TSD-vFinal



## Final BART Determinations
for Affected BART-eligible Sources
in the State of New Jersey

Technical Support Document

State of New Jersey Department of Environmental Pro tection

Division of Air Quality

Bureau of Air Permits 401 E. State Street, 2 nd floor, P.O. Box 27 Trenton, NJ 08625-0027



## March 2, 20112

1.0 BEST AVAILABLE RETROFIT TECHNOLOGY (BART) DETERMINA TIONS

1.1 Introduction

To protect scenic areas across the United States ag ainst regional haze as required by the federal Clean Air Act (CAA), the United States Environmenta l Protection Agency (USEPA) published regulations that require certain types of existing sources of visibility impairing air pollutants install Best Available Retrofit Technology (BART) t o reduce such emissions. 1 On August 4, 2009, the New Jersey Department of Environmental Pr otection (NJDEP) submitted its State Implementation Plan (SIP) Revision for Regional Haz e to protect and enhance visibility levels in the Brigantine Wilderness Area of the Edwin B. Fors ythe National Wildlife Refuge, a federally designated Class I Area, to the USEPA. NJDEP ident ified five facilities in the SIP revision as potentially BART-eligible sources including one fos sil fuel-fire steam electric power plant and four petroleum refineries, and committed to complet e its review of facilities subject to BART in 2010. 2 These facilities are: 1) PSEG Hudson Generating S tation, 2) Chevron Products, 3) Amerada Hess Port Reading Refinery, 4) ConocoPhilli ps Bayway Refinery, and 5) Sunoco Eagle Point.

The listed facilities submitted their own BART anal ysis to NJDEP. 3 NJDEP’s review process to evaluate BART consisted of identifying 1) the facil ities that are BART-eligible; 2) the BARTeligible facilities that are subject to BART review ; and 3) the facilities that must comply with BART including controls, emission limits, and compl iance dates.

1.2 BART-Eligibility

To be BART-eligible a facility must belong to one o f 26 specific source categories with existing stationary emission units (or pieces of equipment) which meet specific criteria for start-up dates and potential emissions of visibility impairing pol lutants including NO x , SO 2 , and PM 10

. 4 The Mid-Atlantic/Northeast Visibility Union (MANE-VU) f ormed a BART workgroup consisting of member states and tribes to assist the region with the BART requirements of the Regional Haze rule including the identification of potentially BA RT-eligible sources and the emission units that comprise them. See Appendix A in NESCAUM’S 2007 re port, Five-Factor Analysis of BARTEligible Sources, for the final list of BART-eligib le sources in the MANE-VU region including New Jersey. 5 Upon reviewing the current potential emissions fr om the applicable equipment still in existence at each named facility, NJDEP determin ed that three of the five New Jersey facilities identified in Appendix A are BART-eligible sources. See Table 1 below.

1 http://www.epa.gov/fedrgstr/EPA-AIR/2005/July/Day-0 6/a12526.pdf

2 http://www.state.nj.us/dep/baqp/2008%20Regional%20H aze/Regional%20Haze%20SIP%20Final2009.pdf

3 http://www.state.nj.us/dep/baqp/2008%20Regional%20H aze/Appendix%20G-8%20%28Final%20Only%29.pdf

4 64 Fed . Reg . 35737; July 1, 1999

5 NESCAUM. Five-Factor Analysis of BART-eligible Sou rces Survey of Options for Conducting BART Determinations. Boston, MA; June 2007.3

Table 1 List of BART-eligible Sources in New Jersey

Cumulative visibility impairing pollutants from BART applicable equipment 1 Potential to Emit (PTE) in tons per year (tpy) Source category/ Facility NO x SO 2 PM 10 BART-eligible

source (PTE > 250 tpy) Power plants: PSEG Hudson 11,846.0 11,659.0 4483.8 Yes Petroleum refineries:

Chevron 262.2 40.5 32.7 Yes Amerada Hess 0.74 1.05 D 2 No ConocoPhillips 541.5 1829.5 66.0 Yes Sunoco Eagle Point 232.5 130.0 45.2 No

Notes: 1 equipment put in place August 7, 1962 through Augus t 7, 1977.

2 De minimis (D) – potential to emit below de minimis reporting threshold (0.05 pounds per hour)

1.2.1 Identification of BART-eligible Sources

NJDEP followed the step-by-step process for determi ning BART-eligibility provided in Appendix Y to Part 51, Section II. 6 The steps in identifying BART-eligible sources ar e:

Step 1: list existing equipment at facilities that fit any BART source category; Step 2: verify the start-up dates of the equipment and check if within the 1962-1977 time window; and Step 3: compare the cumulative potential emissions (PTE) from qualified equipment identified in Steps 1 and 2 to the 250 tons per year (tpy) cutoff for any single visibility impairing pollutant.

One of the MANE-VU BART workgroup’s recommendations was to handle emission units with unknown (UKN) start up dates as if they were instal led within the BART window. See recommendation 7. at Appendix C of the Five Factor Analysis report. 7 As a result, a large number of pieces of equipment were preliminarily id entified in this manner at the New Jersey

sources.

Tables 2 – 6 display the information gathered from the steps above for 1) Hess Corporation, Port Reading Refinery, 2) Sunoco, Eagle Point, 3) Chevro n Products, 4) ConocoPhillips Bayway Refinery, and 5) PSEG Fossil LLC Hudson Generating Station, respectively.

6 http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/4 0cfr51AppY.pdf

7 NESCAUM. Five-Factor Analysis of BART-eligible Sou rces Survey of Options for Conducting BART Determinations. Boston, MA; June 2007.4

1.2.2 Hess Corporation, Port Reading Refinery (PI#1 7996) – Woodbridge, Middlesex County

The Hess Port Reading petroleum refinery currently has one boiler (E66) that falls within the August 7, 1962 through August 7, 1977 BART time fra me. The permitted potential to emit (PTE) totals for this qualified unit are below the 250 tpy applicability threshold for NO x , SO 2 , and PM 10 (0.74, 1.05, and de minimis, 8 respectively), and therefore this source is not BA RTeligible. See Table 2 below.

Note that of all the equipment initially identified as being potentially subject to BART at this source, a large number of pieces comprised the wast ewater treatment plant. Since volatile organic compounds (VOCs) were the only pollutants e mitted from this emission unit, these pieces of equipment were not included in the cumula tive determination of the facility-wide PTE from qualified emission units. The fluidized catal ytic cracking unit (FCCU), also identified on the original list, falls outside the applicable tim e frame with installation occurring in 1960 and is not affected by BART.

Table 2 List of Equipment, Start-up Date, Potential Emissions, and Eligibility Determination – Hess Corporation, Port Reading Refinery

Hess Corporation, Port Reading Refinery (PI#17996) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E1 FCCU –– –– –– E2 SRU –– –– –– E3 FGR 1960 No

–– –– –– N/A

E5 Boiler #3 –– –– –– E6 Boiler #4 1984 No

–– –– –– N/A

E7 – 16 Waste Water Treatment Plant 1973 Yes N/A N/A N/A No 2

E64 Flare 1984 No –– –– –– N/A E66 Space Heating Boiler 1975 Yes 0.74 1.05 D 3 Yes 1

E69 Air Compressor 1997 No –– –– –– N/A E70 Truck Loading Rack P-1960 No –– –– –– N/A

E94 Marine Loading P-1959 No –– –– –– N/A E95 Boiler #1 –– –– –– E96 Boiler #2 –– –– –– E97 Boiler #3 1986 No

–– –– –– N/A

E67 Em. Generator 1984 No –– –– –– N/A

8 http://www.state.nj.us/dep/aqm/Sub8.pdf5

Hess Corporation, Port Reading Refinery (PI#17996) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E2001 HDS Unit Process Heater 2006 No –– –– –– N/A

E2002 Hydrogen Unit Process Heater 2006 No –– –– –– N/A

E2003 E&I Shop Boiler 2002 No –– –– –– N/A

Visibility Impairing Pollutants NO x SO 2 PM 10 PTE Totals (tpy): 0.74 1.05 D 3 < 250 Notes: 1 equipment with applicable emissions to be considere d cumulatively in determining the facility’s BART eligibility

2 not applicable (N/A) – potential emissions from VOC s only
3 De minimis (D) – potential to emit below de minimis level (less than 0.05 pounds per hour)

1.2.3 Sunoco, Eagle Point (PI#55781) – formerly Coa stal Eagle Point, Westville, Gloucester County

The Eagle Point petroleum refinery currently has 11 process heaters and two diesel pumps that fall within the BART time frame. However, the perm itted PTE totals from the qualified units are below the 250 tpy applicability threshold for NO x , SO 2 , and PM 10 (232, 130, and 45, respectively), and therefore this source is not BAR T-eligible. See Table 3 below.

Note that some of the process heaters initially ide ntified as being potentially subject to BART were taken out of service and subsequently removed from the Title V operating permit. All the remaining units have low NO x burners (LNB) and, in any case, are subject to the requirements of an enforceable consent decree (CD) effective as of December 31, 2006. 9

Table 3 List of Equipment, Start-up Date, Potential Emissions, and Eligibility Determination – Sunoco, Eagle Point Sunoco, Eagle Point (PI#55781) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E5 – 7 VPS heaters HA-1, 3A & 3B 1949 No –– –– –– N/A

E8 VPS heater HA-4 1956 No –– –– –– N/A

9 http://www.state.nj.us/dep/baqp/2008%20Regional%20H aze/Appendix%20G%20- %20BART%20Documentation/Appendix%20G-7_Coastal%20Co nsent%20Decree.pdf6

Sunoco, Eagle Point (PI#55781) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E12 FCCU heater 5A 1971 Yes 4.47 4.90 1.80 Yes 1

E412 FCCU heater 5B 1971 Yes 4.47 4.90 1.80 Yes 1

E13 FCCU regenerator 1949 No –– –– –– N/A

E22 – 27 FCCUcompressor engines J15A – F 1949 No –– –– –– N/A

E28 - 30 FCCU heaters B-2, B-3 & B-4 1949 No –– –– –– N/A

E32 Poly heaterB301 1949 No –– –– –– N/A E37 HTU #1 heater 1956 No –– –– –– N/A E39 ISOM PH-1 1953 No –– –– –– N/A E43 Slop oil sump 1972 Yes N/A N/A N/A No 2 E44 ULSD process heater 2H-201 1972 Yes 5.26 1.54 2.72 Yes 1

E45 ULSD process heater 2H-202 1972 Yes 23.0 10.5 4.25 Yes 1

E47 – 48 Cumene loading spots #1 & #2 1960 No –– –– –– N/A

E55 CRU PH-6 1979 No –– –– –– N/A E56 CRU heater PH-1 1967 Yes 18.6 16.6 4.40 Yes 1

E57 CRU heater PH-2 1967 Yes 16.0 14.2 3.77 Yes 1

E58 CRU heater PH-3 1967 Yes 30.3 17.4 6.4 Yes 1

E59 CRU heater PH4A 1967 Yes 43.2 24.9 9.1 Yes 1

E60 CRU heater PH4B 1967 Yes 15.9 9.1 3.4 Yes 1

E62 CRU heater PH5B 1967 Yes 53.9 13.2 2.76 Yes 1

E65 CRU heater HC301 1967 Yes 13.0 12.5 0.96 Yes 1

E67 SRU1 complex 1995 No –– –– –– N/A E6702 SRU2 process 2005 No –– –– –– N/A E77 Sour water stripper –– –– ––

E78 Oil skimmer vessel 1994 No

–– –– –– N/A

E415 East side flare 1967 Yes N/A N/A N/A E416 West side flare 1949 No N/A N/A N/A E417 Ground ZTOF 1995 No N/A N/A N/A No 37

