Comment: Several commenters ( 361, 362, 364, 387, 399, 403, 444, 478, 491, 492, 536) requested that EPA allow demonstration of compliance with the hydrogen chloride, metals, and mercury emission limits based on stoichiometric calculation of emissions or fuel analysis and mass balance calculations at facilities without control other than a wet scrubber or dry scrubber or those not taking credit for control. The commenters argue that this would reduce the cost of stack testing and ongoing compliance could be assured by tracking fuel usage. One commenter ( 362) did agree that if the facility could not demonstrate compliance in this way, then a new performance test should be conducted to show compliance with the emission limitation. The commenter added that is was wasteful to require stack tests that cost $ 5,000 to $ 6,000 each, when compliance can be demonstrated on other ways. The commenter ( 362) suggested a new equation to utilize if EPA allows this option. Two commenters' ( 492, 536) suggested approach was to allow ongoing fuel analysis as a continuing compliance demonstration technique. This approach would involve the following: 1) establish a fuel input limit for pollutants ( e. g., x lb Cl/ MMBtu) based on the compliance test as described in the proposal, 2) periodically sample and analyze each fuel for pollutant concentration and heat value, 3) monitor daily usage of each fuel, 4) calculate average daily pollutant input rate for all wastes fed, and 5) demonstrate that the average daily pollutant input rate is equal to or less than the fuel input limit.

Response: In the final NESHAP, we provide the option to either demonstrate compliance through fuel analysis or through performance testing. The fuel analysis option is for sources that can demonstrate that the fuel pollutant content is less than the applicable emission limit ( e. g., the fuel analysis results show that the ratio of pollutant content to heat content is less than the respective emission limit in the final NESHAP). However, if you cannot demonstrate compliance with the emission limits through fuel analysis, then you will be required to conduct performance testing. We agree that this will reduce the compliance costs for sources and will still demonstrate compliance with the emission limits.

Comment: One commenter ( 536) suggested using published emission factors such as AP 42 or FIRE for hydrogen chloride and particulate matter in lieu of any annual testing or monitoring for these pollutants. The commenter ( 357) stated that allowing sources the option to use " A" rated AP 42 emission factors instead of performance testing is consistent with past permitting history and provides an adequate means of protecting human health and the environment.

Response: We do not allow sources to use published emission factors, such as those in 123 AP 42 or FIRE, to demonstrate compliance with this NESHAP. Published emission factors are average values and do not provide specific emission information about a particular source. The range of data used to develop an emission factor may not all fall under the emission limits in the final NESHAP. Therefore, an emission factor for a specific source may demonstrate compliance with the emission limits of this NESHAP, but the source could be actually out of compliance with the emission limit given the variation between sources. Also, performance testing is used to establish operating parameters that are monitored to ensure ongoing compliance with this NESHAP. We made several changes since proposal to minimize the burden of this rule on affected sources and believe that these changes will result in reduced burden for sources, but the use of site specific performance testing and fuel analysis is key to determining the compliance of each source an establishing a method to determine ongoing compliance.

Comment: Several commenters ( 364, 374, 387, 383, 388, 399, 403, 404, 425, 441, 443, 444, 449, 468, 498, 524, 533) argued that the proposed fuel monitoring requirements are unworkable biomass and multi fuel boilers. The commenters noted that some facilities may receive fuel shipments from up to 100 different suppliers and that the requirement to sample each time a fuel comes from a new supplier, and the possibility for frequent performance testing, could become very burdensome. Some commenters suggested using fuel purchase specifications to demonstrate compliance by comparing the fuel specifications to the maximum fuel pollutant concentration established during the performance testing. The commenters requested that EPA consider fuel testing exemptions for inherently clean fuels, breaking down biomass into several " types" and then conduct quarterly composite samples for fuel pollutant concentration, and modifying the fuel testing requirements to account for complex fuel mixtures.

Response: In the final NESHAP we simplified the fuel sampling and analysis requirements. You must conduct fuel sampling and analysis for each type of fuel initially and then once every five years. You are not required to conduct fuel sampling for fuel shipments from different suppliers as long as they supply the same type of fuel. Since you will only have to do initial and five year fuel sampling, this significantly reduces the burden for sources that receive the same type of fuel from many different suppliers. Furthermore, we designated that all unadulterated biomass is a single type of fuel. We do not allow you to use fuel purchase specifications to demonstrate compliance, you will have to conduct fuel sampling and analysis according to the requirements in the final rule.

Comment: One commenter ( 512) argued that the proposed compliance demonstrations for mercury do not ensure that the emission limit will be met. The commenter explained that keeping track of how a scrubber or precipitator is operating does not mean that mercury emissions are being reduced. The commenter requested that EPA require sources to frequently sample fuel for mercury content along with measuring the inlet and outlet of the control device to determine mercury reduction in order to ensure compliance on a continuous basis.

Response: We disagree with the commenter and believe that the compliance provisions in this NESHAP will ensure that the emission limits will be met. Performance tests demonstrate if a facility is meeting the emission limits and give a clear determination of compliance with the emission limits. During the performance testing, a source must establish operating limits for the type of control device that is used. These operating limits are required to ensure that the source is operating similarly to its operation during the performance test that demonstrated compliance 124 with the emission limits. Sources must also sample and analyze the fuel( s) being burned during the performance test. After the performance testing, the source must monitor fuel type and use and conduct additional fuel sampling and analysis if a new type of fuel is burned. If this new fuel type has a higher pollutant content than the type of fuels burned during the last performance test, the source will be required to conduct additional performance testing within 60 days of burning the new fuel type to demonstrate compliance with the emission limits. Given these requirements, we believe that the final NESHAP ensures compliance with the emission limits while minimizing the burden to demonstrate compliance.

Comment: Several commenters ( 406, 407, 408, 501) believes that the burning of differing proportions of fuel should not constitute a " new mixture" under the NESHAP. The commenters noted that if such an understanding is not included in the final rule, then the implementation could become unmanageable. The commenters considered all bagasse produced from sugarcane grown in the same geographic region to be the " same" fuel, and not subject to the fuel switching provisions of the rule. One commenter ( 492) contended that the requirement to conduct a new performance test every time there is a minor change in fuels is unreasonable. In particular, the commenter argued that fuels are often switched based on economics, with the supplier being selected on the best price bid. In such situations the units are burning like fuels, but the proposed requirements of § 63.7540 would make the owner recalculate the emission level, which may require testing. The commenter believed that this is burdensome and that the costs to possible test and to recalculate emission levels each time a fuel supplier is changed are not accounted for in the economic burden estimate. The commenter suggested that the following language replace the proposed language in § 63.7540: " If you plan to burn a new type of fuel, a fuel from a new supplier, or a new mixture of fuels, and the characteristics of the new fuel( s) are such that the emissions limitations of Table 1 may not be met, you must perform a new performance test."

Response: In the final NESHAP, we made several changes to the fuel sampling and analysis requirements that should address the commenters' concerns. We provided fuel type designations in the final NESHAP such that if you burn the same fuel type ( i. e., biomass, bituminous coal, tires, etc.,) you conduct fuel sampling initially and then once every five years. This eliminates the requirement to conduct different fuel analyses for fuel received from different suppliers. With regard to burning different mixtures of fuels, if you demonstrate compliance through fuel analysis, you can burn any mixture of fuel types, as long as the pollutant content of the fuel mixture remains below your applicable emission limit. If you demonstrate compliance through performance testing, you can burn any mixture of fuel types as long as the pollutant content of the fuel mixture remains below that of the fuel mixture that you burned during your last performance test. This requires you to carefully plan your performance test fuel mixture so that it has the highest fuel pollutant content that you plan to burn. If you decide to burn a new type of fuel or fuel mixture that has a higher pollutant content than the fuel mixture burned during your last performance test, you will be required to conduct a new performance test within 60 days of burning the new fuel mixture.

Comment: One commenter ( 491) stated that the proposed rule does not specify allowable methods for determining chlorine, mercury, and total selected metals content of the fuel. The commenter suggested that EPA clarify its expectation for allowable methods so operators can determine the fuel chlorine content and the mercury content pursuant to rule requirements. The commenter stated that similar circumstances exist in the rule for determination of total selected 125 metals. In addition, the commenter stated that if method selection is expected to be made by the operator and merely included in the site specific test plan pursuant to § 63.7520( a), then EPA should clarify that expectation.

Response: In the final rule, we specify the appropriate methods for determining the chlorine, mercury, and total selected metals content of the fuel. If you would like to use different fuel analysis methods, you can petition the Administrator for an alterative testing plan under § 63.7( e)( 2)( ii) and ( f) of subpart A of part 63.

Comment: Two commenters ( 297, 372) expressed concern over the proposed requirement to recalculate the maximum pollutant input each time you burn a new fuel, fuel from a new mixture, or from a new supplier. The commenters explained that their fuel supply comes from many different suppliers and trying to isolate individual fuel shipments would not be practical. One commenter ( 372) requested that after a source has determined the worst case fuel blend, there should be no requirement to sample fuel or retest as long as the maximum blend percentage of any fuel did not exceed the percentage fired during the performance test. In addition, the commenter also requested that any fuel type that was evaluated and determined not to be part of the worst case fuel blend, could be burned in any amount during the year without fuel analysis or retesting. The commenter also added that the requirement to test fuel from every supplier will be too costly. The commenter also suggested requiring quarterly composite fuel sampling instead of daily fuel analysis.

Response: In the final NESHAP, we modified the fuel sampling and analysis requirements monitoring requirements. You only conduct fuel sampling initially and then once every five years for each type of fuel burned. This eliminates the requirement to conduct fuel sampling for each type of fuel from different suppliers. With regard to the fuel mixture burned during the performance test, if you choose to demonstrate compliance through performance testing, you should evaluate your fuel use and plan the performance test such that the mixture burned has the highest content of pollutants expected to be burned during normal operation. After that performance test, you are allowed to burn any mixture of fuel types that have been sampled, as long as the total fuel pollutant input is less than that during the last performance test. We are still requiring you to conduct performance tests if you burn a new mixture of fuel that contains a higher regulated HAP content that the one burned during the last performance test. You are allowed to burn any mixture of fuels as long as you can demonstrate that the input of regulated HAP in the fuel stream is not greater than that during the last performance test. If you demonstrate compliance through fuel analysis, you must also conduct fuel analyses for each fuel type that you burn initially, and then once every five years. In this situation, all you have to do in demonstrate that the pollutant content of any fuel mixture that you burn is less than your applicable emission limit.

Comment: One commenter ( 413) expressed concern about the frequency that fuel testing would need to be performed because sources purchase fuel from a variety of suppliers and many suppliers provide fuel from a variety of sources. The commenter suggested periodic fuel testing as an alternative compliance option for units with variable fuel supplies.

Response: In the final NESHAP, we revised the fuel sampling results to reduce fuel sampling. You will only have to conduct fuel sampling initially and once every five years for each fuel type burned by the source, regardless of whether it comes from a different source or supplier. 126 The should eliminate the commenter's concern over having to conduct fuel sampling for the same type of fuel from different suppliers.

Comment: The commenter ( 523) stated that tracking natural gas usage should not be required for existing gas fired units. The commenter stated that the requirement to burn only natural gas could be introduced into the Title V permits for these sources, if they desire. The commenter stated that if the existing gas fired unit was converted to solid fuel, the source would need to secure an installation permit and the appropriate MACT requirements would be incorporated into that permit.

