Environmental Protection Agency (EPA).
Final rule.
On September 13, 2004, under authority of section 112 of the Clean Air Act, EPA promulgated national emission standards for hazardous air pollutants for new and existing industrial/commercial/institutional boilers and process heaters. On June 19, 2007, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded the standards.
In response to the Court's vacatur and remand, EPA is, in this action, establishing emission standards that will require industrial/commercial/institutional boilers and process heaters located at major sources to meet hazardous air pollutants standards reflecting the application of the maximum achievable control technology. This rule protects air quality and promotes public health by reducing emissions of the hazardous air pollutants listed in section 112(b)(1) of the Clean Air Act.
This final rule is effective on May 20, 2011. The incorporation by reference of certain publications listed in this rule is approved by the Director of the Federal Register as of May 20, 2011.
EPA established a single docket under Docket ID No. EPA–HQ–OAR–2002–0058 for this action. All documents in the docket are listed on the
Mr. Brian Shrager, Energy Strategies Group, Sector Policies and Programs Division, (D243–01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; Telephone number: (919) 541–7689; Fax number (919) 541–5450; E-mail address:
The information presented in this preamble is organized as follows:
The regulated categories and entities potentially affected by the final standards include:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc., would be regulated by this action, you should examine the applicability criteria in 40 CFR 63.7485 of subpart DDDDD (National Emission Standards for Hazardous Air Pollutants (NESHAP) for Industrial, Commercial, and Institution Boilers and Process Heaters). If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 63.13 of subpart A (General Provisions).
In addition to being available in the docket, an electronic copy of this action will also be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of the action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
Under the Clean Air Act (CAA) section 307(b)(1), judicial review of this final rule is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit by May 20, 2011. Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. This section also provides a mechanism for us to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of this rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a copy to the person listed in the preceding
Section 112(d) of the CAA requires EPA to set emissions standards for hazardous air pollutants (HAP) emitted by major stationary sources based on the performance of the maximum achievable control technology (MACT). The MACT standards for existing sources must be at least as stringent as the average emissions limitation achieved by the best performing 12 percent of existing sources (for which the Administrator has emissions information) or the best performing 5 sources for source categories with less than 30 sources (CAA section 112(d)(3)(A) and (B)). This level of minimum stringency is called the MACT floor. For new sources, MACT standards must be at least as stringent as the control level achieved in practice by the best controlled similar source (CAA section 112(d)(3)). EPA also must consider more stringent “beyond-the-floor” control options. When considering beyond-the-floor options, EPA must consider not only the maximum degree of reduction in emissions of HAP, but must take into account costs, energy, and nonair environmental impacts when doing so.
With respect to alkylated lead compounds; polycyclic organic matter (POM); hexachlorobenzene; mercury (Hg); polychlorinated biphenyls; 2,3,7,8-tetrachlorodibenzofurans; and 2,3,7,8-tetrachlorodibenzo-p-dioxin, the CAA section 112(c)(6) requires EPA to list categories and subcategories of sources assuring that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant are subject to standards under subsection 112(d)(2) or (d)(4). Standards established under CAA section 112(d)(2) must reflect the performance of MACT. “Industrial Coal Combustion,” “Industrial Oil Combustion,” “Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” are listed as source categories for regulation pursuant to CAA section 112(c)(6) due to emissions of POM and Hg (63 FR 17838, 17848, April 10, 1998). In the documentation for the 112(c)(6) listing, the commercial fuel combustion categories included institutional fuel combustion (“1990 Emissions Inventory of Section 112(c)(6) Pollutants, Final Report,” April 1998).
CAA section 129(a)(1)(A) requires EPA to establish specific performance standards, including emission limitations, for “solid waste incineration units” generally, and, in particular, for “solid waste incineration units combusting commercial or industrial waste” (section 129(a)(1)(D)). Section 129 defines “solid waste incineration unit” as “a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments or the general public.”
In
CAA section 129 covers any facility that combusts any solid waste; CAA section 129(g)(6) directs the Agency to the Resource Conservation and Recovery Act (RCRA) in terms of the definition of solid waste. In this
The solid waste definitional rulemaking under RCRA is being finalized in a parallel action and is relevant to this proceeding because some industrial, commercial, or institutional boilers and process heaters combust secondary materials as alternative fuels. If industrial, commercial, or institutional boilers or process heaters combust secondary materials that are solid waste under the final definitional rule, those units would be subject to emission standards issued under section 129. The units subject to this final rule include those industrial, commercial, or institutional boilers and process heaters that do not combust solid waste, as well as boilers and process heaters that combust solid waste but qualify for one of the statutory exclusions contained in section 129(g)(1). EPA recognizes that it has imperfect information on the exact nature of the secondary materials which boilers and process heaters combust, including, for example, how much processing of such materials occurs, if any. We used the information currently available to the Agency to determine which units combust solid waste materials and, therefore, are subject to CAA section 129, and which units do not combust solid waste (or qualify for an exclusion from section 129) and, therefore, are subject to CAA section 112.
A description of EPA's information collection efforts and a description of the development of EPA's proposed response to the
This final rule addresses the combustion of non-solid waste materials in boilers and process heaters located at major sources of HAP. If an owner or operator of an affected source subject to these standards were to start combusting a solid waste (as defined by the Administrator under RCRA), the affected source would cease to be subject to this action and would instead be subject to regulation under CAA section 129. A rulemaking under CAA section 129 is being finalized in a parallel action and is relevant to this action because it would apply to boilers and process heaters that combust any solid waste and are located at a major source. In this final boiler rulemaking, EPA is providing specific language to ensure clarity regarding the necessary steps that must be followed for combustion units that begin combusting non-hazardous solid waste materials and become subject to section 129 standards instead of section 112 standards or combustion units that discontinue combustion of non-hazardous solid waste materials and become subject to section 112 standards instead of section 129 standards.
In addition to combustion units that may switch between the section 112 boiler standards and the section 129 incinerator standards, there are certain instances where boilers and process heaters are already regulated under other MACT standards. In such cases, the boilers and process heaters that are already subject to another MACT standard are not subject to the boiler standards.
In 1986, EPA codified new source performance standards (NSPS) for industrial boilers (40 CFR part 60, subparts Db and Dc) and portions of those standards were revised in 1999 and 2006. The NSPS regulates emissions of particulate matter (PM), sulfur dioxide (SO
This final rule protects air quality and promotes the public health by reducing emissions of some of the HAP listed in CAA section 112(b)(1). As noted above, emissions data collected during development of the rule show that hydrogen chloride (HCl) emissions represent the predominant HAP emitted by industrial, commercial, and institutional (ICI) boilers, accounting for 69 percent of the total HAP emissions.
EPA estimated the costs and benefits associated with the final rule, and the results are shown in the following table. For more information on the costs and benefits for this rule,
This section summarizes the requirements of this action. Section IV below provides a summary of the significant changes to this final rule following proposal.
ICI boilers and process heaters located at major sources of HAP are regulated by this final rule. Waste heat boilers and boilers and process heaters that combust solid waste, except for specific exceptions to the definition of a solid waste incineration unit outlined in section 129(g)(1), are not subject to this final rule.
This final rule affects industrial boilers, institutional boilers, commercial boilers, and process heaters. A process heater is defined as a unit in which the combustion gases do not directly come into contact with process material or gases in the combustion chamber (
This final rule regulates HCl (as a surrogate for acid gas HAP), PM (as a surrogate for non-Hg HAP metals), carbon monoxide (CO) (as a surrogate for non-dioxin/furan organic HAP), Hg, and dioxin/furan emissions from boilers and process heaters.
You must meet the emission limits presented in Table 1 of this preamble. This final rule includes 15 subcategories. Emission limits are established for new and existing sources for each of the subcategories, which are based on unit design.
Metallic HAP (regulated using PM as a surrogate), HCl, and Hg are “fuel-based pollutants” that are a direct result of contaminants in the fuels that are combusted. For those pollutants, if your new or existing unit combusts at least 10 percent solid fuel on an annual basis, your unit is subject to emission limits that are based on data from all of the solid fuel-fired combustor designs. If your new or existing unit combusts at least 10 percent liquid fuel and less than 10 percent solid fuel and your facility is located in the continental United States, your unit is subject to the liquid fuel emission limits for the fuel-based pollutants. If your facility is located outside of North America (referred to as a non-continental unit for the remainder of the preamble and in this final rule) and your new or existing unit combusts at least 10 percent liquid fuel and less than 10 percent solid fuel, your unit is subject to the non-continental liquid fuel emission limits for the fuel-based pollutants. Finally, for the fuel-based pollutants, if your unit combusts gaseous fuel that does not qualify as a “Gas 1” fuel, your unit is subject to the Gas 2 emission limits in Table 1 of this preamble. If your unit is a Gas 1 unit (that is, it combusts only natural gas, refinery gas, or equivalent fuel (other gas that qualifies as Gas 1 fuel)), with limited exceptions for gas curtailments and emergencies, your unit is subject to a work practice standard that requires an annual tune-up in lieu of emission limits.
For the combustion-based pollutants, CO (used as a surrogate for non-dioxin organic HAP) and dioxin/furan, your unit is subject to the emission limits for the design-based subcategories shown in Table 1 of this preamble. If your new or existing boiler or process heater burns at least 10 percent biomass on an annual average heat input
The emission limits in Table 1 apply only to new and existing boilers and process heaters that have a designed heat input capacity of 10 million British thermal units per hour (MMBtu/hr) or greater. We also are providing optional output-based standards in this final rule. Pursuant to CAA section 112(h), we are requiring a work practice standard for four particular classes of boilers and process heaters: New and existing units that have a designed heat input capacity of less than 10 MMBtu/hr, and new and existing units in the Gas 1 (natural gas/refinery gas) subcategory and in the metal process furnaces subcategory. The work practice standard for these boilers and process heaters requires the implementation of a tune-up program as described in section III.F of this preamble.
We are also finalizing a beyond-the-floor standard for all existing major source facilities having affected boilers or process heaters that would require the performance of a one-time energy assessment, as described in section III.F of this preamble, by qualified personnel, on the affected boilers and facility to identify any cost-effective energy conservation measures.
Consistent with
EPA has revised this final rule to require sources to meet a work practice standard, which requires following the manufacturer's recommended procedures for minimizing periods of startup and shutdown, for all subcategories of new and existing boilers and process heaters (that would otherwise be subject to numeric emission limits) during periods of startup and shutdown. As discussed in Section V.F of this preamble, we considered whether performance testing, and therefore, enforcement of numeric emission limits, would be practicable during periods of startup and shutdown. EPA determined that it is not technically feasible to complete stack testing—in particular, to repeat the multiple required test runs—during periods of startup and shutdown due to physical limitations and the short duration of startup and shutdown periods. Therefore, we have established the separate work practice standard for periods of startup and shutdown.
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * * ”(40 CFR 63.2). EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. In
Further, it is reasonable to interpret section 112(d) as not requiring EPA to account for malfunctions in setting emissions standards. For example, we note that Section 112 uses the concept of “best performing” sources in defining MACT, the level of stringency that major source standards must meet. Applying the concept of “best performing” to a source that is malfunctioning presents significant difficulties. The goal of best performing sources is to operate in such a way as to avoid malfunctions of their units.
Moreover, even if malfunctions were considered a distinct operating mode, we believe it would be impracticable to take malfunctions into account in setting CAA section 112(d) standards for boilers and process heaters. As noted above, by definition, malfunctions are sudden and unexpected events and it would be difficult to set a standard that takes into account the myriad different types of malfunctions that can occur across all sources in the category. Moreover, malfunctions can vary in frequency, degree, and duration, further complicating standard setting.
In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 63.2 (definition of malfunction).
Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. (
We are requiring that the owner or operator of a new or existing boiler or process heater must conduct performance tests to demonstrate compliance with all applicable emission limits. Affected units would be required to conduct the following compliance tests where applicable:
(1) Conduct initial and annual stack tests to determine compliance with the PM emission limits using EPA Method 5 or 17.
(2) Conduct initial and annual stack tests to determine compliance with the Hg emission limits using EPA method 29 or ASTM–D6784–02 (Ontario Hydro Method).
(3) Conduct initial and annual stack tests to determine compliance with the HCl emission limits using EPA Method 26A or EPA Method 26 (if no entrained water droplets in the sample).
(4) Use EPA Method 19 to convert measured concentration values to pound per million Btu values.
(5) Conduct initial and annual test to determine compliance with the CO emission limits using EPA Method 10.
(6) Conduct initial test to determine compliance with the dioxin/furan emission limits using EPA Method 23.
As part of the initial compliance demonstration, we are requiring that you monitor specified operating parameters during the initial performance tests that you would conduct to demonstrate compliance with the PM, Hg, HCl, CO, and dioxin/furan emission limits. You must calculate the average hourly parameter values measured during each test run over the three run performance test. The lowest or highest hourly average of the three test run values (depending on the parameter measured) for each applicable parameter would establish the site-specific operating limit. The applicable operating parameters for which operating limits would be required to be established are based on the emissions limits applicable to your unit as well as the types of add-on controls on the unit. The following is a summary of the operating limits that we are requiring to be established for the various types of the following units:
(1) For boilers and process heaters with wet PM scrubbers, you must measure pressure drop and liquid flow rate of the scrubber during the performance test, and calculate the average hourly values during each test run. The lowest hourly average determined during the three test runs establishes your minimum site-specific pressure drop and liquid flow rate operating levels.
(2) If you are complying with an HCl emission limit using a wet acid gas scrubber, you must measure pH and liquid flow rate of the scrubber sorbent during the performance test, and calculate the average hourly values during each test run of the performance test for HCl and determine the lowest hourly average of the pH and liquid flow rate for each test run for the performance test. This establishes your minimum pH and liquid flow rate operating limits.
(3) For boilers and process heaters with sorbent injection, you must measure the sorbent injection rate for each acid gas sorbent used during the performance tests for HCl and for activated carbon for Hg and dioxin/furan and calculate the hourly average for each sorbent injection rate during each test run. The lowest hourly average measured during the performance tests becomes your site-specific minimum sorbent injection rate operating limit. If different acid gas sorbents and/or injection rates are used during the HCl test, the lowest hourly average value for each sorbent becomes your site-specific operating limit. When your unit operates at lower loads, multiply your sorbent injection rate by the load fraction (operating heat input divided by the average heat input during your last compliance test for the appropriate pollutant) to determine the required parameter value.
(4) For boilers and process heaters with fabric filters not subject to PM Continuous Emission Monitoring System (CEMS) or continuous compliance with an opacity limit (
(5) For boilers and process heaters with electrostatic precipitators (ESP) not subject to PM CEMS or continuous compliance with an opacity limit (
(6) For boilers and process heaters that choose to demonstrate compliance with the Hg emission limit on the basis of fuel analysis, you are required to measure the Hg content of the inlet fuel that was burned during the Hg performance test. This value is your maximum fuel inlet Hg operating limit.
(7) For boilers and process heaters that choose to demonstrate compliance with the HCl emission limit on the basis of fuel analysis, you are required to measure the chlorine content of the inlet fuel that was burned during the HCl performance test. This value is your maximum fuel inlet chlorine operating limit.
(8) For boilers and process heaters that are subject to a CO emission limit and a dioxin/furan emission limit, you are required to measure the oxygen concentration in the flue gas during the initial CO and dioxin/furan performance test. The lowest hourly average oxygen concentration measured during the most recent performance test is your operating limit, and your unit must operate at or above your operating limit on a 12-hour block average basis.
These operating limits do not apply to owners or operators of boilers or process heaters having a heat input capacity of less than 10 MMBtu/hr or boilers or process heaters of any size which combust natural gas or other clean gas, metal process furnaces, or limited use units, as discussed in section IV.D.3 of this preamble. Instead, owners or operators of such boilers and process heaters shall submit to the delegated authority or EPA, as appropriate, if requested, documentation that a tune-up meeting the requirements of this final rule was conducted. In order to comply with the work practice standard, a tune-up procedure must include the following:
(1) Inspect the burner, and clean or replace any components of the burner as necessary,
(2) Inspect the flame pattern and make any adjustments to the burner necessary to optimize the flame pattern consistent with the manufacturer's specifications,
(3) Inspect the system controlling the air-to-fuel ratio, and ensure that it is correctly calibrated and functioning properly,
(4) Optimize total emissions of CO consistent with the manufacturer's specifications,
(5) Measure the concentration in the effluent stream of CO in parts per million by volume dry (ppmvd), before and after the adjustments are made,
(6) Submit to the delegated authority or EPA an annual report containing the concentrations of CO in the effluent stream in ppmvd, and oxygen in percent dry basis, measured before and after the adjustments of the boiler, a description of any corrective actions taken as a part of the combustion adjustment, and the type and amount of fuel used over the 12 months prior to the annual adjustment.
Further, all owners or operators of major source facilities having boilers and process heaters subject to this final rule are required to submit to the delegated authority or EPA, as appropriate, documentation that an energy assessment was performed, by a qualified energy assessor, and the cost-effective energy conservation measures indentified.
To demonstrate continuous compliance with the emission limitations, we are requiring the following:
(1) For units combusting coal, biomass, or residual fuel oil (
(2) For units combusting coal, biomass, or residual oil with heat input capacities of 250 MMBtu/hr or greater, we are requiring that PM CEMS be installed and operated and that PM levels (monthly average) be maintained below the applicable PM limit.
(3) For boilers and process heaters with wet PM scrubbers, we are requiring that you monitor pressure drop and liquid flow rate of the scrubber and maintain the 12-hour block averages at or above the operating limits established during the performance test to demonstrate continuous compliance with the PM emission limits.
(4) For boilers and process heaters with wet acid gas scrubbers, you must monitor the pH and liquid flow rate of the scrubber and maintain the 12-hour block average at or above the operating limits established during the most recent performance test to demonstrate continuous compliance with the HCl emission limits.
(5) For boilers and process heaters with dry scrubbers, we are requiring that you continuously monitor the sorbent injection rate and maintain it at or above the operating limits, which include an adjustment for load, established during the performance tests. When your unit operates at lower loads, multiply your sorbent injection rate by the load fraction (operating load divided by the load during your last compliance test for the appropriate pollutant) to determine the required parameter value.
(6) For boilers and process heaters having heat input capacities of less than 250 MMBtu/hr with an ESP, we are requiring that you monitor the voltage and current of the ESP collection plates and maintain the 12-hour block total secondary electric power averages at or above the operating limits established during the Hg or PM performance test.
(7) For units that choose to comply with either the Hg emission limit or the HCl emission limit based on fuel analysis rather than on performance testing, you must maintain monthly fuel records that demonstrate that you burned no new fuels or fuels from a new supplier such that the Hg content or the chlorine content of the inlet fuel was maintained at or below your maximum fuel Hg content operating limit or your chlorine content operating limit set during the performance tests. If you plan to burn a new fuel, a fuel from a new mixture, or a new supplier's fuel that differs from what was burned during the initial performance tests, then you must recalculate the maximum Hg input and/or the maximum chlorine input anticipated from the new fuels based on supplier data or own fuel analysis, using the methodology specified in Table 6 of this final rule. If the results of recalculating the inputs exceed the average content levels established during the initial test then, you must conduct a new performance test(s) to demonstrate continuous compliance with the applicable emission limit.
(8) For all boilers and process heaters, except those that are exempt from the incinerator standards under section 129 because they are qualifying facilities burning a homogeneous waste stream, you must maintain records of fuel use that demonstrate that your fuel was not solid waste.
(9) For boilers and process heaters with an oxygen monitor installed for this final rule, you must maintain an oxygen concentration level, on a 12-hour block average basis, no less than lowest hourly average oxygen concentration measured during the most recent performance test.
(10) For boilers and process heaters that demonstrate compliance using a performance test. You must maintain an operating load no greater than 110 percent of the operating load established during the performance test.
If an owner or operator would like to use a control device other than the ones specified in this section to comply with this final rule, the owner/operator should follow the requirements in 40 CFR 63.8(f), which presents the procedure for submitting a request to the Administrator to use alternative monitoring.
All new and existing sources are required to comply with certain requirements of the General Provisions (40 CFR part 63, subpart A), which are identified in Table 10 of this final rule. The General Provisions include specific requirements for notifications, recordkeeping, and reporting.
Each owner or operator is required to submit a notification of compliance status report, as required by § 63.9(h) of the General Provisions. This final rule requires the owner or operator to include in the notification of compliance status report certifications of compliance with rule requirements.
Semiannual compliance reports, as required by § 63.10(e)(3) of subpart A, are required only for semiannual reporting periods when a deviation from any of the requirements in the rule occurred, or any process changes occurred and compliance certifications were reevaluated.
This final rule requires records to demonstrate compliance with each emission limit and work practice standard. These recordkeeping requirements are specified directly in the General Provisions to 40 CFR part
Records of either continuously monitored parameter data for a control device if a device is used to control the emissions or CEMS data are required.
You are required to keep the following records:
(1) All reports and notifications submitted to comply with this final rule.
(2) Continuous monitoring data as required in this final rule.
(3) Each instance in which you did not meet each emission limit and each operating limit (
(4) Daily hours of operation by each source.
(5) Total fuel use by each affected source electing to comply with an emission limit based on fuel analysis for each 30-day period along with a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel.
(6) Calculations and supporting information of chlorine fuel input, as required in this final rule, for each affected source with an applicable HCl emission limit.
(7) Calculations and supporting information of Hg fuel input, as required in this final rule, for each affected source with an applicable Hg emission limit.
(8) A signed statement, as required in this final rule, indicating that you burned no new fuel type and no new fuel mixture or that the recalculation of chlorine input demonstrated that the new fuel or new mixture still meets chlorine fuel input levels, for each affected source with an applicable HCl emission limit.
(9) A signed statement, as required in this final rule, indicating that you burned no new fuels and no new fuel mixture or that the recalculation of Hg fuel input demonstrated that the new fuel or new fuel mixture still meets the Hg fuel input levels, for each affected source with an applicable Hg emission limit.
(10) A copy of the results of all performance tests, fuel analysis, opacity observations, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this final rule.
(11) A copy of your site-specific monitoring plan developed for this final rule as specified in 63 CFR 63.8(e), if applicable.
We are also requiring that you submit the following reports and notifications:
(1) Notifications required by the General Provisions.
(2) Initial Notification no later than 120 calendar days after you become subject to this subpart, even if you submitted an initial notification for the vacated standards that were promulgated in 2004.
(3) Notification of Intent to conduct performance tests and/or compliance demonstration at least 60 calendar days before the performance test and/or compliance demonstration is scheduled.
(4) Notification of Compliance Status 60 calendar days following completion of the performance test and/or compliance demonstration.
(5) Compliance reports semi-annually.
EPA must have performance test data and other compliance data to conduct effective reviews of CAA Section 112 and 129 standards, as well as for many other purposes including compliance determinations, emissions factor development, and annual emissions rate determinations. In conducting these required reviews, we have found it ineffective and time consuming not only for us but also for regulatory agencies and source owners and operators to locate, collect, and submit emissions test data because of varied locations for data storage and varied data storage methods. One improvement that has occurred in recent years is the availability of stack test reports in electronic format as a replacement for cumbersome paper copies.
In this action, we are taking a step to improve data accessibility. Owners and operators of ICI boilers located at major source facilities will be required to submit to EPA an electronic copy of reports of certain performance tests required under this final rule. Data will be collected through an electronic emissions test report structure called the Electronic Reporting Tool (ERT) that will be used by the staff as part of the emissions testing project. The ERT was developed with input from stack testing companies who generally collect and compile performance test data electronically and offices within State and local agencies which perform field test assessments. The ERT is currently available, and access to direct data submittal to EPA's electronic emissions database (WebFIRE) is scheduled to become available by December 31, 2011.
The requirement to submit source test data electronically to EPA will not require any additional performance testing and will apply to those performance tests conducted using test methods that are supported by ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. The Web site listed below contains a listing of the pollutants and test methods supported by ERT. In addition, when a facility submits performance test data to WebFIRE, there will be no additional requirements for emissions test data compilation. Moreover, we believe industry will benefit from development of improved emissions factors, fewer follow-up information requests, and better regulation development as discussed below. The information to be reported is already required for the existing test methods and is necessary to evaluate the conformance to the test method.
One major advantage of collecting source test data through the ERT is that it provides a standardized method to compile and store much of the documentation required to be reported by this final rule while clearly stating what testing information we require. Another important benefit of submitting these data to EPA at the time the source test is conducted is that it will substantially reduce the effort involved in data collection activities in the future. Specifically, because EPA would already have adequate source category data to conduct residual risk assessments or technology reviews, there would likely be fewer or less substantial data collection requests (e.g., CAA Section 114 letters). This results in a reduced burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and EPA (in terms of preparing and distributing data collection requests).
State/local/Tribal agencies may also benefit in that their review may be more streamlined and accurate because the States will not have to re-enter the data to assess the calculations and verify the data entry. Finally, another benefit of submitting these data to WebFIRE electronically is that these data will improve greatly the overall quality of the existing and new emissions factors by supplementing the pool of emissions test data upon which the emissions factor is based and by ensuring that data are more representative of current industry operational procedures. A common complaint we hear from industry and regulators is that emissions factors are outdated or not representative of a particular source category. Receiving and incorporating
As mentioned earlier, the electronic data base that will be used is EPA's WebFIRE, which is a database accessible through EPA's TTN. The WebFIRE database was constructed to store emissions test and other data for use in developing emissions factors. A description of the WebFIRE data base can be found at
Source owners and operators will be able to transmit data collected via the ERT through EPA's Central Data Exchange (CDX) network for storage in the WebFIRE data base. Although ERT is not the only electronic interface that can be used to submit source test data to the CDX for entry into WebFIRE, it makes submittal of data very straightforward and easy. A description of the ERT can be found at
Source owners and operators must register with the CDX system to obtain a user name and password before being able to submit data to the CDX. The CDX registration page can be found at:
Since proposal, several changes to the applicability of this final rule have been made. First, at proposal, we excluded all units that combust solid waste from the standards, but we have extended the coverage of this final rule to boilers and process heaters that combust solid waste but are exempt, by statute, from section 129 incinerator rules because they are qualifying small power producers or cogeneration units that combust a homogeneous waste stream. This final rule continues to exclude other waste burning units. This is a clarifying change that is consistent with the intent of the proposed rule to establish emissions standards for all boilers and process heaters that are not solid waste incineration units subject to regulation under section 129.
The proposed rule definition of coal was revised to include all types of fossil-based fuels in the coal definition. The final coal definition is: “
The proposed rule included a definition of waste heat boiler that excluded from the definition units with supplemental burners that are designed to supply 50 percent or more of the total rated heat input capacity. The final definition was revised to include all waste heat boilers. The final definition is: “Waste heat boiler means a device that recovers normally unused energy and converts it to usable heat. Waste heat boilers are also referred to as heat recovery steam generators.” Similarly, the waste heat process heater definition was revised to read as follows: “Waste heat process heater means an enclosed device that recovers normally unused energy and converts it to usable heat. Waste heat process heaters are also referred to as recuperative process heaters.” These changes were made in order to exempt the types of units intended at proposal.
The proposed rule exempted blast furnace gas fuel-fired boiler or process heaters, and defined these units as units combusting 90 percent or more of its total heat input from blast furnace gas. We have changed the requirement to 90 percent or more of its total volume of gas in this final rule. This change was made so that the units that were intended to be exempted from this final rule would be exempted. The wording of the proposed exemption did not exempt units that were intended to be exempted because the heating value of blast furnace gas is not as high as that of natural gas.
The proposed rule exempted units that are an affected source in another MACT standard. We amended this language to include any unit that is part of the affected source subject to another MACT standard. We also exempted any unit that is used as a control device to comply with another MACT standard, provided that at least 50 percent of the heat input is provided by the gas stream that is regulated under another MACT standard. This change was made in order to encourage the recovery of energy from high heating value gases that would otherwise be flared.
In the proposed rule, for the fuel-dependent HAP (metals, Hg, acid gases), we identified the following five basic unit types as subcategories: (1) Units designed to burn coal, (2) units designed to burn biomass, (3) units designed to burn liquid fuel, (4) units designed to burn natural gas/refinery gas, and (5) units designed to burn other process gases. In this final rule, for fuel-dependent HAP, we combined the subcategories for units designed to combust coal and biomass into a subcategory for units designed to burn solid fuels. We changed the subcategory for units designed to burn natural gas/refinery gas to a subcategory for units that burn natural gas, refinery gas, and other clean gas. We also added subcategories for non-continental liquid units and limited-use units.
