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Golder Associates Inc.

6026 NW 1st Place

Gainesville, FL 32607 USA

Tel: (352) 336-5600 Fax: (352) 336-6603 www.golder.com

Golder Associates: Operations in Africa, Asia, Australasia, Europe, North America and South America

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation

July 15, 2011 113-87508

Via Electronic Delivery

a-and-r docket@epa.gov

Air and Radiation Docket and Information Center

U.S. Environmental Protection Agency

Docket ID No. EPA-HQ-OAR-2002-0058

RE: FLORIDA SUGAR INDUSTRY’S ADDITIONAL INFORMATION IN SUPPORT OF 

RECONSIDERATION AND AMENDMENT OF NESHAP FOR INDUSTRIAL BOILERS

DOCKET ID NO. EPA-HQ-OAR-2002-0058

On behalf of the Florida Sugar Industry (“FSI”),1 Golder Associates (“Golder”)2is hereby submitting 

additional information for the U.S. Environmental Protection Agency (“EPA”) to consider as EPA moves 

forward with its reconsideration of the “National Emission Standards for Hazardous Air Pollutants for 

Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters” (“Final Boiler 

Rule”).3 Specifically, the FSI is submitting the additional information in this letter, as well as the updated 

emission data and analyses contained in the attached report, which is entitled “Updated MACT Floor 

Analysis for PM and TSM” (Golder 2011). This letter and the attached report are being submitted by the 

FSI in accordance with EPA’s request on May 18, 2011 for additional information concerning the Final 

Boiler Rule. 

The FSI has actively participated in the EPA rulemaking process for the Final Boiler Rule since the mid1990s. The FSI is grateful that the EPA has addressed some of the major concerns that the FSI raised in 

its prior comments to EPA. However, the FSI believes the Final Boiler Rule still contains several 

provisions that should be reconsidered and amended because the provisions are unnecessarily 

burdensome, they are not supported by the relevant facts, and they are not in compliance with the 

applicable law. Accordingly, on May 12, 2011, the FSI filed a petition for administrative reconsideration 

and amendment of the Final Boiler Rule.

In its petition and in this letter, the FSI respectfully requests EPA to reconsider and grant relief concerning 

the following issues:

1. EPA should set the emission limits for particulate matter (“PM”) for the hybrid suspension 

grate (“HSG”) subcategory based solely on the performance of the boilers in this 

subcategory. EPA should not set PM emission limits for HSG boilers (i.e., bagasse 

boilers) based on the performance of coal-fired boilers.

2. The PM emission limit for new HSG boilers is unachievable and inconsistent with the 

Clean Air Act (“CAA”). The CAA requires EPA to set emission limits for new boilers 

based on the performance of the best similar unit, but the FSI is not aware of any 

 

1

The Florida Sugar Industry is comprised of the Sugar Cane Growers Cooperative, the Osceola Farms Company, 

and U.S. Sugar Company. The FSI is joined in this petition by the Rio Grande Valley Sugar Growers of Texas and 

Hawaiian Commercial and Sugar Company of Hawaii. These companies process sugarcane to produce sugar and 

other products.

2 Golder Associates Inc. is an international firm of engineers and environmental consultants.

3

The Final Boiler Rule was published in the Federal Register (“F.R.”) on March 21, 2011. 76 F.R. 15608.
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bagasse-fired boiler in the world that is achieving the PM emission limit that EPA selected 

for new HSG boilers.

3. In the HSG subcategory, EPA should establish an emission limit for Total Select Metals 

(“TSM”) as an alternative, optional emission limit for PM. Although PM emissions from 

some of the FSI’s boilers may be high, emissions of metallic hazardous air pollutants 

(“HAPs”) emitted by bagasse boilers are low because bagasse contains low levels of 

metallic HAP. An alternative standard, based on the TSM emissions from bagasse 

boilers, would provide relief for the FSI while simultaneously protecting human health 

from metallic HAP emissions.

4. Annual stack tests, not continuous emissions monitoring systems (“CEMS”), should be 

used to demonstrate compliance with the PM emission limits for HSG boilers. There are 

no PM CEMS on any bagasse boilers and EPA did not use CEMS data when setting the 

PM emission limit for HSG boilers. Consequently, EPA does not have an adequate 

factual basis to support its PM emissions limit for HSG boilers, if compliance is to be 

determined with a CEMS.

5. EPA should establish a work practice, rather than an emission limit, for the control of 

dioxins and furans (“D/F”) emitted from HSG boilers. EPA did not have actual D/F 

emissions data from bagasse-fired boilers when setting the D/F emission limits for HSG 

boilers. Moreover, little is known about the formation of D/F in the boiler and downstream 

of the boiler, the variability of emissions, and the specific control methods. Since it is not 

feasible for EPA to establish an appropriate D/F emission limit for HSG boilers, EPA 

should establish a work practice standard.

6. Malfunctions should be excluded when determining compliance with the emission limits 

for HSG boilers, consistent with current EPA practice. Regulated sources should not be 

required to undergo the burdensome process set forth in the Final Boiler Rule in order to 

prove an affirmative defense.

Each of these issues is discussed in more detail in the following sections of this letter.

The FSI will incur very significant costs to comply with the Final Boiler Rule and most of these costs will 

be paid to comply with the requirements for PM. The PM emission limits in the Final Boiler Rule will 

compel the FSI to install an electrostatic precipitator (“ESP”) on virtually every existing boiler. Each ESP 

will cost at least $3 million to $5 million. These expenses are unwarranted because the PM emissions 

from bagasse boilers are low in metallic HAP. The Final Boiler Rule has been promulgated by EPA to 

control HAP emissions, but the majority of the costs incurred by the FSI to comply with the PM limit in the 

Final Boiler Rule will have little or no meaningful impact on HAP emissions. These facts warrant EPA’s 

reconsideration of the provisions in the Final Boiler Rule that apply to bagasse boilers in the HSG 

subcategory.

FSI’s Primary Issues Concerning the Final Boiler Rule for Major Sources

Sections 1-6, below, describe the FSI’s primary concerns about the Final Boiler Rule promulgated on 

March 21, 2011. Additional information is provided for EPA’s reconsideration.

