Comment 17: Commenter 18421 recommends that the EPA adopt a comprehensive Energy Assessment and Benchmarking Program similar to that included in the NESHAP for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, 75 FR 32006. The commenter suggests that the EPA use a four-part program consisting of the following:
   * Require facilities to perform an energy assessment using EPA's ENERGY STAR facility Energy Management Assessment Matrix and then to develop an energy management program according to the ENERGY STAR Guidelines for Energy Management (75 FR 32027).
   * Require facilities to implement energy efficiency measures identified in the facilities' energy assessment consistent with section 112 of the CAA.
   * Establish a performance benchmarking program to ensure that available and cost effective energy savings and pollution reductions are achieved.
   * Regularly evaluate the effectiveness of the energy assessment, benchmarking, and implementation program.
Commenter 18421 notes that the 2009 report "Coal-Fired Power Plant Heat Rate Reductions," by Sargent & Lundy, LLC identifies many available heat rate reduction options.
Response to Comment 17: The EPA has considered implementation of such a program as part of this rulemaking but has decided not to do so. An energy efficiency assessment and benchmarking program may be considered instead in the EPA's forthcoming CAA section 111 rulemaking for GHG emissions.
6. The EPA should adopt market-based beyond-the-floor standards.
Comment 18: Commenter 17768 recommends that the EPA create a tradable emissions permit market for HAP as part of the CAA section 112(d) beyond-the-floor standards. The commenter suggests that a market-based mechanism could consist of anything from tradable performance standards to a nationwide emissions budget with an allowance auction. The commenter considers a cap-and-trade system to be the best approach to ensure emission reduction and recommends the market design take into consideration local characteristics and concentrations of pollutants to avoid pollution hotspots. The commenter also suggests that the cap be lowered over time so as to reflect the rate of technological development.
Response to Comment 18: The EPA is unsure how we could establish a trading program as a beyond the floor alternative and we are also unable to estimate the costs of implementing such a program; therefore, we are not creating a tradable emissions permit market for HAP in this final rule.
7. Concerns with differences between MACT standards for new and existing units.
Comment 19: Commenter 17768 expresses concern that less stringent standards for existing units distort the economic incentives facing plant owners when deciding whether to modernize or replace a plant. Stricter standards for new and substantially modified plants, the commenter argues, make building a new plant or substantially modifying an old plant more expensive than otherwise would be the case, resulting in older plants operating longer than is economically efficient. The commenter recommends that the EPA consider ways in which the Utility MACT could be improved to combat grandfathering's negative impacts.
Response to Comment 19: CAA section 112(d) establishes the manner is which MACT standards must be set. Limits for existing sources are based on the top performing 12% of existing sources (or best performing 5 sources for categories and subcategories with less than 30 sources) whereas the limits for new sources are based on the best performing similar source. Although the Courts have determined that variability may be considered, because of the differences in the pool of data from which the limits are calculated, it almost invariably follows that the new-source limits will be more stringent than the existing-source limits, an outcome we believe Congress intended. That result is particularly likely here where the agency has data on a large number of EGUs. The EPA has complied with the statute in setting emission MACT limits for this rule.
8. Concerns with MACT Floor for standards for HCl.
Comment 20: Several commenters (19536, 19537, 19538) believe the EPA has not properly evaluated the MACT floor standards for HCl. The EPA took the average emission rate of the 131 lowest HCl emitting EGUs for which it had HCl emission data. The commenters are concerned that this approach may not have the lowest emitting 131 (12%) coal-fired EGUs because not all of the units included the dataset have SO2controls. Commenters believe that this approach likely resulted in an HCl MACT floor emission rate that is high. Commenters further note that the 0.0020 lb/MMBtu MACT floor emissions rate for existing sources is higher than the HCl rates actually emitted by any of the 131 EGUs in the EPA's dataset and that the data suggests control technologies in use by those sources can achieve greater emission reductions than the MACT floor. The commenters believe that the EPA's HCl emission data implies that EGUs may not have to install scrubbers to meet the EPA's HCl MACT floor for existing sources, and some EGUs may not have to install any SO2 controls. Commenters argue that there are beyond the floor techniques and methodologies that must be at least considered by the EPA in setting the existing source MACT standard for HCl.
Response to Comment 20: The methodology for setting the HCl floor  -  and including variability attributable to operational, process, fuel and other sources of variability  -  are discussed in the preamble for the proposed rule and in response to comments in this final rule. That methodology is consistent with methods used in setting emission floors and accounting for variability for other CAA section 112 rules. The EPA is not setting a beyond-the-floor emission limit for HCl for all the reasons set forth in the proposed rule and in response to comments. We note that the HCl MACT floor will achieve significant reductions (nearly 98% reduction from 2009 levels when combined with the Cross State Air Pollution Rule), and that any additional reductions would be achieved at a very high incremental rate.4D01 - Work Practice Standards: Annual performance testing
Commenters: 17628, 17691, 17715, 17716, 17729, 17758, 17775, 17820
Comment 1: Commenter 17715 states that operating limits for control equipment based on a point-in-time stack test does not recognize the inherent variability of fuel or the balancing act that plant operators perform daily to meet emission limits for, not just HAP, but all of the pollutants that are currently regulated. As currently proposed, units would be constrained by unachievable operational parameters because the set of operating limits that a unit measures during its first performance test would be its maximum operating limits. Subsequent performance tests would further ratchet down operating parameters until they are no longer achievable during a 30-day or annual averaging period.
Commenter 17820 states that any source that is able to normally operate with a margin of compliance will lose part of that margin if they conduct performance testing under normal operations, because they will establish operating limits that would require them to continue to over-control forevermore. The only way such sources could avoid surrendering whatever margin of compliance they have would be to deliberately reduce performance of their controls to attempt to generate the least stringent operating limits consistent with achievement of the applicable emission standard. This proposed approach, therefore, has the perverse result of encouraging sources to focus their attention on learning how to manipulate their operations to allow testing as close as possible to their emission limit by reducing performance of their controls.
Response to Comment 1: The EPA believes that effective monitoring is needed to ensure ongoing compliance with this rule. In order to minimize costs, we have re-examined the various proposed monitoring requirements, and significantly streamlined the basic approaches required under the final rule. In response to these comments about establishing operating limits for control equipment, the final rule does not require any control device operating parameter monitoring. The only generally applicable operating limit that will apply will be for units that opt to use a PM monitor as a parameter monitoring system (PM CPMS) for ensuring compliance with the filterable PM, total metals, or individual HAP metals limits in the final rule. In certain situations, a liquid oil-fired unit also may need to develop a site-specific monitoring plan for parameter monitoring. See further discussion of these issues in the final preamble and under Comment Code Area 5A05 of this document. If a source does not use a PM CPMS in that manner, or opt to use a PM CEMS for direct compliance with a filterable PM emission limit, then the source must test on a quarterly basis. See the final preamble and responses to stack test frequency under Comment Code Area 5A01 of this document for further discussion. For acid gas limits, a source may use an SO2 CEMS (if the unit is equipped with an FGD), an HCl CEMS, or conduct quarterly testing. For Hg, the source will have to use an Hg CEMS (including sorbent trap option) or for LEEs, conduct annual testing.
Under the final rule, for the PM CPMS operating parameter, we clarify that the operating limit be established on a site-specific basis as the maximum hourly average raw output parameter value measured over a single test run during the performance test. For PM CPMS, the most likely raw output value will be a maximum milliamp value. Depending on the emissions limit chosen by the EGU owner or operator, the operating limit will be established during a Method 5 or 29 test demonstrating compliance with the filterable PM, individual HAP metals, or total HAP metals emissions limit. Continuous compliance will be demonstrated by using a 30-day rolling average of all valid hourly data collected during each operating day at the source. Subsequent testing may result in a lowering of this operating limit, or it may allow for a relaxation of the limit, depending on the results obtained during performance testing based on the representative operating conditions at the source at that time.
Comment 2: According to Commenter 17715, performance testing for sources without CEMS is cumbersome and expensive. For low load units, frequent performance testing could require operation of the unit when it would not normally otherwise be operated. Testing should be performed annually for each of the stacks instead of every other month as currently proposed. Testing could not be completed at all of its units within a two-month period due to lack of test crews, unit scheduling, scheduled maintenance, and other considerations. The EPA's assertion that most units will choose to install CEMS may be faulty based on the current lack of HCl CEMS technology and the relative infancy of PM CEMS. The CEMS systems may also not be adequate to measure emissions as low as the EPA has proposed. The commenter states that the EPA should consider the frequency and types of monitoring appropriate for various subcategories, including an exemption for low capacity factor and LEEs.
Comment 3: Commenter 17716 states that for units with add-on emission controls, annual performance testing is sufficient to demonstrate proper operation of control devices.
Response to Comments 2 - 3: The EPA disagrees with the commenters' assertions that the performance testing requirements are excessive or that annual testing is adequate. As discussed in Comment Code 5A01, the EPA has established periodic emissions testing (generally on a quarterly basis) as the primary method for ensuring continuous compliance in situations where a source is not using a CEMS or the use of a PM CPMS as a parameter monitor. For low capacity and low emitting sources, the rule does provide some relief. For low capacity units, the final rule establishes a process similar to the QA operating quarter concept under 40 CFR part 75 for determining whether a test must be done in a given quarter. In addition, liquid oil-fired units with a capacity factor of less than 5% are subject only to the performance tune-up work practice standard in the final rule. For low emitting units, the LEE provisions establish reduced monitoring for Hg based on the initial demonstration, and reduced testing frequency for other pollutants after the source demonstrates over the course of 3 years in other tests that emissions of the applicable pollutant remain below 50% of the emission limit on a consistent basis.
Comment 4: Commenter 17729 states that the proposed rule specifies work practice standards in lieu of specific emission limits for organic compounds. The rule requires annual performance tests as well as 18-month burner inspections.
Response to Comment 4: The EPA has reviewed the comments on the proposed frequency of tune-ups, and made adjustments in the final rule. Under the final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 months, with an exception that if the unit employs a neural-network system for combustion optimization during hours of normal unit operation, the required frequency is a minimum of once every 4 years (48 months).
Comment 5: Commenters 17628 and 17758 agree with and support the EPA's decision to set work practice standards, which require annual performance testing, to address emissions of organic HAP and dioxins.
Comment 6: Commenter 17812 states that the available sulfur to chlorine ratio is sufficient to inhibit dioxin/furan emissions. A review of the ICR for the coal-fired boilers in the Boiler MACT ICR database shows that the sulfur-to-chlorine ratio is far greater than 1:1. This is intuitive as sulfur content ranges from 0.5% to about 6% and chlorine is usually less than 1,000 ppm.
Comment 7: Commenter 17813 agrees that specific emission limits are unnecessary for organic HAP.
Response to Comments 5 - 7: The agency thanks the submitters for their comments in support of work practice standards. The EPA acknowledges these comments, and has made clarifying changes to the applicable provisions in the final rule. In Table 3, we have clarified that this refers to performance tune-ups, not tests, and the provisions of section 63.10006(r) have been corrected to refer to 63.10021(a)(16).
Comment 8: Commenter 8443 notes that a large percentage of the dioxin/furan and non-dioxin organics measurements from ICR testing were at or below the method detection limit. For those two HAP categories, the EPA should establish work practice standards instead of setting MACT limits. A work practice standard is the best way to avoid compliance issues where actual emissions at or below the detection and quantitation limits of a method.
Comment 9: Commenter 17621 states that their evaluation of the ICR test data supports the EPA's conclusion that organic HAP (including dioxin/furan/polychlorinated biphenyl, and non-dioxin organics) are predominantly below detection limits.
Commenter 17871 states that the EPA appropriately used its discretion to impose work practice standards under CAA section 112(h) for organic HAP, including emissions for dioxins and furans. Organic HAP result not from the makeup of the coal, but through highly complicated chemical reactions in the combustion process that occur with unknown frequency. Utility Report to Congress at ES-22. As the EPA notes, the test methods available to measure organic HAP compounds demonstrate that these emissions are at or below the detection level and therefore it is "impracticable to reliably measure emissions from these units." 76 FR 25027. Moreover, because the organic HAP emissions result from the combustion process, the EPA studies demonstrate that the best way to reduce the formation of organic HAP is through improving combustion efficiency. See, e.g., Miller J., Emissions of Organic Hazardous Air Pollutants from the Combustion of Pulverized Coal in a Small-Scale Combustor, Environ. Sci. Technol., 28, 1150-1158, 1994.
