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>>> "JOHNSTON, PAUL K" <PKJOHNSTON@sunocoinc.com> 7/10/09 2:29 PM >>> Max, As you requested, we have prepared a summary table of emissions from sources subject to BART that compares current potential to emit values to those previously reported in the May 2007 submittal. In reviewing this data please note the following changes: * Heater HC-301 was inadvertently omitted as a source in the 2007 submission. The emissions from this source have been added to the table for both 2007 and 2009. * Estimates of the PTE from the East Flare provided in the 2007 submission were based on the highest emission inventory value reported between 2002 and 2007. The current PTE is based on the 2008 emission inventory estimate, which is the first full year that the flare gas recovery system was in operation. * Heaters Isom PH-4, 2H-203, AH-1T, CRU Ph-5A and HC-302 are out of service and deleted from the current Title V permit. With the changes noted above, the aggregate PTE for all BART sources is less than 250 tpy for each pollutant. Feel free to contact me if you have any questions regarding this data. Regards, Paul  <<Microsoft Office Excel Worksheet>> Paul Johnston Lead Environmental Engineer Sunoco Eagle Point Refinery 856-853-4425 
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This message and any files transmitted with it is intended solely for the designated recipcontain privileged, proprietary or otherwise private information. Unauthorized use, copyinof this e-mail, in whole or in part, is strictly prohibited. If you have received it in erthe sender immediately and delete the original and any attachments. CC: Friedman, Max; Wong, Danny 
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Bayway Refinery 

BART Review 

Bart Sources 

Bayway submitted a summary of BART affected sources to NJDEP on March 20, 2007. This 

summary reviewed a list of 70 sources at the refinery provided by the Department. It was 

determined that a total of 13 refinery sources were “potentially” BART affected. This included 12 

refinery heaters and the Sulfur Recovery Unit (SRU). Since that submission, the SRU has been 

removed from service, having been replaced by a state of the art sulfuric acid regeneration plant 

owned and operated by DuPont. 

One heater, the Pipestill Atmospheric Tower Heater, F-701 has undergone two major permit 

reviews for which SOTA applicability was reviewed since 2004 and we believe the Title V 

significant modifications are sufficient to remove this source from the BART eligible list. 

One additional source, the Pipestill Vacuum Tower Heater (F-751) is scheduled to be removed 

from service and replaced by a new state of the art heater. This project is required by an existing 

Consent Decree (Civil Action H-05-258) and has already completed the permit process. We 

believe that a BART analysis of this heater is not warranted since it is scheduled to be replaced. 

Therefore the ten sources which remain from the original list submitted will be reviewed to 

determine if additional controls are warranted. 

1

 F-101 (DSU-1) and F-108 emissions of SO2 and PM10 were used in netting for a PSD permit in 

2004. The project was not major for NOx so those emissions should be included in the BART 

study. Since the SO2 and PM10 were considered as part of a PSD permit they are not BART 

eligible. 

2 Title V Significant Modification was recently completed and source will meet SOTA for these 

pollutants. Not BART eligible. 

3

 Source to be removed by 12/31/2010 and replaced with a newly permitted heater meeting 

SOTA. 

(Note – SO2 numbers in parentheses represent estimated new permit limits following CD 

requirement to comply with NSPS Subpart J) 

Equip. Potential to Emit (tpy) 

No. 

 

Equipment Description 

Facility 

Designation NOx SO2 PM10

E241 PFBW Hydrofiner Heater F-101 PFBW 30.7 170.4 (10.6) 6.6 

E242 DSU-1 Gas Oil Heater F-101 DSU-1 22.3 N/A N/A 

E243 PFBW Reheat Heater F-102 PFBW 186 243.5 (64.4) 24.6 

E245 PFBW Reheat Heater F-103 PFBW 

E246 PFBW Reheat Heater F-104 PFBW 

E247 PFBW Reheat Heater F-105 PFBW 

F-102 – F-105 Emissions combined in one 

stack shown above under F-102. 

E248 PFBW Regen Heater F-106 PFBW 27.6 157.2 (9.6) 6.1 

E250 PFBW Reboiler Heater F-108 PFBW 47.3 N/A N/A 

E253 DSU-2 Reactor Heater F-401 DSU-2 60.9 330.7 (19.4) 4.4 

E257 Atmospheric Tower 

Heater 

F-701 65.72 81.02 16.02

E258 Outboard Flash Heater F-702 157.7 81 23.6 

E259 Vacuum Tower Heater F-751 N/A3 N/A3 N/A3

Total 533.5 1063.8 (185.) 65.3 
Description of BART Eligible Sources 

PFBW Hydrofiner Heater, F-101 

The hydrofiner heater, F-101, was installed in 1969 and is BART eligible for all three pollutants. 

The heater was retrofitted with Callidus Ultra-Low NOx Burners in 1999. Its permitted capacity is 

74 MMBtu/hr. The PTE for NOx emissions is 30.7 tpy based on a permitted emission limit of 7 

lb/hr and operation at that emission rate for an entire year. This allowable emission rate (PTE) is 

already less than half of the newly promulgated NOx RACT limit for Industrial, Commercial and 

Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

The PTE for sulfur dioxide is 170.4 tpy and is based on a permit limit of 38.9 lb/hr. This limit 

derives from a 1974 Consent Order between Exxon and the NJDEP that allowed for fuel to be 

combusted which contained up to 0.5% sulfur in the heaters. The consent order was originally 

crafted when all refinery heaters were equipped to fire fuel oil. This Consent Order remains in 

effect although the refinery is prohibited from firing fuel oil by permit condition U3, OS Summary, 

Reference #64. The refinery is required under the most recent Consent Decree (Civil Action H-5-

258, hereafter known as the “Consent Decree”) to have all heaters comply with NSPS Subpart J 

by December 31, 2010. This requires combustion of fuel that does not exceed 162 ppm H2S, a 

marked reduction from the current permit basis of 0.5% Sulfur. This will be accomplished when 

the Title V Permit is modified to incorporate this Consent Decree requirement the PTE for SO2 

which will result in a new estimated SO2 limit of 10.6 tpy. 

The PTE for PM10 for this heater is 6.6 tpy based on an hourly emission limit of 1.5 lb/hr. This is 

equivalent to 0.02 gr/scf calculated at the capacity of the heater. 

DSU-1 Gas Oil Heater, F-101 

The DSU-1 Gas Oil Heater, F-101 was installed in 1969 and is BART eligible only for NOx. This 

is because its SO2 and PM10 emissions were considered as part of the Clean Fuels PSD permit 

and the emissions were included in the netting for that project. Sources that have undergone 

major permitting reviews since 1977 (e.g. PSD) are not subject to BART. However, this heater 

did not undergo a PSD review for NOx and therefore should be evaluated for BART for that 

pollutant. The heater was retrofitted with Callidus Ultra-Low NOx Burners in 1999. Its permitted 

capacity is 51 MMBtu/hr. The PTE for NOx emissions is 22.3 tpy based on a permitted emission 

limit of 5.1 lb/hr and operation at that emission rate for an entire year. This allowable emission 

rate (PTE) is already half of the newly promulgated NOx RACT limit for Industrial, Commercial 

and Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

Powerformer Reheat Heaters, F-102 – F-105 

These four heaters have individual radiant section but share a common convection section and 

consequently exhaust from a common stack. They were installed in 1971 and are BART eligible 

for all three pollutants. The heaters were retrofitted with Callidus Ultra-Low NOx Burners in 1999. 