1. EPA Should Establish PM Emission Limits for Boilers in the Hybrid Suspension Grate 

Subcategory Based on the Performance of Other Boilers in the Same Subcategory
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In the Proposed Rule,4EPA set emission limits for particulate matter (“PM”) because EPA concluded PM 

is a suitable surrogate for those metals, other than mercury (“Hg”), that are hazardous air pollutants 

(“HAPs”).5 When setting the PM emission limits for new boilers, EPA categorized all of the affected 

boilers into five different subcategories, based upon the type of fuel that is used in the boiler. EPA 

proposed different PM emission limits for each subcategory. Accordingly, a PM emission limit was 

proposed for new biomass-fired boilers [0.008 pound per million British thermal units (lb/MMBtu) of heat 

input] and a different PM emission limit was proposed for new coal-fired boilers (0.001 lb/MMBtu of heat 

input).

EPA’s decision to propose different PM emission limits for the biomass subcategory and the coal 

subcategory was based on the following rationale:

For the fuel-dependent HAP (metals, mercury, acid gases), we identified five basic unit types as 

subcategories. These are the following: (1) Units designed to burn coal, (2) units designed to 

burn biomass, (3) units designed to burn liquid fuel, (4) units designed to burn natural gas/refinery 

gas, and (5) units designed to burn other process gases. Within the basic unit types there are 

different designs and combustion systems that, while having a minor effect on fuel-related HAP 

emissions, have a much larger effect on organic HAP emissions. Therefore, we decided to 

further subcategorize based on these different unit designs but only in proposing standards for 

organic HAP emissions.

75 F.R. at 32017.

In the Final Boiler Rule, EPA did not establish a separate PM emission limit for biomass-fired boilers. 

Instead, EPA placed biomass-fired boilers in the same subcategory with coal-fired boilers and other 

biomass-fired boilers and then promulgated one PM emission limit that applies to all solid fuel-fired 

boilers. EPA explained its action as follows:

In the proposed rule, for the fuel-dependent HAP (metals, Hg, acid gases), we identified the 

following five basic unit types as subcategories: (1) Units designed to burn coal, (2) units 

designed to burn biomass, (3) units designed to burn liquid fuel, (4) units designed to burn natural 

gas/refinery gas, and (5) units designed to burn other process gases. In this final rule, for fueldependent HAP, we combined the subcategories for units designed to combust coal and biomass 

into a subcategory for units designed to burn solid fuels.6

76 F.R. 15617. 

The FSI objects to EPA’s decision to combine biomass-fired boilers and coal-fired boilers when setting 

emission limits for PM. Since EPA did not give notice in the Proposed Rule that EPA intended to use this 

approach in the Final Boiler Rule, the FSI was unable to present its objections to EPA’s approach and the 

resultant emission limit. Because the PM emission limit is central to the purpose of the Final Boiler Rule, 

the FSI requests EPA to reconsider the PM emission limit for biomass boilers that fit within the 

subcategory of HSG boilers.

 

4

For the purposes of this letter, the “Proposed Rule” means the proposed rule that EPA published in the Federal 

Register on June 4, 2010, concerning industrial boilers that are major sources of hazardous air pollutants. See

“National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters” at 75 F.R. 32006. 

5

As discussed below, PM is a suitable surrogate for the non-Hg metallic emissions from other types of solid-fueled

boilers, but bagasse boilers generally have relatively low levels of metallic HAP emissions compared to boilers 

combusting other solid fuels, despite having elevated emissions of PM, and thus bagasse boilers would be unduly 

penalized in the absence of an alternative TSM limit.

6

All of the underlining in this document has been added for emphasis.
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The approach EPA used in the Final Boiler Rule is the exact opposite of the approach that the FSI 

recommended in its comments concerning the Proposed Rule. The FSI and other commenters requested 

EPA to set separate emission limits for each of the separate subcategories of biomass boilers, based on 

the different types of fuels and boilers used in each subcategory. EPA responded to the FSI’s comments 

by making the following statement in the preamble to the Final Boiler Rule:

EPA agrees that for combustion-related pollutants (used as a surrogate for organic HAP 

emissions), the design differences for hybrid suspension grate boilers (also referred to as 

combination suspension/grate boilers) are significant, and that combustion conditions in these 

types of units are not similar to those in dutch ovens or true suspension burners that combust 

fine, dry fuels. Therefore, EPA has added a hybrid suspension grate boiler subcategory for CO 

and dioxin/furan emissions. However, the differences discussed by the commenters with respect 

to PM are less indicative of the design of the boiler and more indicative of the types of air 

pollution controls that are used. In keeping with the subcategorization approach being used for 

this final rule, these units, and all other solid fuel units, will be included in a subcategory for units 

combusting solid fuels for PM, Hg, and HCl.

76 F.R. 15634. 

EPA correctly recognized that the emissions of two combustion-related pollutants [carbon monoxide (CO) 

and D/F] are significantly affected by the design of the HSG boilers used in the FSI’s sugar mills. Given 

the unique characteristics of bagasse and bagasse boilers, it was appropriate for EPA to create a 

separate subcategory for HSG boilers.

In the Final Boiler Rule, EPA did not create a separate PM emission limit for HSG boilers because EPA 

concluded that PM emissions are less a function of boiler design and more a function of air pollution 

controls. The FSI respectfully submits that EPA’s approach was mistaken, and EPA’s conclusion was 

flawed, because EPA did not adequately account for the impact that bagasse and the design of bagasse 

boilers have on PM emissions. The FSI strongly believes that PM emissions from an HSG boiler are 

significantly affected by the boiler’s design, as well as the boiler’s air pollution controls, because these 

boilers are designed and used to burn a fuel with a very high moisture content (48 to 55 percent), the fuel 

has a high degree of variability, and the integration of the boiler into the sugarcane milling process results 

in variable boiler operations and therefore variable emissions.

In general, PM emissions from a boiler are related to the boiler’s combustion efficiency and the ash 

content of the fuel. Boilers that burn a fuel with a high moisture content will typically emit higher amounts 

of uncontrolled PM out of the boiler because the boiler will have a lower combustion efficiency. Variability 

in the fuel also will cause the boiler to have higher levels of uncontrolled PM emissions. Boilers with 

higher CO emissions also typically have higher uncontrolled PM emissions. All of these general 

principles apply to and materially affect the PM emissions from a HSG bagasse boiler.

