***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review***

6560-50-P EO12866_RefineryRTR 2060 AQ75 NPRM RTR_20140226

**ENVIRONMENTAL PROTECTION AGENCY**

**40 CFR Parts 60 and 63 [EPA-HQ-OAR-2010-0682; FRL- ]**  **RIN 2060-AQ75 Petroleum Refinery Sector Risk and Technology Review and New**  **Source Performance Standards**

**AGENCY:** Environmental Protection Agency (EPA).

**ACTION:** Proposed rule.

**SUMMARY:** This action proposes amendments to the national emission standards for hazardous air pollutants for petroleum refineries (40 CFR part 63, subparts CC and UUU) to address the risk remaining after application of the standards promulgated in 1995 and 2002. This action also proposes amendments to the national emission standards for hazardous air pollutants for petroleum refineries based on the results of the EPA review of developments in practices, processes and control technologies and includes new monitoring, recordkeeping and reporting requirements. The EPA is also proposing new requirements related to emissions during periods of startup, shutdown and malfunction to ensure that the standards are consistent with court opinions issued since promulgation of the standards. This action also proposes technical corrections and clarifications for new source***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 2 of 381 performance standards for petroleum refineries (40 CFR part 60, subparts J and Ja) in an effort to improve consistency and clarity. Implementation of this proposed rule will result in projected reductions of 1,760 tons per year of hazardous air pollutants, which will reduce cancer risk and chronic health

effects.

**DATES:** Comments. Comments must be received on or before [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. A copy of comments on the information collection provisions should be submitted to the Office of Management and Budget (OMB) on or before [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Public Hearing. The EPA will be holding public hearings on this proposed rule on **DATES** at **LOCATION** and **CITY** . [Note: Coordinate w/Angela Hackel.]

**ADDRESSES** : Comments. Submit your comments, identified by Docket ID Number EPA-HQ-OAR-2010-0682, by one of the following methods:

 http://www.regulations.gov: Follow the on-line instructions for submitting comments.

 Email: a-and-r-docket@epa.gov. Attention Docket ID Number EPA-HQ-OAR-2010-0682.

 Fax: (202) 566-9744. Attention Docket ID Number EPA-HQ-OAR2010-0682.

 Mail: U.S. Postal Service, send comments to: EPA Docket Center, EPA West (Air Docket), Attention Docket ID Number EPA-HQ-OAR-2010-0682, U.S. Environmental Protection Agency, Mailcode: 28221T, 1200 Pennsylvania Ave., NW, Washington,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 3 of 381 DC 20460. 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, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17 th Street, NW, Washington, DC 20503.

 Hand Delivery: U.S. Environmental Protection Agency, EPA West (Air Docket), Room 3334, 1301 Constitution Ave., NW,Washington, DC 20004. Attention Docket ID Number EPA-HQOAR-2010-0682. Such deliveries are only accepted during the Docket’s normal hours of operation, and special arrangements should be made for deliveries of boxed information.Instructions. Direct your comments to Docket ID Number EPAHQ-OAR-2010-0682. The EPA’s policy is that all comments received will be included in the public docket without change and may be made available online at http://www.regulations.gov, including any personal information provided, unless the comment includes

information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov website is an “anonymous access” system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through http://www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 4 of 381 available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contactinformation in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA’s public docket, visit the EPA Docket Center homepage at: http://www.epa.gov/dockets.

Docket. The EPA has established a docket for this rulemaking under Docket ID Number EPA-HQ-OAR-2010-0682. All documents in the docket are listed in the 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, is not placed on the Internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in regulations.gov or in hard copy at the EPA Docket Center, EPA West, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 5 of 381 Reading Room is (202) 566-1744, and the telephone number for the EPA Docket Center is (202) 566-1742. Public Hearing. The public hearing will be held on [INSERT DATE] at [INSERT LOCATION, ADDRESS, ROOM NUMBER IF AVAILABLE]. The hearing will convene at [INSERT TIME] XXX a.m. (Eastern Standard Time) and end at [INSERT TIME] XXX p.m. (Eastern Standard Time). A lunch break will be held from [INSERT TIME] XXX pm. (Eastern Standard Time) until [INSERT TIME] XXX pm (Eastern Standard Time). Please contact Ms. Virginia Hunt at (919) 541-0832 or at hunt.virginia@epa.gov to register to speak at the hearing. The last day to pre-register in advance to speak at the hearing will be [INSERT DATE]. Additionally, requests to speak will be taken the day of the hearing at the hearing registration desk, although preferences on speaking times may not be able to be fulfilled. If you require the service of a translator or special accommodations such as audio description, please let us know at the time of registration.

**FOR FURTHER INFORMATION:** For questions about this proposed action, contact Ms. Brenda Shine, Sector Policies and Programs Division (E143-01), Office of Air Quality Planning and Standards (OAQPS), U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-3608; fax number: (919) 541-0246; and email address: shine.brenda@epa.gov. For specific information regarding the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 6 of 381 risk modeling methodology, contact Mr. Ted Palma, Health and Environmental Impacts Division (C539-02), Office of Air Quality Planning and Standards (OAQPS), U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541–5470; fax number: (919) 541–0840; and email address: palma.ted@epa.gov. For information about the applicability of the National Emissions Standards for Hazardous Air Pollutants (NESHAP) or the New Source Performance Standards (NSPS) to a particular entity, contact Maria Malave, Office of Enforcement and Compliance Assurance (OECA), telephone number: (202) 564–7027; fax number: (202) 564–0050; and email address: malave.maria@epa.gov.

**SUPPLEMENTARY INFORMATION:** Preamble Acronyms and Abbreviations. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: 10/25 tpy emissions equal to or greater than 10 tons per year of a single pollutant or 25 tons per year of cumulative pollutants ACGIH American Conference of Governmental Industrial Hygienists ADAF age-dependent adjustment factors AEGL acute exposure guideline levels AERMOD air dispersion model used by the HEM-3 model APCD air pollution control devices API American Petroleum Institute BDT best demonstrated technology***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 7 of 381 BLD bag leak detectors BSER best system of emission reduction Btu/ft 2 British thermal units per square foot Btu/scf British thermal units per standard cubic foot CAA Clean Air Act CalEPA California EPA CBI confidential business information CCU catalytic cracking units C cz combustion zone combustibles concentration CDDF chlorinated dibenzodioxins and furans CDX Central Data Exchange CEDRI Compliance and Emissions Data Reporting Interface CEMS continuous emissions monitoring system CFR Code of Federal Regulations CO carbon monoxide CO 2 carbon dioxide CO 2 e carbon dioxide equivalents COMS continuous opacity monitoring system COS carbonyl sulfide CPMS continuous parameter monitoring system CRU catalytic reforming units CS 2 carbon disulfide DCU delayed coking units DIAL differential absorption light detection and ranging EBU enhanced biological unit EPA Environmental Protection Agency ERPG emergency response planning guidelines ERT Electronic Reporting Tool ESP electrostatic precipitator FCCU fluid catalytic cracking units FGCD fuel gas combustion devices FR Federal Register FTIR Fourier transform infrared spectroscopy g PM/kg grams particulate matter per kilogram GC gas chromatograph GHG greenhouse gases GPS global positioning system H 2 S hydrogen sulfide HAP hazardous air pollutants HCl hydrogen chloride HCN hydrogen cyanide HEM-3 Human Exposure Model, Version 1.1.0 HF hydrogen fluoride HFC highest fenceline concentration HI hazard index HQ hazard quotient ICR Information Collection Request***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 8 of 381 IRIS Integrated Risk Information System km kilometers lb/day pounds per day LDAR leak detection and repair LFL lower flammability limit LFL cz combustion zone lower flammability limit LMC lowest measured concentration LOAEL lowest-observed-adverse-effect level LTD long tons per day MACT maximum achievable control technology mg/kg-day milligrams per kilogram per day mg/L milligrams per liter mg/m 3 milligrams per cubic meter Mg/yr megagrams per year MFC measured fenceline concentration MFR momentum flux ratio MIR maximum individual risk mph miles per hour NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NAS National Academy of Sciences NATA National Air Toxics Assessment NEI National Emissions Inventory NESHAP National Emissions Standards for Hazardous Air Pollutants NFS near-field interfering source NHV cz combustion zone net heating value Ni nickel NIOSH National Institutes for Occupational Safety and Health NOAEL no-observed-adverse-effect level NO X nitrogen oxides NRC National Research Council NRDC Natural Resources Defense Council NSPS new source performance standards NTTAA National Technology Transfer and Advancement Act OAQPS Office of Air Quality Planning and Standards OECA Office of Enforcement and Compliance Assurance OMB Office of Management and Budget OSC off-site source contribution OTM other test method PAH polycyclic aromatic hydrocarbons PB-HAP hazardous air pollutants known to be persistent and bio-accumulative in the environment PBT persistent, bioaccumulative, and toxic PCB polychlorinated biphenyls PM particulate matter***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 9 of 381

PM 2.5 particulate matter 2.5 micrometers in diameter and smaller POM polycyclic organic matter ppm parts per million ppmv parts per million by volume ppmw parts per million by weight PEL Probable effect level psia pounds per square inch absolute psig pounds per square inch gauge REL reference exposure level REM Model Refinery Emissions Model RFA Regulatory Flexibility Act RfC reference concentration RfD reference dose RTR residual risk and technology review SAB Science Advisory Board SBA Small Business Administration SBAR Small Business Advocacy Review SCR selective catalytic reduction SISNOSE significant economic impact on a substantial number of small entities S/L/Ts state, local and tribal air pollution control agencies SO 2 sulfur dioxide SRU sulfur recovery unit SSM startup, shutdown and malfunction STEL short-term exposure limit TEQ toxicity equivalent TLV threshold limit value TOC total organic carbon TOSHI target organ-specific hazard index tpy tons per year TRIM.FaTE Total Risk Integrated Methodology.Fate, Transport, and Ecological Exposure model TTN Technology Transfer Network UB uniform background UF uncertainty factor UMRA Unfunded Mandates Reform Act URE unit risk estimate UV-DOAS ultraviolet differential optical absorption spectroscopy VCS voluntary consensus standards VOC volatile organic compounds °F degrees Fahrenheit Δ C the concentration difference between the highest measured concentration and the lowest measured concentration***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 10 of 381 μg/m 3 micrograms per cubic meter

The EPA also defines the following abbreviations for regulations cited within this preamble:

AWP Alternative Work Practice To Detect Leaks From Equipment (40 CFR 63.11(c), (d) and (e)) Benzene NESHAP National Emission Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants (40 CFR part 61, subpart L as of publication in the **Federal Register** at 54 FR 38044, September 14, 1989) BWON National Emission Standard for Benzene Waste Operations (40 CFR part 61, subpart FF) Generic MACT National Emission Standards for Storage Vessels (40 CFR part 63, subpart WW) HON National Emission Standards for Organic Hazardous Air Pollutants (40 CFR part 63, subparts F, G and H) Marine Vessel MACT National Emission Standards for Marine Tank Vessel Loading Operations (40 CFR part 63, subpart Y) Refinery MACT 1 National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC) Refinery MACT 2 National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) Refinery NSPS J Standards of Performance for Petroleum Refineries (40 CFR part 60, subpart J) Refinery NSPS Ja Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) Organization of This Document. The information in this preamble is organized as follows:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 11 of 381 **I. General Information** A. Does this action apply to me? B. Where can I get a copy of this document and other related information? C. What should I consider as I prepare my comments for the EPA? D. Public Hearing **II. Background** A. What is the statutory authority for this action? B. What are the source categories and how do the NESHAP and NSPS regulate emissions? C. What data collection activities were conducted to support this action? D. What other relevant background information and data are available? **III. Analytical Procedures** A. How did we estimate post-MACT risks posed by the source categories? B. How did we consider the risk results in making decisions for this proposal? C. How did we perform the technology review? **IV. Analytical Results and Proposed Decisions** A. What actions are we taking pursuant to CAA Sections 112(d)(2) and 112(d)(3)? B. What are the results and proposed decisions based on our technology review? C. What are the results of the risk assessment and analyses? D. What are our proposed decisions regarding risk acceptability, ample margin of safety and adverse environmental effects? E. What other actions are we proposing? F. What compliance dates are we proposing? **V. Summary of Cost, Environmental and Economic Impacts** A. What are the affected sources, the air quality impacts and cost impacts? B. What are the economic impacts? C. What are the benefits? **VI. Request for Comments VII. Submitting Data Corrections**  **VIII. Statutory and Executive Order Reviews** A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 12 of 381 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 action apply to me? Table 1 of this preamble lists the industries that are the subject of this proposal. Table 1 is not intended to be exhaustive but rather to provide a guide for readers regarding the entities that this proposed action is likely to affect. These proposed standards, once promulgated, will be directly applicable to the affected sources. Thus, federal, state, local and tribal government entities would not be affected by this proposed action. As defined in the “Initial List of Categories of Sources Under Section 112(c)(1) of the Clean Air Act Amendments of 1990” (see 57 FR 31576, July 16, 1992), the “Petroleum Refineries - Catalytic Cracking (Fluid and other) Units, Catalytic Reforming Units, and Sulfur Plant Units” source category and the “Petroleum Refineries - Other Sources Not Distinctly Listed” both consist of any facility engaged in***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 13 of 381 producing gasoline, naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel oils, lubricants, or other products from crude oil or unfinished petroleum derivatives. The first of these source categories includes process vents associated with the following refinery process units: catalytic cracking (fluid and other) units, catalytic reforming units and sulfur plant units. The second source category includes all emission sources associated with refinery process units except the process vents listed in the Petroleum Refineries – Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units Source Category. The emission sources included in this source category include, but are not limited to, miscellaneous process vents (vents other than those listed in Petroleum Refineries – Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units Source Category), equipment leaks, storage vessels, wastewater, gasoline loading, marine vessel loading, and heat exchange systems. **Table 1. Industries Affected by this Proposed Action**

**Industry NAICS**  **a Code**  **Examples of Regulated Entities** Petroleum Refining Industry 324110 Petroleum refinery sources that are subject to 40 CFR part 60, subpart J and Ja and 40 CFR part 63, subparts CC and UUU

a North American Industry Classification System***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 14 of 381 B. Where can I get a copy of this document and other related

information? In addition to being available in the docket, an electronic copy of this action is available on the Internet through the EPA’s Technology Transfer Network (TTN) website, a forum for information and technology exchange in various areas of air pollution control. Following signature by the EPA Administrator, the EPA will post a copy of this proposed action on the TTN’s policy and guidance page for newly proposed or promulgated rules at: http://www.epa.gov/ttn/oarpg/t3pfpr.html. Following publication in the Federal Register, the EPA will post the Federal Register version of the proposal and key technical documents on the project website: http://www.epa.gov/ttn/atw/petref.html. Information on the overall residual risk and technology review (RTR) program is available at the following website: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. C. What should I consider as I prepare my comments for the EPA? Submitting CBI. Do not submit information containing CBI to the EPA through http://www.regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on a disk or CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 15 of 381 information that is claimed as CBI. In addition to one complete

version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not

contain the information claimed as CBI for inclusion in the public docket. If you submit a CD-ROM or disk that does not contain CBI, mark the outside of the disk or CD-ROM clearly that

it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA’s electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research TrianglePark, North Carolina 27711, Attention Docket ID Number EPA-HQOAR-2010-0682. D. Public Hearing The hearing will provide interested parties the opportunity to present data, views or arguments concerning the proposed action. The EPA will make every effort to accommodate all speakers who arrive and register. Because this hearing will be at a U.S. governmental facility, individuals planning to attend the hearing should be prepared to show valid picture identification to the security staff in order to gain access to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 16 of 381 the meeting room. In addition, you will need to obtain a property pass for any personal belongings you bring with you. Upon leaving the building, you will be required to return this property pass to the security desk. No large signs will be allowed in the building, cameras may only be used outside of the building and demonstrations will not be allowed on federal property for security reasons. The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral comments and supporting information presented at the public hearing. Written comments on the proposed rule must be postmarked by [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Commenters should notify Ms. Virginia Hunt if they will need specific equipment, or if there are other special needs related to providing comments at the hearing. The EPA will provide equipment for commenters to show overhead slides or make computerized slide presentations if we receive special requests in advance. Oral testimony will be limited to 5 minutes for each commenter. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email or CD) or in hard copy form. Verbatim transcripts of the hearings and

written statements will be included in the docket for the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 17 of 381 rulemaking. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearing to run either ahead of schedule or behind schedule. Information regarding the hearing

will be available at: http://www.epa.gov/ttnatw01/petrefine/petrefpg.html. **II. Background** A. What is the statutory authority for this action?

1. NESHAPSection 112 of the Clean Air Act (CAA) establishes a twostage regulatory process to address emissions of hazardous air pollutants (HAP) from stationary sources. In the first stage, after the EPA has identified categories of sources emitting one or more of the HAP listed in CAA Section 112(b), CAA Section 112(d) requires us to promulgate technology-based national emissions standards for hazardous air pollutants (NESHAP) for those sources. “Major sources” are those that emit or have the potential to emit 10 tons per year (tpy) or more of a single HAP or 25 tpy or more of any combination of HAP. For major sources, the technology-based NESHAP must reflect the maximum degree of emissions reductions of HAP achievable (after considering cost, energy requirements and non-air quality health and environmental impacts) and are commonly referred to as maximum achievable control technology (MACT) standards.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 18 of 381 MACT standards must reflect the maximum degree of emissions reduction achievable through the application of measures, processes, methods, systems or techniques, including, but not limited to, measures that (1) reduce the volume of or eliminate pollutants through process changes, substitution of materials or other modifications; (2) enclose systems or processes to eliminate emissions; (3) capture or treat pollutants when released from a process, stack, storage or fugitive emissions point; (4) are design, equipment, work practice or operational standards (including requirements for operator training or certification); or (5) are a combination of the above. CAA Section 112(d)(2)(A)-(E). The MACT standards may take the form of design, equipment, work practice or operational standards where the EPA first determines either that (1) a pollutant cannot be emitted through a conveyance designed and constructed to emit or capture the pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with law; or (2) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. CAA Section 112(h)(1)-(2).

The MACT “floor” is the minimum control level allowed for MACT standards promulgated under CAA Section 112(d)(3) and may not be based on cost considerations. For new sources, the MACT floor cannot be less stringent than the emissions control that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 19 of 381 is achieved in practice by the best-controlled similar source. The MACT floor for existing sources can be less stringent than floors for new sources but not less stringent than the average emissions limitation achieved by the best-performing 12 percentof existing sources in the category or subcategory (or the bestperforming five sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, the EPA must also consider control options that are more stringent than the floor. We may establish standards more stringent than the floor based on considerations of the cost of achieving the emission reductions, any non-air quality health and environmental impacts and energy requirements. The EPA is then required to review these technology-based standards and revise them “as necessary (taking into account developments in practices, processes, and control technologies)” no less frequently than every eight years. CAA Section 112(d)(6). In conducting this review, the EPA is not required to

recalculate the MACT floor. Natural Resources Defense Council (NRDC) V. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008). Association of Battery Recyclers, Inc. V. EPA, 716 F.3d 667 (D.C. Cir. 2013). The second stage in standard-setting focuses on reducing any remaining (i.e., “residual”) risk according to CAA Section 112(f). This provision requires, first, that the EPA prepare a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 20 of 381 report to Congress discussing (among other things) methods of calculating the risks posed (or potentially posed) by sources after implementation of the MACT standards, the public health significance of those risks and the EPA’s recommendations as to legislation regarding such remaining risk. The EPA prepared and submitted the Residual Risk Report to Congress, EPA–453/R–99–001 (Risk Report) in March 1999. Congress did not act in response, thereby triggering the EPA’s obligation under CAA Section 112(f)(2) to analyze and address residual risk. Section 112(f)(2) of the CAA requires the EPA to determine for source categories subject to MACT standards whether the emission standards provide an ample margin of safety to protect public health. Section 112(f)(2)(B) of the CAA expressly preserves the EPA’s use of the two-step process for developing standards to address any residual risk and the agency’s interpretation of “ample margin of safety” developed in the

National Emissions Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants (Benzene NESHAP) (54 FR 38044, September 14, 1989). The EPA notified Congress in the Risk Report that the agency intended to use the Benzene NESHAP approach in making CAA Section 112(f) residual risk determinations (EPA–453/R–99–001, p. ES–11). The EPA***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 21 of 381 subsequently adopted this approach in its residual risk determinations and in a challenge to the risk review for the Synthetic Organic Chemical Manufacturing source category, the United States Court of Appeals for the District of Columbia Circuit upheld as reasonable the EPA’s interpretation that subsection 112(f)(2) incorporates the standards established in the Benzene NESHAP. See NRDC V. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008)(“[S]ubsection 112(f)(2)(B) expressly incorporates the EPA’s interpretation of the Clean Air Act from the Benzene standard, complete with a citation to the Federal Register.”); see also A Legislative History of the Clean Air Act Amendments of 1990, vol. 1, p. 877 (Senate debate on Conference Report). The first step in the process of evaluating residual risk is the determination of acceptable risk. If risks are unacceptable, the EPA cannot consider cost in identifying the emissions standards necessary to bring risks to an acceptable level. The second step is the determination of whether standards must be further revised in order to provide an ample margin of safety to protect public health. The ample margin of safety is the level at which the standards must be set, unless an even more stringent standard is necessary to prevent, taking into consideration costs, energy, safety and other relevant factors,

an adverse environmental effect.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 22 of 381 a. Step 1-Determining Acceptability The agency in the Benzene NESHAP concluded that “that the acceptability of risk under Section 112 is best judged on the

basis of a broad set of health risk measures and information” and that the “judgment on acceptability cannot be reduced to any single factor.” Id. at 38046. The determination of what represents an “acceptable” risk is based on a judgment of “what risks are acceptable in the world in which we live” (Risk Report at 178, quoting NRDC V. EPA, 824 F. 2d 1146, 1165 (D.C. Cir. 1987) (en banc) (“Vinyl Chloride”), recognizing that our world

is not risk-free. In the Benzene NESHAP, we stated that “EPA will generally presume that if the risk to [the maximum exposed] individual is no higher than approximately one in 10 thousand, that risk level is considered acceptable.” 54 FR at 38045. We discussed the maximum individual lifetime cancer risk (or maximum individual risk (MIR)) as being “the estimated risk that a person living near a plant would have if he or she were exposed to the maximum pollutant concentrations for 70 years.” Id. We explained that this measure of risk “is an estimate of the upper bound of risk based on conservative assumptions, such as continuous exposure for 24 hours per day for 70 years.” Id. We acknowledged that maximum individual lifetime cancer risk “does not necessarily***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 23 of 381 reflect the true risk, but displays a conservative risk level which is an upper-bound that is unlikely to be exceeded.” Id. Understanding that there are both benefits and limitations to using the MIR as a metric for determining acceptability, we acknowledged in the Benzene NESHAP that “consideration of

maximum individual risk * * * must take into account the strengths and weaknesses of this measure of risk.” Id. Consequently, the presumptive risk level of 100-in-1 million (1- in-10 thousand) provides a benchmark for judging the acceptability of maximum individual lifetime cancer risk, but does not constitute a rigid line for making that determination. Further, in the Benzene NESHAP, we noted that: “[p]articular attention will also be accorded to the weight of evidence presented in the risk assessment of potential carcinogenicity or other health effects of a pollutant. While the same numerical risk may be estimated for an exposure to a pollutant judged to be a known human carcinogen, and to a pollutant considered a possible human carcinogen based on limited animal test data, the same weight cannot be accorded to both estimates. In considering the potential public health effects of the two pollutants, the Agency’s judgment on acceptability, including the MIR, will be influenced by the greater weight of evidence for the known human carcinogen.” Id. at 38046. The agency also explained in the Benzene NESHAP

that: “[i]n establishing a presumption for MIR, rather than a rigid line for acceptability, the Agency intends to weigh it with a series of other health measures and factors. These include the overall incidence of cancer or other serious health effects within the exposed population, the numbers of persons exposed within each individual lifetime***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 24 of 381 risk range and associated incidence within, typically, a 50 km exposure radius around facilities, the science policy assumptions and estimation uncertainties associated with the risk measures, weight of the scientific evidence for human health effects, other quantified or unquantified health effects, effects due to co-location of facilities, and co-emission of pollutants.” Id. at 38045. In some cases, these health measures and factors taken together may provide a more realistic description of the magnitude of risk in the exposed population than that provided by maximum individual lifetime cancer risk alone. As noted earlier, in NRDC V. EPA, the court held that Section 112(f)(2) “incorporates the EPA’s interpretation of the

Clean Air Act from the Benzene Standard.” The court further held that Congress’ incorporation of the Benzene standard applies equally to carcinogens and non-carcinogens. 529 F.3d at 1081-82. Accordingly, we also consider non-cancer risk metrics in our determination of risk acceptability and ample margin of safety. b. Step 2-Determination of Ample Margin of Safety CAA Section 112(f)(2) requires the EPA to determine, for source categories subject to MACT standards, whether those standards provide an ample margin of safety to protect public health. As explained in the Benzene NESHAP, “the second step of the inquiry, determining an ‘ample margin of safety,’ again includes consideration of all of the health factors, and whether to reduce the risks even further.... Beyond that information, additional factors relating to the appropriate level of control***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 25 of 381 will also be considered, including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the agency will establish the standard at a level that provides an ample margin of safety to protect the public health, as required by

Section 112.” 54 FR at 38046. According to CAA Section 112(f)(2)(A), if the MACT standards for HAP “classified as a known, probable, or possible human carcinogen do not reduce lifetime excess cancer risks to the individual most exposed to emissions from a source in the category or subcategory to less than one in one million,” the EPA must promulgate residual risk standards for the source category (or subcategory), as necessary to provide an ample margin of safety to protect public health. In doing so, the EPA may adopt standards equal to existing MACT standards if the EPA determines that the existing standards (i.e., the MACT standards) are sufficiently protective. NRDC V. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008) (“If EPA determines that the existing technology-based standards provide an ‘ample margin of safety,’ then the Agency is free to readopt those standards during the residual risk rulemaking.”) The EPA must also adopt more stringent standards, if necessary, to prevent an adverse***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 26 of 381 environmental effect, 1 but must consider cost, energy, safety and other relevant factors in doing so. The CAA does not specifically define the terms “individual most exposed,” “acceptable level” and “ample margin of safety.” In the Benzene NESHAP, 54 FR at 38044-38045, we stated as an overall objective: In protecting public health with an ample margin of safety under Section 112, EPA strives to provide maximum feasible protection against risks to health from hazardous air pollutants by (1) protecting the greatest number of persons possible to an individual lifetime risk level no higher than approximately 1-in-1 million and (2) limiting to no higher than approximately 1-in-10 thousand [i.e., 100-in-1 million] the estimated risk that a person living near a plant would have if he or she were exposed to the maximum pollutant concentrations for 70 years. The agency further stated that “[t]he EPA also considers incidence (the number of persons estimated to suffer cancer or other serious health effects as a result of exposure to a pollutant) to be an important measure of the health risk to the exposed population. Incidence measures the extent of health risks to the exposed population as a whole, by providing an

estimate of the occurrence of cancer or other serious health effects in the exposed population.” Id. at 38045. In the ample margin of safety decision process, the agency again considers all of the health risks and other health

1 “Adverse environmental effect” is defined as any significant and widespread adverse effect, which may be reasonably anticipated to wildlife, aquatic life or natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental qualities over broad areas. CAA Section 112(a)(7).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 27 of 381 information considered in the first step, including the

incremental risk reduction associated with standards more stringent than the MACT standard or a more stringent standard that EPA has determined is necessary to ensure risk is acceptable. In the ample margin of safety analysis, the agency considers additional factors, including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the agency will establish the standard at a level that provides an ample margin of safety to protect the public health, as required by CAA Section 112(f). 54 FR 38046.

2. NSPS

Section 111 of the CAA establishes mechanisms for controlling emissions of air pollutants from stationary sources. Section 111(b) of the CAA provides authority for the EPA to promulgate new source performance standards (NSPS) which apply only to newly constructed, reconstructed and modified sources.

Once the EPA has elected to set NSPS for new and modified sources in a given source category, CAA Section 111(d) calls for regulation of existing sources, with certain exceptions explained below. Specifically, Section 111(b) of the CAA requires the EPA to establish emission standards for any category of new and modified stationary sources that the Administrator, in his or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 28 of 381 her judgment, finds “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA has previously made endangerment findings under this section of the CAA for more than 60 stationary source categories and subcategories that are now subject to NSPS. Section 111 of the CAA gives the EPA significant discretion to identify the affected facilities within a source category that should be regulated. To define the affected facilities, the EPA can use size thresholds for regulation and create subcategories based on source type, class or size. Emission limits also may be established either for equipment within a facility or for an entire facility. For listed source categories, the EPA must establish “standards of performance” that apply to sources that are constructed, modified or reconstructed after the EPA proposes the NSPS for the relevant source category. 2 The EPA also has significant discretion to determine the appropriate level for the standards. Section 111(a)(1) of the

2 Specific statutory and regulatory provisions define what constitutes a modification or reconstruction of a facility. 40 CFR 60.14 provides that an existing facility is modified and, therefore, subject to an NSPS, if it undergoes “any physical change in the method of operation . . . which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted.” 40 CFR 60.15, in turn, provides that a facility is reconstructed if components are replaced at an existing facility to such an extent that the capital cost of the new equipment/components exceed 50 percent of what is believed to be the cost of a completely new facility.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 29 of 381 CAA provides that NSPS are to “reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” This level of control is commonly referred to as best demonstrated technology (BDT) or the best system of emission reduction (BSER). The standard that the EPA develops, based on the BSER achievable at that source, is commonly a numerical emission limit, expressed as a performance level (i.e., a rate-based standard). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a NSPS. Rather, sources remain

free to elect whatever combination of measures will achieve equivalent or greater control of emissions. Costs are also considered in evaluating the appropriate standard of performance for each category or subcategory. The EPA generally compares control options and estimated costs and emission impacts of multiple, specific emission standard options under consideration. As part of this analysis, the EPA considers numerous factors relating to the potential cost of the regulation, including industry organization and market structure, control options available to reduce emissions of the regulated pollutant(s) and costs of these controls.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 30 of 381 B. What are the source categories and how do the NESHAP and NSPS regulate emissions? The source categories include petroleum refineries engaged in converting crude oil into refined products, including liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oils, lubricating oils and feedstocks for the petrochemical industry. Petroleum refinery activities start with the receipt of crude oil for storage at the refinery, include all petroleum handling and refining operations, and terminate with loading of refined products into pipelines, tank or rail cars, tank trucks, or ships or barges that take products fromthe refinery to distribution centers. Petroleum refineryspecific process units include fluid catalytic cracking units (FCCU) and catalytic reforming units (CRU), as well as units and processes found at many types of manufacturing facilities (including petroleum refineries), such as storage vessels and wastewater treatment plants. HAP emitted by this industry include organics (e.g., acetaldehyde, benzene, formaldehyde, hexane, phenol, naphthalene, 2-methylnaphthalene, dioxins, furans, ethyl benzene, toluene and xylene); reduced sulfur compounds (i.e., carbonyl sulfide (COS), carbon disulfide (CS 2 )); inorganics (e.g., hydrogen chloride (HCl), hydrogen cyanide (HCN), chlorine, hydrogen fluoride (HF)); and metals (e.g., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 31 of 381 mercury, manganese and nickel). Criteria pollutants and other non-hazardous air pollutants that are also emitted include nitrogen oxides (NO X ), particulate matter (PM), sulfur dioxide (SO 2 ), volatile organic compounds (VOC), carbon monoxide (CO), greenhouse gases (GHG), and total reduced sulfur. The federal emission standards that are the primary subject of this proposed rulemaking are:

 National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT 1);

 National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) (Refinery MACT 2);

 Standards of Performance for Petroleum Refineries (40 CFR part 60, subpart J) (Refinery NSPS J); and

 Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja). 1. Refinery MACT Standards The EPA promulgated MACT standards pursuant to CAA Section 112(d)(2) and (3) for refineries located at major sources in three separate rules. On August 18, 1995, the first Petroleum***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 32 of 381 Refinery MACT standard was promulgated in 40 CFR part 63, subpart CC (60 FR 43620). This rule is known as “Refinery MACT 1” and covers the “Sources Not Distinctly Listed,” meaning it includes all emission sources from petroleum refinery process units, except those listed separately under the section 112(c) source category list expected to be regulated by other MACT standards. Some of the emission sources regulated in Refinery MACT 1 include miscellaneous process vents, storage vessels, wastewater, equipment leaks, gasoline loading racks, marine tank vessel loading and heat exchange systems. Certain process vents that were listed as a separate source category under CAA Section 112(c) and that were not addressed as part of the Refinery MACT 1 were subsequently regulated under a second MACT standard specific to these petroleum refinery process vents, codified as 40 CFR part 63, subpart UUU, which we promulgated on April 11, 2002 (67 FR 17762). This standard, which is referred to as “Refinery MACT 2,” covers process vents on catalytic cracking units (CCU) (including FCCU), CRU and sulfur recovery units (SRU). Finally, on October 28, 2009, we promulgated MACT standards for heat exchange systems, which the EPA had not addressed in the original 1995 Refinery MACT 1 rule (74 FR 55686). In this same 2009 action, we updated cross-references to the General Provisions in 40 CFR part 63. On June 20, 2013 (78 FR 37133), we***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 33 of 381 promulgated minor revisions to the heat exchange provisions of Refinery MACT 1. On September 27, 2012, Air Alliance Houston, California Communities Against Toxics and other environmental and public health groups filed a lawsuit alleging that the EPA missed statutory deadlines to review and revise Refinery MACT 1 and 2. The EPA has reached an agreement to settle that litigation. In a consent decree filed January 13, 2014 in the U.S. District Court for the District of Columbia, the EPA commits to perform the risk and technology review for Refinery MACT 1 and 2 and by May 15, 2014, either propose any regulations or propose that additional regulations are not necessary. Under the Consent Decree, the EPA commits to take final action by April 17, 2015, establishing regulations pursuant to the risk and technology

review or to issue a final determination that revision to the existing rules is not necessary. 2. Refinery NSPS Refinery NSPS subparts J and Ja regulate criteria pollutant emissions, including PM, SO 2 , NO X and CO from FCCU catalyst regenerators, fuel gas combustion devices (FGCD) and sulfur recovery plants. Refinery NSPS Ja also regulates criteria pollutant emissions from fluid coking units and delayed coking units (DCU).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 34 of 381 The NSPS for petroleum refineries (40 CFR part 60, subpart J; Refinery NSPS J) were promulgated in 1974, amended in 1976 and amended again in 2008, following a review of the standards. As part of the review that led to the 2008 amendments to Refinery NSPS J, the EPA developed separate standards of performance for new process units (40 CFR part 60, subpart Ja; Refinery NSPS Ja). However, the EPA received petitions for reconsideration and granted reconsideration on issues related to those standards. On December 22, 2008, the EPA addressed petition issues related to process heaters and flares by proposing amendments to certain provisions. Final amendments to Refinery NSPS Ja were promulgated on September 12, 2012 (77 FR 56422). In this action, we are proposing amendments to address

technical corrections and clarifications raised in a 2008 industry petition for reconsideration applicable to Refinery NSPS Ja. We are addressing these issues in this proposal because they also affect sources included within these proposed amendments to Refinery MACT 1 and 2. C. What data collection activities were conducted to support

this action? In 2010, the EPA began a significant effort to gather additional information and perform analyses to determine how to address statutory obligations for the Refinery MACT standards***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 35 of 381 and the NSPS. This effort focused on gathering comprehensive information through an industry-wide Information Collection Request (ICR) on petroleum refineries, conducted under CAA Section 114 authority. The information not claimed as CBI by respondents is available in the docket (see Docket Item Nos. EPA-HQ-OAR-2010-0682-0064 through 0069). The EPA issued a single ICR for sources covered under Refinery MACT 1 and 2 and Refinery

NSPS J and Ja. On April 1, 2011, the ICR was sent out to the petroleum refining industry. In a comprehensive manner, the ICR collected information on processing characteristics, crude slate characteristics, emissions inventories and source testing to fill known data gaps. The ICR had four components: (1) a questionnaire on processes and controls to be completed by all petroleum refineries (Component 1); (2) an emissions inventory to be developed by all petroleum refineries using the emissions estimation protocol developed for this effort (Component 2); (3) distillation feed sampling and analysis to be conducted by all petroleum refineries (Component 3); and (4) emissions source testing to be completed in accordance with an EPA-approved protocol for specific sources at specific petroleum refineries (Component 4). We received responses from 149 refineries. We have since learned that seven refineries are synthetic minor***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 36 of 381 sources, bringing the total number of major source refineries operating in 2010 to 142. Information collected through the ICR was used to establish the baseline emissions and control levels for purposes of the regulatory reviews, to identify the most effective control measures, and to estimate the environmental and cost impacts associated with the regulatory options considered. As part of the information collection process, we provided a protocol for survey respondents to follow in developing the emissions inventories under Component 2 (Emission Estimation Protocol forPetroleum Refineries, available as Docket Item Number EPA-HQOAR-2010-0682-0060). The protocol contained detailed guidance for estimating emissions from typical refinery emission sources and was intended to provide a measure of consistency and replicability for emission estimates across the refining industry. Prior to issuance of the ICR, the protocol was publicly disseminated and underwent several revisions after public comments were received. Draft and final versions of the emission estimation protocol are provided in the docket to this rule (Docket ID Number EPA-HQ-OAR-2010-0682). The protocol provided a hierarchy of methodologies available for estimating emissions that corresponded to the level of information available at refineries. For each emission source, the various emission measurement or estimation methods specific to that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 37 of 381 source were ranked in order of preference, with “Methodology Rank 1” being the preferred method, followed by “Methodology Rank 2,” and so on. Refinery owners and operators were requested through the ICR to use the highest ranked method (with Methodology Rank 1 being the highest) for which data were available. Methodology Ranks 1 or 2 generally relied on

continuous emission measurements. When continuous measurementdata were not available, engineering calculations or sitespecific emission factors (Methodology Ranks 3 and 4) were specified in the protocol by EPA; these methods generally needed periodic, site-specific measurements. When site-specific measurement or test data were not available, default emission factors (Methodology Rank 5) were provided in the protocol by

EPA. As we reviewed the ICR-submitted emissions inventories, we determined that, in some cases, refiners either did not follow the protocol methodology or made an error in their calculations. This was evident because pollutants that we expected to be reported from certain emission sources were either not reported or were reported in amounts that were not consistent with the protocol methodology. In these cases, we contacted the refineries and, based on their replies, made corrections to emission estimates. The original Component 2 submittals, documentation of the changes as a result of our review, and the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 38 of 381 final emissions inventories we relied on for our analyses are

available in the technical memorandum entitled Emissions Data Quality Memorandum and Development of the Risk Model Input File, in Docket ID Number EPA-HQ-OAR-2010-0682. Collected emissions test data (test reports, continuous emissions monitoring system (CEMS) data and other continuous monitoring system data) were used to assess the effectiveness of existing control measures, to fill data gaps and to examine variability in emissions. The ICR requested source testing for a total of 90 specific process units at 75 particular refineries across the industry. We received a total of 72 source tests; in some cases, refinery sources claimed that units we requested to be tested were no longer in operation, did not exist or did not have an emission point to the atmosphere (this was the case for hydrocrackers). In other cases, refiners claimed they were not able to conduct testing because of process characteristics. For example, source testing of DCU proved to be difficult because the moisture content of the steam vent required a significant amount of gas to be sampled to account for dilution. Venting periods of less than 20 minutes did not accommodate this strategy and, therefore, if refiners vented for less than 20 minutes, they did not sample their steam vent. As a result, only two DCU tests out of eight requested were received as part of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 39 of 381 Component 4. Results of the stack test data are compiled and available in Docket ID Number EPA-HQ-OAR-2010-0682. D. What other relevant background information and data are

available? Over the past several years, the EPA has worked with the Texas Commission on Environmental Quality and industry representatives to better characterize proper flare performance.

Flares are used to control emissions from various vents at refineries as well as at other types of facilities not in the petroleum refinery source categories, such as chemical and petrochemical manufacturing facilities. In April 2012, we released a technical report for peer review that discussed our observations regarding the operation and performance of flares. The report was a result of the analysis of several flare efficiency studies and flare performance test reports. To provide an objective evaluation of our analysis, we asked a third party to facilitate an ad hoc peer review process of the technical report. This third party established a balanced peer review panel of reviewers from outside the EPA. These reviewers

consisted of individuals that could be considered “technical combustion experts” within four interest groups: the refinery industry, industrial flare consultants, academia, and

environmental stakeholders.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 40 of 381 The EPA developed a charge statement with ten charge questions for the review panel. The peer reviewers were asked to perform a thorough review of the technical report and answer the charge questions to the extent possible, based on their technical expertise. The details of the peer review process and the charge questions, as well as comments received from the peer review process, were posted online to the Consolidated Petroleum Refinery Rulemaking Repository at the EPA's Technology Transfer Network Air Toxics Web Site (see http://www.epa.gov/ttn/atw/petref.html). These items are also provided in a memorandum entitled Peer Review of “Parameters for Properly Designed and Operated Flares” (see Docket ID Number EPA-HQ-OAR-2010-0682). After considering the comments received from the peer review process, we developed a final technical memorandum (see technical memorandum, Flare Performance Data: Summary of Peer Review Comments and Additional Data Analysis for Steam-Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010- 0682). **III. Analytical Procedures** In this section, we describe the analyses performed to support the proposed decisions for the RTR and other issues addressed in this proposal.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 41 of 381 A. How did we estimate post-MACT risks posed by the source categories? The EPA conducted a risk assessment that provided estimates of the MIR posed by the HAP emissions from each source in the source categories, the hazard index (HI) for chronic exposures to HAP with the potential to cause non-cancer health effects, and the hazard quotient (HQ) for acute exposures to HAP with the potential to cause non-cancer health effects. The assessment also provided estimates of the distribution of cancer risks within the exposed populations, cancer incidence and an evaluation of the potential for adverse environmental effects for each source category. The risk assessment consisted of eight primary steps, as discussed below. The docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682) contains the following document which provides more information on the risk assessment inputs and models: Draft Residual Risk Assessment for Petroleum Refining Source Sector. The methods used to assess risks (as described in the eight primary steps below) are consistent with those peer-reviewed by a panel of the EPA’s Science Advisory Board (SAB) in 2009 and described in their peer review report issued in 2010 3 ; they are also consistent with the key recommendations contained in that report.

3 U.S. EPA SAB. Risk and Technology Review (RTR) Risk Assessment Methodologies: For Review by the EPA’s Science Advisory board with Case***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 42 of 381 1. How did we estimate actual emissions and identify the

emissions release characteristics? We compiled data sets using the ICR emission inventory submittals as a starting point. The data sets were refined following an extensive quality assurance check of source locations, emission release characteristics, annual emission estimates and FCCU release parameters. They were then updated

based on additional information received from refineries. In addition, we supplemented these data with results from stack testing, which were required later than the inventories under the ICR. As the stack test information was received, we compared these data against the refined emission inventories and the default emission factors provided in the Emission EstimationProtocol for Petroleum Refineries (Docket Item Number EPA-HQOAR-2010-0682-0060). Based on the stack test data for FCCU, we calculated that, on average, HCN emissions were a factor of 10 greater than the average emission factor of 770 pounds per barrel FCCU feed provided in the protocol. Therefore, we revised the HCN emissions for FCCU in the emissions inventory used for the risk modeling runs (the results are presented in this preamble). For the 10 facilities that performed a stack test to determine HCN

Studies – MACT I Petroleum Refining Sources and Portland Cement Manufacturing, May 2010.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 43 of 381 emissions from their FCCU, we used the actual emissions measured during the stack tests in place of the inventories originally supplied in response to the ICR. For those facilities that did not perform a stack test, but reported HCN emissions in the emissions inventory portion of the ICR, we increased the emissions of HCN by a factor of 10, assuming the original emission inventory estimates for FCCU HCN emissions were based on the default emission factor in the protocol. The emissions inventory from the ICR and documentation of the changes made to

the file as a result of our review are contained in the technical memorandum entitled Emissions Data Quality Memorandum and Development of the Risk Model Input File, in Docket ID Number EPA-HQ-OAR-2010-0682.

2. How did we estimate MACT-allowable emissions? The available emissions data in the RTR dataset (i.e., the emissions inventory) include estimates of the mass of HAP emitted during the specified annual time period. In some cases,

these “actual” emission levels are lower than the emission levels required to comply with the MACT standards. The emissions level allowed to be emitted by the MACT standards is referred to

as the “MACT-allowable” emissions level. We discussed the use of

both MACT-allowable and actual emissions in the final Coke Oven Batteries residual risk rule (70 FR 19998–19999, April 15, 2005) and in the proposed and final Hazardous Organic NESHAP residual***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 44 of 381 risk rules (71 FR 34428, June 14, 2006, and 71 FR 76609, December 21, 2006, respectively). In those previous actions, we noted that assessing the risks at the MACT-allowable level is inherently reasonable since these risks reflect the maximum level facilities could emit and still comply with national emission standards. We also explained that it is reasonable to consider actual emissions, where such data are available, in both steps of the risk analysis, in accordance with the Benzene NESHAP approach. (54 FR 38044, September 14, 1989.) We requested allowable emissions data in the ICR. However, unlike for actual emissions, where the ICR specified the use of

the Emission Estimation Protocol for Petroleum Refineries (available as Docket Item Number EPA-HQ-OAR-2010-0682-0060), we did not specify a method to calculate allowable emissions. As a result, in our review of these data and when comparing estimates between facilities, we found that facilities did not estimate allowable emissions consistently across the industry. In addition, facilities failed to report allowable emissions for many emission points, likely because they did not know how to translate a work practice or performance standard into an allowable emission estimate and they did not know how to speciate individual HAP where the MACT standard is based on a surrogate, such as PM or VOC. Therefore, the ICR-submitted

information for allowable emissions did not include emission***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 45 of 381 estimates for all HAP and sources of interest. Consequently, we used our Refinery Emissions Model (REM Model) to estimate allowable emissions. The REM model relies on model plants that vary based on throughput capacity. Each model plant contains process-specific default emission factors, adjusted for compliance with the Refinery MACT 1 and 2 emission standards.

The risks associated with the allowable emissions were evaluated using the same dispersion modeling practices, exposure assumptions and health benchmarks as the actual risks. However, because each refinery’s allowable emissions were calculated by using model plants, selected based on each refinery’s actual capacities and throughputs, emission estimates are not specific to a particular latitude/longitude location. Therefore, for risk modeling purposes, all allowable emissions were assumed to be released from the centroid of the facility. (Note: for fugitive (area) sources, the surface area was selected by the size of the model plant and the release point was shifted to the southwest so the center of the fugitive area was near the centroid of the facility). The emission and risk estimates for the actual emission inventory were compared to the allowable emissions and risk estimates. For most work practices, where allowable emission estimates are difficult to predict, the actual risk estimates were higher than those projected using the REM Model estimates. Consequently, we post-processed the two risk files,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 46 of 381 taking the higher risk estimates from the actual emissions inventory for sources subject to work practice standards, such as process equipment leaks, and sources that were not covered in the REM Model and combining them with the risk estimates from sources with more readily determined allowable emissions. The combined post-processed allowable risk estimates provide a conservatively high estimate of the risk allowed under Refinery MACT 1 and 2. The REM Model assumptions and emission estimates, along with the post-processing of risk estimate results that produced the final risk estimates for the allowable emissions, are provided in the docket (see Refinery Emissions and Risk

Estimates for Modeled “Allowable” Emissions in Docket ID Number EPA-HQ-OAR-2010-0682). 3. How did we conduct dispersion modeling, determine inhalation exposures and estimate individual and population inhalation

risks? Both long-term and short-term inhalation exposure concentrations and health risks from the source categories addressed in this proposal were estimated using the Human Exposure Model (Community and Sector HEM-3 version 1.1.0). The HEM–3 performs three primary risk assessment activities: (1) conducting dispersion modeling to estimate the concentrations of HAP in ambient air, (2) estimating long-term and short-term inhalation exposures to individuals residing within 50***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 47 of 381 kilometers (km) of the modeled sources 4 , and (3) estimating individual and population-level inhalation risks using the exposure estimates and quantitative dose-response information. The air dispersion model used by the HEM–3 model (AERMOD) is one of the EPA’s preferred models for assessing pollutant

concentrations from industrial facilities. 5 To perform the dispersion modeling and to develop the preliminary risk estimates, HEM-3 draws on three data libraries. The first is a library of meteorological data, which is used for dispersion calculations. This library includes 1 year (2011) of hourly surface and upper air observations for 824 meteorological stations, selected to provide coverage of the United States and Puerto Rico. A second library of United States Census Bureau

census block 6 internal point locations and populations provides the basis of human exposure calculations (U.S. Census, 2010). In addition, for each census block, the census library includes the elevation and controlling hill height, which are also used in dispersion calculations. A third library of pollutant unit risk

factors and other health benchmarks is used to estimate health

risks. These risk factors and health benchmarks are the latest

4 This metric comes from the Benzene NESHAP. See 54 FR 38046.

5 U.S. EPA. Revision to the Guideline on Air Quality Models: Adoption of a Preferred General Purpose (Flat and Complex Terrain) Dispersion Model and Other Revisions (70 FR 68218, November 9, 2005).

6 A census block is the smallest geographic area for which census statistics are tabulated.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 48 of 381 values recommended by the EPA for HAP and other toxic air pollutants. These values are available at: http://www.epa.gov/ttn/atw/toxsource/summary.html and are

discussed in more detail later in this section. In developing the risk assessment for chronic exposures, we used the estimated annual average ambient air concentrations of each HAP emitted by each source for which we have emissions data in the source category. The air concentrations at each nearby census block centroid were used as a surrogate for the chronic inhalation exposure concentration for all the people who reside in that census block. We calculated the MIR for each facility as the cancer risk associated with a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks per year for a 70-year period) exposure to the maximum concentration at the centroid of

inhabited census blocks. Individual cancer risks were calculated by multiplying the estimated lifetime exposure to the ambient concentration of each of the HAP (in micrograms per cubic meter (μg/m 3 )) by its unit risk estimate (URE). The URE is an upper bound estimate of an individual’s probability of contracting cancer over a lifetime of exposure to a concentration of 1 microgram of the pollutant per cubic meter of air. For residual risk assessments, we generally use URE values from the EPA’s Integrated Risk Information System (IRIS). For carcinogenic pollutants without EPA IRIS values, we look to other reputable***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 49 of 381 sources of cancer dose-response values, often using California EPA (CalEPA) URE values, where available. In cases where new, scientifically credible dose-response values have been developed in a manner consistent with the EPA guidelines and have undergone a peer review process similar to that used by the EPA, we may use such dose-response values in place of, or in addition to, other values, if appropriate. We note here that several carcinogens emitted by facilities in these source categories have a mutagenic mode of action. For these compounds, we applied the age-dependent adjustment factors (ADAF) described in the EPA’s Supplemental Guidance for Assessing Susceptibility from Early-Life Exposure to Carcinogens (“Supplemental Guidance”). This adjustment has the effect of increasing the estimated lifetime risks for these pollutants by a factor of 1.6. Although only a small fraction of the total polycyclic organic matter (POM) emissions were reported as individual compounds, the EPA expresses carcinogenic potency of POM relative to the carcinogenic potency of benzo[a]pyrene, based on evidence that carcinogenic POM have the same mutagenic mode of action as does benzo[a]pyrene. The EPA’s Science Policy Council recommends applying the ADAF to all carcinogenic polycyclic aromatic hydrocarbons (PAH) for which risk estimates are based on potency relative to benzo[a]pyrene. Accordingly, we***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 50 of 381 have applied the ADAF to the benzo[a]pyrene-equivalent portion

of all POM mixtures.

