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 Protection 

Division of Air Quality 

Bureau of Air Permits 

401 E. State Street, 2nd floor, P.O. Box 27 

Trenton, NJ 08625-0027

March 2, 2011 

 
2

1.0 BEST AVAILABLE RETROFIT TECHNOLOGY (BART) DETERMINATIONS 

1.1 Introduction 

To protect scenic areas across the United States against regional haze as required by the federal 

Clean Air Act (CAA), the United States Environmental Protection Agency (USEPA) published 

regulations that require certain types of existing sources of visibility impairing air pollutants 

install Best Available Retrofit Technology (BART) to reduce such emissions.1

 On August 4, 

2009, the New Jersey Department of Environmental Protection (NJDEP) submitted its State 

Implementation Plan (SIP) Revision for Regional Haze to protect and enhance visibility levels in 

the Brigantine Wilderness Area of the Edwin B. Forsythe National Wildlife Refuge, a federally 

designated Class I Area, to the USEPA. NJDEP identified five facilities in the SIP revision as 

potentially BART-eligible sources including one fossil fuel-fire steam electric power plant and 

four petroleum refineries, and committed to complete its review of facilities subject to BART in 

2010.2 These facilities are: 1) PSEG Hudson Generating Station, 2) Chevron Products, 3) 

Amerada Hess Port Reading Refinery, 4) ConocoPhillips Bayway Refinery, and 5) Sunoco Eagle 

Point. 

The listed facilities submitted their own BART analysis to NJDEP.3

 NJDEP’s review process to 

evaluate BART consisted of identifying 1) the facilities 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 compliance dates. 

1.2 BART-Eligibility 

To be BART-eligible a facility must belong to one of 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 pollutants including NOx, SO2, and PM10.

4

 The 

Mid-Atlantic/Northeast Visibility Union (MANE-VU) formed 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 BART-eligible sources and the emission units that 

comprise them. See Appendix A in NESCAUM’S 2007 report, Five-Factor Analysis of BARTEligible Sources, for the final list of BART-eligible sources in the MANE-VU region including 

New Jersey.5 Upon reviewing the current potential emissions from the applicable equipment still 

in existence at each named facility, NJDEP determined 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-06/a12526.pdf 

2

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

3

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

4

64 Fed. Reg. 35737; July 1, 1999 

5

 NESCAUM. Five-Factor Analysis of BART-eligible Sources 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 equipment1 

Potential to Emit (PTE) in tons per year (tpy) 

Source category/ 

Facility 

NOx SO2 PM10

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 D2 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 August 7, 1977. 

2De 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 determining BART-eligibility provided in 

Appendix Y to Part 51, Section II.6 The steps in identifying BART-eligible sources are: 

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 installed 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 identified 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) Chevron Products, 4) ConocoPhillips Bayway 

Refinery, and 5) PSEG Fossil LLC Hudson Generating Station, respectively. 

 

6

http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/40cfr51AppY.pdf 

7

 NESCAUM. Five-Factor Analysis of BART-eligible Sources Survey of Options for Conducting BART 

Determinations. Boston, MA; June 2007. 
4

1.2.2 Hess Corporation, Port Reading Refinery (PI#17996) – 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 frame. The permitted potential to emit 

(PTE) totals for this qualified unit are below the 250 tpy applicability threshold for NOx, SO2, 

and PM10 (0.74, 1.05, and de minimis,8

 respectively), and therefore this source is not BARTeligible. 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 wastewater treatment plant. Since volatile 

organic compounds (VOCs) were the only pollutants emitted from this emission unit, these 

pieces of equipment were not included in the cumulative determination of the facility-wide PTE 

from qualified emission units. The fluidized catalytic cracking unit (FCCU), also identified on 

the original list, falls outside the applicable time 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, 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 

NOx SO2 PM10

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 No2

E64 Flare 1984 No –– –– –– N/A 

E66 Space Heating 

Boiler 

1975 Yes 0.74 1.05 D3 Yes1

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.pdf 
5

Hess Corporation, Port Reading Refinery (PI#17996)

Identify emission units 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 

NOx SO2 PM10

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 NOx SO2 PM10 PTE

Totals (tpy): 0.74 1.05 D3

< 250 

Notes: 

1

equipment with applicable emissions to be considered cumulatively in determining the facility’s 

BART eligibility 

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

3De 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 Coastal 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 permitted PTE totals from the qualified units are 

below the 250 tpy applicability threshold for NOx, SO2, and PM10 (232, 130, and 45, 

respectively), and therefore this source is not BART-eligible. See Table 3 below. 

Note that some of the process heaters initially identified 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 NOx 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, 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 

NOx SO2 PM10

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%20Haze/Appendix%20G%20-

%20BART%20Documentation/Appendix%20G-7_Coastal%20Consent%20Decree.pdf 
6

Sunoco, Eagle Point (PI#55781)

Identify emission units 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 

NOx SO2 PM10

BART 

eligible 

E12 FCCU heater 5A 1971 Yes 4.47 4.90 1.80 Yes1

E412 FCCU heater 5B 1971 Yes 4.47 4.90 1.80 Yes1

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 No2

E44 ULSD process 

heater 2H-201 

1972 Yes 5.26 1.54 2.72 Yes1

E45 ULSD process 

heater 2H-202 

1972 Yes 23.0 10.5 4.25 Yes1

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 Yes1

E57 CRU heater PH-2 1967 Yes 16.0 14.2 3.77 Yes1

E58 CRU heater PH-3 1967 Yes 30.3 17.4 6.4 Yes1

E59 CRU heater PH4A 1967 Yes 43.2 24.9 9.1 Yes1

E60 CRU heater PH4B 1967 Yes 15.9 9.1 3.4 Yes1

E62 CRU heater PH5B 1967 Yes 53.9 13.2 2.76 Yes1

E65 CRU heater HC301 1967 Yes 13.0 12.5 0.96 Yes1

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 

No3
7

Sunoco, Eagle Point (PI#55781)

Identify emission units 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 

NOx SO2 PM10

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 

No2

E98 WWTU – em. 

diesel pump 

1972 Yes 1.50 0.10 3.42 Yes1

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 Yes1

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/A 
8

Sunoco, Eagle Point (PI#55781)

Identify emission units 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 

NOx SO2 PM10

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 

mobile 

equipment as 

needed 

No 

–– –– –– 

N/A 

E5501

5 

LSG preheat 

reactor furnace 

–– –– –– 

E5501

6 

LSG stripper 

reboiler 

2005 No 

–– –– –– 

N/A 

Visibility Impairing Pollutants NOx SO2 PM10 PTE

Totals (tpy): 232.5 130.0 45.2 < 250 

Notes: 

1

equipment with applicable emissions to be considered 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 assigned NJID E415 – 417 and E81 – 93 as a 

permit workaround to ensure that enforceable operational requirements for these flares are part 

of the compliance plan 

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

Chevron currently has two refinery fuel gas-fired furnaces (E1501 and E1502) that fall within the 

applicable BART time frame. The NOx emissions from E1501 and E1502 cumulatively exceed

the PTE threshold and make this facility a BART-eligible source. See Table 4 below. However, 

Chevron proposed an enforceable permit limit to cap out this facility’s NOx 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 wastewater treatment plant. Since VOCs are the 
9

only pollutants emitted from this emission unit, these pieces of equipment were not included in 

the cumulative determination of the facility-wide PTE from qualified emission units. Also a 

process heater, E1601, initially identified as being potentially subject to BART, was taken out of 

service and subsequently removed from the Title V operating permit. 

