# National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2011-31667 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** December 23, 2011 - **Citation:** 76 FR 80598 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [EPA-HQ-OAR-2002-0058; FRL-9503-6] RIN 2060-AR13 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed rule; Reconsideration of final rule. SUMMARY: On March 21, 2011, the EPA promulgated national emission standards for the control of hazardous air pollutants from new and existing industrial, commercial, and institutional boilers and process heaters at major sources of hazardous air pollutants. On that same day, the EPA also published a notice announcing its intent to reconsider certain provisions of the final rule. The EPA subsequently issued a notice on May 18, 2011, to postpone the effective dates of the final rule until judicial review has been completed, or the agency finalizes its reconsideration of the standard, whichever is earlier. In the action to postpone the effective dates of the rule, the EPA also requested the public to submit data and information to assist the EPA in its reconsideration. Following these actions, the Administrator received several petitions for reconsideration. In response to the March 21, 2011, notice announcing its intent to initiate reconsideration and the petitions submitted, the EPA is reconsidering and requesting comment on several provisions of the final rule. Additionally, the EPA is proposing amendments and technical corrections to the final rule to clarify definitions, references, applicability, and compliance issues raised by stakeholders subject to the final rule. DATES: Comments. Comments must be received on or before February 21, 2012. Public Hearing. We will hold a public hearing concerning the proposed items for reconsideration. Persons interested in presenting oral testimony at the hearing should contact Ms. Teresa Clemons at (919) 541-7689 or at clemons.teresa@epa.gov by January 3, 2012. If no one requests to speak at the public hearing by January 3, 2012, then the public hearing will be cancelled. We will specify the date and time of the public hearings on http://www.epa.gov/ttn/atw/boiler/boilerpg.html. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2002-0058, by one of the following methods: • http://www.regulations.gov: Follow the instructions for submitting comments. • Email: Comments may be sent by email to a-and-r-Docket@epa.gov, Attention Docket ID No. EPA-HQ-OAR-2002-0058. • Fax: Fax your comments to: (202) 566-9744, Attention Docket ID No. EPA-HQ-OAR-2002-0058. • Mail: Send your comments to: EPA Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Docket ID No. EPA-HQ-OAR-2002-0058. Please include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St. NW., Washington, DC 20503. • Hand Delivery: In person or by courier, deliver comments to: EPA Docket Center (2822T), EPA West, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460. Such deliveries are only accepted during the Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays), and special arrangements should be made for deliveries of boxed information. Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-2002-0058. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site is an “anonymous access” system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment and with any disk or CD-ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about EPA's public docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Docket Center is (202) 566-1742. FOR FURTHER INFORMATION CONTACT: 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; Email address: shrager.brian@epa.gov. SUPPLEMENTARY INFORMATION: Organization of this Document. The following outline is provided to aid in locating information in this preamble. I. General Information A. Does this notice of reconsideration apply to me? B. What should I consider as I prepare my comments to the EPA? C. How do I obtain a copy of this document and other related information? II. Background Information III. Summary of This Proposed Rule A. What is the source category regulated by this proposed rule? B. What is the affected source? C. What are the pollutants regulated by this proposed rule? D. What emission limits and work practice standards must I meet? E. What are the requirements during periods of startup, shutdown and malfunction? F. What are the testing and initial compliance requirements? G. What are the continuous compliance requirements? H. What are the notification, recordkeeping and reporting requirements? I. How should emissions test results be submitted to EPA? J. What are the proposed compliance dates? IV. Actions We Are Taking V. Discussion of Issues for Reconsideration A. Surrogates and Selected Regulated Pollutants B. Output-Based Standards C. Subcategories D. Monitoring E. Emission Limits F. MACT Floor Methodology G. Tune-up Work Practices H. Energy Assessment I. Affirmative Defense Provisions During Malfunctions J. Work Practices During Startup and Shutdown K. Applicability L. Compliance M. Other Issues Open for Comment VI. Technical Corrections and Clarifications VII. Impacts of This Proposed Rule A. What are the air impacts? B. What are the water and solid waste impacts? C. What are the energy impacts? D. What are the cost impacts? E. What are the economic impacts? F. What are the benefits of this proposed rule? G. What are the secondary air impacts? VIII. Relationship of this Proposed Action to Section 112(c)(6) of the Clean Air Act IX. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations I. General Information A. Does this notice of reconsideration apply to me? The regulated categories and entities potentially affected by this action include: Category NAICS code 1 Examples of potentially regulated entities Any industry using a boiler or process heater as defined in the proposed rule 211 Extractors of crude petroleum and natural gas. 321 Manufacturers of lumber and wood products. 322 Pulp and paper mills. 325 Chemical manufacturers. 324 Petroleum refineries, and manufacturers of coal products. 316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 331 Steel works, blast furnaces. 332 Electroplating, plating, polishing, anodizing, and coloring. 336 Manufacturers of motor vehicle parts and accessories. 221 Electric, gas, and sanitary services. 622 Health services. 611 Educational services. 1 North American Industry Classification System. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this reconsideration action. To determine whether your facility may be affected by this reconsideration 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 Institutional Boilers and Process Heaters). If you have any questions regarding the applicability of the proposed rule 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). B. What should I consider as I prepare my comments to the EPA? Submitting CBI. Do not submit information that you consider to be CBI electronically through http://www.regulations.gov or email. Send or deliver information identified as CBI to only the following address: Mr. Robert Morales, c/o OAQPS Document Control Officer (Room C404-02), U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attn: Docket ID No. EPA-HQ-OAR-2002-0058. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. If you submit a disk or CD-ROM that does not contain CBI, mark the outside of the disk or CD-ROM clearly that it does not contain CBI. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. If you have any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section. C. How do I obtain a copy of this document and other related information? Docket. The docket number for this action and the proposed rule (40 CFR part 63, subpart DDDDD) is Docket ID No. EPA-HQ-OAR-2002-0058. World Wide Web (WWW). In addition to being available in the docket, an electronic copy of this action is available on the WWW through the Technology Transfer Network (TTN) Web site. Following signature, a copy of this notice will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg. The TTN provides information and technology exchange in various areas of air pollution control. II. Background Information On March 21, 2011, the EPA issued final standards for new and existing industrial, commercial, and institutional boilers and process heaters, pursuant to its authority under section 112 of the Clean Air Act (CAA). On the same day as this final rule was issued, EPA also stated in a separate notice that it planned to initiate a reconsideration of several provisions of the final rule. This reconsideration notice identified several provisions of the final rule where additional public comment was appropriate, including: • Revisions to the proposed subcategories. • Establishing a fuel specification through which gas-fired boilers that use a fuel other than natural gas or refinery gas may be considered Gas 1 units. • Establishing a work practice standard for limited use units. • Providing an affirmative defense for malfunction events. This notice also identified several issues of central relevance to the rulemaking where reconsideration was appropriate under CAA section 307(d), including: • Revisions to the proposed monitoring requirements for carbon monoxide for major source boilers. • Revisions to the proposed dioxin emission limit and testing requirement for major source boilers. • Establishing a full-load stack test requirement for carbon monoxide coupled with continuous oxygen (oxygen trim) monitoring. On May 18, 2011, the EPA issued a notice to postpone the effective dates of the March 21, 2011, final rule. This notice also requested that the public submit additional data and information to the EPA by July 15, 2011, for review and consideration in the reconsideration proceedings. Following promulgation of the final rule, the EPA received petitions for reconsideration from the following organizations (“Petitioners”): Alliance for Industrial Efficiency (AIE), U.S. Clean Heat Power Association (USCHPA), Alyeska Pipeline, American Chemistry Council (ACC), American Home Furnishings Alliance (AHFA), American Iron and Steel Institute (AISI), American Coke and Coal Chemicals Institute (ACCCI), American Municipal Power Inc. (AMP), American Petroleum Institute (API), National Petrochemical and Refiners Association (NPRA), Auto Industry Forum (AIF), Citizens Energy Group (CEG), Council of Industrial Boiler Owners (CIBO), CraftMaster Manufacturing Inc. (CMI), District Energy St. Paul, Florida Sugar Industry (FSI), Great Plains Synfuels (GPSP), Hovensa L.L.C., Tesoro Hawaii Corp., Industry Coalition (AF&PA et. al.), JELD-WEN Inc., Michigan State University (MSU), Penn State University (PSU), Purdue University, Renovar Energy Corp., Rochester Public Utilities (RPU), Sierra Club, Southeastern Lumber Manufacturers Association, State of Washington Department of Ecology, The Business Council for Sustainable Energy (BCSE), Utility Air Regulatory Group (UARG), United States Sugar Corporation (U.S. Sugar), Waste Management Inc. (WM), and Wisconsin Electric Power Company. Copies of these petitions are provided in the docket (see Docket ID No. EPA-HQ-OAR-2002-0058). Petitioners, pursuant to CAA section 307(d)(7)(B), requested that the EPA reconsider numerous provisions in the rules. In this action, the EPA is proposing multiple changes to the final rule in response to the reconsideration requests and the issues that the EPA previously identified as reconsideration issues. The EPA also is soliciting comment on several provisions of the final rule for which we are not proposing changes, because the public did not previously have an opportunity to comment on those provisions. The issues upon which the EPA is soliciting comment are discussed in section V of this preamble. III. Summary of This Proposed Rule This section summarizes the requirements of this action. Some of the requirements are currently found in the final boilers rule and are not being proposed to be revised. Section IV below provides a summary of the significant changes the EPA is proposing to make in its reconsideration of the final rule, and on which EPA is soliciting public comment. A. What is the source category regulated by this proposed rule? This proposed rule regulates industrial, commercial, and institutional boilers and process heaters located at major sources of hazardous air pollutants (HAP). Waste heat boilers and process heaters 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 proposed rule. B. What is the affected source? This proposed rule affects industrial, commercial, and institutional 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 ( e.g., indirect fired). A boiler is defined as an enclosed device using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water. C. What are the pollutants regulated by this proposed rule? This proposed rule regulates hydrogen chloride (HCl) (as a surrogate for acid gas HAP), total selected metals (TSM) or particulate