1>>> "JOHNSTON, PAUL K" <PKJOHNSTON@sunocoinc.com> 7/10/09 2:29 PM >>>Max,As you requested, we have prepared a summary table of emissions fromsources subject to BART that compares current potential to emit valuesto those previously reported in the May 2007 submittal. In reviewingthis data please note the following changes:* Heater HC-301 was inadvertently omitted as a source in the 2007submission. The emissions from this source have been added to the tablefor both 2007 and 2009.* Estimates of the PTE from the East Flare provided in the 2007submission were based on the highest emission inventory value reportedbetween 2002 and 2007. The current PTE is based on the 2008 emissioninventory estimate, which is the first full year that the flare gasrecovery system was in operation.* Heaters Isom PH-4, 2H-203, AH-1T, CRU Ph-5A and HC-302 are outof service and deleted from the current Title V permit.With the changes noted above, the aggregate PTE for all BART sources isless 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 JohnstonLead Environmental EngineerSunoco Eagle Point Refinery856-853-44252This message and any files transmitted with it is intended solely for the designated recipient and maycontain privileged, proprietary or otherwise private information. Unauthorized use, copying or distributionof this e-mail, in whole or in part, is strictly prohibited. If you have received it in error, please notifythe sender immediately and delete the original and any attachments.**CC:**Friedman, Max; Wong, Danny3

## 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 we re “potentially” BART affected. This included 12 refinery heaters and the Sulfur Recovery Unit (S RU). Since that submission, the SRU has been removed from service, having been replaced by a st ate of the art sulfuric acid regeneration plant owned and operated by DuPont.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 Pipes till Vacuum Tower Heater (F-751) is scheduled to be removed from service and replaced by a new state of the ar t 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 SO 2 and PM 10 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 SO 2 and PM 10 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 repres ent estimated new permit limits following CD requirement to comply with NSPS Subpart J) Potential to Emit (tpy) Equip.

No. Equipment Description Facility Designation NOx SO 2 PM 10
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-40 1 DSU-2 60.9 330.7 (19.4) 4.4 E257 Atmospheric Tower
Heater F-701 65.7 2 81.0 2 16.0 2

E258 Outboard Flash Heater F-702 157.7 81 23.6

E259 Vacuum Tower Heater F-751 N/A 3 N/A 3 N/A 3
Total 533.5 1063.8 (185.) 65.3Description 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 entir e 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 a nd boilers (0.2 lb/MMBtu).

The PTE for sulfur dioxide is 170.4 tpy and is bas ed on a permit limit of 38.9 lb/hr. This limit
derives from a 1974 Consent Order between Exx on 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 fi ring 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 “Cons ent Decree”) to have all heater s comply with NSPS Subpart J by December 31, 2010. This requires combus tion of fuel that does not exceed 162 ppm H 2 S, a
marked reduction from the curren t 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 SO 2 which will result in a new estimated SO2 limit of 10.6 tpy.

The PTE for PM 10 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 ther efore 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 ra te for an entire year. This allowable emission rate (PTE) is already half of the newly promul gated 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 indivi dual 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 retrofi tted with Callidus Ultra-Low NOx Burners in 1999. The heaters are permitted for a combined heat dut y 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 a nd boilers (0.2 lb/MMBtu).

The PTE for sulfur dioxide is 243.5 tpy and is bas ed on a permit limit of 55.6 lb/hr. This limit
derives from a 1974 Consent Order between Exx on 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 fi ring 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 “Cons ent Decree”) to have all heater s comply with NSPS Subpart J by December 31, 2010. This requires combus tion of fuel that does not exceed 162 ppm H 2 S, a
marked reduction from the curren t 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 SO 2 which will result in a new estimated SO2 limit of 64.4 tpy.

The PTE for PM 10 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 calcul ated 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 Callid us 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 ra te for an entire year. This allowable emission rate (PTE) is already half of the newly promul gated 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 bas ed on a permit limit of 35.9 lb/hr. This limit
derives from a 1974 Consent Order between Exx on 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 fi ring 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 “Cons ent Decree”) to have all heater s comply with NSPS Subpart J by December 31, 2010. This requires combus tion of fuel that does not exceed 162 ppm H 2 S, a
marked reduction from the curren t 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 SO 2 which will result in a new estimated SO2 limit of 9.6 tpy.