Table 4 List of Equipment, Start-up Dates, Potential 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 

NOx SO2 PM10

BART 

eligible 

E1002 Barge Berth 1975 Yes N/A N/A N/A No5

E1501 Atmospheric 

crude furnace 

1976 Yes 181.3 28.0 18.9 Yes1 

E1502 Vacuum crude 

furnace 

1976 Yes 80.9 12.5 13.9 Yes1 

E1601 Hot oil heater 1976 Yes –– –– –– No6

E1801 North Flare 1976 Yes N/A N/A N/A No3

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 

No2

E2301 Desalting water 

drum 

1975 Yes N/A N/A D4 No 

E2401 Light products 

loading rack – 

AER incinerator 

1975 Yes N/A N/A N/A No3
10

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 

NOx SO2 PM10

BART 

eligible 

Visibility Impairing Pollutants NOx SO2 PM10 PTE 

Totals (tpy): 262.5 40.5 32.7 > 250 

Notes: 

1

equipment with applicable emissions to be considered cumulatively in determining the facility’s 

BART eligibility 

2

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

3

not applicable (N/A) – control device, CD2401, was assigned an Equipment NJID as a permit 

workaround to ensure enforceable operational requirements of this flare are part of the 

compliance plan to control VOC while loading gasoline 

4De minimis (D) – potential to emit below de minimis level (less than 0.05 pounds per hour) 

5

not applicable (N/A) – potential emissions are combustion byproducts of the marine vapor 

control, CD1001, used to control VOC from product loading arm 

6

equipment is demolished and removed from the Title V permit 

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

Bayway petroleum refinery currently has 11 process heaters that fall within the applicable BART 

time frame. The cumulative permitted PTE from these qualified units exceed the BART 

threshold for NOx and SO2 emissions (541.5 and 1829.5, respectively), and therefore this facility 

is a BART-eligible source. See Section 1.5.2 for details 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 wastewater treatment plant. Since VOCs were 

the only pollutants to be emitted from this emission unit, these pieces of equipment were not 

included in the cumulative determination of the facility-wide PTE from qualified emission units. 

The FCCU emission unit, also identified on the original list, falls outside the applicable time 

frame with installation occurring in 1949 and is not affected by BART. 

SO2 and PM10 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 not 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 H2S 

content in refinery fuel gas. See section 1.5.2. 

One heater, E244, with a start up date of 1969, suffered 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 heater.10 Consequently this heater is subject to 

 

10 http://edocket.access.gpo.gov/cfr_2006/julqtr/pdf/40cfr51.301.pdf 
11

NSPS subpart J standards for particulate matter, carbon 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 BART because this unit meets USEPA's BART 

exemption guidance in Appendix Y for a "reconstructed" unit for the following reasons: 

(1) the reconstruction date was after August 7, 1977; 

(2) the reconstructed unit went through NSR/PSD permitting; and 

(3) the fixed capital cost of the new component exceeds 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 included 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 the 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 

NOx SO2 PM10

BART 

eligible 

E241 F-101 PFBW 

hydrofiner heater 

1969 Yes 30.7 170.4 6.57 Yes1

E242 F-101 DSU-1 gas 

oil heater 

1969 Yes 22.3 N/A6 N/A6 Yes1

E244 F-102 DSU-1 

Treat Gas heater 

1969 Yes –– –– –– No5

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 Yes1

E248 F-106 PFBW 

Regen Gas heater 

1971 Yes 27.6 157.2 6.1 Yes1

E249 F-107 PFBW 

Dryer heater 

1971 Yes 9.0 23.7 0.88 Yes1

E250 F-108 PFBW 1971 Yes 47.3 N/A6 N/A6 Yes1

 

11 http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/40cfr51AppY.pdf
12

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 

NOx SO2 PM10

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 Yes1

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 No7

E258 F-702 OBFT 

Outboard Flash 

heater 

1970 Yes 157.7 81.0 23.4 Yes1

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 –– –– –– No3

E186 

–E189

Stretford tanks 1974 Yes N/A N/A N/A No4

E267 Cooling Tower UNK N/A N/A N/A N/A No4

E268 

–E270

PFBW vents 1971 Yes N/A N/A N/A No2

E271 

–E272

Marine loading 

operations 

1990 No –– –– –– N/A 

E273 

–E274

Truck loading 

operations 

UNK N/A N/A N/A N/A No2
13

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 

NOx SO2 PM10

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 No2

E292 Fixed roof tank UNK N/A N/A N/A N/A No4

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 NOx SO2 PM10 PTE 

Totals (tpy): 541.5 1829.5 66.0 > 250 

Notes: 

1

equipment with applicable emissions to be considered cumulatively in determining the facility’s 

BART eligibility 

2

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

3

equipment is demolished and removed from the Title V permit 

4

not applicable (N/A) – potential emissions from pollutants other than NOx, SO2, or PM10

5

reconstruction commenced after August 7, 1977 

6

not applicable (N/A) – SO2 and PM10 emissions considered in PSD netting (2004) for the Clean 

Fuels project 

7

SOTA (ULNB + SCR) 2004, 2007 – NOx, 0.03 lb/MMBtu; H2S, 0.10 gr/dscf (or 162 ppmvd) 

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

County 
14

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 NOx, SO2, 

and PM10 (11,846, 11,659, and 4483.8, respectively), and therefore this facility is a BARTeligible source. See Section 1.6.1 for details regarding existing controls and BART 

determinations. 

Unit 2 (E2) is a coal-fired boiler and subject to state-of-the-art controls and federally enforceable 

emission limits by December 31, 2010, due to an enforceable 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 reclaim system (E23) are support systems to E2 

with the potential to emit particulate emissions only. The conveying systems are covered and the 

coal piles are controlled with aqueous spray dust suppression 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, 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 

NOx SO2 PM10

BART 

eligible 

E1 Unit No.1 boiler 1964 Yes 8,360 6,389 1,9963 Yes1

E2 Unit No.2 boiler 1968 Yes 3,486 5,270 2,4803 Yes1

E14 Em. Fire pump 1963 Yes N/A N/A N/A No4

E22 Coal receiving 

system 

1968 Yes N/A N/A 5.42 Yes1

E23 Coal reclaim 

system 

1968 Yes N/A N/A 2.42 Yes1

Visibility Impairing Pollutants NOx SO2 PM10 PTE

Totals (tpy): 11,846 11,659 4483.8 > 250 

Notes: 

1

equipment with applicable emissions to be considered cumulatively in determining the facility’s 

BART eligibility 

2

includes quantifiable fugitive emissions counted for comparison purposes to the 250 tpy cutoff 

3

TSP potential to emit – PM10 to be established (refer to BOP100001) 

4

replaced in 1985-1986 timeframe 

1.3 Subject to BART 

 