The EPA estimated incremental individual lifetime cancer

risks associated with emissions from the facilities in the source categories as the sum of the risks for each of the carcinogenic HAP (including those classified as carcinogenic to humans, likely to be carcinogenic to humans, and suggestive evidence of carcinogenic potential 7 ) emitted by the modeled

sources. Cancer incidence and the distribution of individual cancer risks for the population within 50 km of the sources were also estimated for the source categories as part of this assessment by summing individual risks. A distance of 50 km is consistent with both the analysis supporting the 1989 Benzene NESHAP (54 FR 38044) and the limitations of Gaussian dispersion models, including AERMOD.

To assess the risk of non-cancer health effects from chronic exposures, we summed the HQ for each of the HAP that affects a common target organ system to obtain the HI for that target organ system (or target organ-specific HI, TOSHI). The HQ

7 These classifications also coincide with the terms "known carcinogen, probable carcinogen, and possible carcinogen," respectively, which are the terms advocated in the EPA's previous Guidelines for Carcinogen Risk Assessment, published in 1986 (51 FR 33992, September 24, 1986). Summing the risks of these individual compounds to obtain the cumulative cancer risks is an approach that was recommended by the EPA's SAB in their 2002 peer review of EPA's National Air Toxics Assessment (NATA) entitled, NATA - Evaluating the National-scale Air Toxics Assessment 1996 Data -- an SAB Advisory, available at: http://yosemite.epa.gov/sab/sabproduct.nsf/214C6E915BB04E14852570CA007A682C/$ File/ecadv02001.pdf.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 51 of 381 is the estimated exposure divided by the chronic reference level, which is a value selected from one of several sources. First, the chronic reference level can be the EPA Reference Concentration (RfC) (http://www.epa.gov/riskassessment/glossary.htm), defined as “an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime.” Alternatively, in cases where an RfC from the EPA’s

IRIS database is not available or where the EPA determines that using a value other than the RfC is appropriate, the chronic reference level can be a value from the following prioritized sources: (1) The Agency for Toxic Substances and Disease Registry Minimum Risk Level (http://www.atsdr.cdc.gov/mrls/index.asp), which is defined as “an estimate of daily human exposure to a hazardous substancethat is likely to be without an appreciable risk of adverse noncancer health effects (other than cancer) over a specified duration of exposure”; (2) the CalEPA Chronic Reference Exposure Level (REL) (http://www.oehha.ca.gov/air/hot_spots/pdf/HRAguidefinal.pdf), which is defined as “the concentration level (that is expressed in units of μg/m 3 for inhalation exposure and in a dose expressed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 52 of 381 in units of milligram per kilogram per day (mg/kg-day) for oral exposures), at or below which no adverse health effects are anticipated for a specified exposure duration”; or (3), as noted above, a scientifically credible dose-response value that has been developed in a manner consistent with the EPA guidelines and has undergone a peer review process similar to that used by the EPA, in place of or in concert with other values. The EPA also evaluated screening estimates of acute exposures and risks for each of the HAP at the point of highest off-site exposure for each facility (i.e., not just the census block centroids), assuming that a person is located at this spotat a time when both the peak (hourly) emissions rate and worstcase dispersion conditions occur. The acute HQ is the estimated acute exposure divided by the acute dose-response value. In each case, the EPA calculated acute HQ values using best available, short-term dose-response values. These acute dose-response values, which are described below, include the acute REL, acute exposure guideline levels (AEGL) and emergency response planning guidelines (ERPG) for 1-hour exposure durations. As discussed below, we used realistic assumptions based on knowledge of the emission point release characteristics for emission rates, and conservative assumptions for meteorology and exposure location for our acute analysis.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 53 of 381 As described in the CalEPA’s Air Toxics Hot Spots Program Risk Assessment Guidelines, Part I, The Determination of Acute Reference Exposure Levels for Airborne Toxicants, an acute REL value (http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined

as “the concentration level at or below which no adverse health effects are anticipated for a specified exposure duration.” Id. at page 2. Acute REL values are based on the most sensitive, relevant, adverse health effect reported in the peer-reviewed medical and toxicological literature. Acute REL values are designed to protect the most sensitive individuals in the population through the inclusion of margins of safety. Because margins of safety are incorporated to address data gaps and uncertainties, exceeding the REL value does not automatically indicate an adverse health impact. AEGL values were derived in response to recommendations from the National Research Council (NRC). As described in Standing Operating Procedures (SOP) of the National Advisory Committee on Acute Exposure Guideline Levels for Hazardous Substances (http://www.epa.gov/oppt/aegl/pubs/sop.pdf), 8 “the NRC’s previous name for acute exposure levels—community emergency exposure levels—was replaced by the term AEGL to reflect the broad application of these values to planning,

8 National Academy of Sciences (NAS), 2001. Standing Operating Procedures for Developing Acute Exposure Levels for Hazardous Chemicals, page 2.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 54 of 381 response, and prevention in the community, the workplace, transportation, the military, and the remediation of Superfund

sites.” Id. at 2. This document also states that AEGL values “represent threshold exposure limits for the general public and are applicable to emergency exposures ranging from 10 minutes to eight hours.” Id. at 2. The document lays out the purpose and objectives of AEGL by stating that “the primary purpose of the AEGL program and the National Advisory Committee for Acute Exposure Guideline Levels for Hazardous Substances is to develop guideline levels for once-in-a-lifetime, short-term exposures to airborne concentrations of acutely toxic, high-priority chemicals.” Id. at 21. In detailing the intended application of AEGL values, the document states that “[i]t is anticipated that the AEGL values will be used for regulatory and nonregulatory purposes by U.S. Federal and state agencies and possibly the international community in conjunction with chemical emergency response, planning and prevention programs. More specifically, the AEGL values will be used for conducting various risk assessments to aid in the development of emergency preparedness and prevention plans, as well as real-time emergency response actions, for accidental chemical releases at fixed facilities and from transport carriers.” Id. at 31.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 55 of 381 The AEGL–1 value is then specifically defined as “the airborne concentration (expressed as ppm (parts per million) or mg/m 3 (milligrams per cubic meter)) of a substance above which it is predicted that the general population, including susceptible individuals, could experience notable discomfort, irritation, or certain asymptomatic nonsensory effects. However, the effects are not disabling and are transient and reversible upon cessation of exposure.” Id. at 3. The document also notes that, “Airborne concentrations below AEGL–1 represent exposure levels that can produce mild and progressively increasing but transient and nondisabling odor, taste, and sensory irritation or certain asymptomatic, nonsensory effects.” Id. Similarly, the document defines AEGL–2 values as “the airborne concentration (expressed as parts per million or milligrams per cubic meter) of a substance above which it is predicted that the general population, including susceptible individuals, could experience irreversible or other serious, long-lasting adverse health effects or an impaired ability to escape.” Id. ERPG values are derived for use in emergency response, as described in the American Industrial Hygiene Association’s ERP Committee document entitled, ERPGS Procedures and Responsibilities (http://sp4m.aiha.org/insideaiha/GuidelineDevelopment/ERPG/Docum ents/ERP-SOPs2006.pdf), which states that, “Emergency Response***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 56 of 381 Planning Guidelines were developed for emergency planning and are intended as health-based guideline concentrations for single exposures to chemicals.” 9 Id. at 1. The ERPG–1 value is defined

as “the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to 1 hour without experiencing other than mild transient adverse health effects or without perceiving a clearly defined, objectionable odor.” Id. at 2. Similarly, the ERPG–2 value is

defined as “the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to one hour without experiencing or developing irreversible or other serious health effects or symptoms which could impair an individual’s ability to take protective action.” Id. at 1. As can be seen from the definitions above, the AEGL and ERPG values include the similarly-defined severity levels 1 and 2. For many chemicals, a severity level 1 value AEGL or ERPG has not been developed because the types of effects for these chemicals are not consistent with the AEGL-1/ERPG-1 definitions; in these instances, we compare higher severity level AEGL–2 or ERPG–2 values to our modeled exposure levels to screen for potential acute concerns. When AEGL-1/ERPG-1 values are available, they are used in our acute risk assessments.

9 ERP Committee Procedures and Responsibilities. November 1, 2006. American Industrial Hygiene Association.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 57 of 381 Acute REL values for 1-hour exposure durations are typically lower than their corresponding AEGL–1 and ERPG–1 values. Even though their definitions are slightly different, AEGL–1 values are often the same as the corresponding ERPG–1 values, and AEGL–2 values are often equal to ERPG–2 values. Maximum HQ values from our acute screening risk assessments typically result when basing them on the acute REL value for a particular pollutant. In cases where our maximum acute HQ value exceeds 1, we also report the HQ value based on the next highest acute dose-response value (usually the AEGL–1 and/or the ERPG–1 value). To develop screening estimates of acute exposures in the absence of hourly emissions data, generally we first develop estimates of maximum hourly emissions rates by multiplying the average actual annual hourly emissions rates by a default factor to cover routinely variable emissions. However, for the petroleum refineries category, we incorporated additional information and process knowledge in order to better characterize acute emissions, as described below. The ICR included input fields for both annual emissions and maximum hourly emissions. The maximum hourly emission values were often left blank or appeared to be reported in units other than those required for this emissions field (pounds per hour). Consequently, instead of relying on the inadequate data provided***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 58 of 381 in response to the ICR, we elected to estimate the hourly emissions based on the reported annual emissions (converted to average hourly emissions in terms of pounds per hour) and then to apply an escalation factor, considering the different types of emission sources and their inherent variability, in order to calculate maximum hourly rates. For sources with relatively continuous operations and steady state emissions, such as FCCU, sulfur recovery plants, and continuous catalytic reformers, a factor of 2 was used to estimate the maximum hourly rates from the average hourly emission rates. For sources with relatively continuous emissions, but with more variability, like storage tanks and wastewater systems, a factor of 4 was used to estimate the maximum hourly rates from the average hourly emission rates. For non-continuous emission sources with more variability, such as DCU, cyclic CRU, semi-regenerative CRU, and transfer and loading operations, the number of hours in the venting cycle and the variability of emissions expected in that cycle were used to

determine the escalation factor for each emissions source. The escalation factors for these processes range from 10 to 60. For more detail regarding escalation factors and the rationale for their selection, see Derivation of Hourly Emission Rates for Petroleum Refinery Emission Sources Used in the Acute Risk Analysis, available in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 59 of 381 As part of our acute risk assessment process, for cases where acute HQ values from the screening step were less than or equal to 1 (even under the conservative assumptions of the screening analysis), acute impacts were deemed negligible and no further analysis was performed. In cases where an acute HQ from the screening step was greater than 1, additional site-specific data were considered to develop a more refined estimate of the potential for acute impacts of concern. For these source categories, the data refinements employed consisted of using the site-specific facility layout to distinguish facility property from an area where the public could be exposed. These refinements are discussed more fully in the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682). Ideally, we would prefer to have continuous measurements over time to see how the emissions vary by each hour over an entire year. Having a frequency distribution of hourly emissions rates over a year would allow us to perform a probabilistic analysis to estimate potential threshold exceedances and their frequency of occurrence. Such an evaluation could include a more complete statistical treatment of the key parameters and elements adopted in this screening analysis. Recognizing that this level of data is rarely available, we instead rely on the multiplier approach.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 60 of 381 To better characterize the potential health risks associated with estimated acute exposures to HAP, and in response to a key recommendation from the SAB’s peer review of the EPA’s RTR risk assessment methodologies, 10 we generally examine a wider range of available acute health metrics (e.g., REL, AEGL) than we do for our chronic risk assessments. This is in response to the SAB’s acknowledgement that there are generally more data gaps and inconsistencies in acute reference

values than there are in chronic reference values. In some cases, e.g., when Reference Value Arrays 11 for HAP have been developed, we consider additional acute values (i.e., occupational and international values) to provide a more complete risk characterization. 4. How did we conduct the multipathway exposure and risk screening? The EPA conducted a screening analysis examining the potential for significant human health risks due to exposures via routes other than inhalation (i.e., ingestion). We first determined whether any sources in the source categories emitted any hazardous air pollutants known to be persistent and bio-

10 The SAB peer review of RTR Risk Assessment Methodologies is available at: http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A8525771F00668381/$ File/EPA-SAB-10-007-unsigned.pdf.

11 U.S. EPA. (2009) Chapter 2.9 Chemical Specific Reference Values for Formaldehyde in Graphical Arrays of Chemical-Specific Health Effect Reference Values for Inhalation Exposures (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/061, and available on-line at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=211003.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 61 of 381 accumulative in the environment (PB-HAP). The PB-HAP compounds or compound classes are identified for the screening from the EPA’s Air Toxics Risk Assessment Library (available at http://www.epa.gov/ttn/fera/risk_atra_vol1.html). For the petroleum refinery source categories, we identified emissions of cadmium compounds, chlorinated dibenzodioxins and furans (CDDF), lead compounds, mercury compounds, polychlorinated biphenyls (PCB), and polycylic organic matter (POM). Because PB-HAP are emitted by at least one facility, we proceeded to the second step of the evaluation. In this step, we determined whether the facility-specific emission rates of each of the emitted PB–HAP were large enough to create the potential for significant non-inhalation human health risks under reasonable worst-case conditions. To facilitate this step, we developed emissions rate thresholds for each PB–HAP using a hypothetical upper-end screening exposure scenario developed for use in conjunction with the EPA’s Total Risk Integrated Methodology. Fate, Transport, and Ecological Exposure (TRIM.FaTE) model. We conducted a sensitivity analysis on the screening scenario to ensure that its key design parameters would represent the upper end of the range of possible values, such that it would represent a conservative but not impossible scenario. The facility-specific emissions rates of each of the PB–HAP were compared to the emission rate threshold values for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 62 of 381 each of the PB–HAP identified to assess the potential for significant human health risks via non-inhalation pathways. Wecall this application of the TRIM.FaTE model the Tier I TRIMScreen or Tier I screen. For the purpose of developing emissions rates for our Tier I TRIM-Screen, we derived emission levels for each PB-HAP (other than lead) at which the maximum excess lifetime cancer risk would be 1-in-1 million or, for HAP that cause non-cancer health effects, the maximum HQ would be 1. If the emissions rate of any PB-HAP exceeds the Tier I screening emissions rate for any facility, we conduct a second screen, which we call the Tier II TRIM-screen or Tier II screen. In the Tier II screen, the location of each facility that exceeded the Tier I emission rate is used to refine the assumptions associated with the environmental scenario while maintaining the exposure scenario assumptions. We then adjust the risk-based Tier I screening level for each PB-HAP for each facility based on an understanding of how exposure concentrations estimated for the screening scenario change with meteorology and environmental assumptions. PB-HAP emissions that do not exceed these new Tier II screening levels are considered to pose no unacceptable risks. When facilities exceed the Tier II screening levels, it does not mean that multi-pathway impacts are significant, only that we cannot rule out that possibility based on the results of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 63 of 381the screen. These facilities may be further evaluated for multipathway risks using the TRIM.FaTE model. In evaluating the potential for multi-pathway risk from emissions of lead compounds, rather than developing a screening emissions rate for them, we compared modeled maximum estimated chronic inhalation exposures with the level of the current National Ambient Air Quality Standards (NAAQS) for lead. 12 Values below the level of the primary (health-based) lead NAAQS were considered to have a low potential for multi-pathway risk. For further information on the multi-pathway analysis approach, see the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). 5. How did we assess risks considering emissions control options? In addition to assessing baseline inhalation risks and screening for potential multipathway risks, we also estimated risks considering the potential emission reductions that would be achieved by the control options under consideration. We used

12 In doing so, EPA notes that the legal standard for a primary NAAQS – that a standard is requisite to protect public health and provide an adequate margin of safety (CAA Section 109(b)) – differs from the Section 112(f) standard (requiring among other things that the standard provide an “ample margin of safety”). However, the lead NAAQS is a reasonable measure of determining risk acceptability (i.e., the first step of the Benzene NESHAP analysis) since it is designed to protect the most susceptible group in the human population – children, including children living near major lead emitting sources. 73 FR 67002/3; 73 FR 67000/3; 73 FR 67005/1. In addition, applying the level of the primary lead NAAQS at the risk acceptability step is conservative, since that primary lead NAAQS reflects an adequate margin of safety.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 64 of 381 the same emissions inventory that we used for the risk modeling and applied emission reduction estimates for the control options we are proposing to calculate the post-control risk. We note that for storage vessels, in response to the ICR some facilities reported emissions for their tank farm or a group of storage vessels rather than for each individual storage vessel. In orderto calculate emissions for each storage vessel, we used unitspecific data from the ICR to estimate the pre- and post-control emissions based on the operating characteristics and controls reported for each unit. For example, HAP emissions from each storage vessel were estimated based on the size, contents, and controls reported for that storage vessel. If additional controls would be necessary to comply with proposed requirements for storage vessels, the HAP emissions were again estimated based on the upgraded controls. The pre- and post-control emissions were summed across all storage vessels at the facility to determine a facility-specific emission reduction factor. The facility-specific emission reduction factor was then used to adjust the emissions for each of the pollutants reported for storage vessels at that facility to account for the post-control emissions. In this manner, the expected emission reductions were applied to the specific HAP and emission points in the source category dataset to develop corresponding estimates of risk and incremental risk reductions. The resulting emission file used***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 65 of 381 for post-control risk analysis is available in the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). 6. How did we conduct the environmental risk screening

assessment?

a. Adverse Environmental Effect The EPA has developed a screening approach to examine the potential for adverse environmental effects as required under Section 112(f)(2)(A) of the CAA. Section 112(a)(7) of the CAA defines “adverse environmental effect” as “any significant and widespread adverse effect, which may reasonably be anticipated, to wildlife, aquatic life, or other natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental quality over

broad areas.”

b. Environmental HAP The EPA focuses on seven HAP, which we refer to as “environmental HAP,” in its screening analysis: five PB-HAP and two acid gases. The five PB-HAP are cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury) and lead compounds. The two acid gases are HCl and HF. The rationale for including these seven HAP in the environmental risk screening analysis is presented below. HAP that persist and bioaccumulate are of particular environmental concern because they accumulate in the soil,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 66 of 381 sediment and water. The PB-HAP are taken up, through sediment, soil, water, and/or ingestion of other organisms, by plants or animals (e.g., small fish) at the bottom of the food chain. As larger and larger predators consume these organisms,

concentrations of the PB-HAP in the animal tissues increases as does the potential for adverse effects. The five PB-HAP we evaluate as part of our screening analysis account for 99.8 percent of all PB-HAP emissions (on a mass basis from the 2005 National Emissions Inventory (NEI)).In addition to accounting for almost all of the mass of PBHAP emitted, we note that the TRIM.Fate model that we use to evaluate multipathway risk allows us to estimate concentrations of cadmium compounds, dioxins/furans, POM and mercury in soil, sediment and water. For lead compounds, we currently do not have the ability to calculate these concentrations using the TRIM.Fate model. Therefore, to evaluate the potential for adverse environmental effects from lead, we compare the estimated HEM-modeled exposures from the source category emissions of lead with the level of the secondary NAAQS for

lead. 13 We consider values below the level of the secondary lead NAAQS to be unlikely to cause adverse environmental effects.

13 The secondary lead NAAQS is a reasonable measure of determining whether there is an adverse environmental effect since it was established considering “effects on soils, water, crops, vegetation, man-made materials, animals, wildlife, weather, visibility and climate, damage to and deterioration of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 67 of 381 Due to their well-documented potential to cause direct damage to terrestrial plants, we include two acid gases, HCl and HF, in the environmental screening analysis. According to the 2005 NEI, HCl and HF account for about 99 percent (on a mass basis) of the total acid gas HAP emitted by stationary sources in the U.S. In addition to the potential to cause direct damage to plants, high concentrations of HF in the air have been linked

to fluorosis in livestock. Air concentrations of these HAP are already calculated as part of the human multipathway exposure and risk screening analysis using the HEM3-AERMOD air dispersion model, and we are able to use the air dispersion modeling to estimate the potential for an adverse environmental effect. The EPA acknowledges that other HAP beyond the seven HAP discussed above may have the potential to cause adverse environmental effects. Therefore, the EPA may include other relevant HAP in its environmental risk screening in the future, as modeling science and resources allow. The EPA invites comment on the extent to which other HAP emitted by the source categories may cause adverse environmental effects. Such information should include references to peer-reviewed ecological effects benchmarks that are of sufficient quality for making regulatory decisions, as well as information on the

property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being.”***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 68 of 381 presence of organisms located near facilities within the source categories that such benchmarks indicate could be adversely

affected. c. Ecological Assessment Endpoints and Benchmarks for PB-HAP An important consideration in the development of the EPA’s screening methodology is the selection of ecological assessment endpoints and benchmarks. Ecological assessment endpoints are defined by the ecological entity (e.g., aquatic communities including fish and plankton) and its attributes (e.g., frequency of mortality). Ecological assessment endpoints can be established for organisms, populations, communities or assemblages, and ecosystems. For PB-HAP, we evaluated the following community-level ecological assessment endpoints to screen for organisms directly exposed to HAP in soils, sediment and water:

 Local terrestrial communities (i.e., soil invertebrates, plants) and populations of small birds and mammals that consume soil invertebrates exposed to PB-HAP in the

surface soil.

 Local benthic (i.e., bottom sediment dwelling insects, amphipods, isopods and crayfish) communities exposed to PB-HAP in sediment in nearby water bodies.

 Local aquatic (water-column) communities (including fish and plankton) exposed to PB-HAP in nearby surface waters.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 69 of 381For PB-HAP, we also evaluated the following populationlevel ecological assessment endpoint to screen for indirect HAP exposures of top consumers via the bioaccumulation of HAP in

food chains.

 Piscivorous (i.e., fish-eating) wildlife consuming PBHAP-contaminated fish from nearby water bodies. For cadmium compounds, dioxins/furans, POM and mercury, we identified the available ecological benchmarks for each assessment endpoint. An ecological benchmark represents a concentration of HAP (e.g., 0.77 micrograms of HAP per liter of water) that has been linked to a particular environmental effect level (e.g., a no-observed-adverse-effect level (NOAEL)) through scientific study. For PB-HAP we identified, where possible, ecological benchmarks at the following effect levels:

 **Probable effect level (PEL):** Level above which adverse effects are expected to occur frequently.

 **Lowest-observed-adverse-effect level (LOAEL):** The lowest exposure level tested at which there are biologically significant increases in frequency or severity of adverse

effects.

 **No-observed-adverse-effect level (NOAEL):** The highest exposure level tested at which there are no biologically significant increases in the frequency or severity of

adverse effect.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 70 of 381 We established a hierarchy of preferred benchmark sources

to allow selection of benchmarks for each environmental HAP at each ecological assessment endpoint. In general, the EPA sources that are used at a programmatic level (e.g., Office of Water, Superfund Program) were used, if available. If not, the EPA benchmarks used in regional programs (e.g., Superfund) were used. If benchmarks were not available at a programmatic or regional level, we used benchmarks developed by other federal agencies (e.g., NOAA) or state agencies.

Benchmarks for all effect levels are not available for all PB-HAP and assessment endpoints. In cases where multiple effect levels were available for a particular PB-HAP and assessment endpoint, we use all of the available effect levels to help us to determine whether ecological risks exist and, if so, whether the risks could be considered significant and widespread. d. Ecological Assessment Endpoints and Benchmarks for Acid Gases The environmental screening analysis also evaluated potential damage and reduced productivity of plants due to direct exposure to acid gases in the air. For acid gases, we evaluated the following ecological assessment endpoint:

 Local terrestrial plant communities with foliage exposed to acidic gaseous HAP in the air. The selection of ecological benchmarks for the effects of acid gases on plants followed the same approach as for PB-HAP***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 71 of 381 (i.e., we examine all of the available chronic benchmarks). For HCl, the EPA identified chronic benchmark concentrations. We note that the benchmark for chronic HCl exposure to plants is greater than the reference concentration for chronic inhalation exposure for human health. This means that where EPA includes regulatory requirements to prevent an exceedance of the reference concentration for human health, additional analyses for adverse environmental effects of HCl would not be necessary. For HF, EPA identified chronic benchmark concentrations for plants and evaluated chronic exposures to plants in the screening analysis. High concentrations of HF in the air have also been linked to fluorosis in livestock. However, the HF concentrations at which fluorosis in livestock occur are higher than those at which plant damage begins. Therefore, the benchmarks for plants are protective of both plants and

livestock. e. Screening Methodology For the environmental risk screening analysis, the EPA first determined whether any petroleum refineries emitted any of the seven environmental HAP. For the petroleum refinery source categories, we identified emissions of cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury), lead,

HCl and HF.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 72 of 381 Because one or more of the seven environmental HAP evaluated are emitted by at least one petroleum refinery, we proceeded to the second step of the evaluation. f. PB-HAP Methodology For cadmium, mercury, POM and dioxins/furans, the environmental screening analysis consists of two tiers, while lead is analyzed differently as discussed earlier. In the first tier, we determined whether the maximum facility-specific

emission rates of each of the emitted environmental HAP were large enough to create the potential for adverse environmental

effects under reasonable worst-case environmental conditions.

These are the same environmental conditions used in the human multipathway exposure and risk screening analysis. To facilitate this step, TRIM.FaTE was run for each PB-HAP under hypothetical environmental conditions designed to provide conservatively high HAP concentrations. The model was set to maximize runoff from terrestrial parcels into the modeled lake, which in turn, maximized the chemical concentrations in the water, the sediments, and the fish. The resulting media concentrations were then used to back-calculate a screening threshold emission rate that corresponded to the relevant exposure benchmark concentration value for each assessment endpoint. To assess emissions from a facility, the reported emission rate for each PB-HAP was compared to the screening***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 73 of 381 threshold emission rate for that PB-HAP for each assessment endpoint. If emissions from a facility do not exceed the Tier I threshold, the facility “passes” the screen, and therefore, is not evaluated further under the screening approach. If emissions from a facility exceed the Tier I threshold, we evaluate the facility further in Tier II. In Tier II of the environmental screening analysis, the screening emission thresholds are adjusted to account for local meteorology and the actual location of lakes in the vicinity of facilities that did not pass the Tier I screen. The modeling domain for each facility in the Tier II analysis consists of eight octants. Each octant contains five modeled soil concentrations at various distances from the facility (5 soil concentrations x 8 octants = total of 40 soil concentrations per facility) and one lake with modeled concentrations for water,

sediment and fish tissue. In the Tier II environmental risk screening analysis, the 40 soil concentration points are averaged to obtain an average soil concentration for each facility for each PB-HAP. For the water, sediment and fish tissue concentrations, the highest value for each facility for each pollutant is used. If emission concentrations from a facility do not exceed the Tier II threshold, the facility passes the screen, and is typically not evaluated further. If emissions from a facility exceed the Tier II threshold, the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 74 of 381 facility does not pass the screen and, therefore, may have the potential to cause adverse environmental effects. Such facilities are evaluated further to investigate factors such as the magnitude and characteristics of the area of exceedance. g. Acid Gas Methodology The environmental screening analysis evaluates the potential phytotoxicity and reduced productivity of plants due to chronic exposure to acid gases. The environmental risk screening methodology for acid gases is a single-tier screen that compares the average off-site ambient air concentration over the modeling domain to ecological benchmarks for each of the acid gases. Because air concentrations are compared directly to the ecological benchmarks, emission-based thresholds are not calculated for acid gases as they are in the ecological risk screening methodology for PB-HAP. For purposes of ecological risk screening, EPA identifies a potential for adverse environmental effects to plant communities from exposure to acid gases when the average concentration of the HAP around a facility exceeds the LOAEL ecological benchmark. In such cases, we further investigate factors such as the magnitude and characteristics of the area of exceedance (e.g., land use of exceedance area, size of exceedance area) to

determine if there is an adverse environmental effect.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 75 of 381 For further information on the environmental screening analysis approach, see Section IV.C.5 of this preamble and the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). 7. How did we conduct facility-wide assessments? To put the source category risks in context, we typically examine the risks from the entire “facility,” where the facility includes all HAP-emitting operations within a contiguous area and under common control. In other words, we examine the HAP emissions not only from the source category emission points of interest, but also emissions of HAP from all other emission sources at the facility for which we have data. The emissions inventories provided in response to the ICR included emissions

information for all emission sources at the facilities that are part of the refineries source categories. Generally, only a few emission sources located at refineries are not subject to either Refinery MACT 1 or 2; the most notable are boilers, process heaters and internal combustion engines, which are addressed by

other MACT standards. We analyzed risks due to the inhalation of HAP that are emitted “facility-wide” for the populations residing within 50 km of each facility, consistent with the methods used for the source category analysis described above. For these facility-***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 76 of 381 wide risk analyses, the modeled source category risks were compared to the facility-wide risks to determine the portion of facility-wide risks that could be attributed to each of the source categories addressed in this proposal. We specifically examined the facility that was associated with the highest estimates of risk and determined the percentage of that risk attributable to the source category of interest. The Draft Residual Risk Assessment for Petroleum Refining Source Sector available through the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682) provides the methodology and results of the facility-wide analyses, including all facility-wide risksand the percentage of source category contribution to facilitywide risks.

8. How did we consider uncertainties in risk assessment?

In the Benzene NESHAP we concluded that risk estimation uncertainty should be considered in our decision-making under the ample margin of safety framework. Uncertainty and the potential for bias are inherent in all risk assessments, including those performed for this proposal. Although uncertainty exists, we believe that our approach, which used conservative tools and assumptions, ensures that our decisions are health protective and environmentally protective. A brief discussion of the uncertainties in the emissions datasets, dispersion modeling, inhalation exposure estimates and dose-***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 77 of 381 response relationships follows below. A more thorough discussion

of these uncertainties is included in the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which isavailable in the docket for this action (Docket ID Number EPAHQ-OAR-2010-0682).

a. Uncertainties in the Emission Datasets Although the development of the RTR datasets involved quality assurance/quality control processes, the accuracy of emissions values will vary depending on the source of the data, the degree to which data are incomplete or missing, the degree to which assumptions made to complete the datasets are accurate,

errors in emission estimates and other factors. The emission estimates considered in this analysis are annual totals for 2010, and they do not reflect short-term fluctuations during the course of a year or variations from year to year. The estimates of peak hourly emissions rates for the acute effects screening assessment were based on emission adjustment factors applied to the average annual hourly emission rates, which are intended to account for emission fluctuations due to normal facility operations. As discussed previously, we attempted to provide a consistent framework for reporting of emissions information by developing the refinery emissions estimation protocol and requesting that refineries follow the protocol when reporting***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 78 of 381 emissions inventory data in response to the ICR. This protocol, called Emission Estimation Protocol for Petroleum Refineries, is available in the docket for this rulemaking (Docket Item Number EPA-HQ-OAR-2010-0682-0060). Additionally, we developed our own estimates of emissions that are based on the factors provided in the protocol and the REM Model. We developed emission estimates based on refinery unit capacities, which also provided an estimate of allowable emissions. We then conducted risk modeling using REM Model estimates and by locating emissions at the centroid of each refinery in an attempt to understand the risk associated with emissions from each refinery. Therefore, even if there were errors in the emission inventories reported in the ICR, as was the case in many instances, emissions for those facilities were also modeled using the protocol emission factors. The risk modeling of allowable emissions based on emission factors and unit capacities did not result in significantly different risk results than the actual emissions modeling runs. Results of the allowable emissions risk estimates are provided in the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in Docket ID Number EPA-HQ-OAR-2010-0682. b. Uncertainties in Dispersion Modeling We recognize there is uncertainty in ambient concentration estimates associated with any model, including the EPA’s***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 79 of 381 recommended regulatory dispersion model, AERMOD. In using a model to estimate ambient pollutant concentrations, the user chooses certain options to apply. For RTR assessments, we select some model options that have the potential to overestimate ambient air concentrations (e.g., not including plume depletion or pollutant transformation). We select other model options that have the potential to underestimate ambient impacts (e.g., not including building downwash). Other options that we select have the potential to either under- or overestimate ambient levels (e.g., meteorology and receptor locations). On balance, considering the directional nature of the uncertainties commonly present in ambient concentrations estimated by dispersion models, the approach we apply in the RTR assessments should yield unbiased estimates of ambient HAP concentrations. c. Uncertainties in Inhalation Exposure The EPA did not include the effects of human mobility on exposures in the assessment. Specifically, short-term mobility and long-term mobility between census blocks in the modeling

domain were not considered. 14 The approach of not considering short- or long-term population mobility does not bias the estimate of the theoretical MIR (by definition), nor does it

affect the estimate of cancer incidence because the total

14 Short-term mobility is movement from one micro-environment to another over the course of hours or days. Long-term mobility is movement from one residence to another over the course of a lifetime.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 80 of 381 population number remains the same. It does, however, affect the shape of the distribution of individual risks across the affected population, shifting it toward higher estimated individual risks at the upper end and reducing the number of people estimated to be at lower risks, thereby increasing the estimated number of people at specific high-risk levels (e.g., 1-in-10 thousand or 1-in-1 million). In addition, the assessment predicted the chronic exposures at the centroid of each populated census block as surrogates for the exposure concentrations for all people living in that block. Using the census block centroid to predict chronic exposures tends to over-predict exposures for people in the census block who live further from the facility and under-predict exposures for people in the census block who live closer to the facility. Thus, using the census block centroid to predict chronic exposures may lead to a potential understatement or overstatement of the true maximum impact, but is an unbiased estimate of average risk and incidence. We reduce this uncertainty by analyzing large census blocks near facilities using aerial imagery and adjusting the location of the block centroid to better represent the population in the block, as well as adding additional receptors where the block population is not well represented by a single location.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 81 of 381 The assessment evaluates the cancer inhalation risks associated with pollutant exposures over a 70-year period, which is the assumed lifetime of an individual. In reality, both the length of time that modeled emission sources at facilities actually operate (i.e., more or less than 70 years) and the domestic growth or decline of the modeled industry (i.e., the

increase or decrease in the number or size of domestic facilities) will influence the future risks posed by a given source or source category. Depending on the characteristics of the industry, these factors will, in most cases, result in an

overestimate both in individual risk levels and in the total estimated number of cancer cases. However, in the unlikely scenario where a facility maintains, or even increases, its emissions levels over a period of more than 70 years, residents live beyond 70 years at the same location, and the residents spend most of their days at that location, then the cancer inhalation risks could potentially be underestimated. However, annual cancer incidence estimates from exposures to emissions from these sources would not be affected by the length of time an emissions source operates. The exposure estimates used in these analyses assume chronic exposures to ambient (outdoor) levels of pollutants. Because most people spend the majority of their time indoors, actual exposures may not be as high, depending on the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 82 of 381 characteristics of the pollutants modeled. For many of the HAP, indoor levels are roughly equivalent to ambient levels, but for very reactive pollutants or larger particles, indoor levels are typically lower. This factor has the potential to result in an overstatement of 25 to 30 percent of exposures. 15 In addition to the uncertainties highlighted above, there are several factors specific to the acute exposure assessment that should be highlighted. The accuracy of an acute inhalation exposure assessment depends on the simultaneous occurrence of independent factors that may vary greatly, such as hourly emissions rates, meteorology and human activity patterns. In this assessment, we assume that individuals remain for 1 hour at the point of maximum ambient concentration as determined by the co-occurrence of peak emissions and worst-case meteorological conditions. These assumptions would tend to be worst-case actual exposures as it is unlikely that a person would be located at the point of maximum exposure during the time of worst-case impact. d. Uncertainties in Dose-Response Relationships There are uncertainties inherent in the development of the dose-response values used in our risk assessments for cancer effects from chronic exposures and non-cancer effects from both

15 U.S. EPA. National-Scale Air Toxics Assessment for 1996. (EPA 453/R–01–003; January 2001; page 85.)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 83 of 381 chronic and acute exposures. Some uncertainties may be considered quantitatively, and others generally are expressed in qualitative terms. We note as a preface to this discussion a point on dose-response uncertainty that is brought out in the EPA’s 2005 Cancer Guidelines; namely, that “the primary goal of EPA actions is protection of human health; accordingly, as an Agency policy, risk assessment procedures, including default options that are used in the absence of scientific data to the contrary, should be health protective” (EPA 2005 Cancer Guidelines, pages 1–7). This is the approach followed here as summarized in the next several paragraphs. A complete detailed discussion of uncertainties and variability in dose-response relationships is given in the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).

Cancer URE values used in our risk assessments are those that have been developed to generally provide an upper bound estimate of risk. That is, they represent a “plausible upper limit to the true value of a quantity” (although this is usually not a true statistical confidence limit). 16 In some circumstances, the true risk could be as low as zero; however,

16 IRIS glossary (http://www.epa.gov/NCEA/iris/help_gloss.htm).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 84 of 381 in other circumstances, the risk could also be greater. 17 When developing an upper-bound estimate of risk and to provide risk values that do not underestimate risk, health-protective default approaches are generally used. To err on the side of ensuring adequate health-protection, the EPA typically uses the upper bound estimates rather than lower bound or central tendency estimates in our risk assessments, an approach that may have limitations for other uses (e.g., priority-setting or expected benefits analysis). Chronic non-cancer RfC and reference dose (RfD) values represent chronic exposure levels that are intended to be health-protective levels. Specifically, these values provide an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure (RfC) or a daily oral exposure (RfD) to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. To derive values that are intended to be “without appreciable risk,” the methodology relies upon an uncertainty factor (UF) approach (U.S. EPA, 1993, 1994) which considers uncertainty, variability and gaps in the available data. The UF are applied to derive reference values that are intended to protect against appreciable risk of

17 An exception to this is the URE for benzene, which is considered to cover a range of values, each end of which is considered to be equally plausible, and which is based on maximum likelihood estimates.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 85 of 381 deleterious effects. The UF are commonly default values, 18 e.g., factors of 10 or 3, used in the absence of compound-specific data; where data are available, UF may also be developed using compound-specific information. When data are limited, more assumptions are needed and more UF are used. Thus, there may be a greater tendency to overestimate risk in the sense that further study might support development of reference values that are higher (i.e., less potent) because fewer default assumptions are needed. However, for some pollutants, it is possible that risks may be underestimated. While collectively termed “UF,” these factors account for a number of different quantitative considerations when using observed animal (usually rodent) or human toxicity data in the development of the RfC. The UF are intended to account for: (1) variation in susceptibility among the members of the human population (i.e., inter-individual variability); (2) uncertainty

18 According to the NRC report, Science and Judgment in Risk Assessment (NRC, 1994) “[Default] options are generic approaches, based on general scientific knowledge and policy judgment, that are applied to various elements of the risk assessment process when the correct scientific model is unknown or uncertain.” The 1983 NRC report, Risk Assessment in the Federal Government: Managing the Process, defined default option as “the option chosen on the basis of risk assessment policy that appears to be the best choice in the absence of data to the contrary” (NRC, 1983a, p. 63). Therefore, default options are not rules that bind the Agency; rather, the Agency may depart from them in evaluating the risks posed by a specific substance when it believes this to be appropriate. In keeping with EPA’s goal of protecting public health and the environment, default assumptions are used to ensure that risk to chemicals is not underestimated (although defaults are not intended to overtly overestimate risk). See EPA, 2004, An Examination of EPA Risk Assessment Principles and Practices, EPA/100/B–04/001 available at: http://www.epa.gov/osa/pdfs/ratf-final.pdf.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 86 of 381 in extrapolating from experimental animal data to humans (i.e., interspecies differences); (3) uncertainty in extrapolating from data obtained in a study with less-than-lifetime exposure (i.e., extrapolating from sub-chronic to chronic exposure); (4) uncertainty in extrapolating the observed data to obtain an estimate of the exposure associated with no adverse effects; and (5) uncertainty when the database is incomplete or there are problems with the applicability of available studies. Many of the UF used to account for variability and uncertainty in the development of acute reference values are quite similar to those developed for chronic durations, but they more often use individual UF values that may be less than 10.The UF are applied based on chemical-specific or health effectspecific information (e.g., simple irritation effects do not vary appreciably between human individuals, hence a value of 3 is typically used), or based on the purpose for the reference value (see the following paragraph). The UF applied in acute reference value derivation include: (1) heterogeneity among humans; (2) uncertainty in extrapolating from animals to humans; (3) uncertainty in lowest observable adverse effect (exposure) level to no observed adverse effect (exposure) level adjustments; and (4) uncertainty in accounting for an incomplete database on toxic effects of potential concern. Additional adjustments are often applied to account for uncertainty in***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 87 of 381 extrapolation from observations at one exposure duration (e.g., 4 hours) to derive an acute reference value at another exposure duration (e.g., 1 hour). Not all acute reference values are developed for the same purpose and care must be taken when interpreting the results of

an acute assessment of human health effects relative to the reference value or values being exceeded. Where relevant to the estimated exposures, the lack of short-term dose-response values at different levels of severity should be factored into the risk characterization as potential uncertainties. Although every effort is made to identify appropriate human health effect dose-response assessment values for all pollutants emitted by the sources in this risk assessment, some HAP emitted by these source categories are lacking dose-response assessments. Accordingly, these pollutants cannot be included in the quantitative risk assessment, which could result in quantitative estimates understating HAP risk. To help to alleviate this potential underestimate, where we conclude similarity with a HAP for which a dose-response assessment value is available, we use that value as a surrogate for the

assessment of the HAP for which no value is available. To the extent use of surrogates indicates appreciable risk, we may identify a need to increase priority for new IRIS assessment of that substance. We additionally note that, generally speaking,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 88 of 381 HAP of greatest concern due to environmental exposures and hazard are those for which dose-response assessments have been performed, reducing the likelihood of understating risk. Further, HAP not included in the quantitative assessment are assessed qualitatively and considered in the risk characterization that informs the risk management decisions, including with regard to consideration of HAP reductions achieved by various control options. For a group of compounds that are unspeciated (e.g., glycol ethers), we conservatively use the most protective reference value of an individual compound in that group to estimate risk. Similarly, for an individual compound in a group (e.g., ethylene glycol diethyl ether) that does not have a specified reference value, we also apply the most protective reference value from the other compounds in the group to estimate risk. e. Uncertainties in the Multipathway AssessmentFor each source category, we generally rely on sitespecific levels of PB-HAP emissions to determine whether a refined assessment of the impacts from multipathway exposures isnecessary. This determination is based on the results of a twotiered screening analysis that relies on the outputs from models that estimate environmental pollutant concentrations and human exposures for four PB-HAP. Two important types of uncertainty

associated with the use of these models in RTR risk assessments***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 89 of 381 and inherent to any assessment that relies on environmental modeling are model uncertainty and input uncertainty. 19 Model uncertainty concerns whether the selected models are appropriate for the assessment being conducted and whether they adequately represent the actual processes that might occur for that situation. An example of model uncertainty is the question of whether the model adequately describes the movement of a pollutant through the soil. This type of uncertainty is difficult to quantify. However, based on feedback received from previous EPA SAB reviews and other reviews, we are confidentthat the models used in the screen are appropriate and state-ofthe-art for the multipathway risk assessments conducted in support of RTR. Input uncertainty is concerned with how accurately the models have been configured and parameterized for the assessment at hand. For Tier I of the multipathway screen, we configured the models to avoid underestimating exposure and risk. This wasaccomplished by selecting upper-end values from nationallyrepresentative data sets for the more influential parameters in the environmental model, including selection and spatial configuration of the area of interest, lake location and size,

19 In the context of this discussion, the term “uncertainty” as it pertains to exposure and risk encompasses both variability in the range of expected inputs and screening results due to existing spatial, temporal, and other factors, as well as uncertainty in being able to accurately estimate the true result.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 90 of 381 meteorology, surface water and soil characteristics and structure of the aquatic food web. We also assume an ingestion exposure scenario and values for human exposure factors that represent reasonable maximum exposures. In Tier II of the multipathway assessment, we refine the model inputs to account for meteorological patterns in the vicinity of the facility versus using upper-end national values and we identify the actual location of lakes near the facility rather than the default lake location that we apply in Tier I. By refining the screening approach in Tier II to account for local geographical and meteorological data, we decrease the

likelihood that concentrations in environmental media are overestimated, thereby increasing the usefulness of the screen. The assumptions and the associated uncertainties regarding the selected ingestion exposure scenario are the same for Tier I and

Tier II. For both Tiers I and II of the multipathway assessment, our approach to addressing model input uncertainty is generally cautious. We choose model inputs from the upper end of the range of possible values for the influential parameters used in the models, and we assume that the exposed individual exhibits ingestion behavior that would lead to a high total exposure. This approach reduces the likelihood of not identifying high risks for adverse impacts.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 91 of 381 Despite the uncertainties, when individual pollutants or facilities do screen out, we are confident that the potential for adverse multipathway impacts on human health is very low. On the other hand, when individual pollutants or facilities do not screen out, it does not mean that multipathway impacts are significant, only that we cannot rule out that possibility and that a refined multipathway analysis for the site might be necessary to obtain a more accurate risk characterization for the source categories.

For further information on uncertainties and the Tier I and II screening methods, refer to the risk document Appendix 4, Technical Support Document for TRIM-Based Multipathway Tiered Screening Methodology for RTR. f. Uncertainties in the Environmental Risk Screening AssessmentFor each source category, we generally rely on sitespecific levels of environmental HAP emissions to perform an environmental screening assessment. The environmental screening assessment is based on the outputs from models that estimate environmental HAP concentrations. The same models, specifically the TRIM.FaTE multipathway model and the AERMOD air dispersion model, are used to estimate environmental HAP concentrations for both the human multipathway screening analysis and for the environmental screening analysis. Therefore, both screening assessments have similar modeling uncertainties.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 92 of 381 Two important types of uncertainty associated with the use of these models in RTR environmental screening assessments—and inherent to any assessment that relies on environmental modeling—are model uncertainty and input uncertainty. 20 Model uncertainty concerns whether the selected models are appropriate for the assessment being conducted and whether they adequately represent the movement and accumulation of environmental HAP emissions in the environment. For example, does the model adequately describe the movement of a pollutant through the soil? This type of uncertainty is difficult to quantify. However, based on feedback received from previous EPA SAB reviews and other reviews, we are confident that the models used in the screen are appropriate and state-of-the-art for the environmental risk assessments conducted in support of our RTR analyses. Input uncertainty is concerned with how accurately the models have been configured and parameterized for the assessment at hand. For Tier I of the environmental screen for PB-HAP, we configured the models to avoid underestimating exposure and risk

to reduce the likelihood that the results indicate the risks are lower than they actually are. This was accomplished by selecting

20 In the context of this discussion, the term “uncertainty,” as it pertains to exposure and risk assessment, encompasses both variability in the range of expected inputs and screening results due to existing spatial, temporal, and other factors, as well as uncertainty in being able to accurately estimate the true result.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 93 of 381 upper-end values from nationally-representative data sets for the more influential parameters in the environmental model, including selection and spatial configuration of the area of interest, the location and size of any bodies of water, meteorology, surface water and soil characteristics and structure of the aquatic food web. In Tier I, we used the maximum facility-specific emissions for cadmium compounds, dioxins/furans, POM, and mercury and each of the media when comparing to ecological benchmarks. This is consistent with the conservative design of Tier I of the screen. In Tier II of the environmental screening analysis for PB-HAP, we refine the model inputs to account for meteorological patterns in the vicinity of the facility versus using upper-end national values, and we identify the locations of water bodies near the facility location. By refining the screening approach in Tier II to account for local geographical and meteorological data, we

decrease the likelihood that concentrations in environmental media are overestimated, thereby increasing the usefulness of the screen. To better represent widespread impacts, the modeled soil concentrations are averaged in Tier II to obtain one average soil concentration value for each facility and for each PB-HAP. For PB-HAP concentrations in water, sediment and fish tissue, the highest value for each facility for each pollutant

is used.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 94 of 381 For the environmental screening assessment for acid gases, we employ a single-tiered approach. We use the modeled air concentrations and compare those with ecological benchmarks. For both Tiers I and II of the environmental screening assessment, our approach to addressing model input uncertainty is generally cautious. We choose model inputs from the upper end of the range of possible values for the influential parameters used in the models, and we assume that the exposed individual exhibits ingestion behavior that would lead to a high total exposure. This approach reduces the likelihood of not identifying potential risks for adverse environmental impacts. Uncertainty also exists in the ecological benchmarks for the environmental risk screening analysis. We established a hierarchy of preferred benchmark sources to allow selection of benchmarks for each environmental HAP at each ecological assessment endpoint. In general, EPA benchmarks used at a programmatic level (e.g., Office of Water, Superfund Program) were used if available. If not, we used EPA benchmarks used in regional programs (e.g., Superfund). If benchmarks were not available at a programmatic or regional level, we used benchmarks developed by other agencies (e.g., NOAA) or by state agencies. In all cases (except for lead, which was evaluated through a comparison to the NAAQS), we searched for benchmarks at the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 95 of 381 following three effect levels, as described in Section III.A.6 of this preamble: 1. A no-effect level (i.e., NOAEL). 2. Threshold-effect level (i.e., LOAEL). 3. Probable effect level (i.e., PEL). For some ecological assessment endpoint/environmental HAP combinations, we could identify benchmarks for all three effect levels, but for most, we could not. In one case, where different agencies derived significantly different numbers to represent a threshold for effect, we included both. In several cases, only a single benchmark was available. In cases where multiple effect levels were available for a particular PB-HAP and assessment endpoint, we used all of the available effect levels to help us

to determine whether risk exists and if the risks could be considered significant and widespread. The EPA evaluated the following seven HAP in the environmental risk screening assessment: cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury), lead compounds, HCl and HF. These seven HAP represent pollutants that can cause adverse impacts for plants and animals either through direct exposure to HAP in the air or through exposure to HAP that is deposited from the air onto soils and surface waters. These seven HAP also represent those HAP for which we can conduct a meaningful environmental risk screening***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 96 of 381 assessment. For other HAP not included in our screening assessment, the model has not been parameterized such that it can be used for that purpose. In some cases, depending on the HAP, we may not have appropriate multipathway models that allow us to predict the concentration of that pollutant. The EPA acknowledges that other HAP beyond the seven HAP that we are evaluating may have the potential to cause adverse environmental effects and, therefore, the EPA may evaluate other relevant HAP in the future, as modeling science and resources allow.