Sunoco, Eagle Point (PI#55781) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

flare E81 Sulfolane/clay treater unit, FL1 N/A N/A N/A

E82 CRU-2 /HTU-4, FL2 1967 Yes

N/A N/A N/A

E83 Hydrotreater 1, FL3 1956 No N/A N/A N/A

E84 ULSD unit, FL4 2006 No N/A N/A N/A E85 ISOM /HTU-2, FL5 1953 No N/A N/A N/A

E86 Vacuum pipestill, FL6 N/A N/A N/A

E87 FCCU, FL7 N/A N/A N/A E88 Catalytic poly unit, FL8 1949 No

N/A N/A N/A

E89 Cumene unit, FL9 1960 No N/A N/A N/A

E90 Sulfur recovery unit, FL10 1995 No N/A N/A N/A

E91 Alkylation unit, FL11 1953 No N/A N/A N/A

E92 Powerhouse, FL12 2002 No N/A N/A N/A

E93 WWTP, FL13 1972 Yes N/A N/A N/A E94 API separator 1949 No N/A N/A N/A E95 API thickener N/A N/A N/A E97 Aeration basin 1972 Yes N/A N/A N/A E96 Dock sump 4/10/77 Yes N/A N/A N/A No 2

E98 WWTU – em. diesel pump 1972 Yes 1.50 0.10 3.42 Yes 1

E99 Handex 1992 No N/A N/A N/A N/A E142 River pump diesel fire pump driver UNK Yes 2.9 0.2 0.4 Yes 1

E310 Brinemaker #1 –– –– –– E311 Brinemaker #2 1984 No

–– –– –– N/A

E318 Duct burner – gas turbine #1 –– –– ––

E319 Gas turbine #1 –– –– –– E320 Duct burner – gas 1990 No

–– –– –– N/A8

Sunoco, Eagle Point (PI#55781) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

turbine #2 E321 Gas turbine #2 –– –– –– E325 Diesel fire pump 1990 No –– –– –– N/A E334 J15G FCCU

compressor engine 1997 No –– –– –– N/A

E341 Boiler 5 –– –– –– E342 Boiler 6 –– –– –– E343 Boiler 7 –– –– –– E344 Boiler 8 2001 No

–– –– –– N/A

E5600 Distillate fired engine –– –– ––

E5601 Distillate fired boiler 1 –– –– ––

E5602 Distillate fired boiler 2 Temporary mobileequipment as needed No

–– –– –– N/A

E5501 5 LSG preheat reactor furnace –– –– ––

E5501 6 LSG stripper reboiler 2005 No

–– –– –– N/A

Visibility Impairing Pollutants NO x SO 2 PM 10 PTE Totals (tpy): 232.5 130.0 45.2 < 250 Notes: 1 equipment with applicable emissions to be considere d cumulatively in determining the facility’s BART eligibility

2 not applicable (N/A) – potential emissions are VOCs only

3 not applicable (N/A) – flare control system was as signed NJID E415 – 417 and E81 – 93 as a permit workaround to ensure that enforceable operat ional requirements for these flares are part of the compliance plan

1.2.4 Chevron Products (PI#18058) – Perth Amboy, Mi ddlesex County

Chevron currently has two refinery fuel gas-fired f urnaces (E1501 and E1502) that fall within the applicable BART time frame. The NO x emissions from E1501 and E1502 cumulatively exceed the PTE threshold and make this facility a BART-eli gible source. See Table 4 below. However, Chevron proposed an enforceable permit limit to cap out this facility’s NO x emissions to less than the 250 tpy PTE cutoff from the two qualified furnaces. See Section 1.5.1 for details.

Note that of all the equipment initially identified as being potentially subject to BART at this source, a large number of pieces comprised the wast ewater treatment plant. Since VOCs are the9

only pollutants emitted from this emission unit, th ese pieces of equipment were not included in the cumulative determination of the facility-wide P TE from qualified emission units. Also a process heater, E1601, initially identified as bein g potentially subject to BART, was taken out of service and subsequently removed from the Title V o perating permit.

Table 4 List of Equipment, Start-up Dates, Potentia l Emissions, and Eligibility Determination – Chevron Products

Chevron Products (PI#18058) Identify equipment Verify dates If yes, compare PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E1002 Barge Berth 1975 Yes N/A N/A N/A No 5

E1501 Atmospheric crude furnace 1976 Yes 181.3 28.0 18.9 Yes 1

E1502 Vacuum crude furnace 1976 Yes 80.9 12.5 13.9 Yes 1

E1601 Hot oil heater 1976 Yes –– –– –– No 6

E1801 North Flare 1976 Yes N/A N/A N/A No 3

E2001 #3 API separator diversion box N/A N/A N/A

E2002 #3 API separator forebay N/A N/A N/A

E2003 #3 API separator N/A N/A N/A E2004 - 2005 IAF units N/A N/A N/A

E2006 Equalization tank N/A N/A N/A E2007 Oily water bin N/A N/A N/A E2008 Oil bin N/A N/A N/A E2009 Stormwater diversion box N/A N/A N/A

E2010 Float separation box N/A N/A N/A

E2011 Sludge mixing tank N/A N/A N/A

E2012 Sludge settling tank 1977 Yes

N/A N/A N/A No 2

E2301 Desalting water drum 1975 Yes N/A N/A D 4 No

E2401 Light products loading rack – AER incinerator 1975 Yes N/A N/A N/A No 310

Chevron Products (PI#18058) Identify equipment Verify dates If yes, compare PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

Visibility Impairing Pollutants NO x SO 2 PM 10 PTE Totals (tpy): 262.5 40.5 32.7 > 250 Notes: 1 equipment with applicable emissions to be considere d cumulatively in determining the facility’s BART eligibility

2 not applicable (N/A) – potential emissions from VOC s only
3 not applicable (N/A) – control device, CD2401, was assigned an Equipment NJID as a permit workaround to ensure enforceable operational requir ements of this flare are part of the compliance plan to control VOC while loading gasoli ne 4 De minimis (D) – potential to emit below de minimis level (less than 0.05 pounds per hour) 5 not applicable (N/A) – potential emissions are comb ustion byproducts of the marine vapor control, CD1001, used to control VOC from product l oading arm

6 equipment is demolished and removed from the Title V permit

1.2.5 ConocoPhillips Bayway Refinery (PI#41805) – L inden, Union County

Bayway petroleum refinery currently has 11 process heaters that fall within the applicable BART time frame. The cumulative permitted PTE from thes e qualified units exceed the BART threshold for NO x and SO 2 emissions (541.5 and 1829.5, respectively), and th erefore this facility is a BART-eligible source. See Section 1.5.2 for d etails regarding existing controls and proposed BART.

Note that of all the equipment initially identified as being potentially subject to BART at this source, a large number of pieces comprised the wast ewater treatment plant. Since VOCs were the only pollutants to be emitted from this emissio n unit, these pieces of equipment were not included in the cumulative determination of the fac ility-wide PTE from qualified emission units. The FCCU emission unit, also identified on the orig inal list, falls outside the applicable time frame with installation occurring in 1949 and is no t affected by BART.

SO 2 and PM 10 emissions from two process heaters, E242 and E250, were considered in netting for modifications incorporated into the facility’s PSD permit in 2004 in order to meet the USEPA’s low sulfur gasoline requirements, and may n ot be subject to BART for these two visibility impairing pollutants. In any case these heaters are subject to federal Subpart J – Standards of Performance for Petroleum Refineries ( NSPS subpart J) that regulates the H 2 S content in refinery fuel gas. See section 1.5.2.

One heater, E244, with a start up date of 1969, suf fered extensive damage from a fire in the late 1990’s that required reconstruction. According to ConocoPhillips, the reconstruction exceeded 50 percent (%) of the replacement cost of the heate r. 10 Consequently this heater is subject to

10 http://edocket.access.gpo.gov/cfr_2006/julqtr/pdf/4 0cfr51.301.pdf11

NSPS subpart J standards for particulate matter, ca rbon monoxide and sulfur oxides that are included in the facility’s Title V operating permit . Sources reconstructed after 1977, which reconstruction had gone through NSR/PSD permitting, are not BART-eligible. 11 To summarize, process heater E244 is therefore not affected by BA RT because this unit meets USEPA's BART exemption guidance in Appendix Y for a "reconstruct ed" unit for the following reasons: (1) the reconstruction date was after August 7, 197 7; (2) the reconstructed unit went through NSR/PSD per mitting; and (3) the fixed capital cost of the new component exc eeds 50 percent of the fixed capital cost of a comparable entirely new source. See Appendix A to this Technical Support Document ( TSD) for ConocoPhillips' email confirming this information.

The Sulfur Recovery Unit (SRU), E266, that was incl uded in the initial list of potentially BART qualified equipment, has been dismantled and, after confirmation by NJDEP’s Regional Enforcement Office, was subsequently removed from t he equipment list. See Table 5 below.

Table 5 List of Equipment, Start-up Date, Potential Emissions, and Eligibility Determination – ConocoPhillips Bayway Refinery ConocoPhillips Bayway Refinery (PI#41805) Identify equipment Verify dates If yes, compare PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E241 F-101 PFBW hydrofiner heater 1969 Yes 30.7 170.4 6.57 Yes 1

E242 F-101 DSU-1 gas oil heater 1969 Yes 22.3 N/A 6 N/A 6 Yes 1

E244 F-102 DSU-1 Treat Gas heater 1969 Yes –– –– –– No 5

E243 F-102 PFBW Reheat heater E245 F-103 PFBW Reheat heater E246 F-104 PFBW Reheat heater E247 F-105 PFBW Reheat heater 1971 Yes 186 1066.5 24.6 Yes 1

E248 F-106 PFBW Regen Gas heater 1971 Yes 27.6 157.2 6.1 Yes 1

E249 F-107 PFBW Dryer heater 1971 Yes 9.0 23.7 0.88 Yes 1

E250 F-108 PFBW 1971 Yes 47.3 N/A 6 N/A 6 Yes 1

11 http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/4 0cfr51AppY.pdf12

ConocoPhillips Bayway Refinery (PI#41805) Identify equipment Verify dates If yes, compare PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

Reboiler heater E251 F-251 FCCU feed preheat heater 1949 No –– –– –– N/A

E253 F-401 DSU-2 Reactor heater 1972 Yes 60.9 330.7 4.4 Yes 1

E254 F-401 DDU heater Oct 77 No –– –– –– N/A

E255 F-601 CNH heater Oct 77 No –– –– –– N/A

E256 F-601 ISOM Purge Gas heater Oct 77 No –– –– –– N/A

E257 F-701 Pipestill Atmospheric heater 1970 Yes N/A N/A N/A No 7

E258 F-702 OBFT Outboard Flash heater 1970 Yes 157.7 81.0 23.4 Yes 1

E259 F-752 Vacuum Tower heater 2009 No –– –– –– N/A

E260 ISOM Reactor Charge heater Oct 77 No –– –– –– N/A

E261 ISOM Reactivation Gas heater Oct 77 No –– –– –– N/A

E262 SDA Hot Oil heater Oct 77 No –– –– –– N/A

E263 –E265 FCCU regenerator and catalyst hoppers 1949 No –– –– –– N/A

E266 Sulfur recovery Claus plant 1967/74 Yes –– –– –– No 3

E186 –E189 Stretford tanks 1974 Yes N/A N/A N/A No 4

E267 Cooling Tower UNK N/A N/A N/A N/A No 4

E268 –E270 PFBW vents 1971 Yes N/A N/A N/A No 2

E271 –E272 Marine loading operations 1990 No –– –– –– N/A

E273 –E274 Truck loading operations UNK N/A N/A N/A N/A No 213

ConocoPhillips Bayway Refinery (PI#41805) Identify equipment Verify dates If yes, compare PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E275 –E277 E279 Emergency flares (pilot flame only) 1941 –

1949 No –– –– –– N/A

E280 –E282 E294 1916 – 1945 No –– –– –– N/A

E295 –E296 Oct 77 No –– –– –– N/A

E301 Wastewater

treatment

UNK N/A N/A N/A N/A No 2

E292 Fixed roof tank UNK N/A N/A N/A N/A No 4

E299 Fixed roof tank 1997 No –– –– –– N/A E302 Temp. catalyst additive hopper 1997 No –– –– –– N/A

E502 Hydrogen plant heater 2006 No –– –– –– N/A

E503 Hydrogen 2006 No –– –– –– N/A E504 Merifiner thermal oxidizer 2006 No –– –– –– N/A

E1003 -1010, E1013 -1015, E1116 Polypropylene unit 2003 No –– –– –– N/A

E1302 –1304 Diesel engines - concrete crusher 2001 No –– –– –– N/A

Visibility Impairing Pollutants NO x SO 2 PM 10 PTE Totals (tpy): 541.5 1829.5 66.0 > 250 Notes:
1 equipment with applicable emissions to be considere d cumulatively in determining the facility’s BART eligibility

2 not applicable (N/A) – potential emissions from VOC s only
3 equipment is demolished and removed from the Title V permit

4 not applicable (N/A) – potential emissions from pol lutants other than NO x , SO 2 , or PM 10 5 reconstruction commenced after August 7, 1977

6 not applicable (N/A) – SO 2 and PM 10 emissions considered in PSD netting (2004) for the Clean Fuels project

7 SOTA (ULNB + SCR) 2004, 2007 – NO x , 0.03 lb/MMBtu; H 2 S, 0.10 gr/dscf (or 162 ppmvd)

1.2.6 PSEG Fossil LLC Hudson Generating Station (PI #12202) – Jersey City, Hudson County14

Hudson Generating Station currently has four pieces of equipment that fall within the BART time frame with permitted PTE totals above the 250 tpy applicability threshold for NO x , SO 2 , and PM 10 (11,846, 11,659, and 4483.8, respectively), and th erefore this facility is a BARTeligible source. See Section 1.6.1 for details reg arding existing controls and BART determinations.