The heaters are permitted for a combined heat duty of 448 MMBtu/hr. Since the heaters emit 

from a common stack compliance is determined at the stack although individual emission limits 

exist for the separate heaters based on their heat duty. 

The PTE for NOx emissions is 186 tpy based on a permitted emission limits totaling 42.5 lb/hr 

and operation at that emission rate for an entire year. This allowable emission rate (PTE) is 

already less than half of the newly promulgated NOx RACT limit for Industrial, Commercial and 

Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

The PTE for sulfur dioxide is 243.5 tpy and is based on a permit limit of 55.6 lb/hr. This limit 

derives from a 1974 Consent Order between Exxon and the NJDEP that allowed for fuel to be 

combusted which contained up to 0.5% sulfur in the heaters. The consent order was originally 

crafted when all refinery heaters were equipped to fire fuel oil. This Consent Order remains in 

effect although the refinery is prohibited from firing fuel oil by permit condition U3, OS Summary, 
Reference #64. The refinery is required under the most recent Consent Decree (Civil Action H-5-

258, hereafter known as the “Consent Decree”) to have all heaters comply with NSPS Subpart J 

by December 31, 2010. This requires combustion of fuel that does not exceed 162 ppm H2S, a 

marked reduction from the current permit basis of 0.5% Sulfur. This will be accomplished When 

the Title V Permit is modified to incorporate this Consent Decree requirement the PTE for SO2 

which will result in a new estimated SO2 limit of 64.4 tpy. 

The PTE for PM10 for these heaters is 24.6 tpy based on an hourly emission limit of 5.6 lb/hr. 

This is equivalent to 0.02 gr/scf calculated at the capacity of the heater. 

PFBW Regen Heater, F-106 

The PFBW Regen Heater, F-106, was installed in 1971 and is BART eligible for all three 

pollutants. The heater was retrofitted with Callidus Ultra-Low NOx Burners in 1999. Its permitted 

capacity is 66 MMBtu/hr. The PTE for NOx emissions is 27.6 tpy based on a permitted emission 

limit of 6.3 lb/hr and operation at that emission rate for an entire year. This allowable emission 

rate (PTE) is already half of the newly promulgated NOx RACT limit for Industrial, Commercial 

and Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

 

The PTE for sulfur dioxide is 157.2 tpy and is based on a permit limit of 35.9 lb/hr. This limit 

derives from a 1974 Consent Order between Exxon and the NJDEP that allowed for fuel to be 

combusted which contained up to 0.5% sulfur in the heaters. The consent order was originally 

crafted when all refinery heaters were equipped to fire fuel oil. This Consent Order remains in 

effect although the refinery is prohibited from firing fuel oil by permit condition U3, OS Summary, 

Reference #64. The refinery is required under the most recent Consent Decree (Civil Action H-5-

258, hereafter known as the “Consent Decree”) to have all heaters comply with NSPS Subpart J 

by December 31, 2010. This requires combustion of fuel that does not exceed 162 ppm H2S, a 

marked reduction from the current permit basis of 0.5% Sulfur. This will be accomplished When 

the Title V Permit is modified to incorporate this Consent Decree requirement the PTE for SO2 

which will result in a new estimated SO2 limit of 9.6 tpy. 

The PTE for PM10 for this heater is 6.1 tpy based on an hourly emission limit of 1.4 lb/hr. This is 

equivalent to 0.02 gr/scf calculated at the capacity of the heater. 

PFBW Reboiler Heater, F-108 

The PFBW Reboiler Heater, F-108, was installed in 1971 and is BART eligible only for NOx. This 

is because its SO2 and PM10 emissions were considered as part of the Clean Fuels PSD permit 

and the emissions were included in the netting for that project. Sources that have undergone 

major permitting reviews since 1977 (e.g. PSD) are not subject to BART. However, this heater 

did not undergo a PSD review for NOx and therefore should be evaluated for BART for that 

pollutant. The heater was retrofitted with Callidus Ultra-Low NOx Burners in 1999. Its permitted 

capacity is 114 MMBtu/hr. The PTE for NOx emissions is 47.3 tpy based on a permitted emission 

limit of 10.8 lb/hr and operation at that emission rate for an entire year. This allowable emission 

rate (PTE) is already half of the newly promulgated NOx RACT limit for Industrial, Commercial 

and Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

 

DSU-2 Reactor Heater, F-401 

The DSU-2 Reactor Heater, F-401 was installed in 1972 and is BART eligible for all three 

pollutants. The heater was retrofitted with Callidus Ultra-Low NOx Burners in 2000. Its permitted 

capacity is 139 MMBtu/hr. The PTE for NOx emissions is 60.9 tpy based on a permitted emission 

limit of 13.9 lb/hr and operation at that emission rate for an entire year. This allowable emission 

rate (PTE) is half of the newly promulgated NOx RACT limit for Industrial, Commercial and 

Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

 
The PTE for sulfur dioxide is 330.7 tpy and is based on a permit limit of 75.5 lb/hr. This limit 

derives from a 1974 Consent Order between Exxon and the NJDEP that allowed for fuel to be 

combusted which contained up to 0.5% sulfur in the heaters. The consent order was originally 

crafted when all refinery heaters were equipped to fire fuel oil. This Consent Order remains in 

effect although the refinery is prohibited from firing fuel oil by permit condition U3, OS Summary, 

Reference #64. The refinery is required under the most recent Consent Decree (Civil Action H-5-

258, hereafter known as the “Consent Decree”) to have all heaters comply with NSPS Subpart J 

by December 31, 2010. This requires combustion of fuel that does not exceed 162 ppm H2S, a 

marked reduction from the current permit basis of 0.5% Sulfur. This will be accomplished When 

the Title V Permit is modified to incorporate this Consent Decree requirement the PTE for SO2 

which will result in a new estimated SO2 limit of 19.4 tpy. 

The PTE for PM10 for this heater is 4.4 tpy based on an hourly emission limit of 1 lb/hr. This is 

equivalent to 0.006 gr/scf calculated at the capacity of the heater. 

Pipestill Atmospheric Tower Heater, F-701 

The Pipestill Atmospheric Tower Heater, F-701 was installed in 1970. This heater underwent a 

major permit review (significant modification) in 2004 and was reviewed at that time for SOTA 

applicability. Part of that project involved the installation of ULNB on the heater. A second major 

permit review was recently completed (again, a significant modification) due to a Consent Decree 

requirement to install SCR on this heater. Again, a SOTA review was completed. Since this 

heater has now undergone two major permitting efforts and was reviewed for PSD/NSR 

applicability and underwent Subchapter 18 analysis we believe this heater is no longer BART 

eligible. 

Pipestill Vacuum Tower Heater, F-751 

The Pipestill Vacuum Tower Heater, F-701 was installed in 1970. This heater underwent a major 

permit review (significant modification) in 2004 and was reviewed at that time for SOTA 

applicability. We believe that review should have made this heater no longer BART eligible. 

