*** E.O . 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** EO12866 NESHAP Major Sources
- Industrial Commercial Institutional Boiler and Process Heaters RIN 2060
-AR1 3 Proposed Rule

– Reconside ration 2011101 4 6560
- 50
- P **ENVIRONMENTAL PROTECTION AGENCY**

**40 CFR Part 63**  **[ EPA** **- HQ** **- OAR** **- 2002**  **- 0058**  **; FRL** **- ]** 

**RIN 2060**  **- A** 

**R13 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; notice of reconsideration of final rule . **SUMMARY :**  On March 21, 2011 , the EPA promulgated national emission standards for the control of hazardous air pollutants f rom 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 to reconsider certain provisions of the final rule. The EPA subsequently issued a notice on May 18, 2011 , to stay the effective date s of the final rule until judicial review has been completed, or the agency finalizes its reconsideration of the standard. In the action to stay the effective dates of the rule, the EPA also requested the public to submit data and information to support the reconsideration. Following these actions, the Administrator received several petition s for reconsideration . In*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 2 of 147 response to the March 21, 2011 notice of reconsideration and the petition s submitted , EPA is reconsidering and requesting comment
on several provisions of the final rule . Additionally , 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 **[INSERT DATE 45**  **DAYS FROM DATE OF**  **PUBLICATION]** . 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

– 7 689 or at clemons.teresa@epa.gov by **[INSERT DATE 10 DAYS FROM DATE OF PUBLICATION]** . If no one requests to speak at the public hearing by **[INSERT DATE 10 DAYS FROM DATE OF PUBLICATION]**  **,** 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- 200 2
- 0 058 , by one of the following methods:

• www.regulations.gov : Follow the instructions for submitting comments.

• Email : Comments may be sent by email to a - and- r -*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 3 of 147 Docket@ epa.gov , Attention Docket ID No. EPA
- HQ - OAR200 2
- 0 058 .

• Fax : Fax your comments to: (202) 566
- 9744, Attention Docket ID No. EPA- HQ - OAR- 2002
- 0058 .

• Mail : S end 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 c ourier, deliver comments to : EPA Docket Center (2822T) , EPA West, Room 3334 , 1301 Constitution Ave., NW, Washington, DC 20 460 . 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 - OAR200 2
- 0 058 . EPA’s policy is that all comments received will be*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 4 of 147 included in the public docket without change and may be made available online at www.regulations.gov , including any personal information provided, unless the comment includes information claimed to be confidential business i nformation (CBI) or other information whose disclosure is restricted by statute . Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or email . The www.regulations.gov website is an “anonymous access” system, which means 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 EPA without going through 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 EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, 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 o f any defects or viruses . For additional information about EPA’s*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 5 of 147 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 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 www.regulations.gov or in hard copy at the EPA Docket Center , EPA West Building, Room 3334 , 1301 Constituti on 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
- 5 450; E
-mail address: shrager.brian@epa.gov . **SUPPLEMENTARY INFORMATION:***** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 6 of 147 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 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 VI . Technical Corrections and Clarifications VI I . 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?*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 7 of 147 G. What are the secondary air impacts? VI I I . Relationship of this Proposed Action to Section 112(c)(6) of the C lean 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 8 of 147 325 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 permit ting authority*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 9 of 147 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 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- 200 2
- 0 058 . 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 EPA, mar k 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 t o 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 10 of 147 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- 200 2
- 0 058 . 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. **I I**  **. Background Information**  On March 2 1 , 20 1 1 , 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 initiated a reconsideration of several provisions of the final rule in a separate notice. This*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 11 of 147 reconsideration notice ident i fied 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 reconsideration notice also identified several issues of central relevance to the rulemaking where reconsideration wa s appropriate under CAA section 307(d), including:

 Revisions to the proposed monitoring requirements for carbon monoxide for major sour ce 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, EPA issued a notice to stay the effective dates of this rule. This notice also requested that the public*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 12 of 147 submit additional data and information to EPA by July 15, 2011 for review and consideration in the reconsideration proceedings. Following promulgation of the final rule , EPA received petition s for reconsideration from the following organizations (“Petitioners”) : Alliance for Industrial Efficiency (AIE), US Clean Heat Power Association (USCHPA), Alyeska Pipeline, American Chemistry Counci l (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 Manufacture rs Association, State of Washington Department of Ecology, The Business Council for Sustainable Energy (BCSE), Utility Air Regulatory Group (UARG), United States Sugar Corporation (US Sugar), Waste Management Inc. (WM), and Wisconsin Electric Power*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 13 of 147 Company . Cop ies of the s e petition s are provided in the docket ( see Docket ID No. EPA- HQ - OAR- 200 2
- 0 058 ) . Petitioners , pursuant to CAA section 307(d)(7)(B), requested that 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. **III. Summary of This Proposed Rule** This section summarizes the requirements of this action. Section IV below provides a summary of the significant changes to this proposed rule. A. What is the source category regulated by this proposed rule? This proposed rule regulates i ndustrial, 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?*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 14 of 147 This proposed rule affects industrial , commercial, and ins titutional boilers and process heaters. A process heater is defined as a unit in wh ich 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 recove ring 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 15 of 147 proposed for new and existing sources in each of 14 subcategories , which are shown in Table 1 of this preamble. Hydrogen chloride and Hg are “fuel -based pollutants” that direct ly 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 l iquid fuel ( except as noted in the rule ) and less than 10 percent solid fuel and your faci lity 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 the preamble and in this proposed rule) , and your new or existing unit combusts liquid fuel ( except as noted in the rule ) and less than 10 percent solid fuel, your unit is subject to the non
- cont inental 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,*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 16 of 147 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 emiss ion 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

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).*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 17 of 147 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 le ss 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 bioma ss, 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 emiss ion 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. 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 )*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 18 of 147 Subcategory Particulat

e Matter (PM) (or total selected metals) (lb per MMBtu of heat input) a Hydroge

n Chlorid e (HCl) (lb per MMBtu of heat input) Mercury

(Hg) (lb per MMBtu of heat input) Carbon

Monoxide (CO) (ppm @3% oxygen) a Alterna

te CO CEMS limit, (ppm @3% oxygen) b
Existing

– Solid fuel NA 0.026 5.2 E - 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

– B iomass Wet Stoker/ Slop ed Grate/Other 0.029

(5.7E - 05) NA NA 730 450

Existing

– B iomass Kiln
- Dried Stoker/Slop ed Grate/Other 0.32

(0.004) NA NA 250 NA

Existing
- Biomass Fluidized Bed 0.11

(0.0012) NA NA 370 180

Existing

– 0.051 NA NA 58 1400*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 19 of 147 Biomass Suspension Burner (0.0011)
Existing

– Biomass Dutch Ovens/Pile Burners 0.0 3 6

(2.4E
- 04) NA NA 8 10 440

Existing

– Biomass Fuel Cells 0.0 33

(4.9E
- 05) NA NA 15 00 NA
Existing

– Biomass Hybrid Suspension Grate 0.44

(4.9E
- 04) NA NA 3900 730

Existing

– Liquid NA 0.0012 2.6E
- 05 NA NA Existing

– Heavy Liquid 0.062 c NA NA 10 18
Existing

– Light Liquid 0.0034 c NA NA 7 NA
Existing

– non Continental L iquid 0.008 c NA NA 18 91 d

Existing

– Gas 2 (Other Process Gases) 0.0067

(2.4E
- 04) 0.0017 7.9E
- 06 4 NA

New
– Solid Fuel NA 0.026 8.6E - 07 NA NA

New
–Coal Stoker 0.028

(2.2E
- 05) NA NA 16 34
New - Coal 0.0011 NA NA 17 59*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 20 of 147 Fluidized Bed (1.7E
- 05) New
– Coal Burning Pulverized Coal 0.0013

(2.8E
- 05) NA NA 9 28

New
– B iomass Wet Stoker/Slop ed Grate/Other 0.0048

(2.6E
- 05) NA NA 430 460

New
– B iomass Kiln
- Dr ied Stoker/Slop ed Grate/Other 0.32

(0.004) NA NA 250 NA

New - Biomass Fluidized Bed 0.0098

(4.2E
- 05) NA NA 230 26

New
– Biomass Suspension Burner 0.051

(0.0011) NA NA 58 1400

New
– Biomass Dutch Ovens/Pile Burners 0.0 3 6

(4.1E
- 05) NA NA 8 10 440

New
– Biomass Fuel Cells 0.011

(4.9E
- 05) NA NA 210 NA

New
– Biomass Hybrid Suspension Grate 0.026

(4.9E
- 04) NA NA 1500 730

New
– Liquid NA 0.0012 4 . 9E - 07 NA NA*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 21 of 147 New
– Heavy Liquid 0.013 c NA NA 10 18
New
– Light Liquid 0.0013 c NA NA 3 NA
New
– Non Continental L iquid 0.008 c NA NA 18 91 d

