## TECHNICAL SUPPORT DOCUMENT FOR BEST AVAILABLE RETROFIT TECHNOLOGY UNDER THE REGIONAL HAZE RULE

AQPSTR 0 9
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April 29 , 2011

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

1021 NORTH GRAND AVENUE EAST

P.O. BOX 19276 SPRINGFIELD, ILLINOIS 6279 4
- 92762 

### Table of Contents List of Acronyms............................................................................ 4 Figures....................................................................................... . 5 Tables......................................................................................... 6 Executive Summary ....................................................................... 7 1.0 Introduction ...................................................................... . 9 2.0 BART
- Eli gible Sources in Illinois ............................................ 12 3.0 Visibility Modeling of BART
- Eligible Sources .... ......................... 14 3 .1 Modeling Methodolog y................................................. 1 5 3. 2 M odeling Results .......................................... ...... ........ . 18 4.0 BART Controls in Illinoi s ................................................... ... 2 3 4 .1 BART Controls for Illinois EGUs .................................... 2 3 4 .1.1 EGUs Under the MPS and CPS............................... 2 4 4.1.1.1 Dynegy ......... .......................................... 2 5 4 .1. 1. 2 Ameren ........ ........................................... 2 8 4.1. 1.3 Midwest Generation .................. ..... .............. 30 4.1. 2 Other Illi nois EGUs ......... ............... ................ ...... 31 4.1. 2.1 CWL P ................................. .................. .. 3 3 4 .1.2 .2 Dominion Kincaid ...................................... 3 5 4. 2 BART Controls for Non
- EGUs ........................................ 3 8 4 .2.1 C ITGO ............................................................ 3 8 4 .2.2 ExxonMobil ...................... ................................. 3 9 5 .0 Su mmary ........................... ................................................. 4 3 References .................................................................................... 4 53 

### Table of Contents (continued)

Appendix A Single Source Modeling to Support Regional Haze BART Modeling Protocol Appendix B Regional Air Quality Analysis for Ozone, PM 2.5 , an d 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 C ITGO Petroleum Corporation4 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 Flu e Gas Desulfurization IPM Integrated Planning Model LADCO Lake Michigan Air Directors Consortium LNB Low NO x Burner MPS Multi

- Pollutant Standard s MRPO Midwest Regional Planning Organization NH 3 Ammonia NO x Oxides of N itrogen OFA Over

- fire Air PAMS Photochemical Assessment Monitoring Sites PM Particulate Matter PM 2.5 Particulate Matter 2.5 microns in diameter PM 10 Particulate Matter 10 microns in diameter NSPS New Source Performance Standards SCR Selective Cataly tic Reduction SDA Spray Dryer Absorbers SIP State Implementation Plan SLAMS State and Local Air Monitoring Sites SNCR Selective Non

- catalytic Reduction SO 2 Sulfur Dioxide SPM Special Purpose Monitors USEPA United States Environmental Protection Agency VOC Volatile Organic Compounds VOM Volatile Organic Material5 

### Figures

Figure 3. 1 Model Domain with Class I Areas.................................... 16 Figure 3. 2 Illinois Sources Sub ject to BART...................................... 2 16 

### 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 A reas and T otal D iscrete R eceptors ............ ........ 17 Table 3 . 3 CALPUFF Modeling Results
- Number of D ays with

I mpacts G reater T han 0.5 D eciviews at N earby Cla ss I A reas ......... 19 Table 3 . 4 List of Units Subject to BART ....................................... ....... ... 2 2 Table 4.1 Presumptive BART Emission L imits for Coal
- F ired EGUs ... .......... 2 4 Table 4 . 2 NO x R eductions from Dynegy EGUs
- BART vs. MPS .... ...... ........ 2 7 Table 4 .3 SO 2 R eductions from Dynegy E GUs
- BART vs. MPS ........... ........ 2 7 Table 4 .4 NO x R eductions from Ameren EGUs
- BART vs. MPS ... .. ...... ........ 2 9 Table 4 .5 SO 2 R eductions from Ameren EGUs
- BART vs. MPS ...... ......... . . . 30 Table 4.6 NO x R eductions from Midwest Generation EGUs
- BART vs. CPS . ... 3 2 Table 4.7 SO 2 R eductions from Midwest Generation EGUs
- BART vs. CPS . ... 3 3 Table 4.8 NO x R eductions from CWLP
- BART vs. MOU .................. ...... .... 3 4 Table 4.9 SO 2 R eductions from CWLP
- BART vs. MOU .................. ..... ..... 3 4 Table 4.10 Comparison of Visibility Impacts from Dominion Kincai d

Emissions Control Scenarios

– Number of Days with Impacts Greater Than 0.5 Deciviews................................................ .... 3 7 Table 4.1 1 NO x R eductions from Dominion
- BART vs. MOU .................. ...... 37 Table 4.12 SO 2 R eductions from Dominion
- BART vs. MOU .................. .. ..... 3 8 Table 4 . 1 3 NO x R eductions from CITGO
- BART vs. Consent Decree ... . ... ...... 40 Table 4 . 1 4 SO 2 R eductions from CITGO
- BART vs. Consent Decree ... ...... ... . 4 0 Table 4 . 1 5 NO X R eductions from ExxonMobil
- BART vs. Consent Decree ...... . 4 1 Table 4 . 16 SO 2 R eductions from ExxonMobil
- BART vs. Consent Decree ....... . 4 27 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 1999 1 , is aimed at achieving pristine visibility conditions in the subject areas by 206 4. 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. A s part of a strategy to reduce pollu tants such as oxides of nitrogen (“NO x ”), sulfur dioxide (“SO 2 ”) , 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”) 2 published by USEPA in July of 2005, must be one of 26 specified source categories ; were in existence in August 1977 ; began operating af

ter 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 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 Midwes t 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 consultat ions with other RPO s and st ates 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.8

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 theref ore required to submit revisions to its State Implementation Plan (“ SIP ”) to require that subject emission sources install cost effectiv e retrofit control technologies or provide equivalent emission reductions.
Illinois has promulgated emission control re quirements 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 c ontained in f ederally 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 t o 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

.9

1.0 Introduction In an effort to restore national parks and wilderness area s 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

a ny future impairment. These ame ndments 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 prist ine visibility conditions at federal Class I areas by 2064. The Rule also addressed the visibility effects of pollution source s over a wide geographic range , and included sources from states without any Class I areas located within them.

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

s uch as oxides of nitrogen (“NO x ”), sulfur dioxide (“SO 2 ”), and particulate matter (“PM”) , that certain stationary emission sources should be subject to a Best Available Ret rofit 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 statio nary 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”) 2 published 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 challenge d by the American Corn Growers Association in the United St ates 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. T he ruling denied the challenge to the R egional H aze R ule 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, USEPA10

promulgated final amendments to its R egional H aze R ule that specifically apply to the BART provisions of the rule. 70 F ed. Reg. 39104 (July 6, 2005).

As stated in the final BART Guidelines , “ T he process of establishing BART emission limitations can be logically broken down into three steps:

(1) States identify tho se sources which meet the defi nition 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 contribut e to any impairment of visibility [ in a Class I area .] ‟ . A source which fits this description is „ subject to BART

. ‟

(3) F or each source subject to BART, s tates then identify the appropriate type and the level of control for reducing emissions

. ”

The BART G ui deline s 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 impac ts, as recommended by USEPA

. 2

The BART G uideline s identif y the following visibility

- impairing pollutants: SO 2 , 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 guideline s also allow states to exclude visibility

- impairing pollutants from consideration if they are below de minimis levels (i.e., 40 TPY for SO 2 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 limita tion 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 fiv e 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. Thi s 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 Re gional 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 devel oped in consultation with the MRPO, the other participating MRPO states, the USEPA, and participating F LMs

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

- eligible stationary sources in Illinois are s ubject 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.12

2.0 BART
- Eligible Sources in Illinois A cc ording 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 visibility

impairing pollutant (i.e., SO 2 , NO x , 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 T itle 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 request ed the date s 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 I llinois 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 chemic al process plants , two Portland cement plants , two glass fiber processing plants , one lime plant and one iron and steel plant

.13 Table 2.1 Initial List of BART
- Eligible Sources
S ource N ame County S ource 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 Sall e 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 Aventin e 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 Ene rgy 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 Soy land Power Coop Pike 149817AAB Midwest Generation LLC

- Will County Will 197810AAK Dynegy Midwest Generation Inc

- Wood River Madison 119020AAE14

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. US EPA guidance for performance of visibility modeling is set forth in the Phase 2 Summary Report and Recommendations for Modeling Long Range Trans port 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, inclu ding Illinois, the USEPA, and participating F LMs. 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 I llinois 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 G uidelines. Specifically, the MRPO used the Comprehensive Air Q uality Model

w ith E xtensions (“ CAMx ”) , with all p oint source particulate matter emissions domain

- wide set to zero to determine the contribution of particulate matter e missions to visibility impairment in the e astern U nited S tates . The MRPO demonstrated that particulate matter emissions from all point so urces in the domain do not contribute to visibility impairment ( impact greater than 0.5 deciviews ) anywhere in the e astern U nited S tates

. Since particulate matter emissions from just the BART

- eligible sources represent a small fraction of the total partic ulate 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 PM 2.5 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 BA RT

- eligible source using the CALPUFF model on a n individual unit basis. CALPUFF is a non - steady

- state puff dispersion model tha t 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

v ersions of the CALPUFF modeli ng system used for this analysis a re 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

ce lls 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

- 20 04). T he 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 t o 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 SO 2 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 A rea R eceptor I ndex. 4 A ccording to the

Figure 3 . 1 Model Domain w ith 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 lis t 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 U nited S tates 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 T able 3. 2 Class I Receptor A reas and T o tal D iscrete R eceptors

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 A nnual background concentrations for the e aster n United States are also given in Table 2

- 1 of USEPA‟s visi bility 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 d eci v iews , 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 A rea BOWA MN 856 Brigantine National Wildlife Refuge NJ 16 Dolly Sods/Otter Creek Wilderness WV 187 Great Gulf Wilderness NH 38 Great Smoky Mountains Na tional 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 Na tional Park VA 298 Sipsy Wilderness AL 148 Voyageurs National Park MN 36618

The CALPOST post

- processing software was used to depict the output from the CALPUFF mode l. These plots provided initial qualitative spatial information on visual impacts from each BART

- eligible source. C ALPOST was used to determine the number of days at each receptor that have at least 5 % degradation in light extinction (1 /Mm) over backgrou nd 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 a n individual unit basis. I llinois EPA used either maxi mum daily or maximum hourly emission rate s for SO 2 and NO x , 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 B ART G uideline s , the 98 th p ercentile value should be compared to the contribution threshold to determine whether a BART

- eligible source is subject to BART

. I f it is determined that for a given source there are more than 2 1 days in three years ( the 98 th 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 98 th percentile based on modeling one year) with a 0.5 deciviews impact, then the source is subject to BART

. Table 3. 3 contains the maxi mum 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 C lass I areas

. The six C lass I areas listed in Table 3.3 are those most frequently impacted by sources in Illinois. T o preserve clarity in the tabular results, only these six C lass I areas are listed. All of the Class I areas listed previously i n Table 3.2 were included in the modeling, however.19 Table 3 . 3 CALPUFF Modeling Results
- Number of D ays W ith I mpacts G reater than 0.5 D eciviews at N earby Class I A reas

Source Category Source Name Max. Days Class I Areas 3 Y rs 1 Y r BOWA HEGL ISLE M ACA 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 C arbon 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 th e modeling, eleven sources in Illinois exceed the 0.5 deciview visibility impact threshold on at least 22 days over the three

- year model ing timeframe , or on at least eight days in any one of the three modeled years . These sources are highlighted in red in Table 3. 320

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 p articulate 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 m uch 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 PM 2.5 emissions in the modeling of BART

- eli gible 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 model ing timeframe , or on fewer than 8 days in any one of the three modeled years did not have reliable PM 2.5 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 PM 2.5 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 modelin g results reflected in Table 3.3 for this source properly considered particulate matter emissions, in combination with emissions of SO 2 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 yea rs 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 so urces (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 d etermination 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 model ing timeframe , or on at least eight days in any one of the three modeled ye ars , 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 BART22 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. Powert on 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 tra in 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 Dallm an 1 ExxonMobil Coker ch g 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 111 B

- 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 flare23

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 follo wing 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 th e 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 the se factors to determine the level of control necessa ry 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 f or 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 requir ements and commitments for coal

- fired EGUs in Illinois that are subject

- to

- BART include: the Multi

- Pollutant Standard s (“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

- co ntrol 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 Presumptiv e BART Emission Limits for Coal
- Fired EGUs Pollutant Boiler Type Coal Type Presumptive Limit (lbs/mmBTU) SO 2 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

- fir ed 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 tangential

fired All 0.62 Cyclone All 0.10

4.1.1 EGUs under the MPS a nd 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, requir ing the installation of state

- of

- the

- art pollution controls on many of their electric generating units in25

Illinois. These regulat ions were promulgated to allow coal

- fired electric utilities more flexibility in meeting the Illinois M ercury R ule in exchange for significant NO x and SO 2 reductions. Appendix C contains the relevant p ortions of the fully adopted Illinois Mercury Rule, with the requirements for NOx and SO 2 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 u ltimately be contained in federally enforceable permits.
The MPS and CPS require affected utilities to meet fleet

- wide average emission rates, whic h 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 l imits i n 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 approva l of the S tate‟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 NO x and SO 2 than will implementation of BART controls on just subject to BART emission units. Emission reductions occurring after 2015 will improve visibilit y 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 s ubsections provide Illinois EPA‟s analysis of the emission reductions expected from the MPS and CPS and a descri ption 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. O nly the three coal

- fired boilers at Baldwin are subject to BART , however

. Units 1 and 2 at Baldwin are cyclone

- fired boiler s burning sub

- bituminous coal, while U nit 3 is a tangent i ally

- fired unit burning sub

- bituminous coal. Currently, Units 1 and 2 a re controlled by over - fire air (“OFA”) and selective catalytic reduction (“ SCR ”) for NO x , while26

U nit 3 is controlled by low

- NO x burners and OFA

. All three units are also limited b y a federal consent decree which requires that by December 31, 2012 NOx emis sions cannot exceed 0.10 pounds per million British thermal units (“ lb/ mm BTU ”) of NO x 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

- bitu minous coal , the presumptive BART emission limit for NO x is 0.15 lb/mmBTU. Since all three units at Baldwin are required to meet 0.10 lb/mmBTU, t he presumptive BART limits for NO x will be met

. All three units at Baldwin currently use low

- s ulfur coal to reduce SO 2 emissions

. However, Dynegy is instal l ing dry scrubbers on all three units at Baldwin by December 31, 2012 , which will allow these units to achieve SO 2 emissions levels well below the presumptive BART limit of 0.15 lb/mmBTU. Dynegy has also com mitted to installing baghouses for particulate control on all three units by December 31, 2012

.

Table s 4.2 and 4.3 compare the emission reductions expected from Dynegy system wide from compliance with t he MPS and the expected emission reductions from co mpliance with BART for NO x and SO 2 , 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 th e 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 c ompliance with t he MPS will reduce NO x emissions from Dynegy system wide by 23,8 31 TPY compared to 2002 emissions levels , and will reduce SO 2 emissions system wide by 47, 347 TPY compared to 2002 emissions levels

. Applying presumptive BART control s to just the units at Baldwin that are subject to BART will yield NOx reduction s of 1 6,169 TPY , and SO 2 reductions of 16, 658 TPY

. Compliance with t he MPS on a system

- wide basis will therefore yield much larger reductions of NO x and SO 2 than will the application of BART

.27

Table 4.2 NO x reductions from Dynegy EGUs BART vs. MPS

Base Year Presumpt ive 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 0.1 0 9,925 0.10 9, 925 0.10 9, 925 Baldwin 2 37,135 0.4 7,40 5 0.1 0 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 2,02 1 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 1 6,169 23,8 31 23,8 31 *The MPS emission limits are a system

- wide average and are not intended to re flect unit

- specific emission limits.

Table 4.3 SO 2 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 6,7 98 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 ar e a system

- wide average and are not intended to re flect 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. T hree of these, Coffeen , Duck C reek , 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 coal s . NOx emissions from b oth units a re already controlled using SCR s. Ameren installed wet scrubber s 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 addit ion to low

- NO x burners for NO x control. Ameren install ed 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

- bitu minous coal

. Unit 2 has low

- NO x burners, which Ameren plans to upgrade with a new low

- NO x burner/ OFA system. NO x is currently being controlled at Unit 3 w ith an SCR and low

- NO x burners. A meren 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 reduction s of NO x and SO 2 by 201 5 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 reduction s of almost 28, 000 TPY of NO x , and more than 131, 000 TPY of SO 2 by 2015 , which is much greater than would be achieved by subject

- to

- BART units meeting presumptive BART emission limits

.29

Table 4.4 NO x reductions from Ameren EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015 * MPS Final *

Plant Unit 1000

mmBTU Lbs/

mm BTU Tons Lbs/

mmBTU Tons/Year

Reduction Lbs/

mmBTU Tons/Year

Reduction Lbs/

mmBTU Tons/Year

Reduction Coffeen 1 18,570 0.53 4,918 0.1 0 3, 990 0.11 3,900 0.11 3,900 Coffeen 2 37,545 0.5 9,422 0.1 0 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 9 04 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 N A 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 1 6 , 17 1 27,896 27,896 *The MPS emission limits are a system

- wide average and are not intended to re flect unit

- specific emission limits.30

Table 4.5 SO 2 reductions from Ameren EGUs BART vs. MPS

Base Year Presumptive BART MPS 2015 * MPS Final *

Plant Unit 1 000

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 7,66 7 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 re flect unit

- specific emission lim its.

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 st ation are subject to BART. All four units are cyclone

- type boilers firing sub

- bituminous coal and vent to a common stack

. Current NO x control for all units31

consists of low

- NO x burners and OFA

. Midwest Generation is expected to install selective non

cata lytic reduction ( SNCR ) control s on all four units by 2012

. The units currently burn low

sulfur coal to c ontrol for SO 2 , but Midwest Generation currently plans to install flue gas desulfurization ( FGD ) equipment by the end of 2013 on all four units

.

Joli et 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 burn ing sub

- bituminous coal. Current NO x control s for B oiler s 71, 72, 81 , and 82 consist of low

- NO x burners and OFA

. Midwest Generation is expected to install SNCR controls on these four units by 2012. F or SO 2 , Midwest Generation is expected to instal l 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. NO x emissions from Unit 4 are currently controlled by low

- NO x burners and OFA

. Midwest Generation is expected to i n stall an SNCR on this unit by 2012

. For SO 2 , Midwest Generation is expected to i n stall FGD equipment by 2019

.

It should be noted that under the CPS , Midwest Generation is not required to meet unit specific emission limits for NO x or SO 2 , and that the anticipated CPS emission est imates given in Table s 4.6 and 4.7 reflect the fleet

- wide average emissions for all units. Tables 4.6 and 4.7 show that the C PS will lead to system

- wide reductions of more than 38,000 TPY of NO x and more than 35,000 TPY of SO 2 by 2015, which are much grea ter 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 negoti ated separate agreements with these companies to address the BART requirements. Consistent with these agreements, b oth plants have either installed controls or plan to install controls that will meet or exceed the presumptive BART limits . Unit

- specific

r equirements for these sources are contained in federally

- enforceable permits , which are included32

as part of Illinois‟ SIP submittal. The individual BART

- eligible units at each source are described in the following sections.

Table 4.6 NO x reductions from Midwest Generation EGUs BART vs. MPS

Base Year Presumptive BART CPS 2015 * C PS 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 0.1 5

- 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 0.1 0 6, 547 0.11 6,490 0.11 6,490 Powerton 52 21,13 7 0.73 7,695 0.1 0 6, 638 0.11 6,552 0.11 6,552 Powerton 61 18,293 0.66 5,995 0.1 0 5,080 0.11 5,031 0.11 5,031 Powerton 62 18,088 0.66 5,936 0.1 0 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 4 67 0.11 467 Will County 4 27,585 0.15 2,009 0.15 0 0.11 552 0.11 552 0.360 2 2 , 630 38,155 38,155 *The CPS emission limits are a system

- wide average and are not intended to re flect unit

- specific emission limits.33

Table 4.7 SO 2 reductions from Midwest Generation EGUs BART vs. MPS

Base Year Presumptive BART C PS 2015 * C PS 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 W ill 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 re flect unit

- specific emission limits.

4 .1. 2 .1 CWLP The subject

- to

- BART units at CWLP are Dallman 3 1, Dallman 3 2, and Lakeside 8. CWLP shut down t he Lakeside unit in 2009. The Dallman 3 1 and 3 2 units are cyclone boilers and burn bituminous coal. CWLP currently o perates 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 SCR s , or equivalent controls, to control NO x emissions on an annual basis. For SO 2 , 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 b y 2015. C WLP also agreed to meet a NO x emission rate of 0.11 lb/mmBTU by 2017. The Illinois EPA considers the operation of SCRs on the two subject

to

- BART units at CWLP at the emission rates contained in the agreement between CWLP and the Illinois EPA t o be sufficient to meet the BART requirement. For SO 2 , 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

c ontent of 6.0 lb s /mmBTU). Tables 4.8 and 4.9 reflect the reductions expected from operation of the se controls by 2015 , and demonstrate that CWLP will achieve emission reductions for NOx and SO 2 , respectively, which meet or exceed the presumptive BART cont rol requirements

.

Table 4.8 NO x R eductions 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/

m mBT U Tons/Year

Reduction Lbs/

mmBTU Tons/Year

Reduction Dallman 31 4,528 1.1 0 2,484 0.12 2,2 12 0.1 2 2,212 0.11 2,235 Dallman 32 4,787 1.11 2,654 0.12 2,3 66 0.1 2 2,366 0.11 2,391 Lakeside 8 1,593 0.94 749 0.12 6 53 0 749 0 749 5,2 31 5,327 5,375 *The emission limit is an average between D allman U nits 31 and 32. The emission limits shown here are not intended to re flect unit

- specific emission limits.

Table 4.9 SO 2 R eductions from CWLP
- BART vs. MOU

Base Year 2002 Presumptive BART MOU 2015 * MOU Final *
Plant Unit 1000

mmBTU Lbs/

mm BTU Tons Lbs/

mmBTU Tons/Year

Reduction Lbs/

m mBT U 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 2 36 0. 23 284 Lakeside 8 1,593 5.47 4,358 0. 30 4,1 19 0 4,358 0 4,358 4,310 4,781 4,875 * The emission limit is an average between Dallman U nits 31 and 32. The emission limits shown here are not intended to re flect 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 cyclone s and both burn sub

- bituminous coal. Dominion currently operates SCRs on both units at Kincaid to control NO x emissions, which, when operated on an annual basis, will meet the presumptive B ART control requirement for cyclone boilers. There are currently no controls in place to reduce emissions of SO 2 . The original agreement between Dominion and the Illinois EPA required that SO 2 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 Ki ncaid 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, Domi nion agreed to further reduce SO 2 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 agree ment 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 NO x emission rate of 0.07 lbs/mmBTU on a year

- round basis beginning March 1, 2013 , and that SO 2 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.

Dominio n‟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 SO 2 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 des cribed in Section 3 .0 of this report. The Illinois EPA has performed additional modeling, using the feder ally

- approved modeling protocol , to assess the visibility improvements of both the original and the revised36

agreements, and on an expanded list of Cla ss 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 r esults shown in Table 4.10 compare the number of day s exceeding the 0.5 deciview threshold at Class I areas for the following scenarios: NOx and SO 2 emissions at Kincaid meeting the presumptive BART emission limits of 0.10 and 0.15 lbs/mmBTU, respectively; NOx and SO 2 emissions at Kincaid meeting the emissi on limits of 0.07 and 0.18 lbs/mmBTU, respectively per the original agreement; and NOx and SO 2 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

ar eas were predicted to have no da ys exceeding 0.5 deciviews in either scenario. Comparing the number of days exceeding 0.5 deciviews between p resumptive BART controls and the two control scenarios, the results demonstrate that Dominion‟s original control plan resul t ed in generally equivalent visibility improvements than would be expected from controls meet ing the presumptive BART emission limits. At Mammoth Cave and Isle Royale, Dominion‟s original control plan resulted in fewer days exceed ing 0.5 deciviews, compar ed to p resumptive BART , but the p resumptive 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 Roya le, 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 excee ding the threshold between the scenarios modeled

. The Illinois EPA concludes t hat 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 Kinca id 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

Table s 4.1 1 and 4.1 2 compare the emission reductions expected from Dominion‟s final control plan and the emission red uctions that would occur from compliance with the presumptive BART emission limits for NOx and SO 2 . As shown in the tables, expected NO x emission reductions from Dominion‟s final control plan exceed the reductions that would occur from implementation of p resumptive BART by more than 9 00 TPY

. Expected SO 2 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 improvement s than will the presumptive BART emission limits , the Illinois EPA believes the final control plan meets the BART requirement for the Kincaid facility.

T able 4.1 1 NO x R eductions from Dominion
- BART vs. M OU
Base Year 2002 Presumptive BART Final Agreement
Plant Unit 1000

mmBTU Lbs/

mmBTU Tons Lbs/ mmBTU Tons/Year

Reduction Lbs/

m mBT U Tons/Year

Reduction Kincaid 1 32,265 0.64 10,300 0.1 0 8, 686 0. 07 9,171 Kincaid 2 32,238 0.66 10,605 0.1 0 8, 993 0.07 9,476 1 7,679 18,648 * The emission limit is an average between Kincaid Units 1 and 2 . The emission limits shown here are not intended to re flect unit

- specific emission limits.38

Table 4.1 2 SO 2 R eductions from Dominion
- BART vs. Final Agreement

Base Year 2002 Presumptive BART Final Agreement 2015 * Final Agreement 201 7 * Plant Unit 1000

mmBTU Lbs/

mmBTU Tons Lbs/

mmBTU Tons/Year

Reduction Lbs/

m mBT U Tons/Year

Reduction Lbs/

mmBTU Tons/

Year Reduction Kincaid 1 32,265 0.55 8,8 73 0.15 6,4 53 0. 20 5,646 0.15 6,4 53 Kincaid 2 32,238 0.54 8,7 0 4 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 U nits 1 and 2. The emission lim its shown here are not intended to re flect unit

- specific emission limits.

4 .2 BART C ontrol s 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 sour ces are the C ITGO 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 decree s . The consent decrees establish f

ederally

- enforceable emission l imits f or these sources that have resulted , or will result, in significant reductions in SO 2 and NO x 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 s ubsections describe the requirements established by the consent decrees for these sources.

4 .2.1 C ITGO The burners and heat ers that are subject to BART are required by the consent decree to burn fuel gas having no more than 0.1 g ra ins per dry standard cubic foot of hydrogen sulfide , consistent with Standards of Performance for New Stationary Sources ( NSPS ) Subpart J limits. (4 0 CFR § 60.100) The F luid C atalytic C racking U nit (FCCU) has an SCR/wet gas scrubber system that began operation early in 2008. The FCCU controls will reduce SO 2 by more than 85% and NO x by at least 9 0 %. In 2008, a tail gas recovery unit was installed to control SO 2 emissions from t he 119A and 119B sulfur trains . Units 119 A and 119 B ha d previously been un controlled

. Th ese control s have reduce d SO 2 from each train by a bout 98%, reducing the emissions to below the NSPS Subpart J limit of 250 p arts p er m il lion of v olume (“ppmv”) of SO 2 . Tables 4.1 3 and 4.1 4 compare expected emissions for NO x and SO 2 , respectively, from the application of controls on39

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

- wide basis, the co nsent decree will decrease NO x emissions by more than 1,200 TPY , and will decrease SO 2 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

re finery.

4 .2.2 ExxonMobil As with C ITGO , 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 NO x emissions from the FCCU by 201 1

. The south sulfur recovery unit now operate s with a tail gas recovery unit installed in 2008, which reduce s emissions of SO 2 to below the NSPS Subpart J limit of 250 ppmv of SO 2 . Tables 4.15 and 4.16 compare expected emissions reductions for NO x and SO 2 , respectively, from the application of contr ols 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 NO x emissions by more than 1,600 TPY , and will decrease SO 2 emissions by more than 18,000 TPY . The Illinois EPA c onsiders the requirements of the consent decree to be sufficient to meet the requirements for BART for the ExxonMobil refinery.40 Table 4.1 3 NO x 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 REGENERATIO N 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 4.1 4 SO 2 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 RECOV ERY 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 15125.2841 Table 4.1 5 NO X Reductions from ExxonMobil
- BART vs. Consent Decree 2002 Base BART controls Consent Decree 201 1 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 INCLUDI NG 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 C HARGE 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 ISOSTRI P 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 t he Exxon Mobil Consent Decree requires that the facility have a flare minimization plan and to construct and operate flare gas recovery

.42 T able 4.1 6 SO 2 Reductions from ExxonMobil
- BART vs. Consent Decree 2002 Base BART controls Consent Decree 20 09 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 H EATER 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 0.0 9 0.0 9 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 HEA TER 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 18 820

. 79 1882 0

. 7 9 * Emission reductions are uncertain but t he Exxon Mobil 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 unde r 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.

U SEPA‟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 Organiz ations (“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 conj unction 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 w as developed in consultation with the MRPO, the other participating MRPO states, the USEPA, and participating FLMs.

T his document describe s Illinois‟ approach for meeting the BART requirements for emission sources in Illinois that have been shown to be BA RT

- 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 Nati onal Park in Kentucky, the Mingo Wilderness Area in Missouri, and Isle Royale National Park in Michigan. Illinois is therefore required to submit revisions to44

its S tate I mplementation P lan to require that subjec t emission sources install cost

- effective

re trofit 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 enviro nmental benefits, than would be provided by implementation of BART. Other emission units are subject to provisions contained in f ederally

- enforceable consent decrees which meet or exceed the emission reductions than would be achieved by BART. The remaini ng 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. T hese req uirements, which were developed consider ing 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 tha t 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 o ther 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 F ed. R eg. 35714
- 35774 ( July 1, 1999 ) . 2. Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) D eterminations; Final Rule , 70 F ed. R eg. 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/Recep tors/index.cfm 5 . Guidance for Estimating Natural Visibility Con ditions Under the Regional Haze Rule , USEPA, EPA
- 45 4/B
- 03
- 005, September 2003. www.epa.gov/ttn/amtic/files/ambie nt/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. S trimaitis, 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 CALM ET Meteorological Model (Version 5). Earth Tech, Inc., Concord, MAModeling 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 de cision by the States about which BART eligible sources “cause or contribute” to visibility impairment and are subject to BART. The threshold used to determine whet her 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 recommend s CALPUFF for modeling single source visibility impacts at Cl ass 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 recomme nds the use of judgment to determine whether VOC, ammonia, or primary PM emi ssions contribute to visibility impairment (EPA, 2005). An additional mo deling analysis will be pe rformed to determine whether VOC, ammonia, and primary PM em issions 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 an d 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 ru le. Each State will need to make a policy decision to either accept th is position or to impose BA RT controls on their EGUs. Since the CAIR rule regulates SOX and NOX emissions, some consideration for other EGU emissions including prim ary 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 im pairment 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 mode ling), use of model plants to exempt individual sources, and cumulative modelin g to show that cert ain elevated point source emissions species do no t contribute to visibility de gradation 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 sour ces based on actual emissions and minimum distance to a Class I ar ea. (Note, the Q/d metric wasModeling Protocol: Page 2 of 8identified in EPA’s proposed rule and is similar to the emissionsdistance criteria suggest ed 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 th at the emissions-di stance criteria associated with less than 0.5 dv visibility impa cts on nearby Class I areas was consistent with a Q/d value of < 5.) (3) Review the results of the new CALP UFF modeling to determine which sources have less than a 0.5 dv im pact on nearby Class I areas and which can, therefore, be assume d 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 dete rmine 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 appl ied with the VOC, ammonia, and PM fine and coarse mass emissions “zeroed-out” fr om 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 incl uded 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 IMPAIR MENT MODELING: SUBJECT TO BART The CALPUFF modeling system is used to es timate 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 (CAL POST) (Scire et al, 2000a; Scire et al, 2000b). The versions of the CALPUFF modelin g 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 Repo rt 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 aModeling 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 year s 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 us ing discrete receptor points covering the Class I areas with an approximate resolu tion of 1 km. POSTUTIL is used to repartition nitrate into the gas or partic ulate phase depending on the estimated ammonia availability. This option has been shown to improve model performance (Scire et al, 2001). CALPOST is then applie d 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 year s 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 plo tting 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 latitu des 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 Elevat ion Model terrain height, distributed with CALPUFF and match the horizontal grid specifications. Meteorological inputs to CALPUFF are output from a prognostic mete orological model using four-dimensional data assimilation. MM5v3.6 ou tput is used to supply hourly meteorological data to CALPUFF.Modeling Protocol: Page 4 of 8 Observation data is included in the ETA an alysis fields used to initialize MM5 so additional assimilation of observational data in CALMET is redundant to the specific purpose of a prognostic meteorological mode l, 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 us ed to support regional photochemical modeling applications for the ozone, PM2.5, and regional haze State Implementation Plans (Baker, 2004; Bake r, 2005; Johnson, 2003). Modeling options are set to be consis tent with the IWAQM guidance. A few modifications to the suggested parameter se ttings 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 vari ables 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/m 3 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. Th ese 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 an d ambient observations. A scatter plot showing the prediction-observation pairs ov er the entire calendar year of 2004 is shown in Figure 2. Figure 2. CAMx4 model and ambient ammonia Predictions at Bondville, IllinoisModeling Protocol: Page 5 of 8 SOURCE SPECIFIC INPUTS: EMISSIONS and STACK PARAMETERS States will use the 24-hr maximum emi ssions rate between 2002 and 2004. If this data is not available, then a short term “a llowable” 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 actu al annual emissions di vided 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 informatio n 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 de nsity 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 wa y 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 ar eas 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 T N 736 Hercules-Glades MO 80 Isle Royale National Park MI 966 James River Face VA 52 Linville Gorge NC 66 Lye Brook Wilderness V T 103 Mammoth Cave National Park KY 302 Mingo MO 47 Seney MI 173 Shenandoah National Park VA 298 Sipsy Wilderness A L 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 necessitate s using the CALPOST background light extinction option 6, which computes light extinction from speciated PM measurements with a monthly RH adjustme nt 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% be st 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 equati on, which are needed for CALPOST option 6. Annual background concentrations for the eastern United States are given in the Guidance for Estimating Natu ral 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 Dako ta 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(nat ural conditions in deciviews/10) Second, the chemically speciated natural ba ckground 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*[a mmonium 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 expresse d 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 fo r 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 A nnual 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 1.131Modeling Protocol: Page 7 of 8 The visibility degradation be yond natural conditions expressed in deciviews is kept for each Class I area and ranked over th e length of the modeling simulation. The criteria used to determine if a source is “c ontributing” to visibility impairment is the 98 th 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 98 th percentile is interpreted as any source with more than 21 days of visibili ty impairment over the 3 year modeling period or 7 days of visibi lity 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 impair ment over the 3 year modeling period is “contributing” to visibility impairment. The gridded receptor run wi ll be post processed thro ugh CALPOST for plotting purposes. The plots show th e 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 subjec t 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 pr e-control emission rates (EPA, 2005). The post-control CALPUFF simu lation 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 Simulati ons (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 Re lated Values Workgroup (FLAG) Phase I Report. December 2000. Johnson, M. Meteorological Modeling Protoc ol: IDNR 2002 Annual MM5 Application, 2003. See http://www.iowacleanair.com/pr of/progdev/file s/protocol.pdf (accessed March 1, 2005). LADCO, 2005. Conceptual Model of PM2.5, Re gional Haze, and Ozon e. 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’ Guid e for the CALPUFF Dispersion Model (version 5). Earth Tech. 2000a. http://src.com/calpuff/calpuff1.htmModeling 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. Moor e, 2001: The Southwest Wyoming Regional CALPUFF Air Quality Modeling Study – Volume I. Prepared for the Wyoming Dept of Environmen tal Quality. Available from Earth Tech, Inc., 196 Baker Avenue, Concord, MA. US EPA, 1998. Interagency Workgroup on Air Qualit y Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long Range Transp ort Impacts. EPA Document Number: EPA-454/R-98- 019 US EPA, 2003. Regional Haze: Estimating Natural Visi bility 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 Summe rhays, Randall Robinson, Todd Hawes. July 14, 2005.

# Regional Air Quality Analyses for

Ozone, PM 2. 5 

# , and Regional Haze: F inal Technical Support Document

April 25 , 2008 States of Illinois, Indiana, Michigan, Ohio, and WisconsinAppendix C Illinois Mereury Rule
The Illinois EPA is seeking approval from the United States Environmental Protection Agency of the following holded provisions of the Illinois Mercury Rule, 35 Ill. Adm. Code Part 225, Subpart B: Control of Mercury Emissionsfrom Coal-Fired Electric Generating Units, under this submission. Please note that the non-bolded provisions are included for 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 NO x 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) If the 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

1requirements 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 of its 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 of supporting 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) of this 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.

2c) Control Technology Requirements for Emissions of Mercury. 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) of this 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) of this Scction), the owncr or operator of the EGU must install, to the extent not already installed, and properly operate and maintain one of the following emission control devices: i) A Halogenated Activated Carbon Injection System, complying with the sorbent injection requirements of subsection (c )(2) of this Section, except as may be otherwise provided by subsection (c)(4) of this Section, and followed by a Cold-Side Electrostatic Precipitator or Fabric Filter; or ii) If the 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) of this 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 of the designated EGUs does not exceed 4% of the total gross MW capacity of the MPS Group. For any EGU subject to one of these two options, unless the EGU is subject to the emission standards in subsection (d)(2) of this Section, beginning on January l, 2013, and continuing until such date that the owner or operator of the EGU commits to comply with the mercury emission standard in subsection (d)(2) of this Section, the owner or operator of the EGU must install and properly operate and maintain a Halogenated Activated Carbon Injection System that complies with the sorbent injection requirements of subsection (c )(2) of this 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 of subsection (c)(2) of this Section is defined as the "principal control technique."