As described in the preamble to the proposed rule, within the basic unit types there are different designs and combustion systems that, while having a minor effect on fuel-dependent HAP emissions, have a much larger effect on pollutants whose emissions depend on the combustion conditions in a boiler or process heater. In the case of boilers and process heaters, the combustion-related pollutants are the organic HAP. In the proposed rule, we identified the
The proposed rule included numerical emission limits for PM, Hg, HCl, CO, and dioxin/furan, and limits for those same pollutants are included in this final rule. Unlike the proposed rule, we included a compliance alternative in the final rule to allow owners and operators of existing affected sources to demonstrate compliance on an output-basis instead of on a heat input basis. Compliance with the alternate output-based emission limits would require measurement of boiler operating parameters associated with the mass rate of emissions and energy outputs. If you elect to comply with the alternate output-based emission limits, you must use equations provided in the final rule to demonstrate that emissions from the applicable units do not exceed the output-based emission limits specified in the final rule. If you use this compliance alternative using the emission credit approach, you must also establish a benchmark, calculate and document the emission credits generated from energy conservation measures implemented, and develop and submit the implementation plan no later than 180 days before the date that the facility intends to demonstrate compliance.
This final rule includes work practice standards for most of the same units for which we proposed work practice standards, including new and existing units in the Gas 1 subcategory, existing units with heat input capacity less than 10 MMBtu/hr, and new and existing metal process furnaces. In addition to those subcategories for which we proposed work practices, this final rule includes work practices for all units during periods of startup and shutdown, new units with heat input capacity less than 10 MMBtu/hr, limited use units, and units combusting other clean gases. Other clean gases are gases, other than natural gas and refinery gas (as defined in this final rule), that meet contaminant level specifications that are provided in the final rule.
In this final rule, we have expanded the definition of energy assessment with respect to the requirements of Table 3 of this final rule, by providing a duration for performing the energy assessment and defining the evaluation requirements for each boiler system and energy use system. These requirements are based on the total annual heat input to the affected boilers and process heaters.
This final rule requires an energy assessment for facilities with affected boilers and process heaters using less than 0.3 trillion Btu per year (TBtu/y) heat input to be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the energy output from these units must be evaluated to identify energy savings opportunities within the limit of performing a one day energy assessment. An energy assessment for a facility with affected boilers and process heaters using 0.3 to 1 TBtu/year must be three days in length maximum. From these boilers, the boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated, within the limit of performing a three day energy assessment. For facilities with affected boilers and process heaters using greater than 1 TBtu/year heat input, the energy assessment must address the boiler system and any energy use system accounting for at least 20 percent of the energy output to identify energy savings opportunities.
The expanded definition for energy assessment clarifies the duration and requirements for each energy assessment for various units based on energy use. We have also added a definition for steam and process heating systems to clarify the components for each boiler system which must be considered during the energy assessment, including elements such as combustion management, thermal energy recovery, energy resource selection, and the steam end-use management of each affected boiler.
Lastly, we have clarified the requirement in Table 3 to evaluate facility energy management practices as part of the energy assessment and a definition of an energy management program was added. The use of the ENERGY STAR Facility Energy Assessment Matrix as part of this review is recommended, but it was removed as a requirement in Table 3. The definition of an energy management program added to the rule is consistent with the ENERGY STAR Guidelines for Energy Management that can be referenced for further guidance. ENERGY STAR provides a variety of tools and resources that support energy management programs. For more information, visit
For startup, shutdown, and malfunction (SSM), the requirements have changed since proposal. For periods of startup and shutdown, EPA is finalizing work practice standards, which require following manufacturers specifications for minimizing periods of startup and shutdown, in lieu of numeric emission limits. For malfunctions, EPA added affirmative defense language to this final rule for exceedances of the numerical emission limits that are caused by malfunctions.
The first significant change to the testing and initial compliance requirements is that units greater than 100 MMBtu/hr must comply with the CO limits using a stack test rather than CO CEMS. EPA also added optional output-based limits that promote energy efficient boiler operation. Another significant change is that for units combusting gaseous fuels other than natural gas or refinery gas, in order to qualify for the Gas 1 subcategory work practice standard, the gases that will be combusted must be certified to meet the contaminant levels specified for Hg and hydrogen sulfide (H
The only significant change to the continuous compliance requirements is for monitoring of CO. Rather than using CO CEMS, as proposed, units will be required to continuously monitor and record the oxygen level in their flue gas during the initial compliance test and establish an operating limit that requires that the unit operate at an oxygen percentage of at least 90 percent of the operating limit on a 12-hour block average basis. Units will be required to continuously monitor oxygen to ensure continuous compliance.
In this final action, we are requiring that owners or operators of boilers that choose to commence or recommence combustion of solid waste must provide 30 days notice of the date upon which the source will commence or recommence combustion of solid waste. The notification must identify the name of the owner or operator of the affected source, the location of the source, the boiler(s) or process heater(s) that will commence burning solid waste, and the date of the notice; the currently applicable subcategory under this subpart; the date on which the unit became subject to the currently applicable emission limits; and the date upon which the unit will commence or recommence combusting solid waste.
For each limited-use unit, owners or operators must monitor and record the operating hours on a monthly basis for the unit. This will ensure that units qualify for the limited-use subcategory.
We also added a requirement that sources keep records of operating load in order to demonstrate continuous compliance with the operating load operating limit.
When malfunctions occur, owners or operators must keep records of the occurrence and duration of each malfunction of the boiler or process heater, or of the associated air pollution control and monitoring equipment, as well as records of actions taken during periods of malfunction to minimize emissions, including corrective actions to restore the malfunctioning boiler or process heater, air pollution control, or monitoring equipment to its normal or usual manner of operation.
Finally, for facilities that elect to use emission credits from energy conservation measures to demonstrate compliance, owners or operators must keep a copy of the Implementation Plan required in this rule and copies of all data and calculations used to establish credits.
In this final action, we are making a number of technical corrections and clarifications to subpart DDDDD. These changes improve the clarity and procedures for implementing the emission limitations to affected sources. We are also clarifying several definitions to help affected sources determine their applicability. We have modified some of the regulatory language that we proposed based on public comments.
In several places throughout the subpart, including the associated tables, we have corrected the cross-references to other sections and paragraphs of the subpart.
We revised 40 CFR 63.7485 to clarify that for the purposes of subpart DDDDD, a major source of HAP is as defined in 40 CFR 63.2, except that for oil and gas facilities a major source of HAP is as defined in 40 CFR 63.761 (40 CFR part 63, subpart HH, National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities). This change was made because facilities subject to subpart HH contain units that will be subject to subject DDDDD.
The word “specifically” was removed from § 63.7491(i) in order to clarify the exclusion for boilers and process heaters regulated by other HAP regulations.
We revised 40 CFR 63.7505(c) to clarify that performance testing is needed only if a boiler or process heater is subject to an applicable emission limit listed in Table 2.
We made several changes to the initial compliance demonstration requirements. We revised 40 CFR 63.7510(a) to clarify that sources using a second fuel only for start up, shut down, and/or transient flame stability are still considered to be sources using a single fuel. We revised 40 CFR 63.7510(c) to clarify that boilers and process heaters with a heat input capacity below 10 MMBtu per hour are not required to conduct a performance test for CO because they are not subject to a numerical emission limit for CO. In 40 CFR 63.7510(d), we clarified that boilers and process heaters that use a CEMS for PM are exempt from the performance testing and operating limit requirements specified in 40 CFR 63.7510(a) because the CEMS demonstrates continuous compliance. We revised 40 CFR 63.7510(c) and (d) to clarify that compliance for those provisions does not apply to units burning natural gas or refinery gas.
We changed the performance testing requirements in 40 CFR 63.7515(b), (c), and (d) to state that performance testing for a given pollutant may be performed every 3 years, instead of annually, if measured emissions during 2 consecutive annual performance tests are less than 75 percent of the applicable emission limit.
In 40 CFR 63.7515(e), we clarified that boilers and process heaters with a heat input capacity below 10 MMBtu per hour are required to conduct tune-ups biennially, while larger natural gas and other Gas 1 units are required to conduct annual tune-ups.
We revised 40 CFR 63.7515(f) to clarify that monthly fuel analyses are required only for fuel types for which emission limits apply.
We made several changes to 40 CFR 63.7520 to clarify the performance testing requirements. We revised paragraph (c) to clarify that performance tests must be conducted at representative operating load conditions, instead of at the maximum normal operating load. Language was also added to this section and to Table 4 to subpart DDDDD to establish an operating limit for the boiler or process heater and clarified that the operating load must not exceed 110 percent of the load used during the performance test. We revised paragraph (d) to clarify that compliance with operating limits using a continuous parameter monitoring systems are based on the 4-hour block averages of the data collected by the continuous parameter monitoring systems.
In 40 CFR 63.7522, we made several changes to the provisions for using emissions averaging. In paragraph (a), we clarified that average emissions must be “* * * not more than 90 percent of the applicable emission limit.” We also added a sentence to clarify that new boilers and process heaters may not be included in an emissions average used to demonstrate compliance according to that section. Equations 2 and 3 were revised to correct the discount factor from 0.9 to 1.1 because the actual emissions are multiplied by the discount factor. We also revised paragraph (c) to clarify that the deadline to establish emission caps to demonstrate compliance with the emission averaging option is 60 days after the publication of the final rule as referenced in paragraph (g)(2)(i), and revised paragraph (g) to clarify that facilities are required to submit an implementation plan as referenced in § 63.7522(g)(1).
We made several clarifying changes to the monitoring requirements in 40 CFR 63.7525. We revised paragraph (a) to clarify that only boilers or process heaters subject to a CO limit are required to install a continuous oxygen monitoring system. We adopted language from § 63.7525(d)(2) to § 63.7525(a)(6) to clarify what constitutes a deviation. In 40 CFR 63.7525(c)(7), we clarified that owners/operators are required to determine 6-minute and daily block averages excluding data from periods in which the continuous opacity monitoring system is out of control.
The initial compliance provisions in 40 CFR 63.7530(b) were revised to clarify that facilities are exempted from the initial compliance requirements of conducting a fuel analysis if only one
We revised 40 CFR 63.7540(a)(9)(i) to remove the reference to Procedure 2 in Appendix F to 40 CFR part 60; Procedure 2 specifies the ongoing QA/QC requirements for PM CEMS after certification and is correctly referenced in paragraph (a)(9)(iii) of that section.
We revised the notification requirements in 40 CFR 63.7545 to clarify that notifications should be submitted to the delegated authority, and to clarify that the Notification of Intent to conduct a performance test must be submitted 60 days before the test is scheduled to begin.
The reporting requirements originally in 40 CFR 63.7550(g) and (g)(1) through (g)(3) are more correctly considered notification requirements, so they were moved to § 63.7545(e)(8).
In response to comments asking for clarification, we have added definitions to 40 CFR 63.7575 for “Calendar year,” “Operating day,” “Refinery gas,” and “Valid hourly average.” We have also revised several definitions in that section based on public comments. For example, we revised the definition of “boiler” to describe what is meant by the term “controlled flame combustion” as used in that definition; revised “metal processing furnace” to include homogenizing furnaces; revised the definitions of “dry scrubber,” “electrostatic precipitator,” and “fabric filter,” to indicate that these are all considered dry control systems. The definition of “wet scrubber” was revised to clarify that, “A wet scrubber creates an aqueous stream or slurry as a byproduct of the emissions control process.”
The definition of “Tune-up” was removed from 40 CFR 63.7575 because all of the requirements for a tune-up are provided in the rule language at 40 CFR 63.7540(a)(10), making the definition unnecessary.
Several of the definitions in 40 CFR 64.7575 were revised to clarify the types of equipment to which different standards apply. For example, the definition of “Temporary boiler” was revised to include additional criteria that could be used to identify temporary boilers from permanently installed units. The definition of “Unit designed to burn oil subcategory” was revised to exclude periods of gas curtailment and gas supply emergency from the 48-hour limit on liquid fuel combustion. Likewise, the definition of “Period of natural gas curtailment” was revised to clarify that contractual agreements for curtailed gas usage or fluctuations in price do not constitute periods of gas curtailment under the scope of this regulation. The definition of “Waste heat boiler” was revised to remove the criteria that 50 percent of total rated heat input capacity had to be from waste gases. We also revised the definition of “Natural gas” to include gas derived from naturally occurring mixtures found in geological formations as long as the principal constituent is methane, consistent with the definition provided in 40 CFR part 60 subpart Db. A definition of propane, was also incorporated into the definition of natural gas.
Several changes were made to the tables to subpart DDDDD as a result of the public comments on the proposed rule.
In Tables 1 and 2, the references to “Other gases” were revised to “Gas 2” to clarify that units burning natural gas, refinery gas, or other clean gases are not subject to emission limitations. The emission limits in these two tables were also revised to include averaging times for those pollutants for which measurements are taken with a continuous emission monitor.
In Table 3, the references to “§ 63.11202 and § 63.11203” in the table heading were revised to correctly reference 40 CFR 63.7540. The text in the first and second column of Table 3 was revised to clarify that the requirements apply to both boilers and process heaters. A new row was added to clarify that work practice standards apply to new boilers or process heaters with a rated heat input capacity less than 10 MMBtu per hour. Language was also added to clarify that the energy assessment is a one-time requirement for existing boilers and process heaters. Additionally, new language was added clarifying the evaluation of the facility's energy management program as part of the energy assessment.
In Table 4, operating limits for pH added to Item 1 for wet scrubbers, as specified in 40 CFR 63.7530(b)(3)(i). Item 5 revised to clarify that “Any other control type” only means add-on air-pollution control devices. The operating limits were also revised to clarify which units and control combinations were required to install and operate a bag leak detection system, to install and operate a continuous opacity monitor, or to monitor voltage and amperage of an ESP. These changes removed the appearance that some units would need to do more than one type of monitoring for control of PM. This table was also revised to include a row for an operating limit for unit operating load for those units that demonstrate compliance using a performance test.
Table 5 was revised to include EPA Method 23 as the accepted method for measuring dioxin/furan. A new Table 11 was also added to document the toxic equivalency factors that should be used to demonstrate compliance with the toxic equivalents (TEQ) emission limits.
Table 7 was revised to include dry scrubbers and activated carbon injection used to comply with Hg or dioxin/furan emission limitations, and to include procedures for determining the corresponding operating limit requirements. Procedures were also added for determining the operating limit for unit operating load for units that demonstrate compliance through performance testing. Finally, this table was revised to clarify how the operating limits should be determined for wet scrubbers and for ESPs operated with wet scrubbers.
Table 8 was revised to correct certain cross-references to 40 CFR 63.7530, and to include procedures for demonstrating continuous compliance with the operating limit for unit operating load.
Table 9 was revised to correct cross-references to 40 CFR 63.7550(c) and Table 3 for work practice standards. Language in Item 1.c. revised to more clearly match the language in 40 CFR 63.7530(d) and (e), and Item 1.c. was split into Items 1.c. and 1.d.
The definition of a boiler and the definition of a process heater have been revised to include units that combust solid waste but are exempt, by statute, from section 129. This change was necessary in order to provide coverage of units that would otherwise be exempt from any requirements. The revised definitions read as follows:
As a result of new data received for the floor calculations, revised treatment of low reported CO data to consider measurement error, and a new subcategorization scheme, some of the final CO limits for new sources in Table 1 of this final rule are more stringent than proposed, as are some of the other limits for certain subcategories (e.g., PM and Hg for liquid fuel units, and PM and HCl for solid fuel units when compared to the proposed new source limits for the proposed biomass/bio-based fuel subcategory). Where a final limit is more stringent than proposed, 40 CFR 63.6 of subpart A (General Provisions), requires that new sources that commenced construction between proposal and promulgation be allowed to comply with the proposed limits for 3 years (i.e., up to the existing source compliance date) and then comply with the final limits for new sources listed in Table 1 of this final rule. In this final rule we have added a new Table 12 to outline the emission limits applicable to sources that commenced construction between proposal and promulgation and updated the rule language to provide instructions on which limits apply to them for the 3 year period after this final rule is published. These sources have the option to comply with Table 1 (final) limits from the start, if they choose.
Many commenters who criticized the pollutant-by-pollutant approach also filed comments on other rules such as the recent Portland Cement NESHAP and the NSPS and Emission Guidelines for Hospital/Medical Infectious Waste Incinerators (HMIWI). Some commenters expressed concern that EPA used a similar pollutant-by-pollutant approach in the HMIWI rulemaking and that rulemaking is being challenged before the D.C. Circuit. Commenters also submitted a variety of suggestions on calculating a multi-pollutant approach. Some commenters suggested that human health be considered by weighting pollutants according to relative-toxicity and then ranking the units in each subcategory according to their weighted emission totals in order to identify the best performing 12 percent of sources for all pollutants.
Section 112(d)(3) is ambiguous as to whether the MACT floor is to be based on the performance of an entire source or on the performance achieved in controlling particular HAP. Congress specified in section 112(d)(3) the minimum level of emission reduction that could satisfy the requirement to adopt MACT. For new sources, this floor level is to be “the emission control that is achieved in practice by the best controlled similar source.” For existing sources, the floor level is to be “the average emission limitation achieved by the best performing 12 percent of the existing sources” for categories and subcategories with 30 or more sources, or “the average emission limitation achieved by the best performing 5 sources” for categories and subcategories with fewer than 30 sources. Commenters point to the statute's reference to the best performing “sources,” and claim that Congress would have specifically referred to the best performing sources “for each pollutant” if it intended for EPA to establish MACT floors separately for each HAP. EPA disagrees. The language of the Act does not address whether floor levels can be established HAP-by-HAP or by any other means. The reference to “sources” does not lead to the assumption the commenters make that the best performing sources can only be the best-performing sources for the entire suite of regulated HAP. Instead, the language can be reasonably interpreted as referring to the source as a whole or to performance as to a particular HAP. Similarly, the reference in the new source MACT floor provision to “emission control achieved by the best controlled similar source” can mean emission control as to a particular HAP or emission control achieved by a source as a whole.
Industry commenters also stressed that section 112(d) requires that floors be based on actual performance from real facilities, pointing to such language as “existing source”, “best performing”, and “achieved in practice”. EPA agrees that this language refers to sources' actual operation, but again the language says nothing about whether it is referring to performance as to individual HAP or to single facility's performance for all HAP. Industry commenters also said that Congress could have mandated a HAP-by-HAP result by using the phrase “for each HAP” at appropriate points in section 112(d). The fact that Congress did not do so does not compel any inference that Congress was
Commenters also point to EPA's subcategorization authority, and claim that because Congress authorized EPA to distinguish among classes, types, and sizes of units, EPA cannot distinguish units by individual pollutant, as they allege EPA did in the proposed rule. However, that statutory language addresses EPA's authority to subcategorize sources within a source category prior to setting standards, which EPA has done for boilers and process heaters. EPA is not distinguishing within each subcategory based on HAP emitted. Rather, it is establishing emissions standards based on the emissions limits achieved by units in each subcategory. Therefore, EPA's subcategorization authority is irrelevant to the question of how EPA establishes MACT floor standards once it has made the decision to distinguish among sources and create subcategories.
EPA's long-standing interpretation of the Act is that the existing and new source MACT floors are to be established on a HAP-by-HAP basis. One reason for this interpretation is that a whole plant approach could yield least common denominator floors—that is floors reflecting mediocre or no control, rather than performance which is the average of what best performers have achieved.
For example, if the best performing 12 percent of facilities for HAP metals were also the worst performing units for organics, the floor for organics or metals would end up not reflecting best performance. In such a situation, EPA would have to make some type of value judgment as to which pollutant reductions are most critical to decide which sources are best controlled.
The central purpose of the amended air toxic provisions was to apply strict technology-based emission controls on HAPs.
It is true that legislative history can sometimes be so clear as to give clear meaning to what is otherwise ambiguous statutory text. As just explained, EPA's HAP-by-HAP approach fulfills the evident statutory purpose and is supported by the most pertinent legislative history. A few industry commenters nonetheless indicated that a HAP-by-HAP approach is inconsistent with legislative history to section 112(d), citing to page 169 of the Senate Report. Since this Report was to a version of the bill which did not include a floor provision at all (much less the language at issue here), it is of no relevance.
Industry commenters also noted that EPA retains the duty to investigate and, if justifiable, to adopt beyond the floor standards, so that potential least common denominator floors resulting from the whole facility approach would not have to “gut the standards.” That EPA may adopt more stringent standards based on what is “achievable” after considering costs and other factors is irrelevant to how EPA is required to set MACT floors. MACT floors must be based on the emission limitation achieved by the best performing 12 percent of existing sources, and, for new sources, on the level achieved by the best controlled similar source, and EPA must make this determination without consideration of cost. At best, standards reflecting a beyond-the-floor level of performance will have to be cost-justified; at worst, standards will remain at levels reflecting mediocre performance. Under either scenario, Congress' purpose in requiring floors is compromised.
EPA notes, however, that if optimized performance for different HAPs is not technologically possible due to mutually inconsistent control technologies (for example, metals performance decreases if organics reduction is optimized), then this would have to be taken into account by EPA in establishing a floor (or floors). The Senate Report indicates that if certain types of otherwise needed controls are mutually exclusive, EPA is to optimize the part of the standard providing the most environmental protection. S. Rep. No. 228, 101st Cong. 1st sess. 168 (although, as noted, the bill accompanying this Report contained no floor provisions). It should be
All available data for boilers and process heaters indicate that there is no technical problem achieving the floor levels contained in this final rule for each HAP simultaneously, using the MACT floor technology. Data demonstrating a technical conflict in meeting all of the limits have not been provided, and, in addition, there are a number of units that meet all of the final existing source emission limits.
Where the proposed MACT floor is below the LOQ or PQL then that source category has a technological measurement limitation. A few commenters suggested RL values should be used when developing the floor limits. They stated that the RL is the lowest level at which the entire analytical system gives reliable signals and includes an acceptable calibration point. They added that use of an acceptable calibration point is critical in showing that numbers are real versus multiplying the MDL by various factors.
Several commenters stated that all non-detect values should be excluded from MACT floor calculations. They believed that excluding all non-detect values would eliminate any potential errors or accuracy issues related to testing for compliance. Due to inconsistencies of the MDL value reported for non-detect data, one commenter suggested treating all such values as zero. This would provide a consistent approach for setting the floor as well as determining compliance. Issues discussed by a multitude of commenters were that a wide range of detection limit values were reported and
The probability procedures applied in calculating the floor or an emissions limit inherently and reasonably account for emissions data variability including measurement imprecision when the database represents multiple tests from multiple emissions units for which all of the data are measured significantly above the method detection level. That is less true when the database includes emissions occurring below method detection capabilities and are reported as the method detection level values.
EPA's guidance to respondents for reporting pollutant emissions used to support the data collection specified the criteria for determining test-specific method detection levels. Those criteria insure that there is only about a 1 percent probability of an error in deciding that the pollutant measured at the method detection level is present when in fact it was absent. Such a probability is also called a false positive or the alpha, Type I, error. Because of sample and emissions matrix effects, laboratory techniques, sample size, and other factors, method detection levels normally vary from test to test for any specific test method and pollutant measurement. The expected measurement imprecision for an emissions value occurring at or near the method detection level is about 40 to 50 percent. Pollutant measurement imprecision decreases to a consistent relative 10 to 15 percent for values measured at a level about three times the method detection level.
Also in accordance with our guidance, source owners identified emissions data which were measured below the method detection level and reported those values as equal to the method detection level as determined for that test. An effect of reporting data in this manner is that the resulting database is truncated at the lower end of the measurement range (i.e., no values reported below the test-specific method detection level). A floor or emissions limit based on a truncated database or otherwise including values measured near the method detection level may not adequately account for measurement imprecision contribution to the data variability. That is, an emission limit set based on the use of the MDL to represent data below the MDL may be significantly different than the actual levels achieved by the best performing units due to the imprecision of the measurements. This fact, combined with the low levels of emissions measured from many of the best performing units, led EPA to develop a procedure to account for the contribution of measurement imprecision to data variability.
We applied the following procedures to account for the effect of measurement imprecision associated with a database that includes method detection level data. The first step was to define a method detection level that is representative of the data used in establishing the floor or emissions limit and that also minimizes the influence of an outlier test-specific method detection level value. We reviewed each pollutant-specific data set to identify the highest test-specific method detection level reported that was also equal to or less than the average emissions level (
The second step in the process is to calculate three times the representative
In response to comments that EPA should have used the PQL, RL, or LOQ values in place of non-detect values, we disagree that use of those values is appropriate for calculating the MACT floors for two reasons. First, these terms are not defined statistically or consistently from method to method but are relatively arbitrary multiples (
In response to the comments received, we reviewed the quality of the data relative to information provided for each emissions test. Method 10 is structured such that we can assess measurement data quality relative to the calibration span of the instrument (see
We can estimate the equivalent of the method detection level for a measurement with an instrumental test method (e.g., EPA Methods 3A, 6C, 7E, and 10) using a square root formula and these allowable data quality criteria. For example, in the case of a calibration span value of 25 ppmv, the square root formula (i.e., square root of the sum of the squares) would indicate a value of 0.9 ppmv. Consistent with the methodology we applied for non-instrumental methods, discussed in the previous comment response where we established limits no less than 3 times the MDL in order to avoid a large degree of measurement imprecision, this estimated measurement error value would translate to a limit of 3.0 ppmv (rounded up from 2.7 ppmv). For tests done with calibration spans of greater than 25 ppmv, the corresponding estimated measurement error would be greater. For example, the estimated measurement error using the square root formula for a calibration span of 100 ppmv would be about 4 ppmv which would translate to a limit of 12 ppmv. For a calibration span of 1000 ppmv, the estimated measurement error would be 35 ppmv or a limit of about 100 ppmv.
Commenters raised concerns that existing units would have difficulty demonstrating compliance with the MACT floor limits. They suggested best performers with advanced air pollution control technologies should not be required to install additional add-on equipment to meet the emission limits. Commenters requested that EPA assess how many existing boilers and process heaters in each subcategory will be able to meet the standards without taking any further control measures. Several commenters contacted manufacturers regarding a retrofit project for their boilers and process heaters and they noted that manufacturers were unwilling to guarantee a retrofit would meet the limits.
Similarly, commenters raised concerns that new units would have even more difficulty demonstrating compliance with the MACT floor limits. These commenters had difficulty identifying a single source whose emissions testing data demonstrated they could achieve all of the MACT
Some commenters expressed concern that EPA had not properly evaluated whether there are technically feasible means of achieving the MACT floors. The commenters contended that the approach does not identify reasons why best performing sources achieve emissions levels reflected in the test data and they suggested that the intent of the MACT floor standard setting process is to discover effective control techniques so that other performers in the source category could emulate those techniques, reduce their emissions, and achieve similar emission levels. Commenters added that EPA has not adequately considered air pollution control device (APCD) conflicts with one another or compatibility of controls on certain boilers. Additionally, choosing to optimize controls for one pollutant may preclude optimization of controls for another pollutant e.g., minimizing CO in the combustion system is opposed to minimizing NO
EPA agrees with commenters who note that many of the data sets are small. However, stakeholders were encouraged to provide additional data, and EPA significantly revised some of the proposed emission limits based on new test data. We received little or no additional data for some subcategories for which data sets were small at proposal. For all data sets, the final emission limits are based on the available data and reflect EPA's assessment of variability. Moreover, after consideration of the comments on the achievability of the emission limits, EPA performed additional analyses and detailed examinations of the data and developed revised limits that are based on what has been demonstrated to be achieved in practice. As described in more detail in the docket memorandum entitled “Revised MACT Floor Analysis (2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source,” EPA has made adjustments to treatment of non-detect values, the statistical methodology, and monitoring requirements, and also incorporated new data and data corrections into our analyses. Accordingly, the final emission limits better reflect the performance of the MACT floor units than the proposed limits. EPA notes that for each subcategory, there are existing units that are meeting the MACT floor limits or are expected to meet the limits through application of available control technology.
Finally, in response to comments about low CO limits conflicting with a unit's ability to meet NO
EPA first took fuel into consideration, to the extent it is reflected in differences in boiler design, when we divided the source category into subcategories. EPA is aware that differences between given types of units, and fuel, can affect technical feasibility of applying emission control techniques, and has addressed this concern in the final rule. For a fuel based pollutant, such as PM, performance testing must be conducted under representative full load operating conditions, which, along with the parameter monitoring requirements, provides an assurance that the standards are being met at all times. For Hg and HCl, we modified the fuel based variability analysis in consideration of comments received on this approach. The first modification to the analysis was the introduction of a solid fuel subcategory, which includes any unit burning at least 10 percent, on an annual heat input basis, of any coal, fossil solid, biomass, or bio-based solid fuel. Given the wide variety in fuel types that compose the floor, the statistical analysis accounts for some of the inter-unit variability for different fuel types identified to be in the floor. The second modification was the development of a fuel variability factor (FVF). The FVF calculations were similar to the calculations used at proposal, but they were simplified to remove the control efficiency calculation and the method for identifying outliers in the data was also adjusted. The revised FVF analysis calculated a ratio for all fuel analysis data points for units in the top 12 percent for existing units and the top performing unit for new units in each subcategory. This ratio compared the reported fuel analysis data, converted to units of lb/MMBtu, to the emission test outlet data, converted to units of lb/MMBtu, during the stack tests. At proposal we conducted an outlier analysis of only the maximum ratios for each unit, but we revised the outlier analysis to consider all of the ratios from top performers within each subcategory. We then defined and identified outliers using the test of 3 times the standard deviation and 3 minus the standard deviation for all of the ratios in the subcategory. After removing outliers, the remaining maximum ratio for each subcategory was identified and multiplied by the 99 percent UPL.
