Appendix N 

DuPont Submittal 
 

December 4, 2007 

Certified Mail No. 7000 0520 0023 1267 9231 

Receipt Return Requested

Elliott Bickerstaff, P.E., DEE 

Chief, MDEQ Air Support Branch 

101 Capitol Centre 

101 West Capitol Street 

Jackson, MS 39201 

RE: DuPont DeLisle Plant Information Relative to the Regional Haze Rule 

Dear Mr. Bickerstaff: 

Enclosed is an engineering analysis prepared in response to the August 30, 2006 

letter from Ms. Michelle Root of your staff. 

If you have any questions or need additional information, please call me on (228) 

255-4931. 

 Very truly yours, 

 Eduardo Ramos 

 Sr. Consultant, Environmental 

 DeLisle Plant 

Enclosure 
BCC: 

EC01-A10 

R. S. Pietras 

F. M. Holman 

J. C. deRuyter – Brandywine Bldg # 9446 
 1

Regional Haze Rule Information 

DuPont DeLisle Plant 

Prepared by 

John C. deRuyter 

Principal Consultant 

Energy Engineering 

DuPont Engineering & Research Technology 

Wilmington, Delaware 

November 30, 2007 
Regional Haze Rule Information – DuPont Delisle Plant 

November 30, 2007 

2

A. Background 

MDEQ has requested information from the DuPont DeLisle Plant relative to potential SO2

emissions reductions from Emission Point AF-101, the stack serving the two coal fired boilers, 

identified as Boilers 1 and 2 (AF-101A and AF-101B). MDEQ did recognize that the facility is not 

BART eligible, but indicated that state consideration of addressing Reasonable Progress for 

Class I Areas such as Breton National Wildlife Refuge requires consideration of potential 

emissions reductions from non-BART eligible sources. In setting the progress goals, the state 

must “consider the cost of compliance, the time necessary for compliance, the energy and non-air 

impacts of compliance, and the remaining useful life of any potentially affected sources.” Based 

on the proximity to Breton and the facility’s SO2 emissions, emissions controls for the boilers will 

need to be evaluated based on these factors. This letter attempts to provide DuPont’s initial input 

relative to this request. This response does not include modeling of the potential impact on 

visibility at Breton due to these potential emissions reductions; if that is needed, additional time 

would be required in order to complete that modeling. This analysis does not include a rigorous 

engineering analysis of the installation and O&M costs of the various options, but rather uses 

available information to estimate the costs and impacts. If a higher level of detailed analysis is 

required, additional time would be necessary. In addition, comments regarding information 

provided by Michelle Root in the referenced email are also provided. 

B. Description of Feasible Options 

The following provides a summary of the options initially considered for emissions reductions 

from the coal fired boilers. The primary focus is on SO2 emissions, with one option considered 

viable for NOx emissions reductions for comparison. The four CAA statutory factors requested to 

be considered are: 

• Cost of compliance. 

• Time necessary for compliance. 

• Energy and non-air quality environmental impacts of compliance. 

• Remaining useful life of any existing source subject to such requirements. 

The remaining useful life of the boilers is estimated to be at least 20 years providing adequate 

routine maintenance and proper operation are practiced. That would result in an overall life of 

about 50 years. DuPont has operated boilers for longer periods. It is currently not anticipated 

that alternative steam supply opportunities would arise that would eliminate the need for the two 

coal fired boilers, but if that did occur, the overall life of the units would be reduced. 

Each of the other factors are addressed for the evaluated options below. 

1. Baseline Case Using Coal with SO2 Emissions at Permit Limit 

The baseline case is used as a comparison case for the other options. This case also provides a 

basis for evaluating potential emission reductions. The permit limit is 4.8 lb/MMBtu, or 3.0% 

sulfur at 12,000 Btu/lb (typical average coal HHV). 

2. Baseline Case With the Current Coal Specification Sulfur Limit 

Current coal sulfur content is 2.5% in order to provide operating margin without exceeding the 

limit. There is no additional cost for using the current coal, but emissions are reduced from the 

permitted level. 