The PTE for PM 10 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 ther efore 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 promul gated 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 Callid us 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 NO x RACT limit for Industrial, Commercial and Institutional (ICI) heaters a nd boilers (0.2 lb/MMBtu).The PTE for sulfur dioxide is 330.7 tpy and is bas ed on a permit limit of 75.5 lb/hr. This limit
derives from a 1974 Consent Order between Exx on 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 fi ring 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 “Cons ent Decree”) to have all heater s comply with NSPS Subpart J by December 31, 2010. This requires combus tion of fuel that does not exceed 162 ppm H 2 S, a
marked reduction from the curren t 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 SO 2 which will result in a new estimated SO2 limit of 19.4 tpy.

The PTE for PM 10 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 in stallation 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. Agai n, 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 insta lled 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 significa ntly lower than the newly promulgated NOx RACT limit for Industrial, Commercial and Instituti onal (ICI) heaters and boilers (0.2 lb/MMBtu).

The PTE for sulfur dioxide is 81.0 tpy and is base d on a permit limit of 18.5 lb/hr. This limit
derives from a 1974 Consent Order between Exx on 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 fi ring 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 “Cons ent Decree”) to have all heater s comply with NSPS Subpart J by December 31, 2010. This requires combus tion of fuel that does not exceed 162 ppm H 2 S, a
marked reduction from the curren t 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 SO 2

.

The PTE for PM 10 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 calculat ed at the capacity of the heater.Determination of BART

EPA allows states to use MACT standards to help assess potential limit s and controls for BART eligible sources. There is no MACT standard fo r 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 informat ion can be instructive and helpful in determining BART. New Jersey publishes and maintains a St ate of the Art Manual that describes controls
and emission limits for new and reconstructed sour ces. 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 RB LC 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 t he limits established in a permit. There is no record that those limits were achieved in practice. Fina lly, 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 equiva lent or more stringent that BART.

Top Down Analysis for NOx

Several techniques are available to reduce NOx em issions. Selective Catalytic Reduction (SCR) is generally accepted as the most effective cont rol 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 th erefore 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 limit s 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+ h eaters has SCR listed as the cont rol 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 c onsidered representative. Nearly all of the sources listed represented BACT and the averag e 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 Se lective 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 fr om the fact that high tem peratures 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 tec hnique for NOx nor are we aware of any use of SNCR specifically on refinery heaters.

We believe it is clear that ULNB represents BAR T 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 SO 2

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

H 2 S. 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 mean s 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 system s are capable of removing large amounts of H 2 S lowering the concentration in fuel gas from 1%-2% down to <10 ppm levels in some cases. The process is very capital intensive. However, near ly all of a refinery’s sour fuel gas can be treated
in a few amine treaters and distributed to doz ens of furnaces. When smaller amounts of H 2 S must be removed a caustic contacting solution is sometimes used to treat the fuel gas.

Another method sometimes used to reduce SO 2 emissions is to install a caustic scrubber and treat the flue gas from a source, removing the SO 2 that has been creating during combustion. While effective in reducing SO 2 emissions it is not cost effective since it has to be applied to each
source of SO 2 . Caustic scrubbing is most often used on a single large source of SO 2 such as a large utility boiler burning coal or an FCCU at a refinery.

SO 2 scrubbing should not be considered BART when multiple small sources of SO 2 are involved. It is cost prohibitive. Amine scrubbing is equ ally effective as caustic scrubbing and could be considered in a BART analysis.

New Jersey does not address SO2 emissions fr om 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 t hese 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 PM 10

There are two main methods for reducing PM 10 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 co nstructed on each of the BART eligible sources. There are no known refinery heaters that have employed scrubbing as a means of reducing PM 10 emissions.

New Jersey does not address PM 10 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”. Pr oper, efficient combustion will minimize PM 10 emissions. If NEW heaters are employing thes e 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 PM 10

.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 re present 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 SO 2 indicates that burning NSPS compliant fuel gas represents BART for all refinery heaters. In ev ery case reviewed in the RACT/BACT/LAER Clearinghouse it was shown that burning N SPS compliant gas represented BACT for new sources. It is our position that Best Availabl e 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 Tec hnology. 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 NO x 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 w ill 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 Retrof it 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 it s Hudson Generating Station (“Hudson” or “the facility”) in response to a Ma rch 3, 2009 letter from Mr. William O’Sullivan, P.E. of the New Jersey Department of Environmen tal Protection (“NJDEP” or “the Department”) to Mr. Daniel Cunningham of PSEG as well as recent corresponden ce with Mr. Max Friedman of your staff.