New
– Gas 2 (Other Process Gases) 0.0067

(2.4E
- 04) 0.0017 7.9E - 0 6 4 NA

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 3
-hour average based on continuous emission monitoring ( CEM ). The emission limits in Table 1 apply only to new and existing boilers and process heat ers 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), we are requiring a work practice s tandard 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 met al process furnaces subcategory , and new and existing limited
-use units . The work practice standard for these boilers and process heaters*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 22 of 147 requires the implementation of a tune
-up program . We also are proposing a work practice standard for dioxin/furan emis sions from all subcategories . Finally, the 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, o f 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? The startup, shutdown, and malfunction provisions in the rule have not changed. See 76 FR 15613 . 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 a ffected 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 23 of 147 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 test s to determine compliance with the CO emission limits using EPA Method 10 or install operate and maintain CO 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 per formance test. The lowest or highest hourly parameter average measured during the three test runs (depending*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 24 of 147 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 establ ished for the various types of the following units: (1) For boilers and process heaters with wet PM scrubbers, you must measure pressure drop and liquid flow rate of the scrubber during the performance test, and calculate the average hourly values during each test run. The lowest hourly average determined during the three test runs establishes your minimum site
- specific pressure drop and liquid flow rate operating levels. (2) If you are complying with an HCl emission limit using a wet acid gas scrubber, you must measure pH and liquid flow rate of the scrubber sorbent during the performance test, 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 25 of 147 (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, multip ly 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 C PMS) or continuous compliance with an opacity limit (i.e., 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 C PMS 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 26 of 147 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 C PMS or continuous compl iance 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 parame ters 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 .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 27 of 147 (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 i nlet 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 EPA, as appropriate, documentation*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 28 of 147 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 pe r million by volume dry (ppmvd), before and after any adjustments related to the tune -up are made, (6) Submit to the delegated authority or EPA an annual report containing the concentrations of CO in the effluent stream in ppmvd and oxygen in percent dry basis, 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 29 of 147 Further, all owners or operators of major source facilities having boilers and process heaters subject to this final ru le are required to submit to the delegated authority or EPA, as appropriate, documentation that an energy assessment was performed by a qualified energy assessor and 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 . I f 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 syst em alarm does not sound more than 5 percent of the operating time during any 6
-month period (unless a PM C PMS is used).*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 30 of 147 (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 spe cifications 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, mg/acm, or other instrument output) during all other operating hours where*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 31 of 147 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 (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 31 st , June 30 th , September 30 th , and December 31 st . 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 32 of 147 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 test s. 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 boil ers 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 limit s 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 33 of 147 content of the inlet fuel was maintained at or below your maximum fuel Hg content operati ng 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. I f 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 .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 34 of 147 (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 ce rtifications of compliance with rule requirements in the notification of compliance status report.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 35 of 147 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 CMS data are required. You are required to keep the following records: (1) All reports and noti fications 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 operati on 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 36 of 147 (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 o f Hg fuel input, as required in the rule, for each affected source with an applicable Hg emission limit. (8) A paragraph that discuss es calculations and supporting information of TSM fuel input, as required in the rule, for each affe cted 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 37 of 147 (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. (1 2 ) A copy of the results of all performance tests, fuel analysis, opacity observations, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 38 of 147 (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 EPA ? The EPA must have performance test data to conduct effective reviews of CAA sections 112 and 129 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 39 of 147 In this proposal , the EPA is presenting a step to improve the ease and effici ency 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 E PA’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 wou ld 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 40 of 147 http://www.epa.gov/ttn/chie f/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 dat a 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).*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 41 of 147 S tate, 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 i s 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 indus try 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, s tate, local, tribal agencies, and the EPA significant time, money, and effort while also improving the*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 42 of 147 quality of emission inventories and, as a result, air quality regulations . J . What are the p roposed compliance dates ? The EPA is proposing to reset the compliance date for existing sources to the date three 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 A** **re 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 i ssues raised by petitioners in their petition s for reconsideration . Section V of this preamble summarizes the se 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 .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 43 of 147 Finally, we are proposing technical correction s to certain applicability and compliance provision s in the final rule. We are seeking public comment only on the issues specifically identified in this notice . 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 response s to certain issues identified in the petition s for reconsideration and the changes to the rule that we are proposing . We solicit comment on all re sponses 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 total selected metals (TSM) , particularly for biomass units, as part of the reconsideration. After assessing the available data, EPA determined that inclusion of these limits is appropriate for some subcategories , and 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 is a more direct measurement of HAP than PM and is therefore*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 44 of 147 appropriate as a pollutant group for regulation with numeric emission limits . For this rule , TSM includes the following eight metals: a rsenic, beryllium, cadmium, chromium, l ead,
manganese, nickel, and selenium. The EPA selected these 8 metals, rather than all of the metals other than mercury, because more t est 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 response to the standards, and the controls that would be appropriate for the 8 metals would be equally effective in reducing emissions of the other 2 metals. Therefore, TSM can serve as a surrogate for all metallic HAP except for mercury, which this rule regulate s separately. For the light liquid, heavy liquid, and non
- continental liquid units subcategories, we considered but are not proposing alternative TSM emission limit s . Instead, we are proposing that these units meet the filterable PM emission limit s in all instances. The TSM alternative was not selected for this proposal because of the limited emission test data for TSM and the large variabil ity in the TSM data . Using the EPA’s MACT floor methodology, the alternative TSM limits resulted in MACT floo r value s which do not appear to represent the actual performance of the best performing unit s . The EPA*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 45 of 147 has sent follow-up inquiries to facilities to confirm these data , and is soliciting comment on whether alternative TSM limits are appropriate for the sub categories 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. 2. Work Practice for Dioxin/Furan Emissions . Multiple petitioners
re quested 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 level that can be accurately measured for each subcategory are as follows : coal stoker - 100 percent; coal fluidized bed
- 8 9 percent; pulverized*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 46 of 147 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. Accordingly, 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 low, and we are not awa re of emissions controls that are demonstrated to reduce dioxin emissions from the low levels*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 47 of 147 indicated by the available data for boilers and process heaters. B. Output -Based Standards 1. Revisions to Boiler Efficiency Analysis . Petitioners requested that EPA reassess the calculation of boiler efficiency , which is the key calculation in the development of output -based standards, because 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 EPA had disregarded feedwater temperature (industry average being 280 degrees F). The inclusion of feedwater temperature provides a more realistic assessment of boiler efficiencies. 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 48 of 1 47 to 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
- spe cific 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 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. b. Output -Based Standards for Units that Generate Electricity . Petitioners pointed out that the final output
-based standards were not designed to consider effic iency improvements from units that generate electricity only. In response to this concern, EPA is proposing to add language to the definition of*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 49 of 147 “Steam output” that addresses boilers that only produce electricity.
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 has made this clarification. d. Legal Authority for Emission Credits. One petit ioner 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 legal as promulgated. Therefore, no changes are being proposed . 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 spec ification. Petitioners requested that EPA allow comment on these subcategory changes and the fuel*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 50 of 147 specification , and EPA is now soliciting comments on the se 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 replace d 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) . S tandards 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 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 -*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 51 of 147 based pollutant . After assessing the points raised by the petitioners, the EPA dete rmined 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
pollut ion 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, correct ions 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 EPA reconsider the liquid unit subcategories and include separate subcategories for units designed to combust light liquids and*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 52 of 147 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 li quids , 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 li quid fuel subcategory for the fuel
based pollutants, Hg and HCl. 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 i ndustrial 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 he at*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 53 of 147 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 conside red light liquid units. 3. Non - Continental Liquid Unit s . The EPA finalized a subcategory for non - continental liquid units. Stakeholders did not have the opportunity to comment on this subcategory . Therefore, 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 - continent al liquid units typically combust refinery gas, they combust residual oil when process requirements*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 54 of 147 necessitate supplementing the available refinery gas. The petitioners requested that , in the absence of data from non
continental units, emission limits fo r non - continental units be based on data from liquid units that combust residual oil. The EPA agrees that it would be appropriate to make th is 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 unit s, 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 set s and the overlap of data for units de s igned to combust various liquid fuels, it is more appropriate to consider all liquid fuel
- fired units together for the development of MACT emission l imits. 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 55 of 147 supply of natural gas or refinery gas as the non
- continental units. The commenter did not provide specific design differen ces 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 subcatego ry 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 bo i lers that are designed to combust kiln
dried wood and for hybrid suspension grate boilers designed to*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 56 of 147 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 57 of 147 “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 p rocess 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 th is 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 58 of 147
c. Clarification of Subcategori es 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 o f 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 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, 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 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 59 of 147 the fuel specification on levels of contaminants in either natural gas or refinery gas. Petitioners further pointed out that a fuel specification for 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 mercury 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, EPA is proposing a fuel specification based only on the mercury level in the gaseous fuel, and that level is the same level that EPA included in the March 2011 final rule. The rationale for the mercury 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. Re garding 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 meet s*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 60 of 147 the fuel specification for mercury will have demonstrated that it contains an amount of mercury 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 61 of 147 the CAA. Therefore, 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 li eu 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 locati on as it i s 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
e fficiency . We agree with petitioners that use of the data from such devices is not only an appropriate control for*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 62 of 147 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 63 of 147 units. Accordingly, we are proposing to remove the PM CEMS requirement for biomass units. Relative to application for other boiler units, s everal 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 monitor ing technology would best be employed as parametric monitors ( PM CPMS ) and used to determine compliance wi th 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 64 of 147 options in the rule for the use of Hg CEMS . We seek comment on the use of these monitors as described in the rule . 4. Use of SO 2 CEMS for demonstrating continuous compliance with HCl emission limits. A petitioner requested that 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. 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 65 of 147 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
con sistent with good air pollution control practices and that the CMS be in continuous operation in accordance with a written quality control program. This rule clarifies 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 peti t ioners 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 subj ect. We also agree that such periods are to be categorized as*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 66 of 147 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. 6. Averaging Times. The EPA has determined the 30 day rolling average for parameter monitoring and compliance with operating limits is appropriate for this rule. 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 cycli ng, 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 [<<place holder to reference docket item of RTI Study MEMO here>> ] 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 provide a means for the source operator to*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 67 of 147 account for that variability by applying a long term average for establishing compliance. We expect more problematic control system variability (e.g. ESP t ransformer 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 E PA received additional data from stakeholders and incorporated all of the data into the MACT database. The new data include 36 mercury test runs, 168 PM test runs, 24 dioxin/furan test runs, 133 CO test runs, 63 HCl test runs, and 22 TSM test runs. In addi tion to the stack test data, EPA received fuel analyses for three facilities and over 51,000 hours of CO CEMS data from three 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 68 of 147 additional quality assurance. These test reports document the test results for the summary t est data that were submitted to EPA as part of EPA’s Phase 1 information collection request. Th is 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. Incorporat ion of Minimum Detection Levels and Measurement Imprecision . In develop ing 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 va rious standards. The preamble to the final rule described the se 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 present s the rati onale in the following paragraphs . We are soliciting comment on the procedures described below.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 69 of 147 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 decreas es 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. Th is 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 e rror exists that a pollutant measured at the method detection level is present when in fact it i s absent. Such a probability is also*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 70 of 147 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 measu red 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 71 of 147 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 method 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 represent s 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 72 of 147 representative detection level (RDL) as characteristic of accepted source emissions measurement performance. The second step in the process is to cal culate 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 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 ent irely for measurement variability. I n 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 73 of 147 procedure to all sub categories 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 calcu lations in the June 4, 2010, propos ed 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 us e of CO CEMS. Some petitioners noted that some affected sources currently use CO CEMS and that install ing 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 .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 74 of 147 In response to these requests, EPA has calculated a CO CEMS based MACT floor for each subcategory for which data were available . Fa cilities 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 limit s . Most sources that reported CEMS data had 30 days of data either reported as hourly or da ily 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 fi rst computed dail y 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
ca lculated for the following subcategories: f luidized 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 bu rn biomass/bio
-based solids, fluidized*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 75 of 147 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, s uspension 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, units designed to burn light liquids , 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 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 3
-hour average basis, as discussed below. If sufficient additional data are provided by March 1, 2012, the EPA will consider adjusting the averaging time 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 76 of 147 Floor Analysis ( October 2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Po llutants

