Several commenters ( 364, 387, 399) argued that EPA's approach might be a reasonable approach if the data set were representative of the population of boilers, but the only coal fired boiler data used in determining the MACT floor were from fluidized bed boilers and the commenters noted that fluidized bed boilers are inherently lower emitting sources, which would bias the overall mercury emission data set lower. The commenters also pointed out that in addition to not using all of the available data, several of the units used to establish the MACT floor have other air pollution controls ( spray dryers, limestone injection) in addition to fabric filters. Since these additional controls are known to remove mercury, the commenters contended that the resulting MACT floor calculation would be biased low because of these additional air pollution controls that are beyond the floor level of control.

One commenter ( 529) discussed the MACT floor calculated in the October 2002 MACT Floor Analysis, which clearly shows that individual test runs from the same source were used to calculate the MACT floor. The commenter pointed out that section 112( d) of the CAA requires the existing source MACT floor be calculated using the " best performing 12 percent of existing sources" not the best performing 12 percent of source tests from existing sources.

Response: As discussed in the proposal preamble, the MACT floor analysis for mercury was based on a two step process. First the percentage of units with control technologies that were identified that could achieve mercury emission reductions was determined using the boiler population databases. If the control technology analysis indicated that at least 12 percent of 88 sources in the subcategory used a control device that could achieve mercury emission reductions, then the control technology present at the median ( 6th percentile) was identified as the MACT floor control technology. The MACT floor level of control for mercury was identified as a fabric filter. The control effectiveness of fabric filters was based on emissions information for utility boilers that indicated that mercury emissions reduction were being achieved with this technology. In this case, we could use control efficiency information from another similar source category to supplement the information available in this source category because of the similarity in fuel burned, combustor type, and control methodology and operation. We maintain that fabric filters are still the appropriate level of control for the MACT floor.

Second, the emission limit associated with the MACT floor control technology was calculated using emissions information for units in the subcategory, whenever possible. For most of the subcategories developed, emissions information was adequate. Only for the emission limit for new source liquids and the variability factor for new source solids was fuel pollutant content incorporated into the MACT floor analyses. The mercury fuel content of coal from the utility industry was used in developing the variability factors for new solid fired units. This was done because mercury emissions depend on the quantity of mercury in the fuel burned. Coal available to utilities and industrial boilers and process heaters are expected to be similar, and coal is the solid fuel that is routinely used in such units that has generally the greatest degree of HAP variability. We maintain that the utility database used at proposal to develop the variability factor for new sources was adequate in establishing the MACT floor emission limit.

The EPA recognizes that the mercury emissions database for industrial boilers is limited. However, EPA is directed by the CAA to develop standards for sources using whatever data is available. Prior to proposal and during the ICCR process, EPA conducted a thorough search for HAP emission test reports. This search was supported by industry, trade groups, and States. For criteria pollutants, such as PM, substantial emission information was available and gathered. For mercury and other HAP, this was not the case. Industrial boilers have not generally been required to test for HAP emissions. In the proposed rule, EPA requested commenters to provide additional emissions information. However, only one source provided any additional mercury emissions data. This information ( test results from three additional coal fired industrial boilers) was used to revise the mercury emission limit for existing sources. We also reviewed the mercury emission database used to develop the MACT floor emission limit for existing sources. After review, we determined that a revision to the variability factor was appropriate. The additional data and the revised variability factor was used to re calculate the mercury emission limit to be 0.000009 lb/ MMBtu ( from 0.000007 lb/ MMBtu at proposal).

Comment: One commenter ( 492) presented the following from the MACT Floor Analysis ( Docket item II B 14): " The MACT floor emission level for mercury is based on emissions test information from units using fabric filters. Approximately 14 percent of the boilers in the population database used scrubbers. The emissions database contains mercury information on 7 different boilers using scrubbers." The commenter noted that " scrubber" in the second and third sentences should read " fabric filters."

Response: The EPA thanks the commenter and will make the corrections identified. 89 Comment: Two commenters ( 396, 410) questioned EPA's determination of emission limits for new liquid fuel fired units. One commenter ( 410) contended that for new liquid fuelfired units, EPA's PM and HCl emission limits are based on the average performance of the bestcontrolled existing unit as a not to be exceeded new source emission limit. The commenter explained that by establishing the new source emission limitation at the average performance level achieved by the best controlled existing source, EPA will require a new source to achieve average performance much better than the average performance of the best controlled existing source in order to not violate the emission standard. The commenter concluded that this was a beyond thefloor requirement and a beyond the floor requirement for liquid fired units is not warranted. Two commenters ( 396, 410) suggested that EPA should employ a more careful statistical approach to reflect variability, and must reflect all the factors ( e. g., fuel burned, operating conditions, performance of control technology) that give rise to variation in emissions performance and set a standard at an achievable level rather than an average level. Otherwise, even the best performing source would be out of compliance half of the time. One commenter ( 410) added that EPA attempted to reflect variability only in fuel burned in its variability factor, and this calculation was not sufficiently statistically based. The commenters provided examples of their interpretation of EPA's calculations and limitations. The commenter recommended that EPA establish a fuel related variability factor for liquid fired units that reflects a chlorine content at least two standard deviations above the mean chlorine content of residual oil.

One commenter ( 415) stated that the EPA must develop a mercury emission limit for liquid fuel boilers and process heaters. The commenter suggested that EPA should identify the existing data on mercury emissions from this sector and establish a MACT floor for mercury emissions from liquid fuel fired boilers and process heaters using that data.

Response: As discussed in the MACT floor memorandum, there was no available emissions test data for Hcl from the liquid fuel fired boilers. Therefore, the available fuel analysis chlorine data for residual oil and distillate oil was identified for the purposes of determin a hydrogen chloride emission limit for new sources in the liquid subcategory. The MACT floor emission limit calculations for Hcl were done using the highest residual data point. Assuming that all the chlorine in the fuel would be emitted as Hcl, the chlorine content value was converted to an uncontrolled emission factor. Based on previous EPA work, we used a control device efficiency of 95% for wet scrubbers ( although many can achieve as high as 99% reduction) to control Hcl. We contend that variability was adequately incorporated into the new source emission limit because the highest fuel content point and an achievable removal efficiency was used in the calculation. We would also add that the MACT floor analysis indicated that there was not MACT floor level of control to reduce mercury emissions for new liquid fired units.

Comment: One commenter ( 413) asserted that selecting best control technology for MACT floors does not work for mercury because combustion yields three forms of mercury ( elemental, gaseous ionic, and particulate) and the level of mercury control achieved by a control technology depends on the relative concentrations of each of the three forms. As an example, the commenter used a scrubber that removes gaseous ionic mercury, but does not remove elemental mercury. The commenter added that control efficiency for fabric filters is greatly affected by coal chemistry and plant operating conditions. The commenter explained that if coal has a very low chloride level, most of the mercury formed will be in the elemental state and a fabric filter will be ineffective in capturing it. The commenter also noted that if a boiler is operated such that very 90 low levels of carbon exist in the flue gas, then the ability of a fabric filter to capture mercury is greatly reduced. One commenter ( 442) cautioned that the effectiveness of fabric filters for controlling mercury emissions depends on the design of the whole air pollution control system. Some acid gas scrubbers can decrease mercury collection efficiencies of ESPs and fabric filters by converting mercury to non particulate matter which passes through the fabric filter.

Response: The EPA recognizes that there are different forms of mercury and not all forms will be controlled equally with every control technology. However, the emissions database does not speciate mercury emissions, so only total mercury emissions were considered in the analysis. Fabric filters were determined to be the basis for the MACT floor emission limit based on information in the utility boiler standards that indicated fabric filters can achieve greater mercury emissions reduction than other existing add on technologies. Because the test reports did not speciate mercury, it is possible that the mercury emissions information may incorporate fabric filters that achieve a range of control for the various mercury forms.

The EPA would like to clarify that sources are not required to install fabric filters to meet the standard. The rule allows sources to use any control technology, including fuel switching, to meet the mercury emission limits.

Comment: One commenter ( 415) said that the proposed emission limits for mercury must be significantly strengthened to reflect the removal performance of the best performing units and to protect public health and the environment. The commenter noted that fabric filters are capable of mercury capture efficiencies ranging from 72 to 90 percent. The commenter expressed concern that the mercury emission limit could be a no control standard for mercury because the limit is sufficiently high enough that most boilers would not be required to use additional controls. One commenter ( 448) said that the proposed emission levels for mercury do not meet the requirements of MACT development under section 112( d). The commenter stated that EPA appeared to have ignored performance data of existing control devices, such as enhanced fabric filters downstream of an activated carbon injection device. The commenter added that information from the electric utility MACT information collection request and subsequent field test data was also not considered. The commenter asserted that information from the utility standard on mercury controls would have provided a better indication of control than the single emission point not achieving mercury reductions in configuration similar to those used in municipal waste combustors.

Response: We considered mercury control information developed in the utility boiler standard for the Boiler MACT standard. The utility boiler information indicated a much lower control effectiveness for mercury than the commenter had indicated. We requested additional information in the proposal preamble. However, none was provided by the commenters. Additionally, we do not have specific information about types of control devices. For example, we know a boiler is equipped with a fabric filter but we do not have information to the specific type of fabric filter. We did review carbon injection as an above the floor technology ( see chapter 9) but determined that it was not appropriate for the final rule.

Comment: One commenter ( 512) argued that the floor for new solid fuel fired sources should include carbon injection for mercury control. The commenter explained that EPA cannot 91 set new source floors based solely on control technologies. The commenter noted that EPA set the new source floor based on engineering assumptions about the control efficiency of certain control technologies ( i. e., the best controlled) but did not select the lowest emitting ( i. e., the best performing) sources. If EPA correctly used this methodology, the commenter argued that it should have selected carbon injection as the floor for new units because one unit uses this technology and EPA has noted that carbon injection is capable of achieving high mercury reductions in other categories ( e. g., incinerators) and it is expected to be the control technology of choice for reducing mercury from coal fired utility boilers. The commenter noted that not all boilers and process heaters using fabric filters have the lowest emissions, yet EPA selected this technology for the basis of the MACT floor based on knowledge that it could perform to high levels. Therefore, it does not matter that the unit using carbon injection is not the lowest emitting source; the fact that one source is using the best technology for mercury control should lead EPA to select carbon injection as the MACT floor for new sources. One commenter ( 390) contended that the MACT floor for new units reflects the mercury control benefits of systems installed under the NSPS and not on what the EPA speculates may become available in the future.

Response: As discussed in the proposal preamble, we identified one existing industrial boiler that was using carbon injection. However, the emissions data that we obtained from the boiler indicated that this unit was not achieving mercury emission reduction. This result led us to conclude that it was not the new source floor level of control. We considered carbon injection as a beyond the floor option, but decided that while this control technique has been used in other source categories, there is no demonstrated evidence that it would work for industrial boilers and process heaters because the type of mercury emitted and properties of the emission streams are sufficiently different for boilers and process heaters and other source categories. For fabric filters, we had some emissions information for utility boilers that indicated that mercury emissions reduction were being achieved with this technology. In this case, we could confidently use control efficiency information from another similar source category to supplement the information available in this source category. Unlike fabric filters, the available emissions information indicated that carbon injection was not effective for industrial boilers and process heaters.

Comment: One commenter ( 492) stated that EPA must demonstrate that a source ( or sources, in the case of the existing source standard) is actually achieving the standard established. The commenter noted that EPA recognized that certain fuels, while providing decreased emissions for some HAP, may contribute to higher emissions in other types of HAP ( i. e., gaseous fuels may have low PM and metal emissions, but may have higher organic HAP emissions than solid fuels). The commenter was concerned that EPA, in establishing emission limits or when conducting the floor evaluation, has not considered whether the best performing sources can achieve the emissions limitations in the aggregate. The commenter noted that section 112( d) of the CAA requires EPA to establish standards that are duplicable by others. Some of the best units may be achieving low emissions based on methods that are not available to other units within the source category or subcategory. The commenter believes that this requires the EPA to the following: ( 1) discover how these sources actually are " controlling" emissions, and ( 2) set standards that are achievable through application of various measures, techniques, methods or processes.

