, reasonably available data that EPA 

determines it needs to evaluate . 

Appendix H - Page 1 
Appendix I: Additional Claims Concerning the Billings Refinery Referenced in 

Consent Decree Subparagraph 252.b 

As provided by Consent Decree Subparagraph 252.b, entry of the Consent Decree shall 

resolve all civil liability of ExxonMobil to the United States and the Applicable Co-Plaintiff for 

the following alleged past violations of the CWA and RCRA (including the regulations 

implementing the CWA and RCRA) identified during June 2002 and/or July 2002 EPA 

inspections of the Billings Refinery: 

Alleged CWA Violations 

A. Alleged past violations of NPDES Permit MT0000477, Parts I.C.1.a and I.C.3 based on 

the acute toxicity of samples collected from outfall 001 on December 4, 2001, December 

25, 2001, January 31, 2002, February 26, 2002, March 19, 2002, April 23, 2002, May 28, 

2002, and June 12, 2002; 

B. Alleged past violations of NPDES Permit MT0000477, Part I.C.1. Outfall 002: NonContact Cooling Water based on discharges causing visible oil sheens at outfall 002 

during November 2000, November 2001, February 2002 and March 2002; 

C. Alleged past violations of the General Permit for Stormwater Discharges Associated with 

Industrial Activity MTR 000000 (Authorization 000104) based on: (i) the failure of the 

Billings Refinery Storm Water Pollution Prevention Plan (“SWPPP”) to identify certain 

potential sources of pollution to storm water discharges associated with the scrap metal 

yard located in the South Refinery Drainage Area; and (ii) the SWPPP’s failure to 

provide an up-to date identification of the individual responsible for implementing the 

SWPPP. 

D. Alleged past violations of 40 C.F.R. § 112.5(a) based on failure to incorporate a 

December 29, 1999 amendment to the Billings Refinery’s Spill Prevention Control and 

Countermeasure Plan (“SPCC Plan”) into the February 28, 2000 version of the Refinery’s 

SPCC Plan. 

E. Alleged past CWA violations concerning management of materials in Tank 350 

(identified by EPA during its July 2002 inspection). 

Alleged RCRA Violations 

F. Alleged past violations of RCRA requirements based on storage of the following 

uncharacterized wastes in the scrap yard and/or lay down area at the Billings Refinery: 

heat exchanger bundles containing possible heat exchanger bundle cleaning sludge, 

welding rods, discarded aerosol cans, discarded insulation, and refrigeration and air 

conditioning equipment. 

G. Alleged past violations of RCRA requirements based on application of waste at the 

Billings Refinery’s Land Treatment Unit during periods of high winds. 

Appendix I - Page 1 
--

Appendix J: Table of Alleged CWA Violations at the Joliet Refinery Referenced in 

Consent Decree Subparagraph 252.c.(1) 

Month and Year Outfall No. Parameter and Other Details 

1/1996 003 total organic carbon (daily maximum mg/l) 

2/1996 003 total organic carbon (daily maximum mg/l) 

3/1996 001 biological oxygen demand (daily maximum mg/l - 4 days during month) 

3/1996 001 total suspended solids (daily maximum mg/l - 2 days during month) 

4/1996 001 biological oxygen demand (daily maximum mg/l) 

4/1996 001 ammonia (daily maximum mg/l) 

4/1996 003 total organic carbon (daily maximum mg/l) 

6/1996 003 total organic carbon (daily maximum mg/l) 

7/1996 003 total organic carbon (daily maximum mg/l) 

9/1996 001 total suspended solids (monthly average mg/l) 

9/1996 001 total suspended solids (daily maximum mg/l) 

5/1997 001 total suspended solids (daily maximum mg/l) 

5/1997 001 ammonia (daily maximum mg/l) 

12/1997 002 total organic carbon (daily maximum mg/l) 

6/1998 001, 002, 003 total residual chlorine (daily maximum mg/l) 

12/1998 003 total organic carbon (daily maximum mg/l) 

1/1999 001 total suspended solids (monthly average lb/day) 

1/1999 001 total suspended solids (daily maximum mg/l) 

6/1999 001 total suspended solids (daily maximum mg/l) 

6/1999 001 total suspended solids (daily maximum lb/day) 

6/1999 oil sheen on river 

7/1999 002 total organic carbon (daily maximum mg/l) 

8/1999 002 total organic carbon (daily maximum mg/l) 

8/1999 003 total organic carbon (daily maximum mg/l) 

9/1999 001 total suspended solids (daily maximum mg/l) 

9/1999 001 total suspended solids (monthly average lb/day) 

5/2000 002 total organic carbon (daily maximum mg/l) 

6/2000 005 unauthorized discharge of 2 gallons of oil (Special Condition 9) 

10/2000 001, 002, 003 total residual chlorine (daily maximum mg/l) 

11/2000 001 total suspended solids (daily maximum mg/l) 

7/2001 004 total organic carbon (daily maximum mg/l) 

Appendix J - Page 1
Appendix J: Table of Alleged CWA Violations at the Joliet Refinery Referenced in 

Consent Decree Subparagraph 252.c.(1) (continued) 

Month and Year Outfall No. Parameter and Other Details 

10/2001 002 total organic carbon (daily maximum mg/l) 

10/2001 008 unauthorized discharge of 2 gallons of oil (Special Condition 9) 

10/2001 – oil sheen on river 

11/2001 002 total organic carbon (daily maximum mg/l) 

1/2002 001, 002, 003 total residual chlorine (daily maximum mg/l) 

5/2002 001, 002, 003 total residual chlorine (daily maximum mg/l) 

8/2002 001, 002, 003 total residual chlorine (daily maximum mg/l) 

9/2003 – chromium 

10/2002 001 ammonia (daily maximum mg/l) 

11/2002 001 ammonia (daily maximum mg/l - 4 days during month) 

11/2002 005 oil and grease (daily maximum mg/l) 

12/2002 001 ammonia (daily maximum mg/l - 7 days during month) 

3/2003 003 total organic carbon (daily maximum mg/l) 

5/2003 003 total organic carbon (daily maximum mg/l) 

6/2003 004 oil and grease (daily maximum mg/l) 

4/2004 001 ammonia (daily maximum mg/l - 3 days during month) 

5/2004 008 oil and grease (daily maximum mg/l) 

5/2004 001 ammonia (daily maximum mg/l - 2 days during month) 

6/2004 001 ammonia (daily maximum mg/l) 

6/2004 003 pH (daily maximum SU) 

8/2004 008 total organic carbon (daily maximum mg/l) 

8/2004 001 pH (daily maximum SU) 

11/2004 001 ammonia (daily maximum mg/l) 

12/2004 001 ammonia (daily maximum mg/l) 

1/2005 003 total organic carbon (daily maximum mg/l - 2 days during month) 

Appendix J - Page 2
Appendix K: Table of Alleged CERCLA Section 103 and EPCRA Section 304 

Reporting Violations at the Joliet Refinery Referenced in Consent 

Decree Subparagraph 252.c.(1) 

