60696 Federal Register / Vol. 83, No. 227 / Monday, November 26, 2018 / Rules and Regulations 
ENVIRONMENTAL PROTECTION 
AGENCY 
40 CFR Parts 60 and 63 
[EPA–HQ–OAR–2010–0682; FRL–9986–68– 
OAR] 
RIN 2060–AT50 
National Emission Standards for 
Hazardous Air Pollutants and New Source Performance Standards: Petroleum Refinery Sector Amendments 
AGENCY : Environmental Protection 
Agency (EPA). 
ACTION : Final rule. 
SUMMARY : This action finalizes 
amendments to the petroleum refinery National Emission Standards for Hazardous Air Pollutants (NESHAP) (referred to as Refinery MACT 1 and Refinery MACT 2) and to the New Source Performance Standards (NSPS) for Petroleum Refineries to clarify the requirements of these rules and to make technical corrections and minor revisions to requirements for work practice standards, recordkeeping, and reporting which were proposed in the Federal Register on April 10, 2018. This action also finalizes amendments to the compliance date of the requirements for existing maintenance vents from August 1, 2017, to December 26, 2018, which were proposed in the Federal Register on July 10, 2018. 
DATES : This final rule is effective on 
November 26, 2018. The incorporation by reference of certain publications listed in the rule was approved by the Director of the Federal Register as of June 24, 2008. 
ADDRESSES : The Environmental 
Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA–HQ–OAR–2010–0682. All documents in the docket are listed on the https://www.regulations.gov 
website. Although listed, some information is not publicly available, e.g., confidential business information 
(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 form. Publicly available docket materials are available either electronically through https://www.regulations.gov, or in hard 
copy at the EPA Docket Center, EPA WJC West Building, Room Number 3334, 1301 Constitution Ave. NW, Washington, DC. The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m. Eastern Standard Time (EST), Monday through Friday. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the Docket Center is (202) 566–1742. 
FOR FURTHER INFORMATION CONTACT : For 
questions about this final action, contact Ms. Brenda Shine, Sector Policies and Programs Division (E143–01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541– 3608; fax number: (919) 541–0516; and email address: shine.brenda@epa.gov. For information about the applicability of the NESHAP to a particular entity, contact Ms. Maria Malave, Office of Enforcement and Compliance Assurance, U.S. Environmental Protection Agency, EPA WJC South Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460; telephone number: (202) 564–7027; 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. 
AFPM American Fuel and Petrochemical 
Manufacturers 
API American Petroleum Institute 
AWP Alternative Work Practice CAA Clean Air Act CBI confidential business information CFR Code of Federal Regulations 
CEDRI Compliance and Emissions Data 
Reporting Interface 
CDX Central Data Exchange CRA Congressional Review Act CRU catalytic reforming unit DCU delayed coking unit EPA Environmental Protection Agency FCCU fluid catalytic cracking unit FR Federal Register HAP hazardous air pollutant(s) lbs pounds LEL lower explosive limit MACT maximum achievable control 
technology 
MPV miscellaneous process vent NAAQS National Ambient Air Quality 
Standards 
NESHAP National Emission Standards for 
Hazardous Air Pollutants 
NOCS Notice of Compliance Status NSPS New Source Performance Standard NTTAA National Technology Transfer and 
Advancement Act 
OEL open-ended line OSHA Occupational Safety and Health 
Administration 
PM particulate matter ppb parts per billion ppm parts per million PRA Paperwork Reduction Act PRD pressure relief device psi pounds per square inch psia pounds per square inch absolute 
RFA Regulatory Flexibility Act RIN Regulatory Information Number RSR Refinery Sector Rule SMR steam-methane reforming TTN Technology Transfer Network UMRA Unfunded Mandates Reform Act VOC volatile organic compounds 
Background information. On April 10, 
2018, and July 10, 2018, the EPA 
proposed revisions to the Petroleum Refineries NESHAP and NSPS, (April 2018 Proposal and July 2018 Proposal), respectively (83 FR 15458, April 10, 2018; 83 FR 31939, July 10, 2018). After consideration of the public comments we received on these proposed rules, in this action, we are finalizing revisions to the NESHAP and NSPS rules. We summarize the significant comments we received regarding the April 2018 Proposal and the July 2018 Proposal and provide our responses in this preamble. In addition, a Response to Comments document, which is in the docket for this rulemaking, summarizes and responds to additional comments which were received regarding the April 2018 Proposal. A ‘‘track changes’’ version of the regulatory language that incorporates the changes in this action is also available in the docket. 
Organization of this document. The 
information in this preamble is organized as follows: 
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. Judicial Review and Administrative 
Reconsideration 
II. Background III. What is included in this final rule? 
A. Clarifications and Technical Corrections 
to Refinery MACT 1 
B. Clarifications and Technical Corrections 
to Refinery MACT 2 
C. Clarifications and Technical Corrections 
to NSPS Ja 
IV. Summary of Cost, Environmental, and 
Economic Impacts and Additional Analyses Conducted 
V. Statutory and Executive Order Reviews 
A. Executive Orders 12866: Regulatory 
Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review 
B. Executive Order 13771: Reducing 
Regulations and Controlling Regulatory Costs 
C. Paperwork Reduction Act (PRA) D. Regulatory Flexibility Act (RFA) E. Unfunded Mandates Reform Act 
(UMRA) 
F. Executive Order 13132: Federalism G. Executive Order 13175: Consultation 
and Coordination With Indian Tribal 
Governments 
H. Executive Order 13045: Protection of 
Children From Environmental Health Risks and Safety Risks 
I. Executive Order 13211: Actions 
Concerning Regulations That 
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Significantly Affect Energy Supply, 
Distribution, or Use 
J. National Technology Transfer and 
Advancement Act (NTTAA) and 1 CFR part 51 
K. Executive Order 12898: Federal Actions 
To Address Environmental Justice in Minority Populations and Low-Income Populations 
L. Congressional Review Act (CRA) 
I. General Information 
A. Does this action apply to me? 
Regulated entities. Categories and 
entities potentially regulated by this 
action are shown in Table 1 of this preamble. 
TABLE 1—NESHAP ANDINDUSTRIAL  
SOURCE CATEGORIES AFFECTED BY  
THISFINAL ACTION  
NESHAP and source category NAICS1 
code 
40 CFR part 63, subpart CC Pe-
troleum Refineries ..................... 324110 
1North American Industry Classification 
System. 
Table 1 of this preamble is not 
intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by the final action for the source category listed. To determine whether your facility is affected, you should examine the applicability criteria in the appropriate NESHAP. If you have any questions regarding the applicability of any aspect of this NESHAP, please contact the appropriate person listed in the preceding 
FOR FURTHER INFORMATION  
CONTACT section of this preamble. 
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 final action will also be available on the internet. Following signature by the EPA Administrator, the EPA will post a copy of this final action at: https://www.epa.gov/stationary-sources-air- pollution/petroleum-refinery-sector-risk- and-technology-review-and-new-source. Following publication in the Federal Register, the EPA will post the Federal 
Register version and key technical 
documents at this same website. 
C. Judicial Review and Administrative 
Reconsideration 
Under Clean Air Act (CAA) section 
307(b)(1), judicial review of this final action is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by January 25, 2019. Under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the requirements. 
Section 307(d)(7)(B) of the CAA 
further provides that only an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review. This section also provides a mechanism for the EPA to reconsider the rule if the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within the period for public comment or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule. Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, EPA WJC South Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with a copy to both the person(s) listed in the preceding 
FOR FURTHER INFORMATION  
CONTACT section, and the Associate 
General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW, Washington, DC 20460. 
II. Background 
On December 1, 2015, the EPA 
finalized amendments to the Petroleum 
Refinery NESHAP in 40 Code of Federal Regulations (CFR) part 63, subparts CC and UUU, referred to as Refinery MACT 1 and 2, respectively, and the NSPS for petroleum refineries in 40 CFR part 60, subparts J and Ja (80 FR 75178) (December 2015 Rule). The final 
amendments to Refinery MACT 1 include a number of new requirements for ‘‘maintenance vents,’’ pressure relief devices (PRDs), delayed coking units (DCUs), and flares, and also establishes a fenceline monitoring requirement. 
The December 2015 Rule included 
revisions to the continuous compliance alternatives for catalytic cracking units and provisions specific to startup and shutdown of catalytic cracking units and sulfur recovery plants. The December 2015 Rule also finalized technical corrections and clarifications to Refinery NSPS subparts J and Ja to address issues raised by the American Petroleum Institute (API) in their 2008 and 2012 petitions for reconsideration of the final NSPS Ja rule that had not been previously addressed. These include corrections and clarifications to 
provisions for sulfur recovery plants, performance testing, and control device operating parameters. 
In the process of implementing these 
new requirements, numerous questions and issues have been identified and we proposed clarifications and technical amendments to address these questions and issues on April 10, 2018 (April 2018 Proposal) (83 FR 15458; April 10, 2018). These issues were raised in petitions for reconsideration and in separately issued letters from industry and in meetings with industry groups. 
The EPA received three separate 
petitions for reconsideration. Two petitions were jointly filed by API and American Fuel and Petrochemical Manufacturers (AFPM). The first of these petitions was filed on January 19, 2016 and requested an administrative reconsideration under section 307(d)(7)(B) of the CAA of certain provisions of Refinery MACT 1 and 2, as promulgated in the December 2015 Rule. Specifically, API and AFPM requested that the EPA reconsider the maintenance vent provisions in Refinery MACT 1; the alternate startup, shutdown, or hot standby standards for fluid catalytic cracking units (FCCUs) in Refinery MACT 2; the alternate startup and shutdown for sulfur recovery units in Refinery MACT 2; and the new catalytic reforming units (CRUs) purging limitations in Refinery MACT 2. The request pertained to providing and/or clarifying the compliance time for these requirements. Based on this request and additional information received, the EPA issued a proposal on February 9, 2016 (81 FR 6814), and a final rule on July 13, 2016 (81 FR 45232), fully responding to the January 19, 2016, petition for reconsideration. The second petition from API and AFPM was filed on February 1, 2016 and outlined a number of specific issues related to the work practice standards for PRDs and flares, and the alternative water overflow provisions for DCUs, as well as a number of other specific issues on other aspects of the rule. The third petition was filed on February 1, 2016, by Earthjustice on behalf of Air Alliance Houston, California Communities Against Toxics, the Clean Air Council, the Coalition for a Safe Environment, the Community In-Power and Development Association, the Del Amo Action Committee, the Environmental Integrity Project, the Louisiana Bucket Brigade, the Sierra Club, the Texas Environmental Justice Advocacy Services, and Utah Physicians for a Healthy Environment. The Earthjustice 
petition claimed that several aspects of the revisions to Refinery MACT 1 were 
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1Supplemental Request for Administrative 
Reconsideration of Targeted Elements of EPA’s 
Final Rule ‘‘Petroleum Refinery Sector Risk and Technology Review and New Source Performance 
Standards; Final Rule,’’ Howard Feldman, API, and David Friedman, AFPM. February 1, 2016. Docket ID No. EPA–HQ–OAR–2010–0682–0892. 
2Letter from Matt Todd, API, and David 
Friedman, AFPM, to Penny Lassiter, EPA. July 12, 2016. Available in Docket ID No. EPA–HQ–OAR– 2010–0682. 3Letter from Peter Tsirigotis, EPA, to Matt Todd, 
API, and David Friedman, AFPM. April 7, 2017. 
Available at: https://www.epa.gov/ stationarysources-air-pollution/december-2015- refinerysector-rule-response-letters-qa. 
4Letter from Matt Todd, API, and David 
Friedman, AFPM, to Penny Lassiter, EPA. March 28, 2017. Available in Docket ID No. EPA–HQ– OAR–2010–0682. 
5Meeting minutes for January 27, 2017, EPA 
meeting with API. Available in Docket ID No. EPA– HQ–OAR–2010–0682. 
6David Friedman, ‘‘Comparison of Official CFR 
and e-CFR Postings Regarding MACT CC/UUU and NSPS Ja Postings.’’ Message to Penny Lassiter and Brenda Shine. January 10, 2018. Email. not addressed in the proposed rule, and, 
thus, the public was precluded from commenting on them during the public comment period, including: (1) Work practice standards for PRDs and flares; (2) alternative water overflow provisions for DCUs; (3) reduced monitoring provisions for fenceline monitoring; and (4) adjustments to the risk assessment to account for these changes from what was proposed. On June 16, 2016, the EPA sent letters to petitioners granting reconsideration on issues where petitioners claimed they had not been provided an opportunity to comment. These petitions and letters granting reconsideration are available for review in the rulemaking docket (see Docket ID Nos. EPA–HQ–OAR–2010–0682–0860, EPA–HQ–OAR–2010–0682–0891 and EPA–HQ–OAR–2010–0682–0892). 
On October 18, 2016 (81 FR 71661), 
the EPA proposed for public comment the issues for which reconsideration was granted in the June 16, 2016, letters. The EPA identified five issues for which it was seeking public comment: (1) The work practice standards for PRDs; (2) the work practice standards for emergency flaring events; (3) the assessment of risk as modified based on implementation of these PRD and emergency flaring work practice standards; (4) the alternative work practice (AWP) standards for DCUs employing the water overflow design; and (5) the provision allowing refineries to reduce the frequency of fenceline monitoring at sampling locations that consistently record benzene concentrations below 0.9 micrograms per cubic meter. In that notice, the EPA also proposed two minor clarifying amendments to correct a cross referencing error and to clarify that facilities complying with overlapping equipment leak provisions must still comply with the PRD work practice standards in the December 2015 Rule. 
The February 1, 2016, API and AFPM 
petition for reconsideration included a number of recommendations for technical amendments and clarifications that were not specifically addressed in the October 18, 2016, proposal.
1In 
addition, API and AFPM asked for clarification on various requirements of the final amendments in a July 12, 2016, letter.
2The EPA addressed many of the clarification requests from the July 2016 
letter and the petition for reconsideration in a letter issued on April 7, 2017.
3API and AFPM also 
raised additional issues associated with the implementation of the final rule amendments in a March 28, 2017, letter to the EPA
4and provided a list of 
typographical errors in the rule in a January 27, 2017, meeting
5with the 
EPA. On January 10, 2018, AFPM submitted a letter containing a comparison of the electronic CFR, the Federal Register documents, and the redline versions of the December 2015 Rule and October 2016 amendments to the Refinery Sector Rule noting differences and providing suggestions as to how these discrepancies should be resolved.
6These items are located in 
Docket ID No. EPA–HQ–OAR–2016– 0682. On April 10, 2018 (83 FR 15848), the EPA published proposed additional revisions to the December 2015 Rule addressing many of the issues and clarifications identified by API and AFPM in their February 2016 petition for reconsideration and their subsequent communications with the EPA. 
On July 10, 2018, the EPA published 
a proposed rule (July 2018 Proposal) to revise the compliance date for maintenance vents located at sources constructed on or before June 30, 2014, from August 1, 2017, to January 30, 2019, (83 FR 31939; July 10, 2018). We proposed to change the compliance date to address challenges petroleum refinery owners or operators are experiencing in attempting to comply with the December 2015 Rule maintenance vent requirements, notwithstanding the additional compliance time provided by our revision of the compliance date to August 1, 2017, plus an additional 1- year (i.e., August 1, 2018) compliance 
extension granted by the relevant permitting authorities for each source pursuant to the requirements set forth in the General Provisions at 40 CFR 63.6(i). The requirements for maintenance vents promulgated in the December 2015 Rule resulted in the need for completing the ‘‘management of change process’’ for affected sources (81 FR 45232, 45237, 
July 13, 2016). We also recognized that the Agency had proposed technical revisions and clarifications to the maintenance vent provisions in the April 2018 Proposal and that an 
extension would also allow the EPA to take final action on that proposal prior to the extended compliance date. Technical revisions and clarifications are being finalized in today’s rule. 
The April 2018 Proposal provided a 
45-day comment period ending on May 25, 2018. The EPA received 16 comments on the proposed amendments from refiners, equipment manufacturers, trade associations, environmental groups, and private citizens. The July 2018 Proposal provided a 30-day comment period ending on August 9, 2018. The EPA received comments on the proposed revisions from refiners, trade associations, environmental groups, and private citizens. This preamble to the final rule provides a discussion of the final revisions, including changes in response to comments on the proposal, as well as a summary of the significant comments received and responses. 
III. What is included in this final rule? A. Clarifications and Technical 
Corrections to Refinery MACT 1 
1. Definitions 
What is the history of the definitions 
addressed in the April 2018 Proposal? 
In the April 2018 Proposal, we 
proposed to amend four definitions: Flare purge gas, supplemental natural gas, relief valve, and reference control technology for storage vessel and to define an additional term. Specific to flare purge gas, we proposed for the term to include gas needed for other safety reasons. For flare supplemental gas, we proposed to amend the definition to specifically exclude assist air or assist steam. For relief valves we narrowed the definition to include PRDs that are designed to re-close after the pressure relief. As a complementary amendment, we proposed to add a definition for PRD. Finally, we proposed to revise the definition of reference control technology for storage vessels to be consistent with the storage vessel rule requirements in section 63.660. 
What key comments were received on 
definitions? 
We did not receive public comments 
on the proposed addition and revisions of these definitions. 
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What is the EPA’s final decision on the 
definitions? 
We are finalizing the addition and 
revisions of these definitions as proposed. 
2. Miscellaneous Process Vent 
Provisions 
In the April 2018 Proposal, we 
proposed several amendments to address petitioners’ requests for revisions and clarifications to the requirements identifying and managing the subset of miscellaneous process vents (MPV) that result from maintenance activities. In the July 2018 Proposal, we proposed to change the compliance date of the requirements for existing maintenance vents. We describe each of these proposals in the following subparagraphs. 
a. Notice of Compliance Status (NOCS) 
Report 
What is the history of the NOCS report 
for MPV addressed in the April 2018 Proposal? 
In their March 28, 2017, letter (Docket 
ID No. EPA–HQ–OAR–2010–0682– 0915), API and AFPM noted that the MPV provisions at section 63.643(c) do not require an owner or operator to designate a maintenance vent as Group 1 or Group 2 MPV. However, they stated that the reporting requirements at section 63.655(f)(1)(ii) are unclear as to whether a NOCS report is needed for some or all maintenance vents. We did not intend for maintenance vents to be 
included in the NOCS report. The rule has separate requirements for characterizing, recording, and reporting maintenance vents in section 63.655(g)(13) and (h)(12); therefore, it is not necessary to identify each place where equipment may be opened for maintenance in a NOCS report. To clarify this, we proposed to add language to section 63.643(c) to explicitly state that maintenance vents need not be identified in the NOCS report. 
What key comments were received on 
the NOCS report for MPV provisions? 
We did not receive comments on the 
proposed amendment in section 63.643(c) to explicitly state that maintenance vents need not be identified in the NOCS report. 
What is the EPA’s final decision on the 
NOCS report for MPV provisions? 
We are finalizing the amendment in 
section 63.643(c) as proposed. b. Maintenance Vents Associated With 
Equipment Containing Pyrophoric Catalysts 
What is the history of regulatory text for 
maintenance vents associated with equipment containing pyrophoric catalyst addressed in the April 2018 Proposal? 
Under 40 CFR 63.643(c) an owner or 
operator may designate a process vent as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed, or placed into service. Facilities generally must comply with one of three conditions prior to venting maintenance vents to the atmosphere (section 63.643(c)(1)(i)– (iii)). However, section 63.643(c)(1)(iv) of the December 2015 Rule provides flexibility for maintenance vents associated with equipment containing pyrophoric catalyst (or simply ‘‘pyrophoric units’’), such as hydrotreaters and hydrocrackers, at refineries that do not have pure hydrogen supply. At many refineries, pure hydrogen is generated by steam- methane reforming (SMR), with hydrogen concentrations of 98 volume percent or higher. The other source of hydrogen available at refineries is from the CRU. This catalytic reformer hydrogen may have hydrogen concentrations of 50 percent or more and may contain appreciable concentrations of light hydrocarbons which limit the ability of vents associated with this source of hydrogen to meet the lower explosive limit (LEL) of 10 percent or less. The December 2015 Rule limits the flexibility to maintenance vents associated with pyrophoric units at refineries without a 
pure hydrogen supply. For pyrophoric units at a refinery without a pure hydrogen supply, the December 2015 Rule provides that the LEL of the vapor in the equipment must be less than 20 percent, except for one event per year not to exceed 35 percent. 
API and AFPM took issue with the 
regulatory language that drew a distinction based on whether there is a pure hydrogen supply located at the refinery. As described in the preamble to the April 2018 Proposal (83 FR 15462), we reviewed comments from API and AFPM as well as additional information contained in an August 1, 2017, letter (Docket ID No. EPA–HQ– OAR–2010–0682–0916) which provided evidence that a single refinery may have many pyrophoric units, some that have a pure hydrogen supply and some that do not have a pure hydrogen supply. Thus, our assumption at the time we issued the December 2015 Rule that all 
pyrophoric units at a single refinery either would or would not have a pure hydrogen supply was incorrect. Therefore, we proposed to modify the portion of the regulatory text that distinguished units based on whether there was a pure hydrogen supply ‘‘at the refinery’’ and instead base the regulation on whether a pure hydrogen supply was available for the pyrophoric unit. 