Further information on uncertainties and the Tier I and II environmental screening methods is provided in Appendix 5 of the document Technical Support Document for TRIM-Based Multipathway Tiered Screening Methodology for RTR: Summary of Approach and Evaluation. Also, see the Draft Residual Risk Assessment for Petroleum Refining Source Sector, available in the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682). B. How did we consider the risk results in making decisions for this proposal? As discussed in Section II.A.1 of this preamble, in evaluating and developing standards under CAA Section 112(f)(2), we apply a two-step process to address residual risk. In the first step, the EPA determines whether risks are acceptable. This determination “considers all health information, including risk estimation uncertainty, and includes a presumptive limit on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 97 of 381 maximum individual lifetime [cancer] risk (MIR) 21 of approximately [1-in-10 thousand] [i.e., 100-in-1 million].” 54 FR 38045. If risks are unacceptable, the EPA must determine the emissions standards necessary to bring risks to an acceptable level without considering costs. In the second step of the process, the EPA considers whether the emissions standards provide an ample margin of safety “in consideration of all health information, including the number of persons at risk levels higher than approximately 1-in-1 million, as well as other relevant factors, including costs and economic impacts, technological feasibility, and other factors relevant to each particular decision.” Id. The EPA must promulgate tighter emission standards if necessary to provide an ample margin of safety. In past residual risk actions, the EPA considered a number

of human health risk metrics associated with emissions from the categories under review, including the MIR, the number of persons in various risk ranges, cancer incidence, the maximum non-cancer HI and the maximum acute non-cancer hazard. See, e.g., 72 FR 25138, May 3, 2007; 71 FR 42724, July 27, 2006. The

EPA considered this health information for both actual and allowable emissions. See, e.g., 75 FR 65068, October 21, 2010,

21 Although defined as “maximum individual risk,” MIR refers only to cancer risk. MIR, one metric for assessing cancer risk, is the estimated risk were an individual exposed to the maximum level of a pollutant for a lifetime.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 98 of 381 and 75 FR 80220, December 21, 2010). The EPA also discussed risk

estimation uncertainties and considered the uncertainties in the determination of acceptable risk and ample margin of safety in these past actions. The EPA considered this same type of information in support of this action. The agency is considering these various measures of health information to inform our determinations of risk acceptability and ample margin of safety under CAA Section 112(f). As explained in the Benzene NESHAP, “the first step of judgment on acceptability cannot be reduced to any single factor,” and thus “[t]he Administrator believes that the acceptability of risk under [previous] Section 112 is best judged on the basis of a

broad set of health risk measures and information.” 54 FR 38046. Similarly, with regard to making the ample margin of safety determination, “the Agency again considers all of the health risk and other health information considered in the first step. Beyond that information, additional factors relating to the appropriate level of control will also be considered, including cost and economic impacts of controls, technological feasibility, uncertainties, and any other relevant factors.” Id. The Benzene NESHAP approach provides flexibility regarding factors the EPA may consider in making determinations and how the EPA may weigh those factors for each source category. In***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 99 of 381 responding to comment on our policy under the Benzene NESHAP, the EPA explained that: “[t]he policy chosen by the Administrator permits consideration of multiple measures of health risk. Not only can the MIR figure be considered, but also incidence, the presence of non-cancer health effects, and the uncertainties of the risk estimates. In this way, the effect on the most exposed individuals can be reviewed as well as the impact on the general public. These factors can then be weighed in each individual case. This approach complies with the Vinyl Chloride mandate that the Administrator ascertain an acceptable level of risk to the public by employing [her] expertise to assess available data. It also complies with the Congressional intent behind the CAA, which did not exclude the use of any particular measure of public health risk from the EPA’s consideration with respect to CAA Section 112 regulations, and thereby implicitly permits consideration of any and all measures of health risk which the Administrator, in [her] judgment, believes are appropriate to determining what will ‘protect the public health.’” 54 FR at 38057. Thus, the level of the MIR is only one factor to be weighed in determining acceptability of risks. The Benzene NESHAP explained that “an MIR of approximately one in 10 thousand should ordinarily be the upper end of the range of acceptability. As risks increase above this benchmark, they become presumptively less acceptable under CAA Section 112, and would be weighed with the other health risk measures and information in making an overall judgment on acceptability. Or, the Agency may find, in a particular case, that a risk that includes MIR less than the presumptively acceptable level is unacceptable in the light of other health risk factors.” Id. at 38045. Similarly, with regard to the ample margin of safety***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 100 of 381 analysis, the EPA stated in the Benzene NESHAP that: “EPA believes the relative weight of the many factors that can be considered in selecting an ample margin of safety can only be determined for each specific source category. This occurs mainly because technological and economic factors (along with the health-related factors) vary from source category to source category.” Id. at 38061. We also consider the uncertainties associated with the various risk analyses, as discussed earlier in this preamble, in our determinations of acceptability and ample margin of safety.

The EPA notes that it has not considered certain health information to date in making residual risk determinations. At this time, we do not attempt to quantify those HAP risks that may be associated with emissions from other facilities that do not include the source categories in question, mobile source emissions, natural source emissions, persistent environmental pollution or atmospheric transformation in the vicinity of the sources in these categories. The agency understands the potential importance of considering an individual’s total exposure to HAP in addition to considering exposure to HAP emissions from the source category and facility. We recognize that such consideration may be particularly important when assessing non-cancer risks, where pollutant-specific exposure health reference levels (e.g., RfCs)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 101 of 381 are based on the assumption that thresholds exist for adverse health effects. For example, the agency recognizes that, although exposures attributable to emissions from a source category or facility alone may not indicate the potential for

increased risk of adverse non-cancer health effects in a population, the exposures resulting from emissions from the facility in combination with emissions from all of the other sources (e.g., other facilities) to which an individual is exposed may be sufficient to result in increased risk of adverse non-cancer health effects. In May 2010, the SAB advised the EPA

“that RTR assessments will be most useful to decision makers and communities if results are presented in the broader context of aggregate and cumulative risks, including background

concentrations and contributions from other sources in the

area.” 22 In response to the SAB recommendations, the EPA is incorporating cumulative risk analyses into its RTR risk assessments, including those reflected in this proposal. The agency is: (1) conducting facility-wide assessments, which include source category emission points as well as other emission points within the facilities; (2) considering

22 EPA’s responses to this and all other key recommendations of the SAB’s advisory on RTR risk assessment methodologies (which is available at: http://yosemite.epa.gov/sab/sabproduct.nsf/4AB3966E263D943A8525771F00668381/$ File/EPA-SAB-10-007-unsigned.pdf) are outlined in a memo to this rulemaking docket from David Guinnup entitled, EPA’s Actions in Response to the Key Recommendations of the SAB Review of RTR Risk Assessment Methodologies.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 102 of 381 overlapping sources in the same category; and (3) for some persistent and bioaccumulative pollutants, analyzing the ingestion route of exposure. In addition, the RTR risk assessments have always considered aggregate cancer risk from all carcinogens and aggregate non-cancer hazard indices from all non-carcinogens affecting the same target organ system. Although we are interested in placing source category and facility-wide HAP risks in the context of total HAP risks from all sources combined in the vicinity of each source, we are concerned about the uncertainties of doing so. Because of the

contribution to total HAP risk from emission sources other than those that we have studied in depth during this RTR review, such estimates of total HAP risks would have significantly greaterassociated uncertainties than the source category or facilitywide estimates. Such aggregate or cumulative assessments would compound those uncertainties, making the assessments too

unreliable. C. How did we perform the technology review? Our technology review focused on the identification and evaluation of developments in practices, processes and control technologies that have occurred since the MACT standards were promulgated. Where we identified such developments, in order to inform our decision of whether it is “necessary” to revise the emissions standards, we analyzed the technical feasibility of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 103 of 381 applying these developments, and the estimated costs, energy implications, non-air environmental impacts, as well as considering the emission reductions. We also considered the appropriateness of applying controls to new sources versus retrofitting existing sources. Based on our analyses of the available data and information, we identified potential developments in practices, processes and control technologies. For this exercise, we considered any of the following to be a “development”:

 Any add-on control technology or other equipment that was not identified and considered during development of the original MACT standards.

 Any improvements in add-on control technology or other equipment (that were identified and considered during development of the original MACT standards) that could result in additional emissions reduction.

 Any work practice or operational procedure that was not identified or considered during development of the original MACT standards.

 Any process change or pollution prevention alternative that could be broadly applied to the industry and that was not identified or considered during development of the original MACT standards.

 Any significant changes in the cost (including cost effectiveness) of applying controls (including controls the EPA considered during the development of the original MACT standards). We reviewed a variety of data sources in our investigation of potential practices, processes or controls to consider. Among

the sources we reviewed were the NESHAP for various industries***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 104 of 381 that were promulgated since the MACT standards being reviewed in this action. We reviewed the regulatory requirements and/or technical analyses associated with these regulatory actions to identify any practices, processes and control technologies considered in these efforts that could be applied to emission sources subject to Refinery MACT 1 or 2, as well as the costs, non-air impacts and energy implications associated with the use of these technologies. Additionally, we requested information from facilities as described in Section II.C of this preamble. Finally, we reviewed information from other sources, such asstate and/or local permitting agency databases and industrysupported databases. **IV. Analytical Results and Proposed Decisions** A. What actions are we taking pursuant to CAA Sections 112(d)(2) and 112(d)(3)? In this action, we are proposing the following revisions to the Refinery MACT 1 and 2 standards pursuant to CAA Section 112(d)(2) and (3) 23 : (1) adding MACT standards for DCU decoking operations; (2) revising the CRU purge vent pressure exemption;

23 The EPA has authority under section 112(d)(2) and (d)(3) to set MACT standards for previously unregulated emission points. EPA also retains the discretion to revise a MACT standard under the authority of section 112(d)(2) and (3), see Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011), such as when it identifies an error in the original standard. See also Medical Waste Institute v. EPA, 645 F. 3d at 426 (upholding EPA action establishing MACT floors, based on post-compliance data, when originally-established floors were improperly established).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 105 of 381 (3) adding operational requirements for flares used as air pollution control devices (APCD) in Refinery MACT 1 and 2; and (4) adding requirements and clarifications for vent control bypasses in Refinery MACT 1. The results and proposed decisions based on the analyses performed pursuant to CAA Section 112(d)(2) and (3) are presented below. 1. Delayed Coking Units a. Description of Delayed Coker Process Operations and Emissions We are proposing to establish MACT standards specific to the DCU pursuant to CAA Section 112(d)(2) and (3). The DCU uses thermal cracking to upgrade heavy feedstocks and to produce petroleum coke. Unlike most other refinery operations that are continuous, the DCU operates in a semi-batch system. Most DCU consist of a large process heater, two or more coking drums, and a single product distillation column. The DCU feed is actually

fed to the unit’s distillation column. Bottoms from the distillation column are heated to near cracking temperatures and the resulting heavy oil is fed to one of the coking drums. As the cracking reactions occur, coke is produced in the drum and begins to fill the drum with sponge-like solid coke material. During this process, the DCU is a closed system, with the produced gas streams piped to the unit’s distillation column for product recovery.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 106 of 381 When the first coke drum becomes filled with coke, the feed is diverted to the second coke drum and processing continues via the second coke drum. The full coke drum, which is no longer receiving oil feed, is taken through a number of steps, collectively referred to as decoking operations, to remove the coke from the drum and prepare the drum for subsequent oil feed processing. The decoking steps include: purging, cooling/quenching, venting, draining, deheading, and coke cutting. A description of these steps and the potential emissions from these activities are provided in the next several paragraphs. Once the coke is removed, the vessel is re-sealed (i.e., the drain valve is closed and the “head” is re-attached), pressure tested (typically using steam), purged to remove oxygen, then slowly heated to processing temperatures so it can go back on-line. When the second coke drum becomes filled with coke, feed is diverted back to the first coke drum and the second drum is then decoked. In this manner, the DCU allows for continuous processing of oil even though the individual coke drums operate in cyclical batch fashion. The first step in decoking operations is to purge the coke

drum with steam. This serves to cool the coke bed and to flush oil or reaction products from the coke bed. The steam purge is initially sent to the product distillation column and then diverted to the unit’s blowdown system. The blowdown system***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 107 of 381 serves to condense the steam and other liquids entrained in the steam. Nearly all DCU operate a ”closed blowdown” system, such that uncondensed gases from the blowdown system are sent to the product distillation column or the facility’s light gas plant, recovered as fuel gas, or combusted in a flare. In an open blowdown system, these uncondensed gases would be vented directly to atmosphere. The DCU vent discharge to the blowdown system is specifically defined in Refinery MACT 1 as the “delayed coker vent.” The next step in the decoking process is cooling/quenching the coke drum and its contents via the addition of water, commonly referred to as quench water, at the bottom of the coke drum. The water added to the vessel quickly turns to steam due to the high temperature of the coke bed. The water/steam helps to further cool the coke bed and “quench” any residual coking reactions that may still occur within the hot coke bed. As with the steam purge, steam off-gas from the cooling/quenching cycle is recovered in the unit’s blowdown system and this vent discharge is specifically defined in Refinery MACT 1 as the “delayed coker vent.” After several hours, the coke drum is sufficiently cooled so that the water level in the drum can be raised to entirely cover the coke bed. Although water covers the coke bed, the upper portion of the coke bed may still be well above 212***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 108 of 381 degrees Fahrenheit (°F) and will continue to generate steam. In fact, since the coke drum vessel pressure is greater than atmospheric pressure, the equilibrium boiling point of water in the vessel is greater than 212 °F. Therefore, the water at the top of the coke drum is typically well above 212 °F (superheated water). As the coke drum and its contents continue to cool from the evaporative cooling effect of the steam generation, the steam generation rate and the pressure within the vessel will

decrease. Owners or operators of DCU may use different indicators or set points to determine when the system has cooled sufficiently to move to the venting step; however, one of the most common indicators monitored is the pressure of the coke drum vessel (or steam vent line just above the coke drum, where steam exits the coke drum en route to the blowdown system). When the vessel has cooled sufficiently (e.g., when the coke drum vessel pressure reaches the desired set point), valves are opened to allow the steam generated in the coke drum to vent directly to the atmosphere rather than the closed blowdown system. This vent is commonly referred to as the “coker steam vent” and is typically the first direct atmospheric emission release during the decoking operations when an enclosed blowdown system is used. While this vent gas contains predominately steam, methane and ethane, a variety of HAP are also emitted with this steam. These***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 109 of 381 HAP include light aromatics (e.g., benzene, toluene, and xylene) and light POM (predominately naphthalene and 2-methyl naphthalene). The level of HAP emitted from the DCU has been found to be a function of the quantity of steam generated (see the technical memorandum entitled Impacts Estimates for Delayed Coking Units in Docket ID Number EPA-HQ-OAR-2010-0682). In general, the next step in the decoking process is draining the water from the coke drum by opening a large valve at the bottom of the coke drum. The drain water typically falls from the coke drum onto a slanted concrete pad that directs the water to the coke pit area (where water and coke are collected and separated). Some DCU owners or operators initiate draining at the same time they initiate venting; other owners or operators may allow the vessel to vent for 20 or more minutes prior to initiating draining. While draining immediately may reduce the amount of steam exiting the unit via the stack, as explained below, it is not expected to alter the overall emissions from the unit. During the venting and draining process, the pressure of the system falls to atmospheric. Steam will be generated until the evaporative cooling effect of that steam generation cools the coker quench water to 212 °F. If draining is initiated immediately, some of the superheated water may drain from the DCU before being cooled. A portion of that drained water will then flash to steam during the draining***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 110 of 381 process as that superheated water contacts the open atmosphere. Therefore, draining quickly is not expected to alter the total amount of steam generated from the unit nor alter the overall emissions from the unit. It will, however, alter the relative proportion of the emissions that are released via the vent versus the quench water drain area. The next step in the decoking process is “deheading” the coke drum. At the top of the coke drum is a large 3- to 5-foot diameter opening, which is sealed with a gasketed lid during normal operations. When the steam generation rate from the coke drum has sufficiently subsided, this gasketed lid is removed to

allow access for a water drill that will be used to remove coke from the drum. The process of removing this lid is referred to as “deheading” the coke drum. Different DCU owners or operators may use different criteria for when to dehead the coke drum. If the coke drum is deheaded soon after venting is initiated, some steam and associated HAP emissions may be released from this opening. As with draining, it is anticipated that the total volume of steam generated will be a function of the temperature/pressure of the coke drum. Deheading the coke drum prior to the coke drum contents reaching 212 °F will generally

mean that some of the steam will be released from the coke drum head opening. However, this will not alter the total amount of steam generated; it merely alters the location of the release***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 111 of 381 (coke drum head opening versus steam vent). The HAP emissions from the deheading process are expected to be proportional to

the amount of steam released in the same manner as the emissions

from the steam vent. The final step of the decoking process is coke cutting. A high-pressure water jet is used to drill or cut the coke out of the vessel. The drilling water and coke slurry exits the coke drum via the drain opening and collects in the coke pit. Generally, the coke drum and its contents are sufficiently cooled so that this process is not expected to yield significant HAP emissions. However, if the other decoking steps are performed too quickly, hot spots may exist within the coke bed and HAP emissions may occur as water contacts these hot spots

and additional steam and emissions are released. Once the coke is cut out of the drum, the drum is closed and prepared to go back on-line. This process includes pressurizing with steam to ensure there are no leaks (i.e., that the head is properly attached and sealed and the drain valve is fully closed). The vessel is then purged to remove any oxygen and heated by diverting the produced gas from the processing coke drum through the empty drum prior to sending it to the unit’s distillation column. A coke drum cycle is typically 28 to

36 hours from start of feed to start of the next feed.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 112 of 381 b. How Delayed Coker Vents are Addressed in Refinery MACT 1 Delayed coker vents are specifically mentioned as an example within the first paragraph of the definition of “miscellaneous process vent” in Refinery MACT 1. However, the definition of miscellaneous process vent later excludes: “Coking unit vents associated with coke drum depressuring at or below a coke drum outlet pressure of 15 pounds per square inch gauge [psig], deheading, draining, or decoking (coke cutting) or pressure testing after decoking” (see 40 CFR 63.641). According to Refinery MACT 1, “[d]elayed coker vent means a vent that is typically intermittent in nature, and usually occurs only during the initiation of the depressuring cycle of the decoking operation when vapor from the coke drums cannot be sent to the fractionator column for product recovery, but instead is routed to the atmosphere through a closed blowdown system or directly to the atmosphere in an open blowdown system. The emissions from the decoking phases of DCU operations, which include coke drum deheading, draining, or decoking (coke cutting), are not considered to be delayed coker vents” (see 40 CFR 63.641). The first paragraph of the definition of “miscellaneous process vent” also includes blowdown condensers/accumulators as an example of a miscellaneous process vent. Therefore, the DCU blowdown system is a miscellaneous process vent regardless of whether or not the blowdown system is associated with a DCU or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 113 of 381 another process unit. Further, the inclusion of the “delayed coker vent” as an example of a miscellaneous process vent makes it clear that the DCU’s blowdown system vent (if an open blowdown system is used) is considered a miscellaneous process vent. It is less clear from the regulatory text whether the direct venting of the coke drum to the atmosphere via the steam vent during the final depressurization is considered to be a “delayed coker vent” (i.e., whether direct venting to the atmosphere is equivalent to venting “directly to the atmosphere in an open blowdown system”). The regulatory text is clear that this steam vent is exempt from the definition of “miscellaneous process vent” when the pressure of the vessel is less than 15 psig. It is also clear that the subsequent release points from the decoking operations (i.e., deheading, draining, and coke cutting) are excluded from both the definition of “delayed coker vent” and the definition of “miscellaneous process vent.” Further, based on the statements in the background information document for the August 1995 final Refinery MACT 1 rule, 24 the 15 psig pressure limit for the direct venting of the DCU to the atmosphere was not established as a MACT floor control level; it was established to accommodate all DCU at whatever pressure they typically switched

24 National Emission Standards for Hazardous Air Pollutants Petroleum Refineries - Background Information for Final Standards; EPA-453/R-95-015b.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 114 of 381 from venting to the closed blowdown system to venting directly to the atmosphere. Based on this information, as well as the data from the 2011 Refinery ICR, refinery enforcement settlements and other information available, which indicate that all refineries depressurize the coke drum below 15 psig, we have determined that the direct atmospheric releases from the DCU decoking operations are currently unregulated emissions. These unregulated releases include emissions during atmospheric depressuring (i.e., the steam vent), deheading, draining, and coke cutting. c. Evaluation of MACT Emission Limitations for Delayed Coking

Units We evaluated emissions and controls during DCU decoking operations in order to identify appropriate MACT emission limitations pursuant to CAA Section 112(d)(2) and (3). Establishing a lower pressure set point at which a DCU owner or operator can switch from venting to an enclosed blowdown system to venting to the atmosphere is the control technique identified for reducing emissions from delayed coking operations. Essentially, there is a fixed quantity of steam that will be generated as the coke drum and its contents cool. The lower pressure set point will require the DCU to vent to the closed blowdown system longer, where the organic HAP can be recovered***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 115 of 381 or controlled. This will result in fewer emissions released during the venting, draining and deheading process. We consider this control technique, which is a work practice standard, appropriate for the DCU for the reasons discussed below for each of the four possible emission points at the DCU: draining, deheading, coke cutting and the steam vent. For the first three steps, the emissions cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant. For example, during draining, the drain water typically falls from the coke drum onto a slanted concrete pad that directs the water to an open coke pit area (where water and coke are collected and separated). When the coke drum is deheaded, the coke drum head must be removed to provide an accessible opening in the drum so the coke cutting equipment can be lowered into the drum. This opening cannot be sealed during coke cutting because the drilling shaft will occupy the opening and the shaft must be free to be lowered or raised during the coke cutting process. While the emissions from the fourth point, the DCU steam vent, are released via a conveyance designed and constructed to emit or capture such pollutant, as provided in CAA Section 112(h)(2)(B), it is not feasible to prescribe or enforce an emission standard for the DCU steam vent because the application***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 116 of 381 of a measurement methodology for this source is not practicable due to technological and economic limitations. First, it is not practicable to use a measurement methodology for the DCU steam vent. The emissions from the vent typically contain 99-percent water, which interferes with common sample collection and analysis techniques. Also, the flow rate from this vent is not constant; rather, it decreases during the venting process as the pressure in the DCU coke drum approaches atmospheric pressure. Additionally, the venting time can be very short. As part of the ICR, we requested stack testing of eight DCU. After discussions with stack testing experts within the agency and with outside contractors used by industry to perform the tests, we concluded that sources with venting times less than 20 minutes would not be able to perform an emissions test that would yield valid results. Therefore, only two of the eight facilities actually performed the tests. We anticipate all units complying with the proposed standards for DCU steam vents would

vent for less than 20 minutes. Second, it is not feasible to enforce an emission standard only on the steam vent because the timing of drainage and deheading can alter the portion of the decoking emissions that are released from the actual steam vent. If draining and deheading are initiated quickly after venting, this will reduce the emissions discharged from the vent (although as explained***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 117 of 381 above, it does not reduce the emissions from the collective set of decoking operations release points). Consequently, due to the unique nature of DCU emissions, the difficulties associated with monitoring the DCU steam vent, and the inability to construct a conveyance to capture emissions from all decoking release points, we are proposing that it is appropriate to develop work practice standards in place of

emission limits for the DCU. We then reviewed regulations, permits and consent decrees that require coke controls to establish the MACT floor. Refinery NSPS Ja establishes a pressure limit of 5 psig prior to allowing the coke drum to be vented to the atmosphere. Based on a review of permit limits and consent decrees, we found that coke drum vessel pressure limits have been established (and achieved) as low as 2 psig. There are 75 operating DCU according to the Refinery ICR responses, so the sixth percentile is represented by the fifth-best performing DCU. We identified eight DCU with permit requirements or consent decrees specifying a coke drum venting pressure limit of 2 psig; we did not identify any permit or consent decree requirements more stringent than 2 psig. Refinery owners and operators were asked to provide the “typical coke drum pressure just prior to venting” for each DCU in their responses to the Refinery ICR, and the responses indicate that four DCU operate such that the typical venting pressure is 1***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 118 of 381 psig or less. However, this “typical coke drum pressure” does not represent a not-to-be-exceeded pressure limit; it is expected that these units are operated this way to meet a pressure limit of 2 psig. We do not have information to indicate whether these facilities are always depressurized at 1 psig or less. Moreover, there were only four units for which a typical venting pressure of 1 psig was identified and the MACT floor is represented by the fifth-best operating DCU. Therefore, we are proposing that the MACT floor for DCU decoking operations is to depressure at 2 psig or less prior to venting to the atmosphere for existing sources. We are also proposing that the MACT floor for new sources is 2 psig, since the best-performing source is permitted to depressure at 2 psig or less. For additional details on the MACT floor analysis, see memorandum entitled MACT Analysis for Delayed Coking Unit Decoking Operations in Docket ID Number EPA-HQ-OAR-2010-0682. We then considered control options beyond the floor level of 2 psig to determine if additional emission reductions could be cost-effectively achieved. We considered establishing a venting pressure limit of 1 psig or less, since four facilities reported in the ICR that the typical coke drum pressure prior to depressurizing was 1 psig. There are several technical difficulties associated with establishing a pressure limit at this lower level. First, the lowest pressure at any point in a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 119 of 381 closed blowdown system is generally designed to be no lower than 0.5 psig. Consequently, the DCU compressor system would operate with an inlet pressure of no less than 0.5 psig. Second, there are several valves and significant piping (for cooling and condensing steam) between the DCU drum and the recovery compressor. There is an inherent pressure drop when a fluid flows through a pipe or valve. Two valves are used for all DCU

lines to make sure that the unit is either blocked off from the processing fluids or blocked in so there are no product losses out the steam line during processing. Considering the need for two valves and piping needed in the cooling system, DCU designed for a minimal pressure loss will generally still have a 0.5 to 1 psig pressure drop between the DCU drum and the recovery compressor inlet, even for a new DCU designed to minimize this pressure drop. Finally, in order to meet a 1 psig pressure limit at all times, the DCU closed vent system would need to be designed to achieve a vessel pressure of approximately 0.5 psig. Given the above considerations, it is not technically feasible for new or existing DCU to routinely achieve a vessel pressure of 0.5 psig in order to comply with a never-to-be-exceeded drum vessel pressure of 1 psig. As noted previously, facilities that “typically” achieve vessel pressures of about 1 psig or less are expected to do so in order to meet a never-to-be-exceeded drum vessel pressure limit of 2 psig and they are not expected to be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 120 of 381 able to comply with a never-to-be-exceeded drum vessel pressure limit of 1 psig. We considered setting additional work practice standards regarding draining, deheading, and coke cutting. The decoking emissions can be released from a variety of locations, and the 2-psig-or-less limit for depressurizing the coke drum will effectively reduce the emissions from all of these emission points, provided that atmospheric venting via the DCU steam vent is the first step in the decoking process. However, it is possible to start draining water prior to opening the steam vent. We are concerned that owners or operators may adopt this practice as a means to reduce pressure in the coke drum prior to venting the drum to the atmosphere. Initiating water draining prior to reaching 2 psig would result in draining water that is hotter than it would be had the drum been sufficiently cooled (i.e., the pressure limit achieved) prior to draining the vessel, effectively diverting HAP emissions to the water drain area rather than capturing these HAP in the enclosed blowdown system, where they can be either recovered or controlled. Therefore, we are proposing that the coke drum must reach 2 psig or less prior to any decoking operations, which includes atmospheric venting, draining, deheading, and coke cutting. We could not identify any other emission reduction options that could lower the emissions from the DCU decoking operations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 121 of 381 Since we could not identify a technically feasible control option beyond the MACT floor, we determined that the MACT floor pressure limit of 2 psig is MACT for existing sources. We also determined that the same technical limitations of going beyond the 2 psig pressure limit for existing sources exist for new sources; therefore we determined that the MACT floor pressure limit of 2 psig is MACT for new sources. We request comment on whether depressurizing to 2 psig prior to venting to the atmosphere is the appropriate MACT floor and whether it is appropriate to include restrictions for the other three decoking operations draining, deheading and coke cutting, in the MACT requirements. We request comments on whether we have adequately interpreted the information that indicates that there is currently no applicable MACT floor for delayed coking. Under a different interpretation, we would evaluate the need to propose delayed coking standards only under the risk and technology review requirements of the Act (i.e., CAA Section 112(f) and 112(d)(6)) as discussed later in this preamble. Finally, we request comment and supporting information on any other practices that may be used to limit emissions during the decoking operations.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 122 of 381 d. Evaluation of Cost and Environmental Impacts of MACT Emission Limitations for Delayed Coking Units DCU that cannot currently meet the 2 psig pressure limit would be expected to install a device (compressor or steam ejector system) to lower the DCU vessel pressure. In the Refinery NSPS Ja impact analysis, facilities not able to meet the pressure threshold were assumed to purchase and install a larger compressor to lower the blowdown system pressure. Other approaches to lowering blowdown system (and coke drum) pressure exist. Specifically, steam ejectors have been identified as a method to help existing units depressurize more fully in order to achieve a set vessel pressure or drum bed temperature. Upgrading the closed vent system to reduce pressure losses or to increase steam condensing capacity may also allow the DCU to depressurize more quickly while the emissions are still vented to the closed blowdown system. This is important because delays in the decoking operations may impact process feed rates. That is, if the decoking and drum preparation steps take too long, the feed rate to the other coke unit must be reduced to prevent overfilling one coke drum prior to being able to switch to the

other coke drum. This issue is less critical for DCU that operate with 3 or 4 drums per distillation column, but a consistent increase in the decoking times across all drums may***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 123 of 381 still limit the capacity of the DCU at some petroleum

refineries. For existing sources, we assumed all DCU that reported a “typical drum pressure prior to venting” of more than 2 psig would install and operate a steam ejector system to reduce the coke drum pressure to 2 psig prior to venting to atmosphere or draining. The operating costs of the steam ejector system are offset, to some extent, by the additional recovered vapors. Vapors from the additional gases routed to the blowdown system contain high levels of methane (approximately 70 percent by volume on a dry basis) based on DCU steam vent test data. If these vapors are directed to the closed blowdown system rather than to the atmosphere, generally the dry gas can be recovered in the refinery fuel gas system or light-ends gas plant. This recovered methane is expected to off-set natural gas purchases for the fuel gas system. For new sources, it is anticipated that the DCU’s closed vent system could be designed to achieve a 2 psig vessel pressure with no significant increase in capital or operating costs. Designing the system to vent at a lower pressure would also result in additional vapor recovery, which is expected to off-set any additional capital costs associated with the low pressure design closed vent system.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 124 of 381 The costs of complying with the 2 psig coke drum threshold prior to venting or draining are summarized in Table 2 of this preamble. The costs are approximately $1,000 per ton of VOC reduced and approximately $5,000 per ton of organic HAP reduced when considering VOC and methane recovery credits. **Table 2. Nationwide Emissions Reduction and Cost Impacts of Control Option for Delayed Coking Units at Petroleum Refineries** 

**Control Option**  **Capital Cost**  **(million $)**  **Annual ized**  **Costs Without**  **Recovery Credits**  **(million**

**$/yr) Emis**  **s ions** **Reduc tion, VOC**  **(tpy) Emis**  **s ions** **Reduc t**  **ion, HAP (tpy)**  **Cost Effec**  **tive n**  **ess**

**($/ton**

**HAP) Total** **Annual**

**ized Costs**  **w ith VOC**  **R ecovery** 

**Credit (**  **million**

**$/yr) Overall**  **Cost Effective**  **ness with VOC**  **Recovery**

**Credit ($/ton** 

**HAP)** 2 psig 52 10.2 4,250 850 12,000 3.98 4,700

2. CRU Vents A CRU is designed to reform (i.e., change the chemical structure of) naphtha into higher-octane aromatics. Over time, coke deposits form on the reforming catalyst, which reduces the catalyst activity. When catalyst activity is reduced to a certain point, the catalyst is regenerated by burning the coke off of the catalyst. Prior to this coke burn-off process, the catalyst (or reactor vessel containing the catalyst) must be removed from active service and organics remaining on the catalyst (or in the reactor) must be purged from the system. This is generally accomplished by depressurizing the vessel to a certain vessel pressure, then re-pressurizing the vessel with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 125 of 381nitrogen and depressurizing the vessel again. The repressurization and depressurization process is repeated several times until all organics have been purged from the system. The organic HAP emissions from this depressurization/purge cycle vent are typically controlled by directing the purge gas directly to the CRU process heater or venting the gas to a

flare. Refinery MACT 2 requires a 98-percent reduction of organic HAP measured as total organic carbon (TOC) or non-methane TOC or an outlet concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-percent oxygen), whichever is less stringent, for this CRU depressurization/purge cycle vent (purging prior to coke-burn-off). The emission limits for organic HAP for the CRU do not apply to emissions from process vents during depressuring and purging operations when the reactor vent pressure is 5 psig or less. The Refinery MACT 2 requirements were based on the typical operation of CRU utilizing sequential pressurization and passive depressurization. The 5 psig pressure limit exclusion was provided based on state permit conditions, which recognized that depressurization to an APCD (without other active motive of flow) is limited by the back pressure of the control system, which is often a flare or process heater. Source testing information collected from the 2011 Refinery ICR indicates that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 126 of 381 facilities could interpret the rule to allow the 5 psig pressure limit exclusion to be used by units using active purging techniques (such as continuous nitrogen purge or vacuum pump on the CRU reactor at low pressures) to discharge to the atmosphere

without emission controls. The information collected indicates that HAP emissions from a continuous, active purging technique could result in emissions of HAP from CRU depressurization vents much higher than expected to be allowed under the Refinery MACT 2 requirements, which presumed sequential re-pressurization and purging cycles. The testing information received indicated that at one facility, the active purge vent had non-methane TOC concentrations of 700 to 10,000 ppmv (dry basis, as hexane, corrected to 3-percent oxygen) compared to less than 10 ppmv for the typical passive purge vent tested. The annual HAP emissions for the CRU with the active purge vent were estimated to exceed10 tpy, while a comparable unit using the cyclic repressurization and passive depressurization purge technique is projected to have HAP emissions of less than 0.1 tpy. Therefore, we are proposing to amend the exclusion in 40 CFR 63.1566(a)(4) to clarify the application of the 5 psig exclusion, consistent with the MACT floor under CAA Section 112(d)(2) and (3). Specifically, we are limiting the vessel pressure limit exclusion to apply only to passive vessel depressurization. Units utilizing active purging techniques have***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 127 of 381 a motive of flow that can be used to direct the purge gas to a control system, regardless of the CRU vessel pressure. If a CRU owner or operator uses active purging techniques (e.g., a continual nitrogen purge) or active vessel depressurization (e.g., vacuum pump), then the 98-percent reduction or 20 ppmv TOC emission limits would apply to these discharges regardless of the vessel pressure. 3. Refinery Flares The EPA is proposing under CAA Section 112(d)(2) and (3) to amend the operating and monitoring requirements for petroleum refinery flares. We have determined that the current requirements for flares are not adequate to ensure compliance with the Refinery MACT standards. In the development of Refinery MACT 1, the EPA determined that the average emission limitation achieved by the best-performing 12 percent of existing sources

was established as the use of combustion controls for miscellaneous process vents. Further, the EPA stated that “data analyses conducted in developing previous NSPS and the [National Emission Standards for Organic Hazardous Air Pollutants (40 CFR part 63, subparts F, G, and H)] HON determined that combustion controls can achieve 98-percent organic HAP reduction or an outlet organic HAP concentration of 20 ppmv for all vent streams” (59 FR 36139, July 15, 1994). The requirements applicable to flares at refineries are set forth in the General***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 128 of 381 Provisions to 40 CFR part 63 and are cross-referenced in Refinery MACT 1 and 2. In general, flares used as APCD were expected to achieve 98-percent HAP destruction efficiencies when designed and operated according to the requirements in the General Provisions. Recent studies on flare performance, however, indicate that these General Provisions requirements are inadequate to ensure proper performance of refinery flares, particularly when assist steam or assist air is used. Over the last decade, flare minimization efforts at petroleum refineries have led to an increasing number of flares operating at well below their design capacity, and while this effort has resultedin reduced flaring of gases at refineries, situations of overassisting with steam or air have become exacerbated, leading to the degradation of flare combustion efficiency. Therefore, these amendments are necessary to ensure that refineries that use

flares as APCD meet the MACT standards at all times when controlling HAP emissions. Refinery MACT 1 and 2 require flares used as an APCD to meet the operational requirements set forth in the General Provisions at 40 CFR 63.11(b). These General Provisions requirements specify that flares shall be: (1) steam-assisted, air-assisted, or non-assisted; (2) operated at all times when emissions may be vented to them; (3) designed for and operated with no visible emissions (except for periods not to exceed a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 129 of 381 total of 5 minutes during any 2 consecutive hours); and (4) operated with the presence of a pilot flame at all times. The General Provisions also specify requirements for both the minimum heat content of gas combusted in the flare and maximum exit velocity at the flare tip. The General Provisions only specify monitoring requirements for the presence of the pilot flame and the operation of a flare with no visible emissions. For all other operating limits, Refinery MACT 1 and 2 require an initial performance evaluation to demonstrate compliance but there are no specific monitoring requirements to ensure continuous compliance. As noted previously, flare performance tests conducted over the past few years suggest that the current regulatory requirements are insufficient to ensure that refinery flares are operating consistently with the 98-percent HAP

destruction efficiencies that we determined were the MACT floor. In 2012, the EPA compiled information and test data collected on flares and summarized its preliminary findings on operating parameters that affect flare combustion efficiency (see technical report, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). The EPA submitted the report, along with a charge statement and a set of charge questions to an external peer review panel. The panel concurred with the EPA’s assessment that three primary factors affect flare performance: (1) the flow of the vent gas***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 130 of 381 to the flare; (2) the amount of assist media (e.g., steam or air) added to the flare; and (3) the combustibility of the vent gas/assist media mixture in the combustion zone (i.e., the net heating value, lower flammability, and/or combustibles concentration) at the flare tip. Following is a discussion of requirements we are proposing for refinery flares, along with impacts and costs associated with these new requirements. All of the requirements for flares operating at petroleum refineries in this proposed rulemaking are intended to ensure compliance with the Refinery MACT 1 and 2 standards when using a flare as an APCD. Also, since we are proposing to amend Refinery MACT 1 and 2 so that these standards include all of the regulatory provisions applicable to flares, these subparts would no longer cross-reference the flare requirements in the General Provisions.

a. Pilot Flames Refinery MACT 1 and 2 reference the flare requirements in the General Provisions, which require a flare used as an APCD device to operate with a pilot flame present at all times. Pilot flames are proven to improve flare flame stability; even short durations of an extinguished pilot could cause a significant reduction in flare destruction efficiency. In this action, we are proposing to remove the cross-reference to the General Provisions and instead include the requirement that flares***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 131 of 381 operate with a pilot flame at all times and be continuously monitored for using a thermocouple or any other equivalent device in Refinery MACT 1 and 2. We are also proposing to amend Refinery MACT 1 and 2 to add a new operational requirement to use automatic relight systems for all flare pilot flames. An automatic relight system provides a quicker response time to relighting a snuffed-out flare compared to manual methods and thereby results in improved flare flame stability. In comparison, manual relighting is much more likely to result in a longer period where the pilot remains unlit. Because of safety issues with manual relighting, we anticipate that nearly all refinery flares are already equipped with an automated device to relight the pilot flame in the event it is extinguished. Also, due to the possibility that a delay in relighting the pilot could result in a flare not meeting the 98-percent destruction efficiency for the period when the pilot flame is out, we are proposing to amend Refinery MACT 1 and 2 to add this requirement to ensure that the pilot operates at all times.

b. Visible Emissions Refinery MACT 1 and 2 reference the flare requirements in the General Provisions, which require a flare used as an APCD to operate with visible emissions for no more than 5 minutes in a 2-hour period. Owners or operators of these flares are required to conduct an initial performance demonstration for visible***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 132 of 381 emissions using EPA Method 22 of 40 CFR part 60, Appendix A-7. We are proposing to remove the cross-reference to the General

Provisions and include the limitation on visible emissions in Refinery MACT 1 and 2. In addition, we are proposing to amend Refinery MACT 1 and 2 to add a requirement that a visible emissions test be conducted each day and whenever visible emissions are observed from the flare. We are proposing that owners or operators of flares monitor visible emissions at a minimum of once per day using an observation period of 5 minutes and EPA Method 22 of 40 CFR part 60, Appendix A-7. Additionally, any time there are visual emissions from the flare, we are proposing that another 5-minute visible emissions observation period be performed using EPA Method 22 of 40 CFR part 60, Appendix A-7, even if the minimum required daily visible emission monitoring has already been performed. For example, if an employee observes visual emissions or receives notification of such by the community, the owner or operator of the flare would be required to perform a 5-minute EPA Method 22 observation in order to check for compliance upon initial observation or notification of such event. We are also proposing that if visible emissions are observed for greater than one continuous minute during any of the required 5-minute observation periods, the monitoring period shall be extended to

2 hours.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 133 of 381 Industry representatives have suggested to the EPA that flare combustion efficiency is highest at the incipient smoke point (the point at which black smoke begins to form within the flame). They stated that the existing limit for visible

emissions could be increased from 5 minutes to 10 minutes in a 2-hour period to encourage operation near the incipient smoke point (see memorandum, Meeting Minutes for February 19, 2013; Meeting Between the U.S. EPA and Representatives from thePetroleum Refining Industry, in Docket ID Number EPA-HQ-OAR2010-0682). While we agree that operating near the incipient smoke point results in good combustion at the flare tip, we disagree that the allowable period for visible emissions be increased from 5 to 10 minutes for a 2-hour period. Smoking flares can contribute significantly to emissions of particulate matter 2.5 micrometers in diameter and smaller (PM 2.5 )emissions, and we are concerned that increasing the allowable period of visible emissions from 5 minutes to 10 minutes for every 2-hour period could result in an increase in the PM 2.5 emissions from

flares. As discussed later in this section, we are proposing additional operational and monitoring requirements for refinery flares which we expect will result in refineries installing equipment that can be used to fine-tune and control the amount of assist steam or air introduced at the flare tip such that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 134 of 381 combustion efficiency of the flare will be maximized. These monitoring and control systems will assist refinery flare owners or operators operating near the incipient smoke point without exceeding the visible emissions limit. While combustion efficiency may be highest at the incipient smoke point, it is not significantly higher than the combustion efficiency achieved by these proposed operating limits, discussed below in Section IV.A.3.d of this preamble. As seen in the performance curves for flares (see technical memorandum, Petroleum Refinery SectorRule: Operating Limits for Flares, in Docket ID Number EPA-HQOAR-2010-0682), there is very limited improvement in flare performance beyond the performance achieved at these proposed operating limits. We solicit comments and data on appropriate periods of visible emissions that would encourage operation at the incipient smoke point while not significantly increasing

PM 2.5 emissions. c. Flare Tip Velocity The General Provisions at 40 CFR 63.11(b) specify maximumflare tip velocities based on flare type (non-assisted, steamassisted, or air-assisted) and the net heating value of the flare vent gas. These maximum flare tip velocities are required to ensure that the flame does not “lift off” the flare, which could cause flame instability and/or potentially result in a portion of the flare gas being released without proper***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 135 of 381 combustion. We are proposing to remove the cross-reference to the General Provisions and consolidate the requirements for maximum flare tip velocity into Refinery MACT 1 and 2 as asingle equation, irrespective of flare type (i.e., steamassisted, air-assisted or non-assisted). Based on our analysis of the various studies for air-assisted flares, we identified air-assisted test runs with high flare tip velocities that had high combustion efficiencies. These test runs exceeded the maximum flare tip velocity limits for air-assisted flares using the linear equation in 40 CFR 63.11(b)(8). When these test runswere compared with the test runs for non-assisted and steamassisted flares, the air-assisted flares appeared to have the same operating envelope as the non-assisted and steam-assisted flares. Therefore, we are proposing that air-assisted flares atrefineries use the same equation that non-assisted and steamassisted flares currently use to establish the flare tip velocity operating limit. In developing these proposed flare tip velocity requirements, we considered whether any adjustments to these velocity equations were necessary. The flare tip velocity equations require the input of the net heating value of the vent gas going to the flare, as opposed to the net heating value of the gas mixture at the flare tip (i.e., the combustion zone gas). As discussed later in this section, we found that the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 136 of 381 performance of the flare was much more dependent on the net heating value of the gas mixture in the combustion zone than on the net heating value of only the vent gas going into the flare (excluding all assist media). We considered replacing the term in the velocity equation for the net heating value of the vent gas going into the flare with the net heating value of the gas mixture in the combustion zone. However, the steam addition rates were not reported for the tests conducted to evaluate flame stability as a function of flare tip velocity, so direct calculation of all the terms needed for calculating the net heating value in the combustion zone could not be made. At higher flare tip velocities, we expect that the steam assist rates would be small in comparison to the total vent gas flow rate, so there would not be a significant difference between the net heating value of the vent gas going into the flare and the combustion zone gas net heating value for the higher velocity flame stability tests. We request comment on the need and/or scientific reasons to use the flare vent gas net heating value versus the combustion zone net heating value when determining the maximum allowable flare tip velocity. In the 2012 flare peer review, we also discussed the effect of flame lift off and velocity on flare flame stability (see technical report, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). In looking at***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 137 of 381 ways of trying to prohibit flame instability, we examined the use of the Shore equation as a means to limit flare tip velocity. However, after receiving many comments on use of this equation from the peer reviewers, the uncertainty with how well the Shore equation models the large range of flare operation, and the limited dataset with which recent testing used high velocities (all recent test runs were performed at 10 feet per second or less), we determined that use of the existing velocity equation discussed above was still warranted. We are also proposing for Refinery MACT 1 and 2 to not include the special flare tip velocity equation in the General Provisions at 40 CFR 63.11(b)(6)(i)(A) for non-assisted flares with hydrogen content greater than 8 percent. This equation, which was developed based on limited data from a chemicals manufacturer, has very limited applicability for petroleumrefinery flares in that it only provides an alternative for nonassisted flares with large quantities of hydrogen. Approximately90 percent of all refinery flares are either steam- or airassisted. Furthermore, we are proposing compliance alternatives in this section that we believe provide a better way for flares at petroleum refineries with high hydrogen content to comply with the rule while ensuring proper destruction performance of the flare (see Section IV.A.3.d of this preamble for additional details). Therefore, we are proposing to not include this***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 138 of 381 special flare tip velocity equation as a compliance alternative for refinery flares. We request comment on the need to include this equation. If a commenter supports inclusion of this equation, we request that the commenter submit supporting documentation regarding the vent gas composition and flows and, if available, combustion efficiency determinations that indicate that this additional equation is needed and is appropriate for refinery flares. We also request documentation that the maximum allowable flare tip velocity predicted by this equation adequately ensures proper combustion efficiency. The General Provisions require an initial demonstration that a flare used as an APCD meets the applicable flare tip velocity requirement in 40 CFR 63.11(b). However, most refinery flares can have highly variable vent gas flows and a single

initial demonstration is insufficient to demonstrate continuous compliance with the flare tip velocity requirement. Consequently, we are proposing to amend Refinery MACT 1 and 2 to require continuous monitoring to determine flare tip velocity, calculated by monitoring the flare vent gas volumetric flow rate and dividing by the cross-sectional area of the flare tip. As an alternative to installing continuous volumetric flow rate monitors, we are proposing that the owner or operator may elect to install a pressure- and temperature-monitoring system and use engineering calculations to determine the flare tip velocity.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 139 of 381 d. Refinery Flare Operating and Monitoring Requirements The current requirements for flares in the General Provisions specify that the flare vent gas must meet a minimum net heating value of 200 British thermal units per standard cubic foot (Btu/scf) for non-assisted flares and 300 Btu/scf for air- and steam-assisted flares. Refinery MACT 1 and 2 reference these requirements, but neither the General Provisions nor Refinery MACT 1 and 2 include specific monitoring requirements to monitor the net heating value of the vent gas. Moreover, recent flare testing results indicate that this parameter alone does not adequately address instances when the flare may be over-assisted since it only considers the gas being combusted in the flare and nothing else (e.g., no assist media). However, many industrial flares use steam or air as an assist medium to protect the design of the flare tip, promote turbulence for the mixing, induce air into the flame and operate with no visible emissions. Using excessive steam or air results in dilution and cooling of flared gases and can lead to operating a flare outside its stable flame envelope, reducing the destruction efficiency of the flare. In extreme cases, over-steaming or excess aeration can actually snuff out a flame and allow regulated material to be released into the atmosphere completely uncombusted. Since approximately 90 percent of all flares at refineries are either steam- or air-assisted, it is critical***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 140 of 381 that we ensure the assist media be accounted for in some form or fashion. Recent flare test data have shown that the best way to account for situations of over-assisting is to consider the properties of the mixture of all gases at the flare tip in the combustion zone when evaluating the ability to combust efficiently. As discussed in the introduction to this section, the external peer review panel concurred with our assessment that the combustion zone properties at the flare tip are critical parameters to know in determining whether a flare will achieve good combustion. The General Provisions, however, solely rely on the net heating value of the flare vent gas. We are proposing to add definitions of two key terms relevant to refinery flare performance. First, we are proposing to define “flare vent gas” to include all waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or assist media. We are proposing this definition because information about “flare vent gas” (e.g., flow rate and composition) is one of the necessary inputs needed to evaluate the make-up of the combustion zone gas. To that end, we are also proposing to define the “combustion zone gas” as flare vent gas plus the total steam-assist media and premix assist air that is supplied to the flare. Based on our review of the recent flare test data, we have determined that the following combustion zone operational limits***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 141 of 381 can be used to determine good combustion: net heating value (Btu/scf), lower flammability limit (LFL) or a total combustibles fraction (e.g., a simple carbon count). In this action, we are proposing these new operational limits, along with methods for determining these limits in the combustion zoneat the flare tip for steam-assisted, air-assisted and nonassisted flares to ensure that there is enough combustible material readily available to achieve good combustion. For air-assisted flares, use of too much perimeter assist air can lead to poor flare performance. Based on our analysis, we found that including the flow rate of perimeter assist air in the calculation of combustion zone operational limits in itself does not identify all instances of excess aeration. The data suggest that the diameter of the flare tip, in concert with the amount of perimeter assist air, provides the inputs necessary to calculate whether or not this type of flare is over-assisted. Therefore, we are proposing that in addition to complying with combustion zone operational limits to ensure that there is enough combustible material available to adequately combust the gas and pass through the flammability region, air-assisted flares would also comply with an additional dilution parameter that factors in the flow rate of the flare vent gas, flow rates of all assist media (including perimeter assist air), and diameter of flare tip to ensure that degradation of flare***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 142 of 381 performance from excess aeration does not occur. This dilution parameter is consistent with the combustion theory that the more “time” the gas spends in the flammability region above the flare tip, the better it will combust. Also, since both the volume of the combustion zone (represented by the diameter here) and how quickly this gas is diluted to a point below the flammability region (represented by perimeter assist air flow rate) characterize this “time,” it makes sense that we propose such a term (see technical memorandum, Petroleum Refinery Sector Rule:Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR2010-0682). It should be noted that in the 2012 flare peer review report, we considered a limit for perimeter assist air via the

stoichiometric air ratio. This stoichiometric air ratio is the

ratio of the actual mass flow rate of assist air to the theoretical stoichiometric mass flow rate of air (based on complete chemical combustion of fuel to carbon dioxide (CO 2 ) and water) needed to combust the flare vent gas. However, we are not proposing to include this term as part of the calculation methodology, as we have determined that the dilution parameter

discussed in this section better assures that air-assisted flare performance is not degraded due to excess aeration. The proposed rule allows the owner or operator flexibility to select the form of the combustion zone operational limit***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 143 of 381 (i.e., net heating value, LFL, or total combustibles fraction) with which to comply in order to provide facilities the option of using monitors they may already have in place. The monitoring methods we are proposing take into account the combustible properties of all gas going to the flare (i.e., flare vent gas, assist gas, and premix air) that affects combustion efficiency, and they can be used to determine whether a flare has enough

combustible material to achieve the desired level of control (and whether it is being over-assisted). These methods require the owner or operator to input the flow of the vent gas to the flare, the characteristics of the vent gas going to the flare (i.e., either a heat content (Btu/scf), LFL, or total combustible fuel content, depending on how the operational limit is expressed), and the flow of assist media added to the flare. To estimate the LFL, we are proposing to use a calculation method based on the Le Chatelier equation. The Le Chatelier calculation uses the reciprocal of the volume-weighted average over the LFL of the individual compounds in the gas mixture to estimate the LFL of the gas mixture. Although Le Chatelier’s equation was originally limited to binary mixtures of combustible gases, we are proposing a method that was developed by Karim, et al. (1985) and assumes a LFL of infinity for inert gases. We are also aware of other methods and/or adjustments that can be made to the Le Chatelier equation in order to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 144 of 381 calculate a more accurate estimate of the LFL of a gas mixture (see technical memorandum, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). We are soliciting comment on the use of this proposed method. Recent data indicate that one set of operational limits may not be sufficient for all refinery flares. Flares that receive vent gas containing significant levels of both hydrogen and

olefins often exhibit lower combustion efficiencies than flares that receive vent gas with only one (or none) of these compounds. Therefore, we are proposing more stringent operational limits for flares that simultaneously receive vent gas containing significant levels of both hydrogen and olefins (see technical memorandum, Petroleum Refinery Sector Rule:Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR2010-0682). Although the minimum net heating value in the combustion zone (i.e., Btu/scf) is a good indicator of combustion efficiency, as noted in the flare peer review report, the LFL and combustibles concentration (or total combustibles) in the combustion zone are also good indicators of flare combustion efficiency. For some gas mixtures, such as gases with high hydrogen content, the LFL or combustibles concentration in the combustion zone may be better indicators of performance than net heating value. Consequently, we are proposing operational***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 145 of 381 limits expressed all three ways, along with associated monitoring requirements discussed later in this section. The three operating limits were established in such a way that each limit is protective on its own. As such, the owner or operator may elect to comply with any of the three alternative operating limits at any time, provided they use a monitoring system capable of determining compliance with each of the proposed alternative operating limits on which they rely (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). For example, the owner or operator may elect to install monitoring for only one of the three alternative operating limits, in which case the owner or operator must comply with that selected operating limit at all times. If the owner or operator installs a system capable of monitoring for all three of the alternative operating limits, the owner or operator can choose which of the three operating limits the source will rely on to demonstrate compliance. A summary of the operating limits specified in this proposed rule is provided in Table 3 of this preamble. We are proposing that owners or operators of flares used as APCD would conduct an initial performance test to determine the values of the parameters to be monitored (e.g., the flow rate and heat content of the incoming flare vent gas, the assist media flow***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 146 of 381 rate, and pre-mix air flow rate, if applicable) in order to demonstrate continuous compliance with the operational limits in Table 3. We are proposing to require owners or operators to record and calculate 15-minute block average values for these parameters. Our rationale for selecting a 15-minute block averaging period is provided below in Section IV.A.3.e of this preamble. **Table 3. Operating Limits for Flares in this Proposed Action**