Unit 2 (E2) is a coal-fired boiler and subject to s tate-of-the-art controls and federally enforceable emission limits by December 31, 2010, due to an enf orceable consent decree (CD). 12 Required controls include year-round operation of selective catalytic reduction (SCR); flue gas desulfurization (FGD) and full-size baghouse. The Unit 1 boiler (E1) is uncontrolled and primarily combusts natural gas, but is permitted to burn No. 6 fuel oil.

The coal receiving system (E22) and the coal reclai m system (E23) are support systems to E2 with the potential to emit particulate emissions on ly. The conveying systems are covered and the coal piles are controlled with aqueous spray dust s uppression systems. See Table 6 below.

Table 6 List of Equipment, Start-up Date, Potential Emissions, and Eligibility Determination – PSEG Fossil LLC Hudson Generating Station PSEG Fossil LLC Hudson Generating Station (PI#12202 ) Identify emission units Verify dates If yes, compar e PTE to 250 tpy cutoff Potential to Emit (PTE) in tons per year (tpy) Equip. NJID Equipment Description Start-up

Date 8/7/62 –

8/7/77 NO x SO 2 PM 10 BART eligible

E1 Unit No.1 boiler 1964 Yes 8,360 6,389 1,996 3 Yes 1 E2 Unit No.2 boiler 1968 Yes 3,486 5,270 2,480 3 Yes 1 E14 Em. Fire pump 1963 Yes N/A N/A N/A No 4 E22 Coal receiving system 1968 Yes N/A N/A 5.4 2 Yes 1

E23 Coal reclaim system 1968 Yes N/A N/A 2.4 2 Yes 1

Visibility Impairing Pollutants NO x SO 2 PM 10 PTE Totals (tpy): 11,846 11,659 4483.8 > 250 Notes:
1 equipment with applicable emissions to be considere d cumulatively in determining the facility’s BART eligibility

2 includes quantifiable fugitive emissions counted fo r comparison purposes to the 250 tpy cutoff
3 TSP potential to emit – PM 10 to be established (refer to BOP100001)
4 replaced in 1985-1986 timeframe

1.3 Subject to BART

12 http://www.epa.gov/compliance/resources/cases/civil /caa/psegfs.pdf15

Based on the cumulative assessment of all BART-elig ible sources in the MANE-VU region, all member states with BART-eligible facilities contrib ute to visibility impairment at Class I areas. 13 Therefore, as a member state of MANE-VU, the State of New Jersey adhered to the MANE-VU Board decision that any source that meets the BART eligibility requirements is subject to BART review. 14 Of the five potentially BART-eligible sources, or facilities, in New Jersey, three are subject to BART review. These facilities are: 1) C hevron Products, 2) ConocoPhillips Bayway Refinery, and 3) PSEG Hudson Generating Station.

1.4 Evaluation of BART Analyses

For each qualified emission unit at an eligible fac ility, BART must be established for pollutants reasonably anticipated to impair visibility. The t hree New Jersey facilities which are subject to BART submitted emissions control analyses that incl uded analytical information about affected equipment; existing controls in use; available retr ofit controls; technical feasibility; costs of compliance; remaining useful life; energy and other environmental impacts as applicable; and other supporting data. NJDEP developed tables summ arizing each facility’s current compliance requirements, including enforceable consent decree requirements and recent rule development, and proposed BART alternatives, to help determine t he best control options, establish emission limits, and set compliance deadlines for the qualif ied emission units. 15

1.5 Petroleum Refineries

Petroleum refineries are one of 26 specific categor ies identified as being applicable to the BART requirement. The qualifying emission units at Chev ron and ConocoPhillips that are subject to BART review are process heaters that combust refine ry fuel gas, and natural gas in a few cases. Table 7 lists a number of available retrofit contro l measures to reduce NO x , SO 2 and PM 10 emissions from process heaters at petroleum refiner ies.

According to USEPA there are a number of available control alternatives to reduce NO x emissions from process heaters. 16,17,18,19, 20 Control techniques include combustion modifications to help prevent the formation of NO x such as low NO x burners (LNB), ultra low NO x Burners (ULNB), and flue gas recirculation (FGR). In addition, there are add-on NO x controls including selective catalytic reduction (S CR) or selective non-catalytic reduction (SNCR). These post-combustion controls can be used either alone or in conjunction with combustion control techniques as illustrated below in Table 7. The effectiveness levels of the controls, ranked from most to least, indicate best control for new heaters. Existing process

13 NESCAUM. Five-Factor Analysis of BART-eligible Sou rces Survey of Options for Conducting BART Determinations. Boston, MA; June 2007.

14 Ibid.

15 http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/4 0cfr51AppY.pdf

16 http://www.epa.gov/ttn/catc/dir1/procheat.pdf , p.24

17 http://www.epa.gov/visibility/pdfs/bart_ria_2005_6_ 15.pdf , p.8-19

18 http://www.epa.gov/ttn/catc/dir1/fnoxdoc.pdf , p.36

19 http://www.epa.gov/ttnnaaqs/ozone/ctg_act/199309_no x_epa453_r-93-034_process_heaters(rev).pdf , p.2-8

20 http://www.epa.gov/visibility/pdfs/bart_ria_2005_6_ 15.pdf , p. 3-716

heaters throughout the petroleum refinery source ca tegory are commonly retrofit with LNBs and ULNBs. SCR retrofits are less widely in use due to space constraints and other factors such as size, utilization rate, and temperature range. 21 According to USEPA SNCR is generally not used. 22

Refinery fuel gas contains varying concentrations o f hydrogen sulfide (H 2 S). Petroleum refineries commonly employ amine scrubbing to proce ss, or condition, the refinery fuel gas to reduce the levels of H 2 S before combustion in the process heaters to reduc e SO 2 emissions. Add-on SO 2 and PM 10 controls for individual refinery fuel gas-fired pr ocess heaters are not used in practice due to the low sulfur level after in-pr ocess gas conditioning. As the sulfur content in fuel decreases, the cost per ton of control for ind ividual units to remove additional sulfur increases. 23

Table 7 List of Potential Retrofit Emission Control Techniques for Process Heaters at Petroleum Refineries Potential Retrofit Control Techniques for Process H eaters at Petroleum Refineries Pollutant Available control

options Percent (%)

reduction Potentially applicable Technically feasible

1. ULNB + SCR 85 – 99 Yes Case-by-case 1

2. ULNB + SNCR 75 – 95 Yes No 2 3. SCR 80 – 90 Yes Case-by-case 1

4. ULNB 75 – 85 Yes Yes 5. SNCR 30 – 75 Yes No 2

6. LNB + FGR 50 – 72 Yes Yes NO x

7. LNB 50 Yes Yes

1. Fuel switching > 95 Yes Yes 2. Fuel processing 90 Yes No 3 SO 2

3. Scrubbers 90 – 99.9 No No 4

1. Wet scrubbers 2. ESP 90 No No 4 PM 10

3. Good combustion practices Yes Yes Notes: 1 Case-by-case – not widely in use on process heaters within the industry

2 Not reasonably applicable – temperature dependent a nd limited operating range
3 Not practically applicable to individual process he aters – typically in-process gas treatment

4 Not practically applicable to refinery fuel gas if already low sulfur concentrations

New Jersey regulates NO x emissions from process heaters under N.J.A.C. 7:27 -19.7(h). Any process heater located at a petroleum refinery that is rated 50 million BTU per hour (MMBtu/hr), or greater, and that combusts refinery fuel gas, sh all emit NO x at a rate no greater than the applicable maximum allowable NO x emission rate of 0.20 pound per million BTU (lb/MM Btu). 24 The State of the Art (SOTA) performance emission le vel for NO x from NJDEP’s SOTA Manual

21 http://www.4cleanair.org/PM25Menu-Final.pdf , p.162

22 http://www.epa.gov/ttn/nsr/gen/refbact.pdf , p.3-9

23 http://www.epa.gov/visibility/pdfs/bart_ria_2005_6_ 15.pdf , p.8-25

24 http://www.state.nj.us/dep/aqm/Sub19.pdf , p.4217

for Petroleum Refineries is 0.07 lb/MMBtu for burner replacement. 25 Certain petroleum refineries, like ConocoPhillips, are also subject t o enforceable consent decrees (CD) that require process heaters greater than 40 MMBtu/hr to reduce emission rates to 0.04 lb/MMBtu, or less. NJDEP used these emission levels as a baseline in d etermining BART. See Table 8 below.

Table 8 Comparison of NO x Performance Limits for Process Heaters Located at Petroleum Refineries

NO x limits RACT

N.J.A.C. 7:27-19.7 SOTA Manual Consent Decree (typical from USEPA refinery initiative) lb/MMBtu 0.20 0.07* 0.04 *performance limit for burner replacement

The process heaters under consideration in this doc ument are subject to federal Subpart J – Standards of Performance for Petroleum Refineries ( NSPS Subpart J) 26 that requires H 2 S content in refinery fuel gas be less than 162 ppmvd (or 0.1 gr/dscf).

In addition N.J.A.C. 7:27-19.7(g) requires annual c ombustion adjustments for process heaters with a maximum gross heat input rate of at least fi ve million BTU per hour, or greater.

1.5.1 Chevron (PI#18058) BART Analysis

The two refinery fuel gas-fired furnaces, E1501 and E1502, referred to by Chevron as the Crude Unit Heaters, comprise the BART-eligible source. H owever, the Crude Unit Heaters have been idling for several years as illustrated in Table 9 below, and did not operate in 2009 as reported to NJDEP in its electronic emission statement.