Response to Comments 8 - 9: The commenters essentially agree with the EPA's approach taken in the proposed rule, and the EPA continues to believe that a work practice standard approach is appropriate for organic HAP emissions from EGUs.
Comment 10: Commenter 17775 notes that during the ICR, 170 coal-fired EGUs were required to test for organic HAP emissions and possible organic surrogates such as CO and total hydrocarbons. Fifty other EGUs were required to test for dioxins. To increase the likelihood of actually measuring dioxin emissions, the EPA required these units to conduct sampling over a longer-than-normal 8-hour period. This organic and dioxin testing produced far more "non-detect" observations than actual detected values. The commenter states that this is hardly surprising because coal-fired EGUs have a strong economic incentive to operate their boilers as efficiently as possible. The high number of measurements that were below the detection limit make setting a MACT limit impossible for these HAP because, by definition, a measurement below the detection limit has greater error associated with it than the value measured. In other words, one does not even know if the substance is present. Furthermore, the commenter believes that setting an emissions limit at the detection limit would be unenforceable because the error associated with a compliance measurement would make it impossible to certify the accuracy of the measurement. The EPA could not enforce an emission limit set below the level of quantitation, which is at least three times higher than the detection limit.
Response to Comment 10: The commenter essentially agrees with the EPA's approach taken in the proposed rule, and the EPA continues to believe that a work practice standard approach is appropriate for organic HAP emissions from EGUs.
Comment 11: Commenter 17691 requests that the EPA clarify whether a source is to conduct only a work practice standard of a tune-up or both a tune-up and an annual performance test. There also appears to be a contradiction with the work practice standards listed in Table 3; the table requires an annual performance test.
Response to Comment 11: The agency has clarified Table 3 in the final rule. All affected sources must perform an initial tune-up as a work practice standard for dioxin/furans and other organic HAP, and then complete each successive tune-up within 36 months of the preceding tune-up. There is no performance testing for dioxin/furans or other organic HAP required under this rule.
 4D02 - Work Practice Standards: Tune-up
Commenters: 16849, 17197, 17316, 17402, 17620, 17623, 17627, 17656, 17677, 17681, 17696, 17704, 17705, 17711, 17712, 17714, 17716, 17718, 17722, 17725, 17728, 17730, 17737, 17740, 17752, 17758, 17770, 17772, 17775, 17776, 17801, 17807, 17815, 17820, 17821, 17873, 17877, 17883, 17885, 17886, 17909, 17912, 17925, 18014, 18015, 18031, 18037, 18426, 18428, 18437, 18498, 18539, 19032, 19121, 19122, 18023
Comment 1: Numerous commenters (16849, 17197, 17316, 17402, 17623, 17627, 17656, 17677, 17696, 17704, 17712, 17714, 17716, 17718, 17725, 17728, 17730, 17740, 17752, 17758, 17770, 17772, 17775, 17776, 17807, 17815, 17820, 17821, 17873, 17877, 17885, 17886, 17902, 17925, 18015, 18037, 18426, 18437, 18498, 18539, 19032, 19121, 18023) oppose or have issues with the proposed tune-up requirements for dioxin/furan and non-dioxin/furan organic HAP control. In general, the commenters support the use of work practices but take issue with the specific requirements proposed. Specific comments are as follows:
Comment 2: Commenter 17316 states that the work practice requirements are confusing in that Table 3, which is supposed to list work practice requirements, only states that "performance tests be conducted annually," does not explicitly mention tune‐ups, and a reference to "tests" in the table is confusing, as such terminology does not seem consistent with the notion of a work practice. In addition, section 63.10006(r) specifies that tune‐ups be conducted no less frequently than every 18 months, which does not seem consistent with the annual frequency implied in Table 3. Further, section 63.10006(r) indicates that tune‐ups be conducted in accordance with the provisions of section 63.10007; but the commenter states that they cannot find any reference to tune‐ups in section 63.10007.
Commenter 18426 recommends removing the Table 3 from the rule because it does not contain any work practice standards.
Commenters 18539 and 19120 state that as currently written, the intent of the required frequency of work practice requirements is unclear. Commenters indicate that page 424 of the preamble states that work practice standards are annual. However, section 63.10006(r) indicates that each performance tune-up specified must be no more than 18 months after the previous performance tune-up. Additionally, section 63.10021(a)(16), specifies an 18-month frequency for only burner inspection, and specifies the requirement to follow manufacturer's recommendation for other practices, lending to the assumption that all other work practice requirements are on an as-needed basis.
Response to Comments 1 - 2: The EPA acknowledges these comments, and has made clarifying changes to the applicable provisions in the final rule. In Table 3, we have clarified that this refers to performance tune-ups, not tests, and have addressed the frequency requirement as discussed in response to the comments below about the appropriateness of the 18 month frequency. The provisions of section 63.10006(r) have been corrected to refer to section 63.10021(a)(16).
Comment 3: Commenter 17197 recommends adding additional compliance flexibility for EGUs with advanced boiler combustion control technology and adding an alternate surrogate CO CEMS compliance demonstration option to the work practices requirements. For units with advanced boiler combustion control technology, the commenter recommends that the rule also provide for alternate methods to demonstrate good combustion control practices. EGUs operating neural-net based advanced coordinated boiler combustion control systems that provide enhanced boiler performance although minimizing NOX and CO emissions should be exempt from the tune-up activities and documentation requirement. These activities are continually being performed by the neural-net system. The commenter includes specific regulatory text illustrating how they recommend the requirement be revised. Commenter 17623 also states that some of the tune-up requirements do not reflect the use of modern operational controls that keep combustion conditions within a range of parameters to meet compliance with emission requirements for NOX and CO. The EPA should ensure that the tune-up requirements are clear and compatible with modern boiler operations.
Response to Comment 3: The EPA has decided not to include alternate work practice standards, such as a CO requirement, but has adjusted the language in the final rule to recognize the value of automated boiler optimization tools such as neural-net systems. See further detail in the response below on the timing of tune-ups required under the final rule.
Comment 4: Commenters 16849 and 18015 recommend that physical internal inspections be required during a unit's major outage schedule. In the interim, Commenter 16849 states that external inspections including review of burner reading, visual inspection of streamers in the burner flame, etc. could be performed.
Comment 5: Commenter 17316 recommends that the time between burner inspections be increased from 18 months to at least 24 months, as outages are not always scheduled annually. In addition, a provision should be added indicating that if a unit is shutdown at the time of the tune‐up deadline, the facility is allowed a week from the time of the unit's next startup to perform the tune‐up. Such an extension provision is included in the Boiler Major Source MACT rule.
Comment 6: Multiple commenters (17623, 17704, 17725, 18437, 19121, 19122, 18023) suggest that the required frequency for tune-ups be changed from 18 months to every 24 to 30 months because EGUs are typically on a planned boiler outage of 24 months or longer. Commenter 17623 suggests that for units that run with longer than 30-month planned outage cycles, permitting authorities should have the flexibility to allow for even longer periods between boiler tune ups. 18023 recommends extending the boiler tuning interval to 36 months.
Commenter 17902 recommends that that the requirement for an annual performance test in Table 3 be no more than every 3 years (or 5 years with real-time combustion tuning) due in part to issues related to outage planning.
Comment 7: Multiple commenters (17712, 17696, 17820, 17885, 17886, 17902, 17925, 18037, 18498, 19032) recommend that the EPA extend the interval for conducting the required performance tune-up to 36 months. Commenter 17696 states that performing a burner inspection and cleaning requires a maintenance outage of at least three to four days. Many coal-fired base load EGUs are now operating for periods of up to 36 months between scheduled maintenance outages due to use of more durable components and better control of boiler feedwater chemistry. A burner inspection every 18 months will force many EGUs to shut down every 18 months for the sole reason of performing a burner inspection. Because boiler startups and shutdowns are when components are subject to maximum thermal stresses and are most likely to fail, forced startups and shutdowns to conduct burner inspections will cause more unit downtime and additional repairs. The proposed tune-up requirement will result in reduced operating time for EGUs and lower reliability for the electrical grid in general, as well as increased EGU operating costs. For an EGU that has not made any significant changes in fuel or equipment and because the EPA acknowledges that the significant majority of coal-fired EGUs emit organic HAP below the MDL, the requirement to perform burner inspections every 18 months is not justified.
Comment 8: Commenter 17716 states that most utilities utilize a 2-year or a 3-year cycle for major outages, particularly for large boilers. The commenter's boilers are on a 36 to 38 month cycle. Coordinating the tune-up cycle to the same cycle that each utility employs for major outages would mean that tune-ups could be completed within the duration of a planned major outage without further disrupting service.
Comment 9: Commenters 17728 and 17775 state that most EGUs do not have planned annual outages, burner inspections can take up to 30-days, and they do not stock many burner components that may need to be replaced so that parts must be special-ordered and months may be required for delivery. Commenter 17728 recommends that to avoid significant increases in the frequency of planned outages, and to keep inspection and repair frequency consistent with that for major outages, a more appropriate interval between inspections and repairs would be at least 36 months, and not 18 months.
Comment 10: Commenter 17775 states that among the companies it surveyed, the median time between major planned outages is about 36 months and only a few EGUs have outages as frequently as every 18 months. The commenter states that burner inspections at coal-fired EGUs can take up to 30-days including ten days to cool the boiler, place scaffolding in the unit and restart it and most utilities do not stock all burner components; ordering parts can require months for delivery. The EPA's premise in its proposal that burner repairs can always be completed during the same outage that a burner problem is discovered is unwarranted. The commenter cites the results of an evaluation of three different inspection and repair schedules and states that the EPA's proposed schedule would result in additional outages whereas the 36-month schedule would allow most utilities to retain their current outage schedules. The commenter submitted suggested regulatory text to address their concerns. Commenter 17772 made similar statements and adds that because burner repairs are not always needed immediately, burner parts that affect optimization of CO and NOX must be installed within 6 months after the burner inspection and that burner parts that do not affect optimization of CO and NOX be installed during the next scheduled outage.
Comment 11: Commenter 17681 states that there should be an exemption from the requirement for burner inspection every 18 months or boiler inspections if the unit has not run since the last inspection. There should be a minimum run time of possibly 9,000 hours or 18 months, whichever comes first.
Response to Comments 4 - 11: The EPA has reviewed the comments on the proposed frequency of tune-ups, and made adjustments in the final rule. Under the final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 months, with an exception that if the unit employs a neural-network system for combustion optimization during hours of normal unit operation, the required frequency is a minimum of once every 4 years (48 months). The EPA recognizes that units which employ neural net optimization systems are continually moving through this process, and we are clarifying in the final rule that we would only require a single record of CO and NOX information from the pre-tune up and post-tune up operating periods. For units that are operating without neural net optimization systems we are also requiring this information from pre tune up and post tune up. We have modified the rule language to require combustion tuning per manufacturer's instructions, as applicable, and otherwise in accordance with best combustion engineering practices for the specific burner type. The collection of this information is intended to assess whether or not combustion characteristics of the unit have changed as a result of the burner inspection, maintenance, and repair or replacement. We recognize that there are economic factors present that provide good incentive for units to maintain optimal combustion as a course of normal operation, and realize that this optimization is dependant on several variables, including burner type, combustion air controls, and post-combustion NOX control capability among others. By assessing pre-tune up and post-tune up combustion parameters we expect that units will be able to show continuing organic HAP control achieved through this work practice.
Comment 12: Commenter 17197 recommends that specific dates be replaced with time references from publication of the final rule. The commenter also asks what constitutes an acceptable or compliant burner inspection is not provided. Are online visual inspections adequate? The "clean or replace any components of the burner as necessary" provision is vague, unenforceable best practices guidance that should be dropped or at least clarified since no specificity is provided that defines allowable burner component degradation. At what point must components be cleaned or replaced? Commenter 17316 states that it would be helpful if the rule specified a compliance deadline for the initial tune‐up; i.e., section 63.10005 contains a generic stipulation indicating that compliance must be demonstrated no later than 180 days after the applicable compliance deadline  -  it is not clear if this timeline applies to tune‐ups as well as performance testing?