What key comments were received on 
the regulatory text for maintenance vents associated with equipment containing pyrophoric catalyst? 
Comment b.1: One commenter 
(–0953) stated that the proposed language is inadequately defined, and allows the refiner to opt in to the provision providing flexibility by, for example, shutting down the source of the pure hydrogen supply. 
Response b.1: In most cases, the 
pyrophoric unit will be supplied by either pure SMR hydrogen or catalytic reforming hydrogen. As purging with hydrogen is one of the steps used to de- inventory this equipment, the refiner cannot shutdown the hydrogen supply prior to de-inventorying the equipment. If a pyrophoric unit can be supplied with either SMR and catalytic reformer hydrogen, and the SMR hydrogen is being used during normal operations of the pyrophoric unit prior to de- inventorying the unit, we consider it a violation of the good air pollution control practices requirement in section 63.643(n) to switch the hydrogen supply 
only for de-inventorying the equipment. We also note that the refiner must keep records of the lack of a pure hydrogen supply as required at section 63.655(i)(12)(v). 
Comment b.2: One commenter stated 
that the EPA has not provided any assessment of the potential increase of uncontrolled emissions to the atmosphere, or an analysis of the increase in health risks or the environmental impact of the proposed exemption, or an assessment of the industry-provided cost data. 
Response b.2: The docket for the 
rulemaking includes the information upon which we based our decisions, including costs and environmental impact estimates of the provision providing flexibility to maintenance vents associated with pyrophoric units without a pure hydrogen supply. We had reviewed this information and determined that it was a reasonable estimate of the impacts (see Docket ID Nos. EPA–HQ–OAR–2010–0682–0733 and –0909). This information supports our statement in the April 2018 
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Proposal that this amendment is not 
projected to appreciably impact emission reductions associated with the standard. In fact, considering secondary emissions from the flare or other control system needed to comply with the 10 percent LEL limit, this provision providing flexibility to maintenance vents associated with pyrophoric units without a pure hydrogen supply is expected to result in a net environmental benefit. 
Comment b.3: One commenter stated 
that the exemption does not comport with the requirements of CAA section 112(d)(2)–(3), which requires the standards to be no less stringent than the maximum achievable control technology (MACT) floor. The commenter points to the voluntary survey of hydrogen production units as submitted by API and notes that 12 of 62 units not connected to a pure hydrogen supply reported being able to comply with the 10 percent LEL standard. As such, the commenter contends that the MACT floor should be 10 percent LEL for equipment containing pyrophoric catalysts regardless of whether or not they are connected to a pure hydrogen supply and, thus, there should be no alternative based on whether or not a pure hydrogen supply is available. Furthermore, the commenter stated that costs cannot be used as justification for providing a higher emission limit alternative to MACT standards, particularly those based on the MACT floor. 
Response b.3: As an initial matter, the 
EPA did not intend to re-open the issue of what is the MACT floor for pyrophoric units through the proposal. Rather, the issue raised was whether the flexibility provided should only be for pyrophoric units located at a refinery without a pure hydrogen supply or should also apply to pyrophoric units located at a facility that has a pure hydrogen supply but for which pure hydrogen is not available at the unit. Regardless, we disagree with the commenter that the survey results submitted by API support a conclusion that 10 percent LEL is the MACT floor for all pyrophoric units. The survey provided by API was not the type of rigorous survey that could provide a basis for establishing the MACT floor. As an initial matter, the API survey did not include the universe of pyrophoric units and there is no information to suggest whether the best performers for the subset of units addressed in the survey represents the top performing 12 percent of sources across the industry. 
Also, because the exact questions and definitions of terms were not provided, there may be some misinterpretation of 
the results. For example, it is unclear from the summary provided if the question was whether the facility owners or operators could meet 10 percent LEL for all events (i.e., a never- 
to-be-exceeded limit) or if this was more of an operational average. 
We agree with the commenter that 
costs cannot be considered in establishing a MACT standard. We based this provision on an assessment of the overall environmental impacts associated with the emission limitations and concluded that the best performing pyrophoric units without a pure hydrogen supply, when considering secondary impacts, was to meet a 20 percent LEL with one exception not to exceed 35 percent LEL per year. The API survey does not provide support to change our analysis of the MACT floor in the December 2015 Rule. 
Comment b.4: One commenter 
(–0958) pointed out that the proposed amendment to section 63.643(c)(1)(iv) is inconsistent with the description of the amendment included in the preamble to the April 2018 Proposal. Specifically, the description of the amendment in the preamble of the April 2018 Proposal does not contain the additional phrase, ‘‘considering all such maintenance vents at the refinery,’’ which was included in the amendatory text. The commenter suggested that the EPA delete this phrase as it could be interpreted to limit the use of the 35 percent allowance to once per year per 
refinery rather than to once per year per piece of equipment. 
Response b.4: We agree that the 
preamble discussion and the rule language regarding these revisions are not consistent. We did not intend to limit the one time per year 35 percent LEL to the refinery; rather, we intended it to apply to each pyrophoric unit without a pure hydrogen supply. Consistent with our intent as expressed in the preamble discussion of the April 2018 Proposal, 83 FR at 15462, we are removing the phrase, ‘‘considering all such maintenance vents at the refinery’’ from the regulatory text at section 63.643(c)(1)(iv) for the final amendments promulgated by this rulemaking. 
What is the EPA’s final decision on the 
regulatory text for maintenance vents associated with equipment containing pyrophoric catalyst? 
We are finalizing the proposed 
amendment with one change. In response to the public comments received, we are not including the phrase ‘‘considering all such maintenance vents at the refinery’’ in the final regulatory text at section 63.643(c)(1)(iv), as revised by this rulemaking. 
c. Control Requirements for 
Maintenance Vents 
What is the history of the provisions for 
the control requirements for maintenance vents addressed in the April 2018 Proposal? 
Paragraph 63.643(a) specifies that 
Group 1 miscellaneous process vents must be controlled by 98 percent or to 20 parts per million by volume or to a flare meeting the requirements in section 63.670. This paragraph also states in the second sentence that requirements for maintenance vents are specified in section 63.643(c), ‘‘and the owner or operator is only required to comply with the requirements in section 63.643(c).’’ Paragraphs (c)(1) through (3) then specify requirements for maintenance vents. Paragraph (c)(1) requires that equipment must be depressured to a control device, fuel gas system, or back to the process until one of the conditions in paragraph (c)(1)(i) through (iv) is met. In reviewing these rule requirements, the EPA noted that we did not specify that the control device in (c)(1) must also meet the Group 1 miscellaneous process vent control device requirements in paragraph (a). The second sentence in section 63.643(a) could be misinterpreted to mean that a facility complying with the maintenance vent provisions in section 63.643(c) must only comply with the requirements in paragraph (c) and not the control requirements in paragraph (a) for the control device referenced by paragraph (c)(1). In omitting these requirements, we did not intend that the control requirement for maintenance vents prior to atmospheric release would not be compliant with Group 1 controls as specified in section 63.643(a). In order to clarify this intent, we proposed to amend paragraph section 63.643(c)(1) to include control device specifications equivalent to those in section 63.643(a). 
What key comments were received on 
the provisions for the control requirements for maintenance vents? 
We received one comment in support 
of this revision. 
What is the EPA’s final decision on the 
provisions for the control requirements for maintenance vents? 
We are finalizing the amendment to 
§ 63.643(c)(1) to include control device specifications equivalent to those in § 63.643(a), as proposed. 
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d. Additional Maintenance Vent 
Alternative for Equipment Blinding 
What is the history of the maintenance 
vent alternative for equipment blinding addressed in the April 2018 Proposal? 
We proposed a new alternative 
compliance option for the subset of maintenance vents subject to the provisions addressed at § 63.643(c)(v). The proposed alternative compliance option would apply to equipment that must be blinded to seal off hydrocarbon- containing streams prior to conducting maintenance activities. 
What key comments were received on 
the maintenance vent alternative for equipment blinding? 
We received two comments on the 
proposed amendment. One commenter expressed concern regarding the burden of the recordkeeping associated with this alternative compliance option. The second commenter asserted that the use of work practice standards for maintenance vents is illegal. As detailed in the comment summaries and responses included in the response to comment document for this final rule (Docket ID No. EPA–HQ–OAR–2010– 0682), we were not persuaded to make changes to the proposed amendments. 
What is the EPA’s final decision on the 
maintenance vent alternative for equipment blinding? 
We are finalizing the new alternative 
compliance option for the subset of 
maintenance vents subject to the requirements of § 63.643(c)(v) for which equipment blinding is necessary, as proposed. 
e. Recordkeeping for Maintenance Vents 
on Equipment Containing Less Than 72 Pounds per Day (lbs/day) of Volatile Organic Compounds (VOC) 
What is the history of the provisions 
regarding recordkeeping for maintenance vents on equipment containing less than 72 lbs/day of VOC provisions addressed in the April 2018 Proposal? 
Under section 63.643(c) an owner or 
operator may designate a process vent as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed, or placed into service. The rule specifies that prior to venting a maintenance vent to the atmosphere, process liquids must be removed from the equipment as much as practical and the equipment must be depressured to a control device, fuel gas system, or back to the process until one of several conditions, as applicable, is met. One condition specifies that 
equipment containing less than 72 lbs/ day of VOC can be depressured directly to the atmosphere provided that the mass of VOC in the equipment is determined and provided that refiners keep records of the process units or equipment associated with the maintenance vent and the date of each maintenance vent opening, and the estimate of the total quantity of VOC in the equipment at the time of vent opening. Therefore, each maintenance vent opening would be documented on an event-basis. 
Industry petitioners noted that there 
are numerous routine maintenance activities, such as replacing sampling line tubing or replacing a pressure gauge, that involve potential releases of very small amounts of VOC, often less than 1 lb/day, that are well below the 72 lbs/day of VOC threshold provided in section 63.643(c)(1)(iii). They claimed that documenting each individual event is burdensome and unnecessary. As stated in the preamble to the April 2018 Proposal (83 FR 15463), the EPA agrees that documentation of each release from maintenance vents which serve equipment containing less than 72 lbs/ day of VOC is not necessary provided there is a demonstration that the event is compliant with the requirement that the equipment contains less than 72 lbs/ day of VOC. Therefore, we proposed to revise the event-specific recordkeeping requirements specific to maintenance vent openings in equipment containing less than 72 lbs/day of VOC to only require a record demonstrating that the total quantity of VOC in the equipment based on the type, size, and contents is less than 72 lbs/day of VOC at the time of the maintenance vent opening. 
What key comments were received on 
the recordkeeping for maintenance vents on equipment containing less than 72 lbs/day of VOC provisions? 
We received two comments on this 
proposed amendment. One commenter maintained that the event-specific recordkeeping requirements are too burdensome, while the other commenter maintained that the recordkeeping 
requirements are not adequate to assure compliance with the rule. As detailed in the comment summaries and responses included in the response to comment document for this final rule (Docket ID No. EPA–HQ–OAR–2010–0682), we concluded that the proposed amendment struck the right balance between requiring the necessary information needed to demonstrate and enforce compliance with the 72 lbs/day of VOC maintenance vent provision while reducing the recordkeeping and 
reporting burden with more detailed records. 
What is the EPA’s final decision on the 
recordkeeping for maintenance vents on equipment containing less than 72 lbs/ day of VOC provisions? 
We are finalizing these amendments 
as proposed. 
f. Bypass Monitoring for Open-Ended 
Lines (OEL) 
What is the history of the bypass 
monitoring provisions for OELs addressed in the April 2018 Proposal? 
API and AFPM requested clarification 
of the bypass monitoring provisions in section 63.644(c) for OEL (Docket ID Nos. EPA–HQ–OAR–2010–0682–0892 and –0915). This provision excludes components subject to the Refinery MACT 1 equipment leak provisions in section 63.648 from the bypass monitoring requirement. Noting that the provisions in section 63.648 only apply to components in organic hazardous air pollutants (HAP) service (i.e., greater 
than 5-weight percent HAP), API and AFPM asked whether the EPA also intended to exclude open-ended valves or lines that are in VOC service (less than 5-weight percent HAP) and are capped and plugged in compliance with the standards in NSPS subpart VV or VVa or the Hazardous Organic NESHAP (HON; 40 CFR part 63, subpart H) that are substantively equivalent to the Refinery MACT 1 equipment leak provisions in section 63.648. Commenters noted that OELs in conveyances carrying a Group 1 MPV could be in less than 5-weight percent HAP service, but could still be capped and plugged in accordance with another rule, such as NSPS subpart VV or VVa or the HON. As stated in the preamble to the proposed rule (83 FR 15464), the EPA agrees that, because the use of a cap, blind flange, plug, or second valve for an open-ended valve or line is sufficient to prevent a bypass, the Refinery MACT 1 bypass monitoring requirements in section 63.644(c) are redundant with NSPS subpart VV in these cases. Therefore, we proposed to amend section 63.644(c) to make clear that open-ended valves or lines that are capped and plugged sufficient to meet the standards in NSPS subpart VV at § 60.482–6(a)(2), (b), and (c), are not subject to the bypass monitoring in section 63.644(c). 
What key comments were received on 
the bypass monitoring provisions for OELs? 
Comment f.1: One commenter (–0958) 
expressed support for the addition of 
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the bypass monitoring option for capped 
or plugged OELs in section 63.644(c)(3). The commenter suggested that the EPA similarly amend section 63.660(i)(2) to provide this new monitoring alternative for vent systems handling Group 1 storage vessel vents. A different commenter (–0953) opposed this revision, stating that the EPA did not show or provide any evidence to support the statement that the monitoring requirements are ‘‘redundant with NSPS subpart VV.’’ The commenter recommended that the EPA require a compliance demonstration or otherwise demonstrate that the provisions are equivalent. 
Response f.1: The December 2015 
Rule bypass provisions require either a flow indicator or the use of a valve locked in a non-diverting position using a car-seal or lock and key. The general equipment leak provisions for OELs are installation of a plug, cap or secondary valve. Based on the effectiveness of this equipment work practice standard, continuous or periodic monitoring of these secondarily-sealed lines are not generally required. With the elimination of the exemption for discharges associated with maintenance activities and process upsets under the definition of ‘‘periodically discharged’’ in the December 2015 Rule, there are a number of process lines that are not traditional bypass lines and that were not previously considered an MPV or an MPV bypass, but now are. Many of these lines are small and not conducive to the installation of a car-seal or lock and key so they cannot comply with the current bypass provisions. Most of these small lines have been previously regulated via Refinery MACT 1’s requirement to comply with the NSPS open-ended line provisions, which are an effective means to control emissions from these smaller lines. Because the existing equipment leak provisions for these types of OELs serve the same purpose and are more appropriate for these smaller lines, we determined that it is reasonable to provide for this method of compliance for these OELs. 
What is the EPA’s final decision on the 
bypass monitoring provisions for OELs? 
We are finalizing this amendment as 
proposed. In response to comments received on the proposed rule, we are providing this new monitoring alternative for vent systems handling Group 1 storage vessel vents at section 63.660(i)(2) in the final rule. g. Compliance Date Extension for 
Existing Maintenance Vents 
What is the history of the compliance 
date extension for existing maintenance vents addressed in the July 2018 Proposal? 
In the July 2018 Proposal, we 
proposed to amend the compliance date for maintenance vent provisions applicable to existing sources (i.e., those 
constructed or reconstructed on or before June 30, 2014) promulgated at 40 CFR 63.643(c). The basis for this proposal was that sources needed additional time to follow the ‘‘management of change’’ process. We also noted that we had proposed substantive revisions to the maintenance vent requirements as part of the April 2018 Proposal. 
What significant comments were 
received on the compliance date extension for existing maintenance vents? 
Comment g.1: One commenter (–0968) 
stated that the proposed compliance extension is arbitrary and capricious 
because the EPA has not provided any evidence as to why refineries could not comply with the August 1, 2017, compliance date and why a revised compliance date of January 30, 2019, is as expeditious as practicable, as required by CAA section 112(i)(3)(A). The commenter noted that the EPA referred to the fact that some number of refinery owners and operators have applied for and received compliance extensions of up to one year from their permitting authorities pursuant to 40 CFR 63.6(i), but does not provide any evidence of these applications or subsequent state agency determinations in the rulemaking record. The commenter further noted that the EPA’s failure to provide this information in the record for the rulemaking has inhibited the public’s ability to provide fully informed comments, and as such, the EPA is in violation of the notice-and- comment and public participation requirements of CAA section 307(d). The commenter also disagreed with the EPA’s statement in the preamble of the July 2018 Proposal that the source requests for an extension from the permitting authorities is demonstrative of refinery owners and operators acting on ‘‘good faith efforts.’’ Rather, the commenter asserted that the filing of these requests shows an avoidance of compliance with the rule. 
The commenter stated that the 
proposed compliance extension is particularly harmful since the EPA has acknowledged that there are significant disproportionate impacts of refinery pollution to communities of color and 
low-income people. The commenter noted that the EPA has not supported the conclusion in the July 2018 Proposal that the extension of compliance would have an insignificant effect on emissions reductions. A separate commenter (–0971) concurred with the EPA’s conclusions that the proposed compliance extension would have an insignificant effect on emissions reductions. 
The commenter also stated that the 
EPA’s reliance on regulatory uncertainty due to the April 2018 Proposal as part of the justification for the need for a compliance extension is at odds with the CAA’s explicit prohibition on any delay or postponement of a final rule based on reconsideration (see CAA section 307(d)(7)(B)). The commenter further added that this provision only allows the EPA to stay a rule’s effective date during reconsideration, not to postpone compliance, and only enables the EPA to do so for up to three months. Another commenter (–0971) expressed support for the proposed compliance extension for maintenance vents because of regulatory uncertainty since the EPA proposed amendments in April 2018 Proposal, but has not yet finalized those proposed amendments. The commenter stated that these revisions are critical to providing certainty as to what is required and to assure equipment may be isolated for maintenance under all expected maintenance situations. The commenter noted that maintenance vents are located across the refinery, and time will be needed to review procedures that would implement those revisions under refinery management of change processes, incorporate the changes into refinery compliance procedures and recordkeeping and reporting systems, and provide training to employees. 
Response g.1: The EPA is not 
finalizing the extension of the compliance date as proposed in July 2018. However, in order to provide sources with time to understand the amended maintenance requirements, to determine which maintenance compliance option best meets their needs, and to come into compliance we are modifying the compliance date so that it is 30 days following the effective date of the final rule. Due to the variety of different types of maintenance vents and their ubiquitous nature, there has been some uncertainty as to how the maintenance vent requirements apply; whether the provisions, as promulgated, are appropriate for all types of vents; 
and the time needed to make the requisite modifications to ensure 
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7Cf. 5 U.S.C. 553(d) providing a 30-day period 
prior to a rule taking effect. compliance. The maintenance vent 
provisions in their current form were promulgated in the December 2015 Rule in order to replace a start-up, shutdown and malfunction (SSM) provision that was included in the original MACT standard. The EPA was replacing the SSM provisions because in Sierra Club v. EPA, [551 F.3d 1019 (D.C. Cir. 2008)], 
the D.C. Circuit determined that SSM provisions, similar to those included in the Refinery MACT were inconsistent with the requirements of the CAA. The EPA originally provided a compliance date as of the effective date of the December 2015 Rule (January 30, 2016), but subsequently extended that date to August 2017 based on information from refineries that they needed more time to comply. As previously noted, many refineries sought a further extension until August 2018 from state permitting authorities. Establishing a compliance date 30 days following promulgation of these revisions will allow refineries a modest amount of time to ensure any remaining maintenance vents not yet in compliance with the MACT, as modified through this final action, are in compliance. 
With respect to the comments on the 
effect of emissions reductions relative to the July 2018 Proposal, we reached this conclusion based on several factors. First, maintenance events typically occur about once per year or less frequently for major equipment. Thus, during the proposed period of the compliance extension (approximately 6 months from the August 2018 compliance date that applied to most refineries due to extensions granted by state permitting authorities), some equipment would have no major events and other equipment, at most, should experience only one event. Second, facilities would still be required to comply with the general requirements to use good air pollution control practices during maintenance events. Many facility owners or operators already have standard procedures for emptying and degassing equipment. While these procedures are not as stringent as the MACT requirements for maintenance vents as adopted in the December 2015 Rule and as we had proposed in April 2018, they would provide some limit on emissions to the atmosphere. In a meeting with industry representatives, an example of the type of emissions occurring from maintenance vents was provided to the Agency (Docket ID No. EPA–HQ–OAR–2010–0682–0909). Based on that example, the Agency estimates that approximately 200 lbs of VOC would be released from purging 6 pieces of equipment containing pyrophoric catalyst when venting at 35 percent LEL rather than 10 percent LEL. Based on our previous analysis of impacts for risk and technology review revisions to Refinery MACT 1, we estimate approximately 10 percent of VOC emissions are HAP, so that we estimate on the order of approximately 3 pounds of HAP emissions (0.1 × 200/ 
6) would occur per major equipment venting event. The maintenance vent provisions as adopted in the December 2015 Rule were projected to reduce emissions of HAP by 5,200 tons per year (80 FR 75178, December 1, 2015). Therefore, based on the low expected emissions from each major equipment venting event, the expected limited occurrence of maintenance venting events, and the likelihood that many types of maintenance venting events are in compliance with the MACT, the compliance extension would have an insignificant effect on emissions. 
