(g) For affected boilers that switch fuels or make a physical modification to the boiler that results in the applicability of a different subcategory, you must demonstrate compliance within 180 days of the effective date of the fuel switch or physical modification consistent with §63.11225(g). However, if you become newly-subject to Subpart JJJJJJ as the result  of a permit condition (e.g., as a synthetic area source), you must  comply with the requirements of  §63.9(b)(2).
Response: We are adding a new paragraph (i) to 40 CFR 63.11210 to clarify the initial compliance requirements for boilers located at existing major sources of HAP that become area sources on a timely basis. Any such existing boiler at the existing source must demonstrate compliance with Subpart JJJJJJ within 180 days of the later of March 21, 2014 or upon the existing major source commencing operation as an area source. Any new or reconstructed boiler at the existing source must demonstrate compliance with Subpart JJJJJJ within 180 days of the later of March 21, 2011 or startup. Notification of such changes must be submitted according to 40 CFR 63.11225(g).
Commenter Name: Michael J. Bradley
Commenter Affiliation: The Clean Energy Group
Document Control Number: EPA-HQ-OAR-2006-0790-2448-A1
Comment Excerpt Number: 5
Comment: We expect that many sources will seek to qualify as area sources if they are able, including through permit limitations. For example, an oil-fired unit that is currently a major source may reduce permitted potential to emit (PTE) through a permit limit on quantity of oil combusted. Particularly during the upcoming time period when existing area source units are subject to requirements, while major source units are not, clarification on the timing of notification and compliance demonstration requirements is necessary. In the Area Source Boiler Rule, §63.11225(a)(2) states that "As specified in §63.9(b)(2), you must submit the Initial Notification no later than 120 calendar days after May 20, 2011 or within 120 days after the source becomes subject to the standard." However, the EPA proposes to amend §63.11210(g) to clarify the compliance demonstration requirements for units that switch subcategories as the result of a physical modification or fuel switch. We request clarification as to which requirement governs newly-limited synthetic area sources, and specifically when notification requirements are due.
Response: See the response to EPA-HQ-OAR-2006-0790-2448-A1, excerpt 6.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 14
Comment: Proposed §63.11214(c) must also be revised to clarify that the facility is only certifying to the accuracy of the information used in the assessment as a snapshot. Since the assessment is a one-time requirement, the certification should indicate that it is only an accurate depiction of the facility at the time of the assessment, thereby removing any suggestion that a new assessment is needed if the facility changes.
Response: The intent of the requirement to perform an energy assessment is to identify energy conservation measures that can be implemented to reduce the facility energy demand which would result in reduced fuel use and a corresponding reduction in emissions. A certification that an energy assessment was conducted must be submitted with the NOCS. We do not believe it is necessary to clarify in the final rule that facilities are only certifying to the accuracy of the assessment as of the time it is conducted. We disagree with the commenter's assertion that a new assessment would not be necessary if the facility changes. In the event that a facility undergoes major changes that would require a new NOCS to be submitted, the facility would need to re-certify that an energy assessment was conducted and is an accurate depiction of the facility.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 18
Comment:  §63.11196(d) of this proposal states:
      (d) If you own or operate an industrial, commercial, or institutional boiler or process heater and would be subject to this subpart except for the exemption in §63.11195(b) for commercial and industrial solid waste incineration units covered by part 60, subpart CCCC or subpart DDDD, and you cease combusting solid waste, you must be in compliance with this subpart on the effective date of the switch from waste to fuel.
      "Effective date" is unclear in this context and should be clarified by specifically referencing the provisions of the CISWI rules that identify this effective date as being the date identified by the source for the transition from the CISWI rule to the area source rule and not the date the source ceases to burn solid waste or the effective date of the part 63 subpart JJJJJJ rule.
Response: See the response to EPA-HQ-OAR-2006-0790-2482-A2 excerpt 20.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 19
Comment:  Proposed §63.11196(d) deals with compliance timing for boilers and process heaters that have been subject to the CISWI rule, but stop firing solid waste and thus become subject to this major source rule instead. The language of this paragraph needs to be clear that this transition only occurs if the unit is stopping solid waste burning permanently. As currently worded, a temporary stoppage (which happens frequently at CISWI) units would appear to make this rule applicable rather than CISWI.
Response: See the response to EPA-HQ-OAR-2006-0790-2482-A2 excerpt 20.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 20
Comment:  Citing process heaters in proposed §63.11196(d) is incorrect since the Area Source NESHAP only applies to boilers.
To address these issues (1 through 3) we suggest the following revision to §63.11196(d).
(d) If you own or operate an industrial, commercial, or institutional boiler and would be subject to this subpart except for the exemption in § 63.11195(b) for commercial and industrial solid waste incineration units covered by part 60, subpart CCCC or subpart DDDD, and you intend to permanently cease combusting solid waste, you must be in compliance with this subpart on the effective date of the switch from waste to fuel part 60 subparts CCCC or DDDD to this subpart as identified under the provisions of §§60.2145(a)(2) and (3), or §§60.2710(a)(2) and (3).
Response: We agree with the commenter and 40 CFR 63.11196(d) of the final rule references the appropriate sections of the CISWI NSPS and Emission Guidelines (part 60 subparts CCCC and DDDD).
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 31
Comment: Regardless of the fuel capability identified in an initial notification, the distinction between a new source and an existing source should only be made based upon a source's capability to burn a particular fuel as of the effective date of the rule. Many facilities have boilers that can burn either gas or liquid. Because the price of gas is currently lower than the price of most liquid fuels, they likely are currently firing gas during normal operation, with liquid being fired only during periods of curtailment. Therefore, many of these facilities did not submit an initial notification for the area source rule, since gaseous fuel fired boilers that only burn liquid during periods of curtailment are not covered by the area source rule. In the future, the price of liquid fuel may be lower than the price of gaseous fuel, and facilities may want to preferentially burn liquid fuel over gas fuel. A change in the fuel from the initial notification should not in and of itself, reclassify a source as a new source for purposes of 40 CFR 63 Subpart JJJJJJ. This interpretation is comparable to the fuel switching provisions in the NSPS and PSD regulations.
Response: See the responses to EPA-HQ-OAR-2006-0790-2474-A2, excerpt 8, and EPA-HQ-OAR-2006-0790-2459-A2, excerpt 9.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 32
Comment: Many boilers which have capability to burn fuel oil, for instance, as back-up for natural gas, may not have filed the initial notice of applicability. The EPA has provided guidance stating that if a source fails to file an initial notification and then plans to burn oil in the future; it would be considered to be a new source.
This guidance appears to be contrary to the regulatory text which states at §63.11194 (c): An affected source is a new source if you commenced construction or reconstruction of the affected source after June 4, 2010 and you meet the applicability criteria at the time you commence construction.
If a source already has oil or alternate fuel capability, then that source would not be commencing construction or making a modification to the source. The text of the rule also states at §63.11194 (d):
A boiler is a new affected source if you commenced fuel switching from natural gas to solid fossil fuel, biomass, or liquid fuel after June 4, 2010. CIBO suggests that the following sentence be added to the text of §63.11194(d) after the above sentence to clarify that to become a new source you must modify that source to be capable of accommodating the new fuel, so that new sources are not created simply by failing to submit an initial notification or a notice of fuel switching, for a unit that is already capable of accommodating that fuel:
Notwithstanding these definitions, a source that submits notification to fuel switch, but which was capable of accommodating the new fuel on or before June 4, 2010 shall not become a new affected unit.
Response: See the responses to EPA-HQ-OAR-2006-0790-2474-A2, excerpt 8, and EPA-HQ-OAR-2006-0790-2459-A2, excerpt 9.
Commenter Name: Russell A. Wozniak
Commenter Affiliation: Dow Chemical Company
Document Control Number: EPA-HQ-OAR-2006-0790-2423-A1
Comment Excerpt Number: 9
Comment: The EPA should remove the requirement for a 30-day prior notice in §63.11225(g).
In §63.11225(g), the EPA provides the following language:
      If you intend to switch fuels or make a physical change to the boiler, and this fuel switch or change may result in the applicability of a different subcategory or a switch out of subpart JJJJJJ due to a switch to 100 percent natural gas, you must provide 30 days prior notice of the date upon which you will switch fuels. The notification must identify:
      (1) The name of the owner or operator of the affected source, the location of the source, the boiler(s) that will switch fuels or be physically modified, and the date of the notice.
      (2) The date upon which you will commence the fuel switch or modification.
Dow suggests the following revisions to the proposed regulatory text below. New text is shown in underline text. Change/revised text is shown in strike-through font.
      (g) If you intend to have switched fuels or made a physical change to the boiler, and this fuel switch or change may result resulted in the applicability of a different subcategory or a switch out of subpart JJJJJJ due to a switch to 100 percent natural gas, you must provide 30 days prior notice of the date upon which you switched fuels within 30 days of the change. The notification must identify:
      (1) The name of the owner or operator of the affected source, the location of the source, the boiler(s) that will have switched fuels or  be physically were modified, and the date of the notice.
      (2) The date upon which you will commence the fuel switch occurred.
The EPA's reconsideration proposal still requires a 30-day prior notice when an owner/operator plans to switch out of Subpart JJJJJJ due to a switch to 100% natural gas. This advance notification requirement delays such a change if the owner/operator decides in a rapid fashion to cease combustion of other fuels. For example, if the owner/operator decides on March 1st to switch to 100% natural gas, the owner/operator must first provide 30 days advance notice of such change, thus delaying this type of change until early April. Instead of delaying the switch to combustion of 100% natural gas, which is the cleanest burning fossil fuel, we suggest that the owner/operator be allowed to make notification of this type of change within 30 days after the change has occurred. This type of notice will still alert the EPA or state/local agencies that the source is no longer subject to 40 CFR 63 Subpart JJJJJJ in a timely manner.
Response: The EPA agrees with the commenter's suggested revision regarding the notification requirement for an owner/operator switching fuels or making a physical change to a boiler where the fuel switch or physical change results in the applicability of a different subcategory within Subpart JJJJJJ or a switch out of subpart JJJJJJ. The revision to the notification requirement also includes owners/operators switching fuels or making a physical change where the fuel switch or physical change results in the applicability of Subpart JJJJJJ and owners/operators that take a permit limit that results in the applicability of a different subcategory within Subpart JJJJJJ, a switch out of Subpart JJJJJJ, or the applicability of Subpart JJJJJJ. The final rule requires that the owner/operator make notification of these types of changes within 30 days after the change occurs.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 49
Comment: EPA SHOULD NOT REQUIRE 30 DAYS ADVANCE NOTICE FOR FUEL SWITCHING TO NATURAL GAS
The EPA has reworded §63.11225(f) from the final rule (re-numbering resulted in this requirement being §63.11225(g) in the reconsideration proposal), which contains the requirement for 30 days prior notice before a unit can become a gaseous fuel-fired unit and switch out of Subpart JJJJJJ applicability. This advance notification requirement delays such a change if the owner/operator decides in a rapid fashion to cease combustion of other fuels. For example, if the owner/operator decides on March 1st to switch to 100% natural gas, the owner/operator must first provide 30 days advance notice of such change, thus delaying this type of change until early April. Instead of delaying the switch to combustion of 100% natural gas, which is the cleanest burning fossil fuel, we suggest that the owner/operator be allowed to make notification of this type of change within 30 days after the change has occurred. This type of notice will still alert the EPA or state/local agencies in a timely manner that the source is no longer subject to 40 CFR 63 Subpart JJJJJJ.