– 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 parts per million by volume, dry basis. 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 performer s 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 77 of 147 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 select CO CEMS data by ranking each unit according to its minimum 10
- day rolling average CO CEMS value and then determin ing the best performers for each subcategory . We discuss one exception below. Within each subcategory, we ranked the minimum 10
- day rolling averages from lowest to highest to determine the best performing 12 percent . 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 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 fo r non continental liquid units. Only one of the non - continental boiler s submitted CO CEMS data, with a total of 24 hourly*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 78 of 147 average s . 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 impact s the UPL calculation and abi lity 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 dataset s . 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 floor s 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. 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 f loor s for CO . S eparate 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 correlate s to the units identified*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 79 of 147 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 suggest s that the CEMS floors are reasonable. 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 wa s determined using data from a single unit , with two exceptions . The fluidized bed units designed to burn biomass/bio
-based solids and s tokers/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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 80 of 147 be higher than the existing source , so the value reverts to the existing source value. The 99% UPL calculations for CO CEMS used the following statistical formula:

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 di stribution. 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 ( October 2011) for the Industrial, Commercial, and Institutional Boilers and Process Heater s*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 81 of 147 National Emission Standards for Hazardous Air Pollutants

– Major Source” for further details about the calculations. 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 sect ion 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 82 of 147 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 in formation do not indicate that Hg and HCl should be considered separately for liquid units designed to combust various types of liquids. The EPA requests comment on this approach, and to the extent that other approaches are*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 83 of 147 suggested, EPA requests data and rationale to support any suggested approaches. 3. Selection of Confidence Level for CO . In the final rule, 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 re flect 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 9 9 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 84 of 147 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 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 85 of 147 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 comple ting 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.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 86 of 147 Third, the EPA included a burner inspec tion 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 . Petitione rs 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, 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 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*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 87 of 147 the energy assessment include energy use systems located off
site. We have revised the definition of “Energy assessment” to clarify our intent. 2. Compliance Date . Petitioners requested that EPA clarify the due date of the energy assessment. All emission standards must be met by the compliance date, even if compliance demonstrations are sometimes allowed after the compliance date. In order to meet the requirements of the rule, energy assessments must, therefore, be completed by the compliance date for existing sources. 3. Maximum Duration Requirements . Petitioners requested that EPA reconsider the stated “maximum time” to conduct the energy assessment because the maximum times were not included in the proposal, and stakeholders had no opportunity to comment. The concern raised by petitioners is that, as the final definition of “Energy assessment” is worded, a deviation and a potential violation could occur if the energy assessment effort exceeds these time limits. Our intent for in cluding the “maximum time” in the final rule definition was to minimize the burden on the smaller fuel use facilities, many of which are likely small entities, by limiting the extent of the energy assessment. Our concern was that if there was no time limit , these small facilities would have no means to limit the time/effort of an*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 88 of 147 outside energy assessor that is contracted to perform the energy assessment. We have revised the definition of “Energy assessment” to change the maximum time from one day to 8 technical hours and from three days to 24 technical hours . This would allow sources to perform longer assessments at their discretion. I. Affirmative Defense Provisions During Malfunctions The EPA finalized affirmative defense provisions for malfunctions. As part of this reconsideration proposal, we are soliciting comments on the affirmative defense provisions that were included in the final rule. The rationale for the affirmative defense provisions is provided in the preamble to the final rule . See 76 FR 1564 2. J. Work Practices During Startup and Shutdown 1. Alternative Site
- Specific Work Practices . The EPA finalized a work practice standard for periods of startup and shutdown that requires facilities to minimize emissions consistent with manufacturers’ recommended procedures. Petitioners requested that the EPA clarify whether the requirement applies to the boiler or the control device manufacturer. The EPA is clarifying that all components of the affected source related to emissions are subject to this requirement. The EPA also is proposing to allow sources to develop their own procedures to*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 89 of 147 minimize emissions, in the absence of or in lieu of manufacturers’ recommendations. Such procedures must be approved by the implementing authority. 2. Operating Parameters and Opacity Limits . Petitioners requested that EPA clarify that the operating limits and opacity limits do not apply during periods of startup and shutdown. Having finalized work practice standards for these periods of time, EPA agrees that the requested clari fication is what was intended in the final rule. 3. Overall Approach to Startup and Shutdown. The EPA finalized a work practice standard for periods of startup and shutdown that requires facilities to minimize emissions consistent with manufacturer’s recommended procedures. The rationale for the work practice is presented in the preamble to the final rule . See 76 FR 15642 . We are soliciting comment on this approach because stakeholders did not have the opportunity to comment on this approach prior to i ssuance of the final rule. K. Applicability 1. Exemption for Units Serving as Control Devices. In the final rule, EPA exempted any boiler or process heater that is used as a control device to comply with another subpart of part 63 , provided that at least 50 percent of the heat input to the boiler is provided by the gas stream that is regulated under*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 90 of 147 another subpart. Petitioners requested that EPA extend the exemption to units that serve as control devices for EPA standards issued under parts 60 or 61 of the CAA. We recognize that part 61 is another part relevant to the NESHAP program and should be treated the same as the exemption provided for part 63. Although part 60 does not regulate HAP, EPA does want to continue to use combustion controls for organic pollutants that part 60 addresses, as it provides a pollution prevention strategy and reduces the need for facilities to install other combustion equipment to serve as dedicated control devices for NSPS and NESHAP regulated gas streams (e.g., thermal oxidizers and flares). In addition, many of the potential add
- on combustion technologies do not recover energy , and the resulting combustion using these technologies would emit approximately the same level of contaminants as a boiler without the added benefit of energy recovery . Therefore, the EPA is now proposing to exempt any boiler or process heater that is used as a control device to comply with standards issued under part 60, part 61, or part 63 of the CAA, provided that at least 50 percent of the heat input to the boiler is provided by a gas stream that is subject to standards under those parts.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 91 of 147 2. Waste Heat Boilers and Process Heaters. Petitioners requested that EPA clarify that waste heat process heaters, like waste heat boilers, are not subject to the standards. Petitioners are correct that EPA intended to exempt waste heat process heaters from the rule, and EPA is amending the definition of process heater to exclude waste heat process heaters. We also are clarifying that waste heat boilers and process heaters can include supplemental burners as long as those burners combust only Gas 1 fuels, up to 50 percent of their heat input. 3. Units Firing Comparable Fuels. Petitioners requested that E PA clarify whether boilers and process heaters burning comparable fuels, as defined under the Resource Conservation and Recovery Act (RCRA), are subject to the NESHAP for industrial, commercial, and institutional boilers and process heaters. Section 261.38 states that hazardous secondary materials (i.e., spent materials, sludges and byproducts) that have fuel value and whose hazardous constituent levels are comparable to those found in fuel oil that could be burned in their place are not solid wastes and hence not hazardous wastes under Subtitle C of RCRA. These materials are called comparable fuels. Since comparable fuels are not hazardous waste, boilers and process heaters burning comparable fuels are not subject to the NESHAP for hazardous waste combustor s (part 63, Subpart*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 92 of 147 EEE), which includes boilers and process heaters that burn RCRA hazardous waste. Therefore, boilers and process heaters burning comparable fuels are covered by the NESHAP for industrial, commercial, and institutional boilers and process heaters. L. Residential Unit Exemption. During the initial phases of implementation of the area source boiler rule, stakeholders requested clarification from EPA on the applicability of the area source rule to residential boilers, particularly those units at individual residences located at institutional facilities. The EPA’s intent was not to cover such units, and during reconsideration, the EPA is amending the area source rule accordingly. Similarly, the final major source rule could be interpreted to cover residential boilers at large institutions, which was not the intent of the rule . Accordingly, EPA is proposing to exempt residential boilers from the rule and is proposing the following definition of residential boiler to the major source rule: Residential boiler means a boiler, used in a dwelling containing four or fewer family units, to provide heat and/or hot water. This definition includes boilers used primarily to provide heat and/or hot water for a dwelling containing four or fewer families located at an institutional facility (e.g.,*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 93 of 147 university campus, military base, church grounds) or commercial/industrial facility (e.g., farm). M. Compliance 1. Extending Compliance Dates. On May 18, 2011, the EPA issued a stay of the effective date of the final rule . The EPA is proposing several revisions to the standards in today’s rule. As such, we are proposing to revise the compliance date for existing sources to three years after the date of publication of the final reconsideration rule. This date is being p roposed in order to enable facilities sufficient time to install controls and make compliance
- related decisions. For new sources, the EPA is proposing that the compliance date is 60 days after the date of publication of the final reconsideration rule , or upon startup, whichever is later. This date assumes that the final reconsideration rule will be subject to the Congressional Review Act, which will delay the effective date of the rule by 60 days. We are proposing to extend the compliance dates for all standards for several reasons. First, the proposed changes to the emission limits for units in every subcategory and the proposed use of work practice standards for dioxin/furan emissions for all subcategories will have a significant impact on the compliance s trategies that are selected by the affected*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 94 of 147 sources. For instance, the proposed changes in PM emission limits for existing biomass fluidized bed, hybrid suspension grate, and the newly proposed dry stoker subcategories would require different PM control se lections than the emission limits finalized in March 2011. The proposed changes in Hg, HCl, and PM emission limits for units designed to burn liquid fuels are likely to result in different compliance responses and control selections for all of these pollut ants. For coal stoker units, the increased stringency of the proposed PM and HCl emission limits would require increased control efficiencies that, while not necessarily changing the types of controls needed, may impact the design of those controls. Second , when EPA announced the reconsideration and issued the stay of the effective date, a signal was sent to industry that requirements could change significantly. The resulting uncertainty has limited the ability of affected sources to begin making appropriat e selections of control technologies and other compliance decisions. Even if significant changes were not being proposed, an extended compliance date would likely be necessary to provide enough time for facilities to achieve compliance. Third, most of the dioxin emission limits that were finalized in March 2011 were below the level that EPA has now determined can be accurately measured using the*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 95 of 147 required test method. This was pointed out by stakeholders who petitioned the EPA to move to a work practice approach because the levels of dioxin/furan were too low to accurately measure and resulted in a high degree of uncertainty regarding how to meet the limits. The uncertainty resulted in the inability of sources to select dioxin/furan control technology, and al so prevented sources from selecting controls for other pollutants because the emission controls must be designed to work properly when operated together. For instance, if a source required an ESP for PM control but needed carbon injection to potentially me et a very low dioxin/furan emission limit, the source may choose a fabric filter for PM control instead of an ESP. Alternatively, if a source no longer needed carbon injection, the particulate loading to the PM control device would be decreased, which may result in a different design or possibly a selection of a different control technology. For all of the reasons discussed above, the EPA has determined EPA is proposing that the compliance date for existing sources is three years after the date of publicati on of the final reconsideration rule . Finally, the EPA has received comments that the availability of control equipment and vendors to install control equipment for boilers is in question due to the large number of units requiring controls in conjunction*** E.O. 12866 and 13563 Review

