# 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 Re gional Haze Rule

Dear Mr. Bickerstaff:

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

letter from Ms. Michelle R oot of your staff.

If you have any questions or need addition al 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 # 94461



# Regional Haze Rule Information

DuPont DeLisle Plant

Prepared by

John C. deRuyter Principal Consultant Energy Engineering DuPont Engineering & Research Technology Wilmington, Delaware

November 30, 2007Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 2

A. Background

MDEQ has requested information from the DuPont DeLisle Plant relative to potential SO 2 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 consi deration of addressing Reasonable Progress for

Class I Areas such as Breton National Wildlif e Refuge requires consideration of potential emissions reductions from non-BART eligible source s. 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 a ffected sources.” Based on the proximity to Breton and the facility’s SO 2 emissions, emissions cont rols 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 d oes 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 mode ling. 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 im pacts. 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 SO 2 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 es timated to be at least 20 years providing adequate routine maintenance and proper operation are practic ed. 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 w ould eliminate the need for the two coal fired boilers, but if that did occur, th e overall life of the uni ts would be reduced.

Each of the other factors are address ed for the evaluated options below.

1. Baseline Case Using Coal with SO 2 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 t he current coal, but emissions are reduced from the permitted level.

3. Burn Lower Sulfur CoalRegional Haze Rule Information – DuPont Delisle Plant November 30, 2007 3

Coal could be purchased with lower inherent su lfur 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 specif ications (including both chorine and mercury s pecifications) 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 possibl e 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 practi cal sulfur level is believed to be about 1.5%. However, actual performance and options woul d need to be thoroughly evaluated and test burns accomplished in order to firmly establish capability.

4. Install SO 2 Scrubbers and Use Coal with Lower Sulfur Content

The most practical types of SO 2 scrubbers that would be applicable to boilers of this size are spray dry absorbers with a downstream baghouse (f abric 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 scrubbe rs use higher cost reagents than limestone wet scrubbers typically used in electric utility syst ems. However, the cost of the limestone wet scrubber systems for smaller units is not justifi ed compared to the other options. Since the spray dryer and sodium wet scrubber reagents have a signi ficant cost, it is most appropriate to utilize

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

and 1.05% S. With a downstream scrubber of ei ther 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 SO 2 scrubbing. As part of the evaluati on, 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 boile r). 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 consist ently 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.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 4

C. SO 2 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 SO 2 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. SO 2 reductions vs Baseline (4.8 Lb/MMBtu) would be 2059 TPY with resultant incremental cost of $358/ton SO 2 removed. If compared to the current coal spec limit (3.96 lb/MMBtu), SO 2 reduction would be 998 TPY with an incremental cost effectiveness vs Baseline of $738/ton SO 2 removed.

2. Coal 2

Coal 2 is assumed to be coal with 1.5% S (2.38 lb/MMBtu SO 2 per AP-42 using 12,000 Btu/lb AsReceived HHV). Annual costs would increase approximately $1.05MM per year for increased coal purchase price. SO 2 reductions vs Baseline (4.8 Lb/MMBtu) would be 3057 TPY with

resultant incremental cost effectiveness of $344/ton SO 2 removed. If compared to the current coal spec limit (3.96 lb/MMBtu), SO 2 reduction would be 1996 TPY with an incremental cost effectiveness vs current coal of $527/ton SO 2 removed.

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

resultant incremental cost effect iveness vs Coal 1 of $316/ton SO 2

.

3. Coal 3

Coal 3 is assumed to be coal with 1.05% S (1.66 lb/MMBtu SO 2 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. SO 2 reductions vs Baseline (4.8 Lb/MMBtu) would be 3958 TPY with

resultant incremental cost effectiveness of $399/ton SO 2 removed. If compared to the current coal spec limit (3.96 lb/MMBtu), SO 2 reduction would be 2899 TPY with an incremental cost effectiveness vs current coal of $545/ton SO 2 removed.