**Operating Parameter**  **a Operating Limits: Flares**  **without Hydrogen-Olefin Interaction**  **b Operating Limits: Flares**  **with Hydrogen-Olefin Interaction**  **b** Combustion zone parameters for all flares NHV cz ≥ 270 Btu/scf ≥ 380 Btu/scf LFL cz ≤ 0.15 volume fraction ≤ 0.11 volume fraction C cz ≥ 0.18 volume fraction ≥ 0.23 volume fraction Dilution parameters for flares using perimeter assist air NHV dil ≥ 22 Btu/ft 2 ≥ 32 Btu/ft 2 LFL dil ≤ 2.2 volume fraction/ft ≤ 1.6 volume fraction/ft C dil ≥ 0.012 volume fraction-ft ≥ 0.015 volume fraction-ft

a The operating parameters are:

NHV cz = combustion zone net heating value LFL cz = combustion zone lower flammability limit C cz = combustion zone combustibles concentration NHV dil = net heating value dilution parameter LFL dil = lower flammability limit dilution parameter C dil = combustibles concentration dilution parameter b Hydrogen-Olefin interactions are assumed to be present when the concentration of hydrogen and olefins in the combustion zone exceed all three of the following criteria: (1) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by volume. (2) The cumulative concentration of olefins in the combustion zone is greater than 2.5 percent by volume. (3) The cumulative concentration of olefins in the combustion zone plus the concentration of hydrogen in the combustion zone is greater than 7.4 percent by volume. Btu/ft 2 = British thermal units per square foot.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 147 of 381 We are soliciting comment on the appropriateness of the operating limits and dilution parameters in Table 3 of this preamble and whether they ensure that refinery flares operate in a manner that that will ensure compliance with the MACT requirements for vents to achieve a 98-percent organic HAP

reduction. Combustion zone gas monitoring alternatives. As discussed previously in this section, we are proposing to define the combustion zone gas as the mixture of gas at the flare tip consisting of the flare vent gas, the total steam-assist media and premix assist air. In order to demonstrate compliance with the three combustion zone parameter operating limits of net heating value, LFL and total combustibles fraction, the owner or operator would need to monitor four things: (1) flow rate of the flare vent gas; (2) flow rate of total steam assist media; (3) flow rate of premix assist air and (4) specific characteristics associated with the flare vent gas (e.g., heat content, composition). In order to monitor the flow rates of the flare vent gas, total steam assist media, and premix assist air, we are proposing that refinery owners or operators use a continuous volumetric flow rate monitoring system or a pressure- and temperature-monitoring system with use of engineering calculations. We are also proposing use of either of these monitoring methods for purposes of determining the flow rate of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 148 of 381 perimeter assist air (for compliance with the dilution parameter). However, the one component that will determine how many combustion zone parameter operating limits an owner or operator can comply with is the specific type of monitor used to characterize the flare vent gas. Monitoring the individual component concentrations of the flare vent gas using an on-line gas chromatograph (GC) along with monitoring vent gas and assist gas flow rates will allow the owner or operator to determine compliance with any of the three proposed combustion zone operating limits and any of the three proposed dilution operating limits (if using air-assisted flares). We considered requiring all refinery owners or operators of flares to only use a GC to monitor the flare vent gas composition but since facilities may have other non-GC monitors already in place (e.g., calorimeters), we are not proposing such a requirement at this time. However, use of a GC can improve refinery flare operation and management of resources. For example, use of a GC to characterize the flare vent gas can lead to product/cost savings for refiners because they could more readily identify and correct instances of product being unintentionally sent to a flare, either through a leaking pressure relief valve or other conveyance that is ultimately routed to the flare header system. In addition, an owner or operator that chooses to use a GC (in lieu of one of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 149 of 381 the other proposed monitoring alternatives) will be more likely to benefit from the ability to continuously fine-tune their operations (by reducing assist gas addition and/or supplemental gas to the flare) in order to meet any one of the three operating limits. Furthermore, some facilities are already required to use a GC to demonstrate compliance with state flare requirements. We are soliciting comment on the additional benefits that using a GC offers and whether it would be reasonable to require a GC on all refinery flares. As an alternative to a continuous compositional monitoring system, we are proposing to allow the use of grab samples along with engineering calculations to determine the individual component concentration. Like the on-line GC, the grab sampling option relies on compound speciation and is therefore flexible to use with any form of the operational limits we are proposing. The disadvantage of this option is that if a grab sample indicates non-compliance with the operational limits, the permitting authority could presume non-compliance from the time of the previous grab sample indicating compliance, which would include all 15-minute periods in that time period. However, there are a number of situations where the refinery owner or operator may find this option advantageous. For example, some flares receive flows only from a specific process with a consistent composition and high heat content. In this case, the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 150 of 381 owner or operator may elect to actively adjust the assist gas flow rates using the expected vent gas composition and rely on the analysis of the grab sample to confirm the expected vent gas composition. This alternative may also be preferred for flares that are used infrequently (non-routine flow flares) or that have flare gas recovery systems designed and operated to recover 100 percent of the flare gas under typical conditions. For these flares, flaring events may be so seldom that the refinery owner or operator may prefer the uncertainty in proactive control to the higher cost of continuous monitors that would seldom be

used. As an alternative to performing a compositional analysis with use of a GC (through either on-line monitoring or analysis of the grab sample), we are proposing that owners or operators of flares may elect to install a device that directly monitors vent gas net heating value (i.e., a calorimeter). If the owner or operator elects this monitoring method, we are proposing that they must comply with the operating limits that are based on the net heating value operating limit. Similarly, we are also proposing that owners or operators of flares may elect to install a device that directly monitors the total hydrocarbon content of the flare vent gas (as a measure of the combustibles concentration). If the owner or operator elects this monitoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 151 of 381 method, they must comply with the operating limits that are

based on the combustibles concentration. e. Data Averaging Periods for Flare Gas Operating Limits We are proposing to use a 15-minute block averaging period for each proposed flare operating parameter (including flare tip velocity) to ensure that the flare is operated within the appropriate operating conditions. As flare vent gas flow rates and composition can change significantly over short periods of time, a short averaging time was considered to be the most appropriate for assessing proper flare performance. Furthermore, since flare destruction efficiencies can fall precipitously fast below the proposed operating limits, short time periods where the operating limits are not met could seriously impact the overall performance of the flare. With longer averaging times, there may be too much opportunity to mask these short periods of poor performance (i.e., to achieve the longer-term average operating limit while not achieving a high destruction efficiency over that time period because of short periods of poor performance). Moreover, a 15-minute averaging period is in line with the test data and the analysis used to establish the operating limits in this proposed rule. Ninety-three percent of the flare test runs used as a basis for establishing the proposed operating limits ranged in duration from 5 to 30 minutes, and 77***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 152 of 381 percent of the runs ranged in duration from 5 to 20 minutes. The failure analysis (discussed below in Section IV.A.3.f of this preamble) considered minute-by-minute test run data, but as there are limitations on how quickly compositional analyses can be conducted, many of the compositional data still reflect set

values over 10- to 15-minute time intervals. Because the GC compositional analyses generally require 10 to 15 minutes to conduct, shorter averaging times are not practical. To be

consistent with the available test data and to ensure there are no short periods of significantly poor performance, we are proposing 15-minute block averaging times. Given the short averaging times for the operating limits, we are proposing special calculation methodologies to enable refinery owners or operators to use “feed forward” calculations to ensure compliance with the operating limits on a 15-minute block average. Specifically, the results of the compositional analysis determined just prior to a 15-minute block period are to be used for the next 15-minute block average. Owners or operators of flares will then know the vent gas properties for the upcoming 15-minute block period and can adjust assist gas flow rates relative to vent gas flow rates to comply with the proposed operating limits. Owners or operators of flares that elect to use grab sampling and engineering calculations to determine compliance***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 153 of 381 must still assess compliance on a 15-minute block average. The composition of each grab sample is to be used for the duration of the episode or until the next grab sample is taken. We are soliciting comment on whether this approach is appropriate, and whether grab samples are needed on a more frequent basis to ensure compliance with the operating limits.

f. Other Peer Review Considerations In an effort to better inform the proposed new requirements for refinery flares, in the spring of 2012 the EPA summarized its preliminary findings on operating parameters that affect flare combustion efficiency in a technical report and put this report out for ad-hoc peer review. Based on the feedback received from the ad-hoc peer review panel, the EPA considered many of the concerns peer reviewers expressed in their comments in the development of this proposal for refinery flares (see memorandum, Peer Review of “Parameters for Properly Designed and Operated Flares”, in Docket ID Number EPA-HQ-OAR-2010-0682). While the more substantive issues have been previously discussed in Sections IV.A.3.a through e of this preamble, the following discussion addresses other peer review considerations that the EPA either discussed in the peer review technical document or considered from comments received by the peer review panel that played a role in the development of this proposal.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 154 of 381 Test data quality and analysis. For steam-assisted flares, we asked peer reviewers to comment on our criteria for excluding available flare test data from our analyses. In general, peer reviewers considered the EPA’s reasons for removing certain test data (prior to performing any final analysis) to be appropriate; however, one reviewer suggested the EPA complete an analysis of quality on the data before applying any criteria, and several reviewers commented on the level of scrutiny of the 10 data points specifically discussed in the technical report for not meeting the combustion zone LFL trend. These reviewers stated it appeared the EPA had scrutinized test data more if it were

inconsistent with the LFL threshold conclusions made in the report. Although we felt it was appropriate to discuss specific test data not fitting the trend, we do agree with the reviewers that a more general and standard set of criteria should be applied to all test data prior to making any conclusion. In addition, other peer reviewers saw no reason why the EPA should exclude 0-percent combustion efficiency data points, or data points where smoking occurs, or single test runs when there was also a comparable average test run. Therefore, in response to these peer review comments, the EPA performed a validation and usability analysis on all available test data. This resulted in a change to the population of test data used in our final analysis (see technical memorandum, Flare Performance Data:***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 155 of 381 Summary of Peer Review Comments and Additional Data Analysis for Steam-Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010-0682 for a more detailed discussion of the data quality and analysis). To help determine appropriate operating limits, severalpeer reviewers suggested the EPA perform a false-positive-tofalse-negative comparison (or failure type) analysis between the potential parameters discussed in the technical report as indicators of flare performance. The reviewers suggested that the EPA attempt to minimize the standard error of all false positives (i.e., poor observed combustion efficiency when the correlation would predict good combustion) and false negatives (i.e., good observed combustion efficiency when the correlation would predict poor combustion). In response to these comments, the EPA has conducted a failure analyses of these parameters which helped form the basis for the operating limits we are proposing for flares (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). Some peer reviewers contended that it is appropriate for the EPA to round each established operating limit to the nearest whole number, because using a decimal implies far more accuracy and reliability than can be determined from the test data. Based on these comments, we have given more consideration to the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 156 of 381 number of significant figures used in the operating limits, and we are proposing to use two significant figures for the flare operating limits in these proposed amendments. Multiple peer reviewers performed additional analyses to try and determine the appropriateness of the limits raised in the technical report. Some peer reviewers tried to fit the data to a curve, others performed various failure analyses, while

others looked at different metrics not discussed in the technical report (see memorandum, Peer Review of “Parameters forProperly Designed and Operated Flares”, in Docket ID Number EPAHQ-OAR-2010-0682). Based on the conclusions drawn from these various analyses, a range of combustion zone net heating value targets from 200 Btu/scf to 450 Btu/scf were identified as metrics that would provide a high level of certainty regarding good combustion in flares (Note: 450 Btu/scf was the assumed to be approximately equivalent to a combustion zone LFL of 10 percent). We solicit comment on this range and the appropriateness for which the operating limits selected in this proposal will ensure compliance with the MACT requirements for vents at petroleum refineries. Effect of supplemental gas use. Most flares normally operate at a high turndown ratio, which means the actual flare gas flow rate is much lower than what the flare is designed to handle. In addition, steam-assisted flares have a manufacturers’***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 157 of 381 minimum steam requirement in order to protect the flare tip. A combination of high turndown ratio and minimum steam requirement will likely require some owners or operators to add supplemental gas to achieve one of the combustion zone gas operating limits we are proposing here (e.g., combustion zone combustibles concentration (C cz ) ≥ 18 volume percent; combustion zone lower flammability limit (LFL cz ) ≤ 15 volume percent; or combustion zone net heating value (NHV cz ) ≥ 270 Btu/scf). However, finetuning the actual steam flow to the flare should significantly reduce the need for supplemental gas. We considered proposing a steam-to-vent gas ratio limitation on steam-assisted flares. however, a steam-to-vent gas ratio alone cannot fully address over-steaming because it would not account for the variability of chemical properties within the flare gas. We request that commenters on this issue provide supporting documentation on their potential to reduce steam as well as their use of supplemental gas to achieve the proposed operating limit(s), and how it could affect cost and potential emissions. We emphasize that the amount and cost of supplemental gas should be reflective of conditions after any excess steam use has been

rectified. It would not be valuable to consider situations where large amounts of supplemental gas are added, while steam is simultaneously added far in excess of the amount recommended by the flare manufacturer or other guidance documents.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 158 of 381 In assessing the combustion zone gas and looking at all the gas at the flare tip, another potential source of added heat content comes from the gas being used as fuel to maintain a continuously lit pilot flame. However, since pilot gas is being used as fuel for a continuous ignition source and is burned to create a flame prior to (or at the periphery of) the combustion zone, this gas does not directly contribute to the heat content or flammability of the gas being sent to the flare to be controlled under Refinery MACT 1 or 2. In addition, in looking at available test data, the pilot gas flow rate is generally so small that it does not significantly impact the combustion zone properties at all. Furthermore, by leaving pilot gas out of the combustion zone operating limit calculations, the equations become simplified and a requirement to continuously monitor pilot gas flow rate can be avoided. Therefore, we are proposing that the owner or operator not factor in the pilot gas combustible component (or net heating value) contribution when determining any of the three proposed combustion zone gas operating limits (C cz , LFL cz , or NHV cz ). Effects of wind on flame performance. Several published studies have investigated the significance of wind on the fluid mechanics of a flare flame (see technical memorandum, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). These studies were conducted in wind***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 159 of 381 tunnels at crosswind velocities up to about 60 miles per hour (mph) and have illustrated that increased crosswind velocity can have a strong effect on flare flame dimensions and shape, causing the flame to become segmented or discontinuous, and wake-dominated (i.e., where the flame is bent over on the downwind side of a flare pipe and is imbedded in the wake of the flare tip), which may lead to poor flare performance due to fuel stripping. However, the majority of this research is confined to laboratory studies on flares with effective diameters less than 3 inches, which have been shown not to be representative of industrial-sized flares. Research that does include performance tests conducted on flares scalable to refinery flares (i.e., 3- inch, 4-inch, and 6-inch pipe flares) was conducted with flare tip velocities as low as 0.49 feet per second and crosswind velocities of about 26 mph and less; all tests resulted in good flare performance. Furthermore, there is no indication that crosswind velocities negatively impact flare performance in the recent flare performance tests. These tests were conducted on various sizes of industrial flares (i.e., effective diameters ranging between 12 and 54 inches) in winds of about 22 mph and less, and at relatively low flare tip velocities (i.e., 10 feet per second or less). (See Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682.)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 160 of 381 We are aware of flare operating parameters that consider crosswind velocity; however, using the available flare performance test data, we were unable to determine a clear correlation that would be appropriate for all refinery flares. For example, the momentum flux ratio (MFR) is a measure of momentum strength of the flare exit gas relative to the crosswind (i.e., the product of flare exit gas density and velocity squared divided by the product of air density and crosswind velocity squared). The plume buoyancy factor is the ratio of crosswind velocity to the flare exit gas velocity, and considers the area of the flare pipe. The power factor is the ratio of the power of the crosswind to the power of combustion of the flare gas. Because the available flare performance test data have relatively low flare tip velocities, and crosswind velocities were relatively constant during each test run, we are unable to examine these parameters to the fullest extent. In light of the data available from performance tests (Gogolek et al., 2010), we asked peer reviewers whether the MFR could be used in crosswind velocities greater than 22 mph at the flare tip to indicate wake-dominated flame situations. We also

asked for comment on observations that in the absence of crosswind greater than 22 mph, a low MFR does not necessarily indicate poor flare performance. Peer reviewers suggested that

there are no data available from real industrial flares in winds***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 161 of 381 greater than 22 mph to support that MFR could be used to identify wake-dominated flame situations. In addition, we received no further peer review comments that have caused us to reconsider the observation we made in the April 2012 technical report that in the absence of crosswind greater than 22 mph, a low MFR does not necessarily indicate poor flare performance. We request comment with supporting data and rationale on any of these, or other parameters, as a measure of wind effects on flare combustion efficiency. We considered including observation requirements for detecting segmented or discontinuous wake-dominated flames, especially for winds greater than 22 mph (where limited test data is available). However, owners or operators of flares cannot control the wind speed, and it would be detrimental to increase the quantity of flared gases in high crosswindconditions in efforts to improve the MFR and reduce wakedominated flow conditions. Furthermore, there is no indication that crosswind velocities negatively impact flare performance in the recent flare performance tests. For these reasons, we are not proposing any flare operating parameter(s) to minimize wind effects on flare combustion efficiency. g. Impacts of the Flare Operating and Monitoring Requirements The EPA expects that the newly proposed requirements for refinery flares discussed in this section will affect all flares***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 162 of 381 at petroleum refineries. Based on data received as a result of the Refinery ICR, we estimate that there are 510 flares operating at petroleum refineries and that 285 of these receive flare vent gas flow on a regular basis (i.e., other than during periods of startup, shutdown, and malfunction). Costs were estimated for each flare for a given refinery, considering operational type (e.g., receive flare vent gas flow on a regular basis, use flare gas recovery systems to recover 100 percent of routine flare flow, handle events during startup, shutdown, or malfunction only, etc.) and current monitoring systems already installed on each individual flare. Costs for any additional monitoring systems needed were estimated based on installed costs received from petroleum refineries and, if installed costs were unavailable, costs were estimated based on vendor-purchased equipment. The baseline emission estimate and the emission reductions achieved by the proposed rule were estimated based on current vent gas and steam flow data submitted by industry representatives. The results of the impact estimates are summarized in Table 4 of this preamble. We note that the requirements for refinery flares we are proposing in this action will ensure compliance with the Refinery MACT standards when flares are used as an APCD. As such, these proposed operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 163 of 381 approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric tonnes per year of carbon dioxide equivalents (CO 2 e). For more detail on the impact estimates, see the technical memorandum Petroleum Refinery Sector Rule: Flare Impact Estimates in Docket ID Number EPA-HQ-OAR-2010-0682. **Table 4. Nationwide Cost Impacts of Proposed Amendments to Ensure Proper Flare Performance** 

**Affected source Total capital investment**  **(million $) Total annualized costs**  **(million $/ yr) Flare Monitoring**  147 36.3

4. Vent Control Bypasses a. Relief Valve Discharges Refinery MACT 1 recognized relief valve discharges to be the result of malfunctions. Relief valves are designed to remain closed during normal operation and only release as the result of unplanned and/or unpredictable events. A release from a relief valve usually occurs during an over pressurization of the system. However, emissions vented directly to the atmosphere by relief valves in organic HAP service contain HAP that are otherwise regulated under Refinery MACT 1. Refinery MACT 1 regulated relief valves through equipment leak provisions that applied only after the pressure relief occurred. In addition the rule followed the EPA’s then-practice of exempting SSM events from otherwise applicable emission standards. Consequently, with relief valve releases defined as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 164 of 381 unplanned and nonroutine and the result of malfunctions, Refinery MACT 1 did not restrict relief valve releases to the atmosphere but instead treated them the same as all malfunctions through the SSM exemption provision. In Sierra Club V. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court determined that the SSM exemption violates the CAA. See section IV.E. of this preamble for additional discussion. To ensure this standard is consistent with that decision, these proposed amendments remove the malfunction exemption in Refinery MACT 1 and 2. To ensure compliance with this amendment, we are also proposing to require that sources monitor relief valves using a system that is capable of identifying and recording the time and duration of each pressure release and of notifying operators that a pressure release has occurred. Pressure release events from relief valves to the atmosphere have the potential to emit large quantities of HAP. Where a pressure release occurs, it is important to identify and mitigate it as quickly as possible. For purposes of estimating the costs of this requirement, we assumed that operators would install electronic monitors on each relief valve that vents to the atmosphere to identify and record the time and duration of each pressure release. However, we are proposing to allow owners and operators to use a range of methods to satisfy these requirements, including the use of a parameter monitoring system (that may***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 165 of 381 already be in place) on the process operating pressure that is sufficient to indicate that a pressure release has occurred as well as record the time and duration of that pressure release. Based on our cost assumptions, the nationwide capital cost of installing these electronic monitors is $9.54 million and the annualized capital cost is $1.36 million per year. b. Bypass Lines For a closed vent system containing bypass lines that can divert the stream away from the APCD to the atmosphere, Refinery MACT 1 requires the owner or operator to either: (1) install, maintain and operate a continuous parametric monitoring system (CPMS) for flow on the bypass line that is capable of detecting whether a vent stream flow is present at least once every hour, or (2) secure the bypass line valve in the non-diverting position with a car-seal or a lock-and-key type configuration. Under option 2, the owner or operator is also required to inspect the seal or closure mechanism at least once per month to verify the valve is maintained in the non-diverting position (40 CFR 63.644(c)). We are proposing under CAA Section 112(d)(2) and (3) that the use of a bypass at any time to divert a Group 1 miscellaneous process vent is a violation of the emission standard, and to specify that if option 1 is chosen, the owner or operator would be required to install, maintain and operate a CPMS for flow that is capable of recording the volume of gas***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 166 of 381 that bypasses the APCD. The CMPS must be equipped with an automatic alarm system that will alert an operator immediately when flow is detected in the bypass line. We are proposing this revision because, as noted above, APCD are not to be bypassed because doing so could result in a release of regulated organic HAP to the atmosphere. In Sierra Club V. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court determined that standards under CAA Section 112(d) must provide for compliance at all times and a release of uncontrolled HAP to the atmosphere is inconsistent with that requirement. c. In Situ Sampling Systems (Onstream Analyzers) The current Refinery MACT 1 definition of “miscellaneous process vent” states that “in situ sampling systems (onstream analyzers)” are not miscellaneous process vents. 40 CFR 63.641. For several reasons, we are proposing to remove “in situ sampling systems (onstream analyzers)” from the list of vents not considered miscellaneous process vents. First, the language used in this exclusion is inconsistent. We generally consider“in situ sampling systems” to be non-extractive samplers or inline samplers. There are certain in situ sampling systems where the measurement is determined directly via a probe placed in the process stream line. Such sampling systems do not have an atmospheric vent, so excluding these from the definition of “miscellaneous process vent” is not meaningful. The***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 167 of 381 parenthetical term “onstream analyzers” generally refers to sampling systems that feed directly to an analyzer located at the process unit, and has been interpreted to exclude the “onstream” analyzer’s vent from the definition of miscellaneous process vents. As these two terms do not consistently refer to the same type of analyzer, the provision is not clear. Second, we find that there is no technical reason to include analyzer vents in a list of vents not considered miscellaneous process vents. For extractive sampling systems and systems with purges, the equipment leak standards in Refinery MACT 1 require that the material be returned to the process or controlled. Thus, the only potential emissions from any sampling system compliant with the Refinery MACT 1 equipment leak provisions would be from the analyzer’s “exhaust gas” vent. The parenthetical term “onstream analyzers” indicates that the focus of the exemption is primarily on the analyzer (or analyzer vent) rather than the sampling system. This phrase has been interpreted to exclude the “onstream” analyzer’s vent from the definition of miscellaneous process vents. Analyzer venting is expected to be routine (continuous or daily intermittent venting). We are proposing to delete this exclusion from the definition of “miscellaneous process vent” and to require these vents to meet the standards applicable to miscellaneous process***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 168 of 381 vents at all times. We expect most analyzer vents to be Group 2 miscellaneous process vents because analyzer vents are not expected to exceed the 72 pounds per day (lb/day) emissions threshold for Group 1 miscellaneous process vents. However, if there are larger analyzer vents that exceed the 72 lb/day emissions threshold for Group 1 miscellaneous process vents, these emission sources would need to be controlled as a Group 1 miscellaneous process vent under this proposal. We solicit comment on the existence of any onstream analyzers that have VOC emissions greater than 72 lb/day and why such vents are not

amenable to control. d. Refinery Flares and Fuel Gas Systems The current definition of “miscellaneous process vent” in Refinery MACT 1 states that “gaseous streams routed to a fuel gas system” are not miscellaneous process vents. Furthermore, the affected source subject to Refinery MACT 1 does not specifically include “emission points routed to a fuel gas system, as defined in §63.641 of this subpart.” The EPA allowed these exemptions for streams routed to fuel gas systems because according to the 1994 preamble for Refinery MACT 1, “these vents are already controlled to the most stringent levels achievable” (59 FR 36141, July 15, 1994). Since gaseous streams routed to a fuel gas system are eventually burned as fuel, typically in a boiler or process heater, these combustion controls burning the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 169 of 381 gaseous streams as fuel effectively achieve this most stringent level of control (i.e., 98-percent organic HAP reduction or an outlet organic HAP concentration of 20 ppmv for all vent streams). However, there can be instances when gaseous streams from the fuel gas system that would otherwise be combusted in a boiler or process heater are instead routed to a flare (e.g., overpressure in the fuel gas system, used as flare sweep gas, used as flare purge gas). In cases where an emission source is required to be controlled in Refinery MACT 1 and 2 but is routed to a fuel gas system, we are proposing that any flare receiving gases from that fuel gas system must comply with the flare operating and monitoring requirements discussed in Section IV.A.3 of this preamble. B. What are the results and proposed decisions based on our technology review? 1. Refinery MACT 1 – 40 CFR Part 63, Subpart CC Refinery MACT 1 sources include miscellaneous process vents, storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems, and wastewater.

a. Miscellaneous Process Vents Many unit operations at petroleum refineries generate gaseous streams containing HAP. These streams may be routed to other unit operations for additional processing (e.g., a gas***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 170 of 381 stream from a reactor that is routed to a distillation unit for separation) or they may be sent to a blowdown system or vented to the atmosphere. Miscellaneous process vents emit gases to the atmosphere, either directly or after passing through recovery and/or APCD. Under 40 CFR 63.643, the owner or operator must reduce organic HAP emissions from miscellaneous process vents using a flare that meets the equipment specifications in 40 CFR 63.11 of the General Provisions (subpart A) or use APCD (e.g., thermal oxidizers, carbon adsorbers) to reduce organic HAP emissions by 98 weight-percent or to a concentration of 20 parts per million by volume (ppmv) dry basis, corrected to 3-percent

oxygen. In the technology review, we did not identify any practices, processes or control technologies beyond those already required by Refinery MACT 1. Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements for miscellaneous process vents pursuant to CAA Section 112(d)(6). b. Storage Vessels Storage vessels (also known as storage tanks) are used to store liquid and gaseous feedstocks for use in a process, as well as liquid and gaseous products coming from a process. Most storage vessels are designed for operation at atmospheric or near atmospheric pressures; high-pressure vessels are used to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 171 of 381 store compressed gases and liquefied gases. Atmospheric storage vessels are typically cylindrical with a vertical orientation, and they are constructed with either a fixed roof or a floating roof. Some, generally small, atmospheric storage vessels are oriented horizontally. High pressure vessels are either spherical or horizontal cylinders. Section 63.646(a) requires certain existing and new storage vessels to comply with 40 CFR 63.119 through 40 CFR 63.121 of the HON. Under 40 CFR 63.119 through 63.121, storage vessels must be equipped with an internal floating roof with proper seals, an external floating roof with proper seals, an external floating roof converted to an internal floating roof with proper seals or a closed vent system routed to an APCD that reduces HAP emissions by 95 percent. Storage vessels at existing sources that use floating roofs are not required under Refinery MACT 1 to install certain fitting controls included in 40 CFR 63.1119 of the HON (e.g., gaskets for automatic bleeder vents, slit fabric covers for sample wells, flexible fabric seals or gasketed sliding covers for guidepoles and gasketed covers for other roof openings). See 40 CFR 63.646(c). In 2012, we conducted a general analysis to identify the latest developments in practices, processes and control technologies for storage vessels at chemical manufacturing facilities and petroleum refineries, and we estimated the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 172 of 381 impacts of applying those practices, processes and technologies to model storage vessels. (See Survey of Control Technology for Storage Vessels and Analysis of Impacts for Storage VesselControl Options, December 29, 2011, in Docket ID Number EPA-HQOAR-2010-0871.) We used this analysis as a starting point for conducting the technology review for storage vessels at refineries. In this analysis, we identified fitting controls, particularly controls for floating roof guidepoles, and monitoring equipment (liquid level monitors and leak monitors) as developments in practices, processes and control technologies for storage vessels. In our refinery-specific review, we also noted that the Group 1 storage vessel size and vapor pressure thresholds in Refinery MACT 1 were higher than those for storage

vessels in MACT standards for other similar industries. Therefore, we also evaluated revising the Group 1 storage vessel thresholds as a development in practices for storage vessels in the refining industry. We used data from our 2011 ICR to evaluate the impacts of requiring the additional controls identified in the technology review for the petroleum refinery source category. The emission reduction options identified during the technology review are: (1) requiring guidepole controls and other fitting controls for existing external or internal floating roof tanks as required in the Generic MACT for storage vessels (40 CFR part 63, subpart***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 173 of 381 WW) in 40 CFR 63.1063; (2) option 1 plus revising the definition of Group 1 storage vessel to include smaller capacity storage vessels and/or storage vessels containing materials with lower vapor pressures and (3) option 2 plus requiring additional monitoring to prevent roof landings, liquid level overfills and to identify leaking vents and fittings from tanks. We identified options 1 and 2 as developments in practices, processes and control technologies because these options are required for similar tanks in some chemical manufacturing MACT standards and we believe they are technologically feasible for storage vessels at refineries (e.g., Generic MACT, the HON). Option 3 is also an improvement in practices because these monitoring methods have been required for refineries by other regulatory agencies. Under option 1, we considered the impacts of requiring improved deck fittings and controls for guidepoles as is required for other chemical manufacturing sources in the Generic MACT. Specifically, we considered these controls for storage vessels with existing internal or external floating roof tanks. This option also includes the inspection, recordkeeping, and reporting requirements set forth in the Generic MACT to account for the additional requirements for fitting controls. We areaware of recent waiver requests to EPA to allow in-service, topside inspections instead of the out-of-service inspections required on a 10-year basis for internal floating roof tanks for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 174 of 381 facilities that are currently subject to 40 CFR part 60, subpart Kb and Refinery MACT 1. The requirements of Generic MACT allow for this option if there is visual access to all the deck components. Under option 1, we considered the Generic MACT provisions for in-service, top-side inspection. We are requesting comment on whether or not these in-service inspections are adequate for identifying conditions that are indicative of deck, fitting, and rim seal failures; we are also requesting comment on methods to effectively accomplish top-side inspections. For option 2, we evaluated revising the definition of Group 1 storage vessels to include smaller capacity storage vessels and/or storage vessels with lower vapor pressure, such that these additional storage vessels would be subject to the Group 1 control requirements. For storage vessels at existing sources, Refinery MACT 1 currently defines Group 1 storage vessels to be those with a capacity of 177 cubic meters (46,760 gallons) or greater, and a true vapor pressure of 10.4 kilopascals (1.5 pounds per square inch absolute (psia)) or greater. Under option 2, we evaluated the impacts of changing the definition of Group 1 storage vessels to include storage vessels with a capacity of 151 cubic meters (40,000 gallons) or greater and a true vapor pressure of 5.2 kilopascals (0.75 psia) or greater, and also evaluated including storage vessels with a capacity of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 175 of 381 76 cubic meters (20,000 gallons) or greater (but less than 151 cubic meters), provided the true vapor pressure of the stored liquid is 13.1 kilopascals (1.9 psia) or greater. These thresholds are consistent with storage vessel standards already required for the chemical industry (e.g., the HON). We believe the predominant effect of changing these thresholds will be fixed roof tanks at existing petroleum refineries shifting from Group 2 storage vessels to Group 1 storage vessels. These fixed roof tanks would thus need to be retrofitted with floating roofs or vented to an APCD in order to comply with the provisions for Group 1 storage vessels. We estimated the impacts of option 2 by assuming all uncontrolled fixed roof storage vessels that meet or exceed the proposed new applicability requirements for Group 1 storage vessels (based on the information collected in the Refinery ICR) would install an internal floating roof with a single rim seal and deck fittings to the existing fixed roof

tank. The costs of these fixed roof retrofits were added to the costs determined for option 1 to determine the cost of option 2. Under option 3, we considered the impacts of including additional monitoring requirements for Group 1 storage vessels (in addition to fitting controls and fixed roof retrofits considered under options 1 and 2). The monitoring requirements evaluated include monitoring of internal or external floating roof tanks with EPA Method 21 (of 40 CFR part 60, Appendix A-7)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 176 of 381 or optical gas imaging for fittings, and requiring the use of liquid level overfill warning monitors and roof landing warning

monitors. These costs were estimated based on the total number of Group 1 storage vessels considering the change in the applicability thresholds included in option 2. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Control Options for Storage Vessels at Petroleum Refineries, June 27, 2012, in Docket ID Number EPA-HQ-OAR-2010-0682. Table 5 of this preamble presents the impacts for the three options considered. Although the options were considered cumulatively, the calculation of the incremental cost effectiveness allows us to assess the impacts of the incremental change between the options. As seen by the incremental cost effectiveness column in Table 5, both options 1 and 2 result in a net cost savings considering the VOC recovery credit for product not lost to the atmosphere from the storage vessel. The incremental cost effectiveness for option 3 exceeds $60,000 per ton of HAP removed. We consider option 3 not to be cost effective and are not proposing to require this additional monitoring. Based on this analysis, we consider option 2 to be cost effective. We are, therefore, proposing to revise Refinery MACT 1 to cross-reference the corresponding storage vessel***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 177 of 381 requirements in the Generic MACT (including requirements for guidepole controls and other fittings as well as inspection requirements), and to revise the definition of Group 1 storage vessels to include storage vessels with capacities greater than or equal to 20,000 gallons but less than 40,000 gallons if the maximum true vapor pressure is 1.9 psia or greater and to include storage tanks greater than 40,000 gallons if the maximum true vapor pressure is 0.75 psia or greater. **Table 5. Nationwide Emissions Reduction and Cost Impacts of Control Options for Storage Vessels at Petroleum Refineries** 

**Control Option**  **Capital Cost**  **(million $)**  **Annual ized**  **Costs Without**  **Recovery Credits**  **(million**

**$/yr) Emis**  **sions Reduc**  **tion,**

**VOC (tpy)**  **Emis sions** **Reduc tion,** 

**HAP (tpy)**  **Cost Effec** **tive ness**  **($/ton**

**HAP) Total** **Annual**

**ized Costs**  **w ith VOC**  **R ecovery** 

**Credit (**  **million**

**$/yr) Overall**  **Cost Effec**  **tiveness w**  **ith VOC Recovery** 

**Credit ($/ton** 

**HAP) Incre**  **mental**

**Cost Effec**  **tiveness with VOC**  **Recovery**

**Credit ($/ton** 

**HAP)** 1 11.9 1.8 11,800 720 2,470 (4.8) (6,600) (6,690) 2 18.5 3.1 14,600 910 3,430 (5.0) (5,530) (1,140) 3 36.4 9.6 16,000 1,000 9,580 0.56 560 61,500

c. Equipment Leaks Equipment leaks are releases of process fluid or vapor from processing equipment, including pump and compressor seals, process valves, relief devices, open-ended valves and lines, flanges and other connectors, agitators and instrumentation systems. These releases occur primarily at the interface between connected components of equipment or in sealing mechanisms.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 178 of 381 Refinery MACT 1 requires the owner or operator of an existing source to comply with the equipment leak provisions in 40 CFR part 60, subpart VV (Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry) for all equipment in organic HAP service. The term “in organic HAP service” means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percent by weight of total organic HAP. Refinery MACT 1 specifies that the owner or operator of a new source must comply with the HON, as modified by Refinery MACT 1. The provisions for both new and existing sources require inspection (either through instrument monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7, or other method such as visible inspection) and repair of leaking equipment. For existing sources, the leak definition under 40 CFR part 60, subpart VV triggers repair at an instrument reading of 10,000 parts per million (ppm) for all equipment monitored using EPA Method 21 of 40 CFR part 60, Appendix A-7 (i.e., pumps and valves; instrument monitoring of equipment in heavy liquid service and connectors is optional). For new sources, the Refinery MACT 1-modified version of the HON triggers repair of leaks for pumps at 2,000 ppm and for valves at 1,000 ppm. Refinery MACT 1 requires new and existing sources to install a cap, plug or blind flange, as appropriate, on open-ended valves***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 179 of 381 or lines. Refinery MACT 1 does not require instrument monitoring of connectors for either new or existing sources. We conducted a general analysis to identify the latest developments in practices, processes and control technologies applicable to equipment leaks at chemical manufacturing facilities and petroleum refineries, and we estimated the impacts of applying the identified practices, processes and technologies to several model plants. (See Analysis of Emissions Reduction Techniques for Equipment Leaks, December 21, 2011, in Docket ID Number EPA-HQ-OAR-2010-0869.) We used this general analysis as a starting point for conducting the technology review for equipment leaks at refineries, but did not identify any developments beyond those in the general analysis. We estimated the impacts of applying the practices, processes and technologies identified in the general analysis to equipment leaks in petroleum refinery processes using the information we collected through the 2011 Refinery ICR. In general, leak detection and repair (LDAR) programs have been used by many industries for years to control emissions from equipment leaks. Over the years, repair methods have improved and owners and operators have become more proficient at implementing these programs. The specific developments identified include: (1) requiring repair of leaks at a concentration of 500 ppm for valves and 2,000 ppm for pumps for new and existing sources***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 180 of 381 (rather than 10,000 ppm for valves and pumps at existing sources and 1,000 for valves at new sources); (2) requiring monitoring of connectors using EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair of leaks for valves and pumps at a concentration of 500 ppm; and (3) allowing the use of optical gas imaging devices as an alternative method of monitoring. The first option we evaluated was to require repair based on a leak definition of 500 ppm for valves and a leak definition of 2,000 ppm for pumps at both new and existing sources. The nationwide costs and emission reduction impacts of applying those lower leak definitions to equipment leaks at petroleum refineries are shown in Table 6 of this preamble. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. The emissions reduction results in product not being lost by a leak; this additional product can be sold to generate revenue, referred to as a VOC recovery credit. Table 6

shows costs and cost effectiveness both with and without the VOC recovery credit. Based on the estimated organic HAP emission reductions of 24 tpy and the cost effectiveness of $14,100 per ton of organic HAP (including VOC recovery credit), we consider lowering the leak definition not to be a cost-effective option for reducing HAP emissions. We are, therefore, proposing that it***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 181 of 381 is not necessary to revise Refinery MACT 1 pursuant to CAA Section 112(d)(6) to require repair of leaking valves at 500 ppm or greater and repair of leaking pumps at 2,000 ppm or greater.