Commenter 17718 adds that the EPA should clarify whether the time frame to accomplish this initial performance tune-up is within 180 days after the compliance date. It may be impossible to perform the initial tune-up within the 180 day window following the compliance date due to the potential outage schedule that the unit may be following depending on when this proposed rule is finalized. It is likely that sufficient outage time will not be available within the 180-day initial compliance window to facilitate all of this work on multiple units. One year is a more workable time frame in which to accomplish this work.
Response to Comment 12: The EPA believes the general guidelines for conducting the inspection are adequate and are consistent with best engineering practice that sources would follow as part of routine, normal operating procedures. Initial compliance with work practice standards for existing units must occur within 180 days from the promulgation date as the commenter notes, and the initial compliance demonstration for the tune-up work practice standard under CAA section 63.10005(f) is subject to that timeline, however the EPA recognizes that a tune-up may take place prior to promulgation of the rule. In that case the initial compliance demonstration for the EGU is 42 months (36 months from the promulgation date plus 180 days) or, in the case of units employing neural net combustion controls, 54 months (48 months plus 180 days). If the tune-up occurs prior to the effective date, the source must maintain adequate records to show that the tune-up met the requirements of this standard.
Comment 13: Commenter 17402 requests that the time period between tune ups be no longer than 36 months with the expectation that if other factors require outages in the interim, then tune-ups would be conducted sooner. The requirement to inspect burners at least every 18 months does not allow for scheduling with major overhauls, which occur at 24 to 36 months. The proposed tune up would require an extended outage as such events involve scaffolding set up and taken down; boiler cooling; and cleaning, which varies depending on ash build up and how clean the furnaces need to be. For a dual boiler furnace, this process would take at least two weeks to be able to reach all the corners of the furnace. Burner inspection no more frequently than every 36 months is adequate if detailed data inspections are performed at that time and visual inspections using binoculars are performed during short outages in between. Burners would be inspected by scoping devices for condition, alignment and slag build up. This would occur at least every 12-18 months depending upon where the unit is in the outage cycle. Based on visual inspections, necessary new burners can be ordered and delivered by the next planned overhaul. Because coal burners last at least 6 years, a combination of the detailed and visual inspections should ensure that the burners would be well maintained and proactively replaced when necessary. Burners are tolerant of minor burner deterioration which does not affect the quality of the operation. Therefore, a detailed annual inspection is neither necessary nor practical because burners are only one of several contributors to combustion performance monitored on a regular basis.
Response to Comment 13: The EPA generally agrees, and has adjusted the final rule to require time between tune-ups be no longer than 36 months, or 48 months in some circumstances, as noted elsewhere in this document.
Comment 14: Commenter 17656 states that the tune-up requirements are already followed by reasonably operated sources although the regulation imposes unrealistic timeframes that do not align with the maintenance schedules/manufacturer requirements for the equipment in question. Also, the regulation requires unnecessary documentation for an annual report on emission tests, inspection, repairs, adjustments, findings and corrective actions.
Response to Comment 14: The EPA generally agrees, and has adjusted the final rule as noted above. The EPA believes the minimal recordkeeping associated with this work practice standard is not unduly burdensome.
Comment 15: Commenter 17714 recommends that the work practice standards be allowed to be performed during normal planned outages, which would minimize additional boiler startups and shutdowns.
Comment 16: Commenter 17730 states that the implementation of the proposed work practice standard requirement will require the unit to be fully shut down and the schedule for shut down is substantially too frequent. Only one of commenter's five facilities follows an annual outage schedule in which the boiler tune-up could be completed. Their remaining facilities follow a two- or 3-year schedule under which this tune-up procedure could be conducted, and these outages are sometimes delayed. If the EPA must retain the work practice requirement, the boiler tune-up should be moved from the 12 - 18 month cycle to not longer than once every five years to be conducted coincident with a scheduled plant outage, as appropriate.
Comment 17: Commenter 17740 suggests revisions to the proposed work practices for organic HAP. Commenter 17740 states the proposed inspection frequency is inconsistent with common operating practices. Although smaller, shorter outages do occur more frequently, they are too short to accommodate the type of inspection required by the proposed rule. Burner inspections and repairs are much more effective when done from boiler scaffolding; the cost of constructing boiler scaffolding is on the order of $100,000 per event. The commenter was unable to ascertain whether the EPA has included outage costs and replacement power costs in the economic evaluation justifying the work practice requirement. Replacement power costs to customers can be substantial for extended outages like these and can run into millions of dollars. The commenter recommends that the EPA require inspections every 3 to 5 years.
Comment 18: Commenter 17740 states that the proposed annual, off-line tune-up is excessive and unnecessary. Many units in operation today are equipped with advanced neural networks and/or digital control systems that allow for on-line tuning to optimize the combustion process without the need for physical burner inspections as proposed by the EPA. Although these systems do benefit from periodic off-line maintenance, the frequency of off-line maintenance should be on the order of every three to five years instead of annually. The commenter urges the EPA to change the tune-up requirements from annual off-line tune-ups to annual on-line tune-ups, with off-line tune-ups and burner inspections occurring every three to five years. Commenters 17776 and 17873 submitted similar comments.
Response to Comments 15 - 18: The EPA generally agrees and has adjusted the frequency of tune-ups as discussed above and reduced the cost of compliance burden of this rule accordingly.
Comment 19: Commenter 17752 states that the EPA should specifically recognize that burner inspections are not applicable for cyclone-fired boilers since they do not contain any of the typical burner components that are present in pulverized coal burner. Although a maintenance outage would typically be planned every 18 months, any burner inspection that needs to be accomplished from inside the boiler would typically need to occur during a major outage, about once every 36 months.
Commenters 17813 and 19120 state that the current 18 month interval between inspections is inconsistent with established utility practice and should be based on engineering experience and judgment. Commenter 17813 states that a minimum 36 month period is required.
Response to Comment 19: The EPA generally agrees with the comment and has modified the rule to state that if specific aspects of the inspection process are not applicable to a cyclone fired boiler, then only those elements of the basic procedure would be adjusted according to best combustion engineering practice for that burner type. On timing, see responses above for reduced frequency in final rule.
Comment 20: Commenter 17776 recommends that the EPA require inspection every 3 to 5 years instead of annually. Commenter 17627 recommends that burner inspection be coordinated with typical scheduled outage cycles.
Comment 21: Several commenters (17712, 17877, 17885, 19032) state work practice standards need to accommodate situations when new parts are required for burner optimization. For some small systems, such as many rural electric cooperatives, necessary parts may not be inventoried and may take several months to acquire. In other cases, there may be 50 or more burners on a single (large) unit. A thorough inspection with time to implement changes is virtually impossible during a non-major (i.e., less than 2 week) outage  -  and major outages may only occur once every 2 to 3 years. Further, the full cycle of inspection, procurement of equipment and labor, planning for a maintenance window, execution of repair and optimization, tuning, and performance verification will routinely require more than 18 months. To complicate matters units may be in periods of high need such as during summer or winter peaking when replacement parts become available, thus making shutdown for repair not feasible due to reliability or other paramount concerns. In such cases one commenter believes utilities should be given a reasonable time to optimize considering the electric demands on the system.
Comment 22: Commenter 17722 states that the rule is vague on the extent of the burner inspection and repair process. During a minor outage, it is unusual for personnel to physically enter the boiler because the duration of the outage is insufficient for the boiler to cool and the gas path to be cleared for safe entry. If the EPA is envisioning an annual, close-up visual inspection, this would necessitate additional days of outage which is cost-prohibitive. The EPA should clarify that the annual inspection during minor outages only needs to be a visual inspection conducted from the exterior of the boiler through existing boiler openings. Also, the EPA does not specify a repair schedule if problems are detected by the inspection. GRE suggests that repairs be conducted as expeditiously as possible, but if boiler entry is required that the repairs be conducted during the next shutdown requiring boiler entry.
Comment 23: Commenter 17718 states that because power generation boilers operation requires continuous monitoring as described below, the commenter recommends that work practice standards are not needed for boiler tune-ups and that the EPA should remove this requirement. Because of differences in outage cycles, burner monitoring practices, use of automated feedback combustion control systems, flame pattern monitoring, and other work practices to ensure efficiency, the proposed requirement for boiler tune-up work practices is inappropriate for power generation boilers and should be removed from the proposed rule. In the alternative, the EPA should at a minimum allow sources to petition the EPA for approval of work practice standards that do not meet the specified criteria, but do meet an objective of proper boiler operation.
The commenter notes that some boilers do not have annual outages and run for 3 to 5 year periods. Some boilers operate under pressure requiring that burner monitoring be done remotely with instrumentation. Some boilers that are not pressurized have such intense flames that direct observation has to be supplemented by instrumentation. The commenter states that a power generation boiler typically has a feedback combustion control system that performs "tune-ups" continuously by monitoring temperature and residual oxygen levels and distribution in the exhaust. Additionally boiler operators continuously monitor the boiler when it is in operation. When suspicious flame patterns are observed investigations are performed. The commenter suggests that an alternative is to allow the source to petition the EPA for a work practice standard.
The commenter also states that the EPA should reconsider the time frame to accomplish the initial performance tune-up. Commenter sates that the current 180 days is insufficient and in inconsistent with typical outage schedules. As an example, longer outage times are needed to perform burner inspections and clean/repair necessary components (as described in proposed 40 CFR 63.10021(a)(16)(i)). The commenter notes that they have moved to multi-year major outage schedules and it is likely that sufficient outage time will not be available within the 180-day initial compliance window to facilitate all of this work on multiple units.
Comment 24: Commenter 17821 states that the EPA should recognize that sources subject to the requirement for a tune up every 18 months routinely operate continuously for long periods at a time and do not necessarily schedule a routine maintenance outage every 18 months. Rather they often schedule regular outages at longer intervals and then they may take what are considered "opportunity outages" when a unit is forced off line for a mechanical failure. During these periods an EGU will elect to stay off line for a longer period of time, commonly a couple of days to a week, and conduct other repairs and maintenance that require an outage to perform. Since conducting a tune-up requires inspection and maintenance of internal components, it can only be conducted during an outage. However opportunity outages are unpredictable and cannot be scheduled with certainty. Thus EGUs cannot rely on them for the performance of a tune-up inspection. Forcing a tune-up into these periods would come at a potentially significant economic loss to the owner, particularly during peak periods. To prevent this situation, the EPA should allow a source the ability to seek a waiver or extension from the local permitting Agency to allow sources to perform a tune-up on a less frequent basis that fits with the source's operations.
Comment 25: Commenter 17925 states that it may be that the work practices are not appropriate for every unit design. For instance, the listed requirements may not be applicable for a circulating fluidized bed type boiler. Therefore, it is suggested that the owner/operator of the unit be allowed the option of having the unit's vendor document the tune up details that are appropriate for the particular unit being addressed. By allowing this flexibility, the ultimate goal of good combustion performance can be more likely achieved in every case.
Comment 26: Commenter 18426 states that the requirement to shutdown every 18 months for burner inspection is not practical, and should be required when the unit is shutdown or no more than 36 to 48 months. Also, the requirement for CO and NOX optimization for units having no manufacturer's specifications is not enforceable. It would be more practicable to require training and operator certification, identify who is required to be trained and certificated, identify what the training will encompass, and the frequency of training. Operational manuals should also be required that cover the procedures for boiler operation including, but not limited to, startup, shutdown, and malfunction; load changes; the optimal operating conditions of the boiler; and recordkeeping and reporting requirements.
Comment 27: Commenter 18539 states the necessary frequency for inspecting the burner is specific to individual units, based on years of engineering experience and judgment, and should not be required on a specific 18-month frequency. In some cases, that will double the number of required outages, doubling costs associated with those outages.
The commenter states that the underlying assumption that the combustion equipment is not being maintained is false in that it behooves the facility to keep all combustion equipment in top operational status. The reductions in emissions and increased efficiency are the primary goals of the facility. These actions are already completed as a course of business continuously (on line and off line) and not on a set schedule. By imposing a time limit on the "official" tune ups will result in more outages, recordkeeping and reporting that will serve no benefit.