What is the EPA’s final decision on the 
compliance date extension for existing maintenance vents? 
The EPA is not finalizing the 
compliance extension as proposed in the July 2018 Proposal. However, in order to provide sources with time to understand the amended maintenance requirements, to determine which maintenance compliance option best meets their needs, and to come into compliance, we are modifying the compliance date so that it is 30 days following the effective date of the final rule.
7 
3. Pressure Relief Device Provisions 
a. Clarification of Requirements for PRD 
‘‘in organic HAP service’’ 
What is the history of the requirements 
for PRD ‘‘in organic HAP service’’ addressed in the April 2018 Proposal? 
The introductory text for the 
equipment leak provisions for PRD in section 63.648(j) requires compliance with no detectable emission provisions for PRD ‘‘in organic HAP gas or vapor service’’ and the pressure release management requirements for PRD ‘‘for all pressure relief devices.’’ However, the pressure release management requirements for PRD in section 63.648(j)(3) are applicable only to PRD ‘‘in organic HAP service.’’ There are five specific provisions within the pressure release management requirements for PRD listed in paragraphs 63.648(j)(3)(i) through (v). In the first four paragraphs, the phrase ‘‘each [or any] affected pressure relief device’’ is used, but this phrase is missing in the fifth paragraph. 
API and AFPM requested that we clarify whether releases listed in section 63.648(j)(3)(v) are limited to PRDs ‘‘in organic HAP service.’’ Consistent with the requirements in section 63.648(j)(3)(i) through (iv) and the Agency’s intent when promulgating the provisions in section 63.648(j)(3), we proposed to add the phrase, ‘‘affected pressure relief device’’ to section 63.648(j)(3)(v). We also proposed to amend the introductory text in paragraph (j) to add the phrase, ‘‘in organic HAP service’’ at the end of the last sentence to further clarify that the pressure release management requirements for PRD in section 63.648(j)(3) are applicable to ‘‘all pressure relief devices in organic HAP service.’’ 
What key comments were received on 
the requirements for PRD ‘‘in organic HAP service’’? 
We did not receive any public 
comments on these proposed amendments. 
What is the EPA’s final decision on the 
requirements for PRD ‘‘in organic HAP service’’? 
We are finalizing these amendments 
as proposed. 
b. Redundant Release Prevention 
Measures in 40 CFR 63.648(j)(3)(ii) 
What is the history of the requirements 
for redundant release prevention measures addressed in the April 2018 Proposal? 
Section 63.648(j)(3)(ii) lists options 
for three redundant release prevention measures that must be applied to affected PRDs. The prevention measures in paragraph (j)(3)(ii) include: (A) Flow, temperature, level, and pressure indicators with deadman switches, monitors, or automatic actuators; (B) documented routine inspection and maintenance programs and/or operator training (maintenance programs and operator training may count as only one redundant prevention measure); (C) inherently safer designs or safety instrumentation systems; (D) deluge systems; and (E) staged relief system where initial pressure relief valves (with lower set release pressure) discharges to a flare or other closed vent system and control device. In their petition for reconsideration (Docket ID No. EPA– HQ–OAR–2010–0682–0892), API and AFPM requested clarification as to whether two prevention measures can be selected from the list in § 63.648(j)(3)(ii)(A). API and AFPM noted that the rule does not state that the measures in paragraph (j)(3)(ii)(A) 
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are to be considered a single prevention 
measure. The Agency grouped the measures listed in subparagraph A together because of similarities they have; however, they can be separate measures. Therefore, as the EPA explains in the preamble to the April 2018 Proposal (83 FR 15464), if these measures operate independently, they are considered two separate redundant prevention measures. 
What key comments were received on 
the requirements for redundant release prevention measures? 
We did not receive any public 
comments on this proposed amendment. 
What is the EPA’s final decision on the 
requirements for redundant release prevention measures? 
We are finalizing the amendment to 
§ 63.648(j)(3)(ii)(A), which clarifies that independent, non-duplicative systems count as separate redundant prevention measures, as proposed. 
c. Pilot-Operated PRD and Balanced 
Bellows PRD 
What is the history of the provisions for 
pilot-operated PRD and balanced bellows PRD addressed in the April 2018 Proposal? 
In a letter dated March 28, 2017, API 
and AFPM requested clarification on whether pilot-operated PRDs are required to comply with the pressure release management provisions of section 63.648(j)(1) through (3). Based on our understanding of pilot-operated PRD (see memorandum, ‘‘Pilot- operated PRD,’’ in Docket ID No. EPA–HQ–OAR– 2010–0682) and balanced bellows PRD, we proposed that pilot-operated and balanced bellows PRD are subject to the requirements in section 63.648(j)(1) and (2), but are not subject to the requirements in section 63.648(j)(3) 
because the primary releases from these PRD are vented to a control device. We also proposed to amend the reporting requirements in section 63.655(g)(10) and the recordkeeping requirements in section 63.655(i)(11) to retain the requirements to report and keep records of each release to the atmosphere through the pilot vent that exceeds 72 lbs/day of VOC, including the duration of the pressure release through the pilot vent and the estimate of the mass quantity of each organic HAP release. 
What key comments were received on 
the provisions for pilot-operated PRD and balanced bellows PRD? 
We received one public comment on 
this proposed amendment. The commenter was generally opposed to the addition of balanced bellows and 
pilot-operated PRD to the work practice standard requirements for PRD. The comment and the EPA’s response are available in the response to comments document for this rulemaking (Docket ID No. EPA–HQ–OAR–2010–0682). 
What is the EPA’s final decision on the 
provisions for pilot-operated PRD and balanced bellows PRD? 
We are finalizing these amendments 
as proposed. 
4. Delayed Coking Unit Decoking 
Operation Provisions 
What is the history of the delayed 
coking unit decoking operation provisions addressed in the April 2018 Proposal? 
The provisions in 40 CFR 63.657(a) 
require owners or operators of DCU to depressure each coke drum to a closed blowdown system until the coke drum vessel pressure or temperature meets the applicable limits specified in the rule (2 psig or 220 degrees Fahrenheit for existing sources). Special provisions are provided in 40 CFR 63.657(e) and (f) for DCU using ‘‘water overflow’’ or ‘‘double-quench’’ method of cooling, respectively. According to 40 CFR 
63.657(e), the owner or operator of a DCU using the ‘‘water overflow’’ method of coke cooling must hardpipe the overflow water (i.e., via an overhead 
line) or otherwise prevent exposure of the overflow water to the atmosphere when transferring the overflow water to the overflow water storage tank whenever the coke drum vessel temperature exceeds 220 degrees Fahrenheit. The provision in 40 CFR 63.657(e) also provides that the overflow water storage tank may be an open or fixed-roof tank provided that a submerged fill pipe (pipe outlet below existing liquid level in the tank) is used to transfer overflow water to the tank. 
In the October 18, 2016, 
reconsideration proposal, we opened the provisions in 40 CFR 63.657(e) for public comment, but we did not propose to amend the requirements. In response to the October 18, 2016, reconsideration proposal, we received several comments regarding the provisions in 40 CFR 63.657(e) for DCU using the water overflow method of coke cooling. Based on these comments, in the April 2018 Proposal we proposed amendments to the water overflow requirements in 40 CFR 63.657(e) to clarify that an owner or operator of a DCU with a water overflow design does not need to comply with the provisions in 40 CFR 63.657(e) if they comply with the primary pressure or temperature limits in 40 CFR 63.657(a) prior to overflowing any water. We also 
proposed to add a requirement to use a separator or disengaging device when using the water overflow method of cooling to prevent entrainment of gases from the coke drum vessel to the overflow water storage tank and we proposed that gases from the separator must be routed to a closed vent blowdown system or otherwise controlled following the requirements for a Group 1 miscellaneous process vent. As separators appear to be an integral part of the water overflow system design, we did not project any capital investment or additional operating costs associated with this proposed amendment. 
What key comments were received on 
the delayed coking unit decoking operation provisions? 
The following is a summary of the key 
comments received in response to our April 2018 Proposal and our responses to these comments. Detailed public comments and the EPA responses are included in the response to comments document for this final action (Docket ID EPA–HQ–OAR–2010–0682). 
Comment 1: Industry commenters 
(–0955, –0958) stated that the proposed amendment to require DCU using the water overflow compliance option to have a disengaging device is unsupported by the record for the proposed rule and was not included in the Information Collection Request (ICR) or MACT floor analysis supporting the December 2015 Rule. The commenters noted that the EPA has not determined how many DCU use the water overflow method of coke cooling or how many will require the installation of a disengaging device, instead basing the provisions on a report by one facility using such a device. The same commenters stated that the EPA has not quantified the expected emission reductions associated with the proposed amendment to require DCU using the water overflow compliance option to have a disengaging device. One of the commenters (–0955) maintained that the emissions from the overflow water are small and sufficiently controlled via the submerged fill requirement. This 
commenter provided various analyses to support their contention that the emissions from their overflow water are small, including results of facility- specific industrial hygiene monitoring programs, which the commenter claims have shown that operators exposures to benzene are ‘‘orders of magnitude below the Occupational Safety and Health Administration (OSHA) exposure limit of 1.0 parts per million (ppm), at 0.003 ppm (300 parts per billion (ppb)) and 
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less.’’ Both of these commenters also 
asserted that the EPA should not finalize the proposed amendment to require DCU using the water overflow compliance option to have a disengaging device. 
Another commenter (–0953) asserted 
that the EPA did not provide any quantitative assessment of emissions from water overflow DCU compared to the primary MACT standard in order to demonstrate that the water overflow is at least as stringent as the MACT floor requirement (no draining or venting until the pressure in the drum is at or below 2 psig). According to the commenter, without this direct supporting analysis, the EPA’s inclusion of the water overflow provision is arbitrary and capricious. The commenter recommended that the water overflow provisions not be finalized or that additional control requirements be placed on the storage tank receiving the water overflow. Specifically, the commenter recommended that the rule require these tanks to be vented to a control device that achieves 98-percent destruction efficiency or better. Alternatively, the commenter recommended that the EPA develop minimum requirements for the liquid height and volume of water in the receiving tank and a maximum limit on the temperature of the water in the tank. The commenter also recommended that the EPA set restrictions on the re-use of the overflow water without prior additional treatment to remove organic contaminants. 
Two commenters (–0955, –0958) 
stated that, if the requirement to use a disengaging device is finalized, the EPA should provide a compliance date 3 years after the effective date of the rule, as provided under CAA section 112(i)(3)(A), due to the expected expense and timing needed for equipment installation to comply with this requirement. One commenter (–0955) described the specific steps required for a DCU system not equipped with a disengaging device to comply with the proposed rule including: Design, engineering, permit application submission and permit receipt, and installation, estimating it will take between 24–36 months to complete. 
Response 1: We agree that we did not 
include the water overflow provisions 
in the MACT floor analysis supporting the December 2015 Rule. The MACT floor analysis resulted in a determination that emissions from the DCU must be controlled (no atmospheric venting, draining or deheading of the coke drum) until the coke drum vessel pressure is at or below 2 psig is the MACT floor. In developing an alternative compliance method, such 
as the DCU water overflow provisions, we are only required to ensure that the alternative being provided is at least as stringent (achieves the same or lower emissions) as the established MACT floor. 
We disagree that the record does not 
support the proposal. In comments received on the June 30, 2014, proposed risk and technology review ‘‘Sector Rule,’’ Phillips 66 requested special provisions for water overflow (see Docket ID No. EPA–HQ–OAR–0682– 0614). Further, we understood from background meetings that there are two main suppliers of DCU technology, one of which took over the ConocoPhillips technology licenses (see Docket ID No. EPA–HQ–OAR–2010–0682–0216). As Phillips 66 was an initial developer of the technology, we surmised that the DCU designed for water overflow were likely all based on the Phillips 66 design. They also noted in their comments that they operated two units with water overflow design. While the ICR supporting the December 2015 Rule did not specifically ask about the water overflow method of cooling, we did ask the height of the drum and the height of the water in the drum prior to first draining. Three DCU were reported to have water height when first draining equal to the drum height and two DCU were reported to have water height greater than the drum height. From these data, we estimated that 2 to 5 DCU used the water overflow method of cooling. We understood that Phillips 66 likely operated most of the DCU designed to use the water overflow method of cooling. Therefore, when Phillips 66 provided a water overflow DCU design that included a water-vapor disengaging drum, we expected all water overflow DCU had this design. In subsequent meetings with API and AFPM, we discussed our findings and our intention to add a requirement for a vapor disengaging drum (see Docket ID No. EPA–HQ–OAR–2010–0682–0910 and –0911). These records clearly show we carefully considered this proposed requirement and we informed industry representatives from API, AFPM, and some individual refinery representatives of our conclusions prior to the proposal. 
We agree that the EPA has not 
provided a quantitative assessment of the emissions from the DCU when using water overflow. Rather, for the December 2015 Rule, we relied on a qualitative assessment because the precise mechanism of the emissions from the DCU is not well understood. This qualitative analysis did not 
consider the entrainment of gases in the overflow water or the need for the use of a disengaging drum. To support this 
final action, we estimated, to the best of our ability, the emissions from a typical DCU using water overflow method of cooling for units using a vapor disengaging device and one with no vapor disengaging device and compared them with the emissions projected for a DCU using conventional method of cooling complying with the 2 psig MACT standard. We found that the emissions from a DCU using water overflow method of cooling and a vapor disengaging device had emissions significantly less than a conventional DCU complying with the 2 psig standard. We also found that the emissions from a DCU using the water overflow method of cooling without a vapor disengaging device could have emissions exceeding those for a conventional DCU complying with the 2 psig pressure limit (see memorandum entitled ‘‘Estimating Emissions from Delayed Coking Units Using the Water Overflow Method of Cooling’’ in Docket ID No. EPA–HQ–OAR–2010–0682). Our emission estimates are higher than the emissions estimated by the commenter because their analyses did not consider entrained gases in the overflow water. In a follow-up meeting with this commenter, we learned that the concentration monitored near the overflow water tank was 0.3 ppm benzene (consistent with the value of 300 ppb). This concentration, while below the OSHA exposure limit of 1 ppm, is not ‘‘orders of magnitude below’’ the OSHA exposure limit and provides strong evidence that emissions near the water overflow tank are higher than would be projected based on their analysis submitted during the comment period. 
Based on our analysis, we find that 
the water overflow method of cooling alternative achieves greater emission reductions than the primary 2 psig pressure limit when a vapor disengaging device is used for the overflow water prior to the water storage tank. Because emissions without the disengaging device in the case where the receiving tank is not vented to a control device can exceed that of a conventional DCU complying with the 2 psig pressure limit, we conclude that it is necessary for the alternative compliance method to require use of a disengaging device unless the receiving tank is vented to a control device. 
Although cost consideration is not 
relevant for determining MACT, we disagree that the EPA did not consider the expense of installing a disengaging device. As part of the cost estimates for 
the DCU MACT requirements established in the December 2015 Rule, 
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80 FR 75226, we considered compliance 
costs for every DCU that did not already meet the 2 psig pressure limit. Because we already considered compliance costs in our burden estimates for the December 2015 Rule, there was no basis for assuming that compliance with the alternative standard proposed here would result in additional or otherwise different compliance costs and to do so would result in double-counting the compliance costs. 
With respect to the commenter 
requesting additional controls on the tank receiving the water overflow, our analysis supports the conclusion that the main source of emissions from the water overflow systems is entrained vapors in the overflow water. We agree that venting the receiving tank to a control device is a reasonable alternative to using a disengaging device and we have added this as an alternative compliance option for DCU using the water overflow method of cooling. However, venting the receiving tank to a control device when a vapor disengaging device is already used is unnecessary and redundant. We agree that adding certain limitations on overflow water temperature, receiving tank water volume and temperature can help to reduce emissions when a vapor disengaging device is not used, but we do not believe adding these limitations will make water overflow without a vapor disengaging device equivalent to the primary 2 psig emission limitation. Based on our analysis, we find that the use of a disengaging device with submerged fill requirement is as stringent as the MACT floor and that additional restrictions on the receiving storage vessel for these DCU are not necessary to comply with MACT. 
Finally, regarding the compliance 
date, we agree that it will take time to design, procure, and install a disengaging drum for those DCU using water overflow and that do not currently have a disengaging drum. Similarly, venting the receiving tank to a control device as an alternative to using a disengaging device will also require time to design and retrofit the tank with a fixed roof and closed vent system to control. We originally provided a 3-year compliance schedule due to the design, engineering, and equipment installation that could be required to meet the emission limitations for DCU in the December 2015 Rule. As the December 2015 Rule did not require a vapor disengaging drum or controlled tank and similar enhancements in the enclosed blowdown system will be needed for facilities to comply with the 
April 2018 Proposal, we are providing a limited compliance extension, of 2 years from the effective date of this final rule 
that alters the work practice standard by establishing the vapor disengaging drum requirement. This extension will only be afforded for DCU that use the water overflow method of cooling without adequate systems for a vapor disengaging device or controlled tank, which we consider to be as expeditious as practicable based on comments received on the April 2018 Proposal. We are also including operational requirements on the water overflow system for these DCU in the interim to minimize emissions to the greatest extent possible as requested by one of the commenters. These operational limits will not require any additional equipment, so implementation can occur immediately. We do not expect that these operational limits are sufficient to ensure that emissions from these units will be less than conventional DCU complying with the 2 psig standard at all times, but they will help to ensure emissions are not unrestricted in this interim period. We also note that pursuant to the provisions in § 63.6(i), which are generally applicable, refinery owners or operators may seek compliance extensions on a case-by-case basis if necessary. 
What is the EPA’s final decision on the 
delayed coking unit decoking operation provisions? 
We are finalizing the requirement for 
DCU using the water overflow provisions in section 63.657(e) to use a separator or disengaging device to prevent entrainment of gases in the cooling water. In response to comments, we are providing a limited compliance extension, of 2 years from the effective date of this final rule, only for DCU that use the water overflow method of cooling that document the need to design, procure, and install a disengaging device, which we consider to be as expeditious as practicable based on comments received on the April 2018 Proposal. We are providing operational restrictions on these DCU in the interim to minimize emissions to the greatest extent possible. Finally, in response to comments, we are including, as an alternative to the use of a vapor disengaging drum, requirements to discharge the overflow water to a storage vessel vented to a control device (i.e., a vessel meeting the requirements 
for storage vessels in 40 CFR part 63, subpart SS). 5. Fenceline Monitoring Provisions 
What is the history of the fenceline 
monitoring provisions addressed in the April 2018 Proposal? 
We proposed several amendments to 
the fenceline monitoring provisions in Refinery MACT 1. Many of the proposed revisions to the fenceline monitoring provisions are related to requirements for reporting monitoring data. 
The December 2015 Rule included 
new EPA Methods 325A and B specifying monitor siting and quantitative sample analysis procedures. Method 325A requires an additional monitor be placed near known VOC emission sources if the VOC emissions source is located within 50 meters of the monitoring perimeter and the source is between two monitors. In the April 2018 Proposal, we proposed an alternative to the additional monitor 
siting requirements if the only known VOC emission sources within 50 meters of the monitoring perimeter between two monitors are pumps, valves, connectors, sampling connections, and open-ended line sources. The proposed alternative requires that these sources be actively monitored monthly using audio, visual, or olfactory means and quarterly using Method 21 or the AWP for equipment leaks. 
In addition, we proposed to revise the 
quarterly reporting requirements in section 63.655(h)(8) to specify that it means calendar year quarters (i.e., Quarter 1 is from January 1 to March 31; Quarter 2 is from April 1 through June 30; Quarter 3 is from July 1 through September 30; and Quarter 4 is from October 1 through December 31) rather than being tied to the date compliance monitoring began. 
We also proposed to require one field 
blank per sampling period rather than two as currently required. Similarly, we proposed to decrease the number of duplicate samples that must be collected each sampling period. Instead of requiring a duplicate sample for every 10 monitoring locations, we proposed that facilities with 19 or fewer monitoring locations be required to collect one duplicate sample per sampling period and facilities with 20 or more sampling locations be required to collect two duplicate samples per sampling period. We also proposed to require that duplicate samples be averaged together to determine the sampling location’s benzene concentration for the purposes of calculating the benzene concentration difference (Dc). 
Consistent with the requirements in 
section 63.658(k) for requesting an alternative test method for collecting 
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and/or analyzing samples, we also 
proposed to revise the Table 6 entry for section 63.7(f) to indicate that section 63.7(f) applies except that alternatives directly specified in 40 CFR part 63, subpart CC, do not require additional notification to the Administrator or the approval of the Administrator. 