3. Burn Lower Sulfur Coal 
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November 30, 2007 

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Coal could be purchased with lower inherent sulfur content. The boilers are equipped with hot 

side Electrostatic Precipitators (ESPs). The boilers are wall fired dry bottom units firing 

bituminous coal. The boiler design places limitations on the type of coal that can be fired, so that 

PRB coal, for instance, is not a viable option. Coal choices would be limited to bituminous coal. 

In addition, the boilers are subject to the now vacated 40CFR Part 63, Subpart DDDDD 

requirements which had a compliance date of September 13, 2007. A project was implemented 

to upgrade the ESPs, and coal specifications (including both chorine and mercury specifications) 

with existing boiler/PM control are being used to demonstrate compliance with those prior 

emission limits. Therefore, the availability of coal supplies is limited based on the required 

specifications which might also change with a revised Subpart DDDDD regulation. There will be 

a cost increase in coal delivered to the site with lower sulfur requirements. The estimated 

additional cost per ton is included in the options analysis. Three levels of lower sulfur content are 

evaluated- 2.0%, 1.5%, and 1.05%. It is quite possible that coal with lower sulfur levels could 

negatively impact ESP performance due to ash resistivity effects. Therefore, while a lower sulfur 

level is included in the analysis, the lowest practical sulfur level is believed to be about 1.5%. 

However, actual performance and options would need to be thoroughly evaluated and test burns 

accomplished in order to firmly establish capability. 

4. Install SO2 Scrubbers and Use Coal with Lower Sulfur Content 

The most practical types of SO2 scrubbers that would be applicable to boilers of this size are 

spray dry absorbers with a downstream baghouse (fabric filter) or a sodium wet scrubber. The 

spray dryer has an inherent advantage of providing a dry waste product that could be disposed of 

similarly to the existing coal ash. The sodium wet scrubber would require additional investment 

and O&M cost for treatment of a liquid waste stream prior to disposal in the plant’s waste water 

treatment system. Both of those types of scrubbers use higher cost reagents than limestone wet 

scrubbers typically used in electric utility systems. However, the cost of the limestone wet 

scrubber systems for smaller units is not justified compared to the other options. Since the spray 

dryer and sodium wet scrubber reagents have a significant cost, it is most appropriate to utilize 

them with lower sulfur coal. Two cases are evaluated for scrubbing with lower sulfur coal- 1.5% S 

and 1.05% S. With a downstream scrubber of either type- spray dry absorber or sodium wet 

scrubber- the impact of lower sulfur level on ESP performance becomes less of an issue due to 

downstream PM capture capability. Those two sulfur levels are therefore used for cost 

comparisons with use of SO2 scrubbing. As part of the evaluation, it is assumed that each boiler 

would be provided with its own scrubber train so that boiler uptime can be optimized and use of 

backup natural gas firing will be minimized. The cost evaluations include the requirement for use 

of natural gas firing during scrubber installation, and that cost is amortized using the capital 

recovery factor. 

5. Install Low NOx Burners (LNB) 

As mentioned above, for comparison purposes, installation of replacement LNB was evaluated for 

both boilers (4 burners per boiler). That is the only NOx reduction method currently demonstrated 

that would be directly applicable to these boilers. The furnace height is inadequate for overfire air 

and SNCR. Application of SCR to these boilers would be extremely difficult and would probably 

require replacement of the hot side ESPs with an SCR; but even with such an assumption, the 

boiler outlet flue gas temperature is not consistently in an optimum range for SCR. Therefore, 

only LNB retrofit was evaluated. Since the boilers require a coal with proper ash resistivity, 

slagging routinely occurs in the furnace, so that NOx reductions achievable with LNB would 

probably be in the 40% reduction range- that is used for the comparison analysis. 
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November 30, 2007 

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C. SO2 Emissions Reductions and Economic Comparison of Options 

1. Coal 1 

Coal 1 is assumed to be coal with 2.0% S (3.17 lb/MMBtu SO2 per AP-42 using 12,000 Btu/lb AsReceived HHV). Annual costs would increase approximately $740M (M=1000) per year for 

increased coal purchase price. SO2 reductions vs Baseline (4.8 Lb/MMBtu) would be 2059 TPY 

with resultant incremental cost of $358/ton SO2 removed. If compared to the current coal spec 

limit (3.96 lb/MMBtu), SO2 reduction would be 998 TPY with an incremental cost effectiveness vs 

Baseline of $738/ton SO2 removed. 