32) For each EGU for which injection of halogenated activated carbon is required by subsection (c)(l) of this Section, the owner or operator of the EGU must inject halogenated activated carbon in an optimum manner, which, except as provided in subsection (c)(4) of this Section, is defined as all of the following: A) The use of an injection system designed for effective absorption of mercury, considering the configuration of the 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 FLUEP AC MC Plus, or the injection of any other halogenated activated carbon or sorbent that the owner or operator of the EGU has demonstrated to have similar or better effectiveness for control of mercury emissions; and C) The injection of sorbent 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 of input 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 of input mercury, 5.0 Ibs per million actual cubic feet; iii) For an EGU firing a blend of subbituminous and bituminous coal, a rate that is the weighted average of the 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 of subsections (c)(2)(C)(i), (c)(2)(C)(ii), or (c)(2)(C)(iii) of this Section on a unit-specific basis, provided that the owner or operator of the 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 of subsection (c)(2)(C) of this Scction, the flue gas flow shall be the gas flow rate in the stack for all units except for those

4equipped 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 of Charles' Law for the differences in gas temperatures in the stack and at the inlet to the electrostatic precipitator (V esp = 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) of this Section must submit an application to the Agency proposing such rate or rates, and must meet the requirements of subsections (c)(3)(A) and (c)(3)(B) of this Section, subject to the limitations of subsections (c)(3)(C) and (c)(3)(D) of this 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 of relevant 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 of the EGU may supplement its application; and C) Any decision of the 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 of the 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 of the 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 of subsection (c )(2) of this Section for any system needed to carry out the evaluation, as further provided as follows: A) The owner or operator of the EGU must conduct the evaluation in accordance with a formal evaluation program submitted to the Agency at least 30 days prior to commencement of the evaluation;

5B) The duration and scope of the evaluation may not exceed the duration and scope reasonably needed to complete the desired evaluation of the 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 of the EGU must submit a report to the Agency no later than 30 days after the conclusion of the evaluation that describes the evaluation conducted and which provides the results of the evaluation; and D) If the evaluation of the alternative control technique shows less effective control of mercury emissions from the EGU than was achieved with the principal control technique, the owner or operator of the EGU must resume use of the principal control technique. If the evaluation of the alternative control technique shows comparable effectiveness to the principal control technique, the owner or operator of the 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 of the principal control technique. If the evaluation of the alternative control technique shows more effective control of mercury emissions than 'the control technique, the owner or operator of the 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 of this Section must also comply with thc following additional requirements: A) For the first 36 months that injection of sorbent is required, it must maintain records of the usage of sorbent, the flue gas flow rate from the EGU (and, if the unit is equipped with activated carbon injection prior to a hot-side electrostatic precipitator, flue gas temperature at the inlet of the hot-side electrostatic precipitator and in the stack), and the sorbent feed rate, in pounds per million actual cubic feet of flue, on a weekly average; B) After the first 36 months that injection of sorbent is required, it must monitor activated sorbent feed rate to the EGU, gas flow rate in the stack, and, if the 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 of flue gas, on an hourly average; and

6C) If a blend ofbitwninous and subbituminous coal is fired in the EGD, it must keep rccords of the 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 of this 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 of the EGD notifies the Agency that it will comply with these standards) and continuing thereafter, the owner or operator of the EGU must comply with one of the 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 of input mercury. 2) For each EGD in an MPS Group that has been addressed under subsection (c)(I )(B) of this Section, beginning on the date when the owner or operator of the EGD notifies the Agency that it will comply with these standards and continuing thereafter, the owner or operator of the EGD must comply with one of the 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 of input mercury. 3) Compliance with the mercury emission standard or reduction requirement of this subsection (d) must be calculated in accordance with Section 225.230(a) or (d), or Section 225.232 until December 31, 2013.

74) 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 of this Subpart. e) Emission Standards for NO x and S02. 1) NO x 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 NO x 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 of the 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) NO x Emission Standards.

8f) 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 NO x 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 NO x 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 NO x 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 NO x 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 NO x and S02 Allowances.

9I) 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 NO x 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) of this 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) of this Section. Such allowances that are not retired for compliance, or otherwise surrendered pursuant to a consent decree to which the State of Illinois 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 of this 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 NO x or S02 standard in subsection (e) of this 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 of this subsection (f), NO x 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 NO x 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 of this subsection (f) for the previous calendar year, and which includes identification of al1y allowances that have been surrendered to the USEP A 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

10from 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, if such 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 of the EGU.

11b) 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)

12Section 225.295 Combined Pollutant Standard: Emissions Standards for NO x and S02 a) Emissions Standards for NO x 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 NO x 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 of the 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.]

13d) The CPS group average annual S02 emission rate, annual NO x emission rate and ozone season NO x emission rates shall be determined as follows: n n ER avg =:E (S02i or NO xi tonsy:E (HI;) i=1 i=1
Where:
ER avg = HI i , = S02i 

## = NO xi = 

### 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 NO x 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 NO x and 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) If Crawford 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

14B) On or before December 31, 2018, install and have operational FGD equipment on Crawford 7; 5) If Crawford 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 of specified 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 550 0 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 350 0 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 of the 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 of subsections 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)

15225.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)

16Prepared for: Dominion Energy, Inc.



# BART Analysis for the Kincaid Power Plant

ENSR Corporation January 2009 Document No.: 02285-076-400Prepared 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.: 02285-076-400i January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### Contents

Executive Summary ...........................................................................................................................................1

1.0 Introduc tion ................................................................................................................... ......................... 1-1

2.0 Background Data ................................................................................................................ ................... 2-1 2.1 Overview of BART Emission Units................................................................................................ .. 2-1 2.2 Existing Contro l Technol ogies.................................................................................................. ....... 2-1 2.3 Baseline Em issions ............................................................................................................. ............ 2-1

3.0 Emission Contro l Altern atives.................................................................................................. ........... 3-1 3.1 SO 2 Cont rol....................................................................................................................... ............... 3-1 3.1.1 Technical Feasibility of Alternative SO 2 Contro ls ............................................................. 3-1 3.1.2 Impacts of Alternative SO 2 Contro ls.................................................................................. 3-4 3.1.3 Discussion of Candidate SO 2 Control Tec hnologies ........................................................ 3-5 3.2 NO X Emission Contro ls............................................................................................................. ....... 3-6 3.2.1 Technical Feasibility of Alternative NO x Contro ls ............................................................. 3-6 3.2.2 Discussion of Candidate NO x Control Tec hnologies ........................................................ 3-7 3.3 PM Emission Cont rol............................................................................................................ ........... 3-7 3.4 Control Sc enario s .............................................................................................................. .............. 3-8

4.0 Meteorological Data used in Vi sibility Improvemen t Modeli ng....................................................... 4-1 4.1 Elements of the Refined A nalysis ............................................................................................... .... 4-1 4.2 CALMET Pr ocessing .............................................................................................................. ......... 4-1

5.0 CALPUFF Modeling Procedures.................................................................................................... ...... 5-1 5.1 CALPUFF Modeling Domain and Recept ors.................................................................................. 5-1 5.2 Technical Options Used in the M odeling ........................................................................................ 5 -1 5.3 Natural Conditions and Monthly f(RH) at Cla ss I Areas ................................................................. 5-1 5.4 Light Extinction and Haze Impact Calcul ations .............................................................................. 5-2

6.0 CALPUFF Modeling and BART De termination R esults .................................................................... 6-1 6.1 Modeled Contro l Scenar ios...................................................................................................... ....... 6-1 6.2 Modeling Results for Baseline Em issions....................................................................................... 6 -1 6.3 Modeling Results for the Alte rnative Contro l Cases ....................................................................... 6-1 6.4 Cost of BART Control Cases ..................................................................................................... ..... 6-4 6.5 Conclu sions .................................................................................................................... ................. 6-6ii January 2009 BART Analysis for Kincaid Power Station 02285-076-400 7.0 Refere nces..................................................................................................................... ......................... 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 Co ntrol Emi ssions.............................. ES-2 Table ES- 2 8th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control Option Em issions............................................................................................................... .....ES-3 Table ES-3 Visibility Improvement and Annual Cost s for Each Control Option at Mammoth Cave .......ES-3 Table 2-1 Kincaid Baseli ne Emi ssions ..................................................................................................... 2-3 Table 2-2 Kincaid Baseline Sta ck Paramete rs......................................................................................... 2-3 Table 3-1 Total Capital and Annual Costs Associated with Technically Feasible SO 2 Control Technologies Applied to Kincaid Units 1 a nd 2.............................................................................................. 3 -4 Table 3-2 Kincaid Future DSI with Tr ona Emissions (C ase 1) .............................................................. 3-10 Table 5-1 MRPO Ozone and Ammonia S easonal Concent rations ......................................................... 5-1 Table 5-2 Annual Average Natural Ba ckground Concent rations ............................................................ 5-2 Table 6-1 Regional Haze Impacts Due to Baseline and BART Control Emis sions ................................ 6-2 Table 6-2 Visibility Improvement and Annual Costs for Each Control Ca se at Mingo ........................... 6-4 Table 6-3 Visibility Improvement and Annual Costs for Each Control Case at Mammoth Cave ........... 6-5iii January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### List of Figures Figure ES- 1 8 th Highest Regional Haze Impacts Averaged Over 3 Years Due to Baseline and BART Control Option Em issions............................................................................................................... .....ES-2 Figure ES-2 Annual Costs vs. Visibility Im provem ents........................................................................... ...ES-4 Figure 4-1 Kincaid CALMET and CALP UFF Modeling Domain............................................................... 4-3 Figure 4-2 Location of Meteorological Stations used in CALMET Processi ng ........................................ 4-4 Figure 6-1 8 th 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: Case s 1, 1a, and 2........ 6-3 Figure 6-3 Annual Costs vs. Visibili ty Improvem ents................................................................................ 6-6ES-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 Be st Available Retrofit Technology (BART) to those existing eligible sources in order to help meet the target s for visibility improvement at designated Class I areas. The IEPA has identified the two coal-fired boilers, Unit s 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 R egional Haze State Implementation Plan (SIP). The BART rules require that sources that are subject to BART perform a site-specif ic BART analysis including a control technology review and CALPUFF modeling to a ssess the visibility impact of the emission units. Additionally, for large Electric Generating Units (E GU) affected by the rule, the source should meet presumptive control levels for nitrogen oxide (NO X ) and sulfur dioxide (SO 2 ) unless it is determined that alternative control levels are justified or equivalent in effectiveness. The presumpt ive BART limits for these units are continuous year-round operatio n of the existing SCR systems at 0.10 pound per million British thermal unit (lb/MMBtu) for NO X and 0.15 lb/MMBtu or 95 percent control for SO 2 . This report documents the case-by-case BART analysis conducted for NO x , SO 2 , and PM 10 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 So rbent Injection (DSI) with Trona capable of achieving an SO 2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.18 lb/MMBtu (if achi evable), enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu.

• Case 3 . Firing 1.62%-sulfur Illinois Basin bitumi nous coal, Wet Flue Gas Desulfurization (WFGD) capable of achieving an SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu. Kincaid Units 1 and 2 currently employ high-efficiency Elec trostatic 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, respecti vely. These emissions ar e 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 le vel of 0.015 lb/MMBtu. The DSI with Trona system has the potential for significant reductions in PM emissions 1 . 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 H 2 SO 4 removal due to Trona injection.

1 PM 10 filterable and condensable emissions were reduced by ap proximately 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.pdfES-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 CALPUFF modeling results for meteorological dat abase 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 resu lts of the baseline emissions indicate that the 8 th highest visibility impacts at Mingo and Mammoth Cave are abo ve the 0.5 delta deciview significance threshold. Therefore, a BART determinat ion analysis was conducted. CALPUFF modeling results for visibility impr ovements due to application of the four SO 2 control cases at the two Class I areas are tabulated in Table ES-1 and graphica lly plotted in Figure ES-1. The table indicates that substantial visibility improvements occur with the implement ation 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 98 th percentile change of at least 0.5 deltadeciview) occur at either Class I ar ea 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 ControlES-3 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Figure ES-1 8 th 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 Area8th 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, WFGDES-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Tables ES-2 and ES-3 list the projected annualized contro l cost that is a function of the capital and annual operating costs, as well as fixed c apital charges estimated by Dominion Energy. The table also presents a computation of each control case’s visibility improv ement 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 8 th highest regional haze impacts at Mingo and Ma mmoth Cave, respectively, averaged over the three years. Figure ES-2 presents a graph of visibi lity 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 SO 2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the us e 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 Case a 8 th 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 $24,820,000 b $23,100,000 Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000 c $29,210,000 Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.26 $94,700,000 d $85,060,000 Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.46 $125,370,000 e $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 Case a 8 th 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 $24,820,000 b $25,720,000 Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000 c $32,710,000 Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.25 $94,700,000 d $98,200,000 Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.40 $125,370,000 e $152,950,000ES-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

0.00.1 0.2 0.30.40.5 0.6 0.70.80.9 1.0 1.11.21.3 1.4 1.5 8th Highest delta-dv (Average of 3-Years)Cost ($/year) Mingo Mammoth

Baseline Case 2 Case 3

Case 1 Case 1A1-1 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 visi bility 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 Environmen tal 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 Ki ncaid Power Plant as BART-eligible emission units. The BART rules require that sources that are subject to BART perform a site-specif ic BART analysis including a control technology review and CALPUFF modeling to a ssess the visibility impact of the emission units. Additionally, for large Electric Generating Units (E GU) affected by the rule, the source should meet presumptive control levels for nitrogen oxide (NO X ) and sulfur dioxide (SO 2 ) unless it is determined that alternative control levels are justified or equivalent in effectiveness. The presumpt ive BART limits for these units are continuous year-round operatio n of the existing SCR systems at 0.10 pound per million British thermal unit (lb/MMBtu) for NO X and 0.15 lb/MMBtu or 95 percent control for SO 2 . The BART analysis was conducted in accordance with th e 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 technologi es 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, operat ing problems and reliability, and adverse side effects on the rest of the facility. 3. Step 3 – Evaluate the control effectiveness of th e remaining technologies based on current pollutant concentrations, flue gas properties and compos ition, control technology performance, and other factors. 4. Step 4 – Evaluate the annual and incremental co sts of each feasible option in accordance with approved EPA methods, as well as the associated en ergy and non-air quality environmental impacts. 5. Step 5 – Determine the visibili ty impairment associated with base line 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 c onsequence of air pollution control equipm ent may be considered in the final BART decision-making process. This report documents the case-by- case BART analysis conducted for SO 2 , NO x 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 SO 2 , NO x and PM control technologies. The available meteorological data and the CALPUFF modeli ng procedures are described in Sections 4.0 and 5.0, respectively. The results of the vi sibility improvement modeling using CALPUFF are presented in Section 6.0, along with the BART recommendation. Re ferences are listed in Section 7.0.2-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### 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 operati on during the time period (1962-1977) targeted by the Regional Haze BART Rule. Un its 1 and 2 are cyclone-fired boilers manufactured Babcock & Wilcox. These two units each have a rate d capacity of 4,200,000 lb/hr of superheated steam at 2,620 psig and 1,005°F. The steam is directed to dedic ated 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 NO x emissions. Kincaid’s permit requires t he SCR system need only be operated during the ozone season (May 1 st through September 30 th ) and must achieve a NO x 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 l east 0.10 lb/MMBtu according to the station’s permits. Units 1 and 2 currently burn low-sulf ur Powder River Basin (PRB ) sub-bituminous coal to control SO 2 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 SO 2 and NO x baseline emissions were determined using measurement data collected by the continuous emissi ons monitoring system (CEMS) during the years 2002 through 2006. Filterable PM baseline emissions were deter mined using the highest results of the latest stack tests conducted in November 1999. The SO 2 and NO x baseline emission rates were derived from maximum daily emissions measured by the CEMS) during the years 2002 through 2006. The PM emi ssions were derived from the results of stack tests conducted in November 1999. Speciation of the parti culate matter emissions into filterable and condensable PM 10 components was determined using the following approach:

• Filterable PM was subdivided by size category cons istent 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 PM 10 and 36% of the PM emissions are fine filterable PM 10 emissions (less than 2.5 microns in size).

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine filterable PM 10 based on the best estimate for electric utility c oal combustion in Table 6 of “Catal og 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 PM 10 emissions, assumed to consist of H 2 SO 4 , are based on procedures presented in “Estimating Total Sulfuric Acid Emissi ons from Stationary Power Plants," EPRI, Technical Update, March 2007 (and reaffirmed in a Marc h 2008 update). For coal-fired boilers, H 2 SO 4 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 H 2 SO 4 emission rate (lb/hr), Q is the baseline SO 2 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 equ ipped with SCR, the maximum daily NO x 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 PM 10 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 PM 10 emissions from cyclone boilers, AP-42 directs you to the use the pulverized c oal emission factor for cyclone boilers. Table 2-1 provides a summary of the SO 2 , NO x , 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.2-3January 2009BART Analysis for Kincaid Power Station02285-076-400Table 2-1 Kincaid Baseline EmissionsTable 2-2 Kincaid Baseline Stack ParametersCaseUTM Northing(m)UTMEasting (m)BaseElevation (m)StackHeight (m)StackDiameter (m)Flue GasTemperature (°K)Flue Gas FlowRate (m3/s)Flue GasVelocity (m/s)Baseline 4,385,605.6 284,850.0182.87 186.69 9.03 410.93 1,673.26 26.213-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### 3.0 Emission Control Alternatives

The visibility impairing pollutants discussed in this section include NO X , SO 2 , and PM. Information on control of these pollutants through application of a control devi ce, combination of devices, and/or operational change is provided. 3.1 SO 2 Control Sulfur dioxide emissions are generated in fossil fuel-fired combustion units from the ox idation of sulfur present in the fuel. Approximately 98% of the sulfur in coal is emitted upon combustion as gaseous sulfur oxides, SO 2 and SO 3 . Uncontrolled emissions of SO 2 are directly related to the fuel sulfur content, and not by the firing mechanism, boiler size, or operation. Many coal-f ired boilers in the U.S. limit emissions of SO 2 through the use of low sulfur western coals, including Powder Ri ver Basin Coal. Compared with higher sulfur eastern bituminous coal that may contain as much as 4% sulf ur, the practice of burning western coal can reduce SO 2 emissions by approximately 70% to 90%. Howeve r, control equipment can generally remove a higher percentage of the SO 2 from higher sulfur coal than lower sulfur c oal. The selection of coal type and sulfur content, therefore, is an import ant aspect of the determination of BART and needs to be considered in conjunction with add-on control alternat ives when performing the BART analysis. The Unit 1 and 2 boilers currently bur n low-sulfur PRB coal to limit SO 2 emissions. Alternative SO 2 control technologies available to further reduce SO 2 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 SO 2 control technologies are addressed in the remainder of this section. 3.1.1 Technical Feasibility of Alternative SO 2 Controls The technical feasibility and performance levels of the alternative SO 2 control technologies are evaluated below in terms of their applica tion to Kincaid Units 1 and 2. Wet Flue Gas Desulfurization WFGD typically uses limestone or lime to react with SO 2 from coal-fired boilers. The temperature of the flue gas is reduced to its adiabatic saturation temperature and the SO 2 is removed from the flue gas by reaction with the alkaline medium. SO 2 is absorbed into the scrubbing slurry, which falls into the lower section of the vessel known as the reaction tank. Finely gr ound 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: CaCO 3 + SO 2 → CaSO 3 • 1/2 H 2 O + CO 2 CaSO 3 •1/2 H 2 O + 3H 2 O + O 2 → 2 CaSO 4 •2 H 2 O3-2 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 re actions for lime scrubbing are as follows: Ca(OH) 2 +SO 2 → CaSO 3 • 1/2 H 2 O + 1/2 H 2 O Ca(OH) 2 + SO 2 + 1/2 O 2 + H 2 O → CaSO 4 •2 H 2 O Whether limestone or lime is used as the reagent for SO 2 removal, additional equipment is needed for preparing the lime/limestone slurry and collecting and c oncentrating 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 SO 2 emissions resulting from combustion of high-sulfur coal s. 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 en vironmental impacts incl uding generating an additional solid waste stream and an additional liquid waste stream. WFGD has been applied on many coal-fired boilers in t he United States. These installations have been demonstrated to consistently achieve SO 2 removal efficiencies ranging from 90% to in excess of 95%. These high SO 2 control efficiencies would provide Dominion with an opportunity to use higher sulfur Illinois bituminous coal and still meet the presumptive BART li mit of 0.15 lb/MMBtu. Al though 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 consider ably 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 trans portation from Wyoming, due to recent incidents of derailments and delays in PRB coal shipments. If Dominion were required to install WFGD for SO 2 control, therefore, they woul d 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 c oal and will achieve an outlet SO 2 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 particl e 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 evapor ated by the hot flue gases. The SO 2 are absorbed onto the hydrated lime par ticles 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 SO 2 removal efficiencies are signi ficantly higher when the dry3-3 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 CaSO 3 and CaSO 4 ). The largest of these particles are separated by gravity from the gas in the absorbing chamber by gravit y 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 de vice, it allows for further reaction of the lime captured in the filter media with the SO 2 in the flue gas. This is due to the laye r of porous filter cake on the surface of the filter that contains the reagent that all flue gas mu st pass through. This allows for increased efficiency of control of SO 2 and H 2 SO 4 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 ut ilization, 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 c onsistently achieve SO 2 removal efficiencies of 80 to 90%. For the purposes of the visib ility 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 SO 2 emission level of 0.15 lb/MMBtu consist ent with the presum ptive BART limit. Dry Sorbent Injection (DSI) with Trona A variety of manufacturers have developed DSI systems for SO 2 control on coal-fired boilers. This technology uses very standard process equipment, including carb on steel storage silos, material handling equipment, blowers, and pneumatic transport piping, all of whic h are commodity components available from multiple vendors at similar cost. In order to remove SO 2 compounds from hot exhaust gases, finely ground Trona, sodium sesquicarbonate [Na 3 (HCO 3 )], can be injected into the hot gas stream to react with the SO 2 and form sodium sulfite (Na 2 SO 3 ). 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(Na 3 (HCO 3 )•(CO 3 )•2H 2 O) + 3SO 2 → 3Na 2 SO 3 + 5H 2 O + 4CO 2 A plant’s operating conditions will ultimately affect the effectivene ss of DSI with Trona in removing SO 2 . The most important variables for high removal efficiency are injection temperature, SO 2 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 SO 2 removal rates during the short term demonstration tests discussed below. In 2005 the Mirant Potomac River Station 2 demonstrated a maximum SO 2 control of ≈ 80% while burning Central Appalachian and Columbian coals. In 2008, We Energies Presque Isle Power Plant demonstrated a maximum SO 2 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 SO 2 control of ≈ 60% and an SO 2 emission rate of 0.20 lb/MMBtu based upon a 30-day rolling average. Dominion has assumed 60% SO 2 removal for PRB coal at Kincaid for several reasons, related to differences in the units, the limited testing scope at Presque Isle and t he 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 eval uated for Kincaid. Further, the Presque Isle tests consisted of only 8-hour injections of Trona in a 90 MW unit. Effective utiliz ation 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 exampl e, during normal operations Kincaid operates at reduced loads and lower temperatures at night, which ty pically which reduces the reactivity of Trona. The

2 http://www.mirant.com/our_business/where_we_wo rk/Unredacted_Trona_Test_Report_011706BC.pdf3-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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 proces s 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 th e use of the water spray, the increased stack gas temperature will tend to avoid the local impacts of increased H 2 SO 4 emissions associated with oxidation of SO 2 to SO 3 by the SCR catalyst and the subsequent formation of H 2 SO 4 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 scr ubber. Trona is a very reactive reagent that can be used to achieve a range of efficiencies depending upon th e amount of sorbent injected into the ductwork. Two cases are presented for Trona injection for SO 2 control (Cases 1 and 1a), with slightly different SO 2 emission rates (0.20 lb/MMBtu for Case 1 and 0.18 lb/MMBtu for Case 1a). Although the lower SO 2 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 SO 2 Controls The alternative control technologies available to control SO 2 emissions from Units 1 and 2 are DSI with Trona, DS/FF and WFGD. This section documents the ec onomic, non-air environmental, and energy impacts associated with applying alternative co ntrol 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 SO 2 control technologies were provided by Dominion Energy. The annual fixed capital charges and annual operating costs were also provided by Dominion. An interest ra te of 9.8% and an amortizati on 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 SO 2 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 DS I with Trona, DS/FF and WF GD as the available SO 2 control technologies providing the highest removal efficiencies relative to other technologies. Of the two scrubber options, the DS/FF combinatio n is considered the preferred control technology. The disadvantages of WFGD compared to DS/FF system include:

• higher water consumption or wastewater treatm ent requirement resulti ng in increased energy and utility operating costs;

• liquid effluent from the wet scrubber requires pretr eatment to meet regulatory requirements before discharge to a municipal sewer;

• problems associated with the disposal of wet sl udge resulting from the process, requiring extensive sludge thickening and dewatering equipment;

• a relatively low stack gas temperature result ing in reduced buoyancy and lower plume rise, and hence poorer dispersion of the residual pollutants;

• visible steam plume under most meteorological condit ions, especially during perio ds of high relative humidity; and

• corrosion, scaling and fouling of scrubber internal s, 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 SO 2 and other acid gas emissions, as well as the control of sec ondary 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 WF GD 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 inco rporated into the visibility modeling. 3.1.3 Discussion of Candidate SO 2 Control Technologies The SO 2 control technologies identified for evaluat ion include DSI with Trona (two possible SO 2 emission rates), DS/FF and WFGD. Of these tech nologies, WFGD is capable of higher SO 2 control efficiencies ranging from 90 to 95%, providing Dominion with the flexibilit y of using medium-sulfur Il linois bituminous coal. The DS/FF, on the other hand, is capable of achieving SO 2 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 SO 2 removal rates of up to 70% when firing low- sulfur PRB coals as demonstrated at the We Energies Presque Isle Power Plant. The WFGD syst em, however, has significant disadvantages compared3-6 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 with the other SO 2 removal options. The WFGD system has substantially higher capital and annual operating costs than the other SO 2 removal options. Compared with these other options, WFGD would result in significant environmental and energy impacts, incl uding increased power requirements, increased water consumption, liquid effluent requiring pretreatment , wet sludge requiring dewatering, and cooler and less buoyant plume. 3.2 NO X Emission Controls Nitrogen oxides formed during the combustion of coal are generally classified as either thermal NO xor fuelbound NO x . Thermal NO x is formed when elemental nitrogen in the combustion air is oxidized at the high temperatures in the primary combustion zone yi elding nitrogen oxide (NO) and nitrogen dioxide (NO 2 ). The rate of formation of thermal NO x is a function of residence time and free oxygen, and increases exponentially with peak flame temperatures. Thermal NO x from coal combustion can be effe ctively controlled by techniques that limit available oxygen or reduce peak flame temperatures in the primary combustion zone. Fuel-bound NO x is formed by the oxidation of chemically bound nitrogen in the fuel. The rate of formation of fuel-bound NO x is primarily a function of f uel bound nitrogen content, but is affected by fuel/air mixing. The technologies available to control NO X from coal-fired boilers include co mbustion controls, such as lowNO x burners (LNB), and post-combustion techniques, su ch as selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR). Because Units 1 a nd 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 c apable of 30 to 50 percent control. The Unit 1 and 2 boilers currently in corporate SCR for the control of NO x emissions during the ozone season. As demonstrated below, this control technology is considered the most effective in reducing NO x 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 NO x Controls The technical feasibility and performance levels of the alternative NO x control technologies are evaluated below in terms of their applica tion to Kincaid Units 1 and 2. Selective Catalytic Reduction Selective Catalytic Reduction (SCR) is a proce ss that involves post-combustion removal of NO x from flue gas utilizing a catalytic reactor. In the SCR process, ammonia injected into the flue gas reacts with NO x and oxygen to form nitrogen and water vapor. The SCR process converts NOx to nitrogen and water by the following general reactions: 4NO + 4NH 3 + O 2 → 4N 2 + 6H 2 O 2NO 2 + 4NH 3 + O 2 → 3N 2 + 6H 2 O The reactions take place on the surface of a catalyst. T he function of the catalyst is to effectively lower the activation energy of the NO x 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 subsys tems, including the SCR r eactor, ammonia injection system, and ammonia storage and delivery system. Ty pically, the SCR reactor would be located downstream of the economizer and upstream of the air pre-heater and the particulate control system. From the3-7 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 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 S CR 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 tem perature). 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 cata lyst 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 ran ge. Operation above the maximum temperature results in oxidation of ammonia to ammonia sulfate and NO x , thereby actually increasing NO x emissions. SCR with ammonia injection technology is a demonstr ated, commercially available technology. SCR has been used with other coal-fired boilers; therefore, S CR is technically feasible for the control of NO X emissions from Units 1 and 2. Performance data from Units 1 and 2 indicate that the SCR systems are capable of NO x removal efficiencies ranging from 85 to 90%. Based on these performanc e 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-combusti on 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 NO X with ammonia, where a portion of the NO X is converted to molecular nitrogen and water. Without the use of a catalyst or supplemental fuel injection, the NO X reduction reaction temperatur e must be tightly controlled between 1,600 and 2,200°F (between 1,600 and 1,800°F fo r 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 NO X emissions. SNCR with ammonia injection technology is a demonstrat ed, commercially available technology. SNCR has been used with other coal-fired boilers; therefore, SNCR is indeed technica lly feasible for the control of NO X emissions from Units 1 and 2. However, NO X removal efficiencies with SNCR are lower than SCR, typically ranging from 30 to 50% depending on the combustion process and inlet NO x 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 NO x Control Technologies The NO X 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 NO x emissions from coal-fired boilers. Further, SCR is the only technology capable of achieving the presumptive BART limit for cyclone furnaces. Accordingly, continuous operatio n of the SCR systems with a rolling 30-day emission rate of 0.10 lb/MMBtu is recomm ended as BART for Kincaid Units 1 and 2. 3.3 PM Emission Control Kincaid Units 1 and 2 currently employ high-efficiency Elec tro-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 si gnificantly below the per mitted 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 0.0153-8 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 lb/MMBtu. The DSI with Trona system ha s been shown significant reductions in PM 3 . Dominion has conservatively assumed that there wi ll 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 additiona l PM controls were consi dered 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 ant icipated performance levels, the proposed NO x and particulate control technologies are considered BART for Units 1 and 2. Therefore, the following SO 2 control scenarios are included in the modeling assessment:

• Case 1 . Firing 0.3%-sulfur PRB sub- bituminous coal, Dry So rbent Injection (DSI) with Trona capable of achieving an SO 2 emissions level of 0.20 lb/MMBtu and enhanced year-round operation of the SCR at a NO x 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 SO 2 emissions level of 0.18 lb/MMBtu (i f achievable), enhanced year-round operation of the SCR at a NO x emission level of 0.07 lb/MMBtu, and r eplacement of the exis ting 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 SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu.

• Case 3 . Firing 1.62%-sulfur Illinois Basin bitumi nous coal, Wet Flue Gas Desulfurization (WFGD) capable of achieving an SO 2 emissions level of 0.15 lb/MMBtu and year-round operation of the SCR at a NO x emission level of 0.10 lb/MMBtu. A DS/FF or WFGD system is capable of achieving a fi lterable PM emission level of 0.015 lb/MMBtu. The DSI with Trona system has shown significant reductions in PM 4 . Dominion has conservati vely 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 NO x control. The NO x controls have been demonstrated of being capable of achieving a NO x emission level of 0.10 lb/MMBtu. For the DSI with Trona options, Dominion would commit to a NO x emission rate of 0.070 lb/MMBtu. The alternative control technologi es will not only affect SO 2 and NO X emission levels from Units 1 and 2, but also will affect the emissions and speciation of PM 10 . The PM 10 emissions and speciation for modeling purposes were determined using the following approach:

• Filterable PM was subdivided by size category cons istent 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 PM 10 and 53 percent of the PM emissions are fine filterable PM 10 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 th e visibility analysis.

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM 10 based on the best estimate for electric utility coal combustion in Table 6 of “Catal og of Global Emissions Inventories and

3 PM 10 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 PM 10 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.pdf3-9 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Emission Inventory Tools for Black Carbon”, Wil liam Battye and Kathy Boyer, EPA Contract No. 68- D-98-046, January 2002.

• Condensable inorganic PM 10 emissions, assumed to consist of H 2 SO 4 , are based on “Estimating Total Sulfuric Acid Emissions from Stationary Po wer Plants," EPRI, Technical Update, March 2007. For coal-fired boilers equipped with SCR, H 2 SO 4 emissions are determined by the following relationship: E = (Q)(98.06/64.04)(F1+S2 F3)(F2) where: E is the H 2 SO 2 emission rate (lb/hr), Q is the baseline SO 2 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 SO 2 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 PM 10 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 SO 2 , NO x , 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.3-10January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-2 Kincaid Future DSI with Trona Emissions (Case 1)3-11January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-3 Kincaid Future Enhanced DSI with Trona Emissions (Case 1a)3-12January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-4 Kincaid Future DS/FF Emissions (Case 2)3-13January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-5 Kincaid Future WFGD Emissions (Case 3)3-14January 2009BART Analysis for Kincaid Power Station02285-076-400Table 3-6 Kincaid Future DSI with Trona, DS/FF and WFGD Stack ParametersCase DescriptionUTMNorthing(m)UTMEasting(m)BaseElevation(m)StackHeight(m)StackDiameter(m)Flue GasTemperature(°K)Flue GasFlow Rate(m3/s)Flue GasVelocity(m/s)1DSI, EnhancedSCR, ESP4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.26 26.211aEnhanced DSI,Enhanced SCR,FF,4,385,605.6 284,850.0 182.87 186.69 9.03 410.93 1,673.26 26.212SCR, Dry Scrubber,FF4,385,605.6 284,850.0 182.87 186.699.03 352.59 1,463.18 22.863 SCR, ESP, WFGD 4,385,605.6 284,850.0 182.87 186.699.03 324.82 1,373.33 21.464-1 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### 4.0 Meteorological Data used in Visibility Im provement Modeling

This section discusses refinements to the Lake Michig an Air Directors Consortium (LADCO) and Midwest Regional Planning Organization (MRPO) meteorologica l database that was used for the Kincaid BART modeling. 4.1 Elements of the Refined Analysis ENSR made several refinements to the CALMET me teorological database produced by LADCO/MRPO for BART CALPUFF analyses for Midwestern States. Th e 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 w ould not be considered appropriate for a more refined analysis. ENSR developed a refined meteorological database t hat included a modeling domain encompassing the two Class I areas (Mingo and Mammoth Cave), the Kincaid fa cility, and the appropriate buffers around the source and Class I areas for puffs recirculation. This domai n 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/s ettings, when appropriate, that were used to develop the LADCO/MRPO CALMET database. To improve the dat abase even further, ENSR introduced act ual surface, precipitation, and twice-daily upper air sounding observations into the refined meteorological database. These improvements in the CALMET database provide more accurate plume trajectori es 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 sugg ested 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 CALM ET 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) dom ain 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 th is 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 CALM ET (Version 5.8, Level 070623) to produce threedimensional wind fields for three years (2002-2004). Adv anced meteorological data in the form of prognostic mesoscale meteorological data, such as the Fifth Gene ration 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 us ed by LADCO/MRPO for their BART assessments. These prognostic meteorological data sets were initiall y combined with the 6-km grid resolution terrain and land use data to more accurately characterize the wi nd flow throughout the modeling domain. The gridded terrain data was derived using the U.S. Geological Surv ey (USGS) 90-meter grid spacing Digital Elevation Model (DEM) files. These files were processed in t he TERREL pre-processor program. The gridded land use data was derived from USGS 1:250,000 Com posite 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 ball oon 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 02285-076-400 Figure 4-1 Kincaid CALMET and CALPUFF Modeling Domain4-4 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 Figure 4-2 Location of Meteorological Stations used in CALMET Processing5-1 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 CALP UFF (Version 5.8, Level 070623) that has been posted at http://www.src.com/calpuff/dow nload/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 ar ound 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

O 3 (ppb) 31 31 31 37 37 37 33 33 33 27 27 27
NH 3 (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 Mont hly f(RH) at Class I Areas Two Class I areas were modeled for the Kincaid faci lity. 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 m odeling 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 databa se 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 t hat 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 annual5-2 January 2009 BART Analysis for Kincaid Power Station 02285-076-400 average background with the 98 th 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 visi bility impacts based on the source’s impacts at the 98 th percentile day modeled results. This procedure is c onsistent 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 no ted below with site-specif ic considerations, and corresponding to the annual average natural background concentrations (EPA 2003, Appendix B). To determine the input to CALPOST, it is first necessa ry 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 scatte ring. This remaining extinction is due to naturally occurring particles, and is held constant for the entire year’s simulation. Theref ore, 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 μ g/m 3 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 μ g/m 3 )* 21.58 21.02
* Extinction values include Rayleigh scattering.