What key comments were received on 
the fenceline monitoring provisions? 
We received minor comments on 
these proposed revisions. The comment summaries and the EPA responses are available in the response to comments document for this final rule (Docket ID No. EPA–HQ–OAR–2010–0682). 
What is the EPA’s final decision on the 
fenceline monitoring provisions? 
The proposed revisions to the 
fenceline monitoring requirements, as described above, are being finalized as proposed with one minor change. In the April 2018 proposal, § 63.655(h)(8)(viii) specified that CEDRI would calculate the biweekly concentration difference (Dc) for benzene for each sampling period and the annual average Dc for benzene for each sampling period. However, in order to accurately reflect CEDRI’s current configuration, we are finalizing § 63.655(h)(8)(viii) to require the reporter to calculate and report the values of the biweekly and annual average Dc for benzene. 
6. Storage Vessel Provisions 
What is the history of the storage vessel 
provisions addressed in the April 2018 Proposal? 
We received comments from API and 
AFPM in their February 1, 2016, petition for reconsideration regarding the incorporation of 40 CFR part 63, subpart WW, storage vessel provisions and 40 CFR part 63, subpart SS, closed vent systems and control device provisions into Refinery MACT 1 requirements for Group 1 storage vessels at 40 CFR 63.660. The pre-amended version of the Refinery MACT 1 rule specified (by cross reference at 40 CFR 63.646) that storage vessels containing liquids with a vapor pressure of 76.6 kilopascals (approximately 11 pounds per square inch (psi)) or greater must be vented to a closed vent system or to a control device consistent with the requirements in section 63.119 of the HON. API and AFPM pointed out that the EPA did not retain this provision at 40 CFR 63.660 in the December 2015 Rule. We agree that the language was inadvertently omitted. We did not intend to deviate from the longstanding requirement limiting the vapor pressure of material that can be stored in a floating roof tank. Therefore, we proposed to revise the introductory text in 40 CFR 63.660 to clarify that owners or operators of affected Group 1 storage vessels storing liquids with a maximum true vapor pressure less than 76.6 kilopascals (11.0 psi) can comply with either the requirements in 40 CFR part 63, subpart WW or SS, and that owners or operators storing liquids with a maximum true vapor pressure greater than or equal to 76.6 kilopascals (11.0 psi) must comply with the requirements in 40 CFR part 63, subpart SS. 
We also received comments from API 
and AFPM in their February 1, 2016, petition for reconsideration regarding provisions in section 63.660(b). Section 63.660(b)(1) allows Group 1 storage vessels to comply with alternatives to those specified in section 63.1063(a)(2) of subpart WW. Section 63.660(b)(2) specifies additional controls for ladders having at least one slotted leg. The petitioners explained that section 63.1063(a)(2)(ix) provides extended compliance time for these controls, but that it is unclear whether this additional compliance time extends to the use of the alternatives to comply with section 63.660(b). We proposed language to 
clarify that the additional compliance time specified in the alternative included at section 63.1063(a)(2) applies to the implementation of controls in section 63.660(b). 
We also proposed language to clarify 
at section 63.660(e) that the initial inspection requirements that apply with initial filling of the storage vessels are not required again if a vessel transitions from the existing source requirements in section 63.646 to new source requirements in section 63.660. 
The following is a summary of the 
comment received in response to our April 2018 Proposal and our response to this comment. We did not receive any other comments related to the proposed amendments for storage vessels. 
What comment was received on the 
storage vessel provisions? 
Comment 1: One commenter (–0958) 
claims that the EPA proposed revisions to the introductory paragraph of section 63.660 to allow certain storage vessels to comply with alternative requirements is not an acceptable control measure. The commenter states that the proposed revisions included 11.0 psia as parenthetical equivalent to the 76.6 kPa threshold. The commenter recommended that the EPA revise the 11.0 psia to 11.1 psia as this represents a more accurate conversion and consistency with historical regulations. 
Response 1: Upon reviewing this 
issue, we agree with the commenter that 11.1 psia is the correct value to use when converting 76.6 kilopascals to psia and we are revising the proposed language to use 11.1 psia rather than 11.0 psia in this introductory paragraph. 
What is the EPA’s final decision on the 
storage vessel provisions? 
After considering public comments on 
the proposed amendments, the EPA is finalizing the amendment to the introductory text in 40 CFR 63.660 with a change from 11.0 psia to 11.1 psia. We are finalizing the amendments to section 63.660(b) and section 63.660(e) as proposed. 
7. Flare Control Device Provisions 
What is the history of the flare control 
device provisions addressed in the April 2018 Proposal? 
API and AFPM requested clarification 
in a December 1, 2016, letter to the EPA (Docket ID No. EPA–HQ–OAR–2010– 0682–0913) regarding assist steam line designs that entrain air into the lower or upper steam at the flare tip. The industry representatives noted that many of the steam-assisted flare lines have this type of air entrainment and likely were part of the dataset analyzed to develop the standards established in the December 2015 Rule for steam- assisted flares. API and AFPM, therefore, maintain that these flares should not be considered to have assist air, and that they are appropriately and adequately regulated under the final standards in the December 2015 Rule for steam-assisted flares. Because flares with assist air are required to comply with both a combustion zone net heating value (NHV
cz) and a net heating 
value dilution parameter (NHV dil), there 
is increased burden in having to comply with two operating parameters, and API and AFPM contend that this burden is unnecessary. 
In the preamble to the April 2018 
Proposal, we stated that air intentionally entrained through steam nozzles meets the definition of assist air. However, we also noted that if this is the only assist air introduced prior to or at the flare tip, it is reasonable in most cases for the owner or operator to only need to comply with the NHV
czoperating limit. 
We also noted that, for flare tips with an effective tip diameter of 9 inches or more, there are no flare tip steam induction designs that can entrain enough assist air to cause a flare operator to have a deviation of the NHV
diloperating limit without first 
deviating from the NHV czoperating 
limit. Therefore, we proposed in section 63.670(f)(1) to allow owners or operators of flares whose only assist air is from perimeter assist air entrained in lower 
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and upper steam at the flare tip and 
with a flare tip diameter of 9 inches or greater to comply only with the NHV
cz 
operating limit. Steam-assisted flares with perimeter assist air and an effective tip diameter of less than 9 inches would remain subject to the requirement to account for the amount of assist air intentionally entrained within the calculation of NHV
dil. We further 
proposed to add provisions to section 63.670(i)(6) specifying that owners or operators of these smaller diameter steam-assisted flares use the steam flow rate and the maximum design air-to- steam ratio of the steam tube’s air entrainment system for determining the flow rate of this assist air. 
We also proposed several clarifying 
amendments for flares in response to API and AFPM’s February 1, 2016, petition for reconsideration (Docket ID No. EPA–HQ–OAR–2010–0682–0892) as outlined below. 
•For air assisted flares, we proposed 
to amend section 63.670(i)(5) to include provisions for continuously monitoring fan speed or power and using fan curves for determining assist air flow rates to clarify that this is an acceptable method of determining air flow rates. 
•We proposed two amendments 
relative to the visible emissions 
monitoring requirements in section 63.670(h) and (h)(1). We proposed to clarify that the initial 2-hour visible emission demonstration should be conducted the first time regulated materials are routed to the flare. We also proposed to amend section 63.670(h)(1) to clarify that the daily 5-minute observations must only be conducted on days the flare receives regulated materials and that the additional visible emissions monitoring is specific to cases when visible emissions are observed while regulated material is routed to the flare. 
•We proposed to amend section 
63.670(o)(1)(iii)(B) to clarify that the owner or operator must establish the smokeless capacity of the flare in a 15- minute block average and to amend section 63.670(o)(3)(i) to clarify that the exceedance of the smokeless capacity of the flare is based on a 15-minute block average. 
What comments were received on the 
flare control device provisions? 
The following is a summary of one 
comment received in response to our April 2018 Proposal and our response to this comment. All other comments related to the proposed amendments for the flare provisions are included in the response to comments document for this final action (Docket ID No. EPA–HQ– 2010–0682). Comment 1: One commenter (–0958) 
explained that assist air may only be entrained in upper steam. Thus, they requested that the proposed revision to section 63.670(f)(1) and section 63.670(i)(6) be changed from ‘‘lower and upper’’ to ‘‘lower and/or upper.’’ The commenter also requested that the EPA clarify that the tip diameter referenced in section 63.670(i)(6) is the effective diameter as defined in section 63.670(n)(1) and section 63.670(k)(1). Finally, the commenter requested that the EPA clarify that section 63.670(i)(6) applies to flares with an effective diameter less than 9 inches and stated that perimeter air monitoring for a steam-assisted flare with an effective diameter equal to or greater than 9 inches is not required. 
Response 1: We did not mean to limit 
the air entrainment provisions to only instances where air is entrained in both lower and upper steam at the flare tip. We agree that the language ‘‘lower and/ or upper steam’’ is more accurate and consistent with our intent. We also agree that we should refer to the ‘‘effective diameter’’ of the flare tip as defined in the equation for NHV
dilin 
section 63.670(n)(1). This clarification was made in section 63.670(f)(1); this term is not used in section 63.670(i)(6). 
What is the EPA’s final decision on the 
flare control device provisions? 
After considering the comments, we 
are finalizing the proposed amendment in section 63.670(f)(1) and section 63.670(i)(6) with a change in language from ‘‘lower and upper’’ to ‘‘lower and/ or upper.’’ We are also finalizing the proposed amendment in section 63.670(f)(1) with a change in language from ‘‘flare tip diameter’’ to ‘‘effective diameter,’’ a term that is defined in section 63.670(n)(1) and section 63.670(k)(1). The proposed clarifying amendments related to air assisted flares, visible emissions monitoring requirements, and smokeless capacity of the flare are being finalized as proposed. 
8. Recordkeeping and Reporting 
Provisions 
What is the history of the recordkeeping 
and reporting provisions addressed in the April 2018 Proposal? 
We proposed several clarifying 
amendments for recordkeeping and reporting requirements in response to questions received from API and AFPM as well as in response to API and AFPM’s March 28, 2017, letter (Docket ID No. EPA–HQ–OAR–2010–0682– 0915). 
Refinery owners or operators must 
submit a NOCS with 150 days of the compliance date associated with the 
provisions in the December 2015 Rule. We proposed to amend sections 63.655(f) and (f)(6) to provide that sources having a compliance date on or after February 1, 2016, may submit the NOCS in the periodic report rather than as a separate submission. 
We proposed several amendments for 
electronic reporting requirements at sections 63.655(f)(1)(i)(B)(3) and (C)(2), (f)(1)(iii), (f)(2), and (f)(4) to clarify that when the results of performance tests or evaluations are reported in the NOCS, the results are due by the date the NOCS is due, whether the results are reported via Compliance and Emissions Data Reporting Interface (CEDRI) or in hard copy as part of the NOCS report. If the results are reported via CEDRI, we also proposed to specify that sources need not resubmit those results in the NOCS, but may instead submit specified information identifying that a performance test or evaluation was conducted and the units and pollutants that were tested. We also proposed to add the phrase ‘‘Unless otherwise specified by this subpart’’ to sections 63.655(h)(9)(i) and (ii) to make clear that test results associated with a NOCS report are due at the time the NOCS is due and not within 60 days of completing the performance test or evaluation. We also proposed to amend several references in Table 6—General Provisions Applicability to Subpart CC that discuss reporting requirements for performance tests or performance evaluations. 
We proposed to revise the provision 
in section 63.655(h)(10) to include processes to assert claims of EPA system outage or force majeure events as a basis 
for extending the electronic reporting deadlines. 
We also proposed to revise section 
63.655(i)(5) to restore the subparagraphs which were inadvertently not included in the published CFR due to a clerical error. 
The amendments to section 
63.655(h)(5)(iii) included in the 
December 2015 Rule (80 FR 75247) were not included in the regulations as published by the CFR. As reflected in the instructions to the amendments, we intended for the option to use an automated data compression recording system to be an approved monitoring alternative. In addition, in reviewing this amendment, the EPA noted that 40 CFR 63.655(h)(5) specifically addresses mechanisms for owners or operators to request approval for alternatives to the continuous operating parameter monitoring and recordkeeping provisions, while the provisions in 40 CFR 63.655(i)(3) specifically include 
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options already approved for 
continuous parameter monitoring system (CPMS). Consistent with our intent for the use of an automated data compression recording system to be an approved monitoring alternative, we proposed to move paragraph 63.655(h)(5)(iii) to 63.655(i)(3)(ii)(C). 
Finally, we proposed a number of 
editorial and other corrections in Table 2 of the April 2018 Proposal (83 FR 15470). 
What significant comments were 
received on the recordkeeping and reporting provisions? 
The following is a summary of the 
significant comments received in response to our April 2018 Proposal and our response to these comments. All other comments related to the proposed amendments for the recordkeeping and reporting provisions are included in the response to comments document for this final action (Docket ID No. EPA–HQ– 2010–0682). 
Comment 1: One commenter (–0958) 
objected to the proposed revisions to section 63.655(f) and section 63.655(f)(6) which require facilities to include their NOCS in the periodic report following the compliance activity. The commenter suggested that the EPA revert to the 150-day NOCS 
submission requirements as was included in the December 2015 Rule amendments for the sources listed in Table 11 of 40 CFR part 63, subpart CC, which have a compliance date on or after February 1, 2016. The commenter explained that for petroleum refinery owners and operators completing compliance activities requiring an NOCS in the latter half of the periodic reporting period, as little as 60 days could be provided to perform the test and generate the submission in order to include it in the periodic report. 
Response 1: The proposed revisions 
were specifically included to address the commenter’s original request to align the new compliance notifications with the semiannual periodic reports to reduce burden. As the commenter has withdrawn the request for these revisions, we are not finalizing these proposed revisions. 
Comment 2: One commenter (–0958) 
supported the proposed revision allowing petroleum refinery owners and operators to request an extension for reporting under specified circumstances. One such circumstance is if the EPA’s electronic reporting systems is out-of-service in the five business days prior to the report due date. Proposed revisions in section 63.655(h)(10)(i) and section 63.1575(l)(1) require the extension request to include the date, time, and length of the electronic reporting system outage. The commenter requested that the EPA remove these details from the requirements for the extension request as this is information the EPA, rather than the reporter, keeps. The commenter suggested that the EPA could require reporters to identify the dates on which they attempted to access the system in the 5-day period preceding the reporting due date. 
Response 2: We agree with the 
commenter. While users may know the length of time for a planned outage, as this information is provided to users, it is unlikely that a user will know the length of time for an unplanned outage. However, users will know the dates and times that they attempted but were unable to access the system. Therefore, we have revised the language in section 63.655(h)(10)(i) and section 63.1575(l)(1) to state that owner or operators must provide information on the date(s) and time(s) the Central Data Exchange (CDX) or the CEDRI was unavailable when the user attempted to access it in the 5 business days prior to the submission deadline. 
What is the EPA’s final decision on the 
recordkeeping and reporting provisions? 
In response to the public comments 
received, we are not finalizing the proposed amendments to section 63.655(f) and section 63.655(f)(6) which require facilities to include their NOCS in the periodic report following the compliance activity. 
Also in response to the public 
comments received, we are finalizing the proposed amendment to section 63.655(h)(10) with changes. In the final rule, a refinery owner or operator’s request for an extension must include information on the date(s) and time(s) the CDX or the CEDRI was unavailable when the user attempted to access it in the 5 business days prior to the submission deadline, rather than requiring information regarding the length of the outage. 
We are finalizing the amendments to 
the electric reporting requirements in sections 63.655(f)(1)(i)(B)(3) and (C)(2), (f)(1)(iii), (f)(2), and (f)(4), sections 63.655(h)(9)(i) and (ii), and Table 6— General Provisions Applicability to 40 CFR part 63, subpart CC, as proposed. 
We are finalizing the restoration of 
paragraph 63.655(i)(5), as proposed. We are also finalizing moving paragraph 63.655(h)(5)(iii) to 63.655(i)(3)(ii)(C), as proposed. We are also finalizing the editorial and other corrections in Table 2 of the April 2018 Proposal (83 FR 15470), as proposed. B. Clarifications and Technical 
Corrections to Refinery MACT 2 
1. FCCU Provisions 
What is the history of the FCCU 
provisions addressed in the April 2018 Proposal? 
In order to demonstrate compliance 
with the alternative particulate matter (PM) standard for FCCU as provided at section 63.1564(a)(5)(ii), the outlet (exhaust) gas flow rate of the catalyst regenerator must be determined. As provided in section 63.1573(a), owners or operators may determine this flow 
rate using a flow CPMS or an alternative. Currently, the language in section 63.1573(a) restricts the use of the alternative to occasions when ‘‘the unit does not introduce any other gas streams into the catalyst regenerator vent.’’ API and AFPM (Docket ID No. EPA–HQ–OAR–2010–0682–0915) claim that while this restriction is appropriate for determining the flow rate for applying emissions limitations downstream of the regenerator because additional gases introduced to the vent would not be measured using this method, it is not a necessary constraint for determining compliance with the alternative PM limit. This is because the alternative PM standard applies at the outlet of the regenerator prior to the primary cyclone inlet and this is the flow measured by the alternative in section 63.1573(a). As described in the preamble of the April 2018 Proposal (83 FR 15471). We proposed to amend section 63.1573(a) to remove that restriction. 
Additionally, API and AFPM noted in 
their February 1, 2016, petition (EPA– HQ–OAR–2010–0682–0892) for reconsideration that the FCCU alternative organic HAP standard for startup, shutdown, and hot standby in section 63.1565(a)(5)(ii) requires maintaining the oxygen concentration in the regenerator exhaust gas at or above 1 volume percent (dry) (i.e., greater than 
or equal to 1-percent oxygen (O
2) 
measured on a dry basis); however, they claim process O
2analyzers measure O 2 
on a wet basis. As described in the preamble of the April 2018 Proposal (83 FR 15471), meeting the 1-percent O
2 
standard on a wet basis measurement will always mean that there is more O
2 
than if the concentration value is corrected to a dry basis. As such, we proposed to amend section 63.1565(a)(5)(ii) and Table 10 to allow for the use of a wet O
2measurement for 
demonstrating compliance with the standard so long as it is used directly with no correction for moisture content. 
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The following is a summary of the one 
comment received in response to our 
April 2018 Proposal and our response to this comment on the proposed amendments to the FCCU provisions. 
What comment was received on the 
FCCU provisions? 
Comment 1: One commenter (–0958) 
supported the EPA’s proposed revisions to section 63.1573(a)(1), which allows the use of the inlet velocity requirement during periods of startup, shutdown, and malfunction (SSM) for an FCCU as an alternative to the PM standard regardless of the configuration of the catalytic regenerator exhaust vent stream. The same commenter suggested additional clarifications relative to the alternative PM standard. These clarifications include: 
(1) Amending the last sentence in 
section 63.1573(a)(1) to clarify that the requirement to use the same procedure for performance tests and subsequent monitoring does not apply to the use of the alternative in section 63.1564(c)(5), since the alternative only applies during SSM. 
(2) Revising the first sentence of 
section 63.1573(a)(2) to specifically allow use for demonstrating compliance with section 63.1564(c)(5). 
(3) Amending the footnote to Item 12 
in Table 3 to make it clear that either alternative in (a)(1) or (a)(2) is acceptable for demonstrating compliance. The commenter also recommended providing a separate footnote as other items reference footnote 1. 
(4) Adding the footnote from Item 12 
in Table 3 to Item 10 in Table 7. 
Response 1: We agree with the 
commenter that the last sentence in section 63.1573(a)(1) is provided to ensure that the operating limits are established using the same monitoring techniques as the on-going monitoring. As no site-specific operating limit is required for compliance with section 63.1564(c)(5), that requirement is not applicable to this additional allowance of this alternative. We are revising the language in the final rule to clarify. 
We disagree that it is appropriate to 
revise the first sentence in section 63.1573(a)(2), as requested by the commenter, because the flow rate must be determined based on actual flow conditions, not standard conditions; therefore, Equation 2 in section 63.1573 is not applicable to demonstrate compliance with section 63.1564(c)(5). 
What is the EPA’s final decision on the 
FCCU provisions? 
In consideration of public comments, 
we are finalizing the amendments to the FCCU provisions, as proposed with one change to section 63.1573(a) to clarify that the provision does not apply to the use of the alternative in section 63.1564(c)(5). 
2. Other Provisions 
What is the history of the other Refinery 
MACT 2 provisions addressed in the April 2018 Proposal? 
We proposed several clarifying 
amendments for other Refinery MACT 2 requirements in response to API and AFPM’s petition for reconsideration (Docket ID No. EPA–HQ–OAR–2010– 0682–0892) as well as in response to the API and AFPM’s March 28, 2017, letter (Docket ID No. EPA–HQ–OAR–2010– 0682–0915). 
We proposed to amend section 
63.1572(d)(1) to be consistent with the analogous language in section 63.671(a)(4). 