The commenter ( 492) stated that the floor methodology must provide a reasonable 92 estimate of what the best performers achieve, regardless of which method EPA uses. The commenter noted recent court decisions that criticize EPA for not determining a reasonable estimate of the best performers based on all of the factors that affected emissions for a particular rule.

Response: We disagree with the commenter. The emission test database and population database show that there is at least one source with the MACT floor control technologies required in the proposed and final rule. Additionally, we received 4 test reports after proposal ( which are now in the docket) from emission tests conducted at a boiler in Michigan State University. The reports also show that the source utilizes the MACT floor levels of control identified in the rule.

Comment: One commenter ( 451) contended that EPA may not use control technology as the basis for the MACT floor since other factors ( e. g., type of fuel combusted) affect HAP emission levels. The commenter stated that the MACT floor should reflect the emission levels actually achieved by the " best performing" sources, regardless of how the emission levels are achieved ( e. g., through add on controls, cleaner fuels). One commenter ( 415) said that the approach used by EPA in establishing the MACT floor for the boilers NESHAP is not consistent with recent legal decisions ( Cement Kiln Recycling Coalition v. EPA, 255 F. 3d 855, 865 ( D. C. Cir. 2001). The commenter stated that the MACT floor should be based on actual emissions of the relevant best performing sources, rather than specific technologies in use. The commenter added that in some cases lower emissions may be achieved by a combination of lower emission fuels, operational parameters, or other means separate from or in addition to end of stack controls.

Response: First, we believe the MACT floor methodology we use is consistent with D. C. Circuit's holding in the National Lime case. The D. C. Circuit held that by focusing only on technology EPA ignored the directive in section 112( d)( 2) to consider pollution reducing measures including process changes and substitution of materials.

The EPA agrees with the commenter that all factors which might control HAP emissions must be considered in making a floor determination for each subcategory. However, EPA disagrees that it must express the floor as a quantitative emission level in those instances where the source on which the floor determination is based has not adopted or implemented any measure that would reduce emissions.

A detailed discussion of the MACT floor methodology is presented in the memorandum " MACT Floor Analysis for New and Existing Sources in the Industrial, Commercial, and Institutional Boilers and Process Heaters Source Categories" in the docket. In summary, we considered several approaches to identifying MACT floor for existing industrial, commercial, and institutional boilers and process heaters. Based on recent court decisions, in most cases the most acceptable approach for determining the MACT floor is likely to involve primarily the consideration of available emissions test data. However, after review of the available HAP emission test data, we determined that it was inappropriate to use this MACT floor approach to establish emission limits for boilers and process heaters. The main problem with using only the HAP emissions data is that, based on the test data alone, uncontrolled units ( or units with low efficiency add on controls) were frequently identified as being among the best performing 12 percent of sources in a subcategory, while many units with high efficiency controls were not. 93 However, these uncontrolled or poorly controlled units are not truly among the best controlled units in the category. Rather, the emissions from these units are relatively low because of particular characteristics of the fuel that they burn, that can not reasonably be replicated by other units in the category or subcategory. A review of fuel analyses indicate that the concentration of HAP ( metals, HCl, mercury) vary greatly, not only between fuel types, but also within each fuel type. Therefore, a unit without any add on controls, but burning a fuel containing lower amounts of HAP, can have emission levels that are lower than the emissions from a unit with the best available add on controls. If only the available HAP emissions data are used, the resulting MACT floor levels would, in most cases, be unachievable for many, if not most, existing units, even those that employ the most effective available emission control technology. Another problem with using only emissions data is that there is very limited or no HAP emissions information available to the Agency for the subcategories. This is consistent with the fact that units in these source categories have not historically been required to test for HAP emissions.

We also considered using HAP emission limits contained in State regulations and permits as a surrogate for actual emission data in order to identify the emissions levels from the best performing units in the category for purposes of establishing MACT standards. However, we found no State regulations or State permits which specifically limit HAP emissions from these sources.

Consequently, we concluded that the most appropriate approach for determining MACT floors for boilers and process heaters is to look at the control options used by the units within each subcategory in order to identify the best performing units. Information was available regarding the emission control options employed by the population of boilers identified by the EPA. We considered several possible control controls ( i. e., factors that influence emissions), including fuel substitution, process changes and work practices, and add on control technologies. We first considered whether fuel switching would be an appropriate control option for sources in each subcategory. We considered the feasibility of both fuel switching to other fuels used in the subcategory and to fuels from other subcategories were considered. This consideration included determining whether switching fuels would achieve lower HAP emissions. A second consideration was whether fuel switching could be technically achieved by boilers and process heaters in the subcategory considering the existing design of boilers and process heaters. We also considered the availability of various types of fuel. After considering these factors, we determined that fuel switching was not an appropriate control technology for purposes of determining the MACT floor level of control for any subcategory. This decision was based on the overall effect of fuel switching on HAP emissions, technical and design considerations, and concerns about fuel availability.

We also concluded that process changes or work practices were not appropriate criteria for identifying the MACT floor level of control for units in the boilers and process heaters category. The HAP emissions from boilers and process heaters are either fuel dependent ( i. e., mercury, metals, and inorganic HAP) or combustion related ( i. e., organic HAP). Fuel dependent HAP are typically controlled by removing them from the flue gas after combustion. Therefore, they are not affected by the operation of the boiler or process heater. Consequently, process changes would be ineffective in reducing these fuel related HAP emissions.

On the other hand, organic HAP can be formed from incomplete combustion of the fuel. Good combustion practice ( GCP), in terms of boilers and process heaters, could be defined as the system design and work practices expected to minimize organic HAP emissions. While few 94 sources in EPA's database specifically reported using good combustion practices, the data that we have suggests that boilers and process heaters within each subcategory might use any of a wide variety of different work practices, depending on the characteristics of the individual unit. The lack of information, and lack of a uniform approach to assuring combustion efficiency, is not surprising given the extreme diversity of boilers and process heaters, and given the fact that no applicable Federal standards, and most applicable State standards, do not include work practice requirements for boilers and process heaters. Even those States that do have such requirements do not require the same work practices. For example, CO emissions are generally a good indicator of incomplete combustion, and, therefore, low CO emissions might reflect good combustion practices. ( As discussed in the proposal, CO is considered a surrogate for organic HAP emissions.) Therefore, we considered whether existing CO emission limits might be used to establish good combustion practice standards for boilers and process heaters. We reviewed State regulations applicable to boilers and process heaters, and then for each subcategory we matched the applicability of State CO emission limits with information on the locations and characteristics of the boilers and process heaters in the population database. Ultimately, we found that very few units ( less than 6 percent) in any subcategory were subject to CO emission limits. We concluded that this information did not allow EPA to identify a level of performance that was representative of good combustion across the various units in any subcategory. Therefore, we did not establish a CO emission limit, as a surrogate for organic HAP emissions, as a part of the MACT floor for existing units. However, we have considered the appropriateness of such requirements in the context of evaluation possible beyond the floor options.

In general, boilers and process heaters are designed for good combustion. Facilities have an economic incentive to ensure that fuel is not wasted, and the combustion device operates properly and is appropriately maintained. In fact, existing boilers and process heaters are used typically as high efficiency control devices to control ( reduce) emission streams containing organic HAP compounds from various process operations. Therefore, EPA's inability to establish a combustion practice requirement as part of the MACT floor for existing sources in this category should not reduce the incentive for owners and operators to run their boilers and process heaters at top efficiency.

As a result of the evaluation of the feasibility of establishing emission limits based on control techniques such as fuel switching and good combustion practices, we concluded that addon control technology should be the primary factor for purposes of identifying the best controlled units within each subcategory of boilers and process heaters. We identified the types of air pollution control techniques currently used. We ranked those controls according to their effectiveness in removing the different HAP categories of pollutants; including metallic HAP and PM, inorganic HAP such as acid gases, mercury, and organic HAP. We then listed all the boilers and process heaters in the population database in order of decreasing control device effectiveness within each subcategory for each pollutant type. Then we identified the top 12 percent of units within each category based on this ranking, and determined what kind of emission control technology, or combination of technologies, the units in the top 12 percent employed. Finally, we looked at the emissions test data from boilers and process heaters that used the same control technology, or technologies, as the units in the top 12 percent to estimate the average emissions limitation achieved by the these units.

This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by units in the top 12 percent. 95 The analysis of the measured emissions from units representative of the top 12 percent is reasonably designed to provide a meaningful estimate of the average performance, or central tendency, of the best controlled 12 percent of units in a given subcategory. For existing subcategories where less than 12 percent of units in the subcategory use any type of control technology, we looked to see if we could estimate the central tendency of the best controlled units by looking at the unit occupying the median point in the top 12 percent ( the unit at the 94th percentile). If the median unit of the top 12 percent is using some control technology, we might use the measured emission performance of that individual unit as the basis for estimating an appropriate average level of control of the top 12 percent. For subcategories were less than 6 percent of the units in a HAP grouping used controls or limited emissions, the median unit for that HAP grouping reflects no emissions reduction. Therefore, in these circumstances, EPA believes that it has appropriately established the MACT floor emission levels for these sources as no emission reduction.

Comment: One commenter ( 512) argued that EPA's approach to setting MACT floors for existing sources is fundamentally flawed. The commenter explained that none of the floors set by EPA reflect the actual emissions of the best performing sources but were based on the assumed control efficiency of add on controls. The commenter noted that EPA admitted that many factors influence emissions, not just control equipment, and that the available data show that some sources are performing better than the floor. The commenter also noted that Congress required EPA to set MACT emission standards based on the performance of " sources," not simply the " technology system" and cautioned that EPA should not rely on data from sources that are not among the top 12 percent when determining standards or variability. The commenter added that if EPA is concerned that the existing sources may not be able to meet MACT emission standards under all relevant conditions, it should develop a targeted variability factor that is based on performance fluctuations of the top 12 percent sources and which accounts for factors other than MACT technology that influence source performance. The commenter contended that under no circumstance should EPA rely on the data from sources that are not among the top 12 percent when determining performance standards or variability.

Three commenters ( 343, 479, 492) supported EPA's approach to establishing the MACT floors for boilers and process heaters. Two commenters ( 479, 492) specifically supported the method of using both control technologies and emissions data to establish MACT floors. One commenter ( 343) agreed with EPA that using HAP emissions data alone is not appropriate since uncontrolled units may have lower emissions than controlled units due to fuel characteristics and that HAP emissions from boilers and process heaters are primarily dependent upon the composition of the fuel. In addition, the commenter stated EPA's approach of developing subcategories based on fuel used, unit size, and evaluating control options used by the units within each subcategory to determine the MACT floor is most appropriate. One commenter ( 492) expressed that, for a source category as large and diverse as this one, add on technology is the most viable way of accounting for variability. Two commenters ( 479, 492) noted that the approach that EPA used to determine the MACT floor in this proposal is not countramanded by the holding in the Cement Kiln ruling. The commenters explained that EPA used the emission data from the best performing 12 percent of the sources as opposed to the worst source using the MACT control.

Response: As discussed in the proposal preamble, the MACT floor analysis was based on 96 a two step process. First the percentage of units with control technologies that could achieve mercury emissions reductions was determined using the boiler population databases. We identified the types of air pollution control techniques currently used. We ranked those controls according to their effectiveness in removing the different HAP categories of pollutants; including metallic HAP and PM, inorganic HAP such as acid gases, mercury, and organic HAP. We then listed all the boilers and process heaters in the population database in order of decreasing control device effectiveness within each subcategory for each pollutant type. Then we identified the top 12 percent of units within each category based on this ranking, and determined what kind of emission control technology, or combination of technologies, the units in the top 12 percent employed. Second, we looked at the emissions test data from boilers and process heaters that used the same control technology, or technologies, as the units in the top 12 percent to estimate the average emissions limitation achieved by the these units.