Table 9 Summary of 2002 – 2009 Annual Emissions of Visibility Impairing Pollutants – Chevron (PI#18058) Equip. NJID E1501-Atmospheric Crude Furnace F501 E1502-Vacuum C rude Furnace F510

NO x NO x SO 2 PM 10 NO x NO x SO 2 PM 10 Pollutant lb/MMBtu* tons per year (tpy) lb/MMBtu* tons per year (tpy) Year 2002 0.15 109.41 9.25 2.43 0.10 11.68 1.47 1.17 2003 0.16 105.77 8.37 9.80 0.10 9.88 1.20 2.06 2004 0.16 115.20 9.31 10.67 0.10 11.39 1.41 2.38 2005 0.16 99.96 7.06 9.26 0.10 13.65 1.48 2.85 2006 0.16 87.12 4.74 8.07 0.10 16.05 1.34 3.35 2007 0.16 46.82 3.09 4.34 0.10 6.12 0.62 1.28 2008 0.14 19.09 1.16 1.60 0.08 2.01 0.23 0.11 2009** –– –– –– –– –– –– –– ––

25 http://www.state.nj.us/dep/aqpp/downloads/sota/sota 3.pdf , p.3.3-6

26 http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=185bdc165a6c68b9a1df1bc3fa8e658c&rgn =div6&view=text&node=40:6.0.1.1.1.21&idno=4018

* based on stack testing ** source did not operate

Chevron reported that no decision has been made to restart the Crude Unit to date. Consequently, given the operational history of thes e two furnaces, Chevron proposed to cap out the annual potential to emit NO x from these BART qualified heaters to less than 250 tons per year. This is consistent with the MANE-VU Air Dire ctors’ recommendation that by accepting a permit limit, a facility may “cap-out” of BART-elig ibility. See recommendation 1. at Appendix C of the Five Factor Analysis report. 27

Chevron proposed that the annual fuel input for eac h furnace be limited to approximately 95 percent of the current allowable limits in its Titl e V operating permit. The annual BTU consumption is continuously monitored using a flow rate meter and heat content analyzer. 28 Accordingly, the cumulative annual allowable NO x PTE from E1501 and E1502 will be reduced by five percent to 249 tpy from 262.5 tpy which is below the 250 tpy BART eligibility cutoff. The facility is required to annually report process information such as the amount of fuel burned and actual emission rates for each process heater t o NJDEP through the Emission Statements program according to N.J.A.C. 7:27-21. 29 See Table 10 below.

Chevron submitted a permit modification (BOP100001) to NJDEP on December 8, 2010 requesting the proposed BART requirements be incorp orated as part of its operating permit conditions for the Crude Unit Heaters. See Appendi x B at the end of this TSD. If the decision is made to restart the Crude Unit, and Chevron request s an increase in PTE that results in cumulative NO x emissions greater than 250 tpy from these two qual ified furnaces, then E1501 and E1502 shall be subject to BART and the facility ’s operating permit must be revised to include new applicable requirements.

Table 10 Summary of Final Permit Limits to Cap NO x Emissions below 250 tpy from Qualified Equipment at Chevron (PI#18058) Annual Heat Input*

Existing Proposed Proposed Potential to Emit (PTE) Equip. NJID Equipment Description Proposed

permit restriction (Btu/yr) (Btu/yr) (tpy) Proposed compliance date

E1501 F-501 Atmospheric crude furnace Reduce

annual heat input 2,189.3 billion

(any consecutive 365-day period) BOP090002 2,079.8 billion

(any consecutive 365-day period) 172 March 15, 2011

E1502 F-510 Vacuum Reduce

annual heat 941.7 billion

(any 894.6 billion

(any 77 March 15, 2011

27 NESCAUM. Five-Factor Analysis of BART-eligible Sou rces Survey of Options for Conducting BART Determinations. Boston, MA; June 2007.

28 http://datamine2.state.nj.us/DEP_OPRA/OpraMain/REPO RT_FACADE?id=a8acb14d9d3f4b1ed49bfb952e12a64 1fde1122acf05d1217e9938b3612795d0deec0b282a8f7fcd52 67954f6e3d16a3450764cfda6b46a0f4c0161c228a622c b68baec4c3656669a71adb7b1bd8c7d987945fa168fd23ba

29 http://www.state.nj.us/dep/aqm/Sub21.pdf19

crude furnace input consecutive 365-day period) BOP090002 consecutive

365-day period)

Total (tpy): 249 (<250) *natural gas or refinery gas

1.5.2 ConocoPhillips Bayway Refinery (PI#41805) BAR T Analysis

The USEPA undertook an enforcement initiative focus ed on Clean Air Act compliance violations within the petroleum refinery sector wit h respect to New Source Review (NSR)/Prevention of Significant Deterioration (PSD) and New Source Performance Standards (NSPS). On January 27, 2005, the United States Dep artment of Justice (USDOJ), USEPA, and NJDEP entered into an enforceable consent decree (C D) 30 with ConocoPhillips including its New Jersey refinery. The types of equipment that a re affected by the terms of the CD include: fluidized catalytic cracking units (FCCUs); heaters and boilers; flares; and sulfur recovery units (SRUs). The resulting CD primarily requires reduct ions of nitrogen oxide and sulfur dioxide, precursors to fine particulate matter. 31 Bayway petroleum refinery currently has 11 refine ry fuel gas-fired process heaters that are subject to BART and the requirements of the CD. See Table 11 below.

Table 11 Summary of Consent Decree Requirements for Combustion Units – ConocoPhillips Equipment NJID Pollutant Control strategy Emission limit Compliance date Combustion units – 30% total allowable heat input capacity incl: E241 E242 E243 E245 E246 E247 E248 E250 E253 E258 One, or any

combination: SCR or SNCR; ULNB; or other qualifying technologies 12/31/2008

E257 E259 NO x

SCR 0.040 lb/MMBtu, or lower

12/31/2010* Upgrade gas system** 40 CFR 60 Subpart J - H 2 S, 0.10 gr/dscf (or 162 ppmvd) 06/30/2011 E241 E242 E243 E245 E246 E247 E248 E249 E250 E253 E258 SO 2

Eliminate fuel oil N/A 01/27/2005

30 http://www.epa.gov/compliance/resources/cases/civil /caa/conocophillips.html

31 http://www.epa.gov/particles/basic.html20

Equipment NJID Pollutant Control strategy Emission limit Compliance date burning*** * BOP070011 modification ** Upgrade refinery fuel gas system no later than 12/31/2010, Paragraph 114(b) ***Affects any existing combustion devices from the Date of Lodging, Paragraph 117

According to paragraph 99 of the CD, “By no later t han December 31, 2012, Combustion Units with Qualifying Controls will represent at least 30 % of the total maximum heat input capacity or, if less, the allowable heat input capacity, as show n in Appendix B, of all of the Combustion Units located at a particular Covered Refinery.” ... “Any Qualifying Controls can be used to satisfy this requirement, regardless of when the Qu alifying Controls were installed.” Qualifying controls are defined in the CD as one, or any combi nation of SCR or SNCR; current generation or next generation ULNB; or other qualifying techno logies that can reduce NO x emissions to 0.040 lbs/MMBtu. All the BART qualified heaters ar e currently equipped with ULNBs with internal FGR to control NO x with overall average NO x emissions of approximately 0.04 lbs/MMBtu.

In addition, as of the date of lodging, January 27, 2005, ConocoPhillips eliminated fuel oil burning in these heaters (BOP050011). Moreover the facility is obliged to upgrade the gas system by December 31, 2010, and to comply with the H 2 S requirements of NSPS subpart J by June 30, 2011. Subpart J also stipulates continuou s monitoring of the H 2 S concentration based on a 3-hour rolling average. ConocoPhillips is alr eady required to monitor the H 2 S concentration of the refinery fuel gas as a condition of their op erating permit. See Table 12 below.Table12 Summary of Current Title V Permit Conditions for BART Qualified Equipment (BOP100005) – ConocoPhillips (PI#41805)NOxSO2PM10Heat InputAllowableemissionlimitAllowableemissionlimitAllowableemissionlimitEquip.NJIDEquipmentDescription(MMBtu/hr)FueltypeExistingControl(s)(lb/hr)ExistingControl*(lb/hr)ExistingControl(lb/hr)Notes1. E241 F-101 PFBWhydrofinerheater74 CallidusULNB**7 38.9 1.52. E242 F-101 DSU-1gas oil heater51 CallidusULNB**5.1 N/A N/A SO2and PM10nettingfor PSD, 20043. E243 F-102 PFBWReheat heater167CallidusULNB**4. E245 F-103 PFBWReheat heater90CallidusULNB**5. E246 F-104 PFBWReheat heater108CallidusULNB**6. E247 F-105 PFBWReheat heater83448CallidusULNB**42.6 2445.6 Individual radiantsections; sharedconvection section7. E248 F-106 PFBWRegen Gasheater66 CallidusULNB**6.3 35.9 1.48. E249 F-107 PFBWDryer heater10 ULNB** 2 5.4 0.29. E250 F-108 PFBWReboiler heater114 CallidusULNB**10.8 N/A N/A SO2and PM10nettingfor PSD, 200410.E253F-401 DSU-2Reactor heater139RFGonlyCallidusULNB**13.9 75.5 1.011.E258F-702 OBFTOutboardFlash heater500 RFGandNGJohnZinkULNB**+ airpreheater36Fuelswitching18.5GCP5.35 H2S, 162 ppmvd (or0.10 gr/dscf)***average of three 1-hour block averages*firing of fuel oil is not allowed in these furnaces (Paragraph 117 of Consent Decree, H-05-0258)**Ultra Low NOxBurner (ULNB) employs internal Flue Gas Recirculation***existing gas system averages about 80 ppm H2S; reducing SO2emissions also reduces condensable particulate emissionsDue to misinterpretation of the de minimis levels a llowed in the Regional Haze rule, E249, a 10

MMBtu/hr process heater, was initially excluded fro m ConocoPhillips BART analysis. Based on informal guidance from USEPA regarding determinatio n of de minimis exemption levels that are based on cumulative plant-wide emissions, 32 NJDEP considers E249 subject to BART review. Refer to Table 5. However, given the existing ULNB , add-on NO x control to a unit of this relatively small size is unlikely to be cost effect ive due to its low impact over baseline levels. 33

There are three process heaters that serve the faci lity’s crude unit, E257, E258, and E259. All have ULNBs. Note that an operating permit modifica tion (BOP070010) to install SCR on the Pipestill heaters, E257 and E259, per the CD, was a pproved by NJDEP on January 1, 2009 and compliance is expected by December 31, 2010. In co njunction with the SCR installation, E259 was replaced in 2009 with a new heater and is no lo nger considered a qualified unit. Likewise E257 is not identified in Table 5 as a qualified un it. Based on USEPA’s ranking of available control options, ULNB and SCR is the best control c ombination and therefore NJDEP has determined that these NO x controls are BART for this unit, E257. USEPA esti mates a reduction of 500 tons per year in total NO x emissions (actual) from E257 and E259. 34

ConocoPhillips budgeted $45,000,000 to install SCR for E257 and E259 which are rated at 500 MMBtu/hr and 275 MMBtu/hr, respectively. E258 is r ated at 500 MMBtu/hr and is equipped with first generation ULNB combustion control. Usi ng the actual capital cost for E257 and E259, ConocoPhillips estimated the cost of modifyin g E258 to be two-thirds, or $30,000,000, based on its size. See Table 13 below.

However the feasibility and costs of retrofit contr ols depend on the refinery configuration. E258 is a heat recovery unit that sits atop an air prehe ater which is not a qualified unit. There is no acceptable location to install SCR since the flue g as temperature is too high before E258 and too low aft to operate properly. Also due to space con straints, both E258 and the air preheater would need to be replaced to accommodate SCR. Due to spa ce and temperature constraints, SCR is not technically feasible, and therefore is not a viable option. NJDEP has determined that the existing NO x controls are BART for E258.

The remaining process heaters have Callidus ULNBs a nd range in size from 51 to 167 MMBtu/hr. The installed capital cost for retrofit controls would be similar to E258, rated at 500 MMBtu/hr, regardless of the size of the unit. Annu al emissions reductions will be lower for these smaller units resulting in greater cost effec tiveness numbers.