The FSI previously provided EPA with a substantial amount of information demonstrating that bagasse 

boilers have unique characteristics and emission profiles. Among other things, bagasse boilers are 

unique because:

 They burn a fuel that has a very high moisture content (48 to 55 percent).

 They require much higher excess air rates than other boilers.

 The high excess air rates aid in drying the fuel and promoting better turbulence, but the 

high excess air rates reduce the residence time in the combustion zone.

 The process of drying and burning the fuel in the boiler, combined with the high moisture 

content of the fuel, result in relatively low combustion temperatures in the boiler, in spite 

of the boiler’s high heat release rates.
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 The bagasse boilers burn a wet biomass at relatively low temperatures while using high 

excess air rates, which collectively produce higher uncontrolled CO and PM emissions 

than other biomass boilers.

 They have a lower combustion efficiency than coal-fired boilers or boilers designed to 

burn a drier biomass fuel and, thus, bagasse-fired boilers have higher uncontrolled PM 

emissions than coal-fired boilers or boilers that burn drier types of biomass.

Bagasse boilers tend to have higher uncontrolled PM emissions than other solid fuel boilers. Although 

the air pollution control technology applied after a bagasse boiler (e.g., an ESP) will affect PM emissions, 

a bagasse boiler will still have higher controlled PM emissions than other types of solid fuel boilers 

equipped with the same air pollution control technology because the uncontrolled PM emissions entering 

the air pollution control device from the bagasse boiler will be higher than the uncontrolled PM emissions 

from other boilers.

In light of these facts, EPA should set separate PM emission limits for the HSG boiler subcategory, based 

solely on the PM emissions data for boilers in this subcategory. This approach should be used to set the 

PM emission limits for both new sources and existing sources in this subcategory.

Separate PM emission limits for the HSG boiler subcategory are necessary to comply with the legal 

standards that are applicable to the Final Boiler Rule. Section 112(d)(3) of the CAA requires EPA to set 

the MACT floor for new units based on the performance of “similar sources.” EPA has defined similar 

sources in Title 40, Part 63.41 of the Code of Federal Regulations (40 CFR 63.41) to mean units that are 

“structurally similar in design and capacity” and have “comparable emissions.” EPA already has 

acknowledged that HSG bagasse boilers have distinctly different emissions characteristics with regard to 

combustion-related pollutants (CO and D/F). EPA also should acknowledge that HSG bagasse boilers 

have different emissions characteristics with regard to PM. HSG bagasse boilers are not similar to, and 

do not have comparable emissions to, coal-fired boilers. Therefore, the emissions data for coal-fired 

boilers should not be used to set the PM emission limits for HSG bagasse-fired boilers.

The FSI provided a MACT floor analysis to EPA during the public comment period for the Proposed Rule. 

To assist EPA with its reconsideration of the Final Boiler Rule, the FSI has prepared an updated MACT 

floor analysis concerning the PM emissions from existing HSG boilers. See Golder 2011 (attached). The 

FSI’s floor analysis is based on updated emissions data. The FSI’s floor analysis uses the same 

methodology that EPA used when EPA calculated the emission limits that were presented in the Final 

Boiler Rule. The FSI’s updated MACT floor analysis indicates that the appropriate PM emission limit for 

existing HSG boilers is 0.32 lb/MMBtu. 

2. The PM Emission Limits for New Hybrid Suspension Grate Boilers are Unachievable and 

Inconsistent with the CAA

In the Proposed Rule, EPA proposed a PM emission limit of 0.008 lb/MMBtu for new boilers in the 

biomass subcategory. Different PM limits were proposed for coal-fired boilers.

In the Final Boiler Rule, EPA promulgated a PM standard of 0.0011 lb/MMBtu for all new solid fuel boilers. 

EPA did not create a separate PM emission limit for new biomass-fired boilers or new HSG boilers. 

Unlike the Proposed Rule, the Final Boiler Rule did not contain separate PM emission limits for new 

boilers in different solid fuel subcategories.

The FSI objects to EPA’s decision to establish one PM emission limit for all new solid fuel boilers. The 

FSI’s objection is an appropriate topic for reconsideration because the EPA’s action was not a logical 

outgrowth of the position EPA took in the Proposed Rule.

It is not appropriate to place HSG bagasse-fired boilers in a subcategory with coal and other solid fuel-fired

boilers because they are not similar sources. Combining both types of boilers in one subcategory will result
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in a much lower PM limit for HSG bagasse boilers than would be obtained if the PM emission limit for HSG

bagasse boilers had been properly based on similar units (i.e., bagasse-fired HSG units). Indeed, the PM 

limit for biomass-fired boilers was lowered from 0.008 lb/MMBtu in the Proposed Rule to 0.0011 lb/MMBtu 

in the Final Boiler Rule.

It is not reasonable to expect a new HSG bagasse-fired boiler to meet the same PM emission limit as a 

new coal-fired boiler. Coal-fired boilers can use a fabric filter baghouse to control PM emissions, but HSG 

bagasse boilers cannot. Since the PM emission limit in the Final Boiler Rule for new solid fuel boilers was 

based on the use of fabric filter baghouse technology, it would be inappropriate (i.e., arbitrary and 

capricious) to apply the same PM emission limit to a HSG bagasse boiler that cannot use baghouse 

technology.

7

The Final Boiler Rule sets an extremely low PM limit for HSG bagasse-fired boilers, which is 

approximately 8 times more stringent than the limit in the Proposed Rule. This PM limit is of central 

relevance to the Final Boiler Rule because it establishes PM emission standards that cannot be achieved 

by new bagasse-fired boilers in the HSG subcategory.

The FSI is deeply concerned that new HSG boilers will not be able to comply with the applicable PM limit 

in the Final Boiler Rule. Under the CAA, the PM emission limits for new boilers must be based on the 

performance of the best operating similar unit in a subcategory, but the FSI is not aware of any HSG 

boiler in the world that is operating at the PM level established in the Final Boiler Rule. The FSI also is 

not aware of any vendor that will guarantee, for a bagasse-fired boiler, compliance with the new source 

PM emission limit contained in the Final Boiler Rule.

No bagasse boilers are equipped with fabric filter baghouses. Moreover, it is not feasible to use fabric 

filter baghouses on HSG (bagasse) boilers.

 Bagasse as produced and burned has a high moisture content (48 to 55 percent).