Response: All existing sources that burn gas and/ or oil only are specifically exempted from any fuel monitoring provisions. New sources that burn gas only do not have to monitor fuel use. If you have an existing or new source that co fires gas with solid fuels, you must monitor all fuel use on a monthly basis.

Comment: One commenter ( 536) requested that EPA minimize monitoring burdens on smaller systems. The commenter contended that smaller systems are being asked to monitor too frequently for their budgetary manpower and pose a significant time and financial burden.

Response: We agree with the commenter and have taken some steps to minimize the monitoring burden on smaller sources. For example, we removed the requirement for new sources with heat input capacities less than 100 MMBtu/ hr that have a work practice standard for CO to install a CEMS for CO. Instead, these sources will have to conduct annual CO stack tests. This results in a significant reduction in monitoring equipment and manpower costs. We have also included the option to demonstrate compliance through fuel analysis if the results of the fuel analysis show that the fuel pollutant content is less that the applicable emission limit.

Comment: Several commenters ( 364, 399, 387) argued that some smaller boiler stacks are poor structural candidates for retrofitting continuous opacity monitoring systems ( COMS). In some cases, the commenters noted that to install a COMS, facilities may have to completely replace the stack.

Response: In the final NESHAP we have provided additional options for demonstrating compliance, such a fuel analysis in order to minimize the compliance burden. We realize that some sources will have some additional retrofitting costs to install COMS. If a source believes that the installation of a COMS may be too burdensome, you can petition the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63.

Comment: One commenter ( 491) stated that it is not clear what the requirement " to conduct all monitoring in continuous operation at all times that the unit is operating" means. The commenter suggested that § 63.7525( c)( 2) be clarified as follows: § 63.7525( c)( 2) Except for, monitoring malfunctions, associated repairs and required quality assurance or control activities ( including, as applicable, calibration checks and required zero and span adjustments), you must operate all CPMS at all times that the affected source is operating. A CPMS is not required to be operated when the affected source is not operating. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not 127 malfunctions.

Response: We understand the commenter's concern and incorporated their suggested language changes into the final NESHAP.

Comment: One commenter ( 491) requested that EPA clarify that § 63.7505( c) applies to continuous monitoring systems.

Response: In the final NESHAP, we added language to § 63.7505( c) that clarify that this section applies to continuous monitoring systems.

Comment: One commenter ( 375) contended that the EPA's assertion that CEMS for particulate matter have not been demonstrated in the United States for the purpose of determining compliance was inaccurate. The commenter believes that EPA has demonstrated that particulate matter CEMS can be used from determining compliance with a particulate matter emission limit. The Office of Enforcement and Compliance Assurance has required the use of particulate matter CEMS in serval enforcement actions. The particulate matter CEMS installed as part of the Tampa Electric enforcement action has been operating for over one year and has met the proposed performance specifications. The commenter requested that CEMS be allowed as an option to determine compliance with the particulate emission limits in the NESHAP. The commenter stated for those facilities that install wet scrubbers to control sulfur dioxide, the use of upstream particulate removal device operating parameters will not be sufficient to determine compliance with the particulate matter standard at the stack. The commenter suggested the proposed rule should require particulate matter CEMS for wet stack installations or the proposal of a different mode of compliance assurance.

Response: We do not explicitly provide an option in the final boilers NESHAP for the use of particulate CEMS. However, you can petition the Administrator for an alterative monitoring plan under § 63.8( f) of subpart A of part 63. You must provide the necessary site specific monitoring plan for your particulate matter CEMS, including appropriate QA/ QC plans for the CEMS. If you are approved to use particulate matter CEMS to determine compliance with an applicable particulate matter emission limit, exceedances of the emission limit will be considered a violation of standard and you will not be given the operating range allowances provided for parametric monitoring systems since the particulate matter CEMS provides real time determination of compliance with the emission limits.

Comment: One commenter ( 364, 399, 387) questioned whether only whole numbers be used in recording instantaneous values and computing various averages of opacity. The commenter also asked if a 3 hour block average that exceeds the highest 1 hour block average recorded during the performance test by 0.1 percent be considered an exceedance. The commenter contended that if this is the case, then exceedances will occur on a continuous basis.

Response: In the final NESHAP, we adopted a fixed opacity limit for new and existing sources. These fixed opacity limits do not include decimal places, therefore, you must determine compliance by using whole numbers for your opacity data. For example, the existing source opacity limit for solid fuel fired units is 20 percent. Since the limit is not 20.0 percent, as long as your 6 minute average is 20.4 percent or less, you will be in compliance. 128 Comment: Several commenters ( 364, 375, 387, 388, 399, 449, 498, 524, 533) requested that EPA allow existing common stack opacity monitoring systems be grandfathered from the requirements of § 63.8( b)( 2) and ( b)( 3) that would require monitors on individual effluents before they combine. The commenters believe that this could be a costly requirement for some affected sources with no demonstrable environmental benefit. The commenters also noted that in some cases, these " individual" opacity monitoring systems would not satisfy the location requirements under PS 1 and, as such, could not be used to demonstrate compliance with applicable regulations under a State rule or an NSPS.

Response: The final rule does not provide a specific " grandfather" clause for existing monitoring systems. However, since the final rule has adopted a fixed opacity operating limit, the use of a common stack opacity monitor would not pose a compliance issue under this standard. If you fall under this situation, you should apply to the Administrator for an alternative monitoring plan under § 63.8( f) of subpart A of part 63 to demonstrate compliance with a common stack opacity monitoring system.

Comment: One commenter ( 445) requested that EPA allow the use of existing continuous opacity monitoring systems and non mercury CEMS as an alternative to the operating limits for mercury. The commenter explained that these existing programs provide assurances of unit operations and that no other requirements are warranted.

Response: Under the final boilers NESHAP, sources have the option of using opacity monitors ( or bag leak detection devices for units with fabric filters), or fuel analysis as an option to demonstrate compliance with the mercury emission limits. If you wish to use another monitoring strategy for demonstrating compliance with the mercury emission limits, you can petition the Administrator for an alterative monitoring plan under § 63.8( f) of subpart A of part 63.

11.3 OPERATING LIMITS Comment: Several commenters ( 355, 359, 374, 384, 393, 409, 410, 413, 417, 478, 482, 484, 521, 522, 523, 535) opposed the use of operating limits for demonstrating compliance with the boilers NESHAP. Other commenters argued that the establishment of, and ongoing compliance with, site specific limitations present difficult challenges due to fuel variability, institutional procurement practices, and equipment useful life and will create needless and overly stringent limits that cannot be consistently maintained. Several commenters ( 359, 409, 413, 482) opposed using operating limits as a means of demonstrating continuous compliance with emission limitations because they reduce operational flexibility, eliminate control device margins, and provide incentives for sources to conduct performance tests at less than optimal conditions. Several commenters ( 374, 410, 417, 523) stated that the use of operating limits was inappropriate because it effectively sets a new NESHAP emission limit as the emissions are actually emitted during the performance test. Some commenters ( 375, 393, 413) objected to the use of operating limits because EPA has not proven a direct correlation between those operating limits and actual emission levels.

Response: We believe that continuous monitoring is needed to ensure ongoing compliance with this rule. In order to minimize costs, we look for parameters that are already monitored to 129 use for compliance demonstration. We require performance tests to demonstrate compliance with emission limits, then use operating limits to ensure the source is operating similarly to how it was operating when it completed a successful performance test. Operating limits are not direct measures of emissions, but provide measure of fuel characteristics and control device performance. In addition, we modified and simplified opacity limits, fuel sampling/ testing requirements, and are allowing emission averaging. You are also able to petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 364, 370, 374, 382, 383, 387, 388, 391, 392, 399, 401, 404, 406, 407, 408, 449, 452, 491, 492, 498, 501, 521, 524, 533) requested that EPA follow previous opacity limit approaches found in boilers new source performance standards ( NSPS) ( 40 CFR part 60, subpart Db and Dc) where 20 percent opacity is the limit and one excursion to 27 percent is allowed per day for soot blowing. The commenters stated that such a limit may not be achievable on an ongoing basis because boiler and particulate collection equipment performance varies over time due to equipment condition, fuel variations, operating variations, and other uncontrollable parameters. One commenter ( 404) requested that EPA consider a fixed opacity limit similar to the boilers NSPS Subpart Db and suggested a 14 percent opacity limit that was calculated by taking the particulate matter emission ratio ( NSPS and MACT) and applying it to the 20 percent opacity limit in the NSPS. One commenter ( 374) suggested that EPA promulgate a requirement for corrective action when opacity levels exceed 20 percent for 10 consecutive 6 minute periods and have an overall limit of 27 percent. Several commenters ( 357, 388, 449, 492, 498, 524, 533) listed several issues that need to be resolve before implementation if EPA decides to stay with the proposed opacity monitoring requirement: 1) How should a one hour block average be calculated for performance test runs that last longer than one hour? 2) Should only whole numbers be used for establishing limits and determining compliance? 3) How will the opacity monitoring requirements work for units with more than one stack? 4) How will the opacity monitoring requirements work for units that share a common control device? 5) Define increases in opacity and opacity operating limits in 5 percent increments consistent with EPA Method 9 and historic regulatory enforcement activities Response: We agree with the commenters that an opacity operating limit based on performance testing results may not be appropriate, and that a fixed opacity limit similar to the NSPS requirements would be a better solution. Therefore, in the final NESHAP, we incorporated the industrial boilers NSPS opacity provisions ( 20 percent, one 6 minute 27 percent period per day) for existing sources that may have an applicable opacity operating limit. If you have a new source that has applicable opacity operating limit, you will be required to meet a 10 percent opacity limit based on a 3 hour block average.

Comment: Three commenters ( 355, 370, 417) argued that limiting the fuel pollutant content to the level occurring during the performance test is overly restrictive and limits flexibility. One commenter ( 355) stated that it is unreasonable to establish any type of limit based on the particular coal being combusted at the time of a compliance test, because the composition and characteristics of coal can vary widely from the same mine and seam. Another commenter ( 417) pointed out that if a facility uses a low chlorine fuel, even if the performance test results are well below the hydrogen chloride emission limit, the chlorine content during the performance test becomes the new limit. Then a facility is locked into an artificially restrictive operating limit by 130 requirements that they recalculate the maximum chlorine input from any new fuel and conduct a new performance test. This penalizes facilities that use fuels with low pollutant content.

Response: We agree with the commenters that the proposed fuel pollutant content operating limit may not address normal fuel pollutant variation. In the final boilers NESHAP, we modified the performance testing and fuel sampling requirements to address fuel pollutant content variation, to minimize the compliance burden, and to simplify the requirements. You must conduct your performance test with the fuel type or mixture of fuel types that have the highest content of pollutants regulated by this NESHAP. As long as you burn the same fuel types or mixture of fuel types that have been sampled and have a pollutant content lower than the type or mixture of types burned during the last performance test, you meet the fuel content operating limit requirements of this NESHAP. Therefore, the final NESHAP bases compliance on fuel type and should eliminate the commenter's concern over locking into an artificially restrictive operating limit.

Comment: One commenter ( 395) recommended that the agency revise the regulation to allow sources to operate control equipment within the ranges identified by the equipment manufacturers. These ranges will ensure that the equipment is operated appropriately and, thus, effectively controlling the emissions of the associated source.

Response: We do not provide this option in the final boilers NESHAP. Control devices may operate differently in practice than what the manufacturer recommends. Therefore, we are requiring sources to set site specific operating ranges based on performance testing results.