Nevertheless, this heater is due to be replaced with a new heater by December 31, 2010 and 

therefore will not require BART review. 

Pipestill Outboard Flash Tower Heater, F-702 

The Pipestill Outboard Flash Tower Heater, F-702 was installed in 1970 and is BART eligible for 

all three pollutants. The heater was retrofitted with John Zink designed Low NOx Burners in the 

1990’s. Its permitted capacity is 500 MMBtu/hr. The PTE for NOx emissions is 157.7 tpy based 

on a permitted emission limit of 36 lb/hr and operation at that emission rate for an entire year. 

This allowable emission rate (PTE) is significantly lower than the newly promulgated NOx RACT 

limit for Industrial, Commercial and Institutional (ICI) heaters and boilers (0.2 lb/MMBtu). 

 

The PTE for sulfur dioxide is 81.0 tpy and is based on a permit limit of 18.5 lb/hr. This limit 

derives from a 1974 Consent Order between Exxon and the NJDEP that allowed for fuel to be 

combusted which contained up to 0.5% sulfur in the heaters. The consent order was originally 

crafted when all refinery heaters were equipped to fire fuel oil. This Consent Order remains in 

effect although the refinery is prohibited from firing fuel oil by permit condition U3, OS Summary, 

Reference #64. The refinery is required under the most recent Consent Decree (Civil Action H-5-

258, hereafter known as the “Consent Decree”) to have all heaters comply with NSPS Subpart J 

by December 31, 2010. This requires combustion of fuel that does not exceed 162 ppm H2S, a 

marked reduction from the current permit basis of 0.5% Sulfur. This will be accomplished when 

the Title V Permit is modified to incorporate this Consent Decree requirement the PTE for SO2. 

The PTE for PM10 for this heater is 23.4 tpy based on an hourly emission limit of 5.35 lb/hr. This 

is equivalent to 0.01 gr/scf calculated at the capacity of the heater. 
Determination of BART 

EPA allows states to use MACT standards to help assess potential limits and controls for BART 

eligible sources. There is no MACT standard for Heaters and Boilers. A Heater and Boiler MACT 

standard was promulgated in 2006 but that rule did not address any of the BART pollutants and 

the rule was vacated in 2008. 

A review of other rules and sources of information can be instructive and helpful in determining 

BART. New Jersey publishes and maintains a State of the Art Manual that describes controls 

and emission limits for new and reconstructed sources. The SOTA manual for refineries has a 

section specific to heaters. The SOTA limit for NOx for new heaters is 0.05 lb/MMBtu. If you are 

replacing burners in a heater the SOTA limit is 0.07 lb/MMBtu. 

The RACT/BACT/LAER Clearinghouse (RBLC) was also queried regarding limits imposed on 

new sources. It must be noted first that the RBLC contains limits primarily for new sources which 

is not consistent with the “retrofit” nature of BART. Second, the RBLC data queried was almost 

exclusively not verified. That is, these were the limits established in a permit. There is no record 

that those limits were achieved in practice. Finally, BART is concerned with retrofit “technology” 

more than emission limits themselves so it is important to note the technology listed under the 

RBLC. Most of the RBLC entries represent Best Available Control Technology (BACT) which by 

their very nature would seem to be equivalent or more stringent that BART. 

Top Down Analysis for NOx

Several techniques are available to reduce NOx emissions. Selective Catalytic Reduction (SCR) 

is generally accepted as the most effective control for NOx emissions. SCR relies on a reaction 

between ammonia and nitrogen oxides to form nitrogen and water. The use of a catalyst makes 

this reaction relatively fast at temperatures in the 500 degree range. The technique is relatively 

costly, takes up valuable real estate and suffers from unreacted ammonia emissions (ammonia 

slip). Of these the most problematic is cost and therefore is it typically only used for new sources. 

New Jersey’s “State of the Art” manual for refinery heaters does contain limits for NOx that would 

not require the installation of SCR. The limits are easily achievable using ULNB. Thus, one 

could say that New Jersey considers ULNB to be “State of the Art”. 

A review of the RBLC yielded 30+ new heaters that have been permitted within the past 10 

years. Only one of these 30+ heaters has SCR listed as the control device and it was noted that 

it was voluntarily installed. The vast majority of the heaters were using ULNB as the means of 

control with three control devices listed as Low NOx Burners and 3 where no control was listed. 

Permitted emissions ranged from 0.033 lb/MMBtu to 0.6 lb/MMBtu. The latter number was from 

the Kenai Peninsula in Alaska and should not be considered representative. Nearly all of the 

sources listed represented BACT and the average emission limit was ~0.045 lb/MMBtu, easily 

achievable with ULNB. 

We believe that although SCR is an effective control technique, it is not reasonable for a retrofit 

application. It does not show once in the RBLC as required to meet BACT. If BACT is something 

less than SCR then BART should be as well. A variation on SCR is Selective Non-Catalytic 

Reduction, or SNCR. It should be mentioned for the sake of completeness. This technique 

involves spraying ammonia directly into a flue gas stream and relying on the same reaction to 

take place as in SCR. This technique suffers from the fact that high temperatures are required for 

the reaction to take place in the absence of catalyst. While these temperatures sometimes are 

found in heaters the temperature zone where SNCR is successful tends to move as the heater is 

turned down from maximum firing to other operating levels. Most industrial heaters operate at a 

wide range of firing rates which makes SNCR an unacceptable choice for NOx control. SNCR 

was not listed once in the RBLC as a control technique for NOx nor are we aware of any use of 

SNCR specifically on refinery heaters. 

We believe it is clear that ULNB represents BART and that technologies that are slightly less 

effective should also be considered; specifically any generation of LNB installed to reduce NOx 

emissions. 
Top Down Analysis for SO2 

Sulfur dioxide is produced form the combustion in a heater of fuel containing hydrogen sulfide, 

H2S. The hydrogen sulfide is produced from sulfur in the incoming crude oil during various 

refinery processing steps. It is removed from products and generally ends up if the gases that 

are burned as fuel in process heaters. Two means of dealing with sulfur dioxide emissions are 

well known. The first involves removing hydrogen sulfide from the fuel gas using an amine based 

(typically) absorbing solution. Such systems are capable of removing large amounts of H2S 

lowering the concentration in fuel gas from 1%-2% down to <10 ppm levels in some cases. The 

process is very capital intensive. However, nearly all of a refinery’s sour fuel gas can be treated 

in a few amine treaters and distributed to dozens of furnaces. When smaller amounts of H2S 

must be removed a caustic contacting solution is sometimes used to treat the fuel gas. 

Another method sometimes used to reduce SO2 emissions is to install a caustic scrubber and 

treat the flue gas from a source, removing the SO2 that has been creating during combustion. 

While effective in reducing SO2 emissions it is not cost effective since it has to be applied to each 

source of SO2. Caustic scrubbing is most often used on a single large source of SO2 such as a 

large utility boiler burning coal or an FCCU at a refinery. 

SO2 scrubbing should not be considered BART when multiple small sources of SO2 are involved. 

It is cost prohibitive. Amine scrubbing is equally effective as caustic scrubbing and could be 

considered in a BART analysis. 