32 USEPA. Additional Regional Haze Questions; August, 2006.

33 http://www.epa.gov/ttn/nsr/gen/refbact.pdf , p. 3-17

34 http://www.epa.gov/compliance/resources/decrees/ame nded/noticeoflodging-firstamendmentconocophillips-c d.pdf23Table 13 Comparison of Technically Feasible NOxControl Technologies – Bayway (PI#41805)ActualEmissionRateAnnualEmissionsAnnualEmissionsReductionInstalledCapitalCostAnnualOperatingCostEstimateTotalAnnualizedCosts*CostEffectivenessIncrementalCostFeasible ControlAlternative(s)lb/MMBtu (tpy) (tpy) ($ 1998) ($/yr) ($/yr) ($/ton)($/ton)ToxicImpactAdverseEnviron.ImpactEnergyImpactE258 (F-702)Baseline (1stgenULNB)0.057** 79*** N/A N/A N/A N/A N/A N/A––––––a. ULNB newergeneration (21% eff.)0.045 62 17 $ 1,750,000 Minimal $ 249,000 $ 15,659 No No Nob. SCR (79% eff.) 0.012 17 45 $30,000,000 $450,000$ 3,775,000 $ 76,161$104,933Yes No No*based on 7% interest rate and 10 yrs remaininguseful life of equipment, the capital recovery factor (CRF) is 0.14238.**based on CEMS.***based on 2009 reported emissionsAccording to the CD, at least 30% of the total maxi mum heat input capacity or, if less, the

allowable heat input capacity of the process heater s located at Bayway Refinery, as shown in Appendix B of the first amendment to the CD, must u se qualifying technologies that can reduce NO x emissions to 0.040 lbs/MMBtu. 35 Of the remaining process heaters considered in th is section, all are equipped with Callidus ULNBs, and over 55 percent (%) of the units emit less than the 0.040 lbs/MMBtu design value. As shown in Table 14 below, the actual NO x emissions average 0.048 lb/MMBtu. Based on the performance of the existing ULNBs, compared to the NO x performance levels cited in Table 8, and the expec ted higher cost effectiveness numbers, NJDEP has determined that existing NO x controls are BART.

Table 14 Summary of Actual 2000-2001 Average NO x Emissions of Remaining Process Heaters

Allowable Heat Input Actual NO x Emission Rate

(lb/MMBtu) Equip. NJID Equipment

Description MMBtu/hr 2000 2001 Avg. 1. E241 F-101 PFBW

hydrofiner heater 74 0.050 0.074 0.062

2. E242 F-101 DSU-1

gas oil heater 51 0.038 0.035 0.0365

3. E243 F-102 PFBW

Reheat heater 167 0.039 0.043 0.041

4. E245 F-103 PFBW

Reheat heater 90 0.039 0.048 0.0435

5. E246 F-104 PFBW

Reheat heater 108 0.035 0.043 0.039

6. E247 F-105 PFBW

Reheat heater 83 0.028 0.046 0.037

7. E248 F-106 PFBW

Regen Gas heater 66 0.100 0.150 0.125

8. E250 F-108 PFBW

Reboiler heater 114 0.026 0.029 0.0275

9.E253 F-401 DSU-2

Reactor heater 139 0.021 0.025 0.023

Overall average NO x emission rate 0.048

There are 18 heaters total, including 10 of the 11 affected process heaters listed in Table 15 below, that will become NSPS compliant in June, 201 1 under the CD requirements after the upgrade to the gas system that serves the furnaces named in the CD. Heater, E258, is already compliant with NSPS subpart J as noted in Tables 12 and 15. The affected gas system receives fuel gas from a variety of units that currently hav e amine treaters but was prone to spikes above 162 ppm. The upgrades to the gas system, primarily re-routing certain gas streams, will ensure

35 http://www.epa.gov/compliance/resources/decrees/ame nded/noticeoflodging-firstamendmentconocophillips-c d.pdf25

that compliance with subpart J can be maintained un der all potential refinery scenarios including start-up, shutdown, and maintenance.

Monitoring of this gas system for compliance with t he existing standard, 0.5% sulfur according to the operating permit, typically indicates a conc entration about 60 ppmv of H 2 S. The NSPS subpart J standard is 162 ppmv (0.1 gr/dscf) H 2 S based on a three-hour rolling average (average of three 1-hour block averages per NJDEP Bureau of Technical Services). According to NSPS subpart J, affected facilities can sample refinery gas continuously to monitor H 2 S in lieu of having a SO 2 CEM.

Compliance with 162 ppmv H 2 S limit under NSPS subpart J is estimated to reduce annual PTE SO 2 from affected heaters, including E242 and E250, by approximately 94 percent (%). See Table 15 below. NJDEP has determined that complian ce with the H 2 S requirements of NSPS subpart J as BART.

Table 15 Estimated SO 2 Emission Rates based on NSPS subpart J for Affecte d Process Heaters– ConocoPhillips (PI#41805) Heat Input SO 2

tons per year Equip. NJID Equipment

Description MMBtu/hr

Allowable Allow. Est.* lb/hr** lb/ MMBtu Notes

1. E241 F-101 PFBW

hydrofiner heater 74 170.4 10.6 2.42 0.033

2. E242 F-101 DSU-1

gas oil heater 51 121.3 7.40 1.68 0.033

3. E243 F-102 PFBW

Reheat heater 167

4. E245 F-103 PFBW

Reheat heater 90

5. E246 F-104 PFBW

Reheat heater 108

6. E247 F-105 PFBW

Reheat heater 83 448 1066.5 64.4 14.7 0.033

7. E248 F-106 PFBW

Regen Gas heater 66 157.2 9.6 2.19 0.033

8. E249 F-107 PFBW

Dryer heater 10 23.7 1.45 0.33 0.033

9. E250 F-108 PFBW

Reboiler heater 114 271.6 16.5 3.76 0.033

10.E253 F-401 DSU-2

Reactor heater 139 330.7 19.4 4.43 0.032 Upgrade gas system by December 31, 2010; and comply with NSPS subpart J H 2 S limits, 162 ppmvd (or 0.10 gr/dscf), average of three 1-hour block averages, by June30, 2011.

Totals (tpy): 2141.4 129.35 94% reduction allowable SO 2 11.E258 F-702 OBFT 500 81 N/A 18.5 0.03 NSPS subpa rt J26 Heat Input SO 2

tons per year Equip. NJID Equipment

Description MMBtu/hr

Allowable Allow. Est.* lb/hr** lb/ MMBtu Notes

Outboard Flash heater compliant (BOP090004)

*Annual SO 2 numbers represent estimated new permit limits foll owing CD requirement to comply with NSPS subpart J. **Compliance with 162 ppmv H 2 S limit will result in SO 2 emission rates approximately the same as these hou rly emissions based on 3-hr rolling average.

Annual combustion adjustments of the process heater s are to be carried out according to the manufacturer’s recommended procedures and maintenan ce schedule pursuant to N.J.A.C. 7:27- 19.7 and 19.16 to ensure complete combustion throug h good combustion practices (GCP). When operating properly, SO 2 , NO x , CO, PM 10 , and VOCs from refinery fuel gas-fired process hea ters are relatively low. 36

NJDEP has determined that the NO x , SO 2 and PM controls, emission limits, averaging times, and compliance dates from the CD for ConocoPhillips’ Ba yway refinery are BART. ConocoPhillips submitted an application to modify its Title V oper ating permit to incorporate the H 2 S requirements of NSPS subpart J in December, 2010 (B OP110001) . Full implementation is expected by June 30, 2011.

Table 16 Summary of Final BART for NO x , SO 2 , and PM 10 at ConocoPhillips Bayway Refinery (PI#41805) Equip. NJID Equipment

Description BART Controls BART Emission Limit Compliance

Date

NO x Existing ULNB 7 lb/hr (any 60-

min. period) Effective

BOP090004 10.6 tpy SO 2 Upgrade gas system H 2 S***

162 ppmvd (three-hour rolling average) 06/30/2011*

Pending approval BOP110001

Continue GCP Effective BOP090004 1. E241 F-101 PFBW

hydrofiner heater 74 MMBtu/hr

PM 10

Upgrade gas system** 1.5 lb/hr

06/30/2011

NO x Existing ULNB 5.1 lb/hr (any

60-min. period) Effective

BOP090004 7.4 tpy 2. E242 F-101 DSU-1 gas oil

heater 51 MMBtu/hr SO 2 Upgrade gas system H 2 S***

162 ppmvd 06/30/2011*

Pending approval

36 http://www.epa.gov/compliance/resources/publication s/assistance/sectors/notebooks/petrefsn.pdf , p.3927

Equip. NJID Equipment

Description BART Controls BART Emission Limit Compliance

Date

(three-hour rolling average) BOP110001

Continue GCP Effective BOP090004 PM 10

Upgrade gas system** 1.1 lb/hr

06/30/2011

NO x Existing ULNB 42.6 lb/hr Total

(any 60-min. period) Stack testing Effective

BOP090004

64.4 tpy SO 2 Upgrade gas system** H 2 S***

162 ppmvd (three-hour rolling average) 06/30/2011*

Pending approval BOP110001

Continue GCP Effective BOP090004 3. E243

4. E245

5. E246

6. E247 F-102 PFBW Reheat

heater (167 MMBtu/hr) F-103 PFBW Reheat heater (90 MMBtu/hr) F-104 PFBW Reheat heater (108 MMBtu/hr) F-105 PFBW Reheat heater (83 MMBtu/hr) PM 10

Upgrade gas system** 5.6 lb/hr

06/30/2011

NO x Existing ULNB 6.3 lb/hr (any

60-min. period) Effective

BOP090004 9.6 tpy SO 2 Upgrade gas system H 2 S***

162 ppmvd (three-hour rolling average) 06/30/2011*

Pending approval BOP110001

Continue GCP Effective BOP090004 7. E248 F-106 PFBW Regen

Gas heater 66 MMBtu/hr

PM 10

Upgrade gas system** 1.4 lb/hr

06/30/2011

NO x Existing ULNB 2 lb/hr (any 60-

min. period) Effective

BOP090004 1.45 tpy 8. E249 F-107 PFBW Dryer

heater 10 MMBtu/hr SO 2 Upgrade gas system H 2 S***

162 ppmvd (three-hour 06/30/2011*

Pending approval BOP11000128

Equip. NJID Equipment

Description BART Controls BART Emission Limit Compliance

Date

rolling average)

Continue GCP In 2010 N.J.A.C. 7:27-19.7(g) PM 10

Upgrade gas system** 0.2 lb/hr

06/30/2011

NO x Existing ULNB 10.8 lb/hr (any

60-min. period) Effective

BOP090004 16.5 tpy SO 2 Upgrade gas system H 2 S***

162 ppmvd (three-hour rolling average) 06/30/2011*

Pending approval BOP110001

Continue GCP Effective BOP090004 9. E250 F-108 PFBW

Reboiler heater 114 MMBtu/hr

PM 10

Upgrade gas system** 2.4 lb/hr

06/30/2011

NO x Existing ULNB 13.9 lb/hr (any

60-min. period) Effective

BOP090004 19.4 tpy SO 2 Upgrade gas system H 2 S***

162 ppmvd (three-hour rolling average) 06/30/2011*

Pending approval BOP110001

Continue GCP Effective BOP090004 10. E253 F-401 DSU-2

Reactor heater 139 MMBtu/hr

PM 10

Upgrade gas system** 1 lb/hr

06/30/2011

NO x Existing ULNB 36 lb/hr (rolling

one-day basis) CEMS Effective

BOP090004

81 tpy 11. E258 F-702 OBFT

Outboard Flash heater 500 MMBtu/hr SO 2 Continue/ maintain gas conditioning H 2 S***

162 ppmvd (three-hour rolling average) Effective

BOP09000429

Equip. NJID Equipment

Description BART Controls BART Emission Limit Compliance

Date

Continue GCP PM 10

Continue/ maintain gas conditioning 5.35 lb/hr (avg.

three one-hour stack tests) Effective

BOP090004

*Compliance date required by Consent Decree (gas system must be updated by December 31, 2010) ** Sulfur removal has cobenefit of reducing co ndensable PM *** in lieu of SO 2 CEM (NSPS is considered a surrogate for short term SO 2 limits on each heater) **** Based on estimated allowable PTE after incorp oration of Consent Decree in Title V permit

1.6 Fossil fuel-fire steam Electric Power Plant s of more than 250 Million British Thermal Units (BTU) per Hour Heat Input

The BART requirement applies to qualified emission units located at Fossil fuel-fire steam Electric Power Plants of more than 250 Million Brit ish thermal units (BTU) per hour heat input that generate electricity for sale. Appendix Y Gui delines for BART require coal-fired electric generating units (EGUs) greater than 200 MW meet 0. 15 lb/MMBtu emission limit for SO 2 ; and for any size oil-fired units, the sulfur fuel conte nt must be limited to 1 percent or less by weight. The BART guidelines also set year-round use of SCR or SNCR as the presumptive BART for NO x for EGUs currently using these controls. For oil and gas-fired EGUs current combustion controls should be part of the BART determination.