Additional incremental SO 2 emissions reductions for Coal 3 over Coal 1 would be 1899 TPY with

a resultant incremental cost effe ctiveness vs Coal 1 of $443/ton SO 2

.

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

resultant incremental cost effect iveness vs Coal 2 of $584/ton SO 2

.

4. Spray Dry Absorber Using Coal 3

Application of a spray dry absorber with downstream baghouse is assumed to provide 85% SO 2 reduction. While it is possible to achieve highe r 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 insta llation period incremental gas cost. Overall SO 2 reduction vs Coal 3 firing alone would be 1790 TPY with an incremental cost effectiveness of $6054/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 2691 TPY vs use of Coal 2 firing alone and an incremental cost effectiveness of $4222/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 3689 TPY vs use of Coal 1 firing alone and an incremental cost effectiveness of $3165/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 5748 TPY vs Baseline SO 2 emissions of 4.8 lb/MMBtu and an increm ental cost effectiveness of $2160/ton SO 2 removed.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 5

However, this is not a viable comparison since cu rrent 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 SO 2 emissions reduction of 4687 TPY vs current coal spec equivalent SO 2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of $2649/ton SO 2 removed.

5. Sodium Wet Scrubber Using Coal 3

Application of a sodium wet scrubbe r is assumed to provide 95% SO 2 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 SO 2 reduction vs Coal 3 firing alone would be 2000 TPY with an incremental cost effectiveness of $4184/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 2901 TPY vs use of Coal 2 firing alone and an incremental cost effectiveness of $3066/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 3899 TPY vs use of Coal 1 firing alone and an incremental cost effectiveness of $2362/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 5958 TPY vs Baseline SO 2 emissions of 4.8 lb/MMBtu and an increm ental cost effectiveness of $1670/ton SO 2 removed. However, this is not a viable comparison since cu rrent 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 SO 2 emissions reduction of 4897 TPY vs current coal spec equivalent SO 2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of $2031/ton SO 2 removed.

6. Spray Dry Absorber Using Coal 2

Application of a spray dry absorber with downstream baghouse is assumed to provide 85% SO 2 reduction. While it is possible to achieve highe r 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 insta llation period incremental gas cost. Overall SO 2 reduction vs Coal 2 firing alone would be 2556 TPY with an incremental cost effectiveness of $4231/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 1654 TPY vs use of Coal 3 firing alone and an incremental cost effectiveness of $6217/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 3554 TPY vs use of Coal 1 firing alone and an incremental cost effectiveness of $3131/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 5613 TPY vs Baseline SO 2 emissions of 4.8 lb/MMBtu and an increm ental cost effectiveness of $2114/ton SO 2 removed. However, this is not a viable comparison since cu rrent 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 SO 2 emissions reduction of 4552 TPY vs current coal spec equivalent SO 2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of $2607/ton SO 2 removed.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 6

7. Sodium Wet Scrubber Using Coal 2

Application of a sodium wet scrubbe r is assumed to provide 95% SO 2 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 SO 2 reduction vs Coal 2 firing alone would be 2856 TPY with an incremental cost effectiveness of $2924/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 1955 TPY vs use of Coal 3 firing alone and an incremental cost effectiveness of $4002/ton SO 2 removed.

Use of this option would provide a total SO 2 emissions reduction of 3854 TPY vs use of Coal 1 firing alone and an incremental cost effectiveness of $2249/ton SO 2 removed.

Use of this option would provide a total SO 2 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 cu rrent 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 SO 2 emissions reduction of 4852 TPY vs current coal spec equivalent SO 2 emissions of 3.96 lb/MMBtu and an incremental cost effectiveness of $1938/ton SO 2 removed.