 Due to the moisture content of the fuel, the flue gas stream reaches near saturated 

conditions (normally 20 to 30 percent moisture content), which would lead to plugging 

and blinding of the bags in the baghouse.

 Bagasse fuel is about three times less dense than wood. The particle size range of 

bagasse is much greater than the range of wood particles fired in boilers. The particles 

are light, and many are long and stringy. Given these characteristics and the high excess 

air rates at which the boilers must operate, the potential exists for burning particles to be 

carried out of the furnace and thus create a fire hazard for a baghouse.

 There is no known operation of a fabric filter baghouse on a bagasse-fired boiler 

anywhere in the world. 

Since bagasse boilers burn a wet biomass at relatively low temperatures and high excess air rates, they 

produce higher CO and PM emissions compared to other biomass-fired boilers. The FSI’s revised MACT 

floor analyses for bagasse boilers (attached) indicates a PM limit of 0.022 lb/MMBtu is appropriate for 

new sources, based on extensive stack test data. However, the FSI’s floor analyses assumed stack tests 

would be used for determining compliance. The FSI cannot reasonably calculate an appropriate PM 

emission limit if compliance is determined by using a PM CEMS, especially given EPA’s treatment of 

malfunctions in the Final Boiler Rule (discussed below).

 

7

The requirement to use a PM CEMS compounds the problems associated with the PM emission limits for new 

bagasse-fired boilers. EPA’s use of stack test data to set a PM emission limit, combined with a PM CEMS to monitor 

performance, renders the PM limit even more stringent and compliance even more doubtful because the PM limit 

must be met on a continuous basis.
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Parenthetically, the establishment of artificially low PM emission limits for new sources creates a 

disincentive to companies that otherwise would consider investing in new HSG boilers as a compliance 

strategy. Further, an artificially low PM emission limit may make natural gas the only fuel option for those 

who wish to build new boilers, but most sugar mills are located in rural areas and do not have access to 

natural gas. Further, the economics of sugar mills depend on the use of the bagasse as fuel; natural gas 

and other fossil fuels are too expensive to be used as a sugar mill’s primary fuel.

EPA should set PM limits for new sources in the HSG subcategory, based upon the bagasse boiler data 

that were submitted to EPA and placed in the docket for the Final Boiler Rule, and based on the updated 

emissions data that are being submitted to EPA with this letter. The MACT floor analysis should not 

include units designed to burn coal or units which use pollution control technologies that are not 

applicable to the boilers in the HSG subcategory. As noted above, the FSI has developed an updated 

MACT floor analysis for new sources in the HSG subcategory. The FSI’s floor analysis uses the same 

methodology that EPA used when preparing the emission limits in the Final Boiler Rule, except that a 

99.9% UPL was used for setting the MACT floor limit for new sources.8 The FSI’s floor analysis 

demonstrates that the appropriate PM emission limit for new HSG boilers is 0.022 lb/MMBtu. 

3. EPA Should Establish an Emission Limit for Total Select Metals (TSM) as an Alternative to the 

PM Emission Limit for Bagasse Boilers

In the Proposed Rule, EPA set PM emission limits for existing and new solid fuel boilers as a surrogate 

for non-Hg metallic HAP. EPA elected to not set a TSM limit. EPA’s rationale was:

Most, if not all, non-mercury metallic HAP emitted from combustion sources will appear on the 

flue gas fly-ash. Therefore, the same control techniques that would be used to control the fly-ash 

PM will control non-mercury metallic HAP. PM was also chosen instead of specific metallic HAP 

because all fuels do not emit the same type and amount of metallic HAP but most generally emit 

PM that includes some amount and combination of metallic HAP. The use of PM as a surrogate 

will also eliminate the cost of performance testing to comply with numerous standards for 

individual non-mercury metals.

75 F.R. at 32018.

In the Final Boiler Rule, EPA promulgated a PM standard for all solid fuel boilers, using PM as a 

surrogate for non-Hg metallic HAP. In EPA’s responses to public comments concerning the Proposed 

Rule,9EPA presented the following rationale for its decision to use a PM standard in lieu of a TSM limit:

Although the vacated rule contained a TSM alternative standard, the rule also included a health 

based alternative to exclude manganese while complying with the TSM alternative limit. Unlike 

the vacated rule we are not finalizing health based alternatives and EPA determined a TSM 

alternative would not provide much additional flexibility to regulated sources.

The non-Hg metal HAP are very likely to be present in the particulate phase and will be captured 

along with the filterable PM in the primary PM control device. The partitioning of the metal HAPs 

is very complicated and can depend upon the fuel type, the form of the metals in the fuel, other 

constituents in the fuel and the time-temperature profile of the post-combustion environment. 

 

8

Parenthetically, the FSI does not agree with EPA’s methodology, which uses the 99% upper prediction level when 

setting the MACT floor for new sources. This conclusion is because only one unit is used to set the MACT floor for 

new sources, and thus a limited amount of data is used to determine the MACT floor.

9

See EPA’s Responses to Comments on National Emission Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, Volume 2 of 2, response to comment 

2941.1, comment excerpt number 23.
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EPA’s Office of Research & Development has conducted studies that showed good control of the 

non-Hg metal HAP followed good control of bulk PM (filterable) across the primary PM control 

device.

The FSI believes a TSM option would indeed provide additional flexibility to regulated sources, and this 

flexibility is truly needed to avoid unnecessary and potentially huge capital and operating costs for new air 

pollution control equipment.

EPA received numerous comments on the use of PM as a surrogate for non-Hg metallic HAP. Some 

commenters supported the use of PM, because they were concerned that low and perhaps unachievable 

TSM limits might result if a TSM limit were promulgated. Other commenters, including the FSI, strongly 

supported a TSM standard as an alternative to a PM standard because their fuel contains very low 

concentrations of TSM and generates low TSM emissions.

In the Final Boiler Rule, EPA created a subcategory for biomass-fired HSG boilers for the CO and D/F 

standards. For PM, EPA chose to group all solid fuel boilers together into a single subcategory. 