**Table 6. Nationwide Emissions Reduction and Cost Impacts of Monitoring and Repair Requirements at Lower Leak Definitions**  **(500 ppm for Valves; 2,000 ppm for Pumps)**

**Capital**

**Cost (million**  **$) Annual**  **ized Costs**  **Without Recovery**  **Credits (million** 

**$/yr) Emis**  **sions Reduc**  **tion,**

**VOC (tpy)**  **Emis sions** **Reduc tion,** 

**HAP (tpy)**  **Cost Effec** **tive ness**  **( $/ton** 

**VOC) Cost** **Effec tive**  **ness (**  **$/ton**

**HAP) Total** **Annual**

**ized Costs**  **w ith VOC**  **R ecovery** 

**Credit (**  **million**

**$/yr) Overall**  **Cost Effective**  **ness with VOC**  **Recovery**

**Credit ($/ton** 

**VOC) O**  **verall Cost** **Effec tiveness**  **w ith VOC**  **R ecovery** 

**Credit ($/ton** 

**HAP)** 1.22 0.53 342 24 1,550 22,100 0.34 987 14,100

We note that we are aware that some owners and operators are required to repair leaking valves as low as 100 ppm and pumps as low as 500 ppm. However, given that we consider requiring repair of leaking valves at 500 ppm or greater and repair of leaking pumps at 2,000 ppm or greater not to be cost effective. As documented in Analysis of Emissions Reduction Techniques for Equipment Leaks (December 21, 2011, in Docket ID Number EPA-HQ-OAR-2010-0869), the cost effectiveness for this option would be even higher than the values shown in Table 6 of this preamble. The second option we considered was connector monitoring and repair. Several standards applying to chemical manufacturing facilities, including the HON, include requirements for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 182 of 381 connector monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A-7) and requirements for repair of any connector leaks above 500 ppm VOC. Neither the Refinery MACT 1 nor the NSPS for equipment leaks from refineries (40 CFR part 60, subpart GGG and 40 CFR part 60, subpart GGGa) currently require connector monitoring and repair (provisions are provided for connector monitoring in Refinery MACT 1, but they are optional). We evaluated the costs and emissions reduction of requiring connector monitoring and repair requirements for equipment leaks

at refineries. The nationwide costs and emission reduction impacts, both with and without VOC recovery credit, are shown in Table 7 of this preamble. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. Based on the high annualized cost ($13.9 million per year) and high cost effectiveness ($153,000 per ton of HAP) of connector monitoring and repair for equipment leaks at refineries, we are proposing that it is not necessary to revise Refinery MACT 1 pursuant to CAA Section 112(d)(6) to require connector monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 183 of 381 **Table 7. Nationwide Emissions Reduction and Cost Impacts of Applying Monitoring and Repair Requirements to Connectors at**  **Petroleum Refineries (500 ppm)**

**Capital**

**Cost (million**  **$) Annual**  **ized Costs**  **Without Recovery**  **Credits (million** 

**$/yr) Emis**  **sions Reduc**  **tion,**

**VOC (tpy)**  **Emis sions** **Reduc tion,** 

**HAP (tpy)**  **Cost Effec** **tive ness**  **( $/ton** 

**VOC) Cost** **Effec tive**  **ness ($/ton** 

**HAP) Total** **Annual**

**ized Costs**  **w ith VOC**  **R ecovery** 

**Credit (**  **million**

**$/yr) Overall**  **Cost Effec**  **tiveness w**  **ith VOC Recovery** 

**Credit ($/ton** 

**VOC) O**  **verall Cost** **Effec tiveness**  **w ith VOC**  **R ecovery** 

**Credit ($/ton** 

**HAP)** 52.1 13.9 1,230 86 11,300 161,000 13.2 10,700 153,000

Another development identified was to provide optical gas imaging provisions (including the required instrument specifications, monitoring frequency, and repair threshold) as an alternative monitoring option where instrument monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7, is required in Refinery MACT 1. Since Refinery MACT 1 was issued, there have been developments in LDAR work practices using remote sensing technology for detecting leaking equipment. In this method of detecting leaks, an operator scans equipment using a device or system specially designed to use one of several types of remote sensing techniques, including optical gas imaging of infrared wavelengths, differential absorption light detection and ranging (DIAL), and solar occultation flux. The most common remote sensing instrument is a passive system that creates an image based on the absorption of infrared wavelengths (also referred to as a “camera”). A gas cloud containing certain hydrocarbons (i.e., leaks) will show up as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 184 of 381 black or white plumes (depending on the instrument settings and characteristics of the leak) on the optical gas imaging instrument screen. This type of instrument is the device on which our evaluation of optical gas imaging instruments is based, and the instrument to which we are referring when we use the term “optical gas imaging instrument.” These optical gas imaging instruments can be used to identify specific pieces of equipment that are leaking. Other optical methods, such as DIAL and solar occultation flux, are used primarily to assess

emissions downwind of a source. These methods cannot be used to identify specific leaking equipment; they would only measure theaggregate emissions from all equipment and any other source upwind of the measurement location. While we did review these technologies as discussed further (see the discussion under fenceline monitoring, Section IV.B.1.h of this preamble), we do

not consider DIAL and solar occultation flux methods to be suitable alternatives to EPA Method 21 for monitoring equipment leaks and are not considering them further in our technology review for equipment leaks. We expect that all refinery streams “in organic HAP service” will include at least one of the compounds visible with an optical gas imaging instrument, such as benzene, methane, propane or butane. Therefore, it is technically feasible to use an optical gas imaging instrument to detect leaks at petroleum***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 185 of 381 refineries. The optical gas imaging device can monitor many more pieces of equipment than can be monitored using instrument monitoring over the same period of time, and we expect that specific requirements for using an optical gas imaging device to detect leaks without accompanying instrument monitoring could be an appropriate alternative to traditional leak detection methods (EPA Method 21, as specified in 40 CFR part 60, Appendix A-7). Owners and operators currently have the option to use the Alternative Work Practice To Detect Leaks From Equipment (AWP) at 40 CFR 63.11(c), (d) and (e). This AWP includes provisions for using optical gas imaging in combination with annual monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7. In this proposal, we are considering the use of optical gas imaging without an accompanying requirement to conduct annual monitoring using EPA Method 21, and developing a protocol for using optical gas imaging techniques. We anticipate proposing the protocol as Appendix K to 40 CFR part 60. Rather than specifying the exact instrument that must be used, this protocol would outline equipment specifications, calibration techniques, required performance criteria, procedures for conducting surveys and training requirements for optical gas imaging instrument operators. This protocol would also contain techniques to verify that the instrument selected can image the most prevalent chemical in the monitored process unit. Because field conditions***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 186 of 381 greatly impact detection of the regulated material using optical gas imaging, the protocol would describe the impact these field conditions may have on readings, how to address them and instances when monitoring with this technique is inappropriate. Finally, the protocol would also address difficulties with identifying equipment and leaks in dense industrial areas. Pursuant to CAA Section 112(d)(6), we are proposing to allow refineries to meet the LDAR requirements in Refinery MACT 1 by monitoring for leaks via optical gas imaging in place of EPA Method 21 (of 40 CFR part 60, Appendix A-7), using the monitoring requirements to be specified in Appendix K to 40 CFR part 60. When Appendix K is proposed, we will request comments on that appendix and how those requirements would apply for purposes of this proposed action. We will not take final action adopting use of Appendix K to 40 CFR part 60 for optical gas imaging for refineries subject to Refinery MACT 1 until such time as we have considered any comments on that protocol as it would apply to refineries. We do not yet know the exact requirements of Appendix K to 40 CFR part 60, and this cannot provide a reliable estimate of potential costs at this time. However, we have calculated an initial estimate of the potential costs and emission reduction impacts, assuming that Appendix K to 40 CFR part 60 is similar to the AWP without the annual monitoring using EPA Method 21 of 40 CFR part 60, Appendix A-7.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 187 of 381 For more information on these potential impacts, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. d. Gasoline Loading Racks Loading racks are the equipment used to fill gasoline cargo tanks, including loading arms, pumps, meters, shutoff valves, relief valves and other piping and valves. Emissions from loading racks may be released when gasoline loaded into cargo tanks displaces vapors inside these containers. Refinery MACT 1 specifies that Group 1 gasoline loading racks at refineries must comply with the requirements of the National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations) in 40 CFR part 63, subpart R. The standard specified in 40 CFR part 63, subpart R is an emission limit of 10 milligrams of total organic compounds per liter of gasoline loaded (mg/L). Additionally, 40 CFR part 63, subpart R requires all tank trucks and railcars that are loaded with gasoline to undergo annual vapor tightness testing in accordance with EPA Method 27 of 40 CFR part 60, Appendix A-8. For our technology review of Group 1 gasoline loading racks subject to Refinery MACT 1, we relied on two separate analyses. First, we previously conducted a technology review for gasoline distribution facilities (71 FR 17353, April 6, 2006), in which no new control systems were identified. Second, more recently,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 188 of 381 we conducted a general analysis to identify any developments in practices, processes and control technologies for transfer operations at chemical manufacturing facilities and petroleum refineries. (See Survey of Control Technology for Transfer Operations and Analysis of Impacts for Transfer OperationControl Options, January 20, 2012, in Docket ID Number EPA-HQOAR-2010-0871.) We identified several developments as part of this analysis and evaluated the impacts of applying the developments to gasoline loading racks subject to Refinery MACT 1. We have not identified any developments beyond those in the second analysis. The identified developments include controlling loading racks above specific throughput thresholds by submerged loading and by venting displaced emissions from the transport vehicles through a closed vent system to an APCD that reduces organic regulated material emissions by at least 95 percent. We evaluated the emissions projected using this control technique for a range of different gasoline vapor pressures (to consider the different seasonal formulations of gasoline). We determined that submerged loading in combination with 95-percent control of displaced vapors would allow emissions of 12 to 42 mg/L of gasoline loaded, depending on the vapor pressure of the gasoline (see Evaluation of the Stringency of Potential Standards for Gasoline Loading Racks at Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0871.) The current Refinery***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 189 of 381 MACT 1 emission limit for gasoline loading is 10 mg/L of gasoline loaded. We did not identify any developments in practices, process and control technologies for gasoline loading racks that would reduce emissions beyond the levels already in Refinery MACT 1. Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements for gasoline loading racks pursuant to CAA Section 112(d)(6). e. Marine Vessel Loading Operations Marine vessel loading operations load and unload liquid commodities in bulk, such as crude oil, gasoline and other fuels, and naphtha. The cargo is pumped from the terminal’s large, above-ground storage tanks through a network of pipes and into a storage compartment (tank) on the vessel. The HAP emissions are the vapors that are displaced during the filling operation. Refinery MACT 1 specifies that marine tank vessel loading operations at refineries must comply with the requirements in 40 CFR part 63, subpart Y (National Emission Standards for Marine Tank Vessel Loading Operations, “Marine Vessel MACT”). We previously completed a technology review of the Marine Vessel MACT (40 CFR part 63, subpart Y) and issued amendments to subpart Y in 2011 (76 FR 22595, Apr. 21, 2011). The analysis conducted for the marine vessel loading source category specifically considered loading of petroleum products such as***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 190 of 381 conventional and reformulated gasoline. As such, the conclusions drawn from this analysis are directly applicable to marine vessel loading operations at petroleum refineries. We have not identified any developments beyond those addressed in that analysis. The Marine Vessel MACT required add-on APCD for loading operations with HAP emissions equal to or greater than 10 tpy of a single pollutant or 25 tpy of cumulative pollutants (referred to as “10/25 tpy”). In our technology review of the Marine Vessel MACT standards, we considered the use of add-on APCD for marine vessel loading operations with HAP emissions less than 10/25 tpy. We also evaluated the costs for lean oil absorption systems as add-on APCD under the Marine Vessel MACT technology review. Depending on the throughput of the vessel, costs ranged from $77,000 per ton HAP removed for barges to $510,000 per ton HAP removed for ships ($3,900 per ton VOC removed to $25,000 per ton VOC removed) (see Cost Effectiveness and Impacts of Lean Oil Absorption for Control of Hazardous Air Pollutants from Gasoline Loading - Promulgation in Docket Item Number EPA-HQ-OAR-2010- 0600-0401). We consider requiring add-on APCD for these smaller marine vessel loading operations not to be cost effective. As part of the technology review of 40 CFR part 63, subpart Y, we also considered requiring marine vessel loading operations with emissions less than 10/25 tpy and offshore operations to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 191 of 381 use submerged loading (also referred to as submerged filling). We did include this requirement in the Marine Vessel MACT. However, when we amended the Marine Vessel MACT, we specifically excluded marine vessel loading operations at petroleum refineries from these provisions, deferring the decisions to include this requirement until we performed the technology review for Refinery MACT 1. The submerged filling requirement in 40 CFR part 63, subpart Y cites the cargo filling line requirements developed by the Coast Guard in 46 CFR 153.282. We project that applying the submerged filling requirements to marine vessel loading operations at petroleum refineries will

have no costs or actual emission reductions because marine vessels carrying bulk liquids, liquefied gases or compressed gas hazardous materials are already required by 46 CFR 153.282 to have compliant “submerged fill” cargo lines that also meet the requirements of the Marine Vessel MACT. While we do not anticipate that this requirement will affect actual emissions,

it will lower the allowable emissions for these sources under Refinery MACT 1. Therefore, we are proposing, pursuant to CAA Section 112(d)(6), to amend 40 CFR part 63, subpart Y to delete the exclusion for marine vessel loading operations at petroleum refineries, which would require small marine vessel loading operations (i.e., operations with HAP emissions less than 10/25 tpy) and offshore marine vessel loading operations to use***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 192 of 381 submerged filling based on the cargo filling line requirements

in 46 CFR 153.282. f. Cooling Towers/Heat Exchange Systems Heat exchange systems include equipment necessary to cool heated non-contact cooling water prior to returning the cooling water to a heat exchanger or discharging the water to another process unit, waste management unit or to a receiving water body. Heat exchange systems are designed as closed-loop recirculation systems with cooling towers or once-through systems that do not recirculate the cooling water through a cooling tower. Heat exchangers in heat exchange systems are constructed with tubes designed to prevent contact between hot process fluids and cooling water. Heat exchangers occasionally develop leaks that allow process fluids to enter the cooling water. The volatile HAP and other volatile compounds in these process fluids are then emitted to the atmosphere due to stripping in a cooling tower or volatilization from a cooling water pond or receiving water body. We established MACT standards for heat exchange systems at refineries in 2009 (see 74 FR 55686, October 28, 2009, as amended at 75 FR 37731, June 30, 2010). The EPA received a petition for reconsideration from the American Petroleum Institute (API) and granted reconsideration on certain issues. On June 20, 2013, we issued a final rule addressing the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 193 of 381 petition, clarifying rule provisions, and revising the monitoring provisions to provide additional flexibility (78 FR 37133). We are not aware of any developments in processes, practices or control technologies beyond those we recently considered in our analysis of emission reduction techniques for heat exchange systems, which can be found in the docket (Docket Item Number EPA-HQ-OAR-2003-0146-0229). Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements for heat exchange systems pursuant to CAA Section 112(d)(6). g. Wastewater Treatment Wastewater collection includes components such as drains, manholes, trenches, junction boxes, sumps, lift stations and sewer lines. Wastewater treatment systems are divided into threecategories: primary treatment operations, which include oilwater separators and equalization basins; secondary treatment systems, such as biological treatment units or steam strippers; and tertiary treatment systems, which further treat or filter wastewater prior to discharge to a receiving body of water or reuse in a process. Refinery MACT 1 requires wastewater streams at a new or existing refinery to comply with 40 CFR 61.340 through 61.355 of the NESHAP for Benzene Waste Operations (BWON) in 40 CFR part 61, subpart FF. The BWON requires control of wastewater***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 194 of 381 collection and treatment units for facilities with a total annual benzene quantity of greater than or equal to 10 megagrams per year (Mg/yr). Individual waste streams at refineries with a total annual benzene quantity greater than or equal to 10 Mg/yr are not required to adopt controls if the flow-weighted annual average benzene concentration is less than 10 parts per million by weight (ppmw) or the flow rate is less than 0.02 liters per minute at the point of generation. The BWON requires affected waste streams to comply with one of several options for controlling benzene emissions from waste management units and for treating the wastes containing benzene (55 FR 8346, 58 FR 3095). Although the BWON specifically regulates benzene only, benzene is considered a surrogate for organic HAP from wastewater treatment systems at petroleum refineries. Benzene is present in nearly all refinery process streams. It is an excellent surrogate for wastewater pollutants because its unique chemical properties cause it to partition into the wastewater more readily than most other organic chemicals present at petroleum refineries. We stated our rationale regarding the use of benzene as a surrogate for refinery HAP emissions from wastewater in the original preamble to Refinery MACT 1 (59 FR 36133).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 195 of 381 We performed a technology review for wastewater treatment systems to identify different control technologies for reducing emissions from wastewater treatment systems. We also reviewed the current standards for wastewater treatment systems in different rules including the HON, the proposed NSPS for wastewater systems at petroleum refineries, and the BWON (See Technology Review for Industrial Wastewater Collection and Treatment Operations at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682.) We identified several developments in processes, practices and control technologies for wastewater treatment, and evaluated the cost and cost effectiveness of each of those developments: (1) requiring wastewater drain and tank controls at refineries with a total annualized benzene quantity of less than 10 Mg/yr; (2) requiring specific performance parameters for an enhanced biological unit (EBU) beyond those required in the BWON; and (3) requiring wastewater streams witha VOC content of 750 ppmv or higher to be treated by steamstripping prior to any other treatment process for facilities with high organic loading rates (i.e., facilities with total annualized benzene quantity of 10 Mg/yr or more). These options are, for the most part, independent of each other, so the costs and cost effectiveness of each option are considered separately. Option 1 was evaluated because refineries with a total annual benzene quantity of less than 10 Mg/yr are not required***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 196 of 381 to install additional controls on their wastewater treatment system. Thus, these refineries are limiting the amount of benzene produced in wastewater streams to less than 10 Mg/yr, which effectively limits their benzene emissions from wastewater to less than 10 Mg/yr. Option 2 is intended to improve the performance of wastewater treatment systems that use an EBU, and thereby achieve additional emission reductions. The BWON, as it applies under Refinery MACT 1, has limited operational requirements for an EBU. Available data suggest that these systems are generally effective for degrading benzene and other organic HAP; however, without specific performance or operational requirements, the effectiveness of the EBU to reduce emissions can be highly variable. Under option 2, more stringent operating requirements

are considered for the EBU at refineries. Option 3 considers segregated treatment of wastewater streams with a volatile organic content of greater than 750 ppmw, or high-strength wastewater streams, directly in a steam stripper (i.e., not allowing these streams to be mixed and treated in the EBU). Preliminary investigations revealed direct treatment of wastewater by steam-stripping is only cost effective for high-strength wastewater streams of sufficient quantities. For more detail regarding the impact analysis for these control options, see Technology Review for Industrial***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 197 of 381 Wastewater Collection and Treatment Operations at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682. Table 8 provides the nationwide impacts for the control options. Based on the costs and emission reductions for each of the options, we consider none of the options identified to be cost effective for reducing emissions from petroleum refinery wastewater treatment systems. We are proposing that it is not necessary to revise Refinery MACT 1 to require additional controls for wastewater treatment systems pursuant to CAA Section 112(d)(6). **Table 8. Nationwide Emissions Reduction and Cost Impacts of Control Options Considered for Wastewater Treatment Systems at**  **Petroleum Refineries**

**Control Option**  **Capital Cost**  **(million $) Annualized**  **Costs (million** 

**$/yr) Emissions**  **Reduc t**  **ion, VOC (tpy)**  **Emissions Reduction,**  **HAP (tpy) Cost** **Effective ness**  **($/ton**

**VOC) Cost** **Effective ness**  **($/ton**

**HAP)** 1 19.7 4.2 592 158 7,100 26,600 2 223 28.6 2,060 549 13,900 52,100 3 142 50.7 3,480 929 14,500 54,500

h. Fugitive Emissions The EPA recognizes that, in many cases, it is impractical to directly measure emissions from fugitive emission sources at refineries. Direct measurement of fugitive emissions from sources such as wastewater collection and treatment operations, equipment leaks and storage vessels can be costly and difficult, especially if required to be deployed on all sources of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 198 of 381 fugitives within a refinery and certainly on a national scale. This is a major reason why fugitive emissions associated with refinery processes are generally estimated using factors and correlations rather than by direct measurement. For example, equipment leak emissions are estimated using factors and

correlations between leak rates and concentrations from EPA Method 21 instrument monitoring. Fugitive emissions from

wastewater collection and treatment are estimated based on process data, material balances and empirical correlations. Relying on these kinds of approaches introduces uncertainty into the emissions inventory for fugitive emission sources. For each of the individual fugitive emission points, we evaluated developments in processes, practices and control technologies for measuring and controlling fugitive emissions from these sources. For storage vessels, we considered but are not proposing to require EPA Method 21 of 40 CFR part 60, Appendix A-7 or optical gas imaging monitoring to identify fugitive emissions from each individual storage vessel. For equipment leaks, we considered and are proposing to adopt the use of optical gas imaging devices following 40 CFR part 60, Appendix K in lieu of using EPA Method 21. For wastewater treatment systems, we considered but are not proposing to require enhanced monitoring and operating limits for the EBU. The monitoring techniques evaluated in the subsections above***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 199 of 381 have been very specific to the emission points being evaluated and are generally labor intensive. Given the number of potential fugitive emission points at refineries, coupled with the difficulty of accessing some release points because of safetyconcerns makes more frequent or additional direct or pointspecific monitoring beyond what is being proposed above impractical.Although we are not proposing to require several sourcespecific monitoring approaches that we evaluated, we remain concerned regarding the potential for high emissions from these regulated sources due to the difficulties in monitoring actual emission levels. For example, the regulations require infrequent monitoring of storage tank floating roof seals (visual inspections are required annually and direct inspections of primary seals are required only when the vessel is emptied and degassed, or no less frequently than once every 5 years for internal floating roofs or 10 years for external floating roofs with secondary seals). Given these inspection frequencies, tears or failures in floating roof seals may exist for years prior to being noticed, resulting in much higher emissions than expected or estimated for these sources in the emissions inventory. Similarly, water seals, which are commonly used to control emissions from wastewater collection drain systems, may be difficult to monitor (e.g., some are underground so visible***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 200 of 381 emissions tests cannot be performed) and are subject only to infrequent inspections. During hot, dry months, these water seals may dry out, leaving an open pathway of vapors to escape from the collection system to the atmosphere. Significant emission releases may occur from these “dry” drains, which could persist for long periods of time prior to the next required inspection. In light of the impracticality of directly monitoring many of these fugitive emission sources on a regular basis, which would help ensure these fugitive sources are properly functioning to the extent practical, we evaluated a fenceline monitoring program under CAA Section 112(d)(6). In this section, we evaluate the developments in processes, practices and control technologies for measuring and controlling fugitive emissions from the petroleum refinery as a whole through fenceline monitoring techniques. Fenceline monitoring will identify a significant increase in emissions in a timely manner (e.g., a large equipment leak or a significant tear in a storage vessel seal), which would allow corrective action measures to occur more rapidly than it would if a source relied solely on the traditional infrequent monitoring and inspection methods. Small increases in emissions are not likely to impact the fenceline concentration, so a fenceline monitoring approach will generally***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 201 of 381 target larger emission sources that have the most impact on the ambient pollutant concentration near the refinery. Historically, improved information through measurement data has often led to emission reductions. However, without a specific emission limitation, there may be no incentive for owners or operators to act on the additional information. Therefore, as part of the fenceline monitoring approach, we seek to develop a not-to-be exceeded annual fenceline concentration, above which refinery owners or operators would be required to implement corrective action to reduce their fenceline concentration. We sought to develop a maximum fenceline

concentration action level that is consistent with the emissions projected from fugitive sources compliant with the provisions of Refinery MACT 1. Thus, this section details our technology review to identify developments in processes, practices and technologies for measuring air toxics at the fenceline of a facility. Upon selection of a specific fenceline monitoring method, we provide our rationale for the specific details regarding the fenceline monitoring approach, including requirements for siting the monitors, procedures for adjusting for background interferences, selection of the fenceline action level, and requirements for

corrective action.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 202 of 381 Developments in monitoring technology and practices. The

EPA reviewed the available literature and identified several different methods for measuring fugitive emissions around a petroleum refinery. These methods include: (1) passive diffusive tube monitoring networks; (2) active monitoring station networks; (3) ultraviolet differential optical absorption spectroscopy (UV-DOAS) fenceline monitoring; (4) open-path Fourier transform infrared spectroscopy (FTIR); (5) DIAL monitoring; and (6) solar occultation flux monitoring. We considered these monitoring methods as developments in practices under CAA Section 112(d)(6) for purposes of all fugitive emission sources at petroleum refineries. Each of these methods has its own strengths and weaknesses, which are discussed in the following paragraphs. Fenceline passive diffusive tube monitoring networks employ a series of diffusive tube samplers at set intervals along the fenceline to measure a time-integrated ambient air concentration at each sampling location. A diffusive tube sampler consists of a small tube filled with an adsorbent, selected based on the pollutant(s) of interest, and capped with a specially designed

cover with small holes that allow ambient air to diffuse into the tube at a small, fixed rate. Diffusive tube samplers have been demonstrated to be a cost-effective, accurate technique for measuring ambient concentrations of pollutants resulting from***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 203 of 381 fugitive emissions in a number of studies. 25,26 In addition, diffusive samplers are used in the European Union to monitor and maintain air quality, as described in European Union directives 2008/50/EC and Measurement Standard EN 14662-4:2005 for benzene. The International Organization for Standardization developed a standard method for diffusive sampling (ISO/FDIS 16017-2). In 2009, the EPA conducted a year-long fenceline monitoring pilot project at Flint Hills West Refinery in Corpus Christi, Texas, to evaluate the viability and performance of passive diffusive sampling technology. Overall, we found the technology to be capable of providing cost effective, high spatial-density long-term monitoring. This approach was found to be relatively robust and implementable by modestly trained personnel and provided useful information on overall concentration levels and source identification using simple upwind and downwind comparisons. 27 Combined with on-site meteorological measurements, 2-week time-integrated passive monitoring has been shown to provide useful facility emission diagnostics.

25 McKay, J., M. Molyneux, G. Pizzella, V. Radojcic. Environmental Levels of Benzene at the Boundaries of Three European Refineries, prepared by the CONCAWE Air Quality Management Group’s Special Task Force on Benzene Monitoring at Refinery Fenceline (AQ/STF-45), Brussels, June 1999.

26 Thoma, E.D., M.C. Miller, K.C. Chung, N.L. Parsons, B.C. Shine. 2011. Facility Fenceline Monitoring using Passive Sampling, J. Air & Waste Manage Assoc. 61: 834-842.

27 Thoma, et al, 2011.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 204 of 381 There are several drawbacks of time-integrated sampling, including the lack of immediate feedback on the acquired data and the loss of short-term temporal information. Additionally, time-integrated monitoring usually requires the collected sample to be transported to another location for analysis, leading to possible sample integrity problems (e.g., sample deterioration, loss of analytes, and contamination from the surrounding environment). However, time-integrated monitoring systems are generally lower-cost and require less labor than time-resolved monitoring systems. Furthermore, while passive diffusive tubemonitoring employs time-integrated sampling, these timeintegrated samples still represent much shorter time intervals (2 weeks) than many of the current source-specific monitoring and inspection requirements (annually or less frequently). Consequently, passive diffusive tube monitoring still allows earlier detection of significant fugitive emissions than conventional source-specific monitoring. Active monitoring station networks are similar to passive diffusive tube monitoring networks in that a series of discrete sampling sites are established; however, each sampling location uses a pump to actively draw ambient air at a known rate through an adsorption tube. Because of the higher sampling rate, adsorption tubes can be analyzed on a daily basis, providing additional time resolution compared to diffusive tube sampling***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 205 of 381 systems. Alternatively, the active sampling system can directly feed an analyzer for even more time resolution. However, this direct analysis of ambient air generally has higher detection limits than when the organic vapors are collected and concentrated on an adsorption matrix prior to analysis. Active monitoring stations have been used for a variety of pollutants in a variety of settings and the methods are well-established. However, compared to the passive diffusive tube monitoringstations, the sampling system is more expensive, more laborintensive, and generally requires highly-trained staff to operate. UV-DOAS fenceline monitoring is an “open-path” technology. An electromagnetic energy source is used to emit a beam of electromagnetic energy (ultraviolet radiation) into the air towards a detection system some distance from the energy source (typically 100 to 500 meters). The electromagnetic energy beam interacts with components in the air in the open path between the energy source and the detector. The detector measures the disruptions in the energy beam to determine an average pollutant concentration across the open path length. Because the UV-DOAS system can monitor integrated concentrations over a fairly long path-length, fewer monitoring “stations” (energy source/detector systems) would be needed to measure the ambient concentration around an entire refinery. However, each UV-DOAS monitoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 206 of 381 system is more expensive than an active or passive monitoring station and generally requires significant instrumentation shelter to protect the energy source and analyzer when used for long-term (ongoing) measurements. Advantages of UV-DOAS systems include providing real-time measurement data with detection limits in the low parts per billion range for certain compounds. Fog or other visibility issues (e.g., dust storm, high pollen, wildfire smoke) will interfere with the measurements. UV-DOAS systems have been used for fenceline monitoring at several U.S. petroleum refineries and petrochemical plants. UV-DOAS monitoring systems are specifically included as one of the measurement techniques suitable under EPA’s Other Test Method 10 (OTM-10). 28 Open-path FTIR is similar to UV-DOAS monitoring except that an infrared light source and detector system are used. Like the UV-DOAS monitoring approach, the open-path FTIR monitoring system will measure the average pollutant concentration across the open path length between the infrared source and detector. Path lengths and equipment costs for an open-path FTIR system are similar to those for a UV-DOAS system, and the open-path FTIR system provides real-time measurement data. The open-path FTIR system has spectral interferences with water vapor, CO and

28 “Optical Remote Sensing for Emission Characterization from Non-Point Sources.” Final ORS Protocol, June 14, 2006. Available at: http://www.epa.gov/ttn/emc/prelim/otm10.pdf.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 207 of 381

CO 2 , which can impact the lower detection limit for organic vapors. Open-path FTIR fenceline monitoring has also been used to measure ambient air concentrations around several petroleum refineries and petrochemical plants. Open-path FTIR isspecifically included as a measurement technique in EPA’s OTM10. Although open-path FTIR can be used to measure a largernumber of compounds than UV-DOAS, the detection limit of openpath FTIR for benzene is higher than for UV-DOAS, as noted in OTM-10. In other words, open-path FTIR is not as sensitive to benzene levels as is UV-DOAS. As benzene is an important pollutant from fugitive sources at petroleum refineries and can often be used as a surrogate for other organic HAP emissions, this high detection limit for benzene is a significant disadvantage. Thus, for the purposes of measuring organic HAP from fugitive sources at the fenceline of a petroleum refinery, a UV-DOAS monitoring system is expected to be more sensitive than an open-path FTIR system. As the cost and operation of open-path FTIR and UV-DOAS systems are very comparable, the benzene detection limit issue is a significant differentiator between these two methods when considering fenceline monitoring to measure fugitives around a petroleum refinery. DIAL monitoring systems employ a pulsed laser beam across the measurement path. Small portions of the light are backscattered due to particles and aerosols in the measurement***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 208 of 381 path. This backscattered light is collected through a telescope system adjacent to the laser and measured via a sensitive light detector. The timing of the received light provides a measure of the distance of the emission plume. Two different wavelengths of light are pulsed in quick succession: one wavelength that is absorbed strongly by the pollutant of interest and one that is not absorbed. The difference in the returned signal strength between these two light pulses provides a measure of the concentration of the pollutant. Thus, a unique advantage of the DIAL monitoring system is that it can provide spatially resolved pollutant concentrations in two dimensions. Measurements can be made in a relatively short period of time, so the method also provides good time resolution. The DIAL monitoring system has been used in a variety of studies to measure emissions from petroleum refinery and petrochemical sources. It is typically used for specific, shorter-term studies (one to several weeks in duration). The equipment is expensive, has limited availability in the U.S., and requires highly trained professionals to operate. Although DIAL monitoring is included as an appropriate method for EPA’s OTM-10, there are no known long-term applications of this technology for the purpose of fenceline monitoring. Given the limited availability of the equipment and qualified personnel to operate the equipment, we do not consider DIAL monitoring to be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 209 of 381 technically feasible for the purposes of ongoing, long-term fenceline monitoring. The last fenceline monitoring method evaluated was solar

occultation flux. Solar occultation flux uses the sun as the light source and uses an FTIR or UV detector to measure the average pollutant concentration across the measurement path. In this case, the measurement path is vertical. In order to measure the concentrations around an industrial source, the measurement device is installed in a specially equipped van, which is slowly driven along the perimeter of the facility. Measurement signal strength and a global positioning system (GPS) enables determination of pollutant concentrations along the perimeter of the site. This method provides more spatial resolution of the emissions than the UV-DOAS or open-path FTIR methods and is less expensive than a DIAL system. It has the advantage that only one monitoring system is needed per facility, assuming a mobile device is used. Disadvantages of this method include the need of full-time personnel to drive the equipment around the perimeter of the facility (or the need to buy a detector for each measurement location around the perimeter of the facility, if set locations are used), potential accessibility issues for some fenceline locations (e.g., no road near the fenceline), and the measurement method cannot be used at night or during cloudy periods. It would be possible to purchase numerous detection***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 210 of 381 devices and establish fixed monitoring stations similar to the passive or active monitoring approaches described earlier, but this would be very expensive. Furthermore, any application of solar occultation flux is dependent on the sun, so this approach would mean significant periods each calendar day when the monitoring system would not be able to provide data. Based on our evaluation of this technology, we determined that this method is not a reasonable approach for monitoring fenceline concentrations of pollutants around a petroleum refinery on a long-term, ongoing basis. We are soliciting comment on the application of alternative monitoring techniques previously discussed for purposes of fenceline monitoring at refineries. Costs associated with fenceline monitoring alternatives. Based on our review of available monitoring methods, we determined that the following monitoring methods were technically feasible and appropriate for monitoring organic HAP from fugitive emission sources at the fenceline of a petroleum refinery on a long-term basis: 1) passive diffusive tube monitoring networks; (2) active monitoring station networks; (3) UV-DOAS fenceline monitoring; and (4) open-path FTIR. While DIAL monitoring and solar occultation flux monitoring can be used for short-term studies, we determined that these methods were not appropriate for continuous monitoring at petroleum refineries. This section evaluates the costs of these technically feasible***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 211 of 381 monitoring methods. As noted previously, the cost identified for the open-path monitoring methods (UV-DOAS and FTIR) are very similar. Therefore, we developed costs for only the UV-DOAS system because this method provides lower detection limits for pollutants of interest (specifically, benzene). Costs for the fenceline monitoring methods are dependent on the sampling frequency (for passive and active monitoring locations) and the number of monitoring locations needed based on the size and geometry of the facility. For the open-path methods, we estimated that four monitoring systems (along the east, west, north and south fencelines) would be needed, regardless of the size of the refinery. Some fencelines at larger refineries may be too long for a single open path length,but we did not vary the number of detectors needed for the openpath systems based on refinery size in order to provide a reasonable lower-cost estimate for the open-path monitoring option. For small petroleum refineries (less than 750 acres), we estimated 12 passive or active monitoring stations would be sufficient. For medium-sized refineries (750 to 1,500 acres), we estimated 18 monitoring stations would be required; for large refineries (greater than 1,500 acres), we estimated that 24 monitoring stations would be needed. For the passive diffusive tube monitoring we assumed a 2-week sampling interval; for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 212 of 381 active monitoring stations, we assumed a daily sampling frequency. We estimated the first year installation and equipment costs for the passive tube monitoring system could cost up to $100,000 for larger refineries (i.e., 24 sampling locations). Annualized costs for ongoing monitoring are projected to be approximately $40,000 per year, assuming the ongoing sample analyses are performed in-house. Capital costs for active sampling systems were estimated to be approximately twice that of the passive system for the larger refinery. Ongoing costs were more than 10 times higher, however, due to the daily sampling frequency. Equipment costs for a single UV-DOAS system were estimated to be about $100,000, so a complete fenceline monitoring system (four systems plus shelters) was estimated to cost more than $500,000. A refinery using this technology for

two fenceline locations estimated the annualized cost of calibrating and maintaining these systems approaches $1-million per year. (See Fenceline Monitoring Technical Support Document, in Docket ID Number EPA-HQ-OAR-2010-0682). Table 9 provides the nationwide costs of the monitoring approaches as applied to all U.S. petroleum refineries.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 213 of 381 **Table 9. Nationwide Cost Impacts of Fenceline Monitoring Options at Petroleum Refineries** 

**Monitoring Option Monitoring Option Description**  **Capital Cost**  **(million $) Annual**  **i zed**  **Costs (million** 

**$/yr)** 1 Passive diffusive tube monitoring network 12.2 5.58 2 Active sampling monitoring network 20.6 33.1 3 Open-path monitoring (UV-DOAS, FTIR) 71.0 45.6

The primary goal of a fenceline monitoring network is to ensure that the emission reductions projected by the Refinery MACT 1 standards for fugitive sources are achieved in practice. The cumulative nationwide emissions from storage vessels, equipment leaks, and wastewater treatment systems projected after the implementation of these proposed standards is approximately 37,000 tpy VOC and 5,300 tpy HAP. It is difficult

to estimate the emission reductions that the fenceline monitoring network will achieve. If a facility is experiencing no significant leaks from the required control equipment, then we anticipate that emission reductions resulting from the fenceline monitoring would be minimal. However, where one or more significant leaks are occurring at a facility, a fenceline monitoring system would provide for identification of such leaks much earlier than current monitoring requirements and would also help ensure that emissions beyond those projected from implementation of the MACT are quickly addressed. We note that any costs for a fugitive monitoring system would be offset, to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 214 of 381 some extent, by product recovery since addressing these leaks more quickly than would otherwise occur based on the more infrequent monitoring required would reduce product losses. Based on the low cost and relative benefits of passivemonitoring, which include the ability to generate timeintegrated concentration measurements at low detection limits, coupled with relative ease of deployment and analysis, the EPAis proposing to require refineries to deploy passive timeintegrated samplers at the fenceline. These samplers would monitor the level of fugitive emissions that reach the fenceline from all fugitive emission sources at the facility. The EPA is proposing to require fugitive emission reductions if fenceline concentrations exceed a specified concentration action level, as described further below. These proposed fenceline monitoring requirements complement the EPA’s proposal to allow the use of the optical gas imaging camera as described in Appendix K of 40 CFR part 60 as an alternative work practice for measuring emissions from equipment leaks, in lieu of monitoring with EPA Method 21 of 40 CFR part 60, Appendix A-7 (see Section IV.B.1.c of this preamble for further discussion). Both approaches utilize low-cost methods to help ensure that total fugitives from a facility are adequately controlled. Because there is no current EPA test method for passive diffusive tube monitoring, as part of this action we are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 215 of 381 proposing specific monitor citing and sample collection requirements as EPA Method 325A of 40 CFR part 63, Appendix A, and specific methods for analyzing the sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A. We are proposing

to establish an ambient concentration of benzene at the fenceline that would trigger required corrective action. A brief summary of the proposed fenceline sampling requirements and our rationale for selecting the corrective action concentration levels are provided below. Siting, design and sampling requirements for fenceline monitors. The EPA is proposing that passive fenceline monitors collecting 2-week time-integrated samples be deployed to measure fenceline concentrations at refineries. We are proposing that refineries deploy passive samplers at 12 to 24 points circling the refinery perimeter. A primary requirement for a fenceline monitoring system is that it provides adequate spatial coverage for determination of representative pollutant concentrations at the boundary of the facility or operation. In an ideal scenario, fenceline monitors would be placed so that any fugitive plume originating within the facility would have a high probability of intersecting one or more monitors, regardless of wind direction. This proposed monitoring program would require that monitors be placed at 15 to 30 degree intervals along the perimeter of the refinery, depending on the size of the facility. For small***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 216 of 381 refineries (less than 750 acres), monitors should be placed at 30 degree intervals, for a total of 12 locations; for facilities that are larger than 750 acres and less than 1,500 acres, monitors should be placed at 20 degree intervals, at 18 locations; and for facilities greater than 1,500 acres, monitors should be placed at 15 degree intervals, accounting for 24 locations. We have also established an alternative siting procedure where monitors can be placed every 2,000 feet along the fenceline of the refinery, which may be easier to implement, especially for irregularly-shaped facilities. In proposing these requirements for the number and location of required monitors, the EPA assumes that all portions of the facility are contiguous such that it is possible to define a single facility boundary or perimeter, although this perimeter may be irregular in shape. We request comment on how these monitoring requirements should be adapted for instances where one or more portions of the facility are not contiguous, and on the number and location of facilities for which special fenceline monitoring requirements to accommodate non-contiguous operations might apply. We are proposing that the highest concentration of benzene, as an annual rolling average measured at any individual monitor and adjusted for background (see below), would be compared against the concentration action level in order to determine if there are significant excess emissions of fugitive emissions***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 217 of 381 that need to be addressed. Existing sources would be required to deploy samplers no later than 3 years after the effective date of the final rule; new sources would be required to deploy samplers by the effective date of the final rule or startup, whichever is later. Because the proposed concentration action level is composed of 1 year’s worth of data, we are proposing that refinery owners and operators would be required to demonstrate compliance with the concentration action level for the first time 1 year following the compliance date, and thereafter on a 1-year rolling annual average basis (i.e., considering results from the most recent 26 consecutive 2-week sampling intervals and recalculating the average every 2 weeks). Benzene as an appropriate target analyte. Passive diffusive

tube monitors can be used to determine the ambient concentration of a large number of compounds. However, different sorbent materials are typically needed to collect compounds with significantly different properties. Rather than require multiple tubes per monitoring location and require a full analytical array of compounds to be determined, which would significantly increase the cost of the proposed fenceline monitoring program, we are proposing that the fenceline monitors be analyzed specifically for benzene. Refinery owners or operators may elect to do more detailed speciation of the emissions, which could help identify the process unit that may be contributing to a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 218 of 381 high fenceline concentration, but we are only establishing monitoring requirements and action level requirements for benzene. We consider benzene to be an excellent surrogate for organic HAP from fugitive sources for multiple reasons. First, benzene is ubiquitous at refineries, and is present in nearly all refinery process streams such that leaking components generally will leak benzene at some level (in addition to other compounds). Benzene is also present in crude oil and gasoline, so most storage tank emissions include benzene. As described previously in our discussion of wastewater treatment systems, benzene is also a very good surrogate for organic HAP emissions from wastewater and is already considered a surrogate for organic HAP emissions in the wastewater treatment system control requirements in Refinery MACT 1. Second, the primary releases of benzene occur at ground level as fugitive emissions from process equipment, storage vessels and wastewater collection and treatment systems, and the highest ambient benzene concentrations outside the facility will likely occur near the property boundary near ground level, so fugitive releases of benzene will be effectively detected at the ground-level monitoring sites. According to the emissions inventory we have relied on for this proposed action, 85 percent of benzene emissions from refineries result from ground-level fugitive emissions from equipment and wastewater collection and treatment***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 219 of 381(see the Component 2 database contained in Docket ID Number EPAHQ-OAR-2010-0682). Finally, benzene is present in nearly all process streams. Therefore, the presence of benzene at the

fenceline is also an indicator of other air toxics emitted from fugitive sources at refineries. For the reasons discussed above, we believe that benzene is the most appropriate pollutant to monitor. We believe that other compounds, such as PAH or naphthalene, would be less suitable indicators of total fugitive HAP for a couple of reasons. First, they are prevalent in stack emissions as well as fugitive emissions, so there is more potential for fenceline monitors to pick up contributions from non-fugitive sources. In contrast, almost all benzene comes from fugitive sources, so monitoring

for benzene increases our confidence that the concentration detected at the fenceline is from fugitives. Second, as compared to benzene, these other compounds are expected to be present at lower concentrations and, therefore, would be more difficult to measure accurately using fenceline monitoring. We request comments on the suitability of selecting benzene or other HAP, including PAH or naphthalene, as the indicator to be monitored by fenceline samplers. We also request comment on whether it would be appropriate to require multiple HAP to be monitored at the fenceline considering the capital and annual cost for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 220 of 381 additional monitors, and if so, which pollutants should be

monitored. Adjusting for background benzene concentrations. Under this proposed approach, absolute measurements along a facility fenceline cannot completely characterize which emissions are associated with the refinery and which are associated with other background sources. The EPA recognizes that sources outside the refinery boundaries may influence benzene levels monitored at the fenceline. Furthermore, background levels driven by local upwind sources are spatially variable. Both of these factors

could result in inaccurate estimates of the actual contribution of fugitive emissions from the facility itself to the concentration measured at the fenceline. Many refineries and petrochemical industries are found side-by-side along waterways or transport corridors. With this spatial positioning, there is a possibility that the local upwind neighbors of a facility could cause different background levels on different sides of the facility. To account for background concentrations (i.e., to

remove the influence of benzene emissions from sources outside the refinery on monitored fenceline values), we are proposing to adjust monitored fenceline values to account for background

concentrations as described below. We solicit comments on alternative approaches for making these adjustments for background benzene.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 221 of 381 Fenceline-deployed passive samplers measure concentrations that originate from both the observed facility and from off-sitesources. The relative contribution of the facility versus offsite source(s) to the measured concentration depends on the emission levels of the observed facility and off-site sources (including both near-field and remote sources), transporting wind direction and atmospheric dispersion. The ability to identify facility and off-site source contributions is reliant on the measurement scheme selected. The most basic (and lowest cost) approach involves different calculations using 2-week deployed samplers located only at the facility fenceline. Greater discrimination capability is found by adding passive samplers to specific areas of the facility, reducing the time duration of the passive samplers, and coupling measured meteorology information to the passive sampler analysis. Selective use of time-resolved monitoring or wind sector sampling approaches provides the highest source and background discrimination capability. The approach we are proposing seeks

to remove off-site source contributions to the measured fenceline concentrations to the greatest extent possible using

the most cost-effective measurement solutions. The highest fenceline concentration (HFC) for each 2-week sampling period can be expressed as: 

##   i i 

### OSC MFC Maximum HFC

 ***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 222 of 381

where: HFC = highest fenceline concentration, corrected for background.

MFC i = measured fenceline concentration for the sampling period at monitoring location i.

OSC i = estimated off-site source contribution for the sampling period at monitoring location i. The off-site source contribution (OSC) consists of two primary components: (1) a slowly varying, spatially uniform background (UB) concentration and, in some cases, (2) potential near-field interfering sources.

i i 

### NFS UB OSC  

where: UB = uniform background concentration.

NFS i = near-field interfering source concentration contribution at monitoring location i. In some deployment scenarios (such as spatially isolated facilities), the major off-site source component can be identified as background concentrations that are uniform across the facility fenceline and neighboring area. In this scenario, a

UB concentration level can be determined and subtracted from the measured fenceline concentrations for each sampling period. This can be accomplished through use of facility-measured or otherwise available, quality assured time-resolved (or wind***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 223 of 381 sector-resolved) background monitoring data, or from placement of additional passive samplers at upwind locations away from the facility fenceline and other sources. In other scenarios, such as where other industrial sources or a highway are located nearby, background concentrations are likely not uniform. These outside sources would influence some, but not perhaps not all, fenceline monitors and, therefore, the true “background” concentration would vary, depending where on the fenceline the measurement was taken. In this case, background is not uniform, and monitoring location-specific near-field interfering source (NFS) values would need to be

determined. Due to the difficulties associated with determining location-specific NFS values, we are proposing to approximate OSC by using the lowest measured concentration (LMC) at the facility fenceline for that period. In this case, the HFC for the monitoring period, corrected for background, would be

calculated as: 

### LMC HMC C HFC

   

where:

Δ C = concentration difference between the highest and lowest measured concentrations for the sampling period. HMC = highest measured fenceline concentration for the sampling period.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 224 of 381 LMC = lowest measured fenceline concentration for the sampling period. This alternative is directly applicable for all refinery locations and requires no additional, off-site, upwind monitors, the placement of which is impossible to prescribe a priori. Use of LMC provides a reasonable proxy for OSC in most cases, but

can over- or underestimate OSC in some cases. In locations where there are few upwind source contributions and where wind direction is relatively consistent, upwind passive samples on the fenceline can provide a realistic approximation of the actual off-site background levels. As the meteorology becomes more complicated (e.g., mixed wind directions, higher percentage of calm winds), the LMC will reflect a progressively larger amount of emissions from the facility itself, so differential calculations may underestimate the true HFC for some monitoring periods (by inadvertently allowing some facility emissions to be subtracted as part of “background”). On the other hand, if a near-field source impacts the highest measured concentration monitoring location significantly, but contributes little to the monitoring location with the LMC, the LMC differential calculation (i.e., Δ C) could lead to an artificially elevated assessment of the highest fenceline concentration, corrected for background.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 225 of 381 Based on our examination of previous fenceline monitoring results, we expect that the use of the LMC differential will provide an accurate method by which to determine HFC. Therefore, we are not proposing to limit the use of the LMC differential

calculation in cases where there are no near-field sources and where mixed wind direction (or calm wind) is common. In these special cases, use of the UB concentration alone (no NFS term) may be more accurate than using LMC. We are seeking comment on how to identify conditions under which the LMC differential may underestimate the highest fenceline concentration, corrected for background, and the need to require facilities to determine and

use UB rather than LMC in these cases. We also recognize that under different site-specific conditions, the NFS contribution may affect certain fenceline monitoring stations more than others, causing the LMC differential calculation to overestimate the facility’s contribution to the highest fenceline concentration. Therefore, we are also proposing to allow owners or operators of petroleum refineries to develop site-specific monitoring plans to

determine UB and NFS i . If standard 2-week passive fenceline data and site analysis indicate potential near-field off-site source interferences at a section of the refinery, the proposal allows the owner or operator to conduct additional sampling strategies to determine***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 226 of 381 a local background (OSC term) for use in the HFC calculation. The owner or operator would be required to report the basis for this correction, including analyses used to identify the sources and contribution of benzene concentration to the passive sampler concentration, within 45 days of the date the owner or operator

first measures an exceedance of the concentration action level. We envision that facilities would implement these additional strategies to refine fenceline concentration estimates only if appropriate given site-specific characteristics and only if HFC determined by the LMC approach is likely to exceed the concentration action level (see discussion below regarding this action level). Facilities with HFC below the concentration action level based on the simple LMC differential calculation would not be required to make any further demonstration of the influence of background sources on

concentrations measured at the fenceline. For facilities where additional background adjustment is appropriate, optional strategies could include deployment of additional passive samplers at distances from the fenceline (toward and away from suspected NFS) and reducing the time intervals of passivedeployments to increase time resolution and wind directioncomparison capability. In complex cases, such as two refineries sharing a common fenceline, wind-sector sampling or various***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 227 of 381 forms of time-resolved monitoring may be required to ascertain

the fenceline concentrations. We are proposing that owners or operators of petroleum refineries electing to determine monitoring location-specific NFS concentrations must prepare and submit a site-specific monitoring plan. The monitoring plan is required to identify specific near-field sources, identify the location and type of monitors used to determine UB and NFS concentrations, identify the monitoring location(s) for which the NFS concentrations would apply, and delineate the calculations to be used to determine monitoring location specific NFS concentrations (for those monitoring locations impacted by the near-field source). We are proposing that the site-specific monitoring plan must be submitted to the Administrator for approval and receive approval prior to its use for determining HFC values. The EPA requests comment on the most appropriate approach(es) for adjusting measured fenceline concentrations for background contributions, including (in complex cases) where meteorology is highly variable or where one or more near-field

off-site sources affect the measured fenceline concentration (MFC) at a refinery. We are also seeking comment on the adequacyof the proposed requirements for developing and approving sitespecific monitoring plans.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 228 of 381 Concentration action level. As mentioned above, the EPA is proposing to require refineries to take corrective action to reduce fugitive emissions if monitored fenceline concentrations exceed a specific concentration action level on a rolling annual average basis. We selected this fenceline action level to be consistent with the maximum projected fenceline concentration for petroleum refineries when all fugitive sources are controlled to the levels projected after the implementation of these proposed standards. We estimated the long-term ambient post-control benzene concentrations at each petroleum refinery using the post-control emission inventory and EPA’s American Meteorological Society/EPA Regulatory Model dispersion modeling system (AERMOD). Concentrations were estimated by the model at a set of polar grid receptors centered on each facility, as well as surrounding census block centroid receptors extending from the facility outward to 50 km. For purposes of this modeling analysis, we assumed that the nearest off-site polar grid receptor was the best representation of each facility’s fenceline concentration in the post-control case, unless there

was a census block centroid nearer to the fenceline than the nearest off-site polar grid receptor or an actual receptor was identified from review of the site map. In those instances, we

estimated the fenceline concentration as the concentration at the census block centroid. Only receptors (either the polar or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 229 of 381 census block) that were estimated to be outside the facility fenceline were considered in determining the maximum benzene level for each facility. We note that this analysis does not correlate to any particular metric related to risk. The maximum post-control benzene concentration modeled at the fenceline for any facility is 9 micrograms per cubic meter (μg/m 3 ) (annual average). (For further details of the analysis, see memo entitled Fenceline Ambient Benzene Concentrations Surrounding Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.) The facility inventories generally project emissions with the required fugitive controls working as designed (e.g., no tears in seals for storage vessel floating roofs and water in all water drain seals). If facility inventories are correct, annual average benzene concentrations would not exceed 9 μg/m 3 at the fenceline of any facility. Because the modeling approach considers only the emissions from the refinery, with no contribution from background or near-field sources, this concentration is comparable to the highest modeled fenceline concentration after correcting for background concentrations, as described previously. The EPA is proposing to set the standard

at this concentration action level. We also note that this modeling effort evaluated the annual average benzene concentration at the fenceline, so that this action level***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 230 of 381 applies to the annual average fenceline concentration measured at the facility. The EPA recognizes that, because it is difficult to directly measure emissions from fugitive sources, there is significant uncertainty in current emissions inventories for fugitives. Thus, there is the potential for benzene

concentrations monitored at the fenceline to exceed modeled concentrations. However, given the absence of fenceline monitors at most facilities, there is very limited information available at present about fenceline concentrations and the extent to which they may exceed concentrations modeled from inventories. In the absence of additional data regarding the concentration of fugitive emissions of benzene at the fenceline, the EPA believes it is reasonable to rely on the maximum modeled fenceline value as the concentration action level. We are soliciting comment on alternative concentration action levels and other approaches for establishing the concentration action level. Due to differences in short-term meteorological conditions, short-term (i.e., two-week average) concentrations at thefenceline can vary greatly. Given the high variability in shortterm fenceline concentrations and the difficulties and uncertainties associated with estimating a maximum 2-week fenceline concentration given a limited number of years of meteorological data used in the modeling exercise, we determined***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 231 of 381 that it would be inappropriate and ineffective to propose a short-term concentration action level that would trigger corrective action based on a single 2-week sampling event. One objective for this monitoring program is to identify significant fugitive emission releases early, so that corrective action can be implemented in a more timely fashion, and thereby

achieve additional emission reductions that would not be achieved without the fenceline monitoring requirement. We believe the proposed fenceline monitoring approach and a rolling annual average concentration action limit (i.e., using results from the most recent 26 consecutive 2-week samples and recalculating the average every 2 weeks) will achieve this objective. The proposed fenceline monitoring will provide the refinery owner or operator with fenceline concentration information once every 2 weeks. Therefore, the refinery owner or operator will be able to timely identify occurrences of unusually high emissions leading to elevated fenceline concentrations. We anticipate that the refinery owners or operators will elect to identify and correct these sources early, in efforts to avoid exceeding the annual benzene

concentration action level.