Response to Comments 20-27: The EPA has modified the rule to state that if specific aspects of the inspection process are not applicable to a given boiler type or are lacking manufacturer;s specifications, then only those elements of the basic procedure would be adjusted according to best combustion engineering practice for that burner type.  Appropriate records of tune-up and combustion optimization procedures must be retained on site. On timing, see responses above for reduced frequency in final rule. The EPA does believe that a work practice standard is justified for controlling organic HAP, and thus has retained the work practice standard in the final rule.
Comment 28: Multiple commenters (17402, 17722, 17725,17730, 17737, 17740, 17752, 17772, 17775, 17820) suggest revisions to the requirements to optimize CO and NOX emissions. Specific comments are as follows:
a. Regarding requirements for the optimization of CO and NOX, Commenter 17775 states that a change in CO characteristics does not necessarily mean that the burners need to be adjusted or inspected; it likely means that the set point needs to be adjusted. This adjustment could be made during the periodic optimization thus potentially eliminating the necessity for a burner inspection. The commenter states that regarding the proposed requirement that the "optimization should be consistent with the manufacturer's specification", EGU operators are in the best position to determine how best to configure the burners to meet a given criterion and provides suggested regulatory text to modify the proposal requirement.
b. Commenter 17775 states that EGUs have NOX CEMS but few have in-situ equipment to measure CO and that most utilities would hire contractors to measure CO during recalibration and adjustment of EGU components that could affect CO emissions. The most efficient manner to achieve the EPA's goal is to measure NOX and CO at the most commonly utilized load range or near full load, whichever is the most appropriate. This is generally the load at which most burner suppliers conduct performance testing to meet guarantees. The commenter provides suggested regulatory language to this effect.
c. Commenter 17402 states that optimizing both CO and NOX is very dependent on the boiler type and air pollution controls. Therefore, the commenter attempts to optimize combustion performance first and then reduce the NOX using SCRs and SNCRs. The EPA should clarify that EGUs will not be held to a NOX or CO limit based on this optimization.
d. Regarding the requirement to measure the concentration in the effluent stream of CO and NOX in ppm, by volume, and oxygen in volume percent, before and after the adjustments are made, several commenters (17402, 17776, 17873) assume that portable CO, NOX and O2 monitors will meet the requirements of this section, but suggest that the EPA confirm this as a clarification.
e. Commenter 17730 states that the requirement to optimize the emissions of CO and NOX lacks definition in the proposed rule, and needs explanation prior to the rule being finalized in order for sources to understand how best to comment. To simply state that the source needs to check the baseline emissions before and after the optimization is an inadequate definition of the requirement. The work practice standard, as currently proposed, is unenforceable and leaves the definition of the requirement to explanation in some future guidance document when the agency should appropriately address the issue in the rule. The process of optimization seeks to achieve the lowest emissions of both NOX and CO, but there is no definition of how low these values are supposed to be or even if the values need to be lower after the optimization than before optimization. Although the proposed rule does require the source to identify the NOX and CO emissions before and after the optimization, the emissions of these two pollutants can vary substantially, and it is conceivable that the emissions after an optimization could be higher than before. The proposed rule suggests that sources follow the manufacturer specification for NOX and CO, but there will likely be few sources that have these specifications and where they might have the manufacturer's specifications, they are likely not applicable due to changes in the boiler configuration due to the addition of boiler components, for example, low NOX burners. The commenter appreciates the goal of achieving good combustion efficiency to control the emissions of organic HAP, however, it seems that the emissions of organic HAP are already at an extremely low level based on the ICR test data. Given the extremely low values that were recorded during the ICR testing, the commenter requests that the EPA consider a replacement of the proposed work practice standard requirement for a boiler inspection and replacement of parts as appropriate to comply with a good practices standard.
f. Commenter 17737 states that the requirement to "optimize" NOX and CO emissions "consistent with the manufacturer's specifications" presents some significant challenges. First, there are no "manufacturer's specifications" per se relating to boiler optimization. Boiler manufacturers will, in certain cases, offer a "vendor guarantee" to achieve some emission level, however, a "vendor guarantee" is not a "manufacturer's specification." Vendor emission guarantees are intended to demonstrate to the owner that the unit is capable of achieving a specified emission rate for a short and defined period, under specified conditions. The set points needed to achieve the guarantee emission limit cannot be sustained overall operating conditions, and vendors will not guarantee those emission levels over all operating conditions. Boiler operators are in the best position to determine parameters for optimizing operations given a continually changing set of constraints, and they should be given the discretion to set those parameters. The EPA should also make clear in final rule that the annual optimization should in no way compromise or hinder the boiler tuning required to meet permitted emission limits. The commenter provides suggested revised wording for section 63.1002l(a)(16)(iv).
g. Commenter 17740 states the requirements to must adjust burners and optimize total emissions of CO and NOX by being consistent with manufacturer's specifications could produce more emissions than current burner and combustion air settings developed through actual operating experience. The EPA should modify this language to allow facilities to use operational experience to adjust burners and optimize emissions rather than being restricted to manufacturer's specifications, which do not reflect changes in fuel quality and the condition of the burners at the time of the combustion tuning. Commenters 17776 and 17873 submitted similar comments.
h. Commenter 17752 states that since CO and NOX are both dependent on excess oxygen (O2) (and inversely related), the definition of optimum is unclear. Moreover, the commenter does not have any "manufacturer specifications" as the EPA suggests on how to conduct the optimization. Burner manufacturers typically provide one time guarantees on NOX and CO based on one time testing. Also, the EPA should clarify that the optimization testing should only need to be performed at full load (or the predominately operated load) in order to avoid having to complete a long and complex set of tests at various load points.
i. Commenter 17752 states that the EPA appears to assume that all sources have CO monitors available, when in fact many sources do not have equipment available to measure CO emissions.
j. Commenter17627 states that combustion optimization systems should satisfy all proposed work practice standards. Commenter 17627 states that the EPA should qualify daily observations reported by plant operators as a means to track combustion conditions.
k. Commenter 17722 states that the NOX and CO tune-ups are unnecessary. Instead, the EPA should require a written operation and maintenance plan to define efficient operation, based on best professional judgment of the operators, in consultation with burner manufacturers.
l. Commenter 17725 requests that the EPA recognize that even identical or `twin' units have operational and performance differences that make them unique to some degree. The commenter states that plant operations staff are continuously focused on improving boiler operations and are constantly monitoring and adjusting combustion parameters to maintain and improve combustion efficiency. These efforts are often constrained by NOX emissions limits, excess O2, CO emission limits and other operating parameters to achieve the balance required by good operating practices and environmental constraints.
m. Commenter 17772 suggests that language in the rule should state that burner parts that effect optimization of CO and NOX must be installed within 6 months after the burner inspection and that burner parts that do not affect optimization of CO and NOX be installed during the next scheduled outage.
n. Commenter 17718 states that the EPA needs to clarify what constitutes optimization of controls. For example, would this require operation of all available scrubber vessels or all precipitator sections even if not needed to meet permit limits?
o. Commenter 17718 states that work practice standards for optimizing both NOX and CO emissions appear somewhat contradictory since the actions taken to reduce one value will generally increase the other value. The proposed rule provides no guidance as to the EPA's expectations on the proper balance necessary to achieve such "optimization." At a minimum, the EPA should explain the specific testing and documentation necessary to demonstrate optimization.
p. Commenter 17820 states that to the extent the requirements to optimize CO and NOX are retained, the requirement for burner optimization to be consistent with manufacturer's specifications should be removed. Burner manufacturers provide one-time guarantees for NOX and sometimes CO and are usually based on a limited number of fuels, and many of these specifications were established years ago. EGU operators are in the best position to determine how best to configure burners to meet a given criterion. The EPA should allow the option for operator-defined procedures, consistent with accepted burner operating practices and current environmental permit limits/requirements, rather than sole reliance on manufacturer's specifications.
q. Commenter 17885 states that in some cases conforming burner optimization to manufacture's specifications, as proposed, may be inconsistent with best practices for a unit in question. Or such specifications may not exist. Utilities should be able to implement their own best management practices if they are demonstrated to best for the unit.
Comment 29: Regarding optimization of NOX and CO, Commenter 17781 states that under CAA section 63.10021(a) the requirement for optimization of NOX and CO is not understood as to the desired outcome. There is no recommendation from any vendor on how to optimize NOX and CO, as the results go in opposite directions. Low NOX may mean high CO, and low CO may mean high NOX. Generally, combustion tuning involves trying to get the lowest NOX without generating any significant CO, whatever that NOX level might be. The commenter notes that the minimization of CO will cause other pollutants, like NOX, to increase. In light of this general tradeoff between CO reductions and NOX increases, the concept of optimizing the levels of these two pollutants is very subjective and open to considerable interpretation.
Comment 30: Regarding the inspection of flame patterns, Commenter 17775 states that most large utility boilers have observation ports that can, in some cases, be used to assess the quality of the flames. Some boilers do not have inspection ports, and it would be unreasonable to require such boilers to install inspection ports. Moreover, flame observations on certain boiler types such as cyclones and possibly tangential boilers would not generally be useful. The EPA seems to have recognized this by requiring that the flame pattern must be inspected "as applicable." The final rule should clarify that boilers without observation ports and boilers where observations of flames are not beneficial are exempt from the proposed section 63.10021(a)(16)(ii) requirements.
Commenter 17402 states that flame pattern is generally an unreliable and subjective indicator of combustion quality. Flame patter is also not clearly observable at high loads. Visibility is limited, and at high loads, distinct flame envelopes and flame fronts are difficult, if not impossible, to see. Although flame patterns can be better observed at lower loads, full furnace gas flow dynamics are not developed, and low load flame fronts will not mimic high load flame envelopes. Original equipment manufacturers provide little information on flame pattern adjustment. Because of activated carbon injection, unburned carbon in the ash is not a good combustion indicator. Thus, the commenter suggests that other options be substituted for flame observations, including, but not limited to, cyclone and pulverizer coal feeder loadings, pulverizer performance parameters, damper operations as a function of mill and/or cyclone loadings, evaluating windbox pressures, assessing burner airflows and proportions and CEM information.
Commenter 17730 states that if the EPA must retain the boiler tune up work practice standard, specifically to require the optimization of the flame in the boiler, the EPA must provide more definition of what is required before the rule is finalized in order for members of the public to effectively comment. Failing to provide a definition for this requirement will lead to the issuance of staff guidance later, further perpetuating the implementation of regulation through guidance.
Commenter 17752 states that the EPA should specifically recognize that flame pattern inspections are not applicable for cyclone and tangential-fired boilers. Cyclone boilers do not exhibit measurable flame patterns because the cyclone itself is the burner and the flame is opaque. Also, in the case of a tangential boiler, the furnace is filled with a spiraling flame that covers most of the furnace and therefore the furnace is essentially the burner.
Commenter 18023 states that inspecting flame patterns in EGUs for the purpose of tuning burners is improper. EGUs can have 50 or more burners, and not all flames are visible. Observing overall flame patterns, at times, can aid performance engineers in diagnosing major burner deficiencies such as flame impingement on a water wall or flame detachment; however, inspecting flame patterns does not assist in combustion optimization. Inspecting flame patterns for the purpose of tuning burners is more appropriate for industrial boiler practices in which an observer peers through a glass at the burner and then makes changes to nearby controls to optimize the flame. EGU burners cannot feasibly be tuned in this manner. Therefore, observing overall flame patterns should be excluded from the work practice standards.
Commenter 17807 states that it is impracticable for them to inspect and adjust flame pattern and in their experience would not improve assurance of compliance.
Commenter 17820 states that the rule should clarify that boilers without observation ports are exempt from the requirement to inspect the flame pattern. It would not be reasonable to require such boilers to install inspection ports solely for purposes of this rule.
Comment 31: Regarding fuel and air flow calibration, Commenter 17775 states that air flow calibration is rarely done on most coal-fired EGUs because it is difficult. Most utilities control air flow by controlling excess O2 because this is a more accurate measure of the combustion efficiency. In addition, excess O2 can be more accurately measured than air flow. Instead of requiring annual calibration of air flow devices, the final rule should instead require calibration of the excess O2 monitors which are installed in virtually all EGU flue gas ducts.