However, as EPA correctly noted in the preamble, the emissions of the non-Hg metallic HAPs can be 

quite different for different solid fuels because of the differences in the fuels being burned in the various 

types of boilers. Indeed, the TSM content of bagasse produced in Florida is approximately three (3) times 

lower than the TSM content of central Appalachian coal, when compared on a lb/MMBtu basis.10

Since EPA created a separate subcategory for HSG boilers and all of these boilers burn the same fuel, it 

is reasonable to develop a TSM limit for the HSG subcategory. Although the PM emissions from HSG 

boilers may be higher than some other boiler subcategories, the TSM emissions from HSG boilers are 

generally low. Therefore, it is appropriate to set a TSM standard as an alternative to the PM limit for HSG 

boilers, because the fuel characteristics and TSM emissions for these boilers are well documented in 

EPA’s docket for the Final Boiler Rule. It should not be difficult to set a TSM standard for HSG boilers 

because the FSI previously provided EPA with a MACT floor analysis for TSM and the FSI has provided 

an updated MACT floor analysis for TSM in the attached report. Without a TSM alternative, the FSI will 

be severely penalized, despite the already low emissions of non-mercury metals from the FSI’s boilers.

In EPA’s recently proposed Utility MACT Rule (40 CFR 63, Subpart UUUUU),11 EPA took the opposite 

approach from the one EPA adopted in the Final Boiler Rule. For the Utility MACT Rule, EPA proposed 

not only TSM limits, but also individual HAP metal limits as alternatives to the PM limit. EPA’s rationale 

for proposing these alternative limits was as follows:

Some sources have expressed a preference for individual non-Hg metal HAP emission limitations 

rather than the use of PM as a surrogate. Thus, EPA has analyzed the data for that purpose and 

we are proposing both alternate individual HAP metal limitations and total HAP metal limitations 

for all subcategories except liquid oil fired EGUs. These limitations provide equivalent control of 

metal HAP as the proposed PM limitations.

76 F.R. at 25059 (May 3, 2011). The approach adopted by EPA in the Utility MACT Rule is the same 

approach that EPA should follow with HSG boilers.

The cost of performance testing to comply with a TSM standard will not be much greater than the cost of 

complying with a PM standard. The cost of performing a Method 5 test for PM is approximately $6,000. 

The cost of performing a Method 29 test for 10 metals (antimony, arsenic, beryllium, cadmium, chromium, 

cobalt, lead, manganese, nickel, and selenium) is approximately $11,000. This cost differential is 

 

10 The FSI submitted extensive bagasse fuel analysis data to EPA as part of the Combustion Survey in 2008.

11 76 F.R. 24976 et seq. (May 3, 2011).
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insignificant when compared to the overall cost of complying with the Final Boiler Rule, which will require 

millions of dollars in expenditures for additional air pollution control equipment on virtually all of the FSI’s 

existing boilers, if not the total replacement of the boilers.

The TSM alternative is of central relevance to the Final Boiler Rule because this alternative will create a 

much more appropriate and less costly approach to controlling non-Hg metallic HAP emissions from HSG 

boilers. Under the Final Boiler Rule, HSG boilers with comparatively low emissions of HAP metals will 

have to make significant investments for the purpose of controlling PM emissions. Although the Final 

Boiler Rule has been promulgated for the purpose of reducing HAP emissions, the FSI’s investments for 

PM control (e.g., ESP) will have little or no impact on HAP emissions.

EPA should set both TSM and PM limits for existing and new boilers in the HSG subcategory. Affected 

sources should be allowed to choose the alternative they wish to use when demonstrating compliance –

i.e., either PM or TSM, at the permittee’s option. The attached MACT floor analysis for HSG bagasse 

boilers demonstrates that the appropriate TSM limits for this subcategory are as follows:

 Existing Source MACT - 4.4x10-4 lb/MMBtu

 New Source MACT - 4.4x10-4 lb/MMBtu

4. Stack Tests, not PM CEMS, Should be Used to Demonstrate Compliance with the PM Emission 

Limit for HSG Boilers

In the Proposed Rule, EPA required the use of a PM CEMS for demonstrating compliance with the PM 

limit for any boiler that has a heat input of 250 million British thermal units per hour (MMBtu/hr) or greater 

and fires coal, biomass, or residual oil. The Final Boiler Rule adopts this requirement, without change.

There are no HSG bagasse boilers with PM CEMS. Consequently, EPA had no PM CEMS data on which 

to base a MACT floor emission limit for HSG boilers. The PM emission limits for HSG boilers (and all 

solid-fuel boilers) are based on compliance stack tests (i.e., the average of three runs). Therefore, the 

PM emission limits set for HSG boilers do not properly reflect the emission rates and variability inherent in 

long-term operations of such boilers. PM emissions from HSG boilers with PM CEMS would likely be 

higher than reflected during a 3-run test, due to the variability in long-term operation of the boiler, and 

because the data collected during malfunctions with a CEMS cannot be excluded when determining 

whether the boiler is in compliance with the PM emission limit, unless an affirmative defense is proven.

In the preamble to the Final Boiler Rule, EPA explained that it rejected the use of a CO CEMS for 

compliance purposes because EPA did not have sufficient CO CEMS data to use when setting CO 

emission limits:

“While many comments were received opposing EPA’s proposal to set limits based on stack test 

data, EPA cannot set limits based on CEMs data because the available CEMS data are

insufficient to set emission limits that are reflective of the best performing 12 percent of sources in 

the various subcategories......In this instance, the alternative that EPA selected was to base the 

limits on 3-run stack test data.......The CO emission limits in today’s rule must be met through the 

use of a stack test during the initial and annual compliance tests, and parametric monitoring is 

required to demonstrate continuous compliance.

76 FR 15646. 

In setting the CO limits in the Final Boiler Rule, EPA used the 99.9-percent upper prediction limit (UPL) as 

a way of accounting for the variability of CO emissions. Also, EPA only required an annual CO stack test 

and continuous oxygen (O2) monitor, in lieu of a CO CEMS.
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The same logic should be applied in regards to PM CEMS for HSG boilers. Since EPA used stack test 

data to set the PM emissions limits for HSG boilers, it is not appropriate for EPA to require the use of a 

PM CEMS when determining compliance with the PM emission limits. Instead, EPA should use an 

annual stack test and surrogate parameters to monitor the performance of a boiler’s PM control systems.