matter (PM) (as a surrogate for non-mercury HAP metals), carbon monoxide (CO) (as a surrogate for non-dioxin/furan organic HAP), mercury (Hg), and dioxin/furan emissions from boilers and process heaters. D. What emission limits and work practice standards must I meet? You must meet the emission limits presented in Table 1 of this preamble for each subcategory of units listed in the table. This proposed rule includes 17 subcategories, which are based on unit design. New and existing units in 3 of the subcategories would be subject to work practices standards in lieu of emission limits for all pollutants. Numeric emission limits are being proposed for new and existing sources in each of 14 subcategories, which are shown in Table 1 of this preamble. HCl and Hg are “fuel-based pollutants” that directly result from 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 liquid fuel (except as noted in this proposed rule) 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 the lower contiguous 48 states and Alaska (referred to as a non-continental unit for the remainder of this preamble and in this proposed rule), and your new or existing unit combusts liquid fuel (except as noted in this rule) 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 metal process furnace, limited-use unit, or Gas 1 unit (that is, it combusts only natural gas, refinery gas, or other clean gas that meets the fuel specification, 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, PM (a surrogate for metallic HAP) and CO (a surrogate for non-dioxin organic HAP), your unit is subject to the emission limits for the design-based subcategories shown in Table 1 of this preamble. We also are proposing, as alternatives to the PM limits, total selected metals emission limits for subcategories of units that combust solid fuels or Gas 2 fuels. If your new or existing boiler or process heater burns at least 10 percent biomass on an annual average heat input 1 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, on an annual average heat input basis, 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 lower contiguous 48 states or Alaska and your new or existing boiler or process heater burns light liquid fuel ( i.e., distillate oil, biodiesel, or vegetable 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 light liquid subcategory. If your facility is located in the lower contiguous 48 states or Alaska and your new or existing boiler or process heater burns heavy liquid fuel (other liquids that are not defined as light liquids) and less than 10 percent coal and less than 10 percent biomass, on an annual average heat input basis, your unit is in the heavy liquid subcategory. If your non-continental new or existing boiler or process heater burns liquid fuel 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 combustion-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. If your unit combusts only natural gas, refinery gas, or equivalent fuel (other gas that qualifies as Gas 1 fuel), with limited exceptions for gas curtailment and emergencies, your unit is subject to a work practice standard that requires an annual tune-up in lieu of emission limits. 1 Heat input means heat derived from combustion of fuel in a boiler or process heater and does not include the heat derived from preheated combustion air, recirculated flue gases or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns). Table 1—Emission Limits for Boilers and Process Heaters [lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table below] Subcategory Filterable Particulate Matter (Filterable PM) (or total selected metals) (lb per MMBtu of heat input) a Hydrogen chloride (HCl) (lb per MMBtu of heat input) a Mercury (Hg) (lb per MMBtu of heat input) a Carbon monoxide(CO) (ppm @3% oxygen) a Alternate CO CEMS limit, (ppm @3% oxygen) b Existing—Solid fuel NA 0.022 3.1E-06 NA NA Existing—Coal Stoker 0.028 (8.3E-05) NA NA 220 34 Existing—Coal Fluidized Bed 0.088 (1.7E-05) NA NA 56 59 Existing—Coal-Burning Pulverized Coal 0.044 (5.9E-05) NA NA 41 28 Existing—Biomass Wet Stoker/Sloped Grate/Other 0.029 (5.7E-05) NA NA 790 410 Existing—Biomass Kiln-Dried Stoker/Sloped Grate/Other 0.32 (0.004) NA NA 250 ND Existing—Biomass Fluidized Bed 0.11 (0.0012) NA NA 370 180 Existing—Biomass Suspension Burner 0.051 (0.0011) NA NA 58 1,400 Existing—Biomass Dutch Ovens/Pile Burners 0.036 (2.4E-04) NA NA 810 440 Existing—Biomass Fuel Cells 0.033 (4.9E-05) NA NA 1,500 ND Existing—Biomass Hybrid Suspension Grate 0.44 (4.9E-04) NA NA 3,900 730 Existing—Liquid NA 0.0012 2.6E-05 NA NA Existing—Heavy Liquid c 0.062 NA NA 10 18 Existing—Light Liquid c 0.0034 NA NA 7 d 60 Existing—non-Continental Liquid c 0.0080 NA NA 18 e 91 Existing—Gas 2 (Other Process Gases) 0.0067 (2.4E-04) 0.0017 7.9E-06 4 ND New—Solid Fuel NA 0.022 8.6E-07 NA NA New—Coal Stoker 0.028 (2.2E-05) NA NA 19 34 New—Coal Fluidized Bed 0.0011 (1.7E-05) NA NA 17 59 New—Coal-Burning Pulverized Coal 0.0013 (2.8E-05) NA NA 9 28 New—Biomass Wet Stoker/Sloped Grate/Other 0.029 (2.6E-05) NA NA 590 410 New—Biomass Kiln-Dried Stoker/Sloped Grate/Other 0.32 (0.0040) NA NA 250 ND New—Biomass Fluidized Bed 0.0098 (4.2E-05) NA NA 230 180 New—Biomass Suspension Burner 0.051 (0.0011) NA NA 58 1,400 New—Biomass Dutch Ovens/Pile Burners 0.036 (4.1E-05) NA NA 810 440 New—Biomass Fuel Cells 0.011 (4.9E-05) NA NA 210 ND New—Biomass Hybrid Suspension Grate 0.026 (4.9E-04) NA NA 1,500 730 New—Liquid NA 0.0012 4.9E-07 NA NA New—Heavy Liquid c 0.013 NA NA 10 18 New—Light Liquid c 0.0011 NA NA 3 d 60 New—Non-Continental Liquid c 0.0080 NA NA 18 e 91 New—Gas 2 (Other Process Gases) 0.0067 (2.4E-04) 0.0017 7.9E-06 4 ND NA—Not applicable; ND—No data available. a 3-run average, unless otherwise noted. b 10-day rolling average, unless otherwise noted. c Total selected metals alternative limits are not available to units in any of the liquid subcategories. d 1-day block average. e 3-hour rolling average. 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 proposed rule. Pursuant to CAA section 112(h), the final rule requires a work practice standard for the following particular classes of boilers and process heaters: new and existing units that have a designed heat input capacity of less than 10 MMBtu/hr, new and existing units in the Gas 1 (natural gas/refinery gas) subcategory and in the metal process furnaces subcategory, and new and existing limited-use units. The work practice standard for these boilers and process heaters requires the implementation of a tune-up program. We also are proposing a work practice standard for dioxin/furan emissions from all subcategories. Finally, the final rule includes 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 IV of this preamble, of the affected boilers and facility to identify any cost-effective energy conservation measures. E. What are the requirements during periods of startup, shutdown, and malfunction? We are not proposing to change the malfunction provisions in this rule. See 76 FR 15613. We are proposing revised work practice standards for periods of startup and shutdown. The final rule required that an owner/operator must “Minimize the unit's startup and shutdown periods following the manufacturer's recommended procedures. 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.” While we are maintaining a work practice approach for startup and shutdown, we are proposing to change the work practice standards to better reflect the maximum achievable control technology. First, we are proposing definitions of startup and shutdown. We are proposing to define startup as the period between the state of no combustion in the unit to the period where the unit first achieves 25 percent load ( i.e., a cold start). We are proposing to define shutdown as the period that begins when a unit last operates at 25 percent load and ending with a state of no fuel combustion in the unit. For periods of startup and shutdown, we are proposing the following work practice standard: you must employ good combustion practices and demonstrate that good combustion practices are maintained by monitoring O 2 concentrations and optimizing those concentrations as specified by the boiler manufacturer; you must ensure that boiler operators are trained in startup and shutdown procedures, including maintenance and cleaning, safety, control device startup, and procedures to minimize emissions; and you must maintain records during periods of startup and shutdown and include in your compliance reports the O 2 conditions/data for each startup event, length of startup/shutdown and reason for the startup/shutdown ( i.e., normal/routine, problem/malfunction, outage). You must comply with all applicable emissions limits at all times except for startup and shutdown periods, during which times you must comply with these work practices. F. What are the testing and initial compliance requirements? We are requiring that the owner or operator of a new or existing boiler or process heater conduct performance tests to demonstrate compliance with all applicable emission limits. An owner or operator of any affected unit would be required to conduct the following compliance tests as applicable: (1) Conduct initial and annual stack tests to determine compliance with the PM emission limits using EPA Method 5 or 17 or conduct initial and annual stack tests to determine compliance with the TSM emission limits using EPA Method 29 for those subcategories with alternate TSM limits. (2) Conduct initial and annual stack tests to determine compliance with the Hg emission limits using EPA Method 29, 30B, 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 are in the sample). (4) Use EPA Method 19 to convert measured concentration values to pound per million Btu values. (5) Conduct initial and annual tests to determine compliance with the CO emission limits using EPA Method 10 or install, operate, and maintain CO continuous emission monitoring systems (CEMS) to determine compliance with the alternate CO CEMS-based emission limits. 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 or TSM (as appropriate), Hg, HCl, and CO 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 parameter average measured during the three test runs (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 across the scrubber 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, 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 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 injection rate operating limit value. (4) For boilers and process heaters with fabric filters not subject to PM Continuous Parametric Monitoring System (PM CPMS) or continuous compliance with an opacity limit ( i.e., continuous opacity monitoring systems (COMS)), you must operate the fabric filter such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during any 6-month period unless a PM CPMS is installed to monitor PM control. For the purposes of the rule, we define a PM CPMS as a continuous parametric monitoring device based on a detection principle of light scatter, light scintillation, beta attenuation, or mass accumulation detection of PM in the exhaust gas or representative exhaust gas sample, installed and operated on the effluent stack or duct downstream of any particulate control device(s), and programmed to provide a continuous electronic signal representative of ongoing particulate matter control device performance. (5) For boilers and process heaters with electrostatic precipitators (ESP) not subject to PM CPMS or continuous compliance with an opacity limit ( i.e., COMS), you must measure the secondary voltage and secondary current of the ESP collection fields during the Hg and PM performance test. You then calculate the average total secondary electric power value from these parameters for each test run. The lowest hourly average total secondary electric power measured during the three test runs establishes your site-specific minimum operating limit for the ESP on a 12-hour block average basis. (6) For boilers and process heaters that choose to demonstrate compliance with the Hg emission limit by fuel analysis, you must measure the Hg content of the inlet fuel that was burned during the Hg performance test. This value is your maximum fuel Hg content operating limit. (7) For boilers and process heaters that choose to demonstrate compliance with the HCl emission limit by fuel analysis, you must measure the chlorine content of the inlet fuel that was burned during the HCl performance test. This value is your maximum fuel chlorine content operating limit. (8) For boilers and process heaters that choose to demonstrate compliance with the total selected metals emission limit on the basis of fuel analysis, you are required to measure the total selected metals content of the inlet fuel that was burned during the total selected metals performance test. This value is your maximum fuel total selected metals content operating limit. (9) For boilers and process heaters that are subject to a CO emission limit, you must record the oxygen concentration representative of your boiler operation ( e.g., oxygen trim) during the initial performance test. 