This approach reasonably ensures that the emission limit selected as the MACT floor adequately represents the average level of control actually achieved by units in the top 12 percent. The analysis of the measured emissions from units representative of the top 12 percent is reasonably designed to provide a meaningful estimate of the average performance, or central tendency, of the best controlled 12 percent of units in a given subcategory. For existing subcategories where less than 12 percent of units in the subcategory use any type of control technology, we looked to see if we could estimate the central tendency of the best controlled units by looking at the unit occupying the median point in the top 12 percent ( the unit at the 94th percentile). If the median unit of the top 12 percent is using some control technology, we might use the measured emission performance of that individual unit as the basis for estimating an appropriate average level of control of the top 12 percent.

Comment: Several commenters ( 348, 388, 401, 449, 492, 498, 524, 533 ) opposed the use of emissions data from large units to establish the MACT floor for small and limited use units. One commenter ( 401) stated that it was not appropriate to assume that emissions rates achievable by large units are achievable by small units, even the best controlled units. Several commenters ( 388, 449, 498, 524, 533) argued that the use of large unit data in MACT determinations for other subcategories would defeat the purpose of the subcategorization and violate the requirements of section 112 because the use of this data does not represent sources in the relevant category or subcategory. Furthermore, the commenters noted that most existing State and Federal regulations do not regulate units less than 10 MMBtu/ hr due to their low emissions and extension of emission data from larger sources ignores that lack of regulation. One commenter ( 348) questioned the use of the MACT floor database for smaller units because it does not contain data from smaller units.

Response: The EPA disagrees with the commenters and maintains that it has conducted the MACT floor analysis appropriately. First, EPA calculated the control technology used by the best controlled 12 percent of sources in the subcategory. For example, only units in the population database less than 10 MMBtu/ hr ( and not in the limited use subcategory) were used to determine the MACT floor control technology for units in the small subcategories. Second, EPA used information in the emissions test database to calculate the emission level associated with the MACT floor control technology. The emissions test database did not contain test data for limited use or small boilers and process heaters. The EPA's interpretation of section ___ of the CAA allows EPA to use information from similar sources to set the MACT floor when no information 97 from the subcategory is available. Although the units in the small and limited use subcategories are different enough to warrant their own subcategory ( i. e., different purposes and operation), emissions of the specific types of HAP for which limits are being proposed are expected to be related more to the type of fuel burned and the type of control used, than to unit operation. Consequently, EPA determined that emissions information from large fuel fired units could be mused to establish MACT floor levels for the small and limited use subcategories because the fuels and controls are similar. The proposal preamble requested additional information from commenters to refine/ revise the approach if necessary. No commenters provided emissions information for limited use or small subcategory boilers or process heaters.

Comment: Several commenters ( 374, 382, 388, 449, 492, 498, 524, 533) believe that new distillate oil fuel fired boilers and process heaters should be exempt from PM and HCl emission limit requirements in addition to other rule requirements. Several commenters ( 382, 388, 449, 498, 524, 533) noted that EPA has generally treated distillate oil on par with natural gas relative to emission requirements and that no basis for imposing these emission limits exists. Commenters explained that EPA already recognizes the lower emissions of these units since it does not require emission testing. However, commenters noted that units will be required to demonstrate compliance with the emission limits in their operating permit even if EPA does not require testing in the boilers NESHAP. The commenters ( 382, 388, 449, 492, 498, 524, 533) contended that a regulatory rationale does not exist for concluding PM and HCl emissions are controlled in liquid fuel fired units other than those firing residual oils. Since there are no units within the emissions database that are firing distillate oil or diesel oil that are equipped with any PM or HCl controls or emissions test data for these pollutants, commenters ( 492, 382) argued that EPA apparently has arbitrarily imposed emission limits that are based on firing residual oil on units fired with distillate oil. The commenter ( 492) also noted that emissions from distillate oil fired units are inherent with the units and the fuel. Hydrogen chloride emissions are a function of the fuel chloride content, which is not a detailed requirement in ASTM oil specifications. Furthermore, the commenter argued that emissions limitations serve no regulatory purpose if there is no mechanism for control. The commenter concluded by pointing out that PM and HCl emissions from distillate oil fired units are very low and are not controllable by the source, so that they could legitimately be considered de minimis. Several commenters ( 374, 382, 388, 449, 498, 524, 533) suggested that these units should only have to comply with the initial notification requirements in the general provisions ( 40 CFR part 63, subpart A).

Response: Units firing distillate fuel are still included in the liquid subcategory. As such they are subject to the emission limits that are applicable to liquid fuel fired units. However, we do recognize that emissions from firing distillate oil are lower than from firing residual oil, and reflect this in the rule. Units firing only distillate oil are only required to submit a signed statement that they fire distillate oil, and are not subject to testing or monitoring requirements. 98 9.0 OPTIONS BEYOND THE MACT FLOOR 9.1 General Comment: Several commenters ( 376, 393, 491, 536) supported the EPA's proposal not to require beyond the floor MACT standards for any subcategories. One commenter ( 393) urged EPA to set the MACT standards equal to the MACT floors for each subcategory. One commenter ( 491) supported EPA's decision to set the emissions limitations at the MACT floor and not establish emission standards beyond the floor. The commenter stated that the standard can be achieved by most existing sources in the source category in a cost effective manner and the standard will provide a sufficient level of emission controls to adequately protect the public and the environment. One commenter ( 390) urged the EPA to carefully assess the costs and actual availability of any beyond the floor control technologies not commercially available. The commenter added that any further control beyond the floor, based on the EPA Utility and Mercury Study, will have little incremental effect on public health while proving very costly.

Two commenters ( 512, 527) argued that EPA could achieve more emission reductions from this source category through this standard. One commenter ( 527) stated that EPA concluded that most beyond the floor options for existing units would further reduce emissions but the cost would be too high to consider it a feasible beyond the floor option. The commenter stated that the impact of this rationale is the missed opportunity to remove hundreds of tons of hazardous air pollutants ( HAP) emitted directly into the air each year by the affected sources in this industry. The commenter stated that this not a question as to the availability of control and measurement options, but rather, EPA's gauge of what if any cost is deemed acceptable. One commenter ( 512) argued that EPA's database indicates substantially lower emissions are achievable for this source category and that further reductions should be evaluated as part of a beyond the floor analysis.

Response: For the final rule, EPA maintains that options beyond the MACT floor are not appropriate for the standard. The EPA is required by the Clean Air Act ( CAA) to set the standard at a minimum on the best controlled 12 percent of sources ( for existing units) or best controlled source ( for new units). The CAA also requires EPA to consider costs and non air quality impacts and energy requirements when considering more stringent requirements than the MACT floor. EPA did consider the cost and emission impacts of a variety of regulatory options more stringent than the MACT floor for each subcategory. The EPA recognizes that for some subcategories, more stringent controls than the MACT floor can be applied and achieve additional emission reductions. However, EPA also determined that the cost impacts of such controls were very high. Considering both the costs and emission reductions, EPA determined that it would be infeasible to require any options more stringent than the floor level.

9.2 Carbon Injection Comment: Several commenters ( 364, 376, 387, 388, 393, 399, 406, 407, 408, 413, 446, 447, 449, 452, 492, 498, 501, 519, 524, 533) supported EPA's decision not to require activated carbon injection as an " above the floor" technology. Some commenters ( 364, 387, 388, 393, 399, 413, 449, 492, 498, 524, 533, 536) explained that consideration of the use of activated carbon 99 injection has issues including: 1) insufficient data on the effectiveness of carbon injection for this source category; 2) the reductions indicated from data outside of this source category vary greatly with boiler type and fuel source; 3) contamination of fly ash such that it cannot be beneficially reused for various byproducts; 4) catastrophic foaming in plants with wet flue gas desulfurization; and 5) its use is prohibitively expensive when compared to what EPA considers reasonable for beyond the floor costs. Other commenters ( 393, 406, 407, 408, 413, 447, 501, 519) noted that activated carbon injection has not yet been proven as a commercially viable option for mercury control.

Some commenters ( 415, 451, 527 ) expressed concern that EPA did not propose to require activated carbon injection. One commenter ( 451) contended that EPA neglected to consider the high emission reduction levels that can be achieved through carbon injection. As a result, the commenter argued that EPA neglected to consider that it may be possible for coal burning units to match the mercury emissions performance of wood fired units. Another commenter ( 415) argued that the single emission test of the industrial boiler using activated carbon was not representative. Two commenters ( 415, 527) argued that EPA should consider the well documented success of activated carbon injection for the control of mercury from other combustion sources including incinerators, waste to energy facilities, and electric power facilities. One commenter ( 527) stated that the approach to control mercury in this rule appears to ignore the wealth of data and information that is currently available to control mercury from similar flue gas streams. The commenter stated that despite fuel and process differences and therefore potential differences in the control options that might be selected, there are often substantial similarities between the different industries in the design, operation, and flue gas stream characteristics, and therefore the general availability of similar control options.

Response: For the final rule, EPA maintains that options beyond the MACT floor are not appropriate for the standard. The EPA is required by the CAA to set the standard at a minimum on the best controlled 12 percent of sources ( for existing units) or best controlled source ( for new units). The CAA also requires EPA to consider costs and non air quality impacts and energy requirements when considering more stringent requirements than the MACT floor. As documented in the memorandum " Methodology for Estimating Costs and Emissions Impacts for Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants" in the docket, EPA did consider the cost and emission impacts of a variety of regulatory options more stringent than the MACT floor for each subcategory. The EPA recognizes that for some subcategories, more stringent controls than the MACT floor can be applied and achieve additional emission reductions. However, EPA also determined that the cost impacts of such controls were very high. Considering both the costs and emission reductions, EPA determined that it would be infeasible to require any options more stringent than the floor level.

For the final rule, EPA maintains that carbon injection should not be required as an above the floor technology. As discussed in the proposal preamble, we identified one existing industrial boiler that was using carbon injection. The emissions data that we obtained from the boiler indicated that this carbon injection unit was not achieving mercury emissions reductions. This result led us to conclude that it was not the new source floor level of control. However, there may have been other reasons for the ineffectiveness of this system ( e. g., low inlet mercury levels, insufficient carbon injection rate, ESP instead of fabric filter for PM control). Therefore, we considered carbon injection as a beyond the floor option, but decided that while this control 100 technique has been used in other source categories, there is no demonstrated evidence that it would work for industrial boilers and process heaters because the type of mercury emitted and properties of the emission streams are sufficiently different for boilers and process heaters and other source categories. For fabric filters, we had some emissions information for utility boilers that indicated that mercury emissions reductions were being achieved with this technology. In this case, we could confidently use control efficiency information from another similar source category to supplement the information available in this source category. Unlike fabric filters, the available emissions information indicated that carbon injection was not effective for industrial boilers and process heaters.

9.3 Fuel Switching Comment: Several commenters ( 364, 381, 382, 387, 388, 391, 392, 399, 403, 410, 413, 444, 447, 449, 479, 492, 498, 519, 524, 533, 536) supported EPA's conclusion that fuel switching is not a viable regulatory option for setting the MACT floor or considering beyond thefloor options. In support of EPA's conclusion, some commenters ( 364, 381, 399, 387, 479) provided the following arguments against fuel switching: 1) Fuel switching is neither technologically viable nor environmentally beneficial; 2) fuel switching would contradict the National Energy Policy goal of enhancing fuel diversity; 3) fuel switching would force a shift away from bioenergy; 4) fuel switching would not provide the additional minimization of greenhouse gas emissions that the use of biomass would provide; 5) the CAA does not require EPA to consider fuel switching as part of a MACT floor analysis; 6) the inclusion of fuel switching as a MACT floor option under section 112( d)( 3) would eliminate EPA's subcategorization authority as well as EPA's established authority to vary emission standards based on the pollutant content of the fuel burned; and 7) the MACT program is not an appropriate vehicle to force a wholesale change in energy sources that fuel switching to natural gas would entail. One commenter ( 492) explained that fuel switching is not a technology that is feasible for all sources within the category, therefore, it is not " duplicable."