Date of Chemical Release Chemical 

3/18/2005 nitrogen oxides 

1/14/2005 sulfur dioxide and nitrogen oxide 

5/14/2004 nitrogen oxides, nitrogen dioxide, hydrogen sulfide and sulfur dioxide 

11/2/2003 hydrogen sulfide and sulfur dioxide 

10/7/2003 nitrogen oxides and sulfur dioxide 

10/4/2003 nitrogen oxides 

10/24/2002 nitrogen oxides 

9/5/2002 nitrogen oxides 

8/24/2002 nitrogen oxides and sulfur dioxide 

6/1/2002 nitrogen dioxide, nitrogen oxides and sulfur dioxide 

4/6/2002 nitrogen oxides 

3/4/2002 nitrogen oxides and sulfur dioxide 

2/24/2002 nitrogen dioxide and sulfur dioxide 

9/27/1999 benzene 

3/29/1999 nitrogen dioxide and/or nitrogen oxides 

2/20/1999 hydrogen sulfide 

2/5/1999 benzene 

1/5/1999 nitrogen oxides 

5/23/1998 nitrogen oxides 

5/5/98 nitrogen oxides 

2/21/1997 hydrogen sulfide 

3/17/1996 nitrogen oxides 

Appendix K - Page 1
Appendix L: Additional Claims Concerning the Joliet Refinery Referenced in 

Consent Decree Subparagraph 252.c.(2) 

As provided by Consent Decree Subparagraph 252.c.(2), entry of the Consent Decree 

shall resolve all civil liability of ExxonMobil to the Applicable Co-Plaintiff for the following 

alleged past violations of the Illinois Environmental Protection Act (the “IEP Act”), the facility’s 

Clean Air Act Permit Program Permit No. 95120304 (the “CAAPP Permit”), and the Clean Air 

Act (including the regulations implementing the Clean Air Act) at the Joliet Refinery: 

A. All alleged past violations of the IEP Act, Illinois Pollution Control Board Regulations at 

35 Ill. Adm. Code Subtitle B, 40 C.F.R. Parts 60 and 63, the CAAPP Permit, and the 

Clean Air Act specified in IEPA Violation Notice A-2003-00205, dated August 22, 2003; 

B. All alleged past violations of the IEP Act, Illinois Pollution Control Board Regulations at 

35 Ill. Adm. Code Subtitle B, 40 C.F.R. Parts 60 and 63, the CAAPP Permit, and the 

Clean Air Act included in IEPA Violation Notice A-2004-00073, dated February 24, 

2004; 

C. All of the following alleged past violations of the IEP Act, Illinois Pollution Control 

Board Regulations at 35 Ill. Adm. Code Subtitle B, the CAAPP Permit, and the Clean Air 

Act associated with a May 15-16, 2004 shutdown event/release event at the Joliet 

Refinery and a May 17, 2004 follow-up inspection by IEPA: 

(1) Alleged violation of Section 9(a) of the IEP Act and 35 Ill. Adm. Code 201.141 

based on the release of hydrogen sulfide into the atmosphere on May 15-16, 2004; 

(2) Alleged violation of Sections 9.1(d) and 39.5(6)(a) of the IEP Act, 40 C.F.R. 

§ 63.6(e)(1)(i), and CAAPP Permit Condition 9.2.3 based on failure to operate the Joliet 

Refinery’s Saturated Gas Plant and associated equipment in a manner consistent with 

good air pollution control practices on May 15-16, 2004; 

(3) Alleged violation of Section 9.1(d) of the IEP Act and 40 C.F.R. § 63.641 based 

on the routing of material with a vapor pressure greater than 11.1 psia to a Group I 

storage vessel (consisting of Tanks 204, 205, and 421) not equipped with a closed vent 

system and control device on May 15-16, 2004; 

(4) Alleged violation of Section 39.5(6)(a) of the IEP Act and CAAPP Permit 

Condition 5.6.5(b) based on failure to provide copies of data, shift logs, and emissions 

standards to IPA as requested during the May 17, 2004 inspection; 

(5) Alleged violation of Section 9.1(d) of the IEP Act and 40 C.F.R. § 63.10(d)(5)(ii) 

based on failure to report actions taken on May 15-16, 2004 that were inconsistent with 

the facility’s startup, shutdown, and malfunction plan; 

Appendix L - Page 1 
(6) Alleged violations of Sections 9(a) and 39.5(6)(a) of the IEP Act, 35 Ill. Adm. 

Code 218.143, 40 C.F.R. § 60.18(c), and CAAPP Permit Condition 5.2.2(c) based on 

emission of VOM into the atmosphere from a flare on May 15, 2004 in a manner that was 

inconsistent with good air pollution control practices; and 

(7) Alleged violation of Sections 9(a) and 39.5(6)(a) of the IEP Act, 35 Ill. Adm. 

Code 218.144, and CAAPP Permit Condition 5.2.2(f) based on the uncontrolled emission 

of VOM to the atmosphere, and the failure to route material with a vapor pressure of 1.5 

psia or greater to a flare, the refinery fuel gas system, or other control equipment on May 

15-16, 2004. 

Appendix L - Page 2 
Appendix M: Additional Claims Concerning the Baton Rouge Refinery Referenced 

in Consent Decree Subparagraph 252.d 

As provided by Consent Decree Subparagraph 252.d, entry of the Consent Decree shall 

resolve all civil liability of ExxonMobil to the Applicable Co-Plaintiff for all alleged past 

violations identified in each LDEQ Consolidated Compliance Order and Notice of Potential 

Penalty (“CONOPP”) or LDEQ Administrative Order listed below: 

A. CONOPP No. AE-CN-01-0254, issued October 16, 2001, for alleged unpermitted H2S 

and SO2 emissions from sulfur pit relief stacks at the sulfur recovery unit. 

B. CONOPP No. MM-CN-01-0027, issued October 18, 2002, for alleged violations 

identified during the April-May 2001 multimedia inspection and subsequent file review. 

C. CONOPP No. AE-CN-02-0233A, issued November 22, 2004, for alleged violations 

identified during the June 12-15, 2002 inspection and subsequent file review. 

D. Administrative Order AE-AO-02-0255. 

E. The alleged violations set forth in CONOPP No. AE-CN-03-0313, except for the alleged 

violations described in Section V (comprising Subsections V.A through V.G) of the 

Findings of Fact in that CONOPP. 

Appendix M - Page 1 
Appendix N: 

FCCU 

Baton Rouge 

PCLA 2/3 

Baytown FCCU 2 

Baytown FCCU 3

Beaumont FCCU

Billings FCCU 

Joliet FCCU 

Torrance FCCU 

Schedule for Use of CEMS at ExxonMobil’s FCCUs 

NOx CEMS 

Entry Date 

Entry Date 

Entry Date 

Entry Date 

December 31, 2008 

18 months after 

Entry Date 

Entry Date 

SO2 CEMS 

Entry Date 

Entry Date 

Entry Date 

Entry Date 

18 months 

after Entry 

Date 

18 months 

after Entry 

Date 

Entry Date 

CO CEMS O2 CEMS 

Not required by 

Consent Decree 

Entry Date 

Entry Date Entry Date 

Entry Date Entry Date 

Entry Date Entry Date 

18 months after 

Entry Date 

18 months after 

Entry Date 

18 months after 

Entry Date 

18 months after 

Entry Date 

Entry Date Entry Date 

Appendix N - Page 1
Appendix O: Summary of the Understanding Between LDEQ and the Louisiana 

Wildlife and Fisheries Foundation Relating to ExxonMobil’s Payment 

for Beneficial Environmental Projects Under Consent Decree 

Paragraph 159 

LDEQ and the Louisiana Wildlife and Fisheries Foundation (the “Foundation”) have 

agreed that the amount payable by ExxonMobil under Consent Decree Paragraph 159 will be 

used exclusively for the acquisition or acquisitions of coastal lands which are: (a) important as 

fish and wildlife habitat, or (b) important to the enhancement of the state's coastal restoration 

effort, or both. Expenditures by the Foundation shall be limited to the purchase price of the land; 

reasonable and appropriate expenses which are necessary for the purchase, such as costs of 

appraisal and survey and reasonable closing costs; and the reasonable and necessary or prudent 

costs associated with restoration or nourishment of the lands. The Foundation will select the 

lands to be purchased based upon the recommendations of the Secretary of the Louisiana 

Department of Wildlife and Fisheries. 