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. Instead, if requested, owners or operators of such boilers and process heaters shall submit to the delegated authority or the EPA, as appropriate, 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 actions: (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 the system 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 any adjustments related to the tune-up are made, (6) Submit to the delegated authority or the EPA an annual report containing the concentrations of CO in the effluent stream in ppmvd and oxygen in percent dry basis, both measured before and after the adjustments of the unit; 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 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 the EPA, as appropriate, documentation that an energy assessment was performed by a qualified energy assessor and documentation of the cost-effective energy conservation measures indentified by the energy assessment. G. What are the continuous compliance requirements? To demonstrate continuous compliance with the emission limitations, we are requiring the following: (1) For units combusting coal or residual fuel oil ( i.e., No. 4, 5 or 6 fuel oil) with average annual heat input rate of less than 250 MMBtu/hr (from the combustion of those fuels) or any units in the biomass subcategories and all biomass units that do not use a wet scrubber, opacity levels must be maintained to less than 10 percent (daily average) for existing and new units with applicable emission limits. If the unit is controlled with a fabric filter, instead of being subject to continuous opacity monitoring, the fabric filter must be continuously operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during any 6-month period (unless a PM CPMS is used). (2) For units combusting coal or residual oil with heat input capacities of 250 MMBtu/hr or greater from the combustion of those fuels, the EPA is proposing the collection of data using a PM CPMS at all times that the unit is subject to numeric emission limits, with the exception of periods of PM CPMS repair, malfunction, scheduled maintenance, or QA/QC related activities. The operating unit will prepare, and submit for approval, a site-specific monitoring plan that addresses the PM CPMS design, data collection, and the QA/QC elements outlined in 63.8(d), including the performance criteria and design specifications for the monitoring system equipment, the sample interface location, frequency of quality control checks, frequency of system performance evaluations, ongoing operation and maintenance procedures as well as ongoing reporting and recordkeeping procedures. An annual deviation report must be submitted detailing data collected during periods of boiler startup, shutdown or malfunction and PM CPMS malfunction, repair, or other QA/QC related activity. Records of these data must be available on site for inspection, including corrective actions necessary to return the PM CPMS to operation consistent with the site specific monitoring plan. The operating unit will use output data collected from the CPMS (milliamps, milligrams per actual cubic meter, or other instrument output) during all other operating hours where numeric emission limits apply to assess compliance with the operating limit. An arithmetic average of the measurement output values collected during each hour will be calculated, and for each operating day the arithmetic average of all hourly measurement output values will be calculated for the previous 30 operating days. You must transmit four reports per year for each PM CPMS to the EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface, or CEDRI, that is accessed through the EPA's Central Data Exchange (CDX) ( www.epa.gov/cdx ). Complete reports must be submitted within 60 days after March 31st, June 30th, September 30th, and December 31st. Complete reports contain daily PM CPMS rolling 30-day average values for the periods that end with each of the 4 previously mentioned dates. (3) For boilers and process heaters with wet PM scrubbers, you must monitor pressure drop and liquid flow rate of the scrubber and maintain the 30-day rolling 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 30-day rolling 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, you must continuously monitor the sorbent injection rate and maintain the hourly average 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 not required to install a CPMS and having an ESP installed, you must monitor the voltage and current of the ESP collection plates and maintain the 30-day rolling average total secondary electric power at or above the operating limits established during the Hg, PM, or TSM performance test. (7) For units that choose to comply with either the Hg emission limit, the HCl emission limit, or TSM emission limit (solid fuel units only) 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, chlorine content, or TSM content of the inlet fuel was maintained at or below your maximum fuel Hg content operating limit, your chlorine content operating limit, or your TSM 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, maximum chlorine input, and/or maximum TSM 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, you must install, calibrate and operate an oxygen trim system in order to ensure efficient combustion and compliance with the CO standards. (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 or 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. H. What are the notification, recordkeeping and reporting requirements? 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 certifications of compliance with rule requirements in the notification of compliance status report. This proposed rule would require records to demonstrate compliance with each emission limit, operating limit and work practice standard, as specified in the General Provisions. Owners or operators of sources with units with heat input capacity of less than 10 MMBtu/hr, units combusting natural gas or other clean gas, metal process furnaces and limited use units must keep records of the dates and the results of each required boiler tune-up. Records of either continuously monitored parameter data for a control device if a device is used to control the emissions or continuous monitoring systems (CMS) data are required. You are required to keep the following records: (1) All reports and notifications submitted to comply with the rule. (2) Continuous monitoring data as required in the rule. (3) Each instance in which you did not meet each emission limit and each operating limit ( i.e., deviations from the rule). (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 the rule, for each affected source with an applicable HCl emission limit. (7) Calculations and supporting information of Hg fuel input, as required in the rule, for each affected source with an applicable Hg emission limit. (8) A paragraph that discusses calculations and supporting information of TSM fuel input, as required in the rule, for each affected source with an applicable total selected metals emission limit. (9) A signed statement, as required in the 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. (10) A signed statement, as required in the 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. (11) A signed statement, as required in the rule, indicating that you burned no new fuels and no new fuel mixture or that the recalculation of total selected metals fuel input demonstrated that the new fuel or new fuel mixture still meets the total selected metals fuel input levels, for each affected source with an applicable total selected metals emission limit. (12) A copy of the results of all performance tests, fuel analyses, opacity observations, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with the rule. (13) A copy of your site-specific monitoring plan developed for the rule as specified in 63 CFR 63.8(e), if applicable. (14) A copy of your fuel analysis plan at least 60 days prior to demonstrating initial compliance. You also are required to 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 to occur. (4) Notification of Compliance Status 60 calendar days following completion of the performance test and/or compliance demonstration. (5) Compliance reports semi-annually. I. How should emissions test results be submitted to the EPA? The EPA must have performance test data to conduct effective reviews of CAA sections 112 standards, as well as for many other purposes including compliance determinations, emission factor development, and annual emission rate determinations. In conducting these required reviews, the EPA has found it ineffective and time consuming, for us, for regulatory agencies and for source owners and operators, to locate, collect, and submit performance test data because of varied locations for data storage and varied data storage methods. In recent years, however, stack testing firms have typically collected performance test data in electronic format, making it possible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility. In this proposal, the EPA is presenting a step to improve the ease and efficiency of data submittal and increase data accessibility. Specifically, the EPA is proposing that owners and operators of industrial, commercial, and institutional boilers and process heaters submit electronic copies of required performance test reports to EPA's WebFIRE database. The WebFIRE database was constructed to store performance test data for use in developing emission factors. A description of the WebFIRE database is available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main . Data entry would be through an electronic emissions test report structure called the Electronic Reporting Tool (ERT). The ERT would be able to transmit the electronic report through the EPA's CDX network for storage in the WebFIRE database making submittal of data very straightforward and easy. A description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/index.html . The proposal to submit performance test data electronically to the EPA would apply only to those performance tests conducted using test methods that will be supported by the ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at http://www.epa.gov/ttn/chief/ert/index.html. We believe that industry would benefit from this proposed approach to electronic data submittal. With these data, the EPA would be able to develop improved emission factors, make fewer information requests, and promulgate better regulations. One major advantage of the proposed submittal of performance 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 rule. Another advantage is that the ERT clearly states what testing information would be required. Another important proposed benefit of submitting these data to the EPA at the time the source test is conducted is that it should substantially reduce the effort involved in data collection activities in the future. If the EPA has performance test data from these submittals, the EPA will likely need fewer or less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews. This would reduce the burden on both affected facilities (in terms of reduced manpower to respond to data collection requests) and the EPA (in terms of preparing and distributing data collection requests and assessing the results). State, local, and tribal agencies could also benefit from more streamlined and accurate review of electronic data submitted to them. The ERT would allow for an electronic review process rather than a manual data assessment, making review and evaluation of the source provided data and calculations easier and more efficient. Finally, another benefit of the proposed data submittal to WebFIRE electronically is that these data would greatly improve the overall quality of existing and new emissions factors, by supplementing the pool of emissions test data for establishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint from industry and regulators is that emission factors are outdated or do not represent a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA would be able to ensure that emission factors, when updated, represent the most current range of operational practices. In summary, in addition to supporting regulation development, control strategy development and other air pollution control activities, having an electronic database populated with performance test data would save industry, state, local, tribal agencies and the EPA significant time, money, and effort while also improving the quality of emission inventories and, as a result, air quality regulations. J. What are the proposed compliance dates? The EPA is proposing to reset the compliance date for existing sources to the date 3 years after the