2. Coal 2 

Coal 2 is assumed to be coal with 1.5% S (2.38 lb/MMBtu SO2 per AP-42 using 12,000 Btu/lb AsReceived HHV). Annual costs would increase approximately $1.05MM per year for increased 

coal purchase price. SO2 reductions vs Baseline (4.8 Lb/MMBtu) would be 3057 TPY with 

resultant incremental cost effectiveness of $344/ton SO2 removed. If compared to the current 

coal spec limit (3.96 lb/MMBtu), SO2 reduction would be 1996 TPY with an incremental cost 

effectiveness vs current coal of $527/ton SO2 removed. 

Additional incremental SO2 emissions reductions for Coal 2 over Coal 1 would be 998 TPY with a 

resultant incremental cost effectiveness vs Coal 1 of $316/ton SO2. 

3. Coal 3 

Coal 3 is assumed to be coal with 1.05% S (1.66 lb/MMBtu SO2 per AP-42 using 12,000 Btu/lb 

As-Received HHV). Annual costs would increase approximately $1.58MM per year for increased 

coal purchase price. SO2 reductions vs Baseline (4.8 Lb/MMBtu) would be 3958 TPY with 

resultant incremental cost effectiveness of $399/ton SO2 removed. If compared to the current 

coal spec limit (3.96 lb/MMBtu), SO2 reduction would be 2899 TPY with an incremental cost 

effectiveness vs current coal of $545/ton SO2 removed. 

Additional incremental SO2 emissions reductions for Coal 3 over Coal 1 would be 1899 TPY with 

a resultant incremental cost effectiveness vs Coal 1 of $443/ton SO2. 

Additional incremental SO2 emissions reductions for Coal 3 over Coal 2 would be 901 TPY with a 

resultant incremental cost effectiveness vs Coal 2 of $584/ton SO2. 

4. Spray Dry Absorber Using Coal 3 

Application of a spray dry absorber with downstream baghouse is assumed to provide 85% SO2

reduction. While it is possible to achieve higher reduction levels, 85% is considered a reasonable 

long term average achievable removal rate. Total capital requirement is estimated to be $55MM. 

This cost is within the range of the EPA APCTFS estimate. Total annual cost including capital 

recovery is $12.3MM without the amortized installation period incremental gas cost. Overall SO2

reduction vs Coal 3 firing alone would be 1790 TPY with an incremental cost effectiveness of 

$6054/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 2691 TPY vs use of Coal 2 

firing alone and an incremental cost effectiveness of $4222/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 3689 TPY vs use of Coal 1 

firing alone and an incremental cost effectiveness of $3165/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 5748 TPY vs Baseline SO2

emissions of 4.8 lb/MMBtu and an incremental cost effectiveness of $2160/ton SO2 removed. 
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November 30, 2007 

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However, this is not a viable comparison since current coal is lower sulfur than 4.8 lb/MMBtu 

equivalent. It simply serves to indicate the range of comparisons. 

Use of this option would provide a total SO2 emissions reduction of 4687 TPY vs current coal 

spec equivalent SO2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of 

$2649/ton SO2 removed. 