1.6.1 PSEG Fossil LLC Hudson Generating Station (PI #12202)

Hudson Generating Station currently has two boilers serving electric generating units (E1 and E2) and two coal handling systems (E22 and E23) tha t are subject to BART review. One boiler is coal-fired (E2) and subject to controls and fede rally enforceable emission limits effective December 31, 2010, due to an enforceable consent de cree (CD). The other boiler (E1) primarily combusts natural gas but is permitted to burn No. 6 fuel oil.

New Jersey adopted a rule at N.J.A.C. 7:27-27 to co ntrol mercury emissions from specific sources. Compliance with the mercury standard for coal-fired boilers was contingent upon the installation and operation of air pollution control systems to meet the NO x , SO 2 , and PM standards shown in Table 17 below by December 15, 2 012.

Table 17 N.J.A.C. 7:27-27.7(b) – Maximum Allowable NO x , SO 2 and PM Emission Rates for Coal-fired boilers (Operative on and after December 15, 2012)

Pollutant Emission Limit

(lb/MMBtu) Boiler Type30 Pollutant Emission Limit

(lb/MMBtu) Boiler Type

0.100 Dry bottom* NO x 0.130 Wet bottom

SO 2 0.150

PM 0.030

* Unit 2 is a dry bottom boiler

More recently, New Jersey’s NO x rules for boilers serving EGUs were revised on Mar ch 20, 2009. Unless subject to more stringent permit limi ts or otherwise specified in an enforceable agreement, the rules require more stringent NO x limits for boilers serving EGUs based on output and measured in pounds per megawatt-hour (lbs/MW-hr ) beginning May 1, 2015. See Table 18 below.

Table 18 N.J.A.C. 7:27-19.4 Table 3 – Maximum Allow able NO x Emission Rates for Boilers Serving Electric Generating Units (Operative on and after May 1, 2015)

Fuel Type lbs/MWhr Coal 1.50 Heavier than No. 2 fuel oil 2.00 No. 2 and lighter fuel oil 1.00 Gas only 1.00

Also on March 20, 2009, New Jersey adopted an amend ment to its Sulfur in Solid Fuels rule at N.J.A.C. 7:27-10.2(h) which specifies that on and a fter December 15, 2012, the owner or operator of any source that combusts solid fuel sha ll cause it to emit SO 2 at a 24-hour emission rate no greater than 0.250 lbs/MMBTU gross heat inp ut for every calendar day, and at a 30- calendar-day rolling average emission rate no great er than 0.150 lbs/MMBTU gross heat input.

The coal receiving system (E22) and the coal reclai m system (E23) are support systems to the coal-fired E2 with the potential to emit particulat e emissions only. The conveying systems are covered, and the coal piles are controlled with spr ay dust suppression systems. The quantifiable fugitive emissions from the conveying systems were counted for comparison purposes in determining BART eligibility. Fugitive emissions a re those that are not vented through a stack and that cannot be reasonably controlled. 37 These emission units, E22 and E23, are not discus sed further. See Table 19.

37 http://www.state.nj.us/dep/aqm/Sub22.docTable 19 Summary of Current Title V Permit Conditions for BART Qualified Equipment (BOP080003) – PSEGFossil LLC Hudson GeneratingStation (PI#12202)NOxSO2PM10Heat InputAllowableemissionlimitAllowableemissionlimitAllowableemissionlimitEquip.NJIDEquipmentDescription(MMBtu/hr)FueltypeExistingControl(lb/hr)ExistingControl(lb/hr)ExistingControl(lb/hr)NotesNG1,960 None 7.8 100.3*1. E1 Unit No.1boiler(420 MW)4,558#6FONone1,960 0.3% Sby wt1,459GCP227.2*Coal 0.259lb/MMBtu0.25% Sby wt0.216lb/MMBtuESP 607NG3,643 None 3.5 GCP 29.52. E2 Unit No.2boiler(640 MW)6,600#6FOLNB**& SNCR(yearround)3,643 0.3% Sby wt1,907 ESP 191Interim limitsexpire on 12/31/10;Subject to ConsentDecree (see Table23)3. E22 Coal receivingsystemCovered;Spray dustsuppressor1.274. E23 Coal reclaimsystemN/AN/AN/AN/ACovered;Spray dustsuppressor0.2* BOP1000001 Modification to establish PM10maximum allowable emission limits is pending approval.** New LNBs installed in 2008Unit No. 1 Boiler (E1):

Unit No. 1 is a 4,558 MMBtu/hr Babcock and Wilcox c yclone-fired steam generating boiler that began commercial operation in 1964. This unit is p ermitted to combust natural gas or No. 6 fuel oil. See Table 20 below.

Table 20 Current Title V Operating Permit (BOP08000 3) for Unit 1 – PSEG Fossil LLC Hudson Generating Station (PI#12202) Effective Permit Requirements (BOP080003)

Maximum Allowable Emission Limits Heat Input (MMBtu/hr) Pollutant Natural Gas #6 Fuel Oil PTE lb/hr lb/MMBtu lb/hr lb/MMBtu tpy

NO x 1,960 0.39 * 1,960 0.4 * 8,360 SO 2 7.8 0.0017 1,459 0.32 ** 6,389 4,558

PM 10 100.3 0.022 227.2 *** 0.050 *** 995

* NO x emissions avg. plan

** N.J.A.C.7:27-9.2(c)

*** PM 10 based on AP42 emission factors for residual oil (B OP100001)

PSEG intended to retire E1 in 2005. However the Pe nnsylvania-New Jersey-Maryland (PJM) Interconnection designated E1 as a Reliability Must Run (RMR) unit that must remain in service through 2012 to maintain PJM electrical system reli ability. Consequently, this boiler operates infrequently and well below its annual operating ca pacity. In recent years the unit has burned only natural gas, which has inherently lower NO x , SO 2 , and PM 10 emissions, and currently operates without combustion technology or add-on em ission controls. Operational problems have prevented the unit from burning No. 6 fuel oil since 2005 as shown in Table 21 below.

Table 21 Reported Operating Time of Unit No. 1 Firi ng No. 6 Fuel Oil

U1, OS2 – Utility boiler firing No. 6 fuel oil Emission Year Operating time

(days) Emission

Year Operating time

(days) 1999 52 2005* -0- 2000 28 2006* -0- 2001 32 2007* -0- 2002 15 2008* -0- 2003 50 2009* -0- 2004 20 2010** not available * source did not operate on # 6 FO **reporting year 2010 info due April 15, 2011

PSEG searched USEPA’s RACT/BACT/LAER Clearinghouse (RBLC) to identify retrofit technology currently in use with similar equipment to control NO x , SO 2 , and PM 10 emissions. 38

38 http://cfpub.epa.gov/RBLC/index.cfm?action=Home.Hom e&lang=en33

The facility also consulted a vendor to assess tech nical feasibility of various NO x controls and potential NO x reductions. 39 The results are summarized in Table 22 below.

Table 22 List of Potential Retrofit Emission Contro l Techniques for Large Utility Boilers > 250 MMBtu/hr that Combust Natural Gas Potential Retrofit Control Techniques for Unit 1 (E 1) Pollutant Available control options Percent (%) reduction Potentially

applicable Technically feasible

1. SCR 90 Yes Yes 2. LNB/ULNB, OFA + SNCR 55 Yes Yes

3. LNB/ULNB, OFA + FGR 55 Yes Yes

4. LNB/ULNB + OFA 40 Yes Yes 5. FGR 40 Yes Yes 6. SNCR 35 Yes Yes 7. OFA 25 Yes Yes NO x 1

8. LNB/ULNB 20 Yes Yes SO 2 2 1. None PM 10 1. Good combustion practices (GCP) Notes: 1 Reduction based on the current baseline NO x emission for equivalent boilers.

2 None indicated in recent BACT/LAER determinations f or boilers > 250 MMBtu/hr that combust natural gas.

Table 23 shows the NO x control alternatives that were evaluated for Unit 1. Based on efficiency and cost effectiveness, the dominant controls appea r to be a. c. and e. However since Unit 1 must meet 1.00 lbs/MWhr (approx. 0.10 lb/MMBtu) whe n combusting natural gas by May 1, 2015, option a. may be the most viable control alte rnative. This date is consistent with the federal requirement to install BART controls as soo n as practicable but no later than 5 years after USEPA's approval.

In December, 2010 PSEG submitted an application (BO P110001) to modify the Hudson operating permit to include more stringent NO x emission limits, 1.0 lb/MW-hr when burning natural gas and 2.0 lb/MW-hr when burning No. 6 fue l oil, with a compliance date of May 1, 2015, to coincide with the requirements of the revi sed NO x rule at N.J.A.C.7:27-19.4 Table 3 for E1; and to only burn No. 6 fuel oil, already restri cted to 0.3% sulfur by wt, in this boiler when natural gas is curtailed, effective upon approval o f the permit modification but no later than December 31, 2011.

39 http://www.state.nj.us/dep/baqp/2008%20Regional%20H aze/Appendix%20G-8%20%28Final%20Only%29.pdf34Table 23 Comparison of Technically Feasible NOxControl Technologies for Unit #1 Firing Natural Gas – PSEG Fossil LLC Hudson GeneratingStation (PI#12202)ActualEmissionRateAnnualEmissionsAnnualEmissionsReductionInstalledCapitalCostAnnualOperatingCostEstimateTotalAnnualizedCosts*CostEffectivenessIncrementalCostFeasible ControlAlternative(s)lb/MMBtu (tpy) (tpy) ($ 2009) ($/yr) ($/yr) ($/ton)($/ton)ToxicImpactAdverseEnviron.ImpactEnergyImpact1.E1 (Unit #1 – boiler)Baseline (no controls) 0.337 162.1** N/A N/A N/A N/A N/A N/A––––––a. SCR (90% eff.) 0.034 23.51 138.59 $28,205,173 $1,410,706 $5,614,509 $40,508 $87,979b. ULNB, OFA +SNCR (55% eff.)0.152 72.95 89.15 $10,546,981 $ 167,000 $1,738,811 $19,504 N/Ac. ULNB, OFA + FGR(55% eff.)0.152 72.95 89.15 $ 8,136,242 $ 52,300 $1,264,840 $14,187 $35,100d.ULNB + OFA(40% eff.)0.202 97.26 64.84 $ 5,725,504 $0 $ 853,269 $13,160 N/Ae. FGR (40% eff.) 0.202 97.26 64.84 $ 2,410,739$ 52,300 $ 411,571 $ 6,348 See c.f. SNCR (35% eff.) 0.219 105.37 56.73 $ 4,821,477 $ 167,000 $ 885,542 $15,609 N/Ag. OFA (25% eff.) 0.253 121.58 40.52 $ 2,561,410$0 $ 381,726 $ 9,420 N/Ah.ULNB (20% eff.) 0.270 129.68 32.42 $ 3,164,094 $0 $ 471,543 $14,545 N/A*based on 8% interest rate and 10 yrs remaining useful life of equipment, the capital recovery factor (CRF) is 0.14903.**based on last three-year period, 2006 - 200835

Unit No. 2 Boiler (E2):

On July 26, 2002, a federal enforcement settlement required PSEG to install state-of-the-art (SOTA) controls for NO x , SO 2 , and PM on all its coal-fired boilers in the State of New Jersey. These controls included SCR, FGD, and a polishing b aghouse for Hudson Unit No. 2.

An amendment to the initial consent decree was nego tiated to extend the compliance deadlines. As a consequence PSEG Hudson Generating Station spe cifically took interim steps to reduce emissions of NO x , SO 2 and PM until December 31, 2010, when the required pollution control equipment was installed on Unit 2. These interim m easures included year-round operation of the existing NO x control equipment utilizing selective non-catalyti c reduction (SNCR) to reduce NO x , use of 100% ultra-low sulfur coal, compliance wit h annual emission caps for NO x and SO 2 , and operation of an electrostatic precipitator (ESP ) and a fly ash conditioning system to control PM. PSEG was also required to install a more effec tive baghouse than previously required, and to use a carbon injection system to reduce mercury emissions from this facility after the pollution control equipment was installed. Refer to Table 24 below for the interim and final controls for Unit 2 and compliance deadlines.