The Foundation is a non-profit, public charitable foundation, tax exempt under Section 

501(c) (3) of the Internal Revenue Code. It was chartered in 1995, and its sole mission is to 

support the mission and programs of the Louisiana Department of Wildlife and Fisheries (the 

“Department”) and the Louisiana Wildlife and Fisheries Commission (the “Commission”) 

including promotion, development, expansion and improvement of the facilities of the 

Department and Commission. Toward that end, the Foundation exists to encourage public 

conservation and enjoyment of wildlife and fish resources, and to increase the agencies' 

usefulness to the citizens to the state of Louisiana. The Foundation provides a means for 

individuals and corporations to become partners with the Department and the Commission in the 

conservation of Louisiana's fish and wildlife resources, and has spearheaded a multitude of 

projects including cooperative endeavors with state and federal agencies and the private 

sector for fish and wildlife enhancement. 

Once acquisition of the above referenced lands has been accomplished, the Foundation 

will execute an act (or acts) of donation(s) of said lands to the Department and the Commission. 

The Department and Commission will then establish the lands as a wildlife management area, 

wildlife refuge or other natural area; or will enter into cooperative endeavors with other state 

agencies for the protection, management and conservation of the said lands consistent with the 

above stated purposes. 

Appendix O - Page 1 
Appendix P: Joliet Wastewater Treatment Plant Area Program 

1. Summary. As required by Consent Decree Paragraph 134, ExxonMobil shall 

implement the Joliet Wastewater Treatment Plant Area Program (“WWTP Area Program”) as 

described in detail in this Appendix P. The WWTP Area Program requires data collection and 

other actions in the general area of the Joliet Refinery encompassing the wastewater treatment 

plant, the Stormwater Diversion Basin ("SWDB"), the Equalization Biological Treatment Unit 

("EBTU"), the Diversion Box, Inlet Structure, Outlet Box, and other related points (referred to 

herein as the “WWTP Area”) depicted on attached Figure P-1.9/ Generally, the WWTP Area 

Program will include the following elements: flow monitoring, wastewater sampling (and 

subsequent analysis) at specific locations, precipitation monitoring, snowmelt monitoring, sludge 

characterization and removal, confirmation of proper aggressive biological treatment in the 

EBTU, groundwater and soil characterization, data reporting, and to the extent necessary based 

on data collected, measures to bring the WWTP Area into full compliance with applicable legal 

requirements. Certain monitoring and reporting on NPDES Permit compliance at the Joliet 

Refinery also is required. 

2. The WWTP Area Wastewater Monitoring Plan. Within 90 days of the Entry 

Date, ExxonMobil shall submit to EPA for review and approval a WWTP Area Wastewater 

Monitoring Plan designed to identify certain properties of the water entering the EBTU and 

SWDB, and to provide other documentation as described in the sections below. The WWTP 

Area Wastewater Monitoring Plan shall specify a 12-month period ("Monitoring Period") during 

which wastewater shall be collected and analyzed as described below at the following locations 

generally identified on Figure P-1: (1) the SWDB at location 4c; (2) Stream 3 prior to mixing 

with Stream 6 (unless ExxonMobil takes the actions set out in Subparagraph 2.c.iv of this 

Appendix); and (3) Stream 6 near the entrance to the EBTU. The WWTP Area Wastewater 

Monitoring Plan shall include a reasonable time period between the date of EPA approval of the 

WWTP Area Wastewater Monitoring Plan and commencement of the Monitoring Period (such 

time period not to exceed six (6) months) to allow for the installation and completion of testing 

of all equipment necessary to perform the required monitoring programs. The parties will 

attempt to identify a commercially available autosampler for use in this program prior to the 

Date of Lodging. If the parties cannot find a commercially available autosampler acceptable to 

both EPA and ExxonMobil by that date, then ExxonMobil shall be allowed to take samples 

manually. 

a. SWDB, Stream 4c. 

i. SWDB Flow Monitoring. The WWTP Area Wastewater Monitoring Plan 

shall include a protocol for measuring wastewater flow through the Inlet Structure into 

9/ Based on information and belief, formed after reasonable inquiry, ExxonMobil certifies 

by signing this Decree that the WWTP flows are as depicted on Figure P-1, and agrees 

that variances from Figure P-1 may, at EPA's discretion, result in additional or different 

monitoring locations, additional or different monitoring requirements, or both. 

Appendix P - Page 1 
the SWDB, including, but not limited to, detailed plans and a schedule for installing and 

utilizing the following: 

(a) Equipment to monitor and electronically record when the inlet 

valve to the SWDB is open; and 

(b) Flow measuring and recording equipment designed to 

continuously, reliably, and accurately measure, within manufacturer's 

specifications, and record, at intervals no longer than five minutes, the time and 

flow rate of any water entering the SWDB through the Inlet Structure. Measured 

and recorded data shall be sufficient to allow calculation of the flow duration 

(including beginning and ending times) and total volume of the water entering the 

SWDB through the Inlet Structure. ExxonMobil shall also implement procedures 

designed to remove floating oil from the Inlet Structure prior to the SWDB. 

ii. SWDB Sampling. If autosampling is the agreed upon method of 

sampling, the WWTP Area Wastewater Monitoring Plan shall include plans and a 

schedule for installing and utilizing an autosampling device designed to sample the 

wastewater when wastewater flow is diverted from the Inlet Structure into the SWDB. 

The autosampling device shall be designed to minimize headspace in each collected 

sample and shall be installed and used in accordance with the manufacturer's 

recommendations. Sampling during each diversion event shall be conducted in 

accordance with Attachment P-2. Manual sampling procedures shall be consistent with 

the sampling process set out in attachment P-2 and shall be performed in a manner to 

minimize headspace in each collected sample. 

iii. SWDB Analysis. The SWDB samples shall be analyzed in accordance 

with the procedures established in Subparagraph 2.d of this Appendix. 

b. EBTU Consolidated Main Influent, Stream 6. 

i. Stream 6 Flow Sampling. For purposes of determining the volume of 

wastewater flow to the EBTU from Stream 6, equipment shall be installed that is 

designed to continuously, reliably and accurately measure, within manufacturer's 

specifications, and record at intervals no longer than fifteen minutes, the flow rate of 

wastewater at the location labeled as S1 in Figure P-1. The date and time of these 

measurements shall be electronically recorded. Plans and a schedule for installing this 

equipment shall be included in the WWTP Area Wastewater Monitoring Plan. 

ii. Autosampler. If autosampling is the agreed upon method of sampling, 

ExxonMobil shall install an autosampling device that samples Stream 6 and that is 

designed to minimize headspace in each collected sample. The autosampler shall be 

installed and used in accordance with the manufacturer's recommendations. For purposes 

of this Consent Decree and the WWTP Area Wastewater Monitoring Plan, each 

individual sample collected from Stream 6 using the autosampling device shall be 

referred to as a "grab" sample. Manual sampling procedures shall be performed in a 

Appendix P - Page 2 
manner to minimize headspace in each collected sample. 

iii. Stream 6 Composite Sampling. During the Monitoring Period, 

ExxonMobil shall collect for analysis daily composite samples from Stream 6 as follows: 

single grab samples shall be collected (sampling to be conducted manually or using the 

autosampler as described in Subparagraph 2.b.ii. above) at or near the end of the main 

influent pipe to the EBTU six times per calendar day, at a sampling interval of 

approximately four hours. For each day, the grab samples collected (typically 6) will not 

be analyzed individually, but will be combined to create a single daily composite sample 

for analysis. 

iv. Stream 6 Grab Sampling. During the Monitoring Period, ExxonMobil 

shall collect for analysis a series of grab samples from Stream 6 as follows: once per 

calendar week, single grab samples shall be collected (sampling to be conducted 

manually or using the autosampler as described in Subparagraph 2.b.ii. above) at or near 

the end of the main influent pipe to the EBTU 6 times per day, at a sampling interval of 

approximately four hours. The grab samples collected (typically 6) will be analyzed 

individually. In any quarterly reports submitted pursuant to Paragraph 3, ExxonMobil 

may request EPA approval to reduce the frequency or eliminate grab sampling under this 

Paragraph. 

v. Stream 6 Sample Handling. The grab samples and composite samples will 

be handled at all times so as to minimize headspace. 

vi. Stream 6 Analysis. Stream 6 samples shall be analyzed in accordance with 

the procedures established in Subparagraph 2.d of this Appendix. 

c. Diversion Box Flow, Streams 3 and 6. 

i. Stream 3 Flow Monitoring.