We proposed to amend the 
recordkeeping requirements in section 63.1576(a)(2)(i) to apply only when facilities elect to comply with the alternative startup and shutdown standards provided in section 63.1564(a)(5)(ii), section 63.1565(a)(5)(ii), or sections 63.1568(a)(4)(ii) or (iii). 
We proposed several amendments for 
electronic reporting including at section 63.1574(a)(3) to clarify that the results of performance tests conducted to demonstrate initial compliance are to be reported by the due date of the NOCS whether the results are reported via CEDRI or in hard copy as part of the NOCS report. If the results are reported via CEDRI, we also proposed to specify that sources need not resubmit those results in the NOCS, but may instead submit information identifying that a performance test or evaluation was conducted and the units and pollutants that were tested. We also proposed to amend the submission of the results of periodic performance tests and the 1- time hydrogen cyanide (HCN) test required in sections 63.1571(a)(5) and (6) to require inclusion with the semiannual compliance reports as specified in section 63.1575(f) instead of within 60 days of completing the performance evaluation. Similarly, we proposed to streamline reporting of the results of performance evaluations and continuous monitoring systems (as provided in item 2 to Table 43) to align with the semiannual compliance reports as specified in section 63.1575(f) rather than requiring a separate submission. We also proposed to add the phrase ‘‘Unless otherwise specified by this subpart’’ to sections 63.1575(k)(1) and (2) to make clear that performance tests or performance evaluations required to 
be reported in a NOCS report or a semiannual compliance report are not subject to the 60-day deadline specified in the paragraphs. We also proposed to add section 63.1575(l) to address extensions to electronic reporting deadlines. We also proposed clarifying amendments to several references in Table 44—Applicability of NESHAP General Provisions to 40 CFR part 63, subpart UUU. 
Finally, we proposed a number of 
editorial and other corrections in Table 3 of the April 2018 Proposal (83 FR 15472). 
The following is a summary of the 
significant comments received in response to our April 2018 Proposal and 
our response to these comments. It should be noted that the comment summary and response for the reporting extension in section 63.655(h)(10)(i) and section 63.1575(l)(1) is addressed in section III.A.8 of this preamble. All other comments related to the proposed amendments for the other Refinery MACT 2 provisions are included in the response to comments document for this final action (Docket ID No. EPA–HQ– 2010–0682). 
What significant comment was received 
on the other Refinery MACT 2 provisions? 
Comment 1: One commenter (–0958) 
recommended that the EPA revise the proposed requirement in section 63.1571(a), (a)(5), (a)(6), and Table 6 Item 1.ii to complete initial PM (or nickel) performance test within 60 days of startup for new units to instead allow for completion and reporting of the performance test by the 150-day notice of compliance status date since a new unit may not be up to full production rates within the first 60 days. 
Response 1: In reviewing the existing 
provisions regarding performance tests in Refinery MACT 2 (40 CFR part 63, subpart UUU), we agree that the initial performance tests are required to be completed and reported no later than 150 days after the compliance date (see section 63.1574(a)(3)(ii)). To better align the proposed revisions with the existing requirements, we are revising the proposed requirement to complete and report these tests no later than 150 days after the compliance date (see section 63.1574(a)(3)(ii)). 
What is the EPA’s final decision on the 
other Refinery MACT 2 provisions? 
After considering public comment, we 
are finalizing these amendments with some revisions to the due dates for initial performance tests in sections 63.1571(a), (a)(5), (a)(6), and Table 6 
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Item 1.ii as well as edits to the proposed 
language in the extensions to electronic reporting provisions in section 63.1575(l) (as described in section III.A.8 of this preamble). We are finalizing the amendments at section 63.1572(d)(1), section 63.1576(a)(2)(i), and Table 3 of the April 2018 Proposal (83 FR 15472), as proposed. 
C. Clarifications and Technical 
Corrections to NSPS Ja 
We proposed three revisions in NSPS 
Ja to improve consistency, remove redundancy, and correct grammar at section 60.105a(b)(2)(ii), section 60.106a(a)(1)(vi), and section 60.106a(a)(1)(iii), respectively. We did not receive public comments on these proposed amendments. We are finalizing these amendments as proposed. 
IV. Summary of Cost, Environmental, 
and Economic Impacts and Additional Analyses Conducted 
As described in the April 2018 
Proposal and associated memorandum titled, ‘‘Projected Cost and Burden Reduction for the Proposed Amendments of the 2015 Risk and Technology Review: Petroleum Refineries,’’ (Docket ID No. EPA–HQ– OAR–2010–0682–0925), the technical corrections and clarifications included in this final rule are expected to result in overall cost and burden reductions. Consistent with the April 2018 Proposal, the final amendments 
expected to reduce burden are: Revisions of the maintenance vent provisions related to the availability of a pure hydrogen supply for equipment containing pyrophoric catalyst, revisions of recordkeeping requirements for maintenance vents associated with equipment containing less than 72 lbs/ day VOC, inclusion of specific provisions for pilot-operated and balanced bellows PRDs, and inclusion of specific provisions related to steam tube air entrainment for flares. The other final amendments included in this rulemaking will have an insignificant effect on the costs or burdens associated with the standards. Additionally, none of the final amendments are projected to appreciably impact the emissions reductions associated with these standards. 
We are finalizing the provisions for 
maintenance vent recordkeeping and PRD as proposed, and, thus, the cost and burden reductions estimated in the April 2018 Proposal and supporting memorandum are still accurate. The final revisions to the recordkeeping requirements for maintenance vents associated with equipment containing less than 72 lbs/day VOC are estimated 
to yield savings of approximately $677,000 per year considering the actual estimated annualized burden of the December 2015 Rule. The final provisions for pilot-operated and balanced bellows PRDs included in this final rulemaking yield a reduction in capital investment of $1.1 million and a reduction in annualized costs of $330,000 per year considering the actual estimated annualized burden of the December 2015 Rule. 
It should be noted that we are 
finalizing amendments to the proposed provisions for maintenance vent provisions related to the availability of a pure hydrogen supply for equipment containing pyrophoric catalyst and provisions related to steam tube air entrainment for flares with revisions as described in sections III.A.2 and III.A.7 of this preamble. The revisions described in sections III.A.2 and III.A.7 are not expected to impact the cost and burden reductions estimated in the referenced April 2018 Proposal and memorandum for these provisions, as they are clarifying in nature. 
As explained in the April 2018 
Proposal, there were no capital costs estimated for the maintenance vent provisions in the December 2015 Rule and only limited recordkeeping and reporting costs. Capital investment estimates provided by industry stakeholders for the maintenance vent provisions included in the December 2015 Rule was approximately $76 million. The inclusion of the capital costs for the maintenance vent provisions would have increased the previously estimated annualized cost included in the December 2015 Rule by $7,174,400 per year. Through the revisions being finalized in this rule, these costs will not be incurred by refinery owners and operators. Similarly, while significant capital and operating costs were projected for flares, we may have underestimated the number of steam-assisted flares that would also have to demonstrate compliance with the NHV
diloperating 
limit in the December 2015 Rule impacts analysis. Considering such flares, the annualized cost of the December 2015 Rule for steam-assisted flares would have increased the previously estimated annualized cost included in the December 2015 Rule by $3,300,000 per year. Through the revisions being finalized in this rulemaking which allows owners or operators of certain steam-assisted flares with air entrainment at the flare tip to comply only with the NHV
czoperating 
limits, these costs will not be incurred 
by refinery owners and operators. V. Statutory and Executive Order 
Reviews 
Additional information about these 
statutes and Executive Orders can be found at https://www.epa.gov/laws- regulations/laws-and-executive-orders. 
A. Executive Order 12866: Regulatory 
Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review 
This action is not a significant 
regulatory action and was, therefore, not submitted to the Office of Management and Budget (OMB) for review. 
B. Executive Order 13771: Reducing 
Regulations and Controlling Regulatory Costs 
This action is considered an 
Executive Order 13771 deregulatory action. Details on the estimated cost savings of this final rule can be found in the EPA’s analysis of the present value and annualized value estimates associated with this action located in Docket ID No. EPA–HQ–OAR–2010– 0682. 
C. Paperwork Reduction Act (PRA) 
The information collection activities 
in this rule have been submitted for 
approval to OMB under the PRA. The ICR document that the EPA prepared has been assigned EPA ICR number 1692.12. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them. 
One of the final technical 
amendments included in this rule impacts the recordkeeping requirements in 40 CFR part 63, subpart CC for certain maintenance vents associated with equipment containing less than 72 lbs/ day VOC as found at 40 CFR 63.655(i)(12)(iv). The new recordkeeping requirement specifies records used to estimate the total quantity of VOC in the equipment and the type and size limits of equipment that contain less than 72 lbs/day of VOC at the time of the maintenance vent opening be maintained. As specified in 
40 CFR 63.655(i)(12)(iv), additional records are required if the inventory procedures were not followed for each maintenance vent opening or if the equipment opened exceeded the type and size limits (i.e., 72 lbs/day VOC). 
These additional records include identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and records used to estimate the total quantity of VOC in the equipment at the 
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time the maintenance vent was opened 
to the atmosphere. These records will assist the EPA with determining compliance with the standards set forth in 40 CFR 63.643(c)(iv). 
Respondents/affected entities: 
Owners or operators of existing or new 
major source petroleum refineries that are major sources of HAP emissions. The NAICS code is 324110 for petroleum refineries. 
Respondent’s obligation to respond: 
All data in the ICR that are recorded are required by the amendments to 40 CFR part 63, subpart CC, National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries. 
Estimated number of respondents: 
142. 
Frequency of response: Once per year 
per respondent. 
Total estimated burden: 16 hours (per 
year). Burden is defined at 5 CFR 1320.3(b). 
Total estimated cost: $1,640 (per 
year), includes $0 annualized capital or operation and maintenance costs. 
An agency may not conduct or 
sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical 
amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. 
D. Regulatory Flexibility Act (RFA) 
I certify that this action will not have 
a significant economic impact on a 
substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden, or otherwise has a positive economic effect on the small entities subject to the rule. The action consists of amendments, clarifications, and technical corrections which are expected to reduce regulatory burden. As described in section IV of this preamble, we expect burden reduction for: (1) Revisions of the maintenance vent provisions related to the availability of a pure hydrogen supply for equipment containing pyrophoric catalyst, (2) revisions of recordkeeping requirements for maintenance vents associated with equipment containing less than 72 lbs/day VOC, (3) inclusion of specific provisions for pilot-operated and balanced bellows PRDs, and (4) inclusion of specific provisions related to steam tube air entrainment for flares. Furthermore, as noted in section IV of this preamble, we do not expect the final amendments to change the expected economic impact analysis performed for the existing rule. We have, therefore, concluded that this action will relieve regulatory burden for all directly regulated small entities. 
E. Unfunded Mandates Reform Act 
(UMRA) 
This action does not contain any 
unfunded mandate as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any state, local, or tribal governments or the private sector. 
F. Executive Order 13132: Federalism 
This action does not have federalism 
implications. It will not have substantial 
direct effects on the states, the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. 
G. Executive Order 13175: Consultation 
and Coordination With Indian Tribal Governments 
This action does not have tribal 
implications as specified in Executive Order 13175. It will not have substantial direct effect 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. 
H. Executive Order 13045: Protection of 
Children From Environmental Health Risks and Safety Risks 
This action is not subject to Executive 
Order 13045 because it is not economically significant as defined in Executive Order 12866, and because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. The final amendments serve to make technical clarifications and corrections, as well as revise compliance dates. We expect the final revisions will have an insignificant effect on emission reductions. Therefore, the final amendments should not appreciably increase risk for any populations. I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use 
This action is not subject to Executive 
Order 13211 because it is not a significant regulatory action under Executive Order 12866. 
J. National Technology Transfer and 
Advancement Act (NTTAA) and 1 CFR Part 51 
This rulemaking involves technical 
standards. As described in section III.C of this preamble, the EPA has decided to use the voluntary consensus standard ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ as an acceptable alternative to EPA Methods 3A and 3B for the manual procedures only and not the instrumental procedures. This method is available at the American National Standards Institute (ANSI), 1899 L Street NW, 11th Floor, Washington, DC 20036 and the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016–5990. See https:// 
wwww.ansi.org and https://
www.asme.org. 
K. Executive Order 12898: Federal 
Actions To Address Environmental Justice in Minority Populations and Low-Income Populations 
The EPA believes that this action does 
not have disproportionately high and adverse human health or environmental effects on minority populations, low income populations, and/or indigenous peoples, as specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The final amendments serve to make technical clarifications and corrections, as well as revise compliance dates. We expect the final technical clarifications and corrections will have an insignificant effect on emission reductions. The additional compliance time provided for existing maintenance vents is expected to have an insignificant effect on emission reductions as many refiners already have measures in place due to state and other federal requirements to minimize emissions during these periods. Further, the maintenance vent opening periods are relatively infrequent and are usually of short duration. Additionally, the final compliance date only provides approximately 6 months beyond the August 1, 2018, compliance date for most facilities, which are operating under 1-year compliance extensions (from the previous deadline of August 1, 2017) they received from states based on the procedure in 40 CFR 63.6(i). Therefore, the final amendments should 
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not appreciably increase risk for any 
populations. 
L. Congressional Review Act (CRA) 
This action is subject to the CRA, and 
the EPA will submit a rule report to 
each House of Congress and to the Comptroller General of the United States. This is not a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). 
List of Subjects 40 CFR Part 60 
Environmental protection, 
Administrative practice and procedures, 
Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. 
40 CFR Part 63 
Environmental protection, 
Administrative practice and procedures, 
Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. 
Dated: November 8, 2018. 
Andrew R. Wheeler, 
Acting Administrator. 
For the reasons stated in the 
preamble, title 40, chapter I, of the Code 
of Federal Regulations is amended as follows: 
PART 60—STANDARDS OF 
PERFORMANCE FOR NEW STATIONARY SOURCES 
■1. The authority citation for part 60 
continues to read as follows: 
Authority: 42 U.S.C. 7401, et seq. 
Subpart A—General Provisions 
■2. Section 60.17 is amended by 
revising paragraph (g)(14) to read as follows: 
§ 60.17 Incorporations by reference. 
* * * * * 
(g) * * * 
(14) ASME/ANSI PTC 19.10–1981, 
Flue and Exhaust Gas Analyses [Part 10, 
Instruments and Apparatus], (Issued August 31, 1981), IBR approved for §§ 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and (j), 60.105a(b), (d), (f), and (g), 60.106a(a), 60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF, table 2 to subpart JJJJ, §§ 60.285a(f), 60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w), 60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM, §§ 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b), and 60.5413a(d). 
* * * * * 
Subpart Ja—Standards of Performance 
for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 
■3. Section 60.105a is amended by 
revising paragraph (b)(2)(ii) to read as follows: 
§ 60.105a Monitoring of emissions and 
operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU). 
* * * * * 
(b) * * * 
(2) * * * (ii) The owner or operator shall 
conduct performance evaluations of 
each CO
2and O 2monitor according to 
the requirements in § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Method 3, 3A or 3B of appendix A–2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. 
* * * * * 
■4. Section 60.106a is amended by 
revising paragraph (a)(1)(iii) to read as 
follows: 
§ 60.106a Monitoring of emissions and 
operations for sulfur recovery plants. 
(a) * * * 
(1) * * * 
(iii) The owner or operator shall 
conduct performance evaluations of 
each SO 2monitor according to the 
requirements in § 60.13(c) and Performance Specification 2 of appendix B to part 60. The owner or operator shall use Method 6 or 6C of appendix A–4 to part 60. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6. 
* * * * * 
PART 63—NATIONAL EMISSION 
STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES 
■5. The authority citation for part 63 
continues to read as follows: 
Authority: 42 U.S.C. 7401 et seq. Subpart CC—National Emission 
Standards for Hazardous Air Pollutants From Petroleum Refineries 
■6. Section 63.641 is amended by: 
■a. Revising the definitions of ‘‘Flare 
purge gas’’ and ‘‘Flare supplemental gas’’; 
■b. Adding a definition of ‘‘Pressure 
relief device’’ in alphabetical order; 
■c. Revising the introductory text and 
adding paragraphs (1)(i) and (ii) to the 
definition of ‘‘Reference control technology for storage vessels’’; and 
■d. Revising the definition of ‘‘Relief 
valve’’. 
The revisions and addition read as 
follows: 
§ 63.641 Definitions. 
* * * * * 
Flare purge gas means gas introduced 
between a flare header’s water seal and the flare tip to prevent oxygen infiltration (backflow) into the flare tip or for other safety reasons. For a flare with no water seal, the function of flare purge gas is performed by flare sweep gas and, therefore, by definition, such a flare has no flare purge gas. 
Flare supplemental gas means all gas 
introduced to the flare to improve the heat content of combustion zone gas. Flare supplemental gas does not include assist air or assist steam. 
* * * * * 
Pressure relief device means a valve, 
rupture disk, or similar device used 
only to release an unplanned, nonroutine discharge of gas from process equipment in order to avoid safety hazards or equipment damage. A pressure relief device discharge can result from an operator error, a malfunction such as a power failure or equipment failure, or other unexpected cause. Such devices include conventional, spring-actuated relief valves, balanced bellows relief valves, pilot-operated relief valves, rupture disks, and breaking, buckling, or shearing pin devices. 
* * * * * 
Reference control technology for 
storage vessels means either: 
(1) * * * 
(i) An internal floating roof, including 
an external floating roof converted to an 
internal floating roof, meeting the specifications of § 63.1063(a)(1)(i), (a)(2), and (b) and § 63.660(b)(2); 
(ii) An external floating roof meeting 
the specifications of § 63.1063(a)(1)(ii), (a)(2), and (b) and § 63.660(b)(2); or 
* * * * * 
Relief valve means a type of pressure 
relief device that is designed to re-close 
after the pressure relief. 
* * * * * 
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■7. Section 63.643 is amended by: 
■a. Revising paragraphs (c) 
introductory text, (c)(1) introductory 
text, and (c)(1)(ii) through (iv); and 
■b. Adding a new paragraph (c)(1)(v). 
The revisions and addition read as 
follows: 
§ 63.643 Miscellaneous process vent 
provisions. 
* * * * * 
(c) An owner or operator may 
designate a process vent as a 
maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed or placed into service. The owner or operator does not need to designate a maintenance vent as a Group 1 or Group 2 miscellaneous process vent nor identify maintenance vents in a Notification of Compliance Status report. The owner or operator must comply with the applicable requirements in paragraphs (c)(1) through (3) of this section for each maintenance vent according to the compliance dates specified in table 11 of this subpart, unless an extension is requested in accordance with the provisions in § 63.6(i). 
(1) Prior to venting to the atmosphere, 
process liquids are removed from the equipment as much as practical and the equipment is depressured to a control device meeting requirements in paragraphs (a)(1) or (2) of this section, a fuel gas system, or back to the process until one of the following conditions, as applicable, is met. 
* * * * * 
(ii) If there is no ability to measure the 
LEL of the vapor in the equipment based 
on the design of the equipment, the pressure in the equipment served by the maintenance vent is reduced to 5 pounds per square inch gauge (psig) or less. Upon opening the maintenance vent, active purging of the equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside the equipment if the maintenance is a hatch or similar type of opening) is less than 10 percent. 
(iii) The equipment served by the 
maintenance vent contains less than 72 pounds of total volatile organic compounds (VOC). 
(iv) If the maintenance vent is 
associated with equipment containing pyrophoric catalyst (e.g., hydrotreaters 
and hydrocrackers) and a pure hydrogen supply is not available at the equipment at the time of the startup, shutdown, maintenance, or inspection activity, the LEL of the vapor in the equipment must be less than 20 percent, except for one event per year not to exceed 35 percent. (v) If, after applying best practices to 
isolate and purge equipment served by a maintenance vent, none of the applicable criterion in paragraphs (c)(1)(i) through (iv) can be met prior to installing or removing a blind flange or similar equipment blind, the pressure in the equipment served by the maintenance vent is reduced to 2 psig or less, Active purging of the equipment may be used provided the equipment pressure at the location where purge gas is introduced remains at 2 psig or less. 
* * * * * 
■8. Section 63.644 is amended by: 
■a. Revising paragraph (c) introductory 
text; 
■b. Removing the period at the end of 
paragraph (c)(2) and adding ‘‘; or’’ in its 
place; and 
■c. Adding paragraph (c)(3). 
The revision and addition read as 
follows: 
§ 63.644 Monitoring provisions for 
miscellaneous process vents. 
* * * * * 
(c) The owner or operator of a Group 
1 miscellaneous process vent using a 
vent system that contains bypass lines that could divert a vent stream away from the control device used to comply with paragraph (a) of this section either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) shall comply with either paragraph (c)(1), (2), or (3) of this section. Use of the bypass at any time to divert a Group 1 miscellaneous process vent stream to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph (c). 
* * * * * 
(3) Use a cap, blind flange, plug, or a 
second valve for an open-ended valve or 
line following the requirements specified in § 60.482–6(a)(2), (b) and (c). 
* * * * * 
■9. Section 63.648 is amended by: 
■a. Revising the introductory text of 
paragraphs (a), (c), and (j); and 
■b. Revising paragraphs (j)(3)(ii)(A) and 
(E), (j)(3)(iv), (j)(3)(v) introductory text, 
and (j)(4). 