There is considerable variability in the CO emissions from HSG boilers, even when the boilers are 

operating at normal maximum load. The large and rapid fluctuations in the CO emissions from bagasse 

boilers are well documented in the FSI’s prior submittals to EPA (e.g., the FSI’s MACT floor calculations 

for bagasse boilers), which are part of the EPA docket for the Final Boiler Rule. EPA has acknowledged 

this variability by creating a separate subcategory for HSG boilers and establishing separate CO emission 

limits for such boilers. Coincident with the significant variability in CO emissions, one would expect an 

associated variability in PM emissions from HSG boilers. This variability is not likely to be reflected in the 

3-run compliance test data that EPA used to set the MACT floor for HSG boilers.

A major drawback to using a PM CEMS for HSG boilers is the need for a reliable F-Factor to use when 

converting the PM CEMS data to the units of measure used in the applicable PM standard (i.e., lb/MMBtu). 

The difficulty of developing a reliable F-Factor was confirmed in a study the FSI prepared for the Florida 

Department of Environmental Protection many years ago (see attached report). This study demonstrated 

that F-Factors for wood are not applicable to bagasse and, further, no single F-factor is representative of 

bagasse firing. These conclusions reflect the inherent variability of bagasse fuel and bagasse boiler 

operations.

There are several different sampling strategies employed with PM CEMS. One of the common ones is 

“forward scatter”. Problems can occur with forward scatter because changes in the PM size distribution 

can cause erroneous readings with the CEMS. This problem is especially likely to occur if the CEMS is 

calibrated while measuring one PM size distribution, but a different PM size distribution is actually 

experienced in the stack as a result of fluctuations in the process or fuel. Given the routine fluctuations 

that occur with the operations of bagasse boilers and the variations in the bagasse fuel, it seems likely 

that a PM CEMS will produce inaccurate readings when used on an HSG boiler.

Whether to require a PM CEMS or not is of central relevance to the Final Boiler Rule because it will 

determine the method of demonstrating compliance. Using a PM CEMS to comply with an emission limit 

that is based on the average of three stack test runs will almost ensure that the PM emission limit for HSG 

boilers will be exceeded. This problem is exacerbated by the concerns over the accuracy of PM CEMS.

Adequate surrogate parameters are available for ensuring that PM emissions from HSG boilers are 

maintained below the PM emission limit. The Final Boiler Rule requires a variety of surrogate parameters 

for different types of air pollution control equipment (e.g., baghouses, ESPs, and wet scrubbers) for 

boilers with heat input capacities less than 250 MMBtu/hr. Surrogate parameters have been used for 

decades to monitor the performance of PM control devices. Such parameters are routinely used in 

compliance assurance monitoring (“CAM”) plans implemented under the Title V air operating permit 

program.

The FSI requests that the Final Boiler Rule be revised to eliminate the requirement for PM CEMS for HSG 

boilers. Instead, annual stack tests and surrogate monitoring parameters should be used to ensure 

compliance with the PM emission limits for HSG boilers.

5. EPA Should Establish a Work Practice, Rather than an Emission Limit, for the Control of 

Dioxins and Furans

In the Proposed Rule, EPA set emission limits for D/F for several types of boilers. At the time of proposal, 

however, EPA had not established a subcategory for HSG boilers. Accordingly, the Proposed Rule did 

not contain a D/F emission limit for the HSG subcategory and there was no opportunity to comment upon 

a D/F emissions limit for the HSG subcategory.
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In the Final Boiler Rule, EPA promulgated a D/F standard for HSG boilers. This standard appears to 

have been set based upon the D/F emission limit for the suspension burner/dutch oven subcategory, but 

there is almost no data to support the emission limit for the suspension burner/dutch oven subcategory. 

The D/F emission limit for the suspension burner/dutch oven subcategory was based on the D/F data 

from a single boiler and only three (3) consecutive test runs.

Setting a D/F limit on the basis of three test runs from a single boiler is not scientifically valid – i.e., it does 

not reflect the variability of the boilers in the suspension burner/dutch oven subcategory, much less the 

variability of the bagasse boilers in the HSG subcategory. Currently, there is a lack of understanding of 

the exact mechanisms of D/F formation in and downstream of HSG boilers, as well as of the appropriate 

control techniques for HSG boilers. D/F emissions appear to be highly variable from source to source, as 

well as within a single boiler. Therefore, EPA’s methodology could easily result in a limit that is 

unachievable for both suspension burner/dutch oven and HSG boilers.

Since EPA created a separate subcategory for biomass-fired HSG boilers, but does not have D/F data for 

the boilers in the HSG subcategory, EPA should replace the D/F standard for HSG boilers with a work 

practice standard. Work practices are expressly authorized by the CAA in cases where, as here, it is not 

feasible to establish an emission limit:

“if it is not feasible in the judgment of the Administrator to prescribe or enforce an emission 

standard for control of a hazardous air pollutant or pollutants, the Administrator may, in lieu 

thereof, promulgate a design, equipment, work practice, or operational standard, or combination 

thereof, which in the Administrator’s judgment is consistent with the provisions of subsection (d) 

or (f) of this section.”

42 U.S.C. § 7412(h). In this case, adequate data do not exist to promulgate an emission limit for the D/F 

emissions from HSG boilers. In the absence of D/F test data, EPA should promulgate a work practice 

standard to ensure the proper operation of the boilers, thus ensuring consistency with the provisions of 

Section 112 of the CAA.

Prescribing work practice standards for D/F, in lieu of potentially unachievable emission limits, will help 

eliminate the risk that some facilities would have to switch from bagasse (a clean renewable fuel) to 

natural gas or other fossil fuels in order to achieve compliance with EPA’s D/F standard. As a practical 

matter, however, fuel switching to fossil fuel would not be an option for most (if any) sugar mills.

In the Proposed Rule, EPA set work practice standards, rather than emission limits, for the D/F emissions 

from gas boilers and process heaters because the potential cost of installing air pollution control 

equipment to comply with a D/F emission limit would be prohibitively expensive. The same economic 

rationale could be used to justify the use of a work practice, rather than an emission limit, for the D/F 

emissions from HSG boilers.

For all of these reasons, FSI strongly believes the D/F emission limit for HSG boilers should be eliminated 

and a work practice standard established in its place. EPA has the statutory authority under the CAA to 

prescribe a work practice standard instead of a numeric emissions limit. A work practice standard 

requiring good combustion practices would ensure that D/F emissions from bagasse boilers are 

minimized, without subjecting the FSI to the risks associated with an emission limit that is not based on a 

robust set of test data from bagasse boilers.