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with the parallel rulemaking for electric generating units that will require controls from many of the same vendors. While the EPA believes that the maximum time allotted under section 112, three years after promulgation along with an additional year for in stallation of controls that must be approved on a case -by- case basis by the permitting authority, provides enough time for boilers to achieve compliance, the EPA recognizes that maintaining the compliance dates from the March 2011 final rule would essentia lly provide less than 2 years for sources to meet the final standards, whose stringency will not be determined until the reconsideration is final. The EPA is requesting comment on the proposed changes to the compliance dates. 2. Reduced Testing Frequency and Detection Levels. In the final rule, EPA changed the stack testing requirements to allow units that demonstrate compliance for a particular pollutant at a level at or below 75 percent of the emission limit for 2 consecutive years to forego stack testing fo r up to 37 months . The EPA is maintaining this provision for most of the emission limits and is soliciting comment on this provision. The EPA also included , in the final rule analyses , a method to ensure that emission limits are set at levels that can be measured by the available test methods. During the development of the*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 97 of 147 rule, the EPA carefully considered comments regarding the very low levels of some of the finalized emission limits that were based on a level no less than 3 times the “representative detection limit” or RDL. In cases where the calculated MACT floors were lower than the 3 times the RDL value, the calculated floor value was replaced by the 3 times the RDL value. For thes e values, which again represent the lowest level that can be measured, units can qualify for skip testing by meeting the limit rather than a level that cannot be accurately measured. 3. Fuel Analysis of Gaseous Fuels at Co
- Fired Units . Petitioners requested that EPA clarify the fuel analysis requirements for
co - fired units that combust Gas 1 fuels along with either solid or liquid fuels. The EPA is clarifying that Gas 1 fuels are not included in the fuel analysis requirement. 4. Coal Sampling Techniques . Petitioners requested that EPA allow for automated coal sampling systems. The EPA did not intend to exclude these techniques in the final rule and is adding clarifying language to allow for automated coal sampling techniques. **V I**  **. Technical Corrections and Clar** **ific ations**  We are proposing several technical corrections . These amendments are being proposed to correct inaccuracies and*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 98 of 147 oversights that were promulgated in the final rule and to make the rule language consistent with provisions addressed through this reconsideration . These proposed changes are described in T able 2 of this preamble . We request comment on all of these proposed changes. Table 2 . Miscellaneous Technical Correc tions to 40 CFR Part 63, Subpart DDDDD **Section of subpart DDDDD**  **Description of correction** 40 CFR 63.7491(m) We are proposing to clarify the language in this paragraph to use the “unit” instead of “boiler”, and to provide an exemption stating “unless such units do not combust hazardous waste and combust comparable fuels”. 40 CFR 63.7495(b) We are proposing to edit this paragraph to include a provision in §63.6(i) 40 CFR 63.7499 (f)
- (s) We are proposing to edit the labels for each paragraph to accommodate the addition of paragraphs to this section. 40 CFR 63.7499(d) We are proposing to revise the term “stokers” to “stokers/sloped grate/other units” consistent with how the data for this rule was analyzed. 40 CFR 63.7500(d) We are proposing to edit this pa ragraph by adding a new paragraph (d) to clarify that the emission standards apply at all times, except during startup and shutdown, during which time you must comply only with Table 3. 40 CFR 63.7501(b) We are proposing to edit terms in this paragraph t o correct spelling errors. 40 CFR 63.7505(c) We are proposing to edit this paragraph by removing a reference to Table 12, which is being removed from the proposal since we are reconsidering. 40 CFR 63.7510(a) We are proposing to edit this paragraph to create four subparagraphs (1)
- (4) to clarify our intent on fuel analysis requirements for gaseous fuels. 40 CFR 63.7510(f) We are proposing to edit this paragraph to remove references to Table 12, which is being removed from the proposal.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 99 of 147 40 CFR 63.7515( f) We also propose to remove a reference to Table 12, which is being removed from the proposal. 40 CFR 63.7520(d) We are proposing to remove a reference to Table 12, which is being removed from the proposal. 40 CFR 63.7521(c)(1)(ii) We are proposing to e dit this paragraph by changing wording from “1
- hour” to “one - hour”. We are also proposing to clarify the different sampling circumstances for performance stack testing and monthly sampling. 40 CFR 63.7521(c)(2)(ii) 40 CFR 63.7521(d)(2) We are proposing to edit this paragraph by clarifying wording describing sampling requirements to provide more flexibility for automated sampling and reduce overly prescriptive language. 40 CFR 63.7521(e) We are proposing to reference equations 7, 8, and 9 within this paragraph to add clarity. 40 CFR 63.7521( f ) We are proposing to add three sub
-paragraphs to this paragraph to organize exemptions from fuel specification analyses. 40 CFR 63.7522(e)(2) We are proposing to add the units for emission limits to add clarity (pounds per million Btu). We are proposing to revise the definition of the term “Sm” in Equation 2 to clarify that maximum steam generation is in units of pounds per hour. 40 CFR 63.7525(a ) We are proposing to remove a reference to Table 12, which is being removed from the proposal. 40 CFR 63.7525(b ) (3) We are proposing to change language from “concentrations” to “rates” to provide clarity. 40 CFR 63.7525(b ) (5) We are proposing to edit this paragraph by changing wording from “1
- hour” to “one - hour”. 40 CFR 63.7525(d)(3 ) We are proposing to revise the paragraph to add a reference to 65.7535(d) to replace a description of other situations that constitute a monitoring deviation. 40 CFR 63.7525(d)(4) We are proposing changes to c orrect the 12
- hour block average in 63.7525(d)(4) as specified in Table 8. Second, we are proposing to update and explain the averaging times for operating limits in 63.7525(d)(4). 40 CFR 63.7530(c)(2) We are proposing to edit the references to Equation 9 to be Equation 10, to accommodate the change in numbering of equations. 40 CFR 63.7530(c)(3) We are proposing to edit the references to Equation 9 to be Equation 10, to accommodate*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 100 of 147 the change in numbering of equations. 40 CFR 63.7530(c)(4) We are proposing to edit the references to Equation 9 to be Equation 10, to accommodate the change in numbering of equations. 40 CFR 63.7530(h) We are proposing to remove a reference to Table 12, which is being removed from the proposal. 40 CFR 63.7533(b)(2) We are proposing to amend this paragraph to clarify that the use of emission credits from implementation of energy conservation measures can only be used by existing units, and that these credits can be used to demonstrate initial and on
- going compliance. 40 CFR 63.7533(c)(2)(i) We are proposing to edit the reference to Equation 12 to Equation 14, to accommodate the change in numbering of equations. 40 CFR 63.7533(c)(3) We are proposing to edit the reference to Equation 12 to Equation 14, to accommodate the change in numbering of equations. 40 CFR 63.7533(c)(3)(i) We are proposing changes to Equation 12 in this section to clarify the summation to be performed in that equation, and to clarify that the energy credits are expressed as a decimal fraction of the baseline energy input . 40 CFR 63.7533(c)(3) 40 CFR 63.7533(c)(3)(i) and (f) We are revising the names and definitions of the terms in Equations 12 and 13 to be consistent . 40 CFR 63.7533(c)(f) We are revising the paragraph to remove the reference to (f) (1) and (2) because there is no paragraph (2) and only a single paragraph is needed. We are proposing to change the reference to Equation 13 to Equation 15, to accommodate the change in numbering of equations. 40 CFR 63.7535 We are revising the title of this section to add clarity. 40 CFR 63.7535(b) We are adding language to the paragraph to clarify that you must operate monitoring systems while the unit is operating and compliance is required. 40 CFR 63.7535(d) We are revising the paragraph to remove references to “out - of - control periods”. 40 CFR 63.7540(a) We are adding references to Tables 1, 2, 3, and 4 to add clarity. 40 CFR 63.7540(a)(3) We are proposing to change the reference to Equation 9 to Equation 11 to accommodate the change in numbering of equations.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 101 of 147 40 CFR 63.7540(a)(3)(iii) We are proposing to change the reference to Equation 9 to Equation 11 to accommodate the change in numbering of equations. 40 CFR 63.7540(a)(5) We are proposing to change the reference to Equation 11 to Equation 12 to accommodate the change in numbering of equations. 40 CFR 63.7540(a)(5)(iii) We are proposing to change the reference to Equation 11 to Equation 12 to accommodate the change in numbering of equations. 40 CFR 63.7540(a)(9)(i) We are proposing to correc t the reference to 60.13 to 63.8. 40 CFR 63 .7541 (a)(3) and (4) We are proposing changes to c orrect the 12
- hour block average in 63.75 41 ( a )( 3 ) and (4) as specified in Table 8. 40 CFR 63.7545(e)(3) We are proposing to remove a reference to Table 12, which is being removed from the proposal, and adding language to clarify that this applies to facilities “not using a CO CEMS to demonstrate compliance.” 40 CFR 63.7545(f) We are proposing to revise the paragraph to include units that burn “gaseous fuel subject to another subpart of this part” to add clarity. 40 CFR 63.7550(c)(6) We are proposing to change the reference to Equation 10 to Equation 11, to accommodate the change in numbering of equations. 40 CFR 63.7555(d) We are proposing to remove a reference to Table 12, which is being removed from the proposal. 40 CFR 63.7555(d)(4) We are proposing to change the reference to Equation 10 to Equation 11, to accommodate the change in numbering of equations. 40 CFR 63.7555(d)(5) We are proposing to change the reference to Equation 11 to Equation 12, to accommodate the change in numbering of equations. 40 CFR 63.7555(h) We are proposing to revise the paragraph to include units that burn “gaseous fuel subject to another subpart of this part” to add clar ity. 40 CFR 63.7575 We are proposing to revise the definition of process heater to include units heating hot water as a process heat transfer medium . We also included a hierarchy of combustor designs to clarify applicability for units with multiple combustor types. We are proposing to revise the definition of “dutch oven” to clarify that fluidized bed boilers are not part of the dutch oven design*** E.O. 12866 and 13563 Review