One commenter ( 415) stated that the EPA should provide more quantitative information on the potential for fuel switching to reduce HAP emissions. The commenter suggested that, with regard to the overall reduction of HAP associated with fuel switching, it was not clear if the EPA had sufficient data to make a quantitative determination of this issue. Regarding EPA's assertion that the availability of natural gas supply and distribution infrastructure would preclude more significant use of fuel switching, the commenter also requested a more quantitative assessment.

Response: The EPA maintains that fuel switching is not a viable option for the promulgated rule, based on the rationale presented in the proposal preamble. Regarding fuel switching emission reductions/ increases, the memorandum "   " details the fuel switching impacts analysis. The memorandum presents emission impacts for pollutants, including organics, inorganics, and metallic HAPs. This analysis was based on all the emissions information gathered by EPA, consisting of emission test reports for gas fired units and solid fuel units. In the proposal, EPA requested commenters to provide additional information. However, no additional emissions information was provided. Regarding natural gas supply and infrastructure comments, commenters are referred to the fuel switching memorandum. The EPA did not have extensive information on natural gas supply or infrastructure. The EPA did have sufficient information on pipelines and use of natural gas at each boiler and other combustion units to estimate whether a significant number of sources would need to make changes to their combustion unit. The fuel 101 switching analysis also shows that the major annualized cost of fuel switching to natural gas is not the capital cost of equipment/ infrastructure, but the high cost of natural gas relative to other fuels. This cost differential results in the infeasibility of fuel switching to natural gas. 102 10.0 WORK PRACTICES STANDARDS Comment: One commenter ( 445) requested that EPA consider establishing a longer averaging period for the CO work practice standard and exempt periods of startup, shutdown, and malfunction for limited use boilers. The commenter noted that the infrequent and limited use of these boilers makes CO emissions highly variable and would result in difficulty in meeting the CO work practice standard. Four commenters ( 364, 399, 387, 403) supported EPA's conclusion that a one day averaging period for CO is appropriate. Other commenters ( 401, 478) suggested that if EPA decides to keep CO continuous emissions monitoring system requirements, then EPA should provide a 30 day rolling average for the CO standard in order to take into account the existence of fuel and operational variability.

Response: In the final rule we modified the averaging period for solid fuel fired sources that have a work practice standard for CO and are required to monitor CO using CEMS ( i. e., units with a capacity of 100 MMBtu/ hr or more). We changed the averaging period from a 24 hour period to a 30 day rolling average. This change accounts for the variability in fuel characteristics ( e. g., moisture, Btu content, mixture) that occur for solid fuel fired boilers and process heaters. With regard to limited use units, we removed the requirement for those units to install and operate CO CEMS if they have an applicable work practice standard. Limited use units with an applicable CO work practice standard will only have to conduct a performance test for CO emissions. This change was made due to the limited use of such units and the time needed to conduct annual CO CEMS certifications.

Comment: Several commenters ( 418, 431, 475, 503, 504, 505) claimed that the potential for HAP emissions from blast furnace gas or coke oven gas is significantly less than that associated with the combustion of natural gas due to a much smaller concentration of complex hydrocarbon compounds. The commenters believe that sources burning these byproduct gases should not be required to meet a CO limit of 400 ppm or install a CO continuous emissions monitor because CO is not a reliable indicator that HAP emissions are elevated. In addition, units burning high CO concentrated gases may not be able to meet the 400 ppm emission limit. The commenters claimed that this would discourage the use of byproduct fuels and result in increased HAP emissions since the gases would be burned elsewhere, and natural gas burned in their place. One commenter ( 418) recommended that blast furnace gas fueled units be exempted from all work practice standards because this type of fuel does not contain the constituents that generate HAP during combustion. The other commenters ( 431, 475, 503, 504, 505) suggested encouraging the beneficial use of byproduct fuels by exempting them from the MACT requirements or allow units using byproduct fuels to be regulated according to the amount of purchased fossil fuels it utilizes.

Response: We have reviewed the information submitted by the commenters and agree that blast furnace gas contains minimal or even no hydrocarbons. In the final rule, we exempted blast furnace gas fired units from all provisions of the boilers NESHAP. However, these units, as defined by the boilers NESHAP, are boilers and process heaters that receive 90 percent or more of their total heat input ( based on an annual average) from blast furnace gas. If your boiler or process heater receives less than 90 percent of it total heat input from blast furnace gas, then the CO work practice standards could apply to your unit if it meets the definition of new source and is larger than 10 MMBtu/ hr 103 Comment: Several commenters ( 360, 364, 382, 388, 399, 387, 403, 406, 407, 408, 410, 426, 449, 479, 492, 498, 501, 524, 533) requested that EPA implement the CO work practice standard as a trigger for corrective action and not as an emission limit as proposed. Several commenters ( 406, 407, 408, 501) noted that a corrective action trigger would be appropriate because CO is not a HAP, but a surrogate to control related HAP emissions in a general sense as opposed to a quantitative or predictive sense. One commenter ( 360) contended that there was little proof that a 400 ppm CO limit would limit organic HAP emissions. One commenter ( 410) agreed that CO emissions from boilers or heaters provide a reasonable rough indicator of whether good combustion practices are being followed and preferred monitoring CO over monitoring organic HAP directly. The commenter added that based on the PERF study, CO is a weak indicator of organic HAP in concentrations between 10 and 1000 ppm, but good beyond 1000 ppm. The commenter concluded that based on the PERF study, exceedence of the 400 ppm limit should not be considered a violation but should require the owner to take corrective action within a reasonable time frame. Two commenters ( 426, 492) added the CO level being a corrective action trigger will provide incentive to maintain good operating practices without creating violations for conditions that may not be related to increased HAP emissions. One commenter ( 426) listed several planned activities that could cause CO emissions to exceed 400 ppm. The commenter also listed some unforeseen activities that could cause an increase in CO emissions. The commenter added that because of the complexity of refinery operations, it would be difficult and time consuming to identify and document every conceivable situation that would require units to be run at a reduced rate in a startup, shutdown and malfunction plan.

Response: In the final rule, we have clarified that an exceedence of the CO limit constitutes a deviation of the work practice standard. An observed exceedence of a monitoring parameter is not an automatic violation. You are required to report any deviation from an applicable emission limitation ( including operating limit). We will review the information in your report along with other available information to determine if the deviation constitutes a violation. The determination of what emission or operating limit deviation constitutes violations of the standard is up to the discretion of the entity responsible for enforcement of the standard. Since proposal, we revised the rule to provide more flexibility with regard to complying with the work practice standard for CO. For solid fuel fired units, we changed the oxygen correction factor from 3 to 7 percent to more accurately reflect oxygen levels in solid fuel fired units. We also lengthened the averaging period for solid fuel fired units that are required to use CO CEMS from a 24 hour average to a 30 day rolling average. Furthermore, we added a provision that excluded CO emission data when a boiler or process heater is operating at or below 50 percent of the rated capacity. We believe that these changes should address some of the commenters' concern.

Comment: One commenter ( 427) contended that § 63.7500( c) regarding requesting alternative work practices is poorly written and does not convey the requirement clearly. The commenter suggested alternative wording.

Response: This alternative is only applicable if, in the Administrator's judgment, an owner or operator of an affected source has established that an alternative means of emission limitation will achieve a reduction in emissions of a hazardous air pollutant from an affected source at least equivalent to the reduction in emissions of that pollutant from that source achieved under any design, equipment, work practice, or operational emission standard, or combination thereof, established under this part pursuant to section 112( h). For a source to be allowed to establish an 104 alternative work practice standard, the Administrator must determine one of the following: a) HAP cannot be emitted through a conveyance designed and constructed to emit or capture such pollutants, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State, or local law, or b) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. We are not going to modify this section for two reasons: 1) We do not believe that many sources affected by this NESHAP would be in a situation where this alternative would be allowed, and 2) the section refers to § 63.6( g) which clearly spells out the reasons and requirements for petitioning for an alternative work practice standard.

Comment: Several commenters ( 364, 399, 387 383) requested that EPA reevaluate the CO work practice standard. The commenters argued that the current CO standard may result in unintended consequences such as a reduction in the use of biomass fuel. One commenter ( 364) provided an example wherein a boiler affected by a CO limitation could not meet the limitation while burning its standard blend of fuels. To meet the standard, the source cut back the combustion of biomass resulting in an increase of sulfur dioxide emissions due to the additional fossil fuels required. One commenter ( 320) contended that the CO standard of 400 ppm would be impossible to attain with biomass fuels. The commenter contended that there are severe negative economic impacts and minimal reduction in HAP emissions resulting from the CO standard.

Response: Since proposal, we revised the CO work practice standards to address solid fuel fired sources more appropriately. We increased the oxygen correction factor for new solid fuel fired sources from 3 to 7 percent to be more representative of the oxygen levels present in solid fuel fired units. We increased the averaging period for solid fuel fired sources has been increased from 24 hours to a 30 day rolling average to account for normal variations in fuel quality that may affect CO emissions. Finally, we modified the recordkeeping requirements that relate to CO emissions and do not require you to collect or include CO emission data for periods where your boiler or process heater is operating at loads less than 50 percent of total capacity. We believe that these changes should address the commenters concern and should not discourage the beneficial use of renewable energy sources such as biomass.

Comment: One commenter ( 424) stated that EPA underestimated the cost of installing and operating CO continuous emissions monitoring systems and recommended that EPA exempt new gaseous fuel fired boilers from any NESHAP requirements. One commenter ( 490) argued that the CO monitoring requirements for gaseous fuel fired units would be expensive and result in no environmental benefits.

Response: We do not exempt all new gaseous fuel fired boilers and process heaters from any NESHAP requirements. New gaseous fuel fired sources that have a heat input capacity of 10 MMBtu/ hr or more will have an applicable CO work practice standard. However, in the final rule, we no longer require new boilers and process heaters that have a heat input capacity less than 100 MMBtu/ hr to install a CO CEMS if they have an applicable CO work practice standard. Units with a heat input capacity less than 100 MMBtu/ hr will only have to conduct annual performance testing for CO. This change significantly reduces the cost of compliance for new sources. 105 Comment: Several commenters ( 364, 374, 382, 383, 387, 388, 399, 403, 449, 492, 498, 524, 533) suggested modifying the 400 ppm standard so that it does not apply during periods of very low load operation. One commenter ( 492) noted that real time variation of CO measurements from varying operating load conditions must be considered in establishing an achievable CO work practice standard. The commenter added that cycling load and intermittent low load conditions may often result in spikes and fluctuations in CO emissions, and the imposition of a CO limit under very low load conditions may be inappropriate. Several commenters ( 364, 382, 387, 388, 399, 403, 449, 498, 524, 533 ) suggested providing an exemption to the CO standard when units are operating at loads less than 50 percent. One commenter ( 364) also noted that EPA's analysis did not include startup, shutdown, malfunction, and high boiler turndown events into the variability analysis and also pointed out that other existing State CO limitations include exemptions during turndown periods.