Comment: One commenter ( 395) stated it was inappropriate to establish a single set of operating parameters for most control devices serving production operations. Control systems would be influenced by numerous parameters including ambient temperature and humidity, process variations, pollutant concentrations, airflow, etc. The commenter stated that an operating parameter observed at one point in time may not be repeatable, or appropriate, at a later time even though the system continuously maintains proper efficiency.

Response: The final NESHAP contains more flexibility for operating limits than the proposal. We included fixed opacity limits, fuel sampling requirements based on fuel type, and operating limit ranges. To incorporate all the operating factors and ambient conditions into the requirements of this rule would be too onerous. If you expect that the additional flexibility in the final NESHAP is not enough for your source, you may petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 297, 340, 348, 354, 355, 357, 370, 374, 382, 387, 382, 383, 388, 393, 399, 401, 403, 417, 425, 427, 441, 443, 444, 449, 468, 492, 498, 521, 524, 533) objected to the provision in the proposed NESHAP that would establish an opacity " operating limit" based on the initial performance test. Some commenters contended that EPA has provided no data or references demonstrating a relationship between opacity and particulate, total metals, or mercury emissions. Other commenters argued that the proposed opacity limit approach for dry control devices is unworkable due to the inherent inability of continuous opacity monitoring system ( COMS) to accurately measure opacity at levels less than 10 percent. Some commenters argued that the performance and opacity achieved during the initial test may not be representative 131 of the unit's performance. Other commenters explained that equipment condition, fuel and operating variations, and other uncontrollable parameters may result in varying emissions and emissions control equipment efficiencies over time. The commenters also noted that the " worst case fuel" use during initial performance test assumes " a degree of perfection in fuel selection that is hardly achievable in actual practice." The commenters explained that " worst case fuels" with respect to all pollutants must be considered during the performance test, not just for particulate matter. Lastly, the commenters argued that burning " worst case fuels" during the initial performance test may not result in the worst case opacity levels, given that in stack opacities depend on variables beyond the realm of fuel composition ( e. g., particle size distribution, flue gas properties, stack diameters, etc.). One commenter ( 468) noted that the proposed operating limit a) does not take into consideration any margin of compliance; b) ignores the reality of operating dynamics and other seasonal and diurnal changes that influence opacity; c) raises the prospect that a source could exceed the operating limit, but remain below the underlying standard; and d) conflicts with established standards that acknowledge the fundamental variation associated with opacity measurement technology.

Response: We agree with the commenters that an opacity limit based on performance testing may not be appropriate given the normal variation that occurs in boiler and process heater operation. In the final boilers NESHAP, we adopted a fixed opacity limit not set by the performance test. For existing sources, it is similar to the opacity limits in the boilers NSPS ( 40 CFR part 60, subpart Dc). For new sources, it is a limit of 10 percent opacity based on a 3 hour block average. We believe that modifying the opacity limit to a fixed standard, this should address the commenters' concern over normal process variation and the relationship between " worst case" fuels and resulting opacity levels. However, you will still be required to burn the fuel type or mixture of fuel types that contain the highest content of pollutants regulated by this NESHAP when conducting performance tests.

Comment: One commenter ( 492) argued that the procedures for establishing operating parameters during the initial performance test must be prorated to the emission limitations to meet the requirements of the Clean Air Act and to protect the environment. Since the source cannot exceed the standard during the performance test, the operating limitations will result in an " above the floor" control level, which is not warranted by EPA's MACT floor analysis. As a result, the commenter contended that sources either have to run a worst case fuel at the initial performance test or accept above the floor level of control, which would be both costly and detrimental to the environment. The commenter argued that the correct approach is to allow the source to set operating conditions to the level that generates the emissions level established in the rule.

Response: We are not allow facilities to prorate operating limits. Without conducting performance testing over the range of operating conditions, the correlation between operating levels and emission levels are not available. In the final NESHAP we provided additional flexibility for you to comply with the operating limit provisions ( e. g., fixed opacity limits, operating limit ranges, fuel sampling based on fuel type instead of shipment, supplier, or source), and believe that these changes address the commenter's concern.

Comment: Several commenters ( 364, 399, 387) noted that many boilers that share a common particulate matter control device, and conducting a performance test while each boiler is burning its worst case fuels will be difficult to accomplish and may give non representative 132 opacity levels during the performance test. The commenter stated that it is illogical to establish a future opacity operating limit based on this type of short term performance testing.

Response: The final NESHAP contains a fixed opacity limit for both new and existing sources. Therefore, if boilers share a common control device, they will all have to meet the same opacity limit. The eliminates the concern over establishing opacity operating limits during performance testing. Furthermore, we modified the fuel sampling requirements to be based on fuel type and not on shipment, supplier, and source. This change should help you determine the fuel type of fuel mixture that has the highest pollutant content for your performance testing.

Comment: Several commenters ( 364, 372, 374, 382, 387, 388, 399, 401, 406, 407, 408, 410, 417, 443, 449, 452, 479, 491, 492, 498, 501, 523, 524, 533) argued that operating limits ( e. g., parametric monitoring ranges, opacity) should not create the same enforcement implications as emission limits. Some commenters requested that EPA use the operating limits established during the initial performance tests as a trigger for corrective actions that would be spelled out in the startup, shutdown, and malfunction plan. Under this approach, the commenters explained that facilities would be required to respond expeditiously, and would face enforcement exposure if they failed to do so. Therefore, the commenters suggested that EPA change the term " operating limits" to " action levels" or " indicator parameters." Other commenters ( 382, 491, 492) contended that EPA, by setting another set of limitations, has extended the regulations beyond the MACT floor, even though the preamble states that EPA decided not to go beyond the MACT floor level of control. Some commenters ( 374, 382, 388, 417, 449, 452, 479, 498, 524, 533) argued that EPA cannot enforce operating limits as permit limits because there is no direct correlation between an exceedance of an operating limit and the emission limitations. One commenter ( 417) requested that the ambiguity regarding compliance enforcement of operating limits be clarified in the final regulation to provide uniform enforcement across multiple types of affected units. Some commenters ( 374, 388, 401, 449, 492, 498, 524, 533) noted that other MACT provide for a limited number of exceedances before a violation occurs and suggested that following criteria for establishing violations: 1) Failure to initiate correction actions specified in the Operation, Maintenance, and Malfunction ( OMM) plan within 1 hour of becoming aware of a limit deviation; and 2) The occurrence of more than six exceedances for a given operating parameter value associated with monitoring a specific process or control device in any calendar half year monitoring period. The commenters urged the EPA to adopt this language in the final boilers NESHAP. One commenter ( 372) suggested that EPA adjust the opacity operating limits such that if a facility exceeds their existing opacity limit less than 3 percent of the time, then they would demonstrate compliance with the particulate matter, selected metals, and mercury limits.

Response: Since proposal, we made some changes that should address the commenters' concern. In the final NESHAP, we provided an extended range of 10 percent for operating limits established during performance testing. We provided this range to account for normal variation that occurs at boilers and process heaters. We also changed the opacity limit requirement to incorporate fixed opacity limits which are not based on performance testing results. We are not going to provide any exceedance allowances in the final rule. The determination of whether an exceedance of an operating limit is a violation of the standard will be made by the Administrator ( your local permitting authority if your state or local program is delegated authority to administer the NESHAP program). That determination would be made based on the nature of the exceedance, your adherence to your SSM plan during the exceedance, and your history of compliance. 133 Comment: Several commenters ( 359, 413, 482, 484, 523, 535, 536) stated that affected sources should only be required to demonstrate compliance through performance testing with applicable emission limitations for each type of unit.

Response: To ensure ongoing compliance, we need some sort of continuous monitoring provisions. While performance testing gives an accurate measure of compliance for discrete periods, it is generally too expensive to be conducted on an ongoing basis. In effort to minimize costs, we look for operating parameters that are already being measured by sources that can provide an indication of source and control device operation. This approach to monitoring continuous compliance is not unprecedented and we retained the approach in the final rule. The purpose for operating limits is to ensure that the boiler or process heater is operating in a manner similar to its operation during the performance test that demonstrated compliance with the emission limits of this NESHAP.

Comment: Several commenters ( 376, 413, 482,) urged EPA to employ concepts in the compliance assurance monitoring ( CAM) rule that allows for establishment of more rational and reasonable operational parameter levels. The commenter added that sources would then be required to monitor those parameters and respond to changes that indicate problems with the controls that could jeopardize compliance.

Response: We have worked to minimize the compliance costs associated with this NESHAP and in the final NESHAP, we made several changes to achieve this goal. We used guidance from the CAM rule to establish methods for setting operating limits. However, the CAM rule was designed to provide a reasonable assurance of compliance, which is a lower standard of compliance than the NESHAP program, which requires continuous compliance. Therefore, we did not directly incorporate concepts of the CAM rule into the final NESHAP. You are also able to petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 340, 364, 387, 399, 484) questioned how 3 hour block averages for operating limits would be calculated when the three performance test runs exceed three hours in duration. One commenter ( 340) recommended using the terms " three test runs" and the " three run performance test" in the text to establish operating limits.

Response: In the final rule, your operating limits will be based on the lowest or highest average parameter level measured during the three run performance testing. For example, if you are determining the minimum sorbent injection rate ( e. g., your sorbent injection rate operating limit), it would be 90 percent of the lowest average sorbent injection rate measured during the three run performance test as determined by Table 7 of the final rule. The modification of determining your operating limits should address the commenter's concern. Furthermore, we have modified the language in the rule to use the term " test run average" and do not based it on a 1 hour average.

Comment: Several commenters ( 361, 362, 364, 387, 399, 439, 444) expressed concern over the requirement to set operating limits based on the results of three 1 hour performance tests. The commenters pointed out that this method represents only three out of a possible 8,760 134 hours per year, these results would not represent normal operating fluctuations and that maintaining compliance with these operating limits may be difficult. The commenter believes that EPA should allow for typical operational and process variations that cause a process to operate both above and below average values when determining operating limits. Two commenters ( 361, 362) suggested that a more statistically valid method should be used for establishing site specific operating parameters. Several commenters ( 364, 399, 387) suggested that EPA allow facilities the flexibility to set continuous parameter monitoring ranges based on normal operating variability and proposed changes to the regulatory text to address these concerns.

Response: We provided more flexibility in the final rule for regarding operating limits ( i. e., fixed opacity limits not based on performance testing results, a 10 percent operating range for operating limits established by performance testing, option for compliance demonstration through fuel analysis, simplified fuel sampling requirements based on fuel type with no sampling triggers based on fuel supplier or source changes). We believe that these changes allow for operational and process variations that may not be observed during performance testing. However, if you wish to establish a different monitoring strategy based on statistical or some other methods, you can petition the Administrator for an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: Several commenters ( 338, 364, 374, 382, 387, 388, 395, 399, 403, 413, 417 444, 449, 484, 491, 492, 498, 521, 522, 524, 533, 535) requested that EPA allow facilities to prorate fuel pollutant content operating limits established during performance tests by the ratio of the performance test results to the applicable emission limits, then maintain fuel pollutant content levels below the extrapolated value. Some commenters noted that allowing facilities to prorate operating limits would help those that use multiple fuel suppliers by: 1) providing needed operational flexibility; 2) avoiding repeated testing; and 3) eliminating the difficult requirement to conduct performance testing at " worst case" conditions. One commenter ( 491) stated that a new performance test could then be required if the fuel chlorine, mercury, and/ or total selected metals content exceeded the prorated values established during the performance test. Several commenters ( 338, 374, 417, 484, 521, 522, 535) recommended that facilities be able to demonstrate compliance through fuel purchase specifications or certifications. Some commenters ( 374, 492) also requested that EPA provide allowances for facilities to use other compliance strategies that would be more appropriate for specific sites, with prior EPA approval. One commenter ( 413) referenced the CAM protocols and a protocol developed by Electric Power Research Institute ( EPRI) as a background Some commenters ( 364, 399, 387, 403) provided equations that prorate the allowable fuel input by the ratio of the stack testing results to the emission limit for each pollutant.