Commenter 17402 states that the requirement to inspect the system controlling air-to-fuel ratio if necessary is vague and requires clarification. The commenter uses a procedure to verify operation of the combustion system, which includes inspecting excess O2 probes, over fire air systems software, and all associated dampers as well as continuously monitoring opacity and NOX. The commenter states that this type of surveillance will be a more practical and effective method of ensuring good combustion performance because this evaluates the entire system in addition to the burners.
Commenter 17752 states that the EPA should remove the requirement to calibrate air flow as total air flow calibration is rarely done throughout the industry due the difficult nature and unreliable results. The EPA should instead require calibration of excess oxygen monitors that are installed in virtually all boiler ducts since this is a more accurate measure of combustion efficiency.
Commenter 17807 states it is not practicable for them to ispect the system controlling the air-to-fuel ratio and it would not provide improved assurance of compliance beyond what practices are feasible.
Comment 32: Commenter 16849 states that there is no rationale for requiring work practice standards for control of VOCs and dioxin/furans and the ICR data does not support any control of these compounds.
Commenter 17197 states that ICR testing showed that EGU emissions are below detection levels so that no improvement can be attributed to the requirements.
Commenter 19120 questions the necessity of the specific work practice standards given the proposed general requirements and the fact that the significant majority of measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods. 40 CFR 63.1000(b) requires the source to be operated and maintained in a manner consistent with good air pollution control practices for minimizing emissions, which is redundant with the proposed work practice standards under 40 CFR 63.10021(a)(16). The commenter notes the references to available manufacturer's specifications is troublesome due to the age of some affected sources, the manufacturer's specifications, although available, are out of date and inconsistent with the current control practices `for minimizing emissions.
Commenter 17730 states that the boiler tune-up work practices should be eliminated because the data demonstrates that emission of organic compounds, D/F are extremely low. According to the commenter, the EPA's analysis shows that when the sulfur to chlorine ratio is greater than 1, the formation of the organic compounds, dioxins and furans, are inhibited. A sulfur-to-chlorine ratio greater than 1 is typical for coal-fired EGUs.
Commenter 18539 questions the need for work practice standards given the low organic HAP emissions. Section 63.10000(b) requires the source to be operated and maintained in a manner consistent with good air pollution control practices for minimizing emissions, which is redundant with the proposed work practice standards under 40 CFR 63.10021(a)(16). The general requirement to operate and maintain the source in a manner consistent with good air pollution control practices is fully sufficient to control organic HAP from affected sources by ensuring good combustion practices. The proposed work practice standards are duplicative and overly burdensome and in many cases inconsistent with current practices. Several conditions reference available manufacturer¡|s specifications. However, due to the age of some affected sources, the manufacturer¡|s specifications, although available, are out of date and inconsistent with the current control practices for minimizing emissions.
Comment 33: Commenter 17402 recommends that each unit prepare an organic HAP tune-up procedure to reflect unit-specific best practices for tune ups, taking into account individual boiler design and other unit-specific factors. The unit would specify in a certificate of completion that it has completed such a tune-up procedural plan and is keeping it on file at the facility. The plan would then be available at the facility for state inspection. As part of their submittal, the commenter provided suggested revisions to the regulatory text in section 63.10021(a)(16).
Comment 34: Commenter 17620 states that the EPA has sufficient CO emissions data to establish a MACT floor, as it has in other sectors including the ICI Boiler MACT, and offers no rationale for its decision not to employ CO as a surrogate for organic HAP. Instead, the EPA has proposed a work-practice standard, a "tune up" that it acknowledges will not lead to measurable reductions in organic HAP emissions. Commenter 17620 states that the EPA has not attempted to demonstrate that its tune-up requirement will improve the performance of the sources in the category up to the level of the top performers or that a tune up really is the maximum achievable control technology.
Comment 35: Commenter 17705 states that a number of coal-fired EGUs currently have emissions limits for CO established under the best available control technology provisions of the EPA's prevention of significant deterioration (PSD) regulations. These best available control technology (BACT) limits were established based on an analysis by the permitting authority of the technologies or work practices that would result in a maximum reduction of CO from each EGU. The stringent nature of a CO BACT limit requires the EGU operator to optimize the combustion process, similar to what the EPA states would be required under the proposed work practice standard. The commenter employs CO CEMS at its facilities to track compliance with BACT limits, which allows adjustment of combustion processes to assure compliance with the established limits. The EPA should allow compliance with current CO BACT limits as an alternative work practice standard. If the EPA does not allow this alternative work practice standard, the Agency should extend the period between required boiler tune-ups to accommodate current unit outage schedules. The commenter recommends an interval of at least 40 months.
Comment 36: Commenter 17815 states that the EPA should allow utilities to document their operating practices designed to achieve all combustion goals, without imposing requirements for testing, data collection, and inspection schedules. Efficient operations is in the self interest of utilities, and they should be allowed to use documentation of the efficient operating practices they have developed over years of operating experience to meet work practice documentation requirements. A requirement for annual boiler tune up may not provide any benefit if no changes in combustion equipment have been made. Additionally, parametric tuning to improve combustion efficiency and maintain stable operating conditions in the boiler occur on virtually a continuous basis as operators monitor and control the boiler and auxiliary equipment. Similarly, outage scheduling practices are different for different companies because each company has its own outage scheduling practices. In addition, these practices are likely to be different in regulated and unregulated electric utility markets due to costs. In setting inspection requirements, the EPA must recognize differences in practices, and either extend the time between combustion equipment inspections or simply link inspections to the normal outage schedule for each company.
Comment 37: Commenter 17722 states that the tune-up requirements are vague, unnecessary and burdensome, and the EPA should eliminate them. The proposed rule does not appear to require tune-ups. Section 63.10005(f) mentions the initial compliance requirement of a tune-up, but Table 3 does not specify work practice standards; this appears to be an oversight.
Comment 38: Multiple commenters (17711, 17851, 17883, 17909, 17912 and 18014, 18031, 18037, 18428, 18498, 19121) agree that the application of a work practice standard is the most appropriate approach for regulating organic HAP, considering the measurement related issues that the EPA described in the preamble, particularly for dioxin/furan HAP. Commenter 18014 states that this approach will minimize organic HAP emissions although providing a significant cost savings to the industry.
Commenters 17758 and 19120 agree with and support the EPA's decision to set work practice standards, which require annual performance testing, to address emissions of organic HAP and dioxins.
Commenter 17851 states that the EPA should not set a dioxin/furan standard or a non-dioxin organic HAP standard. Doing so will not reduce the emissions of organic HAP.
Comment 39: Commenters 17638 and 17818 request that the EPA establish a work practice standard in lieu of emission limits for organics and dioxin/furans. Commenters disagree with some of the individual elements of the work practice standard, such as the 18-month work practice interval and the requirement to inspect flame patterns as a means of determining optimized combustion. Commenter 17818 further states that conducting burner inspections will often include a requirement to install scaffolding in the furnace, to gain access to the burners, and then removal of the scaffolding. This is a process that is both expensive and time consuming, as well as generally not required except to perform burner inspections or perform repairs. Such activities are generally not done on an annual basis, but rather are less frequently performed during periods of extended maintenance shutdown/inspection. Commenters proposed that the 18-month maximum outage interval should be extended to 24-30 months and the inspection of flame patterns for EGUs for the purpose of tuning burners is improper. EGUs can have 50 or more types of burners, and not all flames are visible. Inspecting flame patterns is more useful for industrial boiler practices in which an observer peers through a glass at the burner and then makes changes to nearby controls to optimize the flame. Commenter 17638 supports a CAM-type approach regarding the establishment of work practices, which provide for reasonable assurance of the unit operation in lieu of a "one size fits all" approach.
Several commenters (17689, 17756, 17928, 17813) state that the 18 month interval between inspections is not consistent with established utility practice regarding periodic outages for maintenance and repair. Commenters recommend a 36 month compliance period. Utilities should be able to implement their own best management practices if they are demonstrated to be best for the unit. For small systems, such as many rural electric cooperatives, many parts may not be inventoried and may take several months to acquire. To complicate matters, units may be in periods of high need, such as during summer or winter peaking when replacement parts become unavailable, thus making shutdown for repair not feasible due to reliability or other paramount concerns. In such cases, NRECA believes utilities should be given reasonable time to optimize considering the electric demands on the system.
Commenter 17756 states that the work practice standards for EGUs to address any emissions of organic HAP and dioxins do not reflect some of the practical realities of operating an EGU.
Several commenters (17761, 17767, 17795) state that the proposed work practice standards regarding organic HAP will have a detrimental impact on the outage schedules of applicable units since every unit would have to perform an onerous inspection and tune-up every 18 months. This scheduled tune-up would require additional outages in between planned major maintenance overhauls further affecting unit availability, overall system reliability, and generating costs. The EPA's ICR test data demonstrated that the majority of applicable units emitted non-detectable levels of organic HAP, even under the utility industry's existing work practice standards and maintenance outage cycles. Commenters (17761, 17795) suggest that there is no need for increased scheduled outages and inspections (every 18 months) for units already emitting non-detectable levels of these HAP and, as such, these standards should be removed from the final rule. Commenter 17767 recommends an extension beyond 18-months.
Commenter 17930 states that the EPA should allow utilities to document their own operating practices, including testing, data collection, and inspection schedules. Each utility has developed documentation practices that best, and most efficiently, serve that particular plant and company. To require other documentation practices would be an unnecessary burden on already taxed utility operators. There are many instances where emissions are below detection levels and should not be used as a basis to establish a work-practice standard.
Several commenters (19536, 19537, 19538) state that the work practice standard should require that all EGUs install real-time software to continuously optimize boiler combustion and perform soot cleaning. These systems continuously monitor the combustion process to determine the optimal balance of fuel and air flows in the furnace to position dampers, burner tilts, overfire air and other controllable parameters at their optimal setting. These systems are already in widespread use throughout the utility industry and have the added benefit of improving efficiency, thus reducing operating costs. A boiler tune-up is not adequate to assure continuous minimization of organic HAP. The work practice standard assumes that all organic HAP are created by incomplete combustion. This assumption is incorrect, especially for dioxins which are formed after the combustion process and whose emission rate depends in part of coal chlorine content.
Response to Comments 28 - 39: The EPA recognizes the economic drivers in place that motivate operators to strive for good combustion control and although we do not wish to insist on combustion tuning that would be counter to that goal we do insist on regular combustion tuning that maintains optimal unit performance and demonstrates compliance with the work practice standard requirements in the final rule. The EPA has carefully reviewed the numerous comments on the specific requirements of the tune-up procedure. In light of these comments, we have made a number of specific changes to address what to do for repairs that may require longer term corrective actions, additional methods for evaluating combustion effectiveness, and clarification on procedures for CO and NOX monitoring. There were specific comments that opposed the reference to manufacturer specifications, if available. The EPA has retained this language in the final rule, but notes that these apply only to the extent applicable. Specifically, if manufacturer specifications only address conditions that are no longer present given current boiler operations, then only those specifications are not applicable and other combustion engineering best practice procedures for that burner type would apply.
The EPA recognizes that units which employ neural net optimization systems are continually moving through this process, and we are clarifying in the final rule that we would only require a single record of CO and NOX information from the pre-tune up and post-tune up operating periods. For units that are operating without neural net optimization systems we are also requiring this information from pre-tune up and post-tune up. We have modified the rule language to require combustion tuning per manufacturer's instructions, as applicable, and otherwise in accordance with best combustion engineering practices for the specific burner type. The collection of this information is intended to assess whether or not combustion characteristics of the unit have changed as a result of the burner inspection, maintenance, and repair or replacement. We realize that optimization is dependant on several variables, including burner type, combustion air controls, and post-combustion NOX control capability among others. By assessing pre-tune up and post-tune up combustion parameters we expect that units will be able to show continuing organic HAP control achieved through this work practice.