For a discussion of how EPA considered other non-fuel variability operations, such as boiler load, see response to the comments provided under “What did we do with the CO Limits”.
There were several comments made on specific aspects of the statistical variability analysis including suggestions for the appropriate confidence interval, appropriate statistic, and EPA's methods for determining the distribution of the dataset. The specific comments and EPA responses are outlined below.
Commenters from industry and industry representatives advocated for a higher UPL. Commenters requested that EPA increase the UPL to 99.9 percent in order to better encompass unit emissions variability and represent a manageable risk. Industry, like environmental advocacy groups, also requested that EPA take into account operator training and its effect on emissions. The commenters claimed that operators are compelled to set emissions targets lower than limits to create a compliance margin which helps avoid violations and their consequences. Commenters also cited recent consideration of a 99.9 percent UPL in the proposed HMIWI MACT rule. Commenters claimed that since the HMIWI database consisted of a small dataset, it was unlikely full variability was observed and thus EPA had no valid statistical basis for the decisions to use 99 percent in the final HWIMI rule. The commenters suggested similar data limitations in the boiler dataset and argued that the 99.9 percent UPL should be used to allow more of a margin for all operating conditions and sample collection variation due to the limited data for the boiler MACT rule.
For CO, EPA considered several comments from industry and States, which provided both quantitative and qualitative comments on how CO emissions vary with load, fuel mixes and other routine operating conditions. After considering these comments EPA determined that a 99.9 percent confidence level for CO would better account for some of these fluctuations. While a good deal of CO data are available, at least for some of the subcategories, the data show highly variable emissions that can result from situations beyond the control of the operator, such as fuel moisture content after a rain event, elevated moisture in the air, and fuel feed issues or inconsistency in the fuel. The higher confidence level selected for CO is intended to reflect the high degree of variability in the emissions. For dioxin/furan, we also are maintaining the 99 percent UPL. Although much of the uncertainty associated with dioxin/furan testing will be mitigated by the requirement in EPA Method 23 to report non-detect values as zero for compliance purposes, the dioxin emission limits remain quite low and the 99 percent UPL provides a high degree of confidence that the best performing units will be able to meet the standards.
With respect to the methods used to compute the UPL for a dataset that is determined to be lognormally distributed, EPA also considered the commenters suggested revisions to the calculations in order to avoid skewing the UPL by calculating the UPL of an arithmetic mean instead of the UPL of a geometric mean. To adjust the calculation EPA considered a scale bias correction approach as well as a new UPL equation based on a Bhaumik and Gibbons 2004 paper, which calculates “An Upper Prediction Limit for the Arithmetic Mean of a Lognormal Random Variable”. Given data availability, EPA selected the Bhaumik and Gibbons 2004 approach which addresses commenters concerns with the proposed computations.
In general, confidence intervals are used to quantify one's knowledge of a parameter or some other characteristic of a population based on a random sample from that population. The most frequently used type of confidence interval is the one that contains the population mean. Given this definition, the 99 percent UCL represents the value which we can expect the mean of the population to fall below 99 percent of the time in repeated sampling. Whereas a confidence interval covers a population parameter with a stated confidence, that is, a certain proportion of the time, there is also a way to cover a fixed proportion of the population with a stated confidence. Such an interval is called a tolerance interval. Confidence limits are limits within which we expect a given population parameter, such as the mean, to lie. Statistical tolerance limits are limits within which we expect a stated proportion of the population to lie. Given these definitions, the 99 percent UTL represents the value which we can expect 99 percent of the measurements to fall below 99 percent of the time in repeated sampling. In other words, if we were to obtain another set of emission observations from the five sources, we can be 99 percent confident that 99 percent of these measurements will fall below a specified level. Since you must calculate the sample percentile, and the sample sizes for the boiler MACT floor data are small, the 99th percentile is underestimated. The UTL should only be used where one can calculate a sample percentile,
In contrast to a confidence interval or a tolerance interval, a prediction interval for a future observation is an interval that will, with a specified degree of confidence, contain the next (or some other pre-specified) randomly selected observation from a population. In other words, the prediction interval estimates what future values will be, based upon present or past background samples taken. Given this definition, the UPL represents the value which we can expect the mean of 3 future observations (3-run average) to fall below, based upon the results of the independent sample of size n from the same population. Finally, the upper limit (UL) is roughly equivalent to the percentile of the actual data distribution for the sample. The UL does not have a robust statistical foundation. Basically, the UL formulation assumes that the data: (1) Represent the population rather than a random sample from that population, and (2) are normally distributed. The data used to develop the MACT floors for this rule do not represent the entire population for any subcategory, and most of the data sets are not normally distributed. For these reasons, EPA concluded that it is not appropriate to use the UL in setting the MACT floor limits.
Other commenters suggested that emissions variability is not statistical but instead based on different operating conditions of individual units. The commenters added that the variability of each unit should be averaged based on individual units and then used to establish UPL calculations instead of assessing a UPL based on individual tests or test runs.
Traditionally, boiler emissions have been regulated on the basis of boiler input energy (lb of pollutant/MMBtu heat input). However, input-based limitations allow units with low operating efficiency to emit more of each pollutant per output (steam or electricity) produced than more efficient units. Considering two units of equal capacity, under current regulations, the less efficient unit will emit more
The criteria used for selecting a specific output-based format were based on the following: (1) Provide flexibility in promotion of plant efficiency; (2) permit measurement of parameters related to stack emissions and plant efficiency, on a continuous basis; and (3) be suitable for equitable application on a variety of facility configurations. The output-based option of mass of pollutant emitted per boiler energy output (lb/MMBtu energy output) meets all three criteria. The majority of ICI boilers produce steam only for process operation or heating and, in this case, the energy output of the boiler is the energy content of the boiler steam output. For those ICI boilers that supply steam to generate, or cogenerate, electricity, the boiler's energy output can include both electrical and thermal (process steam) outputs. There are also some industrial boilers that only generate electricity. Technologies are readily available to measure these energy outputs, and they currently are measured routinely in many industrial plants. Therefore, emission limits based on this format can be applied equitably on a variety of facility configurations. Based on this analysis, an emission limit format based on mass of pollutant emissions per energy output was selected for the alternate output-based standards.
In the case of a boiler that produces steam for process or heating only (no power generation), the lb/MMBtu output-based emission limit is based on the mass rate of emissions from the boiler and the energy content in terms of MMBtu of the boiler steam output. At cogeneration facilities (also known as combined heat and power (CHP)), energy output includes both electricity and process steam. The steam from the boiler is first used to generate electricity. The thermal energy (steam) exiting the electricity generating equipment is then used for a variety of useful purposes, such as manufacturing processes, space heating and cooling, water heating, and drying. The electricity output and the useful energy present in the steam exiting the turbine must both be accounted for in determining the overall energy output from the boiler and converted to a common basis of lb/MMBtu consistent with the output-based standard for steam-only units.
The efficiency and associated environmental benefits of CHP result from avoiding emissions from the generation of electricity at a central station power plant. The avoided emissions at most times are from a less-efficient unit that consequently also has higher emissions. Consequently, the electricity output of the CHP facility in kWh should be valued at the equivalent heat rate of the avoided central station power, nominally 10,000 Btu/kWh. Therefore, the lb/MMBtu output-based emission limit used for compliance with a CHP boiler is based on the mass rate of emissions from the boiler and a total energy output, which is the sum of the energy content of the steam exiting the turbine and sent to process in MMBtu and the energy of the electricity generated converted to MMBtu at a rate of 10,000 Btu per kWh generated (10 MMBtu per MWh).
Compliance with the alternative output-based emission limits would require continuous measurement of boiler operating parameters associated with the mass rate of emissions and energy outputs. In the case of boilers producing steam for process use or heating only (no power generation), the boiler steam output flow conditions would have to be measured to determine the energy content of the boiler steam output. In the case of CHP plants, where process steam and electricity are output products, methods would have to be provided to measure electricity output and the flow conditions of the steam exiting the electrical generating equipment and going to process uses. These conditions will determine the energy content of the steam going to process uses. Instrumentation already exists in many facilities to conduct these measurements since the instrumentation is required to support normal facility operation. Consequently, compliance with the alternate output-based emission limits is not expected to require any additional instrumentation in many facilities. However, additional signal input wiring and programming is expected to be required to convert the above measurements into the compliance format (lb/MMBtu energy).
Since the June 4, 2010, proposal, we obtained steam data (flow, temperature, and pressure) from the best performing units that made up the MACT floor at proposal. In determining alternate equivalent output-based emission limits, we first determined for each of the best performing units the Btu output of the steam and then calculated the boiler efficiency for each of the boilers having available steam/heat input data. Boiler efficiency is defined as steam Btu output divided by fuel Btu input. Next, we determined the average boiler efficiency factor for each subcategory from the best performing units in that subcategory. We then applied the average boiler efficiency factor to the final MACT limits that are in the current format of lb/MMBtu heat input to develop the alternate output-based limits. The efficiency factor approach was selected because the alternative of converting all the reported data in the database to an output-basis would require extensive data gathering and analyses. Applying an average boiler efficiency factor, based on the individual boiler efficiency of the best performing units, essentially converts the heat input-based limits to output-based emission limits.
The alternate output-based emission limits in this final rule do not lessen the stringency of the MACT floor limits and would provide flexibility in compliance and cost and energy savings to owners and operators. We also have ensured that the alternate emission limits can be implemented and enforced, will be clear to sources, and most importantly, will be no less stringent than implementation of the MACT floor limits.
Commenters stated that EPA should provide a clear, statutory-based definition of “Boiler,” and the scope of the required energy assessment. Commenters also stated that if EPA includes an energy assessment requirement in this final rule, it should regulate only the emission source over which it has § 112 authority to regulate. The “boiler” logically includes the combustion unit (the emissions source) and closely associated equipment, from flame to last heat recovery. EPA should adopt this definition of “boiler system,” which reflects the extent of its section 112 authority.
Commenters also recommended that an energy assessment previously conducted of a facility that has not had significant changes to the boilers and associated equipment should be acceptable for initial compliance. Energy performance of facilities strongly depends on equipment configuration, equipment performance, and fuels fired. If these do not change from the time an energy assessment was conducted to the time the Initial Compliance energy assessment report is submitted, the report would be representative of an accurate depiction of the facility.
Several commenters supported the use of energy assessments as a “beyond the floor” control measure and advocated for output-based standards (noting that such an approach is critically important to encourage CHP since input-based emissions regulations fail to credit CHP systems for their greater efficiency, reducing the incentive for CHP to be installed and used throughout U.S. industry). Moreover, since this final boiler rule will apply to a wide variety of manufacturing facilities in multiple sectors producing a variety of final products, normalizing pollutant output per useful energy output is a good way to ensure all affected facilities can be assessed on similar baselines. Several commenters also applauded recognition of energy efficiency measures to achieve pollution reductions and encouraged EPA to continue to view energy efficiency investments favorably. Some commenters criticized EPA's failure to require implementation of findings of the energy assessments.
We agree that the scope of the required energy assessment presented in the proposed rule needs to be clarified and we have done this in this final rule. In the proposed Boiler MACT, the intended scope of the energy assessment did extend beyond the affected boiler. The energy assessment included a requirement that a facility energy management program be developed. The energy assessment was intended to be broader than the affected boiler and process heater and included other systems or processes that used the energy from the boiler and process heater. We disagree that the scope of the energy assessment should be limited to the boiler and directly associated components such as the feed water system, combustion air system, fuel system (including burners), blow down system, combustion control system, and heat recovery of the combustion fuel gas. Including all of the energy using systems in the energy assessment can result in decreased fuel use that results in emission reductions, the result articulated in 112(d)(2). We have included in this final rule a definition of what the energy assessment should include for various size fuel consuming facilities. We also have included a definition of the qualified assessors who must be used to conduct those energy assessments. We have clarified the requirement that the energy assessment include a review of the facility's energy management program and identify recommendations for improvements that are consistent with the definition of an energy management program. A definition of an energy management program that is compatible with the ENERGY STAR Guidelines for Energy Management and other similar approaches was added.
We also agree that a facility should be exempt from the requirement to conduct an energy assessment if an energy assessment has recently been conducted. We have revised the final rule to allow facilities to comply with the requirement by submitting an energy assessment that has been conducted within 3 years prior to the promulgation date of this final rule.
With respect to the second argument, the energy assessment will generate emission reductions through the reduction in fuel use beyond those reductions required by the floor. While the precise quantity of emission reductions will vary from source to
Finally, with respect to the third argument, the requirement to perform the energy audit is, of course, a requirement that can be enforced and thus a standard. As noted, while we do not know the precise reductions that will occur at individual sources, the record indicates that energy assessments reduce fuel consumption and that parties will implement recommendations from an auditor that they believe are prudent. Therefore, the requirement to perform an energy assessment can both be enforced and will result in emission reductions.
We agree that EPA should provide a clear definition of what the energy assessment should encompass. However, we disagree that the energy assessment should be limited to only the boiler and associated equipment. EPA has properly exercised the authority granted to it pursuant to CAA section 112(d)(2) which states that “Emission standards promulgated * * * and applicable to new or existing sources shall require the maximum degree of reduction in [HAP] emissions that the Administrator determines * * * is achievable * * * through application of measures, processes, methods, systems or techniques including, but not limited to measures which * * * reduce the volume of, or eliminate emissions of, such pollutants through process changes, substitution of materials or other modifications * * *.” The purpose of an energy assessment is to identify energy conservation measures (such as, process changes or other modifications to the facility) that can be implemented to reduce the facility energy demand from the affected boiler which would result in reduced fuel use. Reduced fuel use will result in a corresponding reduction in HAP, and non-HAP, emissions from the affected boiler. Reducing the energy demand from the plant's energy using systems can result in additional reductions in fuel use and associated emissions from the affected boilers. We agree that the scope of the required energy assessment needs to be clarified. However, in the proposed Boiler MACT, the intended scope of the energy assessment did extend beyond the affected boiler. The energy assessment did include a requirement that a facility energy management program be developed. The energy assessment was intended to be broader than the affected boiler and process heater and included other systems or processes that used the energy from the boiler and process heater. We disagree that the scope of the energy assessment should be limited to the boiler and directly associated components such as the feed water system, combustion air system, fuel system (including burners), blow down system, combustion control system, and heat recovery of the combustion fuel gas. Including the facility's energy using systems and energy management practices in the energy assessment can identify measures that result in decreased fuel use and related emission reductions. We have included in this final rule a definition of what the energy assessment should include for various size fuel consuming facilities. We also have included a definition of the qualified assessors who must be used to conduct those energy assessments.
We also agree that a facility should be exempt from the requirement to conduct an energy assessment if an energy assessment had recently been conducted. We have revised this final rule to allow facilities to comply with the requirement by submitting an energy assessment that had been conducted within 3 years prior to the promulgation date of this final rule.
Many commenters stated that EPA should have proposed more subcategories, while others believed that too many subcategories were proposed. Many different issues were raised, and some of the key issues that led to changes in the rule include: The need for a limited use subcategory for boilers that operate for only a small percentage of hours during a year; the unique suspension/grate design of units that combust bagasse; the need for a non-continental liquid fuel subcategory for island units that have limited fuel options and other unique circumstances; and the appropriate subcategory for mixed fuel units. The comments and EPA responses are provided below.
In addition to technical reasoning, commenters also submitted requests for a limited-use subcategory on the basis of regulatory precedent, citing the 2010 RICE MACT and 2004 vacated Boiler MACT. Several commenters requested a subcategory and work practices similar to those in the Stationary RICE NESHAP. Several other commenters also stated that the subcategory was warranted because it was included in the previous Boiler MACT rule. These commenters argued that EPA had not provided any justification for eliminating the subcategory in the proposed rule. Some of these commenters also stated that the recordkeeping requirements that were proposed in Section 63.7555(d)(3) for limited-use boilers and process heaters should be the only requirement for these units.
The majority of commenters that requested a limited use subcategory also requested for EPA to adopt a work practice standard for limited use units and not subject the subcategory to emissions testing or monitoring. Commenters argued that EPA has acknowledged that there is no proven control technology for organic HAP emissions from limited use units. Limited use units, such as emergency and backup boilers, cannot be tested effectively due to their limited operating schedules. Based on existing test methods, which require a unit to operate in a steady state, limited use units would have to operate for the sole purpose of emissions testing. One commenter claimed that the proposed rule performance testing would require, not including startup and stabilization, operating at least 15 additional hours of per year, or 24 hours per year if testing for all pollutants is required. Commenters also noted that because the operation of these units is neither predictable nor routine over a 30 day period, back-up boilers would not benefit from 30-day emissions averaging. Commenters argued that establishing numerical standards for limited use units is contrary to the goals of the CAA and will lead to creating
Many commenters also mentioned the economic impacts of a numerical limit on limited-use units and requested work practice standards. Commenters stated that it would not be cost effective to install controls on units that operate at 10 percent capacity or less annually. They claimed that the additional controls would produce minimal emission reductions and would result in the shutdown of limited-use units.
Several commenters claimed that the current distinction between natural gas and oil-fired limited-use units is unnecessary, and that additional requirements for oil-fired units do not produce environmental benefits. Commenters recommended that EPA create a separate subcategory for limited use, oil-fired boilers and suggest that the work practice standard proposed for gas-fired boilers be applied in lieu of emissions standards for these units. Other commenters stated that the limited use subcategory should include new/reconstructed limited use units as well as existing units for all fuel categories. One commenter recommended a tiered approach and stated that for very limited use boilers, EPA should establish a standard with no additional controls or requirements, other than monitoring annual hours of operation. They defined very limited use as <500 hours of operation per year.
One commenter also requested that the regulatory definition of bagasse boiler be altered to take into account that bagasse boilers are hybrid suspension and grate/floor-fired boilers uniquely designed to dry and burn bagasse. The commenter goes on to explain that the majority of drying and combustion take place in suspension and the combustion is completed on the grate or floor. The boilers are designed to have high heat release rates and high excess air rates which are to evaporate high fuel moisture content and this design impacts CO, PM, and organic HAP formation. Under the proposal, most bagasse-fired boilers would be categorized as “suspension burners/dutch ovens designed to burn biomass.” However, the commenter claimed that the CO limit for this subcategory was driven largely by emissions data from units which fire dry biomass (
One commenter went on the say that EPA has inappropriately subcategorized suspension burners/dutch ovens designed to burn biomass as a single subcategory. Hybrid suspension/grate-floor burners are designed such that the wet fuel first undergoes drying and then combustion in suspension within the furnace, with any remaining unburned fuel falling onto the grate to complete combustion. Another commenter also provided technical design elements to highlight the differences between dutch ovens, suspension burners, and the above mentioned hybrid suspension grate burners. This commenter indicated that dutch ovens have two chambers. Solid fuel is dropped down into a refractory lined chamber where drying and gasification take place in the fuel pile. Gases pass over a wall into the second chamber where combustion is completed. Dutch ovens are capable of burning high moisture fuels such as bark, but have low thermal efficiency and are unable to respond rapidly to changes in steam demand. On the contrary, suspension burners combust fine, dry fuels such as sawdust and sander dust in suspension. Rapid changes in combustion rate are possible with this firing method. This commenter added that some dutch oven units located at particleboard, hardboard, and medium density fiberboard plants were misclassified and there are less than 30 true dry-fired suspension burners in operation, and only a small handful of true dutch oven boilers.
Commenters also submitted technical issues justifying the creation of a non-continental or remote location subcategory. One commenter stated that most oil combustion in the petroleum sector is in locations that are islands or in more remote parts of the United States. Island and remote facilities cannot physically access natural gas pipelines, making burning liquid fuels unavoidable. The option of crude oil shipments would be impractical because the ships are limited by size and what is manageable by load/discharge ports. The commenter also claims that in the time it would take a crude ship to arrive, the refinery would have produced the amount of crude in the shipment. Further, while some units at a facility are designed to burn refinery fuel gas, the fuel gas produced at a refinery is less than the energy required to operate the refinery. These non-continental facilities are also limited to the fuel quality provided by their nearby crude slate used in the refining process. That commenter goes on to say that these refineries produce their fuel, the HAP metals content of the fuel used (particularly residual fuel oil) is a direct result of the crude slate used on site. The commenter submitted trace metals from various crudes to show that the content varies substantially between crude oils being used on site.
Another commenter provided the following distinctions for non-continental units: A striking example of fuel system differences for non-continental units is daily variation in fuel gas production due to ambient temperature fluctuations between night and mid-day or resulting from tropical rainfall events, coupled with fin fan cooling systems that are used because of the lack of fresh water available in an island without freshwater lakes or streams. The fuel system experiences a large daily variation in refinery fuel gas due to changes in ambient air temperature. These changes occur as a day-night swing in the refinery or any time there is a significant rain storm. As the ambient air temperature decreases, the amount of propane, butane and heavier molecules in the fuel gas decreases, as those compounds condense out. This results in a change in volume and composition (energy content) of the refinery fuel gas produced which, in the case of rainfall events, occurs very quickly and unpredictably. This temperature variation occurs more frequently than at a mainland refinery because: The method of cooling on gas compressors and distillation column overheads systems is ambient air fin fan coolers (water with cooling towers is not used like a stateside refinery because fresh water is not available other than by desalination); the refinery fuel gas system contains miles of aboveground piping (long lines are affected by rain and weather conditions); refinery fuel gas contains more propane and butane than would natural gas from a pipeline (which condense at closer to ambient temperatures than methane or ethane); the make-up fuel system for the refinery is not a natural gas pipeline as at a stateside refinery. A natural gas pipeline can handle changes in refinery fuel gas produced because natural gas delivery systems are usually large enough to handle changes. A temperature change of 10 to 15 degrees or a rain storm that quickly wets the air fin fans/piping will change the volume and composition (energy content) of the refinery fuel gas produced and also impacts CO emissions.
In addition to the technical limitations described above, one commenter cited other EPA air regulations that have provided separate standards or subcategories for non-continental units. For example, 40 CFR part 60 subparts Db and KKKK include separate standards for “non-continental” units and the 2010 CISWI proposal had a subcategory for smaller remote facilities because of inherent design and operating constraints.
Another commenter mentions that the inability to obtain natural gas removes the option of being able to burn only gaseous fuels as a compliance strategy and burning fuel oil as a supplemental fuel makes complying with this proposed MACT unfairly onerous.
The second type of combination unit commenters discussed was units that co-fire gas and liquid fuels. Many commenters argued that combination oil and gas fired units are of a completely different design than EPA contemplated in setting its standards and cannot be fairly included in the same subcategory with other dedicated gas or oil fired units. Commenters elaborated that the main design difference was due to combustion techniques which require the heater/boiler firebox configuration to compromise between the needs of oil fuel and gas fuel, making it impossible to maximize combustion efficiency or minimize NO
The third type of combination unit, one commenter mentioned, was a subcategory for units co-firing biomass with any solid fuel. Commenters claimed that by failing to recognize the wide verity of fuel inputs and thus the variation in fuel quality (i.e., BTU and
Several commenters disagreed with the EPA statement that boilers are designed to burn only one fuel and that unit will encounter operational problems if another fuel type is fired at more than 10 percent heat input. Commenters stated that some boilers are specifically designed to burn a combination of fuels, and to burn them in varying quantities. Commenters elaborated that such boilers are not able to reach full load on any single fuel and that EPA has incorrectly presumed that all boilers are designed based on a primary fuel. Some commenters identified that many of the boilers used as the basis of the proposed MACT floor emission limits co-fire different fuel types. One commenter stated that if most units are designed to burn a primary fuel and will encounter problems if the 10 percent threshold is exceeded, then EPA has proposed MACT standards that will apply to boilers that by their nature are “encountering problems” due to their fuel mix. The commenter requested that EPA addresses this inconsistency.
Many commenters noted that emissions profiles vary with the fuel which made it very difficult to establish a typical emissions profile. Commenters also explained that combination fuel boilers must often adapt to process steam demands and thus experience frequent load swings and fuel input adjustments that cause significant variation in CO emission levels. Commenters also mentioned that control compatibility should be considered for multi-fuel boilers because they have inherently different control needs depending on the fuels being fired. Commenters went on to say that current limits are based on control equipment that is optimized for one HAP or fuel but the affect of other HAP and fuels or even another control would result in unknown performance and compatibility with other fuel types.
Several commenters also had concerns regarding enforcement and compliance of combination fuel units. One commenter requested that EPA more specifically address the “enforceability” of the “designed to burn” classification and more clearly consider the implications of the multi-fuel boiler operation on testing considerations. Another commenter stated that expressing limits as applicable to units “designed to burn” certain fuels was problematic and should be changed to “permitted to burn” because a State permit could limit the type of fuels combusted at a unit that may have originally been designed to burn other fuel types. Other commenters claimed that the fuel subcategory should be determined by the actual quantity of fuel burned not what the unit is designed to burn. Some questions that commenters requested clarification on were: If compliance tests would be required under different fuel firing conditions, can units with CEMS switch limits depending on what fuel is being combusted, if “designed to combust” is not maintained would actual fuel burned or fuel the unit is permitted to burn determine the subcategory, what would the annual performance test be if in the middle of the year a unit goes from having burned only one type of fuel to only another type the rest of the year.
Several solutions were suggested for addressing combination boilers. Some commenters requested that combination boilers have their own subcategory. Several other industry commenters suggested that EPA modify the subcategory definitions and applicability so that combination fuel units burning more than 10 percent coal with biomass would be regulated under the coal subcategory for fuel-based HAP and units burning more than 10 percent biomass with coal would be regulated under the biomass subcategory for combustion-based HAP. A more general solution proposed, for all types of combination fuel units, was that if a facility combusts more than one fuel type, it must meet the lowest applicable emission limit for all of the fuel types actually burned. Some commenters also requested the development of a formula based approach similar to that of the boiler NSPS SO
Some commenters were concerned that determination of MACT floor limits should be based only on data obtained while firing 100 percent of the affected fuel category and recommended that EPA either exclude all test runs where a unit was co-firing or adjust the data accordingly to remove the co-firing bias.
The subcategories for the combustion-based pollutants are now determined in the following manner. If your new or existing boiler or process heater burns at least 10 percent biomass on an annual average heat input basis, the unit is in one of the biomass subcategories. If your new or existing boiler or process heater burns at least 10 percent coal and less than 10 percent biomass, on an annual average heat input basis, the unit is in one of the coal subcategories. If your facility is located in the continental United States and your new or existing boiler or process heater burns at least 10 percent liquid fuel (such as distillate oil, residual oil) and less than 10 percent coal and less than 10 percent biomass, on an annual average heat input basis, your unit is in the liquid subcategory. If your non-continental new or existing boiler or process heater burns at least 10 percent liquid fuel (such as distillate oil, residual oil) and less than 10 percent coal and less than 10 percent biomass, on an annual average heat input basis, your unit is in the non-continental liquid subcategory. Finally, for the combustion-based pollutants, if your unit combusts gaseous fuel that does not
Commenters, including industry representatives and one government agency, submitted several technical justifications that supported the proposed work practice standards for natural gas and refinery gas units. Many of these commenters stated that Gas 1 units contribute a negligible amount of the total emissions from the source category. One commenter stated that based on a review of air permits issued for natural gas-fired units over the last 10 years no HAP emissions were identified at rates which required the State to set emission limits. Further, many commenters indicated that no currently-available control technology or technique has been indentified to achieve numeric limits for natural gas units. Others went on to argue that tune-ups actually represent the only “floor” technology currently in use at boilers and process heaters in the Gas 1 subcategory. One commenter stated that design characteristics of these units, and hence the emissions-reduction potentials of annual tune-ups, vary widely and no single emission rate or even percentage of emission reduction could be translated into a numerical limit.
Several commenters argued that work practice standards were justified based on the technical infeasibility of emissions testing and the accuracy of testing results from gas units. These commenters stated that most of the emission test data were close to detection limits or in some cases indistinguishable from ambient air near the lowest detect levels, thus preventing the limits from being enforced or reliably measured. Others argued that the application of EPA test methods to measure emissions from natural gas units results in unreliable data given that the emissions are low and below what the test methods can detect, causing repeat tests or significantly lengthening the periods for the tests, which in turn increase the cost of testing.