The revisions read as follows: 
§ 63.648 Equipment leak standards. 
(a) Each owner or operator of an 
existing source subject to the provisions of this subpart shall comply with the provisions of 40 CFR part 60, subpart VV, and paragraph (b) of this section except as provided in paragraphs (a)(1) through (3), and (c) through (j) of this 
section. Each owner or operator of a new source subject to the provisions of this subpart shall comply with subpart H of this part except as provided in paragraphs (c) through (j) of this section. 
* * * * * 
(c) In lieu of complying with the 
existing source provisions of paragraph 
(a) in this section, an owner or operator may elect to comply with the requirements of §§ 63.161 through 63.169, 63.171, 63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 except as provided in paragraphs (c)(1) through (12) and (e) through (j) of this section. 
* * * * * 
(j) Except as specified in paragraph 
(j)(4) of this section, the owner or 
operator must comply with the requirements specified in paragraphs (j)(1) and (2) of this section for pressure relief devices, such as relief valves or rupture disks, in organic HAP gas or vapor service instead of the pressure relief device requirements of § 60.482–4 or § 63.165, as applicable. Except as specified in paragraphs (j)(4) and (5) of this section, the owner or operator must 
also comply with the requirements specified in paragraph (j)(3) of this section for all pressure relief devices in organic HAP service. 
* * * * * 
(3) * * * 
(ii) * * * (A) Flow, temperature, liquid level 
and pressure indicators with deadman 
switches, monitors, or automatic actuators. Independent, non-duplicative systems within this category count as separate redundant prevention measures. 
* * * * * 
(E) Staged relief system where initial 
pressure relief device (with lower set 
release pressure) discharges to a flare or other closed vent system and control device. 
* * * * * 
(iv) The owner or operator shall 
determine the total number of release 
events occurred during the calendar year for each affected pressure relief device separately. The owner or operator shall also determine the total number of release events for each pressure relief device for which the root cause analysis concluded that the root cause was a force majeure event, as defined in this subpart. 
(v) Except for pressure relief devices 
described in paragraphs (j)(4) and (5) of this section, the following release events from an affected pressure relief device are a violation of the pressure release management work practice standards: 
* * * * * 
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(4) Pressure relief devices routed to a 
control device. (i) If all releases and 
potential leaks from a pressure relief device are routed through a closed vent system to a control device, back into the process or to the fuel gas system, the owner or operator is not required to comply with paragraph (j)(1), (2), or (3) (if applicable) of this section. 
(ii) If a pilot-operated pressure relief 
device is used and the primary release valve is routed through a closed vent system to a control device, back into the process or to the fuel gas system, the owner or operator is required to comply only with paragraphs (j)(1) and (2) of this section for the pilot discharge vent and is not required to comply with paragraph (j)(3) of this section for the pilot-operated pressure relief device. 
(iii) If a balanced bellows pressure 
relief device is used and the primary release valve is routed through a closed vent system to a control device, back into the process or to the fuel gas system, the owner or operator is required to comply only with paragraphs (j)(1) and (2) of this section for the bonnet vent and is not required to comply with paragraph (j)(3) of this section for the balanced bellows pressure relief device. 
(iv) Both the closed vent system and 
control device (if applicable) referenced in paragraphs (j)(4)(i) through (iii) of this section must meet the requirements of § 63.644. When complying with this paragraph (j)(4), all references to ‘‘Group 1 miscellaneous process vent’’ in § 63.644 mean ‘‘pressure relief device.’’ 
(v) If a pressure relief device 
complying with this paragraph (j)(4) is routed to the fuel gas system, then on and after January 30, 2019, any flares receiving gas from that fuel gas system must be in compliance with § 63.670. 
* * * * * 
■10. Section 63.655 is amended by: 
■a. Revising paragraphs (f)(1)(i)(A)(1) 
through (3), (f)(1)(i)(B)(3), (f)(1)(i)(C)(2), 
(f)(1)(iii), (f)(2), (f)(4), (g)(2)(i)(B)(1) and (g)(10) introductory text; 
■b. Redesignating paragraph (g)(10)(iii) 
as (g)(10)(iv); 
■c. Adding new paragraph (g)(10)(iii); 
■d. Revising paragraph (g)(13) 
introductory text and paragraph (h)(2)(ii); 
■e. Removing and reserving paragraph 
(h)(5)(iii); 
■f. Revising paragraph (h)(8) 
■g. Revising paragraph (h)(9)(i) 
introductory text and paragraph (h)(9)(ii) introductory text; 
■h. Adding paragraph (h)(10); 
■i. Revising paragraph (i)(3)(ii)(B); 
■j. Adding paragraphs (i)(3)(ii)(C) and 
(i)(5)(i) through (v); ■k. Revising paragraphs (i)(7)(iii)(B) 
and (i)(11) introductory text; 
■l. Adding paragraph (i)(11)(iv); 
■m. Revising paragraph (i)(12) 
introductory text and paragraph (i)(12)(iv); and 
■n. Adding paragraph (i)(12)(vi). 
The revisions and additions read as 
follows: 
§ 63.655 Reporting and recordkeeping 
requirements. 
* * * * * 
(f) * * * 
(1) * * * (i) * * * (A) * * * (1) For each Group 1 storage vessel 
complying with either § 63.646 or 
§ 63.660 that is not included in an emissions average, the method of compliance (i.e., internal floating roof, 
external floating roof, or closed vent system and control device). 
(2) For storage vessels subject to the 
compliance schedule specified in § 63.640(h)(2) that are not complying with § 63.646 or § 63.660 as applicable, the anticipated compliance date. 
(3) For storage vessels subject to the 
compliance schedule specified in § 63.640(h)(2) that are complying with § 63.646 or § 63.660, as applicable, and the Group 1 storage vessels described in § 63.640(l), the actual compliance date. 
(B) * * * 
(3) If the owner or operator elects to 
submit the results of a performance test, 
identification of the storage vessel and control device for which the performance test will be submitted, and identification of the emission point(s) that share the control device with the storage vessel and for which the performance test will be conducted. If the performance test is submitted electronically through the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI) in accordance with § 63.655(h)(9), the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted may be submitted in the Notification of Compliance Status in lieu of the performance test results. The performance test results must be submitted to CEDRI by the date the Notification of Compliance Status is submitted. 
(C) * * * 
(2) If a performance test is conducted 
instead of a design evaluation, results of 
the performance test demonstrating that the control device achieves greater than or equal to the required control efficiency. A performance test conducted prior to the compliance date of this subpart can be used to comply with this requirement, provided that the test was conducted using EPA methods and that the test conditions are representative of current operating practices. If the performance test is submitted electronically through the EPA’s Compliance and Emissions Data Reporting Interface in accordance with § 63.655(h)(9), the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted may be submitted in the Notification of Compliance Status in lieu of the performance test results. The performance test results must be submitted to CEDRI by the date the Notification of Compliance Status is submitted. 
* * * * * 
(iii) For miscellaneous process vents 
controlled by control devices required 
to be tested under § 63.645 and § 63.116(c), performance test results including the information in paragraphs (f)(1)(iii)(A) and (B) of this section. Results of a performance test conducted prior to the compliance date of this subpart can be used provided that the test was conducted using the methods specified in § 63.645 and that the test conditions are representative of current operating conditions. If the performance test is submitted electronically through the EPA’s Compliance and Emissions Data Reporting Interface in accordance with § 63.655(h)(9), the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted may be submitted in the Notification of Compliance Status in lieu of the performance test results. The performance test results must be submitted to CEDRI by the date the Notification of Compliance Status is submitted. 
* * * * * 
(2) If initial performance tests are 
required by §§ 63.643 through 63.653, 
the Notification of Compliance Status report shall include one complete test report for each test method used for a particular source. On and after February 1, 2016, for data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT website (https://www.epa.gov/electronic- reporting-air-emissions/electronic- reporting-tool-ert) at the time of the test, you must submit the results in accordance with § 63.655(h)(9) by the date that you submit the Notification of Compliance Status, and you must include the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted in the Notification of Compliance Status. All other performance test results must 
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be reported in the Notification of 
Compliance Status. 
* * * * * 
(4) Results of any continuous 
monitoring system performance 
evaluations shall be included in the Notification of Compliance Status report, unless the results are required to be submitted electronically by § 63.655(h)(9). For performance evaluation results required to be submitted through CEDRI, submit the results in accordance with § 63.655(h)(9) by the date that you submit the Notification of Compliance Status and include the process unit where the CMS is installed, the parameter measured by the CMS, and the date that the performance evaluation was conducted in the Notification of Compliance Status. 
* * * * * 
(g) * * * 
(2) * * * (i) * * * (B) * * * (1) A failure is defined as any time in 
which the internal floating roof has 
defects; or the primary seal has holes, tears, or other openings in the seal or the seal fabric; or the secondary seal (if one has been installed) has holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a storage vessel that is part of a new source, the slotted membrane has more than a 10 percent open area. 
* * * * * 
(10) For pressure relief devices subject 
to the requirements § 63.648(j), Periodic 
Reports must include the information specified in paragraphs (g)(10)(i) through (iv) of this section. 
* * * * * 
(iii) For pilot-operated pressure relief 
devices in organic HAP service, report 
each pressure release to the atmosphere through the pilot vent that equals or exceeds 72 pounds of VOC per day, including duration of the pressure release through the pilot vent and estimate of the mass quantity of each organic HAP released. 
* * * * * 
(13) For maintenance vents subject to 
the requirements in § 63.643(c), Periodic 
Reports must include the information specified in paragraphs (g)(13)(i) through (iv) of this section for any release exceeding the applicable limits in § 63.643(c)(1). For the purposes of this reporting requirement, owners or operators complying with § 63.643(c)(1)(iv) must report each venting event for which the lower explosive limit is 20 percent or greater; owners or operators complying with § 63.643(c)(1)(v) must report each venting event conducted under those provisions and include an explanation for each event as to why utilization of this alternative was required. 
* * * * * 
(h) * * * 
(2) * * * (ii) In order to afford the 
Administrator the opportunity to have 
an observer present, the owner or operator of a storage vessel equipped with an external floating roof shall notify the Administrator of any seal gap measurements. The notification shall be made in writing at least 30 calendar days in advance of any gap measurements required by § 63.120(b)(1) or (2) or § 63.1063(d)(3). The State or local permitting authority can waive this notification requirement for all or some storage vessels subject to the rule or can allow less than 30 calendar days’ notice. 
* * * * * 
(8) For fenceline monitoring systems 
subject to § 63.658, each owner or 
operator shall submit the following information to the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI) on a quarterly basis. (CEDRI can be accessed through the EPA’s Central Data Exchange (CDX) (https://cdx.epa.gov/). The first quarterly report must be submitted once the owner or operator has obtained 12 months of data. The first quarterly report must cover the period beginning on the compliance date that is specified in Table 11 of this subpart and ending on March 31, June 30, September 30 or December 31, whichever date is the first date that occurs after the owner or operator has obtained 12 months of data (i.e., the first quarterly report will 
contain between 12 and 15 months of data). Each subsequent quarterly report must cover one of the following reporting periods: Quarter 1 from January 1 through March 31; Quarter 2 from April 1 through June 30; Quarter 3 from July 1 through September 30; and Quarter 4 from October 1 through December 31. Each quarterly report must be electronically submitted no later than 45 calendar days following the end of the reporting period. 
(i) Facility name and address. 
(ii) Year and reporting quarter (i.e., 
Quarter 1, Quarter 2, Quarter 3, or 
Quarter 4). 
(iii) For the first reporting period and 
for any reporting period in which a passive monitor is added or moved, for each passive monitor: The latitude and longitude location coordinates; the sampler name; and identification of the type of sampler (i.e., regular monitor, 
extra monitor, duplicate, field blank, inactive). The owner or operator shall determine the coordinates using an instrument with an accuracy of at least 3 meters. Coordinates shall be in decimal degrees with at least five decimal places. 
(iv) The beginning and ending dates 
for each sampling period. 
(v) Individual sample results for 
benzene reported in units of mg/m
3for 
each monitor for each sampling period that ends during the reporting period. Results below the method detection limit shall be flagged as below the detection limit and reported at the method detection limit. 
(vi) Data flags that indicate each 
monitor that was skipped for the sampling period, if the owner or operator uses an alternative sampling frequency under § 63.658(e)(3). 
(vii) Data flags for each outlier 
determined in accordance with Section 9.2 of Method 325A of appendix A of this part. For each outlier, the owner or operator must submit the individual sample result of the outlier, as well as the evidence used to conclude that the result is an outlier. 
(viii) The biweekly concentration 
difference (Dc) for benzene for each sampling period and the annual average Dc for benzene for each sampling period. 
(9) * * * 
(i) Unless otherwise specified by this 
subpart, within 60 days after the date of 
completing each performance test as required by this subpart, the owner or operator shall submit the results of the performance tests following the procedure specified in either paragraph (h)(9)(i)(A) or (B) of this section. 
* * * * * 
(ii) Unless otherwise specified by this 
subpart, within 60 days after the date of 
completing each CEMS performance evaluation as required by this subpart, the owner or operator must submit the results of the performance evaluation following the procedure specified in either paragraph (h)(9)(ii)(A) or (B) of this section. 
* * * * * 
(10)(i) If you are required to 
electronically submit a report through 
the Compliance and Emissions Data Reporting Interface (CEDRI) in the EPA’s Central Data Exchange (CDX), and due to a planned or actual outage of either the EPA’s CEDRI or CDX systems within the period of time beginning 5 business days prior to the date that the submission is due, you will be or are precluded from accessing CEDRI or CDX 
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and submitting a required report within 
the time prescribed, you may assert a claim of EPA system outage for failure to timely comply with the reporting requirement. You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or caused a delay in reporting. You must provide to the Administrator a written description identifying the date(s) and time(s) the CDX or CEDRI were unavailable when you attempted to access it in the 5 business days prior to the submission deadline; a rationale for attributing the delay in reporting beyond the regulatory deadline to the EPA system outage; describe the measures taken or to be taken to minimize the delay in reporting; and identify a date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported. In any circumstance, the report must be submitted electronically as soon as possible after the outage is resolved. The decision to accept the claim of EPA system outage and allow an extension to the reporting deadline is solely within the discretion of the Administrator. 
(ii) If you are required to 
electronically submit a report through CEDRI in the EPA’s CDX and a force majeure event is about to occur, occurs, or has occurred or there are lingering effects from such an event within the period of time beginning 5 business days prior to the date the submission is due, the owner or operator may assert a claim of force majeure for failure to timely comply with the reporting requirement. For the purposes of this paragraph, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature (e.g., hurricanes, earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility (e.g., large scale 
power outage). If you intend to assert a claim of force majeure, you must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or caused a delay in reporting. You must provide to the Administrator a written description of the force majeure event and a rationale for attributing the delay in reporting beyond the regulatory deadline to the force majeure event; describe the measures taken or to be taken to minimize the delay in reporting; and identify a date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported. In any circumstance, the reporting must occur as soon as possible after the force majeure event occurs. The decision to accept the claim of force majeure and allow an extension to the reporting deadline is solely within the discretion of the Administrator. 
(i) * * * (3) * * * (ii) * * * (B) Block average values for 1 hour or 
shorter periods calculated from all measured data values during each period. If values are measured more frequently than once per minute, a single value for each minute may be used to calculate the hourly (or shorter period) block average instead of all measured values; or 
(C) All values that meet the set criteria 
for variation from previously recorded values using an automated data compression recording system. 
(1) The automated data compression 
recording system shall be designed to: 
(i) Measure the operating parameter 
value at least once every hour. 
(ii) Record at least 24 values each day 
during periods of operation. 
(iii) Record the date and time when 
monitors are turned off or on. 
(iv) Recognize unchanging data that 
may indicate the monitor is not functioning properly, alert the operator, and record the incident. 
(v) Compute daily average values of 
the monitored operating parameter based on recorded data. 
(2) You must maintain a record of the 
description of the monitoring system and data compression recording system including the criteria used to determine which monitored values are recorded and retained, the method for calculating daily averages, and a demonstration that the system meets all criteria of paragraph (i)(3)(ii)(C)(1) of this section. 
* * * * * 
(5) * * * 
(i) Identification of all petroleum 
refinery process unit heat exchangers at the facility and the average annual HAP concentration of process fluid or intervening cooling fluid estimated when developing the Notification of Compliance Status report. 
(ii) Identification of all heat exchange 
systems subject to the monitoring requirements in § 63.654 and identification of all heat exchange systems that are exempt from the monitoring requirements according to the provisions in § 63.654(b). For each heat exchange system that is subject to the monitoring requirements in § 63.654, this must include identification of all heat exchangers within each heat exchange system, and, for closed-loop recirculation systems, the cooling tower included in each heat exchange system. 
(iii) Results of the following 
monitoring data for each required monitoring event: 
(A) Date/time of event. 
(B) Barometric pressure. (C) El Paso air stripping apparatus 
water flow milliliter/minute (ml/min) 
and air flow, ml/min, and air temperature, °Celsius. 
(D) FID reading (ppmv). 
(E) Length of sampling period. 
(F) Sample volume. (G) Calibration information identified 
in Section 5.4.2 of the ‘‘Air Stripping 
Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources’’ Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003 (incorporated by reference—see § 63.14). 
(iv) The date when a leak was 
identified, the date the source of the leak was identified, and the date when the heat exchanger was repaired or taken out of service. 
(v) If a repair is delayed, the reason 
for the delay, the schedule for completing the repair, the heat exchange exit line flow or cooling tower return line average flow rate at the monitoring location (in gallons/minute), and the estimate of potential strippable hydrocarbon emissions for each required monitoring interval during the delay of repair. 
* * * * * 
(7) * * * 
(iii) * * * (B) The pressure or temperature of the 
coke drum vessel, as applicable, for the 
5-minute period prior to the pre-vent draining. 
* * * * * 
(11) For each pressure relief device 
subject to the pressure release 
management work practice standards in § 63.648(j)(3), the owner or operator shall keep the records specified in paragraphs (i)(11)(i) through (iii) of this section. For each pilot-operated pressure relief device subject to the 
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requirements at § 63.648(j)(4)(ii) or (iii), 
the owner or operator shall keep the records specified in paragraph (i)(11)(iv) 
of this section. 
* * * * * 
(iv) For pilot-operated pressure relief 
devices, general or release-specific 
records for estimating the quantity of VOC released from the pilot vent during a release event, and records of calculations used to determine the quantity of specific HAP released for any event or series of events in which 72 or more pounds of VOC are released in a day. 
(12) For each maintenance vent 
opening subject to the requirements in § 63.643(c), the owner or operator shall keep the applicable records specified in paragraphs (i)(12)(i) through (vi) of this section. 
* * * * * 
(iv) If complying with the 
requirements of § 63.643(c)(1)(iii), 
records used to estimate the total quantity of VOC in the equipment and the type and size limits of equipment that contain less than 72 pounds of VOC at the time of maintenance vent opening. For each maintenance vent opening for which the deinventory procedures specified in paragraph (i)(12)(i) of this section are not followed or for which the equipment opened exceeds the type and size limits established in the records specified in this paragraph, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere. 
* * * * * 
(vi) If complying with the 
requirements of § 63.643(c)(1)(v), 
identification of the maintenance vent, the process units or equipment associated with the maintenance vent, records documenting actions taken to comply with other applicable alternatives and why utilization of this alternative was required, the date of maintenance vent opening, the equipment pressure and lower explosive limit of the vapors in the equipment at the time of discharge, an indication of whether active purging was performed and the pressure of the equipment during the installation or removal of the blind if active purging was used, the duration the maintenance vent was open during the blind installation or removal process, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere for each applicable maintenance vent opening. 
* * * * * 
■11. Section 63.657 is amended by 
revising paragraphs (a)(1)(i) and (ii), 
(a)(2)(i) and (ii), (b)(5), and (e) to read as follows: 
§ 63.657 Delayed coking unit decoking 
operation standards. 
(a) * * * 
(1) * * * (i) An average vessel pressure of 2 
psig or less determined on a rolling 60- 
event average; or 
(ii) An average vessel temperature of 
220 degrees Fahrenheit or less determined on a rolling 60-event average. 
(2) * * * 
(i) A vessel pressure of 2.0 psig or less 
for each decoking event; or 
(ii) A vessel temperature of 218 
degrees Fahrenheit or less for each 
decoking event. 
* * * * * 
(b) * * * 
(5) The output of the pressure 
monitoring system must be reviewed 
each day the unit is operated to ensure that the pressure readings fluctuate as expected between operating and cooling/decoking cycles to verify the pressure taps are not plugged. Plugged pressure taps must be unplugged or otherwise repaired prior to the next operating cycle. 