We recommend the following revisions to the proposed regulatory text below
     (g) If you intend to have switched fuels or made a physical change to the boiler, and this fuel switch or change may result resulted in the applicability of a different subcategory or a switch out of subpart JJJJJJ due to a switch to 100 percent natural gas, you must provide 30 days prior notice of the date upon which you switched fuels within 30 days of the change. The notification must identify:
     (1) The name of the owner or operator of the affected source, the location of the source, the boiler(s) that have switched fuels or were modified, and the date of the notice.
     (4) The date upon which the fuel switch occurred.
There is no need for prior notice of this type of change since the boiler would no longer be subject to the Subpart JJJJJJ regulation and the owner/operator could have to delay such a change pending this notification requirement. This 30-day advance notice is a potential curtailment of flexibility in our manufacturing operations.

Response: See the response to EPA-HQ-OAR-2006-0790-2423-A1, excerpt 9.
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Rule Language Corrections: Out of Scope
Commenter Name: Jason A Schwartz
Commenter Affiliation: Institute for Policy Integrity
Document Control Number: EPA-HQ-OAR-2006-0790-2419-A1
Comment Excerpt Number: 3
Comment: There is no need for the EPA to look to the Energy Policy and Conservation Act (EPCA) to define "cost‐effective" under the CAA, and there are important differences between the statutes. The definition of "achievable" under §112(d) (and thus the subsidiary definition of "cost‐effective" if the Agency is to require implementation of "cost‐effective energy conservation measures" should be based on the statutory text and purposes of the CAA and not on any part of the EPCA.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration. Nonetheless, neither "cost-effective" nor "cost-effective energy conservation measure" are referenced or defined in the final rule.
Commenter Name: Jason A Schwartz
Commenter Affiliation: Institute for Policy Integrity
Document Control Number: EPA-HQ-OAR-2006-0790-2419-A1
Comment Excerpt Number: 4
Comment: The Agency maintains that its definition of cost-effective -- "a payback period of two years" -- is based on section 325(o)(2)(B)(iii) of the EPCA of 1975. The originally proposed rules' preamble explains that under this section "there is a presumption that an energy conservation standard is economically justified if the increased installed cost for a measure is less than three times the value of the first‐year energy savings resulting from the measure." First, it is not clear how the Agency justifies reading the phrase "three times the value of the first year energy savings" under the EPCA to indicate a 2‐year payback period. These calculations are distinct in obvious ways.
Response: See the response to EPA-HQ-OAR-2006-0790-2419-A1, excerpt 3.
Commenter Name: Jason A Schwartz
Commenter Affiliation: Institute for Policy Integrity
Document Control Number: EPA-HQ-OAR-2006-0790-2419-A1
Comment Excerpt Number: 5
Comment: This interpretation of EPCA omits crucial parts of the EPCA's statutory scheme. The full text of the cited clause from the EPCA is as follows: If the Secretary [of Energy] finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy, and as applicable, water, savings during the first year that the consumer will receive as a result of the standard, as calculated under the applicable test procedure, there shall be a rebuttable presumption that such standard level is economically justified. A determination by the Secretary that such criterion is not met shall not be taken into consideration in the Secretary's determination of whether a standard is economically justified.
The final sentence of this clause indicates that a finding that a standard does not meet the criterion cannot even be taken into consideration for whether the standard is "economically justified." Thus, the definition chosen by the EPA for "cost‐effective" is inappropriate even within the context of the clause they cite to support it.
Response: See the response to EPA-HQ-OAR-2006-0790-2419-A1, excerpt 3.
Commenter Name: Jason A Schwartz
Commenter Affiliation: Institute for Policy Integrity
Document Control Number: EPA-HQ-OAR-2006-0790-2419-A1
Comment Excerpt Number: 6
Comment: The cited clause only makes sense in the context of EPCA's §325(o)(2)(A):
Any new or amended energy conservation standard prescribed by the Secretary under this section for any type (or class) of covered product shall be designed to achieve the maximum improvement in energy efficiency . . . which the Secretary determines is technologically feasible and economically justified.
In this context, it is clear that the section cited by the EPA as justification for the definition of "cost-effective" explicitly sets a floor for the Secretary of Energy's determination of "technologically feasible and economically justified," and is not a reasonable definition of "economically justified" or "cost‐effective" by itself. More generally, Congress intended "economically justified" to mean cost benefit justified, because the statute requires the Secretary of Energy to "determine whether the benefits of the standard exceed its burdens."
Response: See the response to EPA-HQ-OAR-2006-0790-2419-A1, excerpt 3.
Commenter Name: Jason A Schwartz
Commenter Affiliation: Institute for Policy Integrity
Document Control Number: EPA-HQ-OAR-2006-0790-2419-A1
Comment Excerpt Number: 7
Comment: The proposed definition of "cost‐effective energy conservation measure" is "measure that is implemented to improve the energy efficiency of the boiler or facility that has a payback (return of investment) period of two years or less." By implicitly limiting the criteria to the private costs and benefits for regulated parties, this definition clearly falls short of the authority the EPA has under the best interpretation of the statute. Because the EPA has authority to consider a fuller range of social costs and benefits in determining which beyond‐the‐floor regulations are "achievable" under §112(d), the definition of "cost‐effective"could include social costs and benefits. However,  as a practical matter, the EPA will likely continue to exercise its statutory authority to stay focused on private costs and benefits in defining "cost‐effective"for these purposes. All benefits and costs from a project should be considered, and a firm should undertake all investments where the net present value of all costs and benefits is higher than zero.
There are two important practical elements in determining the net present value of private investments: the timeframe of the analysis, and the discount rate for future costs and benefits.
Response: See the response to EPA-HQ-OAR-2006-0790-2419-A1, excerpt 3.
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Testing/Monitoring: Rationale for 30-day rolling average for parameter monitoring
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Commenter Name: S. William Becker
Commenter Affiliation: National Association of Clean Air Agencies (NACAA)
Document Control Number: EPA-HQ-OAR-2006-0790-2455-A1
Comment Excerpt Number: 24
Comment: While the EPA may have used the 99[th] percentile UPL in one recent NSPS, in other NSPS rulemakings, such as the Hg limits under the Utility NSPS 40 CFR Part 60, Subpart Da,[21] it has employed a 90[th] percentile statistical test (t-test) coupled with the same test for the fuel-sampling compliance demonstration.
The EPA has proposed that owners and operators use parametric monitoring (i.e., pH, pressure drop, scrubbant flow rate, etc.) based on stack testing to demonstrate continuous compliance with applicable emission limits. The averaging period used for the parametric monitoring in the original Boiler MACT finalized in March 2011 was a 12-hour average. In the currently proposed amendments, the EPA is requiring proposing that owners and operators instead use a 30-day rolling average. This creates an averaging period for parametric monitoring that is grossly inconsistent with the emission standard set through initial performance test (stack testing). The averaging period for a stack test for an emission standard, such as particulate, is typically determined from the average of three stack test runs, which would be only 1- to 2-hour long runs. Where the emission standard is based on the average of three, 1-hour stack tests, parametric monitoring with a 30-day rolling average (or even a 12-hour average) will not ensure compliance as the affected unit could be operated outside of the range (and presumably above its 3-hour emission limit) for half the month. We do not object to the use of long-term averages per se, as such averages can be a solution to the variability issue. However, there is then no technical justification for the very large variability factors adopted by the EPA (based on 1-hour test runs) in a system that permits 30-day averages to be used for compliance.
[21] See, Memorandum from Robert Wayland, OAQPS, to William Maxwell, OAQPS, "Revised new source performance standard (NSPS) statistical analysis for mercury emissions" (sic), May 31, 2006.
Response: The EPA chose to address variability using a 99% confidence interval in order to maintain a consistent methodology with the development of the MACT floors for other pollutants, and because optional CO CEMS-based limits allow sources additional flexibility in meeting the rule requirements.
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 14
Comment: We support the EPA's determination that a 30-day rolling average for parameter monitoring and compliance with operating limits is appropriate for this rule. A longer averaging time for operating parameters is appropriate, because the standards apply over-all operating conditions, and operating conditions of industrial boilers can be highly variable, especially when fuel mix and load change. The operating parameter ranges will be established using test data obtained at one steady-state operating condition, so a 30-day averaging period allows for some fluctuations that will occur over the range of operating conditions. The EPA is correct in pointing out that variability outside the operator's control such as fuel content, seasonal factors, load cycling, and infrequent hours of needed operation give cause to use a longer averaging period. (76 FR 80536.)
Response: The EPA thanks the commenter for their support and additional justification.
Commenter Name: Barry Christensen
Commenter Affiliation: Occidental Chemical Corporation (OCC)
Document Control Number: EPA-HQ-OAR-2006-0790-2435-A1
Comment Excerpt Number: 13
Comment: OCC supports the use of 30-day averaging times in place of the 12-hour block averaging times. Having consistent and longer averaging times for emission limits and parametric monitoring specified in the rule helps to mitigate short term operational variability.
Response: The EPA thanks the commenter for their support.
Commenter Name: Timothy Serie
Commenter Affiliation: American Coatings Association (ACA)
Document Control Number: EPA-HQ-OAR-2006-0790-2437-A1
Comment Excerpt Number: 4
Comment: ACA generally supports the following proposed changes in the Area Source Boiler Rule:
Revised averaging time from 12-hour average times to 30 days in order to address variability;
Response: The EPA thanks the commenter for their support.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 26
Comment: CIBO supports the proposed use of 30-day rolling averages for parameter monitoring and compliance with operating limits. As explained in the preamble, variables outside the operator's control such as fuel content, seasonal factors, fuel, load cycling, and fewer operating hours support the use of longer averaging periods to determine operating compliance. Longer averaging periods will have a "variability of about half of that represented by the results of short term testing." Moreover, with longer averaging periods, problematic control system variability will result in deviations from a 30-day average on a comparable rate as those for a shorter term average. (76 FR 80536.) CIBO further notes that utilizing 30-day rolling averages for all the data used to comply with the standards in this rule greatly reduces considerable administrative burden and risk of error. Further efficiencies will be realized and potential errors will be reduced by this 30-day rolling average standardization.
Response: The EPA thanks the commenter for their support and additional justification.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 12
Comment: ACC supports the EPA's determination that a 30-day rolling average for parameter monitoring and compliance with operating limits is appropriate for this rule. The EPA is correct in pointing out that variability outside the operator's control such as fuel content, seasonal factors, load cycling and infrequent hours of needed operation provides a basis for using a longer averaging period. (76 FR 80536.) Operating conditions for industrial boilers are especially variable when changes to fuel mixes and loads occur. Since the operating parameter ranges will be established using test data obtained at one steady state operating condition, a 30-day averaging period would account for fluctuations that may occur over the range of operating conditions.
Response: The EPA thanks the commenter for their support and additional justification.