On the contrary, one of the environmental advocacy group commenters stated that EPA exempted natural gas-fired units from CO limits without any discussion or analysis. This commenter argued that nothing in the rulemaking docket showed that measurement would be technically infeasible and identified CO emission test results from over 160 natural gas-fired units in the NACAA database. Further, the commenter suggested that federal, State and local authorities have routinely required CO to be measured at gas fired units since CO is a criteria pollutant under the CAA.
In addition to technical reasoning, many industry and industry representative commenters also supported the adoption of work practice standards on the basis of legal precedent and authority under the CAA. Commenters stated that EPA derives its authority to use work practices in lieu of numeric emission limitations from two different statutory provisions: The narrowly construed provisions of 112(h) and the broad authority under 112(d) as defined in section 302(k). Additionally, one commenter stated that work practice standards for Gas 1 units are consistent with the D.C. Circuit's opinion in
Many commenters also cited economic justifications supporting the proposed work practices for Gas 1 units. These comments included claims that work practice standards avoid economic harm to the manufacturing sector, and they added that the cost to control each unit would be extremely burdensome with minimal benefits to the environment. These commenters suggested that any type of control beyond a tune-up would be a beyond-the-floor option and the complex controls needed to achieve such low emission levels would fail the cost-benefit determination needed to justify a beyond-the-floor option.
On the contrary, two environmental advocacy groups submitted comments opposing EPA's rationale for exempting Gas 1 units from CO limits on the basis of cost. The commenters argued that the only economic defense of work practice standards that would be justified was if economic limitations rendered the measurement of emissions “impracticable.” Further, the commenters suggested that many of these Gas 1 units would require more than a tune-up to achieve comparable reductions to those estimated if a numeric MACT floor standard was required.
Another commenter representing the coal industry also disagreed with EPA's use of a public policy rationale to justify a work practice for Gas 1 units instead of demonstrating that a work practice meets the requirements under section 112(h). The commenter argued that cost considerations were not relevant in a MACT floor analysis and they noted that the per unit costs of complying with MACT standards for gas units are lower than the cost for coal units.
Many commenters from industry, industry trade groups, universities, and State agencies agreed that emission limits would provide a disincentive to operate or switch to natural gas and refinery gas fired units. Commenters claimed that if limits for Gas 1 were adopted, units would switch from natural gas to electric systems powered by coal. Commenters stated that EPA correctly concluded that imposing emission limitations on gas-fired boilers would create a disincentive for switching to gas from oil, coal, or biomass as a control technique and would create an incentive for facilities to switch away from gas to other fuels.
A commenter from a private coal company indicated that EPA's concerns that establishing a MACT floor limit for Gas 1 units would incentivize fuel switching to coal or other fuels contradict EPA's rejection of fuel switching as a MACT floor alternative. The commenter added that if EPA rejected fuel switching because of its costliness and lack of a net emissions benefit, EPA should want to discourage coal units from converting to natural gas rather than promoting fuel switching to natural gas. This commenter also claimed that establishing a work practice standard for only Gas 1 units discriminated in favor of the use of natural gas and against the use of coal. The commenter argued that such a policy rationale invokes considerations that are not relevant in setting MACT floor standards and suggested that such a rationale is in violation of both CAA and the Equal Protection Clause of the Constitution. This commenter added that the only relevant statutory factor under 112(h) to help EPA determine where to apply a work practice standard was whether the hazardous air pollutant cannot be emitted through a conveyance designed and constructed to emit or capture that pollutant, whether the use of such a conveyance would be inconsistent with law, or whether the application of measurement methodology is not practicable due to technological and economic limitations.
In lieu of a single gas subcategory, several of the commenters requested that the Gas 1 subcategory be expanded to include gases similar to natural gas and refinery gas. These commenters argued, much like the commenters advocating for a single gas-fired subcategory, that units fired with process gases generated in chemical plants, pulp and paper plants, iron and steel plants, and similar operations should be included in the Gas 1 subcategory because the emissions data show very little difference in performance. One commenter stated that most of the Gas 2 fuels, including all 9 of the data points used in the proposed floor calculations, are from chemical plants. The commenter added that at a minimum, chemical plant process gas should be grouped with refinery gas in Gas 1 and a new floor made for Gas 2. One commenter noted that EPA did not gather information on composition or heating value in the Phase 1 ICR survey to justify placing chemical process gases in a separate subcategory from natural gas and refinery gas. Another commenter submitted combustion properties of refinery gas and petrochemical gas in order to argue that they are very similar in composition and should be categorized with natural gas in the Gas 1 category.
In order to accomplish this expansion of the Gas 1 subcategory, many commenters also addressed the definition of natural gas and refinery gas. One commenter simply stated that all gases derived from hydrocarbon sources should be classified under the Gas 1 subcategory. Another commenter suggested the definition of refinery gas in 40 CFR part 63 subpart CC for the Petroleum Refineries NESHAP should be used in this final rule. The commenter went on to say that such gases from petrochemical processes have similar compositions to those stated in the Subpart CC definition (e.g. methane, hydrogen, light hydrocarbons, and other components) that are used as fuel in boilers and process heaters and thus should be subcategorized as Gas 1. One commenter stated that the definition of natural gas should be consistent across federal air regulations and suggested that the definition of natural gas should be edited to be consistent with the definition provided in 40 CFR Part 60 Subpart Db. Another commenter requested that the definition of Gas 1 include any boiler or process heater burning at least 90 percent natural gas, refinery gas, or process off-gases with metals and sulfur content equal or less than those in natural gas.
Many other commenters argued that in general the definition of natural gas needs to be broadened to account for non-geological origins of natural gas such as landfill gas, biogas, and synthetic gas in order to promote the use of these renewable fuels. This commenter went on to state that the Gas 1 subcategory excludes biogas and process off gases that have no metals and very comparable combustion characteristics to that of natural gas or refinery gas. One commenter argued that landfill gas (LFG) should be included in Gas 1 with the work practice approach because placing it in the Gas 2 subcategory conflicts with EPA Landfill Methane Outreach Program goals. The commenter goes on to say that there is no assurance that all limits can be achieved with control technologies and installation of controls will be prohibitively expensive and thus LFG projects will be stopped or replaced
Three commenters specifically argued for the inclusion of propane fired boilers within the Gas 1 subcategory. One commenter stated that if propane meets the specifications of ASTM D1835–03a or other specification types like the Gas Processors Association Standard 2140–92 it should be included within the Gas 1 definition. Another commenter requested clarification that boilers firing liquefied petroleum gas (LPG) or propane-derived synthetic natural gas (SNG) as a backup fuel are still classified as Gas 1 boilers. The commenter argued that propane or LPG is mixed with air to make SNG and should be considered natural gas for the purposes of this final rule.
Several commenters specifically requested that hydrogen plant tail gas or similar process gases that are derived from natural gas be included in the Gas 1 subcategory. Commenters argued that hydrogen fuels do not contain HAP and subcategorizing the fuel as Gas 2 subjects the units to limits that would achieve no further reduction of HAP but require extensive performance testing, recordkeeping, fuel analysis and monitoring requirements. One commenter submitted historical facility data from a unit firing byproduct hydrogen and the commenter claimed that the fuel is cleaner burning than natural gas. One commenter suggested an 8 percent by volume minimum hydrogen content in hydrogen-fueled process gases as a criterion for consideration as a Gas 1 fuel. The commenter mentioned that this percentage is based on a 1998 EPA document that established a minimum hydrogen content by volume for non-assisted flare combustion efficiency.
If a separate Gas 2 subcategory remains in the rule, many other commenters requested that work practices be extended to the Gas 2 subcategory based on the claim that gas-fired units, relative to units firing other fuels, have the lowest emissions and pose the lowest risk of all the subcategories. Thus, the use of gas should be encouraged rather than discouraged. Some commenters argued that as a consequence of establishing limits for Gas 2 fuels, some plant sites currently designed to use Gas 2 streams for energy efficient operations will be forced to dispose of process off-gases in other types of combustion sources such as flares. The commenters added that such disposal would result in essentially the same emissions from combustion of the Gas 2 stream using a flare (as opposed to combusting the fuel in a boiler) and additional emissions from consumption of natural gas that would be used in lieu of the Gas 2 fuel. Overall, the standard as proposed for Gas 2 units would result in increased emissions of all pollutants and lower fuel efficiency.
Many commenters believe EPA is not authorized to regulate the entire dioxin/furan class as is currently proposed. They noted that in the section 112 HAP list only two compounds are specifically named, dibenzofuran and 1,3,7,8 TCDD,
Some commenters stated that regulating dioxin/furan emissions from these boilers and process heaters is not necessary because they are not a significant source of emissions. They noted that dioxin/furan emissions are significantly higher in units that burn chlorinated wastes and only those applicable rules (
In lieu of a specific dioxin/furan limit, many commenters suggested that CO should be used as a surrogate and meeting the CO limit would reduce dioxin/furan. While EPA stated in the preamble to the proposed rule that it is not appropriate to use CO as a surrogate, these commenters stated that the precursors to dioxin/furan formation are produced by incomplete combustion and thus dioxin/furan formation itself is indirectly related to the combustion process similar to the other organic HAP CO is currently used as a surrogate for. Another commenter suggested that control of other HAP such as Hg will provide adequate incidental control and reduction of dioxin/furan and the cost of separately monitoring dioxin/furan is not warranted taking into consideration the cost of achieving such emission reductions, energy requirements, and environmental impacts as required by Section 112(d)(2) of the CAA.
On the contrary, another commenter suggested that EPA correctly recognized that dioxin/furan can be formed outside of the combustion unit, not as part of the combustion process, and so sets separate standards for these carcinogens.
Several commenters provided specific comments on a lack of data available for boilers burning bagasse in a combined suspension and grate firing design.
As an alternative to the limits, many commenters offered suggestions for a work practice standard to minimize dioxin/furan emissions. These comments focused on creating boiler-specific plans for implementing good combustion practices along with an operations and maintenance plan. Additionally, boiler operators could maintain a minimum temperature at the outlet of PM control devices to minimize dioxin/furan formation.
Commenters stated that the emissions were so low that they could not be measured, and therefore work practice standards, rather than emission limits, should be finalized for dioxin/furan for all subcategories. EPA disagrees. While emissions were below detectable levels in many tests for a large portion of the dioxin/furan isomers, virtually every test detected some level of dioxin/furan. Furthermore, some of the emission tests detected most or all isomers at some level. Dioxin/furan emissions can be precisely measured for at least some units in each subcategory except for Gas 1. Therefore, except for the Gas 1 subcategory, which is addressed elsewhere in this preamble, the statutory test for establishment of work practice standards—i.e., that measurement of emissions is impracticable due to technological and economic limitations—is not met.
In order to make sure that the emission limits are set at a level that can be measured, EPA used the “three times MDL” approach (discussed elsewhere in this preamble) as a minimum level at which a dioxin/furan emission limit is set. Rather than finalizing work practice standards, but recognizing that emissions tend to be very low compared to more significant sources of dioxin such as incinerators, EPA's approach to dioxin requires an initial compliance test to demonstrate that the units meet the dioxin/furan standard, and no additional compliance testing. Following a test demonstrating compliance with the emission limit, provided that the unit's design is not modified in a manner inconsistent with good combustion practices, the oxygen level must be monitored, and the 12-hour block average must be maintained at or above 90 percent of the level established during the initial compliance test in order to provide an assurance of good combustion. Another important point to mention is that the dioxin/furan test method, EPA Method 23, requires that for compliance purposes, non-detect values should be counted as zero. Therefore, for purposes of compliance, the concern about not being able to meet the standards because of the contribution of non-detect values is moot.
Comment: Many commenters stated EPA should treat new small units in the same manner as existing small units; for boilers and process heaters with a design capacity less than 10 MMBtu/hr, a work practice standard should be implemented instead of numerical limits. These commenters stated that the same technical and economic conditions under section 112(h) for existing units still held true for new units. New small boilers and process heaters (less than 10 mmBtu/hr) are typically designed like comparable existing units with small diameter stacks, or wall vents and no stack. These vents and small stacks do not allow for accurate application of standard EPA test methods required to demonstrate compliance with emission limits, and larger stacks would decrease the efficiencies of the units. They continued that while there are some savings in adding the controls and monitoring equipment during original construction, those savings were minor in comparison to the cost of the control and monitoring equipment itself. One commenter noted that the annual performance tests are over three times the cost of the boiler. In addition, other commenters stated that the D.C. Circuit has upheld EPA's discretion to have insignificant emission sources exempt from regulations, and small units meet this condition.
Several of the commenters who supported work practice standards for small units also believed the size threshold should change. A few commenters suggested the size should be lowered to 5 MMBtu/hr, while most contended that the size threshold should be raised to 20, 25, or 30 MMBtu/hr. Those commenters who wanted the threshold raised noted that even boilers as large as 30 MMBtu/hr experience the same economic implications on their facilities. Some commenters also noted that 40 CFR part 60 subpart Dc New Source Performance Standards have work practice standards for units less than 30 MMBtu/hr. One State agency commented that the proposed rule established stringent emission limits for new small units. The commenter argued that a tiered approach should be used which required higher emission limits for new small units.
Conversely, some commenters agreed with EPA's proposed method of making the limits applicable to new small units. They noted that new boilers can be built with stacks appropriate for testing, or can have temporary stack extensions built for testing. One commenter added that it is not uncommon for new small boilers to vent exhaust into existing larger stacks that would allow for testing.
To address these data limitations, several commenters suggested that EPA should collect additional data that represent SSM events within each subcategory. One commenter had specific ideas for data collection including collecting SSM data from CEMS installed at the facilities previously included in the ICR survey and using portable analyzers to evaluate SSM emissions during future compliance testing. Many other commenters suggested that it would be infeasible to collect additional data given the test method limitations and suggested that a compliance work practice alternative be provided during periods of SSM. Commenters suggested that work practices should be site-specific, not be overly prescriptive, with the goal of minimizing the emissions during SSM periods. Other commenters suggested that EPA adopt an alternative to regulating emissions during SSM events and cited 40 CFR part 63 subpart ZZZZ, which states that startup time must be minimized.
Several commenters expressed separate concerns for EPA's treatment of malfunction events. Many commenters suggested that malfunction events should be excluded from emission limits and many submitted alternatives to including these periods. One commenter supported a limited allowance for malfunction periods where EPA defines the term “malfunction” and precisely identifies events requiring an immediate and complete shutdown. Another commenter suggested EPA should require facilities to develop and implement work practice standards to reduce malfunctions and minimize pollutants emitted during these periods. A third commenter asked that EPA replicate California permits which include a specific provision for malfunction.
Many industry commenters recognized that the proposal preamble included a statement indicating that EPA promised to address periods of equipment malfunction by considering other information before enforcing exceedance of operating limits. However, the commenters suggested that this promise does not prevent EPA, a State, or a plaintiff in a citizen suit from determining that an exceedance during a malfunction constitutes a violation. These commenters preferred EPA to develop explicit compliance alternatives for malfunctions in the rule language.
Several commenters contended that EPA failed to recognize the inherent limitations in the technology and operating conditions used to reduce emissions during SSM. One commenter referenced a case
Regarding comments on treatment of malfunctions, the discussion of EPA's position on malfunctions in the section of this preamble entitled “What are the requirements during periods of startup, shutdown, and malfunction” provides details related to this response. Essentially, EPA has determined that malfunctions should not be viewed as a distinct operating mode and, therefore, any emissions that occur at such times do not need to be factored into development of CAA section 112(d) standards, which, once promulgated, apply at all times. In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 63.2 (definition of malfunction).
Finally, EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. (
Citizen groups also commented that on August 6, 2010, EPA adopted a NESHAP for Portland Cement plants. In its final rule EPA specifically rejected adoption of risk-based exemptions for HCl and Mn. The commenter argues there are no differences sufficient to warrant a reversal of that decision in the Boiler MACT standard. Citizen groups also raised concerns that health risk information cited by EPA for HCl, hydrogen fluoride, hydrogen cyanide, and Mn does not establish “an ample margin of safety” and, therefore, no health threshold should be established. The commenters believe risk-based exemptions at levels less stringent than the MACT floor are prone to lawsuits that could potentially further delay implementation of the Boiler MACT.
Many commenters responded to EPA comment solicitation on how it should “appropriately” simulate all reasonable facility/exposure situations. Commenters contended that boilers can be located among a wide variety of industrial facilities, which makes predicting and assessing all possible mixtures of HCl and other emitted air pollutants difficult. These simulations would require the consideration of emissions from nearby facilities for the almost 15,500 boilers affected by this final rule. Commenters also characterized defining of exposure situations as challenging, for example PM can serve as “carriers” to bring the adhered HAP deep within the lung, where the HAP can interact with the respiratory system directly or be leached
Some commenters disagreed with using a hazard quotient (HQ) approach to establish a risk-based standard because the HQ would not account for potential toxicological interactions. The commenter noted that an HQ approach incorrectly assumes the different acid gases affect health through the same health endpoint, rather than assuming that the gases interact in an additive fashion. This commenter suggested that a hazard index approach, as described in EPA's “Guideline for the Health Risk Assessment of Chemical Mixtures” would be more appropriate.
Industry commenters dispute that emissions from other sources or source categories should be considered when developing an HBCA and they argued that Congress expected EPA to consider the effect of co-located facilities during the 112(f) residual risk program instead of under 112(d). Commenters added that there is no prior EPA precedent for considering co-located facilities from a different source category during the same 112 rulemaking. Commenters also provided examples where co-located sources and source categories are not a concern, such as small municipal utilities that do not operate co-located HAP sources within their fence line and are not located in heavily populated urban areas where other HAP sources are common due to zoning. Representatives of the small municipal utility industry suggested that concerns of co-located HAP sources should not be used to arbitrarily deny health-based relief already approved on a site-specific basis.
Several commenters disputed EPA's consideration of non-HAP collateral emissions reductions in setting MACT standards. They contended that EPA's sole support for its “collateral benefits” theory is legislative history—the Senate Report that accompanied Senate Bill 1630 in 1989 and noted that the D.C. Circuit rejected this use of this theory since the Senate Report referred to an earlier version of the statute that was ultimately not enacted. Instead commenters suggested that other components of the CAA, such as the National Ambient Air Quality Standards (NAAQS), are more appropriate avenues for mitigating emissions of criteria pollutants. Some commenters in the biomass industry noted that even if co-benefits of non-HAP were considered relevant to the analysis, the nominal co-benefits of reducing SO
Several other commenters suggested it is impossible to assess an established health threshold for HCl such that a 112(d)(4) standard could be set without evaluating the collateral benefits of a MACT standard. And, as described in the recently finalized cement kiln MACT rule, setting technology-based standards for HCl will result in significant reductions in the emissions of other pollutants, including SO
Several commenters indicated that the current economic climate requires EPA to balance economic and environmental interests and they indicated that HBCA would help target investments into solving true health threats where limits are no more stringent or less stringent than needed to protect public health. Many commenters provided compliance cost savings if an HBCA is included in this final rule. For example, representatives of one industry estimated aggregated capital savings in excess of $100 million just for the small facilities in the pulp & paper sector. Some commenters stressed the importance of an HBCA options for small entities affected by the regulations. Several other commenters suggested that EPA should estimate the costs and environmental effects of the HBCA option compared to a conventional MACT standard in order to make an informed decision on the adoption of an HBCA.
First, as explained in the preamble to the proposed rule, EPA continues to believe that the potential cumulative public health and environmental effects of acid gas emissions from boilers and other acid gas sources located near boilers supports the Agency's decision not to exercise its discretion under section 112(d)(4). EPA requested in the preamble to the proposed rule information regarding facility-specific emissions of acid gases from boilers as well as sources which may be co-located with boilers. In particular, information concerning the variation of acid gas emission rates that can be expected from the various subcategories of units was identified as a significant data gap. Additional data were not provided during the comment period, and the data already in hand regarding these emissions are not sufficient to support the development of emissions standards for any of the boilers subcategories under section 112(d) that take into account the health threshold for acid gases, particularly given that the Act requires EPA's consideration of health thresholds under section 112(d)(4) to protect public health with an ample margin of safety. In addition, the concerns expressed by EPA in the proposal regarding the potential environmental impacts and the cumulative impacts of acid gases on public health were not assuaged by the comments received.
EPA also received comments recommending not only that EPA establish emissions standards for acid gases pursuant to section 112(d)(4), but that it do so by excluding specific facilities from complying with emissions limits if the facility demonstrates that its emissions do not pose a health risk. EPA does not believe that a plain reading of the statute supports the establishment of such an approach. While section 112(d)(4) authorizes EPA to consider the level of
As explained in the preamble to the proposed rule, EPA also considered the co-benefits of setting a conventional MACT standard for HCl. EPA considered the comments received on this issue and continues to believe that the co-benefits are significant and provide an additional basis for the Administrator to conclude that it is not appropriate to exercise her discretion under section 112(d)(4). EPA disagrees with the commenters who stated that it is not appropriate to consider non-HAP benefits in deciding whether to invoke section 112(d)(4). Although MACT standards may directly regulate only HAPs and not criteria pollutants, Congress did recognize, in the legislative history to section 112(d)(4), that MACT standards would have the collateral benefit of controlling criteria pollutants as well and viewed this as an important benefit of the air toxics program.
Finally, EPA is not adopting an HBEL for manganese, as some commenters recommended. EPA did not propose or solicit comment on the adoption of an HBEL for manganese emissions, and since the final rule regulates PM as a surrogate for HAP metals and therefore does not establish a specific emissions limit for manganese, there is no reason to consider whether it would be appropriate to exercise section 112(d)(4) authority for manganese.
EPA also notes that sources had ample opportunity to perform testing on other units and submit the data to EPA for consideration. EPA informed various industry groups that additional test data would be welcomed, and to the extent that additional data were provided, such data were used in the floor-setting process. Furthermore, the large majority of the proposed emission limits were based on data from both phases of the ICR, with most of the data coming from the phase I ICR, in which EPA requested any existing emissions data, and commenters do not allege any bias associated with the phase I data. The only emission limits that were based primarily on phase II ICR data were the dioxin/furan limits, and for those pollutants, the units were not selected based on any assumptions about their dioxin/furan emissions or the effectiveness of add-on controls. Instead, the units were selected to ensure that data would be available to set floors for the subcategories that EPA was considering at the time of the Phase I ICR.
Some commenters provided input from boiler manufacturers and the guarantees that are currently available on the market for CO emissions. These guarantees include provisions that void the guarantee at loads below 25 percent load. Burner and boiler manufacturers state that CO emissions do fluctuate with load and suggest that limits should not be lower than manufacturer guarantees.
Many commenters took issue with the use of stack test data to set the emission limit. Due to the highly variable nature of CO emissions, setting a standard that boilers must meet at all times based on stack test data does not properly characterize boiler emissions. Noting that stack tests are typically conducted at 90 percent of full load, commenters contended that this represents a small and unrepresentative snapshot in time captured during the best operating conditions. Some commenters compared stack test averages to CEMS values showing extreme differences (CEMS data could be >10 times higher), and stated that stack tests do not come close to capturing the long-term variability of CO emissions. Furthermore, commenters stated that some boilers frequently operate at low-fire conditions and that stack tests are not conducted at “representative operation conditions”. A few commenters cited the DC Circuit [
While EPA did present a comparison of data from units that had both stack test and hourly CO CEMS data available, commenters stated that the data are not representative. EPA presented only three units which have CEMS data and stack test data, and these units do not have data over a wide load range that could be considered to represent typical operating conditions. Commenters also noted that no CEMS data for liquid units were available. Many commenters suggested that EPA acquire and incorporate more CEMS data when setting the limits to show a more accurate picture of variability. A few commenters also pointed out that CEMS data is needed to characterize intra-unit operating variability due to load changes, because the 99 percent UPL only characterizes inter-unit, steady-state operation. Looking at the CEMS data provided, some commenters used the “start anew” method to calculate a 30-day rolling average, and claimed that the unit would exceed the CO limit for several days, showing that the proposed limits are too low and the CEMS data are not appropriately considered.
Some commenters noted the discrepancy between using stack test data to set the limits, and then having to comply by using CEMS. They suggested that whichever method is used to set the limits, the same method should be used for compliance. Several commenters pointed out that although the vacated Boiler MACT included a requirement for CO CEMS, it did not require CO CEMS data obtained at less than 50 percent of maximum load to be included in the 30-day CO average. Commenters recommended that these data exclusions be incorporated in the compliance provisions of this final rule. In addition, a few commenters cited a ruling by the U.S. Court of Appeals for the D.C. Circuit that “a significant difference between techniques used by the Agency in arriving at standards, and requirements presently prescribed for determining compliance with standards, raises serious questions about the validity of the standard.” (
Finally, many commenters stated that the low proposed CO limits will cause additional challenges to boilers that are subject to NO
To develop emission limits based on 3-run stack tests, EPA first reviewed the emission test reports for the best performing sources in order to ensure that that data reflected the actual performance of the units during the testing periods. EPA also incorporated data corrections from facilities that submitted test data, and between these two quality assurance measures, EPA has ensured that accurate data were used to establish the emission limits. Second, EPA examined the operating load at which the stack tests were conducted and found that, as pointed out by multiple commenters, the stack test data are representative of conditions at or near full load. Third, EPA determined that the calibration range of the CO analyzer must be considered in determining the minimum value that can be supported technically during a CO stack test. This assessment of calibration range resulted in some low CO levels being adjusted upward, as explained in more detail in the docket memo entitled “Assessment of Minimum Levels of CO that Can Be Established Under Various Analyzer Calibration Ranges.” EPA then ranked the data for each subcategory and developed stack test-based emission limits using the 99.9 percent UPL. The 99.9 percent level was selected to provide an additional allowance for variability in the CO emission limits, since the CEM data show that CO levels have a higher degree of variability than other pollutants (for which EPA continues to use the 99 percent UPL). This change from the proposed 99 percent UPL level resulted in about a 10 percent increase in each of the CO emission limits (from the 99 percent UPL using the same data). The CO emission limits in today's rule must be met through the use of a stack test during the initial and annual compliance tests, and parametric monitoring is required to demonstrate continuous compliance. As discussed elsewhere in the preamble, during periods of startup and shutdown, units that would otherwise be subject to a numeric emission limit are instead subject to a work practice standard.
Several commenters stated that the Office of Air Quality Planning and Standards (OAQPS) cost manual used to estimate costs was outdated and inaccurate. They noted costs that were missing from the estimates, such as additional man-hours for record-keeping, compliance plan development and implementation, and operating and maintenance expenses. Some costs were said to be underestimated, such as the estimates for catalysts and carbon injection.
Response: EPA cost estimates took the flow rate capabilities of packed bed scrubbers into account by estimating additional scrubbers for units with flow rates beyond 75,000 scfm.
Table 2 of this preamble illustrates, for each basic fuel subcategory, the emissions reductions achieved by this final rule (
EPA estimated the additional water usage that would result from installing wet scrubbers to meet the emission limits for HCl would be 700 million gallons per year for existing sources and 242,000 gallons per year for new sources. In addition to the increased water usage, an additional 266 million gallons per year of wastewater would be produced for existing sources and 194,000 gallons per year for new sources. The annual costs of treating the additional wastewater are $1.4 million for existing sources and $1,055 for new sources. These costs are accounted for in the control costs estimates.
EPA estimated the additional solid waste that would result from the MACT floor level of control to be 100,450 tons per year for existing sources and 580 tons per year for new sources. Solid waste is generated from flyash and dust captured in PM and Hg controls as well as from spent carbon and spent sorbent that is injected into exhaust streams or used to filter gas streams. The costs of handling the additional solid waste generated are $4.2 million for existing sources and $25,000 for new sources. These costs are also accounted for in the control costs estimates.
A discussion of the methodology used to estimate impacts is presented in “Revised Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source (2011)”.
EPA expects an increase of approximately 1.442 billion kilowatt hours (kWh) in national annual energy usage as a result of this final rule. Of this amount, 1.436 billion kWh would be from existing sources and 6.2 million kWh are estimated from new sources. The increase results from the electricity required to operate control devices, such as wet scrubbers, electrostatic precipitators, and fabric filters which are expected to be installed to meet this final rule. Additionally, EPA expects work practice standards such as boilers tune-ups and combustion controls will improve the efficiency of boilers, resulting in an estimated fuel savings of 53 TBtu each year from existing sources and an additional 11 billion BTU each year from new sources. This fuel savings estimate includes only those fuel savings resulting from gas, liquid, and coal fuels and it is based on the assumption that the work practice standards will achieve 1 percent improvement in efficiency.