Response: Since proposal, we changed the fuel monitoring and sampling requirements. In the final NESHAP, we base the fuel sampling requirements on fuel type ( e. g., bituminous coal, anthracite, tires, biomass, residual oil) and no longer require you to sample fuel shipments received from different suppliers or sources as long as the fuel is the same type. Therefore, we do not allow facilities to prorate fuel pollutant content limits. We also modified the fuel sampling provisions such that you are required only to conduct fuel sampling for each type of fuel initially, and then once every five years. We believe that this should address the commenters' concern regarding sources that receive fuel from many different suppliers. We are still requiring you to conduct performance testing with the fuel type or mixtures of fuels that contain the highest amount of regulated pollutants. Given the change in fuel sampling requirements to the fuel type 135 basis, the determination of the types of fuels that have the highest pollutant content should be less onerous. After your performance testing, as long as you burn the types of fuels previously sampled and do not burn new types of fuels or mixtures of fuels with higher regulated pollutant contents, you are not required to conduct any additional fuel sampling or performance testing outside of the normal testing schedule contained in this NESHAP. We also provided an option for you to demonstrate compliance through fuel sampling when the fuel analysis results show fuel pollutant content ( on a pounds per million Btu ( lb/ MMBtu) of heat content basis) is less than your applicable emission limit.

Comment: Several commenters ( 406, 407, 408, 501) contended that in regards to the operating parameters, sources should have the option of performing additional test runs over a range of operating parameters if desired. The commenters also suggested that sources be allowed to exceed the emission limit during such testing without it being a violation, so that the minimum or maximum parameter operating level can be correctly established. The commenters added that once an operating parameter is established, the source should be required to maintain the parameter level within 20 percent of the performance test baseline average value. The commenters also added that sources should be allowed to set operating parameter levels as a function of boiler load. One commenter ( 384) believes EPA should allow sources to propose their own strategy on how to demonstrate compliance.

Response: In the final NESHAP, we do not provide an option for sources to conduct performance testing over a range of operating parameters or loads because it would be difficult to structure performance testing requirements that would incorporate different operating loads and conditions that would benefit sources on a site specific basis. However, if you want to establish operating limits based on operating loads and/ or conditions, you can petition the Administrator for an alternative monitoring plan under section § 63.8( f) of subpart A of part 63. In the final NESHAP, we added additional flexibility in the operating limit requirements to account for normal variation in source operation. We provided fixed opacity limits that are not based on performance testing results and added a 10 percent operating range around operating limits that are established during performance testing. We are also not providing a waiver for emission exceedances experienced during performance testing.

Comment: One commenter ( 445) requested that EPA allow sources to define a range ( as a percentage) for blended fuels to demonstrate compliance with the MACT standard. The commenter explained that blended fuels behave like one of the regional coals within the blend.

Response: We revised the fuel sampling and monitoring requirements in the final NESHAP to be based on fuel type and removed the requirement to conduct fuel sampling for the same fuel types that come from different suppliers or sources. If you demonstrate compliance through performance testing, you must plan to burn the fuel type or mixture of fuel types that contain the highest content of regulated pollutants. After that performance test, you can burn any range of fuel types and mixtures, as long as the results of the fuel sampling for each fuel type or mixture show that the total regulated pollutant content is less than that burned during the last performance test. These changes should provide flexibility for sources that burn a mixture of fuels.

Comment: One commenter ( 499) stated that the fuel based operating limit procedures for 136 chloride, metals, and mercury in § 63.7530 are flawed because they rely too heavily on the performance during a stack test, with no consideration for a margin of safety. The commenter explained that this operating limit approach could inadvertently encourage sources to fire a fuel that has the maximum chloride, metals, and mercury content during the performance test since, provided the source meets the emission limit, there is no incentive to strive for a margin of safety to over comply in order to ensure 100 percent compliance. The commenter stated that this approach is a disincentive to promoting greater emissions reductions and should be changed. In addition, the commenter stated that sources who over comply should be afforded some reward in terms of regulatory relief rather than penalized with more restrictive limits.

Response: We require performance testing for sources that cannot demonstrate compliance with the emission limits of this NESHAP through fuel sampling. The requirement is necessary to ensure that the emission limits are being achieved. Then, we use operating limits established during the performance testing to ensure that the source is operating in manner similar to that during the performance testing. We still require that you burn the fuel type of mixture of fuels that contain the greatest amount of regulated pollutants during performance testing. This assures us that you are able to meet the applicable emission limits burning the fuel type of mixture that contains the greatest content of regulated pollutants. It also provides you with flexibility to burn any fuel type or mixture that contains a lesser amount of regulated pollutants without having to conduct additional performance testing. Given these changes, we are not providing any other relief for sources that over comply because we believe that the changes made since proposal reduce the burden of compliance and provide additional flexibility. Furthermore, the goal of the NESHAP program is to provide a uniform application of the maximum achievable control technology determined for this source category and for all sources within the source category to meet the MACT based emission limits.

11.4 PERFORMANCE TESTING Comment: One commenter ( 358) supported expanding compliance demonstration options to include engineering calculations and other emission estimates to be considered " as good" as actual site specific test data. The commenter contended that the proposed rule did not adequately address cost associated with stack compliance testing and the burden to conduct testing for sources that emit relatively small quantities of HAP.

Response: If you are required to demonstrate compliance through performance testing, we are not going to allow compliance to be demonstrated by engineering calculations or other emission estimates. We are aware of the costs of performance testing and have attempted to minimize the cost of testing through the following provisions: 1) allowance for testing once every three years for sources that have passed performance tests for three consecutive years; and 2) allowance for demonstrating compliance through fuel analysis for units that are not taking credit for pollution control devices or for units that do not require pollution control devices to demonstrate compliance. For units that require control devices to meet the emission limits, we require performance testing because this is the only method to accurately determine the effectiveness of those control devices. The final rule does allow for sources to demonstrate compliance through fuel analysis in cases where the analysis shows that the pollutant concentration in the fuel is less than the applicable emission limit. We also do not require performance testing for any existing gas or liquid fuel fired units, existing small solid fuel fired 137 units, new gas fuel fired units, and new liquid fuel fired units that do not burn residual oil.

Comment: One commenter ( 413) asserted that for sources wanting to base their operating parameter levels on actual test data, EPA should provide a waiver for excess emissions during performance testing to establish operating parameter levels. The commenter explained that in the proposal, EPA wanted sources to test at worst case conditions, which might require a " de tuning" of control devices for sources that have purchased additional capacity for their control device. The commenter added that this would present a conflict for sources whose highest emissions might occur under conditions that are consistent with the unit's basic design, but which the unit might not normally choose to operate.

Response: We are not providing a waiver for excess emissions during performance testing. The requirement for conducting performance testing is to use the fuels, or mixture of fuels, that contain the highest amount of pollutants regulated by the boilers NESHAP. We did not intend to imply that you " de tune" your control device during the performance testing. The purpose of the requirement to burn the fuel or mixture of fuels with the highest pollutant content is to provide an assurance that you will be able to meet the emission limits of the NESHAP even when burning the fuel( s) with the highest pollutant content. To address concerns over compliance flexibility, the final rule provides several different approaches to compliance that were not in the proposed rule such as: 1) fixed opacity limits; 2) operating ranges for operating limits; 3) demonstrating compliance through fuel analysis; and 4) emissions averaging across multiple solid fuel fired boilers at a single facility.

Comment: Two commenters ( 345, 487) requested that EPA clarify that gaseous fuel fired units are not required to demonstrate initial compliance with the emission limitations and work practice requirements. The commenters explained that the proposal is clear that liquid fuel fired units are not required to conduct this demonstration, but does not specifically state that gaseous fuel fired units are exempt from this demonstration. Another commenter ( 478) requested that EPA not require emission testing for existing residual oil fired units since they have no emission standards, or at least not require performance tests for units burning distillate oil.

Response: In the final boilers NESHAP, we clarify that all existing gaseous and liquid fuelfired units are not required to demonstrate initial compliance with the emission limits or work practice standards. Existing gas and liquid fuel fired units smaller than 10 MMBtu/ hr are exempt from all requirements under the final boilers NESHAP, and existing small gas and liquid fuel fired units greater than 10 MMBtu/ hr only have to submit initial notifications. For new liquid fuel fired boilers that do not burn residual oil, the final rule clarifies that no performance testing is required to demonstrate compliance with the emission limits. However, if your new liquid fuel fired unit burns residual oil, you will be required to demonstrate compliance through fuel analysis or performance testing. If your new gas or liquid fuel fired unit is larger than 10 MMBtu/ hr, then you will be required to demonstrate compliance with the CO work practice standard. In this case, if your unit is less than 100 MMBtu/ hr, you can conduct annual performance testing for CO. However, if your new gas or liquid fuel fired unit is larger than 100 MMBtu/ hr, then you will be required to install and operate a CO CEMS to demonstrate compliance with the CO work practice standard.

Comment: One commenter ( 376) requested that EPA allow one year after the compliance 138 deadline for facilities to conduct the initial performance test.

Response: We do not allow one year after compliance to conduct initial performance testing. In the final boilers NESHAP, we included the General Provisions allowance that provides 180 days after the compliance deadline to conduct performance. This timeline is consistent with other NESHAP and NSPS programs and we believe that this is sufficient time for sources to conduct initial performance testing.

Comment: Several commenters ( 388, 400, 449, 492, 498, 524, 533) requested that EPA clarify that a compliance test conducted within 60 days of the initial due date or subsequent annual due dates meets the provisions for testing. The commenters also recommended that EPA allow units not operating within the timeframe of a required performance test to conduct such testing within 60 days of commencing or recommencing operations. The commenters argued that it is nonsensical to require units that do not operate on a regular basis to have to commence operation for the sole purpose of performance testing. One commenter ( 413) requested EPA consider including a " grace period" for periodic testing similar to the period provided for performance of relative accuracy test audits under the Acid Rain Program. The commenter explained that the grace period allows a source time to complete testing after coming back on line from an unexpected event, such as a outage. The commenter added that such a grace period does not extend the deadline for future testing. The commenter added that the grace period would eliminate the need for submission of source specific petitions to seek minor extensions of testing.

Response: We to not provide a " grace period" for conducting performance testing. The final boilers NESHAP has extended the compliance date from three to four years after publication of the final rule and includes the General Provision allowance of 180 days after the compliance date to conduct the initial performance testing. Therefore, we believe that facilities have adequate time to prepare for the initial performance testing requirements. Furthermore, for the annual performance testing requirement, we require that sources conduct their performance testing between 10 and 12 months after the previous performance testing. We also allow sources to conduct testing once every three years if they conduct three consecutive performance tests that demonstrate compliance. We believe that this provides sufficient flexibility for sources to conduct performance testing.

Comment: One commenter ( 332, 424) requested that EPA allow sources to use handheld monitors on a routine basis according to EPA approved calibration and testing protocols instead of periodic source testing. One commenter ( 332) noted that the use of reasonably accurate and cost effective instrumentation would do more to improve the environment than expensive and precise, yet infrequent source tests.