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cate gory. We are proposing to revise the definition of “energy assessment” to clarify the length days for each category of facilities. We are proposing to revise the definition of “equivalent” to remove references to hydrogen sulfide. We are proposing to revise the definition of “fluidized bed boiler” to clarify that pulverized coal boilers are not included. We are proposing to revise the definition of “hybrid suspension grate boiler” to clarify that “ the fuel combusted in these units exceed a moisture cont ent of 40 percent on an as
- fired basis” and “Fluidized bed, dutch oven, and pile burner designs are not part of the hybrid suspension grate boiler design category.” We are proposing to revise the definition of “fuel cell” to clarify that “fluidized bed, dutch oven, pile burner, hybrid suspension grate, and suspension burners are not part of the fuel cell subcategory.” We are proposing to revise the definition of “liquid fuel” to include vegetable oil. We are proposing to revise the definition of “process heater” to include “units heating hot water as a process heat transfer medium” and to clarify that “waste heat process heaters are excluded from this definition” similar to the exemption allowed for waste heat boilers. We are proposing to revise the defi nition of “steam output” to include a description of the total energy output for a boiler that generates only electricity. We are proposing to revise the definition of “stoker” to clarify that “fluidized bed, dutch oven, pile burner, hybrid suspension gra te, suspension burners, and fuel cells are not considered to be a stoker design.” We are proposing to revise the term “suspension boiler” to instead be “suspension burner”, to provide consistent terminology throughout the rule and to clarify that “fluidiz ed bed, dutch oven, pile burner, and hybrid suspension grate*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 103 of 147 units are not part of the suspension burner subcategory.” We are proposing to revise the definition of “waste heat boiler” to clarify that the definition includes fired and unfired waste heat bo ilers. We are proposing to revise the definition of “waste heat process heater to clarify that the definition includes fired and unfired waste heat process heaters. We are proposing to add new definitions of “12
- hour block average”, “actual heat rate”, “average annual heat input rate”, “biodiesel”, “daily block average”, “heavy liquid”, “light liquid”, “other combustor”, “oxygen analyzer”, “oxygen trim system”, “pile burner”, “residential boiler”, “sloped grate”, “stoker/sloped grate/other unit designed to burn dry biomass”, “stoker/sloped grate/other unit designed to burn wet biomass”, “total selected metals”, “unit designed to burn heavy liquid subcategory”, “unit designed to burn light liquid subcategory”, and “vegetable oil”. We are proposing to remove the definition of “liquid fuel subcategory” Table 3 We are proposing to revise item 4c to clarify the major systems “consuming energy from affected boilers and process heaters and which are under the control of the boiler/process heater owner/operator. ” We are proposing to edit item 5 to remove the reference to Table 12, which is being removed from the proposal. Table 4 We are proposing editing the operating limits for items 1 and 2 to read “one
- hour” instead of “1
- hour”.
**VII. Impacts of this**  **Proposed Rule**  A. What are the air impacts? Table 3 of this preamble illustrates, for each basic fuel subcategory, the emissions reductions achieved by the proposed*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 104 of 147 rule (i.e., the difference in emissions between a boiler or process heater controlled to the floor level of control and boilers or process heaters at the current baseline) for new and existing sources. Nationwide emissions of selected HAP (i.e., HCl, HF, mercury, metals, and VOC) will be reduced by 45,000 tons per year for existing units and 19 t ons per year for new units. Emissions of HCl will be reduced by 37,000 tons per year for existing units and 0 tons per year for new units. Emissions of mercury will be reduced between 0.5 to 1.8 tons per year for existing units and 20.2 pounds per year for new units. Emissions of filterable PM will be reduced by 41,2 00 tons per year for existing units and 1,500 tons per year for new units. Emissions of non -mercury metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel , and selenium) will be reduced by 2,200 tons per year for existing units and 19 ton s per year for new units. In addition, emissions of SO 2 are estimated to be reduced by 558,400 tons per year for existing sources and 0 tons per year for new sources. A dis cussion of the methodology used to estimate emissions and emissions reductions is presented in “ Revised (November 2011) Methodology for Estimating Cost and Emission Impacts for Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP - Major Source ” in the docket.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 105 of 147 T able 3 . Summary of Emissions Reductions for Existing and New Sources (tons/yr) Source Subcategory HCl PM Non Mercury Metals a Mercuryb VOC Existing Units Limited Use 1 2 0.45 2.2E
- 04 1

Solid units 34,815 34,830 271 0.4 to 1.4 2,487 Liquid units 2,039 6,240 1,905 0.0 4 to 0.3 1,815
Non Continental Liquid units 158 29 4 0.001 to 0.01 169

Gas 1 (NG/RG) units 21 118 0.9 0.01 85

Gas 1 Metallurgica l Furnaces 0.4 3 0.02 0.001 23

Gas 2 (other)units 4 11 0.07 0.004 to 0.005 138

New Units Solid units 0 1,462 19 0.01 0

Liquid units 0 0 0 0 0 Gas 1 units 0 0 0 0 0 Gas 1 Metallurgica l Furnaces 0 0 0 0 0

Gas 2 (other) units 0 0 0 0 0

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. b Mercury reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled "Revised (November 2011) Methodology for Estimating Cost and Emissions Impacts for Industrial,*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 106 of 147 Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants

– Major Source" for a description of the two methods for estimating mercury reductions. B. What are the water and solid waste impacts? The EPA estimated the additional water usage that would result from installing wet scrubbers to meet the emission limits for HCl would be 1.2 billion gallons per year for existing sources and 0 gallons per year for new sources. In addition to the increased water usage, an additional 416 million gallons per year of wastewater would be produced for existing sources and 0 gallons per year for new sources. The annual costs of treating the additional wastewater are $2.3 million for existing sources and $ 0 for new sources. These costs are accounted for in the control costs estimates. The EPA estimated the additional solid waste that would result from the MACT floor level of control to be 286,000 tons per year for existing sources and 1,700 tons per year for new
sources. Solid waste is generate d from flyash and dust captured in PM and mercury controls as well as from spent carbon that is injected into exhaust streams or used to filter gas streams. The costs of handling the additional solid waste generated are $12.0 million for existing sources and $70,600 for new sources. These costs are also accounted for in the control costs estimates.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 107 of 147 A discussion of the methodology used to estimate impacts is presented in “ Revised (November 2011) Methodology for Estimating Cost and Emission Impacts for Indus trial, Commercial, and Institutional Boilers and Process Heaters NESHAP - Major Source ” in the Docket. C. What are the energy impacts? The EPA expects an increase of approximately 1.5 billion kilowatt hours (kWh) in national annual energy usage as a resul t of the proposed rule. Of this amount, 1.4 billion kWh would be from existing sources and 120 million kWh from new sources. The increase results from the electricity required to operate control devices, such as wet scrubbers, electrostatic precipitators, and fabric filters which are expected to be installed to meet the proposed rule. Additionally, the EPA expects work practice standards such as boilers tune
-ups and combustion controls will improve the efficiency of boilers, resulting in an estimated fuel s avings of 47.3 trillion BTU each year from existing sources . EPA did not estimate fuel savings and efficiency improvements on new boilers since new boilers are expected to be tuned-up up upon installation and will not achieve additional fuel savings in the first year. This fuel savings estimate includes only those fuel savings resulting from gas 1 , liquid, and coal fuels and it is based on the assumption*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 108 of 147 that the work practice standards will achieve 1 percent improvement in efficiency. D. What are the cost impacts? To estimate the national cost impacts of the proposed rule for existing sources, we developed average baseline emission factors for each fuel type/control device combination based on the emission data obtained and contained in the Boiler MACT emis sion database. If a unit reported emission data, we assigned its unit
- specific emission data as its baseline emissions. For units that did not report emission data, we assigned the appropriate emission factors to each existing unit in the inventory databas e, based on the average emission factors for boilers with similar fuel, design, and control devices. We then compared each unit’s baseline emission factors to the proposed MACT floor emission limit to determine if control devices were needed to meet the emission limits. The control analysis considered fabric filters and activated carbon injection to be the primary control devices for mercury control ; electrostatic precipitators for units meeting mercury limits but requiring additional control to meet the PM or total selected metals limits ; wet scrubbers or fabric filters with dry injection to meet the HCl limits ; tune -ups, replacement burners, combustion controls , and oxidation catalysts for CO and organic HAP*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 109 of 147 control ; and tune -ups for dioxin/furan control . We identified where one control device could achieve reductions in multiple pollutants, for example a fabric filter was expected to achieve both PM and mercury control , in order to avoid overestimating the costs. We also included costs for testing and moni toring requirements contained in the proposed rule. The resulting total national cost impact of the proposed rule is 5.4 billion dollars in capital expenditures and 1.9 billion dollars per year in total annual costs. Considering estimated fuel savings resu lting from work practice standards and combustion controls, the total annualized costs are reduced to 1.5 billion dollars. The total capital and annual costs include costs for control devices, work practices, testing and monitoring. While these costs a re h igher than the costs estimated for the final rule, these estimates are based on an inventory that includes 300 additional units that were identified after the final rule was completed. The costs associated with the final rule inventory are just under $5.0 billion in capital expenditures and $1.75 billion in total annual costs ($1.35 billion considering fuel savings). Table 4 of this preamble shows the capital and annual cost impacts for each subcategory. Costs include testing and monitoring costs, but not recordkeeping and reporting costs.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 110 of 147 T able 4 . Summary of Capital and Annual Costs for New and Existing Sources Source Subcategory Estimated/ Projected No. of Affected Units Capital

Costs (10 6 $) Testing

and Monitoring Annualized Costs (10 6 $/yr) Annualized

Cost (10 6 $/yr)(cons idering fuel savings) Existing Units Coal units 616 2,713 46 953

Biomass units 508 639 33 169 Heavy Liquid units 322 769 8.4 264
Light Liquid units 581 930 5.1 277

Non Continental Liquid units 44 181 1.5 42

Gas 1 (NG/RG) units 11,911 77 0.9 (295)

Gas 2 (other) units 129 132 2.3 55
Energy Assessmen t ALL 1,704 (Facilities) N/A N/A 28

New Units Coal units 0 0 0 0

Biomass units 82 381 5.6 99 a Liquid units 0 0 0 0*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 111 of 147 Gas 1 (NG/RG) units 1,762 11 0 5.1 a