* * * * * 
(e) The owner or operator of a delayed 
coking unit using the ‘‘water overflow’’ 
method of coke cooling prior to complying with the applicable requirements in paragraph (a) of this section must meet the requirements in either paragraph (e)(1) or (e)(2) of this section or, if applicable, the requirements in paragraph (e)(3) of this section. The owner or operator of a delayed coking unit using the ‘‘water overflow’’ method of coke cooling subject to this paragraph shall determine the coke drum vessel temperature as specified in paragraphs (c) and (d) of this section and shall not otherwise drain or vent the coke drum until the coke drum vessel temperature is at or below the applicable limits in paragraph (a)(1)(ii) or (a)(2)(ii) of this section. 
(1) The overflow water must be 
directed to a separator or similar disengaging device that is operated in a manner to prevent entrainment of gases from the coke drum vessel to the overflow water storage tank. Gases from the separator or disengaging device must be routed to a closed blowdown system or otherwise controlled following the requirements for a Group 1 miscellaneous process vent. The liquid from the separator or disengaging device must be hardpiped to the overflow water storage tank or similarly transported to prevent exposure of the overflow water to the atmosphere. The overflow water storage tank may be an open or uncontrolled fixed-roof tank provided that a submerged fill pipe (pipe outlet below existing liquid level in the tank) is used to transfer overflow water to the tank. 
(2) The overflow water must be 
directed to a storage vessel meeting the requirements for storage vessels in subpart SS of this part. 
(3) Prior to November 26, 2020, if the 
equipment needed to comply with paragraphs (e)(1) or (2) of this section are not installed and operational, you must comply with all of the requirements in paragraphs (e)(3)(i) through (iv) of this section. 
(i) The temperature of the coke drum, 
measured according to paragraph (c) of this section, must be 250 degrees Fahrenheit or less prior to initiation of water overflow and at all times during the water overflow. 
(ii) The overflow water must be 
hardpiped to the overflow water storage tank or similarly transported to prevent exposure of the overflow water to the atmosphere. 
(iii) The overflow water storage tank 
may be an open or uncontrolled fixed- roof tank provided that all of the following requirements are met. 
(A) A submerged fill pipe (pipe outlet 
below existing liquid level in the tank) is used to transfer overflow water to the tank. 
(B) The liquid level in the storage tank 
is at least 6 feet above the submerged fill pipe outlet at all times during water overflow. 
(C) The temperature of the contents in 
the storage tank remain below 150 degrees Fahrenheit at all times during water overflow. 
* * * * * 
■12. Section 63.658 is amended by 
revising paragraphs (c)(1), (2) and (3), 
(d)(1) introductory text and (d)(2), (e) introductory text, (e)(3)(iv), (f)(1)(i) introductory text, and (f)(1)(i)(B) to read as follows: 
§ 63.658 Fenceline monitoring provisions. 
* * * * * 
(c) * * * (1) As it pertains to this subpart, 
known sources of VOCs, as used in Section 8.2.1.3 in Method 325A of appendix A of this part for siting passive monitors, means a wastewater 
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treatment unit, process unit, or any 
emission source requiring control according to the requirements of this subpart, including marine vessel loading operations. For marine vessel loading operations, one passive monitor should be sited on the shoreline adjacent to the dock. For this subpart, an additional monitor is not required if the only emission sources within 50 meters of the monitoring boundary are equipment leak sources satisfying all of the conditions in paragraphs (c)(1)(i) through (iv) of this section. 
(i) The equipment leak sources in 
organic HAP service within 50 meters of the monitoring boundary are limited to valves, pumps, connectors, sampling connections, and open-ended lines. If compressors, pressure relief devices, or agitators in organic HAP service are present within 50 meters of the monitoring boundary, the additional passive monitoring location specified in Section 8.2.1.3 in Method 325A of appendix A of this part must be used. 
(ii) All equipment leak sources in gas 
or light liquid service (and in organic HAP service), including valves, pumps, connectors, sampling connections and open-ended lines, must be monitored using EPA Method 21 of 40 CFR part 60, appendix A–7 no less frequently than quarterly with no provisions for skip period monitoring, or according to the provisions of § 63.11(c) Alternative Work practice for monitoring equipment for leaks. For the purpose of this provision, a leak is detected if the instrument reading equals or exceeds the applicable limits in paragraphs (c)(1)(ii)(A) through (E) of this section: 
(A) For valves, pumps or connectors 
at an existing source, an instrument reading of 10,000 ppmv. 
(B) For valves or connectors at a new 
source, an instrument reading of 500 ppmv. 
(C) For pumps at a new source, an 
instrument reading of 2,000 ppmv. 
(D) For sampling connections or open- 
ended lines, an instrument reading of 500 ppmv above background. 
(E) For equipment monitored 
according to the Alternative Work practice for monitoring equipment for leaks, the leak definitions contained in § 63.11 (c)(6)(i) through (iii). 
(iii) All equipment leak sources in 
organic HAP service, including sources in gas, light liquid and heavy liquid service, must be inspected using visual, audible, olfactory, or any other detection method at least monthly. A leak is detected if the inspection identifies a potential leak to the atmosphere or if there are indications of liquids dripping. (iv) All leaks identified by the 
monitoring or inspections specified in paragraphs (c)(1)(ii) or (iii) of this section must be repaired no later than 15 calendar days after it is detected with no provisions for delay of repair. If a repair is not completed within 15 calendar days, the additional passive monitor specified in Section 8.2.1.3 in Method 325A of appendix A of this part must be used. 
(2) The owner or operator may collect 
one or more background samples if the owner or operator believes that an offsite upwind source or an onsite source excluded under § 63.640(g) may influence the sampler measurements. If the owner or operator elects to collect one or more background samples, the owner or operator must develop and submit a site-specific monitoring plan for approval according to the requirements in paragraph (i) of this section. Upon approval of the site- specific monitoring plan, the background sampler(s) should be operated co-currently with the routine samplers. 
(3) If there are 19 or fewer monitoring 
locations, the owner or operator shall collect at least one co-located duplicate sample per sampling period and at least one field blank per sampling period. If there are 20 or more monitoring locations, the owner or operator shall collect at least two co-located duplicate samples per sampling period and at least one field blank per sampling period. The co-located duplicates may be collected at any of the perimeter sampling locations. 
* * * * * 
(d) * * * 
(1) If a near-field source correction is 
used as provided in paragraph (i)(2) of 
this section or if an alternative test method is used that provides time- resolved measurements, the owner or operator shall: 
* * * * * 
(2) For cases other than those 
specified in paragraph (d)(1) of this 
section, the owner or operator shall collect and record sampling period average temperature and barometric pressure using either an on-site meteorological station in accordance with Section 8.3.1 through 8.3.3 of Method 325A of appendix A of this part or, alternatively, using data from a United States Weather Service (USWS) meteorological station provided the USWS meteorological station is within 40 kilometers (25 miles) of the refinery. 
* * * * * 
(e) The owner or operator shall use a 
sampling period and sampling frequency as specified in paragraphs 
(e)(1) through (3) of this section. 
* * * * * 
(3) * * * 
(iv) If every sample at a monitoring 
site that is monitored at the frequency 
specified in paragraph (e)(3)(iii) of this section is at or below 0.9 mg/m
3for 2 
years (i.e., 4 consecutive semiannual 
samples), only one sample per year is required for that monitoring site. For yearly sampling, samples shall occur at least 10 months but no more than 14 months apart. 
* * * * * 
(f) * * * 
(1) * * * 
(i) Except when near-field source 
correction is used as provided in 
paragraph (i) of this section, the owner or operator shall determine the highest and lowest sample results for benzene concentrations from the sample pool and calculate Dc as the difference in these concentrations. Co-located samples must be averaged together for the purposes of determining the benzene concentration for that sampling location, and, if applicable, for determining Dc. The owner or operator 
shall adhere to the following procedures when one or more samples for the sampling period are below the method detection limit for benzene: 
* * * * * 
(B) If all sample results are below the 
method detection limit, the owner or 
operator shall use the method detection limit as the highest sample result and zero as the lowest sample result when calculating Dc. 
* * * * * 
■13. Section 63.660 is amended by 
revising the introductory text, paragraph (b) introductory text, paragraphs (b)(1) and (e), and paragraph (i)(2) introductory text, and adding paragraph (i)(2)(iii) to read as follows: 
§ 63.660 Storage vessel provisions. 
On and after the applicable 
compliance date for a Group 1 storage vessel located at a new or existing source as specified in § 63.640(h), the owner or operator of a Group 1 storage vessel storing liquid with a maximum true vapor pressure less than 76.6 kilopascals (11.1 pounds per square inch) that is part of a new or existing source shall comply with either the requirements in subpart WW or SS of this part according to the requirements in paragraphs (a) through (i) of this section and the owner or operator of a Group 1 storage vessel storing liquid with a maximum true vapor pressure greater than or equal to 76.6 kilopascals (11.1 pounds per square inch) that is 
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part of a new or existing source shall 
comply with the requirements in subpart SS of this part according to the requirements in paragraphs (a) through (i) of this section. 
* * * * * 
(b) A floating roof storage vessel 
complying with the requirements of 
subpart WW of this part may comply with the control option specified in paragraph (b)(1) of this section and, if equipped with a ladder having at least one slotted leg, shall comply with one of the control options as described in paragraph (b)(2) of this section. If the 
floating roof storage vessel does not meet the requirements of § 63.1063(a)(2)(i) through (a)(2)(viii) as of June 30, 2014, these requirements do not apply until the next time the vessel is completely emptied and degassed, or January 30, 2026, whichever occurs first. 
(1) In addition to the options 
presented in §§ 63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage vessel may comply with § 63.1063(a)(2)(viii) using a flexible enclosure device and either a gasketed or welded cap on the top of the guidepole. 
* * * * * 
(e) For storage vessels previously 
subject to requirements in § 63.646, 
initial inspection requirements in § 63.1063(c)(1) and (c)(2)(i) (i.e., those 
related to the initial filling of the storage vessel) or in § 63.983(b)(1)(i)(A), as applicable, are not required. Failure to perform other inspections and monitoring required by this section shall constitute a violation of the applicable standard of this subpart. 
* * * * * 
(i) * * * 
(2) If a closed vent system contains a 
bypass line, the owner or operator shall 
comply with the provisions of either § 63.983(a)(3)(i) or (ii) or paragraph (iii) of this section for each closed vent system that contains bypass lines that could divert a vent stream either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part. Except as provided in paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any time to divert a Group 1 storage vessel either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph (i)(2). 
* * * * * (iii) Use a cap, blind flange, plug, or 
a second valve for an open-ended valves 
or line following the requirements specified in § 60.482–6(a)(2), (b) and (c). 
* * * * * 
■14. Section 63.670 is amended by: 
■a. Revising paragraph (f); 
■b. Revising paragraphs (h) 
introductory text, (h)(1), and (i) 
introductory text; 
■c. Adding paragraphs (i)(5) and (6); 
■d. Revising paragraph (j)(6) 
introductory text; 
■e. Revising the definition of the Q cum 
term in the equation in paragraph (k)(3); 
■f. Revising paragraph (m)(2) 
introductory text; 
■g. Revising the definitions of the Q NG2, 
QNG1, and NHV NGterms in the equation 
in paragraph (m)(2); 
■h. Revising paragraph (n)(2) 
introductory text; 
■i. Revising the definitions of the Q NG2, 
QNG1, and NHV NGterms in the equation 
in paragraph (n)(2); and 
■j. Revising paragraphs (o) introductory 
text, (o)(1)(ii)(B), (o)(1)(iii)(B), and (o)(3)(i). 
The revisions and additions read as 
follows: 
§ 63.670 Requirements for flare control 
devices. 
* * * * * 
(f) Dilution operating limits for flares 
with perimeter assist air. Except as 
provided in paragraph (f)(1) of this section, for each flare actively receiving perimeter assist air, the owner or operator shall operate the flare to maintain the net heating value dilution parameter (NHVdil) at or above 22 British thermal units per square foot (Btu/ft
2) determined on a 15-minute 
block period basis when regulated material is being routed to the flare for at least 15-minutes. The owner or operator shall monitor and calculate NHV
dilas specified in paragraph (n) of 
this section. 
(1) If the only assist air provided to a 
specific flare is perimeter assist air intentionally entrained in lower and/or upper steam at the flare tip and the effective diameter is 9 inches or greater, the owner or operator shall comply only with the NHV
czoperating limit in 
paragraph (e) of this section for that flare. 
(2) [Reserved] 
* * * * * 
(h) Visible emissions monitoring. The 
owner or operator shall conduct an initial visible emissions demonstration using an observation period of 2 hours using Method 22 at 40 CFR part 60, appendix A–7. The initial visible emissions demonstration should be conducted the first time regulated materials are routed to the flare. Subsequent visible emissions observations must be conducted using either the methods in paragraph (h)(1) of this section or, alternatively, the methods in paragraph (h)(2) of this section. The owner or operator must record and report any instances where visible emissions are observed for more than 5 minutes during any 2 consecutive hours as specified in § 63.655(g)(11)(ii). 
(1) At least once per day for each day 
regulated material is routed to the flare, conduct visible emissions observations using an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A–7. If at any time the owner or operator sees visible emissions while regulated material is routed to the flare, even if the minimum required daily visible emission monitoring has already been performed, the owner or operator shall immediately begin an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A–7. If visible emissions are observed for more than one continuous minute during any 5-minute observation period, the observation period using Method 22 at 40 CFR part 60, appendix A–7 must be extended to 2 hours or until 5- minutes of visible emissions are observed. Daily 5-minute Method 22 observations are not required to be conducted for days the flare does not receive any regulated material. 
* * * * * 
(i) Flare vent gas, steam assist and air 
assist flow rate monitoring. The owner 
or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volumetric flow rate in the flare header or headers that feed the flare as well as any flare supplemental gas used. Different flow monitoring methods may be used to measure different gaseous streams that make up the flare vent gas provided that the flow rates of all gas streams that contribute to the flare vent gas are determined. If assist air or assist steam is used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volumetric flow rate of assist air and/or assist steam used with the flare. If pre-mix assist air and perimeter assist are both used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of separately measuring, calculating, and recording the volumetric flow rate of premix assist air and perimeter assist air used with the 
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flare. Flow monitoring system 
requirements and acceptable alternatives are provided in paragraphs (i)(1) through (6) of this section. 
* * * * * 
(5) Continuously monitoring fan 
speed or power and using fan curves is 
an acceptable method for continuously monitoring assist air flow rates. 
(6) For perimeter assist air 
intentionally entrained in lower and/or upper steam, the monitored steam flow rate and the maximum design air-to- steam volumetric flow ratio of the entrainment system may be used to determine the assist air flow rate. 
(j) * * * 
(6) Direct compositional or net 
heating value monitoring is not required 
for gas streams that have been demonstrated to have consistent composition (or a fixed minimum net heating value) according to the methods in paragraphs (j)(6)(i) through (iii) of this section. 
* * * * * 
(k) * * * 
(3) * * * 
* * * * * 
Qcum= Cumulative volumetric flow over 15- 
minute block average period, standard 
cubic feet. 
* * * * * 
(m) * * * 
(2) Owners or operators of flares that 
use the feed-forward calculation 
methodology in paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor flare supplemental gas flow additions to the flare must determine the 15-minute block average 
NHV
czusing the following equation. 
* * * * * 
QNG2= Cumulative volumetric flow of flare 
supplemental gas during the 15-minute block period, scf. 
Q
NG1= Cumulative volumetric flow of flare 
supplemental gas during the previous 15-minute block period, scf. For the first 15-minute block period of an event, use the volumetric flow value for the current 15-minute block period, i.e., Q
NG1= 
QNG2. 
NHV NG= Net heating value of flare 
supplemental gas for the 15-minute block period determined according to the requirements in paragraph (j)(5) of this section, Btu/scf. 
* * * * * 
(n) * * * 
(2) Owners or operators of flares that 
use the feed-forward calculation 
methodology in paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor flare supplemental gas flow additions to the flare must determine the 15-minute block average NHV
dilusing the following equation 
only during periods when perimeter 
assist air is used. For 15-minute block periods when there is no cumulative volumetric flow of perimeter assist air, the 15-minute block average NHV
dil 
parameter does not need to be calculated. 
* * * * * 
QNG2= Cumulative volumetric flow of flare 
supplemental gas during the 15-minute 
block period, scf. 
QNG1= Cumulative volumetric flow of flare 
supplemental gas during the previous 15-minute block period, scf. For the first 15-minute block period of an event, use the volumetric flow value for the current 15-minute block period, i.e., Q
NG1= 
QNG2. 
NHV NG= Net heating value of flare 
supplemental gas for the 15-minute 
block period determined according to the requirements in paragraph (j)(5) of this section, Btu/scf. 
* * * * * 
(o) Emergency flaring provisions. The 
owner or operator of a flare that has the 
potential to operate above its smokeless capacity under any circumstance shall comply with the provisions in paragraphs (o)(1) through (7) of this section. 
(1) * * * 
(ii) * * * (B) Implementation of prevention 
measures listed for pressure relief 
devices in § 63.648(j)(3)(ii)(A) through (E) for each pressure relief device that can discharge to the flare. 
* * * * * 
(iii) * * * 
(B) The smokeless capacity of the flare 
based on a 15-minute block average and 
design conditions. Note: A single value 
must be provided for the smokeless capacity of the flare. 
* * * * * 
(3) * * * 
(i) The vent gas flow rate exceeds the 
smokeless capacity of the flare based on 
a 15-minute block average and visible emissions are present from the flare for more than 5 minutes during any 2 consecutive hours during the release event. 
* * * * * 
■15. Table 6 to Subpart CC is amended 
by revising the entries ‘‘63.6(f)(3)’’, 
‘‘63.6(h)(8)’’, 63.7(a)(2)’’, ‘‘63.7(f)’’, ‘‘63.7(h)(3)’’, and ‘‘63.8(e)’’ to read as follows: 
TABLE 6—G ENERAL PROVISIONS APPLICABILITY TO SUBPART CCa 
Reference Applies 
to subpart CC Comment 
*******  
63.6(f)(3) ........... Yes ................... Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to § 63.642(n) and performance test 
results may be written or electronic. 
*******  
63.6(h)(8) .......... Yes ................... Except performance test results may be written or electronic. 
*******  
63.7(a)(2) .......... Yes ................... Except test results must be submitted in the Notification of Compliance Status report due 150 days after 
compliance date, as specified in § 63.655(f), unless they are required to be submitted electronically in 
accordance with § 63.655(h)(9). Test results required to be submitted electronically must be submitted by the date the Notification of Compliance Status report is submitted. 
*******  
63.7(f) ............... Yes ................... Except that additional notification or approval is not required for alternatives directly specified in Subpart 
CC. 
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TABLE 6—G ENERAL PROVISIONS APPLICABILITY TO SUBPART CCa—Continued 
Reference Applies 
to subpart CC Comment 
*******  
63.7(h)(3) .......... Yes ................... Yes, except site-specific test plans shall not be required, and where § 63.7(h)(3)(i) specifies waiver sub-
mittal date, the date shall be 90 days prior to the Notification of Compliance Status report in § 63.655(f). 
*******  
63.8(e) .............. Yes ................... Except that results are to be submitted electronically if required by § 63.655(h)(9).  
*******  
■16. Table 11 to subpart CC is amended 
by revising items (2)(iv), (3)(iv) and 
(4)(v) to read as follows: 
TABLE 11—C OMPLIANCE DATES AND REQUIREMENTS  
If the construction/ 
reconstruction date is ...  Then the owner or operator must comply with . . . And the owner or operator must achieve compliance . . . Except as provided in . . . 
*******  
(2) * * * ..................... (iv) Requirements for existing sources 
in § 63.643(c).On or before December 26, 2018 ....... §§ 63.640(k), (l) and (m) and 
63.643(d). 
*******  
(3) * * * ..................... (iv) Requirements for existing sources 
in § 63.643(c).On or before December 26, 2018 ....... §§ 63.640(k), (l) and (m) and 
63.643(d). 
*******  
(4) * * * ..................... (v) Requirements for existing sources 
in § 63.643(c).On or before December 26, 2018 ....... §§ 63.640(k), (l) and (m) and 
63.643(d). 
*******  
■17. Table 13 to Subpart CC is 
amended by revising the entry 
‘‘Hydrogen analyzer’’ to read as follows: 
TABLE 13—C ALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS 
Parameter Minimum accuracy 
requirements Calibration requirements 
*******  
Hydrogen analyzer ..... ±2 percent over the concentration 
measured or 0.1 volume percent, 
whichever is greater.Specify calibration requirements in your site specific CPMS monitoring plan. 
Calibration requirements should follow manufacturer’s recommendations at a minimum. 
Where feasible, select the sampling location at least two equivalent duct diam-
eters from the nearest control device, point of pollutant generation, air in- leakages, or other point at which a change in the pollutant concentration oc-curs. 
Subpart UUU-–National Emission 
Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units 
■18. Section 63.1564 is amended by 
revising the introductory text of 
paragraphs (b)(4)(iii), (c)(3), and (c)(4) and revising paragraph (c)(5)(iii) to read as follows: § 63.1564 What are my requirements for 
metal HAP emissions from catalytic cracking units? 