Response: We do not allow the use of handheld monitors in lieu of performance testing. The only pollutant regulated by the boilers NESHAP that could be tested using a handheld monitor is carbon monoxide, and for carbon monoxide we modified the final rule to require CEMS only for larger sources that have a heat input of 100 MMBtu/ hr or more. Sources with heat input less than 100 MMBtu/ hr that have a carbon monoxide work practice standard are only required to conduct annual performance testing.

Comment: Several commenters ( 388, 449, 491, 492, 498, 524, 533) requested that EPA 139 allow performance testing on a single unit and allow the results of that testing to represent units that are similar. The commenters noted that another EPA MACT standard includes such a provision. The commenters also noted that similar units: 1) use the same fuel; 2) are operated in the same manner; 3) are of the same design; and 4) are tested at the highest load expected at any of the represented units.

Response: In the final boilers NESHAP, we provide additional compliance flexibility compared to the proposed NESHAP. However, we do not allow the performance testing on a single unit represent units that are similar. The performance of individual units can vary and therefore we do not feel that using representative performance tests would ensure compliance with the emission limits.

Comment: One commenter ( 523) stated that this rule need not impose stack testing requirements because Title V permits cover such provisions. The commenter believes that mandating stack testing in the rule could conflict with existing Title V permits. In addition, the commenter stated that the monitoring requirements in this proposed rule are extremely costly, burdensome, and unnecessary.

Response: We have worked to minimize the testing and monitoring requirements of this rule while retaining the ability to ensure compliance with the emission limits and work practice requirements. Sources may conduct performance testing once every three years if they conduct successful performance testing for three consecutive years. We are also allowing sources to conduct only fuel sampling if they can demonstrate compliance with the hydrogen chloride, mercury, or total selected metals emission limits through fuel analysis. However, stack testing is the only method for demonstrating compliance with the emission limits for units that cannot demonstrate compliance through fuel analysis.

Comment: Several commenters ( 354, 357, 395, 404, 417, 441, 444, 452, 478, 491, 521, 535) objected to the requirement to conduct performance testing at " worst case" conditions. The commenters found this requirement to be unrealistic because stack testing must be scheduled well in advance and worst case conditions depend on fuel, load, and many other variables, making it impossible to assure that the testing will occur during " worst case" conditions. Two commenters ( 521, 535) contended there can be no guarantee that mineral properties for a fuel source at the time of the baseline test can be guaranteed beyond the content identified during purchase contract negotiations with a fuel supplier. One commenter ( 417) recommended that testing be required under normal operating conditions. Two commenters ( 357, 441) suggested that EPA define what " worst case" conditions are because sources do not have the experience to determine " worstcase representative process conditions.

Response: Since proposal, we modified the performance testing requirements regarding the conditions at which you must conduct the testing. During performance testing, you are required to burn the type of fuel or mixture of fuel types that have the highest concentration of regulated HAP. This is what is considered " worst case" for the purpose of performance testing. Since this performance testing requirement is based on the fuel type, and not on any other variables, the determination of the fuel type or fuel mixture that contains the highest level of regulated pollutants is reasonable. After the initial performance testing, you must conduct an analysis of the fuel types that you burn in your unit initially and then once every five years. The fuel analysis applies to each type of fuel and you are not required to conduct additional analyses if 140 you receive a fuel type from a different supplier. Given the revised fuel sampling requirements ( e. g., based on fuel type and not on supplier, etc), developing the fuel blend during the performance testing should address the commenters' concern..

Comment: Several commenters ( 364, 387, 388, 399, 449, 468, 492, 498, 524, 533) requested that EPA clarify that particulate matter testing to determine compliance is based on the " front half" catch and that any " back half" condensable particulate matter is excluded from the compliance determination. The commenters believed that the data EPA used to set the MACT floor is based on " front half" testing data and that compliance determinations should be based on the same methodology. Furthermore, since the metals for which PM is serving as a surrogate for are of the non condensible type that the front half collects.

Response: For the purposes of this NESHAP, only the " front half", or filterable catch of an EPA Method 5 sampling train should be used to demonstrate compliance with any applicable particulate matter emission limit.

Comment: Several commenters ( 354, 355, 357, 374, 382, 388, 400, 427, 447, 449, 484, 491, 492, 498, 519, 524, 533) objected to the requirement for annual performance tests because they believe that it is overly burdensome given the ongoing compliance demonstrations required by the boilers NESHAP. Several commenters ( 357, 382, 388, 400, 444, 449, 478, 492, 498, 524, 533) suggested that initial performance testing should be required with subsequent performance testing occurring every 3 to 5 years. Some commenters stated that 5 year test intervals are consistent with Title V permits and have been allowed in other MACT standards ( e. g., Hazardous Waste Combustors). One commenter ( 484) suggested that if a source fails a performance test, then the source should be required to perform two consecutive successful annual performance tests prior to returning to a three year cycle. One commenter ( 478) urged EPA to extend the reduced testing provision from three years to five years for facilities that have conducted three consecutive tests that demonstrate compliance with this NESHAP. One commenter ( 404) recommended that EPA allow facilities to immediately use the three year testing schedule if they have three valid stack tests indicating compliance in the past several years. Another commenter ( 491) suggested that provisions be included in the rule to allow operators of " clean units" to be eligible for reduced performance testing frequency. As an example, the commenter stated that a boiler or process heater with emissions no greater than 80 percent of the compliance level should be required to test only every three years. In addition, the commenter stated that units with even " cleaner" performance should be granted required test frequencies of every five years. The commenter urged EPA to revise Subpart DDDDD to include reduced performance testing frequency for " clean units," with EPA reserving the authority to require testing at any time if due cause exists to indicate emissions are no longer " clean."

Response: We have worked to minimize the testing and monitoring requirements of the final rule while retaining the ability to ensure compliance with the emission limits and work practice requirements. Sources may conduct performance testing once every three years if they conduct successful performance testing for three consecutive years. We are also allowing sources to demonstrate compliance with the hydrogen chloride, mercury, and total selected metals emission limits through fuel testing if they do not need emission control devices to achieve the standard. However, stack testing is the only method for demonstrating compliance with the emission limits for units that cannot demonstrate compliance through fuel testing. 141 Comment: One commenter ( 491) stated that sampling of coal burned during a three hour performance test is not practicable with some coal feed system designs. The commenter requested that EPA clarify that testing samples obtained by following procedures established to obtain a representative sample of coal as bunkered for burning during the performance test is acceptable for the measurements required in § 63.7530( c).

Response: In the final boilers NESHAP, you must sample and analyze the fuel types that you burn initially and then once every five years for each type ( e. g., bituminous coal, tires, biomass, etc.) of fuel burned in a boiler or process heater. Therefore, we believe that this addresses the commenter's concern regarding sampling frequency. You would have to conduct additional fuel analyses only if you burn a new type of fuel. We have provided a specific procedure for you to follow as you conduct fuel sampling, including the development of a sitespecific fuel analysis plan, in § 63.7521.

Comment: Several commenters ( 364, 382, 387, 388, 399, 413, 444, 449, 468, 492, 498, 521, 522, 524, 533, 535) objected to the requirement for larger solid fuel fired units (> 250 MMBtu/ hr) to use the ASTM method for determining mercury emissions and requested that EPA remove this requirement. The commenters argued that the ASTM method is more expensive, is not an EPA reference method, uses a considerably more complex sampling train and analytical methods, and that there are minimal differences between the results of the two test methods. Some commenters argued that EPA has not provided information on or explained the logic for requiring different test methods depending on heat input capacity. Furthermore, the commenters explained that the data used to set the MACT floor were conducted using EPA Method 29. The commenters contended that performance testing for mercury should allow use of either Method 29 or Draft ASTM Z65907 for any size source at the discretion of the affected source.

Response: In the final NEHSAP, we removed requirement for units > 250 MMBtu/ hr to use the ASTM method for mercury performance testing. All sources have the option of using either EPA Method 29 or ASTM Method D6784 02 for conducting performance tests for mercury.

Comment: Several commenters ( 382, 388, 449, 498, 524, 533) requested that EPA allow affected units with dry controls the option to utilize either Method 26 or 26A for the determination of hydrogen chloride emissions. The commenters explained that as an isokinetic test method, Method 26A may be performed in the " back half" of a Method 5 sampling train and the use of this method could provide some savings for testing costs.

Response: In the final boilers NESHAP, the performance testing requirements allow you to use either EPA Method 26 or 26A for the determination of hydrogen chloride emissions.

Comment: Commenters ( 364, 399, 387) recommended that EPA amend EPA Method 19 applicability to clarify that it can apply to the calculation of hydrogen chloride, selected metals, and mercury emissions. The commenter noted that currently, Method 19 states that it should be used for the determination of particulate matter, sulfur dioxide, and oxides of nitrogen emissions. If the applicability of Method 19 to these other pollutants is not amended, the commenter is concerned that implementation problems could result. 142 Response: We are not going to modify Method 19 in this rulemaking because it is outside of the scope of this rulemaking. We realize that the equations provided in Method 19 were developed for pollutants other than those regulated in this NESHAP, but those equations can be used for the pollutants regulated by this NESHAP. We clarify in the final NESHAP which equations from Method 19 you should use in order to avoid confusion.

Comment: Several commenters ( 357, 364, 399, 387, 403, 406, 407, 408, 501) requested that EPA promulgate an alternative procedure for calculating heat input. Some commenters noted that the use of EPA Method 19 is difficult to apply where multiple fuels are burned and some of those fuels may have variable moisture content and the published F factors may not apply, or may significantly differ from the actual F factors. The commenters recommended that EPA allow sources to use the thermal efficiency method to determine heat input.

Response: We consider the use of thermal efficiency a viable option to determine heat input. However, we do not specifically outline a method in the boilers NESHAP to evaluate heat efficiency or monitor heat input. If you want to use boiler or process heater efficiency to determine heat input, you must petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63. Typically, boilers monitor steam flow. Through the use of boiler efficiency measurements and calculations, you can determine the heat input of a boiler. If you own or operate a boiler and want to use boiler efficiency, you must use a current ASTM method for determining heat input in your alternative monitoring plan. Process heaters may have different outputs to relate to heat input. If you can demonstrate the relation of process output to heat input, we consider that a viable method to determine heat input. For boilers and process heaters, your alternative monitoring plan must include the requirement to determine unit efficiency before or during the initial performance test and to determine unit efficiency with every subsequent performance test to make sure that any changes in unit efficiency are reflected in each performance test result.

Comment: One commenter ( 491) stated that the proposed boilers NESHAP does not specify allow methods for determining the heating value of fuel. The commenter suggested that EPA clarify its expectations for allowable methods so operators can determine the fuel heating value pursuant to rule requirements. In addition, the commenter stated that if method selection is expected to be made by the operator and merely included in the site specific test plan pursuant to § 63.7520( a), then EPA should clarify that expectation.

Response: In the final NESHAP, we outline methods to be used for determining fuel heating value in Table 6. However, if you want to use another method, you can petition the Administrator for the use of an alterative testing plan under § 63.7( e)( 2)( ii) and ( f) of subpart A of part 63.

Comment: One commenter ( 413) requested EPA to allow the use of Method 101 A to measure mercury emissions. The commenter noted that Method 29 specifically notes that mercury can be measured, alternatively, using EPA method 101 A.

Response: In the final NESHAP, we allow either EPA Method 29 or the ASTM Method D6784 02, to measure mercury emissions. As EPA Method 29 specifically allows for the use of EPA Method 101 A, you could use that method to demonstrate compliance with the mercury 143 emission limits of this NESHAP. However, neither EPA Method 29 nor Method 101 A has been revised to reflect the best laboratory techniques for preserving and recovering mercury from the permanganate impingers. If you believe this might be an issue for you, the ASTM Method D6784 02 may be a better choice.