date of publication of the final reconsideration rule. For new sources, the EPA is proposing to change the compliance date to 60 days after the date of publication of the final reconsideration rule or upon startup, whichever is later. We are not proposing to change the date that identifies whether a source is new or existing. This date, June 4, 2010, is the publication date of the original proposed rule. IV. Actions We Are Taking In this notice, we are granting reconsideration of, and requesting comment on, issues presented in the March 21, 2011, reconsideration notice as well as a subset of other issues raised by petitioners in their petitions for reconsideration. Section V of this preamble summarizes these issues and discusses our proposed responses to each issue. We have revised the rule language to address provisions related to the reconsideration and are requesting comment on the revised rule text to clarify definitions, applicability, compliance and references to various sections of the rule. Finally, we are proposing technical corrections to certain applicability and compliance provisions in the final rule. We are seeking public comment only on the issues specifically identified in Section V of this action. We will not respond to any comments addressing other aspects of the final rule or any other related rulemakings. V. Discussion of Issues for Reconsideration This section of the preamble contains EPA's basis for our responses to certain issues identified in the petitions for reconsideration and the changes to the rule that we are proposing. We solicit comment on all responses and revisions discussed in the following sections: A. Surrogates and Selected Regulated Pollutants 1. Alternative Total Selected Metals Limit. Multiple petitioners requested that EPA include an emission limit for TSM as an alternative to the PM limits in the final rule, particularly for biomass units, as part of the reconsideration. After assessing the available data, the EPA determined that inclusion of these limits is appropriate for some subcategories, and the EPA is proposing TSM limits for each subcategory of units that combust solid fuels or Gas 2 fuels. Sources will have the option of meeting either the TSM limit or the alternative PM limit. The TSM measurement, which directly quantifies the HAP metals rather than relying on a surrogate, is a more direct measurement of HAP than PM and is, therefore, appropriate as a pollutant group for regulation with numeric emission limits. For this rule, TSM includes the following eight metals: Arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium. The EPA selected these eight metals, rather than all of the HAP metals other than Hg, because more test data are available for these metals than for the other two HAP metals, cobalt and antimony. The use of 8 of 10 metals should have little or no impact on a facility's selection of controls to meet the standards, and the controls that would be used to reduce emissions of the eight metals would be equally effective in reducing emissions of the other two metals. Therefore, TSM can serve as a surrogate for all metallic HAP except for Hg, which the final rule regulates separately. For the light liquid, heavy liquid and non-continental liquid units subcategories, we are not proposing alternative TSM emission limits. Instead, we are proposing that these units meet the filterable PM emission limits in all instances. We are not proposing the TSM alternative because of the limited emission test data for TSM and the large variability in the TSM data for these subcategories. Using the EPA's maximum achievable control technology (MACT) floor methodology, the alternative TSM limits resulted in MACT floor values which do not appear to represent the actual performance of the best performing units. The EPA has sent follow-up inquiries to facilities to confirm these data, and is soliciting comment on whether alternative TSM limits are appropriate for the subcategories of units designed to combust liquid fuels. The EPA also is soliciting comment on whether an alternative approach to calculating the TSM MACT floors for these units is appropriate. If the EPA receives sufficient information that supports the alternative TSM standards for units designed to combust liquid fuels, we will consider adopting these limits in the final rule. 2. Work Practice for Dioxin/Furan Emissions. Multiple petitioners requested that EPA reassess the potential for applying work practice standards for dioxins/furans in lieu of numeric emission limits. The EPA has re-assessed the dioxin/furan data sets and has determined that, similar to data for electric utilities for which work practice standards were proposed for dioxins/furans, the large majority of the emission measurements for all of the subcategories are below the level that can be accurately measured using EPA Method 23. While the EPA recognized this as an issue prior to issuing the final rule, sufficient time was not available to fully analyze the issue. For this proposal, the EPA conducted extensive analyses to determine the lowest level of emissions that can be accurately measured using EPA Method 23. The percentages of measurements (test runs) below the method detection level (a level at which the pollutant is known to be present but is not accurately quantified) is about 55 percent, which is 10 percent lower than the percentage for electric utilities. However, in addition to the high percentage of measurements below the method detection level, a very high percentage of measurements are below the level that can be accurately measured (see section V.E.3 of this preamble) for each subcategory. Those percentage are as follows: Coal stoker—100 percent; coal fluidized bed—89 percent; pulverized coal—85 percent; biomass stoker/other—100 percent; biomass fluidized bed—100 percent; biomass dutch oven/pile burner—80 percent; biomass fuel cell—100 percent; heavy liquid—96 percent; light liquid—100 percent; gas 2 (other process gases)—100 percent; non-continental liquid—100 percent (based on No. 6 oil data). While data are not available for two of the biomass subcategories, there is no reason to believe that dioxin emissions for those subcategories would be different than for the other biomass-based subcategories. Based on the percentages of data below the method detection limit coupled with the percentage of data below the level that can be accurately quantified, the EPA concludes that emissions from industrial boilers and process heaters cannot practicably be measured, and the EPA is now proposing work practice standards in place of numeric emission limits for dioxin/furan. The work practice standards require an annual tune-up to ensure good combustion. Details on the assessment of the minimum level that can be accurately measured can be found in the docket memorandum entitled “Updated data and procedure for handling below detection level data in analyzing various pollutant emissions databases for MACT and RTR emissions limits.” We do not expect that the change from numeric emission limits to work practice standards will result in less public health protection because the levels of dioxin emitted from units in the source category are at or near current detection level capabilities, and we are not aware of any emissions controls that are demonstrated to reduce dioxin emissions from the low levels indicated by the available data for boilers and process heaters. B. Output-Based Standards 1. Revisions to Boiler Efficiency Analysis Petitioners requested that the EPA reassess the calculation of boiler efficiency, which is the key calculation in the development of output-based standards, because the EPA's calculations often resulted in efficiencies that were unrealistically high, often above 100 percent, which is a physical impossibility. The petitioners attributed this to the fact that the EPA had disregarded feedwater temperature (industry average being 280 degrees F). The inclusion of feedwater temperature provides the correct assessment of boiler efficiency because it accounts for the heat energy that is supplied by steam from the boiler to heat the feedwater. The steam used to heat the feedwater is supplied by the boiler and was reported by facilities as part of the boiler “steam output,” but was not accounted for in the final rule efficiency calculations. Thus, the EPA has modified the development of the revised output-based emission limits to include the heat (energy) associated with the feedwater. The revised boiler efficiencies of the best performing units for each subcategory were determined by the equation: Boiler Efficiency = (Steam output (Btu) − Feedwater Input (Btu))/(Fuel Input (Btu)) To calculate “feedwater input (Btu)”, we used the industry average temperature of 280 degrees F and determined a heat content value of 249.3 Btu/lb. Unit operators provided the “steam output (Btu)” for each best performing unit in response to the EPA's information gathering efforts. For all best performing units reporting this steam energy output data, we calculated boiler efficiencies, as well as corresponding input-to-output conversion factors (CF). We averaged CF from the best performing units that have realistic boiler efficiencies averaged and assigned a subcategory-specific conversion factor. Finally, we applied the revised average CF to the proposed input-based emission limits to develop the revised alternate output-based limits. The resultant proposed output-based limits provide a compliance option that achieves emission reductions equivalent to those achieved by the input-based limits and encourage energy efficiency. 2. Other Changes to Output-Based Provisions a. Accommodating Emissions Averaging Provisions. In order to allow for emissions averaging for units that elect to comply with the output-based emission limits, the EPA is proposing to add additional equations to the rule to allow for emissions averaging as requested by petitioners. Averaging of output based limits was not included in the final rule due to time constraints, but there is no technical reason why averaging of output-based limits is inappropriate. The output-based limits are equivalent to the input-based limits and promote energy efficiency, and, therefore, EPA is proposing to allow averaging for units that elect to comply with the output-based standards. b. Output-Based Standards for Units that Generate Electricity. Petitioners pointed out that the final output-based standards were not designed to consider efficiency improvements from units that generate electricity only. In response to this concern, the EPA is proposing to add language to the definition of “Steam output” that addresses boilers that only produce electricity. The language provides fuel-specific conversion factors for electricity generating units that result in output-based standards in units of pounds per megawatt-hour. c. Clarification that output-based standards are alternative standards. Petitioners requested that the EPA clarify in the tables that the output-based standards are alternative standards to the input-based standards. The EPA is proposing regulatory text to make this clarification. d. Legal Authority for Emission Credits. One petitioner questioned the legal authority of the emission credit system and stated that it should be removed from the final rule. However, the petitioner provided no support for its position, and the EPA continues to believe that the emission credit system is consistent with the CAA as promulgated. Therefore, no changes are being proposed. However, we are specifically requesting comment on: (1) The overall concept of the emission credit provision, (2) how to administer it consistently across the country, and (3) available guidelines to inform the delegated authority's decision to approve the implementation plan. C. Subcategories In the final rule, the EPA added subcategories for hybrid suspension/grate biomass units, limited-use units, solid fuel units, and non-continental liquid units. The EPA also added a fuel specification to the final rule that would allow units combusting gases not defined as “Gas 1” gases to qualify as Gas 1 units by demonstrating that the fuels combusted meet a fuel specification. Petitioners requested that EPA allow comment on these subcategory changes and the fuel specification, and EPA is now soliciting comments on these portions of the final rule, including the changes and particular issues described in sections [1 through 7] below. Petitioners also requested additional subcategories, clarification of several subcategory definitions, and changes to some of the subcategory definitions. 