5. Sodium Wet Scrubber Using Coal 3 

Application of a sodium wet scrubber is assumed to provide 95% SO2 reduction. Total capital 

requirement is estimated to be $39MM. This cost is within the range of the EPA APCTFS 

estimate. Total annual cost including capital recovery is $9.8MM without the amortized 

installation period incremental gas cost. Overall SO2 reduction vs Coal 3 firing alone would be 

2000 TPY with an incremental cost effectiveness of $4184/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 2901 TPY vs use of Coal 2 

firing alone and an incremental cost effectiveness of $3066/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 3899 TPY vs use of Coal 1 

firing alone and an incremental cost effectiveness of $2362/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 5958 TPY vs Baseline SO2

emissions of 4.8 lb/MMBtu and an incremental cost effectiveness of $1670/ton SO2 removed. 

However, this is not a viable comparison since current coal is lower sulfur than 4.8 lb/MMBtu 

equivalent. It simply serves to indicate the range of comparisons. 

Use of this option would provide a total SO2 emissions reduction of 4897 TPY vs current coal 

spec equivalent SO2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of 

$2031/ton SO2 removed. 

6. Spray Dry Absorber Using Coal 2 

Application of a spray dry absorber with downstream baghouse is assumed to provide 85% SO2

reduction. While it is possible to achieve higher reduction levels, 85% is considered a reasonable 

long term average achievable removal rate. Total capital requirement is estimated to be $55MM. 

This cost is within the range of the EPA APCTFS estimate. Total annual cost including capital 

recovery is $11.7MM without the amortized installation period incremental gas cost. Overall SO2

reduction vs Coal 2 firing alone would be 2556 TPY with an incremental cost effectiveness of 

$4231/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 1654 TPY vs use of Coal 3 

firing alone and an incremental cost effectiveness of $6217/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 3554 TPY vs use of Coal 1 

firing alone and an incremental cost effectiveness of $3131/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 5613 TPY vs Baseline SO2

emissions of 4.8 lb/MMBtu and an incremental cost effectiveness of $2114/ton SO2 removed. 

However, this is not a viable comparison since current coal is lower sulfur than 4.8 lb/MMBtu 

equivalent. It simply serves to indicate the range of comparisons. 

Use of this option would provide a total SO2 emissions reduction of 4552 TPY vs current coal 

spec equivalent SO2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of 

$2607/ton SO2 removed. 
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November 30, 2007 

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7. Sodium Wet Scrubber Using Coal 2 

Application of a sodium wet scrubber is assumed to provide 95% SO2 reduction. Total capital 

requirement is estimated to be $39MM. This cost is within the range of the EPA APCTFS 

estimate. Total annual cost including capital recovery is $9.3MM without the amortized 

installation period incremental gas cost. Overall SO2 reduction vs Coal 2 firing alone would be 

2856 TPY with an incremental cost effectiveness of $2924/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 1955 TPY vs use of Coal 3 

firing alone and an incremental cost effectiveness of $4002/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 3854 TPY vs use of Coal 1 

firing alone and an incremental cost effectiveness of $2249/ton SO2 removed. 

Use of this option would provide a total SO2 emissions reduction of 5913 TPY vs Baseline SO2 

emissions of 4.8 lb/MMBtu and an incremental cost effectiveness of $1590/ton SO2 removed. 

However, this is not a viable comparison since current coal is lower sulfur than 4.8 lb/MMBtu 

equivalent. It simply serves to indicate the range of comparisons. 

Use of this option would provide a total SO2 emissions reduction of 4852 TPY vs current coal 

spec equivalent SO2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of 

$1938/ton SO2 removed. 

8. LNB Retrofit 

Uncontrolled NOx emissions from the boilers are assumed to be 0.88 lb/MMBtu per AP-42 using 

12,000 Btu/lb HHV coal. Retrofit of LNB (4 burners per boiler) to these boilers is considered 

viable. As indicated above, OFA, SNCR, and SCR are not considered viable options. Since the 

furnace of these boilers routinely experiences slagging conditions, it is likely that a NOx reduction 

of 40% could be achievable with retrofit installation of LNB alone. Based on boiler capacity of 

209 MMBtu/hr and an annual capacity factor of 69%, total NOx emission reduction from LNB 

retrofit to the boilers would be 445 TPY. The cost for retrofit LNB installation on both boilers is 

estimated to range from $1.7MM to $3.9MM using different reference sources with a mid-range 

estimate of $2.8MM. The mid-range estimate is believed to be closest to actual based on past 

DuPont LNB retrofit experience. Including incremental additional natural gas cost for 4 weeks of 

downtime per boiler results in a total cost effectiveness of $1204/ton NOx removed. 