To estimate the national cost impacts of this final rule for existing sources, we developed average baseline emission factors for each fuel type/control device combination based on the emission data obtained and contained in the Boiler MACT emission database. If a unit reported emission data, we assigned its unit-specific emission data as its baseline emissions. If a unit did not report emission data but similar units at the facility with the same fuel and combustor design reported data, the average of all similar units at a given facility was assigned as its baseline emissions. If no unit-specific or similar units from the same facility had data available, a baseline average emission factor was assigned to the unit. Units that reported non-detect emission data for a pollutant that did not have a standardized numeric detection limit were assigned to the average of all non-detect emission data for that pollutant. For the remaining units that did not report emission data, we assigned the appropriate emission factors to each existing unit in the inventory database, based on the average emission factors for boilers with similar fuel, design, and control devices. We then compared each unit's baseline emission factors to the final MACT floor emission limit to determine if control devices were needed to meet the emission limits. The control analysis considered fabric filters and activated carbon injection to be the primary control devices for Hg control, ESP for units meeting Hg limits but requiring additional control to meet the PM limits, wet scrubbers, dry injection/fabric filters, or increased caustic rates to meet the HCl limits, depending on whether or not the facility was assumed to have a wastewater discharge permit, tune-ups, replacement burners, and combustion controls for CO and organic HAP control, and carbon injection for dioxin/furan control. We identified where one control device could achieve reductions in multiple pollutants, for example a fabric filter was expected to achieve both PM and Hg control in order to avoid overestimating the costs. We also included costs for testing and monitoring requirements contained in this final rule. The resulting total national cost impact of this final rule is 5.1 billion dollars in capital expenditures and 1.8 billion dollars per year in total annual costs. Considering estimated fuel savings resulting from work practice standards and combustion controls, the total annualized costs are reduced to 1.4 billion dollars. The total capital and annual costs include costs for control devices, work practices, testing and monitoring. Table 3 of this preamble shows the capital and annual cost impacts for each subcategory. Costs include testing and monitoring costs, but not recordkeeping and reporting costs.
Using Department of Energy projections on fuel expenditures, the number of additional boilers that could be potentially constructed was estimated. The resulting total national cost impact of this final rule in the 3rd year is 21 million dollars in capital expenditures and 6.1 million dollars per year in total annual costs, when considering a 1 percent fuel savings.
Potential control device cost savings and increased recordkeeping and reporting costs associated with the emissions averaging provisions and reduced testing allowance in this final rule are not accounted for in either the capital or annualized cost estimates.
A discussion of the methodology used to estimate cost impacts is presented in “Revised Methodology for Estimating the Control Costs for Industrial, Commercial, and Institutional Boiler and Process Heater NESHAP (2011)” and “Revised Methodology for Estimating Cost and Emission Impacts for Industrial, Commercial, and Industrial Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source (2011)” in the Docket.
Under this final rule, EPA's economic model suggests the average national market-level variables (prices, production-levels, consumption, international trade) will not change significantly (
In addition to estimating this rule's social costs and benefits, EPA has estimated the employment impacts of the final rule. We expect that the rule's direct impact on employment will be small. We have not quantified the rule's indirect or induced impacts. For further explanation and discussion of our analysis, see Chapter 4 of the RIA.
The benefit categories associated with the emission reduction anticipated for this rule can be broadly categorized as those benefits attributable to reduced exposure to hazardous air pollutants (HAPs) and those attributable to exposure to other pollutants. Because we were unable to monetize the benefits associated with reducing HAPs, all monetized benefits reflect improvements in ambient PM
These quantified benefits estimates represent the human health benefits associated with reducing exposure to PM
For this final rule, we have expanded and updated the analysis since the proposal in several important ways. Using the Comprehensive Air Quality Model with extensions (CAMx) model, we are able to provide boiler sector-specific air quality impacts attributable to the emission reductions anticipated from this final rule. We believe that this modeling provides estimates that are more appropriate for characterizing the health impacts and monetized benefits from boilers than the generic benefit-per-ton estimates used for the proposal analysis.
To generate the boiler sector-specific benefit-per-ton estimates, we used CAMx to convert emissions of direct PM
In addition, we estimated the ozone benefits for this final rule. Volatile organic compounds (VOC) are the primary ozone precursor affected by this final rule. We used CAMx to convert emissions of VOC into changes in ambient ozone levels and BenMAP to estimate the changes in human health associated with that change in air quality.
Furthermore, CAMx modeling allows us to model the reduced Hg deposition that would occur as a result of the estimated reductions of Hg emissions. Although we are unable to model Hg methylation and human consumption of Hg-contaminated fish, the Hg deposition maps provide an improved qualitative characterization of the Hg benefits associated with this final rulemaking.
For context, it is important to note that the magnitude of the PM benefits is largely driven by the concentration response function for premature mortality. Experts have advised EPA to consider a variety of assumptions, including estimates based on both empirical (epidemiological) studies and
EPA strives to use the best available science to support our benefits analyses. We recognize that interpretation of the science regarding air pollution and health is dynamic and evolving. After reviewing the scientific literature and recent scientific advice, we have determined that the no-threshold model is the most appropriate model for assessing the mortality benefits associated with reducing PM
Most of the estimated PM-related benefits in this final rule would accrue to populations exposed to higher levels of PM
It should be emphasized that the monetized benefits estimates provided above do not include benefits from several important benefit categories, including reducing other air pollutants, ecosystem effects, and visibility impairment. The benefits from reducing other pollutants have not been monetized in this analysis, including reducing 167,000 tons of CO, 30,000 tons of hydrochloric acid, 820 tons of HF, 23 grams of dioxins/furans, 2,900 pounds of Hg, and 22,700 tons of other metals each year. Specifically, we were unable to estimate the benefits associated with HAPs that would be reduced as a result of this rule due to data, resource, and methodology limitations. Challenges in quantifying the HAP benefits include a lack of exposure-response functions, uncertainties in emissions inventories and background levels, the difficulty of extrapolating risk estimates to low doses, and the challenges of tracking health progress for diseases with long latency periods. Although we do not have sufficient information or modeling available to provide monetized estimates for this rulemaking, we include a qualitative assessment of the health effects of these air pollutants in the RIA for this final rule, which is available in the docket. In addition, we provide maps of reduced mercury deposition anticipated from these rules in the RIA for this final rule.
In addition, the monetized benefits estimates provided in Table 4 do not reflect the disbenefits associated with increased electricity usage from operation of the control devices. We estimate that the increases in emissions of CO
This analysis does not include the type of detailed uncertainty assessment found in the 2006 PM
For more information on the benefits analysis, please refer to the RIA for this final rule that is available in the docket.
For units adding controls to meet the proposed emission limits, we anticipate very minor secondary air impacts. The combustion of fuel needed to generate additional electricity would yield slight increases in emissions, including NO
Section 112(c)(6) of the CAA requires EPA to identify categories of sources of seven specified pollutants to assure that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant are subject to standards under CAA Section 112(d)(2) or 112(d)(4). EPA has identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” “Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categories that emit two of the seven CAA Section 112(c)(6) pollutants: POM and Hg. (The POM emitted is composed of 16 polyaromatic hydrocarbons and extractable organic matter.) In the
Specifically, as byproducts of combustion, the formation of POM is effectively reduced by the combustion and post-combustion practices required to comply with the CAA Section 112 standards. Any POM that do form during combustion are further controlled by the various post-
In lieu of establishing numerical emissions limits for pollutants such as POM, we regulate surrogate substances. While we have not identified specific numerical limits for POM, CO serves as an effective surrogate for this HAP, because CO, like POM, is formed as a byproduct of combustion, and both would increase with an increase in the level of incomplete combustion.
Consequently, we have concluded that the emissions limits for CO function as a surrogate for control of POM, such that it is not necessary to require numerical emissions limits for POM with respect to boilers and process heaters to satisfy CAA Section 112(c)(6).
To further address POM and Hg emissions, this final rule also includes an energy assessment provision that encourage modifications to the facility to reduce energy demand that lead to these emissions.
Under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011), this action is an “economically significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities.
Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 and any changes in response to OMB recommendations have been documented in the docket for this action. For more information on the costs and benefits for this rule see the following table.
The information collection requirements in this final rule will be submitted for approval to the OMB under the
The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
This final rule would require maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions aside from the notification of alternative fuel use for those units that are in the Gas 1 subcategory but burn liquid fuels for periodic testing, or during periods of gas curtailment or gas supply emergencies. The recordkeeping requirements require only the specific information needed to determine compliance.
When a malfunction occurs, sources must report them according to the applicable reporting requirements of this Subpart DDDDD. An affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions is available to a source if it can demonstrate that certain criteria and requirements are satisfied. The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonable preventable and not caused by poor maintenance and or careless operation) and where the source took necessary actions to minimize emissions. In addition, the source must meet certain notification and reporting requirements. For example, the source must prepare a written root cause analysis and submit a written report to the Administrator documenting that it has met the conditions and requirements for assertion of the affirmative defense.
To provide the public with an estimate of the relative magnitude of the burden associated with an assertion of the affirmative defense position adopted by a source, EPA provides an administrative adjustment to this ICR that shows what the notification, recordkeeping and reporting requirements associated with the assertion of the affirmative defense might entail. EPA's estimate for the required notification, reports and records, including the root cause analysis, totals $3,141 and is based on the time and effort required of a source to review relevant data, interview plant employees, and document the events surrounding a malfunction that has caused an exceedance of an emission limit. The estimate also includes time to produce and retain the record and reports for submission to EPA. EPA provides this illustrative estimate of this burden because these costs are only incurred if there has been a violation and a source chooses to take advantage of the affirmative defense.
The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $95.9 million. This includes 280,459 labor hours per year at a total labor cost of $26.5 million per year, and total non-labor capital costs of $69.3 million per year. This estimate includes initial and annual performance test, conducting an documenting an energy assessment, conducting fuel specifications for Gas 1 units, repeat testing under worst-case conditions for solid fuel units, conducting and documenting a tune-up, semiannual excess emission reports, maintenance inspections, developing a monitoring plan, notifications, and recordkeeping. Monitoring, testing, tune-up and energy assessment costs and cost were also included in the cost estimates presented in the control costs impacts estimates in section IV.D of this preamble. The total burden for the Federal government (averaged over the first 3 years after the effective date of the standard) is estimated to be 97,563 hours per year at a total labor cost of $5.2 million per year.
Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and use technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the
The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business according to Small Business Administration (SBA) size standards by the North American Industry Classification System category of the owning entity. The range of small business size standards for the affected industries ranges from 500 to 1,000 employees, except for petroleum refining and electric utilities. In these latter two industries, the size standard is 1,500 employees and a mass throughput of 75,000 barrels/day or less, and 4 million kilowatt-hours of production or less, respectively; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.
Pursuant to section 603 of the RFA, EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review Panel to
As required by section 604 of the RFA, we also prepared a final regulatory flexibility analysis (FRFA) for today's final rule. The FRFA addresses the issues raised by public comments on the IRFA, which was part of the proposal of this rule. The FRFA, which is included as a section in the RIA, is available for review in the docket and is summarized below.
Section II.A of this preamble describes the reasons that EPA is finalizing this action. The rule is intended to reduce emissions of HAP as required under section 112 of the CAA. Many significant issues were raised during the public comment period, and EPA's responses to those comments are presented in section V of this preamble or in the response to comments document contained in the docket. Significant changes to the rule that resulted from the public comments are described in section IV of this preamble.
The primary comments on the IRFA were provided by SBA, with the remainder of the comments generally supporting SBA's comments. Those comments included the following: EPA should have adopted a health-based compliance alternative (HBCA) which provides alternative emission limits for threshold chemicals; EPA should have adopted additional subcategories, including the following: Subcategories based on fuel type (including coal rank, bagasse, biomass by type, and oil by type), unit design type (
In response to the comments on the IRFA and other public comments, EPA made the following changes to the final rule. EPA adopted additional subcategories, including a limited-use subcategory for units that operate less than 10 percent of the operating hours in a year, a non-continental liquid unit subcategory for units with the unique challenges faced by remote island locations, and a combination suspension/grate boiler subcategory. EPA also consolidated the subcategories for units combusting various types of solid fuels, which will simplify compliance and will allow units to combust varying percentages of different solid fuels without triggering subcategory changes. EPA also decreased monitoring and testing costs by eliminating the CO CEMS requirement for units greater than 100 mmBtu/hr and changing the dioxin testing requirement to a one-time test. The final rule also includes work practice standards for additional subcategories, including limited-use units, new small units, and units combusting gaseous fuels that are demonstrated to have similar contaminant levels to natural gas. Finally, EPA is finalizing emission limits that are less stringent than the proposed limits for most of the subcategory/pollutant combinations. The emission limit changes are largely due to the changes in subcategories, data corrections, and incorporation of new data into the floor calculations. Additional details on the changes discussed in this paragraph are included in sections IV and V of this preamble.
While EPA did make significant changes based on public comment, EPA did not finalize a HBCA or HBELs and is maintaining, but clarifying, the energy assessment requirement. The discussion of the HBCA decision is included in section V of this preamble. Some changes to the energy assessment requirement that will reduce costs for small entities include a the following provisions: The energy assessment for facilities with affected boilers and process heaters using less than 0.3 trillion Btu per year heat input will be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a one-day energy assessment; and the energy assessment for facilities with affected boilers and process heaters using 0.3 to 1.0 trillion Btu per year will be 3 days in length maximum. The boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a 3-day energy assessment. In addition, energy assessments that have been conducted after January 1, 2008 are considered adequate as long as they meet or are amended to meet the requirements of the energy assessment.
While EPA did not make major adjustments to the emissions averaging provisions, the change to a solid fuel subcategory will enable all solid fuel-fired units at a facility to use the emissions averaging provision for Hg, PM, and HCl.
The rule applies to a many different types of small entities. The table below describes the small entities identified in the Combustion Facility Survey.
We compared the estimated costs to the sales for these entities. The results are found in the following table.
The information collection activities in this ICR include initial and annual stack tests, fuel analyses, operating parameter monitoring, continuous O2 monitoring for all units greater than 10 mmBtu/hr, continuous emission monitoring for PM at units greater than 250 mmBtu/hr, certified energy audits, annual or biennial tune-ups (depending on the size of the combustion equipment), preparation of a site-specific monitoring plan and a site-specific fuel monitoring plan, one-time and periodic reports, and the maintenance of records. Based on the distribution of major source facilities with affected boilers or process heaters reported in the 2008 survey entitled “Information Collection Effort for Facilities with Combustion Units (ICR No. 2286.01),” there are 1,639 existing facilities with affected boilers or process heaters. Of these, 94 percent are located in the private sector and the remaining 6 percent are located in the public sector. A table included in the FRFA summarizes the types and number of each type of small entities expected to be affected by the major source rule.
The Agency expects that persons with knowledge of .pdf software, spreadsheet and relational database programs will be necessary in order to prepare the report or record. Based on experience with previous emission stack testing, we expect most facilities to contract out preparation of the reports associated with emission stack testing, including creation of the Electronic Reporting Tool submittal which will minimize the need for in depth knowledge of databases or spreadsheet software at the source. We also expect affected sources will need to work with web-based applicability tools and flowcharts to determine the requirements applicable to them, knowledge of the heat input capacity and fuel use of the combustion
As required by section 212 of SBREFA, EPA also is preparing a Small Entity Compliance Guide to help small entities comply with this rule. Small entities will be able to obtain a copy of the Small Entity Compliance guide at the following Web site:
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104–4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, we generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any 1 year. Before promulgating a rule for which a written statement is needed, section 205 of the UMRA generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows us to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before we establish any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government agency plan under section 203 of the UMRA. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.
We have determined that this final rule contains a Federal mandate that may result in expenditures of $100 million or more for State, local, and Tribal governments, in the aggregate, or the private sector in any 1 year. Accordingly, we have prepared a written statement entitled “Unfunded Mandates Reform Act Analysis for the Proposed Industrial Boilers and Process Heaters NESHAP” under section 202 of the UMRA which is summarized below.
As discussed in section I of this preamble, the statutory authority for this final rulemaking is section 112 of the CAA. Title III of the CAA Amendments was enacted to reduce nationwide air toxic emissions. Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP which require existing and new major sources to control emissions of HAP using MACT based standards. This NESHAP applies to all ICI boilers and process heaters located at major sources of HAP emissions.
In compliance with section 205(a) of the UMRA, we identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives is presented in the docket.
The regulatory alternative upon which this final rule is based represents the MACT floor for industrial boilers and process heaters and, as a result, it is the least costly and least burdensome alternative.
The regulatory impact analysis prepared for this final rule, including the Agency's assessment of costs and benefits, is detailed in the “Regulatory Impact Analysis for the Proposed Industrial Boilers and Process Heaters MACT” in the docket. Based on estimated compliance costs associated with this final rule and the predicted change in prices and production in the affected industries, the estimated social costs of this final rule are $1.5 billion (2008 dollars).
It is estimated that 3 years after implementation of this final rule, HAP would be reduced by thousands of tons, including reductions in hydrochloric acid, hydrogen fluoride, metallic HAP including Hg, and several other organic HAP from boilers and process heaters. Studies have determined a relationship between exposure to these HAP and the onset of cancer, however, the Agency is unable to provide a monetized estimate of the HAP benefits at this time. In addition, there are significant reductions in PM
The UMRA requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by this final rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of the rule are discussed previously in this preamble.
We do not believe that there will be any disproportionate budgetary effects of this final rule on any particular areas of the country, State or local governments, types of communities (e.g., urban, rural), or particular industry
The Unfunded Mandates Act requires that we estimate the effect of this final rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and international competitiveness of the U.S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material.
The nationwide economic impact of this final rule is presented in the “Economic Impact Analysis for the Industrial Boilers and Process Heaters MACT” in the docket. This analysis provides estimates of the effect of this rule on some of the categories mentioned above. The results of the economic impact analysis are summarized previously in this preamble. The results show that there will be a small impact on prices and output, and little impact on communities that may be affected by this final rule. In addition, there should be little impact on energy markets (in this case, coal, natural gas, petroleum products, and electricity). Hence, the potential impacts on the categories mentioned above should be small.
The Unfunded Mandates Act requires that we describe the extent of the Agency's prior consultation with affected State, local, and tribal officials, summarize the officials' comments or concerns, and summarize our response to those comments or concerns. In addition, section 203 of the UMRA requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. We have consulted with State and local air pollution control officials. We have also held meetings on this final rule with many of the stakeholders from numerous individual companies, institutions, environmental groups, consultants and vendors, labor unions, and other interested parties. We have added materials to the Air Docket to document these meetings.
In addition, we have determined that this final rule contains no regulatory requirements that might significantly or uniquely affect small governments. While some small governments may have some sources affected by this final rule, the impacts are not expected to be significant. Therefore, this final rule is not subject to the requirements of section 203 of the UMRA.
Executive Order 13132 (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
This final rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this final rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comment on this proposed rule from State and local officials.
Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. Executive Order 13175 requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.”
EPA has concluded that this action may have tribal implications. However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This rule would impose requirements on owners and operators of major industrial boilers. We are only aware of a few installations of industrial, commercial, or institutional boilers owned or operated by Indian tribal governments. We conducted outreach to tribal environmental staff on this rule through the Tribal Air Newsletter, discussions at the National Tribal Forum and the monthly conference call with the National Tribal Air Association, we also hosted a webinar on the proposed rule in which tribal environmental staff participated.
Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that: (1) Is determined to be “economically significant” as defined under Executive Orders 12866 and 13563, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of this planned rule on children, and explain why this planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.
This final rule is not subject to Executive Order 13045 because the Agency does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. The reason for this determination is that this final rule is based solely on technology performance.
Executive Order 13211, (66 FR 28355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211 defines “significant energy actions” as “any action by an agency (normally published in the
We estimate a 0.05 percent price increase for the energy sector and a −0.02 percent percentage change in production. We estimate a 0.09 percent increase in energy imports. For more information on the estimated energy effects, please refer to the economic impact analysis for this final rule. The analysis is available in the public docket.
Therefore, we conclude that this final rule when implemented is not likely to have a significant adverse effect on the supply, distribution, or use of energy.
Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Pub. L. 104–113; 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (
This rulemaking involves technical standards. EPA cites the following standards in the final rule: EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29 of 40 CFR part 60. Consistent with the NTTAA, EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicable voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are placed in the docket for the proposed rule.
The three voluntary consensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the final rule.
The voluntary consensus standard American Society of Mechanical Engineers (ASME) PTC 19–10–1981–Part 10, “Flue and Exhaust Gas Analyses,” is cited in the proposed rule for its manual method for measuring the oxygen, CO
The voluntary consensus standard ASTM D6522–00, “Standard Test Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers and Process Heaters Using Portable Analyzers” is an acceptable alternative to EPA Method 3A for identifying CO and oxygen concentrations for this final rule when the fuel is natural gas.
The voluntary consensus standard ASTM Z65907, “Standard Method for Both Speciated and Elemental Mercury Determination,” is an acceptable alternative to EPA Method 29 (portion for Hg only) for the purpose of this final rule. This standard can be used in the final rule to determine the Hg concentration in stack gases for boilers with rated heat input capacities of greater than 250 MMBtu/hr.
In addition to the voluntary consensus standards EPA used in the proposed rule, the search for emissions measurement procedures identified 15 other voluntary consensus standards. EPA determined that 13 of these 15 standards identified for measuring emissions of the HAP or surrogates subject to emission standards in the proposed rule were impractical alternatives to EPA test methods for the purposes of this final rule. Therefore, EPA does not intend to adopt these standards for this purpose. The reasons for this determination for the 13 methods are discussed below.
The voluntary consensus standard ASTM D3154–00, “Standard Method for Average Velocity in a Duct (Pitot Tube Method),” is impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the proposed rulemaking since the standard appears to lack in quality control and quality assurance requirements. Specifically, ASTM D3154–00 does not include the following: (1) Proof that openings of standard pitot tube have not plugged during the test; (2) if differential pressure gauges other than inclined manometers (
The voluntary consensus standard ASTM D3464–96 (2001), “Standard Test Method Average Velocity in a Duct Using a Thermal Anemometer,” is impractical as an alternative to EPA Method 2 for the purposes of the proposed rule primarily because applicability specifications are not clearly defined,
The voluntary consensus standard ISO 10780:1994, “Stationary Source Emissions—Measurement of Velocity and Volume Flowrate of Gas Streams in Ducts,” is impractical as an alternative to EPA Method 2 in the proposed rule. The standard recommends the use of an L-shaped pitot, which historically has not been recommended by EPA. EPA specifies the S-type design which has large openings that are less likely to plug up with dust.
The voluntary consensus standard, CAN/CSA Z223.2–M86 (1999), “Method for the Continuous Measurement of Oxygen, Carbon Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed Combustion Flue Gas Streams,” is unacceptable as a substitute for EPA Method 3A since it does not include quantitative specifications for measurement system performance, most notably the calibration procedures and instrument performance characteristics. The instrument performance characteristics that are provided are nonmandatory and also do not provide the same level of quality assurance as the EPA methods. For example, the zero and span/calibration drift is only checked weekly, whereas the EPA methods require drift checks after each run.
Two very similar voluntary consensus standards, ASTM D5835–95 (2001), “Standard Practice for Sampling Stationary Source Emissions for Automated Determination of Gas Concentration,” and ISO 10396:1993, “Stationary Source Emissions: Sampling for the Automated Determination of Gas Concentrations,” are impractical alternatives to EPA Method 3A for the purposes of this final rule because they lack in detail and quality assurance/quality control requirements. Specifically, these two standards do not include the following: (1) Sensitivity of the method; (2) acceptable levels of analyzer calibration error; (3) acceptable levels of sampling system bias; (4) zero drift and calibration drift limits, time span, and required testing frequency; (5) a method to test the interference response of the analyzer; (6) procedures
The voluntary consensus standard ISO 12039:2001, “Stationary Source Emissions—Determination of Carbon Monoxide, Carbon Dioxide, and Oxygen—Automated Methods,” is not acceptable as an alternative to EPA Method 3A. This ISO standard is similar to EPA Method 3A, but is missing some key features. In terms of sampling, the hardware required by ISO 12039:2001 does not include a 3-way calibration valve assembly or equivalent to block the sample gas flow while calibration gases are introduced. In its calibration procedures, ISO 12039:2001 only specifies a two-point calibration while EPA Method 3A specifies a three-point calibration. Also, ISO 12039:2001 does not specify performance criteria for calibration error, calibration drift, or sampling system bias tests as in the EPA method, although checks of these quality control features are required by the ISO standard.
The voluntary consensus standard ASME PTC–38–80 R85 (1985), “Determination of the Concentration of Particulate Matter in Gas Streams,” is not acceptable as an alternative for EPA Method 5 because ASTM PTC–38–80 is not specific about equipment requirements, and instead presents the options available and the pro's and con's of each option. The key specific differences between ASME PTC–38–80 and the EPA methods are that the ASME standard: (1) Allows in-stack filter placement as compared to the out-of-stack filter placement in EPA Methods 5 and 17; (2) allows many different types of nozzles, pitots, and filtering equipment; (3) does not specify a filter weighing protocol or a minimum allowable filter weight fluctuation as in the EPA methods; and (4) allows filter paper to be only 99 percent efficient, as compared to the 99.95 percent efficiency required by the EPA methods.
The voluntary consensus standard ASTM D3685/D3685M–98, “Test Methods for Sampling and Determination of Particulate Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but is lacking in the following areas that are needed to produce quality, representative particulate data: (1) Requirement that the filter holder temperature should be between 120° C and 134° C, and not just “above the acid dew-point;” (2) detailed specifications for measuring and monitoring the filter holder temperature during sampling; (3) procedures similar to EPA Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4) technical guidance for performing the Method 5 sampling procedures,
The voluntary consensus standard ISO 9096:1992, “Determination of Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying Ducts—Manual Gravimetric Method,” is not acceptable as an alternative for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA Method 5 for collection of particulate matter. The standard ISO 9096 does not provide applicable technical guidance for performing many of the integral procedures specified in Methods 1, 2, and 5. Major performance and operational details are lacking or nonexistent, and detailed quality assurance/quality control guidance for the sampling operations required to produce quality, representative particulate data (
The voluntary consensus standard CAN/CSA Z223.1–M1977, “Method for the Determination of Particulate Mass Flows in Enclosed Gas Streams,” is not acceptable as an alternative for EPA Method 5. Detailed technical procedures and quality control measures that are required in EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing requirement to repeat weighing every 6 hours until a constant weight is achieved. Third, EPA Method 5 requires the filter weight to be reported to the nearest 0.1 milligram (mg), while CAN/CSA Z223.1 requires only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot for velocity measurement when plugging of the tube opening is not expected to be a problem. Whereas, EPA Method 5 requires an S-shaped pitot.
The voluntary consensus standard EN 1911–1,2,3 (1998), “Stationary Source Emissions-Manual Method of Determination of HCl-Part 1: Sampling of Gases Ratified European Text-Part 2: Gaseous Compounds Absorption Ratified European Text-Part 3: Adsorption Solutions Analysis and Calculation Ratified European Text,” is impractical as an alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered equivalent to EPA Method 26 or 26A because the sample absorbing solution (water) would be expected to capture both HCl and chlorine gas, if present, without the ability to distinguish between the two. The EPA Methods 26 and 26A use an acidified absorbing solution to first separate HCl and chlorine gas so that they can be selectively absorbed, analyzed, and reported separately. In addition, in EN 1911 the absorption efficiency for chlorine gas would be expected to vary as the pH of the water changed during sampling.
The voluntary consensus standard EN 13211 (1998), is not acceptable as an alternative to the Hg portion of EPA Method 29 primarily because it is not validated for use with impingers, as in the EPA method, although the method describes procedures for the use of impingers. This European standard is validated for the use of fritted bubblers only and requires the use of a side (split) stream arrangement for isokinetic sampling because of the low sampling rate of the bubblers (up to 3 liters per minute, maximum). Also, only two bubblers (or impingers) are required by EN 13211, whereas EPA Method 29 require the use of six impingers. In addition, EN 13211 does not include many of the quality control procedures of EPA Method 29, especially for the use and calibration of temperature sensors and controllers, sampling train assembly and disassembly, and filter weighing.
Two of the 15 voluntary consensus standards identified in this search were not available at the time the review was conducted for the purposes of the proposed rule because they are under development by a voluntary consensus body: ASME/BSR MFC 13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 (and possibly 1); and
Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR part 63, list the EPA testing methods included in the proposed rule. Under § 63.7(f) and § 63.8(f) of subpart A of the General Provisions, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures.
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice (EJ). Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations, low-income, and Tribal populations in the United States.