New Jersey does not address SO2 emissions from refinery heaters in its SOTA manual. A 

review of the RBLC indicates that there is no control equipment required for any of the sources 

listed. In fact, the database indicates that that no controls were feasible for these sources. The 

permit requirements range from 25 ppm (2 sources) to 160 ppm (~20 sources) and it is inferred 

that amine treating is used in order to achieve these levels. In addition, all of these permits 

considered these limits to represent BACT. As mentioned previously, we believe that Best 

Available Retrofit Technology” should not be more stringent than “Best Available Control 

Technology”. 

We believe that refinery fuel gas treated to meet New Source Performance Standards should 

represent BART. 

Top Down Analysis for PM10 

There are two main methods for reducing PM10 emissions from heaters. Similar to sulfur dioxide, 

particulates can be scrubbed from individual heater stacks. This is exceedingly expensive and 

not cost effective. They would also have to be constructed on each of the BART eligible sources. 

There are no known refinery heaters that have employed scrubbing as a means of reducing PM10

emissions. 

New Jersey does not address PM10 emissions from refinery heaters in its SOTA Manual. A 

review of the RBLC reveals that the only means of PM10 emission control specified in the permits 

for every heater listed in the query was “Good Combustion Practices” or Proper Design, 

Operation and Good Engineering Practices”. Proper, efficient combustion will minimize PM10

emissions. If NEW heaters are employing these practices and they have been determined to 

represent BACT then BART should not be considered to be more stringent. 

We believe that “Good Combustion Practices” and “Proper Design, Operation and Good 

Engineering Practices” represent BART for PM10. 
Demonstration That Existing and Planned Controls Represent BART for 

Bayway Refinery BART Eligible Sources. 

All of the sources that are BART eligible are process heaters. We believe that BART 

requirements will be identical for each source and therefore we will present the determination 

once, rather than repeating it for each heater. 

Based on the top-down analysis presented above we believe that the existing Ultra Low NOx 

Burners (ULNB) on the BART eligible heaters represent BART controls. Although the Pipestill 

Outboard Flash Tower, F-702 has older Low NOx Burners (LNB) the PTE for this furnace is lower 

than all other BART eligible heaters on a lb/MMBtu basis. 

The top down analysis of controls for SO2 indicates that burning NSPS compliant fuel gas 

represents BART for all refinery heaters. In every case reviewed in the RACT/BACT/LAER 

Clearinghouse it was shown that burning NSPS compliant gas represented BACT for new 

sources. It is our position that Best Available Retrofit Technology should not be more stringent 

than Best Available Control Technology. 

Our review indicates that BART for process heaters should be good combustion practices. 

Review of the New Jersey SOTA manual and the RBLC indicate that no additional controls are 

required. Good combustion practices represent BACT in each and every case of the permitted 

sources reviewed in the RBLC. It is our position that Best Available Retrofit Technology should 

not be more stringent than Best Available Control Technology. It is particularly true in this case 

since no permits were shown to require any additional controls. 

Other Comments 

It should be noted that the Consent Decree mentioned in the text of this review requires that at 

least 30% of the refinery heaters be “controlled” as defined in the Decree. That means they must 

be designed to emit no more than 0.04 lb/MMBtu NOx at test stand conditions (no air preheat). 

All heaters at Bayway have ULNB meeting this requirement with the exception of the LNB 

installed on F-702. 

In addition, the Department has indicated that it will be issuing a Refinery RACT rule in the future. 

This rule is targeting NOx emissions from heaters as one of its initiatives. We believe that this 

rule will also represent acceptable BART controls and that we will comply with those limits. 
 Services Corporation 

 80 Park Plaza, Newark, NJ 07102-4194 

 tel: 973.430.7000 

 

 Services Corporation 

VIA E-MAIL and FEDERAL EXPRESS 

July 15, 2009 

Mr. Yogesh Doshi 

Section Chief, Bureau of Operating Permits 

Division of Air Quality 

New Jersey Department of Environmental Protection 

401 East State St. – 2nd Floor 

Trenton, NJ 08625 

Reference: PSEG Fossil LLC 

Hudson Generating Station 

Program Interest No. 12202 

Preliminary Best Available Retrofit Technology (BART) Control Plan

Dear Mr. Doshi: 

PSEG Fossil LLC (“PSEG Fossil” or “the Company”) is submitting a preliminary Best Available 

Retrofit Technology (“BART”) control plan for its Hudson Generating Station (“Hudson” or “the 

facility”) in response to a March 3, 2009 letter from Mr. William O’Sullivan, P.E. of the New 

Jersey Department of Environmental Protection (“NJDEP” or “the Department”) to Mr. Daniel 

Cunningham of PSEG as well as recent correspondence with Mr. Max Friedman of your staff. 

Please note that this letter contains PSEG Fossil’s preliminary BART control plan and PSEG 

Fossil will be submitting a formal BART control plan within the next few weeks. This was 

acceptable to NJDEP as noted during a July 9th phone conversation between Mr. Max Friedman 

of your staff and myself. 

BACKGROUND 

One of the most common forms of air pollution - haze - degrades visibility in many American 

cities and scenic areas. Haze is caused when sunlight encounters tiny pollution particles in the 

air, which reduce the clarity and color of what we see, particularly during humid conditions. 

The haze-forming pollution comes from a variety of natural and manmade sources. Natural 

sources can include windblown dust, and soot from wildfires. Manmade sources can include 

motor vehicles, electric utility and industrial fuel burning, and manufacturing operations. 

Particulate matter pollution is the major cause of reduced visibility (haze) in parts of the United 

States, including many of our national parks. Some haze-causing particles are directly emitted to 
Mr. Yogesh Doshi 

July 15, 2009 Page 2 

the air. Others are formed when gases emitted to the air form particles as they are carried many 

miles from their source. 

The Clean Air Act of 1990 (Title I, Sections 169A and 169B) declared it a national goal to 

prevent any future, and to remedy any existing, impairment of visibility in 156 mandatory federal 

Class I areas, the impairment of which results from manmade air pollution. New Jersey’s only 

federal Class I area is the Brigantine Wilderness Area of the Edwin B. Forsythe National 

Wildlife Refuge located near Brigantine, Atlantic County. In response to increased adverse 

visibility impacts at federal Class I “pristine” air quality areas due to existing major sources, the 

U.S. Environmental Protection Agency (EPA) promulgated the BART rules in 1999. 

Revisions to the regional haze rules were promulgated on July 6, 2005 and October 13, 2006. 

These regulations require states to establish goals for improving visibility by developing longterm strategies for reducing emissions of air pollutants that cause visibility impairment. The 

overall goal of the regional haze regulations is to achieve natural background visibility 

conditions in all Class I areas by the year 2064. 

To avoid confusion with other Clean Air Act requirements which also use the term "major 

stationary source" to refer to a somewhat different population of sources, the regional haze rule 

uses the term "BART-eligible source" to describe these sources. The BART-eligible sources are 

sources that meet the following criteria: 

1) Major stationary sources that contain emission units whose operations fall 

within one or more of 26 specifically listed source categories; 

2) Emission units that were put in place between August 7, 1962 and August 7, 

1977; and 

3) Major stationary sources with a combined potential to emit 250 tons per year 

(“tons/yr”) or more of a visibility-impairing pollutant (“VIP”), namely 

nitrogen oxides (“NOx”), particulate matter less than 10 microns (“PM10”) or 

sulfur dioxide (“SO2”), from qualified emission units. Qualified emission 

units are defined as emission units that meet the criteria of #2 above with 

cumulative potential to emit SO2, NOx, or PM10 are greater than 40 tons/yr, 

40 tons/yr, or 15 tons/yr, respectively. 