Commenter Name: Michael L. Krancer
Commenter Affiliation: Pennsylvania Department of Environmental Protection (PA DEP)
Document Control Number: EPA-HQ-OAR-2006-0790-2449-A1
Comment Excerpt Number: 7
Comment: PA DEP agrees that a 30-day rolling average for parameter monitoring is an appropriate averaging period, which ensures that emission limits will be "practically enforceable."
Response: The EPA thanks the commenter for their support.
Commenter Name: Jessica Bridges
Commenter Affiliation: U.S. Clean Heat & Power Association (USCHPA)
Document Control Number: EPA-HQ-OAR-2006-0790-2451-A1
Comment Excerpt Number: 2
Comment: The EPA has determined that the 30-day rolling average for parameter monitoring and demonstration of continuous compliance with operating limits is appropriate for this rule. From review of studies the EPA expects that variability of long term emissions averaging will be about half that represented by the short term testing proposed in the final rule (12-hour block). We agree that using the 30-day rolling average will reduce overall variability.
Response: The EPA thanks the commenter for their support and additional justification.
Commenter Name: Michael J. Bradley
Commenter Affiliation: The Clean Energy Group
Document Control Number: EPA-HQ-OAR-2006-0790-2448-A1
Comment Excerpt Number: 13
Comment: [We support EPA's proposed revisions to compliance monitoring, including] A 30-day rolling average for parameter monitoring and demonstrating compliance with operating limits.
Response: The EPA thanks the commenter for their support.
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 15
Comment: We also request that the EPA add a 30-day averaging period to the operating load requirement in Table 3 of the rule. Table 3 requires operators to maintain the operating load of each unit such that it does not exceed 110% of the average operating load recorded during the most recent performance test. For the same reasons provided above for the other operating parameters, the EPA should allow a 30-day averaging period for operating load so short term high load periods that are more than 10% above the tested load do not result in deviations. Facilities make every attempt to schedule stack tests during periods of high utilization, but sometimes need to operate at more than 100% of the load achieved during the stack test for short periods of time in order to meet operational demands. The way the requirement is currently written implies that the 110% load limitation is instantaneous. We note that in Table 7, the load monitoring requirement does have a 30-day averaging period specified.
Response: We disagree with the commenter. We understand that actual maximum normal operating load for a particular facility may be dependent on local conditions, but we expect it will generally be between 90 and 100% of design capacity and that performance testing can be scheduled during such periods of operation. We do not believe there is a need to amend the rule. Source operators are not required to conduct source testing at maximum loads, but they must conduct testing at representative operating loads. If a source operator conducts a performance test at load levels more than 10% below the level where they need to operate, the source operator must re-test at a higher load level. Should seasonal load variability require operation at a substantially higher load than where the unit was originally tested, the source operator must re-test at the higher lower. The rationale for requiring re-testing is that the performance test sets the operating parameter limits for the unit and control device. If the unit is operated at a substantially higher load than where it was tested, there is not reasonable assurance that the unit will meet the emission limitations of the rule with the same operating parameters.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 13
Comment: ACC recommends a 30-day averaging period for Table 3 operating load requirements.
ACC recommends that the EPA also add a 30-day averaging period for the operating load requirement in Table 3 to be consistent with the load monitoring requirement in Table 7 of the rule. Table 3 requires operators to maintain the operating load of each unit such that it does not exceed 110% of the average operating load recorded during the most recent performance test. For the same reasons provided above for the other operating parameters, the EPA should allow a 30-day averaging period for operating load so that short term high load periods that are more than 10% above the tested load, either individually or in combination, do not result in deviations. Facilities make every attempt to schedule stack tests during periods of high utilization, but sometimes need to operate at more than 100% of the load achieved during the stack test for short periods of time in order to meet operational demands. The provisions in the current requirement imply that the 110% load limitation is for an instantaneous event; however, lesser events in total could exceed the load limitation due to normal variability over time.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 15.
Commenter Name: Bob Machaver
Commenter Affiliation: Public Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2416
Comment Excerpt Number: 2
Comment: Calculation of 30-Day Rolling Averages: The definition of "30-Day Rolling Average", and the description of the 30-Day Rolling Average calculation process in §63.11224, should be revised, so that the 30-Day Rolling Average is calculated as the average of all valid data hours over the last 30 operating days, NOT the average of Daily Average values over the last 30 operating days. This is a very critical distinction, as using the latter approach (averaging daily average values) substantially overweights startup and shutdown hours, which occur on partial operating days, and does not produce a representative 30-day average. All hours in the averaging period should count equally in determining the overall 30-operating day rolling average.
For example, if a source should startup at say 10 PM on 15 of its last 30-operating days. For those 15 days, the daily average will consist of 2 startup hours, when operating parameter values are typically not in compliance with applicable limits. If the boiler operates continuously on the other 15 days, and these hourly values are within compliance with a 10 or 20% margin, they may still not compensate (offset) the atypical values that occurred during the brief operating period on the other 15 days, if the 30-day average is determined as the average of daily averages. In other words, if instead of determining compliance as the average 390 data points (15 days x 24 hours + 15 days x 2), compliance is determined as the average of 30 daily averages (15 for continuous operating days and 15 for startup days), the result is substantially skewed, is not representative of actual emissions released to the environment, and could result in an inappropriate compliance deviation.
All valid data hours in the 30-operating day look back should be weighted equally in determining compliance.

Response: We are amending the final rule to clarify that the average is based on all valid hourly averages during each 30-day rolling average period. Hourly averages are not summed to a daily average as an intermediate data value for purposes of determining each 30 boiler operating day average.
Commenter Name: Bob Machaver
Commenter Affiliation: Public Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2416
Comment Excerpt Number: 3
Comment: CO/O2 Monitoring System Averaging Period - 63.11224(a)(5) and Table 7: The rule establishes a 30-operating day data averaging period for all operating parameters, except CO/O2, for which the data averaging period has been set at 10 operating days. As discussed in the preamble, CO can be very variable during non-steady state operating conditions, and since averaging includes all operating periods, including startup and shutdown, it would seem appropriate that CO/O2 be assigned the same averaging period as other operating parameters, i.e. 30-rolling days.

Response: The EPA has established a 30-day rolling average compliance period where available data supports our decision. Where we did not have substantial data to support a 30-day rolling average period, we established shorter compliance periods. We are retaining the 10-day rolling average requirement for CO in the final rule.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 52
Comment: CIBO opposes the EPA's decision not to include emissions averaging as a potential compliance method in the proposed reconsideration Area Source Boiler Rule. (76 FR 80532.) A 30-day averaging period will have significant benefits. The EPA has previously noted that the Small Business Administration Panel "recommended that EPA carefully weigh the potential burden of compliance requirements and consider for small entities options such as, emission averaging within facility. . . " (75 FR 31919.) The EPA has further acknowledged in the context of the Major Source Boiler Rule, that "emissions averaging represents an equivalent, more flexible and less costly alternative to controlling certain emission points to MACT levels" and its application "would not lessen the stringency of the MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators." (75 FR 32034.) The same rationale applies equally to area sources.
Response: The logic for including certain provisions in the Major Source Boiler Rule does not apply to the Area Source Boiler Rule. For example, multiple large solid fuel boilers are more typical of major source facilities than of area source facilities. In general, major source boilers are located at different types of facilities than those where area source boilers are located (e.g., large industrial facilities versus small commercial and institutional facilities). The commenter cites emissions averaging as an appropriate small entity compliance option and asserts that the same rationale for allowing emissions averaging at major source facilities applies equally to area source facilities. The commenter, however, does not cite any small entity area source facilities or any area source facilities, for that matter, where the owner or operator of those facilities asserts that emissions averaging provisions would provide a less burdensome compliance method.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 53
Comment: If the EPA were to include emissions averaging as a compliance method, CIBO urges it not to apply a 10% reduction on emissions limits. In the final rule, the EPA includes a restriction on emissions averaging that requires facilities using that option to meet a standard that is 10% stricter than the otherwise applicable limits. (76 FR 15670.) The EPA should not include this 10% penalty for using emissions averaging because it is arbitrary, unnecessary for environmental protection and reduces the flexibility that averaging provides.
Response: See the response to EPA-HQ-OAR-2006-0790-2443-A1, excerpt 52.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 19
Comment: The EPA included emissions averaging as a compliance option in the final Major Source Boiler Rule, and this should be a compliance option for area sources as well. The EPA has previously noted that the Small Business Administration Panel "recommended that EPA carefully weigh the potential burden of compliance requirements and consider for small entities options such as, emission averaging within facility. . . " (75 FR 31919.) Although the EPA asserts that it "proposed provisions consistent with each of the Panel's recommendations regarding area source facilities," the EPA did not include in the final Area Source Boiler Rule an emission averaging compliance alternative for area sources. The EPA has further acknowledged that "emissions averaging represents an equivalent, more flexible and less costly alternative to controlling certain emission points to MACT levels" and its application "would not lessen the stringency of the MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators." (75 FR 32034.) During the reconsideration process, the EPA should adopt this flexible compliance alternative for area sources.
Response: See the response to EPA-HQ-OAR-2006-0790-2443-A1, excerpt 52.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 8
Comment: CIBO notes that there are other issues related to the O2 provisions of the final Area Source Boiler Rule. Specifically, O2 compliance basis for O2 CEMS is given as 30-day rolling average. This appears to be an error since it is a12-hour block average that is required in the rule. See Table 7, 76 FR 15596. However, the word "block" is missing in Table 7 item 7 for O2 and item 6c for ESP secondary amperage and voltage. Id.  These two should be clarified to be block averages if that is the EPA's intent.
Response: We are amending 40 CFR 63.11224(d) in the final rule to agree with Table 7.  It was our intention to change the block averages to 30-day rolling averages.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 14
Comment: The EPA should provide for variable operating parameter limits because of variable operating conditions.
ACC also recommends that the EPA allow for operating parameter limits to vary with unit load fraction as applicable to the operating parameter and specific affected source, and recognize that those operating parameters do not necessarily vary in a linear relationship with load, e.g., pressure drop typically varies with the (flow).[2] In Table 6, the EPA only allows for operating parameter limit variation due to boiler load fraction to be applied to activated carbon injection rates. However, variations with load and other operating conditions also occur for the other operating parameters- wet scrubber pressure drop and liquid flow rate, ESP secondary power. Flue gas flow rate and characteristics vary over load and with other operating variables such as fuel quality, to the extent that the single hourly average value determined during the high load steady state performance test will not apply to other conditions if overall performance is optimized.
Response: We allow for operating parameter limit variation due to boiler load fraction for activated carbon injection rates because there is a straightforward, linear relationship between boiler load, carbon injection rate, and emission rate. The same cannot be said for other operating parameters. However, we are aware that relationships between boiler load, operating parameters, and emission rates may exist outside of carbon injection rates (either linear or non-linear). If a source is able to prove such a relationship exists, the source may submit a request for alternative monitoring to implement such a scheme. Additionally, the permitting authority may allow the unit to operate under different operating scenarios (e.g., low load, mid load, high load) consisting of different operating parameters (with each operating scenario tested), if such a scheme falls within the scope of the regulation.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 27
Comment: In Table 6, the EPA only allows for operating parameter limit variation due to boiler load fraction to be applied to activated carbon injection rates. However, variations with load and other operating conditions also occur for the other operating parameters- wet scrubber pressure drop and liquid flow rate, ESP secondary power. Flue gas flow rate and characteristics vary over load and with other operating variables such as fuel quality, to the extent that the single hourly average value determined during the high load steady state performance test will not apply to other conditions if overall performance is optimized. The EPA should provide an allowance for any operating parameters to vary with unit load fraction as applicable to the operating parameter and specific affected source, and recognize that those operating parameters do not necessarily vary in a linear relationship with load, e.g., pressure drop typically varies with the (flow).