5.4 Light Extinction and Ha ze Impact Calculations The CALPOST postprocessor was used for part of the calc ulation 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: b ext = 3 f(RH) [(NH 4 )2SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray The concentrations, in square brackets, are in μ g/m 3 and b ext is in units of Mm -1 . The Rayleigh scattering term (b Ray ) 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 02285-076-400 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 extinc tion 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 cont ribution to the total source-caused extinction from ammonium sulfate and nitrate is then added to the other, non-hygroscopic com ponents of the particulate concentration (from coarse and fine soil, secondary organic aerosols, and from elemental carbon) to yi eld 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 pr esents 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 alternat ive control scenarios for Units 1 and 2. 6.2 Modeling Results fo r 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 y ears 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 8 th highest delta-deciview. Figure 6-1 indicates that the higher visibility impacts occur at Mi ngo Wilderness and they are due to that park’s proximity to Kincaid. The results of the baseline emissions indicate that the 8 th 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 y ears 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 improvem ents occur with either Case 1/1a (DSI with Trona) and Case 2 (DS/FF) controls and that no percept ible visibility impacts (defined by a 98 th percentile change of at least 0.5 delta-deciview) occur at an y 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 improvem ent 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 H 2 SO 4 emissions associated with WFGD. Addition of WFGD would reduc e visibility impacts by about 0.96 de lta-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 8 th 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 Area8th 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, WFGD6-3 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 AreaAverage Delta-Deciview of 8 Highest Days Case 1: 0.3% S PR B 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, FF6-4 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 Domini on Energy. The table also presents a computation of each control case’s visibility improve ment 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 8 th highest regional haze impacts at Mingo and Mammoth Ca ve, 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 th e most cost-effective option for the visibility improvement attained. As Figure 6-3 indica tes, the incremental cost effectiveness of proceeding to Case 1a from Case 1 is steep (very li ttle 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 Case a 8 th 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 $24,820,000 b $23,100,000 Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.27 $32,210,000 c $29,210,000 Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.26 $94,700,000 d $85,060,000 Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.46 $125,370,000 e $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 Case a 8 th 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 $24,820,000 b $25,720,000 Case 1a: 0.3% S PRB Coal, enhanced DSI with Trona, Enhanced year-round SCR, FF 0.23 $32,210,000 c $32,710,000 Case 2: 0.5% S PRB Coal, year-round SCR, DS, FF 0.25 $94,700,000 d $98,200,000 Case 3: 1.62%S Illinois Coal, year-round SCR, ESP, WFGD 0.40 $125,370,000 e $152,950,0006-6 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

0.00.1 0.2 0.30.40.5 0.6 0.70.80.9 1.0 1.11.21.3 1.4 1.5 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 th e recommended BART control case is Case 1, with the use of DSI with Trona and enhanced SCR performance operat ion. 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 SO 2 emission rate lower than 0.20 lb/MMBtu to be achieved in practice with the use of DSI with Trona will be determin ed 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 (E PA), 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 (E PA), 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 Ava ilable Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 70, No. 128 published July 6, 2005) Regional Haze Regulations; Revisions to Provisions Gove rning 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 BA RT Modeling Protocol November 17, 2005, Lake Michigan Air Directors Consortium, Des Plaines, ILJanuary 2009 BART Analysis for Kincaid Power Station 02285-076-400 

### Appendix A Meteorological Stations used in CALMET ProcessingJanuary 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/MURPH YSB 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 MUNICI PAL 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 -86.68January 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 -86.57IN 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 DECREETABLE OF CONTENTS

I. JURISDICTION AND VENUE ............................................6 II. APPLICABILITY AND BINDING EFFECT ..................................7 III. OBJECTIVES ..........................................................9 IV. DEFINITIONS ..........................................................9 V. AFFIRMATIVE RELIEF ................................................1 7 A. Fluid Catalytic Cracking Units ......................................1 7 B. NOx Emissions Reductions from the FCCUs ...........................1 8 C. SO 2 Emissions Reductions from the FCCUs ............................2 8 D. Particu late Matter Emissions Reductions from the FCCUs .................3 9 E. Carbon Monoxide Emissions Reductions from the FCCUs ................4 1 F. NSPS Applicability to the FCCU Catalyst Regenerators ..................4 4 G. NOx Emissio ns Reductions from Combustion Units .....................4 9 H. SO 2 Emissions Reductions from and NSPS Applicability of Heaters, Boilers and Other Fuel Gas Combustion Devices ..............................5 6 I. Su lfur Recovery Plant Operations ....................................5 8 J. Flaring Devices ..................................................6 7 K. Control of Acid Gas Flaring and Tail Gas Incidents ......................7 1 L. Control of Hydrocarbon Flaring Incidents ..............................8 1 M. CERCLA/EPCRA Rep orting ........................................8 2 N. Ben zene Waste NESHAP Program Enhancements .......................8 3 O. Leak Detectio n and Repair Program Enhancements .....................1 00 P. Other Com p liance Program Requirem e nts Applicable to the Billings and Joliet Refineries .................................................1 14 Q. Incorporation of Consent Decree Requirem e nts into Federally Enforceable Permits ..............................................1 20 VI. EMISSION CREDIT GENERATION .....................................1 2 4 VII. MODIFICATIONS TO IMPLEMENTATION SCHEDULES ...................1 2 6 VIII. ENVIRONMENTALLY BENEFICIAL PROJECTS ..........................1 3 1 IX. R ECORDKEEPING AND REPORTING ...................................1 3 8

-i-X. CIVIL PENALTY .....................................................1 39 XI. STIPULATED PENALTIES .............................................1 4 3 XII. INTEREST ...........................................................1 6 7 XIII. RIGHT OF ENTRY ....................................................1 6 7 XIV. FORCE MAJEURE ....................................................1 6 8 XV. RETENTION OF JURISDICTION / DISPUTE RESOLUTION .................1 7 1 XVI. E FFECT OF SETTLEMENT ............................................1 7 3 XVII. GENERAL PROVISIONS ..............................................1 8 7 XVIII. TERMINATION ......................................................1 9 8 XIX. SIGNATORIES .......................................................2 0 2

-ii-TABLE OF APPENDICES Appendix A: Combustion Unit Information Appendix B: PEMS Program Requirem e nts Appendix C: NSPS Subpart J Com p liance Schedule for Certain Heaters and Boilers Appendix D: NSPS Subpart J Com p liance 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 De vices Operated by Covered Refineries Appendix G: NSPS Subpart J Com p liance Sche dule 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 Claim s Concerning the Billings Ref i nery Ref e renced in Consent Decree Subparagraph 252.b Appendix J: Table of Alleged CWA Violati ons 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 Claim s Concerning the Joliet Refinery Referenced in Consent Decree Subparagraph 252.c.(2) Appendix M: Additional Claim s 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: Sum ma ry of the Understanding Between LDEQ and the Louisiana W ildlife and Fisheries Foundation Relating to ExxonMobil’s Payment for Beneficial Environmental Projects Under Consent Decree Paragraph 159 Appendix P: Joliet W a stewater Treatm e nt 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 Treatm e nt 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
WH EREAS, defendant Exxon Mobil Corporation currently owns and operates petroleum refineries located in Baton Rouge, Louisian a; Baytown, Texas; and Billings, Montana. Defendant ExxonMobil Oil Corporation (form e rly 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.”
WH EREAS, plaintiff the United States of Amer ica (“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 requirem e nts of the Clean Air Act, and the regulations and permits promulgated thereunder at the Covered Refineries.
WH EREAS, the United States specifically alleges that ExxonMobil has violated and/or continues to violate the following st atutory and regulatory provisions: 1) Prevention of Significant Deteriorati on (“PSD”) requirem e nts 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 Requirem e nts for Non-Attainm e nt 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

1gas combustion devices and fluid catalytic cracking unit catalyst regenerators for NOx,
SO 2 , CO and PM; 2) New Source Perform a nce Standards (“NSPS”) found at 40 C.F.R. Part 60, Subparts A and J (“Refinery NSPS Regulations”), prom ulgated under Section 111 of the Act, 42 U.S.C. § 7411, for sulfur recovery plants, fu el gas combustion devices, and fluid catalytic cracking unit catalyst regenerators; 3) Leak Detection and Repair (“LDAR”) requirem e nts 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
Wa ste Operations promulgated pursuant to Section 112(e) of the Act, and found at 40 C.F.R. Part 61, Subpart FF (“Benzene W a ste NESHAP Regulations”).
WH EREAS, the United States also alleges upon information and belief that ExxonMobil has violated and/or continues to violate certain other legal requirem e nts applicable to the Covered Refineries, including requirem e nts imposed by the following statutes and the regulations promulgated thereunder: (i) the Clean W a ter Act (the “CW A ”), 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 requirem e nts found at Section 103(a) of the Com p rehensive Environmental Response, Com p ensation, and Liability Act (“CERCLA”), 42 U.S.C. § 9603(a), and Section 304 of the Emergency Planning a nd Com m unity Right-to-Know Act (“EPCRA”), 42 U.S.C. § 11004.

2WH EREAS, 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 Ref i neries are located to the extent that such plan or rules implement, adopt or incorporate the above-described Federal requirem e nts. WH EREAS, the State of Illinois (on behalf of the Illinois Environmental Protection Agency), the State of Louisiana (on behalf of the Louisiana Departm e nt of Environmental Quality), and the State of Montana (on behalf of the Montana Departm e nt of Environmental Quality) (ref e rred to herein as the “Co-Plaintif fs ”) have joined in this m a tter 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 requirem e nts. WH EREAS, with respect to the provisions of Subsection V.K (“Control of Acid Gas Flaring and Tail Gas Incidents”) of this Consent Decree, EPA m a intains 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 [ o r sour water stripper gases] be directed to an appropriate recovery facility, such as a Claus sulfur plant," see Information for Proposed New Source Perform a nce Standards: Asphalt Concrete Plants, Petroleum Refineries, Storage Vessels, Secondary Lead Smelters and Refineries, Brass or Bronze Ingot Production Pl ants, Iron and Steel Plants, Sewage Treatm e nt Plants , Vol. 1, Main Text at 28.
WH EREAS, EPA further m a intains 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 reasona bly preventable -- circumvents the purposes and intentions of the standards at 40 C.F.R. Part 60, Subpart J.

3WH EREAS, 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” m a y result in flaring of “Acid Gas” or “Sour W a ter Stripper Gas” on occasion, as those terms are defined herein, a nd that such flaring does not violate 40 C.F.R. § 60.11(d) if the owner or operator, to the extent practicable, m a intains and operates such units in a m a nner consistent with good air pollution control practice for m i nim i zing emissions during these periods.
WH EREAS, 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 requirem e nts, and m a intains that it has been and rem a ins in comp liance with all applicable statutes, regulations and permits and is not liable f o r civil penalties and injunctive relief as alleged in the Comp laint.
WH EREAS, 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 m a nner that achieves com p liance with existing statutory and regulatory standards (“Global Settlem e nt Strategy”).
WH EREAS, ExxonMobil consents to the sim u ltaneous filing of the Com p laint and lodging of this Consent Decree so as to accom p lish 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 m a nagem e nt practices set forth in this Consent Decree at the Covered Refineries to reduce air emissions through participation in the Global Settlem e nt Strategy.

4WH EREAS, even bef o re entry into the settlem e nt negotiations that resulted in this Consent Decree, ExxonMobil had taken significant steps to reduce air pollutant emissions from the Covered Refineries, including by: 1) installi ng the f i rst 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 (“W G S”) SO 2 and PM control systems on its Baton Rouge Refinery FCCUs (which com me nced operation in 1976) and Baytown Refinery FCCUs (which com me nced operation in 1974 and 1975).
WH EREAS, by entering into this Consent Decree, ExxonMobil is com m itted to m a king further reductions in air pollutant emissions from its operations.
WH EREAS, 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 com p ared to historical baseline emissions: 1) nitrogen oxide by approxim a tely 10,200 tons; and 2) su lfur dioxide by approxim a tely 40,700 tons.
WH EREAS, ExxonMobil has waived any applicable federal or state requirem e nts of statutory notice of the alleged violations.
WH EREAS, coordinated negotiations between the United States and ExxonMobil and Chalm e tte Refining, L.L.C. – addressing m u ltiple petroleum refineries owned and/or operated by those entities – resulted in two com p lem e ntary Consent Decrees, nam e ly: (i) this Consent Decree with ExxonMobil (relating to the Covered Refineries); and (ii) a separate Consent Decree with Chalm e tte Refining, L.L.C. that has been l odged with the United States District Court for the Eastern District of Louisiana (relating to a re finery in Chalm e tte, Louisiana that is owned by

5Chalm e tte Refining, L.L.C. and operated for a nd on behalf of Chalm e tte Refining, L.L.C. by ExxonMobil Oil Corporation).
WH EREAS, the Parties agree that: (i) settlem e nt of the m a tters set f o rth in the Comp laint (filed herewith) and in Section XVI (Ef f

ect of Settlem e nt) 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 m o st appropriate means of resolving this m a tter. WH EREAS, the Parties recognize, and the Court by entering the Consent Decree finds, that the Consent Decree has been negotiated at arm s -length and in good faith and that the Consent Decree is fair, reasonable, and in the public interest. NOW THEREFORE, with respect to the m a tters set f o rth in the Comp laint 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 consen t 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 m a tter 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 m a tter 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 Com p laint states a claim upon which relief m a y 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 Departm e nt of Justice by 28 U.S.C. §§ 516 and 519.

62. 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 com me ncement 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 Managem e nt 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 m emb ers 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.

76. 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 m o re requirem e nts of this Consent Decree) and shall provide a copy of the Consent Decree to a ny 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 m a ke 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 m ay f ile a m o tion to modif y the Consent Decree to ma ke 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 m o tion and the Court finds that the transferee does not have the f i nancial and technical ability to assum e 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 perform a nce of th e work contemplated under this Consent Decree is undertaken in accordance with the deadlines and requirem e nts contained in this Consent Decree

8and any attachm e nts hereto. ExxonMobil shall provide a copy of this Consent Decree (or an extract of applicable provisions of this Consen t 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 Cons ent Decree) m a y be provided by electronic means but do not need to be supplied to firms who are retained to supply m a terials or equipment to satisfy requirem e nts 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

m eaning 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 de fined, for purposes of the Consent Decree and the reports and documents submitted pursuant hereto, as f o llows: 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

m ean Tail Gas.

9b. “Acid Gas Flaring” or “AG Flaring” shall mean the combustion of Acid Gas and/or Sour W a ter Stripper Gas in an AG Flaring Device. Nothing in this definition shall be construed to modify, limit, or affect EPA’s aut hority to regulate the flaring of gases that do not fall within the definitions of Acid Gas or Sour W a ter 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 W a ter 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 Ref i nery utilizes any Flaring Devices other than those specified above for the purpose of combus ting Acid Gas and/or Sour W a ter Stripper Gas, those Flaring Devices shall be AG Flaring Devices and shall be subject to the requirem e nts 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 W a ter Stripper Gas from one or

mo re 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. Wh ere such continuous or intermittent combustion from one or m o re 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
fr om the initial com me ncement of AG Flaring within the AG Flaring Incident.

10e. “Applicable Co-Plaintif f” shall mean the f o llowing 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 W e ight % 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 m mB tu/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) th e 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 Co rporation and located at I-55 and Arsenal

11Road in Channahon, Illinois; and (6) the Torrance Refinery, owned and operated by ExxonMobil Oil Corporation and located at 3700 W e st 190 th 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/m mB TU 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/m mB TU HHV.

m. “Date of Lodging” or “Date of L odging of the Consent Decree" shall

m ean 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 m a tters under this Consent Decree relating to the Baton Rouge Refinery, the Baytown Refine ry, and/or the Billings Refinery, the term “ExxonMobil” shall mean Exxon Mobil Corporation and its successor and assigns. For m a tters 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 m a tters 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.

12q. “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 f o ss il 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 CO 2 inside the regenerator and there is O 2 (greater than 0.5% by volume as

m easured 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 W a ter 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
Wa ter Stripper Gas and/or Tail Gas. To the extent that any Covered Ref i nery 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 W a ter Stripper Gas, those Flaring

13Devices 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-gener ated gases, except for Acid Gas or Sour W a ter 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. Wh ere such continuous or intermittent flaring from a Hydrocarbon Flaring Device continues into subsequent, contiguous, non-overlapping twenty-four (24) hour pe riod(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 com me ncement of fl aring within the HC Flaring Incident. y. “IEPA” shall mean the Illinois Environmental Protection Agency and any successor departm e nt or agency of the State of Illinois. z. “LDEQ” shall mean the Louisiana Departm e nt of Environmental Quality and any successor departm e nts or agencies of the State of Louisiana. aa. “Low NOx Combustion Promoter” shall mean a catalyst that is added to a FCCU that m i nim i zes NOx emissions while m a intaining its ef f

ectiveness as a combustion promoter. ab. “ Malfunction,” as specified by 40 C.F.R. § 60.2, shall mean: “[A]ny sudden, infrequent, and not reasonably preventabl e failure of air pollution control equipment, process equipment, or a process to operate in a norm a l or usual m a nner. Failures that are caused in part by poor m a intenance or careless operation are not m a lfunctions.”

14ac. “MDEQ” shall mean the Montana Departm e nt of Environmental Quality and any successor departm e nt 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/ m mB TU 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/m mB TU 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 m a tter. 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.

15an. “ Sour W a ter Stripper Gas” or “SW S Gas” shall mean the gas produced by the process of stripping or scrubbing refinery sour water.

ao. “ SO 2 Reducing Catalyst Additive” shall mean a catalyst additive that is introduced to an FCCU to reduce SO 2 emissions by reduction and adsorption.
ap. “ SO 2 ” 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 cat alytic reaction of sulfur dioxide and hydrogen sulfide. For the purposes of this Consent Decr ee, the SRPs at the ref i neries 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) B eaumont SRP : The SRP at the Beaumont Refinery (the “Beaumont SRP”) consists of three Claus trains: Claus 1, Claus 2, Claus 3. (3) J oliet SRP : The SRP at the Joliet ref i nery (the “Joliet SRP”) consists of three Claus trains: North Train, East Train, and W e st Train. (4) T orrance 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 co mpounds 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 m o re of SO 2 emissions in any 24 hour period ; or (2) combusted in a therm a l incinerator and results in excess emissions of 500 pounds or mo re of SO 2 in any 24-hour period. Only those time periods which are in

16excess of a SO 2 concentration of 250 ppm (rolling 12-hour average) shall be used to determine the amount of excess SO 2 emissions from the incinerator. ExxonMobil shall use engineering judgment and/or other monitoring data to estimate emissions during periods in which the SO 2 continuous emission analyzer has exceeded the range of the instrum e nt 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 Novem b er 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 W e t Gas Scrubber (“W G S”) that com me nced operation in 1976 serves as an SO 2 and PM control device for the Baton Rouge FCCUs.

17b. Baytown FCCU 2 and Baytown FCCU 3 : The Baytown Refinery has two FCCUs, designated FCCU 2 and FCCU 3. A W G S that com me nced operation in 1974 serves as
an SO 2 and PM control device for FCCU 2, and a W G S that com me nced operation in 1975
serves as an SO 2 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 W G S that

com me nced operation in 2004 serves as an SO 2 and PM control device for the FCCU. The Beaumont FCCU also has third-stage cyclones. d. Billings FCCU : The Billings Ref i nery 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 NO x control device for the FCCU. An electrostatic precipitator that com me nced 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 NO x 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 NO x emission limits established by this Subsection. ExxonMobil will

m onitor com p liance with the emission limits through the use of CEMS, as specified by this Subsection V.B.

1813. 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 Therm a l 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% O 2 on a 365-day rolling average basis) and 100 ppmvd NOx or less (at 0% O 2 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) T he 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% O 2 on a 365-day rolling average basis); and (ii) as close to 50 ppmvd as practicable. ExxonMobil shall com p ly with the long-term Final NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 15.c. (2) T he 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% O 2 on a 7-day rolling average basis); and (ii) as close to 100 ppmvd as practicable. ExxonMobil shall com p ly with the short-term Final NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 15.c.

1914. 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 Therm a l 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% O 2 on a 365-day rolling average basis) and 100 ppmvd NOx or less (at 0% O 2 on a 7-day rolling average basis); provided , however , that ExxonMobil shall not be required to design the control system in a m a nner 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) T he 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% O 2 on a 365-day rolling average basis); and (ii) as close to 50 ppmvd as practicable. ExxonMobil shall com p ly with the long-term Final NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 15.c. (2) T he 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% O 2 on a 7-day rolling average basis); and (ii) as close to 100 ppmvd as practicable. ExxonMobil shall com p ly with the short-term Final

20NOx Limit upon submission of the Study report referenced in Subparagraphs 15.b. and 15.c.
15. Baton Rouge and Beaumont NOx Minimiz a tion Studies . ExxonMobil shall

com p lete 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 Minim i zation Study”); and (ii) the Beaumont FCCU NOx control system, by no later than July 1, 2009 (the “Beaumont NOx
Minim i zation 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% O 2 on a 365-day rolling average basis) and 100 ppmvd NOx (at 0% O 2 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 m a nner that creates a safety problem or impairs unit feed rate, conversion, feed slate or yield selectivity, unless reasonable steps can be taken to

com p ensate for such impairm e nt. b. W ithin 90 days after the com p letion of each Study, ExxonMobil shall submit a written report to EPA that shall sum ma rize 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

m easured 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

21practicable to 50 ppmvd NOx (at 0% O 2 on a 365-day rolling average basis) and 100 ppmvd NOx (at 0% O 2 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% O 2 on a 365-day rolling average basis) or 100 ppmvd NOx (at 0% O 2 on a 7-day rolling average basis), then the relevant Study report shall include a plan for m a king 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, m a de, and incorporated into federally-enforceable permits in a m a nner 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 m a king the supplemental NOx reductions, and for submitting a com p letion report

22documenting 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 System s . (1) E xxonMobil 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 m a y include, but are not limited to, use of a Therm a l DeNOx system and/or use of NOx-reducing catalyst additive and/or low NOx combustion promoter). (2) E xxonMobil 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) B y no later than December 31, 2006, ExxonMobil shall specify and com p ly 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% O 2 Short-term limit: 95 ppmvd NOx on a 7-day rolling average basis at 0% O 2 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% O 2
23Short-term limit: 105 ppmvd NOx on a 7-day rolling average basis at 0% O 2 (2) I n the Sem i -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) B y no later than June 30, 2010, ExxonMobil shall specify and

com p ly 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% O 2 Short-term limit: 70 ppmvd NOx on a 7-day rolling average basis at 0% O 2 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% O 2 Short-term limit: 90 ppmvd NOx on a 7-day rolling average basis at 0% O 2 (2) I n the Sem i -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 m a y include, but are not limited to, use of a Therm a l 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 Decem b er 31, 2008, ExxonMobil shall com p ly with NOx emission limits of 40 ppmvd at 0% O 2 on a 365-day rolling average basis and 80 ppmvd at 0% O 2 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 com p liance 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 natura l gas curtailment, ExxonMobil shall com p ly with an alternate short-term NOx emission limit of 120 ppmvd at 0% O 2 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 Decem b er 31, 2012, ExxonMobil shall com p ly with NOx emission limits of 20 ppmvd at 0% O 2 on a 365-day rolling average basis and 40 ppmvd at 0% O 2 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.

25b. Final NOx Limits

. By no later than the Entry Date, ExxonMobil shall

com p ly with NOx emission limits of 20 ppmvd at 0% O 2 on a 365-day rolling average basis and 40 ppmvd at 0% O 2 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 f r om the Torrance FCCU will not be used in determining com p liance 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 com p ly 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 m a in stack during the particular period. In the first Sem i -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, Shutdow n , and Malfunction

. NOx emissions (i) caused by or attributable to the startup, shutdown, or Malfunc tion of an FCCU listed in Subsection V.A and/or (ii) during periods of Malfunction of the releva nt FCCU’s NOx Control System will not be used in determining com p liance 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

26to m i nim i ze 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 sh all 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 m a in 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 O 2 CEMS at each of the FCCUs at the refineries listed in Subsection V.A to monitor perform a nce and to report com p liance 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 m a y be monitored in accordance with an alternative monitoring plan approved by EPA. ExxonMobil shall m a ke 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 perform a nce 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 requirem e nts of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil m ay 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

27quarter in which a RAA or RATA is not perform e d. The Parties agree that the CEMS m a y need to be moved and reinstalled because of the installation of control equipment, and that once

m oved it will need to be re-calibrated and re-certified. C. SO 2 EMISSIONS REDUCTIONS FROM THE FCCUs

. 22. General . ExxonMobil shall implement a program to reduce SO 2 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 SO 2 emission limits established by this Subsection. ExxonMobil will

m onitor com p liance with the emission limits through the use of CEMS, as specified by this Subsection V.C.
23. SO 2 Emissions Control for Baytown FCCU 2 .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from Baytown FCCU 2 by upgrading and operating its existing W G S. b. Final SO 2 Limits

. By no later than December 31, 2009, ExxonMobil shall

com p ly with SO 2 emission limits of 25 ppmvd at 0% O 2 on a 365-day rolling average basis and 50 ppmvd at 0% O 2 on a 7-day rolling average basis at Baytown FCCU 2.
24. SO 2 Emissions Control for Baytown FCCU 3 .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from Baytown FCCU 3 by operating its existing W G S. b. Final SO 2 Limits

. By no later than the Entry Date, ExxonMobil shall

com p ly with SO 2 emission limits of 25 ppmvd at 0% O 2 on a 365-day rolling average basis and 50 ppmvd at 0% O 2 on a 7-day rolling average basis at Baytown FCCU 3.

2825. SO 2 Emissions Control for the Baton Rouge FCCUs .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from the Baton Rouge FCCUs by: (i) operating its existing W G S; and (ii) taking other steps to reduce SO 2 (which m a y include, but are not limited to, use of SO 2 Reducing Catalyst Additive) during planned routine m a intenance on the Baton Rouge W G S. b. Final SO 2 Limits

. By no later than the January 1, 2006, ExxonMobil shall

com p ly with SO 2 emission limits of 35 ppmvd at 0% O 2 on a 365-day rolling average basis and 70 ppmvd at 0% O 2 on a 7-day rolling average basis at the Baton Rouge FCCUs.
26. SO 2 Emissions Control for the Beaumont FCCU .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from the Beaumont FCCU by operating its existing W G S. b. Final SO 2 Limits

. By no later than the Entry Date, ExxonMobil shall

com p ly with SO 2 emission limits of 25 ppmvd at 0% O 2 on a 365-day rolling average basis and 50 ppmvd at 0% O 2 on a 7-day rolling average basis at the Beaumont FCCU.
27. SO 2 Emissions Control for the Joliet FCCU .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from the Joliet FCCU by installing and operating a W G S. b. Final SO 2 Limits

. By no later than December 31, 2008, ExxonMobil shall

com p ly with SO 2 emission limits of 25 ppmvd at 0% O 2 on a 365-day rolling average basis and 50 ppmvd at 0% O 2 on a 7-day rolling average basis at the Joliet FCCU.
28. SO 2 Emissions Control for the Torrance FCCU .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from the Torrance FCCU by using low sulfur feed in the FCCU.

29b. Final SO 2 Limits

. By no later than the Entry Date, ExxonMobil shall

com p ly with SO 2 emission limits of 25 ppmvd at 0% O 2 on a 365-day rolling average basis and 50 ppmvd at 0% O 2 on a 7-day rolling average basis at the Torrance FCCU. 29. SO 2 Emissions Control for the Billings FCCU .

a. SO 2 Control System

. ExxonMobil presently intends to control SO 2 emissions from the Billings FCCU by: (i) converting the FCCU to Full Burn Operation; and (ii) implementing a special two-step protocol using SO 2 Reducing Catalyst Additives, as

sum ma rized below. (1) S tep 1. Step 1 of the protocol will com me nce shortly after the Entry Date. Step 1 will require a perform a nce of a short-term trial to identify the

com me rcially-available catalyst additive that achieves the greatest SO 2 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) S tep 2. Step 2 of the protocol will com me nce several years after the Entry Date. Step 2 will require a perform a nce of another short-term trial to identif y the f u ture-generation com me rcially-available catalyst additive that achieves the greatest
SO 2 reduction at the Required Addition Rate. Once the best-perf o rming additive is identified, ExxonMobil shall use that additive at the Required Addition Rate during a defined demonstration period. (3) R equired Addition Rate

. For the purpose of this Paragraph 29 and Paragraph 30, the term “Required Addition Rate” shall mean addition of 20.0 Average
We ight % of Total Catalyst Added, unless EPA agrees to a lesser weight % addition rate

30for a particular SO 2 Reducing Catalyst Additive based on a demonstration by ExxonMobil that a lesser addition rate achieves an equal or greater total reduction in SO 2 emissions f r om the Billings FCCU. The Average W e ight % of Total Catalyst Added shall be calculated based on the Total Catalyst Addition Rate during the two year baseline period from Novem b er 2001 to October 2003. As required by this Paragraph 29 and Paragraph 30, ExxonMobil shall add SO 2 Reducing Catalyst Additive at the Required Addition Rate in a m a nner that m i nim i zes SO 2 emissions; provided , however , that ExxonMobil shall not be required to use the Additive in a m a nner 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 com p ensate for such impairm e nt. b. Final SO 2 Limits

. The final long-term and short-term SO 2 limits f o r the Billings FCCU shall be established by one of two m e thods, designated as “Option A” and “Option B” below. (1) O ption A. Under Option A, the final long-term and short-term SO 2 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 SO 2 Reducing Catalyst Additive protocol. ExxonMobil shall com p ly with any long-term and short-term Final
SO 2 Limits set under Subparagraph 30.i according to the schedule prescribed by Subparagraph 30.i. (2) O ption B. Under Option B, ExxonMobil m a y, at any time up to and including its proposing emission limits under Subparagraph 30.h, accept and agree to

com p ly im me diately with concentration-based SO 2 emission limits of 25 ppmvd on a

31365-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 rem a ining 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 SO 2 Reducing Catalyst Additive Program

. Unless and until ExxonMobil selects Option B under Subparagraph 29.b.(2), ExxonMobil shall implement an SO 2 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 SO 2 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. SO 2 Baseline Data f o r 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 SO 2 Reducing Catalyst Additives. The Baseline Data Report shall include all relevant
SO 2 and O 2 CEMS data and all other data set forth in Appendix H.

c. Identification and Selection of SO 2 Reducing Catalyst Additives f o r Trial Use and Trial Procedures

. By the following dates, ExxonMobil shall select and submit for EPA approval a written plan f o r use of at least three com me rcially available SO 2 Reducing Catalyst Additives that ExxonMobil proposes to use for short-term trials at the Billings FCCU.

32No later than 255 Days after the Entry Date for the Step 1 trials of currentgeneration SO 2 Reducing Catalyst Additives No later than January 15, 2010 for the Step 2 trials of futuregeneration SO 2 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 m e thod 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 SO 2 Reducing Catalyst Additives that are likely to perform the best at reducing SO 2 emissions in the FCCU. EPA will base its approval or disapproval of the SO 2 Reducing Catalyst Additives on its assessment of the perform a nce of the proposed A dditives in other FCCUs and the similarity of those FCCUs to ExxonMobil’s Billings FCCU, with the objective of testing SO 2 Reducing Catalyst Additives likely to have the best perform a nce in reducing SO 2 emissions. If EPA objects to one or m o re of the proposed SO 2 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 SO 2 Reducing Catalyst Additives by ExxonMobil. d. Perform a nce 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 com me nce and com p lete the short-term trials in accordance with the following schedule:

33For the Step 1 trials of current-generation SO 2 Reducing Catalyst Additives: Com me ncement Date No later than 300 days after the Entry Date Com p letion Date No later than 480 days after the Entry Date For the Step 2 trials of fu ture-generation SO 2 Reducing Catalyst Additives: Com me ncement Date No later than March 1, 2010 Com p letion 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 perform a nce of each SO 2 Reducing Catalyst Additive that was tested in the short-term trials. (1) I n each Trials Report, ExxonMobil shall sum ma rize the results of the trials and shall provide all relevant SO 2 and O 2 CEMS data and all other data set forth in Appendix H. Each Trials Report shall also sum ma rize any safety problems or impairm e nts of unit feed rate, conversion, feed slate, or yield selectivity observed in the trials, and all steps that were taken to attem p t to eliminate the problems or com p ensate for such impairm e nts. (2) I n each Trials Report, ExxonMobil shall identify the Additive that achieved the lowest SO 2 concentration, corrected to 0% O 2 , when averaged over the entire trial period and the additive that reduced emissions the m o st f r om a predicted uncontrolled baseline during the trials (the “Best-Perform i ng Additive”). If EPA determines that another Additive tested in the trials was the Best-Perf o rming Additive in the trials, then EPA, after consultation with the Applicable Co-Plaintif f, will so notif y 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) E xxonMobil shall submit the Trials Reports in accordance with the following schedule: For the Step 1 trials of current-generation SO 2 Reducing Catalyst Additives: Report Due Date No later than 540 days after the Entry Date For the Step 2 trials of fu ture-generation SO 2 Reducing Catalyst Additives: Report Due Date No later than Decem b er 1, 2010 f. Step 1 Interim Reduction Period

. By no later than 585 days after the Entry Date, ExxonMobil shall com me nce 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 m a nner that creates a saf e ty problem or impairs unit feed rate, conversion, feed slate, or yield se lectivity, unless reasonable steps can be taken to eliminate the problem or com p ensate for such impairm e nt. ExxonMobil shall continue using the Best-Perf o rming Additive at the Required Addition Rate until com me ncement of the Step 2 trials under Subparagraph 30.d.
g. Step 2 Demonstration

. ExxonMobil shall com me nce and com p lete a demonstration of the Best-Performing Additive for Step 2 in accordance with the following schedule:
Com me ncement Date No later than January 15, 2011
Com p letion 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 m a nner that
mi nim i zes SO2 emissions; provided , however , that ExxonMobil shall not be required to operate the FCCU or use the Additive in a m a nner that creates a saf e ty problem or impairs unit f e ed rate, conversion, feed slate, or yield selectivity, unless reasonable steps can be taken to eliminate the

35problem or com p ensate for such impairm e nt. Even after com p letion of the demonstration, ExxonMobil shall continue using the Best-Performing Additive at the Required Addition Rate until ExxonMobil begins com p lying with proposed and final SO 2 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 sum ma rize the results of the demonstration and shall provide all relevant SO 2 and O 2 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) SO 2 emission limits, both as measured at 0% O 2 , for the Billings FCCU. ExxonMobil shall com p ly with the emission limits it proposes for the Billings FCCU beginning im me diately upon submission of the Step 2 Demonstration Report. ExxonMobil shall continue to com p ly with these limits unless and until ExxonMobil is required to com p ly with the emissions limits set by EPA pursuant to Subparagraph 30.i. i. Establishment of Final Limits f o r 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 SO 2 emissions from the Billings FCCU. EPA will establish 365-day rolling average and 7-day rolling average concentration-based (ppmvd) SO 2 emission limits, corrected to 0% oxygen, which limits can be

me t with a reasonable certainty of com p liance. Such limits m a y be the sam e as the limits proposed by ExxonMobil in accordance with Subparagraph 30.h. ExxonMobil m a y propose, and
EPA m a y establish, alternative emissions limits to be applicable during alternative operating

36scenarios. EPA will determine the limits based on: (i) the level of perform a nce during the Step 2 Demonstration Period; (ii) a reasonable certainty of com p liance; and (iii) any other available and relevant information. EPA will notify ExxonMob il of its determination of the long-term and short-term concentration-based SO 2 emissions limits. ExxonMobil shall im me diately (or within thirty (30) days, if EPA’s limit is m o re stringent than the limit proposed by ExxonMobil) operate the FCCU so as to com p ly 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 m a nner and amount applicable during the Step 2 Demonstration Period (in lieu of meeting the EPA-established limits).
31. Startup, Shutdow n , and Malfunction

. SO 2 emissions (i) caused by or attributable to the startup or shutdown of an FCCU that is not controlled by a W G S and/or (ii) during periods of Malfunction of the FCCU or Malfunction of the relevant FCCU’s W G S or SO 2 Reducing Catalyst Additive system will not be used in determining com p liance with the short-term (7-day) SO 2 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 m i nim i ze SO 2 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

37Alternative Monitoring Plan approved by EPA if it is necessary to bypass the FCCU’s m a in stack during the particular period of startup, shutdown, or Malfunction.
32. Demonstrating Compliance with FCCU SO 2 Emission Limits for the FCCUs . By no later than the dates set out in Appendix N, ExxonMobil shall use SO 2 and O 2 CEMS at each of the FCCUs at the refineries listed in Subsection V.A to monitor perform a nce and to report com p liance with the terms and conditions of this Subsection V.C relating to SO 2 emissions from the FCCUs. As permitted by Paragraph 31, emissions during certain periods

ma y be monitored in accordance with an Alternative Monitoring Plan approved by EPA. ExxonMobil shall m a ke 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 com p liance 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 requirem e nts of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil m ay 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 perform e d. The Parties agree that the CEMS m a y need to be moved and reinstalled because of the installation of control equipment, and that once

m oved it will need to be re-calibrated and re-certified.

38D. 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

m onitor com p liance with the emission limits as specif i ed 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 com p ly 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 D ecember 31, 2009 Baytown FCCU 3 C onsent 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

com me nce operation of new third-stage cyclones on the Billings FCCU; and, thereafter (ii) com p lete a perform a nce test to assess PM emissions from the Billings FCCU under “turn down” conditions based on the average of three runs in a test perform e d in accordance with Method 5B or 5F. If PM emissions during that perform a nce test are less than 1.0 pound of PM per 1000 pounds of coke burned, then the Billings FCCU shall com p ly 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 perform a nce test are greater than or equal to 1.0 pound of PM per 1000 pounds of coke burned, then ExxonMobil

39shall take additional steps to reduce PM emissions f r om the Billings FCCU and shall com p ly 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 sum ma rizes the results of the perform a nce test and either: (i) indicates that ExxonMobil will com p ly with the emission limit by December 31, 2006 under this Paragraph; or (ii) indicates that ExxonMobil will com p ly with the emission limit by December 31, 2008 and

sum ma rizes the additional steps that ExxonMobil intends to take to com p ly with the emission limit under this Paragraph.
35. NSR Emission Limits for PM

. At any time during the term of the Consent Decree, ExxonMobil m a y 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 perform e d 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, Shutdow n , and Malfunction

. PM emissions (i) caused by or attributable to the startup or shutdown of an FCCU that is not controlled by a W G S and/or (ii) during periods of Malfunction of the FCCU or Malfunction of the relevant FCCU’s W G S, third-stage cyclones or electrostatic precipitator will not be used in determining com p liance with any PM emission limits established by Paragraphs 34 and 35, provided that during such periods ExxonMobil implements good air pollution control practices to m i nim i ze PM emissions. Nothing in this Paragraph shall be construed to relieve ExxonMobil of any obligation under any

40federal, state, or local law, regulation, or pe rmit 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 becom e s 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
Sem i -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 m a y 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 EMISSION S 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 com p liance with the emission limits with CEMS, as specified by this Subsection V.E.

4139. Emission Limits for CO . Consistent with the NSPS regulations at 40 C.F.R., Part 60, Subpart J, ExxonMobil shall com p ly with an emission limit of 500 ppmvd CO corrected to 0% O 2 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 C onsent Decree Entry Date Baytown FCCU 3 C onsent 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 m a y accept the following Final CO Limits for a FCCU: Long-term limit: 150 ppmvd CO on a 365-day rolling average basis at 0% O 2 Short-term limit: 250 ppmvd CO on a 24-hour rolling average basis at 0% O 2 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, Shutdow n , and Malfunction . CO emissions (i) caused by or attributable to the startup, shutdown, or Malfunc tion 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 comp liance 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 m i nim i ze 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 em issions during periods of startup, shutdown, or

42Malfunction, or to document the occurrence and/or cause of a startup, shutdown, or Malfunction event. Emissions during any such period of st artup, 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 m a in stack during the particular period of startup, shutdown, or Malfunction.
42. Demonstrating Compliance w i th CO Emissions Limits . By no later than the dates set out in Appendix N, ExxonMobil shall use CO and O 2 CEMS at each of the FCCUs at the refineries listed in Paragraph 39 to monitor emissions and to report com p liance 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 m a y be monitored in accordance with an Alternative Monitoring Plan approved by EPA. ExxonMobil shall m a ke emissions

m onitoring data available to EPA as soon as practicable following an EPA request for such data. For the Baton Rouge FCCUs, the Baytown FCCU s, the Beaumont FCCU, the Billings FCCU, and the Torrance FCCU, unless com p liance 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 requirem e nts of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3, and 5.1.4, ExxonMobil m a y conduct: (1) either a Relative Accuracy Audit (“RAA”) or a Relativ e 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 perform e d. The Parties agree that the CEMS m a y need to be moved and reinstalledbecause of the installation of control equipment, and that once moved it will need to be recalibrated and re-certified.