Gas 2 (other) units 0 0 0 0
a Total annualized costs for new units do not account for fuel savings since no fuel savings are estimated in the first year for new units. Using Department of Energy projections on fuel expenditures, the number of additional boilers that could be potentially constructed was estimated. The resulting total national cost impact of the proposed rule for new boilers in the 3rd year is 393 million dollars in capital expenditures and 104 mi llion dollars per year in total annual costs. Potential control device cost savings and increased recordkeeping and reporting costs associated with the emissions averaging provisions in the proposed rule are not accounted for in either the capital or annualized cost estimates. A discussion of the methodology used to estimate cost impacts is presented in “ Revised (November 2011) Methodology for Estimating Cost and Emission Impacts for Industrial, Commercial, and Institutional Boilers and Process Heaters NE SHAP - Major Source ” in the Docket. E. What are the economic impacts?*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 112 of 147 The EPA analyzed the economic impacts of this proposed rule using the methodology that was discussed in the final rule RIA and in the preamble to the final rule. See FR 76 15651. The market impact results are very similar to the results presented in the final rule and the RIA. The agencies economic model suggests the average national price increases for industrial sectors are less than 0.01 percent , while average annual domestic production may fall by less than 0.01 percent . Because of higher domestic prices, imports slightly rise. The change in US surplus is now
- 1. 9 3 billion dollars (2006$). For the RIA, it was
- 1.86 billion dollars (2006$). The results for sales tests for small businesses were somewhat reduced. For the s ales tests u sing small companies i dentified in the Combustion Survey , the mean cost to receipts dropped from 4 percent in the RIA to 2 percent for this proposed rule and the median was 0.2 percent for both. The number of parent companies with sales tests exceeding 3 percent dropped from 8 in the RIA to 6 for this proposed rule. There was no change in the results for small public entities. Median cost is still about $1.1 million and representative small major public entities would have cost
- to - revenue ratios above 10 percent. The change in employment estimates between the RIA and the proposal is minimal. In the RIA for the final rule, we estimated*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 113 of 147 employment changes ranging between −3100 to + 6,500 employees, with a central estimate of +1,700 . For this proposal, we estimate employment changes ranging between −3 0 00 to + 6, 3 00 employees, with a central estimate of +1, 6 00 . The benefits estimates increased for th is proposal. In the RIA for the final rule, we estimated benefi ts ranging from $22 billion (2008$) to 54 billion (2008$) at a 3 percent discount rate. For this proposal, we estimate benefits ranging from $27 billion (2008$) to 67 billion (2008$) at a 3 percent discount rate. The range for the RIA was $20 billion (2008 $) to 49 billion (2008$) at a 7 percent discount rate . The range for th is proposal i s $25 billion (2008$) to 61 billion (2008$) at a 7 percent discount rate.
F . What are the benefits of this proposed rule ? We calculated health benefits u sing the methodology described in the RIA prepared for the March 21, 2011, final rule. We incorporated the revised emission reductions estimated for th is reconsideration proposal into the analysis . We were unable to estimate the benefits from reducing exposure to HAPs and ozone, ecosystem impairment, and visibility impairment, including reducing 18 7 ,000 tons of carbon monoxide, 37,000 tons of HCl, 1,000 tons of HF, 1,000 to 3,600 pounds of mercury, and*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 114 of 147 2,200 tons of other metals. Please refer to the full description in the final Boiler RIA of the unquantified benefits as well as analysis limitations and uncertainties. These monetized benefits are approximately 23 percent higher than the final rule benefits due to the increase in SO 2 emission reductions. We estimate the total monetized benefits of this proposed regulatory action to be $2 7 billion to $ 67 billion (2008$, 3 percent discount rate) in the implementation year (201 5 ). A summary of the monetized benefits estimates at discount rates of 3 percent and 7 percent i s provided in Table 4 of this preamble . A summary of the avoided health incidences is provided in Table 5 of this preamble. **Table 4 .**  **Summary of the Monetized Benefits Estimates for the Final Boiler MACT (millions of 2008$)**  **1** Pollutant Emissions