An “exceedance” of the benzene concentration action level would occur when the rolling annual average highest fenceline concentration, corrected for background (determined as described***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 232 of 381 previously), exceeds 9 μg/m 3 . Upon exceeding the concentration action level, we propose that refinery owners or operators would be required to conduct analyses to identify sources contributing

to fenceline concentrations and take corrective action to reduce fugitive emissions to ensure fenceline benzene concentrations remain at or below 9 μg/m 3 (rolling annual average). Corrective action requirements. As described previously, the EPA is proposing that the owner or operator analyze the samples and compare the rolling annual average fenceline concentration, corrected for background, to the concentration

action level. This section summarizes the corrective action requirements in this proposed rule. First, we are proposing that the calculation of the rolling annual average fenceline concentration must be completed within 30 days after the completion of each sampling episode. If the rolling annual average fenceline benzene concentration, corrected for background, exceeds the proposed concentration action level (i.e., 9 μ g/m 3 ), the facility must, within 5 days of comparing the rolling annual average concentration to the concentration action level, initiate a root cause analysis to determine the primary cause, and any other contributing cause(s), of the exceedance. The facility must complete the root cause analysis and implement corrective action within 45 days of initiating the root cause analysis. We are not proposing specific controls or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 233 of 381 corrections that would be required when the concentration action level is exceeded because the cause of an exceedance could vary greatly from facility to facility and episode to episode, since many different sources emit fugitive emissions. Rather, we are proposing to allow facilities to determine, based on their own analysis of their operations, the action that must be taken to

reduce air concentrations at the fenceline to levels at or below

the concentration action level. If, upon completion of the corrective action described above, the owner or operator exceeds the action level for the next two-week sampling episode following the completion of a first set of corrective actions, the owner or operator would be required to develop and submit a corrective action plan that would describe the corrective actions completed to date. This plan would include a schedule for implementation of additional measures to achieve compliance within a timeframe that the owner or operator can demonstrate is as soon as practical. This plan would be submitted to the Administrator for approval within 30 days of an exceedance occurring during the next two-week sampling episode following the completion of the initial round of corrective action. The EPA would evaluate this plan based on the ambient concentrations measured, the sources identified as contributing to the high fenceline concentration, the potential emission reduction measures identified, and the emission***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 234 of 381 reduction measures proposed to be implemented in light of the costs of the options considered and the reductions needed to

reduce the ambient concentration below the action level threshold. To minimize burden on the state implementing agencies and provide additional resources for identifying potential emission sources, we are proposing not to delegate approval of this plan. The refinery owner or operator is not deemed out of compliance with the proposed concentration action level, provided that the appropriate corrective action measures are taken according to the time-frame detailed in an approved corrective action plan. The EPA requests comment on whether it is appropriate to establish a standard time frame for compliance with actions listed in a corrective action plan. We also request comment on whether the approval of the corrective action plan should be delegated to state, local and tribal governments. The EPA’s post-control dispersion modeling (described in Section III.A of this preamble), which relies on reported emissions inventories adjusted to reflect the additional controls on equipment leaks and storage vessels proposed in this rulemaking, indicates that fugitive emissions at all refineries are low enough to ensure that fenceline concentrations of benzene do not exceed the proposed concentration action level. Assuming the reported inventories and associated modeling are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 235 of 381 accurate, we expect that few, if any, facilities will need to engage in required corrective action. We do, however, expect that facilities may identify “poor-performing” sources (e.g., unusual leaks) from the fenceline monitoring data and will implement voluntary corrective action measures to avoid exceeding the annual average concentration action level. As mentioned previously, we envision most of these “voluntary

actions” would be similar to actions to correct issues that would be required to be corrected once identified by the traditional periodic inspections or monitoring. To the extent a source needs to take a corrective action measure, such measure is necessary to ensure compliance with MACT, and those projected costs are already included in the projected costs of the Refinery MACT 1 rule requirements, as modified by the proposed

amendments. While the emission reductions are also included in the projected benefits of the initial MACT standards and those standards as modified by the risk and technology review, earlier

detection and correction of these issues would lead to emission

reductions from actual emission levels. It is difficult to quantify these emission reductions. Therefore, we have not estimated any emission reductions specific to the fenceline monitoring requirements. By selecting a ground-level fenceline monitoring approach and by selecting benzene as the surrogate for organic HAP***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 236 of 381 emissions, we believe that the proposed monitoring approach will effectively target Refinery MACT 1 regulated fugitive emission sources. However, there may be instances where the fenceline concentration is impacted by a low-level miscellaneous process vent, heat exchange system or other similar source. As these sources are regulated under Refinery MACT 1 and the emissions from these sources were included in our post-control modeling file (from which the 9 μ g/m 3 fenceline concentration action level was developed), sources would not be able to avoid taking corrective action by claiming the exceedance of the fenceline concentration was from one of these emission points rather than from fugitive emission sources. There may be instances in which the high fenceline concentration is impacted by a non-Refinery MACT 1 emission source. The most likely instance of this would be leaks from HON equipment or HON storage vessels co-located at the refinery. Because these sources have similar control requirements and corrective action requirements as the Refinery MACT 1 emission sources, we believe that petroleum refineries with these

additional sources should still be able to meet the 9 μ g/m 3 fenceline concentration action level. However, we consider the fenceline monitoring requirement to be specific to Refinery MACT 1 emission sources. Therefore, we are proposing to allow refinery owners or operators to develop site-specific monitoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 237 of 381 plans to determine the impact of these non-Refinery MACT 1

emission sources on the ambient benzene concentration measured at the fenceline. This monitoring plan would be identical to those used by refinery owners or operators that elect to determine monitoring location-specific NFS values for nearby off-site sources. In this case, however, the NFS is actually within the refinery fenceline. Upon approval and implementation of the monitoring plan, the refinery owner or operator would determine the highest fenceline concentration corrected for background; the background correction in this case includes a correction for the co-located non-Refinery MACT 1 emission source(s). The EPA requests comment on whether the corrective action requirements should be limited to exceedances of the fenceline concentration solely from Refinery MACT 1 emission sources and whether a refinery owner or operator should be allowed to exceed the annual average fenceline concentration action level if theycan prove the exceedance of the action level is due to a nonRefinery MACT 1 emissions source. We also request comment on the requirements proposed for refinery owners or operators to demonstrate that the exceedance is caused by a non-Refinery MACT 1 emissions source. Specifically, we request comment on whether the “near-field source” correction is appropriate for on-site sources and whether there are other methods by which refinery***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 238 of 381 owners or operators with co-located, non-Refinery MACT 1 emission sources can demonstrate compliance with the proposed fenceline concentration action level for Refinery MACT 1

emission sources. Additional requirements of the fenceline monitoring program. We are proposing that fenceline data at each monitor location be reported electronically for each semiannual period’s worth of sampling periods (i.e., six to seven 2-week sampling periods per semiannual period). These data would be reported within 45 days of the end of each quarter, and will be made available to the public through the EPA’s electronic reporting and data retrieval portal. We are proposing that facilities be required to conduct fenceline monitoring on a continuous basis, in accordance with the specific methods described above, even if benzene concentrations, as measured at the fenceline, routinely are substantially lower than the concentration action level. In light of the low annual monitoring and reporting costs associated with the fenceline monitors (as described in the next section), and the importance of the fenceline monitors as a means of ensuring the control of fugitives achieves the expected emission levels, we believe it is appropriate to require collection of fenceline monitoring data on a continuous basis. However, the EPA recognizes that fugitive benzene emissions from***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 239 of 381 some facilities may be so low as to make it improbable that

exceedances of the concentration action level would ever occur. In the interest of reducing the cost burden on facilities to comply with this rule, the EPA solicits comment on approaches for reducing or eliminating fenceline monitoring requirements for facilities that consistently measure fenceline concentrations below the concentration action level, and the measurement level that should be used to provide such relief. Such an approach would be consistent with graduated requirements for valve leak monitoring in Refinery MACT 1 and other equipment leak standards, where the frequency of required monitoring varies depending on the percent of leaking valves identified during the previous monitoring period (see, for example, 40 CFR 63.648(c) and 40 CFR 63.168(d)). The EPA requests comment on the minimum time period facilities should be required to conduct fenceline monitoring; the level of performance, in terms of monitored fenceline concentrations, that would enable a facility to discontinue use of fenceline monitors or reduce the frequency of data collection and reporting; and any adjustments to the optical gas imaging camera requirements that would be necessary in conjunction with such changes to the fenceline monitoring requirements.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 240 of 381 i. Delayed Coking Units As noted in Section IV.A of this preamble, we are soliciting comments on the need to establish MACT standards for DCU under CAA Section 112(d)(2) and (3). Even if we were to assume that there is already an applicable MACT standard for DCU, a technology review of this emission source, as prescribed under CAA Section 112(d)(6), would lead us to propose a depressurization limit of 2 psig because of technology advancements since the MACT standards were originally issued and because it is cost effective. Industry representatives have pointed out that Refinery NSPS Ja requires DCU at new and modified sources to depressure to 5 psig, and they have indicated that EPA should not require a lower depressurization limit under a CAA Section 112(d)(6) technology review. Further, industry representatives also provided summary-level information (available in Docket ID Number EPA-HQ-OAR-2010-0682 as correspondence from API entitled Coker Vent Potential Release Limit Preliminary Emission, Cost and Cost Effectiveness Estimates) on costs to depressure to 5 psig versus 2 psig. While the cost information does not show large differences for any particular facility to depressure at 5 psig versus 2 psig, the information does show a large range in potential costs betweenrefineries. At this time, we do not have the detailed, refineryspecific cost breakdowns to compare against our cost***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 241 of 381 assumptions, which were derived from data obtained for a facility that did install the necessary equipment to meet a 2 psig limit. We also do not have detailed information on the design and operation of the DCU in industry’s cost study to evaluate whether there are any differences that would warrant subcategories. We solicit information on designs, operational factors, detailed costs and emissions data for DCU, and we specifically solicit comments on what should be the appropriate DCU depressurization limit if we were to adopt such a requirement pursuant to CAA Section 112(d)(6) rather than pursuant to CAA Section 112(d)(2) and (3). 2. Refinery MACT 2 – 40 CFR Part 63, Subpart UUU The Refinery MACT 2 source category regulates HAP emissions from FCCU, CRU and SRU process vents. Criteria pollutant emissions from FCCU and SRU are regulated under 40 CFR part 60, subparts J and Ja (Refinery NSPS J and Refinery NSPS Ja, respectively). We conducted a technology review of Refinery NSPS J emission limits from 2005 to 2008 and promulgated new standards for FCCU and SRU (among other sources) in Refinery NSPS Ja on June 24, 2008 (73 FR 35838). Our current technology review of Refinery MACT 2 relies upon, but is not limited to, consideration of this recent technology review of Refinery NSPS

J for FCCU and SRU.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 242 of 381

a. FCCU Process Vent The FCCU has one large atmospheric vent, the coke burn-off exhaust stream for the unit’s catalyst regenerator. HAP emissions from this FCCU process vent include metal HAP associated with entrained catalyst particles and organic HAP,mostly by-products of incomplete combustion from the coke burnoff process. As the control technologies associated with each of these classes of pollutants are very different, the controls associated with each of these classes of pollutants are considered separately. Metal HAP emission controls. The current Refinery MACT 2 includes several different compliance options, some based on PM as a surrogate for total metal HAP and some based on nickel (Ni) as a surrogate for total metal HAP. Refinery NSPS J was the

basis of the PM emission limits and the metal HAP MACT floor in Refinery MACT 2. Refinery NSPS J limits PM from FCCU catalyst regeneration vents to 1.0 gram particulate matter per kilogram (g PM/kg) of coke burn-off, with an additional incremental PM allowance for liquid or solid fuel burned in an incinerator, waste heat boiler, or similar device. Refinery MACT 2 states that FCCU subject to Refinery NSPS J PM emission limits are required to demonstrate compliance with Refinery NSPS J PM emission limits as specified in Refinery NSPS J. As provided in Refinery NSPS J, ongoing compliance with the PM emission limits***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 243 of 381 is determined by compliance with a 30-percent opacity limit, except for one 6-minute average per hour not to exceed 60- percent opacity. FCCU not subject to Refinery NSPS J may elect to comply with the FCCU PM provisions in Refinery NSPS J.Alternatively, they may comply with a 1.0 g PM/kg of coke burnoff emission limit in Refinery MACT 2 (with no provision for an additional incremental PM allowance for liquid or solid fuel burned in an incinerator, waste heat boiler, or similar device). Compliance with this limit in Refinery MACT 2 is demonstrated by either a 1-hour average site-specific opacity limit using a continuous opacity monitoring system (COMS) or APCD-specific daily average operating limits using CPMS. Refinery MACT 2 also includes two emission limit alternatives that use Ni, rather than PM, as the surrogate for

metal HAP. The first of these Ni alternatives is a mass emission limit of 13 grams Ni per hour; the second nickel alternative is an emission limit of 1.0 milligrams Ni per kilogram of coke burn-off. Compliance with the Ni emission limits in Refinery MACT 2 is demonstrated by either a daily average site-specific Ni operating limit (using a COMS and weekly determination of Ni concentration on equilibrium FCCU catalyst), or APCD-specific daily average operating limits using CPMS and monthly average Ni concentration operating limit for the equilibrium FCCU catalyst.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 244 of 381 Under Refinery MACT 2, an initial performance demonstration (source test) is required to show that FCCU is compliant with the emission limits selected by the refinery owner or operator. No additional performance test is required for facilities already complying with Refinery NSPS J. The performance test is a one-time requirement; additional performance tests are only required if the owner or operator elects to establish new operating limits, or to modify the FCCU or control system in such a manner that could affect the control system’s performance. Under the review for Refinery NSPS J, we conducted a literature review as well as a review of the EPA’s refinery settlements and state and local regulations affecting refineries to identify developments in practices, processes and control technologies to reduce PM emissions from refinery sources (see Summary of Data Gathering Efforts: Emission Control and Emission Reduction Activities, August 19, 2005, and Review of PM Emission Sources at Refineries, December 20, 2005, Docket Item Number EPA-HQ-OAR-2007-0011-0042). At that time, we identified regulations for PM from FCCU that were more stringent than the Refinery NSPS J requirements for PM, and we promulgated more stringent PM limits in Refinery NSPS Ja. Refinery NSPS Ja limits PM from FCCU catalyst regeneration vents to 1.0 g PM/kg of coke burn-off for modified or reconstructed FCCU, with no incremental***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 245 of 381 allowance for PM-associated liquid or solid fuels burned in a post-combustion device. Furthermore, an emission limit of 0.5 g PM/kg of coke burn-off was established for FCCU constructed after May 14, 2007. In addition, the Refinery NSPS J review identified improvements in APCD monitoring practices, which were included in the Refinery NSPS Ja standards. Refinery NSPS J includes a 30-percent opacity limit as the only ongoing monitoring requirements for PM from the FCCU. This 30-percent opacity limit has shown to be lenient and high in comparison to recent federal rules that have included more stringent opacity limits (e.g., 40 CFR part 60, subpart Db with 20-percent opacity), and recent state and local agency rules that omit opacity limits altogether in favor of operating limits for the emission control systems. Based on the Refinery NSPS J review, Refinery NSPS Ja does not include an opacity limit, but includes updated and more appropriate monitoring approaches, such as requiring bag leak detectors (BLD) for fabric filter control systems, and requiring CPMS for electrostatic precipitators (ESP) and wet scrubbers. Additionally, Refinery NSPS Ja includes an option to measure PM emissions directly using a PM CEMS. For this monitoring alternative, a direct PM concentration limit (equivalent to the conventional FCCU PM emission limit in terms of g PM/kg of coke burn-off) is included in the rule. Finally, in our review for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 246 of 381 Refinery NSPS J, we noted that, even with improved monitoring methods, periodic source testing is needed to verify the performance of the control system as it ages. In Refinery NSPS Ja, annual performance demonstrations are required for affected FCCU. The Refinery NSPS Ja standards for PM from FCCU reflect the latest developments in practices, processes and control technologies. In our current review of Refinery MACT 2, we did not identify any other developments in practices, processes or control technologies since we promulgated Refinery NSPS Ja in

2008. The conclusions of the technology review conducted for the Refinery NSPS J PM emission limits are directly applicable to Refinery MACT 2; the initial Refinery MACT 2 rule recognized this by providing that compliance with Refinery NSPS J would also be compliance with Refinery MACT 2. We considered the impacts of proposing to revise Refinery MACT 2 to incorporate the developments in monitoring practices and control technologies reflected in the Refinery NSPS Ja limits and monitoring provisions. As noted above, Refinery NSPS Ja includes a limit of 0.5 g PM/kg of coke burn-off for newly constructed sources. There would be no costs associated with requiring the lower emission limit of 0.5 g PM/kg of coke burn-off for Refinery MACT 2 new sources under CAA Section 112(d)(6) because these sources would***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 247 of 381 already be required to comply with that limit under Refinery NSPS Ja. Therefore, we are proposing that it is necessary pursuant to CAA Section 112(d)(6) to revise Refinery MACT 2 to incorporate the Refinery NSPS Ja PM limit for new sources. We are also proposing to establish emission limits and monitoring requirements in Refinery MACT 2 that are consistent with those in Refinery NSPS Ja. This option would not impose any additional cost on sources already subject to Refinery NSPS Ja. We note that for facilities subject to Refinery NSPS J, this would not lead to duplicative or conflicting monitoring requirements because Refinery NSPS J already includes a provision that allows affected facilities subject to Refinery NSPS J to instead comply with the provisions in Refinery NSPS Ja (see 40 CFR 60.100(e)). In addition, in conjunction with our proposal to revise Refinery MACT 2 to include the more stringent requirements in Refinery NSPS Ja, we are proposing to remove the less stringent compliance option of meeting the requirements of Refinery NSPS J. As described previously, Refinery NSPS J includes an incremental PM emissions allowance for post-combustion devices and relies on a 30-percent opacity limit that is outdated and has been demonstrated to be ineffective at identifying exceedances of the 1.0 g PM/kg coke burn-off emissions limit.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 248 of 381 We also reviewed the compliance monitoring requirements for the Refinery MACT 2 PM and Ni-based emission limits. As described previously, Refinery MACT 2 includes operating limits based on APCD operating parameters or site-specific opacity limits. There are differences between the monitoring approaches in Refinery MACT 2 for these limits and Refinery NSPS Ja monitoring approaches for the NSPS PM limit, so we evaluated whether it is necessary, pursuant to CAA Section 112(d)(6), to revise the monitoring provisions in Refinery MACT 2 consistent with the requirements in Refinery NSPS Ja. The first significant difference is in the averaging times used for the different operating limits. Refinery NSPS Ja requires a 3-hour rolling average for the operating limits for parametric monitoring systems; Refinery MACT 2 includes daily averaging of the operating limits. Typically, the averaging time for operating limits is based on the duration of the performance test used to establish those operating limits. As the performance test duration is 3 hours (three 1-hour test runs) and compliance with the PM (or Ni) emission limit is based on the average emissions during this 3-hour period, the most appropriate averaging period for these operating limits is 3 hours. Using a daily average could allow poor performance (i.e., control equipment for shorter periods (e.g., 3-hour averages that are higher than the PM emissions limit in Refinery NSPS***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 249 of 381 Ja). For example, assume an operating limit developed from a performance test has a value of 1 and that values exceeding this level would suggest that the control system is not operating as well as during the performance test (i.e., potentially exceeding the PM emission limit). If the control system is run for 18 hours operating at a level of 0.9 and 6 hours at a level of 1.2, the unit would be in compliance with the daily operating limit even though the unit may have 6 consecutive hours during which the operating limit was exceeded. Reducing the averaging time does not impact the types of monitors required; it merely requires the owner or operator of the unit to pay more careful attention to the APCD operating parameters. We are proposing that it is necessary, pursuant to CAA Section 112(d)(6), to incorporate the use of 3-hour averages rather than daily averages for parameter operating limits in Refinery MACT 2 for both the PM and Ni limits, because this is a cost-effective development in monitoring practice. The site-specific opacity operating limit for PM in Refinery MACT 2 (for units not electing to comply with Refinery NSPS J) has a 1-hour averaging period, but the Ni operating limits (which use opacity monitoring) have a 24-hour averaging period. These averaging periods are inconsistent with the duration of the performance test, which is over a 3-hour period. We are proposing, pursuant to CAA Section 112(d)(6), to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 250 of 381 incorporate the use of 3-hour averages for the site-specific opacity operating limit and the Ni operating limits rather than daily averages because this is a cost-effective development in monitoring practice. We also compared the APCD-specific operating parameters used in Refinery MACT 2 to those that we promulgated for Refinery NSPS Ja. The Refinery NSPS Ja rule includes monitoring approaches that are not included in Refinery MACT 2. These include the option of using PM CEMS and requiring BLD for fabric filter control systems. Adding a PM CEMS as an option for demonstrating compliance with the Refinery MACT 2 PM limit (similar to what is provided in Refinery NSPS Ja) would not impact the costs of complying with Refinery MACT 2 because sources can choose whether or not to adopt this monitoring method. With respect to BLD, there is only one refinery that currently uses a baghouse (fabric filter) to control emissions from its FCCU (although one additional unit has indicated that it has plans to install a fabric filter control within the next few years). Under the existing requirements in Refinery MACT 2 (assuming that the FCCU currently operating with a fabric filter has not elected to comply with the Refinery NSPS J PM emission limit option), it is required to comply with a site-specific opacity operating limit. For new, reconstructed, or modified FCCU, Refinery NSPS Ja requires use of BLD. While we generally***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 251 of 381 consider the BLD to be superior to opacity monitors for ensuring fabric filter control systems are operating efficiently, it is difficult to determine what, if any, increment in assurance that the unit is properly controlled would be achieved by requiring the one facility currently operating a fabric filter control system and complying with a site-specific opacity operating limit to switch from a COMS to BLD. Therefore, we are proposing that it is not necessary to require the one existing FCCU with a fabric filter control system to switch from COMS to a BLD system because this would require additional monitoring equipment (with additional costs) and little to no associated increase in assurance that the unit is properly controlled. Although we are not proposing to require existing sources using a fabric filter to use BLD, we are proposing to include BLD as an option to COMS; owners or operators of FCCU using fabric filter-type control systems at existing sources can elect (but are not required) to use BLD in lieu of COMS and the site-specific opacity operating limit. The Refinery NSPS Ja monitoring requirements for ESP include CPMS for monitoring and recording the total power and the secondary current to the entire system. The current MACT requires monitoring voltage and secondary current or monitoring only the total power to the APCD. While these monitoring requirements are similar, we consider that the Refinery NSPS Ja***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 252 of 381 requirements will provide improved operation of the ESP. As the monitors required to measure these parameters are a routine part of ESP installations, we project no additional costs for monitoring equipment. We expect that a new performance test would be needed to ensure that both total power and secondary current are recorded during the source test. As discussed later in this section, we are proposing to require ongoing performance tests regardless of the monitoring option, so we are not projecting any additional costs specific to revising the monitoring requirements for ESP. Because the Refinery NSPS Ja monitoring and operating requirements for ESP are expected to provide improved performance of the APCD with no incremental costs, we propose that it is necessary, pursuant to CAA Section 112(d)(6), to incorporate the total power and the secondary current operating limits into Refinery MACT 2. Refinery NSPS Ja provides a specific monitoring alternative to pressure drop for jet ejector-type wet scrubbers or any other type of wet scrubbers equipped with atomizing spray nozzles. Owners or operators of FCCU controlled by these types of wet scrubbers can elect to perform daily checks of the air or water pressure to the spray nozzle rather than monitor pressure. Refinery MACT 2 currently excludes these types of control systems from monitoring pressure drop but includes no specific monitoring to ensure the jet ejectors or atomizing spray nozzle***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 253 of 381 systems are properly operating. Since proper functioning of the jet ejectors or atomizing spray nozzles is critical to ensuring these control systems operate at the level contemplated by the MACT, some monitoring/inspection requirement of these components is necessary to ensure compliance with the FCCU PM or Ni emission limit. The owner or operator of a jet ejector-type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles should be performing routine checks of these systems, such as the daily checks of the air or water pressure to the spray nozzles, as required in Refinery NSPS Ja. These daily checks are consistent with good operational practices for wet scrubbers and should not add significant burden to the FCCU wet scrubber owner or operator. For these reasons, we propose itis necessary to require owners or operators of a jet ejectortype wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles to perform daily checks of the air or water pressure to the spray nozzles pursuant to CAA Section 112(d)(6). Finally, in our action promulgating Refinery NSPS Ja, we noted that, even with improved monitoring methods, periodic source testing is needed to verify the performance of the control system as it ages. In Refinery NSPS Ja, annual performance demonstrations are required for new sources. FCCU subject to Refinery MACT 2 as new sources would also be subject***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 254 of 381 to Refinery NSPS Ja and would have to comply with the annual testing requirements in Refinery NSPS Ja. However, Refinery MACT 2 does not include periodic performance tests for any FCCU. We considered adding an annual testing requirement for FCCU subject to Refinery MACT 2. The annual nationwide cost burden exceeds $1 million per year and we project only modest improvement in control performance resulting from the performance demonstrations. We considered requiring FCCU performance tests once every 5 years (i.e., once per title V permit period). The nationwide annual cost of this additional testing requirement for FCCU is projected to be, on average, $213,000 per year. We consider this to be a reasonable minimum frequency for which affected sources should demonstrate direct compliance with the

FCCU emission limits and that this cost is reasonable. Therefore, we propose that it is necessary, pursuant to CAA Section 112(d)(6), to require a performance test once every 5 years for all FCCU under to Refinery MACT 2. Organic HAP. Refinery MACT 2 uses CO as a surrogate for organic HAP and establishes an emission limit of 500 ppmv CO (dry basis). Some FCCU, referred to as complete-combustion FCCU, employ excess oxygen in the FCCU regenerator and are able to meet this emission limit without the need for a post-combustion device. Other FCCU, referred to as partial-combustion FCCU, do not supply enough air/oxygen for complete combustion of the coke***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 255 of 381

to CO 2 and, therefore, produce a significant quantity of CO in the regenerator exhaust. Partial-combustion FCCU are typically followed by a post-combustion unit, commonly referred to as a CO boiler, to burn the CO in the regenerator exhaust in order to meet the 500 ppmv CO limit (and to recover useful heat from the exhaust stream). In our review of Refinery NSPS J, we conducted a review of state and local regulations affecting refineries to identify control strategies to reduce CO emissions or VOC emissions from refinery sources (see Review of VOC Emission Sources atRefineries, December 14, 2005, Docket Item Number EPA-HQ-OAR2007-0011-0043). We also conducted a review of federal, state and local regulations affecting refineries to identify control strategies to reduce CO emissions from refinery sources (see Review of CO Emission Sources at Refineries, December 22, 2005, Docket Item Number EPA-HQ-OAR-2007-0011-0044). We did not identify any developments in practices, processes and control technologies to reduce CO or VOC emissions from FCCU as part of the review of Refinery NSPS J, and we have not identified any developments in practices, processes and control technologies for FCCU that would reduce organic HAP since promulgation of Refinery MACT 2. We are proposing that it is not necessary to revise the regulatory provisions for organic HAP in the current MACT standards for FCCU, pursuant to CAA Section 112(d)(6).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 256 of 381 Inorganic HAP. As mentioned previously, Refinery MACT 2 includes a CO emission limit of 500 ppmv. Although this limit is expressly provided as a limit addressing organic HAP emissions, this emission limit is also expected to limit the emissions of oxidizable inorganic HAP, such as HCN. That is, the CO concentration limit was developed as an indicator of complete combustion for all oxidizable pollutants typically found in exhaust gas from the FCCU regenerator operated in partial burn mode. We note that HCN concentrations in FCCU regenerator exhaust with high CO levels also have high HCN concentrations and that HCN concentrations in the regenerator exhaust from complete-combustion FCCU (those meeting the 500 ppmv CO limit without the need for a post-combustion device) are much lower than those from partial burn FCCU prior to a post-combustion device. Thus, we consider that the CO emission limit also acts as a surrogate for the control of oxidizable inorganic HAP, such

as HCN.

The source test data from the ICR effort revealed that HCN emissions from FCCU are greater than previous tests indicated, particularly for complete-combustion FCCU. The increase in HCN emissions was observed at units meeting lower NO X emission limits, which have recently been required by consent decrees, state and local requirements and Refinery NSPS Ja. The higher HCN emissions from complete-combustion FCCU appear to be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 257 of 381 directly related to operational changes made in efforts to meet

these lower NO X emission limits (e.g., reduced excess oxygen levels in the regenerator and reduced regenerator bed temperatures). These higher HCN emissions were only observed in complete-combustion FCCU; FCCU that operated in partial burn mode followed by a CO boiler or similar post-combustion devicehad significantly lower HCN emissions subsequent to the postcombustion device.

Based on our review of the available ICR data and the technologies used in practice, we considered establishing specific emission limits for HCN. In order to comply withemission limits for HCN, owners or operators of completecombustion FCCU would either have to operate their FCCU regenerator at slightly higher temperatures and excess oxygen concentrations (to limit the formation of HCN in the regenerator) or employ a post-combustion device or thermal oxidizer to destroy HCN exhausted from the FCCU regenerator. However, each of these options comes with significant secondary energy and environmental impacts. First, both of these control strategies would yield a significant increase in NO X emissions. We anticipate that most FCCU owners or operators would have to install a selective catalytic reduction (SCR) system to meet

their NO X emission limits, if applicable. Operation of the SCR would have energy impacts and may have additional secondary PM 2.5***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 258 of 381 impacts (associated with ammonia slip from the SCR). We expect that modifying the regenerator operating characteristics is the most cost-effective option, although installing and using a thermal oxidizer may be necessary, depending on the operational characteristics of the regenerator and the HCN control requirement. Using a thermal oxidizer to treat FCCU regenerator exhaust, a gas stream that has limited heating value (due to the already low CO concentrations) would be much more expensive and would have additional energy and secondary impacts associated with the auxiliary fuel needed for the device, as compared to modifying regenerator operating conditions. We first performed a screening analysis of the impacts of making only operational changes to the FCCU with the highest HCN concentrations. If this control option is not cost effective for these FCCU, it would not be cost effective for units that have lower HCN concentrations and lower HCN emissions. Similarly, if operating changes in the FCCU regenerator alone are not cost effective, then we can assume that installing a thermal oxidizer

to achieve this same level of HCN emission reductions would also not be cost effective. We calculated the cost of changing the regenerator parameters and adding an SCR for the FCCU with the highest HCN emissions rate reported in the ICR, which is an annual emissions rate of 460 tpy. This is also the largest FCCU in operation in the United States and its territories. Based on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 259 of 381 the size of this unit, we project that an SCR would be expected to cost approximately $13-million and have annualized costs of approximately $4.0-million/yr. Thus, if the HCN emissions can be reduced by 95 percent, the cost effectiveness would be approximately $9,000 per ton of HCN. A smaller FCCU had similar HCN concentrations and annual HCN emissions of 141 tpy. Based on the size of this unit, we project an SCR would be expected to cost approximately $7-million and have annualized costs of approximately $1.5-million/yr. Assuming a 95-percent reduction in HCN emissions, the cost effectiveness would be approximately $11,000 per ton of HCN. The second-highest emitting FCCU was larger than this unit, but had lower HCN concentrations. This third unit had emissions of 184 tpy. Based on the size of this unit, we expect that an SCR would cost approximately $9-million and have annualized costs of approximately $2.2-million/yr. Assuming a 95-percent reduction in HCN emissions, the cost effectiveness would be approximately $12,600 per ton of HCN. These costs are for the FCCU with the largest HCN emissions and the lowest control cost (assuming operational changes alone are insufficient to significantly reduce HCN emissions), and the average cost effectiveness for these units exceeds $10,000 per

ton HCN emissions reduced. Based on the economies of scale and considering lower HCN concentrations for all other units, the costs per ton of HCN removed for a nationwide standard would be***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 260 of 381 higher. If a post-combustion device is needed to achieve a specific HCN emissions limit, the costs would be even higher. Based on the cost, secondary energy and secondary environmental impacts of an HCN emission limit beyond that achieved by the CO emission limit as a surrogate for HCN, we are proposing, at this time, that it is not necessary, pursuant to CAA Section 112(d)(6), to revise the MACT standard to establish a separate HCN standard. As our understanding of the mechanisms

of HCN and NO X formation improves and as catalyst additives evolve, it may be possible to achieve both low NO X and low HCN emissions without the use of an SCR and/or post-combustion controls. However, at this time our test data indicate an inverse correlation between these two pollutants. The three facilities with the highest HCN concentrations were the

facilities with the lowest NO X concentrations, all of which were below 20 ppmv (dry basis, 0-percent excess air) during the performance tests. While a 20 ppmv NO X limit may be achievable, we anticipate that further reducing the NO X new source performance limits for FCCU would either increase PM 2.5 secondary emissions (via the use of an SCR and its associated ammonia slip) or further increase HCN emissions (if combustion controls are used).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 261 of 381

b. CRU Process Vents A CRU is designed to reform (i.e., change the chemical structure of) naphtha into higher-octane aromatics. The reforming process uses a platinum or bimetal (e.g., platinum and rhenium) catalyst material. Small amounts of coke deposit on the catalyst during the catalytic reaction and this coke is burned off the catalyst to regenerate catalyst activity. There are three types of CRU classified by differences in how the units are designed and operated to effect reforming catalyst regeneration. Semi-regenerative reforming is characterized by shutting down the reforming unit at specified intervals, or at the operator’s convenience, for in situ catalyst regeneration. Semi-regenerative CRU typically regenerate catalyst once every 8 to 18 months, with the regeneration cycle lasting approximately 2 weeks. Cyclic-regeneration reforming is characterized by continuous or continual reforming operation with periodic (but frequent) regeneration of catalyst in situ by isolating one of the reactors in the series, regenerating the catalyst, then returning the reactor to the reforming operation. The regeneration of the catalyst in a single reactor may occur numerous times per year (e.g., once a month), and the regeneration of each reactor may take 3 to 5 days to complete. Continuous-regeneration reforming units use moving catalyst bed reactors situated vertically (which is why they are often***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 262 of 381 referred to as platforming units). Catalyst flows down the series of reactors. At the bottom of the last reactor, catalyst is continually isolated and sent to a special regenerator. After regeneration, the regenerated catalyst is continually fed to the first (top) reactor. Thus, continuous-regeneration reforming units are characterized by continuous-reforming operation along with continuous-regeneration operation. The catalytic reforming reaction is performed in a closed reactor system; there are no emissions associated with the processing portion of the CRU. There is a series of emission points associated with the CRU catalyst regenerator. Regardless of the type of CRU used, there is a series of steps conducted to effect catalyst regeneration. These steps are: (1) initial depressurization/purge; (2) coke burn-off; (3) catalyst rejuvenation; and (4) reduction/final purge. The primary emissions during the depressurization/purge cycle are organic HAP. Inorganic HAP, predominately HCl and chlorine, are emitted during the coke burn-off and rejuvenation cycles. The reduction purge is mostly inert materials (nitrogen and/or hydrogen). Refinery MACT 2 contains organic HAP emission limits for the depressurization/purge cycle (purging prior to coke-burn-off) and inorganic HAP emission limits for the coke burn-off and catalyst rejuvenation cycles. Our technology review, summarized below, considers each of these emission limits separately. For***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 263 of 381 additional details on the technology review for CRU, see Technology Review Memorandum for Catalytic Reforming Units at Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682. Organic HAP. Refinery MACT 2 requires the owner or operatorto comply with either a 98-percent reduction of TOC or nonmethane TOC, or an outlet concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-percent oxygen). The emission limits for organic HAP for the CRU do not apply to emissions from process vents during depressuring and purging operations when the reactor vent pressure is 5 psig or less. Control technologies used include directing the purge gas directly to the CRU process heater to be burned, recovering the gas to the facility’s fuel gas system, or venting to a flare or other APCD. The pressure limit exclusion was provided to allow atmospheric venting of the emissions when the pressure of the vessel fell below that needed to passively direct the purge gas to the APCD (most commonly the CRU process heater or flare). We did not identify any developments in practices, processes and control technologies for reducing organic HAP emissions from CRU. However, as noted in Section IV.A.2 of this preamble, we are proposing to amend the pressure limit exclusion pursuant to CAA Sections 112(d)(2) and (3) to clarify that this limit only applies during passive vessel depressuring. Also, as described in Section IV.A.3 of this preamble, we are proposing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 264 of 381 revisions to Refinery MACT 1 and 2, pursuant to CAA Sections 112(d)(2) and (3), to ensure flares used as APCD meet the required destruction efficiency, which includes flares used to control the organic HAP emissions from the CRU depressurization/purge vent streams. Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for inorganic HAP during the coke burn-off and rejuvenation cycles.Refinery MACT 2 requires owners or operators of existing semiregenerative CRU to reduce uncontrolled emissions of HCl by 92- percent by weight or to a concentration of 30 ppmv (dry basis, corrected to 3-percent oxygen) during the coke burn-off andrejuvenation cycles. Owners or operators of new semiregenerative CRU, new or existing cyclic CRU, or new or existing continuous CRU are required to reduce uncontrolled emissions of HCl by 97-percent by weight or to a concentration of 10 ppmv(dry basis, corrected to 3-percent oxygen) during the coke burnoff and rejuvenation cycles. Technologies used to achieve these limits include caustic spray injection, wet scrubbers, and solid adsorption systems. We conducted a technology review for CRU by reviewing the ICR responses and scientific literature. We did not identify any developments in practices, processes and control technologies for reducing inorganic HAP emissions from CRU. We are proposing that it is not necessary to revise the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 265 of 381 current inorganic HAP MACT standards for CRU, pursuant to CAA Section 112(d)(6).

c. SRU Process Vents Most sulfur recovery plants at petroleum refineries use the Claus reaction to produce elemental sulfur. In the Claus reaction, two moles of hydrogen sulfide (H 2 S) react with one mole

of SO 2 in a catalytic reactor to form elemental sulfur and water vapor. Prior to the Claus reactors, one-third of the H 2 S in the sour gas feed to the sulfur plant must be oxidized to SO 2 to have the correct proportion of H 2 S and SO 2 for the Claus reaction. This oxidation step is performed in the “Claus burner.” The remaining gas stream, after the elemental sulfur is condensed, is referred to as “tail gas.” HAP emissions in tail gas from sulfur recovery plants are predominately COS and CS 2 , which are primarily formed as side reactions of the Claus process. Refinery MACT 2 contains HAP standards for SRU that were based on the Refinery NSPS J SO 2 and reduced sulfur compounds emission limits. Refinery NSPS J includes an emission limit of 300 ppmv reduced sulfur compounds for a reduction control system not followed by an incinerator, and an emission limit of 250 ppmv SO 2 (dry basis, 0-percent excess air) for oxidative control systems or reductive control systems followed by incineration. These Refinery NSPS J limits apply only to Claus sulfur recovery plants with a sulfur recovery capacity greater than 20 long tons***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 266 of 381 per day (LTD). These emission limits effectively required sulfur recovery plants to achieve 99.9-percent sulfur recovery. Refinery MACT 2 defines SRU as “a process unit that recovers elemental sulfur from gases that contain reduced sulfur compounds and other pollutants, usually by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide.” This definition specifically excludes sulfur recovery processes that do not recover elemental sulfur, such as the LO-CAT II process, but does not necessarily limit applicability to Claus SRU. Refinery MACT 2 requires owners or operators of an SRU that is subject to Refinery NSPS J to meet the Refinery NSPS J limits. Owners or operators of an SRU that is not subject to Refinery NSPS J can elect to meet the emission limits in Refinery NSPS J or meet a reduced sulfur compound limit of 300 ppmv (dry basis, 0-percent excess air) regardless of the type of control system or the presence of an incinerator. Unlike Refinery NSPS J, Refinery MACT 2 does not have a capacity applicability limit, so this 300 ppmv reduced sulfur compound limit is applicable to all SRU (as that term is defined), regardless of size. Upon completion of our technology review for Refinery NSPS J, we promulgated Refinery NSPS Ja, which includes new provisions for the sulfur recovery plant. First, Refinery NSPS Ja limits are now applicable to all sulfur recovery plants, not just Claus sulfur recovery plants. Second, emission limits were***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 267 of 381 added for sulfur recovery plants with a capacity of 20 LTD or less, to require new, small sulfur recovery plants to achieve a target sulfur recovery efficiency of 99-percent. These limits are a factor of 10 higher than the emission limits for larger sulfur recovery plants (i.e., 3,000 ppmv reduced sulfur compounds for a reduction control system not followed by an incinerator and 2,500 ppmv SO 2 for oxidative control systems or reductive control systems followed by incineration). Refinery

NSPS J did not include emission limits for these smaller sulfur recovery plants. Third, new correlations were introduced toprovide equivalent emission limits for systems that use oxygenenriched air in their Claus burner. The technology review conducted for Refinery NSPS J focused

on SO 2 emissions. Under our current technology review for Refinery MACT 2, we considered the developments in practices, processes or control technologies identified in the Refinery NSPS J technology review as they pertain to HAP emissions and the existing Refinery MACT 2 requirements. We considered the new Refinery NSPS Ja limits for small sulfur recovery plants. While Refinery NSPS Ja establishes criteria pollutant emission limits for these smaller sulfur recovery plants that were previously unregulated for such emissions, these sources are already covered under Refinery MACT 2. Refinery MACT 2 requires these SRU to meet a 300 ppmv reduced***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 268 of 381 sulfur compound limit, which is more stringent than the 3,000 ppmv limit established in Refinery NSPS Ja. We also considered the new correlations in Refinery NSPS Ja for SRU that use oxygen-enriched air in their Claus burner. In the technology review under Refinery NSPS J, we identified a change in practice in the operation of certain Claus SRU. At the time we promulgated Refinery MACT 2, we assumed that all units were using ambient air in the Claus burner, and we established the same emission limits as in Refinery NSPS J. Now, however, we understand that some facilities are using oxygen-enriched air. This practice lowers the amount of inert gases introduced into the SRU and improves operational performance and reliability of the sulfur recovery plant. Air is approximately 20.9 percent by volume oxygen and 79.1-percent inert gases (predominately nitrogen with 1-percent argon and other inert gases). The inert gases introduced in the Claus burner become a significant portion of the overall tail gas flow. When oxygen enrichment is used in the Claus burner, there are fewer inert gases in the tail gas and a lower overall tail gas flow rate. The same molar flow rate of reduced sulfur compounds will be present in the tail gas, but without the additional flow of inerts from the ambient air, the concentration of the reduced sulfur compounds (or SO 2 ) in the tail gas is higher.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 269 of 381 In developing Refinery NSPS Ja, we included a correlation equation that facilities can use to adjust the concentration limit based on the enriched-oxygen concentration used in the Claus burner. This equation is designed to allow the same mass of emissions for these units as is allowed for units using only ambient air. That is, the emission equation establishes a concentration limit for units using oxygen enrichment so that

the mass emissions from the unit do not exceed the mass emissions allowed under the 250 ppmv SO 2 (or 300 ppmv reduced sulfur compounds) emissions limits in Refinery NSPS J and in Refinery MACT 2. The new equation in Refinery NSPS Ja for large sulfur recovery plants (those with sulfur recovery greater than 20 LTD) provides an equivalent mass emissions rate of reduced sulfur HAP from the SRU as is currently required in Refinery MACT 2 while allowing a practice that improves the operational reliability of the unit. There are no costs to providing this option for units using oxygen-enriched air because: 1) it is an option that the owner or operator can elect to meet instead of the existing 250 ppmv SO 2 emissions limit and 2) owners or operators of SRU that use oxygen-enriched air are expected to already routinely monitor the inlet air oxygen concentration for operational purposes. Therefore, we are proposing that it is necessary, pursuant to CAA Section 112(d)(6), to amend Refinery MACT 2 sulfur recovery requirements to include this equation***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 270 of 381 that addresses the use of oxygen-enriched air as a development in practice in SRU process operations. The emission limits for large sulfur recovery plants (those with sulfur recovery greater than 20 LTD) in Refinery NSPS Ja are equivalent to those in Refinery MACT 2. We are proposing to allow owners or operators subject to Refinery NSPS Ja limits for sulfur recovery plants with a capacity greater than 20 LTD to comply with Refinery NSPS Ja as a means of complying with Refinery MACT 2. We have not identified any additional developments in practices, processes or control technologies for HAP from SRU since development of Refinery NSPS Ja. C. What are the results of the risk assessment and analyses?

1. Inhalation Risk Assessment Results Table 10 of this preamble provides an overall summary of

the results of the inhalation risk assessment. **Table 10. Petroleum Refining Source Sector Inhalation Risk Assessment Results** 

**Maximum Individual**  **Cancer Risk (-in-1 million)**  **a Estimated**  **Population at Increased Risk**  **Levels of**

**Cancer Estimated**  **Annual Cancer Incidence**  **(cases per year)**  **Maximum Chronic**  **Non-ca n**  **cer TOSHI**  **b Maximum**  **Screening Acute Non**  **cancer HQ c**  Actual Emissions

60 ≥ 1-in-1 million: 5,000,000

≥ 10-in-1 million:

100,000 0.3 0.9 HQ REL = 5 (Nickel Compounds)***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 271 of 381

≥ 100-in-1 million: 0 Allowable Emissions d

100 ≥ 1-in-1 million: 7,000,000 e

≥ 10-in-1 million: Greater than 90,000 e

≥ 100-in-1 million: 0 0.6 <1 -

a Estimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category. b Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the thyroid system for actual emissions and the neurological system for allowable emissions.

c The maximum off-site HQ acute value of 5 is driven by emissions of nickelfrom CCU. See Section III.A.3 of this preamble for explanation of acute doseresponse values. Acute assessments are not performed on allowable emissions because of a lack of detailed hourly emissions data. However, because of the conservative nature of the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be comparable to actual acute estimates. d The development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates for Modeled “Allowable” Emissions, which can be found in Docket ID Number EPA-HQ-OAR-2010-0682.

e Population risks from allowable emissions were only calculated for the model plant emissions (REM) approach. For the 138 facilities modeled using the modeled plant approach the population risks greater than 10-in-1 million was estimated to be 90,000. If we consider the second approach to determining allowable emissions (combined the results of the actual and REM emissions estimates) we estimate that the allowable population risks greater than 10- in-1 million would be greater than 90,000 people. Further, the number of people above 1-in-1 million would also be higher than the 7,000,000 estimated using the REM model.

The inhalation risk modeling performed to estimate risks based on actual emissions relied primarily on emissions data from the ICR, updated based on our quality assurance review as described in Section III.A.1 of this preamble.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 272 of 381 The results of the chronic baseline inhalation cancer risk assessment indicate that, based on estimates of current actual emissions, the maximum individual lifetime cancer risk (MIR) posed by the refinery source category is 60-in-1 million, with benzene and naphthalene emissions from equipment leaks and storage tanks accounting for 98 percent of the MIR risk. The total estimated cancer incidence from refinery emission sources based on actual emission levels is 0.3 excess cancer cases per year or one case in every 3.3 years, with emissions of naphthalene, benzene, and 2-methylnaphthalene contributing 22 percent, 21 percent and 13 percent, respectively, to this cancer incidence. In addition, we note that approximately 100,000 people are estimated to have cancer risks greater than 10-in-1 million, and approximately 5,000,000 people are estimated to have risks greater than 1-in-1 million as a result of actual emissions from these source categories. When considering the MACT-allowable emissions, the maximum individual lifetime cancer risk is estimated to be up to 100-in-1 million, driven by emissions of benzene and naphthalene from refinery fugitives (e.g., storage tanks, equipment leaks and wastewater) and the

estimated cancer incidence is estimated to be 0.6 excess cancer cases per year or one excess case in every 1.5 years. Greater than 90,000 people were estimated to have cancer risks above 10- in-1 million and approximately 7,000,000 people were estimated***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 273 of 381 to have cancer risks above 1-in-1 million considering allowable emissions from all petroleum refineries. The maximum modeled chronic non-cancer HI (TOSHI) value for

the source sector based on actual emissions was estimated to be less than 1. When considering MACT-allowable emissions, the

maximum chronic non-cancer TOSHI value was also estimated to be

less than 1.

2. Acute Risk Results Our screening analysis for worst-case acute impacts based on actual emissions indicates the potential for five pollutants – acetaldehyde, acrolein, arsenic, benzene and nickel - to exceed an HQ value of 1, with an estimated worst-case maximum HQ

of 5 for nickel based on the REL values. This REL occurred at a facility reporting nickel emissions from the FCCU vent. One hundred thirty six (136) of the 142 petroleum refineries had an estimated worst-case HQ less than or equal to 1 for all HAP; except for the one facility that had an estimated REL of 5, the remaining five refineries with an REL above 1 had an estimated worst-case HQ less than or equal to 3. To better characterize the potential health risks associated with estimated worst-case acute exposures to HAP, and in response to a key recommendation from the SAB’s peer review of EPA’s RTR risk assessment methodologies, we examine a wider range of available acute health metrics than we do for our***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 274 of 381 chronic risk assessments. This is in acknowledgement that there are generally more data gaps and inconsistencies in acute reference values than there are in chronic reference values. By definition, the acute CalEPA REL represents a health-protective level of exposure, with no risk anticipated below those levels, even for repeated exposures; however, the health risk from higher-level exposures is unknown. Therefore, when a CalEPA REL is exceeded and an AEGL-1 or ERPG-1 level is available (i.e., levels at which mild effects are anticipated in the general public for a single exposure), we have used them as a second comparative measure. Historically, comparisons of the estimated maximum off-site 1-hour exposure levels have not been typically made to occupational levels for the purpose of characterizing public health risks in RTR assessments. This is because occupational ceiling values are not generally considered protective for the general public since they are designed to protect the worker population (presumed healthy adults) for short-duration (less than 15-minute) increases in exposure. As a result, for most chemicals, the 15-minute occupational ceiling values are set at levels higher than a 1-hour AEGL-1, making comparisons to them irrelevant unless the AEGL-1 or ERPG-1 levels are also exceeded. Such is not the case when comparing

the available acute inhalation health effect reference values for some of the pollutants considered in this analysis.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 275 of 381 The worst-case maximum estimated 1-hour exposure to acetaldehyde outside the facility fence line for the source categories is 1 mg/m 3 . This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQ REL =2) and is well below the 1-hour AEGL-1 (HQ AEGL-1 =0.01) and the ERPG-1 (HQ ERPG-1 =0.05). The worst-case maximum estimated 1-hour exposure to acrolein outside the facility fence line for the source categories is 0.005 mg/m 3 . This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQ REL =2) and is below the 1-hour AEGL-1 (HQ AEGL-1 =0.1) and the ERPG-1 (HQ ERPG-1 =0.04). The worst-case maximum estimated 1-hour exposure to nickel compounds outside the facility fence line for the source categories is 0.001 mg/m 3 . This estimated worst-case exposure exceeds the 1-hour REL by a factor of 5 (HQ REL =5). There are no AEGL, ERPG or short-term occupational values for nickel to use as comparison to the acute 1-hour REL value. The worst-case maximum estimated 1-hour exposure to arsenic compounds outside the facility fence line for the source categories is 0.0004 mg/m 3 . This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQ REL =2). There are no AEGL, ERPG or short-term occupational values for arsenic to use as comparison to the acute 1-hour REL value. The maximum estimated 1-hour exposure to benzene outside the facility fence line is 2.7 mg/m 3 . This estimated exposure***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 276 of 381 exceeds the REL by a factor of 2 (HQ REL =2), but is significantly below both the 1-hour ERPG-1 and AEGL-1 value (HQ ERPG-1 (or AEGL-1) = 0.02). This exposure estimate neither exceeds the AEGL-1/ERPG-1 values, nor does it exceed workplace ceiling level guidelines designed to protect the worker population for short duration (<15 minute) exposure to benzene, as discussed below. The occupational short-term exposure limit (STEL) standard for benzene developed by the Occupational Safety and Health Administration is 16 mg/m 3 , “as averaged over any 15-minute period.” 29 Occupational guideline STEL for exposures to benzene have also been developed by the American Conference of Governmental Industrial Hygienists (ACGIH) 30 for less than 15

minutes 31 (ACGIH threshold limit value (TLV) – STEL value of 8.0 mg/m 3 ), and by the National Institute for Occupational Safety and Health (NIOSH) 32 “for any 15 minute period in a work day” (NIOSH REL – STEL of 3.2 mg/m 3 ). These shorter duration occupational

29 29 CFR 1910.1028, Benzene. Available online at http://www.osha.gov/pla/oshaweb/owadisp.show_document?p_table=STANDARD&p_id=1 0042.