Response: See the response to EPA-HQ-OAR-2006-0790-2444-A1, excerpt 14.
Commenter Name: Neil Gormley
Commenter Affiliation: Earthjustice et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2473-A2
Comment Excerpt Number: 16
Comment: The EPA proposes to allow sources to demonstrate compliance with emissions limits by averaging emissions data over a longer time period. Specifically, the EPA proposes to permit compliance determinations to be made on the basis of a 30-day rolling average. Although rolling averages are better than block averages, which allow polluters to comply based on the entirely fortuitous circumstance of a new block period beginning between elevated test runs, the EPA has failed to adjust the applicable emissions limits to account for a 30-day averaging period. As a result, the EPA's proposed standards will not require units to control emissions to the level of the best performers. This is true in at least two respects. First, the EPA calculated the emissions limits based on the highest 1-hour emissions tests of the best sources (adjusting upwards for assumed variability). Thus, the numerical limits reflect peak emissions, not average emissions. By definition, an average emission level is lower than an emissions peak. See 76 FR at 80536/2. Yet the EPA now proposes to allow all sources to emit on average at the same level that the best sources emit at peak times. Second, the EPA selected the best performers on the basis of 1-hour test runs, not 30-day averages. Units not selected as the best performers may actually have yielded lower 30-day average emissions limits than those selected. To comply with the requirement to set the MACT floor based on the best performers, the EPA must use the same methodology both in selecting the best performers and then in calculating the limits. For both of these reasons, the EPA's failure to adjust its emissions limits in accordance with the switch to 30- day average compliance determinations is contrary to CAA §112(d)(3) and arbitrary.
Response: The commenter is incorrect in stating that the EPA proposed to allow sources to demonstrate compliance with emissions limits by averaging emissions data on the basis of a 30-day rolling average. Neither the proposed reconsideration action, nor this final rule, allows sources to demonstrate compliance with emission limits on a 30-day rolling average basis. As explained in the December 23, 2011 proposal (76 FR 80536), compliance with the emissions limit is determined based on a performance stack test. Continuous compliance is demonstrated by maintaining operating parameters within limits established during the performance stack test.  Compliance with the operating parameter limits is determined based on 30-day rolling averages.  Compliance with emissions limits is established using the average of the three 1-hour emissions tests. For the CO limit, if a CEMS is installed, compliance is demonstrated using a 10-day rolling average. The EPA contends compliance with the CO limits measured continuously, even if measured over a 10-day rolling average, is equally stringent a continuous compliance demonstration as continuous parameter measurements over a 30-day rolling average. Any instance in which an affected source fails to meet an operating limit is considered a deviation, and all deviations must be reported.
The commenter is incorrect in stating that the EPA calculated the emissions limits based on the highest 1-hour emissions tests of the best sources (adjusting upwards for assumed variability). Emissions limits were calculated on the basis of the average of three 1-hour test runs of the best sources adjusted for variability, not on the highest 1-hour emissions tests as asserted by the commenter. The numerical limits reflect the average emissions of the best sources adjusted for variability, not the peak emissions.
Commenter Name: Monica Lopes
Commenter Affiliation: NAES Corporation
Document Control Number: EPA-HQ-OAR-2006-0790-2469-A1
Comment Excerpt Number: 1
Comment: Under 40 CFR 63.11223(b) the EPA is proposing to allow facilities to conduct boiler tune‐ups while burning the type of fuel that provided the majority of the heat input to the boiler over the 12 months prior to the tune‐up. Please clarify if this would also be acceptable if the fuel that provided the majority of the heat input was natural gas but the boiler meets the definition of oil‐fired boiler provided in the rule.
Response: The EPA agrees that if the boiler is a dual-fuel unit, and the fuel that provided the majority of the heat input over the 12 months prior to the tune-up was natural gas, the tune-up should be conducted while the boiler is operating on natural gas.
Testing/Monitoring: CO CEMS-Appropriate compliance alternative
Commenter Name: Bart Sponsellar
Commenter Affiliation: Wisconsin Department of Natural Resources (Wisconsin DNR)
Document Control Number: EPA-HQ-OAR-2006-0790-2453-A1
Comment Excerpt Number: 6
Comment: The Department feels establishing a CO CEMS based emission limitation from limited data or data from sources different from the identified 12% best performing sources is problematic. We believe the EPA can allow sources to use the previously suggested CO/O2 CMS trim system as a parametric monitoring alternative in place of meeting a continuous CO CEMS emission limitation. Under this approach the source periodically (biennial suggested) demonstrates compliance with the primary stack test based emission limit. A correlation is determined of stack test CO to the CO measured using the CO/O2 CMS system over normal load ranges. The CMS CO concentration then becomes the value to be monitored on a continuous basis. The EPA proposed this same type of approach using a PM CMS in place of a PM CEMS for continuous compliance. The parametric CO correlation can also show a source is in compliance with the stack test emission limit at full load but can also show that a source operating under good combustion at lower loads may emit at higher CO levels.
Response: We agree with the commenter and we have selected two different paths for source operators to achieve compliance; either using a certified CO CEMS with a 10-day rolling average or by conducting annual emissions testing and using an O2 CEMS or O2 trim system as a parametric monitor.
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Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 6
Comment: In addition to units required to use CO CEMS, there may also be units that would prefer to install CO CEMS, so that an alternative CO limit based on use of CEMS is needed.  It would be much more appropriate and cost effective for regulated facilities and regulatory authorities if the EPA would provide alternative CO limits and their basis for facilities to utilize CO CEMS instead of O2 CEMS, rather than requiring individual facilities to petition for alternative monitoring practices.
Response: See the response to EPA-HQ-OAR-2006-0790-2453-A1, excerpt 6.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 7
Comment: In order to allow for use of CO CEMS with O2 correction, the EPA needs to establish CO emission limits on an appropriate basis using emission data on the same basis, i.e CEMS data.  Since the final rule provides work practices for startup/shutdown periods, an appropriate basis for a CO limit using a CO CEMS would be a 30-day rolling average based on actual CO readings over the appropriate operating range.
Response: See the response to EPA-HQ-OAR-2006-0790-2416, excerpt 3.
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 20
Comment: The EPA is proposing to amend the monitoring requirements in 40 CFR 63.11224(a) to allow sources subject to a CO emission limit the option to install, operate and maintain a CO and O2 CEMS. (76 FR 80536, Dec. 23, 2011). This will allow facilities to choose between compliance using CO CEMS or compliance using an O2 CEMS in combination with CO stack testing. We support the EPA's decision to allow more flexibility in the CO monitoring requirements and allow facilities that already have CO CEMS to use their existing systems.
Response: The EPA thanks the commenter for their support.
Commenter Name: Barry Christensen
Commenter Affiliation: Occidental Chemical Corporation (OCC)
Document Control Number: EPA-HQ-OAR-2006-0790-2435-A1
Comment Excerpt Number: 4
Comment: OCC supports the proposed increased flexibility in the compliance monitoring requirements. In particular, where numerical limits must be measured, we support the EPA's option to allow either CEMS equipment or stack testing procedures to demonstrate compliance. For example, this includes the proposed CO limits that are based on either stack testing or continuous monitoring. This monitoring flexibility also includes the use of O2 measuring systems in lieu of continuous CO monitoring systems. We support this as it will certainly lower the economic burden to the affected facilities. However, it will still be possible to use a CO CEMS instead of using an O2 monitor and conducting stack sampling.
Response: The EPA thanks the commenter for their support.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 25
Comment: The EPA is proposing to amend the monitoring requirements in §63.11224(a) to allow sources subject to a CO emission limit the option to install, operate and maintain a CO and O2 CEMS. (76 FR  80536, Dec. 23, 2011.) This will allow facilities to choose between compliance using CO CEMS and compliance using an O2 CEMS in combination with CO stack testing. We support the EPA's decision to allow this flexibility in the CO monitoring requirements and allow facilities that already have CO CEMS to use their existing systems.
Response: The EPA thanks the commenter for their support.
Commenter Name: Michael L. Krancer
Commenter Affiliation: Pennsylvania Department of Environmental Protection (PA DEP)
Document Control Number: EPA-HQ-OAR-2006-0790-2449-A1
Comment Excerpt Number: 6
Comment: PA DEP supports the EPA's proposed amendment to allow an alternative to the installation of CO and O2 CEMS. The EPA's proposed alternative compliance option provides flexibility in demonstrating compliance with a CO emission limit in a defensible manner.
Response: The EPA thanks the commenter for their support.
Commenter Name: Bart Sponsellar
Commenter Affiliation: Wisconsin Department of Natural Resources (Wisconsin DNR)
Document Control Number: EPA-HQ-OAR-2006-0790-2453-A1
Comment Excerpt Number: 7
Comment: We propose that a source with a CO/O2 CMS trim system be allowed to determine an alternative CO emission limitation at full load, if appropriate.
Response: The EPA has provided two paths for compliance with the rule; either using a CO CEMS and a 10-day rolling average limit or using an annual stack test and O2 correlation; the latter of which is normally conducted at full load. Alternative compliance conditions may be approved by an administrator on a case-by-case basis.
Testing/Monitoring: CO CEMS-Specifications/operations
Commenter Name: Bob Machaver
Commenter Affiliation: Public Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2416
Comment Excerpt Number: 6
Comment: Monitoring System Activities Resulting in Data Loss that do not Constitute Deviations: Preventive/Routine Maintenance: Section 63.11221 (d) provides an enumeration of the types of monitoring system activities (QA, QC, repairs associated with malfunctions) that do not constitute monitoring system "Deviations", even if they should cause data loss.
One additional activity that should be included in the list of allowed monitoring system activities that may result in data loss without triggering the need to report a deviation is "Preventive/Routine Maintenance" of a monitoring system, which is an activity critical for reliable system performance, but may incur a few hours of data interruption/loss. As an alternative, the rule might include a definition of Quality Control (QC) that explicitly specifies Preventive/Routine Maintenance as a QC activity.
It is also suggested that the word "required" be removed as a qualifier before the phrase quality assurance (QA) or QC. Calibration gas span checks may be performed as a diagnostic or verification tool, and re-calibrations may be performed to improve system performance without being "required." Having to distinguish whether a QA or QC activity is required before undertaking it is an unnecessary and unwarranted burden on plant maintenance personnel.

Response: The EPA disagrees with the commenter. Source operators will define required monitoring system QA/QC activities in their monitoring plans and identification of such activities should not place an undue burden on plant maintenance personnel. Monitoring plan activities, including such as those the commenter mentioned, are excepted by 40 CFR 63.11221(d).