1. Solid Fuel. The EPA added a solid fuel subcategory to the final rule that replaced previously proposed separate subcategories for units designed to burn solid fossil-based fuels and units designed to burn solid bio-based fuels. The solid fuel subcategory applied to pollutants identified in the final rule as fuel-based pollutants (PM, HCl, and Hg). Standards for combustion-based pollutants (CO and dioxin/furan), however, were based on specific subcategories for the various types of combustion units, including the specific fuel types the units were designed to combust. The rationale for the change is presented in the preamble to the final rule and the EPA is, in this action, soliciting comments on the solid fuel subcategory. One significant change is also being proposed related to the solid fuel subcategory. Several petitioners provided information to support the position that PM should be considered a combustion-based pollutant rather than a fuel-based pollutant. After assessing the points raised by the petitioners, the EPA determined that PM emissions are influenced both by fuel type and unit design. Therefore, it is appropriate to treat PM as a combustion-based pollutant. Differences in PM particle size, applicability of air-pollution controls to units combusting various fuels, and the lack of demonstration of certain control technologies on certain designs of boilers ( e.g., fabric filters are not used on any hybrid suspension grate boilers) suggest that PM is more appropriately classified as a combustion-based pollutant. Therefore, the EPA is now proposing separate PM limits for each “combustion-based” subcategory. Emission limits for HCl and Hg were developed for the same subcategories as presented in the March 21, 2011, final rule; the only changes associated with the HCl and Hg emission limits are due to new data, corrections to old data, and inventory changes. 2. Units Designed to Combust Liquid Fuels. The EPA finalized a single subcategory covering liquid fuel-fired units (with limited exceptions such as non-continental liquid units and limited-used units). Petitioners requested that the EPA reconsider the liquid unit subcategories and include separate subcategories for units designed to combust light liquids and units designed to combust heavy liquids. Petitioners cited issues related to achievability of standards and the types of controls that are used on liquid units but did not cite design differences that could be used to justify a subcategory. However, we identified several design differences, including the need for steam atomization or high-pressure atomization of heavy liquids, the need for heated storage vessels for heavy liquids in some climates, and the lack of a demonstration that the new source PM limit based on combustion of light liquid fuels had been achieved by any unit combusting heavy liquid fuels. Therefore, the EPA is proposing separate subcategories for heavy liquid-fired and light liquid-fired units for PM and CO, pollutants that are dependent on combustor design. Units designed to combust light and heavy liquids will continue to be grouped together in a liquid fuel subcategory for Hg and HCl, which are the fuel-based pollutants. Light liquids include distillate oil, biodiesel and vegetable oil. Heavy liquids include all other liquid fuels that are combusted in boilers, including byproduct liquid fuels generated at industrial facilities and residual oil. Units that combust any liquid fuels (and less than 10 percent coal/solid fossil fuel and less than 10 percent biomass/bio-based solid fuel) where at least 10 percent of the heat input from liquid fuels on an annual heat input basis comes from heavy liquids would be considered heavy liquid units. Units that combust any liquid fuels (and less than 10 percent coal/solid fossil fuel and less than 10 percent biomass/bio-based solid fuel) that are not part of the unit designed to burn heavy liquid subcategory would be considered light liquid units. 3. Non-Continental Liquid Units. The EPA finalized a subcategory for non-continental liquid units. Stakeholders did not have the opportunity to comment on this subcategory. Therefore, the EPA is now soliciting comments on the non-continental liquid unit subcategory. The preamble to the final rule presents the rationale for the establishment of the subcategory. See 76 FR 15635. The EPA also is proposing to revise several of the emission limits for non-continental liquid units due to the receipt of new emissions data for PM and CO from these units and the development of performance estimates based on the combustion of No. 6 fuel oil (rather than all types of liquid fuels). The rationale for estimating the performance of these units based on data from No. 6 oil units is presented below. Petitioners pointed out that non-continental units do not combust distillate oil because of availability issues. While non-continental liquid units typically combust refinery gas, they combust residual oil when process requirements necessitate supplementing the available refinery gas. The petitioners requested that, in the absence of data from non-continental units, emission limits for non-continental units be based on data from liquid units that combust residual oil. The EPA agrees that it would be appropriate to make this change for the combustion-based pollutants due to the design of these units and the unique constraints faced by these units. We now have data for both CO and PM from non-continental units, and there are no longer data gaps for these pollutants. We are thus able to establish numeric emission limits using data from within the subcategory. For fuel-based pollutants, Hg and HCl, the EPA determined that, based on the very limited data sets and the overlap of data for units designed to combust various liquid fuels, it is more appropriate to consider all liquid fuel-fired units together for the development of MACT emission limits. This is consistent with the treatment of Hg and HCl for solid fuel units. 4. Liquid Units in Alaska. A petitioner requested that liquid units in Alaska be included in the non-continental liquid unit subcategory or in a separate, newly created subcategory for units in Alaska. The petitioner stated that units in Alaska face the same difficulties with respect to the available supply of natural gas or refinery gas as the non-continental units. The commenter did not provide specific design differences from other types of liquid units. In addition, no test data are available for liquid-fired units in Alaska. Finally, while units in Alaska may face some unique constraints, the design of such units is different from the non-continental units because the units are designed to combust different fuels ( i.e. non-continental units combust No. 6 fuel oil, which was not reported as a fuel for any unit in Alaska in the responses to the EPA's information collection request). For these reasons, the EPA is not proposing a subcategory for liquid units in Alaska and is not including these units in the non-continental subcategory. The EPA is, however, soliciting comment and supporting rationale on whether a subcategory for liquid units in Alaska is appropriate, and is requesting stack test data that could be used to establish MACT floors if such a subcategory is justified. 5. Biomass. Petitioners requested additional biomass subcategories and clarifications to the final subcategories. Suggestions included separate subcategories (for all pollutants) for boilers that are designed to combust kiln-dried wood and for hybrid suspension grate boilers designed to combust bagasse, clarification of which subcategory covers pile burners, and separation of the dutch oven and suspension burner subcategories. In addition to soliciting comment on the proposed changes described below, the EPA is requesting comment on whether additional subcategories are appropriate, as well as data and rationale in support of any additional subcategories. a. Boilers Designed to Combust Kiln-Dried Wood. With respect to a separate subcategory for boilers designed to combust kiln-dried wood, the EPA is proposing a separate subcategory for these units based on the design of the boilers and the unique nature of the facilities that combust this material. These facilities are carefully integrated to utilize their available resources on-site, and the boilers are designed and sized to efficiently combust biomass that has already undergone a drying process that enhances the fuel quality. Care is taken within the facility to maintain the fuel moisture content at levels far lower than virgin biomass materials, typically less than 2 percent moisture. The EPA is proposing emission limits for PM and CO for this subcategory of units that we are calling biomass dry stokers. For HCl and Hg, the final rule's approach of regulating these pollutants under the “solid fuel subcategory” for all solid fuel units has not changed. b. Hybrid Suspension Grate Boilers Designed to Combust Bagasse. In the final rule, the EPA added a subcategory for hybrid suspension/grate boilers, which included boilers that are designed to combust very wet biomass fuels such as bagasse. The rationale for the establishment of the subcategory is presented in the preamble to the final rule. See 76 FR 15634-15635. Petitioners pointed out that in addition to their unique designs that provide fuel drying within the combustor, these units are highly integrated into the sugar production process and primarily combust specific materials that are generated on-site. Petitioners emphasized that the particle size profile from these units differs significantly from units designed to combust other types of fuels. As discussed in section V.C.1 of this preamble, the EPA is now considering PM to be a “combustion based” pollutant. Accordingly, the EPA is proposing emission limits for PM (along with an alternate TSM standard) and CO for these types of units. For HCl and Hg, the final rule's approach of regulating these pollutants under the “solid fuel subcategory” for all solid fuel units has not changed. c. Clarification of Subcategories for Pile Burners, Dutch Ovens, and Suspension Boilers. The final rule did not address pile burners, and it established a single subcategory that covered dutch ovens and suspension boilers. Petitioners pointed out that dutch ovens and suspension boilers are inherently different types of boilers and requested EPA to create separate subcategories for those types of units. Petitioners also pointed out that pile burners are very similar to dutch ovens, and, as such, should be included in the dutch oven subcategory. The EPA evaluated these clarification requests and determined that the petitioners' points regarding the design and other differences between dutch ovens and suspension boilers are valid. The EPA agrees that dutch ovens and pile burners should be included in the same subcategory and suspension burners should be a separate subcategory. Therefore, the EPA is proposing separate emission limits for the combustion-based pollutants for these subcategories. All of these types of units will remain in the solid fuel subcategory for the fuel-based pollutants. 6. Gaseous Fuel Specification. Multiple petitioners requested reconsideration of the fuel specification that the EPA finalized but did not propose. Petitioners correctly pointed out that the levels of the fuel specification were based only on natural gas and suggested that it would be appropriate to base the fuel specification on levels of contaminants in either natural gas or refinery gas. Petitioners further pointed out that a fuel specification for hydrogen sulfide (H 2 S) is not directly related to potential HAP emissions from boilers and process heaters and the H 2 S fuel specification should be eliminated from the rule. The EPA has reexamined the fuel specification and agrees that the key contaminant for demonstration of comparability from a HAP perspective is Hg and that the H 2 S fuel specification that was finalized does not provide a direct indication of potential HAP from combustion of gaseous fuel. Accordingly, the EPA is proposing a fuel specification based only on the Hg level in the gaseous fuel, and that level is the same level that the EPA included in the March 2011 final rule. The rationale for the Hg fuel specification is included in the preamble to the final rule. See 76 FR 15639. One petitioner stated that the inclusion of a fuel specification demonstrates that emissions can be measured from the units that combust the gaseous fuels, and therefore, the units cannot be regulated by a work practice standard. Regarding this point, the EPA recognizes that the contaminants in the fuel may be able to be measured, but the resulting emissions from combustion of the fuel are another matter entirely. For instance, a unit that combusts a fuel that meets the fuel specification for Hg will have demonstrated that its fuel contains an amount of Hg that is comparable to that found in natural gas. The emissions data for natural gas-fired units show the overwhelming majority of emissions to be below the level that can be accurately quantified by the available test methods. Therefore, the same is expected of units combusting gases with similar contaminant levels to natural gas. Thus, a work practice standard is the appropriate standard for these units. The EPA also is requesting comment on whether additional parameters should be included in the fuel specification. 