BART-eligible sources may be required to apply emissions control technology to reduce 

emissions of VIPs, if such emissions are demonstrated to cause an adverse visibility impact 

at the nearest Class I areas. The major recommendations for BART visibility impact 

modeling and application of emissions controls are: 

1) Identify BART-eligible sources (based on date of operation, potential 

emissions of VIPs and facility source category) 

2) Identify which pollutants have greater than EPA-suggested de minimis

emissions levels 

3) Identify sources that are subject to BART 

4) Identify baseline visibility impact of each BART source 

5) Identify feasible controls and emission changes 

6) Identify the change in visibility impact for each candidate BART control 
Mr. Yogesh Doshi 

July 15, 2009 Page 3 

option 

7) Compare the visibility improvement of BART control options to other 

statutory factors in the engineering analysis 

HUDSON GENERATING STATION 

Hudson is considered BART-eligible because it meets the above criteria. Hudson is a fossil fuelfired electric generating station located at Duffield and Van Keuren Avenues in Jersey City, 

Hudson County, New Jersey. Currently, there are two (2) electric generating units (“EGUs”) at 

the facility: Hudson Unit No. 1 and Hudson Unit No. 2. Additional equipment at the facility 

supports the operation of Hudson Units No. 1 and 2. 

Hudson is subject to the Title V Operating Permit Rule (N.J.A.C. 7:27-22). The Department 

issued the initial Hudson Title V Operating Permit on December 29, 2005. The most recently 

approved Title V permit modification for Hudson was issued by the Department on May 27, 

2008 (BOP080001). 

The emission sources at Hudson that were installed between August 7, 1962 and August 7, 1977 

with their current potential to emit are included in the following table. 

Table 1. Current Potential to Emit NOx, SO2, and PM10 from Sources Installed Between 

August 7, 1962 and August 7, 1977 

Emissions (tons/yr)(1)

Emission Unit NOx SO2 PM10

Unit No. 1 8,360 6,389 995(2)

Unit No. 2 3,486(3) 5,270(3) 5,122(2)

Coal Receiving System -- -- 2.7 

Coal Reclaim System -- -- 1.2 

(1) Emission limits from the facility’s Title V permit No. BOP080001 unless otherwise noted.

(2) PM10 emission rates proposed by PSEG Fossil in 12/2/2008 Title V modification 

application, based on stack testing. 

(3) The NOx and SO2 emission caps are from the Consent Decree, and are in effect for calendar 

years 2008 through 2010. 

The emission units in Table 1 above are subject to BART, and PSEG Fossil’s preliminary BART 

control plan for these units is addressed below. 

In NJDEP’s November 1, 2006 letter to Mr. Francis X. Sullivan of PSEG, the Department stated 

that the facility’s emergency fire pump (Emission Unit U7, Equipment E14 in Hudson’s Title V 

permit) was BART-eligible. The facility’s emergency fire pump is a pump supplied with 

mechanical power by a stationary internal combustion engine used to maintain water pressure or 

flow for fire fighting at the facility. The emergency fire pump was originally installed in 1963. 

However, PSEG Fossil’s records indicate that the emergency fire pump’s emission source, the 
Mr. Yogesh Doshi 

July 15, 2009 Page 4 

stationary internal combustion engine, was replaced in the 1985-1986 timeframe, which is 

outside the August 7, 1962 through August 7, 1977 period for BART-eligibility. Therefore, the 

emergency fire pump is not subject to BART. 

HUDSON UNIT NO. 1

Hudson Unit No. 1 (Emission Unit U1, Equipment E1 in Hudson’s Title V permit) is a cyclonefired steam electric generating unit with an electric generating capacity of approximately 420 

megawatts (“MW”). Hudson Unit No. 1 was manufactured by Babcock and Wilcox, and is 

permitted to burn either natural gas or No. 6 fuel oil. Hudson Unit No. 1 began commercial 

operation on December 10, 1964. Hudson Unit No. 1 is equipped with with Continuous 

Emissions Monitoring Systems (“CEMS”) for NOx, SO2, and carbon monoxide (“CO”), as well 

as a Continuous Opacity Monitoring System (“COMS”) for opacity. 

Please note that although NJDEP’s November 1, 2006 letter to Mr. Francis X. Sullivan of PSEG 

references water injection, the facility does not utilize this control device to comply with its NOx 

emissions. 

The currently permitted NOx, SO2, and PM10 emission rates for Hudson Unit No. 1, expressed in 

pounds per million British thermal unit (“lb/MMBtu”), are summarized in Table 2 below: 

Table 2. Current Hudson Unit No. 1 Permitted NOx, SO2, and PM10 Emission Rates 

Emissions (lb/MMBtu) 

Fuel NOx SO2 PM10

Natural Gas 0.39 0.0017 0.022(1)

No. 6 Fuel Oil 0.43 0.32 0.050(1)

(1) PM10 emission rate proposed by PSEG Fossil in 12/2/2008 Title V modification application, 

based on stack testing. 

HUDSON UNIT NO. 1 BART

In September 2004, PSEG Fossil advised PJM1

 that it intended to retire Hudson Unit No. 1 

because the Company was unable to continue operating it economically. PJM subsequently 

determined, however, that Hudson Unit No. 1 was needed by PJM for reliability purposes. In 

April 2005, Hudson Unit No. 1 became one of the first units located within the PJM footprint to 

be designated as a Reliability Must Run (“RMR”) unit by PJM. Hence, Hudson Unit No. 1 

continues to remain in service to maintain electrical system reliability. 

As an RMR unit, Hudson Unit No. 1 operates relatively infrequently and well below its annual 

operating capacity. Also, operational problems have prevented the unit from burning No. 6 fuel 

oil since 2005, so in recent years the unit has burned only natural gas, which has inherently lower 

 

1 PJM refers to the Pennsylvania-New Jersey-Maryland Interconnection, a regional transmission organization that 

manages the competitive wholesale electricity market in New Jersey, twelve other states, and the District of 

Columbia. 
Mr. Yogesh Doshi 

July 15, 2009 Page 5 

NOx, SO2, and PM10 emissions than No. 6 oil firing. The limited amount of operation on almost 

exclusively natural gas is reflected in Table 3 below, which summarizes the potential and actual 

emissions of NOx, SO2, and PM10 for Hudson Unit No. 1, and compares the unit’s actual fuel use 

to its potential fuel use. 

Table 3. Hudson Unit No. 1 Potential and Actual Emissions and Fuel Use 

Emissions (tons/yr) 

NOx SO2 PM10

Fuel Use 

(MMBtu/yr) 

Fuel-Based 

Capacity Factor 

(%) 

Potential 

 8,360 6,389 995(1) 39,930,000 100% 

Year Actual 

2004 177.74 45.06 9.75 927,489 2.3% 

2005 196.37 6.06 6.32 1,695,213 4.2% 

2006 58.52 2.24 1.98 532,758 1.3% 

2007 51.77 2.12 1.86 499,321 1.3% 

2008 34.20 1.33 3.15 344,013 0.9% 

(1) PM10 emission rate proposed by PSEG Fossil in 12/2/2008 Title V modification 

application, based on stack testing. 