Reductions (tons) Total Monetized

Benefits (at 3% discount rate) Total Monetized Benefits (at 7% discount rate) PM2.5 - related benefits Direct PM2.5 2 5 , 601 $ 1 , 8 00 to $ 4 , 5 00 $1, 7 00 to $4, 1 00 SO 2 55 8 , 430 $2 5 ,000 to $ 63 ,000 $ 23 ,000 to $ 57 ,000 1All estimates are for the implementation year (201 5 ), and are rounded to two significant figures so numbers may not sum across rows . All fine particles are assumed to have equivalent health effects . Benefits from reducing hazardous air pollutants (HAP) are not included . These estimates do not include energy disbenefits valued at $22 million . These benefits reflect existing boilers and new boilers anticipated to come online by 201 5 .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 115 of 147 **Table 5 .**  **Summary of the Avoided Health Incidences for the Final Boiler MACT**  **1 Avoided Health**  **In cidences**  **Avoided Premature Mortality** 3 , 1 00 to 8 , 0 00 **Avoided Morbidity** Chronic Bronchitis 2 , 0 00 Acute Myocardial Infarction 4, 9 00 Hospital Admissions, Respiratory 75 0 Hospital Admissions, Cardiovascular 1, 6 00 Emergency Room Visits, Respiratory 3,0 00 Acute Bronchitis 4 , 6 00 Work Loss Days 3 9 0,000 Asthma Exacerbation 5 1,000 Minor Restricted Activity Days 2 , 3 00,000 Lower Respiratory Symptoms 55 ,000 Upper Respiratory Symptoms 41 ,000 1All estimates are for the implementation year (201 5 ), and are rounded to two significant figures. All fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These benefits reflect existing boilers and new boilers anticipated to come online by 201 5 . G. What are the secondary air impacts? For units adding controls to meet the proposed emission limits, we anticipate very minor secondary air impacts. The combustion of fuel needed to generate additional electricity would yield slight increases in emissions, including NOx , CO, PM and SO 2 and an increase in CO 2 emissions. Since NOx and SO 2 are covered by capped emissions trading programs, and methodological limitations prevent us from quantifying the change in CO and PM, we do not estimate an increase in secondary air impac ts for this*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 116 of 147 final rule from additional electricity demand. We do estimate greenhouse gas impacts, which result from increased electricity consumption, to be 931 , 0 00 tons per year from existing units and 79 ,700 tons per year from new units. **VIII. Relationsh ip of this**  **Proposed Action to Section 112(c)(6)**  **of the CAA** Section 112(c)(6) of the CAA requires the EPA to identify categories of sources of seven specified pollutants to assure that sources accounting for not less than 90 percent of the aggregate emissions of each such pollutant are subject to standards under CAA Section 112(d)(2) or 112(d)(4). The EPA has identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” “Commerci al Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categories that emit two of the seven CAA Section 112(c)(6) pollutants: POM and Hg. (The POM emitted is composed of 16 polyaromatic hydrocarbons and extractable organic matter.) I n the Federal Register notice Source Category Listing for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements, 63 FR 17838, 17849, Table 2 (1998), the EPA identified “Industrial Coal Combustion,” “Industrial Oil Combustion,” “Industrial Wood/Wood Residue Combustion,” “Commercial Coal Combustion,”*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 117 of 147 “Commercial Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” as source categories “subject to regulation” for purposes of CAA Section 112(c)(6) with respect to the CAA Section 112(c)(6) pollutants that these units emit. For Hg, the 112(c)(6) requirement is directly met through the proposed emission limits for mercury. Through these emission limits, the types of boilers and process heaters listed in section 112(c)(6) are subject to regulation. For POM, which are byproducts of combustion, the formation of POM is effectively reduced by the combustion and post
combustion practices required to comply with the CAA Section 112 standards. The tune -up requirement for all major source units and the CO emission limits will ensure that good combustion practices are followed, thus minimizing emissions of organic HAP, including POM. Any POM that do form during combustion would be reduced by the various post
- combustion controls. The add
- on PM control systems (either fabric filter or wet scrubber) and activated carbon injection in the fabric filter
-based systems would reduce emissions of these organic pollutants . It i s, therefore, reasonable to conclude that POM emissions will be substantially controlled. Thus, while this final rule does not identify specific numerical emission limits for POM, emissions*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 118 of 147 of POM are, for the reasons noted below, nonetheless “subject to
regulation” for purposes of Section 112(c)(6) of the CAA. In lieu of establishing numerical emissions limits for pollutants such as POM, we regulate surrogate substances . While we have not identified specific numerical limits for POM, CO serves as an effec tive surrogate for this HAP, because CO, like POM, is formed as a byproduct of combustion, and both would increase with an increase in the level of incomplete combustion . Consequently, we have concluded that the emissions limits for CO function as a surrogate for control of POM, such that it is not necessary to require numerical emissions limits for POM with respect to boilers and process heaters to satisfy CAA Section 112(c)(6). To further address POM and Hg emissions, this final rule also includes an energy assessment provision that encourage modifications to the facility to reduce energy demand that lead to these emissions. **IX .**  **Statutory and Executive Order R eviews**  A . Executive Order 12866 : Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this action is an "economically*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 119 of 147 significant regulatory action” because it is likely to have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments
or communities. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action. Because this action is proposing changes to a final rule and does not increase costs by an amount that would qualify the proposed rule, by itself, as a major rule, the EPA did not prepare a new RIA for this action. In stead , the EPA prepared an assessment of the changes in the costs and benefits of this proposed rule c ompared to the costs and benefits associated with the March 21, 2011 , final rule. Overall, the costs and impacts are estimated to be similar to the costs and impacts associated with the final rule , although the distribution i s somewhat different and the number of affected units in the inventory has increased by about 300 units . When comparing the costs using only those sources that were part of the final rule inventory, the costs have decreased. The EPA re - ran the multimarket model*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 120 of 147 to assess changes in economic impacts, and this analysis confirmed that the overall economic impacts are similar to the final rule. The benefits are projected to increase by about 23 percent because of the increase in the estimated SO 2 reductions . A summary of the costs and benefits of the final rule is provided in the preamble to the final rule ( see 76 FR 15658) and the detailed analysis for the final rule is provided in the RIA for the final rule. In addition, memoranda are provided in the docket to document the changes in costs, economic impacts, and benefits associated with this proposed rule . B . Paperwork Re duction Act The information collection requirements in this proposed rule will be submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act , 44 U.S.C. 3501 et seq . The Information Collection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2028.07. The information collection requirements are not enforceable until OMB approves them. The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 121 of 147 authorized by section 114 of the CAA (42 U.S.C. 7414). All info rmation submitted to EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. This proposed rule would require maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions aside from a notification of intent to commence burning solid waste materials and notification of alternative fuel use for those units that are in the Gas 1 subcategory but burn liquid fuels for periodic testing, or during periods of gas curtailment or gas supply emergencies. The recordkeeping requirements require only the specific information needed to determine compliance. The annual monitoring, reporting, and recordkeeping burden for this collection (averaged over the first 3 years after the effective date of the standards) is estimated to be $96.2 million. This i ncludes 324,954 labor hours per year at a total labor cost of $ 30.7 million per year, and total non
- labor capital costs of $ 65.5 million per year. This estimate includes initial and annual performance test, conducting an documenting an energy assessment, conducting fuel specifications for Gas 1 units, repeat testing under worst - case conditions for solid fuel*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 122 of 147 units, conducting and documenting a tune
-up, semiannual excess emission reports, maintenance inspections, developing a monitoring plan, notifications, and recordkeeping. Monitoring, testing, tune
-up and energy as sessment costs and cost were also included in the cost estimates presented in the control costs impacts estimates in section VII.D of this preamble. The total burden for the Federal government (averaged over the first 3 years after the effective date of the standard) is estimated to be 97,613 hours per year at a total labor cost of $ 5.1 million per year. Burden is defined at 5 CFR 1320.3(b). An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. To comment on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, EPA has established a public docket for this rule, which includes this ICR, under Docket ID number EPA- HQ - OAR- 2002
- 0058. Submit any comments related to the ICR to EPA and OMB. See **ADDRESSES** section at the beginning of this notice for where to submit comments to EPA. Send comments to OMB at the Office of Information and Regulatory*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 123 of 147 Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after **[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]**  , a comment to OMB is best assured of having its full effect if OMB receives it by **[INSERT DATE 30 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]**  . The final rule will respond to any OMB or public comments on the information collection requirements contained in this propos al. C . Regulatory Flexibility Act The Regulatory Flexibility Act ( RFA ) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purpose s of assessing the impacts of today’s rule on small entities, small entity is defined as: (1) a small business according to Small Business Administration (SBA) size standards by the North American Industry Classification System category of the owning entit y. The range of small business size standards*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 124 of 147 for the affected industries ranges from 500 to 1,000 employees, except for petroleum refining and electric utilities. In these latter two industries, the size standard is 1,500 employees and a mass throughput o f 75,000 barrels/day or less, and 4 million kilowatt
-hours of production or less, respectively; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not
- for -profit enterprise which is independently owned and operated and is not dominant in its field. Pursuant to section 603 of the RFA, EPA prepared a final regulatory flexibility analysis ( FRFA) that examine d the impact of the March 21, 2011 final rule on small entities along with regulatory alternatives that could reduce that impact. The FRFA was included in the RIA for the final rule and is available for review in the docket. This reconsideration proposal would decrease capital and annualized costs on small entities by about 3 percent and 10 percent, respectively. Therefore, we are relying on the FRFA from the final rule as a conservative assessment of impacts on small entities . See 76 FR 15656
- 15658. We invite comments on the propos ed changes and their impacts on small entities. D . Unfunded Mandates Reform Act*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 125 of 147 Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531
- 1538 , requires Federal agencies , unless otherwise prohibited by law, to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. This March 21, 2011, final rule contained a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any one year. Accordingly, the EPA prepared under section 202 of the UMRA a written statement for the final rule. The discussion below has been updated to reflect the proposed changes . 1. Statuto ry Authority As discussed in section I of this preamble, the statutory authority for this proposed rulemaking is section 112 of the CAA. Title III of the CAA Amendments was enacted to reduce nationwide air toxic emissions. Section 112(b) of the CAA lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP. Section 112(d) of the CAA directs us to develop NESHAP which require existing and new major sources to control emi ssions of HAP using MACT based standards. This NESHAP applies*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 126 of 147 to all ICI boilers and process heaters located at major sources of HAP emissions. 2. Social Costs and Benefits The regulatory impact analysis prepared for the final rule, which we have not revised for this proposed rule , including the Agency’s assessment of costs and benefits, is detailed in the “Regulatory Impact Analysis for the Final Industrial Boilers and Process Heaters MACT (2011) ” in the docket. Based on estimated compliance costs ass ociated with this proposed rule and the predicted change in prices and production in the affected industries, the estimated social costs of this proposed rule are $ 1.49 billion (2008 dollars). It is estimated that 3 years after implementation of this proposed rule, HAP would be reduced by 45,000 tons per year , including reductions in hydrochloric acid, hydrogen fluoride, metallic HAP including Hg, and several other organic HAP from boilers and process heaters. Studies have determined a relationship betwe en exposure to these HAP and the onset of cancer, however, the Agency is unable to provide a monetized estimate of the HAP benefits at this time. In addition, there are significant annual reductions in PM2.5 and in SO 2 that would occur, including 25,000 thousand tons of PM2.5 and 558 thousand tons of SO 2 . These reductions occur within 3 years after the*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 127 of 147 implementation of the proposed regulation and are expected to continue throughout the life of the affected sources. The major health effect associated with reducing PM2.5 and PM2.5 precursors (such as SO 2 ) is a reduction in premature mortality. Other health effects associated with PM2.5 emission reductions include avoiding cases of chronic bronchitis, heart attacks, asthma attacks, and work- lost days (i.e., days when employees are unable to work). While we are unable to monetize the benefits associated with the HAP emissions reductions, we are able to monetize the benefits associated with the PM2.5 and SO 2 emissions reductions. For SO 2 and PM2.5 , we estimated the benefits associated with health effects of PM but were unable to quantify all categories of benefits (particularly those associ ated with ecosystem and visibility effects). Our estimates of the monetized benefits in 201 5 associated with the implementation of the proposed alternative range from $ 27 billion (2008 dollars) to $ 67 billion (2008 dollars) when using a 3 percent discount rate (or from $ 25 billion (2008 dollars) to $ 61 billion (2008 dollars) when using a 7 percent discount rate). This estimate, at a 3 percent discount rate, is about $25 billion (2008 dollars) to $ 65 billion (2008 dollars) higher than the estimated social co sts shown earlier in this section. The general approach used to value benefits is discussed in more detail earlier in*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 128 of 147 this preamble. For more detailed information on the benefits estimated for the rulemaking, refer to the RIA and the memos updating the impacts and benefits in the docket. 3. Future and Disproportionate Costs The UMRA requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by this proposed rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of the rule are discussed previously in this preamble. We do not believe that there will be any disproportionate budgetary effects of this proposed rule on any particular areas of the country, State or local governments, types of communities (e.g., urban, rural), or particular industry segments. See the results of the “Regulatory Impact Analysis for the Final Industrial Boilers and Process Heaters MACT (2 011). ” 4. Effects on the National Economy The Unfunded Mandates Act requires that we estimate the effect of this proposed rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and international competitiveness of the U.S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 129 of 147 The nationwide economic impact of this proposed rule is presented in the “Regulatory Impact Analysis for the Final Industrial Boilers and Process Heaters MACT (2011) ” in the docket. This analysis provides estimates of the effect of this rule on some of the categories mentioned above. The results of the economic impact analysis are summarized previously in this preamble. The results show that there will be a small impact on prices and output, and little impact on communities that may be affected by this proposed rule. In addition, there should be little impact on energy markets (in this case, coal, natural gas, petroleum products, and electricity). Hence, the potential impacts on the categories mentioned above should be small. 5. Consultation with Government Officials The Unfunded Mandates Act requires that we describe the extent of the Agency’s prior consultation with affected State, local, and tribal officials, summarize the officials’ comments or concerns, and summarize our response to those comments or
concerns. In addition, section 203 of the UMRA requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. We consulted with State and local air pollution control officials during the development of the final rule . We have also held meetings on this proposed rule with many of the stakeholders*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 130 of 147 from numerous individual companies, institutions, environmental groups, consultants and vendors, labor unions, and other interested parties. We have added materials to the docket to document these meetings. Consistent with section 205 , EPA has identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives is presented in the docket. The regulatory alternative upon which the emission limits in this proposed rule are based represents the MACT floor s for all subcategories and , as a result, it is the least costly and least burdensome alternative. This rule is not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments . While some small governments may have some sources affected by this proposed rule, the impacts are not expected to be significant. Therefore, this proposed rule is not subject to the requirements of section 203 of the UMRA. E . Executive Order 13132 : Federalism This action does not have federalism implications . It will not have substantial direct effects on the States, on the relationship between the national government and the States, or*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 131 of 147 on the distribution of power and responsibilities among the various levels of government, as specified in Execut ive Order 13132 . This proposed rule will not impose direct compliance costs on s tate or local governments, and will not preempt s tate law . Thus, Executive Order 13132 does not apply to this action . In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and s tate and local governments, EPA specifically solicits comment on this proposed action from s tate and local officials. F . Executive Order 13175 : Consultation and Coordination with Indian Tribal Governments This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000) . It will not have substantial direct effects on tribal governments,
on the relationship between the federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175 . Thus, Executive Order 13175 does not apply to th is action . The EPA specifically solicits additional comment on this proposed action from tribal officials. G . Executive Order 13045 : Protection of Children from Environmental Health Risks and Safety Risks*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 132 of 147 EPA interprets Executive Order 13045 (62 FR 19885, Ap ril 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5
- 501 of the Executive Order has the potential to influence the regulation . This action is not subject to Executive Order 13045 because it is based solely on technology performance . H . Executive Order 13211 : Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution , or Use This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 2 8355, May 22, 2001), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. For the March 21, 2011, final rule, we estimate d a 0.05 percent price increase for the energy sector and a - 0.02 percent percentage change in production. We estimate d a 0.09 percent increase in energy imports. For more information on the estimated energy effects, please refer to the “Regulatory Impact Analysis for the Final Industrial Boilers and Process Heaters MACT (2011) . ” The analysis is available in the public docket. While we did not redo the RIA for this proposed action, the energy impacts for existing sources decreased slightly, and the energy impacts for
new s ource increased due to the increased number of new sources*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 133 of 147 that is now projected. Overall, the projected energy use increased slightly but would not change the analysis that was conducted for the final rule. Therefore, we conclude that the proposed rule when implemented is not likely to have a significant adverse effect on the supply, distribution, or use of energy. I . National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA) , Public Law No. 104
- 113 ,( 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical . Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies . NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not use available and applicable voluntary consensus standards . This proposed rulemaking involves technical standards. EPA proposes to use EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 23, 26, 26A, 29 of 40 CFR part 60 **.** Consistent with the NTTAA, EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicable*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 134 of 147 voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are pl aced in the docket for the proposed rule. The three voluntary consensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the proposed rule. The voluntary consensus standard ASME PTC 19
- 10
- 1981
- Part 10, “Flue and Exhaust Gas Analyses,” is cited in the proposed rule for its manual method for measuring the oxygen, carbon dioxide, and carbon monoxide content of exhaust gas. This part of ASME PTC 19
- 10
- 1981
- Part 10 is an acceptable alternative to Me thod 3B. The voluntary consensus standard ASTM D6522
- 00, “Standard Test Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas - Fired Reciprocating Engines, Combustion Turbines, Boilers and Process Heaters Using Portable Analyzers” is an acceptable alternative to EPA Method 3A for identifying carbon monoxide and oxygen concentrations for the proposed rule when the fuel is natural gas. The voluntary consensus standard ASTM Z65907, “Standard Method for Both Speciated and Elemental Mercury Determination,” is an acceptable alternative to EPA Method 29 (portion for*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 135 of 147 mercury only) for the purpose of the proposed rule. This standard can be used in the proposed rule to determine the mercury concentration in stack gases for boilers with rated heat input capacities of greater than 250 MMBtu per hour. In addition to the voluntary consensus standards EPA uses in the proposed rule, the search for emissions measurement procedures identified 15 other voluntary consensus standards. The EPA determined that 13 of these 15 standards identified for measuring emissions of the HAP or surrogates subject to emission standards in the proposed rule were impractical alternatives to EPA test methods for the purposes of the rule. Therefore, EPA does not intend to adopt these standards for this purpose. The reasons for this determination for the 13 methods are discussed below. The voluntary consensus standard ASTM D3154
- 00, “Standard Method for Average Velocity in a Duct (Pitot Tube Method),” is impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the proposed rulemaking since the standard appears to lack in quality control and quality assurance requirements. Specifically, ASTM D3154
- 00 does not include the following: (1) proof that openings of standard pitot tube have not plugged during the test; (2) if differential pressure gauges other than inclined manometers ( e.g. , magnehelic gauges) are*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 136 of 147 used, their calibration must be checked after each tes t series; and (3) the frequency and validity range for calibration of the temperature sensors. The voluntary consensus standard ASTM D3464
- 96 (2001), “Standard Test Method Average Velocity in a Duct Using a Thermal Anemometer,” is impractical as an alternative to EPA Method 2 for the purposes of the proposed rule primarily because applicability specifications are not clearly defined, e.g., range of gas composition, temperature limits. Also, the lack of supporting quality assurance data for the calibration procedures and specifications, and certain variability issues that are not adequately addressed by the standard limit EPA’s ability to make a definitive comparison of the method in these areas. The voluntary consensus standard ISO 10780:1994, “Stationary Source Emissions