Commenter Name: Bob Machaver
Commenter Affiliation: Public Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2416
Comment Excerpt Number: 7
Comment: Monitoring System Deviations: Section 63.11221(d) indicates the following CEMS data loss periods are not considered monitoring system "Deviations": "periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments".
The types of monitoring system data loss incidents that represent "Deviations" do not appear to be specified in a consistent manner between and §§63.11221(d) and 63.11224(a)(6).
However, §63.11224(a)(6) only explicitly excludes periods of CEMS data loss due to "required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments)" from being designated as monitoring system "Deviations"
Section 63.11224(a)(6) should be revised to be consistent with §63.11221(d), i.e. the types of monitoring system activities which may result in data loss periods (e.g. QA, QC, repairs associated with malfunctions), but do not constitute "Deviations" enumerated in §63.11221(d) should be fully repeated in §63.11224(a)(6) for clarity. Also as indicated in Comment 3 above, the performance of monitoring system "preventive/routine maintenance" should be added to the list of activities that do not constitute a monitoring system Deviation, should they cause data loss.

Response: The EPA agrees with the commenter and is modifying the final rule to point 40 CFR 63.11224(a)(6) to 40 CFR 63.11221(d).
Testing/Monitoring: Oxygen Monitors-Appropriateness and location
Commenter Name: Bob Machaver
Commenter Affiliation: Public Citizen
Document Control Number: EPA-HQ-OAR-2006-0790-2416
Comment Excerpt Number: 5
Comment: CO/O2 Monitoring Location  -  63.11224(a): Section 63.11224(a) indicates that CO and/or O2 must be monitored at the "outlet of the boiler". Typically, the sampling probe for a CO CEMS is located on the stack, and it is not clear if the such a sampling location would be considered part of the "outlet of the boiler" for purposes of Subpart JJJJJJ monitoring. It should be noted that since O2 must be measured in conjunction with CO, the exact location of the sampling probe along the boiler flue gas exhaust system is not critical, since any leakage into the boiler upstream of the sampling point will be adjusted for thru an O2 correction.
It is suggested that the language "outlet of the boiler" be replaced by "representative sampling location within the boiler, the boiler exhaust system or stack". It should also be noted that the preamble to this proposed rule revision indicates that the phrase "outlet to the boiler" would be removed from the rule.

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Response: The EPA agrees with the commenter and is modifying the rule language to reflect that CO CEMS be located at the outlet of the boiler, after any add-on controls or flue gas recirculation system and before release to the atmosphere, and that O2 monitors and O2 trim systems be installed to monitor O2 in the boiler flue gas, boiler firebox, or other appropriate intermediate location.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 2
Comment: The final Area Source Boiler Rule imposes a CO emission limit on coal-fired subcategories with compliance proven by a triennial Method 10 CO emission test, in combination with an O2 operating limit proven with an O2 CEMS. (76 FR 15594.) While CIBO agrees that CO CEMS should not be required for units under Subpart DDDDD or Subpart JJJJJJ, the O2 monitoring requirements as finalized are not appropriate or workable in some cases and additional flexibility is required.
Response: See the response to EPA-HQ-OAR-2006-0790-2416, excerpt 5.
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 17
Comment: The optimum location of the sensor or sampling point is dependent on the specific boiler design. In different applications, that location might be at the furnace exit, in the convection pass, at the boiler outlet or at another downstream location. We recommend that this definition be modified as follows to accommodate the boiler-specific location of the sensing point:
Oxygen analyzer system means all equipment required to determine the O2 content of a gas stream and used to monitor O2 in the boiler flue gas, boiler or firebox, or other appropriate intermediate location.
Response: The EPA agrees with the commenter and is modifying the definition of an O2 analyzer system in the final rule.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 8
Comment: ACC recommends the following changes to the regulatory language to enhance clarity and ensure no negative impact to operations.
Oxygen sensing location
The Oxygen analyzer system is defined in §63.11237 of the Reconsideration Proposal in part as follows:
     Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas or firebox.
The optimum location of the sensor or sampling point is dependent on the specific boiler design. In different applications, that location might be at the furnace exit, in the convection pass, at the boiler outlet or at another downstream location. ACC recommends that this definition be modified as follows to accommodate the boiler-specific location of the sensing point: Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas, boiler or firebox, or other appropriate intermediate location.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 21
Comment: The Oxygen analyzer system is defined in §63.11237 in part as follows:
"Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas or firebox. ..."
The optimum location of the sensor or sampling point is dependent on the specific boiler design. In different applications, that location might be at the furnace exit, in the convection pass, at the boiler outlet or at another downstream location. We recommend that this definition be modified as follows to accommodate the boiler-specific location of the sensing point:
Oxygen analyzer system means all equipment required to determine the oxygen content of a gas stream and used to monitor oxygen in the boiler flue gas, boiler or firebox, or other appropriate intermediate location.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 20
Comment: As set forth in comments on the CIBO's Petition for Reconsideration of the final Area Source Boiler Rule, the EPA's proposed O2 monitoring requirements are appropriate. This approach is technically sound, adds flexibility and is less costly and burdensome than the continuous O2 monitoring requirements utilizing CEMS.
Many existing boilers already utilize O2 analyzers for indication, alarm, and O2 trim control, where the fuel/air ratio is automatically controlled for optimum combustion conditions. The sensing location for existing O2 monitors is typically in the optimum location to sense gas composition as reliably as possible, because sensing of O2 in these cases maintains proper excess air levels and helps prevent unsafe operating conditions. For units equipped with existing O2 sensors and O2 trim control systems, flue gas composition is already used for combustion tuning and control characterization. Therefore, if O2 monitoring is desired for continuous compliance under the Area Source Boiler Rule, sensing O2 at the current location prior to the stack would be logical and proper from a technical perspective. The O2 analyzers utilized for these existing purposes are not compliance CEMS meeting PS-3 requirements relative to positioning or other QA/QC requirements. They are, however, calibrated and maintained to provide reliable and safe service for combustion unit operation
Response: The EPA thanks the commenter for their support of the use of O2 monitoring systems.  For response to monitor location, see the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 3, 4
Comment: While CIBO agrees that CO CEMS are not an appropriate mandatory monitoring requirement for a CO limit based on stack test data obtained at full load conditions, monitoring O2 levels in the stack or ductwork leading to the stack to ensure continuous compliance is not appropriate for all units. Many existing boilers already utilize flue gas O2 analyzers for indication, alarm, and O2 trim control, where the fuel/air ratio is automatically controlled for optimum combustion conditions.
The sensing location for existing O2 monitors is typically in the optimum location to sense flue gas composition as reliably as possible, because sensing of O2 in these cases maintains proper excess air levels and helps prevent unsafe operating conditions. For many types of combustion units, that location is near the boiler or process heater furnace outlet in a position upstream of any potential air in-leakage points to avoid erroneous excess air indications. This location is also upstream of air preheaters where utilized, thus avoiding the erroneous (high O2)  indications due to inherent leakage across regenerative air preheater seals or potential tube leakage in recuperative air preheaters.
Response: See response to EPA-HQ-OAR-2006-0790-2453-A1, excerpt 6, for a response to CO compliance alternatives. The EPA thanks the commenter for their support of the use of O2 monitoring systems. For response to monitor location, see the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 7
Comment: ACC supports the EPA's proposed changes to O2 monitoring requirements. In the final rule, the EPA included continuous O2 monitoring with a CEMS as the compliance method for sources with a CO limit, instead of mandating the use of CO CEMS. In the reconsideration proposal, the EPA is proposing to amend the O2 monitoring requirements to allow use of continuous O2 trim analyzer systems instead of O2 CEMS. (76 FR 80536.) The EPA also proposes to remove the requirement that the O2 monitor be located at the outlet of the boiler, so that it can be located at a more representative location, i.e., either within the combustion zone or at the outlet as a flue gas O2 monitor. ACC supports these proposed changes because they allow facilities to utilize existing O2 trim systems rather than having to install CEMS. This approach is technically sound, adds flexibility and is less costly and burdensome than the continuous O2 monitoring requirements using CEMS.
Many existing boilers already utilize flue gas O2 analyzers for indication, alarm, and O2 trim control, where the fuel/air ratio is automatically controlled for optimum combustion conditions. The sensing location for existing O2 monitors is typically in the optimum location to sense flue gas composition as reliably as possible, because sensing of O2 in these cases maintains proper excess air levels and helps prevent unsafe operating conditions. For many types of combustion units, that location is near the boiler furnace outlet in a position upstream of any potential air in leakage points to avoid erroneous excess air indications which would drive controls in an erroneous direction. This location is also upstream of air preheaters where utilized, thus avoiding the erroneous (high O2) indications due to inherent leakage across regenerative air preheater seals or potential tube leakage in recuperative air preheaters. For those units equipped with existing O2 sensors and O2 trim control systems, flue gas composition at those locations would already be used for combustion tuning and control characterization. Therefore, if O2 monitoring is desired for continuous compliance under this rule, sensing O2 at that current location would be technologically sound.
Response: The EPA thanks the commenter for their support of the use of O2 monitoring systems. For response to monitor location, see the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 5
Comment: The most cost effective approach for utilization of O2 CEMS would be to allow the option of continued use of existing O2 analyzers and use of new O2 analyzers of appropriate design for the application to be located in optimum positions for the particular unit involved.  Requiring periodic sensor calibration would be a way to ensure accurate O2 monitoring. If new O2 sensors are required in all cases in the breeching or stack to meet PS-3 requirements, it would be an unjustified additional capital and ongoing O&M expense that will not provide any constructive compliance information. There are some units where locating O2 sensors in the breeching or stack is appropriate, so options should be provided to allow optimum monitoring.
Response: The EPA thanks the commenter for their support of the use of O2 monitoring systems. For response to monitor location, see the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 17.
 Commenter Name: Michael J. Bradley
Commenter Affiliation: The Clean Energy Group
Document Control Number: EPA-HQ-OAR-2006-0790-2448-A1
Comment Excerpt Number: 12
Comment: We support the EPA's proposed revisions to compliance monitoring, including the use of CO CEMS.
Response: The EPA thanks the commenter for their support.
Testing/Monitoring: Oxygen Monitors-Specifications/Operations
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 16
Comment: We support the EPA's proposal to add flexibility and reduce the cost and burden of the continuous O2 monitoring requirements, as these changes allow facilities to utilize existing O2 trim systems rather than installing CEMS.
Response: The EPA thanks the commenter for their support.
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 19
Comment: Section 63.11224(a)(7) should be modified to incorporate a safety component associated with the operation of O2 trim system. Coal-fired boilers subject to the CO limits in this rule may also be equipped to fire other fuels such as natural gas and fuel oil that may be lower emitting and able to operate at lower O2 levels for improved boiler efficiency. Operators may also need to modify the O2 set point or trim system to accommodate fuel quality issues.  Oxygen trim systems not only provide a means for energy efficiency, but they also are integral to furnace combustion control and furnace safety. Therefore, while this system promotes energy efficiency and use of a 30-day rolling average basis does provide some operating flexibility, use of such systems should also consider safety. We recommend that the paragraph §63.11224(a)(7) be revised as follows:
(7) You must operate the oxygen analyzer system with the oxygen level set at or above the minimum percent oxygen by volume that is established as the operating limit for oxygen according to Table 64 to this subpart when firing the fuel or fuel mixture utilized during the most recent CO performance stack test.  Operation of oxygen trim control systems to meet these requirements shall not be done in a manner which compromises furnace safety.