12http://www.epa.gov/compliance/resources/cases/civil/caa/psegfs.pdf 
15

Based on the cumulative assessment of all BART-eligible sources in the MANE-VU region, all 

member states with BART-eligible facilities contribute 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) Chevron 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 facility, BART must be established for pollutants 

reasonably anticipated to impair visibility. The three New Jersey facilities which are subject to 

BART submitted emissions control analyses that included analytical information about affected 

equipment; existing controls in use; available retrofit controls; technical feasibility; costs of 

compliance; remaining useful life; energy and other environmental impacts as applicable; and 

other supporting data. NJDEP developed tables summarizing each facility’s current compliance 

requirements, including enforceable consent decree requirements and recent rule development, 

and proposed BART alternatives, to help determine the best control options, establish emission 

limits, and set compliance deadlines for the qualified emission units.15

 

1.5 Petroleum Refineries 

Petroleum refineries are one of 26 specific categories identified as being applicable to the BART 

requirement. The qualifying emission units at Chevron and ConocoPhillips that are subject to 

BART review are process heaters that combust refinery fuel gas, and natural gas in a few cases. 

Table 7 lists a number of available retrofit control measures to reduce NOx, SO2 and PM10

emissions from process heaters at petroleum refineries. 

According to USEPA there are a number of available control alternatives to reduce NOx

emissions from process heaters. 16,17,18,19, 20 Control techniques include combustion 

modifications to help prevent the formation of NOx such as low NOx burners (LNB), ultra low 

NOx Burners (ULNB), and flue gas recirculation (FGR). In addition, there are add-on NOx

controls including selective catalytic reduction (SCR) 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 Sources Survey of Options for Conducting BART 

Determinations. Boston, MA; June 2007. 

14 Ibid. 

15 http://edocket.access.gpo.gov/cfr_2008/julqtr/pdf/40cfr51AppY.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_nox_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. 3-7 
16

heaters throughout the petroleum refinery source category 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 of hydrogen sulfide (H2S). Petroleum 

refineries commonly employ amine scrubbing to process, or condition, the refinery fuel gas to 

reduce the levels of H2S before combustion in the process heaters to reduce SO2 emissions. 

Add-on SO2 and PM10 controls for individual refinery fuel gas-fired process heaters are not used 

in practice due to the low sulfur level after in-process gas conditioning. As the sulfur content in 

fuel decreases, the cost per ton of control for individual 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 Heaters at Petroleum Refineries

Pollutant Available control 

options 

Percent (%) 

reduction 

Potentially applicable Technically feasible

1. ULNB + SCR 85 – 99 Yes Case-by-case1

2. ULNB + SNCR 75 – 95 Yes No2

3. SCR 80 – 90 Yes Case-by-case1

4. ULNB 75 – 85 Yes Yes 

5. SNCR 30 – 75 Yes No2

6. LNB + FGR 50 – 72 Yes Yes 

NOx

7. LNB 50 Yes Yes 

1. Fuel switching > 95 Yes Yes 

2. Fuel processing 90 Yes No3

SO2

3. Scrubbers 90 – 99.9 No No4

1. Wet scrubbers 

2. ESP 90 

No No4PM10

3. Good combustion practices Yes Yes 

Notes: 

1Case-by-case – not widely in use on process heaters within the industry 

2Not reasonably applicable – temperature dependent and limited operating range 

3Not practically applicable to individual process heaters – typically in-process gas treatment 

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

New Jersey regulates NOx 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, shall emit NOx at a rate no greater than the 

applicable maximum allowable NOx emission rate of 0.20 pound per million BTU (lb/MMBtu).24 

The State of the Art (SOTA) performance emission level for NOx 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.42 
17

for Petroleum Refineries is 0.07 lb/MMBtu for burner replacement.25 Certain petroleum 

refineries, like ConocoPhillips, are also subject to 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 determining BART. See Table 8 below. 

Table 8 Comparison of NOx Performance Limits for Process Heaters Located at Petroleum 

Refineries 

NOx 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 document are subject to federal Subpart J – 

Standards of Performance for Petroleum Refineries (NSPS Subpart J)26 that requires H2S 

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 combustion adjustments for process heaters 

with a maximum gross heat input rate of at least five 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. However, 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 Crude Furnace F510 

Pollutant NOx NOx SO2 PM10 NOx NOx SO2 PM10

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** –– –– –– –– –– –– –– –– 

 

25http://www.state.nj.us/dep/aqpp/downloads/sota/sota3.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=40 
18

 * 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 these two furnaces, Chevron proposed to cap out 

the annual potential to emit NOx from these BART qualified heaters to less than 250 tons per 

year. This is consistent with the MANE-VU Air Directors’ recommendation that by accepting a 

permit limit, a facility may “cap-out” of BART-eligibility. See recommendation 1. at Appendix 

C of the Five Factor Analysis report.27 

Chevron proposed that the annual fuel input for each furnace be limited to approximately 95 

percent of the current allowable limits in its Title 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 NOx 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 to 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 incorporated as part of its operating permit 

conditions for the Crude Unit Heaters. See Appendix B at the end of this TSD. If the decision is 

made to restart the Crude Unit, and Chevron requests an increase in PTE that results in 

cumulative NOx emissions greater than 250 tpy from these two qualified 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 NOx 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 Sources Survey of Options for Conducting BART 

Determinations. Boston, MA; June 2007. 

28http://datamine2.state.nj.us/DEP_OPRA/OpraMain/REPORT_FACADE?id=a8acb14d9d3f4b1ed49bfb952e12a64

1fde1122acf05d1217e9938b3612795d0deec0b282a8f7fcd5267954f6e3d16a3450764cfda6b46a0f4c0161c228a622c

b68baec4c3656669a71adb7b1bd8c7d987945fa168fd23ba 

29 http://www.state.nj.us/dep/aqm/Sub21.pdf 
19

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) BART Analysis 

The USEPA undertook an enforcement initiative focused on Clean Air Act compliance 

violations within the petroleum refinery sector with respect to New Source Review 

(NSR)/Prevention of Significant Deterioration (PSD) and New Source Performance Standards 

(NSPS). On January 27, 2005, the United States Department of Justice (USDOJ), USEPA, and 

NJDEP entered into an enforceable consent decree (CD)30 with ConocoPhillips including its 

New Jersey refinery. The types of equipment that are 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 reductions of nitrogen oxide and sulfur dioxide, 

precursors to fine particulate matter.31 Bayway petroleum refinery currently has 11 refinery 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 

NOx

SCR 

0.040 

lb/MMBtu, or 

lower 

12/31/2010* 

Upgrade gas system** 40 CFR 60 

Subpart J - 

H2S, 0.10 

gr/dscf (or 162 

ppmvd) 

E241 06/30/2011 

E242

E243

E245

E246

E247

E248 

E249 

E250 

E253 

E258 

SO2

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.html 
20

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 than 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 shown 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 Qualifying Controls were installed.” Qualifying 

controls are defined in the CD as one, or any combination of SCR or SNCR; current generation 

or next generation ULNB; or other qualifying technologies that can reduce NOx emissions to 