Table 24 Summary of Amendment to 2002 Consent Decre e Requirements for Unit 2 – PSEG Fossil LLC Hudson Generating Station (PI#12202)

Equip. NJID Pollutant Control strategy* Emission limit Compliance date

Interim: Use ultra low sulfur coal and operate SNCR year round Annual tonnage cap (3,486 tpy); 0.300 lbs/MMBtu 30-day avg. emission rate 01/01/2007

Final: NO x

Install SCR (to replace SNCR) 0.100 lbs/MMBtu 30-day avg. 0.150 lbs/MMBtu 24-hr avg. 12/31/2010

Interim: Use ultra low sulfur coal (<= 0.25% sulfur content) Annual tonnage cap (5,270 tpy); 0.216 lbs/MMBtu 30-day avg. emission rate 05/01/2007

Final: E2

SO 2

Install dry FGD with spray dryer

absorber (SDA) 0.150 lbs/MMBtu 30-day avg. 12/31/201036

Equip. NJID Pollutant Control strategy* Emission limit Compliance date

Use low sulfur coal (<= 2.00% sulfur content) 0.250 lbs/MMBtu 24-hr avg. Interim: Optimize ESP and fly ash conditioner 01/07/2006

Final: PM

Install full size baghouse ** 0.0150 lbs/MMBtu 12/31/2010 Hg Carbon injection 12/31/2010 Other PM Continuous Emission Monitoring Systems (CE MS) 12/31/2010 * State-of-the-art (SOTA) for sulfur dioxide, nit rogen oxide and particulate matter. Refer to http://www.epa.gov/compliance/resources/cases/civil /caa/psegllc-fcsht-061130.html **The ESP will remain in place and will be operated on an as needed basis at the discretion of PSEG.

Unit 2 is a dry-bottom wall-fired unit and, since b ringing the SCR, FGD, baghouse, and activated carbon on-line, fires low sulfur bituminous coal. The existing LNBs, installed on Unit 2 in 2008, continue to be used in addition to the new SCR. Th e new FGD is a dry type that utilizes Spray Dryer Absorbers (SDAs) in concert with the fabric f ilter (baghouse). The SCR, FGD, baghouse, and carbon injection are newly constructed and comm enced operation on November 24, 2010. PSEG Fossil is still optimizing the operation of th ese new controls. Since commencing operation, however, the average calendar day emissi on rates of NO x and SO 2 have been approximately 0.09 lb/MMBtu and 0.132 lb/MMBtu, res pectively, based on CEMS data through February 1, 2011. The domestic, bituminous coal ra nged from 1.12% to 1.28% sulfur content during the same period.

NJDEP has determined the new selective catalytic re duction (SCR) and the existing low NO x burners (LNBs), dry flue gas desulfurization (FGD) with spray dryer absorber (SDA) and use of 2 percent (%) by weight low sulfur coal, and baghou se air pollution control systems for oxides of nitrogen (NO x ), sulfur dioxide (SO 2 ), and particulate matter (PM), respectively, for E 2, and the existing PM controls for the two coal handling syst ems, are BART.

Under the Clean Air Act, BART requirements must be included as Title V operating permit conditions. This required PSEG to submit a modific ation application to implement the NO x control, emission limits, fuel oil restriction, and compliance deadlines. PSEG submitted a permit modification to NJDEP in December, 2010 to incorpor ate the proposed BART requirements as part of its operating permit conditions for E1 only (BOP110001). The CD requirements for E2, determined by NJDEP to be BART, are already include d in the current approved Title V operating permit, BOP080003.37

Table 25 Summary of Final BART for NO x , SO 2 , and PM 10 at PSEG Fossil LLC Hudson Generating Station (PI#12202) BART emission limit Equip. NJID Equipment Description BART control lb/MMBtu lb/hr Compliance date

Natural Gas NO x SCR (or equivalent) –– 1.00 lb/MWh 24-hour avg

. 05/01/2015

Pending approval BOP110001 SO 2 None –– 7.8 any 60 minute period Effective

BOP080003

PM 10 Continue GCP –– 100.3 three one-hour stack tests Pending

approval BOP1000001 No. 6 fuel Oil - Restricted use during gas curtailm ents only NO x SCR (or equivalent) –– 2.00 lb/MWh 24-hour avg. 05/01/2015

Pending approval BOP110001 0.3% S by wt (exist.) Effective BOP080003 SO 2

Restricted use – gas curtailments only –– 1,459 any 60 minute period 12/31/2011

Pending approval BOP110001 E1 Unit No.1 boiler 4,558 MMBtu/hr

PM 10 Continue GCP –– 227.2 three one-hour stack tests Pending

approval BOP1000001

Coal Existing LNBs Effective BOP080003 NO x

SCR 0.100 30-day

avg. 0.150 24-hr avg. ––

12/31/2010 BOP080003

Dry FGD w/SDA SO 2

<= 2.00% sulfur

content 0.150

30-day

avg. 0.250 24-hr avg. –– 12/31/2010 BOP080003 E2 Unit No.2 boiler 6,600 MMBtu/hr

PM 10 Baghouse (and ESP

as needed) 0.0150

three one- –– 12/31/2010 BOP08000338 BART emission limit Equip. NJID Equipment Description BART control lb/MMBtu lb/hr Compliance date hour stack

tests Natural Gas Existing LNBs Effective BOP080003 NO x

SCR 0.100 30-day

avg. 0.150 24-hr avg ––

12/31/2010 BOP080003

SO 2 No need to operate FGD 0.150

30-day

avg. 0.250 24-hr avg. –– 12/31/2010 BOP080003

PM 10 No need to operate baghouse 0.0150

three onehour stack

tests –– 12/31/2010 BOP080003

No.6 Fuel Oil Existing LNBs Effective BOP080003 NO x

SCR 0.100 30-day

avg. 0.150 24-hr avg ––

12/31/2010 BOP080003

SO 2 Dry FGD w/SDA 0.150 30-day

avg. 0.250 24-hr avg –– 12/31/2010 BOP080003

PM 10 Baghouse (and ESP as needed) 0.0150

three onehour stack

tests –– 12/31/2010 BOP080003

E22 Coal receiving system PM 10 Existing enclosure

and dust suppression system N/A 1.27 Effective BOP080003

E23 Coal reclaiming system PM 10 Existing enclosure

and dust suppression system N/A 0.2 Effective BOP08000339

1.7 Final BART Requirements

Under the Regional Haze rule, States must identify the best system of continuous emission control technology for each eligible source that is subject to BART. After a State has identified the level of control representing BART, it must est ablish an emission limit representing BART and must ensure compliance with that requirement no later than five years after the USEPA approves the State Implementation Plan.

NJDEP has determined that Chevron Products, ConocoP hillips Bayway Refinery, and PSEG Hudson Generating Station, are subject to BART revi ew. The Hess Port Reading and Sunoco Eagle Point petroleum refineries are below the emis sions threshold for BART.

Chevron Products : Chevron currently has two refinery fuel gas-fired f urnaces (E1501 and E1502) that are subject to BART review. Chevron proposed to reduce to its ann ual combustion limit to bring this facility’s potential to emit NO x to less than 250 tons per year (tpy) by March 15, 2 011.

ConocoPhillips Bayway Refinery : Bayway petroleum refinery currently has 11 refinery fuel gas-fired process heaters that are subject to BART review. On January 27, 2005, the U SEPA entered into a CD with ConocoPhillips including its New Jersey refinery. NJDEP has determined that the NO x , SO 2 , and PM controls, emission limits, averaging times, and compliance dates from the CD for the process are BART. Also, the CD requires all the BA RT-qualified process heaters at the Bayway facility to eliminate oil burning, and to only burn refinery fuel gas with an hydrogen sulfide (H 2 S) content less than 162 ppmvd based on NSPS subpar t J. Full implementation is expected by June 30, 2011.

PSEG Hudson Generating Station :

Hudson Generating Station currently has two boilers serving electric generating units (E1 and E2) and two coal handling systems (E22 and E23) tha t are subject to BART review. One boiler is coal-fired (E2) and subject to controls and fede rally enforceable emission limits effective December 31, 2010, due to an enforceable consent de cree (CD). The other boiler (E1) primarily combusts natural gas but is permitted to burn No. 6 fuel oil.

The coal receiving system (E22) and the coal reclai m system (E23) are support systems to E2 with the potential to emit particulate emissions on ly. The conveying systems are covered and the coal piles are controlled with water dust suppressi on system.40

NJDEP has determined that the new selective catalyt ic reduction (SCR) and existing low NO x burners (LNBs), new flue gas desulfurization (FGD), and new baghouse air pollution control systems for oxides of nitrogen (NO x ), sulfur dioxide (SO 2 ) and particulate matter (PM), respectively, for E2, and the existing PM controls for the two coal handling systems, are BART.

In addition PSEG has submitted an application to mo dify the Hudson operating permit to include more stringent NO x emission limits, 1.0 lb/MW-hr when burning natural gas and 2.0 lb/MW-hr when burning No. 6 fuel oil, with a compliance date of May 1, 2015, to coincide with the requirements of the revised NO x rule at N.J.A.C.7:27-19.4 Table 3 for E1; and to o nly burn No. 6 fuel oil, already restricted to 0.3% sulfur by wt, in this boiler when natural gas is curtailed, effective upon approval of the permit modification but no later than December 31, 2011.

The BART requirements must be included as operating permit conditions according to the procedures established in 40 CFR part 70, and the s tate regulations promulgated at N.J.A.C. 7:27-22. Chevron, PSEG Hudson, and ConocoPhillips have submitted timely permit modifications to incorporate the BART requirements. NJDEP commits to post the final operating permit modifications once they are approv ed.41

Appendix A

From: "LaFayette, Doug:" <Doug.LaFayette@conocophillips. com> To: "'Margaret Gardner'" <Margaret.Gardner@dep.state.n j.us> Date: Mon, Jul 19, 2010 5:30 PM Subject: RE: Follow up on BART Analysis

Peg,

First let me wish you a great vacation...get away a nd recharge those batteries!!!

I will look at the tables and respond separately if I have issues with any of them. Regarding your pa rticular questions:

1. E244 (F102 DSU-1) - please verify that "reconstr uction" meets the definition in 51.301 of the BART rule (a question from EPA); F-102 DSU 1 suffered a fire in the late 1990's and was reconstructed and is thus subject to NSPS Subpa rt J. The rebuild easily exceeded 50% of the replacement cost of the heater. The Title V Permit conditions are reflective of its NSPS status.

2. Do these heaters have both ULNB plus FGR? Extern al FGR? (the equipment inventory details from NJEMS list both); The ULNB installed on the heaters at Bayway employ internal Flue Gas Recirculation. The person that p ermitted them (predates my tenure) apparently listed FGR as well as ULNB in RADIUS. None of the heaters employ external FGR.

3. From paragraph 114(b) of consent decree - when d oes ConocoPhillips anticipate submitting a modifica tion to Title V to add NSPS Subpart J sulfur in gas limits for these process heaters? Does CP plan to coordina te with modification application to upgrade the refinery fu el gas system? First, no permit is required for the "upgrade" to t he fuel gas system. A permit will be necessary to incorporate NSPS Subpart J conditions into the existing heaters that are not currently subject to the NSPS in order to comply with CD requirements. The existing "sour" gas system avera ges about 80 ppm H2S but was prone to spikes above 162 ppm from time to time for various known reasons. Baywa y has undertaken several minor projects which will alleviate those spikes. Some of these projects have already been completed and others will be completed during a turnaround later this year. All projects "required" to achiev e compliance with the NSPS will be completed by 12/ 31/2010. Most of these projects involved re-routing certain streams out of the sour gas system. Some projects were necessary to assure compliance with the NSPS even during turn arounds when certain fuel gas treaters were not ava ilable. Note that the CD allows until 6/30/2011 to demonstrate c ompliance with the NSPS and we will comply by that date. The plan is to submit a permit modification to incorpor ate NSPS Subpart J conditions on the heaters not cu rrently subject to NSPS Subpart J by this fall. We anticipate perm it approval before 6/30/2011 but even absent an app roved permit we will comply with the NSPS limit as we have for e very other CD requirement where permit approval lag ged behind the CD compliance date.