This final action establishes national emission standards for new and existing industrial, commercial, institutional boilers and process heaters that combust non-waste materials (
This final rule will reduce emissions of all the listed HAP that come from boilers and process heaters. This includes metals (Hg, arsenic, beryllium, cadmium, chromium, lead, Mn, nickel, and selenium), organics (POM, acetaldehyde, acrolein, benzene, dioxin/furan, ethylene dichloride, formaldehyde, and polychlorinated biphenyls), hydrochloric acid, and hydrofluoric acid. Adverse health effects from these pollutants include cancer, irritation of the lungs, skin, and mucus membranes; effects on the central nervous system, damage to the kidneys, and other acute health disorders. This final rule will also result in substantial reductions of criteria pollutants such as CO, NO
Based on the fact that this final rule does not allow emission increases, EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority, low-income, or Tribal populations. To address Executive Order 12898, EPA has conducted analyses to determine the aggregate demographic makeup of the communities near affected sources. EPA's demographic analysis of populations within the three-mile radius showed that major source boilers are located in areas where minorities are overrepresented when compared to the national average. For these same areas, there is also an overrepresentation of population below the poverty line as compared to the national average. The results of the demographic analysis are presented in “Review of Environmental Justice Impacts”, April 2010, a copy of which is available in the docket. However, to the extent that any minority, low income, or Tribal subpopulation is disproportionately impacted by the current emissions as a result of the proximity of their homes to these sources, that subpopulation also stands to see increased environmental and health benefit from the emissions reductions called for by this rule.
EPA defines “Environmental Justice” to include meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and polices. To promote meaningful involvement, EPA has developed a communication and outreach strategy to ensure that interested communities have access to this final rule and are aware of its content. EPA also ensured that interested communities had an opportunity to comment during the comment period. During the comment period that followed the June 2010 proposal, EPA publicized the rulemaking via EJ newsletters, Tribal newsletters, EJ listservs, and the internet, including the Office of Policy's (OP) Rulemaking Gateway Web site (
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of the Federal Regulations is amended as follows:
42 U.S.C. 7401,
(b) * * *
(27) ASTM D6522–00, Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from
(35) ASTM D6784–02 (Reapproved 2008) Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), approved April 1, 2008, IBR approved for table 1 to subpart DDDDD of this part, table 2 to subpart DDDDD of this part, table 5 to subpart DDDDD of this part, table 12 to subpart DDDDD of this part, and table 4 to subpart JJJJJJ of this part.
(39) ASTM D388–05 Standard Classification of Coals by Rank, approved September 15, 2005, IBR approved for § 63.7575 and § 63.11237.
(40) ASTM D396–10 Standard Specification for Fuel Oils, approved October 1, 2010, IBR approved for § 63.7575.
(41) ASTM D1835–05 Standard Specification for Liquefied Petroleum (LP) Gases, approved April 1, 2005, IBR approved for § 63.7575 and § 63.11237.
(42) ASTM D2013/D2013M–09 Standard Practice for Preparing Coal Samples for Analysis, approved November 1, 2009, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(43) ASTM D2234/D2234M–10 Standard Practice for Collection of a Gross Sample of Coal, approved January 1, 2010, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(44) ASTM D3173–03 (Reapproved 2008) Standard Test Method for Moisture in the Analysis Sample of Coal and Coke, approved February 1, 2008, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(47) ASTM D5198–09 Standard Practice for Nitric Acid Digestion of Solid Waste, approved February 1, 2009, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(48) ASTM D5865–10a Standard Test Method for Gross Calorific Value of Coal and Coke, approved May 1, 2010, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(49) ASTM D6323–98 (Reapproved 2003) Standard Guide for Laboratory Subsampling of Media Related to Waste Management Activities, approved August 10, 2003, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(50) ASTM E711–87 (Reapproved 2004) Standard Test Method for Gross Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter, approved August 28, 1987, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(51) ASTM E776–87 (Reapproved 2009) Standard Test Method for Forms of Chlorine in Refuse-Derived Fuel, approved July 1, 2009, IBR approved for table 6 to subpart DDDDD of this part.
(52) ASTM E871–82 (Reapproved 2006) Standard Test Method for Moisture Analysis of Particulate Wood Fuels, approved November 1, 2006, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(57) ASTM D6721–01 (Reapproved 2006) Standard Test Method for Determination of Chlorine in Coal by Oxidative Hydrolysis Microcoulometry, approved April 1, 2006, IBR approved for table 6 to subpart DDDDD of this part.
(61) ASTM D6722–01 (Reapproved 2006) Standard Test Method for Total Mercury in Coal and Coal Combustion Residues by the Direct Combustion Analysis, approved April 1, 2006, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(64) ASTM D6522–00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, approved October 1, 2005, IBR approved for table 4 to subpart ZZZZ of this part, table 5 to subpart DDDDD of this part, and table 4 to subpart JJJJJJ of this part.
(66) ASTM D4084–07 Standard Test Method for Analysis of Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), approved June 1, 2007, IBR approved for table 6 to subpart DDDDD of this part.
(67) ASTM D5954–98 (Reapproved 2006), Standard Test Method for Mercury Sampling and Measurement in Natural Gas by Atomic Absorption Spectroscopy, approved December 1, 2006, IBR approved for table 6 to subpart DDDDD of this part.
(68) ASTM D6350–98 (Reapproved 2003) Standard Test Method for Mercury Sampling and Analysis in Natural Gas by Atomic Fluorescence Spectroscopy, approved May 10, 2003, IBR approved for table 6 to subpart DDDDD of this part.
(i) * * *
(1) ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus],” IBR approved for §§ 63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to subpart ZZZZZ of this part, and table 4 to subpart JJJJJJ of this part.
(p) The following material is available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272–0167,
(1) National Emission Standards for Hazardous Air Pollutants (NESHAP) for Integrated Iron and Steel Plants—Background Information for Proposed Standards, Final Report, EPA–453/R–01–005, January 2001, IBR approved for § 63.7491(g).
(2) Office Of Air Quality Planning And Standards (OAQPS), Fabric Filter Bag Leak Detection Guidance, EPA–454/R–98–015, September 1997, IBR approved for § 63.7525(j)(2) and § 63.11224(f)(2).
(3) SW–846–3020A, Acid Digestion of Aqueous Samples And Extracts For Total Metals For Analysis By GFAA Spectroscopy, Revision 1, July 1992, in EPA Publication No. SW–846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(4) SW–846–3050B, Acid Digestion of Sediments, Sludges, And Soils, Revision 2, December 1996, in EPA Publication No. SW–846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(5) SW–846–7470A, Mercury In Liquid Waste (Manual Cold-Vapor Technique), Revision 1, September 1994, in EPA Publication No. SW–846,
(6) SW–846–7471B, Mercury In Solid Or Semisolid Waste (Manual Cold-Vapor Technique), Revision 2, February 2007, in EPA Publication No. SW–846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
(7) SW–846–9250, Chloride (Colorimetric, Automated Ferricyanide AAI), Revision 0, September 1986, in EPA Publication No. SW–846, Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third Edition, IBR approved for table 6 to subpart DDDDD of this part.
(q) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH–1211 Geneva 20, Switzerland, +41 22 749 01 11,
(1) ISO 6978–1:2003(E), Natural Gas—Determination of Mercury—Part 1: Sampling of Mercury by Chemisorption on Iodine, First edition, October 15, 2003, IBR approved for table 6 to subpart DDDDD of this part.
(2) ISO 6978–2:2003(E), Natural gas—Determination of Mercury—Part 2: Sampling of Mercury by Amalgamation on Gold/Platinum Alloy, First edition, October 15, 2003, IBR approved for table 6 to subpart DDDDD of this part.
This subpart establishes national emission limitations and work practice standards for hazardous air pollutants (HAP) emitted from industrial, commercial, and institutional boilers and process heaters located at major sources of HAP. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and work practice standards.
You are subject to this subpart if you own or operate an industrial, commercial, or institutional boiler or process heater as defined in § 63.7575 that is located at, or is part of, a major source of HAP, except as specified in § 63.7491. For purposes of this subpart, a major source of HAP is as defined in § 63.2, except that for oil and natural gas production facilities, a major source of HAP is as defined in § 63.761 (subpart HH of this part, National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities).
(a) This subpart applies to new, reconstructed, and existing affected sources as described in paragraphs (a)(1) and (2) of this section.
(1) The affected source of this subpart is the collection at a major source of all existing industrial, commercial, and institutional boilers and process heaters within a subcategory as defined in § 63.7575.
(2) The affected source of this subpart is each new or reconstructed industrial, commercial, or institutional boiler or
(b) A boiler or process heater is new if you commence construction of the boiler or process heater after June 4, 2010, and you meet the applicability criteria at the time you commence construction.
(c) A boiler or process heater is reconstructed if you meet the reconstruction criteria as defined in § 63.2, you commence reconstruction after June 4, 2010, and you meet the applicability criteria at the time you commence reconstruction.
(d) A boiler or process heater is existing if it is not new or reconstructed.
The types of boilers and process heaters listed in paragraphs (a) through (m) of this section are not subject to this subpart.
(a) An electric utility steam generating unit.
(b) A recovery boiler or furnace covered by subpart MM of this part.
(c) A boiler or process heater that is used specifically for research and development. This does not include units that provide heat or steam to a process at a research and development facility.
(d) A hot water heater as defined in this subpart.
(e) A refining kettle covered by subpart X of this part.
(f) An ethylene cracking furnace covered by subpart YY of this part.
(g) Blast furnace stoves as described in EPA–453/R–01–005 (incorporated by reference, see § 63.14).
(h) Any boiler or process heater that is part of the affected source subject to another subpart of this part (i.e., another National Emission Standards for Hazardous Air Pollutants in 40 CFR part 63).
(i) Any boiler or process heater that is used as a control device to comply with another subpart of this part, provided that at least 50 percent of the heat input to the boiler is provided by the gas stream that is regulated under another subpart.
(j) Temporary boilers as defined in this subpart.
(k) Blast furnace gas fuel-fired boilers and process heaters as defined in this subpart.
(l) Any boiler specifically listed as an affected source in any standard(s) established under section 129 of the Clean Air Act.
(m) A boiler required to have a permit under section 3005 of the Solid Waste Disposal Act or covered by subpart EEE of this part (e.g., hazardous waste boilers).
(a) If you have a new or reconstructed boiler or process heater, you must comply with this subpart by May 20, 2011 or upon startup of your boiler or process heater, whichever is later.
(b) If you have an existing boiler or process heater, you must comply with this subpart no later than March 21, 2014.
(c) If you have an area source that increases its emissions or its potential to emit such that it becomes a major source of HAP, paragraphs (c)(1) and (2) of this section apply to you.
(1) Any new or reconstructed boiler or process heater at the existing source must be in compliance with this subpart upon startup.
(2) Any existing boiler or process heater at the existing source must be in compliance with this subpart within 3 years after the source becomes a major source.
(d) You must meet the notification requirements in § 63.7545 according to the schedule in § 63.7545 and in subpart A of this part. Some of the notifications must be submitted before you are required to comply with the emission limits and work practice standards in this subpart.
(e) 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 § 63.7491(l) 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.
The subcategories of boilers and process heaters, as defined in § 63.7575 are:
(a) Pulverized coal/solid fossil fuel units.
(b) Stokers designed to burn coal/solid fossil fuel.
(c) Fluidized bed units designed to burn coal/solid fossil fuel.
(d) Stokers designed to burn biomass/bio-based solid.
(e) Fluidized bed units designed to burn biomass/bio-based solid.
(f) Suspension burners/Dutch Ovens designed to burn biomass/bio-based solid.
(g) Fuel Cells designed to burn biomass/bio-based solid.
(h) Hybrid suspension/grate burners designed to burn biomass/bio-based solid.
(i) Units designed to burn solid fuel.
(j) Units designed to burn liquid fuel.
(k) Units designed to burn liquid fuel in non-continental States or territories.
(l) Units designed to burn natural gas, refinery gas or other gas 1 fuels.
(m) Units designed to burn gas 2 (other) gases.
(n) Metal process furnaces.
(o) Limited-use boilers and process heaters.
(a) You must meet the requirements in paragraphs (a)(1) through (3) of this section, except as provided in paragraphs (b) and (c) of this section. You must meet these requirements at all times.
(1) You must meet each emission limit and work practice standard in Tables 1 through 3, and 12 to this subpart that applies to your boiler or process heater, for each boiler or process heater at your source, except as provided under § 63.7522. If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before May 20, 2011, you may comply with the emission limits in Table 1 or 12 to this subpart until March 21, 2014. On and after March 21, 2014, you must comply with the emission limits in Table 1 to this subpart.
(2) You must meet each operating limit in Table 4 to this subpart that applies to your boiler or process heater. If you use a control device or combination of control devices not covered in Table 4 to this subpart, or you wish to establish and monitor an alternative operating limit and alternative monitoring parameters, you must apply to the EPA Administrator for approval of alternative monitoring under § 63.8(f).
(3) At all times, you must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator that may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.
(b) As provided in § 63.6(g), EPA may approve use of an alternative to the work practice standards in this section.
(c) Limited-use boilers and process heaters must complete a biennial tune-up as specified in § 63.7540. They are not subject to the emission limits in Tables 1 and 2 to this subpart, the annual tune-up requirement in Table 3 to this subpart, or the operating limits in Table 4 to this subpart. Major sources that have limited-use boilers and process heaters must complete an energy assessment as specified in Table 3 to this subpart if the source has other existing boilers subject to this subpart that are not limited-use boilers.
In response to an action to enforce the emission limitations and operating limits set forth in § 63.7500 you may assert an affirmative defense to a claim for civil penalties for exceeding such standards that are caused by malfunction, as defined at § 63.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:
(1) The excess emissions:
(i) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner, and
(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
(iv) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
(3) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and
(4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health; and
(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
(7) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and
(8) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.
(b)
(a) You must be in compliance with the emission limits and operating limits in this subpart. These limits apply to you at all times.
(b) [Reserved]
(c) You must demonstrate compliance with all applicable emission limits using performance testing, fuel analysis, or continuous monitoring systems (CMS), including a continuous emission monitoring system (CEMS) or continuous opacity monitoring system (COMS), where applicable. You may demonstrate compliance with the applicable emission limit for hydrogen chloride or mercury using fuel analysis if the emission rate calculated according to § 63.7530(c) is less than the applicable emission limit. Otherwise, you must demonstrate compliance for hydrogen chloride or mercury using performance testing, if subject to an applicable emission limit listed in Table 1, 2, or 12 to this subpart.
(d) If you demonstrate compliance with any applicable emission limit through performance testing and subsequent compliance with operating limits (including the use of continuous parameter monitoring system), or with a CEMS, or COMS, you must develop a site-specific monitoring plan according to the requirements in paragraphs (d)(1) through (4) of this section for the use of any CEMS, COMS, or continuous parameter monitoring system. This requirement also applies to you if you petition the EPA Administrator for alternative monitoring parameters under § 63.8(f).
(1) For each CMS required in this section (including CEMS, COMS, or continuous parameter monitoring system), you must develop, and submit to the delegated authority for approval upon request, a site-specific monitoring plan that addresses paragraphs (d)(1)(i) through (iii) of this section. You must submit this site-specific monitoring plan, if requested, at least 60 days before your initial performance evaluation of your CMS. This requirement to develop and submit a site specific monitoring plan does not apply to affected sources with existing monitoring plans that apply to CEMS and COMS prepared under appendix B to part 60 of this chapter and that meet the requirements of § 63.7525.
(i) Installation of the CMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions (e.g., on or downstream of the last control device);
(ii) Performance and equipment specifications for the sample interface, the pollutant concentration or
(iii) Performance evaluation procedures and acceptance criteria (
(2) In your site-specific monitoring plan, you must also address paragraphs (d)(2)(i) through (iii) of this section.
(i) Ongoing operation and maintenance procedures in accordance with the general requirements of § 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii);
(ii) Ongoing data quality assurance procedures in accordance with the general requirements of § 63.8(d); and
(iii) Ongoing recordkeeping and reporting procedures in accordance with the general requirements of § 63.10(c) (as applicable in Table 10 to this subpart), (e)(1), and (e)(2)(i).
(3) You must conduct a performance evaluation of each CMS in accordance with your site-specific monitoring plan.
(4) You must operate and maintain the CMS in continuous operation according to the site-specific monitoring plan.
(a) For affected sources that elect to demonstrate compliance with any of the applicable emission limits in Tables 1 or 2 of this subpart through performance testing, your initial compliance requirements include conducting performance tests according to § 63.7520 and Table 5 to this subpart, conducting a fuel analysis for each type of fuel burned in your boiler or process heater according to § 63.7521 and Table 6 to this subpart, establishing operating limits according to § 63.7530 and Table 7 to this subpart, and conducting CMS performance evaluations according to § 63.7525. For affected sources that burn a single type of fuel, you are exempted from the compliance requirements of conducting a fuel analysis for each type of fuel burned in your boiler or process heater according to § 63.7521 and Table 6 to this subpart. For purposes of this subpart, units that use a supplemental fuel only for startup, unit shutdown, and transient flame stability purposes still qualify as affected sources that burn a single type of fuel, and the supplemental fuel is not subject to the fuel analysis requirements under § 63.7521 and Table 6 to this subpart.
(b) For affected sources that elect to demonstrate compliance with the applicable emission limits in Tables 1 or 2 of this subpart for hydrogen chloride or mercury through fuel analysis, your initial compliance requirement is to conduct a fuel analysis for each type of fuel burned in your boiler or process heater according to § 63.7521 and Table 6 to this subpart and establish operating limits according to § 63.7530 and Table 8 to this subpart.
(c) If your boiler or process heater is subject to a carbon monoxide limit, your initial compliance demonstration for carbon monoxide is to conduct a performance test for carbon monoxide according to Table 5 to this subpart. Your initial compliance demonstration for carbon monoxide also includes conducting a performance evaluation of your continuous oxygen monitor according to § 63.7525(a).
(d) If your boiler or process heater subject to a PM limit has a heat input capacity greater than 250 MMBtu per hour and combusts coal, biomass, or residual oil, your initial compliance demonstration for PM is to conduct a performance evaluation of your continuous emission monitoring system for PM according to § 63.7525(b). Boilers and process heaters that use a continuous emission monitoring system for PM are exempt from the performance testing and operating limit requirements specified in paragraph (a) of this section.
(e) For existing affected sources, you must demonstrate initial compliance, as specified in paragraphs (a) through (d) of this section, no later than 180 days after the compliance date that is specified for your source in § 63.7495 and according to the applicable provisions in § 63.7(a)(2) as cited in Table 10 to this subpart.
(f) If your new or reconstructed affected source commenced construction or reconstruction after June 4, 2010, you must demonstrate initial compliance with the emission limits no later than November 16, 2011 or within 180 days after startup of the source, whichever is later. If you are demonstrating compliance with an emission limit in Table 12 to this subpart that is less stringent than (that is, higher than) the applicable emission limit in Table 1 to this subpart, you must demonstrate compliance with the applicable emission limit in Table 1 no later than September 17, 2014.
(g) For affected sources that ceased burning solid waste consistent with § 63.7495(e) and for which your initial compliance date has passed, you must demonstrate compliance within 60 days of the effective date of the waste-to-fuel switch. If you have not conducted your compliance demonstration for this subpart within the previous 12 months, you must complete all compliance demonstrations for this subpart before you commence or recommence combustion of solid waste.
(a) You must conduct all applicable performance tests according to § 63.7520 on an annual basis, except those for dioxin/furan emissions, unless you follow the requirements listed in paragraphs (b) through (e) of this section. Annual performance tests must be completed no more than 13 months after the previous performance test, unless you follow the requirements listed in paragraphs (b) through (e) of this section. Annual performance testing for dioxin/furan emissions is not required after the initial compliance demonstration.
(b) You can conduct performance tests less often for a given pollutant if your performance tests for the pollutant for at least 2 consecutive years show that your emissions are at or below 75 percent of the emission limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions. In this case, you do not have to conduct a performance test for that pollutant for the next 2 years. You must conduct a performance test during the third year and no more than 37 months after the previous performance test. If you elect to demonstrate compliance using emission averaging under § 63.7522, you must continue to conduct performance tests annually.
(c) If your boiler or process heater continues to meet the emission limit for the pollutant, you may choose to conduct performance tests for the pollutant every third year if your emissions are at or below 75 percent of the emission limit, and if there are no changes in the operation of the affected source or air pollution control equipment that could increase emissions, but each such performance test must be conducted no more than 37 months after the previous performance test. If you elect to demonstrate compliance using emission averaging under § 63.7522, you must continue to conduct performance tests annually. The requirement to test at maximum chloride input level is waived unless the stack test is conducted for HCl. The requirement to test at maximum Hg input level is waived unless the stack test is conducted for Hg.
(d) If a performance test shows emissions exceeded 75 percent of the emission limit for a pollutant, you must conduct annual performance tests for that pollutant until all performance tests
(e) If you are required to meet an applicable tune-up work practice standard, you must conduct an annual or biennial performance tune-up according to § 63.7540(a)(10) and (a)(11), respectively. Each annual tune-up specified in § 63.7540(a)(10) must be no more than 13 months after the previous tune-up. Each biennial tune-up specified in § 63.7540(a)(11) must be conducted no more than 25 months after the previous tune-up.
(f) If you demonstrate compliance with the mercury or hydrogen chloride based on fuel analysis, you must conduct a monthly fuel analysis according to § 63.7521 for each type of fuel burned that is subject to an emission limit in Table 1, 2, or 12 of this subpart. If you burn a new type of fuel, you must conduct a fuel analysis before burning the new type of fuel in your boiler or process heater. You must still meet all applicable continuous compliance requirements in § 63.7540. If 12 consecutive monthly fuel analyses demonstrate compliance, you may request decreased fuel analysis frequency by applying to the EPA Administrator for approval of alternative monitoring under § 63.8(f).
(g) You must report the results of performance tests and the associated initial fuel analyses within 90 days after the completion of the performance tests. This report must also verify that the operating limits for your affected source have not changed or provide documentation of revised operating parameters established according to § 63.7530 and Table 7 to this subpart, as applicable. The reports for all subsequent performance tests must include all applicable information required in § 63.7550.
(a) You must conduct all performance tests according to § 63.7(c), (d), (f), and (h). You must also develop a site-specific stack test plan according to the requirements in § 63.7(c). You shall conduct all performance tests under such conditions as the Administrator specifies to you based on representative performance of the affected source for the period being tested. Upon request, you shall make available to the Administrator such records as may be necessary to determine the conditions of the performance tests.
(b) You must conduct each performance test according to the requirements in Table 5 to this subpart.
(c) You must conduct each performance test under the specific conditions listed in Tables 5 and 7 to this subpart. You must conduct performance tests at representative operating load conditions while burning the type of fuel or mixture of fuels that has the highest content of chlorine and mercury, and you must demonstrate initial compliance and establish your operating limits based on these performance tests. These requirements could result in the need to conduct more than one performance test. Following each performance test and until the next performance test, you must comply with the operating limit for operating load conditions specified in Table 4 to this subpart.
(d) You must conduct three separate test runs for each performance test required in this section, as specified in § 63.7(e)(3). Each test run must comply with the minimum applicable sampling times or volumes specified in Tables 1, 2, and 12 to this subpart.
(e) To determine compliance with the emission limits, you must use the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 at 40 CFR part 60, appendix A–7 of this chapter to convert the measured particulate matter concentrations, the measured hydrogen chloride concentrations, and the measured mercury concentrations that result from the initial performance test to pounds per million Btu heat input emission rates using F-factors.
(a) For solid, liquid, and gas 2 (other) fuels, you must conduct fuel analyses for chloride and mercury according to the procedures in paragraphs (b) through (e) of this section and Table 6 to this subpart, as applicable. You are not required to conduct fuel analyses for fuels used for only startup, unit shutdown, and transient flame stability purposes. You are required to conduct fuel analyses only for fuels and units that are subject to emission limits for mercury and hydrogen chloride in Tables 1, 2, or 12 to this subpart. Gaseous and liquid fuels are exempt from requirements in paragraphs (c) and (d) of this section and Table 6 of this subpart.
(b) You must develop and submit a site-specific fuel monitoring plan to the EPA Administrator for review and approval according to the following procedures and requirements in paragraphs (b)(1) and (2) of this section.
(1) You must submit the fuel analysis plan no later than 60 days before the date that you intend to conduct an initial compliance demonstration.
(2) You must include the information contained in paragraphs (b)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all fuel types anticipated to be burned in each boiler or process heater.
(ii) For each fuel type, the notification of whether you or a fuel supplier will be conducting the fuel analysis.
(iii) For each fuel type, a detailed description of the sample location and specific procedures to be used for collecting and preparing the composite samples if your procedures are different from paragraph (c) or (d) of this section. Samples should be collected at a location that most accurately represents the fuel type, where possible, at a point prior to mixing with other dissimilar fuel types.
(iv) For each fuel type, the analytical methods from Table 6, with the expected minimum detection levels, to be used for the measurement of chlorine or mercury.
(v) If you request to use an alternative analytical method other than those required by Table 6 to this subpart, you must also include a detailed description of the methods and procedures that you are proposing to use. Methods in Table 6 shall be used until the requested alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in lieu of site-specific sampling and analysis, the fuel supplier must use the analytical methods required by Table 6 to this subpart.
(c) At a minimum, you must obtain three composite fuel samples for each fuel type according to the procedures in paragraph (c)(1) or (2) of this section.
(1) If sampling from a belt (or screw) feeder, collect fuel samples according to paragraphs (c)(1)(i) and (ii) of this section.
(i) Stop the belt and withdraw a 6-inch wide sample from the full cross-section of the stopped belt to obtain a minimum two pounds of sample. You must collect all the material (fines and coarse) in the full cross-section. You must transfer the sample to a clean plastic bag.
(ii) Each composite sample will consist of a minimum of three samples collected at approximately equal 1-hour intervals during the testing period.
(2) If sampling from a fuel pile or truck, you must collect fuel samples according to paragraphs (c)(2)(i) through (iii) of this section.
(i) For each composite sample, you must select a minimum of five sampling locations uniformly spaced over the surface of the pile.
(ii) At each sampling site, you must dig into the pile to a depth of 18 inches. You must insert a clean flat square shovel into the hole and withdraw a sample, making sure that large pieces do not fall off during sampling.
(iii) You must transfer all samples to a clean plastic bag for further processing.
(d) You must prepare each composite sample according to the procedures in paragraphs (d)(1) through (7) of this section.
(1) You must thoroughly mix and pour the entire composite sample over a clean plastic sheet.
(2) You must break sample pieces larger than 3 inches into smaller sizes.
(3) You must make a pie shape with the entire composite sample and subdivide it into four equal parts.
(4) You must separate one of the quarter samples as the first subset.
(5) If this subset is too large for grinding, you must repeat the procedure in paragraph (d)(3) of this section with the quarter sample and obtain a one-quarter subset from this sample.
(6) You must grind the sample in a mill.
(7) You must use the procedure in paragraph (d)(3) of this section to obtain a one-quarter subsample for analysis. If the quarter sample is too large, subdivide it further using the same procedure.
(e) You must determine the concentration of pollutants in the fuel (mercury and/or chlorine) in units of pounds per million Btu of each composite sample for each fuel type according to the procedures in Table 6 to this subpart.
(f) To demonstrate that a gaseous fuel other than natural gas or refinery gas qualifies as an other gas 1 fuel, as defined in § 63.7575, you must conduct a fuel specification analyses for hydrogen sulfide and mercury according to the procedures in paragraphs (g) through (i) of this section and Table 6 to this subpart, as applicable. You are not required to conduct the fuel specification analyses in paragraphs (g) through (i) of this section for gaseous fuels other than natural gas or refinery gas that are complying with the limits for units designed to burn gas 2 (other) fuels.
(g) You must develop and submit a site-specific fuel analysis plan for other gas 1 fuels to the EPA Administrator for review and approval according to the following procedures and requirements in paragraphs (g)(1) and (2) of this section.
(1) You must submit the fuel analysis plan no later than 60 days before the date that you intend to conduct an initial compliance demonstration.
(2) You must include the information contained in paragraphs (g)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all gaseous fuel types other than natural gas or refinery gas anticipated to be burned in each boiler or process heater.
(ii) For each fuel type, the notification of whether you or a fuel supplier will be conducting the fuel specification analysis.
(iii) For each fuel type, a detailed description of the sample location and specific procedures to be used for collecting and preparing the samples if your procedures are different from the sampling methods contained in Table 6. Samples should be collected at a location that most accurately represents the fuel type, where possible, at a point prior to mixing with other dissimilar fuel types. If multiple boilers or process heaters are fueled by a common fuel stream it is permissible to conduct a single gas specification at the common point of gas distribution.
(iv) For each fuel type, the analytical methods from Table 6, with the expected minimum detection levels, to be used for the measurement of hydrogen sulfide and mercury.