D. Q/d Impact of Options 

The attached table indicates the emission rates and equivalent Q/d relative to Breton, similar to 

the table provided by VISTAS. 

First, however, there are some issues with the VISTAS table. The table indicating Potential 

Emissions lists SO2 emissions of 8802 TPY; that should be 8772.8 TPY based on permit 

conditions and full design heat input at 100% annual capacity factor. That table also lists NOx

emissions of 1418 TPY; that should be 1608 TPY based on the permit application emission rates 

which were based on AP-42 at design heat input. Though not involved with this analysis, the 

listed PM-10 figure of 826 TPY should be 658 TPY based on the permit limit at design heat input. 

The attached table provides the above corrected SO2 and NOx emission rates and shows the 

potential Q/d for those emissions of 190.5 vs 187.2 per the VISTAS table. 

Potential Emissions in the attached table are with the boilers at design heat input (209 MMBtu/hr) 

and 100% annual capacity factor. The Actual/Projected Emissions indicated in the attached table 

are based on the boiler design heat input of 209 MMBtu/hr and an annual capacity factor of 69%, 
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November 30, 2007 

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which is based on the average of actual coal use in 2003 and 2004 (2005 was not representative 

due to Katrina). The distance to Breton is taken as 54.6 km based on the VISTAS table data. 

As indicated in the attached table, Q/d can be significantly reduced with any of the options 

considered. While LNB can reduce NOx and the total SO2+NOx Q/d, it is recognized that 

modeling would be required in order to determine the visibility impact on Breton from NOx 

reductions vs SO2 reductions. As indicated by MDEQ, SO2 emissions are the primary contributor 

to visibility problems at Breton. The NOx information is provided for reference and potential future 

additional evaluation if required. 

E. Time Necessary for Compliance 

Options utilizing scrubbing would require extended time for compliance due to the need for 

detailed design and project implementation as well as capital planning. The high level of 

emissions control system installations in the future planning period in response to CAIR and 

BART will put a significant strain on resource availability and costs. Therefore, if scrubbing was 

required, it is likely that compliance would not be attainable until the 2013 time frame, similar to 

that intended for BART eligible sources. Installation of LNB could probably be provided around 

2011 at the earliest. However, since there is a significant cost involved with LNB installation, it 

appears reasonable to delay that installation to coincide with emissions controls on BART eligible 

units, or nearer the 2013 time frame. 

Options utilizing lower sulfur coal would require time for finding and evaluating alternative coal 

supplies that not only provide lower sulfur levels, but also that can provide required combustion 

performance and compliance with the Subpart DDDDD Boiler MACT regulations. In addition, as 

noted above, the effects of lower sulfur coal use on the performance of the hot side ESP and 

resultant emissions and opacity impact need to be assessed. It is likely that conversion to 

alternative coal would not be possible prior to 2010. However, since there is a cost involved with 

using lower sulfur coal, it appears reasonable to delay such use of lower sulfur coal to coincide 

with emissions controls on BART eligible units, or nearer the 2013 time frame. 

F. Energy and Non-Air Quality Environmental Impacts of Compliance 

This analysis does not provide detailed quantification of energy and non-air quality environmental 

impacts for each compliance option since this is a high level analysis. However, those impacts 

and be described qualitatively. 

Use of lower sulfur alone coal would not entail any significant changes to energy use or non-air 

quality environmental impacts. 