Table 3 illustrates that Hudson Unit No. 1 has operated well below its potential capacity, both 

from an emissions and a fuel use standpoint. From calendar years 2004 through 2008, Hudson 

Unit No. 1’s fuel-based annual capacity factor ranged from a high of 4.2% in 2005 to a low of 

0.9% in 2008. NOx emissions ranged from a high of 196.37 tons/yr in 2005 to a low of 34.2 

tons/yr in 2008. SO2 emissions ranged from a high of 45.06 tons/yr in 2004 to a low of only 1.33 

tons/yr in 2008, with all but 2004 SO2 emissions less than 10 tons/yr. PM10 emissions ranged 

from a high of 9.75 tons/yr in 2004 to a low of only 1.86 tons/yr in 2007. 

The low actual annual NOx, SO2, and PM10 emission rates and utilization rates for Hudson Unit 

No. 1, combined with its marginal economic viability and short remaining useful life, as 

indicated by its RMR status, make it extremely cost-prohibitive to equip this unit with any addon NOx, SO2, and PM10 emission controls. 

PSEG Fossil proposes the existing configuration of the unit, with primary operation on natural 

gas when burning No. 6 fuel oil as BART for this source. 

HUDSON UNIT NO. 2

Hudson Unit No. 2 (Emission Unit U2, Equipment E2 in Hudson’s Title V permit) is a drybottom, wall-fired steam electric generating unit with an electric generating capacity of 

approximately 640 MW. The unit was manufactured by Foster-Wheeler, and is capable of 

burning either pulverized coal, natural gas, or a combination of coal and natural gas. Hudson 

Unit No. 2 is also permitted to burn No. 6 fuel oil. Hudson Unit No. 2 began commercial 

operation on December 18, 1968. Hudson Unit No. 2 is equipped with CEMS for NOx, SO2, 

CO, and mercury (“Hg”), as well as a COMS for opacity. Hudson Unit No. 2 is also required to 

be equipped with a particulate matter (“PM”) CEMS by December 31, 2010. 
Mr. Yogesh Doshi 

July 15, 2009 Page 6 

For NOx emission control, Hudson Unit No. 2 is currently equipped with Low-NOx Burners 

(“LNB”) and Selective Non-Catalytic Reduction (“SNCR”). LNB use modified air and fuel 

entry to slow mixing rates, reduce the oxygen (“O2”) available for NOx formation, and reduce the 

amount of fuel burned at peak flame temperatures. Low NOx burners operate at much lower O2

levels than conventional burners, and therefore generate less fuel and thermal NOx. SNCR 

involves injecting urea into the furnace exhaust gases. The basic chemical reaction involves the 

decomposition of urea and the reaction of nitric oxide (“NO”) with NH2 to form mostly 

elemental nitrogen (“N2”), carbon dioxide (“CO2”), and water (“H2O”). 

Please note that although NJDEP’s November 1, 2006 letter to Mr. Francis X. Sullivan of PSEG 

references flue gas recirculation, the facility no longer employs this control device and it has 

been removed from the facility’s Title V permit. 

For SO2 emission control, on January 1, 2007, the Company began burning Ultra-Low Sulfur 

Coal (“ULSC”) in Hudson Unit No. 2, as required under the terms of a Consent Decree2. “UltraLow Sulfur Coal” is defined in the Consent Decree as sub-bituminous coal obtained by PSEG 

Fossil with a sulfur content of no greater than 0.25%, a nitrogen content of no greater than 1% 

and an ash content no greater than 2.5%, all as determined on a quarterly basis from fuel analysis 

data for each barge of coal delivered to the station during that quarter. The 0.25% sulfur content 

limit is 75% lower than the 1% sulfur content limit in effect for Hudson Unit No. 2 prior to 

January 1, 2007. 

Since May 1, 2007, the Company has burned only ULSC in Hudson Unit No. 2. Under the 

Consent Decree, PSEG Fossil must continue burning 100% ULSC in Hudson Unit No. 2 until 

the Company either shuts down Hudson Unit No. 2 or operates a Flue Gas Desulfurization 

(“FGD”) system on the unit for SO2 emission control. 

For PM10 emission control, Hudson Unit No. 2 is equipped with electrostatic precipitators 

(“ESPs”). The electrostatic precipitation process involves: 1) charging particles by means of ions 

produced in a corona discharge (an electrical discharge accompanied by ionization of the exhaust 

gas), 2) separating the charged particles from the gas stream in an imposed electric field, 3) 

collecting the particles on a grounded surface, and 4) removing the collected particles from the 

grounded surface and consolidating them for disposition. 

NOx emissions are also reduced by combusting ULSC which, with its lower nitrogen content 

than traditional bituminous coals, tends to reduce the formation of NOx during combustion. 

PM10 emissions may also be reduced by combusting ULSC because of its lower ash content than 

traditional bituminous coals. 

The current NOx, SO2, and PM10 emission rates for Hudson Unit No. 2, expressed in lb/MMBtu, 

are summarized in Table 4 below: 

 

2

 United States of America, State of New Jersey v. PSEG Fossil LLC, Civil Action No. 02CV340 (JCL), as 

amended. 
Mr. Yogesh Doshi 

July 15, 2009 Page 7 

Table 4. Current Hudson Unit No. 2 Permitted NOx, SO2, and PM10 Emission Rates 

Emissions (lb/MMBtu) 

Fuel NOx SO2 PM10

Any Coal 0.259(1) 0.216(2) 0.206(3)

Natural Gas 0.49 0.0005 0.0045 

No. 6 Fuel Oil 0.6 0.314 0.031 

(1) Interim 30-day rolling average NOx emission rate proposed by PSEG Fossil in a 1/15/2009 

submittal to NJDEP, based on actual NOx emissions performance with new LNB burning 

ULSC. If approved, this interim limit would remain in effect until SCR operation. 

(2) Interim 30-day rolling average SO2 emission rate in effect until FGD operation. An 

alternative interim SO2 emission rate of 0.310 lb/MMBtu would apply if a force majeure

event prevents PSEG Fossil from procuring ULSC from the current supplier. 

(3) PM10 emission rate proposed by PSEG Fossil in 12/2/2008 Title V modification application, 

based on stack testing. 

Table 5 below summarizes the potential and actual emissions of NOx, SO2, and PM10 for Hudson 

Unit No. 2, and compares the unit’s actual fuel use to its potential fuel use. 

Table 5. Hudson Unit No. 2 Potential and Actual Emissions and Fuel Use 

Emissions (tons/yr) 

NOx SO2 PM10

Fuel Use 

(MMBtu) 

Fuel-Based 

Capacity 

Factor (%) 

Potential 

 3,486(1) 5,270(1) 5,122(2) 49,630,000 100% 

Year Actual 

2004 8,061 21,467 2,928 36,631,793 74% 

2005 8,582 23,960 3,189 40,299,670 81% 

2006 7,401 19,707 1,491 35,844,495 72% 

2007 3,322 4,339 2,055 32,338,221 65% 

2008 2,945 2,177 2,099 25,256,106 51% 

(1) The NOx and SO2 emission caps are from the Consent Decree, and are in effect for 

calendar years 2008 through 2010. 