7. Work Practices for Limited-Use Units. The EPA added a subcategory for limited-use units in the final rule, and petitioners requested an opportunity to comment on the creation of the subcategory and the definition of the subcategory. Specifically, multiple petitioners requested that rather than defining the subcategory to include units that operate less than 10 percent of the hours in a year, the EPA define the subcategory to include units that operate with a capacity factor of 10 percent or less. The petitioners believe that such a change would provide more flexibility, but petitioners did not provide support that such a subcategory would qualify for work practice standards under section 112 the CAA. Therefore, the EPA is not proposing a change to the final approach but is requesting comment on how a subcategory defined with a 10 percent capacity factor would qualify for work practice standards in lieu of emission limits. The EPA also is requesting comment on the limited-use subcategory as finalized, and the rationale for the creation of that subcategory can be found in the preamble to the final rule. See 76 FR 15634. D. Monitoring 1. Oxygen monitoring. Petitioners requested reconsideration of the requirement for installation of oxygen monitoring systems on the outlet of the boiler combustion chamber for numerous technical reasons. Several parties expressed concern regarding this location as it is known to be highly stratified, making it very difficult to find a representative location and certify the instrumentation. In reviewing alternatives to this requirement we find that rather than requiring monitoring of oxygen levels in the stack that follows a combustion unit, a better way to ensure good combustion is by requiring the installation, calibration, monitoring and use of oxygen trim systems to optimize air to fuel ratio and combustion efficiency. We agree with petitioners that use of the data from such devices is not only an appropriate control for efficient combustion and a less burdensome alternative to monitoring stack oxygen concentration but also is a better system for many types of units that experience significant load swings and operate with high levels of excess air. Many units are already fitted with these controls, and this proposed change will reduce the monitoring burden for affected units. These systems will provide adequate combustion control to maintain compliance with the CO emission levels demonstrated during the performance test. We seek comment on the appropriateness of using these controls operated as, and for the purposes, described. 2. PM CEMS. Petitioners requested reconsideration of the use of PM CEMS as compliance monitors for coal, biomass and residual oil units with heat input capacity greater than 250 MMBtu/hr. Petitioners emphasized that PM CEMS are not demonstrated for biomass units and requested EPA to remove the requirement because of technical issues related to PM particle size and the inability of PM CEMS effectively measure PM from biomass units. Petitioners also stated that PM CEMS are not demonstrated at the low levels that are required by the rule. The EPA agrees that PM CEMS are not demonstrated for biomass units and that significant technical concerns exist regarding the technology's ability to monitor emissions from biomass units. The technical concerns include the fact that PM CEMS are calibrated and certified to measure emissions from a single fuel type. A change in fuel would require a change in the calibration curve of the PM CEMS instrument. The unpredictable variety of biomass fuel constituents as well as biomass fuel moisture content make relying on a single calibration point problematic in terms of compliance assessment when these fuel components change. Furthermore, it is impracticable to replicate, during performance testing, all of the varying fuel conditions necessary for calibrating the monitor. For all of these reasons, it is impractical to appropriately apply PM CEMS to provide the accuracy necessary for compliance assessment. Accordingly, we are proposing to remove the PM CEMS requirement for biomass units. Relative to application for other boiler units, several parties expressed concern over the state of readiness of current PM CEMS technology, certification methodology and the technical effort and cost required for the recertification necessary to handle changing fuel and control operating conditions. In our reevaluation of this technology we find that PM monitoring technology would best be employed as parametric monitors (PM CPMS) and used to determine compliance with operating limits rather than emissions limits. This approach reduces the burden of certification of the monitor, which can be a substantial annual cost, and maintains our goals of seeking continuous data monitoring of the source particulate mass emission rate as a 30-day rolling average. We seek comment on the use of these monitors as described in the rule. 3. CEMS Alternative for Hg. Petitioners requested reconsideration of the absence of an option to use Hg CEMS for compliance demonstration and monitoring for units subject to Hg limits whose operators do not want to rely on periodic testing, fuel sampling analysis, and parameter monitoring. We have included options in the proposed rule for the use of Hg CEMS. We seek comment on the use of these monitors as described in the rule. 4. Use of sulfur dioxide ( SO 2 ) CEMS for demonstrating continuous compliance with HCl emission limits. A petitioner requested that the EPA consider adding a provision to the rule to allow for the use of SO 2 CEMS for demonstration of continuous compliance with the HCl emission limits for sources that are equipped with acid gas controls. While the EPA does not have enough information to propose specific requirements, we believe that a reasonable approach would be to allow for the use of SO 2 CEMS provided that the source demonstrates a correlation between SO 2 control and control of other acid gases emitted from each specific unit that chooses to use SO 2 CEMS. Such a relationship is expected because the available add-on controls for acid gases would provide better control efficiencies for the acid gas HAP than for SO 2, and, therefore, demonstration of SO 2 control using CEMS would provide assurance that the acid gas HAP are being controlled. Therefore, the EPA is soliciting comment on the use of SO 2 CEMS for demonstrating continuous compliance with the HCl emission limits with the condition noted above. 5. Minimum Data Availability Provisions. Petitioners noted that the requirement to operate any CMS and collect data at all times is unrealistic and that the agency should include a reasonable minimum data availability limitation allowing for CMS downtime. We have not included any specific minimum data availability requirement for CEMS or other monitoring in the final rule. We disagree with petitioners that we are establishing unreasonable monitoring operating requirements with this rule. Instead, we believe that we are reiterating the source owner's responsibility to operate and maintain the CMS in accordance with existing rules. For example, section 63.8(c) already requires that the source operate the CMS consistent with good air pollution control practices and that the CMS be in continuous operation in accordance with a written quality control program. The final rule clarified that continuous operation does not include periods when the process is not operating and the requirements delineated in the rule otherwise mirror other existing requirements in the MACT general provisions. We do agree with petitioners that a CMS must undergo periodic system inspections, preventive maintenance, and parts replacements in order to continue good operation. It is clear that these events are among normal scheduled quality control events that would be included in the site-specific quality control program that is required under section 63.8(d)(2)(iii) to which the source owner is subject. We also agree that such periods are to be categorized as exceptions to CMS data collection that are already allowed in the rule. Given the existing regulatory requirements and the clarifications in this rule about how to apply those requirements, we believe the rule provides allowances sufficient for CMS operational flexibility and are therefore not proposing any revisions on this issue. 6. Averaging Times. The EPA has determined that a 30-day rolling average for parameter monitoring and demonstration of continuous compliance with operating limits is appropriate for this rule. This would be a change from the final rule, which generally included 12-hour block averages that corresponded to the expected length of the longest duration 3-run emission test that was required to demonstrate initial compliance with the emission limits. The operating limits established through performance testing in this rule represent short term process and control operating conditions representative of compliance. Concerns of variability outside the operators control such as fuel content, seasonal factors, load cycling, and infrequent hours of needed operation prompted us to look at longer averaging periods on which to base operating compliance determination. We are aware from studies of emissions over long averaging periods that long term ( e.g., 30-day) average emissions for a operating in compliance will have a variability of about half of that represented by the results of short term testing. Given that short term tests are representative of distinct points along a continuum of that inherent operational variability, we believe it appropriate to propose 30-day averages in order to provide a means for the source operator to account for that variability by applying a long term average for establishing compliance. We expect more problematic control system variability ( e.g., ESP transformer failure or scrubber venturi fan failure) to result in deviations from a 30-day average relative to compliance almost as much as for a shorter term average. E. Emission Limits 1. Additional Data Received. The EPA received additional data from stakeholders and incorporated all of the data into the MACT database. The new data include 36 Hg test runs, 168 p.m. test runs, 24 dioxin/furan test runs, 133 CO test runs, 63 HCl test runs, and 22 TSM test runs. In addition to the stack test data, the EPA received fuel analyses for 3 facilities and over 51,000 hours of CO CEMS data from 3 facilities. Finally, stakeholders submitted corrections to data and to descriptions of combustion units. We have incorporated these corrections into the project database. For details on the new data and data corrections, see the memorandum in the docket entitled “Revised Handling and Processing of Corrections and New Data in the EPA ICR Databases (October 2011).” 2. Quality Assurance Activities on Best Performers. The EPA requested copies of all of the emission test reports for the best performing units in each subcategory in order to perform additional quality assurance. These test reports document the test results for the summary test data that were submitted to the EPA as part of the EPA's Phase 1 information collection request. This review resulted in multiple changes to data and invalidation of some emission tests. Overall, this effort improved the quality of the data provided by industry. For details on the quality assurance effort, see the memorandum in the docket entitled “Data Quality Review of Best Performers for PM, Hg, HCl, CO, and Dioxin/Furan Emissions from ICI Boilers and Process Heaters at Major Sources of HAP (October 2011).” 3. Incorporation of Minimum Detection Levels and Measurement Imprecision. In developing the final rule, the EPA incorporated procedures to ensure that the available measurement methods would provide accurate emissions measurements at the levels set for the various standards. The preamble to the final rule described these procedures, but stakeholders did not have an opportunity to comment on them. The EPA has made minor adjustments to the methods used to account for measurement imprecision and presents the rationale in the following paragraphs. We are soliciting comment on the procedures described below. Test method measurement imprecision is a contributor to the variability of a set of emissions data. One element is associated with method detection capabilities, and a second is a function of the measurement value. Measurement imprecision is proportionally highest for values measured below or near a method's detection level; measurement imprecision proportionally decreases for values measured above the method detection level. The probability procedures applied in calculating the floor or an emission limit inherently and reasonably account for emissions data variability, including measurement imprecision, when the database includes multiple tests from multiple emissions units for which all data are measured significantly above the method detection level. This is less true when the database includes emissions occurring below method detection capabilities that are reported as the method detection level values. The EPA's guidance to data collection respondents for reporting pollutant emissions specified the criteria for determining test-specific method detection levels. Under those criteria, about a 1 percent probability of an error exists that a pollutant measured at the method detection level is present when in fact it is 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 is 50 percent or greater. 