0.040 lbs/MMBtu. All the BART qualified heaters are currently equipped with ULNBs with 

internal FGR to control NOx with overall average NOx 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 H2S requirements of NSPS subpart J by 

June 30, 2011. Subpart J also stipulates continuous monitoring of the H2S concentration based 

on a 3-hour rolling average. ConocoPhillips is already required to monitor the H2S concentration 

of the refinery fuel gas as a condition of their operating permit. See Table 12 below. 
Table12 Summary of Current Title V Permit Conditions for BART Qualified Equipment (BOP100005) – Conoc

Heat Input NOx SO2 PM

Allowable emission limit 

Allowable emission limit 

Equip. NJID 

Equipment Description 

(MMBtu/hr)

Fuel type Existing 

Control(s) 

(lb/hr) 

Existing Control* 

(lb/hr) 

Existing Control 

1. E241 F-101 PFBW 

hydrofiner heater 

74 Callidus 

ULNB** 

7 38.9 

2. E242 F-101 DSU-1 

gas oil heater 

51 Callidus 

ULNB** 

5.1 N/A 

3. E243 F-102 PFBW 

Reheat heater 

167 Callidus 

ULNB** 

4. E245 F-103 PFBW 

Reheat heater 

90 Callidus 

ULNB** 

5. E246 F-104 PFBW 

Reheat heater 

108 Callidus 

ULNB** 

6. E247 F-105 PFBW 

Reheat heater 

83

448 

Callidus ULNB** 

42.6 244 

7. E248 F-106 PFBW 

Regen Gas heater 

66 Callidus 

ULNB** 

6.3 35.9 

8. E249 F-107 PFBW 

Dryer heater 

10 ULNB** 2 5.4 

9. E250 F-108 PFBW 

Reboiler heater

114 Callidus 

ULNB** 

10.8 N/A 

10.E253 F-401 DSU-2 

Reactor heater 

139 

RFG only 

Callidus ULNB** 

13.9 75.5 

11.E258 F-702 OBFT 

Outboard Flash heater 

500 RFG 

and NG 

JohnZinkULNB** + air preheater 

36 

Fuel switching 

18.5 

GCP 

 *firing of fuel oil is not allowed in these furnaces (Paragraph 117 of Consent Decree, H-05-0258)  **Ultra Low NOx Burner (ULNB) employs internal Flue Gas Recirculation 

***existing gas system averages about 80 ppm H2S; reducing SO2 emissions also reduces condensable particulat
Due to misinterpretation of the de minimis levels allowed in the Regional Haze rule, E249, a 10 

MMBtu/hr process heater, was initially excluded from ConocoPhillips BART analysis. Based on 

informal guidance from USEPA regarding determination 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 NOx control to a unit of this 

relatively small size is unlikely to be cost effective due to its low impact over baseline levels.33 

There are three process heaters that serve the facility’s crude unit, E257, E258, and E259. All 

have ULNBs. Note that an operating permit modification (BOP070010) to install SCR on the 

Pipestill heaters, E257 and E259, per the CD, was approved by NJDEP on January 1, 2009 and 

compliance is expected by December 31, 2010. In conjunction with the SCR installation, E259 

was replaced in 2009 with a new heater and is no longer considered a qualified unit. Likewise 

E257 is not identified in Table 5 as a qualified unit. Based on USEPA’s ranking of available 

control options, ULNB and SCR is the best control combination and therefore NJDEP has 

determined that these NOx controls are BART for this unit, E257. USEPA estimates a reduction 

of 500 tons per year in total NOx 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 rated at 500 MMBtu/hr and is equipped 

with first generation ULNB combustion control. Using the actual capital cost for E257 and 

E259, ConocoPhillips estimated the cost of modifying E258 to be two-thirds, or $30,000,000, 

based on its size. See Table 13 below. 

However the feasibility and costs of retrofit controls depend on the refinery configuration. E258 

is a heat recovery unit that sits atop an air preheater which is not a qualified unit. There is no 

acceptable location to install SCR since the flue gas temperature is too high before E258 and too 

low aft to operate properly. Also due to space constraints, both E258 and the air preheater would 

need to be replaced to accommodate SCR. Due to space and temperature constraints, SCR is not 

technically feasible, and therefore is not a viable option. NJDEP has determined that the existing 

NOx controls are BART for E258. 

The remaining process heaters have Callidus ULNBs and 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. Annual emissions reductions will be lower for 

these smaller units resulting in greater cost effectiveness numbers. 

 

 

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

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

34http://www.epa.gov/compliance/resources/decrees/amended/noticeoflodging-firstamendmentconocophillips-cd.pdf 
Table 13 Comparison of Technically Feasible NOx Control Technologies – Bayway (PI#41805) 

Actual Emission Rate 

Annual Emissions 

Annual Emissions Reduction 

Installed Capital Cost 

Annual Operating Cost Estimate 

Total Annualized Costs* 

Cost Effectiveness 

IncreCost 

Feasible Control Alternative(s) 

lb/MMBtu (tpy) (tpy) ($ 1998) ($/yr) ($/yr) ($/ton) ($/ton

E258 (F-702) Baseline (1st gen 

ULNB) 

0.057** 79*** N/A N/A N/A N/A N/A N/A 

a. ULNB newer generation (21% eff.) 

0.045 62 17 $ 1,750,000 Minimal $ 249,000 $ 15,659 

b. SCR (79% eff.) 0.012 17 45 $30,000,000 $450,000 $ 3,775,000 $ 76,161 

$104

 *based on 7% interest rate and 10 yrs remaining useful life of equipment, the capital recovery factor (CRF) is 0.14238.  **based on CEMS. ***based on 2009 reported emissions 
According to the CD, at least 30% of the total maximum heat input capacity or, if less, the 

allowable heat input capacity of the process heaters located at Bayway Refinery, as shown in 

Appendix B of the first amendment to the CD, must use qualifying technologies that can reduce 

NOx emissions to 0.040 lbs/MMBtu.35 Of the remaining process heaters considered in this 

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 NOx emissions 

average 0.048 lb/MMBtu. Based on the performance of the existing ULNBs, compared to the 

NOx performance levels cited in Table 8, and the expected higher cost effectiveness numbers, 

NJDEP has determined that existing NOx controls are BART. 

Table 14 Summary of Actual 2000-2001 Average NOx Emissions of Remaining Process Heaters 

Allowable 

Heat Input 

Actual NOx 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 NOx 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, 2011 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 have amine treaters but was prone to spikes above 

162 ppm. The upgrades to the gas system, primarily re-routing certain gas streams, will ensure 

 

35http://www.epa.gov/compliance/resources/decrees/amended/noticeoflodging-firstamendmentconocophillips-cd.pdf
25

that compliance with subpart J can be maintained under all potential refinery scenarios including 

start-up, shutdown, and maintenance. 

Monitoring of this gas system for compliance with the existing standard, 0.5% sulfur according 

to the operating permit, typically indicates a concentration about 60 ppmv of H2S. The NSPS 

subpart J standard is 162 ppmv (0.1 gr/dscf) H2S 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 H2S in lieu of 

having a SO2 CEM. 