43F. NSPS APPLICABILITY TO THE FCCU CATALYST REGENERATORS

. 43. NSPS Applicability and Compliance . Each of the FCCU catalyst regenerators
fo r the FCCUs at the ref i neries listed in Subsection V.A shall be an “af f

ected 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 requirem e nts of NSPS Subparts A and J, by the dates set forth below.

a. Sulfur Oxides

. ExxonMobil shall com p ly with the requirem e nts of NSPS Subparts A and J for the following FCCU catalyst regenerators for SO 2 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 SO 2 January 1, 2006 January 1, 2006 D ecember 31, 2006 C onsent Decree Entry Date Consent Decree Entry Date December 31, 2008 Consent Decree Entry Date b. Particulate Matter

. (1) E xxonMobil shall com p ly with the requirem e nts 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 D ecember 31, 2009 C onsent Decree Entry Date Consent Decree Entry Date Consent Decree Entry Date Consent Decree Entry Date (2) E xxonMobil shall com p ly with the requirem e nts of NSPS Subparts A and J f o r the Billings FCCU catalyst regenerator f o r PM: (i) by no later than December 31, 2006, if the results of perform a nce tests conducted pursuant to Subparagraph 34.b are such that com p liance with an emission limit of 1.0 pounds PM per

441000 pounds of coke burned is required by that date; or (ii) by no later than December 31, 2008, if the results of perform a nce tests conducted pursuant to Subparagraph 34.b are such that com p liance 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 com p ly with the requirem e nts 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 C onsent Decree Entry Date C onsent 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 com p ly with the requirem e nts 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 S ubmit AMP six months after Entry Date S ubmit AMP six months after Entry Date AMP pending December 31, 2006 Consent Decree Entry Date Consent Decree Entry Date Wh ere this Subparagraph specifies an alternative monitoring plan (“AMP”) submittal date (rather than a final NSPS Subpart A and J com p liance date), ExxonMobil shall submit to EPA a timely and com p lete AMP application by the date(s) specified. Wh ere 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

45com p lying with the monitoring requirem e nts of NSPS Subparts A and J for the particular equipment within ninety (90) days of receiving notice of the disapproval. The equipment will becom e an affected facility when ExxonMobil receives EPA’s approval of the relevant AMP. A plan for com p lying with the monitoring requirem e nts of NSPS Subparts A and J m a y 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 comp lies with the applicable emissions limitations imposed by NSPS Subpart J, as specified by the preceding Subpa ragraphs, 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, m a intain and operate each FCCU catalyst regenerator and any associated air pollution control equipment in a

ma nner consistent with good air pollution control practice for m i nim i zing emissions. f. For FCCU catalyst regenerators that becom e affected facilities under NSPS Subparts A and J pursuant to this Paragraph 43. Entry of this Consent Decree and

comp liance with the relevant monitoring requirem e nts of this Consent Decree for FCCUs shall satisfy the notice requirem e nts of 40 C.F.R. 60.7(a) and the initial perform a nce test requirem e nts of 40 C.F.R. § 60.8(a).
44. Particular Requirements Applicable to the Baton Rouge FCCUs .

a. Com p liance with NSPS SO 2 Emission Limitations

. By no later than January 1, 2006, ExxonMobil shall ensure that the Baton Rouge FCCUs’ catalyst regenerators

com p ly with the applicable NSPS SO 2 emission limitations at all times, except during periods of startup, shutdown or Malfunction as define d by 40 C.F.R. § 60.2. Specifically, ExxonMobil

46shall: (i) com p ly with the emission limitation established by 40 C.F.R. 60.104(b)(1), except during any period of planned routine m a intenance on the Baton Rouge W G S approved in accordance with 40 C.F.R. 63.1575(j); and (ii) com p ly 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

ma intenance on the Baton Rouge W G S approved in accordance with 40 C.F.R. 63.1575(j).
Com p liance with the provisions of this Subpara graph 44.a shall constitute com p liance with the emission limitations requirem e nts of 40 C.F.R. § 60.104(b). b. MACT Standard Com p liance

. ExxonMobil shall ensure that each of the Baton Rouge FCCUs com p lies with all applicable requirem e nts of the Maxim um 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”) in cluding, but not limited to: (i) the emission limitations imposed by 40 C.F.R. §§ 63.1564(a) and 63.1565(a); (ii) the requirem e nt to prepare and operate at all times in com p liance with an operation, m a intenance, and monitoring plan (an “OMM Plan”), as defined in 40 C.F.R. § 63.1574(f), and a startup, shutdown, and

ma lfunction 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 m a intenance on the Baton Rouge W G S.

c. OMM Plan Requirem e nts

. The OMM Plan(s) for the Baton Rouge FCCUs shall include a schedule and procedures for planned routine m a intenance on the Baton Rouge W G S. The schedule and procedures shall be consistent with good air pollution control practices for m i nim i zing emissions to the extent practicable, and shall incorporate the requirem e nts specified by the following Subparagraphs. (1) T he OMM Plan(s) shall establish schedules and procedures for
mi nim i zing criteria pollutant and hazardous air pollutant emissions associated with

47planned routine m a intenance on the Baton Rouge W G S, to the extent practicable. The OMM Plan shall specifically require that ExxonMobil: (i) m i nim i ze the duration of each planned routine m a intenance period; (ii) m a xim i ze W G S run length between planned routine m a intenance periods; (iii) coordinate planned routine m a intenance on the W GS 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

ma intenance period under the requirem e nts imposed by 40 C.F.R. § 63.1575(j). (2) T he OMM Plan requirem e nts specified by Subparagraph 44.c.(1) shall apply only to planned routine m a intenance on the Baton Rouge W G S, and shall not apply to any unplanned shutdown or m a lfunction. 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 m a lfunction, including ExxonMobil’s duty to operate and m a intain the affected source (including associated air pollution control equipment and monitoring equipment) in a m a nner consistent with good air pollution control practices for m i nim i zing emissions to the extent practicable. d. Emissions of NOx and SO 2 from the Baton Rouge FCCUs during periods of planned routine m a intenance on the Baton Rouge W G S shall not be used in determining

com p liance with the short-term NOx and SO 2 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 m a nner consistent with good air pollution control practices during such periods. Emissions during such periods of planned routine m a intenance on the Baton Rouge W G S 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.

48G. 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 m e et the requirem e nts of Paragraphs 47 and 51. ExxonMobil will monitor com p liance with the emission limits through the use of CEMS, a predictive emissions monitoring system (“PEMS”), or stack tests as described in m o re detail below.
46. Identification of Qualifying Controls . ExxonMobil shall select one or any

com b ination of the following “Qualifying Controls” to satisfy the requirem e nts 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 m mB TU heat input or lower; or iv. p erm a nent 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 requirem e nts of Paragraphs 47, 50, and 51, those reductions m a y not be used as reductions for the construction of new units or the modif i cation 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:

49n 

# ∑ [ ( E actual 

## ) i 

## − 

## ( E a llowabl e 

## ) i 

# ] ≥ 4750 ton s pe r year i = 1

Wh ere: (E allow a ble ) i = [ (The permitted allowable pounds of NOx per million BTU for Combustion Unit i)/(2000 pounds per ton)] x [(the lower of permitted or m a xim um heat input rate capacity in m illion BTU per hour for Combustion Unit i) x (the lower of 8760 or permitted hours per year)]; (E Act u al ) i = T he 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 = T he number of Combustion Units with Qualifying Controls from those listed in Appendix A that are selected by ExxonMobil to satisfy the requirem e nts of the equation set forth in this Paragraph 47. Permit limits established to implement this Paragraph m a y use a 365-day rolling average for Combustion Units that use a CEMS or PEMS to monitor com p liance, and for Combustion Units that do not use a CEMS or PEMS, the permit limits averaging period m u st be no longer than the averaging period of the reference test m e thod. 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. B eaumont Refinery Boiler 33 and Boiler 34 (at Power Plant 3).

50ExxonMobil m a y use the com b ined 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/m mB TU). The emission limit and com b ined permitted heat input capacity for the set m a y 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 m a xim um physical heat input capacity or, if less, the allowable heat input capacity in m mB tu/hr (HHV); ii. the baseline emission rate for the agreed-upon baseline years in pounds of NOx per m mB tu 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. t he utilization rate in annual average m mB tu/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 com me nt 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 f i rst report submitted pursuant to Section IX (Recordkeeping and Reporting) f o llowing the passage of each calendar year until termina tion 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 m mB tu/hr that ExxonMobil plans to use to satisfy the requirem e nts of Paragraphs 47, 50, and 51:

51i. 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/m mB tu (HHV)), with averaging period) and allowable heat input rate (in m mB tu/hr (HHV)) obtained or planned with dates obtained or planned; iv. T he results of emissions tests and annual average CEMS data (reported in ppmvd corrected to 3% O 2 , and in lbs/m mB tu) 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 requirem e nts or other operating restrictions. ExxonMobil m a y 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 Sem i -Annual Report to be submitted under Section IX after December 31, 2008, ExxonMobil shall include a report showing how it satisfied the requirem e nt 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 Sem i -Annual Report to be

52submitted under Section IX after December 31, 2009, ExxonMobil shall include a report showing how it satisfied the requirem e nt of this Paragraph. c. Consistent with Paragraph 47, ExxonMobil shall install the rem a inder 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 m a xim u m heat input capacity of all Combustion Units greater than 40 m mB tu/hr (at HHV) located at each of the Covered Refineries. Any Qualifying Controls m a y be used to satisfy this requirem e nt, 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/m mB TU) for Combustion Units required under Paragraph 47, to ensure that the NOx emission reduction requirem e nts 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 com me ncing operation of a Combustion Unit that will be used to satisf y the requirem e nts of Paragraph 47, ExxonMobil shall monitor such Combustion Unit as follows: i. For each Combustion Unit with a m a xim u m physical capacity greater than 150 mmB tu/hr (HHV), install or continue to operate a NOx and O 2 CEMS. ii. For each Combustion Unit with a m a xim u m physical capacity greater than 100 mmB tu/hr (HHV) but less than or equal to 150 m mB tu/hr (HHV), install or continue to operate a NOx and O 2 CEMS, or monitor NOx emissions with a PEMS developed and operated pursuant to the requirem e nts of Appendix B of this Consent Decree. iii. For each Combustion Unit with a m a xim u m physical capacity of less than or equal to 100 m mB tu/hr (HHV), (a) conduct an initial perform a nce test and any

53periodic tests that m a y be required by EPA or by an Applicable Co-Plaintiff under other applicable regulatory authority; or (b) com p ly with the monitoring requirem e nts described in Subparagraphs 53.i. or 53.ii above. The results of the initial perform a nce testing shall be reported to the EPA and the Applicable Co-Plaintif f within 90 days of com p leting the test. ExxonMobil shall use Method 7E to conduct initial perform a nce testing required by Subparagraph 53.iii. Monitoring with a PEMS that is required by this Paragraph shall be conducted in accordance with the requirem e nts of Appendix B. By no later than 90 days after the Entry Date, ExxonMobil shall submit to EPA for review and com me nt 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 requirem e nts (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 m a xim u m physical capacity of less than or equal to 100 m mB tu/hr (HHV), an additional perform a nce test is not required under this Paragraph if an initial perform a nce test using Method 7E was perform e d 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, m a intain, and operate the CEMS required by Paragraph 53 in accordance with 40 C.F.R. Part 60, Appendices A and F, and the applicable perform a nce specification test of 40 C.F.R. Part 60, Appendix B. For the Baton Rouge Refinery, the Baytown Refinery, the Beaumont Refinery, and the Torra nce Refinery, unless Appendix F is otherwise required by the NSPS, state law or regulation, or a permit or approval, in lieu of the requirem e nts of 40 C.F.R. Part 60, Appendix F §§ 5.1.1, 5.1.3 and 5.1.4, ExxonMobil m a y conduct either a Relative Accuracy Audit (“RAA”) or a Relativ e Accuracy Test Audit (“RATA”) once every

54three (3) years and shall conduct Cylinder Gas Audits (“CGA”) each calendar quarter during which a RAA or a RATA is not performed. 55. The requirem e nts of this Subsection V.G do not exempt ExxonMobil from

com p lying with any and all Federal, state, regional, and local requirem e nts that m a y require technology, equipment, monitoring, or other upgrades based on actions or activities occurring after the Date of Lodging of the Consent Decr ee, or based upon new or modified regulatory, statutory, or permit requirem e nts. 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 requirem e nts except as prohibited under Section VI (Em i ssion 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-Plaintif f of that transfer and shall submit an allocation to EPA and the Applicable Co-Plaintiff for that Covered Refinery’s shar e of NOx reduction requirem e nts of Paragraph 47 that will apply individually to the transferred refinery after such transfer. If ExxonMobil chooses, such allocation m a y be zero. Any such allocation shall be m emo rialized in a Consent Decree modification in accordance with Paragraphs 7 and 269.

55H. SO 2 EMISSIONS REDUCTIONS FROM AND NSPS APPLICABILITY OF HEATERS, BOILERS AND OTHER FUEL GAS COMBUSTION DEVICES

. 58. General . ExxonMobil shall undertake measures to limit SO 2 emissions from refinery heaters and boilers and other fuel combustion devices by restricting H 2 S 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 s ubject 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 ref i nery f u el gas at any of the Covered Ref i neries shall be an “af f

ected facility,” as that term is used in 40 C.F.R. Part 60, Subparts A and J, and shall be subject to, and com p ly with the requirem e nts 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 com p ly with the requirem e nts 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 com p ly with the requirem e nts of NSPS Subparts A and J for fuel gas combustion devices.

c. Wh ere Appendix C or D specifies an alternative monitoring plan (“AMP”) submittal date (rather than a final NSPS Subpart A and J com p liance date), ExxonMobil shall

56submit to EPA a timely and com p lete AMP application by the date(s) specified. To the extent that ExxonMobil seeks approval of an alternative monitoring m e thod that is the sam e or substantially similar to the m e thod identified in the “Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas,” which is attached hereto in Appendix E, ExxonMobil m a y begin using such m e thod im me diately upon submitting its application for approval to use such m e thod. If an AMP is not approved, ExxonMobil shall submit to EPA for approval a plan for com p lying with the monitoring requirem e nts of NSPS Subparts A and J for the particular equipment within ninety (90) days of receiving notice of the disapproval. The equipment will becom e an affected facility when ExxonMobil receives EPA’s approval of the relevant AMP

. A plan for comp lying with the monitoring requirem e nts of NSPS Subparts A and J m a y include a revised AMP application, physical or operational changes to the equipment, or additional or different

m onitoring. d. For som e heaters and boilers that combust low-flow VOC streams from vents, pumpseals, and other sources, it is anticipated that som e of the AMP applications will rely in part on calculating a weighted average H 2 S 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 SO 2 emissions from the heater or boiler will not exceed 20 ppm or that the weighted average
H 2 S concentration is not likely to exceed 0.1 grains H 2 S 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 com p liance 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

57be interpreted as limiting: (i) the use of torch oil in an FCCU regenerator to assist in starting, restarting, m a intaining hot standby, or m a intaining regenerator heat balance; or (ii) combustion of acid soluble oil in a combustion device.
61. Compliance w i th Consent Decree Constitutes Compliance w i th Certain NSPS Subpart A Requirements

. For each fuel gas combustion device that becom e s 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 com p liance with the relevant monitoring requirem e nts of this Consent Decree f o r such f u el gas combustion device will satisf y the notice requirem e nts of 40 C.F.R. § 60.7(a) and the initial perform a nce test requirem e nt of 40 C.F.R. § 60.8(a).
I. SULFUR RECOVERY PLANT OPERATIONS

. 62. General . ExxonMobil shall com p ly with the requirem e nts 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 C onsent Decree Entry Date Beaumont SRP C onsent Decree Entry Date Joliet SRP D ecember 31, 2008 Torrance SRP C onsent 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

com p ly 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:

58a. Emission Lim it

. ExxonMobil shall, for all periods of operation of these SRPs, com p ly 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 shutdow n of a TGU serving as a control device for the
SRP. b. Monitoring

. ExxonMobil shall monitor all emissions points (stacks) to the

atm o sphere 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 com p liant with NSPS requirem e nts at all of the emission points, unless an
SO 2 alternative monitoring procedure has been approved by EPA, pursuant to 40 C.F.R. § 60.13(i), for any of the emission points. The requirem e nt 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 W a ter Stripper Gas diverted from the SRPs.

c. Notice and Initial Perform a nce Test Requirem e nts

. For each SRP listed in Paragraph 63, entry of this Consent Decree and com p liance with the relevant monitoring requirem e nts of this Consent Decree f o r such SRP will satisf y the notice requirem e nts of 40 C.F.R. § 60.7(a) and the initial perform a nce test requirem e nt 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 sum ma ry of the plans, implemented or to be implemented, at each of the Covered Refineries for enhanced m a intenance and operation of the SRPs, the control devices, and the appropriate Upstream Process Units. Those plans shall be

59termed the Preventative Maintenance and Operations Plans (“PMO Plans”). The PMO Plans shall be a com p ilation of ExxonMobil’s approaches for exercising good air pollution control practices and for m i nim i zing SO 2 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 m a intenance turnarounds with
mi nim i zation 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 m a intenance turnarounds of the SRP Claus trains and any control device to coincide with scheduled turnarounds of m a jor 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 requirem e nts imposed by 40 C.F.R. § 60.11(d). Changes to the PMO Plan related to m i nim i zing Acid Gas Flaring and/or SO 2 emissions shall be

sum ma rized and reported by ExxonMobil to EPA and the Applicable Co-Plaintiffs in the Sem iAnnual 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 com me nt on the PMO Plans, warrant or aver in any m a nner that any of the actions that ExxonMobil m a y take pursuant to such PMO Plans will result in

com p liance 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 rem a in solely responsible for com p liance with the Clean Air Act and such other laws and regulations.

6066. Baton Rouge and Joliet Optimiz a tion Studies and Interim Performance Standards . ExxonMobil shall com p lete an optimization study for the Joliet East Claus Train
and W e st Claus Train and an optimization st udy 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 Perform a nce Standards for each of those Claus trains. The Interim Perform a nce Standards for the Baton Rouge 100 Claus Trai n and 200 Claus Train would apply only during planned routine m a intenance on the Baton Rouge TGU, if the relevant Claus train is being operated during the m a intenance period, as provided by Paragraph 67. The Interim Perform a nce Standards f o r the Joliet East Claus Train and W e st Claus Train would only apply until the Joliet
SRP comp lies with NSPS Subpart J requirem e nts, as provided by Paragraph 68. a. The Optimization Studies shall be com p leted by no later than ten (10)

m onths after the Entry Date, and shall include: (i) a detailed evaluation of plant design and capacity, operating param e ters and efficiencies - including catalytic activity, and m a terial 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 instrum e ntation 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 expande d periods of operation; (iv) establishment of baseline data through testing and measurement of key param e ters throughout the Claus train; (v) establishment of a thermodynam i c process model of the Claus train; (vi) for any key
param e ters that have been determined to be at less than optimal levels, initiation of logical, sequential, or stepwise changes designed to move such param e ters toward their optimal values;

61(vii) verification through testing, analysis of continuous emission monitoring data or other

m eans, of incremental and cum u lative improvem e nts 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 perform a nce of the Claus train in light of the actual characteristics of the feeds to the Claus train. b. W ithin sixty (60) days after com p letion 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 recom me nded physical and operational improvem e nts, if any, that would e nhance Claus train efficiency; (iii) propose an Interim Perform a nce Standard (expressed as percent recovery efficiency and/or an emission limitation) for the Claus train; and, if necessary, (iv) propose a schedule for implementing

recom me nded physical or operational improvem e nts required to achieve the proposed Interim Perform a nce Standard. c. Upon submitting an Optimization Study Report, ExxonMobil shall com p ly with its proposed Interim Perform a nce Standard in accordance with this Paragraph 66 or, if necessary, shall begin implementing recom me nded physical or operational improvem e nts required to achieve the proposed Interim Perform a nce Standard. d. If EPA determines that a m o re stringent Interim Perform a nce Standard and/or a different implementation schedule is a ppropriate and can be achieved with a reasonable certainty of com p liance, then EPA, after consu ltation with the Applicable Co-Plaintif f, shall so notify ExxonMobil. Unless ExxonMobil disputes EPA’s determination(s) within 90 days of its receipt of that notice, ExxonMobil shall, in acco rdance with this Paragraph 66, com p ly with such

62new standard within 90 days or, if necessary, such other period as m a y be established by EPA based upon the approved implementation schedule.
67. Particular Requirements for Baton Rouge .

a. Good Air Pollution Control Practices

. Com me ncing on the Entry Date, ExxonMobil shall at all times, including periods of startup, shutdown, and m a lfunction, to the extent practicable, m a intain and operate the Baton Rouge Claus trains, the Baton Rouge TGU, and the Baton Rouge Sulfur Recovery incinerator, in a m a nner consistent with good air pollution control practices for m i nim i zing emissions. b. Tail Gas Treatm e nt

. Com me ncing 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 m a lfunction; or (ii) during planned routine m a intenance on the Baton Rouge TGU, as provided by Subparagraph 67.d.

c. Emissions Limits for Normal Operations

. Com me ncing 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) F or an oxidation control system or a reduction control system followed by incineration, 250 ppm by volume (dry basis) of sulfur dioxide (SO 2 ) at zero percent excess air, on a 12-hour rolling average basis; or (2) F or a reduction control system not followed by incineration, 300 ppm by volume of reduced sulfur compounds and 10 ppm by volume hydrogen sulfide (H 2 S), calculated as ppm SO 2 by volume (dry basis) at zero percent excess air, on a 12-hour rolling average basis.

63d. Particular Requirem e nts Regarding Planned Routine Maintenance on the Baton Rouge TGU

. The requirem e nts of this Subparagraph 67.d shall apply to periods of planned routine m a intenance on the Baton Rouge TGU after the Entry Date. (1) E xxonMobil shall m i nim i ze emissions associated with planned routine m a intenance on the Baton Rouge TGU, to the extent practicable. More specifically, ExxonMobil shall: (i) m i nim i ze the duration of each planned routine

ma intenance period, and specifically limit each such period to no m o re than 30 calendar days in duration; (ii) m a xim i ze TGU run length between planned routine m a intenance periods, and specifically limit their frequency to no m o re than once every five (5) years; (iii) implement appropriate sulfur shedding procedures during any planned routine

ma intenance period; (iv) cease operation of the 400 Claus Train during planned routine

ma intenance on the TGU and coordinate planned routine m a intenance on the TGU with scheduled turnarounds of the 400 Claus Train and m a jor Upstream Process Units; (v) operate the 100 Claus Train and the 200 Claus Train in com p liance with the relevant Baton Rouge Interim Perform a nce Standards, as described above in Paragraph 66, during the planned routine m a intenance period; and (vi) seek and obtain LDEQ’s advance written approval f o r the planned routine m a intenance period (such as by seeking and obtaining a variance pursuant to La. Adm i n. Code tit. 33, III § 1505). (2) T he requirem e nts specified by Subparagraph 67.d.(1) shall only apply to planned routine m a intenance on the Baton Rouge TGU, and shall not apply to any unplanned shutdown or m a lfunction. (3) O n a case-by-case basis, EPA will consider any advance written request by ExxonMobil demonstrating that a particular planned routine m a intenance

64period for the Baton Rouge TGU should be scheduled less than five (5) years after the prior planned m a intenance period so that the planned m a intenance will coincide with a scheduled turnaround of one or m o re m a jor Upstream Process Units. If the request is approved in writing by EPA, then ExxonMobil m a y conduct the planned routine

ma intenance during the period approved by EPA. During any such planned routine

ma intenance period approved under this Subparagraph 67.d.(3), ExxonMobil shall

com p ly with all requirem e nts imposed by Subparagraph 67.d.(1) other than the 30 calendar day/5 year restrictions specified by that Subparagraph.

e. Incorporation of Certain Requirem e nts 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 requirem e nts, to ensure that the requirem e nts shall survive the termination of this Consent Decree: (i) the Interim Perform a nce Standards for the Baton Rouge 100 Claus Train and 200 Claus Train, established pursuant to Subparagraph 66.a; and (ii) the Particular Requirem e nts 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 com p lies at all times with NSPS Subpart A and J requirem e nts 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 W e st Claus Train to the expanded TGU, and taking a refinery-wide shutdown during any period of planned routine m a intenance on the TGU; or (ii) constructing one or m o re additional TGU(s) to control the emissions from the East Claus Train and W e st Claus Train.

65b. Until the Joliet SRP com p lies with NSPS Subpart A and J requirem e nts, ExxonMobil shall operate the East Claus Train and the W e st Claus Train in com p liance with the relevant Joliet Interim Perform a nce 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

m onitored 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

m onitored as part of the relevant emissions limitations set forth in Paragraph 67. e. The Parties recognize that periodic m a intenance m a y be required for properly designed and operated sulfur pit emission control systems and/or equipment.

66ExxonMobil will take all reasonable measures to m i nim i ze emissions while such periodic

ma intenance is being perform e d.
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
mi nim i ze emissions from its Flaring Devices, in a m a nner consistent with the requirem e nts 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 com p ly with, the requirem e nts of 40 C.F.R. Part 60, Subparts A and J, for fuel gas combustion devices. Wh ere two or m o re 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 becom e s 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 com me nce operation of enhancements to its existing flare gas recovery systems at the Beaumont Ref i nery. Those enhanced f l are gas recovery systems will serve certain NSPS Flaring Devices at the Beaumont Refinery, as specified in Appendix G.

67c. By no later than 48 months after the Entry Date, ExxonMobil will construct and com me nce 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 Ref i nery that are identified in Appendix G. d. By no later then the Entry Date, ExxonMobil shall construct and

com me nce operation of fl are gas recovery facilities at the Joliet Ref i nery pursuant to the IEPA Construction Permit f o r the Joliet Coker Blow down Recovery Project (Application Num b er 03060091).
73. Compliance Methods for NSPS Flaring Devices

. a. ExxonMobil shall com p ly with the NSPS Subparts A and J requirem e nts for each NSPS Flaring Device by using one or any com b ination of the following m e thods i. Operate and m a intain 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 m a intain 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 a nd 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 m a lfunctions; iii. Operate the NSPS Flaring Device as a fuel gas combustion device and com p ly with NSPS monitoring requirem e nts by use of a continuous monitor pursuant to 40 C.F.R. § 60.105(a)(4) or with a param e tric monitoring system approved by EPA as an alternative monitoring system under 40 C.F.R. § 60.13(i); or iv. E liminate 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 m e ter; provided , however , that this com p liance m e thod: (a) m a y only be used for the three (3) NSPS Flaring Devices at the Baytown Refinery identified in Appendix

68G; and (b) m a y not be used unless each of those NSPS Flaring Devices will emit less than 500 pounds of SO 2 per day under norm a l conditions. b. For its existing NSPS Flaring Devices, ExxonMobil shall utilize the

com p liance m e thod set forth in Appendix G by the dates specified in Appendix G. Wh ere Appendix G specifies an AMP submittal date (rather than a final NSPS Subpart A and J

com p liance date), ExxonMobil shall submit to EPA a timely and com p lete AMP application by the date(s) specified. To the extent that ExxonMobil seeks approval of an alternative monitoring

me thod that is the sam e or substantially similar to the m e thod identified in the “Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas,” which is attached hereto in Appendix E, ExxonMobil m a y begin using such m e thod im me diately upon submitting its application for approval to use such m e thod. If an AMP is not approved, ExxonMobil shall submit to EPA for approval a plan for comp lying with the monitoring requirem e nts of NSPS Subparts A and J for the particular equipment within ninety (90) days of receiving notice of the disapproval. The equipment will becom e an affected facility when ExxonMobil receives EPA’s approval of the relevant AMP

. A plan for com p lying with the monitoring requirem e nts of NSPS Subparts A and
J m a y 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 refi nery process unit or released to a Flaring Device as a result of relief valve leakage or other emergency Malfunction is exempt from the requirem e nt to comp ly with 40 C.F.R. § 60.104(a)(1).

6975. Compliance w i th Consent Decree Constitutes Compliance w i th Certain NSPS Subpart A Requirements

.

a. Notice Requirem e nts

. For each NSPS Flaring Device listed in Appendix G, entry of this Consent Decree will satisf y the notice requirem e nts of 40 C.F.R. § 60.7(a). b. Perform a nce Test Requirem e nts

. (1) F or each NSPS Flaring Device listed in Appendix G that becom es an affected facility under NSPS Subparts A and J pursuant to this Subsection V.J, entry of this Consent Decree and com p liance with the relevant monitoring requirem e nts of this Consent Decree for the NSPS Flaring Device shall satisfy the notice requirem e nts of 40 C.F.R. § 60.7(a) and the initial perform a nce test requirem e nts of 40 C.F.R. § 60.8(a). (2) W ithin 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 m a y submit velocity calculations which demonstrate that the NSPS Flaring Device meets the perform a nce specification required by 40 C.F.R. § 60.18.
76. Periodic Maintenance of Flare Gas Recovery Systems . The Parties recognize that periodic m a intenance m a y be required for properly designed and operated flare gas recovery systems. ExxonMobil will take all reasonable measures to m i nim i ze emissions while such periodic m a intenance is being perform e d.
77. Safe Operation of Refining Processes . The Parties recognize that under certain conditions, a flare gas recovery system ma y need to be bypassed in the event of an emergency or

70in 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 occurre d at the Covered Refineries between January 1, 1998 and December 1, 2004, and has provided EPA a sum ma ry 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 m i nim i ze 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 requirem e nts of 40 C.F.R. § 60.11(d), ExxonMobil shall investigate the cause of future AG Flaring Inci dents 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 m i nim i ze AG Flaring Inci dents 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-Plaintif f a report that sets f o rth the f o llowing:

71i. The date and time that the AG Flaring Incident started and ended. To the extent that the AG Flaring Incident involved m u ltiple releases either within a twentyfour (24) hour period or within subs equent, 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 sam e Root Cause or significant contributing causes in the future. If two or m o re 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 m a intenance 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 com p leted, a schedule for its (their) implementation, including proposed com me ncement and com p letion 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 m a y choose to submit with the Root Cause Failure Analysis a payment of stipulated penalties in the nature of settlem e nt without the need to specifically identify the grounds for the penalty. Such payment of stipulated penalties shall not constitute an adm i ssion 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

72by which a follow-up report fully conform i ng to the requirem e nts 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 tim e period set forth in this Paragraph 80 (or such additional time as EPA m a y allow) after the due date f o r the initial report f o r 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 dem a nd for stipulated penalties that was issued as a result of ExxonMobil’s failure to submit the report required under this Paragraph within the time fram e 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 com p letion 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 com p letion of the implementation of corrective action(s), ExxonMobil shall submit a report identifying the corrective action(s) taken and the dates of com me ncement and com p letion 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 m i nim i ze 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 m o re 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 com p liance with Subparagraph 81.a of this Decree. EPA does not, however, by its failure to object to any corrective action that ExxonMobil m a y take in the future, warrant or aver in any m a nner that any

73corrective actions in the f u ture shall result in comp liance 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 r eceipt 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 im me diately following an AG Flaring Incident or in the peri od 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 stipul ated penalties f o r AG Flaring Incidents occurring after the Entry Date and by the United States in dem a nding 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 m o re 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 f o llow written procedures; iii. A failure of equipment that is due to a failure by ExxonMobil to operate and ma intain that equipment in a m a nner consistent with good engineering practice; iv. N orth Claus Train furnace power supply interlock system failures at the Joliet Refinery; or

74v. 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 provi sions 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 m o re 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 SO 2 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. W ith respect to any AG Flaring Incident not identified in Paragraphs 83 or 84, the following provisions shall apply:

a. First Tim e : If the Root Cause of the AG Flaring Incident was not a recurrence of the sam e Root Cause that resulted in a previous AG Flaring Incident that occurred since the Entry Date, then: (1) I f 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) I f 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.

75b. Recurrence : If the Root Cause is a recurrence of the sam e 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) t he AG Flaring Incident resulted from a Malfunction; or (2) t he Root Cause previously was designated as an agreed-upon Malfunction under Subparagraph 85.a.(1); or (3) t he 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 com p leted implementation.
86. Defenses . ExxonMobil m a y raise the following affirmative defenses in response
to a dem a nd by the United States f o r stipulated penalties: i. Force m a jeure

. ii. As to Paragraph 83, the AG Flaring Incident does not meet the identified criteria. iii. As to Paragraph 84, Malfunction. iv. A s 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 m a y also assert a startup, shutdown and/or Malfunction def e nse, 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 ava ilable 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

76such 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 f o r such stipulated penalties. 88. Other than for a Malfunction or force ma jeure , 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 Cove red Refinery. EPA m a y elect to reinstate the stipulated penalty provision if ExxonMobil has an AG Flaring Incident which would otherwise be subject to stipulated penalties. EPA's deci sion shall not be subject to dispute resolution. Once reinstated, the stipulated penalty provision shall continue for the rem a ining term of this
Consent Decree. 89. Billings AG Flaring Incidents . W ith respect to AG Flaring Incidents occurring within the Billings Refinery, ExxonMobil shall not be entitled to assert failures, at Montana Sulfur and Chemicals Com p any’s contiguous facility, of air pollution control equipment, process equipment, or a process to operate in a norm a l or usual m a nner 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 Com p any' s contiguous facility. 90. Emission Calculations

.

a. Calculation of the Quantity of Sulfur Dioxide Emissions Resulting f r om AG Flaring

. For purposes of this Consent Decree, the quantity of SO 2 emissions resulting from an AG Flaring Incident shall be calculated by the following formula: Tons of SO 2 = [FR][TD][ConcH 2 S][8.44 x 10 -5 ].

77The quantity of SO 2 emitted shall be rounded to one decim a l point. (Thus, for example, for a calculation that results in a number equal to 10.050 tons, the quantity of SO 2 emitted shall be rounded to 10.1 tons.) For purposes of determining the occurrence of, or the total quantity of
SO 2 emissions resulting f r om, an AG Flaring Incident that is com p rised of intermittent AG Flaring, the quantity of SO 2 emitted shall be equal to the sum of the quantities of SO 2 flared during each 24-hour period starting when the Acid Gas was first flared. b. Calculation of the Rate of SO 2 Emissions During AG Flaring

. For purposes of this Consent Decree, the rate of SO 2 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][ConcH 2 S][0.169]. The emission rate shall be rounded to one decim a l point. (Thus, for example, for a calculation that results in an emission rate of 19.95 pounds of SO 2 per hour, the emission rate shall be rounded to 20.0 pounds of SO 2 per hour; for a calculation that results in an emission rate of 20.05 pounds of SO 2 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 SO 2 per hour
FR = A verage Flow Rate to Flaring Device(s) during Flaring Incident in standard cubic feet per hour
TD = T otal Duration of Flaring Incident in hours
ConcH 2 S = A verage Concentration of Hydrogen Sulfide in gas during Flaring Incident (or im me diately prior to Flaring Incident if all gas is being flared) expressed as a volume fraction (scf H 2 S/scf gas)

788.44 x 10 -5 = [ lb m o le H 2 S/379 scf H 2 S][64 lbs SO 2 /lb m o le H 2 S][Ton/2000 lbs] 0.169 = [lb m o le H 2 S/379 scf H 2 S][1.0 lb m o le SO 2 /1 lb m o le H 2 S][64 lb SO 2 /1.0 lb m o le SO 2 ] The flow of gas to the AG Flaring Device(s) (“FR ”) shall be as measured by the relevant flow

me ter or reliable flow estimation param e ters. Hydrogen sulfide concentration (“ConcH 2 S”) 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 colorim e tric) tube analysis or by any other m e thod approved by EPA or an Applicable Co-Plaintiff. In the event that any of these data points is unavailable or inaccurate, the m i ssing 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 m i ssing data points. 91. Tail Gas Incidents

.
a. Investigation, Reporting, Corrective Action and Stipulated Penalties

. For Tail Gas Incidents, ExxonMobil shall follow the sam e 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. Com me ncing 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 m a intenance on the Baton Rouge TGU perform e d in

com p liance 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 W e st Claus Train. ExxonMobil shall continue to follow the Tail Gas Incident

79investigation and corrective action procedures af ter 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 SO 2 Emissions Resulting from a Tail Gas Incident

. For the purposes of this Consent Decree, the quantity of SO 2 emissions resulting from a Tail Gas Incident shall be calculated by one of the following m e thods, based on the type of
event: i. If Tail Gas is combusted in a f l are, the SO 2 emissions are calculated using the m e thods outlined in Paragraph 90; or ii. If Tail Gas exceeding the 250 ppmvd NSPS J limit is emitted from a m onitored SRP incinerator, then the f o llowing f o rmula applies:
TD TG I ER TG I = 3 [ FR Inc. ] i [Conc. SO 2 – 250] i [0.169 x 10 -6 ] [[20.9 - % O 2 ]/[20.9]] i i = 1 Wh ere: ER TG I = Emissions from Tail Gas Unit at the SRP incinerator, pounds of SO 2 over a 24 hour period
TD TG I = H ours when the incinerator CEM was exceeding 250 ppmvd SO 2 on a rolling twelve hour average, corrected to 0% O2, in each 24 hour period of the Incident
i = Each hour within TD TG I FR Inc. = 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. SO 2 = The average SO 2 concentration (CEMS data) that is greater than 250 ppm in the incinerator exhaust gas, ppmvd corrected to 0% O 2 , for each hour of the Incident % O 2 = O 2 concentration (CEMS data) in the incinerator exhaust gas in volume % on dry basis for each hour of the Incident 0.169 x 10 -6 = [lb mole of SO 2 / 379 scf SO 2 ] [64 lbs SO 2 / lb m o le SO 2 ] [1 x 10 -6 ] Standard conditions = 60 degree F; 14.7 lb force /sq.in. absolute

80In the event the concentration SO 2 data point is inaccurate or not available or a flow m e ter for
FR Inc , 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 sam e 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 Sem i -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 m ay prepare and submit a single Root Cause Analysis for one or m o re 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-Plaintif f 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 f l are gas recovery system (that is, during the time in which the flare gas recovery system is being com mi ssioned), ExxonMobil will not be required to undertake HC Flaring Incident investigations if the Root Caus e of the HC Flaring Incident is directly related to the com mi ssioning of the flare gas recovery system

. iv. I n 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 m ay 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 m a intenance 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 Sem i -Annual Reports due under Section IX.

81ExxonMobil 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 SO 2 emissions during AG Flaring Incidents, shall be used to calculate the quantity and rate of SO 2 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 com p liance with applicable requirem e nts 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 SO 2 and H 2 S releases resulting from those AG Flaring Incidents. Upon com p letion of this review, ExxonMobil shall com p lete 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 requirem e nts of Section 103(a) of CERCLA and Section 304 of EPCRA; and b. submit a CERCLA/EPCRA Com p liance Review Report to EPA and the Applicable Co-Plaintif f that: (i) identifies all AG Flaring Incidents; (ii) if associated violations of Section 103(a) of CERCLA and Section 304 of EPCRA related to SO 2 and H 2 S were

82identified 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 Com m ittee 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 Com m ittee im me diately 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. BENZ E NE WASTE NESHAP PROGRAM ENHANCEMENTS

. 97. In addition to continuing to com p ly with all applicable requirem e nts of 40 C.F.R. Part 61, Subpart FF (“Benzene W a ste NESHAP,” “BWON,” or “Subpart FF”), ExxonMobil agrees to undertake the measures set forth in this Subsection V.N to ensure continuing

com p liance with Subpart FF and to m i nim i ze or eliminate fugitive benzene waste emissions at the Covered Refineries. 98. Subpart FF Compliance Status.
a. Com me ncing on the Date of Entry, ExxonMobil’s Baton Rouge Refinery and Beaumont Refinery shall com p ly with the com p liance 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 Com p liance Option”). b. Com me ncing on the Date of Entry, ExxonMobil’s Baytown Refinery, Billings Ref i nery, Joliet Ref i nery, and Torrance Ref i nery shall com p ly with the com p liance option set forth at 40 C.F.R. § 61.342(e) (hereinafter referred to as the “6 BQ Com p liance Option”).
99. Refinery Compliance Status Changes . During the term of this Consent Decree, ExxonMobil shall not change the com p liance status of any Covered Refinery from the 6 BQ Com p liance Option to the 2 Mg Com p liance 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 com p lete a review and verification of each Covered Refinery’s Total Annual Benzene (“TAB”) and its com p liance with the applicable com p liance 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 sam p ling points, other sam p le wastes, m a intenance 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 sam p ling for benzene concentration at no less than 10 waste streams per Covered Refinery, consistent with the requirem e nts of 40 C.F.R. § 61.355(c)(1) and (3); provided , however , that previous analytical data or documented knowledge of waste streams m a y be used, 40 C.F.R. § 61.355(c)(2), for streams not sam p led.

84Streams sam p led after January 1, 2004 m a y be applied toward the waste stream s requiring sam p ling; iv. a n identification of whether or not the stream is controlled consistent with the requirem e nts of Subpart FF; and

v. an identification of any existing noncom pliance with the requirem e nts of Subpart FF. By no later than 30 days following the com p letion of Phase One of the review and verification process, ExxonMobil shall submit to EPA and the Applicable Co-Plaintiff a BWON Com p liance Review and Verification Report for each Covered Re finery that sets forth the results of Phase One, including but not limited to the item s 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 Ve rification Reports, EPA m a y select up to 20 additional waste streams at each Covered Refinery for additional sam p ling or re-sampling for benzene concentration. ExxonMobil shall conduct the required sam p ling 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 sam p ling to reevaluate the TAB and the uncontrolled benzene quantity and to amend the BWON Com p liance Review and Verif i cation 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 chos e to samp le as part of the Phase One review, ExxonMobil m a y average the results of the two sam p ling events. ExxonMobil shall submit an amended BWON Com p liance Review and Verification Report within 90 days following the date of the com p letion of the required Phase Two sam p ling, if Phase Two sam p ling is required by
EPA.