10/ The WWTP Area Wastewater Monitoring 

Plan shall include a protocol for measuring wastewater flow from the Diversion Box to 

Stream 3, including but not limited to, detailed plans and a schedule for installing and 

utilizing the following: 

(a) Equipment to monitor and electronically record when water is 

released from the Diversion Box into the outlet identified as Stream 3 in Figure 

P-1; and 

10/ Based on information and belief, formed after reasonable inquiry, ExxonMobil certifies 

by signing this Consent Decree that all water pumped or otherwise removed from the 

SWDB to drain the SWDB first is sent through primary treatment (i.e., into the preseparation flumes and through the API separator and DAF unit) before entering the 

EBTU. ExxonMobil shall continue that practice after the Entry Date. 

Appendix P - Page 3 
(b) Flow measuring and recording equipment designed to 

continuously, reliably and accurately measure, within manufacturer's 

specifications, and record at intervals no longer than five minutes, the time and 

flow rate of wastewater from the Diversion Box to Stream 3. Measured and 

recorded data shall be sufficient to allow calculation of the flow duration 

(including beginning and ending times) and total volume of the water entering the 

Stream 3 as a result of a diversion event. Flow from the Diversion Box to Stream 

3 shall be quantified prior to the mixing of Stream 3 with Stream 6. 

ii. Streams 3 and 6 Diversion Event Sampling. The WWTP Area Wastewater 

Monitoring Plan shall include plans and a schedule for using one of the following 

alternative methods (Subparagraphs 2.c.ii.(a) or 2.c.ii.(b)), to be determined in 

ExxonMobil's sole discretion, to sample the wastewater in Streams 3 and 6 when 

wastewater flow is diverted from the Diversion Box to Stream 3: 

(a) Manual Sampling. A level alarm shall be installed in the 

Diversion Box to alert the unit operator of an impending diversion to Stream 3. 

Upon receipt of the alarm, personnel shall be dispatched to sampling locations 

(one at Stream 3 and the other at Stream 6). Manual sampling of both Streams 3 

and 6 shall be coordinated to start simultaneously within 15 minutes after 

overflow at Stream 3 begins, and shall continue in a coordinated manner. 

Sampling shall be done in a manner that minimizes headspace in each collected 

sample. No less than one sample per 15 minute interval shall be taken 

throughout the diversion to Stream 3 and shall continue until overflow of Stream 

3 ceases. Each time any water is diverted from the Diversion Box to Stream 3, 

ExxonMobil shall measure the volume of water flow into Stream 3; or 

(b) Autosampler. Autosampling devices shall be installed and used to 

sample the wastewater in Streams 3 and 6. The autosampling devices shall be 

designed to minimize headspace in each collected sample and shall be installed 

and used in accordance with the manufacturer's recommendations. Each time any 

water is diverted from the Diversion Box to Stream 3, ExxonMobil shall measure 

the volume of water flow into Stream 3, and shall use one or more autosamplers 

to collect samples of Stream 3 and Stream 6 at the same intervals during the 

diversion event. Samples at Stream 6 shall be taken simultaneously with the 

samples taken at Stream 3. After an initial sampling approximately 5 minutes 

after overflow at Stream 3 begins, no less than one sample per every 15 minute 

interval shall be taken throughout the diversion to Stream 3, and shall continue 

until overflow into Stream 3 ceases. 

iii. Stream 3 and 6 Analysis. The Stream 3 and 6 samples shall be analyzed in 

accordance with the procedures established in Subparagraph 2.d of this Appendix. EPA 

and ExxonMobil agree that the samples taken at Stream 3 are primarily for informational 

purposes, and may be useful to identify the source of benzene that may ultimately be 

discharged to the EBTU. 

Appendix P - Page 4 
iv. Alternative Approach to Address Stream 3. Notwithstanding the above 

provisions of Subparagraphs 2.c.i, ii, and iii, ExxonMobil shall have no obligations with 

respect to Streams 3 or 6 pursuant to Subparagraph 2.c. (including, without limitation, 

any requirement for monitoring, sampling, or analysis of wastewater pursuant to 

Subparagraphs 2.c.i, ii, or iii) if ExxonMobil submits as part of the WWTP Area 

Wastewater Monitoring Plan engineering information showing that it has constructed an 

engineering change that permanently ceases wastewater flow discharges to the EBTU 

from Stream 3 as depicted on Figure P-1. If this alternative approach is chosen, 

ExxonMobil shall attach to and submit with the WWTP Area Wastewater Monitoring 

Plan a certification that wastewater flow from Stream 3 to the EBTU as depicted on 

Figure P-1 has been permanently blocked and shall remain so unless EPA and the 

Applicable Co-Plaintiff are notified otherwise. Upon such notification, ExxonMobil 

shall be required to comply with the terms of Subparagraphs 2.c.i - 2.c.iii. 

d. Analytical Requirements. 

i. Analytical Method. For each wastewater sampling location (as described 

in Subparagraphs 2.a., 2.b., and 2.c. above), the WWTP Area Wastewater Monitoring 

Plan shall include a description of how each sample will be prepared in accordance with 

the Toxicity Characteristic Leaching Procedure (Method 1311 in EPA Publication SW846), and a description of the method by which the benzene content of the sample will be 

analyzed. Methods other than Method 1311 may be approved by EPA if ExxonMobil 

demonstrates statistical equivalency between contemporaneous samples analyzed by 

Method 1311 and the proposed alternative method; 

ii. Requirements Regarding Analysis of Each Sample. Each individual grab 

sample taken pursuant to Subparagraphs 2.a., 2.b.iv, and 2.c. shall be analyzed for 

benzene by the method stated in Subparagraph 2.d.i. above. Each 24-hour composite 

sample taken pursuant to Subparagraph 2.b.iii. shall be analyzed for benzene by the 

method stated in Subparagraph 2.d.i. above; 

iii. Mixed Streams. The WWTP Area Wastewater Monitoring Plan shall 

describe the exact placement of the sampling devices and how ExxonMobil will ensure 

collection of a sample containing a mixture of oil and water phases proportional to the 

volumes of the phases in the stream. The WWTP Area Wastewater Monitoring Plan shall 

state: (1) that sampling streams with laminar flow is not allowed, unless the entire stream 

can be collected for a short time; and (2) if sampling the total flow is not practical due to 

high volume, then sampling at a highly turbulent mixing point will be done; 

iv. QA/QC. The WWTP Area Wastewater Monitoring Plan shall include a 

detailed description of the Quality Assurance/Quality Control procedures that 

ExxonMobil will employ to ensure proper collection, handling, preparation, and analysis 

of samples collected. 