Compliance with 162 ppmv H2S limit under NSPS subpart J is estimated to reduce annual PTE 

SO2 from affected heaters, including E242 and E250, by approximately 94 percent (%). See 

Table 15 below. NJDEP has determined that compliance with the H2S requirements of NSPS 

subpart J as BART. 

Table 15 Estimated SO2 Emission Rates based on NSPS subpart J for Affected Process Heaters– 

ConocoPhillips (PI#41805) 

Heat Input SO2

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 

H2S 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 SO2

11.E258 F-702 OBFT 500 81 N/A 18.5 0.03 NSPS subpart J 
26

Heat Input SO2

tons per year 

Equip. 

NJID 

Equipment 

Description MMBtu/hr 

Allowable Allow. Est.* 

lb/hr** lb/ 

MMBtu

Notes 

Outboard 

Flash heater 

compliant 

(BOP090004) 

 *Annual SO2 numbers represent estimated new permit limits following CD requirement to comply with NSPS subpart J.

**Compliance with 162 ppmv H2S limit will result in SO2 emission rates approximately the same as these hourly emissions 

based on 3-hr rolling average. 

Annual combustion adjustments of the process heaters are to be carried out according to the 

manufacturer’s recommended procedures and maintenance schedule pursuant to N.J.A.C. 7:27-

19.7 and 19.16 to ensure complete combustion through good combustion practices (GCP). When 

operating properly, SO2, NOx, CO, PM10, and VOCs from refinery fuel gas-fired process heaters 

are relatively low.36

NJDEP has determined that the NOx, SO2 and PM controls, emission limits, averaging times, and 

compliance dates from the CD for ConocoPhillips’ Bayway refinery are BART. ConocoPhillips 

submitted an application to modify its Title V operating permit to incorporate the H2S 

requirements of NSPS subpart J in December, 2010 (BOP110001) . Full implementation is 

expected by June 30, 2011. 

Table 16 Summary of Final BART for NOx, SO2, and PM10 at ConocoPhillips Bayway Refinery 

(PI#41805) 

Equip. 

NJID 

Equipment 

Description 

BART Controls BART Emission 

Limit 

Compliance 

Date 

NOx Existing 

ULNB 

7 lb/hr (any 60-

min. period) 

Effective 

BOP090004 

SO2 Upgrade gas 10.6 tpy 

system H2S*** 

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 

PM10

Upgrade gas 

system** 

1.5 lb/hr 

06/30/2011 

NOx 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 SO2 Upgrade gas 

system H2S*** 

162 ppmvd 

06/30/2011* 

Pending 

approval 

 

36 http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/petrefsn.pdf , p.39 
27

Equip. 

NJID 

Equipment 

Description 

BART Controls BART Emission 

Limit 

Compliance 

Date 

(three-hour 

rolling average) 

BOP110001 

Continue 

GCP 

Effective 

BOP090004 

PM10

Upgrade gas 

system** 

1.1 lb/hr 

06/30/2011 

 

NOx Existing 

ULNB 

42.6 lb/hr Total 

(any 60-min. 

period) 

Stack testing 

Effective 

BOP090004 

SO2 Upgrade gas 64.4 tpy 

system** H2S*** 

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) 

PM10

Upgrade gas 

system** 

5.6 lb/hr 

06/30/2011 

NOx Existing 

ULNB 

6.3 lb/hr (any 

60-min. period) 

Effective 

BOP090004 

SO2 Upgrade gas 9.6 tpy 

system H2S*** 

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 

PM10

Upgrade gas 

system** 

1.4 lb/hr 

06/30/2011 

NOx Existing 

ULNB 

2 lb/hr (any 60-

min. period) 

Effective 

BOP090004 

1.45 tpy 

8. E249 F-107 PFBW Dryer 

heater 

10 MMBtu/hr SO2 Upgrade gas 

system 

H2S*** 

162 ppmvd 

(three-hour 

06/30/2011* 

Pending 

approval 

BOP110001 
28

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) 

PM10

Upgrade gas 

system** 

0.2 lb/hr 

06/30/2011 

NOx Existing 

ULNB 

10.8 lb/hr (any 

60-min. period) 

Effective 

BOP090004 

SO2 Upgrade gas 16.5 tpy 

system H2S*** 

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 

PM10

Upgrade gas 

system** 

2.4 lb/hr

06/30/2011 

NOx Existing 

ULNB 

13.9 lb/hr (any 

60-min. period) 

Effective 

BOP090004 

SO2 Upgrade gas 19.4 tpy 

system H2S*** 

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 

PM10

Upgrade gas 

system** 

1 lb/hr 

06/30/2011 

NOx 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 SO2 Continue/ 

maintain gas 

conditioning 

H2S*** 

162 ppmvd 

(three-hour 

rolling average) 

Effective 

BOP090004 
29

Equip. 

NJID 

Equipment 

Description 

BART Controls BART Emission 

Limit 

Compliance 

Date 

Continue 

GCP 

PM10

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 condensable PM 

 *** in lieu of SO2 CEM (NSPS is considered a surrogate for short term SO2 limits on each heater) 

 **** Based on estimated allowable PTE after incorporation of Consent Decree in Title V permit 

1.6 Fossil fuel-fire steam Electric Power Plants 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 British thermal units (BTU) per hour heat input 

that generate electricity for sale. Appendix Y Guidelines for BART require coal-fired electric 

generating units (EGUs) greater than 200 MW meet 0.15 lb/MMBtu emission limit for SO2; and 

for any size oil-fired units, the sulfur fuel content 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 

NOx 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) that are subject to BART review. One boiler 

is coal-fired (E2) and subject to controls and federally enforceable emission limits effective 

December 31, 2010, due to an enforceable consent decree (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 control 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 NOx, SO2, and PM 

standards shown in Table 17 below by December 15, 2012. 

Table 17 N.J.A.C. 7:27-27.7(b) – Maximum Allowable NOx, SO2 and PM Emission Rates for 

Coal-fired boilers (Operative on and after December 15, 2012) 

Pollutant Emission Limit 

(lb/MMBtu) 

Boiler Type 
30

Pollutant Emission Limit 

(lb/MMBtu) 

Boiler Type 

NOx 0.100 Dry bottom* 

0.130 Wet bottom 

SO2 0.150 

PM 0.030 

* Unit 2 is a dry bottom boiler 

More recently, New Jersey’s NOx rules for boilers serving EGUs were revised on March 20, 

2009. Unless subject to more stringent permit limits or otherwise specified in an enforceable 

agreement, the rules require more stringent NOx 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 Allowable NOx 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 amendment to its Sulfur in Solid Fuels rule at 

N.J.A.C. 7:27-10.2(h) which specifies that on and after December 15, 2012, the owner or 

operator of any source that combusts solid fuel shall cause it to emit SO2 at a 24-hour emission 

rate no greater than 0.250 lbs/MMBTU gross heat input for every calendar day, and at a 30-

calendar-day rolling average emission rate no greater than 0.150 lbs/MMBTU gross heat input. 