Comment 40: Commenter 17801 states that many of the work practice standards currently defined in the proposed rule have been developed based on boiler operation and do not apply to IGCC combustion turbines. In contrast to boilers, gas turbines compress the inlet air to 15 to 30 times the ambient pressure enabling the conversion of fuel into energy within tens of milliseconds in a small volume. A turbine extracts energy after the combustor reducing the combustor exhaust temperature by over 2000° R in modern gas turbines before the boiler (HRSG). The combustor is housed inside of a pressure vessel designed to withstand these high pressures and extremely high temperatures; therefore, frame gas turbines almost universally have fixed combustion hardware. Existing metallurgy does not allow fuel nozzles to penetrate into the flame zone at normal operating conditions. Low emissions are obtained by altering the fuel distribution to fixed fuel nozzles and addition of diluent. GE recommends that the maintenance guidelines for boilers and IGCC combustion turbines be consistent with the standard design, maintenance and operating practice of either a boiler or a combustion turbine as their design requires differences. For combustion turbines, GE recommends as a standard practice that combustor tuning be performed per the manufacturer's recommended maintenance/outage schedule in lieu of the required tune-up described in section 63.10021. The commenter also requested separate discussions in the preamble of work practices to reflect the difference in boiler and IGCC design and operation. Regarding the preamble discussion of organic HAP formation from incomplete combustion of fuel, the commenter notes that the gasification process minimizes organic HAP in the synthetic gas before it reaches the combustion turbines, which further destroys any residual organic HAP. Therefore, proper operation and maintenance of the gasification process and the combustion turbine per recommended procedures will minimize and control organic HAP emissions such as dioxins/furans. This is technically NOT the same as the work practice standards that the EPA has proposed that are more reflective of traditional coal EGUs. Parameters that are normally monitored for optimal performance of the gasification process and combustion turbine in an IGCC EGU will ensure organic HAP emissions are maintained at minimal levels.
Response to Comment 40: The EPA has modified the rule to state that if specific aspects of the inspection process are not applicable to a given boiler type, then only those elements of the basic procedure would be adjusted according to best combustion engineering practice for that burner type. This flexibility should address these concerns for IGCC units.
Comment 41: Commenter 18426 states that work practice standards are appropriate if measurement of a pollutant is technically or economically problematic, however, organic HAP can be measured from a technical and economic perspective. Therefore, a work practice standard is inappropriate for this CAA section 112(d) standard. A more appropriate approach would be to use a surrogate to demonstrate reductions in organic HAP. Continuous monitoring of CO which demonstrates good combustion practices and insures minimization of organic HAP emissions at all times would be acceptable as part of a parametric monitoring system.
The commenter states that a work practice standard with no criteria for what constitutes good combustion is unenforceable and does not serve the purpose of limiting organic HAP emissions. A tune-up is not a criterion, particularly if the tune-up is on a unit that has switched fuels. The unit will not be as efficient, and therefore, organic HAP emissions will be higher with fuels that it was not originally designed to combust.
Response to Comment 41: The EPA disagrees. Given the test results related to organic HAP during the evaluation of data for this rule, the work practice standard in the final rule is an appropriate method of ensuring that organic HAP emissions remain low and well-controlled from this source category because complete combustion inhibits the formation of organic HAP. As we indicated in the proposal preamble, it was very difficult to develop direct correlations between the average concentration of CO and the amount of organics produced during the prescribed sampling period in the Agency's Multipollutant Control Research Facility (MPCRF) (which was 4 hours for the pilot-scale tests described here). This is especially true for low values of CO as one would expect corresponding low quantities of organics to be produced. The EPA has revised the final rule from the proposal to clarify the requirements, including fixing the erroneous references to conducting a performance test instead of the required tune-up procedures.
4D03 - Work Practice Standards: Other
Commenters: 17197, 17402, 17620, 17627, 17628, 17677, 17704, 17711, 17729, 17730, 17731, 17737, 17756, 17758, 17775, 17800, 17805, 17813, 17816, 17820, 17821, 17843, 17868, 17870, 17904, 18444, 18539, 19122, 19536/19537/19538, 18932, 18023
Comment 1: Numerous commenters (17402, 17628, 17704, 17711, 17737, 17756, 17758, 17775, 17820, 17821, 17843, 17870, 17904, 19122, 18023) agree with and support the decision to establish work practices in lieu of numerical emission limits for dioxins and furans and non-dioxin/furan organic HAP. Specific comments were as follows:
Commenter 17402 states that the EPA's rationale supporting its proposed work practice standard is sound and consistent with the legal framework under the CAA. The commenter supports the EPA's proposal to adopt work practice standards for dioxins and furans and non-dioxin/furan organic HAP and not to propose beyond-the-floor limitations for organic HAP.
Commenters 17704 and 17775 also favor work practice standards for organic HAP over numerical limits. Commenter 17775 adds that the EPA made the correct decision assuming that they are a surrogate for specific HAP emissions that have been found to pose significant risks to public health.
Commenter 17628 agrees with and supports the EPA's conclusion that the proposed work practice standards for the control of organic HAP is consistent with and supported by section 112(h) of the CAA and is the best approach for addressing this category of HAP within the EGU MACT. Commenter 17731 agrees that the CAA section 112(h) prerequisite for replacing standards with work practices has been met, thereby justifying the use of work practices.
Comment 2: Commenter 17620 states that if work practice standards are employed, they should be designed to achieve the same level of emission performance as would be achieved by implementation of an emission limitation.
Comment 3: Commenter 17677 states dioxins/furans and organic HAP emission levels are at non-detectable levels from most power plants surveyed by the EPA and the "tune-up" items proposed are fundamental requirements of power plant operations. Since the EPA information collection request yielded little to no detectable emissions of these HAP, the commenter states that emissions in this HAP group are being satisfactorily controlled with current power plant practices and that no superficial, unquantifiable, random time framed regulations are required.
Several commenters (17731, 17800, 17729, 17813) agree that the low levels of dioxins/furans/organic do not warrant work practices or any standard in the EGU MACT rule.
Commenter 17805 states that the low levels of dioxins/furans do not warrant regulation. The commenter recommends that, if the EPA decides to continue with regulating dioxins/furans, they allow EGU's to perform a one-time energy assessment as allowed under the area source boiler MACT rule.
Comment 4: Commenter 17737 agrees with the decision to implement a work practice standard, although the commenter believes the proposal is unduly complicated. Due to the low emissions of these substances, it should be sufficient to establish a work practice standards requiring no further action beyond operating in accordance with "good engineering practice", which is already a standard title V permit condition. At a minimum, the proposed work practices require some clarification and modification.
Comment 5: Commenter 17758 states that the results of sampling for organics and dioxins during the ICR showed there were far more non-detectable observations than actual detected values. The high number of measurements at or below the detection limit makes setting a MACT limit impossible for these HAP because, by definition, a measurement at or below the detection limit has more error associated with it than the value measured. CAA section 112(h) provides discretion to the EPA to set work practice standards in lieu of emissions limits if the Administrator finds it is not feasible to prescribe or enforce an emissions standard. The high percentage of non-detectable measurement for organics and dioxins shows that it is infeasible to either prescribe or enforce emissions standards for these pollutants.
Response to Comments 1 - 5: The EPA acknowledges commenters' support of the work practice standards. However, the EPA disagrees with commenters' suggestion that a one-time energy assessment would be sufficient. EGUs are not area-source industrial boilers. We believe that the work practice standards we are finalizing are sufficient to ensure that organic HAP emission reductions are continuous and that those emission reductions are of the same magnitude as would have been achieved through an emission limit format, consistent with CAA section 112(h).
We agree with many of comments related to treatment of data reported as detection limit values in the development of MACT floors and emissions limits. The probability procedures applied in calculating the floor or an emissions limit inherently and reasonably account for emissions data variability including measurement imprecision when the database represents multiple tests from multiple emissions units for which all of the data are measured significantly above the method detection level. That is less true when the database includes emissions occurring below method detection capabilities regardless of how those data are reported. The EPA's guidance to respondents for reporting pollutant emissions used to support the data collection specified the criteria for determining test-specific method detection levels.

Those criteria insure that there is only about a 1% probability of an error in deciding that the pollutant measured at the method detection level is present when in fact it was absent. Such a probability is also called a false positive or the alpha, Type I, error. This means specifically that for a normally distributed set of measurement data, 99 out of 100 single measurements will fall within +-2.54 σ of the true concentration. The anticipated range for the average of repeated measurements comes progressively closer to the true concentration. More precisely, the anticipated range varies inversely with the square root of the number of measurements. Thus, if σ is the standard deviation of anticipated single measurements, the anticipated range for 99 out of 100 future triplicate measurements will fall within +- 2.54 σ/√3 of the true concentration. This relationship translates to an expected measurement imprecision for an emissions value occurring at or near the method detection level of about about 40 to 50%.

By assuming a similar distribution of measurements across a range of values and increasing the mean value to a representative higher value (e.g., 3 times minimum detection level), we can estimate measurement imprecision at other levels. For an assumed 3xMDL, the estimated measurement imprecision for a three test run average value would be on the order 10 to 20%. This is about the same measurement imprecision as found for Methods 23 and 29 indicated in the ASME Precision of Manual Stack Emissions Measurements for the sample volumes prescribed in the final rule (e.g., 4 to 6 dscm) for multiple tests.

Analytical laboratories often report a value above the method detection limit that represents the laboratory's perceived confidence in the quality of the value. This arbitrarily adjusted value is expressed differently by various laboratories and is called limit of quantitation, practical quantitation limit, or reporting limit. In many cases, the LOQ, PQL, or RL is simply a multiplication of the method detection limit. Multipliers range from 3 to 10. Consistent with findings expressed in reports of emissions measurement imprecision and the practices of analytical laboratories, we believe that using a measurement value of 3 times a method's detection limit established in a manner that assures 99% confidence of a measurement above zero will produce a representative method reporting limit suitable for establishing regulatory floor values.

On the other hand, we agree with commenters that an emissions limit set determined from a small subset of data or data from a single source may be significantly different than the actual method detection levels achieved by the best performing units in practice. This fact, combined with the low levels of emissions measured from many of the best performing units, led the EPA to review and revise the procedure intended to account for the contribution of measurement imprecision to data variability in establishing effective emissions limits. In response to the comments and internal concerns about the quality of measurements at very low emissions limits especially for new sources, we revised the procedure for identifying a representative method detection level (RDL).

The revised procedure for determining an RDL starts with identifying all of the available reported pollutant specific method detection levels for the best performing units regardless of any subcategory (e.g., existing or new, fuel type, etc.).  From that combined pool of data, we calculate the arithmetic mean value. By limiting the data set to those tests used to establish the floor or emissions limit (i.e., best performers), we believe that the result is representative of the best performing testing companies and laboratories using the most sensitive analytical procedures. We believe that the outcome should minimize the effect of a test(s) with an inordinately high method detection level (e.g., the sample volume was too small, the laboratory technique was insufficiently sensitive, or the procedure for determining the minimum value for reporting was other than the detection level).  We then call the resulting mean of the method detection levels as the representative detection level (RDL) as characteristic of accepted source emissions measurement performance.

The second step in the process is to calculate three times the RDL to compare with the calculated floor or emissions limit. This step is similar to what we have used before including for the Portland cement MACT determination.  We use the multiplication factor of three to approximate reduce the imprecision of the analytical method until the imprecision in the field sampling reflects the relative method precision as estimated by the ASME study that also indicates that such relative imprecision, from 10 to 20%, remains constant over the range of the method.es. For comparing to the floor, if three times the RDL were less than the calculated floor or emissions limit (e.g., calculated from the UPL), we would conclude that measurement variability was adequately addressed. The calculated floor or emissions limit would need no adjustment. If, on the other hand, the value equal to three times the RDL were greater than the UPL, we would conclude that the calculated floor or emissions limit does not account entirely for measurement variability. If indicated, we substituted the value equal to three times the RDL for the calculated floor or emissions limit which results in a concentration where the method would produce measurement accuracy on the order of 10 to 20% similar to other EPA test methods and the results found in the ASME study.
We determined the RDL for each pollutant using data from tests of all the best performers for all of the final regulatory subcategories (i.e., pooled test data). We applied the same pollutant-specific RDL and emissions limit adjustment procedure to all subcategories for which we established emissions limits. We believe that emissions limits adjusted in this manner better ensure measurement variability is adequately addressed relative to compliance determinations than did the procedure applied for the proposal that may have been based on limited data sets.  By accounting for measurement uncertainty in this manner, we also believe that the emissions testing procedures and technologies available are adequate to provide the measurement certainty sufficient for sources to demonstrate compliance at the levels of the revised emissions limits.