–Measurement of Velocity and Volume Flowrate of Gas Streams in Ducts,” is impractical as an alternative to EPA Method 2 in the proposed rule. The standard recommends the use of an L - shaped pitot, which historically has not been recommended by EPA. The EPA specifies the S
- type design which has large openings that are less likely to plug up with dust. The voluntary consensus standard, CAN/CSA Z223.2
-M86(1999), “Method for the Continuous Measurement of Oxygen, Carbon*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 137 of 147 Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed Combustion Flue Gas Streams,” is unacceptable as a substitute for EPA Method 3A since it does not include quantitative specifications for measurement system performance, most notably the calibration proce dures and instrument performance characteristics. The instrument performance characteristics that are provided are nonmandatory and also do not provide the same level of quality assurance as the EPA methods. For example, the zero and span/calibration drift is only checked weekly, whereas the EPA methods requires drift checks after each run. Two very similar voluntary consensus standards, ASTM D5835
- 95 (2001), “Standard Practice for Sampling Stationary Source Emissions for Automated Determination of Gas Con centration,” and ISO 10396:1993, “Stationary Source Emissions: Sampling for the Automated Determination of Gas Concentrations,” are impractical alternatives to EPA Method 3A for the purposes of the proposed rule because they lack in detail and quality assu rance/quality control requirements. Specifically, these two standards do not include the following: (1) sensitivity of the method; (2) acceptable levels of analyzer calibration error; (3) acceptable levels of sampling system bias; (4) zero drift and calibration drift limits, time span, and required testing*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 138 of 147 frequency; (5) a method to test the interference response of the analyzer; (6) procedures to determine the minimum sampling time per run and minimum measurement time; and (7) specifications for data recorders, in terms of resolution (all types) and recording intervals (digital and analog recorders, only). The voluntary consensus standard ISO 12039:2001, “Stationary Source Emissions
-- Determination of Carbon Monoxide, Carbon Dioxide, and Oxygen
--Automated Methods,” is not acceptable as an alternative to EPA Method 3A. This ISO standard is similar to EPA Method 3A, but is missing some key features. In terms of sampling, the hardware required by ISO 12039:2001 does not include a 3
-way calibration valve assembl y or equivalent to block the sample gas flow while calibration gases are introduced. In its calibration procedures, ISO 12039:2001 only specifies a two
-point calibration while EPA Method 3A specifies a three
-point calibration. Also, ISO 12039:2001 does not specify performance criteria for calibration error, calibration drift, or sampling system bias tests as in the EPA method, although checks of these quality control features are required by the ISO standard. The voluntary consensus standard ASME PTC - 38
- 8 0 R85 (1985), “Determination of the Concentration of Particulate Matter in Gas Streams,” is not acceptable as an alternative for EPA Method 5*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 139 of 147 because ASTM PTC - 38
- 80 is not specific about equipment requirements, and instead presents the options available and the pro’s and con’s of each option. The key specific differences between ASME PTC - 38
- 80 and the EPA methods are that the ASME standard: (1) allows in
- stack filter placement as compared to the out - of - stack filter placement in EPA Methods 5 and 17; (2) all ows many different types of nozzles, pitots, and filtering equipment; (3) does not specify a filter weighing protocol or a minimum allowable filter weight fluctuation as in the EPA methods; and (4) allows filter paper to be only 99 percent efficient, as compared to the 99.95 percent efficiency required by the EPA methods. The voluntary consensus standard ASTM D3685/D3685M
- 98, “Test Methods for Sampling and Determination of Particulate Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but is lacking in the following areas that are needed to produce quality, representative particulate data: (1) requirement that the filter holder temperature should be between 120 oC and 134 oC, and not just “above the acid dew
-point;” (2) detailed specifications for measuring and monitoring the filter holder temperature during sampling; (3) procedures similar to EPA Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4) technical guidance for performing the Method 5 sampling*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 140 of 147 procedures, e.g., maintaining and monitoring sampling train operating temperatures, specific leak check guidelines and procedures, and use of reagent blanks for determining and subtracting background contamination; and (5) detailed equipment and/or operational requirements, e.g., component exchange leak checks, use of glass cyclones for heavy particulate loading and/or water droplets, operating under a negative stack pressure, exchanging particulate loaded filters, sampling preparation and implementation guidance, sample recovery guidance, data reduction guidance, and particulate sample calculations input. The voluntary consensus standard ISO 9096:1992, “Determination of Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying Ducts
- Manual Gravimetric Method,” is not acceptabl e as an alternative for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA Method 5 for collection of particulate matter. The standard ISO 9096 does not provide applicable technical guidance for performing many of the integral procedures specified in Methods 1, 2, and 5. Major performance and operational details are lacking or nonexistent, and detailed quality assurance/quality control guidance for the sampling operations required to produce*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 141 of 147 quality, representative particulate data (e.g., guidance for maintaining and monitoring train operating temperatures, specific leak check guidelines and procedures, and sample preparation and recovery procedures) are not provided by the standard, as in EPA Method 5. Also, details of equipment and/or operational requirements, such as those specified in EPA Method 5, are not included in the ISO standard, e.g., stack gas moisture measurements, data reduction guidance, and particulate sample calculations. The voluntary consensus standard CAN/CSA Z223.1
-M1977, “Method for the Determination of Particulate Mass Flows in Enclosed Gas Streams,” is not acceptable as an alternative for EPA Method 5. Detailed technical procedures and quality control measures that are required in EPA Methods 1, 2, 3, and 4 are not included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not include the EPA Method 5 filter weighing requirement to repeat weighing every 6 hours until a constant weight is achieved. Third, EPA Method 5 requires the filter weight to be reported to the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a standard pitot for velocity measurement when plugging of the tube opening is not expected to be a problem. Whereas, EPA Method 5 requires an S
- shaped pitot.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 14 2 of 147 The voluntary consensus standard EN 1911
- 1,2,3 (1998), “Stationary Source Emissions
-Manual Method of Determination of HCl - Part 1: Sampling of Gases Ratified European Text - Part 2: Gaseous Compounds Absorption Ratified European Text
- Part 3: Adsorption Solutions Analysis and Calculation Ratified European Text,” is impractical as an alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered equivalent to EPA Method 26 or 26A because the sample absorbing solution (water) would be expected to capture both HCl and chlorine gas, if present, without the ability to distinguish between the two. The EPA Methods 26 and 26A use an acidified absorbing sol ution to first separate HCl and chlorine gas so that they can be selectively absorbed, analyzed, and reported separately. In addition, in EN 1911 the absorption efficiency for chlorine gas would be expected to vary as the pH of the water changed during
sampling. The voluntary consensus standard EN 13211 (1998), is not acceptable as an alternative to the mercury portion of EPA Method 29 primarily because it is not validated for use with impingers, as in the EPA method, although the method describes procedures for the use of impingers. This European standard is validated for the use of fritted bubblers only and requires the use of a side (split) stream arrangement for isokinetic sampling*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 143 of 147 because of the low sampling rate of the bubblers (up to 3 liters per minute, maximum). Also, only two bubblers (or impingers) are required by EN 13211, whereas EPA Method 29 require the use of six impingers. In addition, EN 13211 does not include many of the quality control procedures of EPA Method 29, especially for the use and calibration of temperature sensors and controllers, sampling train assembly and disassembly, and filter weighing. Two of the 15 voluntary consensus standards identified in this search were not available at the time the review was conducted for the purposes of the proposed rule because they are under development by a voluntary consensus body: ASME/BSR MFC 13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 (and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits Using Multiport Averagi ng Pitot Primary Flowmeters,” for EPA Method 2. Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR part 63, list the EPA testing methods included in the proposed rule. Under §63.7(f) and §63.8(f) of subpart A of the General Provisions, a s ource may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures.*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 144 of 147 EPA welcomes comments on this aspect of the proposed rulema king and, specifically, invites the public to identify potentially
- applicable voluntary consensus standards and to explain why such standards should be used in this regulation. J . Executive Order 12898 : Federal Actions to Address Environmental Justice in Minority Populations and Low
- Income Populations Executive Order (EO) 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice . Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low
- income populations in the United States. For the March 2011 final rule, the EPA determined that rule
would not have disproportionately high and adverse human health or environmental effects on minority or low
- income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority or low
- income population .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 145 of 147 Compared to the final rule, while the proposed amendments are somewhat less stringent for some subcategories of units and more stringent for some others, the overall increased health benefits demonstrate that the conclusions from the environmental justice analysis conducted for the final rule are still valid .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** **National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers** 

**and Process Heaters --**  **Page 146**  **of 147**  **List of Subjects in 40 CFR Part 63** Environmental protection, Administrative practice and p rocedure, Air pollution control , Hazardous substances , Intergovernmental relations, Reporting and Recordkeeping requirements .

Dated :

Lisa P. Jackson , Administrator .*** E.O. 12866 and 13563 Review

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– Do Not Cite, Quote, or Release During Review *** Page 147 of 147 For the reasons cited in the preamb le, title 40, chapter I, part 63 of the Code of Federal Regulations is proposed to be replaced as follows: **PART 63 --**  **[AMENDED] [AMENDATORY TEXT]**