The coal receiving system (E22) and the coal reclaim system (E23) are support systems to the 

coal-fired E2 with the potential to emit particulate emissions only. The conveying systems are 

covered, and the coal piles are controlled with spray dust suppression systems. The quantifiable 

fugitive emissions from the conveying systems were counted for comparison purposes in 

determining BART eligibility. Fugitive emissions are those that are not vented through a stack 

and that cannot be reasonably controlled.37 These emission units, E22 and E23, are not discussed 

further. See Table 19. 

 

37 http://www.state.nj.us/dep/aqm/Sub22.doc 
Table 19 Summary of Current Title V Permit Conditions for BART Qualified Equipment (BOP080003) – PSEG 

Station (PI#12202) 

Heat Input NOx SO2 P

Allowable emission limit 

Allowable emission limit 

Equip. NJID 

Equipment Description 

(MMBtu/hr)

Fuel type Existing 

Control 

(lb/hr) 

Existing Control 

(lb/hr) 

Existing Control 

1. E1 Unit No.1 NG 1,960 None 7.8 

boiler (420 MW) 

4,558 

#6FO 

None 

1,960 0.3% S 

by wt 

1,459 

GCP 

Coal 0.259 

lb/MMBtu 

0.25% S by wt 

0.216 lb/MMBtu 

ESP 

NG 3,643 None 3.5 GCP 

2. E2 Unit No.2 

boiler (640 MW) 

6,600 

#6FO 

LNB** & SNCR (yearround) 

3,643 0.3% S 

by wt 

1,907 ESP 

3. E22 Coal receiving 

system 

Covered; Spray dussuppresso

4. E23 Coal reclaim 

system 

N/A N/A N/A N/A 

Covered; Spray dussuppresso

 * BOP1000001 Modification to establish PM10 maximum allowable emission limits is pending approval. 

** New LNBs installed in 2008
Unit No. 1 Boiler (E1):

Unit No. 1 is a 4,558 MMBtu/hr Babcock and Wilcox cyclone-fired steam generating boiler that 

began commercial operation in 1964. This unit is permitted to combust natural gas or No. 6 fuel 

oil. See Table 20 below. 

Table 20 Current Title V Operating Permit (BOP080003) for Unit 1 – PSEG Fossil LLC Hudson 

Generating Station (PI#12202) 

Effective Permit Requirements (BOP080003) 

Heat Input Maximum Allowable Emission Limits 

(MMBtu/hr)

Pollutant

Natural Gas #6 Fuel Oil PTE 

 lb/hr lb/MMBtu lb/hr lb/MMBtu tpy 

NOx 1,960 0.39* 1,960 0.4* 8,360 

SO2 7.8 0.0017 1,459 0.32** 6,389 

4,558 

PM10 100.3 0.022 227.2*** 0.050*** 995 

 

*NOx emissions avg. plan 

 

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

 ***PM10 based on AP42 emission factors for residual oil (BOP100001)

PSEG intended to retire E1 in 2005. However the Pennsylvania-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 reliability. Consequently, this boiler operates 

infrequently and well below its annual operating capacity. In recent years the unit has burned 

only natural gas, which has inherently lower NOx, SO2, and PM10 emissions, and currently 

operates without combustion technology or add-on emission 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 Firing 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 NOx, SO2, and PM10 emissions. 38

 

 

38 http://cfpub.epa.gov/RBLC/index.cfm?action=Home.Home&lang=en 
33

The facility also consulted a vendor to assess technical feasibility of various NOx controls and 

potential NOx reductions.39 The results are summarized in Table 22 below. 

Table 22 List of Potential Retrofit Emission Control Techniques for Large Utility Boilers > 250 

MMBtu/hr that Combust Natural Gas 

Potential Retrofit Control Techniques for Unit 1 (E1) 

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 

NOx

1

8. LNB/ULNB 20 Yes Yes 

SO2

2

 1. None 

PM10 1. Good combustion practices (GCP) 

Notes: 

1Reduction based on the current baseline NOx emission for equivalent boilers. 

2None indicated in recent BACT/LAER determinations for boilers > 250 MMBtu/hr that 

combust natural gas. 

Table 23 shows the NOx control alternatives that were evaluated for Unit 1. Based on efficiency 

and cost effectiveness, the dominant controls appear to be a. c. and e. However since Unit 1 

must meet 1.00 lbs/MWhr (approx. 0.10 lb/MMBtu) when combusting natural gas by May 1, 

2015, option a. may be the most viable control alternative. This date is consistent with the 

federal requirement to install BART controls as soon as practicable but no later than 5 years after 

USEPA's approval. 

In December, 2010 PSEG submitted an application (BOP110001) to modify the Hudson 

operating permit to include more stringent NOx 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 NOx rule at N.J.A.C.7:27-19.4 Table 3 for 

E1; and to only 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. 

 

39 http://www.state.nj.us/dep/baqp/2008%20Regional%20Haze/Appendix%20G-8%20%28Final%20Only%29.pdf
Table 23 Comparison of Technically Feasible NOx Control Technologies for Unit #1 Firing Natural Gas – PSEG 

Station (PI#12202) 

Actual Emission Rate 

Annual Emissions 

Annual Emissions Reduction 

Installed Capital Cost 

Annual Operating Cost Estimate 

Total Annualized Costs* 

Cost Effectiveness 

IncreCost 

Feasible Control Alternative(s) 

lb/MMBtu (tpy) (tpy) ($ 2009) ($/yr) ($/yr) ($/ton) ($/ton

1.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 $87,9b. ULNB, OFA + SNCR (55% eff.) 

0.152 72.95 89.15 $10,546,981 $ 167,000 $1,738,811 $19,504 N/A 

c. ULNB, OFA + FGR  (55% eff.) 

0.152 72.95 89.15 $ 8,136,242 $ 52,300 $1,264,840 $14,187 $35,1

d. ULNB + OFA 

 (40% eff.) 

0.202 97.26 64.84 $ 5,725,504 $0 $ 853,269 $13,160 N/A 

e. FGR (40% eff.) 0.202 97.26 64.84 $ 2,410,739 $ 52,300 $ 411,571 $ 6,348 See cf. SNCR (35% eff.) 0.219 105.37 56.73 $ 4,821,477 $ 167,000 $ 885,542 $15,609 N/A g. OFA (25% eff.) 0.253 121.58 40.52 $ 2,561,410 $0 $ 381,726 $ 9,420 N/A h. 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 - 2008 
35

Unit No. 2 Boiler (E2):

On July 26, 2002, a federal enforcement settlement required PSEG to install state-of-the-art 

(SOTA) controls for NOx, SO2, and PM on all its coal-fired boilers in the State of New Jersey. 

These controls included SCR, FGD, and a polishing baghouse for Hudson Unit No. 2. 

 

An amendment to the initial consent decree was negotiated to extend the compliance deadlines. 

As a consequence PSEG Hudson Generating Station specifically took interim steps to reduce 

emissions of NOx, SO2 and PM until December 31, 2010, when the required pollution control 

equipment was installed on Unit 2. These interim measures included year-round operation of the 

existing NOx control equipment utilizing selective non-catalytic reduction (SNCR) to reduce 

NOx, use of 100% ultra-low sulfur coal, compliance with annual emission caps for NOx and SO2, 

and operation of an electrostatic precipitator (ESP) and a fly ash conditioning system to control 

PM. PSEG was also required to install a more effective 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 Decree 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: 

NOx

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 

SO2

Install dry FGD with spray dryer 

absorber (SDA) 

0.150 lbs/MMBtu 

30-day avg. 