(2) PM10 emission rate proposed by PSEG Fossil in 12/2/2008 Title V modification 

application, based on stack testing. 

Table 5 illustrates that compared to Hudson Unit No. 1, Hudson Unit No. 2 has operated much 

closer to its potential capacity, both from an emissions and a fuel use standpoint. From calendar 

years 2004 through 2008, Hudson Unit No. 2’s fuel-based annual capacity factor ranged from a 

high of 81% in 2005 to a low of 51% in 2008. NOx emissions ranged from a high of 8,582 

tons/yr in 2005 to a low of 2,945 tons/yr in 2008. SO2 emissions ranged from a high of 23,960 

tons/yr in 2005 to a low of 2,177 tons/yr in 2008. PM10 emissions ranged from a high of 3,189 

tons/yr in 2005 to a low of 2,055 tons/yr in 2007. The substantial reductions in actual NOx and 

SO2 emissions in 2007 and 2008 reflect the Consent Decree-required burning of ULSC in 

Hudson Unit No. 2 beginning in 2007, as well as the installation of new LNB in 2008. 
Mr. Yogesh Doshi 

July 15, 2009 Page 8 

Hudson Unit No. 2’s higher annual utilization and emissions makes it a more appropriate 

candidate for investment in the installation of back-end NOx, SO2, and PM10 emission control 

technologies than Hudson Unit No. 1. 

HUDSON UNIT NO. 2 BART

NOx

The most advanced NOx emission control technology for coal-fired boilers like Hudson Unit No. 

2 is Selective Catalytic Reduction (“SCR”). SCR is a proven technology used on hundreds of 

NOx emission sources in the United States and abroad. SCR uses ammonia (“NH3”) to react with 

NOx in the exhaust gas over a catalyst. NOx from fuel combustion processes is typically found in 

the form of NO or nitrogen dioxide (“NO2”). The general chemical reaction for the reduction of 

NO is: 

4 NO + 4 NH3 + O2 Æ 4 N2 + 6 H2O 

For the reduction of NO2, the reactions are: 

6 NO2 + 8 NH3 Æ 7N2 + 12 H2O 

2 NO2 + 4 NH3 + O2 Æ 3 N2 + 6 H2O 

These reactions occur within a relatively narrow flue gas temperature window. At temperatures 

below approximately 550 o

F, the NOx reduction reactions become less efficient. At temperatures 

above approximately 850 oF, the catalyst is progressively destroyed. 

Under the terms of the Consent Decree, Hudson Unit No. 2 must be equipped with SCR by 

December 31, 2010. The SCR being installed on Hudson Unit No. 2 is a conventional “high 

dust”/“hot side” unit typical of the SCRs installed on utility boilers in the United States. A “high 

dust”/“hot side” SCR is installed prior to any particulate control devices (e.g. ESPs) at a location 

in the flue gas stream where temperatures are suitable for proper operation without the need for 

flue gas reheating. The Hudson Unit No. 2 SCR will inject aqueous ammonia into the flue gas 

stream by means of an injection grid installed between the economizer and air heater sections of 

the boiler. Static mixers will be installed to achieve uniform velocity distribution and mixing of 

NOx and ammonia before the flue gas enters the catalyst. 

With SCR, the maximum NOx emission rates prescribed for Hudson Unit No. 2 in the Consent 

Decree are: 

• 0.150 lb/MMBtu (24-hour average) 

• 0.100 lb/MMBtu (30-day rolling average) 

With SCR operation, potential annual NOx emissions from Hudson Unit No. 2 in calendar year 

2011 and beyond are expected to be even lower than the 3,486 tons/yr NOx emission cap that 

applies in calendar years 2008 through 2010. For example, if Hudson Unit No. 2 burned all 
Mr. Yogesh Doshi 

July 15, 2009 Page 9 

4.963E13 Btu of its permitted fuel emitting at the above 30-day rolling average NOx emission 

rate of 0.100 lb/MMBtu, its potential to emit would be 2,481.5 tons/yr. 

PSEG Fossil proposes the existing configuration of the unit with LNB and SNCR as well as the 

planned future SCR as BART for this source. 

SO2

The advanced SO2 emission control technology PSEG Fossil is installing on Hudson Unit No. 2 

is an FGD system that utilizes a Spray Dryer Absorber (“SDA”) in which an atomized lime 

slurry is injection into the flue gas. The lime slurry will then react with sulfur oxides (“SOx”) to 

form calcium sulfate (“CaSO4”) and calcium sulfite (“CaSO3”) in the flue gas stream. The FGD 

will treat the flue gas downstream of the existing ESPs. 

The FGD will use pebble lime (“CaO”) as a reagent. Pebble lime will be delivered to Hudson by 

truck. Upon delivery, the pebble lime will be pneumatically conveyed to lime storage silos 

and/or to lime storage day bins, as needed. From the storage silos or day bins, the pebble lime 

will be pneumatically conveyed to vertical ball mills, where the pebble lime will be crushed to a 

fine powder. From the ball mills, the crushed pebble lime will be conveyed to lime slakers, 

where water will be added to form calcium hydroxide (“Ca(OH)2”). The slaked lime will be 

transferred to lime slurry storage tanks via transfer pumps. Feed pumps will then transfer the 

lime slurry from the lime slurry storage tanks to atomizing injectors located in the flue gas 

stream. The lime slurry will then react with SO2 in the flue gas stream as follows: 

Ca(OH)2 + SO2 Æ CaSO3•1⁄2(H2O) + 1⁄2(H2O) 

CaSO3•1⁄2(H2O) + 1⁄2 O2 Æ CaSO4•1⁄2(H2O) 

Ca(OH)2 + SO3 Æ CaSO4•1/2(H2O) + 1⁄2( H2O) 

As these reactions occur, the lime slurry water will evaporate, leaving a dry power. The 

reactions products, unreacted reagent, and fly ash will be captured downstream of the FGD by 

the baghouse described below. 

The FGD will utilize a recycle system to optimize reagent utilization. The recycle system will 

include a removal, transport, and storage system to recycle particulates collected in the SDA and 

baghouse hoppers. Recycled material will be re-injected into the lime slurry process stream. 

Particulates collected in the baghouse hoppers will be transported to recycle storage bins using a 

vacuum-type pneumatic conveying system. Recycle material from the recycle storage bins will 

be metered into recycle mix tanks using recycle feeders. Particulates collected at the bottom of 

the SDA vessel will be conveyed to the recycle mix tanks using drag chain conveyers. 