e. Failure to Sample or Analyze Samples Pursuant to the WWTP Area Wastewater 

Monitoring Plan. In the event that ExxonMobil is unable, despite due diligence (e.g., inability 

Appendix P - Page 5 
due to power failures, equipment malfunctions, sample loss, safety issues, weather related 

problems), to obtain any samples (including individual grabs to be composited) or to analyze any 

such sample(s) as required by this Paragraph and by the WWTP Area Wastewater Monitoring 

Plan, then such failure(s) shall not constitute a violation of this Consent Decree if ExxonMobil: 

(1) notes in the operating record any sampling failures; (2) submits to EPA a written explanation 

of the sampling or analytical failure and all documentation related to the sampling or analytical 

failure within 30 business days from the failure; and (3) summarizes any sampling and analytical 

failures in the WWTP Area Monitoring Plan Quarterly Reports and in the WWTP Area 

Monitoring Plan Final Report. Any such failure(s) may, at the discretion of EPA, result in an 

extension of the Monitoring Period. Such an extension shall be reasonably related to the nature 

and extent of ExxonMobil’s sampling and/or analytical failure and other relevant considerations. 

f. Precipitation Indicator. The WWTP Area Wastewater Monitoring Plan shall 

include plans and a schedule for installing and utilizing equipment capable of reliably and 

accurately measuring precipitation amounts and times at the Joliet Refinery during the 

Monitoring Period. The associated recording equipment shall provide electronic recording of 

precipitation start and stop times and precipitation amounts to allow for calculation of the 

duration and volume of a rainfall event. The equipment shall be configured and calibrated in 

accordance with the manufacturer's recommendations for proper equipment operation. The 

parties recognize that wet weather flow to the wastewater treatment plant may sometimes begin 

subsequent to commencement of actual precipitation, and that wet weather flow to the SWDB 

and to Stream 3 may continue after rainfall ends. The parties agree that wet weather flow also 

includes draining of stormwater from tank-diked areas at the facility in connection with a 

precipitation event. 

g. Snowmelt. The WWTP Area Wastewater Monitoring Plan shall include plans 

and a schedule for implementing a system for use in identifying and documenting snowmelt 

events at the Joliet Refinery that cause wet weather flow diversion of wastewater into the SWDB 

during the Monitoring Period. The system shall consist of making and recording the following 

measurements on a daily basis when there is snow on the ground: daily snow depth (to be 

measured at a single location within the refinery at approximately the same time each day), the 

day's high temperature (which may be measured at the refinery or recorded from other reported 

nearby weather stations), and a description of the degree of cloudiness best describing the day 

(e.g. sunny, partly cloudy, cloudy, overcast, etc.). Data recorded by this system may be used as 

one means to support snowmelt as a cause of diversion events that may occur in the absence of 

precipitation when ExxonMobil believes they were caused by snowmelt. Failure by 

ExxonMobil to take a daily measurement shall not be a violation of this Consent Decree so long 

as: (1) no diversion event occurs on the day the measurement is not made, or (2) if a diversion 

does occur on that day, ExxonMobil is able to demonstrate through other means that the 

diversion was associated with a wet weather flow. 

h. Nothing in this Consent Decree shall preclude ExxonMobil from availing itself of 

the "immediate response" provisions of RCRA, as set forth in 40 C.F.R. §§ 264.1(g)(8), 

265.1(c)(11) and 270.1(c)(3) (and analogous Illinois law), for the discharge of hazardous waste 

(or the discharge of a material which, when discharged, becomes a hazardous waste) into a 

surface impoundment, provided that such discharge is directly related to an unanticipated and 

Appendix P - Page 6 
extraordinary event (such as a catastrophic tank rupture or activation of the HF deluge system 

into the facility sewer system). 

3. NPDES Permit Compliance Monitoring Program. 

a. ExxonMobil shall comply with all effluent limitations, permit conditions, and 

other requirements imposed by the NPDES Permit for the Joliet Refinery. 

b. In the Quarterly Reports and Final Report required by Paragraphs 4 and 5 of this 

Appendix, ExxonMobil shall make supplemental reports to EPA on its NPDES permit 

compliance with respect to the effluent limitations and associated effluent monitoring 

requirements as set forth in the NPDES Permit and as documented by the Discharge Monitoring 

Reports (“NPDES Permit Compliance Monitoring”). 

4. WWTP Area Wastewater Monitoring Plan Quarterly Reports. ExxonMobil shall 

submit quarterly progress reports (“WWTP Area Wastewater Monitoring Plan Quarterly 

Reports”) to EPA on a quarterly basis during collection of data pursuant to WWTP Area 

Wastewater Monitoring Plan. The WWTP Area Wastewater Monitoring Plan Quarterly Reports 

shall be due 30 days after the end of each quarterly monitoring period, or approximately 120, 

210, and 300 days into the Monitoring Period. The WWTP Area Wastewater Monitoring Plan 

Quarterly Reports shall summarize the steps taken to implement the WWTP Area Wastewater 

Monitoring Plan. The data to be reported within the WWTP Area Wastewater Monitoring Plan 

Quarterly Report shall include: 

a. For Diversion Events. For each diversion event to the SWDB and to Stream 3 

that ended during the 3-month period being reported: (1) the date and time the diversion event 

started and ended; (2) the date and time that any wet weather or other event which caused the 

diversion event started and ended; (3) the total amount (in inches) of any precipitation that fell 

during a diversion event; (4) the total wastewater volume diverted to the SWDB and/or Stream 

3; (5) the date, time, and concentration of benzene in each sample taken of Streams 4c, 3, and 6; 

(6) Excel spreadsheets showing all water flow measurement data points required under 

Subparagraphs 2.a. and 2.c.; (7) Excel spreadsheets containing all sample collection data points, 

including the date and time a sample was taken, and the benzene result; (8) all laboratory data 

related to the analysis of all SWDB and Streams 3 and 6 water samples, including but not limited 

to, documentation verifying that all QA/QC requirements were met; and (9) a summary of all 

failures to sample or analyze samples in accordance with Paragraph 2 and the WWTP Area 

Wastewater Monitoring Plan. 

b. For Stream 6 to the EBTU Composite and Grab Samples: (1) the date and 

benzene concentration measured for each daily composite influent sample to the EBTU; 

(2) Excel spreadsheets including all water flow measurement data points required under 

Subparagraph 2.b.; (3) Excel spreadsheets including all sample collection data points, including 

the date and time a sample was taken, and the benzene results on each 24-hour composite sample 

that was analyzed; (4) Excel spreadsheets including all sample collection data points, including 

the date and time a sample was taken, and the benzene results for each individual grab sample 

that was individually analyzed; (5) all laboratory data related to the analysis of all Stream 6 

Appendix P - Page 7 
water samples, including, but not limited to, documentation verifying that all QA/QC 

requirements were met; and (6) a summary of all failures to sample or analyze samples in 

accordance with Paragraph 2 and the WWTP Area Wastewater Monitoring Plan. 

c. For NPDES Permit Requirements: (1) the first Quarterly Report shall include 

copies of the Joliet Refinery’s Discharge Monitoring Reports for the 3-month period being 

reported, plus copies of Discharge Monitoring Reports for the three months preceding the start of 

the reporting period; (2) the subsequent Quarterly Reports shall include copies of Discharge 

Monitoring Reports for the 3-month period being reported; and (3) each Quarterly report shall 

include copies of all laboratory reports related to the attached Discharge Monitoring Reports. In 

each report, ExxonMobil shall identify noncompliance, if any, with the effluent limitations and 

associated effluent monitoring requirements in that quarter (and the preceding quarter, in the 

case of the first Quarterly Report), and shall identify steps that it is taking or plans to take to 

address such noncompliance. 