Response: We agree with the commenters that cycling load and intermittent low load conditions may result in fluctuations in CO emissions that sources cannot control. Therefore, in the final rule, we modified the recordkeeping provisions such that you are not required to collect or use CO emission data in determining compliance when your boiler or process heater is operating a loads less than 50 percent of the rated capacity. Furthermore, we also modified the final rule to extend the averaging period for CO emissions from 24 hours to a 30 day rolling average. We believe that this change will continue to provide the desired reduction in organic HAP emissions while accounting for normal unit operation that may affect CO emissions.

Comment: Several commenters ( 364, 382, 383, 387, 388, 399, 401, 404, 406, 407, 408, 430, 449, 498, 524, 533) requested that EPA increase the oxygen correction factor applied to the CO work practice standard for solid fuel fired units, especially biomass fuel fired units. The commenters requested that EPA increase the oxygen correction factor from 3 to 7 percent for solid fuel fired units. Several commenters ( 449, 524, 533, 388, 498) stated that many solid fuelfired units typically operate with excess oxygen levels in the 7 percent range and that higher excess air levels are needed to compensate for the more difficult mixing of air and fuel. The commenters also noted that high moisture fuel with inherent moisture variations coupled with load variations, make the 400 ppmv corrected to 3 percent oxygen CO limit unattainable. Several commenters ( 406, 407, 408, 501) provided CO data from four modern biomass fired boilers that underwent PSD and BACT that showed that these boilers would not comply with the proposed CO standards. Other commenters ( 388, 406, 407, 408, 449, 498, 501, 524, 533) also listed other EPA regulations that have incorporated an oxygen correction factor of 7 percent. Several commenters ( 374, 382, 388, 449, 492, 498, 524, 533) suggested that the 3 percent correction factor remain for gas and oil fired units. One commenter ( 340) stated the CO concentration in Table 8 needed to be referenced to an oxygen concentration of 3 percent is the usual standard for boilers.

Response: We agree that the application of a 3 percent oxygen correction factor for solid fuel fired boilers and process heaters may not be appropriate. Due to the nature of burning solid fuels completely, additional oxygen is needed in the flame zone to ensure complete combustion. Therefore, in the final rule, we increased the oxygen correction factor from 3 to 7 percent for solid fuel fired units. Furthermore, we increased the averaging time for solid fuel fired sources from 24 hours to a 30 day rolling average to account for fuel variations such as moisture. We believe that these changes should address the commenters' concern over the CO work practice standard application to solid fuel fired boilers and process heaters. 106 Comment: Several commenters ( 346, 374, 382, 388, 410, 449, 479, 492, 498, 524, 533) recommended that CO continuous emissions monitoring systems be required only for units greater than 250 MMBtu/ hr. Several commenters ( 360, 492) supported an initial compliance test followed by periodic testing for units less than 250 MMBtu/ hr. Two commenters ( 410, 490) suggested requiring initial compliance tests using a portable CO process monitor for units greater than 100 MMBtu/ hr and less than 250 MMBtu/ hr. The commenters also suggested that EPA exempt units smaller than 100 MMBtu/ hr from the CO work practice standard. One commenter ( 490) suggested for units greater than 100 and up to 250 MMBtu/ hour, the operator would be required to complete an initial stack test and thereafter complete annual inspections and unit adjustments, and subsequent stack tests would be required if the unit burners are replaced. The commenter also added that for units greater than 250 MMBtu/ hour, the operator would be required to complete an initial stack test and annual tuning of the burners, and retesting of the unit would be conducted every 5 years or when burners are replaced. Several commenters ( 332, 371, 424, 479) requested that EPA only require CO continuous emissions monitoring systems on units larger than 40 MMBtu/ hr and allow smaller units to conduct annual CO emission tests. One commenter ( 371) claimed the proposed rule is inconsistent with the current South Coast Air Quality Management District requirements, which allow annual source testing of units that are less than 40 MMBtu/ hr in lieu of continuous emissions monitoring systems.

Response: In the final rule, we require boilers and process heaters that have a heat input capacity of 100 MMBtu/ hr or more to install a CO CEMS only if they have an applicable CO work practice standard. For sources smaller than 100 MMBtu/ hr, annual performance testing for CO is required to demonstrate compliance with the applicable work practice standard. We made this change in the boilers NESHAP to minimize compliance costs for smaller sources that would result from the installation of a CEMS. With a size cutoff of 100 MMBtu/ hr, we are assured that all units with a heat input capacity of 100 MMBtu/ hr or greater will already have a CEMS for other pollutants required by NSPS subpart Dc and the addition of a CO analyzer to an existing CEMS would not be as onerous as installing a CEMS for the purpose of monitoring only CO.

Comment: Two commenters ( 369, 491) recommended that EPA exclude from CO monitoring requirements natural gas and distillate oil fired boilers and process heaters with less than 50 MMBtu/ hr heat input. One commenter ( 491) argued that calculations based on AP 42 emission factors indicated that CO emissions from natural gas and distillate oil fired boilers and process heaters are significantly less than the work practice standard of 400 ppm of CO. Therefore, the commenter stated that there is no point in installing a CO continuous emissions monitoring system and monitoring CO if the emissions are expected to always be well below the proposed work practice limit. In addition, the commenter stated that EPA could promulgate a boiler tune up requirement as a work practice standard to assure that boilers and process heaters are properly maintained. The commenter cited New York State's tune up regulation ( 6NYCRR Part 227 2.4( d)). Another commenter ( 479) requested EPA exempt small and new reconstructed gas and liquid fuel fired units that have minimal emissions. One commenter ( 500) stated that CO continuous emissions monitoring systems are not necessary for new gaseous fired units. The commenter stated that facilities already closely maintain burners for economic reasons. The commenter stated that periodic CO performance testing provides an adequate measure of the combustion performance of a gaseous fired burner, without the need for costly continuous emissions monitoring systems and their respective monitoring plans. 107 Response: In the final rule, we modified the CO monitoring requirements for boilers and process heaters that have a heat input capacity less than 100 MMBtu/ hr. Units with rated heat input capacities less than 100 MMBtu/ hr are not required to install a CO CEMS, but will only have to conduct annual performance testing for CO. We maintain that this change to the monitoring requirements will reduce the cost of compliance for smaller sources but still maintains assurance that these sources are meeting the CO work practice standards.

With regard to the commenter's request to exempt small and new reconstructed gaseous and liquid fuel fired units, the proposed and final rule does not contain any compliance requirements for small gaseous fuel fired sources, new or existing. For new small liquid fuel fired sources, emission limits exist, but the monitoring, recordkeeping, and reporting requirements have been minimized for sources that burn only fossil fuels and do not burn any residual oil.

Comment: One commenter ( 439) suggested that EPA consider the cost effectiveness of requiring continuous emissions monitor on units less than 100 MMBtu/ hr in relation to the potential reduction in HAP emissions given the required work practice standard. The commenter stated that EPA should provide information on actual HAP emissions from improperly operated units and potential HAP reductions resulting from work practice standards. The commenter believes EPA should quantify actual HAP emissions from " improperly operated" units less than 100 MMBtu/ hr and compare these HAP emissions to the costs of implementing the proposed work practice standards for units with the same heat input capacity. The commenter suggested that EPA should revise the requirements and remove work practice standards for new gaseous fuel units less than 100 MMBtu/ hr heat input.

Response: In the final rule, we removed the requirement for sources less than 100 MMBtu/ hr to install and operate CO CEMS if they have an applicable CO work practice standard. These sources will only have to conduct annual performance testing to demonstrate compliance with the CO work practice standard. We believe that this change is an effective way to minimize the compliance cost for many sources.

With regard to quantifying HAP reductions resulting from the application of the work practice standards, obtaining quantitative impacts on HAP emission reductions is difficult due to the site specific nature of boiler and process heater operation and organic HAP emission levels, though experience with boiler and process heater operation demonstrates that organic HAP emissions are minimized through efficient combustion ( e. g., low CO emission levels). For example, if a boiler or process heater is typically operating in an efficient manner and the owner/ operator of such a unit maintains the source in a good manner, the application of a CO work practice standard may not result in significant reductions of organic HAP. However, if a boiler or process heater is not operated in an efficient manner, organic HAP reductions would be more significant. Therefore, arriving at organic HAP reductions is not as straightforward as determining the reduction in hydrogen chloride emissions from installing a scrubber or from switching fuel types. For these reasons, we do not provide emission impacts resulting from the application of work practice standards.

Comment: One commenter ( 340) requested the EPA include a combustion optimization requirement for existing, new, and reconstructed units. There have been papers presented at the Electric Power Research Institute/ EPA Megasymposiums which discuss the effectiveness of tuning boilers using software packages that manage boiler combustion. Decreases of nitrogen 108 compound emissions, less loss on ignition to fly ash, and increases in efficiency were demonstrated. This indicates economic incentives to ensure that fuel is not wasted, and the combustion device operates properly and is appropriately maintained. The commenter requested that EPA include a combustion optimization requirement for existing, new, and reconstructed units. The combustion optimization should use control and automatic boiler tuning algorithms to automatically track time varying physical and operational changes to the boiler in order to optimize boiler efficiency and loss on ignition through closed loop mangagement of the air/ fuel and temperature distributions within the boiler while maintaining the NOx emission rate in compliance with other applicable requirements. Another commenter ( 376) requested that EPA allow the use of Good Combustion Practices demonstrated through combustion optimization in lieu of the CO work practice standard. The commenter expressed concern that the CO work practice standard could have adverse impacts such as increased nitrogen compound emissions.

Response: As we discussed in the preamble to the proposal, we did review good combustion practice references and application of good combustion practices. However, we noted that there was a lack of information, and a lack of uniform approach to assuring combustion efficiency. We noted that these finding were not surprising given the extreme diversity of boilers and process heaters, and given the fact that no applicable Federal standards, and most applicable State standards, do not include work practice requirements for boilers and process heaters. Even those States that do have such requirements do not require the same work practices. Since we were unable to determine any uniform requirements or set of work practices that would meaningfully reflect the use of good combustion practices, or that could be meaningfully implemented across any subcategory of boilers and process heaters, we have not included any specific good combustion practice requirements in the final rule. We do consider monitoring and maintaining CO emission levels to be associated with minimizing emissions of organic HAP. Therefore, controlling CO emissions can be a mechanism for ensuring combustion efficiency and may be viewed as a type of good combustion practice. That is why we included the CO work practice standards in the final rule and did not include any specific good combustion practices.

Comment: One commenter ( 382) supported the use of CO limits as the only new source work practice standard. Three commenters ( 382, 447, 519) noted that there are no " common" good combustion practices that could assure a certain level of HAP emission control across the diverse population of boilers and process heaters. One commenter ( 492) agreed with EPA's finding that CO monitoring is the only applicable new source work practice standard requirement. According to the commenter, the diversity of industrial and commercial boilers and process heaters does not allow for " common" combustion practice requirements that could assure a certain level of HAP emissions, and EPA correctly determined that none are suitable as a basis for the MACT floor. One commenter ( 415) suggested that EPA should incorporate good combustion practice recommendations into the proposed rule. The commenter noted that it is inappropriate for EPA to make the blanket assumption that all existing boilers and process heaters already are operating at optimum efficiency when data suggest otherwise. The commenter stated that EPA should not assume that economic concerns are sufficient to ensure that boilers at all facilities are already operating at peak efficiency. The commenter referenced work done by the Delta Institute on benefits and emission reductions from good combustion practices.

Response: As we explained in the preamble to the proposal, we were unable to identify any uniform requirements or set of work practices that would meaningfully reflect the use of good combustion practices, or that could be meaningfully implemented across any subcategory of 109 boilers and process heaters. That is why we did not promulgate any good combustion practices in this NESHAP. With regard to the commenter's statement that we made a blanket assumption that all boilers and process heaters are operating at optimum efficiency, we maintain that all boilers and process heaters are designed for good combustion and facilities have an economic incentive to ensure fuel is not wasted by maintaining good combustion. However, we do not believe that all facilities operate their units at optimum efficiency. That is why we promulgated a CO work practice standard as a mechanism for ensuring combustion efficiency, which may be viewed as a type of good combustion practice.