Delumpers will be provided to break up oversized particulates that are collected in the SDA 

vessel and prevent them from entering the recycle mix tanks. Slurry transfer pumps will transfer 

recycled slurry from the recycle mix tanks to the lime slurry storage tanks. 
Mr. Yogesh Doshi 

July 15, 2009 Page 10 

Under the terms of the Consent Decree, Hudson Unit No. 2 must be equipped with an FGD 

system by December 31, 2010. With FGD, the maximum SO2 emission rates prescribed for 

Hudson Unit No. 2 in the Consent Decree are: 

• 0.250 lb/MMBtu (24-hour average) 

• 0.150 lb/MMBtu (30-day rolling average) 

With FGD operation, potential annual SO2 emissions from Hudson Unit No. 2 in calendar year 

2011 and beyond are expected to be even lower than the 5,270 tons/yr SO2 emission cap that 

applies in calendar years 2008 through 2010. For example, if Hudson Unit No. 2 burned all 

4.963E13 Btu of its permitted fuel emitting at the above 30-day rolling average SO2 emission 

rate of 0.150 lb/MMBtu, its potential to emit would be 3,722.25 tons/yr. 

PSEG Fossil proposes the existing configuration of the unit with the burning of ULSC as well as 

the planned future FGD as BART for this source. 

PM10

The most advanced technology for particulate matter (“PM”) emission control on a coal-fired 

boiler like Hudson Unit No. 2 is a full-size pulse-jet baghouse. Pulse-jet baghouses are proven 

technology, used on hundreds of PM emission sources in the United States and abroad. Pulse-jet 

baghouses collect PM generated by both coal combustion (i.e., fly ash) and FGD operation 

(CaSO4 and CaSO3). 

The flue gas from Hudson Unit No. 2 will exit the FGD and enter the baghouse inlet plenum. 

The flue gas will be distributed into individual compartments, which can be isolated for 

maintenance or inspection while the unit is still on-line. Filter bags will be located in each 

compartment. The filter bags will be hung from the top of the compartment and supported by a 

cage. Some heavy particulates will fall out into the compartment hoppers simply due to the 

effects of gravity. The remaining particles will be captured on the filter bag surfaces. A ”cake” 

will eventually build up on the filter bag surfaces, and the pressure drop across the bags will 

increase. At a pre-set point, the bags will be cleaned from the inside-out using low-pressure air 

(i.e. a “pulse-jet”) to blow the particulates off the bags for collection in the hoppers. 

Bypass dampers will be installed to allow the flue gas exiting the FGD to bypass the baghouse 

during periods of unit startup and shutdown, as well as when Hudson Unit No. 2 is combusting 

only natural gas. The flue gas exiting the bypass dampers will be directed to the existing Hudson 

Unit No. 2 stack. When Hudson Unit No. 2 is combusting coal or No. 6 fuel oil and operating 

under normal conditions, the bypass dampers will not be utilized and the flue gas will be treated 

by the baghouse. 

Under the terms of a Consent Decree, Hudson Unit No. 2 must be equipped with a baghouse for 

PM emission control by December 31, 2010. The Consent Decree also requires that Hudson 

Unit No. 2 be equipped with a PM CEMS by December 31, 2010. With the baghouse, the 

maximum PM emission rate prescribed for Hudson Unit No. 2 in the Consent Decree is: 
Mr. Yogesh Doshi 

July 15, 2009 Page 11 

• 0.0150 lb/MMBtu3

PSEG Fossil proposes the existing configuration of the unit with the ESP as well as the planned 

future baghouse as BART for this source. 

COAL RECEIVING SYSTEM

The Coal Receiving System (Emission Unit U15, Equipment E22 in Hudson’s Title V permit) is 

the materials handling equipment associated with accepting deliveries of the coal burned in 

Hudson Unit No. 2, through to storage of the coal on the coal pile. 

The coal for Hudson Unit No. 2 is delivered to the facility by barge. The Coal Receiving System 

includes Barge Unloading, Coal Conveyors, the Conveyor Tower, the Transfer Tower, and the 

Coal Pile. 

There are no SO2 or NOx emissions associated with the Coal Receiving System. The Coal 

Receiving System’s potential to emit PM10 is 2.7 tons/yr. 

COAL RECEIVING SYSTEM BART

Given that PM10 emissions are minimal from this equipment, and the emissions from this 

equipment do not tend to travel over long distances that may affect visibility in Federal Class I 

areas

4

, PSEG Fossil proposes the existing configuration of the unit as BART for this source. 

COAL RECLAIM SYSTEM

The Coal Reclaim System (Emission Unit U16, Equipment E23 in Hudson’s Title V permit) is 

the materials handling equipment associated with transferring coal for Hudson Unit No. 2 from 

the coal pile to the unit itself. 

The Coal Reclaim System includes Coal Conveyors, the Breaker House, Feeders, Silos, and 

Pulverizers. 

There are no SO2 or NOx emissions associated with the Coal Receiving System. The Coal 

Reclaim System’s potential to emit PM10 is 1.2 tons/yr.

COAL RECLAIM SYSTEM BART

Given that PM10 emissions are minimal from this equipment, and the emissions from this 

equipment do not tend to travel over long distances that may affect visibility in Federal Class I 

areas, PSEG Fossil proposes the existing configuration of the unit as BART for this source. 

 

3

 PM emission rate is defined in the Consent Decree as the average number of pounds of PM emitted per million 

Btu of heat input, as measured in annual stack tests, in accordance with the reference methods set forth in 40 C.F.R. 

Part 60, Appendix A, Method 5. 

4 The nearest federal Class I area, the Edwin B. Forsythe National Wildlife Refuge located near Brigantine, Atlantic 

County, New Jersey, is located approximately 105 kilometers (65 miles) southeast of Hudson.
Mr. Yogesh Doshi 

July 15, 2009 Page 12 

SUMMARY 

PSEG Fossil’s proposed BART control plan for Hudson is summarized in Table 6 below: 

TABLE 6. SUMMARY OF PROPOSED BART 

Emission 

Unit 

BART 

Proposal NOx SO2 PM10

Action None None None Unit No. 

1 Emission 

Rates 

Retain Current Levels 

(LNB, SNCR) Retain Current Levels Retain Current Levels 

Action Install SCR by 

12/31/2010 

Install FGD by 

12/31/2010 

Install Baghouse 

by 12/31/2010 

Unit No. 

2 Emission 

Rates 

0.150 lb/MMBtu 

(24-hour average) 

0.100 lb/MMBtu 

(30-day rolling 

average) 

0.250 lb/MMBtu 

(24-hour average) 

0.150 lb/MMBtu 

(30-day rolling 

average) 

0.0150 

lb/MMBtu(1)

Coal Action None None None 

Receiving 

System 

Emission 

Rates Retain Current Levels Retain Current Levels Retain Current Levels 

Coal Action None None None 

Reclaim 

System 

Emission 

Rates Retain Current Levels Retain Current Levels Retain Current Levels 

(1) PM emission rate, defined in the Consent Decree as the average number of pounds of PM 

emitted per million BTU of heat input (“lb/mmBTU”), as measured in annual stack tests, in 

accordance with the reference methods set forth in 40 C.F.R. Part 60, Appendix A, Method 5. 

If you have any questions about the issues raised in these comments, please feel free to contact 

Mr. Erin Gorman at (973) 430-6359. 

Sincerely, 

Donald McCloskey 

Director, Environmental Strategy and Policy 

Enclosures 

cc: Max Friedman (NJDEP) 

 Aliya Khan (NJDEP) 

William O’Sullivan, P.E. (NJDEP)