Response: The EPA agrees with the commenter and is incorporating safety language into the final rule.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 24
Comment: Section 63.11224(a)(7) should be modified to incorporate a safety component associated with the operation of O2 trim system. Coal-fired boilers subject to the CO limits in this rule may also be equipped to fire other fuels such as natural gas and fuel oil that may be lower emitting and able to operate at lower O2 levels for improved boiler efficiency. Operators may also need to modify the O2 set point or trim system to accommodate fuel quality issues.
Oxygen trim systems not only provide a means for energy efficiency, but they also are integral to furnace combustion control and furnace safety. Therefore, while this system promotes energy efficiency and use of a 30-day rolling average basis does provide some operating flexibility, use of such systems should also consider safety. We recommend that the paragraph §63.11224(a)(7) be revised as follows:
(7) You must operate the oxygen analyzer system with the oxygen level set at or above the minimum percent oxygen by volume that is established as the operating limit for oxygen according to Table 6 to this subpart when firing the fuel or fuel mixture utilized during the most recent CO performance stack test. Operation of oxygen trim control systems to meet these requirements shall not be done in a manner which compromises furnace safety.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 19.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 11
Comment: In addition, §63.11224(a)(7) should be modified to incorporate a safety component associated with the operation of O2 trim system. Coal-fired boilers subject to the CO limits in this rule may also be equipped to fire other fuels such as natural gas and fuel oil that may be lower emitting and able to operate at lower O2 levels for improved boiler efficiency. Operators may also need to modify the O2 set point or trim system to accommodate fuel quality issues. Oxygen trim systems not only provide a means for energy efficiency, but they also are integral to furnace combustion control and furnace safety. Therefore, while this system promotes energy efficiency and use of a 30-day rolling average basis for the system does provide some operating flexibility, use of such systems should also consider safety. ACC recommends that §63.11224(a)(7) be revised as follows:
You must operate the oxygen analyzer system with the oxygen level set at or above the minimum percent oxygen by volume that is established as the operating limit for oxygen according to Table 64 to this subpart when firing the fuel or fuel mixture utilized during the most recent CO performance stack test. Operation of oxygen trim control systems to meet these requirements shall not be done in a manner which compromises furnace safety.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 19.
Testing/Monitoring: Out of Scope
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 28
Comment: CIBO's Petition for Reconsideration sought consistency in testing requirements for this rule and 5-year Title V permit review cycle. The EPA did not coordinate these provisions in the proposed reconsidered rule. The EPA did revise 40 CFR 63.11220 to clarify that performance testing will be triennial for all sources. (76 FR 80539.) While CIBO supports testing at this lower frequency of 3 years, triennial testing remains overly burdensome and the EPA should modify the finalized emission testing requirements so that they are consistent with the 5-year air permit review cycle. Annual compliance testing is extremely expensive and the benefits of conducting emission tests more frequently then every 5 years do not justify the costs. In addition, as noted in CIBO's Petition for Reconsideration, there is likely to be a shortage of testing and laboratory resources under the current emission testing schedule.
Response: In the December 2010 proposal, performance testing for PM, Hg, and CO was required on an annual basis. Performance stack tests for PM and Hg could be conducted less often if performance stack tests for at least 3 consecutive years showed that emissions were at or below 75% of the emission limit, and if there were no changes in the operation of the affected source or air pollution control equipment that could increase emissions. In that case, a source did not have to conduct a performance test for that pollutant for the next 2 years. Reduced performance testing for CO was not allowed. In response to comments that the proposed testing frequency was overly burdensome, we reduced the required performance testing frequency to a triennial basis for PM, Hg, and CO. The reduced requirements specify performance testing every 3 years, but no longer require demonstration that emissions are at or below 75% of the emission limit for at least 3 consecutive years prior to being allowed to conduct testing every 3 years. We do not consider triennial testing to be overly burdensome and are retaining the requirement.
Commenter Name: S. William Becker
Commenter Affiliation: National Association of Clean Air Agencies (NACAA)
Document Control Number: EPA-HQ-OAR-2006-0790-2455-A1
Comment Excerpt Number: 42
Comment: NACAA agrees that sources may employ automated fuel-sampling equipment, but notes that the 90[th] percentile compliance obligation is inconsistent with the EPA's determination that MACT floors must be set at a 99[th] percentile level.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Donna Celia
Commenter Affiliation: HMH Consulting
Document Control Number: EPA-HQ-OAR-2006-0790-2413-A1
Comment Excerpt Number: 1
Comment: This comment pertains to § 63.11220(b): "If you demonstrate compliance with the mercury emission limit based on fuel analysis, you must conduct a fuel analysis according to §63.11213 for each type of fuel burned monthly."
Why monthly? For facilities in Alaska, fuel is delivered in bulk shipments. Depending upon the remoteness of the facility, some sources received their bulk fuel in only a few large shipments per year. I would presume that this is true in other parts of the country as well, possibly in Hawaii, Guam, other U.S. Territories, and maybe even in parts of the lower 48, or at specific facilities in the lower 48. If the facility performs a fuel analysis from a specific shipment of bulk fuel, wouldn't that test be representative of the entire bulk shipment? Why can't a facility perform the fuel analysis on each bulk shipment of fuel? As for commercial or institutional sources, wouldn't this be true of the local fuel supplier? So, if a hospital in Dutch Harbor has boilers (and I don't know if they do, it's just an example), would a single fuel sample at the bulk terminal for each load of fuel delivered sufficiently demonstrate the mercury content of the fuel used at the hospital? Wouldn't this same fuel sample be applicable to other fuel consumers who buy fuel from the local bulk fuel terminal?
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration. Nevertheless, we point out that we are amending the fuel sampling requirements in 40 CFR 63.11220(c) because we realized that when performance stack testing requirements were revised in the March 2011 final rule we neglected to revise the fuel analysis requirements. In the final rule, we are specifying that the owner or operator does not need to conduct further fuel analysis sampling if, when demonstrating initial compliance with the Hg emission limit, the Hg constituents in the fuel or fuel mixture are measured to be equal to or less than half of the Hg emission limit. If, when demonstrating initial compliance, the Hg constituents in the fuel or fuel mixture are greater than half of the Hg emission limit, the owner or operator must conduct quarterly sampling.
Commenter Name: David L. Meeker
Commenter Affiliation: National Renderers Association (NRA)
Document Control Number: EPA-HQ-OAR-2006-0790-2427-A1
Comment Excerpt Number: 13
Comment: The NRA requests that the EPA finds it is appropriate to include an option to demonstrate compliance directly with a TSM or individual non-Hg metal HAP emissions limitation via fuel sampling for new boilers firing solid or liquid fuels (reconsidered rule includes PM emission limitations) for NESHAP Subpart JJJJJJ. This comment is specifically for the NRA members and customers that will utilize a liquid fuel, not processed fats, as a back-up fuel source for boilers subject to NESHAP Subpart JJJJJJ.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Dan Bosch
Commenter Affiliation: National Federation of Independent Business (NFIB)
Document Control Number: EPA-HQ-OAR-2006-0790-2428-A2
Comment Excerpt Number: 3
Comment: NFIB suggests that to improve these rules further, the EPA should adopt the suggestions the small-entity representatives provided the Agency during the SBAR panel held in 2009. These recommendations include:
   * Allowing facilities meeting the SBA definition of a small business to have reduced and less frequent monitoring, testing and reporting requirements.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 29
Comment: CIBO appreciates the change clarification in of the triennial frequency of performance testing from annually in the final rule to once every 3 years in the reconsideration rule. However, requiring a performance test once every 5 years, as is required in many air permit renewals, will still accomplish the same assurance of compliance at a reduced cost to the regulated source.
A significant amount of testing will be required by sources to determine the compliance status with respect to the rule and to evaluate and select available control strategies. Capital projects to install necessary control equipment cannot proceed until the testing and evaluation is complete.
Due to the high number of sources affected by the rule that have the same concerns, it is likely that availability of stack testing personnel and laboratory facilities to conduct tests will be limited, adding to the time required to complete this essential first step. As outlined below, annual frequent compliance testing requiring multiple test runs for purposes of compliance will further reduce the availability of testing and laboratory resources.
Response: See the response to EPA-HQ-OAR-2006-0790-2443-A1, excerpt 28.
Commenter Name: Neil Gormley
Commenter Affiliation: Earthjustice et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2473-A2
Comment Excerpt Number: 19
Comment: The EPA proposes to eliminate the requirement that sources subject to a CO emission limit monitor CO directly. Instead, sources would be permitted to show compliance with the CO standard based on the O2 content of the outlet or the combustion zone, at the option of the owner or operator. The EPA must require monitoring that "provide[s] reasonable assurance of compliance with emission standards." Sierra Club v. EPA, 353 F.3d 976, 990 (D.C. Cir. 2004) (quoting Natural Resources Defense Council Inc. v. EPA, 194 F.3d 130,136 (D.C. Cir. 1999)). Here, the EPA has not concluded that the O2 monitoring requirements provide reasonable assurance of compliance with CO limits, let alone supported such a determination with record evidence. The EPA has not established that O2 monitoring is a reliable proxy for CO, either at the outlet or in the combustion chamber. Moreover, the EPA does not show that a single performance test is sufficient to establish an O2 content level that reliably corresponds to the CO emission limit.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration. The suitability of monitoring O2 concentration in order to demonstrate continuous compliance with the CO emissions limits was discussed in the response to comments for the final rule published in March 2011. This issue has not been reopened.
Commenter Name: W. Allan Cagnoli
Commenter Affiliation: Hearth, Patio & Barbecue Association (HPBA)
Document Control Number: EPA-HQ-OAR-2006-0790-2438-A1
Comment Excerpt Number: 1
Comment: The requirement to measure CO and O2 before and after each tune-up is the prime instance of unreasonable cost. Upon investigation, the OHH Caucus has learned that the market price for an independent laboratory to perform such measurements, assuming they were technically feasible at all, would be approximately $5,000. The useful life of an ICI OHH is in the range of 15-20 years. Even at the low end of that range, the total lifetime cost of the CO/O2 measurements for a new unit, therefore, would be on the order of $40,000 (eight tune-ups times $5,000 each). The current retail price of such a unit is approximately $25,000. Installation costs $2,500-10,000, depending on the circumstances of the particular ICI facility. Even at the high end of that range, the cost of just the CO/O2 measurements would exceed the cost of purchasing and installing a new unit by $5,000($40,000 vs. $35,000), effectively doubling the lifetime cost of an ICI OHH unit.