Comment: One commenter ( 343) agreed with EPA that CO is a good indicator of incomplete combustion and that minimizing CO emissions should result in minimizing organic HAP emissions. However, two commenters ( 343, 434) recommended that minimizing CO emissions can be accomplished more cost effectively by ensuring that there is sufficient excess air for complete combustion, rather than by installing a CO continuous emissions monitor. One commenter ( 434) recommended that excess air monitors be permitted to control such sources. Another commenter ( 343) suggested the following alternatives: 1) Perform a stack test to demonstrate initial compliance with the 400 ppmvd at 3 percent oxygen, CO emissions limitation. To demonstrate continuous compliance, verify once per month that the burner oxygen setpoint from the initial compliance test has not changed. In the event that changes are made to the operation of the boiler/ process heater that could reasonably be expected to impact CO emissions, a test with a portable analyzer for CO is required to ensure that CO emissions are still below the 400 ppmvd; 2) Use an annual tuning procedure that establishes the minimum oxygen level resulting in 400 ppmv CO and then set the burner oxygen controls to operate above this level with an allowable margin. Burner setpoints are verified once per month to ensure that the settings established during the tuneup have not changed. The commenter referenced procedures used by the Massachusetts Nitrogen Compound Reasonably Available Control Technology regulations.

Response: We chose to use CO CEMS as the monitoring parameter for the CO work practice standard because CO CEMS are proven technologies for measuring CO emissions. In the case of some other pollutants regulated by the boilers NESHAP ( e. g., hydrogen chloride, mercury, etc.), CEMS are not widely proven and are cost prohibitive. Therefore, for several regulated pollutants in this NESHAP we use parametric monitoring systems when direct measurement is not practical. In the final rule, we require sources that have an applicable CO work practice standard to install a CO CEMS if the unit has a heat input capacity of 100 MMBtu/ hr or greater. We have decided to stay with CO CEMS for those units because they would already have to install a CEMS system under the NSPS requirements and the addition of a CO analyzer would be an incremental cost. For units with a heat input capacity less than 100 MMBtu/ hr, we require annual CO performance testing. If you would like to use another method to monitor CO emissions from your boiler or process heater, you can petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63. 110 11.0 COMPLIANCE 11.1 General Comment: Several commenters ( 364, 382, 387, 399, 449, 492,524) insisted that EPA provide flexibility for emission limits, testing, and operating parameters to account for the many diverse equipment arrangements used by boilers and process heaters. One commenter ( 382) argued that the proposal was based on the assumption of a single unit being associated with its own control system and that in practice there are many arrangements that are more complex. The commenters provided several examples of alternate arrangements and requested that EPA specifically address arrangements such as, but not limited to the following: 1) allowing the use of a single opacity monitor or bag leak detection system downstream of a common emissions control device; 2) allowing the use of existing emission monitoring and testing locations whether it serves single or multiple units; 3) emission testing that allows for multiple units being served by a single control device; 4) establishment of control ranges for operating parameters that could vary significantly depending on the number and firing rate of individual units operating; 5) emission testing that can simultaneously cover all of the units served by a common control device rather than testing each unit individually; and 6) flexibility to test emissions from common control devices whether or not full load capability is available at the time. The commenters requested that EPA provide sources an opportunity to propose alternative approaches for compliance demonstrations to their permitting authorities should specific arrangements not be addressed in the rule. One commenter ( 492) suggested that this flexibility may best be served by enabling the " bubbling" compliance concept described in the proposal.

Response: We are aware that a diverse population of boiler and process heater arrangements exist. However, to address in this rule all the different types of arrangements that exist would be too cumbersome and we believe that we would still not be able to incorporate all the existing and future arrangements that will be employed by boilers and process heaters. Therefore, in the final boilersNESHAP we have modified the proposed requirements to provide more flexibility by including such elements as the following: 1) fixed opacity limits similar to those provided in the industrial boilersNSPS; 2) emission averaging provisions for solid fuel fired units; 3) less restrictive fuel sampling requirements that are based on fuel type ( i. e., subbituminous coal, bark, railroad ties, tires) and not triggered by changes in fuel suppliers or fuel location; 4) providing operating ranges around the operating limits; and 5) providing a compliance method based on fuel analysis. If you still require an alternative monitoring strategy for your source, you can petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: Two commenters ( 521, 535) stated that a circulating fluidized bed ( CFB) boiler using limestone injection controls inorganic acid gases effectively and reliably. Therefore, the commenter requested that EPA allow sources having CFB boilers to take pollution control credit, similar to the credit offered to sources having scrubbers and other add on controls.

Response: We acknowledge that CFB boilers that inject limestone and other types of sorbents achieve effected acid gas control. Therefore, we have added CFB boilers with limestone or sorbent injection to the dry scrubber definition. In the final boilers NESHAP, CFB boilers that inject limestone or other types of sorbent will be required to establish a sorbent injection rate during performance testing for hydrogen chloride and must monitor sorbent injection as an 111 operating limit.

Comment: One commenter ( 491) requested that EPA state in § § 63.7530( b) and § 63.7540( a)( 2) that new or reconstructed boilers or process heaters in one of the liquid fuel subcategories that burn only fossil fuels and other gases and do not burn any residual oil are presumed to be in compliance with the applicable requirements and that no gap filling periodic monitoring is required for these units under Title V. The commenter stated that this statement is needed to assure that state regulators do not feel that they have to require gap filling monitoring for these units. One commenter ( 487) requested that EPA clarify the final rule so that gaseous and liquid fuel fired units are not required to comply with the monitoring and data collection requirements proposed in § § 63.7535 and 63.7540, and the monitoring and inspection, operation, and maintenance requirements of § 63.7525.

Response: In the final boilers NESHAP, we have clearly stated that liquid fuel fired units that only burn fossil fuels and do not burn any residual oil demonstrate compliance by certifying that they do not burn any residual oil. We do not believe an additional statement addressing Title V is necessary since we have clearly outlined the compliance requirements for these types of units. We also have clearly stated in § § 63.7535 and 63.7540 the specific requirements for these types of units and believe that no additional clarification is needed in those sections. Furthermore, since these units are not required to have continuous monitoring systems ( CMS), we also believe that no additional clarification is needed in § 63.7525.

Comment: Two commenters ( 354, 417) do not believe that the proposed monitoring, recordkeeping, notification, analytical and stack performance testing requirements in the proposed rule are justified. One commenter ( 354) argued that EPA has not presented evidence that any of these additional requirements will achieve emission reductions, but will be costly and burdensome for affected entities. The commenter recommended that all requirements that are not directly related to quantifiable emission reductions be removed from the final rule.

Response: We disagree with the commenter because continuous monitoring requirements are necessary to ensure ongoing compliance with the emission limits. We require performance testing to demonstrate compliance with the emission limits and use operating parameters to ensure that the source is operating in a manner similar to the way it was operating during the successful performance testing. Parametric monitoring is a tool to minimize the cost that would be associated with installing continuous emission monitoring systems for the regulated pollutants or conducting more frequent performance testing. However, we need the monitoring, recordkeeping, notification, analytical and stack performance testing requirements to provide evidence of compliance with this NESHAP. We have worked to minimize the burden of the boilers NESHAP while remaining confident that compliance with the standard is being sustained.

Comment: One commenter ( 347, 376) requested that EPA allow sources flexibility to use any technology to comply with the applicable emission limitations. One commenter ( 347) requested that EPA clarify whether new sources have to install the MACT floor level of control or if the only requirement is demonstration of compliance with the emission limits.

Response: The NESHAP program is a technology based regulatory program that sets emission limits based on the best performing units in a category. However, existing and new 112 sources are not required to use the specific control technologies that were used to establish the emission limits. You may use any technology or pollution prevention strategy to comply with the applicable emission limits.

Comment: One commenter ( 372) requested that EPA exempt " low risk" sources from most of the ongoing compliance demonstration requirements. The commenter defined low risk facilities as those that demonstrate compliance with the emission limits by as substantial margin, such as less than 50 percent of the emission limit. This margin would be enough to provide assurance of ongoing compliance over the range of fuel variability and normal operating conditions. Using existing opacity limits and requiring chlorine content testing for new fuel types, the commenter believes that this would provide a reasonable alternative to the proposed rule requirements.

Response: We are not providing an exemption for source that demonstrate compliance with the emission limits by a substantial margin. Since proposal, we have minimized the ongoing compliance requirements of the boilers NESHAP in order to reduce the burden on sources, by modifying the fuel sampling requirements, opacity limits, and the definition of operating limits. We are also allowing facilities to conduct performance testing once every three years if they demonstrate compliance with the emission limits for three consecutive years. Therefore, we believe that we have provided a significant amount of flexibility for sources without compromising the measures needed to ensure ongoing compliance with the emission limits.

Comment: One commenter ( 529) questioned the instructions in § 63.7530( c) for conducting performance tests. The instructions indicate that no controls are required, even if a control device is installed and has been identified as part of the MACT floor. The commenter stated that allowing a facility to not take credit for the control device minimizes the reduction of emissions to a level that barely passes the emission standard and provides a disincentive for new technology. Also, § 63.7530( c) allows the regulated facility to use fuel switching to achieve the emission limits. The commenter stated that this practice does not protect human health and asks that either the compliance period be assessed more frequently or the short term firing ratio be enforceable.

Response: The NESHAP program establishes emission limits based on the best performing sources in a category. Some facilities may be able to meet the emission limits through the types of fuel that they burn or through fuel switching. In these cases, we allow fuel analysis as the method to demonstrate compliance because emissions of the regulated pollutants under this NESHAP ( metals, mercury, hydrogen chloride) can be determined through fuel analysis since they are neither formed nor created during the combustion process. Therefore, if the ratio of fuel pollutant content to fuel heat value is lower than the emission limit, we are confident that the source is meeting the emission limit. Since the NESHAP program does not require installation of the specific control technologies used to establish the MACT, only demonstration that the emission limits established by the MACT control technologies are being met, it is acceptable under this program for a facility to demonstrate compliance with the emission limits without the use of addon controls or through fuel switching. Residual health risks from these sources after the NESHAP emission limits have been implemented will be addressed in eight years under the 112( f) residual risk program. 113 Comment: One commenter ( 354) suggested EPA consider requiring mine permitting authorities to impose restrictions on issuance of mining permits for coal seams deemed to have unacceptable levels of HAP.

Response: We are required to develop and implement a NESHAP for boilers and process heaters since they are a listed source category under section 112 of the CAA. Coal mines are not a specifically listed source under this program. Therefore, we cannot regulate coal mines directly under the NESHAP program. For some facilities, their economics allows them to purchase coal with pollutant contents higher than the emission limits and use control to achieve compliance. This is an acceptable option under this NESHAP. As part of their fuel purchasing contracts, sources also have the option of requiring coal mines to only ship coal that contain pollutants at concentrations less than the emission limits of this NESHAP.

Comment: One commenter ( 491) stated that § § 63.7540( a)( 4), ( 6), and ( 8) include provisions for conducting new performance tests in the event a new type of fuel, a fuel from a new supplier, or a new mixture of fuel is burned and the calculated values exceeded the established values. However, it is not clear what time period is allowed for conducting the tests. The commenter suggested that EPA clarify the applicable time period. The commenter requested that EPA allow the source 180 days in which to perform this new performance test. The commenter stated that this time is necessary for the owner or operator to schedule and conduct the performance test and to perform multiple tests if needed to establish worst case fuel conditions. The commenter stated that noncompliance should not result if the new performance test indicates that the applicable emission limitations have not been exceeded.