4. E249 (PFBW dryer heater) - the EPA determined th at deminimis thresholds do not apply on an individu al emission unit basis, so this unit meets the applica bility criteria for BART. It is listed in the table s below. I have no comment here. This is a 10 MMBtu/hr heat er which isn't going to have much impact on visibil ity. I actually thought there was a deminimis but I will d efer to you. Every time BART raises it's ugly head I end up re-reading the rule. I don't have time for that ri ght now. 5. Appendix B of the consent decree doesn't list th e affected combustion units at the Bayway facility. From paragraphs 94 and 95: are any of the facility's com bustion units affected by the CD?42

The original CD was actually published without the BW heater tables. It was a pain for us as well. T he subsequent versions of the CD (following the first and second amendments) which you may not have do include the B ayway heaters in Appendix B. I am attaching a copy of th e Bayway table from Appendix B for your convenience . The print is very small and you may need a magnifying g lass (a big one) but welcome to my world. Note tha t all the heaters burn RFG. We are not allowed (by permit) n or are we capable of burning oil any more at the re finery. As a side note, no one I have spoken with at NJDEP has a copy of the current version of the CD. A current copy should be available from USEPA and/or DOJ.

6. Also I'm assuming that all the process heaters a re subject to good combustion practices since they are all subject to annual combustion tune-ups under N.J.A.C.7:27-19 .7(g). You assume correctly but keep in mind I think the a nnual combustion tuning requirement kicks in for th e smallest heaters this year. Recent rulemakings made all hea ters subject to the rule where only those >50 MMBtu /hr were subject for many years. Let me know if there is anything here that you do n ot understand and I will try to further explain it to you

Doug

-----Original Message----- From: Margaret Gardner [mailto:Margaret.Gardner@dep .state.nj.us] Sent: Monday, July 19, 2010 4:17 PM To: LaFayette, Doug: Cc: Francis Steitz Subject: Follow up on BART Analysis

Hi, Doug.

I'm following up on all the BART analyses submitted by NJ's BART-eligible facilities, and I'm working closely with EPA Region 2 and the Federal Land Manager as I work through each review.

Attached are draft tables summarizing ConocoPhillip s' analysis of affected process heaters that I forw arded to EPA and the FLM for their feedback. If you have questio ns or changes to these preliminary tables, please l et me know.

The following are questions I have which arose duri ng the evaluation of this facility's analysis: 1. E244 (F102 DSU-1) - please verify that "reconstr uction" meets the definition in 51.301 of the BART rule (a question from EPA); 2. Do these heaters have both ULNB plus FGR? Extern al FGR? (the equipment inventory details from NJEMS list both); 3. From paragraph 114(b) of consent decree - when d oes ConocoPhillips anticipate submitting a modifica tion to Title V to add NSPS Subpart J sulfur in gas limits for these process heaters? Does CP plan to coordina te with modification application to upgrade the refinery fu el gas system? 4. E249 (PFBW dryer heater) - the EPA determined th at deminimis thresholds do not apply on an individu al emission unit basis, so this unit meets the applica bility criteria for BART. It is listed in the table s below. 5. Appendix B of the consent decree doesn't list th e affected combustion units at the Bayway facility. From paragraphs 94 and 95: are any of the facility's com bustion units affected by the CD? 6. Also I'm assuming that all the process heaters a re subject to good combustion practices since they are all subject to annual combustion tune-ups under N.J.A.C.7:27-19 .7(g).

I'm trying to wrap this up before leaving on vacati on this Saturday. If possible, please get back to m e by COB this Thursday (7/22).

Thanks for your help, and please feel free to phone me if you'd like to discuss anything.

Peg G.43

Margaret Gardner Division of Air Quality

State of New Jersey Department of Environmental Protection Bureau of Air Permits 401 E. State St. PO Box 27 Trenton, NJ 08625-0027

(609) 292-7095

CC: Francis Steitz <Francis.Steitz@dep.state.nj.us>44

Appendix B45464748

Appendix C: Public Participation Response to Comment Document regarding BART Determi nations

A notice of opportunity for public comment on New J ersey Department of Environmental Protection’s (NJDEP) proposed Best Available Retrof it Technology (BART) determinations was published on December 20, 2010. The public notice, Technical Support Document (TSD), and fact sheet were also posted on the NJDEP Air Qualit y Permitting Program’s website under Public Notices. NJDEP also sent written notificati on of the proposed BART to each environmental commission of the cities of Linden an d Jersey City where ConocoPhillips and PSEG Hudson are located, respectively.

During the public comment period, several comments were received from the United States Fish and Wildlife Service (in concurrence with the Unite d States Forest Service) regarding NJDEP’s proposed BART determinations. The following is a s ummary of those comments, and NJDEP’s responses to those comments.

General

1) Comment: Post all applicable operating permits or other enf orceable commitments as an appendix to the BART section of the Regional Haze S tate Implementation Plan (SIP), including the permit modification from Chevron Prod ucts that requested capped emission limits of oxides of nitrogen (NO x ) below the 250 tons per year (tpy) threshold in or der to be excluded from BART.

Response: Chevron, PSEG Hudson, and ConocoPhillips have subm itted timely permit modifications to incorporate the BART requirements proposed in the TSD. NJDEP commits to post the final operating permits once th e modifications are approved. The consent decrees for PSEG and ConocoPhillips can be found under Appendix G of the Regional Haze SIP that is posted online at http://www.state.nj.us/dep/baqp/2008%20Regional%20H aze/Regional%20Haze.html.

ConocoPhillips Bayway Refinery

2) Comment: For the Bayway process heaters, the NOx control efficiency of 0.04 lb/MMBtu through the use of existing Ultra Low NO x Burners and SCR, and the SO 2 control efficiency of 0.033 lb/MMBtu through a refinery gas upgrade, would seem to be BART for those units.

Response: NJDEP acknowledges the feedback that we have recei ved from the United States Fish and Wildlife Service and the United Sta tes Forest Service concurring with NJDEP’s BART determination for the qualified proces s heaters located at ConocoPhillips Bayway Refinery.49

PSEG Fossil Hudson Generating Station

Unit No.1 gas-fired boiler, E1

3) Comment: Implementation of Selective Catalytic Reduction (S CR) for NO x control on gas boiler E1 by May 1, 2015, would seem to satisfy BART.

Response: E1 must meet 1.00 lbs/MWhr (approx. 0.10 lb/MMBtu) when combusting natural gas by May 1, 2015, under N.J.A.C. 7:27-19. 4. Table 23 of the TSD shows the NO x control alternatives that were evaluated for E1. SCR, or the equivalent, would be required to meet this emission limit.

Unit No.2 coal-fired boiler, E2

4) Comment: From the USEPA Appendix Y Guidelines for BART, cont rol evaluation must take into account 1) the most stringent level of efficiency t hat a control technique is capable of achieving, 40 and 2) upgrades to existing control devices, 41 even if the proposed control option meets the presumptive BART emission limit fo r NO x or SO 2
. Response: The SCR, FGD, baghouse, and carbon injection comme nced operation on November 24, 2010. These are Best Available Contro l Technology (BACT) and Maximum Achievable Control Technology (MACT) contro ls that are also BART.

5) Comment: For NO x control on boiler E2, SCR has been proposed as BAR T with an emission limit of 0.10 lb/MMBtu. Since low NO x burners (LNB) were installed in 2008, as shown in Table 19, it is assumed that BART will be the combination of LNB and SCR. This control technology has delivered control effic iencies of 0.05 to 0.08 lb/MMBtu in many boilers using various types of coals and reage nts. The only information presented about the type of coal being used is that it is les s than or equal to 2% in sulfur content. The type and amount of reagent proposed are not pre sented. Either more information and analysis should be provided to justify an emission limit of 0.10 lb/MMBtu for BART, or a lower emission limit should be proposed.

Response: E2 is a dry-bottom wall-fired unit and fires low s ulfur bituminous coal. The existing LNBs continue to be used in addition to th e new SCR. Since commencing operation, the average calendar day emission rate o f NO x has been approximately 0.09 lb/MMBtu based on CEMS data through February 1, 201 1. The “presumptive” level of NO x control provided for in the EPA BART Guidelines fo r dry-bottom wall-fired units

40 See 40 CFR Part 51, Appendix Y, Section IV.D.STEP 3.1.

41 Ibid., See Section IV.D.STEP 3.450

that combust bituminous coal is 0.39 lb/MMBtu. Thi s SCR/LNB controlled unit is less than 25 percent of the presumptive BART limit.

6) Comment: For SO2 control on boiler E2, Flue Gas Desulfuriza tion (FGD) has been proposed as BART with an emission limit of 0.15 lb/ MMBtu. It is not clear exactly which type of FGD is proposed (e.g., wet, dry sorbe nt injection, lime spray dryer). Wet FGD would be considered to be the most stringent co ntrol available. If any other type of FGD is being proposed, a BART determination that co nsiders the other SO2 control alternatives should be performed. Assuming that wet FGD is the control alternative being implemented as BART, this technology has been shown to be capable of achieving a much lower emission rate than 0.15 lb./MMBtu at oth er Electric Generation Units. The type and amount of reagent proposed are not present ed. Either more information and analysis should be provided to justify an emission limit of 0.15 lb/MMBtu for BART, or a lower emission limit should be proposed. The abov e references remain applicable even if the proposed control alternative meets the “pres umptive” level of control provided for in the EPA BART Guidelines (e.g., 0.15 lb/MMBtu for SO2 control).

Response: The new FGD is a wet/dry type that utilizes Spray Dryer Absorbers (SDAs) in concert with the fabric filter (baghouse). Accordi ng to the U.S. Department of Energy, dry FGD is typically used with low sulfur coal havi ng less than 2 percent by weight sulfur content along with a downstream fabric filte r (baghouse) to capture any byproduct. 42 The domestic, bituminous coal ranged from 1.12% t o 1.28% sulfur content during the operational period from November 24, 201 0 through February 1, 2011. Since commencing operation, the average calendar day emis sion rate of SO 2 has been approximately 0.132 lb/MMBtu based on CEMS data thr ough February 1, 2011 which is lower than 0.15 lb/MMBtu, the EPA “presumptive” lev el.

. Department-initiated Changes In addition to non-substantive minor and/or stylist ic edits (i.e., correcting typos, ensuring consistency, etc.), the NJDEP made the following de partment-initiated changes when finalizing the Technical Support Document and its appendices f or submittal to the USEPA.

1) added information regarding pending permit modifica tion (BOP110001) for ConocoPhillips’ Title V operating permit to incorpo rate the consent decree requirement to implement the H 2 S requirements of NSPS subpart J; 2) added information regarding pending permit modifica tion (BOP110001) for PSEG Hudson Generating Station’s Title V operating permi t to include more stringent NO x emission limits for E1; 3) added the following paragraph regarding E2: “Unit 2 is a dry-bottom wall-fired unit and, since bringing the SCR, FGD, baghouse, and activated carbon on-line, fires low sulfur bitumino us coal. The existing LNBs, installed on

42 http://www.netl.doe.gov/technologies/coalpower/ewr/ coal_utilization_byproducts/pdf/mercury_%20FGD%20wh it e%20paper%20Final.pdf51

Unit 2 in 2008, continue to be used in addition to the new SCR. The new FGD is a dry type that utilizes Spray Dryer Absorbers (SDAs) in conce rt with the fabric filter (baghouse). The SCR, FGD, baghouse, and carbon injection are newly constructed and commenced operation on November 24, 2010. PSEG Fossil is still optimiz ing the operation of these new controls. Since commencing operation, however, the average ca lendar day emission rates of NO x and SO 2 have been approximately 0.09 lb/MMBtu and 0.132 lb /MMBtu, respectively, based on CEMS data through February 1, 2011. The domestic, bituminous coal ranged from 1.12% to 1.28% sulfur content during the same period;” and 4) added NJDEP’s commitment to post the final operatin g permit modifications once they are approved.525354555657