5. WWTP Area Wastewater Monitoring Plan Final Report. No later than 60 days 

after the end of the Monitoring Period for all required monitoring activities, ExxonMobil shall 

submit a WWTP Area Wastewater Monitoring Plan Final Report. The WWTP Area Wastewater 

Monitoring Plan Final Report shall include: 

a. A summary of all steps taken to implement the WWTP Area Wastewater 

Monitoring Plan and all data collected under the WWTP Area Wastewater Monitoring Plan, 

including, but not limited to, the data required to be reported under Subparagraphs 4.a and 4.b of 

this Appendix; 

b. The data required to be reported under Subparagraph 4.a and 4.b for the final 

quarter of the Monitoring Period; 

c. A determination whether the data collected under the WWTP Area Wastewater 

Monitoring Plan indicates that hazardous waste has been treated, stored, or disposed of in the 

SWDB and/or the EBTU, and the data relating to that determination and a detailed description of 

the basis for that determination;11/ 

11/ ExxonMobil acknowledges the rulings in United States v. Mobil Oil Corporation, 1997 

WL 1048911 (E.D.N.Y. Sept. 11, 1997); Texans United Education Fund v. Exxon 

Company USA, CV-H-96-847 (Slip Op. Mar. 2, 1998)(S.D. Tex.); and Texans United 

Education Fund v. Exxon Company USA, CV-H-96-847 (Slip Op. Jun. 17, 1998)(S.D. 

Tex.). ExxonMobil shall not contend in any administrative or judicial forum that a longterm average of discrete disposal events (or batches) of waste water is required in order 

to determine whether RCRA applies; provided, however that in the event that there is a 

change in federal RCRA law, either statutory, regulatory, or based upon EPA written 

guidance or federal court decisions, ExxonMobil may rely upon such change to make 

appropriate contentions regarding its wastes; and further provided that in the event that 

(continued...) 

Appendix P - Page 8 
d. A description of any noncompliance issues identified in implementing the 

WWTP Area Wastewater Monitoring Plan, including a description of any confirmed release of 

hazardous waste to the environment; 

e. Attached copies of Discharge Monitoring Reports for the final quarter of the 

Monitoring Period, and attached copies of all laboratory reports associated with those Discharge 

Monitoring Reports; 

f. A description of noncompliance, if any, with the effluent limitations and 

associated effluent monitoring requirements in the final quarter, and steps that ExxonMobil is 

taking or plans to take to address noncompliance identified in this Subparagraph 5.f and/or 

Subparagraph 4.c pursuant to the NPDES Permit Compliance Monitoring; 

g. A plan and a schedule for implementing any measures necessary, if any, to bring 

the Joliet WWTP Area (including the SWDB and the EBTU) into full compliance with 

applicable legal requirements. The compliance measures shall include any reasonable 

physical/engineering/operational/compliance changes that are deemed necessary to comply with 

applicable legal requirements. The Report shall be subject to review and approval by EPA and 

the Applicable Co-Plaintiff. ExxonMobil shall implement all compliance measures set forth in 

the approved Report, in accordance with the schedule included in the WWTP Area Wastewater 

Monitoring Plan Final Report. 

6. Sludge Characterization and Removal. Within 90 days of the Entry Date, 

ExxonMobil shall submit to EPA for review and approval a Sludge Characterization and 

Removal Plan containing a plan and a proposed schedule for the characterization and removal of 

sludge from the SWDB and the EBTU. 

a. SWDB. The Sludge Characterization and Removal Plan shall include plans for 

sampling, removal, and subsequent management of sludge from the SWDB. Sludge will be 

removed from the SWDB when deemed operationally necessary by ExxonMobil, but no later 

than 24 months after entry of this Consent Decree, and will be characterized for relevant toxicity 

characteristics under 40 C.F.R. Part 261, Subpart C prior to removal. The SWDB sludge shall, 

upon removal, be managed by ExxonMobil in accordance with all applicable laws and 

regulations. 

(...continued)

there is a changed interpretation of RCRA under the law of a State, either based upon

written State agency guidance or State court decisions, ExxonMobil may rely upon such

change in that State to make appropriate contentions regarding its wastes. Nothing herein

shall preclude ExxonMobil from demonstrating that it has not managed RCRA-hazardous

wastes, based on its design and implementation of a waste analysis plan in accordance

with the principles contained in Test Methods for Evaluating Solid Waste,

Physical/Chemical Methods, EPA Publication SW-846, in the event of a continuous

waste water disposal event that occurs over a period of time, and which displays

chemical heterogeneity over time.

Appendix P - Page 9 
b. EBTU. 

(i) Due to operational necessity prior to the Entry Date, sludges have been removed 

from the EBTU. The Sludge Characterization and Removal Plan shall include a 

certification by ExxonMobil that the sludges it removed from the EBTU were 

characterized and disposed of in accordance with applicable regulatory 

requirements. 

(ii) The Sludge Characterization and Removal Plan shall include plans for additional 

sampling, removal, and subsequent management of sludge from the EBTU. 

Sludge will be removed from the EBTU when deemed operationally necessary by 

ExxonMobil, but no later than 24 months after the entry of this Consent Decree, 

and will be characterized for relevant toxicity characteristics under 40 C.F.R. Part 

261, Subpart C prior to removal. The EBTU sludge shall, upon removal, be 

managed in accordance with all applicable laws and regulations. Notwithstanding 

the above, if ExxonMobil determines that it has become operationally necessary 

for ExxonMobil to remove or begin the removal of sludges from the EBTU prior 

to the Entry Date, the Parties agree that the requirements of this Paragraph shall 

be satisfied and no additional sampling, removal or subsequent management of 

sludge from the EBTU shall be required pursuant to this Consent Decree, if 

ExxonMobil submits to EPA in a report as set out in Paragraph 6.c, a certification 

that the sludges removed from the EBTU were characterized and subsequently 

managed in accordance with applicable regulatory requirements. 

c. ExxonMobil will provide EPA with documentation of the sludge removal events 

set out in Subparagraphs 6.a. and 6.b. above within 60 days of the completion of the sludge 

removal effort. The documentation shall include any analytical data collected on the sludges and 

documentation showing the manner in which the sludge was removed, stored, and subsequently 

managed. 

7. Aggressive Biological Treatment. By no later than 90 days of the Entry Date, 

ExxonMobil shall prepare and maintain an Aggressive Biological Treatment Plan, and shall 

provide EPA an informational copy of the Plan. ExxonMobil shall thereafter implement the Plan 

and shall take all other actions required to ensure that the EBTU is operated in compliance with 

the requirements applicable to aggressive biological treatment units listed hazardous waste 

exception under 35 Ill. Admin. Code § 721.131(b)(2)(A) and 40 C.F.R. § 261.31(b)(2). The 

Aggressive Biological Treatment Plan shall include: 

Appendix P - Page 10 
 a. High-Rate Aeration Procedure. A description of a procedure that ExxonMobil will 

establish and follow so that high-rate aeration in the EBTU is continuously achieved during 

normal operations, with the aeration system operating at minimum of 40 hp when the EBTU is 

full, or with the aeration system operating at a minimum of 6 hp per million gallons of treatment 

volume within the EBTU when the EBTU treatment volume is less than capacity. The plan shall 

also identify procedures for addressing any aerator outage (including but not limited to any 

outage due to a power failure affecting the system). ExxonMobil will monitor and record on a 

daily basis the number of aerators operating, total horsepower of the aerators operating, and the 

water volume in the EBTU. 

b. Recordkeeping Procedure. A description of a procedure that ExxonMobil will 

establish and follow to maintain documents and data in ExxonMobil's operating or onsite records 

for a period of 3 years after such documents and data are created demonstrating that it meets the 

standard of aggressive biological treatment (including the requirements regarding horsepower 

and hydraulic retention time) under 35 Ill. Admin. Code § 721.131(b)(2)(A) and 40 C.F.R. 