Please note that this letter contains PSEG Fo ssil’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 9 th phone conversation betw een 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 su nlight encounters tiny pollution particles in the air, which reduce the clarity a nd color of what we see, par ticularly during humid conditions.

The haze-forming pollution comes from a variety of natural and manmade sources. Natural sources can include windblown dust, and soot fr om wildfires. Manmade sources can include motor vehicles, electric utili ty and industrial fuel burning, and manufacturing operations. Particulate matter pollution is the major cause of re duced visibility (haze) in parts of the United States, including many of our national parks. Some haze-causing particles are directly emitted toMr. 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) d eclared it a na tional goal to prevent any future, and to remedy any existing, imp airment of visibility in 156 mandatory federal Class I areas, the impairment of which result s from manmade air polluti on. New Jersey’s only federal Class I area is the Brigantine Wilder ness Area of the Edwin B. Forsythe National Wildlife Refuge located near Brigantine, Atlan tic County. In response to increased adverse visibility impacts at federal Cl ass 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 establis h goals for improving visibility by developing longterm strategies for reducing emissions of air po llutants 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 descri be these sources. The BART-eligible sources are sources that meet the following criteria:

1) Major stationary sources that contai n emission units whose operations fall within one or more of 26 speci fically listed source categories; 2) Emission units that were put in place between August 7, 1962 and August 7, 1977; and 3) Major stationary sources w ith a combined potential to emit 250 tons per year (“tons/yr”) or more of a visibility-i mpairing pollutant (“VIP”), namely nitrogen oxides (“NO

x ”), particulate matter less than 10 microns (“PM 10 ”) or sulfur dioxide (“SO 2 ”), from qualified emission un its. Qualified emission

units are defined as emission units that meet the criteria of #2 above with cumulative potential to emit SO 2 , NO

x , or PM 10 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 demons trated to cause an adverse visibility impact at the nearest Class I areas. The major re commendations for BART visibility impact modeling and application of emissions controls are:

1) Identify BART-eligible sources (bas ed 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 im pact for each candidate BART controlMr. Yogesh Doshi July 15, 2009 Page 3

option 7) Compare the visibility improvement of BART control options to other statutory factors in th e engineering analysis

HUDSON GENERATING STATION

Hudson is considered BART-eligible because it meets the above crite ria. Hudson is a fossil fuelfired electric generating stati on located at Duffield and Van Keuren Avenues in Jersey City, Hudson County, New Jersey. Currently, there are two (2) electric generati ng units (“EGUs”) at the facility: Hudson Unit No. 1 and Hudson Unit N o. 2. Additional equipment at the facility supports the operation of Hudson Units No. 1 and 2.

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

issued the initial Hudson T itle V Operating Permit on December 29, 2005. The most recently approved Title V permit modification for Huds on was issued by the Department on May 27, 2008 (BOP080001).

The emission sources at Hudson that were in stalled 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 NO

x , SO 2 , and PM 10 from Sources Installed Between August 7, 1962 and August 7, 1977
Emissions (tons/yr) (1)

Emission Unit NO

x SO 2 PM 10

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) PM 10 emission rates proposed by PSEG Foss il in 12/2/2008 Title V modification application, based on stack testing.

(3) The NO

x and SO 2 emission caps are from the Consent D ecree, and are in effect for calendar years 2008 through 2010.

The emission units in Table 1 above are subjec t 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 (Emi ssion 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 combusti on engine used to mainta in water pressure or flow for fire fighting at the facility. The emer gency fire pump was originally installed in 1963. However, PSEG Fossil’s records indicate that the emergency fire pump’s emission source, theMr. Yogesh Doshi July 15, 2009 Page 4

stationary internal combustion engine, wa s replaced in the 1985-1986 timeframe, which is outside the August 7, 1962 through August 7, 1977 pe riod 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 generati ng capacity of approximately 420 megawatts (“MW”). Hudson Unit No. 1 was ma nufactured 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 N o. 1 is equipped with with Continuous Emissions Monitoring Systems (“CEMS”) for NO

x , SO 2 , and carbon monoxide (“CO”), as well as a Continuous Opacity Monitori ng 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 u tilize this control device to comply with its NOx

emissions.