85101. Implementation of Actions Necessary to Correct Non-Compliance or to Come Into Compliance .

a. Amended TAB Reports

. If the results of the BWON Com p liance Review and Verification Report indicate that the re ports 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 requirem e nts of Subpart FF, ExxonMobil shall submit, by no later than sixty (60) days after com p letion of the BWON
Com p liance Review and Verification Report(s) , an amended TAB report to EPA and the Applicable Co-Plaintif f. b. BWON Corrective Measures Plan

. (1) B aton Rouge and Beaumont Refineries

. If the results of the
BWON Com p liance Review and Verification Report indicate that ExxonMobil is not in

com p liance with the 2 Mg Com p liance 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 com p letion of the BWON Com p liance Review and Verification Report, a BWON Corrective Measures Plan that identifies with specificity the com p liance strategy and schedule that ExxonMobil shall implement to ensure that the Refinery com p lies with the 2 Mg Com p liance Option as soon as practicable. (2) B aytown, Billings, Joliet, and Torrance Ref i neries

. If the results of the BWON Com p liance Review and Verification Report indicate that ExxonMobil is not in com p liance with the 6 BQ Com p liance Option at the Baytown Ref i nery, 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 com p letion of the BWON Com p liance Review and Verification Report, a BWON Corrective

86Measures Plan that identifies with specif i city the comp liance strategy and schedule that ExxonMobil shall implement to ensure that the Refinery com p lies with the 6 BQ
Com p liance 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.
W ithin sixty (60) days after receiving any no tification 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 Com p liance with the 2 Mg Com p liance Option or the 6 BQ Com p liance Option, as Applicable

. By no later than 30 days after com p letion of the implementation of all actions, if any, required pursuant to Subparagraphs 101.b or 101.c to com e into com p liance with the 2 Mg Com p liance Option or the 6 BQ Com p liance Option, as applicable, ExxonMobil shall submit a report to EPA and the Applicable Co-Plaintiff certifying that, as to the subject Refinery, the Refinery com p lies with the Benzene W a ste NESHAP.
102. Carbon Canisters

. ExxonMobil shall com p ly with the requirem e nts 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 W a ste NESHAP. a. By no later than 180 days after the Entry Date, ExxonMobil shall

comp lete 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 com p letion of the installation of the dual canisters, ExxonMobil shall submit a report certifying the

87comp letion 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 W a ste 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 m o re frequent. This requirem e nt shall com me nce: (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

88and secondary carbon canisters weekly, or in accordance with the frequency specified in 40 C.F.R. § 61.354(d), whichever is m o re frequent. f. ExxonMobil shall replace the original primary carbon canister (or route the flow to an appropriate alternative control device) im me diately when breakthrough is detected between the primary and secondary canister. The original secondary carbon canister (or a fresh canister) will becom e the new primary carbon canister and a fresh carbon canister will becom e the secondary canister. For purposes of this Subparagraph, “im me diately” 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 br eakthrough for canisters greater than 55 gallons. In lieu of replacing the primary canister im me diately, ExxonMobil m a y 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

m onitoring, both canisters m u st be replaced within eight (8) hours of the detection of a breakthrough.
g. Temporary Applications

. ExxonMobil m a y 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

m onitor 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

89with a fresh carbon canister, discontinue flow, or route the stream to an alternate, appropriate device im me diately when breakthrough is detected. For purpose of this Subparagraph,
“im me diately” 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 m u st be discontinued to that canister
im me diately. Such a spent canister m a y not be placed back into Benzene W a ste NESHAP vapor control service until it has been appropriately regenerated. h. ExxonMobil shall m a intain 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 requirem e nts of this Paragraph 102. i. ExxonMobil shall m a intain records associated with the requirem e nts of this Paragraph, including carbon canister monitoring readings and the constituents being

m onitored 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 m a nagem e nt of change procedures to provide f or 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 W a ste NESHAP sam p les to ensure that proper analytical and quality assurance/quality control procedures are f o llowed f o r such samp les.

90a. By no later than 180 days after the Entry Date, ExxonMobil shall

comp lete initial audits of at least half of the laboratories used by the Covered Ref i neries within 180 days after the Entry Date, and shall com p lete initial audits of the rem a ining laboratories within 365 days of the Entry Date. In addition, ExxonMobil shall audit any new laboratory to be used for analyses of benzene sam p les from the Covered Refineries prior use of the new laboratory. If ExxonMobil has com p leted 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 m a y 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 com p liance 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 m o re 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 com p liance 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 sam p les for Benzene W a ste NESHAP purposes.

91b. By no later than 120 days after the Entry Date, ExxonMobil shall

com p lete the development of standard operating procedures (where they do not already exist) for all control devices and treatm e nt processes used to com p ly with the Benzene W a ste NESHAP at each Covered Refinery. By no later than 180 days after the Entry Date, ExxonMobil shall

comp lete an initial training program regarding these procedures f o r all operators assigned to the relevant equipment. Com p arable training shall also be provided to any persons who subsequently becom e operators, prior to their assum p tion of this duty. “Refresher” training in these procedures shall be perform e d 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 requirem e nts of this Subsection V.N are properly trained to implement such requirem e nts that they are hired to perform , as under Subparagraphs 106.a-106.c.
107. Waste/Slop/Off-Spec Oil Management

.

a. Schem a tics

. By no later than 120 days after the Entry Date, ExxonMobil shall submit to the EPA and the Applicable Co-Plaintiff schem a tics for each Covered Refinery that: (i) depict the waste m a nagem e nt units (including sewers) that handle, store, and transfer waste/slop/off-spec oil streams; (ii) identify th e control status of each waste m a nagem e nt unit; and (iii) show how such oil is transferred within the Ref i nery. Representatives f r om ExxonMobil and EPA thereafter m a y confer about the appropriate characterization of each waste/slop/off-spec oil streams and the necessary controls, if any, for the waste m a nagem e nt units handling such oil streams, for purposes of the Covered Refinery’s TAB calculation and

com p liance with the applicable com p liance option. If requested by EPA, ExxonMobil shall promptly submit revised schem a tics that reflect the Parties’ agreements regarding the characterization of these oil streams and the appropriate control standards. ExxonMobil shall

92use these schem a tics in preparing the BWON Sam p ling Plans required under Paragraphs 108 and 109. b. Non-Aqueous Benzene W a ste Stream s . All waste m a nagem e nt 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 W a ste Stream s . For purposes of calculating each Covered Refinery’s TAB pursuant to the requirem e nts of 40 C.F.R. § 61.342(a), ExxonMobil shall include all waste/slop/of f- spec oil streams that becom e “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 adjustm e nts will be m a de to such calculations to avoid the double-counting of benzene. For purposes of com p lying with the applicable com p liance option, all waste m a nagem e nt 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 Com p liance Option or the 6 BQ Com p liance Option.
108. Sampling Under the 6 BQ Compliance Option

. ExxonMobil shall conduct quarterly sam p ling as described by this Paragraph at the Baytown, Billings, Joliet and Torrance Ref i neries f o r 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 sam p ling plan for each such Refinery designed to identify the quarterly benzene quantity in uncontrolled benzene waste streams, including waste/slop/of f- spec oil. That

sam p ling plan (the “BWON Sam p ling Plan”) shall include, but need not be limited to: (i) proposed sam p ling locations and m e thods for flow calculations at the “end of line” of uncontrolled benzene waste streams; (ii) a sim p lified flow diagram that identifies significant,

93uncontrolled benzene waste streams that feed into each proposed sam p ling location; (iii) proposed quarterly sam p ling, at the “point of waste generation,” of each waste stream that contributes 0.05 Mg/yr or m o re to the Refinery’s benzene quantity; and (iv) quarterly sam p ling at all “end of line” and point of waste generation locations identified in Subparagraphs 108.a.(i) and 108.a.(iii). The BWON Samp ling Plans m a y identify com mi ngled, exempt waste stream s for sam p ling, provided ExxonMobil demonstrates that the benzene quantity of those com mi ngled streams will not be underestimated. Additionally, waste streams that are non-aqueous at their point of generation and do not becom e aqueous thereafter shall not be included in the BWON
Sam p ling Plans. b. If changes in processes, operations, or other factors lead ExxonMobil to conclude that its approved BWON Sam p ling 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 Sam p ling Plan to EPA for approval. c. ExxonMobil shall com me nce samp ling under its BWON Sam p ling Plan during the f i rst f u ll calendar quarter f o llowing 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 sam p les from each identified sam p ling location. ExxonMobil shall use the average of all samp les taken and the identified f l ow calculations to determine its quarterly benzene quantity in uncontrolled waste streams and to estimate a calendar year value f o r the Refinery. 109. Sampling Under the 2 Mg Compliance Option

. ExxonMobil shall conduct quarterly sam p ling as described by this Paragra ph at the Baton Rouge and Beaumont Refineries fo r the purpose of calculating quarterly, uncontrolled benzene quantities

94a. By no later than 180 days after the Entry Date, ExxonMobil shall submit to EPA for approval a sam p ling plan for each such Refinery designed to identify the quarterly benzene quantity in uncontrolled benzene waste streams, including waste/slop/of f- spec oil. That

sam p ling plan (the “BWON Sam p ling Plan”) shall include, but need not be limited to: (i) proposed sam p ling locations and m e thods for flow calculations at the “end of line” of uncontrolled benzene waste streams; (ii) quarterly sam p ling of all uncontrolled waste stream s that count toward the 2 Mg/yr calculation an contain greater than 0.05 Mg/yr of benzene; (iii) monthly sam p ling of all uncontrolled waste streams that qualify f o r 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
Sam p ling Plans m a y identify com mi ngled, exempt waste streams for sam p ling, provided ExxonMobil demonstrates that the benzene quantity of those com mi ngled streams will not be underestimated. b. If changes in processes, operations, or other factors lead ExxonMobil to conclude that its approved BWON Sam p ling Plan ma y no longer provide an accurate m e asure of the Refinery’s quarterly benzene quantity in uncontrolled benzene waste streams, ExxonMobil shall submit a revised BWON Sam p ling Plan to EPA for approval. c. ExxonMobil shall com me nce samp ling under its BWON Sam p ling Plan during the f i rst f u ll calendar quarter f o llowing 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 sam p les from each identified sam p ling location. ExxonMobil shall use the average of all samp les taken and the identified f l ow calculations to determine its quarterly benzene quantity in uncontrolled waste streams and to estimate a calendar year value f o r the Refinery.

95d. After at least 8 quarters of sam p ling under an approved BWON Sam p ling Plan under this Paragraph 109, ExxonMobil m a y submit a report to EPA and the Applicable Co-Plaintiff that requests a change in the m onitoring frequency specified by Subparagraph 109.a for one or m o re 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 m o re of the Covered Refineries, then the monitoring frequency requirem e nt under Subparagraph 109.a will be

m odified in accordance with Paragraph 269 (Modifications).
110. Quarterly and Annual Estimations of Uncontrolled Benzene Quantity

. At the end of each calendar quarter following com me ncement of quarterly sam p ling, 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 sam p ling results, non-end of line sam p ling results, and the approved flow calculations. ExxonMobil shall submit the uncontrolled benzene quantity in the Sem i -Annual Reports due under Section IX of this Decree.
111. Corrective Measures

.

a. Applicability (1) F or 6 BQ Com p liance 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-Plaintif f that evaluates all relevant information and identifies whether any action should be taken to reduce benzene quantities in its waste streams f o r the rem a inder of the calendar year. If additional

96actions are determined to be necessary to ensure com p liance with the 6 BQ Com p liance Option, ExxonMobil will include in its written report a BWON Corrective Measures Plan as specified in Subparagraph 111.b (2) F or 2 Mg Com p liance 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-Plaintif f that evaluates all relevant inf o rmation and identifies whether any action should be taken to reduce benzene quantities in its waste streams for the rem a inder of the calendar year. If additional actions are determined to be necessary to ensure com p liance with the 2 Mg Com p liance 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 com p lies with the 6 BQ Com p liance Option or the 2 Mg Com p liance Option, as applicable. If a spill event is the m a in cause of the potentially elevated benzene quantities, the BWON Corrective Measures Plan will f o cus on the spill event and on future measures to m i nim i ze 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 m o re of the conditions specified in

97Subparagraph 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 Com p liance 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 com p liance with the applicable com p liance option, ExxonMobil shall retain a third-party contractor to undertake a com p rehensive TAB study and

com p liance review (“Third-Party TAB Study and Co mp liance 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 Co mp liance Review. Unless EPA disapproves or seeks modifications of the proposal within 30 days after its receipt, ExxonMobil shall authorize the contractor to com me nce work. ExxonMobil shall ensure that the work is com p leted 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 Com p liance 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 Com p liance Review. No later than ninety (90) days after ExxonMobil receives the results of the Third-Party TAB Study and
Com p liance Review or at such other time as ExxonMobil and EPA m a y agree, ExxonMobil shall submit to EPA a plan and schedule for rem e dying any deficiencies identified in the Third-Party TAB Study and Compliance Review and any defi ciencies that EPA identified following the Third-Party TAB Study and Com p liance Review. Unless EPA disapproves or seeks

98m odifications of the proposal within thirty (30) days after its receipt, ExxonMobil shall implement the rem e dial 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 m a y submit a request to the appropriate EPA Region to modify the fr equency 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 m a y 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 m a rk at the drain all area drains that are segregated storm w ater 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 f o llowing reports to EPA and the Applicable Co-Plaintif f:

99i. BWON Com p liance 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. C ertifications of Com p liance, if necessary (under Subparagraph 101.d);

v. Reports certifying the com p letion of installation of dual carbon canisters (under Subparagraph 102.a); vi. S chematics of waste/slop/off-spec oil movem e nts, as revised, if necessary (under Subparagraph 107.a); and vii. BWON Sam p ling Plans (under Subparagraphs 108.a and 109.a), and revised BWON Sam p ling 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 Sem i -Annual Reports submitted pursuant to Section IX (Reporting and Recordkeeping) f o r the six month period covered by the Report: i. An identification of all laboratory audits, if any, com p leted during the six month period, including a description of the m e thods 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 com p ly with the training provisions of Paragraph 106; and iii. A sum ma ry of the sam p ling 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 m i nim i ze or eliminate fugitive emissions of volatile organic compounds (“VOCs”), benzene, volatile hazardous air pollutants (“VHAPs”), and organic

100hazardous 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 requirem e nts. The term s “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 Ref i neries Other than the Billings Ref i nery . 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 becom e an “affected facility” for purposes of 40 C.F.R. Part 60, Subpart GGG, and shall becom e subject to and com p ly with the requirem e nts of 40 C.F.R. Part 60, Subpart GGG, and the requirem e nts of this Subsection V.O. b. Billings Ref i nery . (1) E xxonMobil shall com p ly with the requirem e nts of 40 C.F.R. Part 60, Subpart GGG, and the requirem e nts 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 com p ly with the standards f o r sam p ling connection systems set f o rth at 40 C.F.R. § 60.482-5.

101(2) T wo years after the Entry Date, each existing process unit at the Billings Refinery shall becom e an affected facility for purposes of Subpart GGG, and shall becom e subject to and com p ly with the requirem e nts of 40 C.F.R. Part 60, Subpart GGG, and the requirem e nts of this Subsection V.O, including the standards for sam p ling 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 becom e 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 becom e affected facilities for purposes of Subpart GGG pursuant to this Paragraph 116 , entry of this Consent Decree shall satisfy applicable notification requirem e nts 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 m a intain a set of written LDAR Program Descriptions for a program for comp liance with all federal, state, and local LDAR regulations applicable to each of the Covered Refineries. ExxonMobil shall update the LDAR Program Descriptions as m a y be necessary to ensure continuing com p liance. The LDAR Program Descriptions shall include, at a m i nim um: i. A set of leak rate goals for each Covered Refinery that will be a target for achievem e nt 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 requirem e nts; ii. An identification of all equipment in light liquid and/or in gas/vapor service that is subject to periodic monitoring requirem e nts via Method 21 under any

102applicable 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. P rocedures 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 m i nim i ze 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 m a nagem e nt and has the authority to implement LDAR improvem e nts at the Refinery, as required by Paragraph 119; and viii. A procedure f o r regularly com m unicating LDAR inf o rmation 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 com p letion of annual LDAR training or require its LDAR contractor to provide such training (initial annual LDAR training for all such personnel will be comp leted not later than one year after the Entry Date); iii. For all other Refinery operations and m a intenance personnel (including contract personnel) who have duties relevant to LDAR, ExxonMobil shall provide and require comp letion 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 com p leted not later than one year after the Entry Date); and

103iv. F or the individuals covered by this Paragraph, “refresher” training in LDAR shall be perform e d 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 perform a nce. By no later than 180 days after the Entry Date, ExxonMobil shall establish and m a intain a person or position at each Covered Refinery with responsibility for LDAR

ma nagem e nt and authority to implement LDAR improvem e nts at the Refinery.
120. LDAR Audits

. ExxonMobil shall implement Refinery-wide LDAR Audits – including an Initial LDAR Audit and Regular LDAR Audits – as set f o rth in this Paragraph to ensure each Covered Refinery’s com p liance with all applicable LDAR requirem e nts. Each LDAR Audit shall include, but shall not be limited to: (i) perform i ng com p arative monitoring; (ii) reviewing records to ensure monitoring and repairs were com p leted in the required periods; (iii) reviewing component identification procedures, tagging procedures, and data m a nagem e nt procedures; and (iv) observing LDAR technici ans’ calibration and monitoring techniques. During each LDAR Audit, leak rates shall be calculated for each process unit where com p arative

m onitoring was perform e d.

a. Initial LDAR Audit

. ExxonMobil shall retain a third-party contractor to

com p lete an Initial LDAR Audit for each Covered Refinery by no later than 365 days after the Entry Date. b. Initial Audit Report . W ithin 90 days of comp letion 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 In itial Audit, disclose all areas of identified noncom p liance, and certify ExxonMobil’s com p liance, except for the identified deficiencies. The

104Report shall also include a schedule for correcting any identified deficiencies as soon as practicable.

c. Regular LDAR Audits

. (1) T hird-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 com p leted under Subparagraph 120.a (with approxim a tely 48 months between the Audits). (2) I nternal Audits

. ExxonMobil shall conduct Internal LDAR Audits of each Covered Refinery’s LDAR program by sending personnel familiar with the LDAR program and its requirem e nts from one or m o re of ExxonMobil’s other Covered Refineries or locations to audit another Covered Refinery. ExxonMobil shall

com p lete an Internal LDAR Audit by no later than two (2) years from the date of the

com p letion 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 approxim a tely 48 months between the Audits). ExxonMobil m a y 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) T iming

. To ensure that an LDAR Audit occurs every two (2) years at each Covered Refinery, once a Refinery’s Initial Audit is com p leted, the rem a ining Third-Party Audits and Internal Audits at that Refinery shall be separated by not m o re than two (2) calendar years (with approxim a tely 24 months between the Audits).

105121. 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-com p liance and to prevent, to the extent practicable, a recurrence of the cause of such non-com p liance. ExxonMobil shall, during the term of this Consent Decree, retain the Initia l Audit Report and all other LDAR Audit reports generated pursuant to Paragraph 120, and shall m a intain a written record of all corrective actions that ExxonMobil takes in response to deficiencies identified in any LDAR Audits. After the

com p letion of any LDAR Audit other than th e Initial Audit, ExxonMobil shall include the following information in the next Sem i -Annual Report due under Section IX of this Consent Decree: (i) a sum ma ry, 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 a nd 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 Pum p s . 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

106after 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, comp ressors, and other components shall retain their applicable regulatory leak definition.
123. LDAR Monitoring Frequency .

a. Pum p s . Wh en the lower internal leak definition for pumps becom es applicable under Paragraph 122, and unless m o re frequent monitoring is required by applicable federal, state and/or local requirem e nts, ExxonMobil shall monitor pumps at the internal leak definition on a monthly basis. b. Valves . Wh en the lower internal leak definition for valves becom es applicable under Paragraph 122, and unless m o re frequent monitoring is required by applicable federal, state and/or local requirem e nts, ExxonMobil shall monitor valves (other than difficult to

m onitor 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 m a y continue to report leak rates in valves and pumps against the applicable regulatory leak definition, or m ay 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 becom e applicable). Except as provided otherwise in this Subsection V.O, ExxonMobil shall m a ke a first attem p t at repair and remonitor

107the component within five (5) calendar days after a leak is detected and either com p lete 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 com p leting a documented m a intenance, 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 m a intenance, startup, or shutdown activity; ii. For events involving greater than 1000 but fewer than 5000 valves and pumps, m onitor within two (2) weeks of the documented m a intenance, startup, or shutdown activity; and iii. For events involving greater than 5000 pumps and valves, monitor within four (4) weeks of the documented m a intenance, 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 m a ke a “initial attem p t” 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 attem p t” 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

108greater than the applicable leak definition, ExxonMobil shall repair the valve according to the requirem e nts of Subparagraph 124.b, except that no first repair attem p t requirem e nt shall apply. If ExxonMobil can demonstrate with sufficient, statistically significant monitoring data over a period of at least two years that “initial attem p ts” to repair at 200 ppm worsen or do not improve refinery leak rates, ExxonMobil m a y request EPA to reconsider or amend this requirem e nt. 127. Electronic Monitoring, Storing, and Reporting of LDAR Data

.

a. Electronic Storing and Reporting of LDAR Data

. ExxonMobil has and shall continue to m a intain 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 m a intained 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 instrum e nt and operator. ExxonMobil m a y only use paper logs where necessary or m o re feasible (e.g., small rounds, re-monitoring, or when data loggers are unavailable or broken), and shall record, at a m i nim um, 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 m a nually recorded monitoring data to the electronic

109database m a intained 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 f o r quality assurance/quality control (“QA/QC”) reviews of all data generated by LDAR monitoring technicians. ExxonMobil shall ensure that

m onitoring 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

m onitoring 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) abnorm a l data patterns. 129. Calibration/Calibration Drift Assessment .

a. Calibration

. ExxonMobil shall conduct all calibrations of LDAR

m onitoring equipment at each of the Covered Refineries using m e thane 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 a ssessment 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 approxim a tely equal to the applicable internal leak definition. If any calibration drift assessment af ter the initial calibration shows a negative drift of m o re than 10% from the previous calibration, ExxonMobil shall remonitor all valves that

110were 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. F or 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 m e thod (or an equivalent repair me thod) for the leaking valve (unless the valve is isolated from the process and does not rem a in 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 ma jor environmental concern posed by repairing the leak in that m a nner. If not repaired within 15 days by other means, ExxonMobil shall perform the first “drill and tap” (or equivalent repair m e thod) within 15 days, and a second attem p t (if necessary) within 30 days after the leak is detected. After two unsuccessful attemp ts to repair a leaking valve through the “drill and tap” (or equivalent) me thod, ExxonMobil m a y place the leaking valve on its “delay of repair” list. The requirem e nt to m a ke two attem p ts to repair a leaking component by the drill and tap m e thod m a y be satisfied by m a king two sealant injection attem p ts rather than by m a king m u ltiple taps into the valve body. b. If a new valve repair m e thod not currently in use by the refining industry is planned to be used by ExxonMobil in lieu of the “drill and tap” m e thod referenced in the

111preceding Subparagraph, ExxonMobil shall advise EPA prior to implementing such a m e thod 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 . W ith EPA’s prior written approval,
ExxonMobil m a y begin using an alternate leak detection m e thod – such as a m e thod employing
“Sm a rt LDAR” technology – based on a showing that the alternate leak detection m e thod is equivalent to traditional monitoring m e thods and is allowable under the applicable LDAR regulations. If necessary to implement this Paragraph, the Parties shall m a ke appropriate

m odifications to this Consent Decree in accordance with Paragraph 269.
133. Recordkeeping and Reporting Requirements for this Section

. a. In the Sem i -Annual Reports submitted by ExxonMobil pursuant to Section IX (Recordkeeping and Reporting), ExxonMobil shall include the following information in the Report f o r 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 perform a nce as required by Paragraph 119;

112iv. A certification that the lower leak def i nitions and increased monitoring frequencies have been implemented according to Paragraphs 122 and 123;

v. A certification of the implementation of the “initial attemp t” 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 Requirem e nt for Initial Sem i -Annual Report Each Year

. As part of the first Sem i -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 sum ma ry 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. t he number of valves and pumps found leaking for each process unit; v. the number of “difficult to monitor” pieces of equipment monitored;
vi. t he projected month and year of the next monitoring event f o r that unit;

113vii. 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 attem p ted within f i ve (5) days and thirty (30) days pursuant to Subparagraph 124.b;
ix. t he number of initial attem p ts at repair not m a de promptly and remonitored within five (5) days pursuant to Paragraph 126;

x. the number of repairs not com p leted at the next process unit turnaround pursuant to Paragraph 131; and
xi. t he number of repairs not com p leted 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 W a stewater Treatm e nt Plant Area Program Requirem e nts

. ExxonMobil shall com p ly with the Joliet W a stewater Treatm e nt Plant Area Program requirem e nts 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

ma nagem e nt of oil-bearing hazardous secondary ma terials subject to 40 C.F.R. § 261.4(a)(12) and Ill. Adm i n. Code tit. 35, § 721.104(a)(12)(A) , and shall not use the Material Staging Area for treatm e nt, storage or disposal of m a terials that meet the definition of hazardous waste under 40 C.F.R. § 261.3 and Ill. Adm i n 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. Adm i n. Code tit. 35, § 721.104(a)(12)(A), oil-bearing hazardous secondary m a terials transferred to the Material

114Staging Area shall not be placed on the land and shall not be accum u lated 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. Wh enever the bays are cleaned, ExxonMobil shall inspect the areas around the Material Staging Area to confirm that oil-bearing hazardous secondary m a terials have not been released from the Material Staging Area. d. As provided by 40 C.F.R. § 261.4(a)(12) and Ill. Adm i n. Code tit. 35, § 721.104(a)(12)(A), any residuals generated from processing or recycling oil-bearing hazardous secondary m a terials at the Material Staging Area that are disposed of or intended for disposal shall be designated and m a naged as F037 listed wastes when they are removed from the Material Staging Area. If any oil-bearing hazardous secondary m a terials are released from the Material Staging Area and not im me diately recovered for use in a refining process, then ExxonMobil shall designate and m a nage such released m a terials as F037 listed wastes. e. If ExxonMobil uses the Material Staging Area for m a nagem e nt of waste

ma terials that do not meet the definition of hazardous waste under 40 C.F.R. § 261.3 and Ill. Adm i n Code tit. 35, § 721.103, then ExxonMobil shall segregate such waste m a terials and shall

not com mi ngle such waste m a terials with any oil-bearing hazardous secondary m a terials. f. ExxonMobil shall establish and implement written procedures designed to ensure that the Material Staging Area is used only for m a nagem e nt of m a terials described in Subparagraphs 135.a and 135.e. The procedures shall include use of a written form to document all m a terial transfers to the Material Staging Ar ea, including an indication of the m a terial type, the m a terial quantity, the source of the m a terial, the request and authorization dates, and the

115nam e s of the requester and the individual authorizing the transfer at the Joliet Refinery (“Material Staging Area Transfer Forms”). W ith each W WT P Area W a stewater Monitoring Plan Quarterly Report required under Paragra ph 4 of Consent Decree Appendix P, ExxonMobil shall include a copy of each Material Staging Area Transfer Form com p leted and used for the transfer of m a terial to the Material Staging Area during that quarterly period. W ith the W W TP
Area W a stewater Monitoring Plan Final Report, ExxonMobil shall include a copy of each Material Staging Area Transfer Form com p leted and used for the transfer of m a terial 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. Adm i n. Code tit. 35, § 721.102(f), ExxonMobil shall m a intain appropriate documentation demonstrating that oilbearing hazardous secondary m a terials are being m a naged in the Material Staging Area in accordance with all requirem e nts imposed by 40 C.F.R. § 261.4(a)(12) and Ill. Adm i n. Code tit. 35, § 721.104(a)(12)(A).
136. Joliet RCRA Training Requirem e nts

. By no later than the Entry Date, ExxonMobil shall provide to EPA for review and com me nt 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 m a nagem e nt at the Joliet Refinery; ii. Com p letion 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 Ref i nery to ensure that contractors who perform work at the Joliet Refinery that involves the m a nagem e nt of hazardous waste have had RCRA training.

116137. Billings Refinery Scrap Yard and Laydown Areas

.

a. W ithin 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 W a ste Managem e nt Units and/or Areas of Concern under the current Billings Refinery RCRA permit (Montana Hazardous W a ste Permit, MTHWP-99-02). Pursuant to the Montana adm i nistered RCRA program ExxonMobil shall com p lete 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 perform i ng necessary

rem e diation, 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 W a ste Managem e nt Units and/or Areas of Concern; and (2) any subsequent corrective action at the Scrap Yard and the Laydown Areas. The inf o rmation shall be submitted to EPA at the sam e time the inf o rmation is submitted to the Applicable Co-Plaintif f.

c. W ithin 90 days of the Entry Date, ExxonMobil shall propose to EPA for review and approval modif i cations to its Billings Storm w ater 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 com p rehensive list of the types of m a terial that m a y be placed in Scrap Yard and Laydown Areas; and iii. Assigning direct responsibility for com p liance with the new standard operating procedures regarding the Scrap Yard and the Laydown Areas and for all other SWPPP elements to an ExxonMobil employee.

117W ithin 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 Treatm e nt Unit . W ithin 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 W a ste Permit, MTHWP-99-02) related to waste application at the Land Treatm e nt Unit (the preci se location and area of the Land Treatm e nt 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 Treatm e nt Unit when either: (1) the average hourly wind speed exceeds 10 mph for any 15 consecutive m i nute period, or (2) when m a xim um daily gusts exceed 20 mph for a 5 consecutive mi nute period; provided , however that waste application m a y be resum e d if the conditions in (1) and (2) have not occurred for a period of 60 consecutive m i nutes prior to the time of resum p tion of waste application; ii. A requirem e nt to m a intain a system capable of m easuring and transmitting wind conditions at the Refinery to ExxonMobil personnel necessary for com p liance with the prohibition set forth in Subparagraph 138.i; and iii. Standard operating procedures to assure com p liance with the soil m o isture requirem e nts applicable to the Land Treatm e nt Unit (Montana Hazardous W a ste Permit, MTHWP-99-02, Section III.a.E.7). 139. Billings Refinery Outfall 002

.

a. W ithin 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;

118ii. Requirem e nts for m a intaining 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

m odifications, ExxonMobil shall within 60 days submit an application to the Applicable CoPlaintif f to include the modif i cations in the Billings Ref i nery 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 m a terial in Billings Refinery Tank 350 using trucks or other non-piped m e thods (“Non-Piped Tank 350 Inflow”). b. W ithin 90 days of the Entry Date, ExxonMobil shall propose to EPA for review and approval a draft amendment to its Billings Ref i nery 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 Ref i nery MPDES permit. d. W ithin 90 days of the Entry Date, ExxonMobil shall submit to EPA a description of how wastewaters and/or other ma terial that currently are Non-Piped Tank 350
Inf l ow will be m a naged at the Billings Ref i nery.

119Q. 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 adm i nistratively com p lete applications to the applicable federal, state or local agency to incorporate the emission limits and standards, including NSPS applicability, required by this Consen t Decree that are effective as of the Entry Date into federally-enforceable m i nor or m a jor 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 com p lete permit applications (or, for the Baton Rouge Refinery, following submissi on 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 inf o rmation that the applicable agency seeks following its receipt of the permit m a terials. Promptly upon issuance of such permits or in conjunction with such permitting, ExxonMobil shall file any applications necessary to incorporate the requirem e nts of those permits into the Title V permit f o r 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

120standard under Section V that becom e effective after the Entry Date, ExxonMobil shall submit adm i nistratively comp lete applications to the applicable federal, state or local agency to incorporate that emission limit or standard into federally-enforceable m i nor or m a jor new source review permits or other permits that will ensure that the underlying emission limit or standard survives the termination of this Consent Decr ee 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 becom e ef f

ective after the Entry Date shall survive the termination of this Consent Decree in accordance with Paragraph 145. Following submission of the com p lete permit applications (or, for the Baton Rouge Refinery, following submission of appropriate applications, amendments, or supplements), ExxonMobil shall cooperate with the applicable fe deral, 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 m a terials. Promptly upon issuance of such permits or in conjunction with such permitting, ExxonMobil shall file any applications necessary to incorporate the requirem e nts of those permits into the Title V permit f o r the relevant Covered Ref i nery. 143. Emission Limits and Standards . The following Consent Decree requirem e nts 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

121ii. the requirem e nts 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 requirem e nts of this Consent Decree into T itle V permits shall be in accordance with state Title V rules, including applicable adm i nistrative amendment provisions of such rules.
145. Obligations that Shall Survive Consent Decree Termination

. The requirem e nts 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 requirem e nts shall constitute emission limits and standards that shall survive termination of the Consent Decree by virtue of being incorporated into federally-enforceable permits: (1) S ubparagraphs 13.b, 14.b, 15.d, 16.c, 17.b, 18.b, 19.b, and Paragraph 21in Subsection V.B; (2) S ubparagraphs 23.b, 24.b, 25.b, 26.b, 27.b, 28.b, 29.b, and Paragraph 32 in Subsection V.C; (3) P aragraphs 34 and 35 (if applicable as of the date of termination) in Subsection V.D; (4) P aragraphs 39, 40 (if applicable as of the date of termination), and 42 in Subsection V.E; (5) P aragraph 43 and 44 in Subsection V.F; (6) P aragraphs 52, 53 and 54 in Subsection V.G; (7) S ubparagraphs 59.a and 59.b and Paragraph 60 in Subsection V.H;

122(8) P aragraphs 63 and 64, Subparagraph 67.e, and Paragraph 69 in Subsection V.I; and (9) P aragraphs 70, 71, and 73 in Subsection V.J. b. Certain Other Requirem e nts (1) S ubparagraph 65.a (as specified therein) in Subsection V.I; (2) P aragraph 79 (as specified therein) and Subparagraph 91.a (as specified therein) in Subsection V.K; (3) P aragraph 92 (as specified therein) in Subsection V.L; (4) A ll of this Subsection V.Q; and (5) A ll of Section VI.

c. Agreement Required for Changes to Surviving Requirem e nts

. 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 requirem e nts surviving termination pursuant to Subparagraph 145.b, such requirem e nt shall not be deleted or modified unless EPA and the Applicable Co-Plaintif f shall have f i rst agreed in writing to the deletion or modif i cation.
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 m u st submit permit applications for construction or installation to an applicable

123state 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 inf o rmation 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 emissi ons 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 com p liance with Tier II gasoline or low sulfur diesel requirem e nts; and (2) the emissions f r om those modif i ed 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, SO 2 , PM, VOC, or CO emissions reductions, or apply fo r 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, m a jor non-attainm e nt and/or synthetic m i nor New Source Review (“NSR”) permit or permit proceeding. 149. Exception to General Prohibition . Notwithstanding the general prohibition set forth in Paragraph 148, ExxonMobil m a y use 186 tons per year of NOx, 240 tons per year of
SO 2 , 38 tons per year of PM, 44 tons per year of CO, and 5 tons per year of H 2 SO 4 , from the CD Emissions Reductions as credits or offsets in any PSD, m a jor non-attainm e nt and/or synthetic

124mi nor NSR permit or permit proceeding occurring after the Date of Lodging of the Consent Decree, provided that the new or modif i ed emissions unit: (1) is being constructed or modif i ed for purposes of com p liance with Tier II gasoline or low sulfur diesel requirem e nts; 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 SO 2 corrected to 0% O 2 both on a 3-hour rolling average; iii. For heaters and boilers, no Fuel Oil burning or solid f u el f i ring capability; iv. F or FCCUs, a limit of 20 ppmvd NOx corrected to 0% O 2 or less on a 365-day rolling average basis;

v. For FCCUs, a limit of 25 ppmvd SO 2 corrected to 0% O 2 or less on a 365-day rolling average basis; and vi. F or 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 m a y be used only at the Covered Refinery that generated them ; iii. The CD Emissions Reductions provisions of this Consent Decree are f o r purposes of this Consent Decree only and neither ExxonMobil nor any other entity m a y use CD Emissions Reductions for any purpose, including in any subsequent permitting or enforcement proceeding, except as provided herein; and iv. E xxonMobil still shall be subject to all federal and state regulations applicable to the PSD, m a jor non-attainm e nt and/or m i nor NSR permitting process.
150. Outside the Scope of the General Prohibition . Nothing in this Consent Decree is intended to prohibit ExxonMobil from seeking to:

125i. utilize or generate netting reductions or emission of fs et credits f r om ref i nery 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 f o rth in or established pursuant to this Consent Decree for these refinery units and the m o re stringent emissions limitations that ExxonMobil m a y elect to accept for these refinery units in a permitting process; ii. utilize or generate netting reductions or emission of fs et credits f o r ref i nery units that are not subject to an emission limitation pursuant to this Consent Decree; iii. utilize or generate netting reductions or emission of fs et credits f o r 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 com p liance with the requirem e nts of Paragraphs 15.c, 47, or 50 of this Consent Decree; iv. u tilize emissions reductions f r om 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 sam e time and is permitted as a single project triggers m a jor New Source Review requirem e nts;

v. utilize CD Emission Reductions f o r a Covered Ref i nery’s com p liance with any rules or regulations designed to address regional haze or the non-attainm e nt status of any area (excluding PSD and Non-Attainm e nt 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. u tilize any emission reduction credits recognized under two permits previously issued to ExxonMobil, nam e ly: (1) the Baton Rouge Refining Clean Air Com m itment PSD-LA-667(M-1) and Catalytic Cracking Permit Num b er 2385-V1; and (2) the IEPA Construction Permit for the Joliet Coker Blowdown Recovery Project (Application Num b er 03060091).
VII. MODIFICATIONS TO IMPLEMENTATION SCHEDULES
151. Modifications Relating to Securing Permits or Approvals (in States Where Permits are Characteriz e d as “Approvals”) .

a. Tim e ly Submitting Com p lete Permit Applications and Exercising Best Effort s . For any work under Sections V or VIII of this Consent Decree that requires a federal,

126state 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 fe deral, state and local permits and approvals f o r work and activities required so that permit or approval decisions can be m a de 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 com p ly with all applicable requirem e nts; 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 governm e ntal entity to act upon a timely-submitted, com p lete permit application m a y delay ExxonMobil’s perform a nce 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 af f

ect its ability to comp ly with the implementation schedule set f o rth 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 com p ly 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

m odifications of schedules of implementation if the requirem e nts of this Paragraph 151 are m e t.

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

m odif i cation to a date or dates then: (i) EPA and the Applicable Co-Plaintif f will retain the right to seek stipulated penalties; and (ii) ExxonMobil will retain the right to dispute any dem a nd for stipulated penalties, pursuant to Paragraph 215.