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. 2 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. One effect of reporting data in this manner is that the resulting database is somewhat 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 that is based on a truncated database or otherwise includes values measured near the method detection level may not adequately account for the effects of measurement imprecision on the data variability. 2 American Society of Mechanical Engineers, Reference Method Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack Emission Measurements, CRTD Vol. 60, February 2001. We applied the following procedures to account for the effect of measurement imprecision associated with a database that includes method detection level data. In response to the comments and internal concerns about the quality of measurements at very low emissions limits especially for new sources, we revised the procedure for identifying a representative detection level (RDL). The procedure for determining an RDL starts with identifying all of the available reported pollutant specific method detection levels for the best performing units regardless of any subcategory ( e.g., existing or new, fuel type, etc. ). From that combined pool of data, we calculate the arithmetic mean value. By limiting the data set to those tests used to establish the floor or emissions limit ( i.e., from the best performers), the result also represents the best performing testing companies and laboratories, and data from underperforming laboratories are effectively removed from the floor analysis. The outcome should minimize the effect of a test(s) with an inordinately high method detection level (because, for example, the sample volume was too small, the laboratory technique was insufficiently sensitive, or the procedure for determining the detection level was other than that specified). We then call the resulting mean of the method detection levels as the RDL as characteristic of accepted source emissions measurement performance. The second step in the process is to calculate three times the RDL to compare with the calculated floor or emissions limit. This step is similar to what have used before including for the Portland cement MACT determination. We use the multiplication factor of three to approximate a 99 percent upper confidence interval for a data set of seven or more values. For comparing to the floor, if three times the RDL were less than the calculated floor or emissions limit ( e.g., calculated from the upper prediction limit (UPL)), we would conclude that measurement variability was adequately addressed. The calculated floor or emissions limit would need no adjustment. If, on the other hand, the value equal to three times the RDL is greater than the UPL, we would conclude that the calculated floor or emissions limit does not account entirely for measurement variability. In this situation, we substituted the value equal to three times the RDL for the calculated floor or emissions limit. We determined the RDL for each pollutant using data from tests of all the best performers for all of the final regulatory subcategories ( i.e., pooled test data). We applied the same pollutant-specific RDL and emissions limit adjustment procedure to all subcategories for which we established emissions limits. We believe that emissions limits adjusted in this manner better ensure that measurement variability is adequately addressed relative to compliance determinations than did the procedure applied for calculations in the June 4, 2010, proposed rule that may have been based on data sets smaller than seven tests and as few as one test. We also believe that the emissions testing procedures and technologies available now and in the future will be adequate to provide the measurement certainty sufficient for sources to demonstrate compliance at the levels of the adjusted emissions limits. 4. CO CEMS-Based Alternative Emission Limits and Monitoring. As an alternative to CO stack testing and oxygen monitoring, we are proposing a compliance option that allows the use of CO CEMS. Some petitioners noted that some affected sources currently use CO CEMS and that installing additional monitoring equipment should not be required if a unit elects to comply using existing CO CEMS equipment. In addition, petitioners stated that due to the highly variable nature of CO emissions, an emission limit based on CO CEMS data from boilers over time would more adequately capture the true variability in CO emissions over various operating conditions. In response to these requests, the EPA has calculated a CO CEMS-based MACT floor for each subcategory for which data were available. Facilities would have the option to comply with the alternative CO CEMS-based limits through monitoring with CO CEMS. Through the Section 114 Information Collection Requests and additional voluntary data submittals, a limited amount of CEMS data was available to compute CO CEMS limits. Most sources that reported CEMS data had 30 days of data either reported as hourly or daily averages. Given this limited length of time, we selected a 10-day rolling averaging period in order to allow us to compute multiple data points from each source's dataset. If sources reported CEMS data on both an hourly and daily average basis, we first computed daily averages from the hourly data. Next, we combined the two datasets, sorted the data in sequential calendar data order and computed a series of 10-day rolling averages from each unit. CEMS data on a 10-day rolling average basis could be calculated for the following subcategories: fluidized bed units designed to burn coal/solid fossil fuel, pulverized coal boilers designed to burn coal/solid fossil fuel, stokers designed to burn coal/solid fossil fuel, dutch ovens/pile burners designed to burn biomass/bio-based solids, fluidized bed units designed to burn biomass/bio-based solids, hybrid suspension grate boiler designed to burn biomass/bio-based solids, stokers/sloped grate/others designed to burn wet biomass fuel, suspension burners designed to burn biomass/bio-based solids and units design to burn heavy liquids. CO CEMS data on a 10-day rolling average basis data were not available for the fuel cell units designed to burn biomass/bio-based solids, biomass dry stoker units, and units designed to burn gas 2 (other) gases. Alternate CO CEMS-based limits are not being proposed for these units, but if data are provided for those subcategories prior to March 1, 2012, those data will be considered for use in the final rule. A very limited amount of CEMS data were available from units designed to burn light liquid fuel and units designed to burn liquid fuel located in non-continental States and territories, but not enough data points were available to compute a 10-day rolling average. We do have data sufficient to develop CO CEMS-based limits on a 1-day block average basis for light liquid units and a 3-hour rolling average basis for non-continental liquid units, as discussed below. If sufficient additional data are provided by March 1, 2012, the EPA will consider adjusting the averaging times similar to the other emission limits. In most cases, only one or two units in each subcategory have CO CEMS data available. The memorandum “CO CEMS MACT Floor Analysis (October 2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source” provides a complete breakdown of the CO CEMS data that were available. The EPA is requesting the submittal of additional CO CEMS data to achieve a more robust dataset for the purposes of revising the CO CEMS MACT floor calculations. Please provide your dataset in an electronic spreadsheet or database format with the data reduced to hourly CO averages reported as ppmvd. You should include the oxygen associated with each measurement or report the data at a standardized oxygen concentration, preferably adjusted to 3 percent oxygen. The EPA is expecting to receive additional CEMS data before the final rule and to incorporate those data if received in time. The data will likely change the CO CEMS floors, and may also result in different averaging times, depending on the extent of the data. In order to identify the dataset that would be used to compute a CO CEMS MACT floor emission limit, the EPA first identified all of the units identified as best performers based on their reported stack test results that had 10-day rolling average CO CEMS data available. Refer to the memo “Revised MACT Floor Analysis (October 2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source,” for more information on how the best performing CO stack tests were identified for each subcategory. However, there was very little overlap in the number of best performing units that had both stack test and CO CEMS data available. After comparing the data, only three subcategories would have best performing units with both stack test and applicable CEMS data. Given these data gaps, we opted to rank CO CEMS data based on each units minimum 10-day rolling average CO CEMS value and then determining the best performers for each subcategory. For the three subcategories where we have CEMS data for units that are part of the stack test-based MACT floors, we included the CEMS data from those units in the CEMS-based floors because those units are demonstrated best performers for CO. We discuss two exceptions below, where the data did not allow the use of a 10-day averaging period. Within each subcategory, we ranked the minimum 10-day rolling averages from lowest to highest to determine the best performing 12 percent. Then, we identified any best performers based on the CO stack test data that provided CO CEMS data, and we included those data in the MACT floor pool. Next, we used all of the daily averages from the best performing units to compute a MACT floor based on a 99 percent UPL. For the units designed to burn light liquid fuels, the data were insufficient to calculate 10-day rolling averages. Based on the available data, the averaging basis selected was 1 day. For the units designed to burn liquid fuel in the non-continental liquid units subcategory, the data were insufficient to calculate 10-day rolling averages. Based on the available data, the averaging basis selected was 3 hours for non-continental liquid units. Only one of the non-continental boilers submitted CO CEMS data, with a total of 24 hourly averages. In this case, we used each of the hourly averages from this unit to compute a MACT floor based on a 99 percent UPL. The EPA is aware that the averaging time selection and whether rolling or block averaging is selected impacts the UPL calculation and ability to demonstrate compliance. We believe that the averaging times selected for this proposal are reasonable and note that, to some extent, they are dictated by the limited datasets. The EPA is requesting comment on the most appropriate averaging time ( e.g., hourly, daily) and length of rolling period ( e.g., 10-day, 30-day) to use when calculating the CO CEMS MACT floors and requests specific discussion and new data to support your comments. The length of the averaging time will be affected by the available data in each subcategory. The EPA also is requesting comment on the approach used to calculate the UPL-based MACT floors. Ranking the dataset according to the minimum 10-day rolling average does not necessarily correlate with the ranking used to identify the best performing 12 percent of units with CO stack test data used to calculate the stack test-based floors for CO. Separate sets of units in the stack test and CEMS data sets create the possibility of incongruent results between the two compliance options. To evaluate whether our selection of the units identified as best performers for CO CEMS data correlates to the units identified as best performers for stack test data, we compared the CEMS data and the computed stack test CO MACT floor for each subcategory. Each unit identified as a best performing unit in the CO CEMS analysis had at least one 3-hour CEMS average at or below the corresponding stack test CO MACT floor for the subcategory, which suggests that the units identified as best performers based on the CEMS data are