Comment: One commenter ( 529) recommended that § 63.7515( d) be changed to read "... you must demonstrate compliance and thereafter conduct annual stack tests..." This change requires a facility to demonstrate compliance before entering an annual performance test schedule.

Response: We do not believe that this change is necessary. The final NESHAP has changed since proposal to clarify the performance testing schedule requirements and affected source should readily understand that they are required to conduct initial and annual performance testing. 144 12.0 Recordkeeping and Reporting Comment: One commenter ( 484) stated that EPA's proposal supercedes critical language that facilities rely upon to realize their general duty to minimize emissions during startup, shutdown, and malfunction conditions. In addition, the commenter asserted that uninhibited, ongoing source adjustments to startup, shutdown, and malfunction plans provide the internal control necessary to meet this general duty.

Response: The startup, shutdown, and malfunction ( SSM) plan requirements contained in the General Provisions to part 63 apply to all sources subject to a NESHAP unless specifically exempted for a specific source category. We are not exempting sources from the SSM requirements, unless they have no emission limits or work practice standards under the final rule. The SSM plan requirements are not intended to supercede existing plans to minimize emissions during periods of SSM, but are required in order to make facilities document how their sources undergo SSM, how sources minimize emissions during SSM, and to provide a procedure that sources must follow during periods of SSM. You can incorporate existing SSM plans into the SSM plan required by the final rule. Refer to § 63.6 of subpart A of this part for more information regarding SSM plan requirements.

Comment: One commenter ( 427) requested that the requirement for semiannual compliance reports in § 63.7550( a) be modified to allow the flexibility for annual compliance reports in order to make the rule consistent with other MACT standards with which the commenter is required to comply.

Response: We did not modify the reporting schedule in the final rule. However, the General Provisions ( 40 CFR part 63, subpart A) allows you to petition the Administrator for a different reporting schedule. Furthermore, § 63.7550( b)( 5) allows for an alternative reporting schedule if your permitting authority has already established different reporting dates for your semiannual report pursuant to 40 CFR 70.6( a)( 3)( iii)( A) or 71.6( a)( 3)( iii)( A).

Comment: One commenter ( 427) contended that § 63.7505 ( General Compliance Requirements) must be clarified to state that it applies only if § 63.7500 ( Emission Limits) applies. The commenter stated that § 63.7500 should contain the explicit statement that it applies only to those sources not explicitly exempted under § 63.7490 ( Applicability).

Response: In the final rule, we specifically note in § 63.7505 the minimal requirements for sources that do not have any emission limits or work practice standards under § 63.7500. We believe that § 63.7490 clearly lists which sources are not subject to the final rule ( including the emission limits and work practice standards contained in § 63.7500). We do not provide an additional statement in § 63.7500 that states that the emission limits and work practice standards apply only to source not specifically exempted under § 63.7490.

Comment: One commenter ( 529) suggested that § 63.7535( a) be revised to require monitoring and data collection in accordance with § 63.7535 and the Site Specific Monitoring Plan required by § 63.7505( c).

Response: We agree with the commenter's suggestion and revised the final rule 145 accordingly.

Comment: One commenter ( 491) suggested that § 63.7550( b)( 1) be revised as follows:

§ 63.7550( b)( 1) The first compliance report must cover the period beginning on the compliance date that is specified for you affected source in § 63.7495 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for your source in § 63.7495.

Response: We agree with the commenter's suggestion and in the final rule we have included the change recommended by the commenter.

Comment: One commenter ( 346) recommended that the Quality Assurance Procedures in Appendix F to Part 60 be provided as an acceptable alternative to the site specific monitoring plan because some State permits require this documentation.

Response: The site specific monitoring plan requirements in § 63.7505 apply for all continuous monitoring systems used to comply with this NESHAP. Since the quality assurance procedures in Appendix F to Part 60 apply only to continuous emission monitoring systems and only some new and reconstructed sources will be required to install and operate these systems, these quality assurance procedures do not address the other types of continuous monitoring systems that are based on operating parameters. You can include the quality assurance procedures in Appendix F to Part 60 in the quality assurance section of your site specific monitoring plan if you are required to install and operate a CEMS to comply with this NESHAP.

Comment: One commenter ( 484) recommended that EPA utilize its authority under 40 CFR Part 70 to eliminate duplicative state reporting requirements. The commenter stated that the reporting requirement in § 63.10( d)( 5)( i) of the boilers NESHAP regarding malfunction reporting is duplicative and should be deleted from the standard.

Response: We do not have authority under this rulemaking to eliminate duplicative state reporting requirements. The malfunction reporting required under § 63.10( d)( 5)( i) is a semiannual occurrence for a source that experience startups, shutdowns, or malfunctions and must respond to those occurrences according to their SSM plan. If that requirement overlaps with another requirement in your Title V Operating Permit, you should work with your permitting authority to streamline your reporting requirements.

Comment: Several commenters ( 383, 413, 490, 499) maintained that the recordkeeping and reporting requirements are burdensome, costly, and require unnecessary data. One commenter ( 413) provided examples of unnecessary information. The commenter added that much of the information required cannot be collected automatically but must be manually gathered. Two commenters ( 484, 535) stated that required submission of SSM plans and associated revisions is administratively burdensome and redundant. One commenter ( 383) would like EPA to streamline these requirements and offered to work with EPA to do so.

Response: Since proposal, we have streamlined many of the monitoring requirements, which will result in much less reporting and recordkeeping. These changes especially reduce the amount of manually gathered data associated with the fuel sampling provisions of the final rule. 146 We have worked to minimize the compliance burden of the final rule, and maintain that the recordkeeping and reporting requirements that we have retained are necessary to ensure continuous compliance with the provisions of this NESHAP Comment: One commenter ( 424) requested that EPA clarify if permitting requirements under the boilers NESHAP will be in addition to semiannual reporting under Title V, such as deviation information. One commenter ( 490) stated that these requirements impose burdens over and above what is required by states under State Implementation Plans and Title V monitoring requirements. The commenter urged EPA to reconsider the monitoring, recordkeeping, and reporting requirements associated with this rule and make them compatible with existing Title V requirements for the same emission units.

Response: Making the monitoring, recordkeeping, and reporting requirements of this rule compatible with existing Title V requirements is not feasible. Many states have accepted delegation of the Title V program from EPA and their requirements vary from state to state. Therefore, we cannot make the requirements of this rule fully compatible with existing Title V requirements. In the final rule, we have streamlined many of the monitoring requirements, which will also result in decreased recordkeeping and reporting burdens. Furthermore, many of the monitoring requirements in the final rule are parameters that sources would already be monitoring, so we do not expect this NESHAP will impose burdens over and above what may already be required. If you already have a monitoring program that you believe would satisfy the monitoring elements of this NESHAP, you can petition the Administrator for approval of an alternative monitoring plan under section § 63.8( f) of subpart A of part 63.

Comment: One commenter ( 491) stated there was no reasonable basis to require determining and reporting the average daily hours of operation by each source, or affected source, for each calendar month within the semiannual reporting period. The commenter suggested simplifying § 63.7550( c)( 8) to read, " The hours of operation by each affected source for each calendar month within the semiannual reporting period." One commenter ( 428) stated that given the very large potential increase in the recordkeeping burden for small sources that are not contributors to HAP emissions and the lack of a rationale for collecting such information even for larger sources, the requirement to keep records of daily hours of operation by each source ( § 63.7555( d)( 2)) should be stricken for the regulation Response: In the final rule, we modified the recordkeeping and reporting provisions to require only that monthly fuel use be recorded and reported. Furthermore, the only sources that now have to monitor hours of operation are limited use sources, and they are required to record and report hours of operation on a monthly basis.

Comment: One commenter ( 413) expressed concern regarding how control device parameter deviations during startup, shutdown, and malfunction will be treated by the EPA and what time limit the Administrator will follow in making determinations. The commenter added that a source would not know whether it was in compliance or not if something happens during a startup or a malfunction that is not covered by the plan.

Response: During periods of startup, shutdown, and malfunction, you are required to follow the procedures that you have outlined in your SSM plan according to § 63.6 of subpart A 147 of part 63. In this § 63.6, we explain how parameter deviations would be treated. It states: " At all times, including periods of startup, shutdown, and malfunction, the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. During a period of startup, shutdown, or malfunction, this general duty to minimize emissions requires that the owner or operator reduce emissions from the affected source to the greatest extent that is consistent with safety and good air pollution control practices. The general duty to minimize emissions during a period of startup, shutdown, or malfunction does not require the owner or operator to achieve emission levels that would be required by the applicable standard at other times if this is not consistent with safety and good air pollution control practices, nor does it require the owner or operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator, which may include, but is not limited to, monitoring results, review of operation and maintenance procedures ( including the startup, shutdown, and malfunction plan required in paragraph ( e)( 3) of this section), review of operation and maintenance records, and inspection of the source." Furthermore, it states that: " Malfunctions must be corrected as soon as practicable after their occurrence in accordance with the startup, shutdown, and malfunction plan required in paragraph ( e)( 3) of this section. To the extent that an unexpected event arises during a startup, shutdown, or malfunction, an owner or operator must comply by minimizing emissions during such a startup, shutdown, and malfunction event consistent with safety and good air pollution control practices." This means that the Administrator will review any deviations that occur during a SSM event and respond based on your adherence to your SSM plan and your history of SSM events.

Comment: One commenter ( 491) stated that deviation reporting is required pursuant to § 63.7550. The commenter stated it is unclear why additional deviation reporting is required pursuant to § 63.7545( e)( 1)( vii) when submitting a Notification of Compliance Status report. In addition, the commenter stated that the time period for which deviations need to be reported is not specified. The commenter stated that the initial Notification of Compliance Status is due before the close of business on the 60th calendar day following the completion of the performance test and/ or other initial compliance demonstrations according to § 63.10( d)( 2). The commenter stated there is no basis for requiring duplicative deviation reporting when submitting a Notification of Compliance Status report and recommended deleting § 63.7545( e)( 1)( vii). Response: The deviation reporting required by § 63.7545( e)( 1) is an element of your Notification of Compliance Status report that you must submit after your initial compliance demonstration, or any subsequent performance test or compliance demonstration. This report is required only under these circumstances and the deviation portion addresses any deviation from an applicable emission limit or work practice standard that may have occurred during your performance test or compliance demonstration. The deviation reporting requirement under § 63.7550( d) is an element of your compliance report that must be submitted semiannually. This report requires you to report any deviation from an emission limit, operating limit, and work practice standard that might have occurred during the previous six month period. These reports serve different functions and we did not delete either of the deviation reporting requirements in the final rule. You must submit your semiannual compliance report by July 31 and January 31 each year according to § 63.7550( b)( 4), unless you have an alternative semiannual reporting period in your Title V Operating Permit. 148 Comment: One commenter ( 523) stated that the rule requires that if there are no deviations during a compliance period, then an affirmative statement must be submitted in the semiannual report. The commenter stated that the renewable operating permit program requires sources to use state generated forms for semiannual reports and these forms do not provide for making such a statement specific to individual NESHAPs. The commenter stated that the forms require that the company certify compliance except for the deviations reported. The commenter stated that there is no reason for the boilers NESHAP to require anything separate or different from that already required by the renewable operating permit. Response: The compliance reporting requirements of this NESHAP do not prescribe a specific format for the semiannual report. As previously discussed, many states operate a delegated Title V Operating Permit program and the requirements of those programs can vary from state to state. Therefore, it would be difficult, if not impossible, to capture all the different state specific reporting requirements in this NESHAP. The final rule outlines the elements that must be contained in a semiannual compliance report. You should work with your permitting authority to integrate those required elements into your standard semiannual report.