127d. Force Majeure Inapplicable

. The failure of a governm e ntal entity to act upon a timely-submitted permit or approval application shall not constitute a force ma jeure event triggering the requirem e nts of Section XIV; instead, this Paragraph 151 shall apply.
152. Modifications Relating to Securing EPA Approval under this Consent
Decree . a. For requirem e nts of this Decree where ExxonMobil is prohibited from

com me ncing an action prior to receiving EPA approval, ExxonMobil will use its best efforts to submit m a terials that comp ly with all applicable requirem e nts 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 perform a nce 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

m odification(s) required by this Subparagraph, stipulated penalties will not accrue for the period up to and including the earlier of : (i) the modif i ed 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 requirem e nts 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 com me nce and continue with such subsequent actions even without receipt of EPA approval. If, during th e course of such continuing ExxonMobil actions, EPA disapproves in whole or in part of the m a nner in which ExxonMobil has proceeded, extensions of all relevant deadlines m a y result by agreement of the parties. Stipulated penalties will not accrue nor be due and owing during any period between a scheduled implementation

128date 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 dem a nd for stipulated penalties, pursuant to Paragraph 215.

c. Force Majeure Inapplicable

. The failure of EPA to provide a required approval in a timely m a nner will not constitute a f o rce ma jeure event triggering the requirem e nts 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 com p liance with any deadline or the perform a nce of any work described in Sections V and VIII of this Consent Decree that requires the acquisition and installation of control equipment, including SO 2 Reducing Catalyst Additive or NOx Additives. b. Notification

. If it appears that the com me rcial unavailability of any control equipment m a y delay ExxonMobil’s perform a nce 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 af

f

ect its ability to com p ly with the implementation schedule set f o rth 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 com m unication to EPA) f r om the vendor that the equipment or additive is com me rcially unavailable.

c. Additional Notice Requirem e nts and Requirem e nts Relating to Contacting Vendors

. ExxonMobil shall propose for approval by EPA a modification to the applicable

129schedule of implementation, refer to this Para graph 153 of this Consent Decree, identify the

m ilestone date it contends it will not be able to meet, provide EPA and the Applicable CoPlaintiff with written correspondence to the vendor identifying efforts m a de 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 m a y propose a modified schedule or modification of other requirem e nts of this Consent Decree to address such

com me rcial unavailability. d. Dispute Resolution

. Section XV (Retention of Jurisdiction/Dispute Resolution) shall govern the resolution of any cl aim of com me rcial 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 requirem e nts of this Paragraph are m e t.

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

m odif i cation to a date or dates then: (i) EPA and the Applicable Co-Plaintif f will retain the right to seek stipulated penalties; and (ii) ExxonMobil will retain the right to dispute any dem a nd 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 f o rce ma jeure event triggering the requirem e nts of Section XIV; instead, this Paragraph shall apply.

130154. Procedures for Modifying Implementation Schedules under this Section VII

. Any modifications to implementation schedules under this Section VII shall be m a de in accordance with Paragraph 269.
VIII. ENVIRONMENTALLY BENEFICIAL PROJECTS 155. In accordance with the requirem e nts 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 m a y 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 “Sm a rt LDAR Project”). (1) W ithin 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) com p arative monitoring, to com p are 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 m a ss of VOC emissions from one or m o re leaking components monitored with a Smart LDAR imaging camera. The plan shall also include a description of the project’s overall

131objective(s), the procedures to be followed, a project budget (detailing expected equipment costs, laboratory costs, and contractor costs), and a schedule for perform i ng and com p leting the project. (2) U pon 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 perform i ng 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 m o re prairie habitat restoration projects at the Midewin National Tallgrass Prairie that will require in-kind contributions and expenditures of $1,050,000 or m o re, as described by this Subparagraph 156.d. (1) B y 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 approxim a tely 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 m a naged by the U.S. Departm e nt of Agriculture, Forest Service. ExxonMobil m a y condition the donation upon the United States’ acceptance of the Property subject to the following deed restrictions: “The land shall only be used and m a naged 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

132associated 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 com me rcial development.” (2) T he 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) W ithin 120 days prior to the proposed date of closing, ExxonMobil will provide the Forest Service with all available environmental studies and rem e diation 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,

ma intenance or similar records relating to the Property. (4) T he 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) I f 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) E xxonMobil shall enter into a separate written agreement with the U.S. Departm e nt of Agriculture, Forest Serv ice or its contractors or assignees, pursuant to 16 U.S.C. § 579(c) or other available authorities, for perform a nce of prairie habitat

133restoration, protection, preservation, or ac quisition work at the Midewin National Tallgrass Prairie by no later than December 31, 2009. ExxonMobil shall spend at least $250,000 for perform a nce 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) = R equired 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 m a naged 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 com me rcial development.

e. W ill County Emergency Managem e nt 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 m a terials vehicles, radio equipment, and protective suits) for the Will County Emergency Managem e nt Agency. The Will County Emergency Managem e nt Agency serves as the Local Emergency Planning Com m ittee for the area near ExxonMobil’s Joliet Refinery. f. Billings Ref i nery 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 atm o spheric pressure release valves (“PRVs”) at the

134Billings Refinery, at a cost of no less than $1,500,000 (the “PRV Project”). ExxonMobil shall develop and satisfactorily com p lete the PRV Project as described by the following Subparagraphs. (1) B y no later than 365 days after the Entry Date, ExxonMobil shall

com p lete 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 m i ght be emitted during a release incident at each such PRV, (iii) assess the recent history of releas es (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 treatm e nt systems, flare gas recovery systems, and/or flares. (2) B y 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) sum ma rize 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 m e asures to control hydrogen sulfide emissions from episodic releas es 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).

135(3) E xxonMobil shall implement the PRV Project Plan as approved by EPA and MDEQ, and shall operate and m a intain the hydrogen sulfide emission controls installed as part of the PRV Project .
g. Joliet Refinery Heater Firing Reduction Project

. (1) B y no later than December 31, 2009, ExxonMobil shall install air control technology (including burner m a nage me nt 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 (“CO 2 ”) 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 CO 2 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) E xxonMobil m a y request that EPA and IEPA approve the substitution of another heater or boiler located at the Joliet Ref i nery f o r 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 CO 2 emissions of at least 2000 tons. If EPA and IEPA approve a substitution, ExxonMobil shall not use emission reductions f r om the substitute heater or boiler to com p ly with Subsection V.G of this Decree. 157. ExxonMobil shall include in each Sem i -Annual Report required by Section IX, a progress report for SEPs specified by Paragraph 156. In addition, the first Sem i -Annual Report that is submitted after December 31, 2009 (or after any extended deadline for the perform a nce of

136the SEPs) shall contain the f o llowing inf o rmation with respect to the SEPs specif i ed by Paragraph 156: i. A detailed description of each such SEP as implemented; ii. A brief description of any significan t operating problems encountered, including any that had an impact on the environment, and the solutions for each problem ; iii. A sum ma ry of the costs ExxonMobil incurred in perform i ng the SEPs specified by Paragraph 156; iv. C ertification that the project has been f u lly 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 com p letes 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 dem a nd for payment is m a de at any time by EPA; ii. use the difference to fund an increase in the scope and/or budget of one or m o re 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-m a terial m odification 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 m a terial m odification to the Consent Decree under Paragraph 269. 159. State of Louisiana Beneficial Environmental Projects

. As a term and condition of the settlem e nt 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

137thirty (30) days of the Entry Date in order to fund perform a nce of one or m o re BEPs under La. Adm i n. Code tit. 33, I Chapter 25. In the first Sem i -Annual Report that is required by Section IX, ExxonMobil shall confirm whether that payment was m a de as required by this Paragraph 159. LDEQ has agreed that the Louisiana W ildlife 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 m a kes or causes to be m a de regarding the SEPs or BEPs, ExxonMobil m u st clearly indicate that these projects are being undertaken as part of the settlem e nt of an enforcement action for alleged violations of the Clean Air Act and corollary state statutes.
IX. RECORDKEEPING AND REPORTING 161. ExxonMobil shall submit Sem i -Annual Reports to EPA and the Applicable Co-Plaintif f that contain the f o llowing inf o rmation: i. a progress report on the implementation of the requirem e nts of Section V (Af fi rmative Relief ) at the Covered Ref i neries; ii. a sum ma ry 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 requirem e nts of Section V of this Consent Decree at the Covered Refineries; iv. a progress report on the implementation of the requirem e nts of Section VIII (Environmentally Beneficial Projects);

v. any such additional m a tters as ExxonMobil believes should be brought to the attention of EPA and the Applicable Co-Plaintif f; and vi. a dditional item s required by another Paragraph of this Consent Decree to be submitted with a Sem i -Annual Report.

138Sem i -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 Sem i -Annual Report shall be certified by: (i) the person responsible for environmental m a nagem e nt and com p liance 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 m y direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on m y directions and m y inquiry of the person(s) who m a nage the system, or the person(s) directly responsible for gathering the information, the information submitted is, to the best of m y knowledge and belief, true, accurate, and com p lete.
X. CIVIL PENALTY
162. Civil Penalty .

a. W ithin 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 m a de by Electronic Funds Transfer ("EFT") to the United States Departm e nt of Justice, in accordance with current EFT procedures, referencing DOJ Case Num b er 90- 5-2-1-07030 and the civil action case nam e 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 m a de in accordance with instructions provided to ExxonMobil by the Financial Litigation Unit of the U.S. Attorney' s Office for the Northern

139District of Illinois. Any funds received afte r 11:00 a.m

. (EST) shall be credited on the next business day. ExxonMobil shall provide notice of payment, referencing DOJ Case Num b er 90-5-2-1-07030 and the civil action case nam e and case number to the Departm e nt 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 m a de as follows: (1) $100,000 shall be paid by certified or corporate check payable to the Illinois Environmental Protection Agenc y, or by an electronic funds transfer, fordeposit into the Illinois Environmental Protection Trust Fund, and shall be sent by firstclass m a il (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 nam e and number of the case and ExxonMobil Oil Corporation’s Federal Employer Identification Num b er (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 W e st Randolph Street, 20 th Floor Chicago, IL 60601 and

140Maureen W o zniak Assistant Counsel Illinois EPA 1021 North Grand Avenue East Springfield, IL 62794-9276 (2) T he 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, desi gnated 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 nam e and number of the case and ExxonMobil Oil Corporation = s Federal Employer Identification Num b er (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 W e st Randolph Street, 20 th Floor Chicago, IL 60601 and
Maureen W o zniak 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

141environmental protection, enhancement and education activities in Illinois. The check shall be delivered to the f o llowing address: Environmental Bureau Office of the Illinois Attorney General 188 W e st Randolph Street, 20 th Floor Chicago, IL 60601 The nam e and number of the case and ExxonMobil Oil Corporation’s Federal Employer Identification Num b er (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 m a de by certified check m a de payable to the Louisiana Departm e nt of Environmental Quality and sent to Darryl Seri o, Fiscal Director, Of fi ce of Managem e nt 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 m a de by certified or corporate check m a de payable to the State of Montana and sent to the following address: John L. Arrigo Adm i nistrator, Enforcement Division Montana Departm e nt 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 incom e taxes imposed under federal, state, or local law.

142164. 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 Pr ocedure Act, 28 U.S.C. §§ 3001-3308, and other applicable f e deral 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 ExxonMob il to com p ly 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 f o r f a ilure to com p ly with the concentration-based, rolling average emission limits referenced in Section V shall not start to accrue until there is noncompliance for 5% or m o re 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-com p liance is available, the decision of which alternative to seek shall rest exclusively within the discre tion of the EPA and the Applicable Co-Plaintif f. For the purposes of this Section XI, the term “economic benefit of non-com p liance” means the economic benefit accrued from delaying a capital investm e nt, delaying a one-time expenditure, and avoiding recurring costs (such as operation and m a intenance costs) over the period of

non-com p liance. The overall “economic benefit of non-com p liance” will be calculated based on the total number of days of non-com p liance, and will be m u ltiplied by 1.2 to compute the total stipulated penalty amount under a particular provisi on of this Section XI. That total stipulated penalty amount will be assessed for the full period of non-com p liance, and will not be assessed

143“per day.” In no event shall any stipulated penalty assessed against ExxonMobil exceed $32,500 (or any inflation-adjusted increase in that m a xim um penalty amount set pursuant to the Federal Civil Penalties Inflation Adjustm e nt Act of 1990, as amended by the Debt Collection Improvem e nt Act of 1996) per day for any individual violation of this Consent Decree.

c. Wh ere a single event triggers m o re 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 sti pulated penalties under this Consent Decree and

com me ncing 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 rem e dies 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-com p liance with a specific Consent Decree requirem e nt.

144A. Requirements for NO X 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 com p ly with any of the Baton Rouge and Beaumont NOx
Minim i zation Studies requirem e nts specified by Paragraph 15, including submission of required reports, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $1,000 31 st through 60 th day after deadline $1,500 Beyond 60 th day after deadline $2,000, or an amount equal to 1.2 times the economic benefit of non-com p liance 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 re quired by Subparagraph 16.b or 16.c, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $1,000 31 st through 60 th day after deadline $1,500 Beyond 60 th day after deadline $2,000, or an amount equal to 1.2 times the economic benefit of non-com p liance whichever is greater 169. For failure to install, certify, calibrate, m a intain, and/or operate a CEMS, as required by Paragraph 21, per day, per CEMS:

145Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 31 st through 60 th day after deadline $1,000 Beyond 60 th day after deadline $2,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater.
B. Requirements for SO 2 Emission Reductions from the FCCUs . 170. For each failure to meet any FCCU Final SO 2 Limit set f o rth 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 com p ly with any of the Particular Requirem e nts for the Billings FCCU: Conversion to Full Burn Operation and Two-Step SO 2 Reducing Catalyst Additive Program, as set forth in Paragraph 30, including submission of required reports, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $1,000 31 st through 60 th day after deadline $1,500 Beyond 60 th day after deadline $2,000, or an amount equal to 1.2 times the economic benefit of non-com p liance whichever is greater 172. For failure to install, certify, calibrate, m a intain, and/or operate a CEMS, as required by Paragraph 32, per day, per CEMS: Period of Non-Com p liance 1 st

through 30 th day after deadline 31 st through 60 th day after deadline Beyond 60 th day after deadline Penalty per day $500 $1,000 $2,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater.

146C. Requirements for PM Emissions Reductions from the FCCUs . 173. For each failure to meet any FCCU Final PM Limit that ExxonMobil acceptspursuant to Paragraph 35 (if applicable), per day, per FCCU: $500 for the first day of noncomp liance in which the specified short-term rolling average exceeds the applicable limit, and $1,500 for each day thereafter until ExxonMobil demonstrates com p liance with the applicable limit. 174. For failure to conduct PM testing, as required by Paragraph 37, per day, per
FCCU: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $200 31 st through 60 th day after deadline $500 Beyond 60 th 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, m a intain, and/or operate a CEMS, as required by Paragraph 42, per day, per CEMS: Period of Non-Com p liance 1 st

through 30 th day after deadline 31 st through 60 th day after deadline Beyond 60 th day after deadline Penalty per day $500 $1,000 $2,000, or, an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater.

147E. Requirements Related to NSPS Applicability to FCCU Regenerators . 177. For failure to com p ly 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-Com p liance Penalty per day 1 st

through 30th day $1,000 31 st through 60 th day $2,000 Over 60 days $3,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 178. For failure to com p ly with any of the Particular Requirem e nts Applicable to the Baton Rouge FCCUs specified by Subparagraphs 44.b and 44.c: $3,000 per day of

non-com p liance, or an amount equal to 1.2 times the economic benefit of non-com p liance, 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-Com p liance Penalty per day 1 st

through 30 th day after deadline $2,500 31 st through 60 th day after deadline $6,000 Beyond 60 th day after deadline $10,000, or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 180. For failure to com p ly with the applicable monitoring requirem e nts as set forth in Paragraphs 53 and 54, per Combustion Unit, per day:

148Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 31 st through 60 th day after deadline $1,000 Beyond 60 th day after deadline $2,000, or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 181. For failure to submit the written deliverables required by Paragraph 49, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $200 31 st through 60 th day after deadline $500 Beyond 60 th day after deadline $1,000 G. Requirements for SO 2 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 Combus tion Device (listed in Appendix D) any refinery fuel gas in violation of the applicable requi rem e nts 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 becom e s 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-Com p liance Penalty per day 1 st

through 30th day $2,500 Beyond 31 st day $5,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 183. For burning Fuel Oil in a m a nner inconsistent with the requirem e nts of Paragraph 60, per device, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day $1,750 Beyond 31 st day $5,000

149H. Requirements for Sulfur Recovery Plants

. 184. For failure to com p ly 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-Com p liance Penalty per day 1 st

through 30th day $1,000 31 st through 60 th day $2,000 Over 60 days $3,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 185. For failure to com p ly with NSPS Subparts A and J monitoring requirem e nts at a Sulfur Recovery Plant listed in Paragraph 63, as specified in Subparagraph 64.b, per day, per
SRP: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 Beyond 31 st day after deadline $1,500 Beyond 60 th 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-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 Beyond 31 st day after deadline $1,500 Beyond 60 th day after deadline $2,000
187. For failure to com p lete the Baton Rouge and Joliet optimization studies and reports as required by Paragraph 66, per Refinery, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 Beyond 31 st day after deadline $1,500 Beyond 60 th day after deadline $2,000

150188. For failure to com p ly with any of the Particular Requirem e nts for Baton Rouge FCCUs specified by Subparagraphs 67.a - 67.d: $3,000 per day of non-com p liance, or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 189. For failure to com p ly with an Interim Perform a nce Standard applicable to the Joliet East Claus Train or the Joliet W e st Claus Train under Subparagraph 68.b, per day: Period of Non-Com p liance Penalty per day 1 st

through 30th day $1,000 31 st through 60 th day $2,000 Over 60 days $3,000 or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater. 190. For failure to m a nage all sulfur pit emissions in accordance with the requirem e nts of Paragraph 69, per day, per Refinery: Period of Non-Com p liance Penalty per day 1 st

through 30 th day $1,000 31 st through 60 th day $1,750 Beyond 60 th day $4,000 or an amount equal to 1.2 times the economic benefit of non-com p liance whichever is greater. I. Requirements for Flaring Devices . 191. For failure to com p ly with the requirem e nt in Paragraphs 71 and 73 that an NSPS Flaring Device comp ly with the com p liance m e thod specified in Appendix G, by the date specified in Appendix G, per day, per device: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $500 Beyond 31 st day after deadline $1,500 Beyond 60 th 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.

151J. 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 Com me ncement of Flaring within the Flaring Incident to Termination of Flaring within the Flaring Incident is 3 hours or less; Length of Tim e 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 Com me ncement 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 Tim e of the Tail Gas Incident is greater than 3 hours but less than or equal to 24 hours Length of Tim e of Flaring within the Flaring Incident is greater than 24 hours; Length of Tim e 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 m a trix 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 fo r 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 colum n in the table set forth in this Paragraph applies under circumstances in which flaring occurs intermittently during an

152AG Flaring Incident, the flaring shall be deemed to com me nce at the time that the flaring that triggers the initiation of an AG Flaring Incident com me nces, 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 In cident that (i) starts at 1:00 p.m. on Day 1 and ends at 1:30 p.m. on Day 1; (ii) recom me nces at 4:00 p.m. on Day 1 and ends at 4:30 p.m. on Day 1; (iii) recom me nces at 1:00 a.m

. on Day 2 and ends at 1:30 a.m

. on Day 2; and (iv) f or 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 colum n 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 requirem e nts: Period of Non-Com p liance 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 pursuan t 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 fo llows:

153i. Period of Non-Com p liance 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 com p lete 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 m a y agree in writing): Period of Non-Com p liance 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-Com p liance 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 Com p liance Review, submit a
CERCLA/EPCRA Com p liance Review Report, or perform corrective actions, as required by Paragraph 95, per refinery:

154Period of Non-Com p liance 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-Com p liance 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 m o st 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 f a ilure to com p lete a BWON Com p liance Review and Verif i cation 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 com p liance as required by Subparagraphs 101.c and 101.d, per refinery: Period of Non-Com p liance 1 st

through 30 th day after deadline 31 st through 60 th day after deadline Beyond 60 th day Penalty per day $1,250 $3,000 $5,000, or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater.

155c. For failure to com p ly with the requirem e nts set forth in Paragraph 102 related to the use, monitoring, and replacement of carbon canisters: $1,000 per incident of

non-com p liance, per day. d. For failure to implement the training requirem e nts 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 m a intain any plans or other deliverables required by Paragraph 107: $2,000 per deliverable.
h. For failure to conduct sam p ling in accordance with the sam p ling plans required by Paragraphs 108 or 109: $30,000 per qua rter, per stream, whichever is greater, but not to exceed $150,000 per quarter, per refinery.
i. For f a ilure 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;

156m. For failure to identify/m a rk segregated storm w ater drains as required in Subparagraph 112.b: $1,000 per week per drain not identified/m a rked as required; n. For f a ilure to submit any of the written deliverables required by Subsection V.N (except f o r those deliverables f o r which stipulated penalties are specif i ed 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-com p liance as required in Paragraph 121: Period of Non-Com p liance 1 st

through 30 th day after deadline 31 st through 60 th day after deadline Beyond 60 th day Penalty per day $1,250 $3,000 $5,000, or an amount equal to 1.2 times the economic benefit of non-com p liance, whichever is greater

157e. For f a ilure to perform m onitoring utilizing the lower internal leak rate definitions as specified in Paragraph 122: $100 per component, but not greater than $10,000 per

m onth, 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 m a ke first repair attem p ts within 5 days and/or take other actions required by Paragraph 124: $100 per co m ponent 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 f a ilure to implement the “initial attem p t” repair program set f o rth 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

ma nagem e nt as required by Paragraph 119, or for failure to implement the m a intenance tracking program required by Subparagraph 117.iv: $3,500 per week, per refinery. k. For failure to use dataloggers or m a intain 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 m i ssed event.

m. For failure to com p ly with the requirem e nts for delay of repair set forth at Paragraph 130: $5,000 per valve or pump, per incident of non-com p liance.

158n. For f a ilure to submit a written submission to EPA and/or an Applicable Co-Plaintiff as required by Subsection V.O (except where a m o re 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 f a ilure to comp ly with the requirem e nts f o r chronic leakers set f o rth at Paragraph 131: $5,000 per valve. O. Other Compliance Program Requirements for the Billings and Joliet Refineries . 201. For failure to com p ly with the following Joliet W a stewater Treatment Area Program Requirem e nts under Paragraph 134 and Appendix P: a. For failure to timely submit the W WT P Area W a stewater Monitoring Plan required by Paragraph 2 of Appendix P, or f o r submitting a W WT P Area W a stewater Monitoring Plan that does not substantially conform to the requirem e nts of this Consent Decree: Period of Non-Com p liance 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
WWT P Area W a stewater Monitoring Plan: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000

159c. For failure to timely submit a W WT P Area W a stewater Monitoring Plan Quarterly Report required by Paragraph 4 of Appendix P, or f o r submitting a W W TP Area
Wa stewater Monitoring Plan Quarterly Report that does not substantially conform to the requirem e nts of Appendix P: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000
d. For f a ilure to timely submit the W WT P Area W a stewater Monitoring Plan Final Report required by Paragraph 5 of Appendix P, or f o r submitting a W W TP Area
Wa stewater Monitoring Plan Final Report that does not substantially conform to the requirem e nts of Appendix P: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000e. For failure to meet the scheduling milestones contained in the EPAapproved W WT P Area W a stewater Monitoring Plan Final Report: Period of Non-Com p liance 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 requirem e nts of Appendix P: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000

160g. For failure to meet the scheduling milestones contained in the EPAapproved Sludge Characterization and Removal Plan: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000
h. For failure to com p ly with any requirem e nt of Paragraph 7 of Appendix P relating to Aggressive Biological Treat me nt at the Joliet Refinery EBTU: Period of Non-Com p liance 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 substantia lly conform to the requirem e nts of Appendix P: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000j. For failure to meet the scheduling milestones contained in the EPAapproved Groundwater and Soil Characterization Plan: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000
k. For f a ilure to com p ly with an ef fl uent limitation specif i ed by the Joliet Refinery NPDES Permit, as required by Subparagraph 3.a of Appendix P: (1) F or a violation of a daily m a xim u m limit: $2,000 for the first exceedance of a specified effluent limitation at a particular monitoring point;

161$4,000 for the second exceedance of the sam e specified effluent limitation at a particular m onitoring point; and $5,000 for the third exceedance and each subsequent exceedance of the sam e specified effluent limitation at a particular monitoring point. (2) F or 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 sam e specified effluent limitation at a particular m onitoring point; and $10,000 for the third exceedance and each subsequent exceedance of the sam e specified effluent limitation at a particular monitoring point. (3) Tim e 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 com p liance with that effluent limitation at that particular monitoring point as reported in its Discharge Monitoring Reports over a rolling consecutive twelve (12)

m onth period. 202. For failure to com p ly with any requirem e nt of Paragraph 135 relating to the Joliet Material Staging Area: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000

162203. For failure to timely submit the m a terials related to the Joliet RCRA Training Requirem e nts required by Paragraph 136, or for s ubmitting such m a terials required by Paragraph 136 that do not substantially conform to the requirem e nts of this Consent Decree: Period of Non-Com p liance 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 W a ste Managem e nt Units and/or Areas of Concern as required under Paragraph 137: Period of Non-Com p liance 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 Storm w ater Pollution Prevention Plan required by Subparagraph 137.c, or for submitting such m a terials required by Paragraph 137.c that do not substantially conform to the requirem e nts of this Consent Decree: Period of Non-Com p liance 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 Tr eatm e nt Unit required by Paragraph 138, or for submitting such m a terials required by Paragraph 138 that do not substantially conform to the requirem e nts of this Consent Decree: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000

163207. 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 m a terials required by Paragraph 139 that do not substantially conform to the requirem e nts of this Consent Decree: Period of Non-Com p liance Penalty per day Days 1-30 $750 Days 31-60 $1,500 Over 60 days $3,000
208. For failure to com p ly with any requirem e nt of Paragraph 140 relating to Billings Refinery Tank 350: Period of Non-Com p liance 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-Com p liance 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-Com p liance Penalty per day 1 st

through 30 th day after deadline $300 31 st through 60 th day after deadline $1,000 Beyond 60 th day $2,000

164R. Requirements for Environmentally Bene ficial Projects and Civil Penalties . 211. For failure to timely com p lete implementation of a SEP required under Section VIII, per day: Period of Non-Com p liance Penalty per day 1 st

through 30 th day after deadline $1,000 31 st through 60 th day after deadline $1,500 Beyond 60 th day $2,000
212. For failure to m a ke 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 dem a nd 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 dem a nded in escrow pursuant to Paragraph 215.
T. Payment of Stipulated Penalties . 214. ExxonMobil shall pay stipulated penalties (as required under Paragraph 165) upon written dem a nd by the United States or the Applicable Co-Plaintiff no later than sixty (60) days after ExxonMobil receives such dem a nd. Dem a nd from either the United States or an Applicable Co-Plaintiff shall be deemed a dem a nd from both, but the United States and the Applicable Co-Plaintiff shall consult with each other prior to m a king a dem a nd. 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-Plaintif f, stipulated penalties owed by

165ExxonMobil shall be paid 50 percent to the United States and 50 percent to the Applicable CoPlaintif f. Stipulated penalties shall be paid to the United States and to the Applicable CoPlaintif f in the m a nner set f o rth in Section X (Civil Penalty) of this Consent Decree. A dem a nd fo r the payment of stipulated penalties will identify the particular violation(s) to which thestipulated penalty relates, the stipulated penalty amount the United States or the Applicable CoPlaintiff is dem a nding for each violation (as can be best estimated), the calculation m e thod underlying the dem a nd, and the grounds upon which the dem a nd is based. After consultation with each other, the United States and the Applicable Co-Plaintiff m a y, in their unreviewable discretion, waive payment of any portion of stipulated penalties that m a y accrue under this
Consent Decree. U. Stipulated Penalties Dispute . 215. Should ExxonMobil dispute the United States’ and/or an Applicable Co-Plaintiff’s dem a nd for all or part of a stipulated penalty, it m a y avoid the imposition of a stipulated penalty for failure to pay a stipulated penalty under Paragraph 213 by placing the disputed amount dem a nded in a com me rcial escrow account pending resolution of the m a tter 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 rem e dies to which they are legally entitled, including but not limited to, injunctive relief for ExxonMobil’s violations of this Consent Decree.

166XII. 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 D ecree. 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

ma de 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 cr edentials, shall have a right of entry upon the premises of the facilities of any Covered Ref i nery, at any reasonable time f o r the purpose of

m onitoring com p liance with the provisions of this Consent Decree, including inspecting plant equipment, and inspecting and copying all records m a intained by ExxonMobil pursuant to the requirem e nts of this Consent Decree or in the ordinary course of ExxonMobil’s business that are deemed necessary by EPA or the Applicable Co-Pla intif f to verif y com p liance with this Consent Decree. ExxonMobil shall retain records required under this Consent Decree for the period of

167the Consent Decree. Nothing in this Consen t 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 m a y cause a delay or impedim e nt to perform a nce in com p lying 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 d iligence. In this notice, ExxonMobil shall specifically reference this Paragraph 218 of this Consent Decree and describe the anticipated length of time the delay m a y persist, the cause or causes of the delay, and the measures taken or to be taken by ExxonMobil to prevent or m i nim i ze the delay and the schedule by which those

m easures shall be implemented. ExxonMobil shall take all reasonable steps to avoid or
mi nim i ze such delays. The notice required by this Section shall be effective upon the m a iling of the sam e by certified m a il, return receipt requested, to EPA and the Applicable Co-Plaintiff as specified in Paragraph 266 (Notice). 219. Failure by ExxonMobil to substantially com p ly with the notice requirem e nts of Paragraph 218 as specified above shall render this Section XIV ( Force Majeure ) voidable by the United States, in consultation with the Applicable Co-Plaintif f, as to the specific event f o r which ExxonMobil has failed to com p ly with such notice requirem e nt, and, if voided, is of no effect as to the particular event involved.

168220. The United States, after consultation with the Applicable Co-Plaintiff, shall notify ExxonMobil in writing regarding its claim of a delay or impedim e nt to perform a nce within thirty (30) days of receipt of the force ma jeure notice provided under Paragraph 218. 221. If the United States, after consultation with the Applicable Co-Plaintiff, agrees that the delay or impedim e nt to perform a nce 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 requirem e nt(s) affected by the delay by a period equivalent to the delay actually caused by such circumstances or such other period as m a y be appropriate under the circumstances. Such stipulation shall be filed as a

m odification 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 impedim e nt to perform a nce, ExxonMobil m u st submit the m a tter to the Court f o r resolution to avoid payment of stipulated penalties, by filing a petition fo r determination with the Court. In the event the United States and the Applicable Co-Plaintif f do not agree, the position of the United States on the force ma jeure claim shall becom e the final Plaintiffs’ position. Once ExxonMobil has submitted this m a tter 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 impedim e nt to perform a nce 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

169exercise of due diligence, ExxonMobil shall be excused as to that event(s) and delay (including stipulated penalties), f o r all requirem e nts af f

ected by the delay f o r a period of time equivalent to the delay caused by such circumstances or such other period as m a y be determined by the Court. 223. ExxonMobil shall bear the burden of proving that any delay in meeting any requirem e nt(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 com p liance date based on a particular event m a y, but will not necessarily, result in an extension of a subsequent

com p liance date or dates. 224. Unanticipated or increased costs or expenses associated with the perform a nce 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 ma jeure notice or the Parties' inability to reach agreement. 226. As part of the resolution of any m a tter submitted to this Court under this Section XIV, the Parties by agreement, or the Court, by order, m a y in appropriate circumstances extend or modify the schedule for comp letion 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 impedim e nt to perform a nce agreed to by the United States or approved by this Court. ExxonMobil shall be liable f o r stipulated penalties f o r its f a ilure thereafter to com p lete the work in accordance with the extended or modified schedule.

170XV. RETENTION OF JURISDICTION / DISPUTE RESOLUTION 227. This Court shall retain jurisdiction of this m a tter 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 m a y arise under the provisions of the Consent Decree, until the Consent Decree terminates in accordance with Section XVIII (Term i nation). 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 ma jeure , provided that the Party m a king such application has m a de a good faith attem p t to resolve the m a tter with the other Party. 229. Dispute resolution shall be com me nced 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 m e eting 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

171ExxonMobil with a written sum ma ry 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

sum ma ry 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
f iling. 232. In the event that the United States and an Applicable Co-Plaintiff m a ke 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. Wh ere the nature of the dispute is such that a m o re timely resolution of the issue is required, the time periods set forth in this Section XV m a y be shortened upon m o tion 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, m a y, in appropriate circumstances, extend or

m odify the schedule for com p letion 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 com p lete the work in accordance with the extended or modified schedule.

172XVI. EFFECT OF SETTLEMENT
236. Definitions

. For purposes of this Section XVI, the following definitions apply: a. “Applicable NSR/PSD Requirem e nts” shall mean: (i) PSD requirem e nts 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 Requirem e nts for Non-Attainm e nt 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 requirem e nts 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 requirem e nts 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 Requirem e nts” shall m e an the standards, monitoring, testing, reporting and r ecordkeeping requirem e nts, found at 40 C.F.R. §§ 60.100 through 60.109 (Subpart J), relating to a partic ular pollutant and a particular affected facility, and the corollary general requirem e nts 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 W a ste NESHAP Requirem e nts” shall mean the requirem e nts imposed by the National Emission Standard for Benzene W a ste Operations, 40 C.F.R. Part 61, Subpart FF, and any applicable state, regional, or local regulations that implement, adopt or incorporate the Benzene W a ste NESHAP.

173d. “CERCLA/EPCRA Requirem e nts” shall mean the reporting requirem e nts 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 Requirem e nts” shall mean the requirem e nts relating to equipment in light liquid service and gas and/or vapor se rvice 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 requirem e nts that implement, adopt or incorporate those federal regulations. f. “Post-Lodging Com p liance Dates” shall m e an any dates in this Section XVI after the Date of Lodging (and/or after the Entry Date). Post-Lodging Com p liance 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 Comp liance Dates represent the dates by which work is required to be com p leted or an emission limit is required to be m e t under the applicable provisions of this Consent Decree.
237. Liability Resolution Regarding the Applicable NSR/PSD Requirements . W ith 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 Requirem e nts resulting from construction or m odification from the date of the pre-Lodging construction or modification up to the following dates:

174Unit Pollutant Date Baton Rouge PCLA 2 SO 2 January 1, 2006 NOx 455 days after the Entry Date Baton Rouge PCLA 3 SO 2 January 1, 2006 NOx 455 days after the Entry Date Baytown FCCU 2 SO 2 December 31, 2009 NOx June 30, 2010 Baytown FCCU 3 SO 2 Entry Date NOx June 30, 2010 Beaumont FCCU SO 2 Entry Date NOx October 1, 2009 Billings FCCU SO 2 Either: (i) March 15, 2012, if the Final SO 2 Limit is established by election of Option A under Subparagraph 29.b.(1); or (ii) the date on which a Final SO 2 Limit is established by election of Option B under Subparagraph 29.b.(2) NOx December 31, 2008 Joliet FCCU SO 2 December 31, 2008 NOx December 31, 2012
Torrance FCCU SO 2 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 SO 2 Dates listed in or derived from Appendix C All heaters and boilers other than those listed in Appendix C SO 2 Entry Date

175All Other Fuel Gas Combustion Devices listed in Appendix D SO 2 Dates listed in or derived from Appendix D
238. Conditional Resolution of Liability fo r PM Emissions Under the Applicable NSR/PSD Requirements . W ith 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 com p liance by conducting a perform a nce test representative of norm a l operating conditions for the particular FCCU, then all civil liability of ExxonMobil to the United States and to the Applicable Co-Plaintif fs shall be resolved f o r alleged viol ations of the Applicable NSR/PSD Requirem e nts relating to PM emissions at the particular FCCU resulting from pre-Lodging construction or

m odification of the particular FCCU. 239. Conditional Resolution of Liability fo r CO Emissions Under the Applicable NSR/PSD Requirements . W ith 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 com p liance 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 Requirem e nts 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% O 2 Short-term limit: 250 ppmvd CO on a 24-hour rolling average basis at 0% O 2

176240. 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 Requi rem e nts during the period between the Date of Lodging of the Consent Decree and the Post-Lodging Com p liance Dates shall be rendered void for a particular emissions unit if ExxonMobil m a terially fails to com p ly with the obligations and requirem e nts of Subsections V.B - V.E and V.G f o r that unit; provided , however , that the release in Paragraphs 237, 238, and 239, shall not be rendered void if ExxonMobil rem e dies such

ma terial f a ilure and pays any stipulated penalties due as a result of such m a terial f a ilure.
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 Requirem e nts resulting from construction or

m odification that: (i) com me nced prior to or com me nces after the Date of Lodging of the Consent Decree for pollutants or units not covered by the Consent Decree; or (ii) com me nces after the Date of Lodging of the Consent D ecree 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

177the scope of the release in Paragraphs 237, 238, and 239, and ExxonMobil m u st evaluate any such increases in accordance with th e Applicable PSD/NSR Requirem e nts. 243. Resolution of Liability Regarding Applicable NSPS Subparts A and J Requirements . W ith 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 viol ations of the Applicable NSPS Subparts A and J Requirem e nts from the date that claim s of the United States and the Applicable Co-Plaintiffs resulting from pre-Lodging construction or modi fication (including reconstruction) accrued up to the f o llowing dates: Unit Baton Rouge PCLA 2 Baton Rouge PCLA 3 Baytown FCCU 2

Baytown FCCU 3

Beaumont FCCU

Billings FCCU Pollutant
SO 2 SO 2 SO 2 PM CO Opacity
SO 2 PM CO Opacity
SO 2 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

178Joliet FCCU SO 2 December 31, 2008 PM Entry Date CO 18 months after Entry Date Opacity Entry Date Torrance FCCU SO 2 Entry Date PM Entry Date CO Entry Date Opacity Entry Date All heaters and boilers listed in Appendix C SO 2 Dates listed in or derived from Appendix C All heaters and boilers other than those listed in Appendix C SO 2 Entry Date All Other Fuel Gas Combustion Devices listed in Appendix D SO 2 Dates listed in or derived from Appendix D Baytown SRP SO 2 Entry Date Beaumont SRP SO 2 Entry Date Joliet SRP SO 2 December 31, 2008
Torrance SRP SO 2 Entry Date NSPS Flaring Devices Listed in Appendix G SO 2 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 Requirem e nts that occurred between the Date of Lodging and the Post-Lodging Com p liance Dates shall be rendered void for a particular

179emissions unit if ExxonMobil m a terially fails to com p ly with the obligations and requirem e nts 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

rem e dies such m a terial f a ilure and pays any stipulated penalties due as a result of such m a terial fa ilure.
245. Conditional Resolution of Liability for the Applicable NSPS Subparts A and J Requirements for SO 2 for the Billings FCCU . W ith respect to emissions of SO 2 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 Requirem e nts for SO 2 , and demonstrates com p liance as required by the Applicable NSPS Subparts A and J Requirem e nts for SO 2 , 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 Requirem e nts for SO 2 at the Billings FCCU catalyst regenerator resulting from pre-Lodging construc tion or modification (including reconstruction) of the Billings FCCU catalyst regenerator.
246. Resolution of Liability for Certain Potent ial 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