* * * * * 
(b) * * * 
(4) * * * 
(iii) If you elect Option 3 in paragraph 
(a)(1)(v) of this section, the Ni lb/hr 
emission limit, compute your Ni emission rate using Equation 5 of this section and your site-specific Ni operating limit (if you use a continuous opacity monitoring system) using Equations 6 and 7 of this section as follows: 
* * * * * 
(c) * * * 
(3) If you use a continuous opacity 
monitoring system and elect to comply 
with Option 3 in paragraph (a)(1)(v) of this section, determine continuous compliance with your site-specific Ni 
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operating limit by using Equation 11 of 
this section as follows: 
* * * * * 
(4) If you use a continuous opacity 
monitoring system and elect to comply 
with Option 4 in paragraph (a)(1)(vi) of this section, determine continuous compliance with your site-specific Ni operating limit by using Equation 12 of this section as follows: 
* * * * * 
(5) * * * 
(iii) Calculating the inlet velocity to 
the primary internal cyclones in feet per 
second (ft/sec) by dividing the average volumetric flow rate (acfm) by the cumulative cross-sectional area of the primary internal cyclone inlets (ft
2) and 
by 60 seconds/minute (for unit conversion). 
* * * * * 
■19. Section 63.1565 is amended by 
revising paragraph (a)(5)(ii) to read as 
follows: 
§ 63.1565 What are my requirements for 
organic HAP emissions from catalytic cracking units? 
(a) * * * 
(5) * * * (ii) You can elect to maintain the 
oxygen (O
2) concentration in the 
exhaust gas from your catalyst 
regenerator at or above 1 volume percent (dry basis) or 1 volume percent (wet basis with no moisture correction). 
* * * * * 
■20. Section 63.1569 is amended by 
revising paragraph (c)(2) to read as 
follows: 
§ 63.1569 What are my requirements for 
HAP emissions from bypass lines? 
* * * * * 
(c) * * * 
(2) Demonstrate continuous 
compliance with the work practice 
standard in paragraph (a)(3) of this section by complying with the procedures in your operation, maintenance, and monitoring plan. 
■21. Section 63.1571 is amended by 
revising the introductory text of paragraphs (a), (a)(5) and (a)(6), and by revising the introductory text of paragraphs (d)(1) and (d)(2) to read as follows: 
§ 63.1571 How and when do I conduct a 
performance test or other initial compliance demonstration? 
(a) When must I conduct a 
performance test? You must conduct 
initial performance tests and report the results by no later than 150 days after the compliance date specified for your source in § 63.1563 and according to the provisions in § 63.7(a)(2) and § 63.1574(a)(3). If you are required to do 
a performance evaluation or test for a semi-regenerative catalytic reforming unit catalyst regenerator vent, you may do them at the first regeneration cycle after your compliance date and report the results in a followup Notification of Compliance Status report due no later than 150 days after the test. You must conduct additional performance tests as specified in paragraphs (a)(5) and (6) of this section and report the results of these performance tests according to the 
provisions in § 63.1575(f). 
* * * * * 
(5) Periodic performance testing for 
PM or Ni. Except as provided in 
paragraphs (a)(5)(i) and (ii) of this section, conduct a periodic performance test for PM or Ni for each catalytic cracking unit at least once every 5 years according to the requirements in Table 4 of this subpart. You must conduct the first periodic performance test no later than August 1, 2017 or within 150 days of startup of a new unit. 
* * * * * 
(6) One-time performance testing for 
Hydrogen Cyanide (HCN). Conduct a 
performance test for HCN from each catalytic cracking unit no later than August 1, 2017 or within 150 days of startup of a new unit according to the applicable requirements in paragraphs (a)(6)(i) and (ii) of this section. 
* * * * * 
(d) * * * 
(1) If you must meet the HAP metal 
emission limitations in § 63.1564, you 
elect the option in paragraph (a)(1)(v) in § 63.1564 (Ni lb/hr), and you use continuous parameter monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial performance test. Section 63.1564(b)(2) allows you to adjust the laboratory measurements of the equilibrium catalyst Ni concentration to the maximum level. You must make this adjustment using Equation 1 of this section as follows: 
* * * * * 
(2) If you must meet the HAP metal 
emission limitations in § 63.1564, you 
elect the option in paragraph (a)(1)(vi) in § 63.1564 (Ni per coke burn-off), and you use continuous parameter monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial performance test. Section 63.1564(b)(2) allows you to adjust the laboratory measurements of the equilibrium catalyst Ni concentration to the maximum level. You must make this adjustment using Equation 2 of this section as follows: 
* * * * * 
■22. Section 63.1572 is amended by 
revising paragraphs (c)(1) and (d)(1) to 
read as follows: 
§ 63.1572 What are my monitoring 
installation, operation, and maintenance requirements? 
* * * * * 
(c) * * * 
(1) You must install, operate, and 
maintain each continuous parameter 
monitoring system according to the requirements in Table 41 of this subpart. You must also meet the equipment specifications in Table 41 of this subpart if pH strips or colormetric tube sampling systems are used. You must meet the requirements in Table 41 of this subpart for BLD systems. Alternatively, before August 1, 2017, you may install, operate, and maintain each continuous parameter monitoring system in a manner consistent with the manufacturer’s specifications or other written procedures that provide adequate assurance that the equipment will monitor accurately. 
* * * * * 
(d) * * * 
(1) Except for monitoring 
malfunctions, associated repairs, and 
required quality assurance or control activities (including as applicable, calibration checks and required zero and span adjustments), you must conduct all monitoring in continuous operation (or collect data at all required intervals) at all times the affected source is operating. 
* * * * * 
■23. Section 63.1573 is amended by 
revising paragraph (a)(1) introductory 
text to read as follows: 
§ 63.1573 What are my monitoring 
alternatives? 
(a) * * * (1) You may use this 
alternative to a continuous parameter 
monitoring system for the catalytic regenerator exhaust gas flow rate for your catalytic cracking unit if the unit does not introduce any other gas streams into the catalyst regeneration vent (i.e., complete combustion units 
with no additional combustion devices). You may also use this alternative to a continuous parameter monitoring system for the catalytic regenerator atmospheric exhaust gas flow rate for your catalytic reforming unit during the coke burn and rejuvenation cycles if the unit operates as a constant pressure system during these cycles. You may 
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also use this alternative to a continuous 
parameter monitoring system for the gas flow rate exiting the catalyst regenerator to determine inlet velocity to the primary internal cyclones as required in § 63.1564(c)(5) regardless of the configuration of the catalytic regenerator exhaust vent downstream of the regenerator (i.e., regardless of whether 
or not any other gas streams are introduced into the catalyst regeneration vent). Except, if you only use this alternative to demonstrate compliance with § 63.1564(c)(5), you shall use this procedure for the performance test and for monitoring after the performance test. You shall: 
* * * * * 
■24. Section 63.1574 is amended by 
revising paragraph (a)(3)(ii) to read as 
follows: 
§ 63.1574 What notifications must I submit 
and when? 
(a) * * * 
(3) * * * (ii) For each initial compliance 
demonstration that includes a 
performance test, you must submit the notification of compliance status no later than 150 calendar days after the compliance date specified for your affected source in § 63.1563. For data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT website (https://www.epa.gov/ electronic-reporting-air-emissions/ electronic-reporting-tool-ert) at the time of the test, you must submit the results in accordance with § 63.1575(k)(1)(i) by the date that you submit the Notification of Compliance Status, and you must include the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted in the Notification of Compliance Status. For performance evaluations of continuous monitoring systems (CMS) measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the EPA’s ERT website at the time of the evaluation, you must submit the results in accordance with § 63.1575(k)(2)(i) by the date that you submit the Notification of Compliance Status, and you must include the process unit where the CMS is installed, the parameter measured by the CMS, and the date that the performance evaluation was conducted in the Notification of Compliance Status. All other performance test and performance evaluation results (i.e., those not supported by EPA’s ERT) must be reported in the Notification of Compliance Status. 
* * * * * ■25. Section 63.1575 is amended by: 
■a. Revising paragraphs (f)(1), (k)(1) 
introductory text and (k)(2) introductory 
text; and 
■b. Adding paragraph (l). 
The revisions and additions read as 
follows: 
§ 63.1575 What reports must I submit and 
when? 
* * * * * 
(f) * * * 
(1) A copy of any performance test or 
performance evaluation of a CMS done 
during the reporting period on any 
affected unit, if applicable. The report must be included in the next semiannual compliance report. The copy must include a complete report for each test method used for a particular kind of emission point tested. For additional tests performed for a similar emission point using the same method, you must submit the results and any other information required, but a complete test report is not required. A complete test report contains a brief process description; a simplified flow diagram showing affected processes, control equipment, and sampling point locations; sampling site data; description of sampling and analysis procedures and any modifications to standard procedures; quality assurance procedures; record of operating conditions during the test; record of preparation of standards; record of calibrations; raw data sheets for field sampling; raw data sheets for field and laboratory analyses; documentation of calculations; and any other information required by the test method. For data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT website (https://www.epa.gov/ electronic-reporting-air-emissions/ electronic-reporting-tool-ert) at the time of the test, you must submit the results in accordance with paragraph (k)(1)(i) of this section by the date that you submit the compliance report, and instead of including a copy of the test report in the compliance report, you must include the process unit(s) tested, the pollutant(s) tested, and the date that such performance test was conducted in the compliance report. For performance evaluations of CMS measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the EPA’s ERT website at the time of the evaluation, you must submit the results in accordance with paragraph (k)(2)(i) of this section by the date that you submit the compliance report, and you must include the process unit where the CMS is installed, the parameter measured by the CMS, and the date that the performance 
evaluation was conducted in the compliance report. All other 
performance test and performance evaluation results (i.e., those not 
supported by EPA’s ERT) must be reported in the compliance report. 
* * * * * 
(k) * * * 
(1) Unless otherwise specified by this 
subpart, within 60 days after the date of 
completing each performance test as required by this subpart, you must submit the results of the performance tests following the procedure specified in either paragraph (k)(1)(i) or (ii) of this section. 
* * * * * 
(2) Unless otherwise specified by this 
subpart, within 60 days after the date of 
completing each CEMS performance evaluation required by § 63.1571(a) and (b), you must submit the results of the performance evaluation following the procedure specified in either paragraph (k)(2)(i) or (ii) of this section. 
* * * * * 
(l) Extensions to electronic reporting 
deadlines. (1) If you are required to 
electronically submit a report through 
the Compliance and Emissions Data Reporting Interface (CEDRI) in the EPA’s Central Data Exchange (CDX), and due to a planned or actual outage of either the EPA’s CEDRI or CDX systems within the period of time beginning 5 business days prior to the date that the submission is due, you will be or are precluded from accessing CEDRI or CDX and submitting a required report within the time prescribed, you may assert a claim of EPA system outage for failure to timely comply with the reporting requirement. You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or caused a delay in reporting. You must provide to the Administrator a written description identifying the date(s) and time(s) the CDX or CEDRI were unavailable when you attempted to access it in the 5 business days prior to the submission deadline; a rationale for attributing the delay in reporting beyond the regulatory deadline to the EPA system outage; describe the measures taken or to be taken to minimize the delay in reporting; and identify a date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported. In any circumstance, the report must be submitted electronically as soon as possible after the outage is resolved. The decision to accept the 
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claim of EPA system outage and allow 
an extension to the reporting deadline is solely within the discretion of the Administrator. 
(2) If you are required to 
electronically submit a report through CEDRI in the EPA’s CDX and a force majeure event is about to occur, occurs, or has occurred or there are lingering effects from such an event within the period of time beginning 5 business days prior to the date the submission is due, the owner or operator may assert a claim of force majeure for failure to timely comply with the reporting requirement. For the purposes of this section, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature (e.g., 
hurricanes, earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility (e.g., large scale 
power outage). If you intend to assert a claim of force majeure, you must submit 
notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or caused a delay in reporting. You must provide to the Administrator a written description of the force majeure event and a rationale for attributing the delay in reporting beyond the regulatory deadline to the force majeure event; describe the measures taken or to be taken to minimize the delay in reporting; and identify a date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported. In any circumstance, the reporting must occur as soon as possible after the force 
majeure event occurs. The decision to accept the claim of force majeure and allow an extension to the reporting deadline is solely within the discretion of the Administrator. 
■26. Section 63.1576 is amended by 
revising paragraph (a)(2)(i) to read as follows: 
§ 63.1576 What records must I keep, in 
what form, and for how long? 
(a) * * * 
(2) * * * (i) Record the date, time, and duration 
of each startup and/or shutdown period for which the facility elected to comply with the alternative standards in § 63.1564(a)(5)(ii) or § 63.1565(a)(5)(ii) or § 63.1568(a)(4)(ii) or (iii). 
* * * * * 
■27. Table 3 to Subpart UUU is 
amended by revising the table heading 
and entries for items 2.c, 6, 7, 8 and 9 to read as follows: 
TABLE 3 TOSUBPART UUU OFPART63—C ONTINUOUS MONITORING SYSTEMS FOR METAL HAP E MISSIONS FROM 
CATALYTIC CRACKING UNITS 
*******  
For each new or existing catalytic 
cracking unit . . . If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 
*******  
2. * * * 
c. Wet scrubber .................. Continuous parameter monitoring system to measure 
and record the pressure drop across the scrubber,2 
the gas flow rate entering or exiting the control de-
vice,1and total liquid (or scrubbing liquor) flow rate 
to the control device. 
*******  
6. Option 1a: Elect NSPS subpart J, PM per coke burn- 
off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1).Any ..................................... See item 1 of this table. 
7. Option 1b: Elect NSPS subpart Ja, PM per coke burn- 
off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1).Any ..................................... The applicable continuous monitoring systems in item 2 
of this table. 
8. Option 1c: Elect NSPS subpart Ja, PM concentration 
limit not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1).Any ..................................... See item 3 of this table. 
9. Option 2: PM per coke burn-off limit, not subject to 
the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1).Any ..................................... The applicable continuous monitoring systems in item 2 
of this table. 
*******  
1If applicable, you can use the alternative in § 63.1573(a)(1) instead of a continuous parameter monitoring system for gas flow r ate. 
2If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in 
§ 63.1573(b) instead of a continuous parameter monitoring system for pressure drop across the scrubber. 
■28. Table 4 to Subpart UUU of Part 63 
is amended by revising the entries for 
items 9.c and 10.c to read as follows: 
* * * * * 
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TABLE 4 TOSUBPART UUU OFPART63—R EQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP E MISSIONS FROM 
CATALYTIC CRACKING UNITS 
*******  
For each 
new or existing catalytic cracking unit catalyst regenerator vent . . . You must . . . Using . . . According to these requirements . . . 
*******  
9. * * * 
c. Determine the equilibrium 
catalyst Ni concentration.XRF procedure in appendix A 
to this subpart 1; or EPA 
Method 6010B or 6020 or EPA Method 7520 or 7521 in SW–8462; or an alter-native to the SW–846 meth-od satisfactory to the Admin-istrator.You must obtain 1 sample for each of the 3 test runs; deter-
mine and record the equilibrium catalyst Ni concentration for each of the 3 samples; and you may adjust the labora-tory results to the maximum value using Equation 1 of § 63.1571, if applicable. 
*******  
10. * * * 
c. Determine the equilibrium 
catalyst Ni concentration.See item 9.c. of this table ....... You must obtain 1 sample for each of the 3 test runs; deter-
mine and record the equilibrium catalyst Ni concentration for each of the 3 samples; and you may adjust the labora-tory results to the maximum value using Equation 2 of § 63.1571, if applicable. 
*******  
* * * * * ■29. Table 5 to Subpart UUU is 
amended by revising the entry for item 
3 to read as follows: 
TABLE 5 TOSUBPART UUU OFPART63—I NITIAL COMPLIANCE WITHMETAL HAP E MISSION LIMITS FOR CATALYTIC  
CRACKING UNITS 
*******  
For each new and existing catalytic 
cracking unit . . . For the following emission limit ...  You have demonstrated compliance if . . . 
*******  
3. Subject to NSPS for PM in 40 
CFR 60.102a(b)(1)(ii), electing to 
meet the PM per coke burn-off limit.PM emissions must not exceed 0.5 
g/kg (0.5 lb PM/1,000 lb) of coke burn-off).You have already conducted a performance test to demonstrate initial 
compliance with the NSPS and the measured PM emission rate is less than or equal to 0.5 g/kg (0.5 lb/1,000 lb) of coke burn-off in the catalyst regenerator. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your BLD; CO
2, O2, or CO monitor; or continuous opac-
ity monitoring system meets the requirements in § 63.1572. 
*******  
■30. Table 6 to Subpart UUU is 
amended by revising the entries for 
items 1.a.ii and 7 to read as follows: 
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TABLE 6 TOSUBPART UUU OFPART63—C ONTINUOUS COMPLIANCE WITHMETAL HAP E MISSION LIMITS FOR CATALYTIC  
CRACKING UNITS 
*******  
For each new and existing catalytic 
cracking unit . . . Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance by . . . 
1. * * * ........................................... a. * * *.
ii. Conducting a performance test before August 1, 2017 or within 150 
days of startup of a new unit and thereafter following the testing fre-
quency in § 63.1571(a)(5) as applicable to your unit. 
*******  
7. Option 1b: Elect NSPS subpart 
Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1).PM emissions must not exceed 1.0 
g/kg (1.0 lb PM/1,000 lb) of coke burn-off.See item 2 of this table. 
*******  
■31. Table 10 to Subpart UUU is 
amended by revising the entry for item 
3 to read as follows: 
TABLE 10 TOSUBPART UUU OFPART63—C ONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP E MISSIONS FROM 
CATALYTIC CRACKING UNITS 
*******  
For each new or existing catalytic 
cracking unit . . . And you use this type of control device for your vent . . . You shall install, operate, and maintain this type of continuous monitoring system . . . 
*******  
3. During periods of startup, shut-
down or hot standby electing to 
comply with the operating limit in § 63.1565(a)(5)(ii).Any ................................................. Continuous parameter monitoring system to measure and record the 
concentration by volume (wet or dry basis) of oxygen from each catalyst regenerator vent. If measurement is made on a wet basis, you must comply with the limit as measured (no moisture correc-tion). 
■32. Table 43 to Subpart UUU is 
amended by revising the entry for item 
2 to read as follows: 
TABLE 43 TOSUBPART UUU OFPART63—R EQUIREMENTS FOR REPORTS  
*******  
You must submit . . . The report must contain . . . You shall submit the report . . . 
*******  
2. Performance test and CEMS performance 
evaluation data.On and after February 1, 2016, the information 
specified in § 63.1575(k)(1).Semiannually according to the requirements in 
§ 63.1575(b) and (f). 
■33. Table 44 to Subpart UUU is 
amended by revising the entries ‘‘63.6(f)(3)’’, ‘‘63.6(h)(7)(i)’’, 
‘‘63.6(h)(8)’’, ‘‘63.7(a)(2)’’, ‘‘63.7(g)’’, ‘‘63.8(e)’’, ‘‘63.10(d)(2)’’, ‘‘63.10(e)(1)– 
(2)’’, and ‘‘63.10(e)(4)’’ to read as 
follows: 
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TABLE 44 TOSUBPART UUU OFPART63—A PPLICABILITY OF NESHAP G ENERAL PROVISIONS TO SUBPART UUU 
*******  
Citation Subject Applies to 
subpart UUU Explanation 
*******  
§ 63.6(f)(3) .................. ..................................................... Yes ................... Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are 
changed to § 63.1570(c) and this subpart specifies how and 
when the performance test results are reported. 
*******  
§ 63.6(h)(7)(i) .............. Report COM Monitoring Data 
from Performance Test.Yes ................... Except this subpart specifies how and when the performance test 
results are reported. 
*******  
§ 63.6(h)(8) ................. Determining Compliance with 
Opacity/VE Standards.Yes ................... Except this subpart specifies how and when the performance test 
results are reported. 
*******  
§ 63.7(a)(2) ................. Performance Test Dates ............ Yes ................... Except this subpart specifies that the results of initial perform-
ance tests must be submitted within 150 days after the compli-ance date. 
*******  
§ 63.7(g) ...................... Data Analysis, Recordkeeping, 
Reporting.Yes ................... Except this subpart specifies how and when the performance test 
or performance evaluation results are reported and § 63.7(g)(2) is reserved and does not apply. 
*******  
§ 63.8(e) ...................... CMS Performance Evaluation .... Yes ................... Except this subpart specifies how and when the performance 
evaluation results are reported. 
*******  
§ 63.10(d)(2) ............... Performance Test Results ......... No .................... This subpart specifies how and when the performance test re-
sults are reported. 
*******  
§ 63.10(e)(1)–(2) ......... Additional CMS Reports ............. Yes ................... Except this subpart specifies how and when the performance 
evaluation results are reported. 
*******  
§ 63.10(e)(4) ............... COMS Data Reports .................. Yes ................... Except this subpart specifies how and when the performance test 
results are reported. 
*******  
[FR Doc. 2018–25080 Filed 11–23–18; 8:45 am] 
BILLING CODE 6560–50–P 
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