(v) If you request to use an alternative analytical method other than those required by Table 6 to this subpart, you must also include a detailed description of the methods and procedures that you are proposing to use. Methods in Table 6 shall be used until the requested alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in lieu of site-specific sampling and analysis, the fuel supplier must use the analytical methods required by Table 6 to this subpart.
(h) You must obtain a single fuel sample for each other gas 1 fuel type according to the sampling procedures listed in Table 6 for fuel specification of gaseous fuels.
(i) You must determine the concentration in the fuel of mercury, in units of microgram per cubic meter, and of hydrogen sulfide, in units of parts per million, by volume, dry basis, of each sample for each gas 1 fuel type according to the procedures in Table 6 to this subpart.
(a) As an alternative to meeting the requirements of § 63.7500 for particulate matter, hydrogen chloride, or mercury on a boiler or process heater-specific basis, if you have more than one existing boiler or process heater in any subcategory located at your facility, you may demonstrate compliance by emissions averaging, if your averaged emissions are not more than 90 percent of the applicable emission limit, according to the procedures in this section. You may not include new boilers or process heaters in an emissions average.
(b) For a group of two or more existing boilers or process heaters in the same subcategory that each vent to a separate stack, you may average particulate matter, hydrogen chloride, or mercury emissions among existing units to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraphs (c), (d), (e), (f), and (g) of this section.
(c) For each existing boiler or process heater in the averaging group, the emission rate achieved during the initial compliance test for the HAP being averaged must not exceed the emission level that was being achieved on May 20, 2011 or the control technology employed during the initial compliance test must not be less effective for the HAP being averaged than the control technology employed on May 20, 2011.
(d) The averaged emissions rate from the existing boilers and process heaters participating in the emissions averaging option must be in compliance with the limits in Table 2 to this subpart at all times following the compliance date specified in § 63.7495.
(e) You must demonstrate initial compliance according to paragraph (e)(1) or (2) of this section using the maximum rated heat input capacity or maximum steam generation capacity of each unit and the results of the initial performance tests or fuel analysis.
(1) You must use Equation 1 of this section to demonstrate that the particulate matter, hydrogen chloride, or mercury emissions from all existing units participating in the emissions averaging option for that pollutant do not exceed the emission limits in Table 2 to this subpart.
(2) If you are not capable of determining the maximum rated heat input capacity of one or more boilers that generate steam, you may use Equation 2 of this section as an alternative to using Equation 1 of this section to demonstrate that the particulate matter, hydrogen chloride, or mercury emissions from all existing units participating in the emissions averaging option do not exceed the emission limits for that pollutant in Table 2 to this subpart.
(f) After the initial compliance demonstration described in paragraph (e) of this section, you must demonstrate compliance on a monthly basis determined at the end of every month (12 times per year) according to paragraphs (f)(1) through (3) of this section. The first monthly period begins on the compliance date specified in § 63.7495.
(1) For each calendar month, you must use Equation 3 of this section to calculate the average weighted emission rate for that month using the actual heat input for each existing unit participating in the emissions averaging option.
(2) If you are not capable of monitoring heat input, you may use Equation 4 of this section as an alternative to using Equation 3 of this section to calculate the average weighted emission rate using the actual steam generation from the boilers participating in the emissions averaging option.
(3) Until 12 monthly weighted average emission rates have been accumulated, calculate and report only the average weighted emission rate determined under paragraph (f)(1) or (2) of this section for each calendar month. After 12 monthly weighted average emission rates have been accumulated, for each subsequent calendar month, use Equation 5 of this section to calculate the 12-month rolling average of the monthly weighted average emission rates for the current calendar month and the previous 11 calendar months.
(g) You must develop, and submit to the applicable delegated authority for review and approval, an implementation plan for emission averaging according to the following procedures and requirements in paragraphs (g)(1) through (4) of this section.
(1) You must submit the implementation plan no later than 180 days before the date that the facility intends to demonstrate compliance using the emission averaging option.
(2) You must include the information contained in paragraphs (g)(2)(i) through (vii) of this section in your implementation plan for all emission sources included in an emissions average:
(i) The identification of all existing boilers and process heaters in the averaging group, including for each either the applicable HAP emission level or the control technology installed as of May 20, 2011 and the date on which you are requesting emission averaging to commence;
(ii) The process parameter (heat input or steam generated) that will be monitored for each averaging group;
(iii) The specific control technology or pollution prevention measure to be used for each emission boiler or process heater in the averaging group and the date of its installation or application. If the pollution prevention measure reduces or eliminates emissions from multiple boilers or process heaters, the owner or operator must identify each boiler or process heater;
(iv) The test plan for the measurement of particulate matter, hydrogen chloride, or mercury emissions in accordance with the requirements in § 63.7520;
(v) The operating parameters to be monitored for each control system or device consistent with § 63.7500 and Table 4, and a description of how the operating limits will be determined;
(vi) If you request to monitor an alternative operating parameter pursuant to § 63.7525, you must also include:
(A) A description of the parameter(s) to be monitored and an explanation of the criteria used to select the parameter(s); and
(B) A description of the methods and procedures that will be used to demonstrate that the parameter indicates proper operation of the control device; the frequency and content of monitoring, reporting, and recordkeeping requirements; and a demonstration, to the satisfaction of the applicable delegated authority, that the proposed monitoring frequency is sufficient to represent control device operating conditions; and
(vii) A demonstration that compliance with each of the applicable emission limit(s) will be achieved under representative operating load conditions. Following each compliance demonstration and until the next compliance demonstration, you must comply with the operating limit for operating load conditions specified in Table 4 to this subpart.
(3) The delegated authority shall review and approve or disapprove the plan according to the following criteria:
(i) Whether the content of the plan includes all of the information specified in paragraph (g)(2) of this section; and
(ii) Whether the plan presents sufficient information to determine that compliance will be achieved and maintained.
(4) The applicable delegated authority shall not approve an emission averaging implementation plan containing any of the following provisions:
(i) Any averaging between emissions of differing pollutants or between differing sources; or
(ii) The inclusion of any emission source other than an existing unit in the same subcategory.
(h) For a group of two or more existing affected units, each of which vents through a single common stack, you may average particulate matter, hydrogen chloride, or mercury emissions to demonstrate compliance with the limits for that pollutant in Table 2 to this subpart if you satisfy the requirements in paragraph (i) or (j) of this section.
(i) For a group of two or more existing units in the same subcategory, each of which vents through a common emissions control system to a common stack, that does not receive emissions from units in other subcategories or categories, you may treat such averaging group as a single existing unit for purposes of this subpart and comply with the requirements of this subpart as if the group were a single unit.
(j) For all other groups of units subject to the common stack requirements of paragraph (h) of this section, including situations where the exhaust of affected units are each individually controlled and then sent to a common stack, the owner or operator may elect to:
(1) Conduct performance tests according to procedures specified in § 63.7520 in the common stack if affected units from other subcategories vent to the common stack. The emission limits that the group must comply with are determined by the use of Equation 6 of this section.
(2) Conduct performance tests according to procedures specified in § 63.7520 in the common stack. If affected units and non-affected units vent to the common stack, the non-affected units must be shut down or vented to a different stack during the performance test unless the facility determines to demonstrate compliance with the non-affected units venting to the stack; and
(3) Meet the applicable operating limit specified in § 63.7540 and Table 8 to this subpart for each emissions control system (except that, if each unit venting to the common stack has an applicable opacity operating limit, then a single continuous opacity monitoring system may be located in the common stack instead of in each duct to the common stack).
(k) The common stack of a group of two or more existing boilers or process heaters in the same subcategory subject to paragraph (h) of this section may be treated as a separate stack for purposes of paragraph (b) of this section and included in an emissions averaging group subject to paragraph (b) of this section.
(a) If your boiler or process heater is subject to a carbon monoxide emission limit in Table 1, 2, or 12 to this subpart, you must install, operate, and maintain a continuous oxygen monitor according to the procedures in paragraphs (a)(1) through (6) of this section by the compliance date specified in § 63.7495. The oxygen level shall be monitored at the outlet of the boiler or process heater.
(1) Each CEMS for oxygen (O
(2) You must conduct a performance evaluation of each O
(3) Each O
(4) The O
(5) You must calculate and record 12-hour block average concentrations for each operating day.
(6) For purposes of calculating data averages, you must use all the data collected during all periods in assessing compliance, excluding data collected during periods when the monitoring system malfunctions or is out of control, during associated repairs, and during required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments). Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions. Any period for which the monitoring system malfunctions or is out of control and data are not available for a required calculation constitutes a deviation from the monitoring requirements. Periods when data are unavailable because of required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments) do not constitute monitoring deviations.
(b) If your boiler or process heater has a heat input capacity of greater than 250 MMBtu per hour and combusts coal, biomass, or residual oil, you must install, certify, maintain, and operate a CEMS measuring PM emissions discharged to the atmosphere and record the output of the system as specified in paragraphs (b)(1) through (5) of this section.
(1) Each CEMS shall be installed, certified, operated, and maintained according to the requirements in § 63.7540(a)(9).
(2) For a new unit, the initial performance evaluation shall be completed no later than November 16, 2011 or 180 days after the date of initial startup, whichever is later. For an existing unit, the initial performance evaluation shall be completed no later than September 17, 2014.
(3) Compliance with the applicable emissions limit shall be determined based on the 30-day rolling average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 30-day rolling arithmetic average emission concentration shall be calculated using EPA Reference Method 19 at 40 CFR part 60, appendix A–7.
(4) Collect CEMS hourly averages for all operating hours on a 30-day rolling average basis. Collect at least four CMS data values representing the four 15-minute periods in an hour, or at least two 15-minute data values during an hour when CMS calibration, quality assurance, or maintenance activities are being performed.
(5) The 1-hour arithmetic averages required shall be expressed in lb/MMBtu and shall be used to calculate the boiler operating day daily arithmetic average emissions.
(c) If you have an applicable opacity operating limit in this rule, and are not otherwise required to install and operate a PM CEMS or a bag leak detection system, you must install, operate, certify and maintain each COMS according to the procedures in paragraphs (c)(1) through (7) of this section by the compliance date specified in § 63.7495.
(1) Each COMS must be installed, operated, and maintained according to Performance Specification 1 at appendix B to part 60 of this chapter.
(2) You must conduct a performance evaluation of each COMS according to the requirements in § 63.8(e) and according to Performance Specification 1 at appendix B to part 60 of this chapter.
(3) As specified in § 63.8(c)(4)(i), each COMS must complete a minimum of one cycle of sampling and analyzing for each successive 10-second period and one cycle of data recording for each successive 6-minute period.
(4) The COMS data must be reduced as specified in § 63.8(g)(2).
(5) You must include in your site-specific monitoring plan procedures and acceptance criteria for operating and maintaining each COMS according to the requirements in § 63.8(d). At a minimum, the monitoring plan must include a daily calibration drift assessment, a quarterly performance audit, and an annual zero alignment audit of each COMS.
(6) You must operate and maintain each COMS according to the requirements in the monitoring plan and the requirements of § 63.8(e). You must identify periods the COMS is out of control including any periods that the COMS fails to pass a daily calibration drift assessment, a quarterly performance audit, or an annual zero alignment audit. Any 6-minute period for which the monitoring system is out of control and data are not available for a required calculation constitutes a deviation from the monitoring requirements.
(7) You must determine and record all the 6-minute averages (and daily block averages as applicable) collected for periods during which the COMS is not out of control.
(d) If you have an operating limit that requires the use of a CMS, you must install, operate, and maintain each continuous parameter monitoring system according to the procedures in paragraphs (d)(1) through (5) of this section by the compliance date specified in § 63.7495.
(1) The continuous parameter monitoring system must complete a minimum of one cycle of operation for each successive 15-minute period. You must have a minimum of four successive cycles of operation to have a valid hour of data.
(2) Except for monitoring malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments), you must conduct all monitoring in continuous operation at all times that the unit is operating. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions.
(3) For purposes of calculating data averages, you must not use data recorded during monitoring malfunctions, associated repairs, out of control periods, or required quality assurance or control activities. You must use all the data collected during all other periods in assessing compliance. Any 15-minute period for which the monitoring system is out-of-control and data are not available for a required calculation constitutes a deviation from the monitoring requirements.
(4) You must determine the 4-hour block average of all recorded readings, except as provided in paragraph (d)(3) of this section.
(5) You must record the results of each inspection, calibration, and validation check.
(e) If you have an operating limit that requires the use of a flow monitoring system, you must meet the requirements in paragraphs (d) and (e)(1) through (4) of this section.
(1) You must install the flow sensor and other necessary equipment in a position that provides a representative flow.
(2) You must use a flow sensor with a measurement sensitivity of no greater than 2 percent of the expected flow rate.
(3) You must minimize the effects of swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
(4) You must conduct a flow monitoring system performance evaluation in accordance with your monitoring plan at the time of each performance test but no less frequently than annually. (f) If you have an operating limit that requires the use of a pressure monitoring system, you must meet the requirements in paragraphs (d) and (f)(1) through (6) of this section.
(1) Install the pressure sensor(s) in a position that provides a representative measurement of the pressure (
(2) Minimize or eliminate pulsating pressure, vibration, and internal and external corrosion.
(3) Use a pressure sensor with a minimum tolerance of 1.27 centimeters of water or a minimum tolerance of 1 percent of the pressure monitoring system operating range, whichever is less.
(4) Perform checks at least once each process operating day to ensure pressure measurements are not obstructed (
(5) Conduct a performance evaluation of the pressure monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(6) If at any time the measured pressure exceeds the manufacturer's specified maximum operating pressure range, conduct a performance evaluation of the pressure monitoring system in accordance with your monitoring plan and confirm that the pressure monitoring system continues to meet the performance requirements in you monitoring plan. Alternatively, install and verify the operation of a new pressure sensor.
(g) If you have an operating limit that requires a pH monitoring system, you must meet the requirements in paragraphs (d) and (g)(1) through (4) of this section.
(1) Install the pH sensor in a position that provides a representative measurement of scrubber effluent pH.
(2) Ensure the sample is properly mixed and representative of the fluid to be measured.
(3) Conduct a performance evaluation of the pH monitoring system in accordance with your monitoring plan at least once each process operating day.
(4) Conduct a performance evaluation (including a two-point calibration with one of the two buffer solutions having a pH within 1 of the pH of the operating limit) of the pH monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than quarterly.
(h) If you have an operating limit that requires a secondary electric power monitoring system for an electrostatic precipitator (ESP) operated with a wet scrubber, you must meet the requirements in paragraphs (h)(1) and (2) of this section.
(1) Install sensors to measure (secondary) voltage and current to the precipitator collection plates.
(2) Conduct a performance evaluation of the electric power monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(i) If you have an operating limit that requires the use of a monitoring system to measure sorbent injection rate (e.g., weigh belt, weigh hopper, or hopper flow measurement device), you must meet the requirements in paragraphs (d) and (i)(1) through (2) of this section.
(1) Install the system in a position(s) that provides a representative measurement of the total sorbent injection rate.
(2) Conduct a performance evaluation of the sorbent injection rate monitoring system in accordance with your monitoring plan at the time of each performance test but no less frequently than annually.
(j) If you are not required to use a PM CEMS and elect to use a fabric filter bag leak detection system to comply with the requirements of this subpart, you must install, calibrate, maintain, and continuously operate the bag leak detection system as specified in paragraphs (j)(1) through (7) of this section.
(1) You must install a bag leak detection sensor(s) in a position(s) that will be representative of the relative or absolute particulate matter loadings for each exhaust stack, roof vent, or compartment (
(2) Conduct a performance evaluation of the bag leak detection system in accordance with your monitoring plan and consistent with the guidance provided in EPA–454/R–98–015 (incorporated by reference,
(3) Use a bag leak detection system certified by the manufacturer to be capable of detecting particulate matter emissions at concentrations of 10 milligrams per actual cubic meter or less.
(4) Use a bag leak detection system equipped with a device to record continuously the output signal from the sensor.
(5) Use a bag leak detection system equipped with a system that will alert when an increase in relative particulate matter emissions over a preset level is detected. The alarm must be located where it can be easily heard or seen by plant operating personnel.
(7) Where multiple bag leak detectors are required, the system's instrumentation and alarm may be shared among detectors.
(k) For each unit that meets the definition of limited-use boiler or process heater, you must monitor and record the operating hours per year for that unit.
(a) You must demonstrate initial compliance with each emission limit that applies to you by conducting initial performance tests and fuel analyses and establishing operating limits, as applicable, according to § 63.7520, paragraphs (b) and (c) of this section, and Tables 5 and 7 to this subpart. If applicable, you must also install, and operate, maintain all applicable CMS (including CEMS, COMS, and continuous parameter monitoring systems) according to § 63.7525.
(b) If you demonstrate compliance through performance testing, you must establish each site-specific operating limit in Table 4 to this subpart that applies to you according to the requirements in § 63.7520, Table 7 to this subpart, and paragraph (b)(3) of this section, as applicable. You must also conduct fuel analyses according to § 63.7521 and establish maximum fuel pollutant input levels according to paragraphs (b)(1) and (2) of this section, as applicable. As specified in § 63.7510(a), if your affected source burns a single type of fuel (excluding supplemental fuels used for unit startup, shutdown, or transient flame stabilization), you are not required to perform the initial fuel analysis for each type of fuel burned in your boiler or process heater. However, if you switch fuel(s) and cannot show that the new fuel(s) do (does) not increase the chlorine or mercury input into the unit through the results of fuel analysis, then you must repeat the performance test to demonstrate compliance while burning the new fuel(s).
(1) You must establish the maximum chlorine fuel input (Clinput) during the initial fuel analysis according to the procedures in paragraphs (b)(1)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could burn in your boiler or process heater that has the highest content of chlorine.
(ii) During the fuel analysis for hydrogen chloride, you must determine the fraction of the total heat input for each fuel type burned (Qi) based on the fuel mixture that has the highest content of chlorine, and the average chlorine concentration of each fuel type burned (Ci).
(iii) You must establish a maximum chlorine input level using Equation 7 of this section.
(2) You must establish the maximum mercury fuel input level (Mercuryinput) during the initial fuel analysis using the procedures in paragraphs (b)(2)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could burn in your boiler or process heater that has the highest content of mercury.
(ii) During the compliance demonstration for mercury, you must determine the fraction of total heat input for each fuel burned (Qi) based on the fuel mixture that has the highest content of mercury, and the average mercury concentration of each fuel type burned (HGi).
(iii) You must establish a maximum mercury input level using Equation 8 of this section.
(3) You must establish parameter operating limits according to paragraphs (b)(3)(i) through (iv) of this section.
(i) For a wet scrubber, you must establish the minimum scrubber effluent pH, liquid flowrate, and pressure drop as defined in § 63.7575, as your operating limits during the three-run performance test. If you use a wet scrubber and you conduct separate performance tests for particulate matter, hydrogen chloride, and mercury emissions, you must establish one set of minimum scrubber effluent pH, liquid flowrate, and pressure drop operating limits. The minimum scrubber effluent pH operating limit must be established during the hydrogen chloride performance test. If you conduct multiple performance tests, you must set the minimum liquid flowrate and pressure drop operating limits at the highest minimum values established during the performance tests.
(ii) For an electrostatic precipitator operated with a wet scrubber, you must establish the minimum voltage and secondary amperage (or total power input), as defined in § 63.7575, as your operating limits during the three-run performance test. (These operating limits do not apply to electrostatic precipitators that are operated as dry controls without a wet scrubber.)
(iii) For a dry scrubber, you must establish the minimum sorbent injection rate for each sorbent, as defined in § 63.7575, as your operating limit during the three-run performance test.
(iv) For activated carbon injection, you must establish the minimum activated carbon injection rate, as defined in § 63.7575, as your operating limit during the three-run performance test.
(v) The operating limit for boilers or process heaters with fabric filters that demonstrate continuous compliance through bag leak detection systems is that a bag leak detection system be installed according to the requirements in § 63.7525, and that each fabric filter must be operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during a 6-month period.
(c) If you elect to demonstrate compliance with an applicable emission limit through fuel analysis, you must conduct fuel analyses according to § 63.7521 and follow the procedures in paragraphs (c)(1) through (4) of this section.
(1) If you burn more than one fuel type, you must determine the fuel mixture you could burn in your boiler or process heater that would result in the maximum emission rates of the pollutants that you elect to demonstrate compliance through fuel analysis.
(2) You must determine the 90th percentile confidence level fuel pollutant concentration of the composite samples analyzed for each fuel type using the one-sided z-statistic test described in Equation 9 of this section.
(3) To demonstrate compliance with the applicable emission limit for hydrogen chloride, the hydrogen chloride emission rate that you calculate for your boiler or process heater using Equation 10 of this section must not exceed the applicable emission limit for hydrogen chloride.
(4) To demonstrate compliance with the applicable emission limit for mercury, the mercury emission rate that you calculate for your boiler or process heater using Equation 11 of this section must not exceed the applicable emission limit for mercury.
(d) If you own or operate an existing unit with a heat input capacity of less than 10 million Btu per hour, you must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted a tune-up of the unit.
(e) You must include with the Notification of Compliance Status a signed certification that the energy assessment was completed according to Table 3 to this subpart and is an accurate depiction of your facility.
(f) You must submit the Notification of Compliance Status containing the results of the initial compliance demonstration according to the requirements in § 63.7545(e).
(g) If you elect to demonstrate that a gaseous fuel meets the specifications of an other gas 1 fuel as defined in § 63.7575, you must conduct an initial fuel specification analyses according to § 63.7521(f) through (i). If the mercury and hydrogen sulfide constituents in the gaseous fuels will never exceed the specifications included in the definition, you will include a signed certification with the Notification of Compliance Status that the initial fuel specification test meets the gas specifications outlined in the definition of other gas 1 fuels. If your gas constituents could vary above the specifications, you will conduct monthly testing according to the procedures in § 63.7521(f) through (i) and § 63.7540(c) and maintain records of the results of the testing as outlined in § 63.7555(g).
(h) If you own or operate a unit subject emission limits in Tables 1, 2, or 12 of this subpart, you must minimize the unit's startup and shutdown periods following the manufacturer's recommended procedures, if available. If manufacturer's recommended procedures are not available, you must follow recommended procedures for a unit of similar design for which manufacturer's recommended procedures are available. You must submit a signed statement in the Notification of Compliance Status report that indicates that you conducted startups and shutdowns according to the manufacturer's recommended procedures or procedures specified for a unit of similar design if manufacturer's recommended procedures are not available.
(a) If you elect to comply with the alternative equivalent steam output-based emission limits, instead of the heat input-based limits, listed in Tables 1 and 2 of this subpart and you want to take credit for implementing energy conservation measures identified in an energy assessment, you may demonstrate compliance using emission reduction credits according to the procedures in this section. Owners or operators using this compliance approach must establish an emissions benchmark, calculate and document the emission credits, develop an Implementation Plan, comply with the general reporting requirements, and apply the emission credit according to the procedures in paragraphs (b) through (f) of this section.
(b) For each existing affected boiler for which you intend to apply emissions credits, establish a benchmark from which emission reduction credits may be generated by determining the actual annual fuel heat input to the affected boiler before initiation of an energy conservation activity to reduce energy demand (
(1) The benchmark from which emission credits may be generated shall be determined by using the most representative, accurate, and reliable process available for the source. The benchmark shall be established for a one-year period before the date that an energy demand reduction occurs, unless it can be demonstrated that a different time period is more representative of historical operations.
(2) Determine the starting point from which to measure progress. Inventory all fuel purchased and generated on-site (off-gases, residues) in physical units (MMBtu, million cubic feet, etc.).
(3) Document all uses of energy from the affected boiler. Use the most recent data available.
(4) Collect non-energy related facility and operational data to normalize, if necessary, the benchmark to current operations, such as building size, operating hours, etc. Use actual, not estimated, use data, if possible and data that are current and timely.
(c) Emissions credits can be generated if the energy conservation measures were implemented after January 14, 2011 and if sufficient information is
(1) The following emission points cannot be used to generate emissions averaging credits:
(i) Energy conservation measures implemented on or before January 14, 2011, unless the level of energy demand reduction is increased after January 14, 2011, in which case credit will be allowed only for change in demand reduction achieved after January 14, 2011.
(ii) Emission credits on shut-down boilers. Boilers that are shut down cannot be used to generate credits.
(2) For all points included in calculating emissions credits, the owner or operator shall:
(i) Calculate annual credits for all energy demand points. Use Equation 12 to calculate credits. Energy conservation measures that meet the criteria of paragraph (c)(1) of this section shall not be included, except as specified in paragraph (c)(1)(i) of this section.
(3) Credits are generated by the difference between the benchmark that is established for each affected boiler, and the actual energy demand reductions from energy conservation measures implemented after January 14, 2011. Credits shall be calculated using Equation 12 of this section as follows:
(i) The overall equation for calculating credits is:
(d) The owner or operator shall develop and submit for approval an Implementation Plan containing all of the information required in this paragraph for all boilers to be included in an emissions credit approach. The Implementation Plan shall identify all existing affected boilers to be included in applying the emissions credits. The Implementation Plan shall include a description of the energy conservation measures implemented and the energy savings generated from each measure and an explanation of the criteria used for determining that savings. You must submit the implementation plan for emission credits to the applicable delegated authority for review and approval no later than 180 days before the date on which the facility intends to demonstrate compliance using the emission credit approach.
(e) The emissions rate from each existing boiler participating in the emissions credit option must be in compliance with the limits in Table 2 to this subpart at all times following the compliance date specified in § 63.7495.
(f) You must demonstrate initial compliance according to paragraph (f)(1) or (2) of this section.
(1) You must use Equation 13 of this section to demonstrate that the emissions from the affected boiler participating in the emissions credit compliance approach do not exceed the emission limits in Table 2 to this subpart.
(a) You must monitor and collect data according to this section and the site-specific monitoring plan required by § 63.7505(d).
(b) You must operate the monitoring system and collect data at all required intervals at all times that the affected source is operating, except for periods of monitoring system malfunctions or out of control periods (
(c) You may not use data recorded during monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or out-of-control periods, or required monitoring system quality assurance or control activities in data averages and calculations used to report emissions or operating levels. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
(d) Except for periods of monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments, failure to collect required data is a deviation of the monitoring requirements.
(a) You must demonstrate continuous compliance with each emission limit, operating limit, and work practice standard in Tables 1 through 3 to this subpart that applies to you according to the methods specified in Table 8 to this subpart and paragraphs (a)(1) through (11) of this section.
(1) Following the date on which the initial compliance demonstration is completed or is required to be completed under §§ 63.7 and 63.7510, whichever date comes first, operation above the established maximum or below the established minimum operating limits shall constitute a deviation of established operating limits listed in Table 4 of this subpart except during performance tests conducted to determine compliance with the emission limits or to establish new operating limits. Operating limits must
(2) As specified in § 63.7550(c), you must keep records of the type and amount of all fuels burned in each boiler or process heater during the reporting period to demonstrate that all fuel types and mixtures of fuels burned would either result in lower emissions of hydrogen chloride and mercury than the applicable emission limit for each pollutant (if you demonstrate compliance through fuel analysis), or result in lower fuel input of chlorine and mercury than the maximum values calculated during the last performance test (if you demonstrate compliance through performance testing).
(3) If you demonstrate compliance with an applicable hydrogen chloride emission limit through fuel analysis and you plan to burn a new type of fuel, you must recalculate the hydrogen chloride emission rate using Equation 9 of § 63.7530 according to paragraphs (a)(3)(i) through (iii) of this section.
(i) You must determine the chlorine concentration for any new fuel type in units of pounds per million Btu, based on supplier data or your own fuel analysis, according to the provisions in your site-specific fuel analysis plan developed according to § 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the highest content of chlorine.
(iii) Recalculate the hydrogen chloride emission rate from your boiler or process heater under these new conditions using Equation 10 of § 63.7530. The recalculated hydrogen chloride emission rate must be less than the applicable emission limit.
(4) If you demonstrate compliance with an applicable hydrogen chloride emission limit through performance testing and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum chlorine input using Equation 7 of § 63.7530. If the results of recalculating the maximum chlorine input using Equation 7 of § 63.7530 are greater than the maximum chlorine input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in § 63.7520 to demonstrate that the hydrogen chloride emissions do not exceed the emission limit. You must also establish new operating limits based on this performance test according to the procedures in § 63.7530(b).
(5) If you demonstrate compliance with an applicable mercury emission limit through fuel analysis, and you plan to burn a new type of fuel, you must recalculate the mercury emission rate using Equation 11 of § 63.7530 according to the procedures specified in paragraphs (a)(5)(i) through (iii) of this section.
(i) You must determine the mercury concentration for any new fuel type in units of pounds per million Btu, based on supplier data or your own fuel analysis, according to the provisions in your site-specific fuel analysis plan developed according to § 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the highest content of mercury.