180Claus Train, the 200 Claus Train, and the 400 Claus Train to the TGU. Those physical changes in, and/or changes in the m e thod of operation of, and/or replacement of components are referred to collectively in this Paragraph as the “Speci fied 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-Plaintif fs fo r potential violations of the Applicable NSPS Subparts A and J Requirem e nts 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 . W ith 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 Requirem e nts for CO, and demonstrates initial

com p liance as required by the Applicable NSPS Subparts A and J Requirem e nts 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 Requirem e nts for CO at the Baton Rouge FCCUs resulting from Pre-L odging 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 . W ith 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 Requirem e nts for PM, and demonstrates initial

comp liance as required by the Applicable NSPS Subparts A and J Requirem e nts for PM, then all

181civil 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 Requirem e nts for PM at the Baton Rouge FCCUs resulting from Pre-L odging 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 . W ith 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 Requirem e nts for opacity, and demonstrates initial com p liance with the Applicable NSPS Subparts A and J Requirem e nts for opacity using an approved AMP, then all civil liability of ExxonMobil to the United States and to the Applicable Co-Plaintif f shall be resolved for alleged violations of the Applicable NSPS Subparts A and J Requirem e nts for opacity at the Baton Rouge FCCUs resulting from PreLodging construction or modification (includi ng 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 ga s 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 Regardi ng CERCLA/EPCRA Requirements for Certain Pre-Lodging Acid Gas Flaring Incidents . Upon receipt by EPA of ExxonMobil’s
CERCLA/EPCRA Com p liance Review Report submitted pursuant to Paragraph 95, this Consent Decree shall resolve all civil liability of ExxonMob il to the United States and the Applicable Co182Plaintiffs for alleged violations of CE RCLA/EPCRA Requirem e nts associated with SO 2 and H 2 S releases resulting from pre-Lodging Acid Gas Fl aring Incidents at the Baton Rouge, Baytown, Beaumont, Billings, and Joliet Refineries to the extent that ExxonMobil has identified such violations in its CERCLA/EPCRA Com p liance Re view 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 W a ste NESHAP Requirem e nts at the Covered Refineries that either: (i) com me nced and ceased prior to the Consent Decree Entry Date; or (ii) are based on events identified in the BWON Com p liance Review and Verification Report required under Pa ragraph 100 and are corrected pursuant to the requirem e nts of Paragraph 101.
250. Resolution of Liability Regarding LDAR Requirements . Entry of this Consent Decree shall resolve the civil liability of ExxonM obil to the United States and the Applicable Co-Plaintiffs for alleged violations of LDAR Requi rem e nts at the Covered Refineries that either: (i) com me nced 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 requirem e nts 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 relie f for violations by ExxonMobil of CERCLA/EPCRA

183Requirem e nts, Benzene W a ste NESHAP Require me nts, or LDAR Requirem e nts that either (i) com me nced prior to the Consent Decree Entry Date and continued after the Entry Date; or (ii) com me nced after the Consent Decree Entry Date: i. if ExxonMobil fails to identify any such violation of CERCLA/EPCRA Requirem e nts in its CERCLA/EPCRA Com p liance Review Report and correct such violation as required by Paragraph 95; ii. if ExxonMobil fails to identify any such violation of Benzene W a ste NESHAP Requirem e nts in its BWON Com p liance 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 Requirem e nts 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. Claim s Alleged in Certain EPA No tices of Violation and Findings of Violation

. Entry of this Consent Decree shall reso lve all civil liability of ExxonMobil to the United States and to the Applicable Co-Plaintif fs fo r the alleged past violations set f o rth 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 Viola tion and Finding of Violation relating to the Baton Rouge, Baytown, Beaumont, and Joliet Refineries (dated August 20, 2002). b. Additional Claim s Concerning the Billings Ref i nery . 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

184inspections 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 Ref i nery, as listed in Appendix I; (iii) alleged violations of release reporting requirem e nts 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 Claim s Concerning the Joliet Refinery

. (1) E ntry 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 treatm e nt, storage, and/or disposal of hazardous waste in the diversion basin and/or the equalization/bi ological treatm e nt unit at Joliet Refinery; (ii) alleged violations of RCRA, 42 U.S.C. § 6901 et seq. , based on alleged past unauthorized treatm e nt, storage, and/or dispos al 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,

18533 U.S.C. § 1251 et seq. , based on any alleged past exceedance of com b ined outfall

tem p erature limits imposed by Special Condition 2 of the Joliet Refinery’s NPDES Permit between May 1996 and October 2004; (vi) alleged violations of reporting requirem e nts 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 lo cal 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) E ntry 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 Claim s 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 Bat on Rouge Refinery specified in Appendix M.
253. Audit Policy . Nothing in this Consent Decree is intended to limit or disqualif y ExxonMobil, on the grounds that information wa s not discovered and supplied voluntarily, from seeking to apply EPA’s Audit Policy or any state audit policy to any violations or

non-com p liance 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 adm i nistrative 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

186PSD/NSR, NSPS, NESHAP, and/or LDAR requirem e nts, not identified in this Section XVI of the Consent Decree and/or the Com p laint: a. ExxonMobil shall not assert, and m a y not m a intain, any defense or claim based upon the principles of waiver, res judicata , collateral estoppel, issue preclusion, or claim

- splitting. Nor m a y ExxonMobil assert, or m a intain, any other defenses based upon any contention that the claim s raised by the United States or the Applicable Co-Plaintif fs 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 claim s are deemed resolved by virtue of this Section XVI of the Consent Decree. b. The United States and Applicable Co-Plaintiffs m a y not assert or m a intain 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 m a tters 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-Plaintif fs to undertake any action against any person, including ExxonMobil, to abate or correct conditions which m a y present an im mi nent and substantial endangerment to the public health, welfare, or the environment.
XVII. GENERAL PROVISIONS
256. Other Law s . Except as specifically provided by this Consent Decree, nothing in this Consent Decree shall relieve ExxonMobil of its obligation to com p ly with all applicable federal, state and local laws and regulations, permits, and adm i nistrative orders, including, but

187not limited to, m o re 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 m o re stringent standa rds subsequent to the Date of Lodging of this Consent Decree through rulem a king, 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 com p liance 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 Settlem e nt) 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

rem e dies 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 com p liance 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 com p liance in an alternative or different

ma nner, ExxonMobil m a y petition the Court for relief from any such requirem e nts, in accordance with Rule 60 of the Federal Rules of Civil Procedure. However, if ExxonMobil

188applies to the Court for relief under this Paragraph, the United States and the Applicable CoPlaintif f reserve the right to seek to void all or part of the resolution of liability ref l ected in Section XVI (Ef f

ect of Settlem e nt). 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 com p lete 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-Plaintif fs 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 m u st elect between filing a new action for such

m onetary relief or seeking stipulated penalties under this Consent Decree, if stipulated penalties also are available for the alleged violation(s).
258. Compliance w i th Certain Emission Limits . a. For the purposes of determining com p liance with rolling average limits required under this Consent Decree: (i) at least 365 days is required after the initial com p liance date for an applicable 365-day rolling average limit in order to have sufficient data to evaluate

comp liance with such 365-day rolling average limit; and (ii) at least 7 days is required after the initial com p liance date f o r an applicable 7-day rolling average limit in order to have suf fi cient data to evaluate com p liance with a 7-day rolling av erage limit. Accordingly: (i) each applicable 365-day rolling average limit shall becom e enforceable com me ncing 365 days after the date set forth in this Consent Decree as the date by which ExxonMobil shall begin com p lying with such

189limit; and (ii) each applicable 7-day rolling average limit set out above shall becom e enforceable

com me ncing 7 days after the date set forth in this Consent Decree as the date by which ExxonMobil shall begin com p lying with such limit. b. If ExxonMobil proposes to use an alternative monitoring plan to monitor
an FCCU’s comp liance 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 com p lete 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 com p liance, if necessary, to meet the requirem e nt 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 rem a ins under EPA review). If EPA approves any such proposed alternative

m onitoring plan, ExxonMobil shall use the EPA-approved alternative monitoring plan to monitor

com p liance 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 com p liance monitoring within ninety (90) days of receiving notice of the disapproval. Such substitute plan m a y include a revised alternative monitoring plan application, physical or operational changes to the equipment, or additional or different monitoring. 259. Startup, Shutdow n , Malfunction . Notwithstanding the provisions of this Consent Decree regarding startup, shutdown, and Malfunction, this Consent Decree does not exempt ExxonMobil from the requirem e nts of state laws and regulations or from the requirem e nts of any permits or plan approvals issued to ExxonMobil, as these laws, regulations,

190permits, and/or plan approvals m a y apply to startups, shutdowns, and Malfunctions at the Covered Refineries.
260. Failure of Compliance . The United States and the Applicable Co-Plaintif fs do not, by their consent to the entry of this Consent Decree, warrant or aver in any m a nner that ExxonMobil’s com p lete com p liance with the Cons ent Decree will result in future com p liance 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 rem a in solely responsible for com p liance with the terms of the Consent Decree, all applicab le 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

ma il with respect to all m a tters arising under or relating to the Consent Decree and to waive the formal service requirem e nts 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 sum m ons. The persons identified by ExxonMobil at Paragraph 266 (Notice) are authorized to accept service of process with respect to all m a tters 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 o ccur 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 m a y be dem a nded by the United States and/or the Applicable Co-Plaintif fs as provided in this Consent Decree, provided that stipulated penalties

191that m a y have accrued between the Date of Lodging of the Consent Decree and the Entry Date

ma y 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-Plaintif fs 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 m a y be entered upon com p liance with the public notice procedures set forth at 28 C.F.R. § 50.7, and upon notice to this Court from the United States Departm e nt of Justice requesting entry of the Consent Decree. The United States reserves the ri ght to withdraw or withhold its consent to the Consent Decree if public com me nts 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 requirem e nts 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

com me nt, consideration of any com me nts, and concurrence by the Louisiana Attorney General.
266. Notice . Unless otherwise provided herein, notifications to or com m unications between the Parties shall be deemed submitted on the date they are postmarked. Notifications and com m unications shall be sent by U.S. Mail, postage pre-paid, or private courier service,

192except for notices under Section XIV ( Force Majeure ) and Section XV (Retention of Jurisdiction/Dispute Resolution) which shall be sent by overnight m a il or by certified or registered m a il, return receipt requested. Each report, study, notification or other com m unication 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 com m unication 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, certif ications, or other com m unications required underthis 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. Departm e nt of Justice P.O. Box 7611, Ben Franklin Station Wa shington, 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 Wa shington, DC 20460

193with 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 W e st Jackson Blvd. (AE-17J) Chicago, IL 60604 Attn: Com p liance Tracker and Office of Regional Counsel U.S. EPA, Region 5 77 W e st 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. 15 th St., Suite 3200 Helena, MT 59626

194EPA 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 Com p liance 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 W e st Harrison Des Plaines, IL 60016 and
Maureen W o zniak 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 Adm i nistrator, Enforcement Division Office of Environmental Com p liance Louisiana Departm e nt of Environmental Quality P.O. Box 4312 Baton Rouge, LA 70821-4312

195As to the State of Montana: Enforcement Division Adm i nistrator Montana Departm e nt of Environmental Quality P.O. Box 200901 Helena, MT 59620-0901 and Bureau Chief Air Resources Managem e nt Bureau Montana Departm e nt 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 Com p liance 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

196As 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. 190 th Street Torrance, CA 90509-2929 Any Party m a y 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 com me nts required under this Consent Decree
shall be m a de in writing. All approvals by an Applicable Co-Plaintiff shall be sent from the offices identified in Paragraph 266 (Notice).

197268. Paperwork Reduction Act . The United States has determined that the
inf o rmation required to be m a intained 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 modif i ed 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-m a terial

m odifications 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-m a terial modifications include, but are not be limited to: (i) any modifications to the frequency of reporting obligations; and (ii) any modif i cations to schedules that do not extend the ultimate date f o r comp liance with emissions limitations following the installation of control equipment or the com p letion of a catalyst additive program

. The United States will file non-m a terial 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 m o tion 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 com p leted and satisfied all of the following requirem e nts with respect to this Consent Decree: i. installation of control technology systems as specified in this Consent Decree;

198ii. com p liance with all provisions contained in this Consent Decree, which com p liance m a y 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. c ompletion 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 comp liance with the emission limits established herein, and certification of such com p liance for each unit within the first six (6) month period progress report following the conclusion of the comp liance period.
271. Certification of Completion

. a. Prior to moving for termination, ExxonMobil m a y certify comp letion for

one or m o re of the Covered Refineries of one or m o re of the following Subsections of the Consent Decree, provided that all of the related requirem e nts 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. S ubsection V.I, relating to SRPs; v. Subsections V.J - V.L, relating to Flaring; vi. S ubsections V.N, relating to Benzene W a ste NESHAP; vii. Subsection V.O, relating to LDAR; viii. the requirem e nts of Subsection V.P relating to certain other com p liance requirem e nts at the Billings Ref i nery;

199ix. T he requirem e nts of Subsection V.P relating to certain other com p liance requirem e nts at the Joliet Ref i nery; and x. Section VIII, relating to Environmentally Beneficial Projects. b. W ithin 90 days after ExxonMobil concludes that any of the parts of the Consent Decree identified in this Paragraph 271 have been com p leted, ExxonMobil m a y submit a written report to the Parties listed in Paragraph 266 (Notice) describing the activities undertaken and certifying that the applicable Paragraphs have been com p leted in full satisfaction of the requirem e nts of this Consent Decree, a nd that ExxonMobil is in substantial and m a terial

comp liance with all of the other requirem e nts of the Consent Decree. The report shall contain the following statement, signed by a responsible corporate official of ExxonMobil: To the best of m y knowledge, after thorough investigation, I certify that the information contained in or accom p anying this submission is true, accurate and com p lete. I am aware that there are signif i cant penalties f o r submitting f a lse 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 com me nt by the Applicable Co-Plaintiffs, shall notify ExxonMobil whether the requirem e nts set forth in the applicable Paragraphs have been com p leted in accordance with this Consent Decree. The parties recognize that ongoing obligations under such Paragraphs rem a in and necessarily continue ( e.g. , reporting, record keeping, training, auditing requirem e nts), and that ExxonMobil’s certification is that it is in current com p liance with all such obligations. i. If EPA concludes that the requirem e nts have not been fully com p lied with, EPA shall notify ExxonMobil as to the activities that m u st be undertaken to com p lete the applicable Paragraphs of the Cons ent 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).

200ii. If EPA concludes that the requirem e nts of the applicable Paragraphs have been com p leted in accordance with this Consen t Decree, EPA will so certify in writing to ExxonMobil. This certification shall constitute the certification of com p letion 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-Plaintif f fr om seeking stipulated penalties f o r a violation of any of the requirem e nts of the Consent Decree regardless of whether a Certification of Com p letion 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 Com p letion 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 requirem e nts for termination set forth in Paragraph 270, ExxonMobil shall certify such com p liance and com p letion to the United States and the Applicable Co-Plaintif fs 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 m a y move this Court for an order that this Consent Decree be terminated. If either the United States or the Applicable Co-Plaintif f objects to the certification by ExxonMobil under this Paragraph, then the m a tter 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.

201XIX. 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 m a y be signed in counterparts.

Dated and entered this _______ day of __________, 2005

_______________________________ UNITED STATES DISTRICT JUDGE

202THE 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. Departm e nt of Justice Wa shington, DC 20530

___________________________________ RANDALL M. STONE Trial Attorney Environmental Enforcement Section Environment and Natural Resources Division U.S. Departm e nt of Justice P.O. Box 7611 Wa shington, DC 20044-7611

PATRICK J. FITZGERALD United States Attorney

LINDA W AW ZENSKI Assistant United States Attorney Northern District of Illinois 219 S. Dearborn Street – 5 th Floor Chicago, IL 60604THE 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 Adm i nistrator for Enforcement and Com p liance Assurance United States Environmental Protection Agency 1200 Pennsylvania Avenue, N.W

. Wa shington, DC 20460THE 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 Enf o rcement/Asbestos Litigation Division

___________________________________ ROSEMARIE CAZEAU, Chief Environmental Bureau Assistant Attorney General 188 W e st Randolph St. – 20 th Floor Chicago, IL 60601

FOR THE ILLINOIS ENVIRONMENTAL PROTECTION AGENCY

___________________________________ ROBERT A. MESSINA Chief Legal CounselTHE 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 Departm e nt 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 Com p liance Louisiana Departm e nt 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 Departm e nt of Environmental Quality P.O. Box 4302 Baton Rouge, LA 70821-4302THE 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 Departm e nt of Environmental Quality P.O. Box 200901 Helena, MT 59620-0901

Date: ___________________

___________________________________ DAVID RUSOFF Special Assistant Attorney General Montana Departm e nt of Environmental Quality P.O. Box 200901 Helena, MT 59620-0901THE 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 Com p any (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 22037Appendix 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 Av erage Annual Utilization Rate, mmBtu/hr (HHV) 2000/2001 Av erage 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 inlb/MBtu; John Zink model PXMR10. 8

DCU F-602 140 0.060 Manufacturer's Specification inlb/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 inlb/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 1LEFU 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 w i th 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 (0.02lb/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 2A-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 Av erage Annual Utilization Rate, mmBtu/hr (HHV) 2000/2001 Av erage 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 inlb/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 3PSLA-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 4A-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 T e st 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 T e st Coker Far West BA3000 124 0.082 September 14, 1993 Stack Test Coker Mid B 101A 108 0.075 September 21, 1993 Stack Test Coker West B101C 108 0.085 April 6, 1993 Stack Tes t 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 T e st CUA Vacuum B3 95 0.074 February 2, 1994 Stack T e st CUB Atmospheric H3101 865 0.102 CEMS CUB Vacuum N H 2001 132 0.113 December 16, 1992 Stack Test CUB Vacuum S H 3102 164 0.078 February 1, 1994 Stack T e st FCC Feed Preheater 4B2 336 0.089 Mobil Test Data Furfural 2 Extract BA1/BA2 61 0.064 February 2, 1994 Stack T e st 2001 Basis for NOx Factor 2000/2001 Av erage A nnual Utilization

Rate, mmBtu/hr

(HHV) 2000/2001 Av erage NOx, TPY

August 29, 2001 Stack T e st 62 36
November 16, 1992 Stack Test 19 8
November 16, 1992 Stack Test 37 16 August 31, 2001 Stack T e st 58 18 August 22, 2001 Stack T e st 59 21 August 23, 2001 Stack T e st 63 20 April 6, 1993 Stack T e st 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 T e st 90 22 February 2, 1994 Stack T e st 65 21

CEMS 542 241 December 16, 1992 Stack Test 78 39 August 24, 2001 Stack T e st 99 34

CEMS 1/1/01 forward 221 86 February 2, 1994 Stack T e st 42 12

Appendix A - Page 5HDC Splitter Reb H 3305 83 0.090 June 25, 1998 Stack T e st 1998 Stack Test through 3/14/01; Manufacturer's Specification (0.045 #/MBtu, LHV) 3/15/01 forward; Callidusmodel LE-CSG8W (outside) and LE-CSG-18W (inside)...using 0.05 lb/MBtu for emissions calculations. 51

HDC Stab Reb H 3304 216 0.074 June 26, 1998 Stack T e st 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

Pow e r Plant 2 B oiler 15 402 0.229 December 15, 1993 Stack Test 1993 Stack Test through 1/17/01; CEMS 1/18/01 forward 199

Pow e r Plant 2 B oiler 16 402 0.232 December 15, 1993 Stack Test 1993 Stack Test through 1/17/01; CEMS 1/18/01 forward 220

Pow e r Plant 2 B oiler 17 402 0.228 December 14, 1993 Stack Test 1993 Stack Test through 1/17/01; CEMS 1/18/01 forward 218

Pow e r Plant 2 B oiler 18 402 0.227 December 15, 1993 Stack Test 1993 Stack Test through 1/17/01; CEMS 1/18/01 forward 231

Pow e r Plant 2 B oiler 19 402 0.154 December 14, 1993 Stack Test 1993 Stack Test through 1/17/01; CEMS 1/18/01 forward 232

Pow e r Plant 2 B oiler 22 844 0.130 May 24, 1979 Stack Test through 5/11/00; CEMS 5/12/00 forward CEMS 540

Pow e r Plant 3 B oiler 32 724 0.225 December 21, 1993 Stack Test 1993 Stack Test through 1/18/01; CEMS 1/19/01 forward 492

Pow e r Plant 3 B oiler 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 6Pow e r Plant 3 B oiler 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 H 3408 99 0.055 Manufacturer's Specification of 0.04lb/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 T e st June 28, 1989 Stack T e st 53 27

PtR3 Reformer H3403-6 660 0.073 CEMS CEMS 307 99 PtR3 Stripper Reb H 3402 84 0.059 December 7, 1994 Stack T e st December 7, 1994 Stack Test 55 14

PtR4 Debut Reb B 7201 45 0.066 CEMS CEMS 26 8 PtR4 Depent Reb B 7002 160 0.051 January 26, 1994 Stack T e st August 21, 2001 Stack T e st 75 17 PtR4 Pretreater B7001 132 0.062 January 26, 1994 Stack T e st August 30, 2001 Stack T e st 67 18

PtR4 Reformer B7101- 7104 964 0.061 CEMS CEMS 501 135

TOTALS 10773 3842 State permitting

Appendix A - Page 7A-4: Billings Ref i nery

Unit Source Maximum Heat Input Capacity , mmBtu/hr (HHV) 2000/2001 NOx Emission Rate, lb/mmBtu

(HHV) Basis for NOx Factor 2000/2001 Av erage Annual Utilization Rate, mmBtu/hr (HHV) 2000/2001 Av erage NOx, TPY BOHO B-8 133 0.13 Oct-96 Version of FIRE Database, Table 1.4-1 10 6

Coker K COB 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 8A-5: Joliet Ref i nery

Unit Source Maximum Heat Input Capacity , mmBtu/hr

(HHV) 2000/2001 NOx Emission Rate, lb/mmBtu

(HHV) Basis for NOx Factor 2000/2001 Av erage Annual Utilization Rate (Gas), mmBtu/hr

(HHV) 2000/2001 Av erage Annual Utilization Rate (Oil), mmBtu/hr (HHV) 2000/2001 Av erage 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 T e st 197 0 79 * Burners replaced in Fall 2002 w i th 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); Callidusmodel 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); Callidusmodel 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; Callidusmodel LE-CSG8WSP 212 0 31

Crude Vac. 13-B-2 277 0.175 Gas / 0.391 Oil Gas: April 24, 1992 Stack T e st; 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 9PreTreater 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 10A-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 Av erage 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 2 F-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 4 F-1E/W 527 0.095 CEMS 351 142 Hydrocracker 3 F-3 129 0.057 CEMS 96 24 Hydrocracker 3 F-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 11Appendix B: PEMS Program Requirements PREDICTIVE EMISSIONS MONITO RING SYSTEMS FOR HEATERS AND BOILERS WITH CAPACITIES BETWEEN 150 AND 100 mmBTU/HR A Predictive Emissions Monitoring Systems (“PEMS”) is a m a thematical model that predicts the gas concentration of NO x in the stack based on a set of operating data. Consistent with the CEMS data frequency requirem e nts of 40 C.F.R. Part 60, the PEMS shall calculate a pound per million BTU value at least once every 15 m i nutes, and all of the data produced in a calendar hour shall be averaged to produce a calendar hourly average value in pounds per m illion BTU. The types of information needed for a PEMS are described below. The list of instrum e nts and data sources shown below represent an ideal case. However at a m i nim u m, each PEMS shall include continuous monitoring for at least item s 3-5 below. ExxonMobil will identify and use existing instrum e nts and refinery data sources to provide sufficient data for the development and implementation of the PEMS. Instrumentation: 1. Absolute Hum i dity reading (one instrum e nt per refinery, if available)
2. Fuel Density, Composition and/or specific gravity - On line readings (it m a y be possible if the fuel gas does not vary widely, that a grab sam p le and analysis m ay be substituted) 3. Fuel flow rate 4. Firebox tem p erature 5. Percent excess oxygen 6. Airflow to the firebox (if known or possibly estimated)
7. Process variable data - steam flow rate, tem p erature and pressure - process stream flow rate, tem p erature & pressure, etc. Computers & Software: Relevant data will be collected and stored electronically, using computers and sof t ware. The hardware and sof t ware specif i cations will be specif i ed in the source-specific PEMS. Calibration and Setup:
1. Data will be collected f o r a period of 7 to 10 days of all the data that is to be used to construct the m a thematical model. The data will be collected over an operating Appendix B - Page 1range that represents 80% to 100% of the norm a l operating range of the heater/boiler;
2. A "Validation" analysis shall be conducted to m a ke sure the system is collecting data properly;
3. Stack Testing to develop the actual emissions data for com p arison to the collected param e ter data; and
4. Development of the m a thematical 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 nam e , location, and emission unit number(s); b. Provide expected dates of monitor com p liance demonstration testing. 2. Source Description

a. Provide a simp lified block flow diagram with param e ter monitoring points and emission sam p ling points identified (e.g., sam p ling 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 simp lified block flow diagram with param e ter monitoring points and emission sam p ling points identified (e.g., sam p ling ports in the stack); b. List monitored operating param e ters and norm a l 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 m a intain a continuous PEMS; b. Provide a general description of the software and hardware components of the PEMS, including m a nufacturer, type of computer, nam e (s) of software product(s), monitoring technique (e.g., m e thod of emission correlation). Appendix B - Page 2Manufacturer literature and other similar inf o rmation 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 O 2 for correction purposes, process param e ter(s), and/or emission control device param e ter(s)); d. List all measurement or sam p ling locations (e.g., vent or stack location, process param e ter measurement location, fuel sam p ling location, work stations);

e. Provide a simp lified 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 a nd analytical devices (e.g., therm o couple for temp erature, pressure diaphragm for flow rate);
g. Provide a description of the data acquisition and handling system operation including sam p le calculations (e.g., param e ters to be recorded, frequency of measurement, data averaging time, reporting units, recording process); h. Provide checklists, data sheets, and report format as necessary for com p liance 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, param e ter/emission correlation test plan, instrum e nt range calibrations); b. Provide graphs showing the correlation, and supporting data (e.g., correlation test results, predicted versus m e asured plots, sensitivity plots, computer modeling development data). 6. Initial Verif i cation Test Procedures

a. Perform an initial relative accuracy test (RA test) to verify the perform a nce of the PEMS for the equipment’s operating range. The PEMS m u st meet the relative accuracy requirem e nt of the applicable Perform a nce Specification in 40 C.F.R. Part 60, Appendix B. The test shall utilize the test m e thods of 40 C.F.R. Part 60, Appendix A; b. Identify the m o st significant independently modifiable param e ter affecting the emissions. W ithin the limits of safe unit operation, and typical of the Appendix B - Page 3anticipated range of operation, test the selected param e ter for three RA test data sets at the low range, three at the norm a l operating range and three at the high operating range of that param e ter, for a total of nine RA test data sets. Each RA test data set should be between 21 and 60 m i nutes in duration;

c. Maintain a log or sam p ling report for each required stack test listing the emission rate; d. Demonstrate the ability of the PEMS to detect excessive sensor f a ilure m odes that would adversely affect PEMS emission determination. These failure modes include gross sensor failure or sensor drift;

e. Demonstrate the ability to detect sensor f a ilures that would cause the PEMS emissions determination to drift significantly from the original PEMS value; f. The PEMS m a y use calculated sensor values based upon the m a thematical relationships established with the other sensors used in the PEMS. Establish and demonstrate the number and com b ination 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 param e ters to the PEMS (e.g., transducers, sensors, gas chrom a tograph, periodic laboratory analysis), and a description of the sensor validation procedure (e.g., m a nual or autom a tic check); b. Provide a description of routine control checks to be perform e d during operating periods (e.g., preventive m a intenance schedule, daily m a nual or autom a tic sensor drift determinations, periodic instrum e nt calibrations);

c. Provide m i nim u m data availability requirem e nts and procedures f or supplying m i ssing 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 alarm s ); e. List trouble-shooting procedures and potential corrective actions; f. Provide an inventory of replacement and repair supplies for the sensors;

Appendix B - Page 4g. Specify, for each input param e ter 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 requirem e nts); h. Conduct a quarterly electronic data accuracy assessment tests of the PEMS; i. Conduct sem i annual RA tests of the PEMS. Annual RA tests m a y be conducted if the m o st recent RA test result is less than or equal to 7.5%. Identify the m o st significant independently modifiable param e ter affecting the emissions. W ithin the limits of safe unit operation and typical of the anticipated range of operation, test the selected param e ter for three RA test data pairs at the low range, three at the norm a l operating range, and three at the high operating range of that param e ter for a total of nine RA test data sets. Each RA test data set should be between 21 and 60 m i nutes in duration. 8. PEMS Tuning

a. Perform tuning of the PEMS provided that the fundam e ntal m a thematical 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 fundam e ntal m a thematical relationships in the PEMS model are not changed.

Appendix B - Page 5Appendix 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
Bay t own 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 D ecember 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 com p liance date, ExxonMobil will submit an AMP application for the listed device by the date specified, and the device shall becom e 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, Billi ngs Pipestill Heater F-1 shall com p ly with the emission limitation specified by 40 C.F.R. § 60.104(a)(1) at all times, except when SWS T-23 am m onia overhead gas is combusted in the unit as permitted by pertinent provisions of the Montana State Implementation Plan.
Appendix C - Page 1Appendix C: NSPS Subpart J Compliance Schedule for Certain Heaters and Boilers (continued)
Refinery Combustion Device Compliance Date 3 / Beaumont CHD 1 Heater B-1 S ubmit 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 R e-route vacuum tower overhead gas to fuel gas treatm e nt by no later than December 31, 2005 Joliet R eform e r Heaters 2B3 and 2B4 S ubmit AMP six months after Entry Date for Reformer regen lock hopper vent stream Torrance R eform e r Heater 19F-1 Submit AMP two months after next regeneration cycle for Reformer regen vent stream, but no later than December 31, 2006 Torrance H eaters 25F1-A and 25F1-B S ubmit AMP six months after Entry Date for kerosene/LGO dry e rs 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 com p liance date, ExxonMobil will submit an AMP application for the listed device by the date specified, and the device shall becom e an affected facility on the date that ExxonMobil receives EPA’s approval of the relevant AMP.
Appendix C - Page 2Appendix 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 A MP pending Baton Rouge MVR Combustor/Flare No. 2 A MP pending Bay t own M VR Therm a l Oxidizer VCU-440 Submit AMP six months after Entry Date Bay t own M VR Therm a l Oxidizer VCU-470 Submit AMP six months after Entry Date Bay t own T hermal Oxidizer for Loading Racks 2 & 3 Submit AMP six months after Entry Date
Bay t own Caustic Oxidation Unit Incinera tor S ubmit AMP six months after Entry Date Beaumont MVR - John Zink Combustor S ubmit AMP six months after Entry Date Billings FCCU CO Boiler T reat or re-route SWS T-23 am m onia 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 N BRU Therm a l Vapor Incinerator - 38B-1 Shutdown, treat, or re-route stream by no later than ber 31, 2008 Joliet S BRU Therm a l Vapor Incinerator - 38B-2 Shutdown, treat, or re-route stream by no later than December 31, 2008 Torrance A PI Therm a l Oxidizer 72F2 S ubmit AMP six months after Entry Date Torrance A PI Therm a l Oxidizer 72F4 S ubmit AMP six months after Entry Date Torrance R esid Loading Rack Incinerator 50J-30 Submit AMP six months after Entry Date

Torrance S ulfur Pit Vapor Incinerator 28F-11 S hutdown, treat, or re-route stream by July 1, 2009 Decem

4 / As provided by Consent Decree Subparagraph 59.c, wh ere this Appendix D refers to an AMP submittal date rather than a final com p liance date, ExxonMobil will submit an AMP application for the listed device by the date specified, and the device shall becom e an affected facility on the date that ExxonMobil receives EPA’s approval of the relevant AMP.
Appendix D - Page 1Appendix E: Alternative Monitoring Plan for NSPS Subpart J Refinery Fuel Gas Ref i nery f u el gas streams/systems eligible f o r the Alternative Monitoring Plan (AMP) should be inherently low in H 2 S content, and such H 2 S content should be relatively stable. The refiner requesting an AMP should provide sufficien t 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 diagram s 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 sam p ling point for the alternative monitoring;



### ! A statement that there are no crossover or entry points for sour gas (high H 2 S content) to be introduced into the gas stream/system

. (This should be shown in the piping diagram s );



### ! 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 sam p ling the requested gas stream/system using appropriate H 2 S 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 m i nim um:



### ! for frequently operated gas streams/systems - two weeks of daily monitoring (14 sam p les);



### ! for infrequently operated gas streams/systems, 7 sam p les shall be collected unless other additional information would support reduced sam p ling. Note: All samp les are grab samp les.



### ! A description of how the two weeks (or seven sam p les for infrequently operated gas streams/systems) of monitoring results com p ares to the typical range of H 2 S concentration (fuel quality) expected f o r the gas stream/system going to the af f

ected f u el 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 H 2 S content in the gas stream going to the loading rack flare);



### ! Identification of a representative process param e ter that can function as an indicator of a stable and low H 2 S concentration for each fuel gas stream/system , (e.g., review of gasoline sulfur content as an indicator of sulf ur content in the vapors directed to a loading rack flare); Appendix E - Page 1

### ! Suggested process param e ter limit for each stream/system , the rationale for the param e ter limit and the schedule for the acquisition and review of the process param e ter data. The refiner will collect the proposed process param e ter data in conjunction with the testing of the fuel gas stream 's stable and low H 2 S concentration. The following shall be used for measuring H 2 S in fuel gas within these types of AMPs unless the refiner requests, in writing, approval of an alternative m e thodology:



### ! Conduct H 2 S measurement using detector tubes (“length-of-stain tube” type m easurement);



### ! 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 H 2 S. Data Range and Variability Calculation and Acceptance Criteria For each step of the monitoring schedule, sam p le 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 H 2 S, the sam p le 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 m a xim u m allowable fuel gas standard under NSPS Subpart J, and the Agency believes that using 81 ppm acceptance criteria provides a sufficient m a rgin for ensuring that the emission limit is not exceeded under norm a l 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 H 2 S), 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 H 2 S. As an example, approval m a y be granted based on a review of the test data and any pertinent information which demonstrates that sam p le variability during the test period was due to unusual circumstances. Supplemental test data m a y be taken to demonstrate that process variability is within the plan requirem e nts. Data m a y be removed f r om the variability calculations f o r 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 H 2 S), the source will drop back to the previous step' s m onitoring schedule.



### ! If at any time, one detector tube sam p le value is equal to or greater than 81 ppm H 2 S, then begin sam p ling as specified in Step 6. Note: Standard deviation cannot be calculated for a data set containing one point. Appendix E - Page 2Monitoring Schedule for Approved AMPs For gas streams which m u st meet product specifications for sulfur content, one time only detection tube sam p ling 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 mu st be resubmitted for approval under the AMP. The following are examples of streams needing one time only monitoring:



### ! Certified com me rcial grade natural gas;



### ! Certified com me rcial grade LPG;



### ! Certified com me rcial grade hydrogen;



### ! Gasoline vapors from a loading rack that only loads gasoline meeting a product specification for sulfur content. For other gas streams, the H 2 S 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 param e ter for each stream/system , according to the established process param e ter monitoring or review schedule approved by the agency in the AMP, and at times when conducting H 2 S detector tube sam p ling. Step 2: The refiner will conduct random detector tube sam p ling twice per week for each stream/system for a period of six months (52 sam p les). For fuel gas streams infrequently generated and combusted in affected fuel gas combustion devices (i.e., less frequent than bi

weekly), detector tube sam p les shall be taken each time the fuel gas stream is generated and combusted. A total of at least 24 sam p les shall be collected for infrequently generated gas streams. Monitor and record the selected process param e ter in accordance with the established schedule, and at times when conducting H 2 S testing. Move to Step 3 if the calculated range and variability of the data meets the established acceptance criteria. Submit test data (raw m easurements plus calculated average and variability) to the agency quarterly. Step 3: The refiner will conduct random H 2 S sam p ling once per quarter for a period of six quarters (6 sam p les) with a m i nim um of 1 month between sam p les. A m i nim um of 9 sam p les are required for infrequently generated and combusted fuel gas streams before proceeding to Step 4. Continue to monitor and record the selected process param e ter in accordance with the established schedule, and at times when conducting H 2 S testing. Move to Step 4 if the calculated Appendix E - Page 3range and variability of the data meets the established acceptance criteria. Submit test data (raw m easurements plus calculated average and variability) to the agency quarterly. Step 4: The refiner will conduct random H 2 S sam p ling twice per year for a period of two years (4 sam p les); sam p le randomly in the 1st and 3rd quarters with a m i nim um of 3 months between sam p les. Continue to monitor and record the se lected process param e ter in accordance with the established schedule, and at times when conducting H 2 S testing. Move to Step 5 if the calculated range and variability of the data meets the established criteria. Submit test data (raw m easurements plus calculated average and variability) to the agency sem i annually. Step 5: The refiner will continue to conduct testing on sem i -annual basis. Testing is to occur randomly once every sem i annual period with a m i nim u m of 3 months between sam p les. Continue to monitor and record the selected process param e ter in accordance with the established schedule, and at times when conducting H 2 S testing. If any one sam p le is equal to or greater than 81 ppm H 2 S, then proceed to the samp ling 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 param e ter data indicates a potential change in H 2 S concentration, or a single detector tube sam p le value is equal to or greater than 81 ppm H 2 S, then the fuel gas stream shall be samp led with detector tubes on a daily basis for 7 days (or for infrequently generated gas streams - 7 sam p les during the sam e period of an indicated change in H 2 S concentration, or as otherwise approved by the agency). If the average detector tube result plus 3 standard deviations for those seven sam p les is less than 81 ppm H 2 S, the date and value of change in the selected process param e ter indicator and the samp le results shall be included in the next quarterly report, and the refiner shall resum e m onitoring in accordance with the schedule of the current step. If the average plus 3 standard deviations for those seven sam p les is equal to or greater than 81 ppm H 2 S, sam p ling shall follow the requirem e nts of Step 7. Step 7: If samp le 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 H 2 S), 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 sam p le day. The fuel gas stream shall subsequently be tested daily for a two week period (or 14 sam p les during the sam e event or as otherwise approved by the agency for infrequently generated gas streams). After the two week period is com p lete, sam p ling will continue once per week, until the agency approves a revised sam p ling schedule or m a kes 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 4General 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 sam p les collected over a one week period (7 samp les). For fuel gas streams infrequently generated and combusted in affected fuel gas combustion devices, an audit shall consist of 3 consecutive sam p ling events. (e.g., Rail loading m a y 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 H 2 S detector tube test data and the representative process param e ter 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 O ff-Gas Stream Combusted Exclusively in the Hydrogen Plant Process Heater: Process Description Hydrogen production for the refinery by the steam me thane reforming process. CO 2 is the primary impurity in the hydrogen produced; small amounts of CO and m e thane are also present. Unpurified hydrogen is passed over m o lecular 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 Diagram s Piping diagram s 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 H 2 S Content Since PSA off-gas is a byproduct of hydrogen purification, any H 2 S in the PSA purge gas m u st com e from the hydrogen unit feed. Levels of H 2 S in the PSA gas are negligible because H 2 S mu st be controlled to prevent deactivation of the unit's catalyst. H 2 S is a permanent catalyst poison. The hydrogen unit has 2 scrubbers to remove H 2 S poisoning. The scrubbers are operated in series. The lead scrubber m u st exhibit at least a 70% reduction in H 2 S 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 m a xim i zes the amount of H 2 S removal and assures m a xim um scrubbing potential when one scrubber is off line for absorbent replacement.