Use of a spray dry scrubber would require use of lime as the reagent. Solid waste disposal would 

increase over the current coal ash-only condition by the quantity of calcium sulfate formed in the 

scrubber. This can be estimated based on removal percent and expected calcium/sulfur 

stoichiometric ratio. Costs for that disposal are included within the estimated O&M cost 

estimates. As indicated above, the additional waste would be dry, so it would likely be disposed 

of in a landfill. Additional purchased electricity would be required for operation of the scrubber 

and baghouse, including, for example, lime transport, slurry preparation and injection, baghouse 

pulse air, ash and spent sorbent handling, and increased fan power to compensate for increased 

flue gas pressure drop. Increased purchased electricity would result in increased emissions of 

SO2, NOx, CO2, and other emissions from the electric utility generators providing that power, 

which could in fact, be units that themselves impact Breton with their SO2 and NOx emissions. 

Water would also be consumed for slurry preparation. 
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Use of a sodium wet scrubber would require use of caustic as the reagent. Liquid waste disposal 

would increase for disposal of the scrubber blowdown stream. The existing plant waste water 

treatment facility does not have adequate capacity for that waste stream directly, but some form 

of neutralization and oxidation would be required prior to transfer to the waste treatment system. 

Costs for that disposal are included within the estimated O&M cost estimates. Additional 

purchased electricity would be required for operation of the scrubber, including, for example, 

liquid pumping power and increased fan power to compensate for increased flue gas pressure 

drop. Increased purchased electricity would result in increased emissions of SO2, NOx, CO2, and 

other emissions from the electric utility generators providing that power, which could in fact, be 

units that themselves impact Breton with their SO2 and NOx emissions. Water would also be 

consumed for the scrubber solution. 

Use of LNB would result in increased unburned carbon in the flyash due to lower flame 

temperatures. This could impact the method of disposal of flyash in that beneficial reuse might 

not be possible, and landfill disposal might be the only option. The associated efficiency loss with 

increased unburned carbon would result in incremental increase in coal consumption and the 

associated electricity for pulverization and fan power, as well as increased ash disposal overall. 

G. Comments on Documents Provided by MDEQ 

The following comments are provided on the documents provided by MDEQ: 

1. Potential BART Sources Located in MS - DuPont Units 

The table includes not only Boilers 1 and 2, but also many other units on the plant site even 

though it was agreed that the site overall is not BART eligible, and the boilers individually are not 

BART eligible. In order to avoid confusion, it would be more appropriate to remove all of the 

DuPont DeLisle units from the list of potential BART sources. The actual and potential emission 

rates also do not match those provided in the attachment and explained above. The difference in 

actual emissions might be due to actual coal quality and use during 2002 vs that used for this 

analysis. The basis for the potential emissions for the boilers shown in that table is not known. 

2. VISTAS Potential Control Measure Spreadsheet 

Comments were requested on the listed potential controls for the eligible units at the DeLisle 

facility. As indicated above, none of the units at the DeLisle facility are considered eligible units. 

Ignoring that issue, the listed controls applicable to the two coal fired boilers are commented on 

below. 

• The email accompanying the VISTAS table indicates that the table data is the 

average of costs for all sources in the 1999 NEI. Thus, the control costs and 

$/ton reduced figures shown are averages over many units of unknown size, and 

it is not possible to make constructive comments on those figures since they are 

composite data with no known details. 

• Since they are the average cost for all sources, the control cost and $/ton 

removed figures in the table are totally inappropriate to apply to any specific units 

and their use would lead to inaccurate and misleading results. 

• Many of the specific controls do not have data listed in any event, so even order 

of magnitude comparisons are not possible or of any value. 

• As for the specific control technologies listed for similar boilers to the two coal 

fired boilers at DeLisle, the following comments relative to applicability to those 

units apply: 

a. SNCR - Use of SNCR was discussed above- the short furnace height and 

lack of appropriate temperature zones severely limit applicability. 
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b. LNB - Use of LNB is considered feasible and is addressed above. 

c. SCR - Use of SCR was discussed above- there would be a very high retrofit 

cost due to the likely need to replace the hot side ESP with the SCR, and 

optimum flue gas temperatures are not available. 

d. LNB/OFA - As indicated above, the short furnace height does not allow for 

use of OFA. 

e. IDIS - Use of in-duct sorbent injection is not viable with a hot side ESP. If 

that was to be done, it would require a downstream baghouse, and with that 

cost, it is more likely that a scrubber would be more cost effective. 

f. FGD - FGD as a sodium wet scrubber would be applicable, but at a high cost 

and is addressed above. 

g. SDA - Use of a spray dry absorber or circulating dry scrubber could be 

applicable, but at a high cost and is addressed above. 

h. Wet FGD - Use of a limestone wet scrubber is not economically viable on 

small scale units and was addressed above. 

i. Increased monitoring frequency of PM control - Exactly what is meant by this 

is unknown, but a project has been executed to upgrade the existing hot side 

ESPs on the subject boilers, and that included new discharge electrodes and 

collecting plates, power supplies, rappers, and controls. This rebuild 

included an integrated control system that provides more optimum control. 

j. Venturi scrubber - That is essentially a sodium wet scrubber and is 

addressed above. 

k. Dry ESP- wire plate type - The original ESPs were wire-plate type and 

significant problems occurred with broken wires and other issues. Therefore, 

those have been replaced with rigid electrodes and new collecting plates 

which provide much higher reliability and removal efficiency with the new 

controls. 

l. Fabric Filter (Pulse jet type) - Use of a fabric filter downstream of the existing 

ESPs would be redundant and not required to obtain low PM emissions. 

However, if a spray dry scrubber was utilized, a pulse jet fabric filter would be 

included with that installation downstream of the scrubber. A pulse jet fabric 

filter is considered more appropriate and lower cost than a reverse air unit for 

this size and application. That arrangement is addressed above. 

m. Fabric Filter (Reverse air type) - Covered in item l above. 

n. DSI high and low sulfur coal - This is essentially the same as item e above 

and is not effective upstream of a hot side ESP that is close coupled to the 

boiler outlet. 

o. Wet FGD high and low sulfur coal - This is essentially the same as item h 

above. 
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H. Conclusions Relative to SO2 and NOx Controls for Boilers 1 and 2 

Appropriate control options were evaluated in this high level analysis and those are discussed 

above. Use of the current coal sulfur specification (2.5% S/3.96 lb/MMBtu) already provides a 

level of reduction compared to the allowable level. It appears that a sulfur level in the 1.5% range 

could be viable for long term utilization if progress toward the glide path requires it, but significant 

investigation and testing would need to be conducted to ensure the facility can comply with the 

yet-unspecified performance requirements of Subpart DDDDD Boiler MACT regulation. 

Installation of spray dry absorbers with downstream baghouses or sodium wet scrubbers both 

show a high incremental cost per ton of SO2 removed compared to use of lower sulfur coal alone. 

Those high incremental costs are not considered to be justifiable. For example, EPA has stated 

that CAIR for utility boilers is better than BART. The CAIR rulemaking established SO2 and NOx

emissions reduction levels at points that were considered highly cost effective. The marginal cost 

curves for SO2 and NOx abatement from the CAIR docket (letter from EPA Clean Air Markets 

Division to the Docket, Analysis of the Marginal Cost of SO2 and NOx Reductions dated January 

28, 2004) are shown below. 

Figure 1 

CAIR SO2 cap 

2.5 MM Tons 
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Figure 2 

CAIR NOx cap 

1.30 MM Tons 

As indicated in the charts, the CAIR SO2 and NOx caps (lines added) provided emissions 

reductions at marginal costs of less than $1,800 per ton of both SO2 and NOx. Therefore, 

reasonable incremental cost effectiveness for smaller emission sources under the RHR should 

not exceed those figures. 

NOx reductions should be evaluated relative to visibility at Breton, and if they have a significant 

impact, retrofit of LNB to the boilers could be considered as an additional action. MDEQ should 

advise if modeling of either SO2 or NOx emissions reductions is needed.