30 ACGIH (2001) Benzene. In Documentation of the TLVs® and BEIs® with Other Worldwide Occupational Exposure Values. ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-882417-74-1) and available online at http://www.acgih.org.

31 The ACGIH definition of a TLV-STEL states that “Exposures above the TLV-TWA up to the TLV-STEL should be less than 15 minutes, should occur no more than four times per day, and there should be at least 60 minutes between successive exposures in this range.”

32 NIOSH. Occupational Safety and Health Guideline for Benzene; http://www.cdc.gov/niosh/74-137.html

.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 277 of 381 values indicate potential concerns regarding health effects at exposure levels below the 1-hour AEGL-1 value.

All other HAP and facilities modeled had worst-case acute HQ values less than 1, indicating that they carry no potential to pose acute concerns. In characterizing the potential for acute non-cancer impacts of concern, it is important to remember the upward bias of these exposure estimates (e.g., worst-case meteorology coinciding with a person located at the point of maximum concentration during the hour) and to consider the results along with the conservative estimates used to develop hourly emissions as described earlier, as well as the screening methodology. Refer to the memo in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682, Derivation of hourly emission rates for petroleum refinery emission sources used in the acute risk analysis) for a detailed description of how the hourly emissions were developed for this source sector. 3. Multipathway Risk Screening Results Results of the worst-case Tier I screening analysis indicate that PB-HAP emissions (based on estimates of actual emissions) from several facilities in this source sector exceed the screening emission rates for POM (PAH), CDDF, mercury compounds, and cadmium compounds. For the compounds and facilities that did not screen out at Tier I, we conducted a Tier II screen. The Tier II screen replaces some of the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 278 of 381 assumptions used in Tier I with site-specific data, including the land use around the facilities, the location of fishable lakes, and local wind direction and speed. The Tier II screen continues to rely on high-end assumptions about consumption of local fish and locally grown or raised foods (adult female angler at 99 th consumption for fish 33 and 90 th percentile for consumption of locally grown or raised foods 34 ) and uses an assumption that the same individual consumes each of these foods in high end quantities (i.e., that an individual has high end ingestion rates for each food). The result of this analysis was the development of site-specific emission screening thresholds for POM, CDDF, mercury compounds, and cadmium compounds. It isimportant to note that, even with the inclusion of some sitespecific information in the Tier II analysis, the multi-pathwayscreening analysis is a still a very conservative, healthprotective assessment (e.g., upper-bound consumption of local fish, locally grown, and/or raised foods) and in all likelihood will yield results that serve as an upper-bound multi-pathway risk associated with a facility. While the screening analysis is not designed to produce a quantitative risk result, the factor by which the emissions

33 Burger, J. 2002. Daily consumption of wild fish and game: Exposures of high end recreationists. International Journal of Environmental Health Research 12:343-354

34 U.S. EPA. Exposure Factors Handbook 2011 Edition (Final). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/052F, 2011.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 279 of 381exceed the threshold serves as a rough gauge of the “upperlimit” risks we would expect from a facility. Thus, for example, if a facility emitted a PB-HAP carcinogen at a level 2 times the screening threshold, we can say with a high degree of confidence

that the actual maximum cancer risks will be less than 2-in-1 million. Likewise, if a facility emitted a noncancer PB-HAP at a level 2 times the screening level, the maximum noncancer risks would represent a HQ less than 2. The high degree of confidence comes from the fact that the screens are developed using the very conservative (health-protective) assumptions that we

describe above. Based on the Tier II screening analysis, one facility emits cadmium compounds above the Tier II screening level and exceeds that level by about a factor of 2. Twenty-three facilities emit CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin toxicity equivalent (TEQ) above the Tier II screening level, and the facility with the highest emissions of dioxins exceeds the Tier II screening level by about a factor of 40. No facilities emit mercury compounds above the Tier II screening levels. Forty-four facilities emit POM as benzo(a)pyrene TEQ above the Tier II screening level, and the facility with the highest emissions of POM as benzo(a)pyrene TEQ exceeds its screening level by a

factor of 30.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 280 of 381 Polychlorinated biphenyls (PCB) are PB-HAP that do not currently have multi-pathway screening values and so are not evaluated for potential non-inhalation risks. These HAP, however, are not emitted in appreciable quantities (0.001 tpy) from refinery operations, and we do not believe they contribute to multi-pathway risks for this source category. Results of the analysis for lead indicate that the maximum annual off-site ambient lead concentration was only 2 percent of the NAAQS for lead, and even if the total annual emissions occurred during a 3-month period, the maximum 3-month rolling average concentrations would still be less than 8 percent of the NAAQS, indicating that there is no concern for multi-pathway

risks due to lead emissions. 4. Refined Multipathway Case Study To gain a better understanding of the uncertainty associated with the multipathway Tier I and II screening analysis, a refined multipathway case study using the TRIM.Fate model was conducted for a single petroleum refinery. The site, a refinery in St. John the Baptist Parish, Louisiana, was selected based upon its close proximity to nearby lakes and farms as well as having one of the highest potential multipathway risks for PAH based on the Tier II analysis. The refined analysis for thisfacility showed that the Tier II screen for each pollutant overpredicted the potential risk when compared to the refined***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 281 of 381 analysis results. For this site, the Tier II screen for mercury indicated that mercury emissions were 3 times lower than the screening threshold, indicating a potential maximum HQ for mercury of 0.3. In the refined analysis, the potential HQ was 0.04 or about 7 times lower than that predicted by the Tier II screen. For cadmium emissions, the Tier II screen for this facility indicated that cadmium emissions were about 20 times lower than the screening threshold, indicating a potential maximum HQ for mercury of 0.05. The results of the refined analysis for the selected site in Louisiana show a maximum cadmium HQ of 0.02 or about 3 times lower than that predicted by the Tier II screen. For PAH emissions, the site selected for the refined analysis had PAH emissions 20 times the PAH Tier II screening threshold, indicating a potential cancer risk of 20- in-1 million. When the more refined analysis was conducted forthis site, the potential cancer risks were estimated to be 2-in1 million or about 14 times lower than predicted by the Tier II analysis. Finally, for the facility selected for the refinedassessment, the emissions of CDDF as 2,3,7,8-tetrachlorodibenzop-dioxin TEQ are 5 times higher than the dioxin Tier II screening threshold, indicating a potential maximum cancer risk of 5–in-1 million. In the refined assessment, the cancer risk from dioxins was estimated to be 2-in-1 million, about one-third

of the estimate from the Tier II screen.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 282 of 381 Overall, the refined analysis predicts a potential lifetime cancer risk of 4-in-1 million to the maximum most exposed individual (MIR). The non-cancer HQ is predicted to be well below 1 for all target organs. The chronic inhalation cancer

risk assessment estimated inhalation cancer risk around this same facility to be approximately 10-in-1 million, due in large part to emissions of naphthalene and 2-methylnaphthalene (both non-persistent, bioaccumulative, and toxic (PBT) HAP). Thus, although highly unlikely, if around this facility the person with the highest chronic inhalation cancer risk is also the same person with the highest individual multipathway cancer risk, then the combined, worst-case MIR for that facility could theoretically be 10-in-1 million (risk estimates are expressed as 1 significant figure). While this refined assessment was performed on only a single facility, the results of this single refined analysis indicate that if refined analyses were performed for other sites, the risk estimates would consistently be lower than those estimated by the Tier II analysis. In addition, the risks predicted by the multipathway analyses at most facilities are considerably lower than the risk estimates predicted by the inhalation assessment, indicating that the inhalation risk results are in all likelihood the primary factor in our residual risk determination for this source category.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 283 of 381 Further details on the site-specific case study can be found in Appendix 10 of the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in Docket ID Number EPA-HQ-OAR-2010-0682. 5. Environmental Risk Screening Results

As described in the Draft Residual Risk Assessment for Petroleum Refining Source Sector, which is available in Docket ID Number EPA-HQ-OAR-2010-0682, we conducted an environmental risk screening assessment for the petroleum refineries source category. In the Tier I screening analysis for PB-HAP (other than lead, which was evaluated differently, as noted in Section III.A.6 of this preamble), the individual modeled Tier I concentrations for one facility in the source category exceeded some of the ecological benchmarks for mercury. In addition, Tier

I modeled concentrations for four facilities exceeded sediment and soil ecological benchmarks for PAH. Therefore, we conducted

a Tier II assessment. In the Tier II screening analysis for PB-HAP, none of the individual modeled concentrations for any facility in the source category exceeded any of the ecological benchmarks (either the LOAEL or NOAEL). For lead compounds, we did not estimate any exceedances of the secondary lead NAAQS. Therefore, we did not conduct further assessment for lead compounds.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 284 of 381 For acid gases, the average modeled concentration around each facility (i.e., the average concentration of all off-site data points in the modeling domain) did not exceed any ecological benchmark. In addition, for both HCL and HF, each individual concentration (i.e., each off-site data point in the modeling domain) was below the ecological benchmarks for all

facilities. 6. Facility-Wide Risk Results Table 11 of this preamble displays the results of the facility-wide risk assessment. **Table 11. Petroleum Refining Facility-Wide Risk Assessment Results**  **Number of facilities analyzed** 142 **Cancer Risk:** Estimated maximum facility-wide individual cancer risk (-in-1 million) 70

Number of facilities with estimated facility-wide individual cancer risk of 10-in-1 million or more 54

Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 10-in-1 million or more 50

Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more 115

Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 1-in-1 million or more 107

**Chronic Non-cancer Risk:** Maximum facility-wide chronic non-cancer TOSHI 4 Number of facilities with facility-wide maximum non-cancer TOSHI greater than 1 5

Number of petroleum refining operations contributing 50 percent or more to facility-wide maximum non-cancer TOSHI of 1 or more 0***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 285 of 381 The maximum individual cancer whole-facility risk from all HAP emissions at any petroleum refinery is estimated to be 70- in-1 million, based on actual emissions. Of the 142 facilities included in this analysis, 54 have facility-wide maximum individual cancer risks of 10-in-1 million or greater. At the majority of these facilities (50 of 54), the petroleum refinery operations account for over 50 percent of the risk. There are 115 facilities with facility-wide maximum individual cancer risks of 1-in-1 million or greater. At the majority of these facilities (107 of 115), the petroleum refinery operations account for over 50 percent of the risk. The facility-wide maximum individual chronic non-cancer TOSHI is estimated to be 4, based on actual emissions. Of the 142 refineries included in this analysis, five have a TOSHI value greater than 1. The highest non-cancer TOSHI results from emissions of chlorine from cooling towers. In each case, the petroleum refinery operations account for less than 20 percent of the TOSHI values greater than 1. Additional detail regarding the methodology and the results of the facility-wide analyses are included in the risk assessment documentation (Draft Residual Risk Assessment for Petroleum Refining Source Sector), which is available in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010- 0682).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 286 of 381 7. What demographic groups might benefit from this regulation? To examine the potential for any environmental justice issues that might be associated with the source categories, we performed a demographic analysis of the population close to the facilities. In this analysis, we evaluated the distribution of HAP-related cancer and non-cancer risks from petroleum refineries across different social, demographic, and economic groups within the populations living near facilities identified as having the highest risks. The methodology and the results of the demographic analyses are included in a technical report, Draft Risk and Technology Review – Analysis of Socio-Economic Factors for Populations Living Near Petroleum Refineries,available in the docket for this action (Docket ID Number EPAHQ-OAR-2010-0682). The results of the demographic analysis are summarized in Table 12 of this preamble. These results, for various demographic groups, are based on the estimated risks from actual emissions levels for the population living within 50 km of the

facilities. **Table 12. Petroleum Refining Demographic Risk Analysis Results**

**Nationwide Population with**  **Cancer Risk at or Above 1-in-1**  **Million Population with**  **Chronic Hazard Index Above 1**  Total Population 312,861,265 5,204,234 0 **Race by Percent** White 72 50 0***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 287 of 381

All Other Races 28 50 0 **Race by Percent** White 72 50 0 African American 13 28 0 Native American 1 1 0 Other and Multiracial 14 21 0 **Ethnicity by Percent** Hispanic 17 29 0 Non-Hispanic 83 71 0 **Income by Percent** Below Poverty Level 14 21 0 Above Poverty Level 86 79 0 **Education by Percent** Over 25 and without High School Diploma 15 23 0

Over 25 and with a High School Diploma 85 77 0

The results of the demographic analysis indicate that emissions from petroleum refineries expose approximately 5,000,000 people to a cancer risk at or above 1-in-1 million. The percentages of the at-risk population in each demographic group (except for White and non-Hispanic) are similar to or lower than their respective nationwide percentages. Implementation of the provisions included in this proposal is expected to reduce the number of people estimated to have a cancer risk greater than 1-in-1 million due to HAP emissions from these sources from 5,000,000 people to about 4,000,000. Our analysis of the demographics of the population within 50 km of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 288 of 381 the facilities indicates potential disparities in certain demographic groups, including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma. The population living within 50 km of the 142 petroleum refineries has a higher percentage of minority, lower income and lower education persons when compared to the nationwide percentages of those groups. For example, 50 percent are in one or more minority demographic group, compared to 28 percent nationwide. As noted above, approximately 5,000,000 people currently living within 50 km of a petroleum refinery have a cancer risk greater than 1-in-1 million. Thus, we would expect that half of those people are in one or more minority demographic groups. Because minority groups make up a large portion of the population living near refineries, as compared with their representation nationwide, those groups would similarly see a greater benefit from the implementation of the controls proposed in this rule, if finalized. For example, we estimate that after implementation of the controls proposed in this action (i.e., post-controls), about 1,000,000 fewer people will be exposed to cancer risks greater than 1-in-1 million (i.e., 4,000,000 people). Further, we estimate that approximately 500,000 people no longer exposed to a cancer risk greater than 1-in-1 million would be in a minority demographic group. The post-control risk***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 289 of 381 estimates are discussed further in Section III.A.5 of this preamble. Although the EPA’s proposed fenceline monitoring requirement is intended to ensure that fugitive emissions are controlled as expected by the MACT standards, it is also expected to help the EPA understand and identify emissions of benzene and other fugitives that are impacting communities in close proximity to the facility. While currently-available emissions and monitoring data do not indicate that risks to nearby populations are unacceptable (see Section IV.D.1 of this preamble), we recognize that the collection of additional data through routine fenceline monitoring can provide important information to communities concerned with potential risks associated with emissions from fugitive sources. As noted in Section IV.B.1.h of this preamble, directly monitoring fugitive emissions from each potential emissions source at the facility is impractical. Fenceline monitoring offers a cost-effective alternative for monitoring fugitive emissions from the entire facility. The EPA’s proposal to require the electronic reporting of fenceline monitoring data on a regular basis (i.e., every 2 weeks) will ensure that communities have access to data on benzene levels near the facility, which is directly relevant to the potential health risks posed by the facility. In light of the disproportionate number of some minority and low-income***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 290 of 381 groups exposed to refinery emissions, the fenceline monitoring information is particularly relevant to these communities. The proposed requirements for fenceline monitoring and corrective action when fugitive emissions from a facility exceed the specified corrective action level will serve as an important backstop to protect the health of the populations surrounding the facility, including minority and low-income populations. D. What are our proposed decisions regarding risk acceptability, ample margin of safety and adverse environmental effects? 1. Risk Acceptability As noted in Section II.A.1 of this preamble, the EPA sets standards under CAA Section 112(f)(2) using “a two-step standard-setting approach, with an analytical first step to determine an ‘acceptable risk’ that considers all health information, including risk estimation uncertainty, and includes a presumptive limit on maximum individual lifetime risk (MIR) of approximately 1 in 10 thousand [35] .” (54 FR 38045, September 14, 1989). In this proposal, we estimate risks based on actual emissions from petroleum refineries. We also estimate risks from allowable emissions; as discussed earlier, we consider our analysis of risk from allowable emissions to be conservative and

35 1-in-10 thousand is equivalent to 100-in-1 million. The EPA currently describes cancer risks as ‘n-in-1 million’.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 291 of 381 as such to represent an upper bound estimate on risk from

emissions allowed under the current MACT standards for the source categories.

a. Estimated Risks from Actual Emissions

The baseline inhalation cancer risk to the individual most exposed to emissions from sources regulated by Refinery MACT 1

and 2 is 60-in-1 million based on actual emissions. The estimated incidence of cancer due to inhalation exposures is 0.3 excess cancer cases per year, or 1 case every 3.3 years. Approximately 5,000,000 people face an increased cancer risk greater than 1-in-1 million due to inhalation exposure to actual HAP emissions from these source categories, and approximately 100,000 people face an increased risk greater than 10-in-1 million and up to 60-in-1 million. The agency estimates that the maximum chronic non-cancer TOSHI from inhalation exposure is 0.9

due to actual emissions of HCN from FCCU. The screening assessment of worst-case acute inhalation impacts from actual emissions indicates the potential for five pollutants – nickel, arsenic, acrolein, benzene and acetaldehyde - to exceed an HQ value of 1, with an estimated worst-case maximum HQ of 5 for nickel based on the REL values. One hundred thirty-six of the 142 petroleum refineries had an estimated worst-case HQ less than or equal to 1 for all HAP. One facility had an estimated worst-case maximum HQ of 5 and the remaining***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 292 of 381 five refineries with an HQ above 1 had an estimated worst-case HQ less than or equal to 3. Considering the conservative, health-protective nature of the approach that is used to develop these acute estimates, it is highly unlikely that an individual would have an acute exposure above the REL. Specifically, the analysis is based on the assumption that worst-case emissions and meteorology would coincide with a person being at this exact location for a period of time long enough to have an exposure

level above the conservative REL value. The Tier II multipathway screening analysis of actual emissions indicated the potential for PAH emissions that are about 30 times the screening level for cancer, dioxin and furans

emissions that are about 40 times the cancer threshold and

cadmium emissions that are about 2 times the threshold for noncancer. No facility’s emissions were above the threshold for mercury. As we note above, the Tier II multipathway screen is conservative in that it incorporates many health-protective assumptions. For example, we choose inputs from the upper end of the range of possible values for the influential parameters used in the Tier II screen and we assume that the exposed individual exhibits ingestion behavior that would lead to a high total exposure. A Tier II exceedance cannot be equated with a risk value or a HQ or HI. Rather, it represents a high-end estimate of what the risk or hazard may be. For example, an exceedance of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 293 of 381 2 for a non-carcinogen can be interpreted to mean that we have high confidence that the HI would be lower than 2. Similarly, an exceedance of 30 for a carcinogen means that we have high

confidence that the risk is lower than 30-in-1-million. Our confidence comes from the conservative, or health-protective, assumptions that are used in the Tier II screen. The refined analysis that we conducted for a specificfacility showed that the Tier II screen for each pollutant overpredicted the potential risk when compared to the refined analysis results. That refined multipathway assessment showed

that the Tier II screen resulted in estimated risks that are higher than the risks estimated by the refined analysis by 14 times for PAH, 3 times for dioxins and furans, and 3 times for

cadmium. The refined assessment results indicate that the multipathway risks are considerably lower than the estimated inhalation risks, and our refined multipathway analysis indicates that multipathway risks are low enough that, while they are considered in our proposed decisions, they do not weigh heavily into those decisions because risks for the source category are driven by inhalation.

b. Estimated Risks from Allowable Emissions

We estimate that the baseline inhalation cancer risk to the individual most exposed to emissions from sources regulated by Refinery MACT 1 and 2 is up to 100-in-1 million based on***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 294 of 381 allowable emissions. The EPA estimates that the incidence of cancer due to inhalation exposures could be up to 0.6 excess cancer cases per year, or 1 case approximately every 1.5 years. About 7,000,000 people face an increased cancer risk greater than 1-in-1 million due to inhalation exposure to allowable HAP emissions from these source categories, and greater than 90,000 people face an increased risk greater than 10-in-1 million, and up to 100-in-1 million. Further, we estimate that the maximum chronic non-cancer TOSHI from inhalation exposure values at all

refineries is less than 1 based on allowable emissions.

The baseline risks summarized above do not account for additional risk reductions that we anticipate due to the MACT standards or the technology review requirements we are proposing

in this action. c. Acceptability Determination In determining whether risk is acceptable, the EPA

considered all available health information and risk estimation uncertainty as described above. As noted above, the agency

estimated risk from actual and allowable emissions. While there

are uncertainties associated with both the actual and allowable emissions, we consider the allowable emissions to be an upper bound, based on the conservative methods we used to calculate

allowable emissions.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 295 of 381 The results indicate that both the actual and allowable inhalation cancer risks to the individual most exposed are no greater than approximately 100–in-1 million, which is the presumptive limit of acceptability. The MIR based on actual emissions is 60-in-1 million, a little more than 50 percent ofthe presumptive limit. Based on the results of the refined sitespecific multipathway analysis summarized above and described in Section IV.C.3 of this preamble, we also conclude that the ingestion cancer risk to the individual most exposed is significantly less than 100-in-1 million. In addition, the maximum chronic non-cancer TOSHI is less than 1, and our refined multipathway analysis indicates that non-cancer ingestion risk is less significant than non-cancer risk from inhalation. Finally, the evaluation of acute non-cancer risks was very conservative, and showed acute risks below a level of concern. In determining risk acceptability, we also evaluated population impacts because of the large number of people living near facilities in the source category. The analysis indicates that there are approximately 5 million people exposed to actual emissions resulting in a cancer risk greater than 1-in-1 million, and a substantially smaller number of people (100,000) are exposed to a cancer risk of greater than 10-in-1 million but less than 100-in-1 million (with a maximum risk of 60-in-1 million). The inhalation cancer incidence is approximately one***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 296 of 381 case in every 3 years based on actual emissions. More detail on this risk analysis is presented in Section IV.C and summarized in Tables 10 and 11 of this preamble. The results of the demographic analysis for petroleum refineries indicate that a greater proportion of certain minority groups and low-income populations live near refineries than the national demographic profile. More detail on these population impacts are presented in Section IV.C.7 of this preamble. We did not identify any sensitivity to risks particular to minority and low income populations from pollutants emitted from these source categories. Considering the above information, we propose that the risks remaining after implementation of the existing NESHAP for the Refinery MACT 1 and 2 source categories is acceptable for all proximate populations.

We also note that the estimated baseline risks for the refineries source categories include risks from emissions from DCUs, which are a previously unregulated emission source. As discussed in section IV.A. of this preamble, we are proposing

new MACT standards for these sources that would reduce emissions of HAP by 850 TPY. We estimate that these new standards would not affect the MIR, but would reduce the source category cancer incidence by 15 percent. We solicit comment on all aspects of our proposed acceptability determination. We note that while we are proposing***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 297 of 381 that the risks estimated from actual and allowable emissions are acceptable, the risks based on allowable emissions are at the high end of the range. Furthermore, a significant number of people live in relative proximity to refineries across the country, and therefore a large population is exposed to the risks we estimate here. In particular, we solicit comment on the methodology used to estimate allowable emissions. As noted above, we consider the allowable emissions to be an upper bound

estimate based on the conservative methods used to calculate such emissions. We recognize, however, that some of the health information concerning allowable emissions arguably borders on the edge of acceptability. Specifically, the allowable analysis resulted in a MIR of 100-in-1 million, which is the presumptive limit of acceptability, a large number of people (7,000,000) estimated to be exposed at a cancer risk above 1-in-1 million, and a high cancer incidence (one case approximately every 1.5 years). Although we believe that our allowable emissions represent an upper end estimate, we nonetheless solicit comment on whether the health information currently before the Agency should be deemed unacceptable. We also solicit comment on whether our allowable emissions analysis reflects a reasonable

estimate of emissions allowed under the current MACT standards. Please provide comments and data supporting your position. Such***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 298 of 381 information will aid the Agency to make an informed decision on risk acceptability as it moves forward with this rulemaking. 2. Ample Margin of Safety We next considered whether the existing MACT standards provide an ample margin of safety to protect public health. In addition to considering all of the health risks and other health information considered in the risk acceptability determination, in the ample margin of safety analysis we evaluated the cost and feasibility of available control technologies and other measures that could be applied in these source categories to further

reduce the risks due to emissions of HAP. Due to the nature of the allowable risk analysis, which is based on model plants and post processing to combine risk results 36 , we did not evaluate the risk reductions resulting from applying controls to individual emission sources. Such an approach would require an unnecessarily complex analysis that would not provide any more useful information. Therefore, for purposes of the ample margin of safety, we evaluated the changes in risk that would occur through adoption of a specific technology by looking at the changes to the risk due to actual emissions. We note that while we did not conduct a specific analysis for allowable emissions,

36 As described in the memorandum entitled “Refinery Emissions and RiskEstimates for Modeled “Allowable” Emissions, available in Docket EPA-HQ-OAR2010-0682, the use of model plants and post-processing was for the purpose of ensuring that our analysis would provide a conservative estimate of actual emissions and thus a conservative estimate of risk.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 299 of 381 it is reasonable to expect reductions in risk similar to those

for actual emissions. As noted in our discussion of the technology review in Section IV.B of this preamble, we identified a number of developments in practices, processes or control technologies for reducing HAP emissions from petroleum refinery processes. As part of the risk review, we evaluated these developments to determine if any of them could reduce risks and whether it is necessary to require any of these developments to provide an ample margin of safety to protect public health. We evaluated the health information and control options for all of the emission sources located at refineries, including: storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems, wastewater collection and treatment, FCCU, flares, miscellaneous process vents, CRU and SRU. For each of these sources, we

considered chronic cancer and non-cancer risk metrics as well as acute risk. Regarding our ample margin of safety analyses for chronic non-cancer risk for the various emission sources, we

note that the baseline HI is less than 1 for the entire source category and significantly less than 1 for all of the emission sources except for the FCCU (which had an HI slightly less than 1). Therefore, we did not quantitatively evaluate reductions in

the chronic non-cancer HI for sources other than FCCU in the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 300 of 381 ample margin of safety analysis. Regarding our ample margin of safety analyses for acute risk for all of the various emission sources, we note that our analyses did not identify acute risks at a level of concern and, therefore, we did not quantitatively evaluate reductions in the acute HQ values for each individual emission source in the ample margin of safety analysis. Accordingly, the following paragraphs focus on cancer risk in the determination of whether the standards provide an ample margin of safety to protect public health. For storage vessels, as discussed in Section IV.B of this preamble, we identified and evaluated three control options. Under the technology review, we determined that two of the options, which we call options 1 and 2, are cost effective. We are proposing option 2, which includes all of the requirements of option 1, as part of the technology review. The option 2 controls that we are proposing under the technology review would result in approximately 910 tpy reduction in HAP (a 40-percent reduction from this emission source). As described in Section IV.B of this preamble, not only are these controls cost effective, but we estimate a net cost savings because the emission reductions translate into reduced product loss. These

controls would reduce the cancer risk to the individual most exposed from 60-in-1 million to 50-in-1 million based on actual emissions at the facility where storage tank emissions were***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 301 of 381 driving the risk. However, the MIR remains unchanged for the refinery source categories, at 60-in 1-million, because the facility with the next highest cancer risk is 60-in-1 million and this risk is driven by another emission source. The option 2 controls also would reduce cancer incidence by approximately 2 percent. Finally, we estimate that the option 2 controls reduce the number of people with a cancer risk greater than 10-in-1 million storage tanks from 3,000 to 60 and reduce the number of people with a cancer risk greater than 1-in-1 million from storage tanks from 140,000 to 72,000. Since these controls reduce cancer incidence, and reduce the number of people exposed to cancer risks greater than 1-in-10 million and 1-in-1 million from storage tank emissions, and are cost effective, we propose that these controls are necessary to provide an ample margin of safety to protect public health. We also evaluated one additional control option for storage vessels, option 3, which incorporated both options 1 and 2 along with additional monitoring requirements. We estimate incremental HAP emission reductions (beyond those provided by option 2) of 90 tpy. The incremental cost effectiveness for option 3 exceeds $60,000 per ton, which we do not consider cost effective. In addition, the option 3 controls do not result in quantifiable reductions in the cancer risk to the individual most exposed or the cancer incidence beyond the reductions estimated for the option 2***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 302 of 381 controls. For these reasons, we propose that it is not necessary to require the option 3 controls in order to provide an ample margin of safety to protect public health. For equipment leaks, we identified and evaluated three control options discussed previously in the technology review section of this preamble (Section IV.B). These options are: option 1 - monitoring and repair at lower leak definitions; option 2 - applying monitoring and repair requirements to connectors; and option 3 - optical gas imaging and repair. We estimate that these three independent control options reduce industry-wide emissions of organic HAP by 24 tpy, 86 tpy, and 24 tpy, respectively. We estimate that none of the control options would reduce the risk to the individual most exposed. We also estimate that the cancer incidence would not change perceptively if these controls were required. Finally, we estimate that the control options do not reduce the number of people with a cancer risk greater than 10-in-1 million or the number of people with a cancer risk greater than 1-in-1 million. As discussed above, the available control options for equipment leaks do not provide quantifiable risk reductions and, therefore, we propose that these controls are not necessary to provide an ample margin of safety. For gasoline loading racks, we identified and evaluated one control option discussed previously in the technology review***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 303 of 381 section of this preamble (Section IV.B). As discussed earlier, this option is a new development that results in emissions that are higher than the current level required under Refinery MACT

1. Since we estimate that no emission reductions would result from this new technology and thus no reduction in risk, we propose that this control option is not necessary to provide an ample margin of safety. For marine vessel loading operations, we identified and evaluated two control options discussed previously in the technology review section of this preamble (Section IV.B). The first option would be to require submerged fill for small and offshore marine vessel loading operations. Based on actual emissions, we project no HAP emission reductions for this option, as all marine vessels that are used to transport bulk refinery liquids are expected to already have the required submerged fill pipes. Accordingly, we do not project any changes in risk. While we are proposing this option under the technology review, because the option is not projected to reduce emissions or risk, we propose that a submerged loading requirement is not necessary to provide an ample margin of safety. We also identified and evaluated the use of add-on controls for gasoline loading at small marine vessel loading operations. In the technology review, we rejected this control option because the cost effectiveness exceeded $70,000 ton of HAP reduced. We***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 304 of 381 estimate that this option would not result in quantifiable changes to any of the risk metrics. Because add-on controls would not result in quantifiable risk reductions and we do not consider the controls to be cost effective, we are proposing that add-on controls for gasoline loading at small marine vessel loading operations are not necessary to provide an ample margin of safety. For cooling towers and heat exchangers, we did not identify as part of our technology review any developments in processes, practices or controls beyond those that we considered in our beyond-the-floor analysis at the time we set the MACT standards. We note that we issued MACT standards for heat exchange systems in a final rule on October 28, 2009 (74 FR 55686), but existing sources were not required to comply until October 29, 2012. As a result, the reductions were not reflected in the inventories submitted in response to the ICR for refineries and therefore were not included in our risk analysis based on actual

emissions. We estimate that these MACT standards will result in an industry-wide reduction of over 600 tons HAP per year (or 85 percent). The projected contribution to risk associated with cooling tower emissions after implementation of these MACT standards for heat exchange systems is approximately 1 percent. Because we did not identify any control options beyond those required by the current standards for cooling towers and heat***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 305 of 381 exchange systems, we are proposing that additional controls for these systems are not necessary to provide an ample margin of safety. For wastewater collection and treatment systems, we identified and evaluated three options for reducing emissions. We estimate implementing these independent control options would result in emission reductions of 158 tpy (4 percent), 549 tpy (15 percent), and 929 tpy (25 percent), respectively. None of the control options would reduce the cancer risk to the individual most exposed from 60-in-1 million. Option 1 would reduce the cancer incidence by less than 1 percent, and we expect any reduction in cancer incidence that would result from options 2 or 3 to be small because this source accounts for about 10 percent of the cancer incidence from refineries as a whole and the most stringent control option would reduce emissions from these source by only 25 percent. Finally, we estimate that control option 1 would not reduce the number of people with a cancer risk greater than 10-in-1 million or the number of people with a cancer risk greater than 1-in-1 million. We expect any changes to the number of people with a cancer risk greater than 1-in-1 million from implementation of options 2 or

3 to be small for the same reasons mentioned above for cancer incidence. We estimate the cost effectiveness of these options to be $26,600 per ton, $52,100 per ton, and $54,500 per ton of***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 306 of 381 organic HAP reduced, and we do not consider any of these options to be cost effective. Because of the very small reductions in risk and the lack of cost-effective control options, we propose that these controls are not necessary to provide an ample margin of safety. For FCCU, we did not identify any developments in processes, practices or control technologies for organic HAP. For inorganic HAP from FCCU, in the technology review, we identified and evaluated one control option for an HCN emissions limit and one control option for a PM emissions limit. The PM limit was adopted for new sources in Refinery NSPS Ja as part of our review of Refinery NSPS J. We considered the costs and emission reductions associated with requiring existing sources to meet the new source level for PM under Refinery NSPS Ja (i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg). As indicated in our promulgation of Refinery NSPS Ja, the cost effectiveness of lowering the PM limit for existing sources to the level we are requiring for new sources was projected to be $21,000 per ton of PM reduced (see 73 FR 35845). Based on the typical metal HAP concentration in PM from FCCU, the cost effectiveness of this option for HAP metals is approximately $1 million per ton of HAP reduced. We estimate that this control option would not reduce the cancer risk to the individual most exposed, would not change the cancer incidence, and would not***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 307 of 381 change the number of people with estimated cancer risk greater

than 1-in-1 million or 10-in-1 million. For the HCN emissions limit, we evaluated the costs of controlling HCN using

combustion controls in combination with SCR. The cost effectiveness of this option was approximately $9,000 per ton of HCN. This control option would reduce the non-cancer HI from 0.9 to 0.8 and would not change any of the cancer risk metrics. Based on the cost effectiveness of these options and the limited reduction in cancer and non-cancer risk (the non-cancer risk is below a level of concern based on the existing standards), we propose that additional controls for FCCU are not necessary to provide an ample margin of safety.

Flares are used as APCD to control emissions from several emission sources covered by Refinery MACT 1 and 2. In this proposed rule, under CAA Sections 112(d)(2) and (3), we are proposing operating and monitoring requirements to ensure flares achieve the 98-percent HAP destruction efficiency identified as the MACT Floor in the initial MACT rulemaking in 1995. Flares are critical safety devices that effectively reduce emissions during startup, shutdown, and process upsets or malfunctions. In most cases, flares are the only means by which emissions from pressure relief devices can be controlled. Thus, we find that properly-functioning flares act to reduce HAP emissions, and thereby risk, from petroleum refinery operations. The changes to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 308 of 381 the flare requirements that we are proposing under the technology review will result in sources meeting the level required by the original standards, and we did not identify any control options that would further reduce the HAP emissions from flares. Therefore, we are proposing that additional controls for flares are not necessary to provide an ample margin of safety. For the remaining emission sources within the Refinery MACT 1 and Refinery MACT 2 source categories, including miscellaneous process vents, CRU, and SRU, we did not identify any developments in processes practices and control technologies. Therefore, we are proposing that additional controls for these three Refinery MACT 1 and 2 emission sources are not necessary to provide an ample margin of safety. In summary, we propose that the original Refinery MACT 1 and 2 MACT standards, along with the proposed requirements for storage vessels described above, provide an ample margin of safety to protect public health. We are specifically requesting

comment on whether there are additional control measures for emission sources subject to Refinery MACT 1 and Refinery MACT 2 that are necessary to provide an ample margin of safety to protect public health. In particular, we are requesting that states identify any controls they have already required for these facilities, controls they are currently considering, or other controls of which they may be aware.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 309 of 381 While not part of our decisions regarding residual risk, we note that DCU are an important emission source with respect to

risk from refineries. As described in Section IV.A of this preamble, we are proposing new MACT standards under CAA Sections 112(d)(2) and (3) for DCU. For informational purposes, we also

looked at the risk reductions that would result from implementation of those standards. We estimate no reduction in the cancer risk to the individual most exposed and a decrease in cancer incidence of 0.05 cases per year, or approximately 15 percent. While our decisions on risk acceptability and ample margin of safety are supported even in the absence of these reductions, if we finalize the proposed requirements for DCU, they would further strengthen our conclusions that risk is acceptable with an ample margin of safety to protect public

health.

3. Adverse Environmental Effects We conducted an environmental risk screening assessment for the petroleum refineries source category for lead, mercury, cadmium, PAH, dioxins and furans, HF, and HCl. For mercury, cadmium, PAH, and dioxins and furans, none of the individual modeled concentrations for any facility in the source category exceeded any of the Tier II ecological benchmarks (either the LOAEL or NOAEL). For lead, we did not estimate any exceedances of the secondary lead NAAQS. For HF and HCl, the average modeled***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 310 of 381 concentration around each facility (i.e., the average concentration of all off-site data points in the modeling domain) did not exceed any ecological benchmark. E. What other actions are we proposing? We are proposing the following changes to Refinery MACT 1 and 2 as described below: (1) revising the startup, shutdown, and malfunction (SSM) provisions in order to ensure that the subparts are consistent with the court decision in Sierra Club V. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), which vacated two provisions that exempted sources from the requirement to comply with otherwise applicable Section 112(d) emission standards during periods of SSM; (2) adding a definition to clarify leak detection requirements related to open-ended valves or lines; (3) adding electronic reporting requirements in Refinery MACT 1 and 2; and (4) updating the General Provisions cross-reference

tables.

1. SSM and Affirmative Defense The United States Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in the EPA’s CAA Section 112 regulations governing the emissions of HAP during periods of SSM. Sierra Club V. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1) holding that under***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 311 of 381 Section 302(k) of the CAA, emissions standards or limitations must be continuous in nature and that the SSM exemption violates the CAA's requirement that some Section 112 standards apply continuously. We are proposing the elimination of the SSM exemption in 40 CFR part 63, subparts CC and UUU. Consistent with Sierra Club V. EPA, the EPA is proposing standards in these rules that apply at all times. We are also proposing several revisions to Table 6 of subpart CC of 40 CFR part 63 and to Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions Applicability tables for each subpart) as explained in more detail below. For example, we are proposing to eliminate the incorporation of the General Provisions’ requirement that the source develop an SSM plan. We also are proposing to eliminate and revise certain recordkeeping and reporting requirements related to the SSM exemption as

further described below. The EPA has attempted to ensure that the provisions we are proposing to eliminate are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. We are specifically seeking comment on whether we have successfully

done so. In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below, we are proposing alternate standards for those***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 312 of 381 periods for a few select emission sources. We expect facilities can meet nearly all of the emission standards in Refinery MACT 1 and 2 during startup and shutdown, including the amendments we are proposing in this action. For most of the emission sources, APCD are operating prior to process startup and continue to operate through process shutdown. For Refinery MACT 1 and 2, we identified three emission sources for which specific startup and shutdown provisions may be needed. First, as noted above, most APCD used to control metal HAP emissions from FCCU under Refinery MACT 2 (e.g., wet scrubber, fabric filter, cyclone) would be operating before emissions are routed to them and would be operating during startup and shutdown events in a manner consistent with normal operating periods, such that the monitoring parameter operating limits set during the performance test are maintained and met. However, we recognize that there are safety concerns associated with operating an ESP during startup of the FCCU, as described in the following paragraphs. Therefore, we are proposing specific PM standards for startup of FCCU controlled with an ESP under Refinery MACT 2. During startup of the FCCU, “torch oil” (heavy oil typically used as feed to the unit via the riser) is injected directly into the regenerator and burned to raise the temperature of the regenerator and catalyst to levels needed for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 313 of 381 normal operation. Given the poor mixing of fuel and air in the regenerator during this initial startup, it is difficult to maintain optimal combustion characteristics, and high CO concentrations are common. Elevated CO levels pose an explosion threat due to the high electric current and potential for sparks within the ESP. Consequently, it is common practice to bypass the ESP during startup of the FCCU. Once torch oil is shut off and the regenerator is fueled by catalyst coke burn-off, the CO levels in the FCCU regenerator off-gas will stabilize and the gas can be sent to the ESP safely. When the ESP is offline, the operating limits for the ESP are meaningless. During much of the startup process, either catalyst is not circulating between the FCCU regenerator and reactor or the catalyst circulation rate is much lower than during normal operations. While the catalyst is not circulating or is circulating at reduced rates, the PM and metal HAP emissions are expected to be much lower than during normal operations. Therefore, the cyclone separators that are internal to the FCCU regenerator should provide reasonable PM control during this initial startup. To ensure the internal cyclones are operating efficiently, we are proposing that FCCU using an ESP as the APCD meet a 30-percent opacity limit (on a 6-minute rolling average basis) during the period that torch oil is used during FCCU startup. This opacity limit was selected because it***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 314 of 381 has been used historically to assess compliance with the PM emission limit for FCCU in Refinery NSPS J and because the emission limit can be assessed using manual opacity readings, eliminating the need to install a COMS. We note that Refinery NSPS J includes the exception for one 6-minute average of up to 60-percent opacity in a 1-hour period primarily to accommodate soot blowing events. As no soot blowing should be performed prior to the ESP coming on-line, we are not including this exception to the proposed 30-percent opacity limit during startup for FCCU that are controlled by an ESP. Second, for emissions of organic HAP from FCCU under Refinery MACT 2, we also expect that APCD would be operating before emissions are routed to them, and would be operating during startup and shutdown events in a manner consistent with normal operating periods, such that the monitoring parameter operating limits set during the performance test are maintained and met. However, many FCCU operate in “complete combustion” mode without a post-combustion device. In other words, for FCCU without a post-combustion device, organic HAP are controlled by the FCCU itself, so there is no separate APCD that could be operating during startup and demonstrating continuous compliance with the monitoring parameter operating limits. Therefore, we are proposing specific CO standards for startup of FCCU without a post-combustion device under Refinery MACT 2.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 315 of 381 As mentioned previously, “torch oil” is injected directly into the regenerator and burned during FCCU startup to raise the temperature of the regenerator and catalyst to levels needed for normal operation. During this period, CO concentrations often will exceed the 500 ppm emissions limit due to the poor mixing of fuel and air in the regenerator. The emissions limit is based on CO emissions, as a surrogate for organic HAP emissions, and the emission limit is evaluated using a 1-hour averaging period. This 1-hour averaging period does not provide adequate time for short-term excursions that occur during startup to be offset by lower emissions during normal operational periods. Based on available data during normal operations, ensuring adequate combustion (indicated by CO concentration levels below 500 ppmv) minimizes organic HAP emissions. Low levels of CO in the exhaust gas are consistently achieved during normal operations when oxygen concentrations in the exhaust gas exceed 1-percent by volume (dry basis). Thus, maintaining an adequate level of excess oxygen for the combustion of fuel in the FCCU is expected to minimize organic HAP emissions. Emissions of CO during startup result from a series of reactions with the fuel source and are dependent on mixing, local oxygen concentrations, and temperature. While the refinery owner or operator has direct control over air blast rates, CO emissions may not always directly correlate with the air blast rate. Exhaust oxygen***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 316 of 381 concentrations are expected to be more directly linked with air blast rates and are, therefore, more directly under control of the refinery owner or operator. We are proposing an excess oxygen concentration of 1 volume percent (dry basis) based on a 1-hour average during startup. We consider the 1-hour averaging period for the oxygen concentration in the exhaust gas from the FCCU to be appropriate during periods of FCCU startup because air blast rates can be directly controlled to ensure adequate oxygen supply on a short-term basis. Third, we note that the SRU is unique in that it essentially is the APCD for the fuel gas system at the facility. The SRU would be operating if the refinery is operating, including during startup and shutdown events. There are typically multiple SRU trains at a facility. Different trains can be taken off-line as sour gas production decreases to maintain optimal operating characteristics of the operating SRU during startup or shutdown of a set of process units. Thus, the sulfur recovery plant is expected to run continuously and would only shut down its operation during a complete turnaround or shutdown of the facility. For these limited situations, the 12- hour averaging time provided for the SRU emissions limitation under Refinery MACT 2 may not be adequate time in which to shut down the unit without exceeding the emissions limitation.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 317 of 381 Therefore, we are proposing specific standards for SRU during periods of shutdown. We note also that, for SRU subject to Refinery NSPS J or electing to comply with Refinery NSPS J as provided in Refinery MACT 2, the emissions limit is in terms of SO 2 concentration for SRU with oxidative control systems or reductive control systems followed by an incinerator. While the SO 2 concentration limit provides a reasonable proxy of the reduced sulfur HAP emissions during normal operations, it does not necessarily provide a good indication of reduced sulfur HAP emissions during periods of shutdown. During periods of shutdown, the sulfur remaining in the unit is purged and combusted generally in a thermal oxidizer or a flare. Although the sulfur loading to the thermal oxidizer during shutdown may be higher than during normal operations (thereby causing an increase in the SO 2 concentration and

exceedance of the SO 2 emissions limitation), appropriate operation of the thermal oxidizer will adequately control emissions of reduced sulfur HAP. Thus, during periods of shutdown, the 300 ppmv reduced sulfur compound emission limit alternative (provided for SRU not subject to Refinery NSPS J) is a better indicator of reduced sulfur HAP emissions. In Refinery MACT 2, SRU that elect to comply with the 300 ppmv reduced sulfur compound emission limit (i.e., those not subject to Refinery NSPS J or electing to comply with Refinery NSPS J) and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 318 of 381 that use a thermal incinerator for sulfur HAP control are required to maintain a minimum temperature and excess oxygen level (as determined through a source test of the unit) to demonstrate compliance with the reduced sulfur compound emission

limitation. In Refinery MACT 2, SRU subject to Refinery NSPS J (or that elect to comply with Refinery NSPS J) that use an incinerator to control sulfur HAP emissions are required to install an SO 2 CEMS to demonstrate compliance with the SO 2 emission limitation. For these units, it is impractical to require installation of a reduced sulfur compound monitor or to require a source test to establish operating parameters during shutdown of the SRU because of the few hours per year that the entire series of SRU trains are shutdown. Although the autoignition temperature of COS is unknown, based on the autoignition temperature of CS 2 (between 200 and 250 °F) and the typical operating

characteristics of thermal oxidizers used to control emissions from SRU, we are proposing that, for periods of SRU shutdown, diverting the purge gases to a flare meeting the design and operating requirements in 40 CFR 63.670 (or, for a limited transitional time period, 40 CFR 63.11) or to a thermal oxidizer operated at a minimum temperature of 1200 °F and a minimum outlet oxygen concentration of 2 volume percent (dry basis). We believe that this provides adequate assurance of compliance with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 319 of 381 the 300 ppmv reduced sulfur compound emission limitation for SRU because incineration at these temperatures was determined to be the MACT floor in cases where no tail gas treatment units were used (i.e., units not subject to Refinery NSPS J). For all other emission sources, we believe that the requirements that apply during normal operations should apply during startup and shutdown. For Refinery MACT 1, these emission sources include process vents, transfer operations, storage tanks, equipment leaks, heat exchange systems, and wastewater. Emission reductions for process vents and transfer operations, such as gasoline loading racks and marine tank vessel loading, are typically achieved by routing vapors to thermal oxidizers, carbon adsorbers, absorbers and flares. It is common practice to start an APCD prior to startup of the emissions source it is controlling, so the APCD would be operating before emissions are routed to it. We expect APCD would be operating during startup and shutdown events in a manner consistent with normal operating periods, and that these APCD will be operated to maintain and meet the monitoring parameter operating limits set during the performance test. We do not expect startup and shutdown events to affect emissions from equipment leaks, heat exchange systems, wastewater, or storage tanks. Leak detection programs associated with equipment leaks and heat exchange systems are in place to detect leaks, and, therefore, it is inconsequential whether the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 320 of 381 process is operating under normal operating conditions or is in startup or shutdown. Wastewater emissions are also not expected to be significantly affected by startup or shutdown events because the control systems used can operate while the wastewater treatment system is in startup or shutdown. Working and breathing losses from storage tanks are the same regardless of whether the process is operating under normal operating conditions or if it is in a startup or shutdown event. Degassing of a storage tank is common for shutdown of a process; the residual emissions in a storage tank are vented as part of the cleaning of the storage tank. We evaluated degassing controls as a control alternative for storage vessels and do not consider these controls to be cost effective (see memorandum Survey of Control Technology for Storage Vessels and Analysis of Impactsfor Storage Vessel Control Options, Docket Item Number EPA-HQOAR-2010-0871-0027). Based on this review, we are not proposing specific standards for storage vessels during startup or

shutdown. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a “sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * *” (40 CFR***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 321 of 381 63.2). The EPA has determined that CAA Section 112 does not require that emissions that occur during periods of malfunction be factored into development of Section 112 standards. Under Section 112, emissions standards for new sources must be no less stringent than the level “achieved” by the best-controlled similar source and for existing sources generally must be no less stringent than the average emission limitation “achieved” by the best-performing 12 percent of sources in the category. There is nothing in Section 112 that directs the EPA to considermalfunctions in determining the level “achieved” by the bestperforming or best-controlled sources when setting emission standards. Moreover, while the EPA accounts for variability in setting emissions standards consistent with the Section 112 case law, nothing in that case law requires the EPA to consider malfunctions as part of that analysis. Section 112 uses the concept of “best controlled” and “best performing” unit in defining the level of stringency that Section 112 performance standards must meet. Applying the concept of “best controlled” or “best performing” to a unit that is malfunctioning presents significant difficulties, as malfunctions are sudden and unexpected events. Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category, and given the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 322 of 381 difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not “reasonably” foreseeable. See, e.g., Sierra Club V. EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) (the EPAtypically has wide latitude in determining the extent of datagathering necessary to solve a problem. We generally defer to an agency’s decision to proceed on the basis of imperfect scientific information, rather than to “invest the resources to conduct the perfect study.”). See also, Weyerhaeuser V. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation.”). In addition, the goal of a best-controlled or best-performing source is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well-performing non-malfunctioning source. The EPA’s approach to malfunctions is consistent with***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 323 of 381 CAA Section 112 and is a reasonable interpretation of the

statute. In the event that a source fails to comply with the applicable CAA Section 112(d) standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good-faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source’s failure to comply with the CAA Section 112(d) standard was, in fact, “sudden, infrequent, not reasonably preventable” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 63.2 (definition of malfunction). Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that

such failure can sometimes cause a violation of the relevant emission standard. See, e.g., State Implementation Plans: Response to Petition for Rulemaking; Findings of Excess Emissions During Periods of Startup, Shutdown, and Malfunction; Proposed rule, 78 FR 12460 (Feb. 22, 2013); State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 324 of 381 Malfunctions (Feb. 15, 1983). The EPA is therefore proposing to add an affirmative defense to civil penalties for violations of emission standards that are caused by malfunctions. (See 40 CFR 63.641 and 40 CFR 63.1579 defining “affirmative defense” to mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also are proposing other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; the source must prove by a preponderance of the evidence that it has met all of the elements set forth in 40 CFR 63.642 or 40 CFR 63.1570. (See 40 CFR 22.24.) The criteria are designed in part to ensure that the affirmative defense is available only where the event that

causes a violation of the emission standard meets the narrow definition of malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonably preventable, and not caused by poor maintenance and/or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that the violation “[w]as caused by a sudden, infrequent, and unavoidable failure of air pollution control, process equipment, or a process to operate in a normal or usual manner....” The criteria also are designed to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 325 of 381 ensure that steps are taken to correct the malfunction, to

minimize emissions in accordance with 40 CFR 63.642 or 40 CFR 63.1570 and to prevent future malfunctions. For example, the source must prove by a preponderance of the evidence that “[r]epairs were made as expeditiously as possible when a violation occurred...” and that “[a]ll possible steps were taken to minimize the impact of the violation on ambient air quality, the environment and human health....” In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with Section 113 of the Clean Air Act (see also 40 CFR 22.27). The EPA included an affirmative defense in the proposed rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. § 7602(k) (defining “emission limitation” and “emission standard”). See generally Sierra Club V. EPA, 551 F.3d***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 326 of 381 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is required to ensure

that emissions standards are continuous. The affirmative defense for malfunction events meets this requirement by ensuring that even where there is a malfunction, the emission standard is still enforceable through injunctive relief. The United States Court of Appeals for the Fifth Circuit recently upheld the EPA’s view that an affirmative defense provision is consistent with Section 113(e) of the Clean Air Act. Luminant Generation Co. LLC V. United States EPA, 714 F.3d 841 (5th Cir. Mar. 25, 2013) (upholding the EPA’s approval of affirmative defense provisions in a CAA State Implementation Plan). While “continuous” standards, on the one hand, are required, there is also case law indicating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical V. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA Section 111 “variant provisions” such as provisions allowing for upsets during startup, shutdown and equipment malfunction “appear necessary to preserve the

reasonableness of the standards as a whole and that the record does not support the ‘never to be exceeded’ standard currently in force.” See also, Portland Cement Association V. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though intervening case law such

as Sierra Club V. EPA and the CAA 1977 amendments call into***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 327 of 381 question the relevance of these cases today, they support the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for violations that are proven to be beyond the control of the source. By incorporating an affirmative defense, the EPA has formalized its approach to malfunctions. In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating “upsets beyond the control of the permit holder.” Marathon Oil Co. V. EPA, 564 F.2d 1253, 1272-73 (9 th Cir. 1977). See also, Mont. Sulphur & Chem. Co. V. EPA, 666 F.3d. 1174 (9 th Cir. 2012) (rejecting industry argument that reliance on the affirmative defense was not adequate). But see, Weyerhaeuser Co. V. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission standards are “continuous” as required by 42 U.S.C. § 7602(k), and account for unplanned upsets, and thus support the reasonableness of the standard as a whole. The EPA is proposing the affirmative defense applicable to malfunctions under the delegation of general regulatory authority set out in Section 301(a)(1) of the Act, 42 U.S.C. § 7601(a)(1), in order to balance this tension between provisions of the Act and the practical reality, as caselaw recognizes, that technology***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 328 of 381 sometimes fails. See generally Citizens to Save Spencer County V. U.S. Environmental Protection Agency, 600 F.2d 844, 873 (D.C. Cir. 1979) (using Section 301(a) authority to harmonize inconsistent guidelines related to the implementation of federal preconstruction review requirements). a. General Duty We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(e)(1)(i) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.6(e)(1)(i) by changing the “Yes” in the third column to a “No.” We are making this change because Section 63.6(e)(1)(i) describes the general duty

to minimize emissions and the current characterizes what the general duty entails during periods of SSM and that language is no longer necessary or appropriate in light of the elimination of the SSM exemption. We are proposing instead to add general duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c) that reflects the general duty to minimize emissions while eliminating the reference to periods covered by an SSM exemption. With the elimination of the SSM exemption, there is no need to differentiate between normal operations, startup and shutdown, and malfunction events in describing the general duty.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 329 of 381 Therefore the language the EPA is proposing does not include that language from 40 CFR 63.6(e)(1). We are also proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(e)(1)(ii) by changing the “Yes” in the second column to a “No.” Similarly, we are also proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.6(e)(1)(ii) by changing the “Yes” in the third column to a “No.” Section 63.6(e)(1)(ii) imposes requirements that are not necessary with the elimination of the SSM exemption or are redundant of the general duty requirement being added at 40 CFR 63.642(n) and 40 CFR 63.1570(c).