comparable to the units identified as best performers based on the stack test data. The EPA specifically requests comment on the ranking methodology which should be used, with discussion on whether CO CEMS best performers should be selected from units also identified as best performers from their stack test data, or if a value other than the minimum 10-day rolling average should be used as the basis for ranking the data. Given the limited data available, the proposed new source CO CEMS floors are similar to existing source floors since the existing source CO CEMS UPL for each subcategory was determined using data from a single unit, with two exceptions. The fluidized bed units designed to burn biomass/bio-based solids and stokers/sloped grate/others designed to burn wet biomass fuel each have two units in the existing source floor calculations, whereas the new source floor would be based on the single best performer. In the case of wet biomass stoker/sloped grate/other, the computed new source floor would be higher than the existing source, so the value reverts to the existing source value. The 99 percent UPL calculations for CO CEMS used the following statistical formula: EP23DE11.028 Where: n = the number of daily averages (or hourly averages for non-continental units) m = the number of test runs in the compliance average In this case, m equals 10 given the 10-day rolling average compliance period for all subcategories except for non-continental liquid, where m equals 3 for the 3-hour averaging period. Similar to previous analysis of the distribution of the dataset for stack test data MACT floor calculations, the distribution of each CEMS dataset was classified as either a normal distribution or log-normal distribution. In the case of the CEMS datasets from each of the best performers, the datasets were each log-normally distributed. See the “CO CEMS MACT Floor Analysis (November 2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source” for further details about the calculations. For each subcategory the analysis showed that the datasets were lognormally distributed. Given the rolling-average compliance metric, many of the datasets also exhibit varying degrees of autocorrelation. Autocorrelation describes the correlation between values of the process at different points in time. Although the UPL calculation is affected by autocorrelation, no adjustments were made to incorporate autocorrelation in this dataset. Depending on the final compliance metric selected, EPA may adjust the dataset for the promulgated rule to better address autocorrelation. The EPA is requesting comment on incorporating autocorrelation into the analysis. The EPA considered, but is not proposing, an additional final step for establishing the CO CEMS-based floors. When we compared the performance of the units in the top half of the MACT floor pool (usually a single unit) to the UPL-based floor level, it was revealed that the calculated UPL-based floor level resulted in the best performing units in some subcategories not meeting the limit up to about 25 percent of the time. The following final step in the floor setting process for CEMS-based limits could be used to adjust the CO CEMS-based limits to reflect the level achieved at all times by the best performing sources ( i.e., the top half of the MACT floor units). In those instances where the best 6 percent of units did not meet the calculated limit at all times, the limit was adjusted to reflect the actual level that was demonstrated to be achieved at all times by those units (the highest 10-day, 1-day, or 3-hour average, as applicable, from the best 6 percent of units). The CO CEMS-based emission limits based on this approach are shown in Table 2 of this preamble. The EPA is requesting comment on whether this final step is appropriate for developing CO CEMS-based MACT floors for boilers and process heaters. Table 2—Alternative Approach CO CEMS-Based Emission Limits for Boilers and Process Heaters Subcategory Alternate CO CEMS limit, (ppm @3% oxygen) New and Existing—Coal Stoker 34 New and Existing—Coal Fluidized Bed 78 New and Existing—Coal-Burning Pulverized Coal 35 New and Existing—Biomass Wet Stoker/Sloped Grate/Other 920 New and Existing—Biomass Kiln-Dried Stoker/Sloped Grate/Other (1) New and Existing—Biomass Fluidized Bed 480 New and Existing—Biomass Suspension Burner 2,300 New and Existing—Biomass Dutch Ovens/Pile Burners 440 New and Existing—Biomass Fuel Cells (1) New and Existing—Biomass Hybrid Suspension Grate 1,400 New and Existing—Heavy Liquid 18 New and Existing—Light Liquid 60 New and Existing—non-Continental Liquid 120 New and Existing—Gas 2 (Other Process Gases) (1) 1 No data. F. MACT Floor Methodology 1. Standards for Dioxin/Furans. Petitioners requested that EPA revise the procedure used to calculate the final emission limits for dioxin/furans, with the primary issue being the low levels and how detection limits should be considered. The EPA re-assessed the lowest level that can be accurately measured for dioxin/furan emissions from boilers and process heaters. When we compared those levels to the levels of emissions from all of the units that had test data available, we found that for all subcategories of units, emissions were below the value that can be accurately measured. Details on the establishment of the level that can be accurately measured are provided in the docket memorandum entitled: Updated data and procedure for handling below detection level data in analyzing various pollutant emissions databases for MACT and RTR emissions limits. As discussed in section V.A.2 of this preamble, the EPA is now proposing to regulate dioxin/furan emissions with a work practice standard in lieu of numeric emission limits. 2. Filling Data Gaps for Non-Continental Liquid Units. The EPA included numeric emission limits for non-continental liquid units in the final rule. However, data were not available for all of the regulated pollutants, and EPA relied on the MACT floors for liquid units to establish some of the emission limits. Petitioners requested that in cases where data gaps exist, a more appropriate substitution would be to establish floors based on units that combust No. 6 fuel oil, which is the fuel that the non-continental units are designed to combust. While the EPA agrees that for estimating emission from these units, use of data from No. 6 oil-fired units may be appropriate even though some design differences have been identified (see FR 76 15635, March 21, 2011), we are proposing a different approach for setting emission limits for non-continental liquid units. Additional data were submitted to EPA for PM and CO from non-continental units, and the proposed PM and CO limits are based on these data from within the subcategory. For HCl and Hg, which are considered fuel-based pollutants that are not dependent on combustor design, the EPA is proposing to base limits for all liquid units on the entire data set from liquid-fired units. The currently available data and information do not indicate that Hg and HCl should be considered separately for liquid units designed to combust various types of liquids, and we therefore are proposing Hg and HCl emission limits that are based on the available data for all liquid units. The EPA requests comment on this approach, and to the extent that other approaches are suggested, the EPA requests data and rationale to support any suggested alternative approaches. 3. Selection of Confidence Level for CO. In the final rule, the EPA selected the use of a 99.9 percent confidence interval for calculating the MACT floor for CO emissions. A petitioner requested reconsideration of this selection given the fact that the EPA used a 99 percent confidence interval for all of the other emission limits in the final rule. The petitioner pointed out that if the data are highly variable, the 99 percent confidence interval should adequately reflect the variability of emissions as well as for the data sets for other pollutants. In the development of the final rule, the 99.9 percent confidence interval was selected in part because the standards covered periods of startup and shutdown, while the data did not reflect CO emissions during those periods. While the EPA finalized work practice standards for startup and shutdown periods, the selection of the confidence interval was not revisited due to time constraints. The EPA is now proposing to use a 99 percent confidence interval in order to maintain a consistent methodology with the development of the MACT floors for other pollutants, and because optional CO CEMS-based limits are being proposed that would allow sources additional flexibility in meeting the requirements of the rule. G. Tune-Up Work Practices 1. Requirements for Small and Limited-Use Units. Petitioners requested that the EPA reconsider the tune-up work practices for a subset of very small units. Specifically, petitioners requested that small natural gas- and light oil-fired units (petitioners defined “small” at various levels between 2 MMBtu/hr and 10 MMBtu/hr) be exempted from the rule. While the EPA disagrees that small units should be exempt from the rule, the EPA agrees that for the smallest natural gas-, refinery gas, other clean gas (that meets the fuel specification) and light liquid-fired units, decreased tune-up frequency is appropriate. The large number of small units that can be located at an individual facility, particularly an institution, provides logistical issues with completion of tune-ups on an annual basis. For instance, one institution has over 700 identical small natural gas-fired units that would, under the final rule, each be subject to a biennial tune-up requirement. We are proposing to change that requirement for natural gas-, refinery gas, other clean gas (that meets the fuel specification) and light liquid-fired units equal to or less than 5 MMBtu/hr to a tune-up once every 5 years, with the initial tune-up required by the compliance date and subsequent tune-ups being required at intervals no greater than 5 years from the previous tune-up. 2. Clarifications of Certain Tune-up Provisions. Petitioners requested several changes to the tune-up requirements and timing of completing the various aspects of tune-ups. The issues and the EPA's proposed responses, are presented in the following paragraphs. First, petitioners questioned the requirement that burner inspections (part of the tune-up) must be completed at least once every 36 months, even if this requirement causes a unit to be shut down that otherwise would not have been. The EPA agrees that the burner inspection should not cause units to shut down and is proposing to remove the “every 36 months” requirement. Instead, we are proposing that burner inspections that cannot be completed during a tune-up can be delayed until the next scheduled shutdown. Second, petitioners requested that CO adjustments that are required as part of a tune-up be allowed to be completed within 30 days of the tune-up in order to allow for multiple adjustments and optimization of CO emissions. The EPA agrees that this is a reasonable change and is proposing to allow 30 days from the date the tune-up is completed. Third, the EPA included a burner inspection requirement that is difficult or impossible for certain units to meet. The EPA is proposing to clarify this provision so as not to require a physical inspection that cannot reasonably be completed. 3. Conducting Initial Tune-ups at New Sources. Petitioners requested that the EPA clarify the timing of tune-ups with respect to the compliance dates for existing and new sources. For new units, the EPA recognizes that, as petitioners pointed out, units are generally tuned as part of installation, but a learning curve exists for how to most efficiently operate new units. Accordingly, the EPA is proposing that the initial tune-up after startup must be completed within one year of startup. H. Energy Assessment 1. Scope. Petitioners requested that the EPA clarify the scope of the energy assessment. Specifically, petitioners requested that the scope be clearly limited to only those energy use systems that are located on-site and associated with the affected boilers and process heaters. The final definition for “Energy use system” was intended only to list examples of potential systems that may use the energy generated by affected boilers and process heaters. We did not intend that the energy assessment would include energy use systems using electricity purchased from an off-site source. We also did not intend that the energy assessment include energy use systems located off-site. We are proposing to revise the definition of “Energy assessment” to clarify our intent. 2. Compliance Date. Petitioners requested that the EPA clarify the due date of the energy assessment. All emission standards must be met by the compliance da [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2011-31667. Public record. Not legal advice.