The currently permitted NO

x , SO 2 , and PM 10 emission rates for Hudson Unit No. 1, expressed in pounds per million British thermal unit (“lb/MMB tu”), are summarized in Table 2 below:

Table 2. Current Hudson Unit No. 1 Permitted NO

x , SO 2 , and PM 10 Emission Rates
Emissions (lb/MMBtu)

Fuel NO

x SO 2 PM 10

Natural Gas 0.39 0.0017 0.022 (1)

No. 6 Fuel Oil 0.43 0.32 0.050 (1)

(1) PM 10 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 PJM 1 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 wa s needed by PJM for reliability purposes. In April 2005, Hudson Unit No. 1 became one of the fi rst units located within the PJM footprint to be designated as a Reliability Must Run (“RM R”) unit by PJM. Hence, Hudson Unit No. 1

continues to remain in service to ma intain electrical system reliability.

As an RMR unit, Hudson Unit No. 1 operates re latively infrequently and well below its annual operating capacity. Also, operational problems ha ve prevented the unit from burning No. 6 fuel oil since 2005, so in recent years the unit has burned only natural ga s, 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

NO

x , SO 2 , and PM 10 emissions than No. 6 oil firing. Th e limited amount of operation on almost exclusively natural gas is reflec ted in Table 3 below, which summ arizes the potential and actual

emissions of NO

x , SO 2 , and PM 10 for Hudson Unit No. 1, and compares the unit’s actual fuel use to its potential fuel use.

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

Emissions (tons/yr)

NO

x SO 2 PM 10 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) PM 10 emission rate proposed by PSEG Foss il 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 standpoi nt. From calendar years 2004 through 2008, Hudson Unit No. 1’s fuel-based annual capacity factor ra nged from a high of 4.2% in 2005 to a low of

0.9% in 2008. NO

x emissions ranged from a high of 196.37 tons/yr in 2005 to a low of 34.2 tons/yr in 2008. SO 2 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 SO 2 emissions less than 10 tons/yr. PM 10 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 NO

x , SO 2 , and PM 10 emission rates and utiliz ation rates for Hudson Unit No. 1, combined with its marginal economic vi ability and short remaining useful life, as indicated by its RMR status, make it extremely co st-prohibitive to equip this unit with any addon NO

x , SO 2 , and PM 10 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 electri c generating unit with an elec tric generating capacity of approximately 640 MW. The unit was manufactur ed 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 fu el oil. Hudson Unit No. 2 began commercial operation on December 18, 1968. Hudson Unit No. 2 is equipped with CEMS for NO

x , SO 2 , CO, and mercury (“Hg”), as well as a COMS for opacity. Hudson Unit No. 2 is also required to be equipped with a particulate ma tter (“PM”) CEMS by December 31, 2010.Mr. Yogesh Doshi July 15, 2009 Page 6

For NO

x emission control, Hudson Unit No. 2 is currently equi pped with Low-NO

x Burners (“LNB”) and Selective Non-Catalytic Reduction (“SNCR”). LNB use modified air and fuel entry to slow mixing ra tes, reduce the oxygen (“O 2 ”) available for NO

x formation, and reduce the amount of fuel burned at peak flame temperatures. Low NO

x burners operate at much lower O 2 levels than conventional bur ners, and therefore generate less fuel and thermal NO

x . SNCR involves injecting urea into the furnace exhaust ga ses. The basic chemi cal reaction involves the decomposition of urea and the reacti on of nitric oxide (“NO”) with NH 2 to form mostly elemental nitrogen (“N 2 ”), carbon dioxide (“CO 2 ”), and water (“H 2 O”).

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 SO 2 emission control, on January 1, 2007, the Company began burning Ultra-Low Sulfur Coal (“ULSC”) in Hudson Unit No. 2, as re quired under the terms of a Consent Decree 2 . “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 sta tion during that quarter. The 0.25% sulfur content

limit is 75% lower than the 1% sulfur content limit in effect for H udson Unit No. 2 prior to January 1, 2007.

Since May 1, 2007, the Company has burned only ULSC in H udson Unit No. 2. Under the Consent Decree, PSEG Fossil must continue bu rning 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 SO 2 emission control.