§ 261.31(b)(2). 

8. Groundwater and Soil Characterization. Within 90 days of the Entry Date, 

ExxonMobil shall submit to EPA for review and approval a Groundwater and Soil 

Characterization Plan. The Groundwater and Soil Characterization Plan shall include plans and 

a schedule for quantifying the level of contamination in the groundwater and soil in the area of 

the SWDB and the EBTU, specifically including: 

a. A summary of all relevant information concerning groundwater monitoring and 

soil characterization conducted over the past seven years in the SWDB and EBTU areas, 

including, but not limited to, information on sampling well locations, screening depths, soil 

sample locations, and groundwater and soil sampling results; 

b. A schedule for performing and providing a hydrogeological survey in the SWDB 

and EBTU areas; 

c. A schedule for submitting and implementing a protocol for additional 

groundwater monitoring and soil characterization which is capable of determining: (1) whether 

hazardous constituents have been released to soils or groundwater in the vicinity of the SWDB 

and the EBTU; (2) the rate and extent of migration of hazardous constituents; and (3) the 

concentrations of the hazardous constituents; and 

d. A schedule for submission of the Groundwater and Soil Characterization Plan 

Final Report. The Groundwater and Soil Characterization Plan Final Report shall, based on the 

data collected pursuant to the Groundwater and Soil Characterization Plan, propose corrective 

actions necessary, if any, to remediate soil and groundwater of the SWDB and the EBTU areas. 

9. Review and Approval of ExxonMobil Submissions Under Paragraphs 1-8 above. 

a. EPA shall review all items submitted by ExxonMobil pursuant to Paragraphs 1-8 

Appendix P - Page 11 
above. After review of any item submitted, EPA shall: (1) approve the item in whole or in part; 

(2) approve the item subject to conditions specified in the approval notice; (3) modify the item to 

cure the deficiencies and approve it as modified; (4) disapprove the item in whole or in part, and 

direct that ExxonMobil modify it; or (5) any combination of the above. EPA shall notify 

ExxonMobil in writing of its decision regarding each item submitted for review, and if EPA does 

not approve the item in whole, the notice shall specify those portions of the item that have not 

been approved and the reasons for not approving such item. 

b. In the case of an item that has been approved in whole by EPA, ExxonMobil shall 

proceed to take all actions required by the item approved. 

c. In the case of an item that has been approved subject to specified conditions or 

that has been modified and approved by EPA, ExxonMobil shall either: (1) commence 

implementation of the work required by the item in accordance with the approved schedule, or 

(2) invoke the dispute resolution procedures set forth in Section XV of the Consent Decree with 

respect to EPA’s decision. Regardless of whether ExxonMobil invokes such dispute resolution 

procedures, if ExxonMobil fails to timely commence implementation of the work required by the 

item approved subject to specified conditions or modified and approved, ExxonMobil shall be 

liable for any stipulated penalties demanded under Section XI of the Consent Decree unless 

ExxonMobil prevails in such dispute resolution. 

d. In the case of an item that has been disapproved in whole or in part by EPA, 

ExxonMobil shall, within 45 days of receipt of the notice of disapproval, either: (1) correct the 

deficiencies and resubmit the item for approval, or (2) invoke the dispute resolution procedures 

set forth in Section XV of the Consent Decree with respect to a notice of disapproval. 

Regardless of whether ExxonMobil invokes such dispute resolution procedures, if it fails to 

timely correct the deficiencies specified in the notice of disapproval and resubmit the item, 

(i) ExxonMobil shall be liable for any stipulated penalties demanded under Section XI of the 

Consent Decree and (ii) EPA may modify and approve the item; provided, however, that 

ExxonMobil shall not be liable for stipulated penalties if the stipulated penalties relate to a 

matter in which ExxonMobil prevails in dispute resolution. An item that is resubmitted with the 

same deficiencies that were identified in the notice of disapproval or with substantially similar 

deficiencies shall be deemed to have never been submitted for purposes of calculating stipulated 

penalties. 

e. Notwithstanding the receipt of a notice of disapproval, ExxonMobil shall proceed, 

if so directed by EPA in the notice, to take any action required by any non-deficient portion of 

the item, unless the non-deficient portion of the item is substantially related to a disapproved 

item that ExxonMobil intends to dispute. However, lack of action on non-deficient portions of 

the submittal shall result in stipulated penalties accruing under Section XI of the Consent Decree 

unless ExxonMobil prevails in such dispute resolution over the substantially related disapproved 

item. 

f. In the event that a resubmitted item, or portion thereof, is disapproved, EPA may 

again require ExxonMobil to correct the deficiencies, in accordance with the procedure set forth 

in this Paragraph. EPA may also approve the item subject to conditions specified in the approval 

Appendix P - Page 12 
notice or modify and approve the item as set forth in Subparagraphs 9.a and 9.c. above. In the 

event that EPA approves the item subject to specified conditions or modifies and approves the 

item, ExxonMobil shall commence implementation of the work required by the item in 

accordance with the schedule set forth in the item as approved, or ExxonMobil may invoke the 

dispute resolution procedures set forth in Section XV with respect to a decision by EPA pursuant 

to this Paragraph. Regardless of whether ExxonMobil invokes such dispute resolution 

procedures, if ExxonMobil fails to timely re-submit the item or to implement the work required 

by the item as approved, ExxonMobil shall be liable for any stipulated penalties demanded under 

Section XI unless ExxonMobil prevails in such dispute resolution. 

g. All items required to be submitted to EPA under Paragraphs 1-8 above shall, upon 

approval, be enforceable under this Consent Decree. In the event EPA approves a portion of an 

item required to be submitted to EPA under this Consent Decree, the approved portion shall be 

enforceable under this Consent Decree. ExxonMobil retains the right to invoke dispute 

resolution regarding all items it is required to submit for review and approval under this Consent 

Decree. 

h. Paragraph 229 in the Section of the Consent Decree governing dispute resolution 

provides that the Parties shall expeditiously schedule a meeting to discuss a dispute informally 

not later than fourteen (14) days after receipt of a written notice of dispute. If ExxonMobil 

disputes EPA's approval with conditions, modification, or disapproval of an item submitted 

pursuant to Paragraphs 1-8 in this Appendix P, then stipulated penalties under Consent Decree 

Subparagraphs 201.a -201.k shall not begin to accrue any earlier than twenty-one (21) days after 

a notice of dispute. 

Appendix P - Page 13 
Appendix P: Figure P-1 

[Figure P-1 is on the following page] 

Appendix P - Page 14
Storm Water 

Diversion 

Basin 

Diversion 

Box 

Pre-separation 

Flumes 

Refinery process wastewater/ 

1 

storm water (multiple inlets) 

3 

Inlet Structure 

4c 

4b 

Outlet Box 

Floc 

API 

Separators 

DAF 

Unit 

Wet weather flow and emergency overflow 

West Stormwater Basin Transfer 

Sanitary Treatment 

Guard Basin WWT 

Area Stormwater Drainage 

11 

12 

13 

15 

16 

Boiler Blowdown 

S1 

2 

4a 

9 

6 

5 

F 

F 

EBTU 

8 

7 

Stormwater Ditch 

14 

Figure P-1 

FT-60064 

FT-60051 

outfall 001 

aeration basins 

Clarifiers, guard 

basin and 

To 

Stream 

Bz Sample Point 

Flow Meters Pump 

Level Control 

Legend 

Valve/Sluice Gate (normally open) Valve/Sluice Gate (normally closed) 
Appendix P: Attachment P-2 

Sampling, Analysis and Evaluation of SWDB Stream 

A. Overview 

Each time any water is diverted into the SWDB, ExxonMobil will use a flow meter to 

measure the rate of water flow into the SWDB, and one or more autosamplers to collect samples 

at intervals during the diversion event. The individual grab samples collected by the 

autosampler(s) will be analyzed pursuant to Subparagraph 2.d.i of Appendix P. 