Response: We agree that some time allowance is needed for which a source must conduct a new performance test if it burns a new fuel that has a pollutant content higher than the fuel that they have previously burned and the source cannot demonstrate compliance with the emission limits through fuel analysis. However, we believe that 180 days it too long. We agree that switching the type of fuel requires planning, but we believe that 60 days is adequate time to conduct a performance test in such situations. If a source is planning to switch its fuel, then they should have time to prepare for a performance test. We have also modified the fuel monitoring provisions such that sources are required to conduct fuel analyses only if a new fuel type ( i. e., bituminous coal, tires, biomass) is burned. This should minimize performance testing that is triggered by natural variation with a fuel type. If a new performance test is required due to the use of a new fuel type, then the source must demonstrate compliance with the applicable emission limits and establish new applicable operating limits.

11.2 MONITORING Comment: One commenter ( 417) stated that the proposed rule's approach to monitoring is unduly burdensome and overly restrictive and suggested that affected units be given the flexibility to develop a source specific monitoring program that builds on current monitoring practices and is consistent with existing rule and permit requirements. The commenter also suggested that operators have the flexibility to propose a monitoring plan for ESP performance indicators rather than conforming to a single monitoring requirement.

Response: We revised the monitoring provisions to minimize the burden of the boilers 114 NESHAP on affected sources. However, we must have continuous monitoring provisions to ensure ongoing compliance with the NESHAP and cannot completely eliminate them. We have worked to use parameters already monitored by most sources as the basis for ongoing operating limits. We chose this approach to minimize the monitoring burden. However, we are unable to address all the configurations that exist. If you believe your source needs a more site specific monitoring plan, you can petition the Administrator for an alterative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 297, 364, 387, 399, 491, 492) argued that units that operate fabric filters should be able to use either a continuous opacity monitoring systems ( COMS) or a bag leak detection system to monitor compliance and that a requirement to use both systems would be duplicative, expensive, and not necessary. Some commenters ( 382, 419, 478, 529) recommended that EPA allow facilities that operate fabric filters the option to use pressure drop monitors. One commenter ( 297) expressed concern over the requirement to establish an opacity limit based on the measured opacity during the performance test. The commenter explained that it is not reasonable to have such a requirement because the commenter typically operates the boiler near 0 percent opacity. The commenter argued that it is not reasonable to establish the emission limit at near 0 percent. Another commenter ( 419) noted that COMS are known to have difficulty measuring less than 10% opacity. The commenter's historical opacity levels are between 0 and 5% and commenter does not want to be forced into purchasing an expensive COMS system that is less accurate then their current pressure drop monitoring practice. Several commenters ( 364, 382, 387, 388, 399, 449, 491, 492, 498, 524, 533) recommended that EPA clarify in the final rule that new or existing units with bag leak detectors on fabric filters are not required to monitor opacity nor would they be subject to any opacity limits. The commenters noted that there are conflicting statements within the proposed preamble and rule that indicate that bag leak detection systems and opacity monitoring systems may both be required. One commenter ( 491) stated that bag leak detection systems should be used in all cases. In addition, the commenter stated that the installation and operation of a continuous monitoring system for those boilers and process heaters that are equipped with a fabric filter serves no useful purpose. One commenter ( 492) suggested that a bag leak detection system be considered an operating parameter and a clarification that the General Provisions requirement of submittal of continuous opacity monitoring system data does not apply to fabric filter equipped units.

Response: In the final NESHAP, we clarified that sources using fabric filter control have the option of using either opacity monitoring systems or bag leak detection systems to demonstrate continuous compliance.

Comment: One commenter ( 413) requested EPA explain how sources are to chose the alarm sensitivity for bag leak detectors and whether the level can be adjusted over time. The commenter added that if EPA intends the alarm level to be based on performance testing, EPA has not explained how that would be accomplished. The commenter concluded that EPA has not demonstrated that the 5 percent alarm rate limit is reasonable or that technology is sufficiently reliable to be used as a compliance method.

Response: As outlined in the final NESHAP, we supplied guidance on fabric filter operating in a document entitled " Fabric Filter Bag Leak Detection Guidance." This document is available at www. epa. gov/ ttnemc01/ cam/ tribo. pdf. We believe that the 5 percent alarm rate is a 115 reasonable allowance for sources due to variation in operation and fabric filter failure that can occur during normal operation and have also require sources to develop a startup, shutdown, and malfunction plan that will outline corrective actions when a fabric filter alarm is triggered.

Comment: Some commenters ( 478, 491, 529) expressed concern over the proposed requirement for positive pressure fabric filters to have bag leak detection systems located on each cell, but only one bag leak detection system is required for negative pressure systems. The commenters stated that they understand this requirement when each compartment or cell exhaust directly to the atmosphere, however, many fabric filters exhaust through a stack. Therefore, the commenters stated that a single bag leak detector will be sufficient downstream of a positive pressure fabric filter when all compartments or cells are ducted to a common stack before being exhausted to the atmosphere. One commenter ( 478) argued that as long as a unit can be monitored in accordance with § 63.7505( c)( 1)( i), a single instrument should be sufficient to demonstrate compliance for positive pressure fabric filter systems. One commenter ( 529) reviewed the Fabric Filter Bag Leak Detection Guidance referenced in § 63.7525( f) as providing specifications and recommendations for bag leak detection systems. However, the commenter reported that this document specifically states that it " does not impose regulatory requirements." The commenter recommended that the requirements be pulled from the Guidance and inserted into the MACT or that the guidance document be required to establish bag leak detection system installation, operation and maintenance criteria.

Response: We agree with the commenters. In the final rule, we require only one bag leak detector on the outlet positive pressure fabric filters, as long as they are ducted into a common stack. If the individual fabric filter cells do not duct into a common stack, then bag leak detectors will be required for each cell. The guidance document offers one way to specify an acceptable fabric filter bag leak detection system. You also have the option to petition the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: One commenter ( 393) believes the proposed requirement to use of a bag leak detection system will not demonstrate non compliance with emission limits. The commenter noted that EPA can prove that the activation of a bag leak detection alarm is an indication that the source is exceeding the emission limits of the boilers NESHAP. Another commenter ( 413) questioned EPA's proposal to use opacity and ESP voltage and power measurements as enforceable operating limits because EPA has not provided a direct correlation between opacity and PM or mercury to justify an enforceable limit.

Response: The use of bag leak detectors and ESP voltage/ current monitoring is employed to determine the operational status of the various control devices. The use of operating limits is not based on a direct correlation with emission levels, operating limits are used to ensure that pollution control systems are operating similarly to their operation during the performance test that demonstrated compliance with the emission limits. Since demonstrated and cost effective CEMS for particulate matter, mercury, or total selected metals are not widely used, we use parameters that facilities already monitor to determine control device performance. As we do not have a direct correlation between the operational parameters of these control devices and emission levels, the final rule provides a 10 percent operating range around the parameters established during the performance testing to account for normal variations in operation of the source and pollution control device. 116 Comment: One commenter ( 529) explained that § 63.7540( a)( 9) allows an alarm on the bag leak detection system to not be counted " if inspection of the fabric filter demonstrates that no corrective action is required." The commenter believes this wording implies that the baghouse should be shut down for inspection. This procedure should be covered in the Site Specific Monitoring Plan required in § 63.7505( c) and suggested that EPA modify that language to read " if inspection of the fabric filter in accordance with the Site Specific Monitoring Plan demonstrates that no corrective action is required."

Response: We agree with the commenter that a fabric filter should not have to be shut down for inspection if an alarm is triggered and revised the final NESHAP according to the commenter's suggestion.

Comment: Several commenters ( 364, 399, 387, 519) requested the EPA remove or qualify the requirement that facilities use manufacturer's originally installed control device operating parameter monitoring equipment. The commenter noted that facilities typically replace original equipment for various reasons and, therefore, this requirement may not be appropriate.

Response: We agree with the commenter and removed from the final rule the requirement to use the manufacturer's originally installed monitoring requirement. However, you must have equivalent monitoring equipment in place if you use that monitoring parameter to demonstrate continuous compliance.

Comment: Several commenters ( 364, 399, 387, 468, 491) requested that EPA revise the language in § 63.7530( c)( 6)( ii) and in Tables 7. A and 7. B to require monitoring only for the parameters that impact the specific pollutant for which the control is installed. For example, if a source uses a scrubber to control particulate matter, and hydrogen chloride is controlled by limiting fuel chlorine content, the source should not be required to monitor pH of the scrubber. Or, conversely, if a scrubber controls hydrogen chloride with a scrubber but not particulate matter, then scrubber liquid flow rate and pH would be appropriate monitoring parameters and pressure drop would not.

Response: We agree with the commenters. In the final rule, we completely revised the tables at the end of the rule to make the compliance requirements more simple to understand and apply in practice. For example, if a wet scrubber is used to control particulate matter and is not credited for hydrogen chloride removal, then the source would not be required to monitor pH. Also, if a source is not taking credit for fabric filter control or if the fabric filter control is not applicable to the pollutant in question ( i. e., hydrogen chloride), then the source is not required to monitor bag leak detection alarms.

Comment: Several commenters ( 364, 399, 387, 444) requested that EPA allow certain types of solid fuel fired boilers equipped with dry control devices to choose which operational parameter ( e. g., ESP voltage, fabric filter leak detection) would be used as a sole compliance monitoring method.

Response: For sources with dry control devices, you must either monitor fuel pollutant content, opacity, or fabric filter leak detection alarms to demonstrate compliance. We do not allow the monitoring of ESP parameters as a sole method of compliance for sources with dry 117 controls. We believe that the use of opacity and leak detection monitoring devices are more effective for determining the ongoing operation of a source and its pollution control device than ESP parameters. However, when a wet control device is employed with an ESP, we require the monitoring of ESP parameters as opacity monitoring systems may not be an effective monitoring device in wet exhaust conditions.

Comment: One commenter ( 529) recommended that the word " secondary" be included in all references to voltage, current, and power to clearly specify that all operating limits are established for the secondary side of the transformer/ rectifier set. The commenter explained that operating limits need to be established that allow an operating range for ESPs, or require a multipoint testing and monitoring of firing conditions to describe the ESP operating limit. This is necessary because as a firing rate for a boiler decreases, the pollutant emissions decrease and the power required to charge the particle in the ESP decreases significantly. One commenter ( 413) provided a detailed explanation that ESP power input is not directly related to particulate removal performance. One commenter ( 364, 399, 387) requested that EPA allow the use of monitoring alternatives including the monitoring of voltage applied to an ESP instead of secondary current and secondary voltage. One commenter ( 357) stated that the setting of operating limits is unworkable as stated in the rule regarding ESP readings for solid fuels. The commenter stated that it is not reasonable to set ESP limits based on the performance testing because ash content affects ESP current load. The commenter stated that a particular solid fuel such as coal may have the same selected metals content per Btu, but a different ash content. In addition, the commenter stated the ESP can draw more current while maintaining the same removal efficiency with higher ash loading. The commenter suggested another option for setting ESP operating limits is to determine ESP efficiency and along with fuel analysis determine an operating limit.

Response: The final NESHAP provides you with the option of monitoring voltage and secondary current or total power input to the ESP. We also provided a 10 percent operating range to the operating limit established during the performance testing to allow for normal process variation. If you believe that you need another approach to monitoring your ESP, you can petition the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: One commenter ( 515) expressed concern that the requirement to monitor scrubber pH is not an appropriate operational parameter for a wet scrubber that controls hydrogen chloride. The commenter explained that hydrogen chloride is very water soluble in water and that at low concentrations, the pH of the scrubber liquid will be quite acidic. The commenter requested that EPA require monitoring of scrubber liquid hydrogen chloride content and for facilities to maintain the hydrogen chloride content at or below 10 percent to determine compliance. The commenter noted that this could be done by periodically titrating collected samples with 1N caustic. The commenter also provided hydrogen chloride vapor pressure and concentration curves to support their argument.