Comment 6: Commenter 17730 states that the EPA should not require coal-fired electric utilities to incur the cost associated with the implementation of the work practice standard for dioxin and furans based on measurements of the substance below the method detection limit. According to the commenter, the EPA's stance that detection below the method detection limit generally indicates the presence of the substance is not necessarily true. An analysis by EPRI of the ICR data showed that chemicals that were detected were affected by contamination of the sample with non-flue gas sources of the HAP. Several of the chemicals were also frequently detected in the field blanks and/or method blanks. The commenter states that the chemicals in this HAP group are ubiquitous in the environment and that the test method is so sensitive that it is very difficult to avoid contamination of the sample during sampling and analysis. The EPA should not assume that detection below the method detection limit generally indicates the presence of the substance.
Response to Comment 6: The EPA must address all HAP in this rulemaking. However, as noted elsewhere, we believe that the work practices being finalized are reasonable for this source category and are consistent with the statute. The EPA would note that other commenters have indicated that the work practices are consistent with common EGU practice so we are unclear as to how we are requiring EGUs to "incur the cost" when those costs are already being born by many EGUs. We believe that the requirement is justified to ensure that all EGUs achieve the organic HAP emissions reductions that are currently being achieved by the best performing sources in the category.
Comment 7: Several commenters (18932, 19536, 19537, 19538) disagree with the EPA's decision to not set emission limits for dioxin. Commenter 18932 states there is no factual or legal justification to support the EPA's failure to prescribe dioxin emission limits for EGUs. Based on a similar factual record, including similar monitoring and detection issues, the EPA has specified numerical dioxin limits for the smaller sources in the Major Source Boiler MACT Rule. Thus, there is no rational technical or legal basis for the EPA's failure to set dioxin limits for EGUs.
Several commenters (19536, 19537, 19538) argue that some test results below some MDLs do not address relevant statutory standards, i.e., section 112(h), and the EPA admits that dioxin and other organic emissions have been measured from EGUs so that emissions data exist. For this reason, setting work practices in lieu of emission limits is unlawful and arbitrary. The EPA does not identify any class of sources to which measurement methodology for dioxins and organic HAP is not practicable. Nor does the mere fact that some units recorded test results below the particular MDL that a unit chose show that application of measurement methodologies is impracticable even for those same units. Rather, it merely reflects the EPA's discretionary decisions not to specify a maximum MDL and to collect data in a way that allowed some sources to return test results with extremely high MDLs. The measurement methodologies that allowed many other EGUs to use much lower MDLs are applicable to all EGUs.
Commenters (19536, 19537, 19538) argue also that not all organic emissions were below MDLs. For example, of 150 available tests, 101 test show formaldehyde above the detection limit. Thus, it is not impracticable to set a floor limit for formaldehyde. And for a significant number of units, all dioxin and furan congeners were above the MDL.
Commenters (19536, 19537, 19538) state that any imprecision associated with monitoring emissions at levels near the detection level can be addressed by statistical manipulations, adjusting the limit that accommodates any uncertainty (e.g., 50% above the detection level), or establishing monitoring protocols that reduce the uncertainty to acceptable level. The commenters find no support for the EPA's alternate triple-MDL floor in the ASME ReMAP report upon which the EPA relies.
Commenters (19536, 19537, 19538) also argue that the EPA fails to show that measurement of organic HAP would be economically impracticable.
Commenters (19536, 19537, 19538) also state that the work practices contravene section 112(h)(1) in that the EPA does not show that the work practices yield the maximum achievable degree of reduction and that at a minimum reflect the measures adopted by the EGUs with the lowest emission levels of dioxins and organic HAP. The EPA does not show that EGUs do achieve reductions in dioxins through the use of activated carbon injection and reduction in other organic HAP through the use of SCR systems.
Comment 8: Commenter 17620 does not support the use of CO as a surrogate for dioxins and furans because low CO levels do not guarantee low dioxin and furan emissions. The commenter states that the proposed tune-up does not incorporate work practices that minimize dioxin and furan emissions. The EPA should adopt numeric emission limits consistent with levels achievable through application of MACT, even if those levels are at or below the detection levels. Sources should be required to conduct a stack test, during which PM control device temperature, CO and THC levels, soot conditions and entrained PM levels can be monitored and employed thereafter in parametric monitoring. Exceedances or changes in any of the parametric monitoring conditions would trigger a new dioxin and furan compliance test.
Comment 9: Commenter 17869 states that the ICR data demonstrate no significant correlations between CO or THC and important organic HAP, so it cannot be used as a surrogate for organic HAP. However, Polycyclic Aromatic Hydrocarbons (PAHs) are the non-dioxin organic HAP of the most concern. Because of the recognized toxicity of PAHs, it would be prudent to propose, or at least to ask for comment on the possibility of, a PAH floor.
Response to Comment 7 - 9: The EPA believes that the work practices being finalized for all organic HAP are appropriate and are consistent with the statute and other NESHAP rulemaking efforts. Further, each source category is addressed individually and, although EPA strives for consistency in its approach, there are times where different approaches for different source categories are warranted. The EPA does not believe that, at this time, it can specify a maximum MDL for organic HAP emissions from EGUs as that would require specifying laboratory analysis methods which, at this time, are not universally available in the U.S. (e.g., only one or two laboratories are equipped for high-resolution mass spectroscopy analyses). Our responses to comments on use of the MDL are provided elsewhere in this document.  The remaining comments are addressed elsewhere in the final rule record.
Comment 10: Some commenters support an alternate CO limit. Commenter 17197-11 recommends that the work practice standards include an alternate surrogate CO emissions limit option to demonstrate compliance for dioxin and non-dioxin/furan organic HAP, which would provide a less costly and easier to administer compliance demonstration option for EGUs that already operate CO CEMS for existing CO emission limits. The commenter suggests that a 30-day rolling average CO limit of 0.20 lb/MMBtu would provide the indication of good combustion control practices and provide EGUs important compliance demonstration flexibility.
Commenter 17868 states that they commend the EPA's use of work practices in lieu of CO limits but recommends that the rule includes an alternate surrogate CO limit for additional compliance demonstration flexibility. A surrogate CO limit (if set at a reasonable level (i.e., 0.25 lb/MBtu)) to demonstrate dioxin/furan best combustion control practices might be easier for EGUs with pre-existing CO limits.
Commenter 18444 states that the EPA should set an emission limit for CO to provide a readily measurable indicator of good combustion, which is necessary to avoid high levels of organic HAP emissions. Commenter 18444 states that it is not necessary to set a CO MACT limit that is the average of the lowest 12 percent of the test data. However, the EPA should set a CO limit that avoids poor combustion. The requirement for good combustion is not practically enforceable without setting a CO limit. Also, setting clear CO emission limits is preferable to the proposed limits for the sum of CO and NOX emissions.
Comment 11: Commenter 17904 states that establishing a numeric CO limit as a surrogate would be unnecessary and counterproductive. First, generators have inherent incentives to operate efficiently and reduce the formation of organic HAP through proper and complete combustion. Second, such a standard could undo important progress made on NOX reductions by utilities within the State of Texas that have complied with some of the most aggressive NOX reduction of any state due to the inherent inverse relationship between the control of NOX and CO.
Comment 12: Commenter 17904 states that the EPA should recognize that even identical units have operational and performance differences that make them unique to some degree. Utility boiler operators continuously focus on efficiency and are constantly monitoring and adjusting combustion parameters to maintain efficiency. These efforts are constrained by NOX emissions limits, excess O2, CO levels and other operating parameters to achieve the balance required by good operating practices and environmental constraints. As a result, the EPA's final work practice standard should be consistent with operations necessary to minimize NOX emissions without undue excess CO formation (i.e., CO emissions are in compliance with existing permit limits), although also avoiding conditions that increase slag formation, that create a reducing atmosphere in the boiler that promotes boiler tube corrosion, or otherwise impede the reliable operation of the unit.
Comment 13: Commenter 18023 states that they have investigated the relationship between CO emissions and emissions of organic HAP and that their own data illustrates similar results to the EPA's pilot scale combustor in that CO does not correlate well with organics, CO emissions are highly variable and organic HAP emission are low and generally below the detection limit. They conclude that CO is an inappropriate surrogate for organic HAP and that work practice standards in lieu of emission limits are appropriate. Commenter 17731 also supports the decision to not use CO as a surrogate for organics given the lack of a correlation with organic emissions.
Response to Comments 10 - 13: The EPA understands that emissions of most organic HAP can be minimized by maintaining good combustion conditions. Dioxin and furans are formed post-combustion and their formation is suppressed in coal combustion systems by the presence sulfur (as explained in the proposed rule preamble). A significant majority of the emissions of the organic HAP from the ICR were below the measurement detection limit. Though the EPA still believes that CO is a good indication of poor combustion conditions, and thus a good indicator of organic emissions, the data are not adequate to establish that surrogate relationship for EGUs because of the low levels of organic HAP. We continue to believe that the work practice standard that requires routine boiler/burner maintenance is the best measure for limiting emissions of the organic HAP, and it is justified consistent with CAA section 112(h).
The agency recognizes the differing combustion environment among EGU's and has adapted the language of the final rule to require combustion optimization and yet allow each EGU to optimize combustion according to best practice for the burner type. It follows that this points to minimal NOX creation although maintaining low CO emissions and avoiding slagging and reducing atmospheric conditions within the boiler.
Comment 14: Commenter 17627 recommends that the work practice standards be conducted within 90% of the EGU's net demonstrated capacity rather than at full load as proposed. Testing at a steady state condition would be representative of the unit operating at full load.
Response to Comment 14: The EPA disagrees, finding that the range of "...within 90% of the EGU's net demonstrated capacity..." is too wide a range to conduct these measurements, though we do agree that measurements taken at steady state conditions are desirable.  The final rule requires the measurements before and after the tune-up to be made while operating at full load or the predominantly operated load.
Comment 15: Commenter 17816 states that the EPA needs to clarify what constitutes optimization of controls. For example, would this require operation of all available scrubber vessels or all precipitator sections even if not needed to meet permit limits? In addition, work practice standards for optimizing both NOX and CO emissions appear contradictory since the actions taken to reduce one pollutant will generally increase the other. At a minimum, the EPA should explain the specific testing and documentation necessary to demonstrate optimization. The EPA should, at a minimum, allow sources to petition the EPA for approval of work practice standards that do not meet the specified criteria, but do meet an objective of proper boiler operation.
Commenter 17718 requests that the EPA provide some clarifications and revisions to the work practice standards regarding the definition of "optimization of controls." For example, would this require operation of all available scrubber vessels or all precipitator sections even if not needed to meet permit limits? At a minimum, the EPA should explain the specific testing and documentation necessary to demonstrate optimization. Of further note, the required frequency for boiler tune ups does not reflect standard industry operational practices. It is not unusual for facilities to have scheduled major outages (i.e., outages of sufficient length to conduct a "boiler tune-up") at a frequency of every 3 to 4 years. Consequently, the required boiler tune-up frequency should be no less than every 4 years to reflect common industry operational practices.
Response to Comment 15: There is no requirement in the tune-up provisions to optimize controls. Optimization of combustion to minimize CO and NOX needs to account for the relationship of the two pollutants using good combustion engineering practices, and also includes avoiding combustion issues such as excessive slagging.
Comment 16: Commenter 17820 agrees with the work practices but states that the proposed requirements are far more rigorous than the procedures established under previous NESHAP related to the allowable time between periodic inspections, the time required to repair burners, observation of flames and optimization of CO and NOX.
Response to Comment 16: The time periods have been adjusted based on the comments received and a number of other changes have been made to this requirement so that it reflects good operating and engineering practices for performance tuning an affected unit.
Comment 17: Commenter 17821 states that the EPA needs to clarify work practice standards for PM and all pre-combustion pollutant removal processes used by IGCC units. As written and without clarification on what is a control device for an IGCC unit, the EPA's proposed work practice standards cannot be performed for an IGCC unit. The commenter agrees that numerical limits for organics should not be set for IGCC units. Other parameters normally monitored for optimal performance of the gasification process and combustion turbine in an IGCC EGU will ensure organic HAP emissions are kept at minimal levels.