Work practice standards for HSG boilers should focus on the maintenance of good combustion 

conditions. Potential work practice standards may include the following:

 Maintain compliance with the CO emission limit by complying with the 30-day rolling 

average O2 minimum limit

 Identify and implement good combustion practices (boiler-specific plan)
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 Prepare and implement an Operations and Maintenance Plan (boiler-specific plan)

 Perform a periodic tune-up of the boiler

 Conduct an annual maintenance inspection of the boiler

These work practices will promote good combustion and therefore minimize the formation of D/F.

6. Malfunctions Should be Excluded when Determining Compliance with the Emission Limits for 

Bagasse Boilers, without Undergoing the Burdensome Process Required to Prove an 

Affirmative Defense

The Final Boiler Rule excludes startup and shutdown events when determining compliance with the 

applicable emission limits. However, malfunction events are not excluded, unless the regulated source 

satisfies the requirements for proving an “affirmative defense” to enforcement. The preamble to the Final 

Boiler Rule explains the rationale for EPA’s decision, as follows:

Essentially, EPA has determined that malfunctions should not be viewed as a distinct operating 

mode and, therefore, any emissions that occur at such times do not need to be factored into 

development of CAA section 112(d) standards, which, once promulgated, apply at all times. 

In the event that a source fails to comply with the applicable CAA section 112(d) standards as a 

result of a malfunction event, EPA would determine an appropriate response based on, among 

other things, the good faith efforts of the source to minimize emissions during malfunction periods,

including preventative and corrective actions, as well as root cause analyses to ascertain and 

rectify excess emissions. EPA would also consider whether the source’s failure to comply with 

the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” 

and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 63.2 

(definition of malfunction). Finally, EPA recognizes that even equipment that is properly designed 

and maintained can sometimes fail and that such failure can sometimes cause an exceedance of 

the relevant emission standard. EPA is, therefore, adding to this final rule an affirmative defense, 

as requested by public comment, to civil penalties for exceedances of numerical emission limits 

that are caused by malfunctions.

76 F.R. 15642. The Final Boiler Rule establishes the following requirements, which must be satisfied by 

anyone wishing to assert an affirmative defense as a result of a malfunction:

In response to an action to enforce the emission limitations and operating limits set forth in 

§ 63.7500 you may assert an affirmative defense to a claim for civil penalties for exceeding such 

standards that are caused by malfunction, as defined at § 63.2. Appropriate penalties may be 

assessed, however, if you fail to meet your burden of proving all of the requirements in the 

affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.

(a) To establish the affirmative defense in any action to enforce such a limit, you must timely meet 

the notification requirements in paragraph (b) of this section, and must prove by a preponderance 

of evidence that:

(1) The excess emissions:

(i) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control 

and monitoring equipment, process equipment, or a process to operate in a normal or 

usual manner, and

(ii) Could not have been prevented through careful planning, proper design or better 

operation and maintenance practices; and

(iii) Did not stem from any activity or event that could have been foreseen and avoided, or 

planned for; and
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(iv) Were not part of a recurring pattern indicative of inadequate design, operation, or 

maintenance; and

(2) Repairs were made as expeditiously as possible when the applicable emission limitations 

were being exceeded. Off-shift and overtime labor were used, to the extent practicable to 

make these repairs; and

(3) The frequency, amount and duration of the excess emissions (including any bypass) were 

minimized to the maximum extent practicable during periods of such emissions; and

(4) If the excess emissions resulted from a bypass of control equipment or a process, then 

the bypass was unavoidable to prevent loss of life, personal injury, or severe property 

damage; and

(5) All possible steps were taken to minimize the impact of the excess emissions on ambient 

air quality, the environment and human health; and

(6) All emissions monitoring and control systems were kept in operation if at all possible, 

consistent with safety and good air pollution control practices; and

(7) All of the actions in response to the excess emissions were documented by properly 

signed, contemporaneous operating logs; and

(8) At all times, the facility was operated in a manner consistent with good practices for 

minimizing emissions; and

(9) A written root cause analysis has been prepared, the purpose of which is to determine, 

correct, and eliminate the primary causes of the malfunction and the excess emissions 

resulting from the malfunction event at issue. The analysis shall also specify, using best 

monitoring methods and engineering judgment, the amount of excess emissions that were 

the result of the malfunction.

40 CFR 63.7501. A source operator must submit a formal written report to the Administrator within 

45 days of the occurrence of each malfunction for which the emission limit was exceeded and for which 

the operator wishes to use the affirmative defense.

The FSI agrees with EPA that emissions associated with a malfunction should not be considered when 

determining whether a regulated source is in compliance with the applicable emission limits. However, 

the requirements for establishing an affirmative defense are too extensive and onerous. The obligation to 

“meet your burden of proving all of the requirements in the affirmative defense” is too rigorous to apply to 

each and every malfunction event that may occur, especially in the sugar industry. Consistent with other 

CAA regulations, such as the New Source Performance Standards (“NSPS”), malfunction events should 

automatically be excluded when evaluating compliance with the emission limits.

Consistent with EPA’s current and historical practices, a regulated source should have the ability to 

determine whether the definition of a malfunction in Section 63.2 has been met (i.e., “any sudden, 

infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, 

process equipment, or a process to operate in a normal or usual manner which causes, or has the 

potential to cause, the emission limitations in an applicable standard to be exceeded. Failures that are 

caused in part by poor maintenance or careless operation are not malfunctions.”). The permitting 

authority has the ability to challenge, if necessary, the determination made by the regulated source.

At a sugar mill, upset events occur in the milling process quite frequently. These upsets are caused by a 

number of factors, including the processing of a variable biomass feed material (sugarcane), weather and 

field conditions that affect the sugarcane quality, the changing varieties of sugarcane that are received at 

the mill, and the interconnected nature of the mills themselves. As a result of these factors, the mills 

experience frequent stops and starts, slowdowns, and other interruptions on a daily basis. These events 

are not the result of poor maintenance. Each sugar mill undergoes extensive maintenance on the entire 

facility during the sugarcane milling off-season. As discussed in the documents previously provided to 
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EPA, the boilers are inextricably tied to the milling process, because the bagasse fuel burned in the 

boilers typically is delivered directly from the mills, and also because the large quantities of steam used by 

the mills (to power the milling tandems) come directly from the boilers through a single steam header, 

which serves the entire mill and ties into 5 to 6 boilers. Given the interrelated operation of the mill and 

multiple boilers, the boilers experience daily and hourly fluctuations in their operations, which affect 

emissions. It would be extremely burdensome for a sugar mill operator to go through the process set 

forth in the Final Boiler Rule in order to prove an affirmative defense for every upset event that occurs in 

the mill and affects the boiler operations.