For PM 10 emission control, Hudson Unit No. 2 is equipped with electrostatic precipitators (“ESPs”). The electrostatic precipitation process involves: 1) charging par ticles by means of ions produced in a corona discharge (an electrical di scharge accompanied by ionization of the exhaust gas), 2) separating the charged particles from th e gas stream in an imposed electric field, 3) collecting the particles on a gr ounded surface, and 4) removing th e collected particles from the grounded surface and consolidating them for disposition.

NO

x emissions are also reduced by combusting UL SC which, with its lower nitrogen content than traditional bituminous coals, tends to reduce the formation of NO

x during combustion.

PM 10 emissions may also be reduced by combusting ULSC because of its lo wer ash content than

traditional bituminous coals.

The current NO

x , SO 2 , and PM 10 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 NO

x , SO 2 , and PM 10 Emission Rates
Emissions (lb/MMBtu)

Fuel NO

x SO 2 PM 10 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 NO

x emission rate proposed by PSEG Fossil in a 1/15/2009 submittal to NJDEP, based on actual NO

x emissions performance with new LNB burning ULSC. If approved, this interim limit w ould remain in effect until SCR operation.

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

alternative interim SO 2 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) PM 10 emission rate proposed by PSEG Fossil in 12/2/2008 Title V modification application, based on stack testing.

Table 5 below summarizes the pote ntial and actual emissions of NO

x , SO 2 , and PM 10 for Hudson Unit No. 2, and compares th e unit’s actual fuel use to its potential fuel use.

Table 5. Hudson Unit No. 2 Potentia l and Actual Emissions and Fuel Use
Emissions (tons/yr)

NO

x SO 2 PM 10 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 NO

x and SO 2 emission caps are from the Consent Decree, and are in effect for calendar years 2008 through 2010.

(2) PM 10 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 fu el 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. NO

x emissions ranged from a high of 8,582 tons/yr in 2005 to a low of 2,945 tons/yr in 2008. SO 2 emissions ranged from a high of 23,960 tons/yr in 2005 to a low of 2,177 tons/yr in 2008. PM 10 emissions ranged from a high of 3,189 tons/yr in 2005 to a low of 2,055 tons/yr in 2007. The substantial re ductions in actual NO

x and

SO 2 emissions in 2007 and 2008 reflect the Consen t Decree-required bu rning 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 NO

x , SO 2 , and PM 10 emission control technologies than Hudson Unit No. 1.

HUDSON UNIT NO. 2 BART

NO

x

The most advanced NO

x emission control technology for coal-f ired boilers like Hudson Unit No. 2 is Selective Catalytic Reduction (“SCR”). SCR is a proven technology used on hundreds of

NO

x emission sources in the United States and abroad. SCR uses ammonia (“NH 3 ”) to react with

NO

x in the exhaust gas over a catalyst. NO

x from fuel combustion pro cesses is typically found in the form of NO or nitrogen dioxide (“NO 2 ”). The general chemical reaction for the reduction of

NO is:

4 NO + 4 NH 3 + O 2 Æ 4 N 2 + 6 H 2 O

For the reduction of NO 2 , the reactions are:

6 NO 2 + 8 NH 3 Æ 7N 2 + 12 H 2 O

2 NO 2 + 4 NH 3 + O 2 Æ 3 N 2 + 6 H 2 O

These reactions occur within a re latively narrow flue gas temper ature window. At temperatures below approximately 550 o F, the NO

x reduction reactions become less efficient. At temperatures above approximately 850 o F, the catalyst is progressively destroyed.

Under the terms of the Consent Decree, Huds on 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 th e SCRs installed on utility boilers in the United States. A “high dust”/“hot side” SCR is installed prior to any pa rticulate 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 w ill inject aqueous ammonia into the flue gas stream by means of an injection grid installed be tween the economizer and air heater sections of

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

NO

x and ammonia before the flue gas enters the catalyst.

With SCR, the maximum NO

x 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 NO

x emissions from Hudson Unit No. 2 in calendar year 2011 and beyond are expected to be ev en lower than the 3,486 tons/yr NO

x emission cap that applies in calendar years 2008 through 2010. For example, if Hudson Unit No. 2 burned allMr. Yogesh Doshi July 15, 2009 Page 9

4.963E13 Btu of its permitted fuel emitting at the above 30-day rolling average NO

x 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.