Response to Comment 17: The EPA believes that the changes to the work practice standard and the elimination of operating parameter limits and differences in the schedule for conducting performance tests based on the presence or absence of controls, addresses these IGCC-based concerns.
4E01 - Alternative Limits: Total non-Hg HAP metals (alternative to PM)
Commenters: 17316, 17386, 17402, 17620, 17621, 17716, 17718, 17722, 17725, 17729, 17737, 17747, 17775, 17781, 17796, 17798, 17869, 17870, 17881, 17912, 18014, 18034, 18500, 18023
1. Support total non-Hg HAP metals limit.
Comment 1: Commenter 17725 supports the total metals emissions limit of 0.00003 lb/MMBtu. Commenter recommends the proposals by commenter 17808 to revise the total metals emission rate based on either: (a) the determination of the top 12 percent performers based on the entire database of oil-fired units affected by the rule, or (b) the subcategorization of oil-fired units based on either distillate oil firing or residual oil firing. Commenter also states that the two factors that support the revision of the total metals limit include: (1) the limited sample of stack testing emissions data for oil-fired EGUs, and (2) the limited compliance options for No. 6 oil fired EGUs, including those that already have controls.
Comment 2: Commenter 17402 supports the EPA's decision to include a total metals standard as an alternative compliance option for the emissions standards for non-Hg metallic HAP. The commenter states that the flexibility in compliance options should help to reduce the overall cost of the rule without affecting emissions. Commenter 17648 also supports the EPA's decision to incorporate flexibility in the rule by allowing coal-fired EGUs to meet emission limits for total non-Hg metallic HAP or for individual non-Hg metallic HAP, rather than the PM limit.
Comment 3: Commenter 17747 supports the EPA for proposing either a total non-Hg metals or individual metal emissions limits as an alternative to using PM CEMS on coal-fired EGUs.
Response to Comments 1-3: The EPA appreciates the support of the commenters. We would note, however, that the non-Hg metallic HAP limits are not an alternative to using PM CEMS/CPMS which are a compliance method, not an alternative format for the standard. As noted elsewhere, we are requiring the use of PM CPMS in the final rule unless a source elects to test on a quarterly basis. An EGU owner or operator also may elect to use a PM CEMS for direct compliance with the filterable PM emission limit. Our approach at final is the same as was proposed; that is we are using 12% of the available data rather than 12% of the population for liquid oil-fired EGUs and we have not subcategorized distillate vs. residual oil. However, as noted elsewhere in this document we are establishing a limited-use liquid oil-fired EGU subcategory and establishing filterable PM emission limits.
2. Support PM limit as alternative to non-Hg HAP metals limit
Comment 4: Commenters 17737 and 18023 support the EPA's use of PM as a surrogate for non-Hg HAP metals.
Response to Comment 4: The EPA appreciates the support of the commenters. We would note, however, that the non-Hg metallic HAP limits are not an alternative to using PM CEMS/CPMS which are a compliance method, not an alternative format for the standard. As noted elsewhere, we are requiring the use of PM CPMS in the final rule unless a source elects to test on a quarterly basis. The source also can elect to use a PM CEMS for direct compliance with the filterable PM emission limit.
Comment 5: Commenter 17820 asks that if a total PM limit is retained, a source's filterable PM operating limit could be determined by subtracting the condensable PM measured during the stack performance test from the total PM limit as an alternative to the proposed approach. This would allow the operator with good control to use the operating margin available in the PM control process and would still insure compliance with the total PM limit. This alternative, however, would still remain problematic due to the bias and uncertainty issues associated with Method 202, which is used to measure condensables.
Response to Comment 5: As noted elsewhere in this document, the EPA is finalizing a filterable PM alternative.
3. Support PM limit as alternative to non-Hg HAP metals limit for oil-fired EGUs.
Comment 6: Commenter 17316 suggests that a total particulate limit should be established for oil-fired EGUs to serve as a surrogate (alternative) to the non‐Hg HAP metals emission limits, in the same manner as is done for coal-fired EGUs. Coal-fired units, as well as solid oil-derived fuel EGUs, are allowed to meet either: (a) a total particulate emission limit or, (b) a non‐Hg HAP metals emission limit. However the rule does not provide oil-fired EGUs a similar option to satisfy a total particulate limit as an alternative to satisfying a non‐hg HAP metals limit. Performance testing for particulates is much less costly than for the extensive list of metals covered by this MACT rule, therefore it is expected this would be the preferred option for many sites. In addition, a PM limit would allow on‐going compliance to be monitored by a PM CEMs rather than having to adhere to the very onerous HAP metal performance testing/fuel analysis schedule imposed by the rule. A total particulate limit comparable to the one imposed on coal-fired EGUs would seem appropriate: 0.030 lb/MMBtu.
Comment 7: Commenter 17870 states that the proposed rule for oil-fired EGUs is not reflective of the subcategory and not reasonably achievable. The commenter recommends the EPA reconsider the decision to use a PM limit for liquid oil-fired EGUs to control total HAP metals for liquid oil-fired EGUs. The commenter cites errors and missing data in the ICR database, notably several data errors and missing test results in the spreadsheet summarizing the EPA MACT floor analysis for oil-fired EGUs including, incorrect fuel designations.
Comment 8: Commenter 17621 states that PM emission has better prediction properties than HAP trace metal emissions for all non-Hg HAP metals. The correlations of individual and total non-Hg metals with PM for oil-fired EGUs are statistically significant to the 95% level, similar to the PM correlations for coal-fired EGUs.
Comment 9: Commenter 17796 states that this question should be answered based upon EGUs having particulate control vs. EGUs which do not have particulate control. All utility owners of liquid-fired fuel EGUs should be able to demonstrate initial and continuous compliance based upon fuel sampling. EGUs which have particulate control should receive the same compliance options as a coal-fired boiler. Liquid fuel owners with EGUs utilizing particulate control which are required to stack test for particulates based upon other regulatory commitments should be able to use this PM data to demonstrate compliance and record the control device parameters to establish continuous monitoring permit conditions in lieu of monthly fuel sampling.
Comment 10: Commenter 17808 requests that in light of the various data corrections that they included in their submittal, the EPA consider setting a PM limit for liquid oil-fired EGUs to control total HAP metals. The commenter submitted information that shows that units equipped with ESPs for PM control generally have the lowest reported total HAP Metals emission rates, which suggests that a PM limit would be a reasonable surrogate for total HAP Metals for oil-fired EGUs. Liquid oil-fired EGUs would have the option of complying with a PM limit, a total HAP metals limit, or individual HAP metal limits.
Comment 11: Commenter 17796 responds to the EPA's request for comment on whether the EPA should set a separate standard for Hg if the EPA requires end of stack testing for a total metals limit. The commenter states that the emissions of fuel oil Hg as well as all HAP metals will be based upon the purchased oil. If a stack testing option is inserted into the proposed rule allowing for oil-fired units to be granted the same surrogate compliance demonstration as solid fuel for total PM, facility owners should be required to demonstrate compliance.
Comment 12: Because an analysis of the ICR data indicates a correlation between PM and metals for oil units, Commenter 17820 requests that the EPA extend to oil units the option to use filterable PM as a surrogate for metals and to allow compliance demonstrations through the use of CEMS.
Response to Comments 6-12: Based on a reassessment of the data, the EPA has established a filterable PM limit as an alternate equivalent limit for the HAP metals from liquid oil-fired EGUs. Partly based on comments received, the EPA realized that oil-fired EGUs had mischaracterized the type of oil fired during the testing which made any correlation of the data inconclusive. The EPA contacted all liquid oil-fired EGUs providing data through Part III of the 2010 ICR to confirm the type of oil used. Based on that new information, the top performing liquid oil-fired EGUs (continental) are either residual oil-fired with ESPs or distillate oil-fired. Thus, the EPA believes the filterable PM alternate limit is appropriate. Our responses to comments related to the subcategorization of distillate vs. residual oil are found elsewhere in this document.
With respect to the use of CEMS to demonstrate compliance with a filterable PM limit, we are finalizing the use of a PM monitoring approach, but generally as a CPMS to demonstrate compliance with an operating limit, not a CEMS correlated using Performance Specification 11 used to determine direct compliance with the emission limit. The final rule involves initial compliance testing using Method 5 to demonstrate compliance with the emission limit and then periodic retesting using Method 5 to reconfirm emission limit compliance and re-establish the site-specific operating limit as needed. However, in response to comments, we are providing an option for a source to use a PM CEMS as a direct method of determining compliance with the filterable PM emission limit. Please see the preamble and responses under Comment Code 5A07a for further discussion of the PM CEMS and CPMS requirements.
4. Opposition to PM as a surrogate for metal emissions.
Comment 13: Commenter 17912 opposed the non-Hg metal surrogate alternative proposal.
Comment 14: Commenter 17798 opposes the EPA approach to setting several emission requirements based on source specific test results. The commenter states that, under the NESHAP rules, the EPA proposes a "test and set" compliance requirement in addition to the primary emission limitation set forth in the rule. In this discussion, "metals" refers to non-Hg metals. Of particular concern is the requirement to test for filterable PM with the resulting demonstrated emission rate set as a source's particulate emission limitation. The source then has to demonstrate compliance with this filterable PM limit using a PM CEMS. This approach to PM as a surrogate for metal emissions is problematic for several reasons. First, the EPA set a limit, for total PM (filterable + condensable) based on metals and PM total emissions data from the best performing 12% of sources. To meet the methodology of establishing MACT emission limits, the EPA needs to separately establish a filterable PM limit based on evaluating the PM and metals emissions data for the same set of sources. The current proposal of looking to individual sources in establishing emission limitations for continuous compliance monitoring may impose requirements more or less stringent than the 12 percent best performing sources. From this point of view, the EPA is not consistent with CAA methodologies in establishing NESHAP emission limits.
Comment 15: Commenter 18034 opposes the EPA selection of total PM as a surrogate for HAP emissions. Total PM is not a listed HAP, nor has it ever been a listed HAP. The total PM is currently regulated under 40 CFR section 108(a). Total PM is not a precursor for HAP metals. In fact, HAP metals represent a small subset of total PM and are not a precursor to PM emissions. Regulating total PM as a surrogate under 40 CFR section 112 is regulating an air pollutant listed in 40 CFR section 108(a). Although the EPA has made a general justification for using PM as a surrogate for non-Hg metal HAP, the EPA has not made any valid technical correlation between the proposed PM emission limit and the HAP in question. The EPA did not correlate filterable or total PM capture efficiency to HAP metal removal efficiencies to determine the most representative surrogate. The EPA never identified the portion of PM (either filterable or condensable) that are HAP metals. The EPA did not properly consider the incremental cost and benefits of reducing HAP metals beyond existing emission levels in justifying the proposed MACT limits. The EPA's selection of total PM as a surrogate for HAP metals, without consideration and evaluation of the composition of total particulate, including condensable particulate matter, is tantamount to regulating SO2 emissions (or other constituents of condensable PM) under NESHAP instead of the NSPS.
Comment 16: Commenter 18023 states the EPA must provide a more reasonable surrogate for non-Hg metals, adding that unjustified concerns regarding selenium do not support using total particulate matter as a surrogate.
Commenter 17722 does not support methodology the EPA used in setting the numeric non-Hg HAP metal limits. The commenter recommends the EPA set a filterable PM limit as representative of non-Hg HAP metals based on particulate control devices such as ESPs or baghouses that are capable of 99+ percent reduction as a maximum achievable control technology.
Response to Comments 13 - 16: The EPA has revised the surrogate for non-Hg metallic HAP in the final rule to use filterable PM rather than total PM as the surrogate. The non-Hg metallic HAP are present predominantly in the filterable PM fraction  -  with the exception of selenium. Selenium may be present as a particulate (i.e., filterable) or as the acid gas, SeO2 (condensable). We have revised the non-Hg metallic HAP surrogate because we are also setting emission standards the the acid gas HAP, with HCl (or alternatively SO2) as the surrogate. SeO2 will be captured in acid gas control equipment (e.g., scrubbers, DSI, etc.) similar to the control of its chemical analog SO2.