Appendix E - Page 5Process Param e ter Monitoring and Suggested Process Param e ter Lim it Operation of the scrubbers is checked on a monthly basis with detector tubes. The feed gas H 2 S 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 H 2 S is norm a lly detected at the inlet. A lead scrubber outlet reading of 10 -12 ppm H 2 S would trigger absorbent replacement. The suggested process param e ter limit is 20 ppm H 2 S at the lead H 2 S absorber outlet. Absorber outlet H 2 S measurements will be taken in conjunction with the PSA gas measurements during Steps 2 and 3.

Appendix E - Page 6Appendix F: List of Existing Flaring De vices 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 Ref i nery Main Flare* Turnaround Flare* Joliet Ref i nery 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. Flar ing Devices that are not followed by an asterisk currently are used solely as Hydrocarbon Flaring Devices. Appendix F - Page 1Appendix 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 E ntry Date Subparagraph 73.a.i Baton Rouge Flare 8 E ntry Date Subparagraph 73.a.i Baton Rouge Flare 9 E ntry 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 F lare 3 E ntry Date Subparagraph 73.a.i Baytown F lare 4 S ubmit 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 F lare 5 E ntry Date Subparagraph 73.a.i Baytown F lare 6 E ntry Date Subparagraph 73.a.i Baytown F lare 11 Monitor with CEMS as required by 40 C.F.R. § 60.105(a)(3) or (a)(4) by no later than 12 m onths after Entry Date Subparagraph 73.a.iv

Baytown F lare 14 Monitor with CEMS as required by 40 C.F.R. § 60.105(a)(3) or (a)(4) by no later than 12 m onths after Entry Date Subparagraph 73.a.iv

Baytown F lare 15 Entry Date Subparagraph 73.a.i Baytown F lare 16 Entry Date Subparagraph 73.a.i

6 / As provided by Consent Decree Subparagraph 73.b, wh ere this Appendix G refers to an AMP submittal date rather than a final com p liance date, ExxonMobil will submit an AMP application for the listed device by the date specified, and the device shall becom e an affected facility on the date that ExxonMobil receives EPA’s approval of the relevant AMP. Appendix G - Page 1Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices Operated by Covered Refineries (continued)
Refinery Flaring Device Compliance Date Compliance Method Baytown F lare 17 24 months after Entry Date (so that certain stream s can be re-routed by that Com p liance Date) Subparagraph 73.a.i
Baytown F lare 18 Entry Date Subparagraph 73.a.i Baytown F lare 19 Entry Date for emergency service Submit AMP six months after entry for intermittent low m a ss sweet stream s Subparagraph 73.a.ii Subparagraph 73.a.iii
Baytown F lare 20 24 months after Entry Date for streams other than HF4 stream (so that certain streams can be re-routed by that Com p liance Date) Submit AMP six months after Entry Date for m onitoring HF4 stream when Flare 17 is on turnaround Subparagraph 73.a.i

Subparagraph 73.a.iii

Baytown F lare 21 Entry Date Subparagraph 73.a.i Baytown F lare 22 Entry Date for emergency service Submit AMP six months after Entry Date for m onitoring intermittent low m a ss sweet stream s when Flare 19 is on turnaround Subparagraph 73.a.ii Subparagraph 73.a.iii

Baytown F lare 25 Entry Date for emergency service Submit AMP six months after Entry Date for m onitoring intermittent refinery fuel gas stream s and natural gas stream s Subparagraph 73.a.ii Subparagraph 73.a.iii

Baytown F lare 26 Submit AMP six months after Entry Date for m onitoring certain sweet streams and nitrogencontaining stream s Subparagraph 73.a.iii

Baytown F lare 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 com p leted by that Com p liance Date) Subparagraph 73.a.i

Beaumont Low Pressure (LP) Flare 42 months after Entry Date (so that flare gas recovery system upgrades can be com p leted by that Com p liance Date) Subparagraph 73.a.i

Beaumont FCC Flare 42 months after Entry Date (so that flare gas recovery system upgrades can be com p leted by that Com p liance Date) Subparagraph 73.a.i

Appendix G - Page 2Appendix 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 com p leted by that Com p liance Date) Subparagraph 73.a.i

Billings Flare 48 months after Entry Date (so that flare gas recovery system upgrades can be com p leted by that Com p liance Date) Subparagraph 73.a.i

Torrance F lare 55F-1 Submit AMP six months after Entry Date Subparagraph 73.a.iii Torrance F lare 65F-3 Entry Date Subparagraph 73.a.i Torrance F lare 65F-4 Entry Date Subparagraph 73.a.i Torrance E nclosed Ground Flare 65F-8 8 / Entry Date Subparagraph 73.a.i Turnaround

7 / W ith respect to the Beaumont Refinery’s CHD 1 Fl are, CHD 2 Flare, and Coker Flare, by no later than 42 months after the Entry Date, ExxonMobil shall either: (i) com p lete flare gas recovery system upgrades to bring the particular flare into com p liance with Subpa ragraph 73.a.i; or (ii) re-route streams as required to bring the particular flare into com p liance with Subpa ragraph 73.a.ii or 73.a.iii. In the first Sem i -Annual Report that is due under Section IX after that 42 month period, ExxonMobil shall identify and certify com p liance with a specific com p liance m e thod ( 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 requirem e nt referenced in Subparagraph 75.b.(2) of this Consent Decree; and (ii) is subject to the requirem e nts imposed by SCAQMD Rule 1118 and 40 C.F.R. §§ 60.482-10 and 60.486(d). Appendix G - Page 3Appendix G: NSPS Subpart J Compliance Schedule for NSPS Flaring Devices Operated by Covered Refineries (continued)

Identification of Particular Low Volum e /Low Pressure Streams to be Routinely Combusted in Certain Baytown Refinery Flaring Devices
1. Low Volum e /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 1 st stage discharge knock-out drum) drain • D-714 (C-708 2 nd stage discharge knock-out drum) drain • D-770 (C-770 1 st stage suction knock-out drum) drain • D-771 (C-770 2 nd stage suction knock-out drum) drain • D-772 (C-770 3 rd stage suction knock-out drum) drain • D-780 (C-780 1 st stage suction knock-out drum) drain • D-781 (C-780 2 nd stage suction knock-out drum) drain • D-782 (C-780 3 rd 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 com p ressor) seal oil liquid collection pot drain • C-303 (FCCU 3 wet gas com p ressor) 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 m a ke-up com p ressors) buffer gas (N 2 ) vent and drains off com p ressor lube pots [through D-390] • RGB / LBG fuel gas knock- out drum liquid drain [through D-390] 2. Low Volum e /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 m a y approve addition of that stream to this Appendix through a non-m a terial modification under Consent Decree Paragraph 269, so long as the other conditions of Subparagraph 73.a.iv are m e t.

Appendix G - Page 4Appendix 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 tem p eratures; 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. atm o spheric gas oil, vacuum gas oil, atm o spheric tower bottom s , vacuum tower bottom s , etc.); g. CO boiler firing rate and fuel type, if applicable; h. CO boiler combustion tem p erature, 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 SO 2 , NOx, and CO m a ss 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 1Appendix I: Additional Claims Concern ing 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 Un ited 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 Ref i nery: 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 sam p les 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 W a ter based on discharges causing visible oil sheens at outfall 002 during Novem b er 2000, Novem b er 2001, February 2002 and March 2002;
C. Alleged past violations of the General Perm it for Storm w ater Discharges Associated with Industrial Activity MTR 000000 (Authorization 000104) based on: (i) the failure of the Billings Refinery Storm Wa ter Pollution Prevention Plan (“SWPPP”) to identify certain potential sources of pollution to storm water discharges associated with the scrap m e tal 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 concerni ng m a nagem e nt of m a terials in Tank 350 (identified by EPA during its July 2002 inspection). Alleged RCRA Violations
F. Alleged past violations of RCRA requi rem e nts based on storage of the following uncharacterized wastes in the scrap yard and/or lay down area at the Billings Ref i nery: heat exchanger bundles containing possible heat exchanger bundle cleaning sludge, welding rods, discarded aerosol cans, dis carded insulation, and refrigeration and air conditioning equipment.
G. Alleged past violations of RCRA requirem e nts based on application of waste at the Billings Ref i nery’s Land Treatm e nt Unit during periods of high winds. Appendix I - Page 1-- Appendix J: Table of Alleged CWA Violatio ns at the Joliet Refinery Referenced in Consent Decree Subparagraph 252.c.(1)

Month and Year Outfall No. P arameter and Other Details 1/1996 003 total organic carbon (daily m a xim um mg /l) 2/1996 003 total organic carbon (daily m a xim um mg /l) 3/1996 001 biological oxygen dem a nd (daily m a xim um mg /l - 4 days during month) 3/1996 001 total suspended solids (daily m a xim um mg /l - 2 days during month) 4/1996 001 biological oxygen dem a nd (daily m a xim um mg /l) 4/1996 001 am m onia (daily m a xim um mg /l) 4/1996 003 total organic carbon (daily m a xim um mg /l) 6/1996 003 total organic carbon (daily m a xim um mg /l) 7/1996 003 total organic carbon (daily m a xim um mg /l) 9/1996 001 total suspended solids (monthly average m g /l) 9/1996 001 total suspended solids (daily m a xim um mg /l) 5/1997 001 total suspended solids (daily m a xim um mg /l) 5/1997 001 am m onia (daily m a xim um mg /l) 12/1997 002 total organic carbon (daily maximum mg/l) 6/1998 001, 002, 003 total residual chlorine (daily m a xim um mg /l) 12/1998 003 total organic carbon (daily m a xim um mg /l) 1/1999 001 total suspended solids (monthly average lb/day) 1/1999 001 total suspended solids (daily m a xim um mg /l) 6/1999 001 total suspended solids (daily m a xim um mg /l) 6/1999 001 total suspended solids (daily m a xim um lb/day) 6/1999 oil sheen on river 7/1999 002 total organic carbon (daily m a xim um mg /l) 8/1999 002 total organic carbon (daily m a xim um mg /l) 8/1999 003 total organic carbon (daily m a xim um mg /l) 9/1999 001 total suspended solids (daily m a xim um mg /l) 9/1999 001 total suspended solids (monthly average lb/day) 5/2000 002 total organic carbon (daily m a xim um mg /l) 6/2000 005 unauthorized discharge of 2 gallons of oil (Special Condition 9) 10/2000 001, 002, 003 total residual chlorine (daily m a xim um mg /l) 11/2000 001 total suspended solids (daily m a xim um mg /l) 7/2001 004 total organic carbon (daily m a xim um mg /l)

Appendix J - Page 1Appendix J: Table of Alleged CWA Violatio ns 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 m a xim um mg /l) 10/2001 008 unauthorized discharge of 2 gallons of oil (Special Condition 9) 10/2001 – o il sheen on river 11/2001 002 total organic carbon (daily m a xim um mg /l) 1/2002 001, 002, 003 total residual chlorine (daily m a xim um mg /l) 5/2002 001, 002, 003 total residual chlorine (daily m a xim um mg /l) 8/2002 001, 002, 003 total residual chlorine (daily m a xim um mg /l) 9/2003 – c hromium 10/2002 001 am m onia (daily m a xim um mg /l) 11/2002 001 am m onia (daily m a xim um mg /l - 4 days during month) 11/2002 005 oil and grease (daily m a xim um mg /l) 12/2002 001 am m onia (daily m a xim um mg /l - 7 days during month) 3/2003 003 total organic carbon (daily m a xim um mg /l) 5/2003 003 total organic carbon (daily m a xim um mg /l) 6/2003 004 oil and grease (daily m a xim um mg /l) 4/2004 001 am m onia (daily m a xim um mg /l - 3 days during month) 5/2004 008 oil and grease (daily m a xim um mg /l) 5/2004 001 am m onia (daily m a xim um mg /l - 2 days during month) 6/2004 001 am m onia (daily m a xim um mg /l) 6/2004 003 pH (daily m a xim um SU) 8/2004 008 total organic carbon (daily m a xim um mg /l) 8/2004 001 pH (daily m a xim um SU) 11/2004 001 am m onia (daily m a xim um mg /l) 12/2004 001 am m onia (daily m a xim um mg /l) 1/2005 003 total organic carbon (daily m a xim um mg /l - 2 days during month)

Appendix J - Page 2Appendix 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 C hemical 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 1Appendix 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) A lleged 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 atm o sphere on May 15-16, 2004; (2) A lleged 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 m a nner consistent with good air pollution control practices on May 15-16, 2004; (3) A lleged violation of Section 9.1(d) of the IEP Act and 40 C.F.R. § 63.641 based on the routing of m a terial 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) A lleged 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) A lleged 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 m a lfunction 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 atm o sphere from a flare on May 15, 2004 in a m a nner that was inconsistent with good air pollution control practices; and (7) A lleged 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 atm o sphere, and the failure to route m a terial 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 2Appendix M: Additional Claims Concern ing 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 Consolidat ed Com p liance Order and Notice of Potential Penalty (“CONOPP”) or LDEQ Adm i nistrative Order listed below:
A. CONOPP No. AE-CN-01-0254, issued October 16, 2001, for alleged unpermitted H 2 S and SO 2 emissions from sulfur pit relief stacks at the sulfur recovery unit.
B. CONOPP No. MM-CN-01-0027, issued Oc tober 18, 2002, for alleged violations identified during the April-May 2001 m u ltimedia inspection and subsequent file review.
C. CONOPP No. AE-CN-02-0233A, issued Novem b er 22, 2004, for alleged violations identified during the June 12-15, 2002 inspection and subsequent file review. D. Adm i nistrative 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 (compr ising Subsections V.A through V.G) of the Findings of Fact in that CONOPP.

Appendix M - Page 1Appendix 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

E ntry Date E ntry Date Entry Date December 31, 2008

18 months after Entry Date
Entry Date SO 2 CEMS Entry Date
Entry Date Entry Date Entry Date 18 months after Entry Date 18 months after Entry Date Entry Date CO CEMS O 2 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 1Appendix 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 fi sh 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 recom me ndations of the Secretary of the Louisiana Departm e nt 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 m i ssion is to support the m i ssion and programs of the Louisiana Departm e nt of Wildlife and Fisheries (the “Department”) and the Louisiana Wildlife and Fisheries Com mi ssion (the “Com mi ssion”) including promotion, development, expansion and improvem e nt of the facilities of the Departm e nt and Com mi ssion. 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 becom e partners with the Departm e nt and the Com mi ssion in the conservation of Louisiana's f i sh and wildlife resources, and has spearheaded a m u ltitude 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 accom p lished, the Foundation will execute an act (or acts) of donation(s) of said lands to the Departm e nt and the Com mi ssion. The Departm e nt and Com mi ssion will then establish the lands as a wildlife m a nagem e nt area, wildlife refuge or other natural area; or will enter into cooperative endeavors with other state agencies for the protection, m a nagem e nt and conservation of the said lands consistent with the above stated purposes.

Appendix O - Page 1Appendix P: Joliet Wastew a ter Treatment Plant Area Program
1. Su mma ry . As required by Consent Decree Paragraph 134, ExxonMobil shall implement the Joliet W a stewater Treatm e nt Plant Area Program (“W W TP Area Program”) as described in detail in this Appendix P. The W WT P Area Program requires data collection and other actions in the general area of the Joliet Refinery encom p assing the wastewater treatment plant, the Storm w ater Diversion Basin ("SWDB "), the Equalization Biological Treatm e nt Unit ("EBTU"), the Diversion Box, Inlet Structure, Outlet Box, and other related points (referred to herein as the “W WT P Area”) depicted on attached Figure P-1. 9 / Generally, the W W TP Area Program will include the following elements: flow monitoring, wastewater sam p ling (and subsequent analysis) at specific locations, precipitation monitoring, snowm e lt monitoring, sludge characterization and removal, confirm a tion 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 W WT P Area into f u ll com p liance with applicable legal requirem e nts. Certain monitoring and reporting on NPDES Permit com p liance at the Joliet Refinery also is required.
2. The W WT P Area W a stewater Monitoring Plan . W ithin 90 days of the Entry Date, ExxonMobil shall submit to EPA for review and approval a W WT P Area W a stewater 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 W W TP Area W a stewater 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 m i xing 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 W WT P Area W a stewater Monitoring Plan shall include a reasonable time period between the date of EPA approval of the WWT P Area W a stewater Monitoring Plan and com me ncement of the Monitoring Period (such time period not to exceed six (6) months) to allow for the installation and com p letion of testing of all equipment necessary to perform the required monitoring programs. The parties will attem p t to identify a com me rcially available autosam p ler f o r use in this program prior to the Date of Lodging. If the parties cannot find a com me rcially available autosam p ler acceptable to both EPA and ExxonMobil by that date, then ExxonMobil shall be allowed to take sam p les ma nually.

a. SWDB, Stream 4c

. i. SWDB Flow Monitoring

. The W WT P Area W a stewater 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 W WT P flows are as depicted on Figure P-1, and agrees that variances from Figure P-1 m a y, at EPA' s discretion, result in additional or different m onitoring locations, additional or different monitoring requirem e nts, or both. Appendix P - Page 1the SWDB, including, but not limited to, detailed plans and a schedule for installing and utilizing the f o llowing:

(a) E quipment to monitor and electronically record when the inlet valve to the SWDB is open; and (b) F low measuring and recording equipment designed to continuously, reliably, and accurately measure, within m a nufacturer' s specifications, and record, at intervals no longer than five m i nutes, 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 Sam p ling

. If autosam p ling is the agreed upon m e thod of sam p ling, the W WT P Area W a stewater Monitoring Plan shall include plans and a schedule f o r installing and utilizing an autosam p ling device designed to sam p le the wastewater when wastewater flow is divert ed f r om the Inlet Structure into the SWDB. The autosam p ling device shall be designed to m i nim i ze headspace in each collected sam p le and shall be installed and used in accordance with the m a nufacturer' s recom me ndations. Sam p ling during each diversion event shall be conducted in accordance with Attachm e nt P-2. Manual sam p ling procedures shall be consistent with the sam p ling process set out in attachm e nt P-2 and shall be perform e d in a m a nner to mi nim i ze headspace in each collected sam p le. iii. SWDB Analysis . The SWDB sam p les 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 Sam p ling

. 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 m a nufacturer' s specifications, and record at intervals no longer than fifteen m i nutes, the flow rate of wastewater at the location labeled as S1 in Figure P-1. The date and time of these m easurements shall be electronically recorded. Plans and a schedule for installing this equipment shall be included in the W WT P Area W a stewater Monitoring Plan. ii. Autosam p ler

. If autosamp ling is the agreed upon m e thod of samp ling, ExxonMobil shall install an autosam p ling device that sam p les Stream 6 and that is designed to m i nim i ze headspace in each collected sam p le. The autosam p ler shall be installed and used in accordance with the m a nufacturer' s recom me ndations. For purposes of this Consent Decree and the W WT P Area W a stewater Monitoring Plan, each individual sam p le collected from Stream 6 using the autosam p ling device shall be referred to as a "grab" sam p le. Manual sam p ling procedures shall be perform e d in a Appendix P - Page 2ma nner to m i nim i ze headspace in each collected sam p le. iii. Stream 6 Composite Sam p ling . During the Monitoring Period, ExxonMobil shall collect for analysis daily composite sam p les from Stream 6 as follows: single grab sam p les shall be collected (sampling to be conducted m a nually or using the autosam p ler as described in Subparagraph 2.b.ii. above) at or near the end of the m a in influent pipe to the EBTU six times per calendar day, at a sam p ling interval of approxim a tely four hours. For each day, the grab sam p les collected (typically 6) will not be analyzed individually, but will be com b ined to create a single daily composite sam p le for analysis. iv. S tream 6 Grab Sam p ling

. During the Monitoring Period, ExxonMobil shall collect for analysis a series of grab sam p les from Stream 6 as follows: once per calendar week, single grab sam p les shall be collected (sampling to be conducted ma nually or using the autosam p ler as described in Subparagraph 2.b.ii. above) at or near the end of the m a in influent pipe to the EBTU 6 times per day, at a sam p ling interval of approxim a tely four hours. The grab sam p les collected (typically 6) will be analyzed individually. In any quarterly reports submitted pursuant to Paragraph 3, ExxonMobil ma y request EPA approval to reduce the frequency or eliminate grab sam p ling under this Paragraph.

v. Stream 6 Sam p le Handling

. The grab sam p les and composite sam p les will be handled at all times so as to m i nim i ze headspace. vi. S tream 6 Analysis . Stream 6 samp les 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 W WT P Area W a stewater 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 f o llowing:

(a) E quipment 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 treatm e nt ( 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) F low measuring and recording equipment designed to continuously, reliably and accurately measure, within m a nufacturer' s specifications, and record at intervals no longer than five m i nutes, the time and flow rate of wastewater from the Dive rsion Box to Stream 3. Measured and recorded data shall be suf fi cient to allow calculation of the f l ow 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 m i xing of Stream 3 with Stream 6. ii. Streams 3 and 6 Diversion Event Sam p ling . The W W TP Area W a stewater Monitoring Plan shall include plans and a schedule for using one of the following alternative m e thods (Subparagraphs 2.c.ii.(a) or 2.c.ii.(b)), to be determined in ExxonMobil's sole discretion, to sam p le the wastewater in Streams 3 and 6 when wastewater flow is diverted from the Diversion Box to Stream 3: (a) Manual Sam p ling

. 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 sam p ling locations (one at Stream 3 and the other at Stream 6). Manual sam p ling of both Streams 3 and 6 shall be coordinated to start sim u ltaneously within 15 m i nutes after overflow at Stream 3 begins, and shall continue in a coordinated m a nner. Sam p ling shall be done in a m a nner that m i nim i zes headspace in each collected sam p le. No less than one sam p le per 15 m i nute 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) Autosam p ler

. Autosam p ling devices shall be installed and used to sam p le the wastewater in Streams 3 and 6. The autosam p ling devices shall be designed to m i nim i ze headspace in each collected sam p le and shall be installed and used in accordance with the m a nufacturer' s recom me ndations. 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 m o re autosam p lers to collect sam p les of Stream 3 and Stream 6 at the sam e intervals during the diversion event. Sam p les at Stream 6 shall be taken sim u ltaneously with the sam p les taken at Stream 3. After an initial sam p ling approxim a tely 5 m i nutes after overflow at Stream 3 begins, no less than one sam p le per every 15 m i nute 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 sam p les shall be analyzed in accordance with the procedures established in Subparagraph 2.d of this Appendix. EPA and ExxonMobil agree that the sam p les taken at Stream 3 are primarily for informational purposes, and m a y be useful to identify the source of benzene that m a y ultimately be discharged to the EBTU.
Appendix P - Page 4iv. A lternative 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 requirem e nt for monitoring, sam p ling, or analysis of wastewater pursuant to Subparagraphs 2.c.i, ii, or iii) if ExxonMobil submits as part of the W W TP Area Wa stewater 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 W WT P Area W a stewater 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 rem a in so unless EPA and the Applicable Co-Plaintiff are notified othe rwise. Upon such notification, ExxonMobil shall be required to com p ly with the terms of Subparagraphs 2.c.i - 2.c.iii. d. Analytical Requirem e nts

. i. Analytical Method

. For each wastewater sam p ling location (as described in Subparagraphs 2.a., 2.b., and 2.c. above), the W WT P Area W a stewater Monitoring Plan shall include a description of how each sam p le will be prepared in accordance with the Toxicity Characteristic Leaching Procedure (Method 1311 in EPA Publication SW

846), and a description of the m e thod by which the benzene content of the sam p le will be analyzed. Methods other than Method 1311 m a y be approved by EPA if ExxonMobil demonstrates statistical equivalency between contemporaneous sam p les analyzed by Method 1311 and the proposed alternative m e thod; ii. Requirem e nts Regarding Analysis of Each Sam p le

. Each individual grab sam p le taken pursuant to Subparagraphs 2.a., 2.b.iv, and 2.c. shall be analyzed for benzene by the m e thod stated in Subparagraph 2.d.i. above. Each 24-hour composite sam p le taken pursuant to Subparagraph 2.b.iii. shall be analyzed for benzene by the me thod stated in Subparagraph 2.d.i. above; iii. Mixed Stream s . The W WT P Area W a stewater Monitoring Plan shall describe the exact placement of the sam p ling devices and how ExxonMobil will ensure collection of a sam p le containing a m i xture of oil and water phases proportional to the volumes of the phases in the stream. The W WT P Area W a stewater Monitoring Plan shall state: (1) that sam p ling streams with lam i nar flow is not allowed, unless the entire stream can be collected for a short time; and (2) if sam p ling the total flow is not practical due to high volume, then sam p ling at a highly turbulent m i xing point will be done; iv. QA/QC

. The W WT P Area W a stewater 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 sam p les collected.

e. Failure to Sam p le or Analyze Sam p les Pursuant to the W WT P Area W a stewater Monitoring Plan

. In the event that ExxonMobil is unable, despite due diligence (e.g., inability Appendix P - Page 5due to power failures, equipment m a lfunctions, sam p le loss, safety issues, weather related problems), to obtain any sam p les (including individua l grabs to be composited) or to analyze any such sam p le(s) as required by this Paragraph and by the W WT P Area W a stewater Monitoring Plan, then such failure(s) shall not constitute a violation of this Consent Decree if ExxonMobil: (1) notes in the operating record any sam p ling f a ilures; (2) submits to EPA a written explanation of the sam p ling or analytical failure and all documentation related to the sam p ling or analytical failure within 30 business days from the failure; and (3) sum ma rizes any samp ling and analytical fa ilures in the W WT P Area Monitoring Plan Quarterly Reports and in the W W TP Area Monitoring Plan Final Report. Any such failure(s) m a y, 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 sam p ling and/or analyti cal failure and other relevant considerations. f. Precipitation Indicator

. The W WT P Area W a stewater Monitoring Plan shall include plans and a schedule f o r 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 e quipment 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 m a nufacturer' s recom me ndations for proper equipment operation. The parties recognize that wet weather flow to the wastewater treatm e nt plant m a y som e times begin subsequent to com me ncement of actual precipitation, and that wet weather flow to the SWDB and to Stream 3 m a y continue after rainfall ends. The parties agree that wet weather flow also includes draining of storm w ater from tank-dike d areas at the facility in connection with a precipitation event.
g. Snowm e lt

. The W WT P Area W a stewater Monitoring Plan shall include plans and a schedule for implementing a system for use in identifying and documenting snowm e lt events at the Joliet Refinery that cause wet weat her flow diversion of wastewater into the SWDB during the Monitoring Period. The system shall consist of m a king and recording the following m easurements on a daily basis when there is snow on the ground: daily snow depth (to be m easured at a single location within the refinery at approxim a tely the sam e time each day), the day's high tem p erature (which m a y 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 ma y be used as one means to support snowm e lt as a cause of diversion events that m a y occur in the absence of precipitation when ExxonMobil believes they were caused by snowm e lt. 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 m a de, 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 "im me diate 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 m a terial which, when discharged, becom e s a hazardous waste) into a surface impoundment, provided that such discharge is directly related to an unanticipated and Appendix P - Page 6extraordinary event (such as a catastrophic tank rupture or activation of the HF deluge system into the facility sewer system).
3. NPDES Permit Com p liance Monitoring Program

. a. ExxonMobil shall com p ly with all effluent limitations, permit conditions, and other requirem e nts 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 m a ke supplemental reports to EPA on its NPDES permit com p liance with respect to the effluent limitations and associated effluent monitoring requirem e nts as set forth in the NPDES Permit and as documented by the Discharge Monitoring Reports (“NPDES Permit Com p liance Monitoring”).
4. WWT P Area W a stewater Monitoring Plan Quarterly Reports

. ExxonMobil shall submit quarterly progress reports (“W WT P Area W a stewater Monitoring Plan Quarterly Reports”) to EPA on a quarterly basis during collection of data pursuant to W WT P Area Wa stewater Monitoring Plan. The W WT P Area W a stewater Monitoring Plan Quarterly Reports shall be due 30 days after the end of each quarterly monitoring period, or approxim a tely 120, 210, and 300 days into the Monitoring Period. The W WT P Area W a stewater Monitoring Plan Quarterly Reports shall sum ma rize the steps taken to implement the W W TP Area W a stewater Monitoring Plan. The data to be reported within the W WT P Area W a stewater 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 sam p le 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 spreadsheet s containing all samp le collection data points, including the date and time a sam p le was taken, and the benzene result; (8) all laboratory data related to the analysis of all SWDB and Streams 3 and 6 water sam p les, including but not limited to, documentation verifying that all QA/QC requirem e nts were m e t; and (9) a sum ma ry of all failures to sam p le or analyze sam p les in accordance with Paragraph 2 and the W W TP Area Wa stewater Monitoring Plan. b. For Stream 6 to the EBTU Composite and Grab Sam p les : (1) the date and benzene concentration measured for each daily composite influent sam p le to the EBTU; (2) Excel spreadsheets including all water flow measurement data points required under Subparagraph 2.b.; (3) Excel spreadsheets including all sam p le collection data points, including the date and time a sam p le was taken, and the benzene results on each 24-hour composite sam p le that was analyzed; (4) Excel spreadsheets including all sam p le collection data points, including the date and time a sam p le was taken, and the benzene results for each individual grab sam p le that was individually analyzed; (5) all laboratory data related to the analysis of all Stream 6 Appendix P - Page 7water sam p les, including, but not limited to, documentation verifying that all QA/QC requirem e nts were m e t; and (6) a sum ma ry of all failures to samp le or analyze samp les in accordance with Paragraph 2 and the W WT P Area W a stewater Monitoring Plan.

c. For NPDES Permit Requirem e nts : (1) the f i rst 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 requirem e nts 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. WWT P Area W a stewater 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 W WT P Area W a stewater Monitoring Plan Final Report. The W W TP Area W a stewater Monitoring Plan Final Report shall include:
a. A sum ma ry of all steps taken to implement the W WT P Area W a stewater Monitoring Plan and all data collected under the W WT P Area W a stewater 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 W W TP Area W a stewater 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 f o r 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 Comp any 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 adm i nistrative 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 st atutory, regulatory, or based upon EPA written guidance or federal court decisions, ExxonMobil m a y rely upon such change to m a ke appropriate contentions regarding its wastes; and further provided that in the event that (continued...) Appendix P - Page 8d. A description of any noncompliance issues identified in implementing the WWT P Area W a stewater Monitoring Plan, including a description of any confirm e d 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 labor atory reports associated with those Discharge Monitoring Reports; f. A description of noncompliance, if any, with the effluent limitations and associated effluent monitoring requirem e nts 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 Com p liance Monitoring; g. A plan and a schedule for implementing any measures necessary, if any, to bring the Joliet W WT P Area (including the SWDB and the EBTU) into f u ll com p liance with applicable legal requirem e nts. The comp liance measures shall include any reasonable physical/engineering/operational/compliance changes that are deemed necessary to com p ly with applicable legal requirem e nts. The Report shall be subject to review and approval by EPA and the Applicable Co-Plaintiff. ExxonMobil shall implement all com p liance measures set forth in the approved Report, in accordance with the schedule included in the W W TP Area W a stewater Monitoring Plan Final Report.
6. Sludge Characterization and Removal . W ithin 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 sam p ling, removal, and subsequent m a nagem e nt 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 f o r relevant toxicity characteristics under 40 C.F.R. Part 261, Subpart C prior to removal. The SWDB sludge shall, upon removal, be m a naged 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 m a y rely upon such change in that State to m a ke appropriate contentions regarding its wastes. Nothing herein shall preclude ExxonMobil from demonstrating that it has not m a naged 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 W a ste, Physical/Chem i cal 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 9b. EBTU

. (i) D ue 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 requirem e nts. (ii) The Sludge Characterization and Removal Plan shall include plans for additional sam p ling, removal, and subsequent m a nagem e nt of sludge from the EBTU. Sludge will be removed from the EBTU when deemed operationally necessary by ExxonMobil, but no later than 24 months af ter 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 ma naged in accordance with all applicable laws and regulations. Notwithstanding the above, if ExxonMobil determines that it has becom e 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 requirem e nts of this Paragraph shall be satisfied and no additional sam p ling, removal or subsequent m a nagem e nt 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 ma naged in accordance with applicable regulatory requirem e nts. 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 com p letion of the sludge removal effort. The documentation shall include any analytical data collected on the sludges and documentation showing the m a nner in which the sludge was removed, stored, and subsequently ma naged.
7. Aggressive Biological Treatm e nt

. By no later than 90 days of the Entry Date, ExxonMobil shall prepare and m a intain an Aggr essive Biological Treatm e nt 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 com p liance with the requirem e nts applicable to aggressive biological treatm e nt units listed hazardous waste exception under 35 Ill. Adm i n. Code § 721.131(b)(2)(A) and 40 C.F.R. § 261.31(b)(2). The Aggressive Biological Treatm e nt Plan shall include:

Appendix P - Page 10a. 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 norm a l operations, with the aeration system operating at m i nim um of 40 hp when the EBTU is fu ll, or with the aeration system operating at a m i nim um of 6 hp per million gallons of treatm e nt volume within the EBTU when the EBTU treatm e nt volume is less than capacity. The plan shall also identify procedures for addressing any aer ator 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 m a intain 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 treatm e nt (including the requirem e nts regarding horsepower and hydraulic retention time) under 35 Ill. Adm i n. Code § 721.131(b)(2)(A) and 40 C.F.R. § 261.31(b)(2).
8. Groundwater and Soil Characterization . W ithin 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 sum ma ry 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 sam p ling well locations, screening depths, soil sam p le locations, and groundwater and soil sam p ling results; b. A schedule for perform i ng and providing a hydrogeological survey in the SWDB and EBTU areas; c. A schedule f o r submitting and implementing a protocol f o r 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 m i gration 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 Character ization Plan Final Report shall, based on the data collected pursuant to the Groundwater and Soil Characterization Plan, propose corrective actions necessary, if any, to rem e diate 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 item s submitted by ExxonMobil pursuant to Paragraphs 1-8 Appendix P - Page 11above. 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 com b ination 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) com me nce 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 com me nce 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 dem a nded 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 th e 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 Decr ee 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 dem a nded under Section XI of the Consent Decree and (ii) EPA m a y modify and approve the item ; provided , however , that ExxonMobil shall not be liable for stipulated penalties if the stipulated penalties relate to a ma tter in which ExxonMobil prevails in dispute resolution. An item that is resubmitted with the sam e deficiencies that were identified in the no tice of disapproval or with substantially similar def i ciencies shall be deemed to have never been submitted f o r 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 m ay again require ExxonMobil to correct the deficiencies, in accordance with the procedure set forth in this Paragraph. EPA m a y also approve the item subject to conditions specified in the approval Appendix P - Page 12notice 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 com me nce implementation of the work required by the item in accordance with the schedule set forth in the item as approved, or ExxonMobil m a y invoke the dispute resolution procedures set forth in Sec tion 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 dem a nded under Section XI unless ExxonMobil prevails in such dispute resolution. g. All item s 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 item s 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 13Appendix P: Figure P-1
[Figure P-1 is on the follow i ng page]

Appendix P - Page 14Storm WaterDiversionBasinDiversionBoxPre-separationFlumesRefineryprocesswastewater/storm water(multiple inlets)13Inlet Structure4c4bOutlet BoxFlocAPISeparatorsDAFUnitWetweather flow and emergency overflowWestStormwaterBasinTransferSanitaryTreatmentGuardBasinWWTAreaStormwaterDrainage1112131516BoilerBlowdownS124a965FFEBTU87StormwaterDitch14Figure P-1FT-60064FT-60051outfall 001aeration basinsClarifiers, guardbasin andToStreamBz Sample PointFlow MetersPumpLevelControlLegendValve/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 m e ter to m easure the rate of water flow into the SWDB, and one or m o re autosam p lers to collect sam p les at intervals during the diversion event. The individual grab sam p les collected by the autosam p ler(s) will be analyzed pursuant to Subparagraph 2.d.i of Appendix P.
B. Sam p le Collection Interval ExxonMobil shall collect the first sam p le(s) within 15 m i nutes of the beginning of a discharge. Thereafter, if an autosam p ler is used, the interval between samp les will be based on pre-defined volumes of water that have flowed into the SWDB. If m a nual sam p ling is used, the interval between the sam p les will be based on pre-def i ned volumes of water that have f l owed into the SWDB to the extent practicable. These interval volumes m a y be adjusted by ExxonMobil either before a diversion event (for example, to accom m odate anticipated size of the storm ) or during a diversion event (for example, to accom m odate the conditions encountered during a diversion event). Changes to the sam p le collection interval will be m a de while keeping in m i nd the need to collect enough sam p les to adequately characterize changes in benzene concentration during the diversion event. Regardless of the above, however, ExxonMobil shall take at least 1 sam p le every 90 m i nutes during any release event. The following is an example of possible intervals for sam p le collection, illustrating the concept of variable samp le collection intervals. The flow rate of water entering the SWDB will be monitored and recorded at intervals no larger than five m i nutes. Sam p les after the first will be taken at intervals determined by the volume of water that has entered the SWDB since the previous samp le. For example, the next three sam p les m i ght 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 sam p les scheduled at increased gallon intervals as shown below.

Appendix P - Page 151
2 3
4 5
6
7 8 Samp le Samp ling V olume (gal) Nu mb er Ti me (min) Incre me nt 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 samp les 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 sam p le 1125.0 45,000 2,250,000 . . . until event ceases Hypothetical diversion event ended 1125 m i nutes after beginning. For sim p licity, in this hypothetical example the flow into the SWDB is assum e d to be constant at 2,000 gpm (except for the first 5 m i nute interval). In a real diversion event the flow will be calculated based on the measured values at intervals no larger than 5 m i nutes. 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 m a y 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 f l ow f r om the sam e rainf a ll, the total f l ow into the SWDB arising f r om the sam e rainfall event, whether diverted by one or m o re than one set of inlet valve open/close operations, will be evaluated as a single event, arising f r om a single storm

.

Appendix P - Page 16Appendix Q: Diesel Emissions Reduction SEPs ExxonMobil shall develop and satisfactorily com p lete 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 W o rk (“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 com p lete implementation of the approved SOW s by no later than December 31, 2009.
C. Project Criteria : ExxonMobil’s agreement with a third-party implementing a diesel emissions reduction SEP shall specif y that the SEP shall satisf y each of the f o llowing criteria and shall require the third-party to certify in writing to ExxonMobil and EPA that the following criteria have been m e t: 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 m a y provide also for incremental m a intenance costs and/or costs of repairs on such hardware for a period of up to four years after installation. Appendix Q - Page 14. It shall cover fleets for which the affected municipality, local governm e ntal entity, or other owner/operator has com m itted: (i) to m a intain any equipment installed in connection with the SEP during and after com p leti on of the SEP; (ii) to use ultra low-sulfur diesel f u el with the af f

ected vehicles during and after com p letion 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 m i nim u m 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 2Appendix R: Drawing of Real Estate Referenced in Consent Decree Subparagraph 156.d.(1)
[Appendix R is on the follow i ng 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 follow i ng page]LOCK OOD ROAD3rdST5+254thST002ndST9+55thST3+735thST4+757thST3+55 EFFLUENT

TCHKNOCKENGNEBLDG8thST8+7 OL AC

ATstST2+45BLDGADMAppendix T: Drawing of Joliet Material Staging Area Referenced in Consent Decree Subparagraph 135.a
[Appendix T is on the follow i ng page]