b. SSM Plan We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.6(e)(3)(i) and 63.6(e)(3)(iii)–63.6(e)(3)(ix) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for §63.6(e)(3)(i)-(iii), §63.6(e)(3)(iv), §63.6(e)(3)(v)-(viii), §63.6(e)(3)(ix) to be entries for 63.6(e)(3)(i) and 63.6(e)(3)(iii)–63.6(e)(3)(ix) with “No” in the third column and §63.6(e)(3)(ii) with “Not Applicable” in the third column (that section is reserved). Generally, these paragraphs require development of an SSM plan and specify SSM***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 330 of 381 recordkeeping and reporting requirements related to the SSM plan. As noted, the EPA is proposing to remove the SSM exemptions. Therefore, affected units will be subject to an emission standard during such events. The applicability of a standard during such events will ensure that sources have ample incentive to plan for and achieve compliance and thus the SSM plan requirements are no longer necessary. c. Compliance with Standards We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(f)(1) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.6(f)(1) by changing the “Yes” in the third column to a “No.” The current language of 40 CFR 63.6(f)(1) exempts sources from non-opacity standards during periods of SSM. As discussed above, the court in Sierra Club vacated the exemptions contained in this provision and held that the CAA requires that some Section 112 standard apply continuously. Consistent with Sierra Club, the EPA is proposing to revise standards in this rule to apply at all times. We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(h)(1) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 331 of 381 Provisions table (Table 44) entry for §63.6(h)(1) by changing the “Yes” in the third column to a “No.” The current language of 40 CFR 63.6(h)(1) exempts sources from opacity standards during periods of SSM. As discussed above, the court in Sierra Club vacated the exemptions contained in this provision and held that the CAA requires that some Section 112 standard apply continuously. Consistent with Sierra Club, the EPA is proposing to revise standards in this rule to apply at all times. d. Performance Testing We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.7(e)(1) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.7(e)(1) by changing the “Yes” in the third column to a “No.” Section 63.7(e)(1) describes performance testing requirements. The EPA is instead proposing to add performance testing requirements at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1). The performance testing requirements we are proposing differ from the General Provisions performance testing provisions in several respects. The regulatory text does not include the language in 40 CFR 63.7(e)(1) that restated the SSM exemption. The regulatory text also does not preclude startup and shutdown periods from being considered “representative” for purposes of performance testing,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 332 of 381 however, the testing. However, the specific testing provisions proposed at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1) do not allow performance testing during startup or shutdown. As in 40 CFR 63.7(e)(1), performance tests conducted under this subpart may not be conducted during malfunctions because conditions during malfunctions are often not representative of normal operating conditions. The EPA is proposing to add language that requires the owner or operator to record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that such conditions represent normal operation. Section 63.7(e) requires that the owner or operator make available to the Administrator such records “as may be necessary to determine the condition of the performance test” available to the Administrator upon request, but does not specifically require the information to be recorded. The regulatory text EPA is proposing to add to Refinery MACT 1 and 2 builds on that requirement and makes explicit the requirement to record the

information. e. Monitoring We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.8(c)(1)(i) and 63.8(c)(1)(iii) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 333 of 381 subpart UUU General Provisions table (Table 44) entry for §63.8(c)(1)(i) and §63.8(c)(1)(iii) by changing the “Yes” in the third column to a “No.” The cross-references to the general duty and SSM plan requirements in those subparagraphs are not necessary in light of other requirements of 40 CFR 63.8 that require good air pollution control practices (40 CFR 63.8(c)(1)) and that set out the requirements of a quality control program for monitoring equipment (40 CFR 63.8(d)). We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.8(d) to include separate entries for specific paragraphs of 40 CFR 63.8(d), including an entry for §63.10(d)(3) with “No” in the third column. The final sentence in 40 CFR 63.8(d)(3) refers to the General Provisions’ SSM plan requirement which is no longer applicable. The EPA is proposing to add to the rule at 40 CFR 63.1576(b)(3) text that is identical to 40 CFR 63.8(d)(3) except that the final sentence is replaced with the following sentence: “The program of corrective action should be included in the plan required under §63.8(d)(2).” f. Recordkeeping We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(i) by changing the “Yes” in the second column to a “No.” Section 63.10(b)(2)(i) describes the recordkeeping requirements during***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 334 of 381 startup and shutdown. These recording provisions are no longer necessary because the EPA is proposing that recordkeeping and reporting applicable to normal operations will apply to startup and shutdown. In the absence of special provisions applicable to startup and shutdown, such as a startup and shutdown plan, there is no reason to retain additional recordkeeping for startup and shutdown periods. We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for §63.10(b)(2)(i) with “No” in the third column. Section 63.10(b)(2)(i) describes the recordkeeping requirements during startup and shutdown. We are instead proposing to add recordkeeping requirements to 40 CFR 63.1576(a)(2). When a source is subject to a different standard during startup and shutdown, it will be important to know when such startup and shutdown periods begin and end in order to determine compliance with the appropriate standard. Thus, the EPA is proposing to add language to 40 CFR 63.1576(a)(2) requiring that sources subject to an emission standard during startup or shutdown that differs from the emission standard that applies at all other times must record the date, time, and duration of such periods.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 335 of 381 We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(ii) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for §63.10(b)(2)(ii) with “No” in the third column. Section 63.10(b)(2)(ii) describes the recordkeeping requirements during a malfunction. The EPA is proposing to add such requirements to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2). The regulatory text we are proposing to adddiffers from the General Provisions language that was crossreferenced, which provides the creation and retention of a

record of the occurrence and duration of each malfunction of process, air pollution control, and monitoring equipment. The proposed text would apply to any failure to meet an applicable standard and would require the source to record the date, time, and duration of the failure. The EPA is also proposing to add to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that sources keep records that include a list of the affected source or equipment and actions taken to minimize emissions, an estimate of the quantity of each regulated pollutant emitted

over the standard for which the source failed to meet a standard, and a description of the method used to estimate the***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 336 of 381 emissions. Examples of such methods would include product-loss calculations, mass balance calculations, measurements when available, or engineering judgment based on known process parameters. The EPA is proposing to require that sources keep records of this information to ensure that there is adequate information to allow the EPA to determine the severity of any failure to meet a standard, and to provide data that may document how the source met the general duty to minimize emissions when the source has failed to meet an applicable

standard. We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(iv) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for §63.10(b)(2)(iv)-(v) with “No” in the third column. When applicable, 40 CFR 63.10(b)(2)(iv) requires sources to record actions taken during SSM events when actions were inconsistent with their SSM plan. The requirement is no longer appropriate because SSM plans will no longer be required. The requirement previously applicable under 40 CFR 63.10(b)(2)(iv)(B) to record actions to minimize emissions and***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 337 of 381 record corrective actions is now applicable by reference to 40 CFR 63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii). We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(v) by changing the “Yes” in the second column to a “No.” Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for §63.10(b)(2)(iv)-(v) with “No” in the third column. When applicable, 40 CFR 63.10(b)(2)(v) requires sources to record actions taken during SSM events to show that actions taken were consistent with their SSM plan. The requirement is no longer appropriate because SSM plans would no longer be required. We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for §63.10(c)(9)-(15) to include separate entries for specific paragraphs of 40 CFR 63.10(c), including an entry for §63.10(c)(15) with “No” in the third column. The EPA is proposing that 40 CFR 63.10(c)(15) no longer apply. When applicable, the provision allows an owner or operator to use the affected source's SSM plan or records kept to satisfy the recordkeeping requirements of the SSM plan, specified in 40 CFR 63.6(e), to also satisfy the requirements of 40 CFR 63.10(c)(10) through (12). The EPA is proposing to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 338 of 381 eliminate this requirement because SSM plans would no longer be required, and therefore 40 CFR 63.10(c)(15) no longer serves any useful purpose for affected units. g. Reporting We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a “No” in the second column. Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a “No” in the third column. Section 63.10(d)(5) describes the reporting requirements for startups, shutdowns, and malfunctions. To replace the General Provisions reporting requirement, the EPA is proposing to add reporting requirements to 40 CFR 63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 63.1575(d), and 40 CFR 63.1575(e). The General Provisions requirement that was cross-referenced requires periodic SSM reports as a stand-alone report. In its place, we are proposing language that requires sources that fail to meet an applicable standard at any time to report the information concerning such events in the periodic report already required under each of these rules. We are proposing that the report must contain the number, date, time, duration, and the cause of such events***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 339 of 381 (including unknown cause, if applicable), a list of the affected source or equipment, an estimate of the quantity of each regulated pollutant emitted over any emission limit, and a description of the method used to estimate the emissions. Examples of methods that can be used to estimate emissions would include product-loss calculations, mass balance calculations, measurements when available, or engineering judgment based on known process parameters. The EPA is proposing this requirement to ensure that there is adequate information to determine compliance, to allow the EPA to determine the severity of the failure to meet an applicable standard, and to provide data that may document how the source met the general duty to minimize emissions during a failure to meet an applicable

standard. We will no longer require owners or operators to determine

whether actions taken to correct a malfunction are consistent with an SSM plan, because SSM plans would no longer be required. The proposed rule eliminates the cross-reference to 40 CFR 63.10(d)(5)(i) that contains the description of the previously required SSM report format and submittal schedule from this section. These specifications are no longer necessary because the events will be reported in otherwise required reports with similar format and submittal requirements.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 340 of 381 We note that reporting a failure to meet an applicable standard could include malfunction events for which a source may choose to submit documentation to support an assertion of affirmative defense. If a source provides all the material required in 40 CFR 63.642(p) or 40 CFR 63.1570(g), as applicable, to support an affirmative defense, the source need not submit the same information two times in the same report. While assertion of an affirmative defense is not mandatory and occurs only if a source chooses to take advantage of the affirmative defense, the affirmative defense also requires additional reporting that goes beyond these routine requirements related to a failure to meet an applicable standard for a reason

other than a malfunction. As noted above, we are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a “No” in the second column. Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a “No” in the third column. Section 63.10(d)(5)(ii) describes an immediate report for startups, shutdown, and malfunctions when a source fails to meet an applicable standard but does not follow the SSM plan. We are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 341 of 381 proposing to no longer require owners and operators to report when actions taken during a startup, shutdown, or malfunction were not consistent with an SSM plan, because such plans would no longer be required. 2. Electronic Reporting In this proposal, the EPA is describing a process to increase the ease and efficiency of performance test data submittal while improving data accessibility. Specifically, the EPA is proposing that owners and operators of petroleum refineries submit electronic copies of required performance testand performance evaluation reports by direct computer-tocomputer electronic transfer using EPA-provided software. The direct computer-to-computer electronic transfer is accomplished through the EPA’s Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI). TheCDX is EPA’s portal for submittal of electronic data. The EPAprovided software is called the Electronic Reporting Tool (ERT) which is used to generate electronic reports of performance tests and evaluations. The ERT generates an electronic report package which will be submitted using the CEDRI. The submitted report package will be stored in the CDX archive (the official copy of record) and the EPA’s public database called WebFIRE. All stakeholders will have access to all reports and data in WebFIRE and accessing these reports and data will be very***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 342 of 381 straightforward and easy (see the WebFIRE Report Search and

Retrieval link at http://cfpub.epa.gov/webfire/index.cfm?action=fire.searchERTSubm ission). A description and instructions for use of the ERT can be found at http://www.epa.gov/ttn/chief/ert/index.html and CEDRI can be accessed through the CDX website (www.epa.gov/cdx). A description of the WebFIRE database is available at: http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. The proposal to submit performance test data electronically to the EPA applies only to those performance tests (and/or performance evaluations) conducted using test methods that are supported by the ERT. The ERT supports most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at: http://www.epa.gov/ttn/chief/ert/index.html. We believe that industry would benefit from this proposed approach to electronic data submittal. Specifically, by using this approach, industry will save time in the performance test submittal process. Additionally, the standardized format that the ERT uses allows sources to create a more complete test report resulting in less time spent on data backfilling if a source failed to include all data elements required to be submitted. Also through this proposal industry may only need to submit a report once to meet the requirements of the applicable***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 343 of 381 subpart because stakeholders can readily access these reports from the WebFIRE database. This also benefits industry by cutting back on recordkeeping costs as the performance test reports that are submitted to the EPA using CEDRI are no longer required to be retained in hard copy, thereby reducing staff

time needed to coordinate these records. Since the EPA will already have performance test data in hand, another benefit to industry is that fewer or less substantial data collection requests in conjunction with prospective required residual risk assessments or technology

reviews will be needed. This would result in a decrease in staff time needed to respond to data collection requests. State, local and tribal air pollution control agencies (S/L/Ts) may also benefit from having electronic versions of the reports they are now receiving. For example, S/L/Ts may be able

to conduct a more streamlined and accurate review of electronic data submitted to them. For example, the ERT would allow for an electronic review process, rather than a manual data assessment, therefore, making review and evaluation of the source provided data and calculations easier and more efficient. In addition, the public stands to benefit from electronic reporting of

emissions data because the electronic data will be easier for the public to access. How the air emissions data are collected,***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 344 of 381 accessed and reviewed will be more transparent for all

stakeholders. One major advantage of the proposed submittal of performance test data through the ERT is a standardized method to compile and store much of the documentation required to be reported by this rule. The ERT clearly states what testing information would be required by the test method and has the ability to house additional data elements that might be required by a delegated authority. In addition the EPA must have performance test data to conduct effective reviews of CAA Sections 111 and 112 standards, as well as for many other purposes including compliance determinations, emission factor development and annual emission rate determinations. In conducting these required reviews, the EPA has found it ineffective and time consuming, not only for us, but also for regulatory agencies and source owners and operators, to locate, collect and submit performance test data. In recent years, 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. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 345 of 381 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. Finally, another benefit of the proposed data submittal to WebFIRE electronically is that these data would greatly improve the overall quality of existing and new emissions factors by supplementing the pool of emissions test data for establishing

emissions factors. In summary, in addition to supporting regulation development, control strategy development and other air pollution control activities, having an electronic database populated with performance test data would save industry, state, local and tribal agencies and the EPA significant time, money and effort while also improving the quality of emission inventories and air quality regulations. In addition, we are proposing that the fenceline data at each monitor location (as proposed above) would be reported electronically on a quarterly basis. All data reported electronically would be submitted to CDX through CEDRI and made available to the public.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 346 of 381 3. Technical Amendments to Refinery MACT 1 and 2 a. Open-Ended Valves and Lines Refinery MACT 1 requires an owner or operator to control emissions from equipment leaks according to the requirements of either 40 CFR part 60, subpart VV or 40 CFR part 63, subpart H. For open-ended valves and lines, both subparts require that the open end be equipped with a cap, blind flange, plug or second valve that “shall seal the open end at all times.” However, neither subpart defines “seal” or explains in practical and enforceable terms what constitutes a sealed open-ended valve or line. This has led to uncertainty on the part of the owner or operator as to whether compliance is being achieved. Inspections under the EPA’s Air Toxics LDAR initiative have provided evidence that while certain open-ended lines may be equipped with a cap, blind flange, plug or second valve, they are not operating in a “sealed” manner as the EPA interprets that term. In response to this uncertainty, we are proposing to amend 40 CFR 63.641 to add a definition of “seal.” This proposed definition clarifies that, for the purpose of complying with the requirements of 40 CFR 63.648, open-ended valves and lines are “sealed” by the cap, blind flange, plug, or second valve when there are no detectable emissions from the open-ended valve or line at or above an instrument reading of 500 ppm. We solicit comment on this approach to reducing the compliance uncertainty***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 347 of 381 associated with open-ended valves and lines and our proposed

definition of “seal.” b. General Provisions Cross-Referencing We have reviewed the application of 40 CFR part 63, subpart A (General Provisions) to Refinery MACT 2. The applicable requirements of 40 CFR part 63, subpart A are contained in Table 44 of 40 CFR part 63, subpart UUU. As a result of our review, we are proposing several amendments to Table 44 of 40 CFR part 63, subpart UUU (in addition to those discussed in Section IV.E.1 of this preamble that address SSM) to bring the table up-to-date with requirements of the General Provisions that have beenamended since this table was created, to correct crossreferences, and to incorporate additional sections of the General Provisions that are necessary to implement other subparts that are cross-referenced by this rule. Although we reviewed the application of the General Provisions to Refinery MACT 1 and amended Table 6 of 40 CFR part 63, subpart CC in 2009, we are proposing a few additional technical corrections to this table (in addition to those discussed in Section IV.E.1 of this preamble that address SSM). We are not discussing the details of these proposed technical corrections in this preamble but the rationale for each change to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40 CFR part 63, subpart UUU (including the proposed amendments to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 348 of 381 address SSM discussed above), is included in Docket ID Number EPA-HQ-OAR-2010-0682. 4. Amendments to Refinery NSPS J and Ja As discussed in Section II.B.2 of this preamble, we are addressing a number of technical corrections and clarifications for Refinery NSPS J and Ja to address some of the issues raised in the petition for reconsideration and to improve consistency and clarity of the rule requirements. These issues are addressed in detail in API’s amended petition, dated August 21, 2008 (see Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting minutes for a September 11, 2008 meeting between EPA and API (see Docket Item Number EPA-HQ-OAR-2007-0011-0266). a. The Depressurization Work Practice Standard for Delayed Coking Units HOVENSA and the Industry Petitioners raised several issues with the analysis conducted to support the DCU work practice standard in Refinery NSPS Ja. With the promulgation and implementation of the standards we are proposing for the DCU under Refinery MACT 1, the DCU work practice standards in Refinery NSPS Ja are not expected to result in any further decreases in emissions from the DCU. Any DCU that becomes subject to Refinery NSPS Ja would already be in compliance with Refinery MACT 1, which is a more stringent standard than the DCU work practice standards in Refinery NSPS Ja. As such, we are***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 349 of 381 contemplating various ideas for harmonizing the requirements for the DCU in these two regulations. One option is to amend Refinery NSPS Ja to incorporate the same requirements being proposed for Refinery MACT 1 (the DCU work practice standard in Refinery NSPS Ja is less stringent than the proposed requirements for Refinery MACT 1). Another option we are contemplating is deleting the DCU work practice standard within Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are promulgated and fully implemented. We believe deletion of this work practice standard is consistent with the objectives of Executive Order 13563, “Improving Regulation and Regulatory Review.” We solicit comment on these options as well as any other comments regarding the interaction between the DCU requirements in these two rules (i.e., the need to keep the DCU work practice standard in Refinery NSPS Ja after promulgation of these revisions to Refinery MACT 1.)

b. Technical Corrections and Clarifications In addition to their primary issues, the Industry Petitioners enumerated several points of clarification and recommended amendments to Refinery NSPS J and Ja. These issues are addressed in detail in API’s amended petition for reconsideration, dated August 21, 2008 (see Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting minutes for a September 11, 2008 meeting between EPA and API (see Docket Item***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 350 of 381 Number EPA-HQ-OAR-2007-0011-0266). We are including several proposed amendments in this rulemaking to specifically address

these issues. These amendments are discussed in the remainder of this section. We are addressing these issues now while we are proposing amendments for Refinery MACT 2 in an effort to improve consistency and clarity for sources regulated under both the NSPS and Refinery MACT 2. We are proposing a series of amendments to the requirements for sulfur recovery plants in 40 CFR 60.102a, to clarify the applicable emission limits for different types of sulfur recovery plants based on whether oxygen enrichment is used. These amendments also clarify that emissions averaging across a group of emission points within a given sulfur recovery plant is allowed from each of the different types of sulfur recovery plants, and that emissions averaging is specific to the SO 2 or reduced sulfur standards (and not to the H 2 S limit). The 10 ppmv

H 2 S limit for reduction control systems not followed by incineration must be met on a release point-specific basis. These amendments are being made to clarify the original intent of the Refinery NSPS Ja requirements for sulfur recovery plants. We are proposing a series of corresponding amendments in 40 CFR 60.106a to clarify the monitoring requirements, particularly when oxygen enrichment or emissions averaging is used. The monitoring requirements in Refinery NSPS Ja were incomplete for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 351 of 381 these provisions and did not specify all of the types of monitoring devices needed for implementation. We are also proposing in 40 CFR 60.106a to use the term “reduced sulfur compounds” when referring to the emission limits and monitoring devices needed to comply with the reduced sulfur compound emission limits for sulfur recovery plants with reduction control systems not followed by incineration. The term “reduced sulfur compounds” is a defined term in Refinery NSPS Ja, and the emissions limit for sulfur recovery plants with reduction control systems not followed by incineration is specific to “reduced sulfur compounds.” Therefore, the proposed amendments to the monitoring provisions provide clarification of the requirements by using a consistent, defined term. We are proposing amendments to 40 CFR 60.102a(g)(1) to clarify that CO boilers, while part of the FCCU affected facility, can also be fuel gas combustion devices (FGCD). Industry Petitioners suggested that the CO boiler should only be subject to the FCCU NO X and SO 2 limits and should not be considered a FGCD. While Refinery NSPS Ja clearly states that the coke burn-off exhaust from the FCCU catalyst regenerator is not considered to be fuel gas, other fuels combusted in the CO

boiler must meet the H 2 S concentration requirements for fuel gas like any other FGCD. This amendment is provided to clarify our original intent with respect to fuel gas. Industry Petitioners***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 352 of 381 also noted that some CO boiler “furnaces” may be used as process heaters rather than steam-generating boilers. While we did not originally contemplate that CO furnaces would be used as process heaters, available data from the detailed ICR suggests that there are a few CO furnaces used as process heaters. These CO furnaces are all forced-draft process heaters, and the newly

amended NO X emissions limit in Refinery NSPS Ja for forced-draft process heaters is 60 ppmv, averaged over a 30-day period. Given the longer averaging time of the process heater NO X limits, these two emission limits (for FCCU NO X and for process heater NO X ) are reasonably comparable and are not expected to result in a significant difference in the control systems selected for compliance. As such, we are not amending or clarifying the NO X standards for the FCCU or process heaters at this time. We are, however, clarifying (through this response) that if an emission source meets the definition of more than one affected facility, that source would need to comply with all requirements applicable to the emissions source. We are proposing to revise the annual testing requirement from “conduct a PM performance test at least once every 12 months” to “conduct a PM performance test annually (i.e., once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests)” in 40 CFR 60.104a(b) to clarify our original intent. This provision will ensure that***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 353 of 381 testing is conducted at a reasonable interval while giving owners and operators flexibility in scheduling the testing. We are also proposing to amend 40 CFR 60.104a(f) to clarify that the provisions of that paragraph are specific to owners or operators of an FCCU or FCU that use a cyclone to comply with “the PM per coke burn-off emissions limit” (rather than just the “PM limit”) in 40 CFR 60.102a(b)(1), to clarify that facilities electing to comply with the concentration limit using a PM CEMS would not also be required to install a COMS. We are also proposing to amend 40 CFR 60.104a(j) to delete the requirements

to measure flow for the H 2 S concentration limit for fuel gas, as these are not needed in the performance evaluation. We are proposing amendments to 40 CFR 60.105a(b)(1)(ii)(A) to require corrective action be completed to repair faulty (leaking or plugged) air or water lines within 12 hours of identification of an abnormal pressure reading during the daily checks. We are also proposing amendments to 40 CFR 60.105a(i) to include periods when abnormal pressure readings for a jet ejector-type wet scrubber (or other type of wet scrubber equipped with atomizing spray nozzles) are not corrected within 12 hours of identification, and periods when a bag leak detection system alarm (for a fabric filter) is not alleviated within the time period specified in the rule. These proposed***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 354 of 381 amendments are necessary so that periods when the APCD operation is compromised are properly managed and/or reported. We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and 60.107a(b)(1)(iv) to allow “using tubes with a maximum span between 10 and 40 ppmv, inclusive, when 1 ≤ N ≤ 10, where N = number of pump strokes” rather than “with ranges 0–10/0–100 ppm (N = 10/1)” because different length-of-stain tube manufacturers have different span ranges, and none of the commercially-available tubes have a specific span of 0–10/0–100 ppm (N = 10/1). We are also proposing to amend 40 CFR 60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify that the temporary daily stain sampling must be made “using length-of stain tubes with a maximum span between 200 and 400 ppmv, inclusive, when 1 ≤ N ≤ 5, where N = number of pump strokes.” This proposed amendment clarifies this monitoring requirement, ensures the proper tube range is used, and provides some flexibility in span range to accommodate different manufacturers of the length-of-stain tubes. We also propose to delete the last sentence in 40 CFR 60.105(b)(3)(iii), as there is no long-term H 2 S concentration limit in Refinery NSPS J. We are proposing to clarify that flares are subject to the performance test requirements. We are also proposing to clarify those performance test requirements in 40 CFR 60.107a(e)(1)(ii) and 40 CFR 60.107a(e)(2)(ii) to remove the distinction between***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 355 of 381 flares with or without routine flow. The term “routine flow” is

not defined and it is difficult to make this distinction in practice. F. What compliance dates are we proposing? Amendments to Refinery MACT 1 and 2 proposed in this rulemaking for adoption under CAA Section 112(d)(2) and (3) and CAA Section 112(d)(6) are subject to the compliance deadlines outlined in the CAA under Section 112(i). For all of the requirements we are proposing under CAA Section 112(d)(2) and (3) or CAA Section 112(d)(6) except for storage vessels, which we are also requiring under 112 (f)(2), we are proposing the following compliance dates. As provided in CAA Section 112(i), new sources would be required to comply with these requirements by the effective date of the final amendments to Refinery MACT 1 and 2 or startup, whichever is later. For existing sources, CAA Section 112(i) provides that the compliance date shall be as expeditiously as practicable, but no later than 3 years after the effective date of the standard. In determining what compliance period is as expeditious as practicable, we consider the amount of time needed to plan and construct projects and change operating procedures. Under CAA Section 112(d)(2) and (3), we are proposing new operating requirements for DCU. In order to comply with these new requirements, we project that most DCU owners or operators would***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 356 of 381 need to install additional controls (e.g., steam ejector systems). Similarly, the proposed revision in the CRU pressure limit exclusions would require operational changes and, in some cases, additional controls. The addition of new control equipment would require engineering design, solicitation and review of vendor quotes, contracting and installation of the equipment, which would need to be timed with process unit outage and operator training. Therefore, we are proposing that it is necessary to provide 3 years after the effective date of the final rule for these sources to comply with the DCU and CRU requirements. We are proposing new operating and monitoring requirements for flares under CAA Section 112(d)(2) and (3). We anticipate that these requirements would require the installation of new flare monitoring equipment and we project most refineries would install new control systems to monitor and adjust assist gas (air or steam) addition rates. Similar to the addition of new control equipment, these new monitoring requirements for flares would require engineering evaluations, solicitation and review of vendor quotes, contracting and installation of the equipment, and operator training. Installation of new monitoring and control equipment on flares will require the flare to be taken out of service. Depending on the configuration of the flares and flare header system, taking the flare out of service may also***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 357 of 381 require a significant portion of the refinery operations to be shut down. Therefore, we are proposing that it is necessary to provide 3 years after the effective date of the final rule for owners or operators to comply with the new operating and monitoring requirements for flares. Under CAA Section 112(d)(2) and (3), we are proposing new vent control requirements for bypasses. These requirements would typically require the addition of piping and potentially new control requirements. As these vent controls would most likely be routed to the flare, we are proposing to provide 3 years

after the effective date of the final rule for owners or operators to afford coordination of these bypass modifications with the installation of the new monitoring equipment for the

flares. Under our technology review, we are proposing to require fenceline monitoring pursuant to CAA Section 112(d)(6). These proposed provisions would require refinery owners or operators to install a number of monitoring stations around the facility fenceline. While the diffusive tube sampling system is relatively low-tech and is easy to install, site-specific factors must be considered in the placement of the monitoring systems. We also assume all refinery owners or operators would invest in the analytical equipment needed to perform automated sample analysis on-site and time is needed to select an***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 358 of 381 appropriate vendor for this equipment. Furthermore, additional monitoring systems may be needed to account for near-field contributing sources, for which the development and approval of a site-specific monitoring plan. Considering all of the requirements needed to implement the fenceline monitoring system, we are proposing to provide 3 years from the effective date of the final rule for refinery owners or operators to install and begin collecting ambient air samples around the fenceline of their facility following an approved (if necessary) site-specific monitoring plan. As a result of our technology review for equipment leaks, we are proposing to allow the use of optical gas imaging devices in lieu of using EPA Method 21 of 40 CFR part 60, Appendix A-7 without the annual compliance demonstration with EPA Method 21 as required in the AWP (see 73 FR 73202, December 22, 2008), provided that the owner and operator follows the provisions of Appendix K to 40 CFR part 60. The provision to allow the use of optical gas imaging devices without the annual compliance demonstration using EPA Method 21 is predicated on the use of fenceline monitoring to ensure that leaking equipment are effectively identified. Facilities could begin to comply with the optical gas imaging alternative as soon as Appendix K to 40 CFR part 60 is promulgated. Alternatively, as is currently provided in the AWP, the refinery owner or operator can elect to***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 359 of 381 use the optical gas imaging monitoring option prior to installation and use of the fenceline monitoring system, provided they conduct an annual compliance demonstration using EPA Method 21 as required in the AWP. Under our technology review for marine vessel loading operations, we are proposing to add a requirement for submerged filling for small and for offshore marine vessel loading operations. We anticipate that the submerged fill pipes are already in place on all marine vessels used to transport petroleum refinery liquids, so we are proposing that existing sources comply with this requirement on the effective date of the final rule. We request comment regarding the need to provide additional time to comply with the submerged filling requirement; please provide in your comment a description of the vessels loaded that do not already have a submerged fill pipe, how these vessels comply with (or are exempt from) the Coast Guard requirements at 46 CFR 153.282, and an estimate of the time needed to add the required submerged fill pipes to these

vessels. We are also proposing to require FCCU owners and operators currently subject to Refinery NSPS J (or electing that compliance option in Refinery MACT 2) to transition from the Refinery NSPS J option to one of the alternatives included in the proposed rule. We are also proposing altering the averaging***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 360 of 381 times for some of the operating limits. A PM performance test is needed in order to establish these new operating limits prior to transitioning to the proposed requirements. Additionally, we are proposing that a PM performance test be conducted for each FCCU once every 5 years. We do not project any new control or monitoring equipment will be needed in order to comply with the proposed provisions; however, compliance with the proposed provisions is dependent on conducting a performance test. Establishing an early compliance date for the first performance test can cause scheduling issues as refinery owners or operators compete for limited number of testing contractors. Considering these scheduling issues, we propose to require the first performance test for PM and compliance with the new operating limits be completed no later than 18 months after the effective

date of the final rule. In this action, we are proposing revisions to the SSM provisions of Refinery MACT 1 and 2, including specific startup or shutdown standards for certain emission sources, and we are proposing electronic reporting requirements in Refinery MACT 1 and 2. The proposed monitoring requirements associated with the new startup and shutdown standards are expected to be present on the affected source, so we do not expect that owners or operators will need additional time to transition to these requirements. Similarly, the electronic reporting requirements***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 361 of 381 are not expected to require a significant change in operation or equipment, so these requirements should be able to be implemented more quickly than those that require installation of new control or monitoring equipment. Based on our review of these requirements, we propose that these requirements become effective upon the effective date of the final rule. Finally, we are proposing additional requirements for storage vessels under CAA Sections 112(d)(6) and (f)(2). The compliance deadlines for standards developed under CAA Section 112(f)(2) are delineated in CAA Sections 112(f)(3) and (4). As provided in CAA Section 112(f)(4), risk standards shall not apply to existing sources until 90 days after the effective date of the rule, but the Administrator may grant a waiver for a particular source for a period of up to 2 years after the effective date. While additional controls will be necessary to comply with the proposed new control and fitting requirements for storage vessels, timing of these controls are specified within the Generic MACT (40 CFR part 63, subpart WW). Therefore, we propose that these new requirements for storage vessels become effective 90 days following the effective date of the

final rule.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 362 of 381 **V. Summary of Cost, Environmental and Economic Impacts** A. What are the affected sources, the air quality impacts and cost impacts? The sources affected by significant amendments to the petroleum refinery standards include storage vessels, equipment leaks, fugitive emissions and DCU subject to Refinery MACT 1. The proposed amendments for other sources subject to one or more of the petroleum refinery standards are expected to have minimal air quality and cost impacts. The total capital investment cost of the proposed amendments and standards is estimated at $239 million, $82.8 million from proposed amendments and $156 million from standards to ensure compliance. We estimate annualized costs to be approximately $4.53 million, which includes an estimated $14.4 million credit for recovery of lost product and the annualized cost of capital. We also estimate annualized costs of the proposed standards to ensure compliance to be approximately $37.9 million. The proposed amendments would achieve a nationwide HAP emission reduction of 1,760 tpy, with a concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of this preamble summarizes the cost and emission reduction impacts of the proposed amendments, and Table 14 of this preamble summarizes the costs of the proposed standards to ensure compliance.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 363 of 381 **Table 13. Nationwide Impacts of Proposed Amendments**

**Affected**

**source Total**  **capital invest** 

**ment (million**  **$) Total** **annual**

**ized cost**  **without credit**  **(million**

**$/yr) Product**  **recov e**  **ry**

**credit (mil**  **l ion** 

**$/yr) Total** **annual**

**ized costs**  **(mil l**  **ion**

**$/ yr) VOC** **emis sion** **reduc tions**  **(tpy) Cost** **effec tiveness** 

**($/ton**

**VOC) HAP** **emis sion** **reduc tions**  **(tpy) Cost** **effec tiveness** 

**($/ton**

**HAP) Storage**  **Vessels** 18.5 3.13 (8.16) (5.03) 14,600 (345) 910 (5,530) **Delayed Coking**  **Units** 52.0 10.2 (6.20) 3.98 4,250 937 850 4,680 **Fugitive Emissions**  **(Fenceline Monitoring)**  12.2 5.58 -- 5.58 **Total** 82.8 18.9 (14.4) 4.53 18,800 241 1,760 2,570

**Table 14. Nationwide Costs of Proposed Amendments to Ensure Compliance** 

**Affected source** Total capital investment (million $) Total annualized cost without credit (million $/yr) Product recovery

credit (million

$/yr) Total annualized costs (million $/ yr) **Relief Valve**

**Monitoring** 9.54 1.36 -- 1.36 **Flare Monitoring** 147 36.3 -- 36.3 **FCCU Testing** -- 0.21 -- 0.21 **Total** 156 37.9 -- 37.9

Note that any corrective actions taken in response to the fenceline monitoring program are not included in the impacts shown in Table 13. Any corrective actions associated with fenceline monitoring will result in additional emission

reductions and additional costs. The impacts shown in Table 14 do not consider emission reductions associated with relief valve or flare monitoring***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 364 of 381 provisions or emission reductions that may occur as a result of the additional FCCU testing requirements. The proposed operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric tonnes per year of carbon dioxide equivalents (CO 2 e). B. What are the economic impacts? We performed a national economic impact analysis for petroleum product producers. All petroleum product refiners will incur annual compliance costs of much less than 1 percent of their sales. For all firms, the minimum cost-to-sales ratio is <0.01 percent; the maximum cost-to-sales ratio is 0.87 percent; and the mean cost-to-sales ratio is 0.03 percent. Therefore, the overall economic impact of this proposed rule should be minimal for the refining industry and its consumers. In addition, the EPA performed a screening analysis for impacts on small businesses by comparing estimated annualized engineering compliance costs at the firm-level to firm sales. The screening analysis found that the ratio of compliance cost to firm revenue falls below 1 percent for the 28 small companies likely to be affected by the proposal. For small firms, theminimum cost-to-sales ratio is <0.01 percent; the maximum costto-sales ratio is 0.62 percent; and the mean cost-to-sales ratio is 0.07 percent.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 365 of 381 More information and details of this analysis are provided in the technical document Economic Impact Analysis for Petroleum Refineries Proposed Amendments to the National Emissions Standards for Hazardous Air Pollutants, which is available inthe docket for this proposed rule (Docket ID Number EPA-HQ-OAR2010-0682).

C. What are the benefits? The proposed rule is anticipated to result in a reduction of 1,760 tons of HAP (based on allowable emissions under the MACT standards) and 18,800 tons of VOC emissions per year, not including potential emission reductions that may occur as a result of the proposed provisions for flares or fenceline monitoring. These avoided emissions will result in improvements in air quality and reduced negative health effects associated with exposure to air pollution of these emissions; however, we have not quantified or monetized the benefits of reducing these emissions for this rulemaking. **VI. Request for Comments** We solicit comments on all aspects of this proposed action. In addition to general comments on this proposed action, we are also interested in additional data that may improve the risk assessments and other analyses. We are specifically interestedin receiving any improvements to the data used in the sitespecific emissions profiles used for risk modeling. Such data***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 366 of 381 should include supporting documentation in sufficient detail to allow characterization of the quality and representativeness of the data or information. Section VII of this preamble provides more information on submitting data. **VII. Submitting Data Corrections** The site-specific emissions profiles used in the source category risk and demographic analyses and instructions are available on the RTR web page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. The data files

include detailed information for each HAP emissions release point for the facilities in the source categories. If you believe that the data are not representative or are inaccurate, please identify the data in question, provide your reason for concern and provide any “improved” data that you have, if available. When you submit data, we request that you provide documentation of the basis for the revised values to support your suggested changes. To submit comments on the data downloaded from the RTR page, complete the following steps: 1. Within this downloaded file, enter suggested revisions to the data fields appropriate for that information.

2. Fill in the commenter information fields for each suggested revision (i.e., commenter name, commenter organization, commenter email address, commenter phone number and revision comments).***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 367 of 381 3. Gather documentation for any suggested emissions revisions (e.g., performance test reports, material balance calculations). 4. Send the entire downloaded file with suggested revisions in Microsoft® Access format and all accompanying documentation to Docket ID Number EPA-HQ-OAR-2010-0682 (through

one of the methods described in the ADDRESSES Section of this preamble). 5. If you are providing comments on a single facility or multiple facilities, you need only submit one file for all facilities. The file should contain all suggested changes for all sources at that facility. We request that all data revision comments be submitted in the form of updated Microsoft® Excel files that are generated by the Microsoft® Access file. These files are provided on the RTR web Page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. **VIII. Statutory and Executive Order Reviews** A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory

Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a “significant regulatory action” because it raises novel legal and policy issues. Accordingly, the EPA submitted this action to the Office of Management and Budget***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 368 of 381 (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 (Docket ID Number EPA-HQ-OAR-2010-0682). B. Paperwork Reduction Act The information collection requirements in this rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq.

Revisions and burden associated with amendments to 40 CFR part 63, subparts CC and UUU are discussed in the following paragraphs. OMB has previously approved the information collection requirements contained in the existing regulations in 40 CFR part 63, subparts CC and UUU under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq., OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b). The ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has been assigned the EPA ICR number 1692.08. Burden changes associated with these amendments would result from new monitoring, recordkeeping and reporting requirements. The estimated average burden per response is 1.3 hours (this is the total reporting hours in the second year, technical, managerial, and clerical divided by the total responses in the second year);***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 369 of 381 the frequency of response is semiannual for all reports for all respondents that must comply with the rule’s reporting requirements; and the estimated average number of likely respondents per year is 95 (this is the average in the second year). The cost burden to respondents resulting from the collection of information includes the total capital cost annualized over the equipment’s expected useful life (about $17 million), a total operation and maintenance component (about $16 million per year – this is the average in the second year), and a labor cost component (about $4.5 million per year – this is the average in the second year). 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 ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has been assigned the EPA ICR number 1844.05. Burden changes associated with these amendments would result from new testing, recordkeeping and reporting requirements being proposed with this action. The estimated average burden per response is 26 hours; the frequency of response is both once and every 5 years for respondents that have FCCU, and the estimated average number of likely respondents per year is 67. The cost burden to respondents resulting from the collection of information***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 370 of 381 includes the performance testing costs (approximately $356,000 per year over the first 3 years for the initial performance test and $213,000 per year starting in the fourth year), and a labor cost component (approximately $238,000 per year). An agency may not conduct or sponsor (and a person is not required to respondto) a collection of information unless it displays a currentlyvalid OMB control number. 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, the EPA has established a public docket for this rule, which includes the ICR, under Docket ID Number EPA-HQ-OAR-2010-0682. Submit any

comments related to the ICR to the EPA and OMB. See the

**ADDRESSES** Section at the beginning of this preamble for where to

submit comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503, Attention: Desk Office for the 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 DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The final rule will respond to any OMB or public***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 371 of 381 comments on the information collection requirements contained in this proposal. 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 (SISNOSE). Small entities include small businesses, small organizations and small governmental jurisdictions. For purposes of assessing the impacts of this proposed rule on small entities, a small entity is defined as: (1) a small business in the petroleum refining industry having 1,500 or fewer employees (Small Business Administration (SBA), 2011); (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. After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The small entities subject to the requirements of this***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 372 of 381 proposed rule are small refiners. We have determined that 36 companies (59 percent of the 61 total) employ fewer than 1,500

workers and are considered to be small businesses. For small businesses, the average cost-to-sales ratio is about 0.05 percent, the median cost-to-sales ratio is 0.02 percent and the maximum cost-to-sales ratio is 0.55 percent. The potential costs do not have a more significant impact on small refiners and because no small firms are expected to have cost-to-sales ratios greater than 1 percent, we determined that the cost impacts for this rulemaking will not have a SISNOSE. Although not required by the RFA to convene a Small Business Advocacy Review (SBAR) Panel; because the EPA has determined that this proposal would not have a significant economic impact on a substantial number of small entities, the EPA originally convened a panel to obtain advice and recommendations from small entity representatives potentially subject to this rule’s requirements. The panel was not formally concluded; however, a summary of the outreach conducted and the written comments submitted by the small entity representatives can be found in the docket for this proposed rule (Docket ID Number EPA-HQ-OAR-2010-0682). We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 373 of 381

D. Unfunded Mandates Reform Act This proposed rule does not contain a federal mandate under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538 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. As discussed earlier in this preamble, these amendments result in nationwide costs of $42.4 million per year for the private sector. Thus, this proposed rule is not subject to the requirements of Sections 202 or 205 of the UMRA. This proposed rule is also not subject to the requirements of Section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments because it contains no requirements that apply to such governments and does not impose obligations upon them.

E. Executive Order 13132: Federalism This rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. None of the facilities subject to this action are owned or operated by state governments, and, because no new requirements are being promulgated, nothing in this proposal***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 374 of 381 will supersede state regulations. Thus, Executive Order 13132 does not apply to this rule. In the spirit of Executive Order 13132, and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed rule from state 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 this action. Although Executive Order 13175 does not apply to this action, the EPA consulted with tribal officials in developing

this action. The EPA sent out letters to tribes nationwide to invite them to participate in a tribal consultation meeting and solicit their input on this rulemaking. The EPA conducted the tribal consultation meeting on December 14, 2011. Participants from eight tribes attended the meeting, but they were interested only in outreach, and none of the tribes had delegation for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 375 of 381 consultation. The EPA presented all the information prepared for the consultation and conducted a question and answer session where participants asked clarifying questions about the information that was presented and generally expressed their support of the rulemaking requirements. 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 This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is not economically significant as defined in Executive Order 12866, and because the agency does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to

children. This action’s health and risk assessments are

contained in Sections III.A and B and Sections IV.C and D of this preamble.The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life exposure to emissions from petroleum refineries. 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 under Executive Order 13211 (66 FR 28355, May 22, 2001), because***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 376 of 381 it is not likely to have significant adverse effect on the supply, distribution or use of energy. The overall economic impact of this proposed rule should be minimal for the refining industry and its consumers. 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, 12(d) (15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the agency decides not to use available and applicable VCS. This proposed rulemaking involves technical standards. The EPA proposes to use ISO 16017-2, “Air quality Sampling and analysis of volatile organic compounds in ambient air, indoor air and workplace air by sorbent tube/thermal desorption/capillary gas chromatography Part 2: Diffusive sampling” as an acceptable alternative to EPA Method 325A. This method is available at http://www.iso.org. This method was chosen because it meets the requirements of EPA Method 301 for***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 377 of 381 equivalency, documentation and validation data for diffusive tube sampling. The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS 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 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. The EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it maintains or increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 378 of 381 environmental effects on any population, including any minority, low-income or indigenous populations. Further, the EPA believes that implementation of the provisions of this rule will provide an ample margin of safety to protect the public health of all demographic groups. To examine the potential for any environmental justice issues that might be associated with the refinery source categories associated with today’s proposed rule, we evaluated the percentages of various social, demographic and economic groups within the at-risk populations living near the facilities where these source categories are located and compared them to national averages. Our analysis of the demographics of the population with estimated risks greater than 1-in-1 million indicates potential disparities in risks between demographic groups, including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma groups. In addition, the population living within 50 km of the 142 petroleum refineries has a higher percentage of minority, lower income and lower education persons when compared to the nationwide percentages of those groups. These groups

stand to benefit the most from the emission reductions achieved by this proposed rulemaking, and this proposed rulemaking is projected to result in 1 million fewer people exposed to risks greater than 1-in-1 million.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** Page 379 of 381 The EPA defines “Environmental Justice” to include meaningful involvement of all people regardless of race, color, national origin or income with respect to the development, implementation and enforcement of environmental laws, regulations and policies. To promote meaningful involvement, the EPA conducted numerous outreach activities and discussions, including targeted outreach (such as conference calls and webinars) to communities and environmental justice organizations. In addition, after the rule is proposed, the EPA will be conducting a webinar to inform the public about the proposed rule and to outline how to submit written comments to the docket. Further stakeholder and public input is expected through public comment and follow-up meetings with interested

stakeholders.***E.O. 12866 Review-Draft-Do Not Cite, Quote or Release During Review*** **Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards**  **Page 380 of 381 List of Subjects in 40 CFR Part 63**  Environmental protection, Air pollution control, Hazardous substances, Incorporation by reference, Reporting and recordkeeping requirements, Volatile organic compounds.

____________________________ Dated:

____________________________ Gina McCarthy, Administrator.Page 381 of 381