The FSI requests that EPA replace the “affirmative defense” requirements with the EPA’s historic 

requirements and general duty to minimize emissions. Instead of the onerous provisions contained in the 

Final Boiler Rule, malfunctions should be identified by the regulated source, reported to the regulatory 

agency, and excluded from the emission limits, unless the regulatory agency determines otherwise.

Additional Issues Concerning the Final Boiler Rule for Major Sources. 

1. Emissions Averaging Provisions

The FSI previously submitted timely comments regarding the emissions averaging provisions in the 

Proposed Rule. Section 63.7522 and the preamble to the Proposed Rule explain why it is appropriate to 

allow emissions averaging for PM, HCl, and Hg. Section 63.7522 was adopted in the Final Boiler Rule 

without change. This provision is applauded because it recognizes that a multi-boiler, multi-stack facility 

should be given the opportunity to achieve and maintain compliance with a facilitywide standard, based 

on a combination of all stack emissions, rather than by demanding compliance at each individual stack. 

However, EPA did not address the FSI’s concerns in the Final Boiler Rule, nor did it respond to the FSI’s 

comments.

Therefore, the FSI repeats its request that the emissions averaging option be extended to CO and D/F. 

The rational for allowing a facility to average these constituents is the same as the rationale used by EPA 

in the preamble to the Proposed Boiler Rule for the other controlled emissions: 

“We have concluded that a limited form of averaging could be implemented that would not lessen 

the stringency of the MACT floor limits and would provide flexibility in compliance, cost, and 

energy savings to owners and operators.” 

75 FR 32034.

The FSI also agrees that the total facility emissions on a pounds per million British thermal units 

(lb/MMBtu) basis from averaging should be no less stringent than if each unit achieved the MACT floor 

limits. The FSI merely requests that emissions averaging be allowed for CO and D/F, if EPA continues to 

require a D/F limit for HSG boilers, rather than the work practice standard that the FSI has requested. 

There is no basis for excluding CO and D/F from emissions averaging, because emissions of these 

pollutants are directly correlated with HAPs emissions, and emissions averaging would not allow overall 

facility HAPs emissions to increase. 

The FSI also requests that EPA remove the 10 percent “penalty” associated with the use of emissions 

averaging, and remove the requirement that emissions be capped at the value established 60 days after 

the promulgation of Final Boiler Rule, if a facility chooses to use the emissions averaging method. The 

averaging option is attractive and provides an incentive for a facility to engineer creative new control and 

equipment improvements. If the 10 percent penalty and cap are eliminated, the overall HAP emissions 

control will not be less, but compliance will be less costly.
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Emission averaging has been authorized by EPA for multi-emission point sources subject to the 

Hazardous Organic NESHAP (HON) rule in a commonly covered facility, such as a petroleum refinery or 

chemical plant. The HON rule differs materially in the type of facility and the scope of coverage within a 

facility. The Final Boiler Rule only applies to industrial boilers and process heaters. Boilers and process 

heaters typically do not have multiple pieces of equipment, vessels, and vents from which to choose 

optimization of emission control to achieve reductions to reach a facility wide emission limit. Boilers and 

process heaters have one emission point per unit and sometimes only one emission point for two or more 

units. Thus, the opportunities for emission reductions via related process equipment and vents do not 

exist. For these reasons, the 10 percent penalty for using the averaging method in the Final Boiler Rule is 

inappropriate.

The 10 percent penalty, the emissions cap, and the failure to extend the averaging option to all emission 

limited pollutants are disincentives for those multi-boiler facilities that might otherwise consider averaging. 

These disincentives also create more stringent standards for a subset of affected facilities. They

unnecessarily shrink the number of facilities that might be able to use emissions averaging and they add 

unnecessary capital and operating costs.

For the reasons set forth above, the FSI respectfully requests EPA to allow emissions averaging for CO 

and D/F.

2. Fuel Sampling Procedures

The FSI commented previously on the provision in the fuel sampling requirements that relate to conveyor 

belt operations (Section 63.7521(c)(1)(i) of the Final Boiler Rule). At many facilities it is not possible to 

stop the conveyor belt without severely disrupting operations of the boiler and the facility as a whole. 

Sugar mills have equipment and procedures to obtain grab samples of bagasse directly from the moving 

conveyor belt or as the bagasse is discharged from the mill. These options should be included in the 

Final Boiler Rule.

4. Exemptions from PSD and NSPS

Due to the requirements in the Final Boiler Rule, major modifications to FSI boilers are very likely. It also 

is likely that these modifications may increase emissions of a pollutant that is regulated under the 

prevention of significant deterioration (“PSD”) program or the new source performance standards 

(“NSPS”). Compliance with the Final Boiler Rule should not result in the imposition of additional 

regulatory requirements under the PSD or NSPS programs. Therefore, the Final Boiler Rule should 

explicitly provide that PSD and NSPS requirements will not be triggered simply because an owner or 

operator modifies a unit for the purposes of complying with the Final Boiler Rule. 

Similar provisions have been adopted by EPA in the past. For example, Section 40 CFR 60.32b(c) 

provides that “Physical or operational changes made to an existing municipal waste combustor primarily 

for the purpose of complying with emission guidelines under this subpart [Subpart Cb] are not considered 

in determining whether the unit is a modified or reconstructed facility under subpart Ea or subpart Eb of 

this part.” Similar provisions should be added to the Final Boiler Rule. 
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Conclusion

Thank you for your careful consideration of FSI’s additional information and request for reconsideration of 

the Final Boiler Rule. Please contact me if you have any questions or need additional information 

concerning any of the issues addressed in this letter.

Sincerely,

GOLDER ASSOCIATES INC.

David A. Buff, P.E., Q.E.P.

Principal Engineer

cc: Brian Schrager

Energy Strategies Group

Sector Policies and Programs Division (D243-01)

Office of Air Quality Planning and Standards

U.S. Environmental Protection Agency

Research Triangle Park, NC 27711

Enclosures

DB/edk