Response: We disagree with the commenter and continue to require sources with wet scrubber control of hydrogen chloride ( and other inorganic HAP) to monitor scrubber effluent pH. We believe that establishing a pH operating limit based on the results of a performance test that demonstrates compliance with the hydrogen chloride emission limit will ensure that the wet scrubber is operating similarly to its operation during the performance test that demonstrated 118 compliance with the hydrogen chloride emission limit. Furthermore, the monitoring of pH is a common monitoring parameter for wet scrubbing systems and minimizes additional compliance expenses.

Comment: Several commenters ( 364, 399, 387) requested that EPA change the requirement for wet scrubbers to set operating limits based on the highest pressure drop and liquid flow rate values measured during the initial performance tests to one based on the lowest measurements.

Response: We agree with the commenters and changed the language in the final NESHAP. The proposal language was in error and in the final NESHAP we require that the operating limit to be set at the minimum pressure drop and liquid flow rate that demonstrates compliance with the emission limits.

Comment: One commenter ( 519) argued that the proposed monitoring parameters for ESPs are not indicative of performance of ESPs equipped with microprocessor based control systems. The commenter explained that these types of ESPs adjust power usage based on unit load and the proposed monitoring parameters are inappropriate and unreasonable. The commenter suggested that ESPs equipped with microprocessor control have the following requirements: 1) monitor primary voltage to assure that voltage remains above the minimum level required to assure creation of a corona ( which is a site specific variable depending on ESP geometry); and 2) maintain a log of all instances when the ESP control system trips off or alarms, including the date, duration, and cause of the incident. The commenter also provided a paper explaining ESP operation and suggested monitoring methodologies.

Response: We acknowledge that sources may have different types of control device operating systems but realize that it would be impossible to capture all the different systems in a single rule. If you believe that you can develop a better monitoring plan for your source, you may petition the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 364, 399, 387, 444) requested that EPA establish a larger universe of scrubber designs and appropriate monitoring parameters. The commenters argued that additional scrubber types exist than those in the proposed rule and that the proposed monitoring parameters may not be appropriate for these other types of scrubbers. One commenter ( 364, 399, 387) offered to work with EPA to develop a larger matrix of scrubbers and associated monitoring parameters.

Response: As we discussed in other responses, it would be almost impossible to capture all the different types of control devices in operation and to predict what types of future controls will be employed. Therefore, we provided operating limits for the majority of the control devices in operation. If your source has a different type of control device than one listed in the rule, you can petition the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 374, 388, 403, 444, 445, 449, 478, 498, 523, 524, 533) requested that EPA extend the averaging periods for operating limits based on fuel sampling for 119 pollutant concentrations. The commenters argued that coal quality is inherently variable across suppliers, but also within a single supplier. By providing a time weighted average limit, the affected source would not have rejected individual shipments due to variations that result in fuel pollutant concentrations above the established limit, but could offset over the averaging period to compensate for the off specification shipment of fuel. The commenters explained that such a short averaging time would not be practical given the multitude of fuel suppliers that a facility might have and is also not consistent with the limit for fuel combinations tested during the performance test. One commenter ( 374) explained that longer averaging times are appropriate because 1) fuel pollutant content is variable; 2) these emission limits are designed to address chronic exposure and not acute risks; 3) it provides compliance flexibility; and 4) it provides the same overall emission reductions. One commenter ( 523) stated that daily tracking of fuel usage is unnecessary and likely an inaccurate means of tracking usage since the gauges used to track fuel usage are generally not designed to precisely track daily usage. Some commenters ( 403, 444, 523) requested changing the averaging period to monthly. One commenter ( 478) requested that facilities only be required to track fuel usage on an as occurring basis, such as whenever a fuel, source, or supplier changes.

Response: In the final boiler NESHAP, we modified the fuel sampling requirements. In the revised provisions, you must conduct initial fuel pollutant analysis for each " type" of fuel burned and then conduct further analyses for each fuel type once every 5 years. For the purposes of this NESHAP, a fuel type is defined as each specific category of fuels burned by a source ( e. g., bituminous coal, subbituminous coal, tires, residual oil, biomass, railroad ties, etc.). For example, if a you burn only bituminous coal and bark, then you would have to conduct an initial fuel sample for each fuel, and then one every five years as long as those are the only two types of fuel burned. Even if you receive those same fuel types from a different source or suppliers, you would not have to re sample the fuel as long as it is the same type of fuel that you have already sampled and have been burning. If you start to burn another type of fuel such as tires, then a sample of the tire fuel must be analyzed initially and then every five years as long as the source burns that type of fuel. This should alleviate the commenters' concern over having to conduct fuel sampling for fuel shipments from different sources or suppliers. Also, we modified the fuel use recordkeeping requirements to be on a monthly basis and not on a daily basis.

Comment: Several commenters ( 364, 399, 387) requested that EPA establish longer averaging times for the continuous parameter monitoring provisions of the boilers NESHAP. The commenters argued that the proposed 3 hour block average does not allow enough time for control equipment to respond to systematic adjustments in the manufacturing process and requested a minimum 6 hour block averaging period.

Response: We are not going to extend the averaging periods for continuous monitoring systems beyond 3 hours. In the final NESHAP, we added flexibility through the following provisions: 1) provided a fixed opacity limit based on 6 minute averages for existing sources and 3 hour block averages for new sources; 2) initial and every five year fuel sampling requirements; and 3) a 10 percent range for operating limits established during performance testing. Given these changes in the final rule, we are not going to provide longer operating limit averaging periods.

Comment: One commenter ( 497) recommended a longer averaging period for the proposed CO emission limit, such as an 8 hour averaging period. 120 Response: In the NESHAP, we have made the averaging period for CO to be a rolling 30 day average. We have provided this averaging period to address normal fluctuations in fuel supply an operating conditions. This should address the commenter's concern over CO averaging period.

Comment: One commenter ( 529) questioned the " 6 month period" on which operating limits for bag leak detection systems are assessed. The commenter stated that it is unclear whether this period is a single semiannual period or if the period is a rolling 6 month period where compliance is demonstrated every month.

Response: Consistent with other NESHAPs, the 6 month period is a block period and not a rolling period.

Comment: Several commenters ( 360, 361, 388, 449, 491, 492, 498, 524, 533) requested that EPA remove § 63.7525( e)( 3) in the proposed rule, which requires monthly inspections of electronic equipment and connections. The commenters argued that these requirements add no value, inappropriately increase interaction with electrical equipment adding increased safety concerns, and any system issues would already be detected by other means. Furthermore, the commenters noted that these requirements are not included in PS 1 for opacity monitors nor are they included in the guidance document for leak detection systems. One commenter ( 362) expressed concern that the requirements for continuous monitoring systems would necessitate a monthly shutdown of the affected source to satisfy the inspection requirement. The commenter stated this would be extremely burdensome for units that are required to operate without interruption throughout the entire year, and will likely result in excess emissions due to shutdown/ startup activities. Some commenters ( 360, 492) added that EPA has indicated that these QA/ QC requirements would be withdrawn from other MACT standards and QA/ QC requirements for continuous parameter monitors would be addressed through a generic rulemaking.

Response: We modified the language related to developing site specific monitoring plans and associated QA/ QC requirements. Your site specific monitoring plan no longer requires you to conduct monthly internal inspections and no longer require monthly inspections. You must develop ongoing quality assurance procedures according to the requirements in § 63.8( d) of subpart A of part 63.

Comment: One commenter ( 536) suggested not requiring continuous emission monitoring of carbon monoxide, hydrogen chloride, mercury, or any other pollutant except for opacity. One commenter ( 397) supported the use of opacity monitors for solid fuel fired units.

Response: We do not require CEMS for any pollutants other than opacity, and in some cases, and carbon monoxide. For carbon monoxide CEMS, we limited their requirement to units larger than 100 MMBtu/ hr; smaller units with applicable work practice standards for carbon monoxide only must conduct annual compliance tests. We do not believe the CO CEMS requirement for sources larger than 100 MMBtu/ hr is burdensome as those units would already be required to have a CEMS system under the NSPS requirements.

Comment: Several commenters ( 357, 444, 491, 523) stated that continuous operation of 121 monitoring equipment " at all times" should be better defined by providing a minimum data availability percentage. Two commenters ( 444, 523) noted that the boilers NESHAP allows baghouses a 5 percent allowance for operating in alarm conditions, but there are no such equivalent condition for other continuous monitoring systems. The commenters suggested that EPA provide at least a 5 percent downtime allowance per six month period. One commenter ( 491) noted that § 63.7525( c)( 3) states that any period for which the monitoring system is out ofcontrol and data are not available for required calculations constitutes a deviation from the monitoring requirements. The commenter stated that a deviation from the monitoring requirements should not be a violation if the monitoring equipment has been properly maintained and the malfunction is not reasonably preventable. The commenter requests that § 63.7525( c)( 3) include this statement, " A deviation caused by a monitoring malfunction is not a violation."

Response: We are not going to provide specific continuous monitoring system downtime allowances. Monitor downtime does occur due to calibration and QA/ QC procedures, and from occasional malfunctions. In these situations, your site specific monitoring plan required by § 63.7505( c) will address how you will deal with these issues and you will be expected to bring the monitoring system back into operation in an expeditious manner.

Comment: One commenter ( 405) believes that since many facilities are regulated by one or more programs and an additional layer of requirement will not effect emissions, EPA should delete any requirements for the use of CO monitors on gaseous and oil fired units or limit its application to units larger than 100 MMBtu/ hr. The commenter also argued that it is inappropriate to require the installation of individual CO monitors for small burners. The commenter stated that if EPA retains the CO monitoring requirement, it should clarify its application to process heater units with multiple burners and stacks. Individual burners typically are rated under 10MMBtu/ hr and vent to individual stacks, however, the process unit in aggregate may be larger than 10 MMBtu/ hr.

Response: We limited the application of CO CEMS to units larger than 100 MMBtu/ hr. For a unit with multiple smaller burners with individual stacks, a CO CEMS on each stack would not be required if the burners ducted to each stack are less than 100 MMBtu/ hr.

Comment: One commenter ( 403, 433) recommended the use of generic biomass fuel characterizations by class or categories instead of repeated fuel and emission testing. The commenters explained that these classes would be based on similar easily identifiable fuel characteristics such as source and potential contamination, and on similar chloride, metals, and mercury concentrations. The commenter added that facilities would be required to certify that they are burning only clean fuels or specific fuel mixes such that the stoichiometric emissions are below the regulated values. Two commenters ( 372, 404) requested that EPA consider an exemption or exclusion from compliance requirements for wood/ biomass fired units. The commenters expressed concern over the monitoring, recordkeeping, and reporting requirements for those units. One commenter ( 433) stated that burning differing proportions of biomass and fossil fuel should not constitute a ` new mixture' under the proposed rule.

Response: We do not provide an exemption from fuel sampling for biomass fuel. However, we made two changes since proposal that should address the commenters' concern. First, we modified the fuel sampling requirement to be initially and then once every five years for each fuel type. You are not required to conduct fuel analyses if a similar fuel type ( i. e., biomass, 122 bituminous coal, etc.) comes from a different supplier. Once you have conducted the fuel analysis for each type of fuel that you burn, you will only be required to record the monthly amounts of each fuel type that you burn. You will be required to conduct fuel sampling for each type of fuel every five years thereafter. Also, we adopted a generic biomass characterization and provided a definition for biomass for the purposes of this rule. Therefore, the different types of unadulterated material that are included in the biomass definition are considered to be one type of fuel and you are only required to conduct fuel sampling for biomass once every five years. We believe that this significantly reduces the monitoring, recordkeeping, and reporting requirements of the rule for units that burn biomass. You will still be required to demonstrate compliance through fuel analysis or through performance testing if the fuel analysis shows pollutant content higher than the emission limits of the boilers NESHAP.