12/31/2010 
36

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 (CEMS) 12/31/2010 

 * State-of-the-art (SOTA) for sulfur dioxide, nitrogen 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 bringing 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. The new FGD is a dry type that utilizes Spray 

Dryer Absorbers (SDAs) in concert 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 optimizing the operation of these new controls. Since commencing 

operation, however, the average calendar day emission rates of NOx and SO2 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. 

NJDEP has determined the new selective catalytic reduction (SCR) and the existing low NOx

burners (LNBs), dry flue gas desulfurization (FGD) with spray dryer absorber (SDA) and use of 

2 percent (%) by weight low sulfur coal, and baghouse air pollution control systems for oxides of 

nitrogen (NOx), sulfur dioxide (SO2), and particulate matter (PM), respectively, for E2, and the 

existing PM controls for the two coal handling systems, are BART. 

Under the Clean Air Act, BART requirements must be included as Title V operating permit 

conditions. This required PSEG to submit a modification application to implement the NOx

control, emission limits, fuel oil restriction, and compliance deadlines. PSEG submitted a permit 

modification to NJDEP in December, 2010 to incorporate 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 included in the current approved Title V 

operating permit, BOP080003. 
37

Table 25 Summary of Final BART for NOx, SO2, and PM10 at PSEG Fossil LLC Hudson 

Generating Station (PI#12202) 

Equip. BART emission limit 

NJID 

Equipment 

Description

BART control 

lb/MMBtu lb/hr 

Compliance 

date 

Natural Gas 

NOx SCR (or equivalent) –– 1.00 lb/MWh 

24-hour avg. 

05/01/2015 

Pending 

approval 

BOP110001 

SO2 None –– 7.8 

any 60 minute 

period 

Effective 

BOP080003 

PM10 Continue GCP –– 100.3 

three one-hour 

stack tests 

Pending 

approval 

BOP1000001 

No. 6 fuel Oil - Restricted use during gas curtailments only 

NOx SCR (or equivalent) –– 2.00 lb/MWh 

24-hour avg. 

05/01/2015 

Pending 

approval 

BOP110001 

0.3% S by wt (exist.) Effective 

BOP080003 

SO2

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 

 

PM10 Continue GCP –– 227.2 

three one-hour 

stack tests 

Pending 

approval 

BOP1000001 

Coal 

Existing LNBs Effective 

BOP080003 

NOx

SCR 

0.100 

30-day 

avg. 

0.150 

24-hr avg. 

–– 

12/31/2010 

BOP080003 

SO2 Dry FGD w/SDA 

<= 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 

PM10 Baghouse (and ESP 

as needed) 

0.0150 

three one-

–– 12/31/2010 

BOP080003 
38

Equip. BART emission limit 

NJID 

Equipment 

Description

BART control 

lb/MMBtu lb/hr 

Compliance 

date 

hour stack 

tests 

Natural Gas 

Existing LNBs Effective 

BOP080003 

NOx

SCR 

0.100 

30-day 

avg. 

0.150 

24-hr avg 

–– 

12/31/2010 

BOP080003 

SO2 No need to operate 

FGD 

0.150 

30-day 

avg. 

0.250 

24-hr avg. 

–– 12/31/2010 

BOP080003 

PM10 No need to operate 

baghouse 

0.0150 

three onehour stack 

tests 

–– 12/31/2010 

BOP080003 

No.6 Fuel Oil 

Existing LNBs Effective 

BOP080003 

NOx

SCR 

0.100 

30-day 

avg. 

0.150 

24-hr avg 

–– 

12/31/2010 

BOP080003 

SO2 Dry FGD w/SDA 0.150 

30-day 

avg. 

0.250 

24-hr avg 

–– 12/31/2010 

BOP080003 

PM10 Baghouse (and ESP 

as needed) 

0.0150 

three onehour stack 

tests 

–– 12/31/2010 

BOP080003 

E22 Coal 

receiving 

system 

PM10 Existing enclosure 

and dust suppression 

system 

N/A 1.27 Effective 

BOP080003 

E23 Coal 

reclaiming 

system 

PM10 Existing enclosure 

and dust suppression 

system 

N/A 0.2 Effective 

BOP080003 
39

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 establish 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, ConocoPhillips Bayway Refinery, and PSEG 

Hudson Generating Station, are subject to BART review. The Hess Port Reading and Sunoco 

Eagle Point petroleum refineries are below the emissions threshold for BART. 

Chevron Products: 

Chevron currently has two refinery fuel gas-fired furnaces (E1501 and E1502) that are subject to 

BART review. Chevron proposed to reduce to its annual combustion limit to bring this facility’s 

potential to emit NOx to less than 250 tons per year (tpy) by March 15, 2011. 

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 USEPA entered into a CD with 

ConocoPhillips including its New Jersey refinery. NJDEP has determined that the NOx, SO2, 

and PM controls, emission limits, averaging times, and compliance dates from the CD for the 

process are BART. Also, the CD requires all the BART-qualified process heaters at the Bayway 

facility to eliminate oil burning, and to only burn refinery fuel gas with an hydrogen sulfide 

(H2S) content less than 162 ppmvd based on NSPS subpart 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) that are subject to BART review. One boiler 

is coal-fired (E2) and subject to controls and federally enforceable emission limits effective 

December 31, 2010, due to an enforceable consent decree (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 reclaim system (E23) are support systems to E2 

with the potential to emit particulate emissions only. The conveying systems are covered and the 

coal piles are controlled with water dust suppression system. 
40

NJDEP has determined that the new selective catalytic reduction (SCR) and existing low NOx

burners (LNBs), new flue gas desulfurization (FGD), and new baghouse air pollution control 

systems for oxides of nitrogen (NOx), sulfur dioxide (SO2) 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 modify the Hudson operating permit to include 

more stringent NOx 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 NOx rule at N.J.A.C.7:27-19.4 Table 3 for E1; and to only 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 state 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 approved. 
41

Appendix A

From: "LaFayette, Doug:" <Doug.LaFayette@conocophillips.com> 

To: "'Margaret Gardner'" <Margaret.Gardner@dep.state.nj.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 and recharge those batteries!!! 

I will look at the tables and respond separately if I have issues with any of them. Regarding your particular 

questions: 

1. E244 (F102 DSU-1) - please verify that "reconstruction" 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 Subpart 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? External 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 permitted 

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 does ConocoPhillips anticipate submitting a modification to 

Title V to add NSPS Subpart J sulfur in gas limits for these process heaters? Does CP plan to coordinate with 

modification application to upgrade the refinery fuel gas system? 

First, no permit is required for the "upgrade" to the 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 averages about 80 ppm H2S but was prone to spikes above 162 ppm 

from time to time for various known reasons. Bayway 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 achieve 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 turnarounds when certain fuel gas treaters were not available. Note 

that the CD allows until 6/30/2011 to demonstrate compliance with the NSPS and we will comply by that date. The 

plan is to submit a permit modification to incorporate NSPS Subpart J conditions on the heaters not currently subject 

to NSPS Subpart J by this fall. We anticipate permit approval before 6/30/2011 but even absent an approved permit 

we will comply with the NSPS limit as we have for every other CD requirement where permit approval lagged 

behind the CD compliance date. 