B. Sample Collection Interval 

ExxonMobil shall collect the first sample(s) within 15 minutes of the beginning of a 

discharge. Thereafter, if an autosampler is used, the interval between samples will be based on 

pre-defined volumes of water that have flowed into the SWDB. If manual sampling is used, the 

interval between the samples will be based on pre-defined volumes of water that have flowed 

into the SWDB to the extent practicable. These interval volumes may be adjusted by 

ExxonMobil either before a diversion event (for example, to accommodate anticipated size of the 

storm) or during a diversion event (for example, to accommodate the conditions encountered 

during a diversion event). Changes to the sample collection interval will be made while keeping 

in mind the need to collect enough samples to adequately characterize changes in benzene 

concentration during the diversion event. Regardless of the above, however, ExxonMobil shall 

take at least 1 sample every 90 minutes during any release event. 

The following is an example of possible intervals for sample collection, illustrating the 

concept of variable sample collection intervals. The flow rate of water entering the SWDB will 

be monitored and recorded at intervals no larger than five minutes. Samples after the first will 

be taken at intervals determined by the volume of water that has entered the SWDB since the 

previous sample. For example, the next three samples might be taken at 25,000 gallon intervals, 

the following three at 50,000 gallon intervals, the next eleven at 100,000 gallon intervals, and 

subsequent samples scheduled at increased gallon intervals as shown below. 

Appendix P - Page 15 
1

2

3

4

5

6

7

8

Sample Sampling Volume (gal) 

Number Time (min) Increment Total 

5.0 30,000 

25,000 

27.5 55,000 

25,000 

40.0 80,000 

25,000 

52.5 105,000 

50,000 

77.5 155,000 

50,000 

102.5 205,000 

50,000 

127.5 255,000 

100,000 

177.5 355,000 

100,000 

with samples continuing at increased increments 

19 827.5 150,000 1,655,000 

20 902.5 150,000 1,805,000 

21 1002.5 200,000 2,005,000 

22 1102.5 200,000 2,205,000 

no sample 1125.0 45,000 2,250,000 

. . . until event ceases 

Hypothetical diversion event ended 1125 minutes after beginning. 

For simplicity, in this hypothetical example the flow into the SWDB is assumed to be 

constant at 2,000 gpm (except for the first 5 minute interval). In a real diversion event the flow 

will be calculated based on the measured values at intervals no larger than 5 minutes. Also, in 

this hypothetical example, flow into the SWDB is shown to occur in a single uninterrupted 

event. In a real diversion event, the inlet valve may be opened and later closed, and then have to 

be reopened to allow additional flow, for example if a storm’s intensity lessens for a while and 

then increases again. In such an event, as long as the individual openings of the inlet valve all 

capture the wet weather flow from the same rainfall, the total flow into the SWDB arising from 

the same rainfall event, whether diverted by one or more than one set of inlet valve open/close 

operations, will be evaluated as a single event, arising from a single storm. 

Appendix P - Page 16 
Appendix Q: Diesel Emissions Reduction SEPs 

ExxonMobil shall develop and satisfactorily complete implementation of diesel 

emissions reduction SEPs in accordance with the following: 

A. Allocation: The $1,300,000 to be expended on diesel emissions reduction SEPs shall be 

allocated as follows: 

1. ExxonMobil shall spend no less than $250,000 to implement diesel emissions 

reduction SEPs in the general area where ExxonMobil’s Torrance Refinery is located. 

2. ExxonMobil shall spend no less than $300,000 to implement diesel emissions 

reduction SEPs in the general area where ExxonMobil’s Billings Refinery is located. 

3. ExxonMobil shall spend no less than $250,000 to implement diesel emissions 

reduction SEPs in the general area where ExxonMobil’s Joliet Refinery is located. 

4. ExxonMobil shall spend no less than $250,000 to implement diesel emissions 

reduction SEPs in the general area where ExxonMobil’s Baytown Refinery is located. 

5. ExxonMobil shall spend no less than $250,000 to implement diesel emissions 

reduction SEPs in the general area where ExxonMobil’s Beaumont Refinery is located. 

B. Schedule: By no later than one year after the Consent Decree Entry Date, ExxonMobil 

shall submit a Statement of Work (“SOW”) for each diesel emissions reduction SEP that it 

proposes to perform, which shall include a description of how the SEP meets the criteria in this 

Appendix, a schedule for development and implementation, and an estimated cost. Each SOW 

shall be subject to approval by EPA, after consultation with the appropriate state and local 

authorities. ExxonMobil shall complete implementation of the approved SOWs by no later than 

December 31, 2009. 

C. Project Criteria: ExxonMobil’s agreement with a third-party implementing a diesel 

emissions reduction SEP shall specify that the SEP shall satisfy each of the following criteria 

and shall require the third-party to certify in writing to ExxonMobil and EPA that the following 

criteria have been met: 

1. It shall involve the retrofit of high-emitting, in-service heavy duty diesel vehicles 

with emissions control equipment or the replacement of vehicles or engines in order to reduce 

emissions of particulates and/or ozone precursors. 

2. It shall include as a goal the creation of benefits to sensitive populations that are 

otherwise exposed to particulate emissions and ozone precursors from such vehicles. 

3. It shall cover the hardware and installation costs, and may provide also for 

incremental maintenance costs and/or costs of repairs on such hardware for a period of up to four 

years after installation. 

Appendix Q - Page 1 
4. It shall cover fleets for which the affected municipality, local governmental 

entity, or other owner/operator has committed: (i) to maintain any equipment installed in 

connection with the SEP during and after completion of the SEP; (ii) to use ultra low-sulfur 

diesel fuel with the affected vehicles during and after completion of the SEP; and (iii) to the 

extent feasible, to take steps to achieve additional emissions reduction benefits in connection 

with the project, such as by implementing an idle control program. 

5. It shall involve vehicles that are operated an average of at least four days per 

week. For vehicles operated on a seasonal basis, the four-day-per-week minimum threshold 

under the previous sentence shall apply during the season(s) in which the vehicles are operated. 

D. Reservation: EPA reserves the right to reject all or part of a project plan that could be 

funded by EPA under Section 103 of the Clean Air Act, or that is otherwise inconsistent with 

EPA SEP Policy, applicable EPA guidance, or any other provision of law. 

Appendix Q - Page 2 
Appendix R: Drawing of Real Estate Referenced in Consent Decree 

Subparagraph 156.d.(1) 

[Appendix R is on the following page] 

Appendix S: Drawing of Billings Refinery Scrap Yard and Laydown Areas and 

Land Treatment Unit as Referenced in Consent Decree Paragraphs 

137 and 138 

[Appendix S is on the following page] 
LOCK OOD ROAD

3rd ST 5+25

4th ST 00

2nd ST 9+5

5th ST 3+73

5th ST 4+75

7th ST 3+55

EFFLUENT TCH

KNOCK ENG NE

BLDG

8th ST 8+7

OL AC AT

st ST 2+45

BLDG

ADM
Appendix T: Drawing of Joliet Material Staging Area Referenced in Consent 

Decree Subparagraph 135.a 

[Appendix T is on the following page]