Such doubling, if justifiable at all, could only be justified by some large benefit. But none exists.  One set of primary determinants of the combustion efficiency, and hence the HAP emissions, of an OHH unit includes the type of cordwood it burns, the moisture level of the cordwood, the airflow to the firebox, and the achievement of a relatively high temperature in the firebox.  Another interrelated set includes maintenance and repair at the end of each season of operation, annually conforming the unit to its original design during the warm-weather period of downtime.  Both sets of determinants carefully and systematically addressed by the typical OHH manufacturer's operation and maintenance manual - a market necessity given that sales depend on customer satisfaction and that satisfaction depends largely on combustion efficiency.  Because each owner/operation gains savings by promoting optimum combustion efficiency, it is reasonable to assume that owner/operators in general will follow the manufacturer's recommendations, thereby making the current tune-up requirements, especially the CO/O2 measurement requirement, superfluous. All the EPA need do, assuming it feels compelled by the CAA to reinforce those market incentives, is mandate in the rule that ICI OHH units must follow those recommendations.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: W. Allan Cagnoli
Commenter Affiliation: Hearth, Patio & Barbecue Association (HPBA)
Document Control Number: EPA-HQ-OAR-2006-0790-2438-A1
Comment Excerpt Number: 2
Comment: The CO/O2 measurement requirement creates confusion and uncertainty, an extra burden of unknown dimension for which there is also no counterbalancing benefit. As the EPA acknowledged in the preamble to the final rule, the Agency failed to specify the instruments and methods for the mandated CO/O2 measurements in question and therefore "allow[ed] owners and operators to choose the method of measurement." (76 FR at 15575 col.1.) While Table 4 of the rule mandates the use of certain EPA-adopted methodologies for measuring CO, Table 4 governs only testing aimed at showing compliance with numeric CO emission limits. Moreover, those methodologies do not appear to be applicable as a technical matter to ICI OHH units. For instance, the linchpin method for selecting sampling port locations (i.e., Method 1 in Appendix A-1 to 40 CFR Part 60) states that, while the method "is applicable to gas streams flowing in ducts, stacks, and flues," it "cannot be used when...the flow is cyclonic or swirling...." (§1.2.)  Here, the conduit for exhaust from an ICI OHH unit is a simple vent that is so short and wide as to ensure that the flow is at least "swirling," thereby disqualifying Method 1 and the string of methods that depend on it.[4] The result of the EPA's failure to specify a methodology, either directly in the rule or indirectly, is that owner/operators lack adequate notice of what the EPA and its delegate agencies would find acceptable in the event of enforcement investigations. The creation of such uncertainty is not consonant with the principle inherent in the GACT concept of moderating costs, nor with principles of rationality.
[4] Photographs and diagrams of an ICI OHH appear in Exhibit B.  See also http://www.hea1mor.com/commercial-models.php.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Bart Sponsellar
Commenter Affiliation: Wisconsin Department of Natural Resources (Wisconsin DNR)
Document Control Number: EPA-HQ-OAR-2006-0790-2453-A1
Comment Excerpt Number: 5
Comment: The proposed schedule of annual stack testing for sources subject to emission limitations, especially for smaller sources, is very intensive and costly. We encourage the EPA to consider opportunities for consolidating compliance and testing requirements through the use of a CO and O2 continuous monitoring system with combustion trim (CO/O2 CMS trim)  --  a non-CEMS analyzer based monitoring system. This approach should be allowed as an alternative to the primary defined compliance demonstration requirements.
This approach continuously minimizes emissions and we believe can be allowed under the rule to meet start-up work practices, dioxin/furan work practices, and CO and PM parametric monitoring needs. The EPA has acknowledged that an O2 trim system alone is a better way to operate a boiler. The CO/O2 CMS trim approach takes the next step in operating a boiler for combustion efficiency. We propose that this approach will allow for performance tests every 2 years and tune-ups every 4 years for sources. This is very important as Wisconsin sources are currently subject to biennial stack testing (as applicable). Going to this schedule and simplifying other requirements will significantly reduce the cost of this rule while resulting in the same or potentially better environmental improvement.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 16
Comment: During the reconsideration process, the EPA should revise the emission testing requirements so that frequency of testing is not more than every 5 years. The EPA acknowledges that the cost of testing small boilers and process heaters is prohibitive. While the cost of emissions testing larger units is less prohibitive, the EPA must consider these costs when establishing the frequency of testing. The benefits of testing more frequently than every 5 years do not justify the costs. HAP emissions change only when operating parameters change (e.g., firing rate, maximum contaminant input limits for chloride and Hg, type of fuel, combustion efficiency, O2 content, etc.) or when design changes occur. Absent these changes to an affected source, operating parameters established by implementation of Area Source Boiler Rule are more than sufficient to ensure that emissions will not significantly change over time.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 17
Comment: The Area Source Boiler Rule provisions require owners and operators to install CEMS to measure real-time emissions (O2 and PM), measure and monitor prescriptive operating limits, as well as monitor, measure, and keep records of each type of fuel on a continuous basis to verify compliance with limits established during the compliance test. The Area Source Boiler Rule regulations also stipulate that sources must perform testing under a representative operating load and require sources to maintain within 110% of the average operating load observed during testing. Based on these stringent monitoring requirements, the operating parameters established during testing are sufficient for a source to demonstrate compliance for a 5-year period.  Modifications will be tested under the provisions for new and modified sources, and do not need to be considered in ongoing test requirements.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A2
Comment Excerpt Number: 18
Comment: Other regulations support a 5-year testing cycle. For example, 40 CFR Part 75 requires low mass emissions units to establish NOx emissions curves based on testing conducted every 5 years. Several states require that testing be conducted upon each 5-year Title V permit renewal. All affected major sources subject to Boiler MACT are required to have Title V Permits.
Response: As stated in the preamble for the proposed reconsideration of final rule, dated December 23, 2011, we are not obligated to respond on the merits to any comments addressing aspects of the final rule beyond the topics for which comments were requested. This comment is not on an issue reopened by the December 23, 2011 FR notice and is outside the scope of the current reconsideration.
SSM: Affirmative defense provisions for malfunctions
Commenter Name: Paul Noe
Commenter Affiliation: American Forest & Paper Association (AF&PA) et al.
Document Control Number: EPA-HQ-OAR-2006-0790-2426-A1
Comment Excerpt Number: 21
Comment: The EPA's proposal to provide an affirmative defense for periods of malfunction is without merit. The EPA must instead establish work practices to address emissions during periods of malfunction. Comments recently submitted by the "SSM Coalition" on the EPA's proposed "Risk and Technology Review" rule for Mineral Wool and Wool Fiberglass Manufacturing explain in detail that: (1) EPA must take malfunctions into accounts when setting §112 emissions standards; (2) the proposed affirmative defense is not a permissible substitute for setting emissions standards for periods of malfunction; and (3) the proposed affirmative defense in unreasonable and impracticable.
Several of the undersigned associations also are members of the SSM Coalition. We incorporate these comments of the SSM Coalition by reference. For these reasons, the EPA should set aside the proposed affirmative defense for periods of malfunction and, instead, set a work practice standard for such periods.
Response: The affirmative defense criteria are not requirements that a source must meet. In an action to enforce a violation of a standard caused by a malfunction, a source can choose to assert an affirmative defense. The affirmative defense is not relevant to malfunctions that do not result in violations of emission standards.
The EPA disagrees with comments that criticize the affirmative defense criteria as being overly vague or unduly restrictive and complex. The EPA believes that courts are well equipped and often do evaluate and apply the type of criteria set forth in the affirmative defense. The EPA revised certain criteria of the affirmative defense provisions that may ease the burden for owners and operators. The EPA is eliminating both the immediate notification and 45-day malfunction report requirement.
The EPA has determined that CAA §112 does not require that emissions that occur during periods of malfunction be factored into development of CAA §112 standards. Malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA §112(d) standards, which, once promulgated, apply at all times. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. As the EPA further explained, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. Setting work practice standards under §112 presents the same issues as setting numerical emission limits given the varied nature of malfunctions. Thus, the EPA does not agree with the commenter's suggestion that we apply work practices for malfunction events.
Commenter Name: Robert D. Bessette
Commenter Affiliation: Council of Industrial Boiler Owners (CIBO)
Document Control Number: EPA-HQ-OAR-2006-0790-2443-A1
Comment Excerpt Number: 62
Comment: Given that malfunctions are essentially the same as periods of startup and shutdown, work practice standards should also apply.
As CIBO points out in its Petition, the EPA recognizes in both the Boiler MACT and Area Source Boiler Rule, "that it is not feasible to require stack testing  -  in particular, to complete the multiple required test runs  -  during periods of startup and shutdown due to physical limitations and the short duration of startup and shutdown periods. Operating in startup and shutdown mode for sufficient time to conduct the required test runs could result in higher emissions than would otherwise occur." (76 FR 15577, 15642.) It is irrational to view malfunctions any different than startup/shutdown periods. As such, the EPA should establish work practice standards for malfunctions. The rule is unreasonable as it is and subjects sources to the risk of noncompliance especially given the fact that malfunctions are unavoidable and unpredictable.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 30
Comment: In keeping with the court's holding in Sierra Club, we strongly encourage the Agency to abandon its affirmative defense approach for malfunctions. We believe that the Agency instead should use its authority in either §112(d)(5) or §112(h) to establish a management practice, work practice or operational standard to address a malfunction event that may be experienced by an area source boiler.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Stephen E. Woock
Commenter Affiliation: Weyerhaeuser
Document Control Number: EPA-HQ-OAR-2006-0790-2452-A1
Comment Excerpt Number: 9
Comment: The EPA proposes to treat malfunction events as if emission standards established based on normal process conditions and control equipment should apply. The "Affirmative Defense" policy the EPA proposes to codify as potential protection when malfunctions lead to emissions that exceed standards does not adequately address the issue. On its own it is overly complex in its documentation and reporting requirements that would be difficult, if not impossible, to meet during extreme or catastrophic malfunction events. The legally defensible and feasible approach is to set work practice standards as the NESHAP during malfunction events, as detailed in our trade group comments.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.

Commenter Name: Alicia Meads
Commenter Affiliation: National Association of Manufacturers (NAM)
Document Control Number: EPA-HQ-OAR-2006-0790-2446-A1
Comment Excerpt Number: 16
Comment: The EPA should establish work practices to address emissions during periods of malfunction. Given that the EPA's floor data does not consider malfunctions and that the statute requires that the MACT standard be "achievable," the EPA should set work practice requirements to address periods of malfunctions as well. CAA §112(h) allows the EPA to set work practice standards for situations where "it is not feasible in the judgment of the Administrator to prescribe or enforce an emission standard . . . ." Malfunctions fit with the situations described in the definition of "not feasible to prescribe or enforce an emission standard" as any situation where "the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations." Emission testing for malfunctions would be near impossible to conduct given the sporadic and unpredictable nature of the events. Section 112(h) work practice standards, therefore, are well-suited to address malfunction periods and the complexities and challenges surrounding collecting data and establishing numerical standards for those events.