8. LNB Retrofit

Uncontrolled NO

x 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 burn ers 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 slaggi ng conditions, it is likely that a NOx reduction

of 40% could be achievable with retrofit installati on of LNB alone. Based on boiler capacity of 209 MMBtu/hr and an annual capacity factor of 69%, total NO

x 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 increm ental additional natural gas cost for 4 weeks of downtime per boiler results in a tota l cost effectiveness of $1204/ton NO

x 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 SO 2 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 NO

x emissions of 1418 TPY; that should be 1608 TPY bas ed 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 SO 2 and NO

x 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/Proje cted 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%,Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 7

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 NO

x and the total SO 2 +NO

x Q/d, it is recognized that modeling would be require d in order to determine the visi bility impact on Breton from NOx

reductions vs SO 2 reductions. As indicated by MDEQ, SO 2 emissions are the primary contributor to visibility problems at Breton. The NO

x 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 fu ture planning period in response to CAIR and BART will put a significant strain on resource ava ilability 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. Inst allation of LNB could probably be provided around 2011 at the earliest. However, since there is a si gnificant cost involved with LNB installation, it appears reasonable to delay that installation to co incide 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 per formance of the hot side ESP and resultant emissions and opacity impact need to be as sessed. 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 quantific ation 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 as h-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 dispos al are included within the estimated O&M cost estimates. As indicated above, the additional wa ste 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 transp ort, 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

SO 2 , NO

x , CO 2 , and other emissions from the electric utility generators providing that power, which could in fact, be units that themselves impact Breton with their SO 2 and NO

x emissions. Water would also be consumed for slurry preparation.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 8

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 fo r that waste stream directly, but some form of neutralization and oxidation would be required prio r to transfer to the waste treatment system. Costs for that disposal are included within t he estimated O&M cost estimates. Additional purchased electricity would be required for operat ion of the scrubber, including, for example, liquid pumping power and increased fan power to compensate for increased flue gas pressure drop. Increased purchased electricity wo uld result in increased emissions of SO 2 , NO

x , CO 2 , and

other emissions from the electric utility generators providing that po wer, which could in fact, be units that themselves impact Breton with their SO 2 and NO

x 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 di sposal of flyash in that beneficial reuse might not be possible, and landfill disposal might be the onl y 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 BAR T sources. The actual and potential emission rates also do not match those provided in the a ttachment and explained above. The difference in actual emissions might be due to actual coal q uality 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 cont rols for the eligible units at the DeLisle facility. As indicated above, none of the units at t he 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 t he 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 a ll sources, the cont rol 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 co mments relative to applicability to those units apply:

a. SNCR - Use of SNCR was discussed above- the short furnace height and lack of appropriate temperature z ones severely limit applicability.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 9

b. LNB - Use of LNB is considered feasible and is addressed above.

c. SCR - Use of SCR was discussed abov e- there would be a very high retrofit cost due to the likely need to replac e 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 requir e 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 ex ecuted to upgrade the existing hot side ESPs on the subject boilers, and that included new discharge electrodes and collecting plates, power supplies, r appers, and controls. This rebuild included an integrated control system th at provides more optimum control.

j. Venturi scrubber - That is ess entially 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 utiliz ed, 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.Regional Haze Rule Information – DuPont Delisle Plant November 30, 2007 10

H. Conclusions Relative to SO 2 and NO

x 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 specific ation (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 to ward 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 SO 2 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 SO 2 and NO

x emissions reduction levels at points that were cons idered highly cost effective. The marginal cost

curves for SO 2 and NO

x abatement from the CAIR docket (letter from EPA Clean Air Markets Division to the Docket, Analysis of the Marginal Cost of SO 2 and NO

x Reductions dated January 28, 2004) are shown below.

Figure 1

CAIR SO2 cap

2.5 MM TonsRegional Haze Rule Information – DuPont Delisle Plant November 30, 2007 11

Figure 2

CAIR NOx cap

1.30 MM Tons

As indicated in the charts, the CAIR SO 2 and NO

x caps (lines added) provided emissions reductions at marginal costs of less than $1,800 per ton of both SO 2 and NO

x . Therefore,

reasonable incremental cost effectiveness for smaller emission sources under the RHR should not exceed those figures.

NOx reductions should be evaluated relative to visi bility 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 SO 2 or NO

x emissions reductions is needed.