4. E249 (PFBW dryer heater) - the EPA determined that deminimis thresholds do not apply on an individual 

emission unit basis, so this unit meets the applicability criteria for BART. It is listed in the tables below. 

I have no comment here. This is a 10 MMBtu/hr heater which isn't going to have much impact on visibility. I 

actually thought there was a deminimis but I will defer to you. Every time BART raises it's ugly head I end up 

re-reading the rule. I don't have time for that right now. 

5. Appendix B of the consent decree doesn't list the affected combustion units at the Bayway facility. From 

paragraphs 94 and 95: are any of the facility's combustion 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. The subsequent 

versions of the CD (following the first and second amendments) which you may not have do include the Bayway 

heaters in Appendix B. I am attaching a copy of the Bayway table from Appendix B for your convenience. The 

print is very small and you may need a magnifying glass (a big one) but welcome to my world. Note that all the 

heaters burn RFG. We are not allowed (by permit) nor are we capable of burning oil any more at the refinery. 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 are 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 annual combustion tuning requirement kicks in for the smallest 

heaters this year. Recent rulemakings made all heaters 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 not 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 ConocoPhillips' analysis of affected process heaters that I forwarded to EPA 

and the FLM for their feedback. If you have questions or changes to these preliminary tables, please let me know. 

The following are questions I have which arose during the evaluation of this facility's analysis: 

1. E244 (F102 DSU-1) - please verify that "reconstruction" meets the definition in 51.301 of the BART rule (a 

question from EPA); 

2. Do these heaters have both ULNB plus FGR? External FGR? (the equipment inventory details from NJEMS list 

both); 

3. From paragraph 114(b) of consent decree - when does ConocoPhillips anticipate submitting a modification to 

Title V to add NSPS Subpart J sulfur in gas limits for these process heaters? Does CP plan to coordinate with 

modification application to upgrade the refinery fuel gas system? 

4. E249 (PFBW dryer heater) - the EPA determined that deminimis thresholds do not apply on an individual 

emission unit basis, so this unit meets the applicability criteria for BART. It is listed in the tables below. 

5. Appendix B of the consent decree doesn't list the affected combustion units at the Bayway facility. From 

paragraphs 94 and 95: are any of the facility's combustion units affected by the CD? 

6. Also I'm assuming that all the process heaters are 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 vacation this Saturday. If possible, please get back to me 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 B
45
46
47
48

Appendix C: Public Participation

Response to Comment Document regarding BART Determinations 

A notice of opportunity for public comment on New Jersey Department of Environmental 

Protection’s (NJDEP) proposed Best Available Retrofit 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 Quality Permitting Program’s website under 

Public Notices. NJDEP also sent written notification of the proposed BART to each 

environmental commission of the cities of Linden and 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 United States Forest Service) regarding NJDEP’s 

proposed BART determinations. The following is a summary of those comments, and NJDEP’s 

responses to those comments. 

General

1) Comment: Post all applicable operating permits or other enforceable commitments as an 

appendix to the BART section of the Regional Haze State Implementation Plan (SIP), 

including the permit modification from Chevron Products that requested capped emission 

limits of oxides of nitrogen (NOx) below the 250 tons per year (tpy) threshold in order to 

be excluded from BART. 

Response: Chevron, PSEG Hudson, and ConocoPhillips have submitted timely permit 

modifications to incorporate the BART requirements proposed in the TSD. NJDEP 

commits to post the final operating permits once the 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%20Haze/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 NOx Burners and SCR, and the SO2 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 received from the United 

States Fish and Wildlife Service and the United States Forest Service concurring with 

NJDEP’s BART determination for the qualified process 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 (SCR) for NOx 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 

NOx 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, control evaluation must take into 

account 1) the most stringent level of efficiency that 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 for NOx or SO2. 

Response: The SCR, FGD, baghouse, and carbon injection commenced operation on 

November 24, 2010. These are Best Available Control Technology (BACT) and 

Maximum Achievable Control Technology (MACT) controls that are also BART. 

5) Comment: For NOx control on boiler E2, SCR has been proposed as BART with an 

emission limit of 0.10 lb/MMBtu. Since low NOx 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 efficiencies of 0.05 to 0.08 lb/MMBtu in 

many boilers using various types of coals and reagents. The only information presented 

about the type of coal being used is that it is less than or equal to 2% in sulfur content. 

The type and amount of reagent proposed are not presented. 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 sulfur bituminous coal. The 

existing LNBs continue to be used in addition to the new SCR. Since commencing 

operation, the average calendar day emission rate of NOx has been approximately 0.09 

lb/MMBtu based on CEMS data through February 1, 2011. The “presumptive” level of 

NOx control provided for in the EPA BART Guidelines for 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 3.4 
50

that combust bituminous coal is 0.39 lb/MMBtu. This SCR/LNB controlled unit is less 

than 25 percent of the presumptive BART limit. 

 

6) Comment: For SO2 control on boiler E2, Flue Gas Desulfurization (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 sorbent injection, lime spray dryer). Wet 

FGD would be considered to be the most stringent control available. If any other type of 

FGD is being proposed, a BART determination that considers 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 other Electric Generation Units. The 

type and amount of reagent proposed are not presented. 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 above references remain applicable even 

if the proposed control alternative meets the “presumptive” 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). According to the U.S. Department of Energy, 

dry FGD is typically used with low sulfur coal having less than 2 percent by weight 

sulfur content along with a downstream fabric filter (baghouse) to capture any byproduct.42 The domestic, bituminous coal ranged from 1.12% to 1.28% sulfur content 

during the operational period from November 24, 2010 through February 1, 2011. Since 

commencing operation, the average calendar day emission rate of SO2 has been 

approximately 0.132 lb/MMBtu based on CEMS data through February 1, 2011 which is 

lower than 0.15 lb/MMBtu, the EPA “presumptive” level. 

. 

 

Department-initiated Changes 

In addition to non-substantive minor and/or stylistic edits (i.e., correcting typos, ensuring 

consistency, etc.), the NJDEP made the following department-initiated changes when finalizing 

the Technical Support Document and its appendices for submittal to the USEPA. 

1) added information regarding pending permit modification (BOP110001) for 

ConocoPhillips’ Title V operating permit to incorporate the consent decree requirement 

to implement the H2S requirements of NSPS subpart J; 

2) added information regarding pending permit modification (BOP110001) for PSEG 

Hudson Generating Station’s Title V operating permit to include more stringent NOx

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 bituminous coal. The existing LNBs, installed on 

 

42http://www.netl.doe.gov/technologies/coalpower/ewr/coal_utilization_byproducts/pdf/mercury_%20FGD%20whit

e%20paper%20Final.pdf
51

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 concert 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 optimizing the operation of these new controls. 

Since commencing operation, however, the average calendar day emission rates of NOx and 

SO2 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 operating permit modifications once they 

are approved. 
52
53
54
55
56
57