Comment: Several commenters ( 379, 388, 449, 491, 492, 524, 533) recommended that deviation reports should not be required for routine startup and shutdown events that are consistent with the SSM plan. Two commenters ( 491, 492) proceeded to explain that startups and shutdowns are routine operations for boilers and process heaters, and are addressed in the SSM plan. The commenters argued that there is no need to submit additional data other than to note that there was a startup or shutdown and that the event was consistent with the SSM plan. Several commenters ( 364, 399, 387, 403) requested that EPA should not require reporting of SSM events that do not result in an exceedance of the emission limits. The commenters argued that the proposed language of the boilers NESHAP would require facilities to report every SSM event, regardless of whether an emission limit or operating requirement was violated. The commenters suggested changes to the definition of SSM that would address their concerns. One commenter ( 491) stated that reporting the date and time that each deviation started and stopped, and that the deviation occurred during a period of startup, shutdown, or malfunction should be sufficient. Response: You must submit a deviation report any time you have a deviation from the emission limits, operating limits, or work practice standards required by this NESHAP. Deviations that occur during SSM events are not automatically a violation of the standard. Your deviation report will be reviewed to see if you followed your SSM plan. Furthermore, your history of SSM events and your response to those events are also considered in the evaluation of deviations that occur during SSM events. If no deviations occurred during an SSM event, you are required only to report that you had an SSM event. We did not change the reporting requirements related to SSM events as these requirements have been addressed in previous revisions to the General Provisions to part 63 and represent EPA's policy regarding these events.

Comment: Two commenters ( 413, 499) stated that the rule fails to propose a standard reporting format or an opportunity for electronic reporting. One commenter ( 499) claimed that much of the required data will have to be hand gathered and hand entered into an electronic format. In addition, the rule does not indicate where or to whom this data should be sent. Response: We did not develop a standard reporting format for this NESHAP because you typically report the required elements to your local permitting authority. In many cases, your 149 permitting authority has accepted delegation of this NESHAP and Title V Operating Permit programs. Once delegated, the permitting authority can develop whatever reporting format requirements they wish as long as they meet the minimum requirements established by EPA. Since these reporting requirements may vary, we believe that developing a standard reporting format in this NESHAP is not appropriate. In the final rule, we have streamlined many of the monitoring requirements, which will result in a substantial decrease in recordkeeping and reporting activities, especially those requirements that cannot be automatically recorded. All required reports should be submitted to your local permitting authority according to your Title V Operating Permit.

Comment: Several commenters ( 388, 449, 491, 492, 498, 524, 533) requested that EPA not require readily available electronic records to be stored onsite. One commenter ( 492) noted that significant changes in technology have encouraged many companies to opt for electronic information storage on computers and servers. In many cases, the server may not be located on the actual site, but the data is still readily available. Therefore, the commenter recommended that § 63.7560( c) be revised to recognize the trend to electronic record keeping. One commenter ( 491) suggested changes to § 63.7560( c) to require on site records to be kept for only the first 2 years, and allow off site storage for the last 3 years. Response: We did not modify the records retention requirements of this NESHAP. These requirements are consistent with other NESHAPs and EPA policy. The requirement to have records stored on site is to facilitate timely review of these records by EPA or your permitting authority. Even readily available electronic data stored off site can be unretrievable if your server is down or if there is a problem with your Internet connection. For these reasons, we will still require that you keep records on site for a period of at least 2 years.

Comment: Several commenters ( 343, 346, 360, 396, 427, 434, 492) recommended that EPA clarify that existing units in all of the gaseous and liquid fuel subcategories ( large/ small/ limited use) and new units in the small gaseous fuel subcategory be excluded from recordkeeping and reporting requirements, including requirements of the General Provisions. The commenters opposed the requirement to develop and implement SSM plans and to submit semiannual compliance reports because these subcategories are not subject to any emission limitations, operating limitations, or work practice standards and the requirements are costly. In addition, the commenters requested that the initial notifications not be required for these units. One commenter ( 345) stated that gas fired or small and limited use subcategories should not have any requirements other than an annual certification that no other fuel was used. One commenter ( 490) requested EPA confirm that since no standard is established for existing gas fired units, there would be no recordkeeping and reporting requirements. In addition, the commenter stated that the language of § 63.7550 and the text in Table 9 must be clarified so that compliance reports and SSM reports are not required for units which are not subject to any standard. One commenter ( 396) added that if EPA intends to still require reports for subcategories with no limits or work standards, then they should explain their rationale. Several commenters ( 369, 410, 426, 447, 479, 491, 519) requested that EPA exempt units that are not subject to any emission limitations, work practice standards, or operating limitations from recordkeeping and reporting requirements, including SSM plans and semiannual compliance reports. One commenter ( 355) suggested that all requirements in the proposed rule that are not directly related to quantifiable emission reductions be removed from the rule ( i. e., notification, monitoring, reporting, fuel analyses, and recordkeeping requirements). One commenter ( 491) stated that Title V permits 150 should not be required for units with no substantive requirements. The commenter recommended that these units be excluded from the various procedure requirements such as initial notifications in the boilers NESHAP or exempt them from Title V and other air pollution permit requirements, if they would otherwise be exempt under state or local regulations. Response: In the final rule, we specifically exempt sources with no emission limits or work practice standards from most requirements of this NESHAP and the General Provisions to part 63, including the SSM plan requirements. For large sources ( i. e., sources with heat input capacities of 10 MMBtu/ hr or greater) we require only that you submit an initial notification. See § 63.7505( e) and ( f) of the final rule for the requirements for sources with no emission limits or work practice standards.

Comment: One commenter ( 491) suggested that EPA remove the requirement in § 63.7520 to prepare a site specific test plan for those facilities that do not have to perform any testing. Response: The final rule does not require you to prepare a site specific test plan if you do not have to perform any emission testing. If you demonstrate compliance through fuel sampling and analysis, you will have to develop a site specific fuel sampling plan.

Comment: One commenter ( 380, 476) requested clarification of whether daily fuel use records are required for gas fired boilers. The commenter contended that the preamble and the regulatory text have differing views. The commenter added that since gas fired boilers are subject to only the CO work practice, it is unnecessary to maintain records for fuel use. One commenter ( 427) questioned why it is necessary for gas and liquid fired sources that switch suppliers to submit notifications of fuel changes if they are not required to be controlled. One commenter ( 417) believes the provisions requiring operators to keep daily records of fuel use and operating hours are onerous and unnecessary. If a facility does not have any indication of compliance problems, these recordkeeping obligations should be substantially reduced to require only information about atypical operating hours and new fuels that threaten an emission limit. The commenter ( 417) believes that operators should only have to provide statements if fuel chlorine, mercury or total selected metals will exceed a prorated value equal to the applicable emission standard. Several commenters ( 406, 407, 408, 501) contended that the proposed rule would place unduly burdensome monitoring and recordkeeping requirements on owners of biomassfueled boilers. The commenters added that a strict reading of the proposal could require an almost continuous process of fuel analysis, with extremely burdensome recordkeeping consequences. The commenters added that the reporting requirements for the semiannual compliance reports are excessive. The commenters requested that EPA reduce the requirements to a semiannual statement of compliance, using current state forms already developed for this purpose and that only require deviations from compliance to be included. Response: The final rule does not require existing liquid and gaseous fuel fired units to keep records of fuel use. New gaseous fuel fired units that do not have any emission limits or work practice standards and new liquid fuel fired units that do not burn any residual oil do not have to monitor fuel use. For all other sources that have to monitor fuel use, we have modified the fuel monitoring requirements to be based on monthly fuel use, and no longer require daily fuel use monitoring. We have also modified the fuel sampling requirements to be based on fuel type and not on fuel shipment, supplier, and location. Therefore, if you have to conduct fuel sampling, you will only be required to conduct an initial sample, and then once every five years for each fuel type that you burn. Additional fuel sampling would be triggered only if you burned a new type of 151 fuel. We maintain that the changes to the fuel monitoring and sampling requirements in the final rule will significantly reduce the recordkeeping and reporting burden of the final rule.

Comment: One commenter ( 491) stated that § 63.7555( d) does not contain a clearly relevant applicable requirement for such affected sources unless they were deemed to be electing to comply with an emission limit based on fuel analysis. Therefore, the commenter suggested that the section be modified to read: § 63.7555( d) You must also keep the records in paragraphs ( d)( 1) through ( 5) of this section, as applicable. ( 1) If you operate an affected source in one of the liquid fuel subcategories that burn only fossil fuels and other gases and do not burn any residual oil, or you elect to comply with an emission limit for an affected source based on fuel analysis, you must keep records of daily fuel use by that affected source, including the type( s) of fuel, amount( s) used, the supplier( s), and original source location( s). ( 2) You must keep records of daily hours of operation by each affected source. Response: In the final rule, we modified this section to clarify that all units subject to an emission limit must keep records of fuel use. This requirement has changed from daily fuel use to monthly fuel use in the final rule. Also, we require only that you keep records of operating hours, on a per month basis, if you have a limited use source. As stated in an earlier section of the final rule, if you have a liquid fuel fired unit and you do not burn any residual oil, you are not required to monitor fuel use. We also made several changes to the fuel sampling and analysis requirements that significantly reduce the recordkeeping burden of this NESHAP.

Comment: One commenter ( 357) contended that the recordkeeping requirements should be based on fuel analysis and not supplier. The commenter added that as along as levels established during performance testing are not exceeded, the fuel source does not matter. Response: In the final rule, we modified the fuel monitoring requirements to be based on fuel type, and removed the requirements to conduct additional fuel analyses when you receive fuel from a new supplier, as long as it is the same type of fuel that you have previously analyzed. This change should significantly reduce the monitoring, recordkeeping, and reporting burden of the final rule.

Comment: Two commenters ( 388, 449, 492, 498, 524, 533) stated that only one statement should have to be provided for each fuel in the event that several similar units are fired with the same fuel. One of the commenters ( 492) suggested allowing one statement to be submitted along with the supporting calculations. The commenter did not see any need in requiring repeated statements and calculations for each unit. Furthermore, the commenter noted that if a source is required to burn fuel with certain specifications, then the owner or operator should not have to submit these statements. Response: We do not allow one statement to be provided for similar units burning the same type of fuel. We do not believe that this is a requirement that needs to be changed. The monitoring, recordkeeping, and reporting requirement of this NESHAP, and typically of permits, require information to be submitted based on each unit. The calculations used for the fuel type could be used for all units burning the fuel, therefore, this is not an onerous requirement.

Comment: Several commenters ( 374, 388, 449, 492, 498, 523, 524, 533) suggested that initial notifications should not be required for affected sources that have submitted 112( j) Part 1 152 applications. One commenter ( 523) stated that at a minimum, initial notifications should be required only from sources subject to a work practice or an emission limitation and not simply because a source is subject to a monitoring, recordkeeping, or reporting requirement. One commenter ( 492) contended that requiring these sources to submit similar initial notifications required under § 63.7545( b) and ( c) is redundant and burdensome. Response: Most sources are not required to submit an initial notification under this NESHAP. We do not believe that this is a burdensome requirement. We are not requiring small existing sources to submit an Initial Notification because they do not have any emission limits or work practice standards and believe that this will eliminate several thousand sources from having to submit a notification. All new sources that are subject to this NESHAP, whether they have emission limits and work practice standards or not, will have to submit an Initial Notification.