The NAM disagrees with the EPA's proposal to provide an affirmative defense for periods of malfunction. As has been discussed in various comments in this rulemaking, as well as others where the EPA has proposed a similar affirmative defense, the proposed affirmative defense is not a permissible substitute for setting emissions standards for periods of malfunction, and it is unreasonable and impracticable.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Timothy Serie
Commenter Affiliation: American Coatings Association (ACA)
Document Control Number: EPA-HQ-OAR-2006-0790-2437-A1
Comment Excerpt Number: 16
Comment: ACA believes that the EPA's approach to malfunction episodes including the proposed affirmative defense for violating an emissions standard during a malfunction episode is inconsistent with the CAA, and the EPA should address this issue by promulgating a separate standard for malfunction periods. In the proposed reconsideration the EPA plans to apply the emissions standards, which were calculated during periods of normal operation, at all times, including during a malfunction event. The EPA is seeking comment on an affirmative defense provision requiring the owner or operator of a boiler to meet a list of criteria during a malfunction episode, and failing to meet these criteria exposes the source to potential civil penalties for violating the emissions standards. This approach, including the proposed affirmative defense, is inappropriate for the following reasons.
The EPA fails to provide an adequate legal justification or explain why the emission standard that applies during normal operations should also apply during an unexpected malfunction period, even though the Agency did not consider malfunction periods when calculating and establishing the MACT requirements for this source category. Under CAA §112(d)(3), the EPA must calculate and promulgate emissions standards that are achievable by the best performing existing sources. When calculating this emissions level, however, the EPA did not consider the potential for malfunctions or how these events would affect achievable emissions levels. Therefore, during a malfunction episode, the Agency cannot expect affected sources to meet the emissions limits that were calculated during normal periods of operation. The Agency's approach in this regard is contrary to the CAA §112(d).
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Timothy Serie
Commenter Affiliation: American Coatings Association (ACA)
Document Control Number: EPA-HQ-OAR-2006-0790-2437-A1
Comment Excerpt Number: 17
Comment: The affirmative defense is not an adequate replacement for standards during malfunction episodes and EPA should establish a separate standard for periods of malfunction. The affirmative defense provisions do not remedy the underlying problems with the Agency's approach to malfunction periods. Furthermore, it would likely be impractical for the Agency to recalculate the entire standard and account for malfunctions. Instead, EPA should break down the standard and establish different requirements for periods of malfunction. This approach realizes the limitations of control technology and its effect on emissions levels, and also satisfies the court's decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), by ensuring that standards (even though there may be multiple different standards) are in place at all times during periods of startup, shutdown, and malfunction.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 18
Comment: The EPA failed to present any rationale or justification for its decision to apply the same numeric emission standards established for normal operations for an abnormal event, i.e., a malfunction.
As highlighted above, the court in Sierra Club did not state that the EPA must apply the same standards it establishes for normal operations during periods of SSM. The court's holding is clear that "some" §112 standard must "govern" SSM events but it did not specify which §112 standard. In this rulemaking, the EPA concluded that the Hg and CO standards set for normal operations also must be attained during a malfunction event. However, the EPA has provided no explanation as to why it believes that area source boilers reasonably could be expected to meet the emissions standards applicable to steady-state operations during a malfunction event.
In failing to articulate the basis for its decision, the Agency also ignores the comments submitted by ACC and others encouraging the EPA to establish a work practice standard for malfunction events. This is not reasoned decision-making and we hope that the Agency's "reconsideration" of its affirmative defense approach will prompt the EPA to give reasonable consideration to the fact that a boiler that has a malfunction is not likely to be able to achieve the same level of emission reductions that it achieved and can achieve while operating at steady-state.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 24
Comment: The EPA [does not] explain how the Weyerhaeuser decision (that they do not have to consider every type of malfunction) allows the EPA to ignore all types of malfunctions in establishing emission limits. The EPA fails to explain how it concluded under §112(d) that it is reasonable to ignore all malfunctions in setting emission limits. Even best performing sources have malfunctions and §112(d)(3) requires the EPA to understand the "emission control that is achieved in practice" by such sources.
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 25
Comment: The EPA has not shown how it concluded it did not have to treat emission limits that do not consider malfunctions as "beyond the floor" limits, since the floor must include malfunctions, since such a standard is not achievable by the best performing sources when they malfunction. Rather than supporting the EPA's decision to ignore the fact that malfunction events can lead to higher emissions even at well-operated facilities with the best control equipment, the difficulty in measuring emissions during malfunctions should lead the EPA to conclude that malfunctions are not normal operations and that their authority under CAA §112(h) to prescribe alternative design, equipment, work practice, or operational standards where it is not feasible to set or enforce a numerical emission limit should be employed. The EPA cannot rationally defend its position that malfunctions are normal operations but then ignore those operations in defining the emission limits that are "achieved in practice" by the best performing sources.
If it is possible to gather sufficient representative data reflecting emissions during malfunctions, then the EPA is obligated to consider these data in its calculations of numerical emission limits for steady-state operating conditions (since the EPA asserts malfunctions are not a separate operating mode). If it is not possible to gather sufficient representative data reflecting emissions during malfunctions then the EPA is obligated to treat malfunctions as a separate operating mode. We note that at least for the proposed CO emission limits for most source categories, the EPA has adequate continuous monitoring data to develop alternative standards and thus may have data that includes malfunctions and thus may, as we discuss in Comment II.4.A, actually may be able to establish an emission limitation for CO that does consider malfunctions (i.e., establish the proposed alternative standard as the primary standard for CO for those subcategories.)
Response: See the response to EPA-HQ-OAR-2006-0790-2426-A1, excerpt 21.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 43
Comment: In order to use the affirmative defense, a source is required by proposed §63.7501(b) (and corresponding area rule language) to file a notice of that intent within 2 business days of the start of the event. For many events the information required to decide if there was an exceedance and if the source will claim the affirmative defense will not be available within 2 business days from the start of the event. In order not to forfeit their rights in light of this unreasonable deadline, sources must file an affirmative defense notice for every event whether or not there was an actual exceedance.
Many compliance requirements have long averaging times (30-day averages are commonly specified in this rule). Where the averaging times exceed 2 days, a source often will not even know there was an exceedance in the 2 days after the start of the event. Even with a 1-day averaging time, sources would have to decide in less than 1 day if they plan to use the affirmative defense and make the notice that day. If this notice requirement is maintained the time period for the notice (and for meeting the other affirmative defense requirements) should start with the date that the site determined in accordance with rule requirements that there was an exceedance, rather than from the start of the event.
Under the Refinery Consent Decrees, such notices have typically not been required and lack of these notices does not appear to have had any impact on the use of the affirmative defense or caused any increase in emissions or lessened the response to the event. In fact, if anything, diverting resources from dealing with an event and making reports to authorities associated with immediate response to the event is more likely to have detrimental environmental impacts rather than positive impacts. These notices certainly serve no purpose for immediate response, since notices for those purposes are already required to be provided on a much shorter timeframe to the National Response Center and State and Local Authorities.
Response: The EPA has evaluated the affirmative defense criteria, and is revising both the immediate notification and 45-day malfunction report. Instead, the final rule allows owners or operators seeking to assert an affirmative defense to demonstrate, with all necessary supporting documentation (as was required under the proposed 45-day report), that it has met the affirmative defense criteria by submittal of the affirmative defense report in the first periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If such compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be included in the second compliance, deviation report or excess emission report due after the initial occurrence of the violation of the relevant standard. This change provides sources with sufficient time to demonstrate that they have met the required affirmative defense criteria.
Commenter Name: Matthew Todd
Commenter Affiliation: American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API)
Document Control Number: EPA-HQ-OAR-2006-0790-2482-A2
Comment Excerpt Number: 44
Comment: It is unclear how to handle this notice requirement for multiple exceedances associated with a single event. For instance, a single event could cause a 30-day rolling average to be exceeded for each of 30 days. Are 30 2-day notices required? If this requirement is maintained, the Agency should clarify that only one notice (and one follow-up demonstration letter) is required even if an individual event causes multiple excess emission exceedances.
For these reasons, we recommend the EPA delete the 2-day initial notification requirement as unnecessary, leaving in place only the written demonstration requirement. We believe there is no reason the notification of the decision to use the affirmative defense should be on a different schedule as the supporting information submittal. In fact, the EPA never explains what action they will take as a result of this notice or why they need it, since they will not have any information on which they will evaluate the event and its response until the later submission.
Response: The EPA is removing the requirement to notify the EPA within 2 days of violation of a standard in order to be able to avail themselves to a claim for affirmative defense and instead requires that the affirmative defense report be included in the first periodic compliance, deviation report or excess emission report otherwise required after the initial occurrence of the violation of the relevant standard (which may be the end of any applicable averaging period). If such compliance, deviation report or excess emission report is due less than 45 days after the initial occurrence of the violation, the affirmative defense report may be included in the second compliance, deviation report or excess emission report due after the initial occurrence of the violation of the relevant standard.
Commenter Name: Barry Christensen
Commenter Affiliation: Occidental Chemical Corporation (OCC)
Document Control Number: EPA-HQ-OAR-2006-0790-2435-A1
Comment Excerpt Number: 10
Comment: OCC supports the elimination of the requirement to notify the EPA or the delegated state agency within 2 days of an incident if a party wants to claim an Affirmative Defense. It is not usually possible to conduct a thorough incident review and root cause analysis within 2 days of an incident to determine whether the incident qualifies for an affirmative defense. Therefore, an extended period beyond 2 days is necessary. We support an extension to 45 days, at a minimum, with a provision to request longer if an extended investigation period is needed.
Response: See the response to EPA-HQ-OAR-2006-0790-2482-A2, excerpt 44, regarding 2-day malfunction notice and EPA-HQ-OAR-2006-0790-2482-A2, excerpt 43, regarding 45-day affirmative defense requirements.
Commenter Name: Lorraine Gershman
Commenter Affiliation: American Chemistry Council (ACC)
Document Control Number: EPA-HQ-OAR-2006-0790-2444-A1
Comment Excerpt Number: 29
Comment: Turning to the 2-day notification requirement in §63.11226(b), ACC notes that the EPA recently proposed almost identical affirmative defense requirements in the 2-day notification. It is ACC's understanding that the Agency has been persuaded by comments submitted by ACC and others in industry that the 2-day notification requirement is onerous and burdensome. We also understand that the EPA may be revisiting some of the other requirements in the affirmative defense provisions in order to further reduce the burden on facilities. We therefore request that in its reconsideration the EPA abandon it in the final provisions for area source boilers.
Unlike the 2-day notification which is triggered by the "initial occurrence of the malfunction", the 45-day period for submitting a written report demonstrating that the party qualifies for the affirmative defense commences on the date of "the initial occurrence of the exceedance of the standards." Complying with this timeframe presents several challenges, specifically because most of the content of the report may not be able to be created until the malfunction has ended, which in some cases could be a number of days.
While there is an allowance for requesting and obtaining an extension of the reporting deadline of up to 30 additional days, the owner/operator must comply with the original 45-day requirement unless and until he hears back from the EPA that the extension request is approved. However, there is no requirement for the EPA to act timely in granting or denying an extension request. At a minimum, the rule should provide a timeframe within which the EPA must act on a request and if it fails to do so, the request would be considered granted.
Response: See the response to EPA-HQ-OAR-2006-0790-2482-A2, excerpt 44, regarding 2-day malfunction notice and EPA-HQ-OAR-2006-0790-2482-A2, excerpt 43, regarding 45-day affirmative defense requirements.
Commenter Name: Timothy Serie
Commenter Affiliation: American Coatings Association (ACA)
Document Control Number: EPA-HQ-OAR-2006-0790-2437-A1
Comment Excerpt Number: 18