SO 2

The advanced SO 2 emission control technology PSEG Fossil is installing on Hudson Unit No. 2 is an FGD system that utilizes a Spray Drye r Absorber (“SDA”) in which an atomized lime slurry is injection into the flue gas. The lim e slurry will then react with sulfur oxides (“SO

x ”) to form calcium sulfate (“CaSO 4 ”) and calcium sulfite (“CaSO 3 ”) 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. Fr om the storage silos or day bins, the pebble lime will be pneumatically conveyed to vertical ball m ills, 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 transf er 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 SO 2 in the flue gas stream as follows:

Ca(OH) 2 + SO 2 Æ CaSO 3 •1⁄2(H 2 O) + 1⁄2(H 2 O)

CaSO3•1⁄2(H 2 O) + 1⁄2 O 2 Æ CaSO 4 •1⁄2(H 2 O)

Ca(OH) 2 + SO 3 Æ CaSO 4 •1/2(H 2 O) + 1⁄2( H 2 O)

As these reactions occur, the lime slurry wate r will evaporate, leaving a dry power. The reactions products, unreacted reagent, and fly as h will be captured downstream of the FGD by the baghouse described below.

The FGD will utilize a recycle system to optimi ze 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-i njected into the lime slurry process stream.

Particulates collected in the baghouse hoppers will be transported to recycl e 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 f eeders. Particulates collected at the bottom of the SDA vessel will be conveyed to the recycl e 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, Huds on Unit No. 2 must be equipped with an FGD system by December 31, 2010. With FGD, the maximum SO 2 emission rates prescribed for

Hudson Unit No. 2 in th e Consent Decree are:

• 0.250 lb/MMBtu (24-hour average)

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

With FGD operation, potential annual SO 2 emissions from Hudson Unit No. 2 in calendar year 2011 and beyond are expected to be ev en lower than the 5,270 tons/yr SO 2 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 SO 2 emission rate of 0.150 lb/MMBtu, its potential to emit would be 3,722.25 tons/yr.

PSEG Fossil proposes the existing co nfiguration of the unit with th e burning of ULSC as well as the planned future FGD as BART for this source.

PM 10

The most advanced technology for particulate matte r (“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 (CaSO 4 and CaSO 3 ).

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 indivi dual 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 remaini ng 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 th e 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 co mbusting 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 Un it 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/MMBtu 3

PSEG Fossil proposes the existing c onfiguration of the unit with th e ESP as well as the planned future baghouse as BART for this source.

COAL RECEIVING SYSTEM

The Coal Receiving System (Emission Unit U15, E quipment E22 in Hudson’s Title V permit) is the materials handling equipment associated w ith 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 th e 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 SO 2 or NO

x emissions associated with the Co al Receiving System. The Coal Receiving System’s potential to emit PM 10 is 2.7 tons/yr.

COAL RECEIVING SYSTEM BART

Given that PM 10 emissions are minimal from this equipment, and the emissions from this equipment do not tend to travel ov er long distances that may affect visibility in Federal Class I

areas 4 , PSEG Fossil proposes the exis ting configuration of the unit as BART for this source.

COAL RECLAIM SYSTEM

The Coal Reclaim System (Emi ssion Unit U16, Equipment E23 in Hudson’s Title V permit) is the materials handling equipment associated with transferring coal fo r Hudson Unit No. 2 from the coal pile to the unit itself.

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

Pulverizers.

There are no SO 2 or NO

x emissions associated with the Co al Receiving System. The Coal Reclaim System’s potential to emit PM 10 is 1.2 tons/yr.

COAL RECLAIM SYSTEM BART

Given that PM 10 emissions are minimal from this equipment, and the emissions from this equipment do not tend to travel ov er long distances that may affect visibility in Federal Class I areas, PSEG Fossil proposes the existing configur ation 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 Na tional 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 NO

x SO 2 PM 10

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)

Action None None None Coal Receiving

System Emission

Rates Retain Current Levels Retain Current Levels Retain Current

Levels

Action None None None Coal

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 fort h in 40 C.F.R. Part 60, Appendix A, Method 5.

If you have any questions about the issues raised in these comments, pleas e feel free to contact Mr. Erin Gorman at (973) 430-6359.

Sincerely,

Donald McCloskey Director, Environmenta l Strategy and Policy

Enclosures

cc: Max Friedman (NJDEP) Aliya Khan (NJDEP) William O’Sullivan, P.E. (NJDEP)