Comment: One commenter ( 523) stated that the requirement to submit semiannual reports 30 days after the end of the reporting period conflicts with state reporting requirements. The commenter stated that semiannual reports should be submitted as required by the renewable operating permit ( ROP). Response: As outlined in § 63.7550( b)( 5), if you have an alternative reporting schedule for semiannual reporting outlined in your Title V operating permit, then you can submit the semiannual report required by this NESHAP on those dates. However, these alternative reporting dates must be pursuant to 40 CFR 70.6( a)( 3)( iii)( A) or 40 CFR 71.6( a)( 3)( iii)( A).

Comment: One commenter ( 529) mentioned that the site specific monitoring plan is required to be submitted for approval as stated in § 63.7505( c)( 1), but does not have a stated submission date. The commenter assumes the plan should be submitted in accordance with the submission schedule for the site specific performance evaluation plan shown in § 63.8( e), but would like clarification. Response: In the final rule, we clarify a submittal date for your site specific monitoring plans of 60 days before your initial compliance demonstration. This is the least amount of time before your initial compliance demonstration that you can submit your monitoring plans. We suggest that you submit your monitoring plans more than 60 days before your initial compliance demonstration, especially if you are petitioning the Administrator for an alternative monitoring plan, to allow time for you and your permitting authority to resolve and issues that may exist.

Comment: One commenter ( 523) stated that the rule requires sources to implement a written SSM plan according to the requirements of the NESHAP general provisions. The commenter believes that instead of referencing the general provisions, specific SSM requirements should be adopted in this rule. The commenter stated that the general provisions are intended to be " gap fillers," i. e., requirements which apply unless the specific rule states otherwise. The commenter stated that since the SSM general provisions appear to be in flux due to litigation over the general provisions, the commenter suggested specifying the provisions in this rule and not having 40 CFR 63.6( e) apply. The commenter stated that this approach will also avoid conflicts between the state rules for SSM plans, Title V requirements, and the NESHAP. The commenter stated that the SSM requirements only need to state that such a plan be prepared, implemented, written, and amended as necessary to address SSM issues. In addition, the commenter stated that there should not be any requirement to submit the plans to the state agency for approval, instead simply a requirement that the plan be " approvable" in the sense that it meets the state requirements and those currently listed under § 63.6. 153 Response: We do not incorporate the SSM plan requirements of the general provisions into this rule. The final rule continues to reference the SSM plan requirements in the general provisions. The general provisions exist not as a " gap filler," but as a way to provide consistency for compliance activities that must occur for all sources subject to a NESHAP.

Comment: One commenter ( 523) suggested that since all of the sources affected by this NESHAP are subject to the Title V permit program and since that program already includes a compliance certification requirement, as well as a requirement for reporting at least semiannually, the additional monitoring requirements included in this rule should be modified so that sources can do all required reporting and recordkeeping through their Title V permit program. The commenter asserted that this is especially necessary for sources that are not subject to any emission limitations under the proposed rule. One commenter ( 358) supported all compliance reporting and recordkeeping be provided to the Administrator as part of the facility's Title V operating permit. The commenter suggested requiring compliance reports to be submitted to the reporting agency no less often than annually, as part of the Annual Compliance Certification Statement. Response: We disagree with the commenter and have retained the recordkeeping and reporting elements in the final rule. Several changes have been made since proposal that have reduced the compliance burden of the final rule. However, we believe that we must include recordkeeping and reporting requirements in this rule and not simply let the Title V Operating Permit program develop those requirements. By including recordkeeping and reporting requirements in this rule, this will result in consistent requirements for all sources affected by this rule. If it were left up to Title V mechanisms, sources could have a wide range of recordkeeping and reporting requirements and we do not believe that this would be appropriate. Furthermore, keeping recordkeeping and reporting requirements in the final rule assure us that all affected sources will collect the right types and amount of data to ensure continuous compliance with this NESHAP.

Comment: Several commenters ( 364, 374, 381, 382, 387, 391, 392, 399, 400, 401, 403, 449, 452, 478, 479, 492) agreed with the EPA approach that deviations during periods of startup, shutdown, or malfunction should not automatically constitute violations of the MACT standards. The commenters urged the EPA to retain it in the final boilers NESHAP. One commenter ( 491) supported the position in § 63.7540( d) that deviations that occur during periods of startup, shutdown or malfunctions are not violations if it can be demonstrated to the Administrator's satisfaction that the source was being operated in accordance with the SSM plan. The commenter stated that it may not be possible to comply with limitations during these times. In addition, the commenter stated that the owner or operator should be required to take expeditious action in the event of a malfunction and that non compliance should not result if the malfunction is corrected in a timely manner. Another commenter ( 448) said that the EPA's compliance loophole for startup, shutdown, and malfunction events is unlawful, arbitrary, and capricious since the proposed standards do not require compliance with emission standards during those events. The commenter also questioned how the proposed provision for determining if a facility was operating in compliance with its SSM plan and OMM plan would operate in enforcement suits brought by citizens rather than the Administrator. Response: We maintain that sources should have special provisions for periods of startup, shutdown, and malfunction as these are normal occurrences for boilers and process heaters, but they are also associated with transient behavior of the source which can lead to fluctuations in 154 emission levels. Sources have to consider personnel and equipment safety considerations during these periods and these considerations also effect a source's ability to minimize emissions and respond to such periods. Therefore, we require sources to develop SSM plans to document how they will operate their source during these periods in order to minimize emission levels. We defer to the Administrator the decision on whether deviations that occur during a period of startup, shutdown, or malfunction are violations of the standard because historical and case dependent factors must be reviewed before such a decision is made. To evaluate a deviation that occurs during a period of startup, shutdown, or malfunction, the Administrator must consider whether the source followed their SSM plan, were there any other actions the source could have taken to minimize emissions, does the source have a history of malfunctions that could be attributed to poor maintenance, and other case specific factors. We believe that this is the most appropriate method to evaluate deviations during periods of startup, shutdown, or malfunction.

Comment: One commenter ( 491) stated that § 63.7550( e)( 6) imposes vague and unnecessary requirements. The commenter suggested that § 63.7550( e)( 6) be revised as follows: § 63.7550( e)( 6) A breakdown of the total duration of the deviations during the reporting period into those that are due to startup, shutdown, malfunction, and other causes. Response: We maintain that these requirements are not vague and unnecessary. In the final rule, we do not state that deviations that occur during periods of startup, shutdown, or malfunction are not automatically violations of the standard. This determination would be made by the Administrator. However, for the Administrator to make such a decision, an historical perspective of a source's startup, shutdown, and malfunction events are necessary. Therefore, we require a more detailed breakdown of the reasons for the occurrence of deviations and are not groupiing control equipment problems, process problems into a single malfunction category.

Comment: Several commenters ( 406, 407, 408, 413, 501) requested that EPA require a 30 day notice for performance testing instead of the 60 day notification in the proposal. Several commenters ( 406, 407, 408, 501) contended that a 60 day notification for performance tests should only apply to the initial performance tests. The commenters added that most states have a much shorter notification requirement. The commenters added that it is difficult to plan testing 60 days in advance when a facility has multiple boilers. Response: In the final rule, we have changed the reporting requirements to require that you submit a notification from 30 to 60 days before you conduct your compliance demonstration. The compliance demonstration is either your performance testing or your fuel sampling, depending on how you demonstrate compliance with this NESHAP.

Comment: One commenter ( 491) claimed that the statement regarding periods of startup, shutdown, and malfunction in § 63.7540( b) is problematic and seems inconsistent with the provisions of § 63.7505( a) which provides " you must be in compliance with the emission limitations ( including operating limits) and the work practice standards in this subpart at all times, except during periods of startup, shutdown, and malfunction." The commenter stated that it is not clear what emission limit or operating limit would not be met that must be reported under § 63.7540( b) since the emission limits and operating limits in Table 7. A and 7. B apply to periods other than periods of startup, shutdown, and malfunction. The commenter suggested clarifying § 63.7540( b) as follows: § 63.7540( b) You must report each instance in which you did not meet each emission limit and each operating limit in Tables 7. A and 7. B to this subpart that apply to you, and you must report 155 each instance during a startup, shutdown or malfunction when emissions exceeded the level of a relevant emissions limit or work practice standard, or you did not meet a parameter value for an operating limit in Table 7. B. You must also report each instance in which you did not meet the work practice requirements in Table 8 to this subpart that apply to you. These instances are deviations from the emission limitations and work practice standards in this subpart. These deviations must be reported according to the requirements in § 63.7550. Response: In the final rule, we revised § 63.7540( b) to make it more clear and consistent with our stance on periods of startup, shutdown, and malfunction. In this section, the final rule separates your reporting requirements for deviations based on whether or not a deviation occurred during a period of startup, shutdown, or malfunction.

Comment: One commenter ( 491) stated that the requirement in § 63.7540( d) that a source must demonstrate that it is operated in accordance with its startup, shutdown, and malfunction plan during every event is burdensome and the demonstration to the " Administrator's Satisfaction" statement is vague. The commenter suggested that § 63.7540( d) be revised to as follows: ( d) Consistent with § 63.6( e) and § 63.7( e), deviations that occur during a period of startup, shutdown, or malfunction are not violations if, upon request of the Administrator, you demonstrate that you were operating in accordance with the startup, shutdown, and malfunction plan. Response: We did not revise § 63.7540( d) as suggested by the commenter. We do not believe that the requirement is overly burdensome and will require you to demonstrate that you were operating in accordance with your SSM plan. The Administrator will require this information anyway if you experienced a deviation during a period of startup, shutdown, or malfunction to determine if the deviation is a violation of the standard or not. To include the commenter's suggested language would retard the process of the Administrator's decision by adding another step in the data gathering process that would automatically occur under the proposed and final rule. 156 13.0 Impacts 13.1 Control Costs Comment: Several commenters ( 338,484, 522, 521, 363) stated that EPA has understated the cost to install controls on existing units because of site specific physical constraints. Commenters ( 338, 484, 522) claimed that due to footprint boundaries, some retrofits are only possible through vertical construction schemes, which can cost up to four times more than horizontal construction schemes. One commenter ( 522) explained that universities and colleges are space limited and any additional controls would have to be integrated vertically as opposed to horizontally, thereby significantly increasing costs. Another commenter ( 521) stated that some boilers' fans, duct work, and positioning were not originally designed to handle a baghouse. Therefore, many parts will need to be modified to accommodate a baghouse as part of boiler NESHAP compliance. The commenter stated that based upon estimates from equipment suppliers, the cost for a baghouse could be $ 3.5 million, almost ten times EPA's estimate. One commenter ( 363) contended that installing flue gas scrubbers would be a problem because there would not be enough room on site. The commenter ( 363) added that purchasing the scrubbers would increase the electricity rates and their customers would not be able to absorb the costs. The commenter concluded that the units would be taken out of service, thereby denying customers an economical and reliable source of electricity. Response: Costs and emission impacts estimated for the boiler MACT standard are intended to represent national impacts. Consequently, costs for a specific facility may be lower or higher than what was estimated for a specific model unit. But on a national basis, we believe that our estimates are reasonable. We would also note that the cost algorithms include a cost factor for retrofitting existing boilers, that do incorporate duct length and some spacial concerns. Additionally, facility or boiler specific information on construction schemes were not available to develop cost impacts. Therefore, they could not be incorporated into the cost estimates.