(iii) Recalculate the mercury emission rate from your boiler or process heater under these new conditions using Equation 11 of § 63.7530. The recalculated mercury emission rate must be less than the applicable emission limit.
(6) If you demonstrate compliance with an applicable mercury emission limit through performance testing, and you plan to burn a new type of fuel or a new mixture of fuels, you must recalculate the maximum mercury input using Equation 8 of § 63.7530. If the results of recalculating the maximum mercury input using Equation 8 of § 63.7530 are higher than the maximum mercury input level established during the previous performance test, then you must conduct a new performance test within 60 days of burning the new fuel type or fuel mixture according to the procedures in § 63.7520 to demonstrate that the mercury emissions do not exceed the emission limit. You must also establish new operating limits based on this performance test according to the procedures in § 63.7530(b).
(7) If your unit is controlled with a fabric filter, and you demonstrate continuous compliance using a bag leak detection system, you must initiate corrective action within 1 hour of a bag leak detection system alarm and complete corrective actions as soon as practical, and operate and maintain the fabric filter system such that the alarm does not sound more than 5 percent of the operating time during a 6-month period. You must also keep records of the date, time, and duration of each alarm, the time corrective action was initiated and completed, and a brief description of the cause of the alarm and the corrective action taken. You must also record the percent of the operating time during each 6-month period that the alarm sounds. In calculating this operating time percentage, if inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm shall be counted as a minimum of 1 hour. If you take longer than 1 hour to initiate corrective action, the alarm time shall be counted as the actual amount of time taken to initiate corrective action.
(8) [Reserved].
(9) The owner or operator of an affected source using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the PM CEMS as specified in paragraphs (a)(9)(i) through (a)(9)(iv) of this section.
(i) The owner or operator shall conduct a performance evaluation of the PM CEMS according to the applicable requirements of § 60.13, and Performance Specification 11 at 40 CFR part 60, appendix B of this chapter.
(ii) During each PM correlation testing run of the CEMS required by Performance Specification 11 at 40 CFR part 60, appendix B of this chapter, PM and oxygen (or carbon dioxide) data shall be collected concurrently (or within a 30-to 60-minute period) by both the CEMS and conducting performance tests using Method 5 or 5B at 40 CFR part 60, appendix A–3 or Method 17 at 40 CFR part 60, appendix A–6 of this chapter.
(iii) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 2 at 40 CFR part 60, appendix F of this chapter. Relative Response Audits must be performed annually and Response Correlation Audits must be performed every 3 years.
(iv) After December 31, 2011, within 60 days after the date of completing each CEMS relative accuracy test audit or performance test conducted to demonstrate compliance with this subpart, you must submit the relative accuracy test audit data and performance test data to EPA by successfully submitting the data electronically into EPA's Central Data Exchange by using the Electronic Reporting Tool (see
(10) If your boiler or process heater is in either the natural gas, refinery gas, other gas 1, or Metal Process Furnace subcategories and has a heat input capacity of 10 million Btu per hour or greater, you must conduct a tune-up of the boiler or process heater annually to demonstrate continuous compliance as specified in paragraphs (a)(10)(i) through (a)(10)(vi) of this section. This requirement does not apply to limited-use boilers and process heaters, as defined in § 63.7575.
(i) As applicable, inspect the burner, and clean or replace any components of the burner as necessary (you may delay the burner inspection until the next scheduled unit shutdown, but you must inspect each burner at least once every 36 months);
(ii) Inspect the flame pattern, as applicable, and adjust the burner as necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available;
(iii) Inspect the system controlling the air-to-fuel ratio, as applicable, and ensure that it is correctly calibrated and functioning properly;
(iv) Optimize total emissions of carbon monoxide. This optimization should be consistent with the manufacturer's specifications, if available;
(v) Measure the concentrations in the effluent stream of carbon monoxide in parts per million, by volume, and oxygen in volume percent, before and after the adjustments are made (measurements may be either on a dry or wet basis, as long as it is the same basis before and after the adjustments are made); and
(vi) Maintain on-site and submit, if requested by the Administrator, an annual report containing the information in paragraphs (a)(10)(vi)(A) through (C) of this section,
(A) The concentrations of carbon monoxide in the effluent stream in parts per million by volume, and oxygen in volume percent, measured before and after the adjustments of the boiler;
(B) A description of any corrective actions taken as a part of the combustion adjustment; and
(C) The type and amount of fuel used over the 12 months prior to the annual adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period. Units sharing a fuel meter may estimate the fuel use by each unit.
(11) If your boiler or process heater has a heat input capacity of less than 10 million Btu per hour, or meets the definition of limited-use boiler or process heater in § 63.7575, you must conduct a biennial tune-up of the boiler or process heater as specified in paragraphs (a)(10)(i) through (a)(10)(vi) of this section to demonstrate continuous compliance.
(12) If the unit is not operating on the required date for a tune-up, the tune-up must be conducted within one week of startup.
(b) You must report each instance in which you did not meet each emission limit and operating limit in Tables 1 through 4 to this subpart that apply to you. These instances are deviations from the emission limits in this subpart. These deviations must be reported according to the requirements in § 63.7550.
(c) If you elected to demonstrate that the unit meets the specifications for hydrogen sulfide and mercury for the other gas 1 subcategory and you cannot submit a signed certification under § 63.7545(g) because the constituents could exceed the specifications, you must conduct monthly fuel specification testing of the gaseous fuels, according to the procedures in § 63.7521(f) through (i).
(a) Following the compliance date, the owner or operator must demonstrate compliance with this subpart on a continuous basis by meeting the requirements of paragraphs (a)(1) through (5) of this section.
(1) For each calendar month, demonstrate compliance with the average weighted emissions limit for the existing units participating in the emissions averaging option as determined in § 63.7522(f) and (g).
(2) You must maintain the applicable opacity limit according to paragraphs (a)(2)(i) and (ii) of this section.
(i) For each existing unit participating in the emissions averaging option that is equipped with a dry control system and not vented to a common stack, maintain opacity at or below the applicable limit.
(ii) For each group of units participating in the emissions averaging option where each unit in the group is equipped with a dry control system and vented to a common stack that does not receive emissions from non-affected units, maintain opacity at or below the applicable limit at the common stack.
(3) For each existing unit participating in the emissions averaging option that is equipped with a wet scrubber, maintain the 3-hour average parameter values at or below the operating limits established during the most recent performance test.
(4) For each existing unit participating in the emissions averaging option that has an approved alternative operating plan, maintain the 3-hour average parameter values at or below the operating limits established in the most recent performance test.
(5) For each existing unit participating in the emissions averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to this subpart that applies.
(b) Any instance where the owner or operator fails to comply with the continuous monitoring requirements in paragraphs (a)(1) through (5) of this section is a deviation.
(a) You must submit to the delegated authority all of the notifications in § 63.7(b) and (c), § 63.8(e), (f)(4) and (6), and § 63.9(b) through (h) that apply to you by the dates specified.
(b) As specified in § 63.9(b)(2), if you startup your affected source before May 20, 2011, you must submit an Initial Notification not later than 120 days after May 20, 2011.
(c) As specified in § 63.9(b)(4) and (b)(5), if you startup your new or reconstructed affected source on or after May 20, 2011, you must submit an Initial Notification not later than 15 days after the actual date of startup of the affected source.
(d) If you are required to conduct a performance test you must submit a Notification of Intent to conduct a performance test at least 60 days before the performance test is scheduled to begin.
(e) If you are required to conduct an initial compliance demonstration as specified in § 63.7530(a), you must submit a Notification of Compliance Status according to § 63.9(h)(2)(ii). For the initial compliance demonstration for each affected source, you must submit the Notification of Compliance Status, including all performance test results and fuel analyses, before the close of business on the 60th day following the completion of all performance test and/or other initial compliance demonstrations for the affected source according to § 63.10(d)(2). The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (8), as applicable.
(1) A description of the affected unit(s) including identification of which subcategory the unit is in, the design heat input capacity of the unit, a description of the add-on controls used on the unit, description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non-waste under § 241.3, whether the fuel(s) were processed from discarded non-hazardous secondary materials within the meaning of § 241.3, and justification for the selection of fuel(s) burned during the compliance demonstration.
(2) Summary of the results of all performance tests and fuel analyses, and calculations conducted to demonstrate initial compliance including all established operating limits.
(3) A summary of the maximum carbon monoxide emission levels recorded during the performance test to show that you have met any applicable emission standard in Table 1, 2, or 12 to this subpart.
(4) Identification of whether you plan to demonstrate compliance with each applicable emission limit through performance testing or fuel analysis.
(5) Identification of whether you plan to demonstrate compliance by emissions averaging and identification of whether you plan to demonstrate compliance by using emission credits through energy conservation:
(i) If you plan to demonstrate compliance by emission averaging, report the emission level that was being achieved or the control technology employed on May 20, 2011.
(6) A signed certification that you have met all applicable emission limits and work practice standards.
(7) If you had a deviation from any emission limit, work practice standard, or operating limit, you must also submit a description of the deviation, the duration of the deviation, and the corrective action taken in the Notification of Compliance Status report.
(8) In addition to the information required in § 63.9(h)(2), your notification of compliance status must include the following certification(s) of compliance, as applicable, and signed by a responsible official:
(i) “This facility complies with the requirements in § 63.7540(a)(10) to conduct an annual or biennial tune-up, as applicable, of each unit.”
(ii) “This facility has had an energy assessment performed according to § 63.7530(e).”
(iii) Except for units that qualify for a statutory exemption as provided in section 129(g)(1) of the Clean Air Act, include the following: “No secondary materials that are solid waste were combusted in any affected unit.”
(f) If you operate a unit designed to burn natural gas, refinery gas, or other gas 1 fuels that is subject to this subpart, and you intend to use a fuel other than natural gas, refinery gas, or other gas 1 fuel to fire the affected unit during a period of natural gas curtailment or supply interruption, as defined in § 63.7575, you must submit a notification of alternative fuel use within 48 hours of the declaration of each period of natural gas curtailment or supply interruption, as defined in § 63.7575. The notification must include the information specified in paragraphs (f)(1) through (5) of this section.
(1) Company name and address.
(2) Identification of the affected unit.
(3) Reason you are unable to use natural gas or equivalent fuel, including the date when the natural gas curtailment was declared or the natural gas supply interruption began.
(4) Type of alternative fuel that you intend to use.
(5) Dates when the alternative fuel use is expected to begin and end.
(g) If you intend to commence or recommence combustion of solid waste, you must provide 30 days prior notice of the date upon which you will commence or recommence combustion of solid waste. The notification must identify:
(1) The name of the owner or operator of the affected source, the location of the source, the boiler(s) or process heater(s) that will commence burning solid waste, and the date of the notice.
(2) The currently applicable subcategory under this subpart.
(3) The date on which you became subject to the currently applicable emission limits.
(4) The date upon which you will commence combusting solid waste.
(h) If you intend to switch fuels, and this fuel switch may result in the applicability of a different subcategory, 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, and the date of the notice.
(2) The currently applicable subcategory under this subpart.
(3) The date on which you became subject to the currently applicable standards.
(4) The date upon which you will commence the fuel switch.
(a) You must submit each report in Table 9 to this subpart that applies to you.
(b) Unless the EPA Administrator has approved a different schedule for submission of reports under § 63.10(a), you must submit each report by the date in Table 9 to this subpart and according to the requirements in paragraphs (b)(1) through (5) of this section. For units that are subject only to a requirement to conduct an annual or biennial tune-up according to § 63.7540(a)(10) or (a)(11), respectively, and not subject to emission limits or operating limits, you may submit only an annual or biennial compliance report, as applicable, as specified in paragraphs (b)(1) through (5) of this section, instead of a semi-annual compliance report.
(1) The first compliance report must cover the period beginning on the compliance date that is specified for your affected source in § 63.7495 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days (or 1 or 2 year, as applicable, if submitting an annual or biennial compliance report) after the compliance date that is specified for your source in § 63.7495.
(2) The first compliance report must be postmarked or delivered no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for your source in § 63.7495. The first annual or biennial compliance report must be postmarked no later than January 31.
(3) Each subsequent compliance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31. Annual and biennial compliance reports must cover the applicable one or two year periods from January 1 to December 31.
(4) Each subsequent compliance report must be postmarked or delivered no later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period. Annual and biennial compliance reports must be postmarked no later than January 31.
(5) For each affected source that is subject to permitting regulations pursuant to part 70 or part 71 of this chapter, and if the delegated authority has established dates for submitting semiannual reports pursuant to § 70.6(a)(3)(iii)(A) or § 71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance reports according to the dates the delegated authority has established instead of according to the dates in paragraphs (b)(1) through (4) of this section.
(c) The compliance report must contain the information required in paragraphs (c)(1) through (13) of this section.
(1) Company name and address.
(2) Statement by a responsible official with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report.
(3) Date of report and beginning and ending dates of the reporting period.
(4) The total fuel use by each affected source subject to an emission limit, for each calendar month within the
(5) A summary of the results of the annual performance tests for affected sources subject to an emission limit, a summary of any fuel analyses associated with performance tests, and documentation of any operating limits that were reestablished during this test, if applicable. If you are conducting performance tests once every 3 years consistent with § 63.7515(b) or (c), the date of the last 2 performance tests, a comparison of the emission level you achieved in the last 2 performance tests to the 75 percent emission limit threshold required in § 63.7515(b) or (c), and a statement as to whether there have been any operational changes since the last performance test that could increase emissions.
(6) A signed statement indicating that you burned no new types of fuel in an affected source subject to an emission limit. Or, if you did burn a new type of fuel and are subject to a hydrogen chloride emission limit, you must submit the calculation of chlorine input, using Equation 5 of § 63.7530, that demonstrates that your source is still within its maximum chlorine input level established during the previous performance testing (for sources that demonstrate compliance through performance testing) or you must submit the calculation of hydrogen chloride emission rate using Equation 10 of § 63.7530 that demonstrates that your source is still meeting the emission limit for hydrogen chloride emissions (for boilers or process heaters that demonstrate compliance through fuel analysis). If you burned a new type of fuel and are subject to a mercury emission limit, you must submit the calculation of mercury input, using Equation 8 of § 63.7530, that demonstrates that your source is still within its maximum mercury input level established during the previous performance testing (for sources that demonstrate compliance through performance testing), or you must submit the calculation of mercury emission rate using Equation 11 of § 63.7530 that demonstrates that your source is still meeting the emission limit for mercury emissions (for boilers or process heaters that demonstrate compliance through fuel analysis).
(7) If you wish to burn a new type of fuel in an affected source subject to an emission limit and you cannot demonstrate compliance with the maximum chlorine input operating limit using Equation 7 of § 63.7530 or the maximum mercury input operating limit using Equation 8 of § 63.7530, you must include in the compliance report a statement indicating the intent to conduct a new performance test within 60 days of starting to burn the new fuel.
(8) A summary of any monthly fuel analyses conducted to demonstrate compliance according to §§ 63.7521 and 63.7530 for affected sources subject to emission limits, and any fuel specification analyses conducted according to § 63.7521(f) and § 63.7530(g).
(9) If there are no deviations from any emission limits or operating limits in this subpart that apply to you, a statement that there were no deviations from the emission limits or operating limits during the reporting period.
(10) If there were no deviations from the monitoring requirements including no periods during which the CMSs, including CEMS, COMS, and continuous parameter monitoring systems, were out of control as specified in § 63.8(c)(7), a statement that there were no deviations and no periods during which the CMS were out of control during the reporting period.
(11) If a malfunction occurred during the reporting period, the report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by you during a malfunction of a boiler, process heater, or associated air pollution control device or CMS to minimize emissions in accordance with § 63.7500(a)(3), including actions taken to correct the malfunction.
(12) Include the date of the most recent tune-up for each unit subject to only the requirement to conduct an annual or biennial tune-up according to § 63.7540(a)(10) or (a)(11), respectively. Include the date of the most recent burner inspection if it was not done annually or biennially and was delayed until the next scheduled unit shutdown.
(13) If you plan to demonstrate compliance by emission averaging, certify the emission level achieved or the control technology employed is no less stringent that the level or control technology contained in the notification of compliance status in § 63.7545(e)(5)(i).
(d) For each deviation from an emission limit or operating limit in this subpart that occurs at an affected source where you are not using a CMS to comply with that emission limit or operating limit, the compliance report must additionally contain the information required in paragraphs (d)(1) through (4) of this section.
(1) The total operating time of each affected source during the reporting period.
(2) A description of the deviation and which emission limit or operating limit from which you deviated.
(3) Information on the number, duration, and cause of deviations (including unknown cause), as applicable, and the corrective action taken.
(4) A copy of the test report if the annual performance test showed a deviation from the emission limits.
(e) For each deviation from an emission limit, operating limit, and monitoring requirement in this subpart occurring at an affected source where you are using a CMS to comply with that emission limit or operating limit, you must include the information required in paragraphs (e)(1) through (12) of this section. This includes any deviations from your site-specific monitoring plan as required in § 63.7505(d).
(1) The date and time that each deviation started and stopped and description of the nature of the deviation (
(2) The date and time that each CMS was inoperative, except for zero (low-level) and high-level checks.
(3) The date, time, and duration that each CMS was out of control, including the information in § 63.8(c)(8).
(4) The date and time that each deviation started and stopped.
(5) A summary of the total duration of the deviation during the reporting period and the total duration as a percent of the total source operating time during that reporting period.
(6) An analysis of the total duration of the deviations during the reporting period into those that are due to control equipment problems, process problems, other known causes, and other unknown causes.
(7) A summary of the total duration of CMS's downtime during the reporting period and the total duration of CMS downtime as a percent of the total source operating time during that reporting period.
(8) An identification of each parameter that was monitored at the affected source for which there was a deviation.
(9) A brief description of the source for which there was a deviation.
(10) A brief description of each CMS for which there was a deviation.
(11) The date of the latest CMS certification or audit for the system for which there was a deviation.
(12) A description of any changes in CMSs, processes, or controls since the last reporting period for the source for which there was a deviation.
(f) Each affected source that has obtained a Title V operating permit pursuant to part 70 or part 71 of this chapter must report all deviations as defined in this subpart in the semiannual monitoring report required by § 70.6(a)(3)(iii)(A) or § 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 9 to this subpart along with, or as part of, the semiannual monitoring report required by § 70.6(a)(3)(iii)(A) or § 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in this subpart, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. However, submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the delegated authority.
(g) [Reserved]
(h) As of January 1, 2012 and within 60 days after the date of completing each performance test, as defined in § 63.2, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (
(a) You must keep records according to paragraphs (a)(1) and (2) of this section.
(1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that you submitted, according to the requirements in § 63.10(b)(2)(xiv).
(2) Records of performance tests, fuel analyses, or other compliance demonstrations and performance evaluations as required in § 63.10(b)(2)(viii).
(b) For each CEMS, COMS, and continuous monitoring system you must keep records according to paragraphs (b)(1) through (5) of this section.
(1) Records described in § 63.10(b)(2)(vii) through (xi).
(2) Monitoring data for continuous opacity monitoring system during a performance evaluation as required in § 63.6(h)(7)(i) and (ii).
(3) Previous (
(4) Request for alternatives to relative accuracy test for CEMS as required in § 63.8(f)(6)(i).
(5) Records of the date and time that each deviation started and stopped.
(c) You must keep the records required in Table 8 to this subpart including records of all monitoring data and calculated averages for applicable operating limits, such as opacity, pressure drop, pH, and operating load, to show continuous compliance with each emission limit and operating limit that applies to you.
(d) For each boiler or process heater subject to an emission limit in Table 1, 2 or 12 to this subpart, you must also keep the applicable records in paragraphs (d)(1) through (8) of this section.
(1) You must keep records of monthly fuel use by each boiler or process heater, including the type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous secondary materials that have been determined not to be solid waste pursuant to § 41.3(b)(1), you must keep a record which documents how the secondary material meets each of the legitimacy criteria. If you combust a fuel that has been processed from a discarded non-hazardous secondary material pursuant to § 241.3(b)(4), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in § 241.2. If the fuel received a non-waste determination pursuant to the petition process submitted under § 241.3(c), you must keep a record that documents how the fuel satisfies the requirements of the petition process.
(3) You must keep records of monthly hours of operation by each boiler or process heater that meets the definition of limited-use boiler or process heater.
(4) A copy of all calculations and supporting documentation of maximum chlorine fuel input, using Equation 7 of § 63.7530, that were done to demonstrate continuous compliance with the hydrogen chloride emission limit, for sources that demonstrate compliance through performance testing. For sources that demonstrate compliance through fuel analysis, a copy of all calculations and supporting documentation of hydrogen chloride emission rates, using Equation 10 of § 63.7530, that were done to demonstrate compliance with the hydrogen chloride emission limit. Supporting documentation should include results of any fuel analyses and basis for the estimates of maximum chlorine fuel input or hydrogen chloride emission rates. You can use the results from one fuel analysis for multiple boilers and process heaters provided they are all burning the same fuel type. However, you must calculate chlorine fuel input, or hydrogen chloride emission rate, for each boiler and process heater.
(5) A copy of all calculations and supporting documentation of maximum mercury fuel input, using Equation 8 of § 63.7530, that were done to demonstrate continuous compliance with the mercury emission limit for sources that demonstrate compliance through performance testing. For sources that demonstrate compliance through fuel analysis, a copy of all calculations and supporting documentation of mercury emission rates, using Equation 11 of § 63.7530, that were done to demonstrate compliance with the mercury emission limit. Supporting documentation should include results of any fuel analyses and basis for the estimates of maximum mercury fuel input or mercury emission rates. You can use the results from one fuel analysis for multiple boilers and process heaters provided they are all burning the same fuel type. However, you must calculate mercury fuel input, or mercury emission rates, for each boiler and process heater.
(6) If, consistent with § 63.7515(b) and (c), you choose to stack test less frequently than annually, you must keep annual records that document that your emissions in the previous stack test(s) were less than 75 percent of the applicable emission limit, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the relevant pollutant to increase within the past year.
(7) Records of the occurrence and duration of each malfunction of the boiler or process heater, or of the associated air pollution control and monitoring equipment.
(8) Records of actions taken during periods of malfunction to minimize emissions in accordance with the
(e) If you elect to average emissions consistent with § 63.7522, you must additionally keep a copy of the emission averaging implementation plan required in § 63.7522(g), all calculations required under § 63.7522, including monthly records of heat input or steam generation, as applicable, and monitoring records consistent with § 63.7541.
(f) If you elect to use emission credits from energy conservation measures to demonstrate compliance according to § 63.7533, you must keep a copy of the Implementation Plan required in § 63.7533(d) and copies of all data and calculations used to establish credits according to § 63.7533(b), (c), and (f).
(g) If you elected to demonstrate that the unit meets the specifications for hydrogen sulfide and mercury for the other gas 1 subcategory and you cannot submit a signed certification under § 63.7545(g) because the constituents could exceed the specifications, you must maintain monthly records of the calculations and results of the fuel specifications for mercury and hydrogen sulfide in Table 6.
(h) If you operate a unit designed to burn natural gas, refinery gas, or other gas 1 fuel that is subject to this subpart, and you use an alternative fuel other than natural gas, refinery gas, or other gas 1 fuel, you must keep records of the total hours per calendar year that alternative fuel is burned.
(a) Your records must be in a form suitable and readily available for expeditious review, according to § 63.10(b)(1).
(b) As specified in § 63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.
(c) You must keep each record on site, or they must be accessible from on site (for example, through a computer network), for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 63.10(b)(1). You can keep the records off site for the remaining 3 years.
Table 10 to this subpart shows which parts of the General Provisions in §§ 63.1 through 63.15 apply to you.
(a) This subpart can be implemented and enforced by EPA, or a delegated authority such as your State, local, or tribal agency. If the EPA Administrator has delegated authority to your State, local, or tribal agency, then that agency (as well as EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your State, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a State, local, or tribal agency under 40 CFR part 63, subpart E, the authorities listed in paragraphs (b)(1) through (5) of this section are retained by the EPA Administrator and are not transferred to the State, local, or tribal agency, however, EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the non-opacity emission limits and work practice standards in § 63.7500(a) and (b) under § 63.6(g).
(2) Approval of alternative opacity emission limits in § 63.7500(a) under § 63.6(h)(9).
(3) Approval of major change to test methods in Table 5 to this subpart under § 63.7(e)(2)(ii) and (f) and as defined in § 63.90, and alternative analytical methods requested under § 63.7521(b)(2).
(4) Approval of major change to monitoring under § 63.8(f) and as defined in § 63.90, and approval of alternative operating parameters under § 63.7500(a)(2) and § 63.7522(g)(2).
(5) Approval of major change to recordkeeping and reporting under § 63.10(e) and as defined in § 63.90.
Terms used in this subpart are defined in the Clean Air Act, in § 63.2 (the General Provisions), and in this section as follows:
(1)
(i) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard; or
(ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
(2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards.
(1) Energy assessment for facilities with affected boilers and process heaters using less than 0.3 trillion Btu per year heat input will be one day in length maximum. The boiler system and energy use system accounting for at least 50 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a one-day energy assessment.
(2) The Energy assessment for facilities with affected boilers and process heaters using 0.3 to 1.0 trillion Btu per year will be 3 days in length maximum. The boiler system and any energy use system accounting for at least 33 percent of the energy output will be evaluated to identify energy savings opportunities, within the limit of performing a 3-day energy assessment.
(3) In the Energy assessment for facilities with affected boilers and process heaters using greater than 1.0 trillion Btu per year, the boiler system and any energy use system accounting for at least 20 percent of the energy output will be evaluated to identify energy savings opportunities.
(1) An equivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three composite fuel samples, with each composite consisting of a minimum of three increments collected at approximately equal intervals over the test period.
(2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample.
(3) An equivalent sample preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determinative or analytical method.
(4) An equivalent procedure for determining heat content means a published VCS or EPA method to obtain gross calorific (or higher heating) value.
(5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining metals (especially the mercury, selenium, or arsenic) using an aliquot of the dried sample, then the drying
(6) An equivalent pollutant (mercury, hydrogen chloride, hydrogen sulfide) determinative or analytical procedure means a published VCS or EPA method that clearly states that the standard, practice, or method is appropriate for the pollutant and the fuel matrix and has a published detection limit equal or lower than the methods listed in Table 6 to this subpart for the same purpose.
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or
(2) Liquid petroleum gas, as defined in ASTM D1835 (incorporated by reference,
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 mega joules (MJ) per dry standard cubic
(4) Propane or propane derived synthetic natural gas. Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C
(1) someone who has demonstrated capabilities to evaluate a set of the typical energy savings opportunities available in opportunity areas for steam generation and major energy using systems, including, but not limited to:
(i) Boiler combustion management.
(ii) Boiler thermal energy recovery, including
(A) Conventional feed water economizer,
(B) Conventional combustion air preheater, and
(C) Condensing economizer.
(iii) Boiler blowdown thermal energy recovery.
(iv) Primary energy resource selection, including
(A) Fuel (primary energy source) switching, and
(B) Applied steam energy versus direct-fired energy versus electricity.
(v) Insulation issues.
(vi) Steam trap and steam leak management.
(vi) Condensate recovery.
(viii) Steam end-use management.
(2) Capabilities and knowledge includes, but is not limited to:
(i) Background, experience, and recognized abilities to perform the assessment activities, data analysis, and report preparation.
(ii) Familiarity with operating and maintenance practices for steam or process heating systems.
(iii) Additional potential steam system improvement opportunities including improving steam turbine operations and reducing steam demand.
(iv) Additional process heating system opportunities including effective utilization of waste heat and use of proper process heating methods.
(v) Boiler-steam turbine cogeneration systems.
(vi) Industry specific steam end-use systems.
(1) The equipment is attached to a foundation.
(2) The boiler or a replacement remains at a location for more than 12 consecutive months. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility
(4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition.
As stated in § 63.7500, you must comply with the following applicable emission limits:
As stated in § 63.7500, you must comply with the following applicable emission limits:
As stated in § 63.7500, you must comply with the following applicable work practice standards:
As stated in § 63.7500, you must comply with the applicable operating limits:
As stated in § 63.7520, you must comply with the following requirements for performance testing for existing, new or reconstructed affected sources:
As stated in § 63.7521, you must comply with the following requirements for fuel analysis testing for existing, new or reconstructed affected sources. However, equivalent methods (as defined in § 63.7575) may be used in lieu of the prescribed methods at the discretion of the source owner or operator:
As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:
As stated in § 63.7540, you must show continuous compliance with the emission limitations for affected sources according to the following:
As stated in § 63.7550, you must comply with the following requirements for reports:
As stated in § 63.7565, you must comply with the applicable General Provisions according to the following: