[Federal Register Volume 80, Number 230 (Tuesday, December 1, 2015)]
[Rules and Regulations]
[Pages 75177-75354]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-26486]



[[Page 75177]]

Vol. 80

Tuesday,

No. 230

December 1, 2015

Part II





 Environmental Protection Agency





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40 CFR Parts 60 and 63





Petroleum Refinery Sector Risk and Technology Review and New Source 
Performance Standards; Final Rule

Federal Register / Vol. 80 , No. 230 / Tuesday, December 1, 2015 / 
Rules and Regulations

[[Page 75178]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0682; FRL-9935-40-OAR]
RIN 2060-AQ75


Petroleum Refinery Sector Risk and Technology Review and New 
Source Performance Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action finalizes the residual risk and technology review 
conducted for the Petroleum Refinery source categories regulated under 
national emission standards for hazardous air pollutants (NESHAP) 
Refinery MACT 1 and Refinery MACT 2. It also includes revisions to the 
Refinery MACT 1 and MACT 2 rules in accordance with provisions 
regarding establishment of MACT standards. This action also finalizes 
technical corrections and clarifications for the new source performance 
standards (NSPS) for petroleum refineries to improve consistency and 
clarity and address issues related to a 2008 industry petition for 
reconsideration. Implementation of this final rule will result in 
projected reductions of 5,200 tons per year (tpy) of hazardous air 
pollutants (HAP) which will reduce cancer risk and chronic health 
effects.

DATES: This final action is effective on February 1, 2016. The 
incorporation by reference of certain publications for part 63 listed 
in the rule is approved by the Director of the Federal Register as of 
February 1, 2016. The incorporation by reference of certain 
publications for part 60 listed in the rule were 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 www.regulations.gov Web site. 
Although listed in the index, 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 
http://www.regulations.gov, or in hard copy at the EPA Docket Center, 
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 Air and Radiation Docket and Information 
Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For questions about this final action, 
contact Ms. Brenda Shine, Sector Policies and Programs Division, 
Refining and Chemicals Group (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) 541-0246; and email address: [email protected]. For 
specific information regarding the risk modeling methodology, contact 
Mr. Ted Palma, Health and Environmental Impacts Division (C539-02), 
Office of Air Quality Planning and Standards, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711; 
telephone number: (919) 541-5470; fax number: (919) 541-0840; and email 
address: [email protected]. 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, William Jefferson Clinton Building, 1200 Pennsylvania Ave. NW., 
Washington, DC 20460; telephone number: (202) 564-7027; fax number: 
(202) 564-0050; and email address: [email protected].

SUPPLEMENTARY INFORMATION: 
    Preamble Acronyms and Abbreviations. We use multiple acronyms and 
terms in this preamble. While this list may not be exhaustive, to ease 
the reading of this preamble and for reference purposes, the EPA 
defines the following terms and acronyms here:

10/25 tpy emissions equal to or greater than 10 tons per year of a 
single pollutant or 25 tons per year of cumulative pollutants
AEGL acute exposure guideline levels
APCD air pollution control devices
API American Petroleum Institute
BAAQMD Bay Area Air Quality Management District
BDT best demonstrated technology
BLD bag leak detectors
BSER best system of emission reductions
Btu/ft2 British thermal units per square foot
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI confidential business information
CCU catalytic cracking units
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO carbon monoxide
CO2 carbon dioxide
CO2e carbon dioxide equivalents
COMS continuous opacity monitoring system
COS carbonyl sulfide
CPMS continuous parameter monitoring system
CRA Congressional Review Act
CRU catalytic reforming units
CS2 carbon disulfide
DCU delayed coking units
EPA Environmental Protection Agency
ERPG emergency response and planning guidelines
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FCCU fluid catalytic cracking unit
FGCD fuel gas combustion device
FMP flare management plan
FR Federal Register
FTIR Fourier transform infrared spectroscopy
GC gas chromatograph
GHG greenhouse gases
H2S hydrogen sulfide
HAP hazardous air pollutants
HCl hydrogen chloride
HCN hydrogen cyanide
HF hydrogen fluoride
HFC highest fenceline concentration
HI hazard index
HQ hazard quotient
ICR information collection request
IRIS Integrated Risk Information System
km kilometers
LAER lowest achievable emission rate
lb/day pounds per day
LDAR leak detection and repair
LEL lower explosive limit
LTD long tons per day
MACT maximum achievable control technology
MIR maximum individual risk
mph miles per hour
MPV miscellaneous process vent
NAICS North American Industry Classification System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NFS near-field interfering source
NHVCZ combustion zone net heating value
Ni nickel
NOX nitrogen oxides
NRDC Natural Resources Defense Council
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and standards
OECA Office of Enforcement and Compliance Assurance
OEHHA Office of Environmental Health Hazard Assessment
OEL open-ended line
OMB Office of Management and Budget
PM particulate matter
PM2.5 particulate matter 2.5 micrometers in diameter and 
smaller
ppbv parts per billion by volume
ppm parts per million

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ppmv parts per million by volume
PRA Paperwork Reduction Act
PRD pressure relief device \1\
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    \1\ This term is common vernacular to describe the variety of 
devices regulated as pressure relief valves subject to the 
requirements in 40 CFR part 63 subpart CC.
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psia pounds per square inch absolute
psig pounds per square inch gauge
REL reference exposure level
REM Model Refinery Emissions Model
RFA Regulatory Flexibility Act
RTC response to comment
RTR Risk and Technology Review
SAB Science Advisory Board
SBA Small Business Administration
SCAQMD South Coast Air Quality Management District
SCR selective catalytic reduction
SISNOSE significant economic impact on a substantial number of small 
entities
SO2 sulfur dioxide
SRP sulfur recovery plant
SRU sulfur recovery unit
SSM startup, shutdown and malfunction
TOSHI target organ-specific hazard index
tpy tons per year
UMRA Unfunded Mandates Reform Act
URE unit risk estimate
UV-DOAS ultraviolet differential optical absorption spectroscopy
VCS voluntary consensus standards
VOC volatile organic compounds
[deg]F degrees Fahrenheit
[Delta]C the concentration difference between the highest measured 
concentration and the lowest measured concentration
[mu]g/m\3\ micrograms per cubic meter

    Background Information. On June 30, 2014, the EPA proposed 
revisions to both of the petroleum refinery NESHAP based on our 
residual risk and technology review (RTR). In that action, we also 
proposed to revise the NESHAP pursuant to CAA section 112(d)(2) and 
(3), to revise the SSM provisions in the NESHAP, and to make technical 
corrections to the NSPS to address issues related to reconsideration of 
the final NSPS subpart Ja rule in 2008. In this action, we are 
finalizing decisions and revisions for these rules. We summarize some 
of the more significant comments received regarding the proposed rule 
and provide our responses in this preamble. A summary of all other 
public comments on the proposal and the EPA's responses to those 
comments is provided in the ``Response to Comment'' document, which is 
available in Docket ID No. EPA-HQ-OAR-2010-0682. The ``track changes'' 
version of the regulatory language that incorporates the changes in 
this final action is also available in the docket for this rulemaking.
    Organization of this Document. 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
    A. What is the statutory authority for this action?
    B. How do the NESHAP and NSPS regulate air pollutant emissions 
from refineries?
    C. What changes did we propose for the Petroleum Refinery NESHAP 
and NSPS in our June 30, 2014 RTR proposal?
III. What is included in this final rule?
    A. What are the final NESHAP amendments based on the risk review 
for the Petroleum Refinery source categories?
    B. What are the final NESHAP amendments based on the technology 
review for the Petroleum Refinery source categories?
    C. What are the final NESHAP amendments pursuant to section 
112(d)(2) & (3) for the Petroleum Refinery source categories?
    D. What are the final NESHAP amendments addressing emissions 
during periods of SSM?
    E. What other revisions to the NESHAP and NSPS are being 
promulgated?
    F. What are the requirements for submission of performance test 
data to the EPA?
    G. What are the effective and compliance dates of the NESHAP and 
NSPS?
    H. What materials are being incorporated by reference?
IV. What is the rationale for our final decisions and amendments to 
the Petroleum Refinery NESHAP and NSPS?
    A. Residual Risk Review for the Petroleum Refinery Source 
Categories
    B. Technology Review for the Petroleum Refinery Source 
Categories
    C. Refinery MACT Amendments Pursuant to CAA section 112(d)(2) 
and (d)(3)
    D. NESHAP Amendments Addressing Emissions During Periods of SSM
    E. Technical Amendments to Refinery MACT 1 and 2
    F. Technical Amendments to Refinery NSPS Subparts J and Ja
V. Summary of Cost, Environmental, and Economic Impacts and 
Additional Analyses Conducted
    A. What are the affected facilities, the air quality impacts and 
cost impacts?
    B. What are the economic impacts?
    C. What are the benefits?
    D. Impacts of This Rulemaking on Environmental Justice 
Populations
    E. Impacts of This Rulemaking on Children's Health
VI. Statutory and Executive Order Reviews
    A. Executive Orders 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution or Use
    I. National Technology Transfer and Advancement Act (NTTAA) and 
1 CFR part 51
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. 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--Industrial Source Categories Affected by This Final Action
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                                                               NAICS \a\
                 NESHAP and source category                      Code
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Petroleum Refining Industry.................................     324110
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\a\ North 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 categories listed. To 
determine whether your facility is affected, you should examine the 
applicability criteria in the appropriate NESHAP or NSPS. If you have 
any questions regarding the applicability of any aspect of these NESHAP 
or NSPS, 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 through the 
Technology Transfer Network (TTN) Web site, a forum for information and 
technology exchange in various areas of air pollution control. 
Following signature by the EPA Administrator, the EPA will post a copy 
of this final action at: http://www.epa.gov/ttn/atw/petref.html. 
Following publication in the Federal Register, the EPA will post the 
Federal Register version and key technical documents at this same Web 
site.
    Additional information is available on the RTR Web site at http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. This information includes an 
overview of the RTR program, links to project Web sites

[[Page 75180]]

for the RTR source categories, and detailed emissions and other data we 
used as inputs to the risk assessments.

C. Judicial Review and Administrative Reconsideration

    Under 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 February 1, 
2016. 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 ``[o]nly 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 ``[i]f 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, WJC 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

A. What is the statutory authority for this action?

1. NESHAP
    Section 112 of the CAA establishes a two-stage regulatory process 
to address emissions of hazardous air pollutants (HAP) from stationary 
sources. In the first stage, we must identify categories of sources 
emitting one or more of the HAP listed in CAA section 112(b) and then 
promulgate technology-based NESHAP for those sources. ``Major sources'' 
are those that emit, or have the potential to emit, any single HAP at a 
rate of 10 tons per year (tpy) or more, or 25 tpy or more of any 
combination of HAP. For major sources, these standards are commonly 
referred to as maximum achievable control technology (MACT) standards 
and must reflect the maximum degree of emission reductions of HAP 
achievable (after considering cost, energy requirements, and non-air 
quality health and environmental impacts). In developing MACT 
standards, CAA section 112(d)(2) directs the EPA to consider the 
application of measures, processes, methods, systems or techniques, 
including but not limited to those that reduce the volume of or 
eliminate HAP emissions through process changes, substitution of 
materials, or other modifications; enclose systems or processes to 
eliminate emissions; collect, capture, or treat HAP when released from 
a process, stack, storage, or fugitive emissions point; are design, 
equipment, work practice, or operational standards; or any combination 
of the above.
    For these MACT standards, the statute specifies certain minimum 
stringency requirements, which are referred to as MACT floor 
requirements, and which may not be based on cost considerations. See 
CAA section 112(d)(3). For new sources, the MACT floor cannot be less 
stringent than the emission control achieved in practice by the best-
controlled similar source. The MACT standards for existing sources can 
be less stringent than floors for new sources, but they cannot be less 
stringent than the average emission limitation achieved by the best-
performing 12-percent of existing sources in the category or 
subcategory (or the best-performing 5 sources for categories or 
subcategories with fewer than 30 sources). In developing MACT 
standards, we must also consider control options that are more 
stringent than the floor, under CAA section 112(d)(2). We may establish 
standards more stringent than the floor, based on the consideration of 
the cost of achieving the emissions reductions, any non-air quality 
health and environmental impacts, and energy requirements.
    In the second stage of the regulatory process, the CAA requires the 
EPA to undertake 2 different analyses, which we refer to as the 
technology review and the residual risk review. Under the technology 
review, we must review the technology-based standards and revise them 
``as necessary (taking into account developments in practices, 
processes, and control technologies)'' no less frequently than every 
eight years, pursuant to CAA section 112(d)(6). Under the residual risk 
review, we must evaluate the risk to public health remaining after 
application of the technology-based standards and revise the standards, 
if necessary, to provide an ample margin of safety to protect public 
health or to prevent, taking into consideration costs, energy, safety 
and other relevant factors, an adverse environmental effect. The 
residual risk review is required within eight years after promulgation 
of the technology-based standards, pursuant to CAA section 112(f). In 
conducting the residual risk review, if the EPA determines that the 
current standards provide an ample margin of safety to protect public 
health, it is not necessary to revise the MACT standards pursuant to 
CAA section 112(f).\2\ For more information on the statutory authority 
for this rule, see 79 FR 36879.
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    \2\ The U.S. Court of Appeals has affirmed this approach of 
implementing CAA section 112(f)(2)(A): NRDC v. EPA, 529 F.3d 1077, 
1083 (D.C. Cir. 2008) (``If EPA determines that the existing 
technology-based standards provide an `ample margin of safety,' then 
the Agency is free to readopt those standards during the residual 
risk rulemaking.'').
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2. NSPS
    Section 111 of the CAA establishes mechanisms for controlling 
emissions of air pollutants from stationary sources. Section 111(b) of 
the CAA provides authority for the EPA to promulgate NSPS that apply 
only to newly constructed, reconstructed and modified sources. Once the 
EPA has elected to set NSPS for new and modified sources in a given 
source category, CAA section 111(d) calls for regulation of existing 
sources, with certain exceptions explained below.
    Specifically, section 111(b) of the CAA requires the EPA to 
establish emission standards for any category of new and modified 
stationary sources that the Administrator, in his or her judgment, 
finds ``causes, or contributes significantly to, air pollution which 
may reasonably be anticipated to endanger public health or welfare.'' 
The EPA has previously made endangerment findings under this section of 
the CAA for more than 60 stationary source categories and subcategories 
that are now subject to NSPS.
    Section 111 of the CAA gives the EPA significant discretion to 
identify the affected facilities within a source category that should 
be regulated. To define the affected facilities, the EPA can use size 
thresholds for regulation and create subcategories based on source 
type, class or size. Emission limits also may be established either for 
equipment within a facility or for an entire facility. For listed 
source categories, the EPA must establish ``standards of performance'' 
that apply

[[Page 75181]]

to sources that are constructed, modified or reconstructed after the 
EPA proposes the NSPS for the relevant source category.\3\
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    \3\ Specific statutory and regulatory provisions define what 
constitutes a modification or reconstruction of a facility. 40 CFR 
60.14 provides that an existing facility is modified and, therefore, 
subject to an NSPS, if it undergoes any physical change in the 
method of operation which increases the amount of any air pollutant 
emitted by such source or which results in the emission of any air 
pollutant not previously emitted. 40 CFR 60.15, in turn, provides 
that a facility is reconstructed if components are replaced at an 
existing facility to such an extent that the capital cost of the new 
equipment/components exceed 50-percent of what is believed to be the 
cost of a completely new facility.
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    The EPA also has significant discretion to determine the 
appropriate level for the standards. Section 111(a)(1) of the CAA 
provides that NSPS are to reflect the degree of emission limitation 
achievable through the application of the best system of emission 
reduction which (taking into account the cost of achieving such 
reduction and any non-air quality health and environmental impact and 
energy requirements) the Administrator determines has been adequately 
demonstrated. This level of control is commonly referred to as best 
demonstrated technology (BDT) or the best system of emission reduction 
(BSER). The standard that the EPA develops, based on the BSER 
achievable at that source, is commonly a numerical emission limit, 
expressed as a performance level (i.e., a rate-based standard). 
Generally, the EPA does not prescribe a particular technological system 
that must be used to comply with a NSPS. Rather, sources remain free to 
elect whatever combination of measures will achieve equivalent or 
greater control of emissions.
    Costs are also considered in evaluating the appropriate standard of 
performance for each category or subcategory. The EPA generally 
compares control options and estimated costs and emission impacts of 
multiple, specific emission standard options under consideration. As 
part of this analysis, the EPA considers numerous factors relating to 
the potential cost of the regulation, including industry organization 
and market structure, control options available to reduce emissions of 
the regulated pollutant(s) and costs of these controls.

B. How do the NESHAP and NSPS regulate air pollutant emissions from 
refineries?

    The EPA promulgated the petroleum refinery NESHAP pursuant to CAA 
section 112(d)(2) and (3) for refineries located at major sources in 
two separate rules. On August 18, 1995, the first petroleum refinery 
MACT standard was promulgated in 40 CFR part 63, subpart CC (60 FR 
43620). This rule is known as ``Refinery MACT 1'' and covers the 
``Sources Not Distinctly Listed,'' meaning it includes all emissions 
sources from petroleum refinery process units, except those listed 
separately under the section 112(c) source category list and expected 
to be regulated by other MACT standards (for example, boilers and 
process heaters). Some of the emission sources regulated in Refinery 
MACT 1 include miscellaneous process vents (MPV), storage vessels, 
wastewater, equipment leaks, gasoline loading racks, marine tank vessel 
loading and heat exchange systems.
    On April 11, 2002 (67 FR 17762), EPA promulgated a second MACT 
standard regulating certain process vents that were listed as a 
separate source category under CAA section 112(c) and that were not 
addressed as part of the Refinery MACT 1. This standard, which is 
referred to as ``Refinery MACT 2'', covers process vents on catalytic 
cracking units (CCU) (including FCCU), CRU and SRU and is codified as 
40 CFR part 63, subpart UUU.
    Finally, on October 28, 2009, we revised Refinery MACT 1 by adding 
MACT standards for heat exchange systems, which the EPA had not 
addressed in the original 1995 Refinery MACT 1 rule (74 FR 55686). In 
this same 2009 action, we updated the cross-references to the General 
Provisions in 40 CFR part 63. On June 20, 2013 (78 FR 37133), we 
promulgated minor revisions to the heat exchange provisions of Refinery 
MACT 1.
    On September 27, 2012, Air Alliance Houston, California Communities 
Against Toxics and other environmental and public health groups filed a 
lawsuit alleging that the EPA missed statutory deadlines to review and 
revise Refinery MACT 1 and 2. The EPA reached an agreement to settle 
that litigation and entered into a Consent Decree. The Consent Decree 
provides for the Administrator to sign a final action no later than 
September 30, 2015.
    Refinery NSPS subparts J and Ja regulated criteria pollutant 
emissions, including particulate matter (PM), sulfur dioxide 
(SO2), nitrogen oxides (NOX) and carbon monoxide 
(CO) from FCCU catalyst regenerators, fuel gas combustion devices 
(FGCD) and sulfur recovery plants. Refinery NSPS subpart Ja also 
regulates criteria pollutant emissions from fluid coking units and DCU.
    The NSPS for petroleum refineries (40 CFR part 60, subpart J) were 
promulgated in 1974, amended in 1976 and amended again in 2008, 
following a review of the standards. As part of the review that led to 
the 2008 amendments to the Refinery NSPS subpart J, the EPA developed 
separate standards of performance for new process units (40 CFR part 
60, subpart Ja). However, the EPA received multiple petitions for 
reconsideration on issues related to those standards. The Administrator 
granted the petitions for reconsideration. The EPA addressed petition 
issues related to process heaters and flares by promulgating amendments 
to the Refinery NSPS subparts J and Ja on September 12, 2012 (77 FR 
56422). In this action, we are finalizing technical corrections and 
clarifications to NSPS subparts J and Ja raised by American Petroleum 
Institute (API) in their 2008 petition for reconsideration that were 
not addressed by the final NSPS amendments of 2012.
    The petroleum refining industry consists of facilities that engage 
in converting crude oil into refined products, including liquefied 
petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel 
oils, lubricating oils and feedstocks for the petrochemical industry. 
Currently, 142 facilities have emission sources regulated by either or 
both Refinery MACT 1 and 2.
    Petroleum refinery activities start with the receipt of crude oil 
for storage at the refinery, include all the petroleum handling and 
refining operations, and terminate with loading of refined products 
into pipelines, tank or rail cars, tank trucks, or ships or barges that 
take products from the refinery to distribution centers. Petroleum-
specific process units include FCCU and CRU. Other units and processes 
found at petroleum refineries (as well as at many other types of 
manufacturing facilities) include storage vessels and wastewater 
treatment plants. HAP emitted by this industry include organics (e.g., 
acetaldehyde, benzene, formaldehyde, hexane, phenol, naphthalene, 2-
methylnaphthalene, dioxins, furans, ethyl benzene, toluene and xylene); 
reduced sulfur compounds (i.e., carbonyl sulfide (COS), carbon 
disulfide (CS2))); inorganics (e.g., hydrogen chloride (HCl), hydrogen 
cyanide (HCN), chlorine, hydrogen fluoride (HF)); and metals (e.g., 
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, mercury, 
manganese and nickel (Ni)). This industry also emits criteria 
pollutants and other non-HAP, including NOX, PM, 
SO2, volatile organic compounds (VOC), CO, greenhouse gases 
(GHG) and total reduced sulfur.

[[Page 75182]]

C. What changes did we propose for the Petroleum Refinery NESHAP and 
NSPS in our June 30, 2014, RTR proposal?

    On June 30, 2014, the EPA published a proposed rule in the Federal 
Register addressing the RTR for the Petroleum Refinery NESHAP, 40 CFR 
part 63, subparts CC and UUU. The proposal also included changes 
pursuant to section 112(d)(2) and (3) and technical revisions to the 
NSPS. Specifically, we proposed:
    (1) Pursuant to CAA sections 112(d)(2) and (3):
    a. Refinery MACT 1:
     Adding MACT Standards for DCU decoking operations.
     Adding operational requirements for flares used as APCD in 
Refinery MACT 1 and 2.
     Adding requirements and clarifications for vent control 
bypasses in Refinery MACT 1.
    b. Refinery MACT 2:
     Revising the CRU purge vent exemption.
    (2) Pursuant to CAA sections 112(d)(6) and 112(f)(2):
     Revising Refinery MACT 1 to cross-reference the 
corresponding storage vessel requirements in the Generic MACT (40 CFR 
part 63, subpart WW, as applicable), and revising the definition of 
Group 1 storage vessels to include smaller capacity storage vessels and 
to include storage vessels storing materials with lower vapor 
pressures.
    (3) Pursuant to CAA section 112(d)(6):
    a. Refinery MACT 1:
     Allowing refineries to meet the leak detection and repair 
(LDAR) requirements in Refinery MACT 1 by monitoring for leaks using 
optical gas imaging in place of EPA Method 21, once the monitoring 
protocol set forth in Appendix K is promulgated.
     Amending the Marine Tank Vessel Loading Operations NESHAP, 
40 CFR part 63, subpart Y, to delete the exclusion for marine vessel 
loading operations at petroleum refineries.
     Establishing a fenceline monitoring work practice standard 
to improve the management of fugitive emissions.
    b. Refinery MACT 2:
     Incorporating requirements consistent with those in 
Refinery NSPS subpart Ja for FCCU including:
     Requiring the use of 3-hour averages rather than daily 
averages for parameter operating limits (e.g., depending on the type of 
control device: Opacity, total power, secondary current, pressure drop, 
and/or liquid-to-gas ratio).
     Removing the Refinery NSPS subpart J incremental PM 
emissions allowance for post combustion devices when burning liquid or 
solid fuels, and removing the 30 percent opacity limit for units 
complying with NSPS subpart J.
     Adding requirements for FCCU controls to include bag leak 
detectors (BLD) as an option to continuous opacity monitoring system 
(COMS).
     Incorporating total power and the secondary current 
operating limits for electrostatic precipitators (ESP).
     Requiring daily checks of the air or water pressure to the 
spray nozzles on jet ejector-type wet scrubber or other type of wet 
scrubber equipped with atomizing spray nozzles.
     Requiring FCCU periodic performance testing on a frequency 
of once every 5 years, as opposed to the current rule, which only 
requires an initial performance test.
     Including a correlation equation for the use of oxygen-
enriched air for SRU.
     Allowing SRU subject to Refinery NSPS subpart Ja with a 
capacity greater than 20 long tons per day (LTD) to comply with 
Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2.
    (4) Other proposed changes include:
     Removing exemptions from the rule requirements for periods 
of SSM in order to ensure that the NESHAP are consistent with the court 
decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008).
     Clarifying requirements related to open-ended valves or 
lines.
     Adding electronic reporting requirements.
     Updating the General Provisions cross-reference tables.
     Making technical corrections and clarifications to NSPS 
subparts J and Ja.

III. What is included in this final rule?

    This action finalizes the EPA's determinations pursuant to the RTR 
provisions of CAA section 112 for the Petroleum Refinery source 
categories and amends the Petroleum Refinery NESHAP based on those 
determinations. This action also finalizes other changes to the NESHAP 
including revising Refinery MACT 1 and 2 pursuant to CAA section 112 
(d)(2) and (3), including revising requirements for flares and pressure 
relief devices (PRD). This action finalizes changes to the SSM 
provisions to ensure that the subparts are consistent with the court 
decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), adds 
electronic reporting requirements in Refinery MACT 1 and 2; and updates 
the General Provisions cross-reference tables. Finally, this action 
finalizes technical corrections and clarifications to Refinery NSPS 
subparts J and Ja to address issues raised in the reconsideration of 
these rules.

A. What are the final NESHAP amendments based on the risk review for 
the Petroleum Refinery source categories?

    The EPA is promulgating final amendments to the Petroleum Refinery 
NESHAP pursuant to CAA section 112(f) that expand the existing Refinery 
MACT 1 control requirements and extend these requirements to smaller 
tanks and tanks with lower vapor pressures. Specifically, consistent 
with the proposal, the EPA is amending Refinery MACT 1 by revising the 
definition of Group 1 storage vessels to include storage vessels with 
capacities greater than or equal to 20,000 gallons but less than 40,000 
gallons if the maximum true vapor pressure is 1.0 psia or greater and 
to include storage tanks greater than 40,000 gallons if the maximum 
true vapor pressure is 0.75 psia or greater. The EPA is also adding a 
cross-reference to the storage vessel requirements in the Generic MACT 
(40 CFR part 63, subpart WW and subpart CC), which include requirements 
for guide pole controls and other fittings as well as inspection 
requirements. After considering the public comments, the final 
amendments include minor changes from our proposed requirements to 
clarify language and correct typographical and referencing errors.

B. What are the final NESHAP amendments based on the technology review 
for the Petroleum Refinery source categories?

1. Refinery MACT 1
    We determined that there are developments in practices, processes 
and control technologies that warrant revisions to the MACT standards 
for this source category. Therefore, to satisfy the requirements of CAA 
section 112(d)(6), we are revising the MACT standards to amend 40 CFR 
part 63, subpart Y to delete the exclusion for marine vessel loading 
operations at petroleum refineries. Removing this exclusion will 
require small marine vessel loading operations (i.e., operations with 
HAP emissions less than 10/25 tpy) and offshore marine vessel loading 
operations to use submerged filling based on the cargo filling line 
requirements in 46 CFR 153.282, as proposed.
    We are also finalizing a fenceline monitoring work practice 
standard to improve the management of fugitive emissions and finalizing 
EPA Methods 325A and 325B to support the work

[[Page 75183]]

practice, with some changes from proposal to address issues raised by 
commenters. Key revisions include: New provisions for reduced 
monitoring for facilities with consistently low fenceline 
concentrations; requirements for alternatives to passive monitoring; 
revised placement guidance to allow perimeter monitoring within a 
facility's property boundary provided all sources are encompassed 
within the monitoring perimeter; reductions in the number of monitors 
required for subareas and segregated areas; clarifications on monitor 
placement for internal roadways or other right-of-ways and marine 
docks; and revised timelines for submitting periodic reports (quarterly 
rather than semiannually) and implementing the work practice standard 
(2 years after promulgation rather than 3 years as proposed). We are 
also revising Refinery MACT 1 storage vessel requirements as described 
above under the risk review, as proposed.
2. Refinery MACT 2
    We determined that there are developments in practices, processes 
and control technologies that warrant revisions to the MACT standards 
for this source category. Therefore, to satisfy the requirements of CAA 
section 112(d)(6), we are revising the Refinery MACT 2 standard for 
FCCU subject to Refinery NSPS subpart J or those electing to comply 
with the Refinery NSPS subpart J requirements. As proposed, we are 
removing the incremental PM limit when burning liquid or solid fuels. 
We are finalizing a 20-percent opacity operating limit evaluated on a 
3-hour average, which differs from the proposal to eliminate the 30-
percent opacity limit and instead allow only for a site-specific 
opacity operating limit or control device parameter monitoring. As 
proposed, we are finalizing requirements to make Refinery MACT 2 
consistent with Refinery NSPS subpart Ja for FCCU by including 3-hour 
averages rather than daily averages for parameter operating limits, and 
by including 3-hour averages rather than daily averages for the site-
specific opacity operating limit. We are also finalizing requirements, 
as proposed, for FCCU controls to include adding BLD as an option to 
COMS, incorporating total power and the secondary current operating 
limits for ESP and requiring daily checks of the air or water pressure 
to the spray nozzles on jet ejector-type wet scrubbers or other types 
of wet scrubbers equipped with atomizing spray nozzles.
    Finally, we are finalizing, as proposed, requirements for FCCU 
periodic performance testing at a frequency of once every 5 years 
rather than the current requirements for a one-time initial performance 
test. However, for owners or operators complying with the Refinery NSPS 
subpart J option (with the 20-percent opacity operating limit discussed 
above), if the PM emissions are within 80-percent of the PM limit 
during any periodic performance test (i.e., emissions exceed 0.8 lb PM/
1,000 lbs of coke burn-off), the refinery owner or operator must 
conduct subsequent performance tests on an annual basis. Based on 
comments received, we are also adding requirements in the final rule 
for owners or operators of FCCU to conduct a one-time test for HCN 
emissions from the FCCU concurrent with their first periodic 
performance test, which must be conducted on or before August 1, 2017 
for all FCCU subject to Refinery MACT 2.
    For SRU, as proposed, we are finalizing a correlation equation for 
the use of oxygen-enriched air. Additionally, as proposed, we are 
finalizing requirements to allow sulfur recovery plants subject to 
Refinery NSPS subpart Ja with a capacity greater than 20 LTD to comply 
with Refinery NSPS subpart Ja as a means of complying with Refinery 
MACT 2.

C. What are the final NESHAP amendments pursuant to section 112(d)(2) & 
(3) for the Petroleum Refinery source categories?

1. Refinery MACT 1
    We are finalizing MACT standards for DCU decoking operations that 
require that each coke drum be depressured to a closed blowdown system 
until the coke drum pressure is 2 psig with minor revisions from 
proposal. Specifically, we are finalizing provisions for existing DCU 
affected sources to average over a 60-cycle (i.e., 60 batch) basis to 
comply with the 2 psig limit, rather than the proposed requirement to 
meet the 2 psig limit on a per venting event basis. In addition, we are 
finalizing requirements for new DCU affected sources to depressure to 
2.0 psig on a per-event, not-to-exceed basis, adding one significant 
digit to the limit for new DCU affected sources. For both new and 
existing DCU affected sources, we are finalizing specific provisions 
for DCU with water overflow design and for double quenching.
    We are finalizing operational requirements and the associated 
monitoring, recordkeeping and reporting requirements for flares used as 
APCD in Refinery MACT 1 and 2 with revisions to the requirements 
proposed. Prior to these amendments, Refinery MACT 1 and 2 cross-
referenced the General Provisions requirements at 40 CFR 63.11(b). As 
proposed, this final action replaces the cross reference to the General 
Provisions and incorporates enhanced flare operational requirements 
directly into the Refinery MACT regulations. As proposed, the final 
rule amendments require that refinery flares operate with continuously 
lit pilot flames at all times. Consistent with our proposal, we are 
finalizing requirements for flares to operate with no visible emissions 
and comply with consolidated requirements related to flare tip 
velocity, but in the final rule these direct emissions limits apply 
when flare vent gas flow is below the smokeless capacity of the flare 
rather than at all times. Above the smokeless capacity of the flare, we 
are establishing a work practice standard related to the visible 
emissions and velocity limits; these work practice standards are 
described in more detail in section III.D.1 of this preamble.
    We are finalizing new operational requirements related to 
combustion zone gas properties with revisions from proposal. In 
response to comments on the proposal, we are finalizing requirements 
that flares meet a minimum operating limit of 270 BTU/scf NHVcz on a 
15-minute average, and are allowing refinery owners or operators to use 
a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate 
compliance with this operating limit. We had proposed two separate sets 
of limits, one being more stringent if an olefins/hydrogen mixture was 
present in the waste gas. For each set of limits, we proposed three 
different alternative combustion zone operating limits: One based on 
the combustion zone net heat content with no correction for the heat 
content of hydrogen, one based on the lower flammability limit and one 
based on the combustibles concentration. We proposed that these limits 
be determined on a 15-minute ``feed-forward'' block average approach 
(i.e., compositional data are collected every 15 minutes, after which 
adjustments are made). We have included an additional option for 
refiners to comply where more frequent data are collected (using direct 
net heating value monitoring) to calculate the combustion limit using 
net heating value data from the same 15-minute block period. We are 
simplifying the compliance approach to a single operating limit based 
only on the combustion zone net heating value (with a hydrogen 
correction). As proposed, we are requiring refinery owners or operators 
to characterize the composition of waste gas, assist gas and

[[Page 75184]]

fuel to demonstrate compliance with the operational requirements.
    As proposed, we are also finalizing in this rule a burden reduction 
option to use grab sampling every 8 hours rather than continuous vent 
gas composition or heat content monitors. We are also including, based 
on public comment, provisions to conduct limited initial sampling and 
process knowledge to characterize flare gas composition for flares in 
``dedicated'' service as an alternative to collecting grab samples 
during each specific event. We are finalizing a requirement for daily 
visible emissions observations as proposed, but, based on public 
comment, we are allowing owners or operators to use video surveillance 
cameras to demonstrate compliance with the visible emissions limit as 
an alternative to the daily visible emissions observations.
    For PRD, we are finalizing requirements for monitoring systems that 
are capable of identifying and recording the time and duration of each 
pressure release to the atmosphere, as proposed. Certain PRD with low 
set pressures or low emission potential or in liquid service would not 
be subject to these monitoring requirements. We are finalizing 
requirements to minimize or prevent atmospheric releases of HAP through 
PRD. Instead of the proposed prohibition on such releases, we are 
finalizing work practice requirements that require both preventive 
measures as well as root cause analysis and corrective action that will 
incentivize refinery owners or operators to eliminate the causes of the 
releases.
    We are finalizing requirements for bypass lines with minor 
revisions from those proposed. Specifically, we are not adopting the 
proposed requirement to install quantitative flow monitors and thus are 
leaving in place the requirement to use flow indicators on bypass 
lines. In addition, we are maintaining the requirements to estimate and 
report the quantity of organic HAP released. In response to public 
comment, we are also clarifying changes to remove the proposed 
reference to air intrusion and specifying that reporting of bypasses is 
only required when ``regulated material'' is discharged to the 
atmosphere as a result of a bypass of a control device.
    We are also finalizing revisions to the definition of miscellaneous 
process vent, as proposed. These revisions include deletion of 
exclusions associated with episodic releases and vents from in situ 
sampling systems. As proposed, the final amendments require that these 
vents must meet the standards applicable to MPV.
2. Refinery MACT 2
    For CRU vents, we are finalizing the vessel pressure limit 
exclusion of 5 psig to apply only to passive depressurization, as 
proposed.

D. What are the final NESHAP amendments addressing emissions during 
periods of SSM?

    We are finalizing, as proposed, changes to Refinery MACT 1 and 2 to 
eliminate the SSM exemption. Consistent with Sierra Club v. EPA, 551 F. 
3d 1019 (D.C. Cir. 2008), the EPA has established standards in this 
rule that apply at all times. EPA is revising Table 6 of subpart CC of 
40 CFR part 63 and Table 44 to subpart UUU of 40 CFR part 63 (the 
General Provisions Applicability Tables) to change several references 
related to requirements that apply during periods of SSM. We also are 
eliminating or revising certain recordkeeping and reporting 
requirements related to the eliminated SSM exemptions. We also are 
removing or modifying inappropriate, unnecessary or redundant language 
in the absence of the SSM exemption. Further, for certain emission 
sources in both MACT 1 and 2, we are establishing standards to address 
emissions during these periods. These are described below.
1. Refinery MACT 1
    We are finalizing a work practice standard for PRD that requires 
refinery owners or operators to establish prevention measures for each 
PRD in organic HAP service. Under the work practice standard, where a 
direct release occurs, the refinery is required to perform root cause 
analysis and implement corrective action. The work practice standard 
also limits the number of events that a PRD may release to the 
atmosphere during a 3-year period, as explained further in the section 
IV.D. of this preamble.
    We are also finalizing a work practice standard for emergency 
flaring events that requires refinery owners or operators to establish 
prevention measures, including the development of a flare management 
plan (FMP), and perform root cause analysis and implement corrective 
action following flaring events during which the velocity of waste gas 
going to the flare or visible emissions limits (i.e., opacity) at the 
flare tip are exceeded, and to limit the number of these events allowed 
in a 3-year period, as explained further in section IV.D. of this 
preamble. Both of these work practice standards are consistent with the 
EPA's goal to improve the effectiveness of the rules. These 
requirements will provide a strong incentive for facilities, over time, 
to better operate their processes to prevent PRD and flare releases.
    We are also finalizing requirements for opening process equipment 
to the atmosphere during maintenance events after draining and purging 
to a closed system, provided the hydrocarbon content is less than or 
equal to 10-percent of the lower explosive limit (LEL). For those 
situations where 10-percent LEL cannot be demonstrated, the equipment 
may be opened and vented to the atmosphere if the pressure is less than 
or equal to 5 psig, provided there is no active purging of the 
equipment to the atmosphere until the LEL criterion is met. This 5 psig 
allowance is only available during shutdown. We are also providing 
additional allowances for situations where it is not technically 
feasible to depressurize a control system where there is no more than 
72 lbs VOC per day vented to the atmosphere, consistent with our Group 
1 applicability cutoff for control of process vents, or for catalyst 
changeout activities where hydrotreater pyrophoric catalyst must be 
purged. Provisions to demonstrate that process equipment is opened only 
after the LEL, pressure or mass in the vessel requirement is met 
includes documenting the procedures for equipment openings and 
procedures for verifying that the openings meet the specific, above-
discussed requirements using site-specific procedures used to de-
inventory equipment for safety purposes (i.e., hot work or vessel entry 
procedures).
2. Refinery MACT 2
    The Refinery MACT 2 standards regulate all HAP emissions from the 
three refinery process vents subject to Refinery MACT 2. For FCCU, the 
standard specifies a CO limit as a surrogate for organic HAP and 
specifies a PM limit (or Ni limit) as a surrogate for metal HAP. 
Compliance with the organic HAP emissions limit is demonstrated using a 
continuous CO monitor; compliance with the metal HAP emissions limit is 
demonstrated using either COMS or control device parameter monitoring 
systems (CPMS). At proposal, with the removal of the exemptions in the 
Refinery MACT 2 rule for periods of startup and shutdown, we recognized 
the need for alternative standards during some startup and shutdown 
situations, and we proposed alternative requirements.
    For this final rule, we are including a 1-percent minimum oxygen 
limit as an alternative to the 500 ppmv hourly CO limit during FCCU 
startup for partial

[[Page 75185]]

burn FCCU with CO boilers, as proposed. We are extending that 
alternative limit to all FCCU and extending it to apply during 
shutdown.
    We are not finalizing the proposed alternative opacity limit for 
FCCU during startup. Instead, based on public comments received, we are 
finalizing an alternative minimum cyclone face velocity limit as a 
means to demonstrate compliance with the PM limit during both startup 
and shutdown, regardless of the type of FCCU and its control device. We 
are finalizing alternative standards for sulfur recovery plant (SRP) 
incinerator temperature and excess oxygen limits during SRP shutdown, 
as proposed, and we are extending the proposed alternative standards to 
startup as well.

E. What other revisions to the NESHAP and NSPS are being promulgated?

    We are finalizing technical amendments to NSPS subparts J and Ja 
with limited changes from what we proposed. First, in response to 
comments, we are revising the NSPS requirements that a flow sensor have 
a ``measurement sensitivity'' of no more than 5-percent of the flow 
rate to an ``accuracy'' requirement that the flow sensor have an 
accuracy of 5-percent of the flow rate. This change will make the 
requirements more clear and consistent between the flow meter 
requirements in the NSPS and the MACT standards since it is the same 
flow meter subject to these requirements. We are also revising flare 
flow rate accuracy requirements in Refinery NSPS subpart Ja to make 
them consistent with those we are finalizing in Refinery MACT 1. 
Finally, we are revising 40 CFR 60.101a(b) to begin as ``Except for 
flares and delayed coking units . . .'' to correct an inadvertent 
error. We proposed revisions to this sentence solely to allow sources 
subject to Refinery NSPS subpart J to comply with the provisions in 
Refinery NSPS subpart Ja instead. However, the words ``and delayed 
coking units'' were inadvertently omitted from the initial part of the 
sentence. Thus, as intended, we are finalizing revisions to this 
sentence to allow sources subject to Refinery NSPS subpart J to comply 
with the provisions in Refinery NSPS subpart Ja.

F. What are the requirements for submission of performance test data to 
the EPA?

    As proposed, the EPA is taking a step to increase the ease and 
efficiency of data submittal and data accessibility. Specifically, the 
EPA is finalizing the requirement for owners or operators of Petroleum 
Refinery facilities to submit electronic copies of certain required 
performance test reports through the EPA's Central Data Exchange (CDX) 
using the Compliance and Emissions Data Reporting Interface (CEDRI). 
The EPA believes that the electronic submittal of the reports addressed 
in this rulemaking will increase the usefulness of the data contained 
in those reports, is in keeping with current trends in data 
availability, will further assist in the protection of public health 
and the environment and will ultimately result in less burden on the 
regulated community. Electronic reporting can also eliminate paper-
based, manual processes, thereby saving time and resources, simplifying 
data entry, eliminating redundancies, minimizing data reporting errors 
and providing data quickly and accurately to the affected facilities, 
air agencies, the EPA and the public.
    As mentioned in the preamble of the proposal, the EPA Web site that 
stores the submitted electronic data, WebFIRE, will be easily 
accessible to everyone and will provide a user-friendly interface that 
any stakeholder could access. By making the records, data and reports 
addressed in this rulemaking readily available, the EPA, the regulated 
community and the public will benefit when the EPA conducts its CAA-
required technology and risk-based reviews. As a result of having 
reports readily accessible, our ability to carry out comprehensive 
reviews will be increased and achieved within a shorter period of time.
    We anticipate fewer or less substantial information collection 
requests (ICRs) in conjunction with prospective CAA-required technology 
and risk-based reviews may be needed. We expect this to result in a 
decrease in time spent by industry to respond to data collection 
requests. We also expect the ICRs to contain less extensive stack 
testing provisions, as we will already have stack test data 
electronically. Reduced testing requirements would be a cost savings to 
industry. The EPA should also be able to conduct these required reviews 
more quickly. While the regulated community may benefit from a reduced 
burden of ICRs, the general public benefits from the agency's ability 
to provide these required reviews more quickly, resulting in increased 
public health and environmental protection.
    Air agencies could benefit from more streamlined and automated 
review of the electronically submitted data. Having reports and 
associated data in electronic format will facilitate review through the 
use of software ``search'' options, as well as the downloading and 
analyzing of data in spreadsheet format. The ability to access and 
review air emission report information electronically will assist air 
agencies to more quickly and accurately determine compliance with the 
applicable regulations, potentially allowing a faster response to 
violations which could minimize harmful air emissions. This benefits 
both air agencies and the general public.
    For a more thorough discussion of electronic reporting required by 
this rule, see the discussion in the preamble of the proposal. In 
summary, in addition to supporting regulation development, control 
strategy development, and other air pollution control activities, 
having an electronic database populated with performance test data will 
save industry, air agencies, and the EPA significant time, money, and 
effort while improving the quality of emission inventories, air quality 
regulations, and enhancing the public's access to this important 
information.

G. What are the effective and compliance dates of the NESHAP and NSPS?

    The final amendments to the NESHAP and NSPS in this action are 
effective on February 1, 2016. As proposed, new sources must comply 
with these requirements by the effective date of the final rule or upon 
startup, whichever is later.
    As proposed, existing sources are required to comply with the final 
DCU and CRU requirements no later than 3 years after the effective date 
of the final rule. Similarly, as proposed, owners or operators are 
required to comply with the new operating and monitoring requirements 
for existing flares no later than 3 years after the effective date of 
the final rule.
    We proposed to provide 3 years from the effective date of the final 
rule for refinery owners or operators to install and begin monitoring 
(collecting samples) around the fenceline of their existing facility. 
If refinery owners and operators determined that a site-specific 
monitoring plan was needed, they would also need to submit and receive 
approval for such a plan during the 3-year compliance period. Based on 
information submitted during the comment period, we are finalizing 
requirements that refinery owners or operators begin collecting samples 
around the fenceline within 2 years of the effective date of the final 
rule. Based on information submitted during the comment period, 1 year 
is sufficient time to identify proper monitoring locations and to 
install the required monitoring stations around the facility

[[Page 75186]]

fenceline. However, owners or operators may need additional monitoring 
systems to account for near-field interfering sources (NFS), for which 
the development and approval of a site-specific fenceline monitoring 
plan is required. We expect that the site-specific fenceline monitoring 
plans can take an additional year to develop, submit and obtain 
approval. Consequently, we are providing 2 years from the effective 
date of the final rule for refinery owners or operators to install and 
begin collecting samples around the fenceline of their facility.
    As proposed, we are requiring that existing sources comply with the 
submerged filling requirement for marine vessel loading on the 
effective date of the final rule.
    As proposed, we are providing 18 months after the effective date of 
the final rule to conduct required performance tests and comply with 
any revised operating limits for FCCU.
    We proposed to require refinery owners or operators to comply with 
the revisions to the SSM provisions of Refinery MACT 1 and 2 on the 
effective date of the final rule. As proposed, this final rule requires 
refinery owners or operators to comply with the limits in Refinery MACT 
2 or the alternative limits in this final rule during startup and 
shutdown for FCCU and SRU on the effective date of the final rule.
    The flare work practice standards for high-load flaring events 
(events exceeding the smokeless capacity of the flare) require 
development of FMP (or revision of an existing plan) to specifically 
consider emergency shutdown and other high load events. In this FMP, 
refinery owners or operators must consider measures that can be 
implemented to reduce the frequency and magnitude of these high-load 
flaring events. This may include installation of a flare gas recovery 
system. Additionally, the work practice standards will require refinery 
owners or operators to identify and implement measures that may involve 
process changes. Therefore, we are establishing a compliance date of 3 
years from the effective date of the final rule for refinery owners or 
operators to comply with the work practice standards for high load 
flaring events. We also note that this compliance period is consistent 
with the compliance time provided for the flare operating limits.
    For atmospheric PRD in HAP service we are establishing a work 
practice standard that requires a process hazard analysis and 
implementation of a minimum of three redundant measures to prevent 
atmospheric releases. Alternately, refinery owners or operators may 
elect to install closed vent systems to route these PRD to a flare, 
drain (for liquid thermal relief valves) or other control system. We 
anticipate that sources will need to identify the most appropriate 
preventive measures or control approach; design, install and test the 
system; install necessary process instrumentation and safety systems; 
and may need to time installations with equipment shutdown or 
maintenance outages. Therefore, we have established a compliance date 
of 3 years from the effective date of the final rule for refinery 
owners or operators to comply with the work practice standards for 
atmospheric PRD.
    As proposed, we are requiring compliance with the electronic 
reporting provisions for performance tests conducted for Refinery MACT 
1 and 2 on the effective date of the final rule.
    Finally, we are finalizing additional requirements for storage 
vessels under CAA sections 112(d)(6) and (f)(2) with a compliance date 
90 days after the effective date of the final rule, as proposed.

H. What materials are being incorporated by reference?

    In this final rule, the EPA is including regulatory text that 
includes incorporation by reference. In accordance with requirements of 
1 CFR 51.5, the EPA is incorporating by reference the following 
documents described in the amendments to 40 CFR 63.14:
     ASTM D1945-03 (Reapproved 2010), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 
2010).
     ASTM D1945-14, Standard Test Method for Analysis of 
Natural Gas by Gas Chromatography.
     ASTM D6196-03 (Reapproved 2009), Standard Practice for 
Selection of Sorbents, Sampling, and Thermal Desorption Analysis 
Procedures for Volatile Organic Compounds in Air, (Approved March 1, 
2009).
     ASTM D6348-03 (Reapproved 2010), Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 
through A8, (Approved October 1, 2010).
     ASTM D6348-12e1, Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy.
     ASTM D6420-99 (Reapproved 2010), Standard Test Method for 
Determination of Gaseous Organic Compounds by Direct Interface Gas 
Chromatography-Mass Spectrometry.
     ASTM UOP539-12, Refinery Gas Analysis by GC.
     BS EN 14662-4:2005, Ambient air quality--Standard method 
for the measurement of benzene concentrations--Part 4: Diffusive 
sampling followed by thermal desorption and gas chromatography, June 
27, 2005.
     EPA-454/B-08-002, Quality Assurance Handbook for Air 
Pollution Measurement Systems, Volume IV: Meteorological Measurements, 
Version 2.0 (Final), March 2008.
     EPA-454/R-99-005, Meteorological Monitoring Guidance for 
Regulatory Modeling Applications, February 2000.
     ISO 16017-2:2003(E): Indoor, ambient and workplace air--
Sampling and analysis of volatile organic compounds by sorbent tube/
thermal desorption/capillary gas chromatography--Part 2: Diffusive 
sampling, May 15, 2003.
     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.\4\
---------------------------------------------------------------------------

    \4\ The requirements in Sec.  63.655(i)(5)(iii)(G) associated 
with this incorporation by reference have not changed, but are being 
modified to properly be incorporated into Sec.  63.14(s).
---------------------------------------------------------------------------

    The EPA has made, and will continue to make, these documents 
available electronically through www.regulations.gov and/or in hard 
copy at the appropriate EPA office (see the ADDRESSES section of this 
preamble for more information).

IV. What is the rationale for our final decisions and amendments to the 
Petroleum Refinery NESHAP and NSPS?

A. Residual Risk Review for the Petroleum Refinery Source Categories

1. What did we propose pursuant to CAA section 112(f) for the Petroleum 
Refinery source categories?
    The results of our residual risk review for the Petroleum Refinery 
source categories were published in the June 30, 2014 proposal at (79 
FR 36934 through 36942), and included assessment of chronic and acute 
inhalation risk, as well as multipathway and environmental risk, to 
inform our decisions regarding acceptability and ample margin of 
safety. The results indicated that both the actual and

[[Page 75187]]

allowable inhalation cancer risks to the individual most exposed are no 
greater than approximately 100-in-1 million, which is the presumptive 
limit of acceptability. In addition, the maximum chronic non-cancer 
target organ-specific hazard index (TOSHI) due to inhalation exposures 
was less than 1. The evaluation of acute non-cancer risks, which was 
conservative, showed acute risks below a level of concern. Based on the 
results of the refined site-specific multipathway analysis, we also 
concluded that the ingestion cancer risk to the individual most exposed 
through ingestion is considerably less than 100-in-1 million. In 
determining risk acceptability, we also evaluated population impacts 
because of the large number of people living near facilities in the 
source category. We estimated that 5-million people are exposed to 
increased cancer risks of greater than 1-in-1 million and 100,000 
people are exposed to increased cancer risks of greater than 10-in-1 
million, but, as noted previously, no individual is exposed to 
increased cancer risks of greater than 100-in-1 million. Considering 
the above information, we proposed that the risks remaining after 
implementation of the existing NESHAP for the Refinery MACT 1 and 2 
source categories is acceptable. However, we noted that the risks based 
on allowable emissions are at the presumptive limit of acceptable risk, 
and that a large number of people are exposed to risks of greater than 
1-in-1 million, and we solicited comment on whether EPA should conclude 
that the risk was unacceptable based on the health information before 
the Agency. We also proposed that the original Refinery MACT 1 and 2 
MACT standards, along with the proposed requirements for storage 
vessels, provide an ample margin of safety to protect public health. 
Finally, we proposed that it is not necessary to set a more stringent 
standard to prevent, taking into consideration costs, energy, safety, 
and other relevant factors, an adverse environmental effect.
2. How did the risk review change for the Petroleum Refinery source 
categories?
    As part of the final risk assessment, we conducted a screening 
level analysis of how the information we received during the public 
comment period, along with the changes we are making to the proposed 
rule, would change our proposed risk estimates (More details can be 
found in the ``Final Residual Risk Assessment for the Petroleum 
Refining Source Sector'', Docket ID No. EPA-HQ-OAR-2010-0682).
    First, we received approximately 20 emissions inventory updates for 
specific facilities. These updates included revised emission estimates, 
revised release latitude/longitude locations and other release 
characteristic revisions. The updates provided evidence that the 
quantity of HAP emitted at these specific facilities is lower than 
considered in the risk modeling for the proposed rule. Our assessment 
of the effects of these changes suggests that the cancer maximum 
individual risk (MIR) based on actual emissions may be closer to 40-in-
1 million, as opposed to 60-in-1 million, as projected at proposal. We 
did not quantify the reductions in chronic or acute non-cancer risks 
from these updates. We calculated allowable emissions using the 
Refinery Emissions Model (REM), which estimates emissions based on each 
refinery's capacities and throughputs [See discussion at 79 FR 36888, 
June 30, 2014.] The allowable emission estimates for point and fugitive 
sources were not specific to a particular latitude/longitude location 
so we assumed them to release from the centroid of the facility. 
Therefore, the predicted cancer MIR of approximately 100-in-1 million 
based on allowable emissions and reported in the proposal risk 
characterization does not change based on the submitted emissions 
revisions. We did not quantify changes to other actual risk metrics as 
part of the screening level analysis (i.e., incidence, populations in 
risk bins, multipathway and ecological analyses), but we would expect 
some minor reductions from those presented in the proposed risk 
characterization.
    Second, we are establishing work practice standards in the final 
rule for PRD releases and emergency flaring events, which under the 
proposed rule would not have been allowed. Thus, because we did not 
consider such non-routine emissions under our risk evaluation for the 
proposed rule, we performed a screening assessment of risk associated 
with these non-routine events for the final rule. [We provide further 
details on the screening approach in ``Final Residual Risk Assessment 
for the Petroleum Refining Source Sector'' in Docket ID No. EPA-HQ-OAR-
2010-0682.] We extracted information on these events from the 2011 
Petroleum Refinery ICR data that included the process unit 
identification, mass of emissions, duration of release, and description 
of the incident. We identified the highest HAP mass releases for both 
PRDs and flares from these non-routine events. We assumed these HAP 
emission releases could occur at any facility in the source category. 
Our analysis suggests that these HAP emissions could increase the MIR 
based on actual emissions by as much as 2-in-1 million. Because the PRD 
and flaring events were the worst case HAP mass emission release events 
reported in the 2011 Refinery ICR for the source category, we are 
assuming that actual and allowable risks are no different for these 
events (i.e., a MIR of 2-in-1 million). A MIR increase of 2-in-1 
million attributable to these events, added to our previous estimate 
for allowable risk at proposal will not appreciably change our proposed 
determination that the MIR based on allowable emissions are 
approximately 100-in-1 million. We note that the MIR estimate 
attributable to these non-routine PRD and flaring events was estimated 
using a conservative, screening-level assessment, while the MIR 
estimate at proposal was based on a refined risk assessment. By adding 
a screening estimate to a refined risk estimate, we are merely defining 
an upper limit that we expect the combined risks from both the routine 
and non-routine emissions to be. Similarly, we estimate chronic non-
cancer hazard index (HI) values attributable to the additional 
exposures resulting from non-routine flaring and PRD HAP emissions to 
be well below 1 (HIimmune-system of 0.007) such that there 
is no appreciable change in the maximum chronic non-cancer HI of 0.9 
estimated at proposal for routine emissions, which was based on 
neurological effects.
    The screening analysis projects that the maximum predicted acute 
non-cancer risk from non-routine PRD and flare emissions results in a 
hazard quotient (HQ) based on a recommended reference exposure level 
limit (REL) of up to 14 from benzene emissions. While the analysis 
shows that there is a potential for HQs exceeding 1 for benzene, 
because of the many uncertainties and conservative nature of this 
screening analysis, the likelihood of such exposure and risk are low. 
At proposal, we projected a HQ based on the REL for benzene of up to 2 
from routine emissions. If we conservatively combine the routine and 
non-routine emissions analyses, we would expect the potential for HQs 
based on the REL for benzene to have the potential to increase above 2. 
However, as projected at proposal, we estimate that the acute HQs 
calculated using acute exposure guideline levels (AEGL) and emergency 
response and planning guidelines (ERPG) values for all pollutants 
including benzene would still be well

[[Page 75188]]

below 1 considering both routine and non-routine emissions.
    Considering all of these factors, we do not project risks to be 
significantly different from what we proposed. Based on the risk 
analysis, as informed by the screening level analysis based on 
information obtained during the comment period, we are finalizing our 
determination that the risk remaining after promulgation of the NESHAP 
is acceptable.
3. What key comments did we receive on the risk review and what are our 
responses?
    We received numerous comments on the residual risk assessment 
analyses and results. We summarize the key comments received below, 
along with our responses. A complete summary of all public comments 
received and our responses are in the ``Response to Comment'' Document 
in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
    Comment: Several commenters agreed that the EPA has correctly 
concluded that the proposed rule requirements protect the public with 
an ample margin of safety from refinery emissions. Other commenters 
noted that EPA found residual risks remaining after implementation of 
the MACT standards to be acceptable, and in light of the acceptability 
determination argued that the proposed changes to the rule are not 
justified. The commenters noted that the EPA's detailed emissions 
inventory assessment and risk modeling results demonstrated that, at 
every U.S. refinery, category-specific risks are below the EPA's 
presumptive limit of acceptable risk (i.e., cancer risk of less than 
100-in-1 million).
    Other commenters stated the EPA's risk estimates are understated 
and that the EPA should reduce the benchmark of what it considers 
acceptable lifetime cancer risk instead of the upper limit of 100-in-1 
million. One commenter provided an extensive critique of the cancer, 
chronic and acute affects levels used in the risk assessment and 
recommended that the EPA use California Office of Environmental Health 
Hazard Assessment's (OEHHA) new toxicity values for several chemicals. 
The commenter provided some references for the approaches used to 
derive the California values. The commenter also asserted that risks 
would be unacceptable had these more protective values been used in the 
risk assessment. Some commenters stated the risks from petroleum 
refinery emissions are underestimated because the EPA did not but 
should have included interaction of multiple pollutants, accounted for 
exposure to multiple sources, and assessed the cumulative risks from 
facility-wide emissions and multiple nearby sources impacting an area.
    Response: The approximately 100-in-1 million benchmark was 
established in the Benzene NESHAP (54 FR 38044, September 14, 1989), 
which Congress specifically referenced in CAA section 112(f)(2)(B). 
While this presumptive level provides a benchmark for judging the 
acceptability of MIR, it is important to recognize that it does not 
constitute a rigid line for making that determination. The EPA 
considers the specific uncertainties of the emissions, health effects 
and risk information for the source category in question when deciding 
whether the risk posed by that source category is acceptable. In 
addition, the source category-specific decision of what constitutes an 
acceptable level of risk is a holistic one; that is, the EPA considers 
all potential health impacts--chronic and acute, cancer and non-cancer, 
and multipathway--along with their uncertainties, when determining 
whether the source category presents an unacceptable risk.
    Regarding the comment that in light of the acceptability 
determination the proposed changes to the rule are not justified, we 
note that we also are required to ensure that the standards provide an 
ample margin of safety to protect public health. That analysis is 
separate from the acceptability analysis, and the determination of 
acceptability does not automatically lead us to conclude that the 
standards provide an ample margin of safety to protect public health.
    Regarding the comments that the EPA should use the new California 
OEHHA values, we disagree. The EPA's chemical-specific toxicity values 
are derived using risk assessment guidelines and approaches that are 
well established and vetted through the scientific community, and 
follow rigorous peer review processes.\5\ The RTR program gives 
preference to the EPA values for use in risk assessments and uses other 
values, as appropriate, when those values are derived with methods and 
peer review processes consistent with those followed by the EPA. The 
approach for selecting appropriate toxicity values for use in the RTR 
Program has been endorsed by the Science Advisory Board (SAB).\6\
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    \5\ Integrated Risk Information System (IRIS). IRIS Guidance 
documents available at http://www.epa.gov/iris/backgrd.html.
    \6\ http://yosemite.epa.gov/sab/sabproduct.nsf/0/b031ddf79cffded38525734f00649caf!OpenDocument&TableRow=2.3#2.
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    The EPA scientists reviewed the information provided by the 
commenter regarding the California values and concluded that further 
information is needed to evaluate the scientific basis and rationale 
for the recent changes in California OEHHA risk assessment methods. The 
EPA will work on gathering the necessary information to conduct an 
evaluation of the scientific merit and the appropriateness of the use 
of California OEHHA's new toxicity values in the agency decisions. 
Until the EPA has completed its evaluation, it is premature to 
determine what role these values might play in the RTR process. 
Therefore, the EPA did not use the new California OEHHA toxicity values 
as part of this current action. For more detailed responses regarding 
appropriate reference values for specific pollutants, see the 
``Response to Comment'' document in the public docket (Docket ID No. 
EPA-HQ-OAR-2010-0682).
    Concerning comments that we should consider aggregate risks from 
multiple pollutants and sources, we note that we have done this to the 
extent it is appropriate to do so. We modeled whole-facility risks for 
both chronic cancer and non-cancer impacts to understand the risk 
contribution of the sources within the Petroleum Refinery source 
categories. The individual cancer risks for the source categories were 
aggregated for all carcinogens. In assessing non-cancer hazard from 
chronic exposures to pollutants that have similar modes of action or 
(where this information is absent) that affect the same target organ, 
we summed the HQs. This process creates, for each target organ, a 
TOSHI, defined as the sum of HQs for individual HAP that affect the 
same organ or organ system. Whole-facility risks were estimated based 
on the 2011 ICR emissions data obtained from facilities, which included 
emissions from all sources at the refinery, not just Refinery MACT 1 
and 2 emission sources (e.g., emissions were included for combustion 
units and units subject to the Hazardous Organic NESHAP, if present at 
the refinery). We disagree with the commenter's assertion that 
additional quantitative assessment of risks from sources outside the 
source category is required under the statute. The statute requires the 
EPA to provide the quantitative risk information necessary to inform 
RTR regulatory decisions, and to this end, the EPA conducted a 
comprehensive assessment of the risks associated with exposure to the 
HAP emitted by the source category and supplemented that with 
additional

[[Page 75189]]

information available about other possible concurrent and relevant 
risks.
    Further, the risk assessment modeling accounts for the effects of 
multiple facilities that may be in close proximity when estimating 
concentration and risk impacts at each block centroid. When evaluating 
the risks associated with a particular source category, we combined the 
impacts of all facilities within the same source category and assessed 
chronic exposure and risk for all census blocks with at least one 
resident (i.e., locations where people may reasonably be assumed to 
reside). The MIR considers the combined impacts of all sources in the 
category that may be in close proximity (i.e., cumulative impact of all 
refineries).
    Comment: Several commenters stated that the EPA underestimated 
exposure because emissions are underreported and underestimated. The 
commenters noted that for the risk assessment for the refineries rule, 
the EPA evaluated (1) the emissions reported to the agency pursuant to 
the 2011 Petroleum Refinery ICR as sources' ``actual'' emissions, and 
(2) the emissions the EPA estimates that the existing standards 
currently allow sources to emit using the REM, which it describes as 
``allowable'' emissions. According to the commenters, both the EPA's 
``actual'' and ``allowable'' emissions data sets are incomplete and 
undercount emissions, causing the EPA to significantly underestimate 
the resulting risk in its risk analysis. For example, the commenters 
noted that the EPA assumed the flare destruction efficiency to be 98 
percent, while the EPA's own estimates suggest flare efficiency is 93.9 
percent. The commenters also noted that the EPA has further understated 
risks by ignoring emissions during unplanned SSM events and by ignoring 
HAP for which no reference values are established. One commenter cited 
the TCEQ Emissions Event Database as evidence that SSM emissions are a 
severe public health problem because data show that nearly 1 million 
pounds of HAP are reported from Texas refineries between 2009 and 2013. 
According to these commenters, the EPA needs to adopt standards that 
provide greater protection, including protection from the risks of 
accidents.
    Response: We used the best and most robust facility-specific HAP 
emissions inventory available to us, which was the 2011 ICR, in 
performing the analysis for the proposed rule. We conducted a thorough 
and exhaustive review of the data submitted through the ICR and we 
followed up on source-specific information on a facility-by-facility 
basis, as documented in the ``Emissions Data Quality Memorandum and 
Development of the Risk Model Input File'' (see Docket ID No. EPA-HQ-
OAR-2010-0682-0076). In addition, we took steps ahead of issuing the 
2011 ICR to make sure that facilities could, as accurately as 
practicable, estimate their HAP emissions for purposes of responding to 
the inventory portion of that ICR. We prepared a Refinery Protocol to 
provide guidance to refinery owners or operators to use the best 
available, site-specific data when developing their emissions 
inventory, to ensure all emission sources are included in the 
inventory, and to have a consistent set of emission factors that all 
respondents use if no site-specific emissions data were available. If 
site-specific emissions data were available, sites were to use these 
data preferentially over the default factors. We developed the default 
factors provided in the protocol from the best data available at the 
time.
    The ICR-submitted information for allowable emissions did not 
include emission estimates for all HAP and all emission sources. 
Consequently, we used the REM to estimate allowable emissions. The REM 
relies on model plants that vary based on throughput capacity. Each 
model plant contains process-specific default emission factors, 
adjusted for compliance with the Refinery MACT 1 and 2 emission 
standards.
    We agree with the commenters that studies have shown that many 
refinery flares are operating less efficiently than 98 percent. Prior 
to proposing this rule, we conducted a flare ad hoc peer review to 
advise the EPA on factors affecting flare performance (see discussion 
in the June 30, 2014, proposal at 79 FR 36905). However, we disagree 
with the commenters that the risk analysis should consider this level 
of performance since the existing MACT standard does not allow it. For 
purposes of the risk analysis, we evaluate whether it is necessary to 
tighten the existing MACT standard in order to provide an ample margin 
of safety. Thus, in reviewing whether the existing standards provide an 
ample margin of safety, we review the level of emissions the MACT 
standards allow. In the present case, we considered the level of 
performance assumed in establishing the MACT standard for purposes of 
determining whether the MACT standard provides an ample margin of 
safety. However, we did recognize that facilities were experiencing 
performance issues with flares and that many flares were not meeting 
the assumed performance level at the time we promulgated the MACT 
standard. Thus, we proposed, and are finalizing, revisions to the flare 
operating requirements to ensure that the flares meet the required 
performance level. These provisions are consistent with the EPA's goals 
to improve the effectiveness of our rules.
    Similarly, we do not include startup, shutdown (including 
maintenance events) and malfunction emissions that are not allowed 
under the standard as part of our evaluation of whether the standards 
provide an ample margin of safety. Regarding the HAP emissions from SSM 
events that the commenter is concerned with, we note that our review of 
the TCEQ incident database indicates that many of the large reported 
release events were of SO2 emissions and only a few had 
significant HAP emissions.
    Because in the final rule we are establishing work practice 
standards for PRD and emergency flaring events, we performed a 
screening-level risk analysis to address changes in facility HAP 
emission releases due to these events. Details on this analysis are 
presented in the final risk report for the source category (For more 
details see Appendix 13 of the ``Final Residual Risk Assessment for the 
Petroleum Refining Source Sector,'' Docket ID No. EPA-HQ-OAR-2010-
0682).
    As for HAP with no reference value, the SAB addressed this issue in 
its May 7, 2010, response to the EPA Administrator. In that response, 
the SAB Panel recommended that, for HAP that do not have dose-response 
values from the EPA's list, the EPA should consider and use, as 
appropriate, additional sources for such values that have undergone 
adequate and rigorous scientific peer review. The SAB panel further 
recommended that the inclusion of additional sources of dose-response 
values into the EPA's list should be adequately documented in a 
transparent manner in any residual risk assessment case study. We agree 
with this approach and have considered other sources of dose-response 
data when conducting our risk determinations under RTR. However, in 
some instances no sources of information beyond the EPA's list are 
available. Compounds without health benchmarks are typically those 
without significant health effects compared to compounds with health 
benchmarks, and in such cases we assume these compounds will have a 
negligible contribution to the overall health risks from the source 
category. A tabular summary of HAPs that have dose response values for 
which an exposure assessment was conducted is presented in Table 3.1-1 
of the ``Final Residual Risk Assessment for the Petroleum Refining 
Source Sector'', Docket ID No. EPA-HQ-OAR-2010-0682.

[[Page 75190]]

    Comment: A few commenters asserted that the EPA should decide that 
it is unjust and inconsistent with the CAA's health protection purpose 
to allow the high health risks caused by refineries to fall 
disproportionately on communities of color and lower income communities 
who are least equipped to deal with the resulting health effects. 
Because of that disparity, the commenter stated that the EPA should 
recognize that the risks found are unacceptable and set stronger 
national standards for all exposed Americans.
    Response: For this rulemaking, the EPA conducted both pre- and 
post-control risk-based assessments with analysis of various socio-
economic factors for populations living near petroleum refineries (see 
Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227) and determined that 
there are more African-Americans, Other and multiracial groups, 
Hispanics, low-income individuals, and individuals with less than a 
high school diploma compared to national averages. In determining the 
need for tighter residual risk standards, the EPA strives to limit to 
no higher than 100-in-1 million the estimated cancer risk for persons 
living near a plant if exposed to the maximum pollutant concentration 
for 70 years and to protect the greatest number of persons to an 
individual lifetime risk of no higher than 1-in-1 million. Although we 
consider the risk for all people regardless of racial or socioeconomic 
status, communities near petroleum refineries will particularly benefit 
from the risk reductions associated with this rule. In particular, as 
discussed later, the fenceline monitoring work practice standard will 
be a further improvement in the way fugitive emissions are managed and 
will provide an extra measure of protection for surrounding 
communities.
4. What is the rationale for our final decisions for the risk review?
    As described in section IV.A.2 of this preamble, we performed a 
screening-level analysis to assess the risks associated with inventory 
updates we received for specific facilities and with emissions events 
that were previously not included in the risk assessment because the 
proposed rule did not allow them. Because we are finalizing work 
practice standards to regulate emission events associated with PRD 
releases and emergency flaring, we considered the effect these work 
practice standards would have on risks. As discussed in section IV.A.2 
of this preamble, we project that accounting for these emergency events 
in the baseline risks after implementation of the MACT standards does 
not appreciably change the risks, and at most, could increase the 
proposed rule estimate of MIR by approximately 2-in-1 million. 
Therefore, we would project that any controls applied to these 
emergency events, including the work practice standards for PRDs and 
emergency flaring in this final rule, would not appreciably change the 
proposed post-control risks. Although we would anticipate minimal 
additional risk reductions, we reviewed more stringent alternatives to 
the work practice standards for PRD releases and emergency flaring 
events included in this final rule, and we found that the costs of 
increasing flare capacity to control all PRD releases and to eliminate 
all visible emissions during emergency flaring were too high. We 
estimate the capital costs of applying the velocity and visible 
emissions limit at all times would be approximately $3 billion, and we 
estimate that the costs of controlling all PRD releases with flares 
would be approximately $300 million. [See the discussion in the ``Flare 
Control Option Impacts for Final Refinery Sector Rule'', Docket ID No. 
EPA-HQ-OAR-2010-0682 and the PRD work practice standard discussion in 
section IV.C of this preamble.] Further, we did not receive comments on 
additional control technologies that we should have considered for 
other emission sources (e.g., tanks, DCUs) beyond those considered and 
described at proposal. Consequently, as discussed in section IV.A.2, we 
conclude that the risks from the Petroleum Refinery source categories 
are acceptable and that, with the additional requirements for storage 
vessels that we are finalizing, as proposed, the Refinery MACT 1 and 2 
rules provide an ample margin of safety to protect public health. We 
also maintain, based on the rationale presented in the preamble to the 
proposed rule, that the current standards prevent, taking into 
consideration costs, energy, safety and other relevant factors, an 
adverse environmental effect.

B. Technology Review for the Petroleum Refinery Source Categories

1. What did we propose pursuant to CAA section 112(d)(6) for the 
Refinery MACT 1 (40 CFR part 63, subpart CC) source category?
    The results of our technology review for the Petroleum Refinery 
source categories were published in the June 30, 2014, proposal at (79 
FR 36913 through 36928). The technology review was conducted for both 
MACT source categories as described below.
a. Refinery MACT 1
    Refinery MACT 1 sources include MPV, storage vessels, equipment 
leaks, gasoline loading racks, marine vessel loading operations, 
cooling towers/heat exchange systems and wastewater. Based on 
technology reviews for the sources described above, we proposed that it 
was not necessary to revise Refinery MACT 1 requirements for MPV, 
gasoline loading racks, cooling towers/heat exchange systems, and 
wastewater. For storage vessels, we proposed revisions pursuant to the 
technology review. Specifically, we proposed to cross-reference the 
storage vessel requirements in the Generic MACT (40 CFR part 63, 
subpart WW) to require controls on floating roof fittings (e.g., 
guidepoles, ladder wells and access hatches) and to revise the 
definition of Group 1 storage vessels to include smaller tanks with 
lower vapor pressures. For equipment leaks, we proposed to allow 
refineries to meet LDAR requirements in Refinery MACT 1 by monitoring 
for leaks via optical gas imaging in place of the EPA Method 21, using 
monitoring requirements to be specified in a not-yet-proposed appendix 
K to 40 CFR part 60. For marine vessel loading, we proposed to amend 
the Marine Tank Vessel Loading Operations MACT standards (40 CFR part 
63, subpart Y) to require small marine vessel loading operations (i.e., 
operations with HAP emissions less than 10/25 tpy) and offshore marine 
vessel loading operations at petroleum refineries to use submerged 
filling based on the cargo filling line requirements in 46 CFR 153.282.
    We also proposed an additional work practice standard under the 
technology review to manage fugitive emissions from the entire 
petroleum refinery through a fenceline monitoring and corrective action 
standard. As part of the work practice standard, we specified the 
monitoring technology and approach that must be used, and we developed 
a fenceline benzene concentration action level above which refinery 
owners or operators would be required to implement corrective action to 
reduce their fenceline concentration to below this action level. The 
action level we proposed was consistent with the emissions projected 
from fugitive sources compliant with the provisions of the refinery 
MACT standards as modified by the additional controls proposed for 
storage vessels.
b. Refinery MACT 2
    The Refinery MACT 2 source category regulates HAP emissions from 
FCCU, CRU and SRU process vents. We

[[Page 75191]]

proposed to revise Refinery MACT 2 to incorporate the developments in 
monitoring practices and control technologies reflected in Refinery 
NSPS subpart Ja (73 FR 35838). This included proposing to incorporate 
the Refinery NSPS subpart Ja PM limit for new FCCU sources and to 
revise the monitoring provisions in Refinery MACT 2 to require all FCCU 
sources to meet operating limits consistent with the requirements in 
Refinery NSPS subpart Ja. The existing MACT standard provided that a 
refiner could demonstrate compliance with the PM limit in the MACT by 
meeting the 30-percent opacity limit requirement of Refinery NSPS 
subpart J; we proposed to eliminate that provision and instead 
establish control device operating limits or site-specific opacity 
limits similar to those required in Refinery NSPS subpart Ja. We also 
proposed to incorporate the use of 3-hour averages rather than daily 
averages for monitoring data to demonstrate compliance with the FCCU 
site-specific opacity and Ni operating limits. We proposed additional 
control device-specific monitoring alternatives for various control 
devices on FCCU, including BLD monitoring as an option to COMs for 
owners or operators of FCCU using fabric filter-type control systems, 
and total power and secondary current operating limits for owners or 
operators of ESPs. We also proposed to add a requirement to perform 
daily checks of the air or water pressure to atomizing spray nozzles 
for owners or operators of FCC wet gas scrubbers. Finally, we proposed 
to require a performance test once every 5 years for all FCCU in place 
of the one-time performance test required by the current Refinery MACT 
2.
    At proposal, we did not identify any developments in practices, 
processes and control technologies for CRU process vents based on our 
technology review. For SRU, we proposed to include the Refinery NSPS 
subpart Ja allowance for oxygen-enriched air as a development in 
practice and to allow SRU to comply with Refinery NSPS subpart Ja as a 
means of complying with Refinery MACT 2.
2. How did the technology review change for the Petroleum Refinery 
source categories?
a. Refinery MACT 1
    We are finalizing most of our technology review decisions for 
Refinery MACT 1 emissions sources as proposed; however, as described 
briefly below, we are revising certain proposed requirements.
    We are not taking final action adopting the use of appendix K to 40 
CFR part 60 for optical gas imaging for refinery equipment subject to 
the LDAR requirements in Refinery MACT 1 because we have not yet 
proposed appendix K.
    After considering the public comments, we are finalizing the 
proposed fenceline monitoring requirements, with a few revisions. 
First, we have made numerous clarifications in this final rule to the 
language for the fenceline monitoring siting method and analytical 
method (i.e., Methods 325 A and B, respectively). Specific comments on 
these methods, along with our responses and explanations of the 
revisions to the regulatory text are discussed in the ``Response to 
Comment'' document. Second, we are finalizing a revised compliance 
schedule for fenceline monitoring, which will require refinery owners 
or operators to have the fenceline monitors in place and collecting 
benzene concentration data no later than 2 years from the effective 
date of the final rule, as opposed to 3 years in the proposed rule. 
Third, we have removed the requirement for refinery owners or operators 
to obtain the EPA approval for the corrective action plan. Fourth, we 
are requiring the submittal of the fenceline monitoring data on a 
quarterly basis, as opposed to on a semiannual basis as proposed. 
Fifth, we are providing guidelines for operators to use in requesting 
use of an alternative fenceline monitoring technology to the passive 
sorbent samplers set forth in Method 325B. Finally, to reduce the 
burden of monitoring, we are finalizing provisions that would allow 
refinery owners or operators to reduce the frequency of fenceline 
monitoring for areas that consistently stay well below the fenceline 
benzene concentration action level. Specifically, we are allowing 
refinery owners or operators to monitor every other two weeks (i.e., 
skip period monitoring) if over a two-year period, each sample 
collected at a specific monitoring location is at or below 0.9 [mu]g/
m\3\. If every sample collected from that sampling location during the 
subsequent 2-years is at or below 0.9 [mu]g/m\3\, the monitoring 
frequency may be reduced from every other two weeks to quarterly. After 
an additional two years, the monitoring can be reduced to semiannually 
and finally to annually, provided the samples continue to be at or 
below 0.9 [mu]g/m\3\ during all sampling events at that location. If at 
any time a sample for a monitoring location that is monitored at a 
reduced frequency returns a concentration greater than 0.9 [mu]g/m\3\, 
the owner or operator must return to the original sampling requirements 
for one quarter (monitor every two weeks for the next six monitoring 
periods for that location); if every sample collected from this quarter 
is at or below 0.9 ug/m\3\, then the sampling frequency reverts back to 
the reduced monitoring frequency for that monitoring location; if not 
then the sampling frequency reverts back to the original biweekly 
monitoring frequency.
b. Refinery MACT 2
    We are finalizing, as proposed, our determination that it is not 
necessary to revise the requirements for CRU pursuant to the technology 
review and we are finalizing our determination that it is necessary to 
revise the MACT for SRU and FCCU. For SRU, we are finalizing the 
revisions as proposed. For FCCU, we are making modifications to the 
proposed requirements in light of public comment.
    As discussed previously, we proposed to remove the alternative in 
Refinery MACT 2 for owners or operators to demonstrate compliance with 
the PM limits on FCCU by meeting a 30-percent opacity standard as 
provided in Refinery NSPS subpart J and instead make the FCCU operating 
limits in Refinery MACT 2 consistent with Refinery NSPS subpart Ja. 
Based on the Refinery NSPS subpart J review in 2008, we determined that 
a 30-percent opacity limit does not adequately assure compliance with 
the PM emissions limit (see discussion in the proposed rule at 79 FR 
36929, June 30, 2014). Thus, we included other monitoring approaches in 
Refinery NSPS subpart Ja.
    Comments received on this proposal, along with data available to 
the Agency, confirmed that the 30-percent opacity standard is not 
adequate on its own to demonstrate compliance with the PM (or metal 
HAP) emissions limit in Refinery MACT 2. We also received comments that 
the site-specific opacity alternative, which is the only compliance 
option proposed for FCCU with tertiary cyclones, would essentially 
require owners or operators with these FCCU configurations to meet an 
opacity limit of 10-percent. According to commenters, opacity increases 
with decreasing particle size, so that it is common to exceed 10-
percent opacity during soot blowing or other similar events that 
produce very fine particulates even though mass emissions have not 
changed appreciably.
    Based on the available data, we have determined that a 20-percent 
opacity operating limit is well correlated with

[[Page 75192]]

facilities meeting a limit of 1.0 lb PM/1,000 lbs coke burn-off. 
Therefore, we are retaining the option in Refinery MACT 2 to comply 
with Refinery NSPS subpart J except we are adding a 20-percent opacity 
operating limit in Refinery MACT 2, evaluated on a 3-hour basis. To 
ensure that FCCU owners or operators complying with the Refinery NSPS 
subpart J option can meet the 1.0 lb PM/1,000 lbs emissions limit at 
all times, we are finalizing requirements that owners or operators 
conduct the performance test during higher PM periods, such as soot 
blowing. Where the PM emissions are within 80-percent of the PM limit 
during any periodic performance test, we are requiring the refinery 
owner or operator to conduct subsequent performance tests on an annual 
basis instead of on a 5-year basis.
    We are finalizing our proposed requirement that compliance with the 
control device operating limits in the other compliance alternatives be 
demonstrated on a 3-hour basis, instead of the 24-hour basis currently 
allowed in Refinery MACT 2.
3. What key comments did we receive on the technology review, and what 
are our responses?
a. Refinery MACT 1
    The majority of comments received regarding the proposed amendments 
to Refinery MACT 1 pursuant to our technology review dealt with the 
proposed fenceline monitoring requirements. The primary comments on the 
fenceline monitoring requirements are in this section along with our 
responses. Comment summaries and the EPA's responses for additional 
issues raised regarding the proposed requirements resulting from our 
technology review are in the ``Response to Comment'' document in the 
public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
i. Legal Authority and Need for Fenceline Monitoring
    Comment: Numerous commenters claimed that the proposed fenceline 
monitoring program would unlawfully impose what is effectively an 
ambient air quality standard for benzene, which is not authorized by 
CAA section 112, which only authorizes the control of emission sources. 
The commenters argued it is an ambient standard because sources are 
required to meet the benzene level set or ``perform injunctive relief 
which may or may not address the source of the benzene.'' The commenter 
quoted language from the proposal as support that EPA has described the 
benzene level as an ambient standard: ``We are proposing a HAP 
concentration to be measured in the ambient air around a refinery, that 
if exceeded, would trigger corrective action to minimize fugitive 
emissions.'' 79 FR at 36920 (June 30, 2014). The commenter further 
noted that this requirement is not just ``monitoring'' because it 
establishes a ``not-to-be exceeded'' level. Therefore, the commenters 
stated, the EPA should not finalize this portion of the proposal.
    Response: We disagree with the comment that the fenceline proposal 
is an ambient air standard. First, the owner or operator must place the 
monitors on the facility fenceline to measure emissions from the 
facility, i.e., on the property of the refiner. While we recognize that 
we used the term ``ambient air'' in the preamble to the proposal, we 
note that the placement requirements for the monitors make clear that 
the monitors are not monitoring ambient air, which EPA has defined at 
40 CFR 50.1(e) as ``that portion of the atmosphere, external to 
buildings, to which the general public has access.'' Second, the 
proposed EPA Method 325A sets out procedures to subtract background 
concentrations and contributions to the fenceline benzene 
concentrations from non-refinery emission sources, so that the benzene 
concentrations measured are attributable to the refinery. In other 
words, the fenceline monitoring work practice standard uses a benzene 
concentration difference, referred to as the [Delta]C (essentially an 
upwind and downwind concentration difference) to isolate the refinery's 
emissions contribution.
    Furthermore, we disagree that the fact that refiners are required 
to perform corrective action if the fenceline benzene concentration 
action level is exceeded makes the benzene action level an ambient 
standard. As an initial matter sources are not directly responsible for 
demonstrating that an area is meeting an ambient standard; rather that 
burden falls on states. See e.g., CAA section 110(a)(2). Moreover, the 
``corrective action'' is simply that sources must ensure that fugitive 
emission sources on the property are not emitting HAP at levels that 
will result in exceedances of the fenceline benzene concentration 
action level. In other words, the purpose of the fenceline monitoring 
work practice is to ensure that sources are limiting HAP emissions at 
the fenceline, which are solely attributable to emissions from sources 
within the facility. In fact, the fenceline benzene concentration 
action level was established using emissions inventories reported by 
the facilities, assuming compliance with the MACT standards. Finally, 
monitoring is conducted as part of the work practice standard to 
identify sources that will require additional controls to reduce their 
impact on the fenceline benzene concentration. In that sense, the 
fenceline monitoring work practice standard is not different than, for 
example, our MACT standard for refinery heat exchangers. If a facility 
is exceeding the relevant cooling water pollutant concentration 
``level'' when it performs a periodic test, it must undertake 
corrective action to bring the concentration down below the action 
level.
    Comment: Several commenters noted that EPA's authority under 
section 112(d) is to set ``emissions standards'' and quoted the CAA 
definition of that term: ``A requirement . . . which limits the 
quantity, rate, or concentration of emissions of air pollutants on a 
continuous basis, including any requirement relating to the operation 
or maintenance of a source to assure continuous emission reduction, and 
any design, equipment, work practice or operational standard 
promulgated under this Act.'' 42 U.S.C. 7602(k). The commenters argued 
that the proposed fenceline monitoring standard does not meet this 
definition because it would not ``limit the quantity, rate, or 
concentration of emissions'' from any given emissions point. Also, the 
commenters claimed that the EPA did not designate fenceline monitoring 
as a work practice under CAA section 112(h) since the EPA did not even 
mention CAA section 112(h), nor did it conduct any analysis to show 
that fenceline monitoring meets the CAA section 112(h) factors.
    Response: We disagree with the commenters' assertion that the 
proposed fenceline monitoring work practice standard is not authorized 
under CAA section 112(d)(6). Contrary to the commenter's claims, we 
specifically proposed the fenceline monitoring standard under CAA 
section 112(d)(6) to be a work practice standard that is applied 
broadly to fugitive emissions sources located at petroleum refineries. 
As discussed above, the proposed standard does more than impose 
monitoring as some commenters suggested; it also will limit emissions 
from refineries because it requires the owner or operator to identify 
and reduce HAP emissions through a monitoring and repair program, as do 
many work practice standards authorized under CAA Section 112(h) and 
112(d).
    We note that the sources addressed by the fenceline monitoring 
standard--refinery fugitive emissions sources such as wastewater 
collection and treatment

[[Page 75193]]

operations, equipment leaks, heat exchange systems and storage vessels 
in the Refinery MACT 1 rule--are already subject to work practice 
standards. Our review of these requirements indicates that this 
fenceline monitoring work practice standard would be a further 
improvement in the way fugitive emissions are managed and would provide 
an extra measure of protection for surrounding communities. The 
commenter claims EPA did not analyze how the fenceline monitoring 
requirement meets the criteria in section 112(h). However, that is a 
misinterpretation of how the criteria apply. The criteria are assessed 
with regard to whether it is feasible to ``prescribe or enforce an 
emission standard for a source'', and do not apply to the work practice 
standard. Consistent with the criteria in section 112(h)(2), we 
determined and established that work practice standards are appropriate 
for these Refinery MACT fugitive emissions at the time we established 
the initial MACT standard. In the proposal, (79 FR at 36919, June 30, 
2014), we reaffirmed that it is impracticable to directly measure 
fugitive emission sources at refineries but did not consider it 
necessary to reiterate these findings as part of this proposal to 
revise the existing MACT for these sources under CAA section 112(d)(6). 
We note that the commenters do not provide any grounds to support a 
reevaluation of whether these fugitive emission sources are 
appropriately regulated by a work practice standard.
    Comment: Several commenters questioned the EPA's authority under 
the CAA to promulgate a rule that amounts to an ongoing information 
gathering and reporting obligation. The commenters stated that the EPA 
has not demonstrated that the proposed fenceline monitoring program 
represents an actual emission reduction technology improvement. A 
commenter stated that compliance assurance methods, including 
monitoring, for fugitive emissions and other emission standards are 
established as part of the emission standard and EPA's authority to 
gather information that is not directly required for compliance with a 
specific standard but is related to air emissions is found in CAA 
section 114. Under CAA section 114, the requirement must be related to 
one of the stated purposes and must be reasonable. The commenter did 
not believe that the EPA has demonstrated that the costs of fenceline 
monitoring are reasonable in light of the information already available 
to the EPA and in light of many other means by which the EPA could 
obtain such information.
    Response: We disagree with the commenters' assertion that the 
authority for the fenceline monitoring requirement falls under CAA 
section 114 and not CAA section 112(d) because it is an ``ongoing 
information gathering and reporting obligation.'' The issue here is not 
whether EPA could have required the fenceline monitoring requirement 
under CAA section 114, but rather did EPA support that it was a 
development in processes practices or controls technology under section 
112(d)(6).
    As an initial matter, we disagree with the commenters' 
characterization of the fenceline monitoring standard as ``an 
information gathering and reporting obligation.'' We have repeatedly 
stated that we consider the fenceline monitoring requirement to be a 
work practice standard that will ensure sources take corrective action 
if monitored benzene levels (as a surrogate for HAP emissions from 
fugitive emissions sources) exceed the fenceline benzene concentration 
action level. The standard requires refinery owners or operators to 
monitor the benzene concentration at the refinery perimeter, to 
evaluate the refinery's contribution as estimated by taking the 
concentration difference between the highest and lowest concentrations 
([Delta]C) in each period, and to conduct root cause analysis and take 
corrective action to minimize emissions if the concentration difference 
is higher (on an annual average) than the benzene concentration action 
level. Thus, the fenceline monitoring requirement goes well beyond 
``information gathering and reporting.''
    In addition, the commenters again read section 112(d)(6) too 
narrowly by suggesting that a program considered as a development must 
be a ``technology'' improvement. Section 112(d)(6) of the CAA requires 
the EPA to review and revise the MACT standards, as necessary, taking 
into account developments in ``practices, processes and control 
technologies.'' Consistent with our long-standing practice for the 
technology review of MACT standards, in section III.C of the proposal 
(see 79 FR 36900, June 30, 2014), we list five types of 
``developments'' we consider. Fenceline monitoring fits squarely within 
two of those five types of developments (emphasis added):
     Any add-on control technology or other equipment that was 
not identified and considered during development of the original MACT 
standards.
     Any work practice or operational procedure that was not 
identified or considered during development of the original MACT 
standards.
    As used here, ``other equipment'' is clearly separate from and in 
addition to ``add-on control'' technology and is broad enough to 
include monitoring equipment. In this case, fenceline monitoring is a 
type of equipment that we did not identify and consider during 
development of the original MACT standards. Additionally, the fenceline 
standard is a work practice standard, involving monitoring, root cause 
analysis and corrective action not identified at the time of the 
original MACT standards. Therefore, the fenceline requirements are a 
development in practices that will improve how facilities manage 
fugitive emissions and EPA appropriately relied on section 112(d)(6) in 
requiring this standard.
    Comment: Some commenters contended that because the fenceline 
monitoring standard is in essence an ambient standard, the only 
justification that can be used to support it would be under CAA section 
112(f)(2). The commenters stated that EPA determined that the MACT 
standards pose an acceptable level of risk and protect the public 
health with an ample margin of safety and thus, section 112(f) does not 
support imposition of the fenceline monitoring requirement. Several 
commenters stated that the Agency expressly acknowledges that 
imposition of additional emission standards for fugitive emissions from 
refinery sources are not warranted under CAA section 112(f). Some 
commenters suggested that because the existing MACT standards protect 
public health with an ample margin of safety, the fenceline monitoring 
requirement imposes an unnecessary burden on industry because it is not 
necessary to achieve acceptable risk or provide an ample margin of 
safety.
    Response: EPA is not relying on section 112(f)(2) as the basis for 
the fenceline monitoring requirement. As provided in a previous 
response to comment, we disagree with the commenters that the fenceline 
monitoring requirement is an ambient standard and therefore, we do not 
need to consider what authority would be appropriate for establishing 
an ambient standard that would apply to fugitive sources of emissions 
at refineries. We also disagree with the commenters who suggest that 
EPA may not require fenceline monitoring pursuant to section 112(d)(6) 
because EPA has not determined that fenceline monitoring is necessary 
to ensure an acceptable level of risk or the provide an ample margin of 
safety. Section 112(d)(6) does not

[[Page 75194]]

require EPA to factor in the health considerations provided in section 
112(f)(2) when making a determination whether it is ``necessary'' to 
revise the MACT.
    Comment: Commenters stated that the pilot studies undertaken by the 
EPA and pilot studies undertaken by the refining industry (see the API 
Fenceline Study in the docket for this rulemaking) demonstrate either 
that there is no underestimation of emissions and thus, no need for the 
fenceline monitoring work practice standard, or that fenceline benzene 
data cannot be used to validate emission estimates. Commenters stated 
that none of the refineries in the API study of the proposed refinery 
fenceline standard had study-averaged [Delta]C concentrations that 
exceeded the proposed action level of 9 [micro]g/m\3\ and thus the 
study provides some evidence that U.S. refineries are not 
underestimating emissions. Furthermore, the commenter stated that there 
is significant ambient air monitoring performed that further supports 
low benzene concentrations in the vicinities of refineries and cited 
ambient monitoring data collected by the Southeast Texas Regional 
Planning Commission Air Quality Group and the Texas Commission on 
Environmental Quality (TCEQ).
    Response: We disagree that the API fenceline study demonstrates 
that there is no underestimation of emissions. The API report referred 
to by the commenter actually shows higher [Delta]C concentrations than 
what we expected, when we compare the distribution of [Delta]C's 
presented in the API fenceline study to the distribution of benzene 
concentrations at the 142 refineries we modeled (see memorandum 
``Fenceline Ambient Benzene Concentrations Surrounding Petroleum 
Refineries'', EPA-HQ-OAR-2010-0682-0208). [Note that API did not 
identify the facilities in their study, so we were not able to perform 
a one-to-one comparison of the measured [Delta]C concentrations with 
the modeled fenceline concentrations.] Furthermore, the API conducted 
the study primarily during the fall and winter months (October to 
March) when the ambient temperatures are lower than the annual 
averages. While this may not impact equipment leak emissions, 
temperature can have a significant impact on emissions from storage 
vessels and wastewater treatment systems, so it is likely that the 
annual average [Delta]C for the facilities tested could be higher than 
the ``winter'' averages measured in the API study. Based on our review 
of the API study data, we interpret the results to indicate that there 
may be higher concentrations of benzene on the fenceline attributable 
to fugitive emissions than anticipated at some facilities. These 
studies are an indication that the standard we are finalizing will 
achieve the goal of ensuring that the owners or operators manage 
fugitive emissions within the refinery.
    This regulatory approach also fits with the EPA's goals to improve 
the effectiveness of rules. Specifically, in this case, we are 
improving the effectiveness of the rule in two ways. First, we are 
establishing a fenceline benzene trigger to manage overall fugitive HAP 
emissions, rather than establishing further requirements on many 
individual emission points. Secondly, the rule incentivizes facilities 
to reduce fugitive HAP emissions below the fenceline benzene trigger by 
providing regulatory options for reduced monitoring.
    Regarding ambient monitoring data, we note that existing ambient 
monitors are not located at the fenceline; they are located away from 
sources, and concentrations typically decrease exponentially with 
distance from the emissions source. We are encouraged that data 
referenced by the commenter indicate that ambient levels of benzene are 
within levels that are protective of human health in communities, but 
note that analysis of benzene concentrations in communities does not 
necessarily indicate that refineries located near these communities are 
adequately managing their fugitive HAP emissions.
    Comment: Several commenters reiterated that they do not believe the 
proposed fenceline monitoring is a technology development for equipment 
leaks, storage vessels or wastewater sources. However, if the EPA 
finalizes the fenceline monitoring requirements, the commenters 
suggested that there is no longer a need or regulatory basis for 
imposing both the fenceline monitoring requirements and the existing 
MACT standards for fugitive HAP emission sources. Thus, the EPA should 
remove the current MACT requirements for LDAR, storage vessels and 
wastewater handling and treatment from Refinery MACT 1 if the EPA 
promulgates fenceline monitoring. Addition of fenceline monitoring on 
top of the existing MACT requirements, they argue, would violate the 
Executive Order 12866 mandate to avoid redundant, costly regulatory 
requirements that provide no emission reductions.
    Response: We disagree that the fenceline monitoring standards we 
are finalizing in this rule are redundant to MACT emissions standards 
for fugitive HAP emissions sources. The MACT standards impose 
requirements on fugitive HAP emissions sources consistent with the 
requirements in CAA section 112(d)(2) & (3), and the fenceline 
monitoring requirement is not a replacement for those requirements. 
Rather, based on our review of these standards, we concluded that 
fenceline monitoring is a development in practices, processes or 
control technologies that would improve management of fugitive 
emissions in a cost-effective manner. In selecting this development as 
an across-the-board means of improving management of fugitive 
emissions, we rejected other more costly developments that would have 
applied independently to each fugitive emissions source. Requiring 
refineries to establish a fenceline monitoring program that identifies 
HAP emission sources that cause elevated benzene concentrations at the 
fenceline and correcting high emissions through a more focused effort 
augments but does not replace the existing requirements. We found that, 
through early identification of significant fugitive HAP releases 
through fenceline monitoring, compliance with the existing MACT 
standards for these emissions sources could be improved and that it was 
necessary to revise the existing standards because fenceline monitoring 
is a cost-effective development in processes, practices, and control 
technologies.
    We note that the existing MACT requirements are based on the MACT 
floor (the best performers), and as such, provide a significant degree 
of emission reductions from the baseline. The action level for the 
fenceline work practice standard, by contrast, is not based on the best 
performers but rather on the highest value expected on the fenceline 
from any refinery, based on the modeling of refinery emission 
inventories. As such it is not representative of the best performers 
and could not be justified as meeting the requirements of section 
112(d)(2)and (3). If we were to remove the existing standards for 
fugitive emission sources at the refinery, we would not be able to 
justify that sources are meeting the level of control we identified as 
the MACT floor when we first promulgated the MACT. Nor could we justify 
the fenceline monitoring program we are promulgating as representing 
the MACT floor because we considered cost (and not the best performers 
as previously noted) in identifying the components of the program. 
Although the fenceline monitoring standard on its own cannot be 
justified as meeting the MACT floor requirement for each of the 
separate

[[Page 75195]]

types of fugitive emission sources, that does not mean that it is not 
an effective enhancement of those MACT requirements. To the contrary, 
it works in tandem with the existing MACT requirements to provide 
improved management of fugitive emissions and, in that sense, it is 
precisely the type of program that we believe Congress had in mind when 
enacting section 112(d)(6).
ii. Rule Should Require Real-Time Monitoring Technology for Fenceline 
Monitoring.
    Comment: Numerous commenters stated that the proposed fenceline 
standards, which require monitoring using 2-week integrated passive 
samplers, are flawed and weak for a number of reasons, including that 
the monitoring method does not provide real-time data, does not provide 
adequate spatial coverage of the fenceline, and does not provide a 
mechanism to identify the specific emission source impacting the 
fenceline to manage fugitive emissions. Several commenters suggested 
that this monitoring technology is not state of the art. They claimed 
that there are superior systems in place at refineries that are 
technically and economically feasible, including at Shell Deer Park, 
Texas; BP Whiting, Indiana; and Chevron Richmond, California. Further, 
they claimed that these systems more effectively achieve the objective 
of reducing fugitive emissions. They claimed several systems are 
superior to the proposed system, including open-path systems such as 
ultraviolet differential optical absorption (UV DOAS) and Fourier 
transform infrared spectroscopy (FTIR), as well as point monitors such 
as gas chromatographs. A number of commenters suggested that open-path 
monitors should be required, stating that this technology is capable of 
providing real-time analysis and data on air pollution, is able to 
analyze multiple pollutants simultaneously at low, near-ambient 
concentrations, and is capable of providing more complete geographic 
coverage.
    The commenters also stated that the benefits of real-time monitors 
are particularly important in communities close to refineries, where 
they believe refinery emissions are a major source of toxic pollutants 
and short-term upset events that can have significant public health 
impacts. In particular, the commenters stated that open-path monitors 
promote an individual's right-to-know, in real-time, about harmful 
pollution events affecting their communities, and will allow refinery 
owners or operators to immediately identify fugitive emissions and 
undertake swift corrective action to reduce these emissions. Some 
commenters suggested that, if the EPA rejects these open-path real-time 
monitors, then at a minimum the EPA should require the use of active 
daily monitoring, such as auto-gas chromatograph (GC) systems.
    Finally, a number of commenters recommended that the EPA provide 
sufficient flexibility in its regulations to allow state and local 
jurisdictions to develop, demonstrate, and subsequently require the use 
of alternative monitoring programs, provided these monitoring programs 
are at least equivalent to those in the final rule.
    Response: We understand that many commenters believe real-time 
monitoring would not only help refinery owners or operators in 
identifying emission sources, but also would warn the community of 
releases in real time.
    Both open-path systems and active sampling systems (such as auto-
GCs) mentioned by the commenters, are monitoring systems capable of 
yielding monitoring data quickly--ranging from a few minutes to about a 
day. However, these ``real-time'' systems have not been demonstrated to 
be able to achieve all of the goals stated by the commenters--
specifically, able to provide real-time analysis and data on multiple 
pollutants simultaneously at low-, near-ambient concentrations, with 
more complete geographic (or spatial) coverage of the fenceline.
    The real-time open-path systems suggested by the commenters are all 
limited in that they are not sensitive enough to detect benzene at the 
levels needed to ensure that fenceline monitoring achieves its intended 
goal. The fenceline monitoring system needs to be capable of measuring 
at sub-ppbv levels--well below the 9 [mu]g/m\3\ fenceline benzene 
concentration action level in the final rule, in order to determine the 
[Delta]C. In the proposal, we discussed two open-path monitoring 
technologies, FTIR and UV-DOAS. For the proposed rule, we analyzed the 
feasibility of employing UV-DOAS over FTIR because the UV-DOAS is more 
sensitive to detection of benzene than FTIR, as we described in the 
proposal. We reviewed performance data on several UV-DOAS systems in 
support of the proposed rule, and for this final rule, we considered 
information submitted during the comment period. We found that the 
lowest detection limit reported for any commercially-available UV-DOAS 
system is on the order of 3 ppbv over a 200-meter path length, whereas 
the fenceline benzene concentration action level is 2.8 ppbv 
(equivalent concentration to 9 [mu]g/m\3\). This system is being 
installed at the Shell Deer Park refinery but has not been field 
validated yet. Thus, we do not yet know the detection capabilities of 
the system, as installed. Based on the lowest reported detection limit, 
it cannot achieve the detection levels needed to demonstrate compliance 
with the fenceline standard in this final rule. This system also will 
only cover approximately 5 percent of the fenceline at Shell Deer Park, 
instead of the full fenceline coverage of the passive diffusive tube 
monitoring system we proposed. Facilities would have to deploy a 
monitoring system consisting of many open-path monitors to achieve the 
same spatial coverage as the passive diffusive tube monitoring system.
    For the final rule, we also reviewed other UV-DOAS systems in 
operation at refineries that commenters identified. However, reported 
detection limits for these systems are even higher than for the type of 
system being installed at Shell Deer Park. For example, we reviewed the 
open-path UV-DOAS system information from BP Whiting and found that 
they were able to verify a detection limit of 8 ppbv path average 
concentration for benzene over a 1,500-meter optical path. This is well 
above the 2.8 ppbv fenceline benzene concentration action level, let 
alone the sub-ppbv levels necessary to determine the [Delta]C. 
Moreover, this system, though commercially available, was optimized by 
developing alternative software to improve the detection limit (see 
memorandum ``Meeting Minutes for April 21, 2015, Meeting Between the 
U.S. EPA and BP Whiting'' in Docket ID No. EPA-HQ-OAR-2010-0682). Thus, 
the system, as installed, would not be readily available to other 
refineries. We reviewed data for the UV-DOAS system at the Chevron 
Richmond refinery and found that this system, with optical path lengths 
ranging from 500 to 1,000 meters, has a reported benzene detection 
limit of 5 ppbv averaged over the path length. Again, this is above the 
fenceline benzene concentration action level at the fenceline 
established in this final rule. In addition, we could not find any 
information to support the reported detection limit. We note that the 
public Web site operated by the City of Richmond, California indicates 
that information provided by the system is informational only, not 
quality assured, and not to be used for emergency response or health 
purposes.
    We also disagree with the commenter's claim that if the EPA does 
not finalize requirements for real-time open-path monitors then, at a 
minimum, the EPA should require active daily monitoring. There are two 
methods of

[[Page 75196]]

active monitoring. One method, which we will refer to as the ``auto-GC 
method,'' uses a dedicated gas chromatograph at each monitoring 
location and can return ambient air concentration results multiple 
times a day or even hourly. The other method, which we refer to as 
``method 2,'' uses an active pump to collect gas in a sorbent tube or 
in an evacuated canister over a 1-day period, for later analysis at a 
central location. While active sampling monitoring networks are capable 
of measuring multiple pollutants and would likely be able to detect 
benzene at sub-ppbv levels as necessary to demonstrate compliance with 
the fenceline requirements in this final rule, they consist of discreet 
monitors and would not provide any better spatial coverage of the 
refinery fenceline than a passive diffusive tube monitoring network. 
Further, as shown in Table 9 of the proposed rule (see 79 FR 36923, 
June 30, 2014), like open-path systems, an active sampling monitoring 
network would cost many times that of a passive diffusive tube 
monitoring network. At proposal, we estimated the costs of active daily 
sampling based on ``method 2'' to be approximately 10 times higher than 
for the proposed passive monitoring (see memorandum ``Fenceline 
Monitoring Technical Support Document'', Docket ID No. EPA-HQ-OAR-2010-
0682-0210). We note that this type of active daily sampling based on 
method 2 does not necessarily yield results within 24 hours as the 
sample analysis would be conducted separately. We did not specifically 
estimate the costs of an auto-GC alternative, but the capital costs 
would be at least 20 to 30 times that for the passive diffusive tube 
system, would require shelters and power supplies at all monitoring 
locations and would have operating costs similar to the ``method 2'' 
active monitoring option we considered.
    To date, there are no commercially-available, real-time open-path 
monitors capable of detecting benzene at the sub-ppbv levels necessary 
to demonstrate compliance with the fenceline requirements in this final 
rule. Only a system that can detect such levels will result in 
effective action by facilities to identify and control fugitive 
emissions in excess of those contemplated by the MACT standards. 
Further, active monitoring systems, while potentially capable of 
detecting benzene at sub-ppbv levels, like open-path systems, become 
very costly when enough monitors are located around the facility to 
approach the spatial coverage of the passive diffusive tubes. However, 
we believe that the state of technology is advancing and that the 
capabilities of these systems will continue to improve and that the 
costs will likely decrease. If a refinery owner or operator can 
demonstrate that a particular technology would be able to comply with 
the fenceline standards, the owner or operator can request the use of 
an alternative test method under the provisions of 40 CFR 63.7(f). A 
discussion of the specific requirements for these requests can be found 
in the first comment and response summary of Chapter 8.3 of the 
``Response to Comment'' document.
    Comment: One commenter stated that the required monitoring should 
include real-time monitoring of all chemicals released by refineries 
that pose risks to human health. The commenter stated that the limited 
scope of monitoring required by the proposed rule appears to be guided 
by the EPA's judgment that fugitive, or ``unintended'' emissions pose 
the greatest threat to public health. On the contrary, communities may 
well suffer from the effects of chemicals released into the air under 
normal, permitted emissions. A more expansive monitoring strategy would 
account for both routine and fugitive emissions.
    Several commenters noted that monitoring is limited to benzene as 
opposed to multiple HAP. One commenter noted that ill health 
experienced by refinery neighbors is due in large part to the 
synergistic effects of multiple chemicals. Therefore, the commenter 
stated that it is essential that the rule require monitoring of the 
full range of chemicals with health implications. Other commenters 
recommended that the fenceline monitoring requirement be amended to 
include additional contaminants, such as VOC, that may negatively 
impact human health and the environment. Conversely, other commenters 
stated that the EPA has appropriately selected benzene as a target 
analyte and surrogate for HAP emissions from petroleum refineries, as 
benzene is a common constituent in refinery feedstocks and numerous 
refinery streams, and is present in most HAP-containing streams in a 
refinery.
    Response: As part of the CAA section 112(d)(6) technology review, 
the EPA identified the fenceline monitoring standard as a development 
in practices, processes or control technologies that could improve 
management of fugitive HAP emissions. Thus, to the extent the commenter 
is suggesting that the EPA require the fenceline monitoring system to 
monitor for emissions of non-HAP pollutants, such request goes beyond 
the scope of our action. Furthermore, to the extent that the commenter 
is raising health concerns, although we address residual risk remaining 
after implementation of the MACT standards under CAA section 112(f)(2), 
we note that the MACT standards themselves, including this requirement, 
are aimed at protecting public health, especially in surrounding 
communities. As we explained in the proposal, and as we determine for 
this final rule, the MACT standards as modified by additional 
requirements for storage vessels, provide an ample margin of safety to 
protect public health. We did not propose and are not finalizing a 
fenceline monitoring requirement as necessary to provide an ample 
margin of safety under CAA section 112(f)(2).
    Petroleum refining emissions can contain hundreds of different 
compounds, including many different HAP, and no single method can 
detect every HAP potentially emitted from refineries. While several HAP 
are amenable to quantification via passive diffusive tube monitoring 
using the same adsorbent tubes used for benzene (e.g., toluene, xylenes 
and ethyl benzene, which have uptake rates in Table 12.1 in Method 
325B), we selected benzene as a surrogate because it is present in 
nearly all refinery fugitive emissions. By selecting a single HAP as a 
surrogate for all fugitive HAP, we are able to establish a clear action 
level, which simplifies the determination of compliance for refinery 
owners or operators and simplifies the ability of regulators and the 
public to determine whether sources are complying with the work 
practice standard. As described in the proposal preamble, benzene is 
ubiquitous at refineries and present in nearly all refinery process 
streams, including crude oil, gasoline and wastewater. Additionally, 
benzene is primarily emitted from ground level, fugitive sources that 
are the focus of the work practice standard. Thus, we conclude that 
monitoring of benzene is appropriate and sufficient to identify 
emission events for which the monitoring program is targeting. 
Consequently, we are not requiring quantification of other pollutants 
although refinery owners or operators could choose to analyze the 
diffusive tube samples for additional HAP in conducting root cause 
analysis and corrective action.
iii. Fenceline Monitoring Action Level
    Comment: Several commenters stated that the action level for 
fenceline monitoring (i.e., 9 [mu]g/m\3\ or 2.8 ppbv), was set too 
high. Some of these commenters noted that the EPA selected 9 [mu]g/m\3\ 
as the highest modeled benzene

[[Page 75197]]

concentration at any refinery fenceline. One commenter stated that this 
was arbitrary and capricious and stated the action threshold level 
makes little sense because only 2 of the 142 modeled facilities are 
expected to have fenceline concentrations above 4 [mu]g/m\3\. Several 
commenters noted that the average modeled benzene concentration is 0.8 
[mu]g/m\3\, which is more than an order of magnitude less than the 
proposed fenceline benzene concentration action level.
    Two commenters argued for a lower action level threshold, citing 
the proposed California OEHHA rule, which finalized new and revised 
benzene reference exposure levels (REL) that are more stringent than 
the ones the EPA used in the residual risk assessment supporting the 
proposed rule.
    Two commenters stated that while the fenceline benzene 
concentration action level of 9 [mu]g/m\3\ is relatively protective 
compared to standards adopted by many states, including Louisiana and 
Texas, it is still 80-percent higher than the European Union's standard 
of 5 [mu]g/m\3\. The commenter urged the agency to consider adopting a 
stricter standard comparable to what other industrialized nations use.
    Several commenters stated that the EPA's 9 [mu]g/m\3\ action level 
is inconsistent with the statutory text and objectives of CAA sections 
112(d) and (f), which direct the EPA to focus on the best-performing, 
lowest-emitting sources, in order to require the ``maximum achievable'' 
emission reductions. The commenters stated that the EPA promulgated the 
9 [mu]g/m\3\ limit without properly following the statutory 
requirements for establishing MACT floor limits, pointing out that the 
EPA made no determination of whether or not these general models were 
representative of the emissions levels actually achieved by the 
submitting refinery, and no connection was drawn between the best 
performing sources and the eventual 9 [mu]g/m\3\ limit.
    On the other hand, several commenters opposed the 9 [mu]g/m\3\ 
action level suggesting that it was not achievable and that it is 
arbitrary. Some commenters noted that emission/dispersion models are 
always very site-specific and do not necessarily yield a result that is 
reliable or reproducible. Several commenters stated that additional 
studies are necessary to allow the agency to account for these 
variables and set a more appropriate concentration corrective action 
level. Commenters suggested a 2-year data gathering effort at all 
refineries and data evaluation before determining a specific threshold 
to use.
    Several commenters recommended action levels ranging from 15 [mu]g/
m\3\ to 20 [mu]g/m\3\ of benzene to account for the variability 
expected in monitoring data. The commenters stated that modeling biases 
have underestimated the necessary action level to achieve the stated 
goals of the program.
    Response: First, it is important to note that the purpose of the 
standard has not changed between proposal and promulgation, namely that 
it is a technology-based standard that is an advancement in practices 
to manage fugitive emissions. It is not intended to be a separate or 
new MACT standard promulgated pursuant to CAA sections 112(d)(2) and 
(3) for which a ``floor'' analysis would be required.\7\ Nor is it a 
standard that we are promulgating pursuant to CAA section 112(f)(2) as 
necessary to provide an ample margin of safety to protect public health 
or prevent an adverse environmental effect.\8\ Thus, claims that a 
standard should reflect European Union health-based standards or the 
California OEHHA rule are misplaced. We also disagree with the 
suggestion that the proposed monitoring requirement will allow for 
higher emissions. As noted elsewhere, we are retaining all of the 
source-specific requirements for fugitive emissions sources that exist 
in Refinery MACT 1.
---------------------------------------------------------------------------

    \7\ To the extent that the commenters are suggesting that EPA 
must re-perform the MACT floor analysis for purposes of setting a 
standard pursuant to section 112(d)(6), we note that the D.C. 
Circuit has rejected this argument numerous times, most recently in 
National Association for Surface Finishing et al. v. EPA No. 12-1459 
in the U.S. Court of Appeals for the District of Columbia.
    \8\ Although we did not establish this limit to address residual 
risk under CAA section 112(f)(2), the limit was derived from the 
same inventory used for our risk modelling. Thus, based on our 
current reference concentration for benzene, the 9 [mu]g/m\3\ action 
level will also ensure that people living near the refinery will not 
be exposed to cancer risks exceeding 100-in-1 million.
---------------------------------------------------------------------------

    We disagree with the commenters that suggest that the proposed 
action level of 9 [mu]g/m\3\ is too low and may not be achievable even 
for well-performing facilities. As discussed in the preamble for the 
proposed rule, we selected the 9 [mu]g/m\3\ benzene action level 
because it is the highest value on the fenceline predicted by the 
dispersion modeling and, thus, is a level that we estimate that no 
refinery should exceed when in full compliance with the MACT standards, 
as amended by this final rule. All of the results of our pilot study, 
the API study, and the other ambient monitoring data near refineries 
clearly indicate that this level is achievable. Furthermore, we expect 
the fenceline concentration difference measured following the 
procedures in the final rule to be indicative of refinery source 
contributions and we have provided procedures to isolate these 
concentrations from outside sources, as well as background.
    We expect that the fenceline monitoring standard will result in 
improved fugitive HAP emissions management as it will alert the 
refinery owners or operators of fugitive sources releasing high levels 
of HAPs, such as large leaks, faulty tank seals, etc.
iv. Fenceline Monitoring Root Cause Analysis and Corrective Action 
Provisions
    Comment: A number of commenters objected to the proposal's ``open-
ended'' provisions allowing the EPA to direct refinery owners or 
operators to change their operations in order to achieve the fenceline 
limit, with no regulatory limits on costs and without consideration of 
the impact to safe operations or operability of the plant. Another 
commenter stated that the EPA must properly assess the costs associated 
with the root cause analysis/corrective action requirements and should 
establish a cost effectiveness threshold for any required root cause 
analysis/corrective action to ensure that limited resources are 
effectively and efficiently applied for the control of emissions.
    One commenter stated the proposed fenceline benzene concentration 
action level is effectively an ambient air standard, because corrective 
action to achieve that level is required and that if a facility's 
initial corrective action is unsuccessful, the rule provides that 
further action is required and the EPA must approve that further 
corrective action plan. Thus, the commenter argued, the EPA would 
essentially be able to dictate corrective actions, with no bounds on 
what could be required and no consideration of whether any cost-
effective actions are available to assure the action level is met. The 
commenter continued that such a requirement converts a work practice 
program to an emission limitation and such ambient air limits are not 
authorized by CAA section 112. Several commenters noted that LDAR and 
current work practice programs have no similar requirement for the EPA 
approval, and the commenters suggested that the requirement for the EPA 
approval of any second corrective action should not be included in 40 
CFR 63.658(h).
    Another commenter recommended that, if after corrective action, a 
facility still has an exceedance for the next sampling episode, then 
the facility should be required to do more than it

[[Page 75198]]

did after the first root cause analysis, as the prior corrective action 
clearly did not correct the problem. The commenter stated that one 
corrective action measure the EPA should include in all such instances 
is higher-quality monitoring such as UV-DOAS for at least 1 year to 
monitor, identify, correct and assure ongoing compliance after the 
exceedance problem is fixed.
    Response: The ``on-going'' requirement to achieve the fenceline 
benzene concentration action level is no different in concept from the 
LDAR requirements for equipment or heat exchange systems in the 
Refinery MACT 1 rule, which requires the refinery owner or operator to 
repair the source of the emissions regardless of what it takes until 
compliance with the standard is achieved.
    We disagree with the claim that the EPA must assess the costs 
associated with the root cause analysis/corrective action requirements 
and establish a cost effectiveness threshold for any required root 
cause analysis/corrective action to ensure that limited resources are 
effectively and efficiently applied for the control of emissions. We 
did not attempt to project the costs of the root cause analysis/
corrective action for at least two reasons. First, based on the 
dispersion modeling of the benzene emissions reported in response to 
the inventory section of the 2011 ICR, we project that no refinery 
should exceed that fenceline benzene concentration action level if in 
full compliance with the MACT standards, as amended by this action. 
Thus, assuming compliance with the MACT standards, we would expect that 
there are no costs for root cause analysis/corrective action. To the 
extent that there are exceedances of the action level, the premise of 
the fenceline monitoring is to provide the refinery owners or operators 
with the flexibility to identify the most efficient approaches to 
reduce the emissions that are impacting the fenceline level. Since the 
choice of control is a very site-specific decision, we would have no 
way to know how to estimate the costs. Thus, the source is in the best 
position to ensure that resources are effectively and efficiently spent 
to address any exceedance.
    We intended the proposed requirement for refinery owners or 
operators to submit a corrective action plan for the EPA approval to 
provide the Administrator with information that they were making a 
good-faith effort to reduce emissions below the fenceline benzene 
concentration action level, as expeditiously as practicable. However, 
we understand the importance for refinery owners or operators to begin 
corrective action as soon as possible, without having to wait for the 
EPA approval. Therefore, we are finalizing the requirement for refinery 
owners or operators to submit such plans but we are not finalizing the 
requirement that the EPA must approve the plan prior to the corrective 
action being taken.
    We previously responded to comments regarding UV-DOAS or other 
open-path monitoring systems in this section, explaining that the 
current detection limits for these systems exceeds the action level 
threshold and, thus, these systems would not provide usable data to 
inform corrective action. Thus, we disagree that the EPA should require 
these systems for all facilities whose first attempt at corrective 
action is ineffective.
v. Fenceline Monitor Siting Requirements
    Comment: Numerous commenters provided suggestions on, or requested 
clarification of, the monitor siting requirements. Several commenters 
stated that proposed Method 325A uses the terms ``fenceline or property 
boundary,'' while it should consistently use the term ``property 
boundary'' or even ``property line'' as the fenceline location. Several 
commenters stated that Sections 8.2.2.1.4 and 8.2.2.3 of Draft Method 
325A specify that samplers be placed just beyond the intersection where 
the measured angle intersects the property boundary and this could 
require placing monitors on other people's property, in a road, in a 
water body or in a railroad right-of-way. The commenters suggested that 
facilities should be allowed to place monitors at any vector location 
that meets other requirements between the property boundary and the 
source nearest the property boundary. They stated that facilities need 
this clarification to avoid obstructions (e.g., buildings or trees) 
that may be at the property line.
    Numerous commenters requested that the rule clarify where monitors 
need to be placed in special circumstance, such as refineries bisected 
by a road, railroad or other public right-of-way or a boundary next to 
a navigable waterway. Several commenters stated that refiners should 
not need to place monitors on these property boundaries or other 
property boundaries where there are no residences within 500 feet of 
the property line. Commenters also asked if areas that had non-refinery 
operations, but are still inside the property boundary, would be 
included for purposes of determining where to site monitors.
    A few commenters expressed concern about the approach for 
determining the number of required monitors at a site based on the 
acreage, noting that it is unfair to small facilities and will leave 
gaps in monitoring coverage for very large facilities. Some commenters 
recommended amending the proposed rule to require the placement of 
fenceline monitors at fixed distances along facilities' perimeters with 
no maximum number of monitors. Some commenters stated that the rule 
should specify an acceptable range on the 2,000-foot spacing 
requirement or the radial placement requirement as it may be necessary 
to address accessibility or safety concerns. Several commenters 
suggested that a lower minimum number of sampling monitors should be 
required for very small refineries or small ``subareas.'' These 
commenters noted that refineries often include disconnected parcels 
that can be very small (e.g., 10 acres or less). If each disconnected 
parcel must be treated as a separate subarea, then both sampler siting 
options in Draft Method 325A would result in unnecessarily large 
numbers of samplers extremely close together. Some commenters 
recommended that Method 325A specify that samplers need not be placed 
closer than 500 feet (versus the normal 2,000-foot interval specified 
in Option 2) along the fenceline from an adjoining sampler, regardless 
of whether the radial or linear approach is used and should waive the 
minimum number of samplers specified in Sections 8.2.2.1.1, 8.2.2.2.1, 
and 8.2.3.1. Another commenter added that the rule should waive the 
requirement for additional samplers in Sections 8.2.2.1.5 and 8.2.3.5 
if the 500-foot minimum spacing criterion is compromised.
    Response: We agree that the Method 325A should provide clear and 
consistent language. We have revised the language to be consistent in 
referring to the ``property boundary''. We have also revised the Method 
to allow placement of monitors at any radial distance along either a 
vector location or linear location (that meets the other placement 
requirements) between the property boundary and the source nearest the 
property boundary. That is, the monitors do not need to be placed 
exactly on the property boundary or outside of the property boundary. 
They may be placed within the property closer to the center of the 
plant as long as the monitor is still external to all potential 
emission sources. We do note that if the monitors are placed farther in 
from the property boundary, the owner or operator should take care to 
ensure, if possible, that the radial distance from the sources to the 
monitors is at least 50

[[Page 75199]]

meters. If the perimeter line of the actual placement of the fenceline 
monitors is closer than 50 meters to one or more sources, then the 
additional monitor citing requirements will apply. We have revised 
subparagraphs of Section 8.2.2 to provide this allowance. This 
clarification should address issues related to obstructions such as 
tall walls located at the facility boundary.
    We intended that the fenceline monitoring would create a monitoring 
perimeter capable of detecting emissions from all fugitive emission 
sources at the refinery facility. We have long established that a road 
or other right of way that bisects a plant site does not make the plant 
site two separate facilities, and, thus, would not be considered part 
of the property boundary. As we agree that monitors need only be placed 
around the property boundary of the facility, it would not be necessary 
to place monitors along a road or other right-of-way that bisects a 
facility. We have clarified this in the final rule and Method 325A.
    If the facility is bounded by a waterway on one or more sides, then 
the shoreline is the facility boundary and monitors should be placed 
along this boundary. If the waterway bisects the facility, the waterway 
would be considered internal to the facility and monitors would only be 
needed at the facility perimeter.
    Regarding the comment that monitors should not be required where 
there is no residence within 500 feet of the property line, we 
disagree. We proposed and are finalizing the fenceline monitoring 
standards under CAA section 112(d)(6) as a means to improve fugitive 
HAP emissions management, regardless of whether there are people living 
near a given boundary of the facility.
    Regarding the clarification requested about monitor placement 
considering non-refinery operations, the property boundary monitors 
should be placed outside of all sources at the refinery. This is 
because moving the monitoring line inward to exclude the non-refinery 
source could lead to an underestimation of the [Delta]C compared to the 
monitoring external of the entire site. If the non-refinery source is 
suspected of contributing significantly to the maximum concentration 
measured at the fenceline, a site-specific monitoring plan and 
monitoring location specific near-field interfering source (NFS) 
corrections will be needed to address this situation.
    Section 8.2.3 of Method 325A includes language to provide some 
flexibility when using the linear placement (10% or 250 feet). We consider it reasonable to provide similar placement 
allowance criteria for the radial placement option (1 
degree). We are not providing requirements that would allow small area 
refineries to use fewer than 12 monitoring sites. We do not consider 
that any refinery would be so small as to warrant fewer than 12 
monitors; however, we did not necessarily consider very small subareas 
for irregularly shaped facilities or segregated operations. When 
considering these subareas, we agree that fewer than 12 monitoring 
sites should be appropriate. Therefore, we have provided that monitors 
do not need to be placed closer than 152 meters (500 feet) (or 76 
meters (250 feet) if known sources are within 50 meters (162 feet) of 
the monitoring perimeter, which is likely for these subareas or 
segregated areas) with a stipulation that a minimum of 3 monitoring 
locations be used per subarea or segregated area. We note, however, 
that this distance provision does not obviate the near source extra 
monitoring siting requirements or the requirement to have a minimum of 
three monitors per subarea or segregated area.
    If facility owners or operators have questions regarding the 
required locations of monitors for a specific application, they should 
contact the EPA (or designated authority) to resolve questions about 
acceptable monitoring placement.
vi. Compliance Time for Fenceline Monitoring Requirements
    Comment: Some commenters supported EPA's proposal to provide 3 
years to put a fenceline monitoring program in place, but the 
commenters believe that timing is unclear in the proposed regulatory 
language, which appears in Table 11 to subpart CC, and requested that 
the EPA add the initial compliance date to 40 CFR 63.658(a). One 
commenter stated that instituting this program for all 142 major source 
U.S. refineries would require considerable time. Based on their 
experience with their pilot study, one commenter noted that 
commercially available weather guards meeting the specifications of 
proposed Method 325A are not available and would need to be fabricated. 
Additionally, a commenter stated that only a limited number of 
laboratories in the U.S. are able to perform the necessary analyses. 
According to the commenter, considerable time and effort will be needed 
to qualify additional laboratories and to expand the capacity of 
existing laboratories to handle the samples from 142 refineries.
    Other commenters disagreed with the EPA's proposed compliance time 
and suggested that the EPA shorten the timeline for implementation at 
refineries so that possible corrective action occurs much sooner than 
proposed. The commenters suggested that deployment of passive samplers 
can proceed more promptly than proposed, especially since the EPA has 
simultaneously proposed specific ``monitor siting and sample collection 
requirements as EPA method 325A of 40 CFR part 63, Appendix A, and 
specific methods analyzing the sorbent tube samples as EPA Method 325B 
of 40 CFR part 63, Appendix A.'' Moreover, the commenter noted, a 
principal reason that the EPA selected passive monitors over active 
monitors was due to the relative ``ease of deployment.'' The commenter 
claimed this ease of deployment rationale is undermined by a 3-year 
grace period to deploy passive monitors when the EPA is providing very 
specific criteria for their use. The commenter suggested that the EPA 
require full compliance with the passive monitoring requirement within 
1 year of the effective date of the rule.
    Response: While we realize that it will take some time for the 
refinery owners or operators to understand the final rule and develop a 
compliant monitoring program, we agree that in requiring the passive 
sampler monitoring system, we recognized the ease of implementation and 
deployment. Although industry commenters identified issues they faced 
in the API pilot study while trying to implement the monitoring method, 
we note that the 12 facilities that participated in the API pilot study 
installed the fenceline monitors and began sampling in late 2013 with 
relative ease and within months of obtaining the draft methods. Thus, 
we disagree with the suggestion that 3 years is insufficient and agree 
with other commenters that 3 years is in fact too long. However, we 
also are aware that the API pilot facilities used the direct [Delta]C 
approach proposed and did not attempt to develop site-specific 
monitoring programs to correct for interfering near-field sources. 
Although we expect that facilities could complete direct implementation 
of the proposed fenceline monitoring requirement within 1 year after 
the effective date of the rule, as suggested by some commenters, 
facilities that choose to develop a site-specific monitoring plan would 
need a longer period of time. Therefore, we are finalizing requirements 
that specify that facilities must begin monitoring for the official

[[Page 75200]]

determination of [Delta]C values no later than 2 years after the 
effective date of the rule.
vii. Fenceline Monitoring Recordkeeping and Reporting Requirements
    Comment: Some commenters suggested that facilities should be 
required to submit the monitoring data via the ERT only if they exceed 
the fenceline benzene concentration action level and that all remaining 
data should be kept on-site and available for inspection or upon 
request of the EPA, citing that this is consistent with EPA's 
semiannual NESHAP reporting of only exceptions (i.e., deviations). 
Other commenters requested that the EPA only post the rolling annual 
average concentration values and not the 2-week monitoring data. These 
commenters indicated concern that if errors are present in the raw data 
that are submitted semiannually to the EPA, the data, errors and all, 
will be released to the public and correcting them will not take place 
or will not take place in a timely manner. One commenter added that 
there is very little useful information that can be gleaned from the 
raw data and posting it simply invites misunderstandings.
    Commenters also stated that the EPA should adopt reporting 
requirements to ensure that facilities report the monitoring data 
appropriately. Specifically, commenters recommended that 40 CFR 
63.655(h)(8)(i) should be clarified to only require reporting of valid 
data and cautioned that data should be processed to allow accurate 
calculations of annual averages to be used for reporting and 
evaluation. To accomplish this, commenters recommended that the rule 
provide 75 days from the end of a 6-month sampling period to report to 
the EPA, rather than the proposed 45-day period, in order to provide 
adequate time to obtain quality-assured results for all 2-week sampling 
periods.
    One commenter applauded the proposal's requirements for electronic 
reporting of the fenceline concentration data and making the resulting 
information publicly available. However, the commenter recommended that 
the EPA consider a more truncated data reporting period that is more 
consistent with the associated milestones of collecting a 14-day 
sampling episode. As is, the commenter claimed, the proposed rule would 
have a lag time of up to 7.5 months between data collection and 
posting. The commenter indicated that data reporting on a more frequent 
schedule will not only provide transparency, but will provide states 
and local agencies with information about air quality at refineries at 
a frequency that could allow informed activities to address leaks much 
more quickly and protect public health.
    Response: We disagree with the commenters who suggest that 
facilities only report the rolling annual average or only exceedances 
of the fenceline benzene concentration action level because the 
commenters believe there is little information to be gleaned from the 
raw data. Monitoring data are useful in understanding emissions, 
testing programs, and in determining and ensuring compliance. We 
generally require reporting of all test data, not just values 
calculated from test data and/or where a facility exceeds an emissions 
or operating limit. For example, when we conduct risk and technology 
reviews for source categories, we are adding requirements for 
facilities to submit performance test data into the ERT, not just 
performance test data that indicates an exceedance of an applicable 
requirement. In the Mercury and Air Toxics Rule, we require facilities 
to report direct measurements made with CEMS, such as gas 
concentrations, and we require hourly reporting of all measured and 
calculated emissions values (see discussion at 77 FR 9374, February 16, 
2012). In particular, for the fenceline monitoring requirements in this 
final rule, we offer facilities options for delineating background 
benzene emissions and benzene emissions not attributable to the 
refinery, and we offer options for reduced monitoring, making it even 
more necessary that we have all of the data to review to ensure that 
testing and analyses are being done correctly and in compliance with 
the requirements set out in the regulations, and that root cause 
analyses and corrective actions are being performed where necessary. 
Therefore, as proposed, we are finalizing the requirements that 
facilities report the individual 2-week sampling period results for 
each monitor, in addition to the calculated [Delta]C values in their 
quarterly reporting.
    Regarding commenters' concerns that facilities post accurate data 
and have sufficient time to perform quality assurance on the data, in 
the final rule, we have established provisions for how sources are to 
address outliers and data corrections. Additionally, as proposed, we do 
not require an initial report until facilities have collected 1 year of 
data so that facilities do not report the data until a rolling annual 
average value can be determined. This will allow refinery staff and 
analytical laboratories to iron out any issues that might arise as they 
implement these methods for the first time. Once this initial data 
collection period is complete, we anticipate that data quality issues 
should be infrequent. Therefore, we are providing a 45-day period 
following each quarterly period before facilities must submit the 
monitoring results, which should provide facilities adequate time to 
correct any data errors prior to reporting the data.
    Regarding comments that suggest reporting each 2-week sample result 
soon after its collection, we disagree. This frequency would put undue 
burden on the refinery owners or operators in trying to collect, review 
and quality assure the data prior to reporting. However, we agree with 
commenters that more frequent reporting of the fenceline monitoring 
data would be useful. Therefore, we have revised the reporting 
frequency for the fenceline monitoring data to be quarterly in the 
final rule rather than semiannually as proposed. Additionally, we 
understand that there is a lot of interest in how these data will be 
presented to the public, and we plan to reach out to all stakeholders 
on appropriate approaches for presenting this information in ways that 
are helpful and informative.
b. Refinery MACT 2
    This section provides comment and responses for the key comments 
received regarding the technology review amendments proposed for 
Refinery MACT 2. Comment summaries and the EPA's responses for 
additional issues raised regarding the proposed requirements resulting 
from our technology review are in the ``Response to Comment'' document 
in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
i. FCCU
    We received comments on the consideration of developments in 
pollution controls, the averaging time for FCCU PM limits, and the FCCU 
opacity limit, as discussed below.
    Comment: One commenter stated that the EPA failed to consider 
developments in pollution controls for HAP from FCCUs for two reasons. 
First, the commenter contended that cost is not a valid consideration 
to evaluate if a ``development'' in pollution control is necessary 
pursuant to section 7412(d)(2), (3), (6), unless the EPA is setting a 
``beyond-the-floor'' requirement.
    Second, the commenter claimed that the EPA's review of developments 
is nearly 10 years old and misses some important pollution control

[[Page 75201]]

improvements in the industry. For example, the commenter noted that 
Valero Benicia installed a combination of controls in 2012 including a 
scrubber, SCR and CO Boiler that combine exhaust streams from the FCCU 
and coking and reportedly eliminate HAP emissions entirely from these 
sources.
    The commenter also asserted that EPA consent decrees impose lower 
effective limits on PM than the EPA considered under the technology 
review. The commenter identified the BP Whiting facility as subject to 
0.7 lb PM/1,000 lbs coke burn-off at one FCCU and 0.9 lb PM/1,000 lbs 
coke burn-off at another and claimed these limits are lower than the 
1.0 lb PM/1,000 lbs coke burn-off limit currently mandated by Refinery 
MACT 2.
    Response: We disagree that we cannot consider costs when 
determining if it is necessary to revise an existing MACT standard 
based on developments in practices, processes and control technologies. 
The commenter suggests that we cannot consider costs because of the 
requirements in CAA section 112(d)(2) and (3) for establishing initial 
MACT standards and which do not allow for consideration of costs until 
the second, ``beyond the floor'' phase of the analysis. As discussed 
previously in this preamble where we respond to comments on the 
fenceline monitoring requirements, to the extent that the commenters 
are suggesting that EPA must re-perform the MACT floor analysis for 
purposes of setting a standard pursuant to section 112(d)(6), we note 
that the D.C. Circuit has rejected this argument numerous times, most 
recently in National Association for Surface Finishing et al. v. EPA 
No. 12-1459 in the U.S. Court of Appeals for the District of Columbia.
    Regarding the claim that the EPA did not consider the types of 
controls at the Valero and BP facilities, we disagree. The control 
measures for both of those facilities are controls that existed at the 
time of the development of the MACT standard. Thus, we did not identify 
these technologies as developments in control technologies during the 
technology review. However, we did identify developments in processes 
or practices that reflect better control by the existing technology and 
we reviewed modified emission limits that reflect that better level of 
control. The commenter suggested that we failed to consider a level of 
zero when the Valero facility was able to achieve zero emissions 
through a combined SCR, boiler and scrubber. However, the commenter 
provided no information to support such a claim and we are skeptical 
that such a result could be achieved. We note that the SCR is designed 
specifically to reduce NOX emissions, and would not be 
capable of reducing significantly, much less eliminating completely, 
HAP emissions. Similarly, based on our long-standing understanding of 
the processes, neither a boiler nor a scrubber could achieve such a 
result. Regarding the level of emissions achieved at the BP Whiting 
facility, we note that we evaluated control systems that can meet 0.5 
lb PM/1,000 lb coke burn-off, which is a lower limit than that at BP 
Whiting. We determined that these were cost-effective to require for 
new units that are installing a new control system. However, we 
determined that retrofitting controls designed to meet a PM limit of 
1.0 lb PM/1,000 lbs coke burn-off to now meet a limit of 0.5 lb PM/
1,000 lbs coke burn-off was not cost-effective when considering PM and 
PM2.5 emissions reductions. We projected the cost of the 0.5 
lb PM/1,000 lbs coke burn-off limit in retrofit cases to be $23,000 per 
ton PM emissions reduced. To meet a limit of 0.7 lb PM/1,000 lbs coke 
burn-off or 0.9 lb PM/1,000 lbs coke burn-off, as is the case for BP 
Whiting, the retrofit costs would be similar to this 0.5 lb PM/1,000 lb 
coke burn-off option, but the reductions would be even less, resulting 
in costs over $23,000 per ton. As metal HAP content of FCCU PM is 
approximately 0.1 to 0.2-percent of the total PM, the cost of requiring 
this lower limit for existing FCCU is over $10 million per ton of metal 
HAP reduced. Therefore, we determined that it is not necessary to 
revise the PM standard for existing FCCU sources.
    Comment: Refinery MACT 2 requires the owner or operator to 
demonstrate compliance with the PM FCCU limits by complying with the 
operating limits established during the performance test on a daily 
(i.e., 24-hour) average basis. Several commenters objected to the EPA's 
proposal to revise this requirement to a 3-hour averaging time. 
Commenters restated EPA's arguments for 3-hour averaging time as: (1) 
Daily average could allow FCCUs to exceed limits for short periods 
while still complying with the daily average, (2) consistency with NSPS 
subpart Ja and (3) consistency with duration of testing. The commenters 
stated that the EPA had not provided any data that show that the daily 
average could allow FCCUs to exceed limits for short periods and, 
therefore, the EPA is using a hypothetical compliance assurance 
argument to change emission limits. The commenters stated that a change 
in emission limits is not authorized by CAA section 112 because the 
emission limitations in Refinery MACT 2 for FCCUs were established as 
daily averages following the floor and ample margin of safety 
requirements in section 112(d)(2) of the CAA.
    The commenters also state that the EPA's additional arguments for 
the change to a 3-hour average are irrelevant and legally deficient. 
The commenters stated that the combination of a numerical emission 
limit and an averaging period frames the stringency of a limitation and 
that a reduction in either of those factors results in a significant 
lowering of the operating limit. The commenters conclude that the EPA 
has proposed to change the stringency of the requirements without 
justification, and the CAA requires that such a change in stringency be 
justified pursuant to CAA section 112(d)(6) or (f)(2). The commenters 
stated that increasing stringency for consistency with NSPS rules is 
not a criterion for a CAA section 112(d)(6) action. Rather that section 
requires a change to be due to ``developments.'' The only change in 
technology since the 2002 promulgation of Refinery MACT 2 is the 
availability of PM continuous emission monitoring system (CEMS), which 
is unproven.
    One commenter noted that changing the averaging time is a very 
significant modification considering that the compliance limits would 
apply for periods of SSM. This commenter stated that it is unlikely 
that existing operations can consistently be in compliance with a new 
3-hour average since the current daily averaging was put in place to 
recognize that there will be periods of operating variability that do 
not represent the longer term performance of an FCCU. The commenters 
recommended that the EPA retain the daily averaging requirement.
    Response: We disagree with the commenters' statement that reducing 
the averaging time from a 24-hour basis to a 3-hour basis for 
demonstrating compliance with the FCCU PM emission limit, using 
operating limits established during the performance test, is a change 
to the MACT floor. The emission limit of 1.0 lb PM/1,000 lbs coke burn-
off is the MACT floor, and we are not changing the PM emissions limit 
(or alternate Ni limits) in Table 1 to subpart UUU (except to remove 
the incremental PM limit that did not comport with the MACT floor 
emissions limitation).
    However, whether or not it is a change from the MACT floor is not 
relevant. Pursuant to CAA section 112(d)(6), the EPA must revise MACT 
standards ``as necessary'' considering developments in practices, 
processes and control technologies. For this

[[Page 75202]]

exercise, we considered any of the following to be a ``development'':
     Any add-on control technology or other equipment that was 
not identified and considered during development of the original MACT 
standards.
     Any improvements in add-on control technology or other 
equipment (that were identified and considered during development of 
the original MACT standards) that could result in additional emissions 
reduction.
     Any work practice or operational procedure that was not 
identified or considered during development of the original MACT 
standards.
     Any process change or pollution prevention alternative 
that could be broadly applied to the industry and that was not 
identified or considered during development of the original MACT 
standards.
     Any significant changes in the cost (including cost 
effectiveness) of applying controls (including controls the EPA 
considered during the development of the original MACT standards).
    In determining whether there are ``developments,'' we review, among 
other things, EPA regulations promulgated after adoption of the MACT, 
such as the NSPS we identified in this instance. We identified the 
enhanced monitoring requirements for these operating limits as a 
development in practices that will help ensure FCCU owners or operators 
are properly operating control devices and, thus, are meeting the PM 
emission limit at all times. We further determined that this enhanced 
monitoring was cost effective and proposed that it was necessary to 
revise the existing standard pursuant to CAA section 112(d)(6).
    While we do not have continuous PM emissions data that show actual 
deviations of the PM limit, we do not need such data in order to 
conclude that such deviations could occur when daily averages are used. 
The Refinery MACT 2 (i.e., subpart UUU) rule requires owners or 
operators to establish operating limits based on three 1-hour runs 
during the performance test. As a matter of simple mathematics, a 
source could demonstrate that it is meeting the operating limit based 
on a 24-hour average but could be exceeding the 1.0 lb PM/1,000 lbs 
coke burn-off emission limit based on a 24-hour average or for one or 
more individual 3-hour periods during that 24-hour average. For 
example, an owner or operator could operate with a power input 5-
percent higher than the operating limit for 23 hours, have the ESP off 
(zero power) for one hour, and still comply with a 24-hour average 
operating limit. However, it would be difficult for this same unit to 
meet the 1.0 lb PM/1,000 lbs coke burn-off emissions limit over a 24-
hour period, and it certainly would not meet the limit for every 3-hour 
period during that day. As the operating limit can be established to 
correspond with 1.0 lb PM/1,000 lbs coke burn-off, the 5-percent higher 
power input would likely correspond with a 0.95 lb PM/1,000 lbs coke 
burn-off emissions rate (5-percent lower). Uncontrolled emissions are 
typically 6 to 8 lbs/1,000 lbs coke burn-off. Thus, this unit would 
have emissions averaging approximately 1.2 lbs PM/1,000 lbs coke burn-
off during this 24-hour period [i.e., (0.95*23+7)/24], but would be in 
compliance with the 24-hour average operating limit. The unit would 
obviously also be out of compliance with the 3-hour average over the 
period when the power was turned off. We also have concerns that the 
operating limits are not always linear with the emissions, so that the 
longer averaging times do not effectively ensure compliance with the PM 
emissions limit. Therefore, as proposed, we are finalizing the 
requirement for owners or operators to comply with the operating limits 
on a 3-hour basis, rather than the 24-hour basis currently in the rule.
    Comment: The technology review for FCCUs resulted in the EPA 
proposing to remove the 30-percent opacity alternative limit for 
demonstrating compliance with the PM emissions limit that is available 
for refineries complying with the Refinery NSPS 40 CFR part 63, subpart 
J. Two commenters supported the EPA's proposed removal of the 30-
percent opacity limit for FCCUs. Other commenters stated that current 
technology is good enough for a 10- or 20-percent opacity limit. On the 
other hand, several commenters stated that the proposed removal of the 
30-percent opacity limit must meet the criteria specified in CAA 
section 112(d)(6) and (f)(2), which requires analysis of the statutory 
basis, environmental impacts, costs, operational and compliance 
feasibility and impacts, that the EPA has not conducted. The commenters 
claimed that had the EPA conducted a proper analysis, the EPA would 
have determined that the proposed change to remove the 30-percent 
opacity limit is not necessary or supportable. Additionally, these 
commenters stated that since the underlying PM emissions limit is 
unchanged, there is no emission reduction justification for this 
proposed change, and the change would not meet the CAA section 
112(d)(6) requirement of being cost effective. The commenters also 
noted that processes or practices for existing FCCUs have not changed, 
as required for a CAA section 112(d)(6) revision.
    Several commenters urged the EPA to maintain the 30-percent opacity 
limit for these FCCUs. As a practicable and cost-effective alternative 
to address the EPA's concern as to whether compliance with a 30-percent 
opacity limit ensures compliance with the PM emissions limit, 
commenters suggested annual performance tests to confirm that the FCCU 
is meeting the PM emissions limit, rather than performance tests every 
5 years, as proposed.
    One commenter stated that the EPA never intended for the opacity 
limit in Refinery NSPS subpart J to be used to demonstrate compliance 
with the PM emissions limit, but instead to assure the PM controls 
operate properly. The commenter stated that the EPA's conclusion that 
the 30-percent opacity limit may not be sufficiently stringent to 
ensure compliance with the underlying PM emissions limit is based on a 
false premise as to the purpose of the opacity standard because as the 
EPA states, ``Opacity of emissions is indicative of whether control 
equipment is properly maintained and operated.''
    Several commenters stated that the proposed elimination of the 30-
percent opacity limit currently in Refinery MACT 2 leaves existing 
FCCUs that use cyclones with no viable alternative approach to 
demonstrate compliance with the PM emissions limit without adding or 
replacing controls. They stated the other approaches for demonstrating 
compliance with the PM emissions limit in Refinery MACT 2 (such as 
development of a site-specific opacity limit) do not work for them. The 
commenters stated that although they believe that more frequent 
performance tests would show that the FCCUs are in fact meeting the PM 
emissions limit, the absence of the 30-percent opacity limit would 
force FCCUs using cyclones for PM control to install additional, costly 
PM controls (e.g., ESPs or wet gas scrubbers). They projected that 
these additional controls would cost tens of millions of dollars per 
FCCU and would require at least 3 years of compliance time. 
Additionally, one commenter stated that even FCCUs with additional 
downstream PM controls would not be able to achieve a site-specific 
limit at all times and needed the availability of the alternative 30-
percent opacity limit. One commenter estimated that installing an ESP 
to meet the proposed 10-percent opacity limit would cost approximately 
$121,000/ton, assuming a 32 tpy PM emission reduction. The commenter 
noted that the ESP would also increase GHG emissions and require more 
energy

[[Page 75203]]

resources from the facility. The commenter concluded that installing an 
ESP is neither cost effective nor appropriate considering non-air 
quality environmental and health impacts and energy requirements, and 
recommended that the EPA maintain the current NSPS subpart J 
alternative limits and add additional alternative limits into Refinery 
MACT 2 only as optional limits for demonstrating compliance with the PM 
emissions limit.
    Response: In promulgating Refinery MACT 2, the EPA identified the 
1.0 lb PM/1,000 lbs coke burn-off limit as the MACT floor but allowed a 
compliance option for FCCUs subject to Refinery NSPS subpart J to 
comply with an opacity limit up to 30 percent with one 6-minute 
allowance to exceed the 30-percent opacity in any 1-hour period. As 
stated in the proposal, compliance studies have shown that the 30-
percent opacity limit does not correlate well with the 1.0 lb PM/1,000 
lbs coke burn-off limit, and that an FCCU can comply with the 30-
percent opacity limit while its emissions exceed the PM emissions 
limit.\9\ Regardless of whether the 30-percent opacity limit in 
Refinery NSPS subpart J was designed to ``ensure that the control 
device was operated properly,'' Refinery MACT 2 allows sources subject 
to NSPS subpart J to use the 30-percent opacity limit to demonstrate 
continuous compliance with the PM emissions limit. We have determined 
that the 30-percent opacity limit is inadequate for the purpose of 
demonstrating continuous compliance with the PM emissions limits in 
Refinery MACT 2. As such, we proposed to remove this opacity limit and 
require the owner or operator to either demonstrate compliance with the 
PM emissions limit by continuously monitoring the control device 
parameters established during the performance test or establish and 
monitor a site-specific opacity limit. For clarity, we note that we 
proposed to allow a site-specific opacity limit, not a 10-percent 
opacity limit as some commenters suggest. The site-specific opacity 
limit can be significantly higher than 10 percent, but it cannot be 
lower than 10 percent.
---------------------------------------------------------------------------

    \9\ Compliance Investigations and Enforcement of Existing Air 
Emission Regulations at Region 5 Petroleum Refineries. U.S. 
Environmental Protection Agency, Region 5--Air and Radiation, 
Chicago, Illinois. March 9, 1998.
---------------------------------------------------------------------------

    While the compliance study indicates that a 30-percent opacity 
limit does not correlate well with a 1.0 lb PM/1,000 lbs coke burn-off 
emissions limit, further review of this same study indicates that a 20-
percent opacity limit provides a reasonable correlation with units 
meeting the 1.0 lb PM/1,000 lbs coke burn-off emissions limit. We also 
reviewed the data submitted by the commenters regarding PM emissions 
and opacity correlation. While the data suggest that there is 
variability and uncertainty in the PM/opacity correlation, the data do 
not support that a 30-percent opacity limit would ensure compliance 
even when considering the uncertainty associated with the PM/opacity 
correlation. Based on the variability of the 3-run average opacity 
limits, we determined that, if the 3-hour average opacity exceeded 20-
percent, then it was highly likely (98 to 99-percent confidence) that 
the FCCU emissions from the unit tested would exceed the PM emissions 
limit.
    After considering the public comments, reviewing the data submitted 
with those comments, and further review of the compliance study, in 
this final rule we are adding a 20-percent opacity limit, evaluated on 
a 3-hour average basis for units subject to NSPS subpart J. As we noted 
above, a 20-percent opacity limit provides a reasonable correlation 
with the PM emissions limit, and an exceedance of this 20-percent 
opacity limit will provide evidence that the PM emissions limit is 
exceeded. However, it is possible that units could still exceed the PM 
emissions limit while complying with the 20-percent opacity limit, if 
those units operate close to the 1 lb PM/1,000 lbs coke burn-off 
emissions limit. To address this concern, we considered the commenters' 
suggestion to require a performance test annually rather than once 
every 5 years. Some commenters suggested that this option specifically 
apply to FCCUs with cyclones, but this option is applicable to any 
control system operating very near the PM emissions limit and using an 
opacity limit to demonstrate continuous compliance. We have determined 
that the Refinery NSPS subpart J compliance procedures in Refinery MACT 
2, in combination with a 20-percent opacity limit demonstrated on a 3-
hour average basis and with annual performance tests when a test 
indicates PM emissions are greater than 80-percent of the limit (i.e., 
0.80 lb PM/1,000 lbs coke burn-off), will ensure continuous compliance 
with the PM emissions limit. FCCUs with measured PM emissions during 
the performance test at or below 0.80 lb PM/1000 lbs of coke burn-off 
will remain subject to the requirement to conduct performance tests 
once every 5 years, consistent with the requirements we proposed.
    We do not agree with commenters that the proposed opacity revision 
would add significant cost or compliance burden. The control device-
specific monitoring parameters that were proposed rely on parameters 
commonly used to control the operation of the control device, so the 
monitoring systems should be already available. Further, since we are 
merely changing the opacity limit, we expect these units will already 
have opacity monitoring systems needed to demonstrate compliance with 
the PM emissions limit and would not incur costs for new equipment.
    Comment: Several commenters stated that they agree with the EPA's 
determination in the proposal that the current CO limits provide 
adequate control of HCN. Two commenters stated that there are limited 
HCN emissions data and that more data are needed before the Agency can 
appropriately determine whether an HCN standard is necessary and 
justified. One commenter noted that the process undertaken by the EPA 
to estimate HCN emissions was flawed, and likely overestimates HCN 
emissions significantly. Another commenter stated that they performed 
HCN stack testing at three refineries and subsequent modeling at two 
refineries and concluded that the ambient HCN emissions were well below 
the applicable health limits.
    In contrast, some commenters expressed concerns about high HCN 
levels. One commenter stated that the EPA should consider re-evaluating 
the benefit of low NOX emissions from the FCCU, if that is 
indeed the cause of higher HCN emissions, because exposing people to 
HCN is not acceptable. The commenter also noted that the community now 
also has the increased dangers of storing and transporting aqueous 
ammonia, which is used in some cases to achieve low NOX 
emissions from the FCCU.
    One commenter stated that the EPA must set stronger HCN standards 
on FCCU emissions because of the high release amounts reported, the 
fact that non-cancer risk is driven by emissions of HCN from FCCU, and 
the fact that the EPA has never set standards for HCN emissions. The 
commenter provided a report that they believe shows that the EPA has 
not shown that CO is a reasonable or lawful surrogate to control HCN 
and has not shown that the conditions necessary for a surrogate are met 
with regard to CO and HCN, which is an inorganic nonmetallic HAP. 
Further, the report indicates that SCR is a reasonable and cost 
effective method for controlling HCN and that the EPA failed to review 
and consider other viable methods to control HCN and must do so to 
satisfy its legal obligations in this rulemaking.

[[Page 75204]]

    Response: At the time we promulgated the MACT, we determined that 
the control strategy used by the best performing facilities to reduce 
organic HAP emissions was the use of complete combustion, which occurs 
when the CO concentration is reduced to 500 ppmv (see the proposal for 
Refinery MACT 2 at 63 FR 48899, September 11, 1998). We rejected 
arguments that some facilities operate at CO levels well below 500 ppmv 
and, thus, the MACT floor should be set at a lower CO concentration 
because once CO concentrations reached 500 ppmv, there was no longer a 
correlation between reduced CO concentrations and reduced HAP 
concentrations. And, in fact, emissions of certain HAP, such as 
formaldehyde, tended to increase as CO concentrations were reduced 
below 500 ppmv.\10\
---------------------------------------------------------------------------

    \10\ U.S. EPA, 2001. Petroleum Refineries: Catalytic Cracking 
Units, Catalytic Reforming Units, and Sulfur Recovery Units--
Background Information for Promulgated Standards and Response to 
Comments. Final Report.EPA-453/R-01-011. June. p. 1-19.
---------------------------------------------------------------------------

    In the current rulemaking action, we determined at the time of the 
proposed rule that this also holds true for HCN emissions. That is, 
once CO emissions are reduced to below 500 ppmv (i.e., complete 
combustion is achieved), we no longer see a direct correlation between 
CO concentrations and HCN emissions.
    All of the HCN emissions data we have were reported from units 
operating at or below the 500 ppmv CO limit (i.e., in the complete 
combustion range), so it is not surprising that there is not a strong 
correlation between CO and HCN from the FCCU ICR source test data. 
However, catalyst vendor data and combustion kinetic theory support the 
fact that, in the partial burn mode (with CO concentrations of 2 to 6-
percent, which is 20,000 to 60,000 ppmv), HCN concentrations exiting 
the FCCU regenerator are much greater than for units using complete 
combustion FCCU regenerators or the concentration exiting a post-
combustion device used in conjunction with a partial burn FCCU 
regenerator. Therefore, we maintain that complete combustion is the 
primary control needed to achieve controlled levels of HCN emissions.
    We initially thought the higher levels of HCN emissions that were 
reported by sources achieving complete combustion might be due to a 
switch away from platinum-based combustion promoters to palladium-based 
combustion promoters. However, many of the units that were tested and 
that had some of the lowest HCN emissions used palladium-based oxygen 
promoters. Therefore, it appears unlikely that palladium-based catalyst 
promoters are linked to the higher HCN emissions. We also evaluated one 
commenter's argument that CO is not a good surrogate for HCN emissions, 
but that SCR are a reasonable and cost-effective control strategy. We 
are not aware of any data that suggest that an SCR removes HCN and the 
commenter did not provide any support for that premise. At proposal, we 
evaluated HCN control on units using extra oxygen or converting back to 
platinum-based promoters to oxidize any HCN formed. This would cause 
more NOX formation, which would then require post-combustion 
NOX control, such as an SCR. However, if HCN emissions are 
not a function of CO concentration beyond that required to achieve 
complete combustion (as noted by the commenter), then more aggressive 
combustion conditions and the use of an SCR (to remove the 
NOX formed) may not be a viable control strategy. Therefore, 
considering all of the data currently available and the comments 
received regarding HCN emissions and controls, we maintain that the 
only proven control technique is the use of complete combustion as 
defined by a CO level of 500 ppmv or less. We are not establishing a 
more stringent CO level because, once complete combustion is achieved, 
(i.e., CO concentrations drop below 500 ppmv), no further reduction in 
HCN emissions are achieved.
    For the purposes of Refinery MACT 2, we consider the emission 
limits and operating requirements for organic HAP in Tables 8 through 
14 to subpart UUU of part 63 adequate to also limit HCN emissions.
    Finally, we understand concerns about the reported HCN emissions 
being higher than anticipated and the need for more data to better 
determine HCN emissions levels. To address these concerns, we are 
finalizing a requirement that facility owners or operators conduct a 
performance test for HCN from all FCCU at the same time they conduct 
the first PM performance test on the FCCU following promulgation of 
this rule. Facility owners or operators that conducted a performance 
test for HCN from a FCCU in response to the refinery ICR or subsequent 
to the 2011 Petroleum Refinery ICR following appropriate methods are 
not required to retest that FCCU.
4. What is the rationale for our final approach for the technology 
review?
a. Refinery MACT 1
    We did not receive substantive comments concerning our proposal 
that it was not necessary to revise Refinery MACT 1 requirements for 
MPV, gasoline loading racks and cooling towers/heat exchange systems. 
Based on the rationale provided in the preamble to the proposed rule, 
we are taking final action concluding that it is not necessary pursuant 
to CAA section 112(d)(6) to revise the MACT requirements for MPV, 
gasoline loading racks and cooling towers/heat exchange systems 
emission sources at refineries.
    We proposed that the options for additional wastewater controls are 
not cost effective and thus it was not necessary to revise the MACT for 
these emission sources. We received public comments suggesting that 
emissions from wastewater systems are higher than modeled and that we 
should develop additional technology standards for wastewater treatment 
systems regardless of cost. As we discussed in the proposal, emissions 
from wastewater are difficult to measure and emission estimates rely on 
process data and empirical correlations, which introduces uncertainty 
into the estimates. Although we do not have evidence, based on the 
process data we collected, that emissions are higher than modeled at 
proposal, we note that the fenceline monitoring program effectively 
ensures that wastewater emissions are not significantly greater than 
those included in the emissions inventory and modeled in the risk 
assessment. Furthermore, we believe that cost is a valid consideration 
in determining whether it is necessary within the meaning of section 
112(d)(6) to revise requirements and that we are not required to 
establish additional controls regardless of cost. Consequently, we 
conclude that it is not necessary to revise the Refinery MACT 1 
requirements for wastewater systems pursuant to CAA section 112(d)(6).
    For storage vessels, we identified a number of options, including 
requiring tank fitting controls for external and internal floating roof 
tanks, controlling smaller tanks with lower vapor pressures and 
requiring additional monitoring to prevent roof landings, liquid level 
overfills and to identify leaking vents as developments in practices, 
processes and control technology. We proposed to cross-reference the 
storage vessel requirements in the Generic MACT (effectively requiring 
additional control for tank roof fittings) and to revise the

[[Page 75205]]

definition of Group 1 storage vessels to include smaller tanks with 
lower vapor pressures. We received comments that we could have required 
additional controls on tanks and monitoring for landings, overfills and 
leaking vents described above. We also received comments related to 
clarifications of specific rule references and overlap provisions. We 
addressed these comments in the ``Response to Comments'' document, and 
we maintain that the additional control options described by the 
commenters (tank roof landing/degassing requirements or use of geodesic 
domes to retrofit external floating roofs) are not cost-effective. 
Consequently, based on the rationale provided in the preamble to the 
proposed rule and our consideration of public comments, we are 
finalizing the requirements as proposed with minor clarifications of 
the rule references. However, as with wastewater systems, we note that 
the fenceline monitoring program will ensure that the owner or operator 
is effectively managing fugitive emissions sources and should detect 
landings, overfills, and leaking vents.
    For equipment leaks, we identified specific developments in 
practices, processes and control technologies that included requiring 
repair of leaking components at lower leak definitions, requiring 
monitoring of connectors, and allowing the use of the optical imaging 
camera as an alternative method of monitoring for leaks. We proposed to 
establish an alternative method for refineries to meet LDAR 
requirements in Refinery MACT 1. This alternative would allow 
refineries to monitor for leaks via optical gas imaging in place of EPA 
Method 21, using monitoring requirements to be specified in a not yet 
proposed appendix K to 40 CFR part 60. However, the development of 
appendix K is taking longer than anticipated. Therefore, we are not 
finalizing this alternative monitoring method in Refinery MACT 1.
    We received comments suggesting that additional requirements be 
imposed to further reduce emissions from leaking equipment components, 
such as requiring ``leakless'' equipment, reducing the leak threshold, 
and eliminating delay of repair provisions. As provided in the 
``Response to Comments'' document, we do not agree that these 
additional requirements are cost-effective. Based on the rationale 
provided in the preamble to the proposed rule and our consideration of 
public comments, we conclude that it is not necessary to revise the 
Refinery MACT 1 requirements for equipment leaks. Again, however, the 
fenceline monitoring program is intended to ensure that large leaks 
from fugitive emissions sources, including equipment leaks, are more 
quickly identified and repaired, thereby helping to reduce emissions 
from leaking equipment components.
    For marine vessel loading, we identified control of marine vessel 
loading operations with HAP emissions of less than 10/25 tpy and the 
use of lean oil absorption systems as developments that we considered 
in the technology review. We proposed to amend 40 CFR part 63, subpart 
Y to require small marine vessel loading operations (i.e., operations 
with HAP emissions less than 10/25 tpy) and offshore marine vessel 
loading operations to use submerged filling based on the cargo filling 
line requirements in 46 CFR 153.282. We received comments that other 
options considered during the technology review of the standard were 
cost-effective for small marine vessel loading operations and should be 
required. As provided in the ``Response to Comments,'' we continue to 
believe those other controls are not cost-effective because of the high 
costs of controls for limited additional organic HAP emission 
reduction. Therefore, we are finalizing these amendments as proposed.
    Finally, we proposed that it was necessary to revise the MACT to 
require fenceline monitoring as a means to manage fugitive emissions 
from the entire petroleum refinery, which includes sources such as 
wastewater collection and treatment operations, equipment leaks and 
storage vessels. We received numerous comments regarding the proposed 
requirement to conduct fenceline monitoring, many of which we address 
above and the remainder of which we respond to in the ``Response to 
Comments'' document. After considering comments, we maintain that the 
proposed work practice standard is authorized under section 112 of the 
CAA and will improve fugitive management at the refinery. Therefore, we 
are finalizing the key components of fenceline monitoring work practice 
as proposed. These requirements include the use of passive diffusive 
tube samplers (although we are providing a mechanism to request 
approval for alternative monitoring systems provided certain criteria 
are met), the 9 [mu]g/m3 on a rolling annual average basis 
action level, and the need to perform corrective action to comply with 
the action level.
    Based on public comments received, we are making numerous revisions 
to clarify the fenceline monitor siting requirements. This includes 
provisions to allow siting of monitors within the property boundary as 
long as all emissions sources at the refinery are included within the 
monitoring perimeter. We are also clarifying that we do not consider 
public roads or public waterways that bisect a refinery to be property 
boundaries, and owners or operators do not need to place monitors along 
the internal public right-of-ways. We are also providing provisions to 
allow fixed placement of monitors at 500 feet intervals (with a minimum 
of 3 monitors) for subareas or segregated areas. If an emissions source 
is near the monitoring perimeter, an additional monitor siting 
requirement would still apply. The 500 feet provision is provided to 
reduce burden for facilities with irregular shapes or noncontiguous 
property areas that we did not fully consider at proposal.
    We also received comments on the compliance time and reporting 
requirements associated with the fenceline monitoring provisions. Upon 
consideration of public comments, we have revised the compliance period 
to 2 years after the effective date of the final rule. Thus, beginning 
no later than 2 years after the effective date of the rule, the source 
must have a fenceline monitoring system that is collecting samples such 
that the first rolling annual average [Delta]C value would be completed 
no later than 3 years after the effective date of the final rule. 
Facilities will have 45 days after the completion of the first year of 
sampling, as proposed, to submit the initial data set. We are reducing 
the proposed compliance period from 3 years to 2 years because the 
passive diffusive tube monitors are easy to deploy and pilot study 
demonstrations indicate that significant time is not needed to deploy 
the monitors. However, the reduced compliance period still provides 
time to resolve site-specific monitor placement issues and to provide 
time to develop and implement a site-specific monitoring plan, if 
needed. We are increasing the fenceline monitoring reporting frequency 
(after the first year of data collection) from semiannually to 
quarterly to provide more timely dissemination of the data collected 
via this monitoring program.
b. Refinery MACT 2
    We proposed to revise Refinery MACT 2 to incorporate the 
developments in monitoring practices and control technologies reflected 
in the Refinery NSPS subpart Ja limits and monitoring provisions (73 FR 
35838, June 24, 2008). We are finalizing most of these provisions as 
proposed. Specifically, we are incorporating the

[[Page 75206]]

Refinery NSPS subpart Ja PM limit for new FCCU sources. We are also 
finalizing compliance options for FCCU that are not subject to Refinery 
NSPS subpart J or Ja. These options would allow such sources to elect 
to comply with the Refinery NSPS subpart Ja monitoring provisions to 
demonstrate compliance with the emissions PM limit. We are revising the 
averaging period for the control device operating limits or site-
specific opacity limits to be on a 3-hour average basis in order to 
more directly link the operating limit to the duration of the 
performance test runs, on which they are based, as proposed. We are 
incorporating additional control device-specific monitoring 
alternatives for various control devices on FCCU, including BLD 
monitoring as an option to COMS for owners or operators of FCCU using 
fabric filter-type control systems and total power and secondary 
current operating limits for owners or operators of ESPs. We are adding 
an additional requirement to perform daily checks of the air or water 
pressure to atomizing spray nozzles for owners or operators of FCCU wet 
gas scrubbers not subject to the pressure drop operating limit, as 
proposed. Finally, we finalizing requirements to conduct a performance 
test at least once every 5 years for all FCCU, as proposed. These 
requirements are being finalized to ensure that control devices are 
continuously operated in a manner similar to the operating conditions 
of the performance test and to ensure that the emissions limits, which 
are assessed based on the results of three 1-hour test runs, are 
achieved at all times.
    We also proposed to eliminate the Refinery NSPS subpart J 
compliance option that allows refineries to meet the 30-percent opacity 
emissions limit requirement and revise the MACT to include control 
device operating limits or site-specific opacity limits identical to 
those required in Refinery NSPS subpart Ja. We received numerous 
comments, particularly from owners or operators of FCCU that employ 
tertiary cyclones to control FCCU PM emissions. According to the 
commenters, opacity is not a direct indicator of PM emissions because 
finer particles will increase opacity readings without a corresponding 
mass increase in PM emissions. Additionally, the commenters stated that 
the site-specific opacity limit generally leads to a site-specific 
operating limit of 10-percent opacity, which is too stringent and does 
not adequately account for variability between PM emissions and opacity 
readings. According to the commenters, FCCU with tertiary cyclones 
would need to be retrofitted with expensive and costly controls in 
order to meet the 10-percent opacity limit, even though they are 
meeting the 1 lb/1000 lbs coke burn PM emissions limit. It was not our 
intent to require units to retrofit their controls simply to meet the 
site-specific opacity limit. However, the existing 30-percent opacity 
limit in the subpart J compliance option is not adequate to ensure 
compliance with the PM emissions limit at all times. After reviewing 
the public comments and available data, we determined that, rather than 
removing the subpart J compliance option altogether, it is sufficient 
to add an opacity operating limit of 20-percent opacity determined on a 
3-hour average basis to the existing subpart J compliance option and to 
require units complying with this operating limit to conduct annual 
performance tests (rather than one every 5 years) when the PM emissions 
measured during the source test are greater than 0.80 lb PM/1,000 lbs 
coke burn-off. These provisions improve assurance that these units are, 
in fact, achieving the required PM emissions limitation without 
requiring units to retrofit controls due to variability in the 
correlation of PM emissions and opacity.
    We did not propose to revise the organic HAP emissions limits for 
FCCU to further address HCN emissions. We received numerous comments on 
this issue. We continue to believe that complete combustion is the 
appropriate control needed to control HCN emissions. Consequently, for 
the purposes of Refinery MACT 2, we are not changing the MACT standards 
to further reduce emissions of HCN. However, we understand that there 
are uncertainties and high variability in HCN emissions measured from 
FCCU. In order to address the need for more data to better characterize 
HCN emissions levels, we are finalizing a requirement for refinery 
owners or operators to conduct a performance test for HCN from all FCCU 
(except those units that were tested previously using acceptable 
methods as outlined in the 2011 Refinery ICR) during the first PM test 
required as part of the on-going compliance requirements for FCCU metal 
HAP emissions. These data will be useful to the EPA in understanding 
HCN emissions from FCU and may help to inform future regulatory reviews 
for this source category.
    We proposed that there have been no developments in practices, 
processes, and control technologies for CRU based on our technology 
review and that therefore it is not necessary to revise these 
standards. Based on the rationale provided in the preamble to the 
proposed rule and our consideration of public comments, we are 
finalizing our conclusion.
    For SRU, we identified the Refinery NSPS subpart Ja allowance for 
oxygen-enriched air as a development in practice and we proposed that 
it was necessary to revise the MACT to allow SRU to comply with 
Refinery subpart Ja as a means of complying with Refinery MACT 2. The 
key issue identified by commenters was that Refinery NSPS subpart Ja 
includes a flow monitoring alternative for determining the average 
oxygen concentration in the enriched air stream and that this was not 
included in the proposed amendments to Refinery MACT 2. This was an 
oversight on our part. We are, based on the rationale provided in the 
preamble to the proposed rule and our consideration of public comments, 
finalizing the SRU revisions as proposed but with inclusion of the flow 
monitoring alternative provisions that are in Refinery NSPS subpart Ja 
for this source.

C. Refinery MACT Amendments Pursuant to CAA Section 112(d)(2) and 
(d)(3)

1. What did we propose pursuant to CAA section 112(d)(2) and (d)(3) for 
the Petroleum Refinery source categories?
    We proposed the following revisions to the Refinery MACT 1 and 2 
standards pursuant to CAA section 112(d)(2) and (3) \11\: (1) Adding 
MACT standards for DCU decoking operations; (2) revising the CRU purge 
vent pressure exemption; (3) adding operational requirements for flares 
used as APCD in Refinery MACT 1 and 2; and (4) adding requirements and 
clarifications for vent control bypasses in Refinery MACT 1.
---------------------------------------------------------------------------

    \11\ The EPA has authority under CAA section 112(d)(2) and 
(d)(3) to set MACT standards for previously unregulated emission 
points. EPA also retains the discretion to revise a MACT standard 
under the authority of section 112(d)(2) and (3), see Portland 
Cement Ass'n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011), such as 
when it identifies an error in the original standard. See also 
Medical Waste Institute v. EPA, 645 F. 3d at 426 (upholding EPA 
action establishing MACT floors, based on post-compliance data, when 
originally-established floors were improperly established).
---------------------------------------------------------------------------

    For DCU, we proposed to require that prior to venting or draining, 
each coke drum must be depressured to a closed blowdown system until 
the coke drum vessel pressure is 2 psig or less. As proposed, the 2 
psig limit would apply to each vessel opening/venting/draining event at 
new or existing affected DCU facilities.
    For the CRU, we proposed to require that any emissions during the 
active

[[Page 75207]]

purging or depressuring of CRU vessels meet the applicable organic HAP 
emission limitations in Tables 15 and 16 to subpart UUU regardless of 
the vessel pressure.
    For flares, we proposed to remove cross references to the General 
Provisions requirements for flares used as control devices at 40 CFR 
63.11(b) and to incorporate enhanced flare operational requirements 
directly into the Refinery MACT rules. The proposed rule amendments 
included:
     A ban on flaring of halogenated vent streams.
     A requirement to operate with continuously lit pilot 
flames at all times and to equip the pilot system with an automated 
device to relight the pilot if it is extinguished.
     A requirement to operate with no visible emissions except 
for periods not to exceed a total of 5 minutes during any 2 consecutive 
hours and to monitor for visible emissions daily.
     A requirement to operate with the flare tip velocity less 
than 60-feet-per-second or the velocity limit calculated by an equation 
provided in the proposed rule.
     A requirement to meet one of three combustion zone gas 
properties operating limits based on the net heating value, lower 
flammability limit, or combustion concentration. Owners or operators 
could elect to comply with any one of the three limits at any time. Two 
separate sets of operating limits were proposed: One for gas streams 
not meeting all three ``hydrogen-olefin interaction criteria'' 
specified in the rule and a more stringent set of limits for gas 
streams meeting all three hydrogen-olefin interaction criteria. The 
combustion zone net heating value considered steam assist rates but not 
``perimeter air'' assist rates.
     For air-assisted flares, a requirement to meet an 
additional ``dilution parameter'' operating limit determined based on 
the combustion zone net heating values above, the diameter of the flare 
and the perimeter air assist rates.
    The proposed amendments for flares also included detailed 
monitoring requirements to determine these operating parameters either 
through continuous parameter monitoring systems or grab sampling, 
detailed calculation instructions for determining these parameters on a 
15-minute block average, and detailed recordkeeping and reporting 
requirements. We also proposed provisions to allow owners or operators 
to request alternative emissions limitations that would apply in place 
of the proposed operating limits.
    We proposed to revise the definition of MPV to remove the current 
exclusion for in situ sampling systems (onstream analyzers). We also 
proposed to limit the exclusion for gaseous streams routed to a fuel 
gas system to apply only to those systems for which any flares 
receiving gas from the fuel gas system are in compliance with the 
proposed flare monitoring and operating limits. We note that we also 
proposed revisions related to monitoring of bypass lines, but these 
revisions were proposed to address concerns related to SSM releases and 
are described in further detail in section IV.D. of this preamble.
    We proposed that emissions of HAP may not be discharged to the 
atmosphere from PRD in organic HAP service to address concerns related 
to SSM releases. To ensure compliance with this proposed amendment, we 
proposed to require that sources monitor PRD using a system that is 
capable of identifying and recording the time and duration of each 
pressure release and of notifying operators that a pressure release has 
occurred. This proposed requirement was addressed in section IV.A.4. of 
the preamble for the proposal.
2. How did the revisions pursuant to CAA section 112(d)(2) and (3) 
change since proposal?
    We proposed identical standards for existing and new DCU decoking 
operations, but we are finalizing standards for new and existing 
sources that are not identical. We are finalizing provisions that will 
require owners or operators of existing DCU sources to comply with a 2 
psig limit averaged over 60 cycles (i.e., 60 venting events), rather 
than meet the 2 psig limit on a per venting event basis, as proposed. 
We are finalizing provisions that will require owners or operators of 
new DCU sources to comply with a 2.0 psig limit on a per event, not-to-
exceed basis. We are adding one significant digit to the limit for new 
DCU affected sources because our re-review of permit requirements 
conducted in response to comments identified that the best performing 
DCU source is required to comply with a 2.0 psig limit on a per event 
basis. In response to comments regarding the proposed prohibition on 
draining prior to achieving the pressure limit, we are finalizing 
specific provisions for DCU with water overflow design and for double 
quenching.
    For flares, we are not finalizing the ban that we proposed on 
halogenated vent streams and we are not finalizing the proposed 
requirement to equip the flare pilot system with an automated device to 
relight an extinguished pilot.
    We are revising the MACT to include the proposed no visible 
emissions limit and the flare tip velocity limit as direct emissions 
limits only when the flare vent gas flow rate is below the smokeless 
capacity of the flare. Under the revised standard, when the flare is 
operating above the smokeless capacity, an exceedance of the no visible 
emission limit and/or flare tip velocity limit is not a violation of 
the standard but instead triggers a work practice standard. Flares 
operate above the smokeless capacity only when there is an emergency 
release event and thus the work practice standard is intended to 
address emissions during such emergency release events. (See section 
IV.D. of this preamble for more details regarding this work practice 
standard). We are also adding provisions that would allow sources to 
use video surveillance of the flare as an alternative to daily Method 
22 visible emissions observations.
    For flares, we are also simplifying the combustion zone gas 
property operating limits by finalizing a requirement only for the net 
heating value of the combustion zone gas. We are finalizing 
requirements that flares meet a minimum operating limit of 270 BTU/scf 
NHVcz on a 15-minute average, as proposed, and we are allowing refinery 
owners or operators to use a corrected heat content of 1212 BTU/scf for 
hydrogen to demonstrate compliance with this operating limit. We are 
not finalizing separate combustion zone operating limits for gases 
meeting the hydrogen-olefin interaction criteria that were proposed. We 
are also not finalizing the alternative combustion zone operating 
limits based on lower flammability limit or combustibles concentration.
    We are finalizing ``dilution parameter'' requirements for air-
assisted flares, but we are providing a limit only for the net heating 
value dilution parameter. Similar to the requirements we are finalizing 
for the combustion zone parameters, we are finalizing requirements that 
flares meet a minimum operating limit of 22 BTU/ft2 
NHVdil on a 15-minute average, as proposed, and we are 
allowing refinery owners or operators to use a corrected heat content 
of 1,212 BTU/scf for hydrogen to demonstrate compliance with this 
operating limit. We are not finalizing separate dilution parameter 
operating limits for gases meeting the hydrogen-olefin interaction 
criteria that were proposed. We are also not finalizing the alternative 
dilution parameter operating limits based on lower flammability limit 
or combustibles concentration.

[[Page 75208]]

    We are providing an alternative to use initial sampling period and 
process knowledge for flares in dedicated service as an alternative to 
continuous or on-going grab sample requirements for determining waste 
gas net heat content.
    We are finalizing revisions to the definition of MPV, as proposed.
    We are establishing work practice standards that apply to PRD 
releases in place of the proposed prohibition on PRD releases to the 
atmosphere. The work practice standards that we are finalizing for PRD 
require refiners to establish proactive, preventative measures for each 
PRD to identify and correct direct releases of HAP to the atmosphere as 
a result of pressure release events. Over time, these proactive 
measures will reduce the occurrence of releases and the magnitude of 
releases when they occur, while avoiding the environmental disbenefits 
of having additional flare capacity on standby to control these 
unpredictable and infrequent events. Refinery owners or operators will 
be required to perform a root cause analysis/corrective action 
following such pressure release events. In addition, a second release 
event in a 3-year period from the same PRD with the same root cause on 
the same equipment is a deviation of the work practice standard. A 
third release event in a 3-year period from the same PRD is a deviation 
of the work practice standard regardless of the root cause. PRD release 
events related to force majeure events are not considered in these hard 
limits.
3. What key comments did we receive on the proposed revisions pursuant 
to CAA section 112(d)(2) and (3) and what are our responses?
i. DCU
    Comment: Several commenters argued that the EPA incorrectly set the 
MACT floor emission limitation for DCU. Commenters noted that CAA 
section 112(d)(3)(A) states that the MACT limit for existing sources 
``shall not be less stringent, and may be more stringent than the 
average emission limitation achieved by the best performing 12-percent 
of the existing sources'' excluding those first achieving that level 
within 18 months prior to proposal or 30 months prior to promulgation, 
whichever is later. According to the commenters, the EPA failed to 
follow this procedure in setting the 2 psig vent limit as a MACT floor 
because the EPA incorrectly considered permit limits and other non-
performance based criteria instead of basing the MACT floor on the 
actual performance of sources. Commenters stated that the EPA 
improperly considered permit limits that should have been excluded from 
consideration, as well as considering permit limits for closed 
facilities instead of using more accurate data from operating DCUs at 
sources that submitted actual emissions data. Specifically, commenters 
stated that the DCU at the non-operational plant (Hovensa) should not 
be included. One commenter noted that they operate one of the South 
Coast DCU listed as subject to a 2 psig limit and asserted that it does 
not currently meet that emission limitation. The commenter claimed that 
significant capital investment would be required in order for the DCU 
to comply with the 2 psig limit. According to one commenter, data for 
six of the eight DCU they claim the EPA considered for the MACT floor 
should not be counted in determining the limit that represents the 
average emission limitation actually achieved 18 months prior to the 
proposal.
    Response: CAA section 112(d)(3)(A) states that the existing source 
standard shall not be less stringent than the average emission 
limitation achieved by the best performing 12-percent of the existing 
sources (for which the Administrator has emissions information), 
excluding those sources that have, within 18 months before the emission 
standard is proposed or within 30 months before such standard is 
promulgated, whichever is later, first achieved a level of emission 
rate or emission reduction which complies, or would comply if the 
source is not subject to such standard, with the lowest achievable 
emission rate (as defined by section 171) applicable to the source 
category and prevailing at the time, in the category or subcategory for 
categories and subcategories with 30 or more sources. We consider a 2 
psig emissions limitation to be equivalent to the lowest achievable 
emission rate (LAER) emission limits. Thus, we agree with the commenter 
that sources that first meet the 2 psig limit on or after December 30, 
2012, should be excluded from the MACT floor analysis. We also agree 
that under CAA section 112(d)(3)(A), the MACT floor analysis focuses on 
those sources that are achieving the emission limit (i.e., the emission 
limitation ``achieved by . . . ''). The EPA has previously determined 
that the 6th-percentile unit is a reasonable estimate of the average 
emission limitation achieved by the best performing 12-percent of 
sources especially when averaging across units with and without control 
requirements. As noted in our DCU MACT floor analysis memorandum 
(Docket ID No. EPA-HQ-OAR-2010-0682-0203), the 6th-percentile is 
represented by the fifth-best performing DCU. If we exclude the two 
South Coast refineries and the two Marathon Garyville DCU because these 
sources were not implementing the 2 psig permit limit prior to December 
30, 2012, the fifth-best performing DCU would be represented by the Bay 
Area refineries (4.6 psig). However, based on the 2011 Petroleum 
Refinery ICR responses, 25 out of 75 (33-percent) DCU have a ``typical 
coke drum pressure when first vented to the atmosphere'' of 2 psig or 
less and 10 out of 75 (13-percent) DCU have a ``typical coke drum 
pressure when first vented to the atmosphere'' of 1 psig or less. While 
we acknowledge that these data represent ``typical'' operations and not 
necessarily a never-to-be-exceeded emissions limitation, we conclude 
that this information is sufficient for us to conclude that the average 
emission limitation achieved by the best performing 12-percent of 
sources is consistent with a 2 psig emissions limitation. This is 
because facility owners or operators commonly target to operate at 
approximately half the allowable emissions limit to ensure that they 
can comply with the emissions limit at all times. Therefore, we 
maintain that an average venting pressure of 2 psig is the MACT floor 
level for decoking operation at existing sources based on the ICR 
responses and considering the average performance expected.
    Comment: Four commenters suggested that the 2 psig limit, if 
finalized, should be based on a rolling 30-day average per DCU rather 
than a never to be exceeded ``instantaneous'' standard. According to 
the commenters, an instantaneous standard is unnecessary to address 
HAPs with chronic health impacts and adds cost and compliance 
challenges. According to the commenters, chronic health impacts are not 
materially affected by short-term variability, but instead depend on 
the average concentration of exposure over a 70-year lifetime; 
therefore, there is no health based or environmental reason for 
requiring an instantaneous limit. The commenters noted that there would 
be additional capital costs to comply with a 2 psig not-to-be-exceeded 
limit compared to a 30-day average 2 psig limit vent pressure. One 
commenter specifically requested that the EPA also confirm that a 
pressure of 2.4 psig is compliant with the 2 psig limit vent pressure. 
Another commenter also requested clarification that the vent pressure 
can be rounded to

[[Page 75209]]

one significant figure when determining compliance.
    Response: For new sources, the MACT floor emission limit for DCU is 
based on the best-performing source. Based on this and other comments 
received, we again reviewed existing permit conditions. Based on this 
review, we found that one of the permit requirements specified the 
pressure limit as 2.0 psig for each coke drum venting event. Therefore, 
we are finalizing the new source MACT floor as 2.0 psig on a per coke 
drum venting event basis.
    As discussed in response to the previous comment, we are basing the 
MACT floor for existing source DCU on responses we received from the 
2011 Petroleum Refinery ICR. Because the ICR requested the ``typical 
coke drum pressure when first vented to the atmosphere,'' we do not 
consider the information provided in ICR responses to reflect a 
``never-to-be-exceeded'' limit. Therefore, we evaluated whether it is 
reasonable to allow averaging, and if so, what averaging period should 
be provided.
    Health risks are not considered in establishing MACT requirements, 
so we do not consider the argument that chronic effects are evaluated 
over a 70-year period to be relevant to a determination of the MACT 
floor. However, a primary consideration regarding averaging periods is 
how the averaging period was considered in setting the floor and 
whether the intended reductions will occur under a different averaging 
period. According to the heat balance method for estimating DCU 
emissions, DCU decoking operations emissions are directly proportional 
to the average bed temperature. While the relationship is not exactly 
linear, the average bed temperature is expected to be a function of the 
venting pressure. Moreover, the shape of the pressure-temperature 
correlation curve is such that the emissions at 6 psig are almost 
exactly but not quite three times the emissions at 2 psig. Given the 
expected linearity of the emissions with venting pressures, we are not 
concerned with an occasional venting event above 2 psig because the 
average emissions from a facility meeting an average 2 psig pressure 
limit would be identical to the emissions achieved by a facility that 
vented each time at 2 psig. That is, given the expected linearity in 
the projected DCU emissions to the venting pressure, we conclude that 
it is reasonable to allow averaging across events and that the precise 
averaging period is not a critical concern.
    Most industry commenters requested a 30-day average. However, 
different facilities have different numbers of DCU, different numbers 
of drums per DCU and different cycle times. Consequently, basing the 
averaging period across a given time period would result in 
significantly different number of venting events included in a 30-day 
average for different facilities and generally provide more flexibility 
to larger refineries and less flexibility to smaller refineries. Based 
on the ICR responses, almost half of all DCU operate with two drums and 
about 90-percent of DCU have two to four coke drums; however, a few DCU 
have six or even eight drums. Also, based on the ICR responses, the 
average complete coke drum cycle time is 32 hours, but can be as short 
as 18 hours and as long as 48 hours. Reviewing the ICR responses, we 
found that a 30-day average would include 30 events for some facilities 
and more than 250 events at other facilities.
    Since the existing source MACT standards apply ``in combination'' 
to ``all releases associated with decoking operations'' at a given 
facility, we determined that it was reasonable to consider an averaging 
period that applies to the number of venting events from all coke drums 
at the facility rather than to all coke drums for a specific DCU for a 
specified period of time. This provides a more consistent basis for the 
averaging period and allows the same operational flexibility for small 
refineries as large refineries. Based on the ICR responses, the median 
(typical) DCU has 60 venting events in a 30-day period. Providing an 
averaging period of 60 venting events provides a more consistent 
averaging basis for all facilities, regardless of the number of DCU at 
the facility and the number of drums and cycle times for different DCU. 
Additionally, it eliminates issues with respect to how to handle 
operating days versus non-operating days, e.g., in the event of a turn-
around resulting in a limited number of venting events in a 30-calendar 
day period. Therefore, we are establishing a 2 psig limit based on a 
60-event average considering all coke drum venting events at an 
existing source and we are finalizing a 2.0 psig limit on a per coke 
drum venting event for DCU at new sources.
    We have consistently maintained our policy to round to the last 
digit provided in the emission limit, a pressure of 2.4 psig would 
round to 2 psig and would be compliant with a requirement to depressure 
each coke drum to a closed blowdown system until the coke drum vessel 
pressure is 2 psig or less, but it would not be compliant with the 
revised new source provision to depressure until the coke drum vessel 
pressure is 2.0 psig or less. A coke drum pressure of 2.04, however, 
would be compliant with the revised new source requirement pressure 
limit of 2.0 psig.
ii. Refinery Flares
    Comment: Several commenters suggested that the proposed flare 
operating limits were too complex. The commenters recommended that the 
EPA eliminate the dual flare combustion zone heat content limits 
related to the proposed hydrogen-olefin interaction criteria and 
instead finalize a single combustion zone net heating value of 
approximately 200 BTU/scf, which would minimize the unnecessary burning 
of supplemental gas but still ensure good combustion efficiency.
    A few commenters suggested that the EPA based the proposed 
combustion zone limits on an invalid data analysis, that the 1 minute 
PFTIR data should not be used to establish combustion efficiency 
correlations, and that the emission limits should be set so as to 
provide an equal chance of false positives and negatives. A few 
commenters suggested that the EPA should assign hydrogen a heating 
value of 1,212 BTU/scf to more accurately reflect its flammability in a 
NHV basis and that doing so is consistent with some recent flare 
consent decrees and would help reduce natural gas supplementation for 
facilities complying only with the NHVcz metric.
    Several commenters suggested that neither scientific literature nor 
the available flare test data support the EPA's claim of an adverse 
hydrogen-olefin interaction on combustion efficiency and that the EPA 
should not finalize the more restrictive combustion zone operating 
limits for all flare types. These commenters suggested that the EPA did 
not provide any evidence the assumed hydrogen-olefin effect actually 
exists; that statistical analysis demonstrates the EPA developed their 
limit based on random differences in data; that the PFTIR data analysis 
method of using the individual minute-by-minute data instead of the 
test average data is flawed and leads to invalid conclusions; and that 
proper analysis of the data demonstrates the more stringent operating 
limits for hydrogen-olefin conditions cannot be supported.
    Some commenters suggested that there is evidence to support more 
stringent flare combustion zone limits for a narrowly defined high 
concentration propylene-only condition as outlined in some of the 
recent flare

[[Page 75210]]

consent decrees but that the flare test data do not support more 
stringent operating limits for the proposed hydrogen-olefins criteria 
by the EPA. Additionally, one commenter suggested that if the EPA 
decides to proceed with the more restrictive combustion zone limits for 
the hydrogen-olefins interaction cases then the final rule should not 
expand beyond an interaction between hydrogen and propylene.
    Several commenters suggested that the proposed 15-minute feed 
forward averaging time for flares (e.g., combustion zone parameters, 
air-assist dilution parameters and associated flow rates) is arbitrary, 
unrealistic and unworkable and that the feed forward compliance 
determination should not be finalized and, if it is finalized, the 
averaging time should be extended to 1-hour, 3-hour, or 24-hour. To 
support these suggested averaging periods, commenters claimed that 
typical standards for combustion devices are averaged over these 
suggested timeframes, noting as an example, recent refinery flare 
consent decrees that contain a 3-hour average. The commenters also 
asserted that both a GC and calorimeter will be needed to obtain data 
rapidly enough to try and maintain a 15-minute average; that the feed 
forward approach requires calculation artifices to attempt to correct 
for the fact that compliance cannot be determined until the averaging 
period is over; and that a longer averaging time is needed for 
instrument and control response time.
    Response: In addressing these comments, we further analyzed the 
flare emissions test data. First, to address concerns that the minute-
by-minute analysis produced flawed results, we re-compiled the data 
into approximate ``15-minute averages'' to the extent practical based 
on the duration of a given test run (e.g., a 10-minute run was used as 
1 run and a 32-minute run was divided into 2 runs of 16 minutes each). 
We do not find significant differences in the data or that different 
conclusions would be drawn from the data based on this approach as 
compared with the minute-by-minute analysis used for the proposed rule.
    Next, we evaluated the 15-minute run data using the normal net 
heating value for hydrogen of 274 Btu/scf, which is the value we used 
in the analysis for the proposed rule and also evaluated the data using 
the 1,212 Btu/scf, the value recommended by some commenters. The 1,212 
Btu/scf value is based on a comparison between the lower flammability 
limit and net heating value of hydrogen compared to light organic 
compounds and has been used in several consent decrees to which the EPA 
is a party. Based on our analysis, we determined that using a 1,212 
Btu/scf value for hydrogen greatly improves the correlation between 
combustion efficiency and the combustion zone net heating value over 
the entire array of data. Using the net heating value of 1,212 Btu/scf 
for hydrogen also greatly reduced the number of ``type 2 failures'' 
(instances when the combustion efficiency is high, but the gas does not 
meet the NHVcz limit). One of the primary motivations for the proposed 
approach to provide alternative limits based on lower flammability 
limits and combustibles concentrations was to reduce these type 2 
failures. Therefore, we proposed all three of these parameters (i.e., 
NHVcz, LFL and total combustibles) and allowed flare owners or 
operators to comply with any of the parameter limits at any time. When 
using the net heating value of 1,212 Btu/scf for hydrogen, the other 
two alternatives no longer provide any improvement in the ability to 
predict good flare performance. Consequently, we are simplifying the 
operating limits to use only NHVcz.
    Next, we re-evaluated whether to finalize the proposed dual 
combustion zone operating limits for refinery flares that met certain 
hydrogen-olefins interactions or to finalize a single combustion zone 
net heating value limit. The newly re-compiled PFTIR run average flare 
dataset suggests that higher operating limits may be appropriate for 
some olefin-hydrogen mixtures. However, the dataset using 15-minute 
test average runs is much smaller than the set using 1-minute runs and 
thus creates a greater level of uncertainty. In addition, we cannot 
definitively conclude that a dual combustion zone limit for refinery 
flares meeting certain hydrogen-olefins interactions is appropriate 
given these uncertainties. Thus, in order to minimize these 
uncertainties and streamline the compliance requirements, we used all 
of the 15-minute test run average data together as a single dataset in 
an effort to determine an appropriate, singular combustion zone net 
heating value operational limit.
    Finally, we conducted a Monte Carlo analysis to help assess the 
impacts of extending the averaging time on the test average flare 
dataset of 15-minute runs to 1-hour or 3-hour averaging time 
alternatives. While we consider it reasonable to provide a longer 
averaging time for logistical reasons, the Monte Carlo analysis 
demonstrated, consistent with concerns described in our proposal, that 
short periods of poor performance can dramatically limit the ability of 
a flare to achieve the desired control efficiency. Consequently, we 
find it necessary to finalize the proposed 15-minute averaging period 
to ensure that the 98-percent control efficiency for flares is achieved 
at all times. However, we understand that flare vent gas flow and 
composition are variable. While a short averaging time is needed to 
ensure adequate control given this variability, we also understand the 
complications that this variability places on flare process control in 
efforts to meet the NHVcz limit. Therefore, we are clarifying that the 
270 Btu/scf NHVcz value is an operational limit that must be calculated 
according to the requirements in this rule. We also clarify that 
compliance with this operational limit must be evaluated using the 
equations and calculation methods provided in the rule. We proposed a 
feed forward calculation method to allow refinery owners or operators a 
means by which to adjust steam (or air) and, if necessary, supplemental 
natural gas flow, in order to meet the limit. In other words, ``feed 
forward'' refers to the fact that the rule requires the refinery owners 
or operators to use the net heating value of the vent gas (NHVvg) going 
into the flare in one 15-minute period to adjust the assist media 
(i.e., steam or air) and/or the supplemental gas in the next 15-minute 
period, as necessary for the equation in the rule to calculate an NHVcz 
limit of 270 BTU/scf or greater. We recognize that when a subsequent 
measurement value is determined, the instantaneous NHVcz based on that 
compositional analysis and the flow rates that exist at the time may 
not be above 270 Btu/scf. We clarify that this is not a deviation of 
the operating limit. Rather, the owner or operator is only required to 
make operational adjustments based on that information to achieve, at a 
minimum, the net heating value limit for the subsequent 15-minute block 
average. Failure to make adjustments to assist media or supplemental 
natural gas using the equation provided for calculating an NHVcz limit 
of 270 BTU/scf, using the NHVvg from the previous period, would be a 
deviation of the operating limit.
    Alternatively, if the owner or operator is able to directly measure 
the NHVvg on a more frequent basis, such as with a calorimeter (and 
optional hydrogen analyzer), the process control system is able to 
adjust more quickly, and the owner or operator can make adjustments to 
assist media or supplemental natural gas more quickly. In this manner, 
the owner or operator is not limited by

[[Page 75211]]

relying on NHVvg data that may not represent the current conditions. 
Therefore, the owner or operator may opt to use the NHVvg from the same 
period to comply with the operating limit.
    Based on the results of all of our analyses, the EPA is finalizing 
a single minimum NHVcz operating limit for flares subject to the 
Petroleum Refinery MACT standards of 270 BTU/scf during any 15-minute 
period. The agency believes, given the results from the various data 
analyses conducted, that this operating limit is appropriate, 
reasonable and will ensure that refinery flares meet 98-percent 
destruction efficiency at all times when operated in concert with the 
other suite of requirements refinery flares need to achieve (e.g., 
flare tip velocity requirements, visible emissions requirements, and 
continuously lit pilot flame requirements). For more detail regarding 
our data re-analysis, please see the memorandum titled ``Flare Control 
Option Impacts for Final Refinery Sector Rule'' in Docket ID No. EPA-
HQ-OAR-2010-0682.
    Comment: Numerous commenters objected to the proposed requirements 
to have the velocity and visible emissions limits apply at all times 
for flares. Commenters suggested that flares are not designed to meet 
the visible emissions and flare tip velocity requirements when being 
operated beyond their smokeless capacity and suggested several 
alternative approaches: remove the visible emissions and flare tip 
velocity requirements from the rule altogether; exempt flares from 
these requirements during emergencies; or add a requirement to maintain 
a visible flame present at all times or include a work practice 
standard in the rule when flares are operated beyond their smokeless 
capacity at full hydraulic load. The commenters identified full 
hydraulic load as the maximum flow the flare can receive based on the 
piping diameter of the flare header and operating pressure of processes 
connected to the flare header system. They also specified that full 
hydraulic load would only occur if all sources connected to the flare 
header vented at the same time, which might result from an emergency 
shutdown due to a plant-wide power failure. According to commenters, 
flares are typically designed to operate in a smokeless manner at 20 to 
30-percent of full hydraulic load. Thus, they claimed, flares have two 
different design capacities: A ``smokeless capacity'' to handle normal 
operations and typical process variations and a ``hydraulic load 
capacity'' to handle very large volumes of gases discharged to the 
flare as a result of an emergency shutdown. According to commenters, 
this is inherent in all flare designs and it has not previously been an 
issue because the flare operating limits did not apply during 
malfunction events. However, if flares are required to operate in a 
smokeless capacity during emergency releases, the commenters claimed 
that refineries would have to quadruple the number of flares at each 
refinery to control an event that may occur once every 2 to 5 years.
    To support their suggestions, commenters pointed out that flaring 
during emergencies is the optimum way of handling very large releases 
and that the flare test data clearly demonstrate that visible emissions 
and/or high flare tip velocity do not suggest poor destruction 
efficiency during such events. The commenters also argued that 
operators should not have conflicting safety and environmental 
considerations to deal with during these times. The commenters stated 
that refiners are still subject to a civil suit even if the EPA uses 
its enforcement discretion where such a release would violate the limit 
and in order to avoid such liability, many new flares would have to be 
built. Commenters estimated that 500 new large flare systems at a 
capital cost in excess of $10-20 billion would need to be built because 
of the amount of smokeless design capacity that would be needed and 
that this significant investment would take the industry at least a 
decade to install.
    Response: At the time of the proposed rule, we did not have any 
information indicating that flares were commonly operated during 
emergency releases at exit velocities greater than 400 ft/sec (which is 
270 miles per hour (mph)). Similarly, we did not have information to 
indicate that flares were commonly designed to have a smokeless 
capacity that is only 20 to 30-percent of their ``hydraulic load 
capacity.'' While we are uncertain that refineries actually would 
install additional flares to the degree the commenters claim, based on 
the possibility that there may be an event every 2 to 5 years that 
would result in a deviation of the smokeless limit, we also recognize 
that it would be environmentally detrimental to operate hundreds of 
flares on hot standby in an effort to never have any releases to a 
flare that exceed the smokeless capacity of that flare. This is because 
operating hundreds of new flares to prevent smoking during these rare 
events will generate more ongoing emissions from idling flares than the 
no visible emissions limit might prevent during one of these events. 
Therefore, we considered alternative operating limits or alternative 
standards that could apply during these emergency release events.
    As an alternative to the proposed requirement that flares meet the 
visible emissions and velocity limits at all times, we considered a 
work practice standard for the limited times when the flow to the flare 
exceeds the smokeless capacity of the flare. Owners or operators of 
flares would establish the smokeless capacity of the flare based on 
design specification of the flare. Below this smokeless capacity, the 
velocity and visible emissions standards would apply as proposed. Above 
the smokeless capacity, flares would be required to perform root cause 
analysis and take corrective action to prevent the recurrence of a 
similarly caused event. Multiple events from the same flare in a given 
time period would be a deviation of the work practice standard. Force 
majeure events would not be included in the event count for this 
requirement.
    Based on industry claims that there is a hydraulic load flaring 
event, on average, every 4.4 years, we assumed the best performers 
would have no more than one event every 6 years, or a probability of 
16.7-percent of having an event in any given year. We found that, over 
a long period of time such as 20 years, half of these best performers 
would have 2 events in a 3 year period, which would still result in 
over half the ``best performing'' flares having a deviation of the work 
practice standard if it was limited to 2 events in 3 years. Conversely, 
only 6 percent would have 3 events in 3 years over this same time 
horizon. Based on this analysis, 3 events in 3 years would appear to be 
``achievable'' for the average of the best performing flares.
    Pursuant to CAA section 112(d)(2) and (3), we are finalizing a work 
practice standard for flares that is based on the best practices of the 
industry, and considers the rare hydraulic load events that inevitably 
occur at even the best performing facilities.
    The best performing facilities have flare management plans that 
include measures to minimize flaring during events that may cause a 
significant release of material to a flare. Therefore, we are requiring 
owners or operators of affected flares to develop a flare management 
plan specifically to identify procedures that will be followed to limit 
discharges to the flare as a result of process upsets or malfunctions 
that cause the flare to exceed its smokeless capacity. We are 
specifically requiring refinery owners or operators to implement 
appropriate prevention measures applicable to these

[[Page 75212]]

emergency flaring events (similar to the prevention measures we are 
requiring in this final rule to minimize the likelihood of a PRD 
release). Refiners will be required to develop a flare minimization 
plan that describes these proactive measures and reports smokeless 
capacity. Refiners will need to conduct a specific root cause analysis 
and take corrective action for any flare event above smokeless design 
capacity that also exceeds the velocity and/or visible emissions limit. 
If the root cause analysis indicates that the exceedance is caused by 
operator error or poor maintenance, the exceedance is a deviation from 
the work practice standard. A second event within a rolling 3-year 
period from the same root cause on the same equipment is a deviation 
from the standard. Events caused by force majeure, which is defined in 
this subpart, would be excluded from a determination of whether there 
has been a second event. Finally, and again excluding force majeure 
events, a third opacity or velocity limit exceedance occurring from the 
same flare in a rolling 3-year period is a deviation of the work 
practice standard, regardless of the cause.
    Comment: Several commenters suggested that the EPA should revise 
the combustion efficiency requirements to apply only to steam-assisted 
flares used as Refinery MACT control devices during periods of time 
that the flares are controlling Refinery MACT regulated streams. One 
commenter suggested that the EPA misused the TCEQ data in proposing the 
NHVcz metric and that the proposed limits are overly 
conservative. The commenter requested that the EPA work with 
stakeholders to conduct additional testing to determine what, if any, 
operating parameters are appropriate and necessary to achieve an 
adequate destruction efficiency for non-steam-assisted flares.
    Response: We disagree with the commenters that the combustion 
efficiency requirements should apply only to steam-assisted flares. The 
available data (for runs where steam assist is turned off) as well as 
the available combustion theories suggest that the combustion zone net 
heating value minimum limit, which is the vent gas net heating value 
for unassisted or perimeter air-assisted flares, is necessary to ensure 
proper flare performance. While we agree that additional data on air-
assisted flares would allow for a more robust analysis, the data we do 
have strongly indicate that air-assisted flares can be over-assisted 
and that the combustion efficiency of air-assisted flares that are 
over-assisted is below 98-percent control efficiency.
    Comment: A few commenters suggested that the proposed flare 
regulations should not apply to part 63, subpart R (gasoline loading) 
and subpart Y (marine vessel loading) facilities, and to part 61, 
subpart FF (benzene waste) facilities. The commenters recommended that 
flares associated with gasoline loading, marine vessel loading and 
wastewater treatment emissions need to comply only with the General 
Provisions for flares. Some of these commenters argued that these 
sources are more consistent in flow and composition than other refinery 
sources, so the new requirements are not necessary to ensure good 
combustion for these ``dedicated'' flares. Some commenters suggested 
that operators of flares with consistent flow and composition be 
allowed to use process knowledge or engineering judgment rather than be 
required to install continuous monitors or be subject to ongoing grab 
sampling requirements.
    Some commenters noted that the required control efficiency for some 
refinery emissions sources subject to subpart CC sources is 95-percent. 
One commenter also requested that the EPA provide overlap provisions so 
flares used to control sources from different MACT sources would not 
have duplicative requirements.
    Response: The regulatory revisions that we are finalizing apply to 
petroleum refinery sources subject to part 63, subparts CC and UUU. 
Gasoline loading, marine vessel loading and wastewater treatment 
operations that are part of the refinery affected source as defined at 
40 CFR 63.640 are subject to subpart CC. Gasoline loading, marine 
vessel loading and wastewater treatment operations located at non-
refinery source categories are not subject to part 63, subpart CC and, 
thus, would not be subject to the revisions to subpart CC being 
finalized in this action. To the extent that the commenters are 
requesting that the EPA establish flare requirements that would apply 
to flares that are not part of the refinery affected source, that 
request is beyond the scope of this rulemaking, which only addresses 
revisions to Refinery MACT 1 and 2. When we issue rules addressing 
requirements for other sources with flares, we will consider issues 
similar to those we considered in this action and determine at that 
time whether revisions to those other flare requirements are necessary.
    The commenters note that some subpart CC emissions sources have 
only a control efficiency requirement of 95-percent. While this may be 
true, where the owner or operator chooses to control these sources 
through the use of a flare, operation of that flare was subject to 
operational requirements in the General Provisions at 40 CFR 63.11 and 
the best performing flares were achieving 98-percent control at the 
time the General Provisions were promulgated. At the time the General 
Provisions were promulgated, we received no comments that the EPA 
should set different operational limits for flares that are controlling 
emissions from sources where the standard may vary by level of control 
efficiency and we see no basis to do so now. The purpose of the 
revisions to the flare operating requirements is to ensure that flares 
are operating consistent with the MACT floor requirements for any and 
all sources that may use flares as a control device (79 FR 36905, June 
30, 2014). As the MACT floor control requirements of certain refinery 
sources that allow the use of a flare as a control device is 98-
percent, we established operational limits to ensure flares used as 
control devices meet this MACT requirement.
    To the extent that the commenters are requesting that the EPA 
establish an alternative monitoring approach for flares in dedicated 
service that have consistent composition and flow, we agree that these 
types of flares, which have limited flare vent gas streams, do not need 
to have the same type of on-going monitoring requirements as those with 
more variable waste streams. Thus, we are establishing an option that 
refinery owners or operators can use to demonstrate compliance with the 
operating requirements for flares that are in dedicated service to a 
specific emission source, such as a wastewater treatment operation. 
Refinery owners or operators will need to submit an application for the 
use of this alternative. The application must include a description of 
the system, characterization of the vent gases that could be routed to 
the flare based on a minimum of 7 grab samples (14 daily grab samples 
for continuously operated flares) and specification of the net heating 
value that will be used for all flaring events (based on the minimum 
net heating value of the grab samples). We are also allowing 
engineering estimates to characterize the amount of gas flared and the 
amount of assist gas introduced into the system. For example, the use 
of fan curves to estimate air assist rates is acceptable. Flare owners 
or operators would use the net heating value determined from the 
initial sampling phase and measured or estimated flare vent gas and 
assist gas

[[Page 75213]]

flow rates, if applicable, to demonstrate compliance with the 
standards.
    Comment: A few commenters suggested that the EPA's proposed work 
practice and monitoring standards for flares are CAA section 112(d) 
``developments'' required by law and supported by the evidence, and 
reflect best practices at many refineries today. One commenter 
suggested that the EPA must allow companies with consent decrees to 
meet their consent decree requirements as an alternative compliance 
approach and in lieu of the proposed requirements.
    Response: We proposed the enhanced monitoring requirements and 
operating limits under authority of CAA sections 112(d)(2) and (d)(3) 
to ensure that flares used to control regulated Refinery MACT 1 or 2 
gas streams are meeting the prescribed control efficiencies established 
at the time the MACT standard was promulgated. And, we continue to 
believe that these revisions are appropriate under CAA sections 
112(d)(2) and (d)(3). The commenter has not suggested, and we do not 
believe, that the revisions promulgated would differ in substance if 
they were instead promulgated under CAA section 112(d)(6).
    In general, we expect that the NHVcz monitoring 
requirements that we are finalizing for flares will be consistent with 
the requirements in various consent decrees. However, we have not 
conducted a rigorous evaluation of equivalency between various 
requirements and therefore we are not at this time providing an 
allowance for flare owners or operators to comply with the 
NHVcz operating limits and any provisions for necessary 
monitoring needed in the consent decree in lieu of the NHVcz 
limits and monitoring requirements established in this rule. In the 
event that an owner or operator wishes to continue complying only with 
the requirements of a consent decree, the rule contains provisions by 
which owner or operator can seek approval for alternative limits that 
are at least equivalent to the performance achieved from complying with 
the operating limits included in the final rule.
iii. Pressure Relief Devices
    Comment: Several commenters suggested that the EPA develop a work 
practice approach for atmospheric PRD rather than a prohibition on 
releases. One commenter recommended that the EPA establish a work 
practice standard for atmospheric PRDs that requires refiners to 
implement a base level of preventative measures including: Basic 
process controls, instrumented alarms, documented and verified routine 
inspection and maintenance programs, safety-instrumented systems, 
disposal systems, provide redundant equipment, increase vessel design 
pressure and systems that reduce fire exposure on equipment. 
Additionally, the commenter recommended that the EPA require refiners 
to perform root cause analysis and implement corrective action in the 
event of a release. The commenter stated these requirements would be 
similar to the root cause analysis/corrective action requirements 
recently promulgated for flares under NSPS subpart Ja and provided 
specific regulatory language for a proposed work practice approach. 
(See section 2.4.1.8 in Docket item EPA-HQ-OAR-2010-0682-0583.) One 
commenter requested that the EPA allow a process for companies to 
submit an application for case-by-case limits to be approved by the 
agency, either the EPA or a delegated state similar to the alternate 
NOX limits for process heaters provided in NSPS subpart Ja. 
This commenter recommended that the EPA establish reasonable work 
practice standards, specifically suggesting that the EPA develop work 
practice standards consistent with API 521. The commenter stated that 
the EPA should provide an implementation period for compliance that 
goes beyond the timeframe provided under CAA section 112(d). The 
commenter added that the EPA should adopt specified changes to the 
definition of an atmospheric pressure relief safety valve and provided 
suggested regulatory language for a proposed work practice standard for 
PRDs in EPA-HQ-OAR-2010-0682-0549.
    Another commenter stated that the EPA should require, as the Bay 
Area Air Quality Management District (BAAQMD) does, that any refinery 
that has a reportable PRD event must take certain steps to prevent such 
releases in the future (BAAQMD Rule 8-28-304). In particular, such a 
refinery must create a Process Hazard Analysis, meet the Prevention 
Measures Procedures specified in section 8-28-405, and conduct a 
failure analysis of the incident, to prevent recurrence of similar 
incidents (Id. Reg. section 8-28-304.1). If a second release occurs, 
then, within one year, the facility must vent its PRDs to a vapor 
recovery or disposal system that meets certain requirements (Id. Reg. 
section 8-28-304.2). The commenter asserted that the EPA's prohibition 
on releases to the atmosphere from PRD will ensure that refineries take 
the necessary steps to prevent such releases, or install control 
devices so that any releases from PRDs that must occur are vented 
through a control device to reduce the amount of toxic air pollution 
they emit. At a minimum, the commenter stated, the EPA must prohibit 
these uncontrolled emissions and require monitoring and reporting to 
assure compliance and ensure that the emission standards apply at all 
times, as required by the Act. The commenter argued that the EPA must 
also, however, consider requiring the additional developments that have 
been put into place in the BAAQMD and also require control devices to 
be used for all PRD, as some local air districts require. In addition, 
the commenter supported the EPA's monitoring and reporting requirements 
for PRD releases and the proposed electronic reporting requirements, 
which the EPA recognized are needed to assure compliance and assist 
with future rulemakings and as that provision requires, the EPA also 
must make all information reported publicly available online promptly 
and in an accessible and understandable format.
    Response: We agree that, under the proposal, refineries would 
consider installing add-on controls to comply with the prohibition on 
atmospheric releases from PRDs. In addition, they would consider 
venting these control devices to existing control devices, including 
flares. However, it may not be feasible to vent some or all of the PRDs 
to existing flares if the flares are near their hydraulic load capacity 
based on the processes already connected to the flares. Flares have 
negative secondary impacts when operated at idle conditions for the 
vast majority of time, which could be the case if they were installed 
solely to address PRD releases. These secondary impacts result from 
GHG, CO and NOX emissions. Some PRDs may vent materials that 
are not compatible with flare control and would need to be vented to 
other controls.
    To estimate the impact of the proposed prohibition on venting PRDs 
to the atmosphere, we estimated that at least one new flare per 
facility would be required to handle releases from PRDs, based on the 
number of atmospheric PRDs reported at refineries; that 60-percent of 
the PRDs could be piped to existing controls at minimal costs and the 
other 40-percent would have to be piped to new flares; and that, on 
average, each new flare would service 40 PRDs. Based on these 
assumptions, 151 new flares would be needed or approximately one new 
flare per refinery. At a capital cost of $2 million for each new flare, 
which would not include long pipe runs, if needed, to PRD that are 
dispersed across the plant, we estimate that the capital cost of the

[[Page 75214]]

prohibition on venting to the atmosphere would exceed $300 million. 
Considering the fuel needed (approximately 50,000 scf/day per flare) 
and a natural gas price of $4.50 per 1,000 scf, we estimate the annual 
operating cost for these new flares to be $12 million.
    PRDs are unique in that they are designed for the purpose of 
releasing or ``popping'' as a safety measure to address pressure build-
up in various systems--pipes, tanks, reactors--at a facility. These 
pressure build-ups are typically a sign of a malfunction of the 
underlying equipment. While it would be difficult to regulate most 
malfunction events because they are unpredictable and can vary widely, 
in the case of PRDs, they are equipment installed specifically to 
release during malfunctions and as such, we have information on PRDs in 
our 2011 Refinery ICR and through the SCAAMD and BAAQ rules to 
establish standards for them. After reviewing these comments, we thus 
examined whether it would be feasible to regulate these devices under 
CAA section 112(d)(2) and (3).
    After reviewing the comments, we agree with the commenters who 
suggest that the BAAQMD rule, as well as a similar South Coast Air 
Quality Management District (SCAQMD) rule that address PRD releases 
(SCAQMD Rule 1173), provide work practice standards that reflect the 
level of control that applies to the best performers. Consequently, we 
developed a work practice standard for PRD based on a detailed MACT 
analysis considering the requirements in these rules. Our rationale for 
the selected MACT requirements is provided in section IV.C.4 of this 
preamble. The work practice standards that we are finalizing for PRDs 
require refiners to establish proactive measures for each affected PRD 
to prevent direct release of HAP to the atmosphere as a result of 
pressure release events. In the event of an atmospheric release, we are 
requiring refinery owners or operators to conduct root cause analysis 
to determine the cause of a PRD release event. If the root cause was 
due to operator error or negligence, then the release would be a 
deviation of the standard. For any other release (not including those 
caused by force majeure events), the owner or operator would have to 
implement corrective action. A second release due to the same root 
cause for the same equipment in a 3-year period would be a deviation of 
the work practice standard. Finally, a third release in a 3-year period 
would be a deviation of the work practice standard, regardless of the 
root cause. Force majeure events would not count in determining whether 
there has been a second or third event.
    With respect to defining ``atmospheric pressure relief safety 
valve'' as suggested by the commenter, we note that the June 30, 2014, 
proposed amendments in 40 CFR 63.648(j) used the term ``relief valve'' 
because this was a defined term in Refinery MACT 1. However, the 
proposed amendments included clauses such as ``if the relief valve does 
not consist of or include a rupture disk.'' Thus, we specifically 
intended to apply the pressure relief management requirements broadly 
to ``pressure relief devices'' and not just ``valves.'' To clarify 
this, we have revised the regulatory language to use the term 
``pressure relief device'' rather than ``relief valve'' to clearly 
include rupture disks or similar types of equipment that may be used 
for pressure relief.
4. What is the rationale for our final approach and final decisions for 
the revisions pursuant to CAA section 112(d)(2) and (3)?
    We revised the MACT floor determination for DCU sources. CAA 
section 112(d)(3)(A) requires the MACT floor for existing sources to 
exclude ``. . . those sources that have, within 18 months before the 
emission standard is proposed or within 30 months before such standard 
is promulgated, whichever is later, first achieved a level of emission 
rate or emission reduction which complies, or would comply if the 
source is not subject to such standard, with the lowest achievable 
emission rate (as defined by section 171) applicable to the source 
category and prevailing at the time, in the category or subcategory for 
categories and subcategories with 30 or more sources.'' Because we have 
determined that a 2 psig emissions limitation is equivalent with a LAER 
emission limit for DCU, we revised the MACT floor analysis in order to 
exclude sources that first met the 2 psig limit on or after December 
30, 2012. For existing sources, based on the revised MACT analysis, we 
concluded that the MACT floor is still 2 psig. However, because the 
information on which we relied was submitted in response to the 2011 
Petroleum Refinery ICR which requested ``typical'' venting pressures 
and because providing an allowance to average across venting periods 
does not reduce the emissions reductions achieved, we are providing a 
60-event averaging period for existing sources in response to public 
comments received.
    For new DCU sources, our revised analysis identified one DCU 
subject to permit emission limitations of 2.0 psig pressure limit prior 
to venting on a per event basis. Under CAA section 112(d)(3), the MACT 
standard for new sources cannot be less stringent than the emission 
control achieved in practice by the best-controlled similar source. 
Thus, we are finalizing a limit of 2.0 for new DCU sources. We note 
that as 2.0 psig limit is more stringent than a 2 psig limit because of 
the rounding convention of rounding to the number of significant digits 
for which the standard is expressed. For example, a 2.4 psig venting 
pressure is compliant with a 2 psig limit, while it is not compliant 
with a 2.0 psig limit.
    We evaluated the costs of requiring existing sources to meet a 2.0 
psig limit as a beyond-the-MACT-floor option. We determined the 
incremental cost of going from a 2 psig limit with an allowance to 
average over 60 events to a 2.0 psig limit on a per event basis was 
approximately $70,000 per ton of HAP reduced considering VOC credits. 
Based on this high incremental cost-effectiveness, we concluded that 
the MACT floor requirement for existing DCU sources was MACT. As 
discussed in detail in the proposal, we do not consider it technically 
feasible to meet a 1 psig pressure limit (effectively a 1.4 psig limit) 
on a not-to-be-exceeded basis. Thus, we rejected this beyond the floor 
control option for both existing and new DCU sources. See the 
memorandum titled ``Reanalysis of MACT for Delayed Coking Unit Decoking 
Operations'' in Docket ID No. EPA-HQ-OAR-2010-0682 for additional 
details regarding our re-analysis of MACT for DCU decoking operations.
    In response to comments received on the prohibition of draining 
prior to achieving the proposed pressure limit (see Section 7.2.1 in 
the ``National Emission Standards for Hazardous Air Pollutants from 
Petroleum Refineries--Background Information for Final Amendments: 
Summary of Public Comments and Responses'' in Docket ID No. EPA-HQ-OAR-
2010-0682), we are providing specific provisions to allow for draining 
under special conditions. The specific provision and our rationale for 
providing them are provided below.
    First, we learned that certain DCU are designed to completely fill 
the drum with water and allow the water to overflow in the overhead 
line and drain to a receiving tank in order to more effectively cool 
the coke bed. Owners or operators of this DCU design were concerned 
that the water overflow may be considered a drain and also stated that 
overhead temperature rather than pressure would be a better indicator 
of effective bed cooling. In reviewing this

[[Page 75215]]

type of DCU design, we find that this design has some unique advantages 
to traditional DCU to effect better cooling of the coke drum, and 
therefore we do not want to preclude its use. Based on saturated steam 
properties, we determined that an overhead temperature of 220 [deg]F 
would achieve equivalent or greater emissions reductions than a 2 psig 
pressure limitation and an overhead temperature of 218 [deg]F would 
achieve equivalent or greater emissions reductions than a 2.0 psig 
pressure limitation. Therefore, we are including these temperature 
limits as alternatives to the 2 or 2.0 psig pressure limitations for 
existing and new DCU affected sources, respectively. With respect to 
the overflow ``drain,'' we remain concerned with emissions from 
draining superheated water. However, if submerged fill is used in the 
atmospheric tank receiving the overflow water, the superheated water 
will be cooled by the water within the tank and emissions that occur 
during the conventional draining of water (from the flashing of 
superheated water into steam) can be prevented. Therefore, we are 
allowing the use of water overflow provided the overflow ``drain'' 
water is hard-piped to the receiving tank via a submerged fill pipe 
(pipe below the existing liquid level) whenever the overflow water 
exceeds 220 [deg]F.
    Second, we received comments that, for conventional DCU (those not 
designed to allow water overflow), there is a limit to the maximum 
water level in the drum, which limits to some extent how much cooling 
water can be added to the coke drum. In rare cases, the coke drum does 
not cool sufficiently using the typical cooling steps. In this case, 
the common industry practice is to partially drain the coke drum and 
refill it with additional cooling water. This ``double-quench'' process 
is needed for safety reasons to sufficiently cool the coke drum 
contents prior to the decoking operations. Therefore, commenters 
requested provisions to allow double-quenching of the coke drum. We 
recognize the safety issues associated with coke blow-out during coke 
cutting if there is a portion of the coke bed that is not sufficiently 
cooled and we agree that double-quenching is an effective means to cool 
the coke drum in those rare instances that the typical cooling cycle 
does not sufficiently cool the coke drum contents, so we considered 
granting the commenters' request. As noted previously, the primary 
concern with early draining of the coke drum is the emissions that are 
expected to occur as a result of draining superheated water. We 
recognize, however, that the water temperature near the bottom of the 
coke drum is typically much lower than at the top of the coke drum. If 
the temperature of the water drained from the bottom of the coke drum 
remains below 210 [deg]F, this would minimize steam flashing and 
associated HAP emissions since the water drained would not be 
superheated. We conclude that the use of double quenching is 
appropriate for cases when the coke drum is not sufficiently cooled 
using the normal cooling procedures provided the temperature of the 
water drained remains below 210 [deg]F, and it is consistent with the 
practices of the best performing sources. Consequently, we are 
finalizing provisions to allow the use of double-quenching for DCU 
provided the temperature of the water drained remains below 210 [deg]F.
    For the CRU, we are finalizing the proposed revisions to require 
CRU that employ active purging to meet the MACT emissions limitations 
in Tables 15 and 16 in subpart UUU at all times regardless of vessel 
pressure. We received limited comments regarding our proposal; these 
comments generally concerned the costs associated with the proposed 
emissions limitations. As discussed in our proposal, and based on data 
submitted in response to the ICR, emissions using active purging are 
much higher than those not using active purging. In the original rule, 
we based the MACT floor on the best performing facilities that used 
sequential pressurizations and depressurizations rather than active 
purging. Thus, in the proposal, we concluded that allowing owners or 
operators to actively purge while at low pressures was inconsistent 
with the MACT floor emissions limitations achieved by the best 
performing 12-percent of sources when the MACT floor was originally 
established. As we are simply requiring these facilities to meet the 
same emission levels determined to be MACT, we do not consider costs of 
potential additional controls to be a viable rationale to allow these 
units to emit several times more HAP than the units upon which the MACT 
requirements were based and the emissions levels achieved in practice 
by the vast majority of other CRU sources.
    For flares, we are finalizing proposed revisions to include 
detailed flare monitoring and operating requirements. We are including 
the flaring provisions for refineries in the Refinery MACT rules and 
removing the cross-references to the flaring requirements in the 
General Provisions. The final regulatory requirements differ from the 
proposed requirements in several respects. First, we are not finalizing 
the ban on halogenated vent streams because we did not include 
sufficient justification or include cost estimates for this proposed 
provision and we did not include any monitoring requirements to ensure 
compliance with this ban on halogenated vent streams.
    We are finalizing the proposed no visible emissions limit and the 
flare tip velocity limit but they will apply only when the flare vent 
gas flow rate is below the smokeless capacity of the flare. We received 
a number of comments stating that the no visible emissions limit and 
the flare tip velocity limit cannot be met during large malfunctions 
and emergency shutdown events. In response to comments, we are 
finalizing work practice standards for emergency flaring events using 
the proposed no visible emission limit and flare tip velocity limit as 
thresholds in the final rule to trigger root cause analysis when the 
flare vent gas flow rate is above the smokeless capacity of the flare. 
The final work practice standard includes requirements to develop a 
flare management plan, to implement prevention measures, and to perform 
root cause analysis and implement corrective action following each 
flaring event that exceeds the smokeless capacity of the flare. There 
is also a limit on the number of these flaring events that a given 
flare may have in the 3-year period. We are establishing these 
provisions because we now recognize that flares have two different 
design capacities: A smokeless design capacity and a hydraulic load 
capacity. We determined that the proposed visible emissions limit and 
the flare tip velocity limit for very large flow events are not the 
MACT floor for such events. The final work practice standards for 
flaring events are based on the best performing facilities and will 
result in emission reductions in a technically feasible manner without 
any negative secondary impacts.
    We consider it appropriate to establish a work practice standard 
for flares as provided in CAA section 112(h). While it is possible to 
monitor gaseous streams going into the flare (as we have required for 
the flare operating requirements) it is not possible to design and 
construct a conveyance to capture the emissions from a flare. While 
knowledge of the composition and flow of gases entering the flare 
provides a reasonable basis for establishing operating requirements for 
normal operations, we have no data on flare performance under 
conditions in the hydraulic load range. While smoke in the flare 
exhaust is an indication of incomplete combustion, it is uncertain

[[Page 75216]]

how much deterioration of HAP destruction efficiency occurs during a 
smoking event. We also consider that the application of a measurement 
methodology for flare exhaust is not practicable due to technological 
and economic limitations. Passive FTIR has been used to determine 
combustion efficiency in flare exhaust, but these are essentially 
manual tests, and the measurement accuracy is dependent on how well the 
monitor is aligned with the flare exhaust plume. Changes in wind 
direction require manual movement of the monitoring system. It is also 
unclear if these systems can accurately measure combustion efficiency 
during high smoking events. These systems also require very specialized 
expertise, and we consider that it is both technologically and 
economically infeasible to measure flare exhaust emissions, 
particularly during high load events. Consequently, for emergency flare 
releases, we conclude that it is appropriate to establish a work 
practice standard as provided in CAA section 112(h).
    We also received comments that the daily visible emissions 
observations were burdensome and unnecessary and some commenters 
suggested that facilities be allowed to use video surveillance cameras. 
We concluded that video surveillance cameras would be at least as 
effective as the proposed daily 5-minute visible emissions observations 
using Method 22. We are finalizing the proposed visible emissions 
monitoring requirements Method 22 and the alternative of using video 
surveillance cameras.
    We are simplifying the combustion zone gas property operating 
limits in response to public comments received. Specifically, we are 
finalizing requirements that all flares meet a minimum operating limit 
of 270 BTU/scf NHVcz on a 15-minute average, and we are 
providing that refiners use a corrected heat content of 1,212 BTU/scf 
for hydrogen to demonstrate compliance with this operating limit. We 
determined that a corrected heat content of 1212 BTU/scf for hydrogen 
provided a better indication of flare performance than without the 
correction. We also determined that the other combustion zone 
parameters, which were primarily proposed to provide suitable methods 
for flares that had high hydrogen concentrations, were no longer 
necessary when a 1,212 Btu/scf net heating value is used for hydrogen. 
Therefore, we are not finalizing the alternative combustion zone 
operating limits based on lower flammability limit or combustibles 
concentration. We are also not finalizing separate combustion zone 
operating limits for gases meeting the proposed hydrogen-olefin 
interaction criteria. In our revised analysis of the data, we analyzed 
all of the data together and determined the 270 Btu/scf 
NHVcz operating limit provided in the final rule would 
adequately ensure that flares achieve the desired 98-percent control 
efficiency regardless of the composition of gas sent to the flare.
    For air-assisted flares, we are finalizing the additional 
``dilution parameter'' operating limit only for the net heating value 
dilution parameter, NHVdil. Similar to the requirements we 
are finalizing for the combustion zone parameters, we are finalizing 
requirements that flares meet a minimum operating limit of 22 BTU/
ft2 NHVdil on a 15-minute average, and we are 
providing that refiners use a corrected heat content of 1,212 BTU/scf 
for hydrogen to demonstrate compliance with this operating limit. For 
the reasons explained above, we are not finalizing the proposed 
alternative dilution parameter operating limits based on lower 
flammability limit or combustibles concentration, and we are not 
finalizing separate dilution parameter operating limits for gases 
meeting the proposed hydrogen-olefin interaction criteria.
    For flares in dedicated service, we are establishing an alternative 
to continuous or on-going grab sample requirements for determining 
waste gas net heating content to reduce the burden of sampling for 
flare waste gases that have consistent compositions. Flares in 
dedicated service can use initial sampling period and process knowledge 
to determine a fixed net heating value of the flare vent gas to be used 
in the calculations of NHVcz and, if applicable, 
NHVdil.
    We are revising the definition of MPV to remove the exemption for 
in situ sampling systems for the reasons provided in the proposed rule.
    We received comments recommending that a work practice standard be 
adopted for PRD rather than the proposed prohibition of atmospheric PRD 
releases. Commenters stated that the prohibition was infeasible due to 
the proposed immediate timing of the requirement and impractical due to 
cost considerations. After reviewing these comments as well as the 
BAAQMD rule (Regulation 8, Rule 8-28-304) and the SCAQMD rule (Rule 
1173), we have determined that the work practice standards in these 
rules reflect the level of control that applies to the best performers. 
Therefore, we proceeded to evaluate appropriate MACT requirements based 
on the provisions in these rules.
    The BAAQMD rule requires sources to implement a minimum of three 
prevention measures to limit the possibility of a release. The BAAQMD 
uses a ``release event'' threshold of 10 lbs/day of organic or 
inorganic pollutants; the SCAQMD rule effectively uses a release event 
threshold of 500 lbs VOC/day. When a release event occurs, both rules 
require that the refiner perform a root cause analysis and take 
corrective action (including additional prevention measures). In 
addition, both rules require piping the PRD to a flare if there are 
more than two release events (releases above a certain release size 
threshold) in a 5-year period. Both rules include a number of 
exemptions for certain types of PRD that are not expected to release 
significant amounts of pollutants to the air or that are not feasible 
to control because of pressure considerations. These include PRD 
associated with storage tanks, vacuum systems and equipment in heavy 
liquid service as well as liquid thermal relief valves that are vented 
to process drains.
    There are five refineries subject to the BAAQMD rule and seven 
refineries subject to the SCAQMD rule, accounting for 8-percent of 
refineries nationwide and representing the industry's best performers. 
We consider the BAAQMD rule to be the more stringent of the two because 
this rule requires sources to implement a minimum of three prevention 
measures to limit the possibility of a release (the SCAQMD rule has no 
similar requirement) and uses a lower mass threshold for what is 
considered a ``release event'' (10 lbs/day of organic or inorganic 
pollutants versus the 500 lbs VOC release threshold in the SCAQMD 
rule). Therefore, the BAAQMD rule is considered to be the MACT floor 
requirement for PRDs associated with new affected sources and the 
SCAQMD rule is considered to be the MACT floor for PRDs associated with 
existing affected sources.
    In general, an open PRD is essentially the same as a miscellaneous 
process vent that is vented directly to the atmosphere. Consistent with 
our treatment of miscellaneous process vents and consistent with the 
two California rules, we believe that it is appropriate to exclude 
certain types of PRD that have very low potential to emit based on 
their type of service, size and/or pressure. For example, PRD that have 
a potential to emit less than 72 pounds per day of VOC, considering the 
size of the valve opening, design release pressure, and equipment 
contents, would be considered in a similar manner as Group 2 
miscellaneous

[[Page 75217]]

process vents and would not require additional control. The two 
California rule requirements do not apply to PRD on storage tanks and 
vacuum systems. Most of these PRD have a design release pressure of 2.5 
psig and thus have a very limited potential to emit. It is technically 
infeasible to pipe these sources to a flare (or other similar control 
system) because the back pressure in the flare header system generally 
exceeds 2.5 psig. We note that some storage tanks can operate at 
elevated pressure (i.e., pressure tanks). Therefore, rather than follow 
exactly the requirements in the California rules, we determined it more 
practical to exclude PRD with design release pressure of less than 2.5 
psig.
    Any release from a PRD in heavy liquid service would have a visual 
indication of a leak and any repairs to the valve would have to be 
further inspected and, if necessary, repaired under the existing 
equipment leak provisions. Therefore, consistent with the BAAQMD rule, 
we are exempting PRD in heavy liquid service from the work practice 
standards we are establishing in this final rule.
    Both the BAAQMD and SCAQMD rules exempt thermal expansion valves 
that are ``vented to process drains or back to the pipeline.'' We are 
unclear what is meant by ``vented to process drains''; however, if a 
liquid is released from a PRD via hard-piping to a drain system that 
meets the control requirements specified in Refinery MACT 1, we 
consider that these PRD are controlled and they would not be subject to 
the work practice standard established in this final rule. Similarly, 
all PRD in light liquid service that are hard-piped to a controlled 
drain system (or back to the process or pipeline) are otherwise subject 
to a MACT requirement and would not be subject to the work practice 
standard.
    In considering thermal relief valves not vented to process drains 
or back to the pipeline, we expect that releases from these thermal 
relief valves will be small and generally under the release event 
thresholds specified in the California rules. Therefore, the work 
practice standards do not apply to PRD that are designed solely to 
release due to liquid thermal expansion.
    The primary goal of the PRD work practice standard is to reduce the 
size and frequency of releases. The SCAQMD rule is targeted towards 
fairly large releases (compared to the direct PRD releases reported in 
response to the Refinery ICR), so it will reduce the frequency of large 
releases, but it does little to reduce the frequency of smaller 
releases. To more effectively reduce the size and frequency of all 
releases, we consider it important to require the implementation of 
prevention measures (as required in the BAAQMD rule) and require root 
cause analysis and corrective action for PRD releases from all PRD 
subject to the work practice standard. While we recognize that if a PRD 
opens for a short period of time, the release might be below the 
release thresholds in the SCAQMD rules, we believe the release may be 
indicative of an important issue or design flaw. Because the potential 
for large emissions exist from the PRD subject to the work practice 
standard, we think it is reasonable to require a root cause analysis be 
conducted and appropriate corrective action implemented to potentially 
identify this issue and prevent a second release which, if the issue 
remains uncorrected, could be significant.
    Requiring that prevention measures be implemented on all PRD 
subject to the work practice standard and not establishing a release 
threshold for release events is a variation from the SCAQMD rule. 
However, we also considered the allowable release frequency. We believe 
that our adoption of this approach is balanced by our not adopting the 
SCAQMD provisions requiring that PRD be vented to a flare or other 
control system or that refiners pay a fee if there are multiple 
releases of a certain size within a specified timeframe.\12\ In place 
of this system, we are limiting the number of events from each PRD that 
can occur in a 3 year time period (2, if root causes are different), 
and in place of a fine, or routing to control, stating that the 3rd 
release in 3 years for any root cause is a deviation of the standard.
---------------------------------------------------------------------------

    \12\ The SCAQMD rule requires PRD to be vented to a flare or 
other control device if there is a single release in excess of 2,000 
pounds of VOC in a 24-hour period or three releases in excess of 500 
pounds of VOC in a 5-year period or, alternatively, pay a $350,000 
fee. Thus, the SCAQMD rule would allow, for example, two releases of 
over 500 pounds of VOC each within a 5-year period without any 
penalty provided a third event did not occur. If a third event did 
occur, the refinery owner or operator would then have to vent the 
PRD to a flare or other control system or pay a fee ($350,000) for 
the third release over 500 pounds of VOC.
---------------------------------------------------------------------------

    Because we are not including a size threshold for release events as 
in the SCAQMD rule, it is natural to assume release events would occur 
more frequently than release events subject to the SCAQMD rules. Also, 
based on our Monte Carlo analysis of random rare events, we note that 
it is quite likely to have two or three events in a 5-year period when 
a long time horizon (e.g., 20 years) is considered. Therefore, 
considering our analysis of emergency flaring events and the lack of a 
500 lb/day release threshold, we considered it reasonable to use a 3-
year period rather than a 5-year period as the basis of a deviation of 
the work practice standard.
    The SCAQMD work practice standards do not apply to releases that 
are demonstrated to ``result from natural disasters, acts of war or 
terrorism, or external power curtailment beyond the refinery's control, 
excluding power curtailment due to an interruptible service 
agreement.'' These types of events, which we are referring to as 
``force majeure'' events, are beyond the control of the refinery owner 
or operator. We are providing that these events should not be included 
in the event count, but that they would be subject to the root cause 
analysis in order to confirm whether the release was caused by a force 
majeure event.
    Consistent with the requirements in the SCAQMD rule, we are 
requiring refinery owners or operators to conduct a root cause analysis 
for a PRD release event. If the root cause was due to operator error or 
negligence, then the release would be a deviation of the standard. For 
any other release (not including those caused by force majeure events), 
the owner or operator would have to implement corrective action. We 
consider that a second release due to the same root cause for the same 
equipment in a 3-year period would be a deviation of the work practice 
standard. This provision will help ensure that root cause/corrective 
action are conducted effectively. Finally, a third release in a 3-year 
period (not including those caused by force majeure events) would be a 
deviation of the work practice standard, regardless of the root cause. 
While we are using a 3-year interval rather than the 5-year interval 
provided in the SCAQMD, we consider that the requirements as included 
in this final rule (i.e., the inclusion of prevention measure 
requirements and no thresholds for release events) will achieve 
equivalent if not greater emissions reductions than the SCAQMD rule. We 
also consider that, given the prevention measure requirements and a 3-
year period, there is less likelihood of unusual random events that 
happen over a short period of time that may cause refinery owners or 
operators to feel compelled to vent the PRD to a flare to eliminate 
concerns regarding potential non-compliance. Thus, we project that the 
requirements that we have included in the final rule will achieve 
emissions reductions commensurate to or exceeding the requirements in 
the SCAQMD rule (that serves as the MACT floor for existing sources) 
but will achieve those

[[Page 75218]]

reductions in a more cost-effective manner.
    We also considered requiring all PRD to be vented through a closed 
vent system to a control device as an alternative beyond-the-MACT floor 
requirement. While this requirement would provide additional emission 
reductions beyond those we are establishing as the MACT floor, these 
reduction come at significant costs. Capital costs for requiring 
control of all atmospheric PRD is estimated to be approximately $300 
million compared to $11 million for the requirements described above. 
The total annualized cost for requiring control of all atmospheric PRD 
is estimated to be approximately $41 million/year compared to $3.3 
million/year for the requirements described above. We estimate that the 
incremental cost-effectiveness of requiring control of all atmospheric 
PRD compared to the requirements described above exceeds $1 million per 
ton of HAP reduced. Consequently, we conclude that this is not a cost-
effective option for existing sources.
    The final requirements that we have developed for PRD achieve equal 
or greater emission reductions than those achieved by the SCAQMD rule 
(MACT floor). To the extent those requirements are more stringent that 
the SCAQMD, they are cost-effective. We could not identify an 
alternative requirement that provided further emission reductions in a 
cost-effective manner. Thus, we conclude that the work practice 
standards described above represent MACT for existing sources.
    The BAAQMD rule, which represents the requirements applicable to 
the best performing sources, is the basis for new source MACT for PRD. 
Based on the specific provisions for PRD in the BAAQMD rule, we 
conclude that the MACT floor requirement is to have all PRD in HAP 
service associated with a new affected source vented through a closed 
vent system to a control device. As with existing sources, the PRD WPS 
would also contain the same exclusions (e.g., heavy liquid service 
PRDs, thermal expansion valves, liquid PRDs that are hard-piped to 
controlled drains, PRD with release pressures of less than 2.5 psig, 
PRD with emission potential of less than 72 lbs/day, and PRD on mobile 
equipment). These provisions are similar to the applicability 
provisions of the BAAQMD rule. Thus, we retain the same applicability 
of the work practice standard for PRDs on new or existing equipment, 
but all affected PRD on a new source would be required to be 
controlled. This is essentially equivalent to the proposed requirement 
of no atmospheric releases. We could not identify a control option more 
stringent than the BAAQMD rule as applied to new sources. Therefore, we 
conclude that venting all PRD in HAP service through a closed vent 
system to a flare or similar control system is MACT for PRD associated 
with new affected sources.
    We consider it appropriate to establish a work practice standard 
for PRD as provided in CAA section 112(h). While it may be possible to 
design and construct a conveyance for PRD releases, we consider that 
the application of a measurement methodology for PRDs is not 
practicable due to technological and economic limitations. First, it is 
not practicable to use a measurement methodology for PRD releases. The 
venting time can be very short and may vary widely in composition and 
flow rate. The often-short duration of an event makes it infeasible to 
collect a grab sample of the gases when a release occurs, and a single 
grab sample would not account for potential variation in vent gas 
composition. It would be economically prohibitive to construct an 
appropriate conveyance and install and operate continuous monitoring 
systems for each individual PRD in order to attempt to quantitatively 
measure a release event that may occur only a few times in a 3-year 
period. Additionally, we have not identified an available, technically 
feasible continuous emission monitoring systems that can determine a 
mass VOC or HAP release quantity accurately given the flow, composition 
and composition variability of potential PRD releases from refineries. 
Consequently, we conclude that it is appropriate to establish a work 
practice standard for PRD releases as provided in CAA section 112(h).

D. NESHAP Amendments Addressing Emissions During Periods of SSM

1. What amendments did we propose to address emissions during periods 
of SSM?
    We proposed to eliminate the SSM exemption in 40 CFR part 63, 
subparts CC and UUU. Consistent with Sierra Club v. EPA, we proposed 
standards in these rules that apply at all times. We also proposed 
several revisions to Table 6 of subpart CC of 40 CFR part 63 and to 
Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions 
Applicability tables for each subpart), including eliminating the 
incorporation of the General Provisions' requirement that the source 
develop an SSM plan, and eliminating and revising certain recordkeeping 
and reporting requirements related to the SSM exemption.
    For Refinery MACT 1, we proposed that the use of a bypass at any 
time to divert a Group 1 miscellaneous process vent to the atmosphere 
is a deviation of the emission standard, and specified that refiners 
install, maintain and operate a continuous parameter monitoring system 
(CPMS) for flow that is capable of recording the volume of gas that 
bypasses the APCD.
    We also proposed to revise the definition of MPV to remove the 
exclusion for ``Episodic or non-routine releases such as those 
associated with startup, shutdown, malfunction, maintenance, 
depressuring and catalyst transfer operations.'' We also proposed that 
the control requirements for Group 1 MPV apply at all times, including 
startup and shutdowns.
    For Refinery MACT 2, we proposed alternate standards for three 
emission sources for periods of startup or shutdown. We proposed PM 
standards for startup of FCCU controlled with an ESP under Refinery 
MACT 2 because of safety concerns associated with operating an ESP 
during an FCCU startup. For FCCU controlled by an ESP, we proposed a 
30-percent opacity limit (on a 6-minute rolling average basis) during 
the period that torch oil is used during FCCU startup. For startup of 
FCCU without a post-combustion device under Refinery MACT 2, we 
proposed a CO standard based on an excess oxygen concentration of 1 
volume percent (dry basis) based on a 1-hour average. For periods of 
SRU shutdown, we proposed to allow diverting the SRU purge gases to a 
flare meeting the design and operating requirements in 40 CFR 63.670 
(or, for a limited transitional time period, 40 CFR 63.11) or to a 
thermal oxidizer operated at a minimum temperature of 
1,200[emsp14][deg]F and a minimum outlet oxygen concentration of 2 
volume percent (dry basis). For other emission sources in Refinery MACT 
2, we proposed that the requirements that apply during normal 
operations should apply during startup and shutdown.
2. How did the SSM provisions change since proposal?
a. Refinery MACT 1
    We proposed that when process equipment is opened to the atmosphere 
(e.g., for maintenance), the existing MPV emissions limits apply. In 
this final rule, we are instead finalizing startup and shutdown 
provisions that apply to these venting events. These startup and 
shutdown provisions are work practice standards that allow refinery 
owners or operators to open process equipment

[[Page 75219]]

during startup and shutdown provided that the equipment is drained and 
purged to a closed system until the hydrocarbon content is less than or 
equal to 10-percent of the LEL. For those situations where 10-percent 
LEL cannot be demonstrated (no direct measurement location), the 
equipment may be opened and vented to the atmosphere if the pressure is 
less than or equal to 5 psig. Active purging of the equipment is only 
allowed after the 10-percent LEL level is achieved, regardless of the 
pressure of the equipment/vessel. We are establishing a separate 
requirement for very small process equipment, defined as equipment 
where it is physically impossible to release more than 72 lbs VOC per 
equipment opening based on the size and contents of the equipment. This 
definition is consistent with the Group 1 applicability cutoff for 
control of miscellaneous process vents. We also developed requirements 
specific to catalyst changeout activities where pyrophoric catalyst 
(e.g., hydrotreater or hydrocracker catalysts) must be purged using 
recovered hydrogen. These provisions include: Documenting the 
procedures for equipment openings and procedures for verifying that 
events meet the specific conditions above using site procedures used to 
de-inventory equipment for safety purposes (i.e., hot work or vessel 
entry procedures) and documenting any deviations from the work practice 
standard requirements.
b. Refinery MACT 2
    We are expanding the proposed 1-percent minimum oxygen operating 
limit alternative for organic HAP to apply for all FCCU startup and 
shutdown events (rather than only partial burn FCCU with CO boilers 
during startup). We are replacing the proposed opacity limit 
alternative to the metal HAP standard with a minimum cyclone face 
velocity limit and we are extending that alternative limit to all FCCU 
(regardless of control device) for both startup and shutdown in this 
final rule.
    We are extending the proposed alternative for SRU to monitor 
incinerator temperature and excess oxygen limits during SRU shutdowns 
to also apply during periods of startup.
3. What key comments did we receive on the SSM revisions and what are 
our responses?
a. Refinery MACT 1
    Comment: Many commenters stated that the proposed extension of the 
MPV definition to episodic maintenance startup and shutdown vents and 
elimination of the SSM exception for storage tanks would create 
hundreds or thousands of new vents per refinery per year and generate 
massive on-going burdens. The commenters argued that the EPA has not 
included in the record any analysis of the potential environmental 
benefits, costs or operational and compliance feasibility and impacts 
associated with this requirement and that many of these requirements 
will result in delayed and extended equipment and process outages. One 
commenter asserted that the EPA has articulated no justification for 
applying emission standards to these events, nor any analysis 
consistent with CAA section 112 for a determination that MACT standards 
are appropriately applied to these emission events under the criteria 
in CAA section 112(d).
    Many commenters stated that every time a vessel is opened for 
inspection or maintenance each vent point will have to be evaluated as 
a potential MPV or storage tank vent. If a particular vent point (e.g., 
bleeder) used for maintenance, startup or shutdown handles material 
that is initially greater than 20 ppm HAP, then it is a MPV. If there 
is a potential to emit greater than or equal 72 lbs/day of VOC, then it 
is a Group 1 MPV and must be controlled. If there is a potential of 
less than 72 lb/day VOC release, then it is a Group 2 MPV and subject 
to recordkeeping requirements. Commenters stated that in a refinery 
there would be tens or more such activities per day associated with 
normal maintenance and inspection; during turnarounds, there could be 
hundreds of such MPVs. Commenters added that these MPVs may then need 
to be individually accounted for and permitted creating an unnecessary 
permitting and recordkeeping burden for these periodic emissions.
    Commenters recommended a general set of work practice requirements 
for maintenance, startup and shutdown of vents, based on state 
requirements, that do not impose the permitting, notice and evaluation 
requirements associated with identifying these vents individually. 
Commenters explained that states have dealt with these episodic vents 
by establishing them as a special class of process vent with limited 
recordkeeping requirements and subject to a work practice standard, 
rather than the normal MPV requirements. A key element of these work 
practices is clear identification of the criteria for releasing these 
vents to the atmosphere and for routing these vents to control after 
hydrocarbon is reintroduced, which the commenters asserted the current 
rule does not provide. Commenters proposed that a work practice 
standard could include removing process liquids to the extent practical 
and depressuring smaller volume equipment until a pressure of <5 psig 
is achieved and/or purging and depressuring to a control device until 
the vent has a hydrocarbon concentration of less than 10-percent of the 
LEL. The commenters suggested that these standards should provide clear 
easily monitored criteria for when this equipment can be vented to the 
atmosphere, and should not impose the permitting, notice and evaluation 
requirements associated with identifying these vents as individual 
MPVs. One commenter provided draft regulatory language for a work 
practice requirement.
    Response: We proposed to eliminate the episodic and non-routine 
emission exclusion in order to ensure that the MACT includes emission 
limits that apply at all times consistent with the holding in Sierra 
Club. At the time of the proposal, we expected that essentially all SSM 
event emissions would be routed to flares that are subject to the MACT 
standards and, thus, would serve to control these emissions. However, 
we recognize that maintenance activities that require equipment 
openings are a separate class of startup/shutdown emissions because 
there must be a point in time when the vessel can be opened and any 
emissions vented to the atmosphere. We acknowledge that it would 
require a significant effort to identify and characterize each of these 
potential release points for permitting purposes.
    In considering these comments and whether we should establish a 
separate limit that would apply to these equipment openings, we 
reviewed state permit requirements and the practices employed by the 
best performing sources. We found that some state or local agencies 
required depressuring to 5 psig prior to atmospheric releases while 
others required the gases to have organic concentrations at or below 
10-percent of LEL prior to atmospheric venting. In the final rule, we 
are establishing a requirement that prior to opening process equipment 
to the atmosphere, the equipment must first be drained and purged to a 
closed system so that the hydrocarbon content is less than or equal to 
10-percent of the LEL. For those situations where 10-percent LEL cannot 
be demonstrated, the equipment may be opened and vented to the 
atmosphere if the pressure is less than or equal to 5 psig, provided 
there is no active purging of the equipment to the atmosphere until the 
LEL criterion is met. For equipment where it is not technically 
possible to depressurize to a

[[Page 75220]]

control system, we allow venting to the atmosphere where there is no 
more than 72 lbs VOC per day potential, consistent with our Group 1 
applicability cutoff for control of process vents. For catalyst 
changeout activities where hydrotreater pyrophoric catalyst must be 
purged we have provided limited allowances for direct venting. 
Provisions to demonstrate compliance with this work practice include 
documenting the procedures for equipment openings and procedures for 
verifying that events meet the specific conditions above using site 
procedures used to de-inventory equipment for safety purposes (i.e., 
hot work or vessel entry procedures).
b. Refinery MACT 2
    Comment: Several commenters noted that there was a proposed 
specific alternative metal HAP/PM standard for startup of an FCCU 
controlled with an ESP, but took issue with the fact that no 
alternative PM limits were proposed for startup of FCCU equipped with 
other types of PM controls, or for any FCCU during periods of shutdown 
or hot standby. Regarding the proposed alternative for startup, which 
would provide an alternative in the form of an opacity limit when torch 
oil is in use, commenters stated that there are serious process safety 
concerns which prevent most FCCU ESPs from being operated when torch 
oil is in the regenerator, that is, during periods of startup, shutdown 
and hot standby. To avoid the possibility of a fire and explosion, the 
commenters claimed ESPs are usually de-energized and bypassed during 
these periods and, consequently, these FCCUs are generally unable to 
meet the proposed 30-percent opacity limit.
    Several commenters stated that the EPA's limits on FCCU opacity 
during SSM are unreasonable and ignore the technical requirements for 
transitional operations of those units. The commenters indicated that 
they have ESPs located downstream of the CO boiler and claimed that for 
safety reasons the CO boiler cannot operate during startup, shutdown or 
hot standby. Further, a commenter indicated that the ESP cannot operate 
if the CO boiler is not operating and thus both the CO boiler and the 
ESP must be bypassed during startup, shutdown, and hot standby 
operations.
    Another commenter stated that the EPA offers no data to support the 
achievability of this requirement in practice and discusses information 
for 26 startup/shutdown events that found that none complied with a 30-
percent opacity requirement. Several commenters also noted that 
experience has shown that the 30-percent opacity limit is unachievable 
during these periods for FCCUs controlled with tertiary cyclones, when 
regenerator gas flow is below cyclone minimum design flow.
    Several commenters suggested that the EPA establish a standard 
based on the operation of FCCU catalyst regenerators' internal cyclones 
that function to retain the catalyst in the regenerators and thereby 
minimize catalyst and metal HAP emissions from the regenerators. 
Additional control to meet the Refinery MACT 2 emission limit of not 
more than 1.0 lb PM/1,000 lbs coke burn-off is provided by a bag house, 
wet gas scrubber (WGS), ESP or tertiary (external) cyclone. The 
efficiency of a cyclone is a function of the inlet gas velocity. 
Assuring adequate velocity to the internal cyclones ensures that the 
catalyst sent to these additional controls is minimized and ensures 
that they are operating as effectively as possible. Similarly, even if 
the FCCU cannot meet the normal opacity limits during startup, shutdown 
or hot standby (e.g. due to the ESP being off-line for safety reasons 
or the tertiary cyclones or WGS operating at non-routine conditions), 
assuring adequate velocity to the internal regenerator cyclones will 
control and minimize particulate emissions. Several commenters stated 
support for another commenter's position that all FCCUs should be 
allowed the option of complying with a 20 feet/second minimum inlet 
velocity to the primary regenerator cyclones during periods of startup 
and shutdown, including hot standby, and these commenters provided 
additional technical explanations in their comments.
    On the other hand, some commenters seemed to support the proposed 
opacity limits, but suggested minor revisions. One commenter noted that 
the SCAQMD has granted Valero's request for variances from visible 
emission standards during startup of the FCCU of up to 65-percent 
opacity for up to five minutes, in aggregate, during any 1-hour period, 
and 30-percent as an hourly average for the remaining period, during 
startup events. The application of this variance reflects the 
unavailability and/or ineffectiveness of the ESP during the startup 
condition. Another commenter recommended that either the opacity 
standard should be raised or the time period for averaging should be 
extended so FCCUs can be operated safely during SSM events and still 
remain in compliance.
    Response: We have reviewed the data submitted by the commenters to 
support their assertion that the 30-percent opacity limit (determined 
on a 6-minute average basis) is not achievable during startup and 
shutdown events. While the data are limited, and it is unclear if the 
data provided are indicative of the performance achieved by the best 
performing sources, we do not have adequate data to refute the 
assertion that the 30-percent opacity limit (determined on a 6-minute 
average basis) is not achievable during startup and shutdown events. We 
considered the two options suggested by the commenters, the minimum 
velocity for the internal FCCU regenerator cyclones and the 30-percent 
hourly average opacity limit excluding 5 minutes not exceeding 65-
percent opacity. Again, due to the limited data available during 
startup and shutdown events, we are not able to determine which 
requirement would provide greater HAP emissions reduction. However, we 
note that some facilities may not be required to have an opacity 
monitoring system in place and opacity monitoring is not applicable for 
FCCU controlled with wet scrubbers. Therefore, we find that the minimum 
internal cyclone inlet velocity requirement is more broadly applicable 
than the opacity limit. Also, based on the data provided by the 
commenters, the minimum internal cyclone inlet velocity requirement 
will provide PM (and therefore metal HAP) emissions reductions during 
startup and shutdown periods. Therefore, considering the available 
data, we conclude that MACT for FCCU startup and shutdown events is 
maintaining the minimum internal cyclone inlet velocity of 20 feet/
second.
    Comment: Several commenters stated that the EPA should provide 
alternate standards for startups of FCCU equipped with CO boilers and 
for any FCCU during periods of shutdown and hot standby. The commenters 
stated that the EPA incorrectly assumes that refiners are able to 
safely and reliably start up their FCCU with flue gas boilers in 
service and meet the normal operating limit of 500 ppm CO. They claimed 
that most refiners are unable to reliably start up their FCCU with flue 
gas boilers in service due to the design of the boiler and the fact 
that many boilers are not able to safely and reliably handle the 
transient FCCU operations that can occur during startup, shutdown, and 
hot standby. One commenter stated that FCCU built with CO boilers 
experience issues with flame stability due to fluctuating flue gas 
compositions and rates when starting up and shutting down. Accordingly, 
the commenter stated, startup and shutdown activities at FCCU using a 
boiler as an APCD are not currently meeting the Refinery MACT 2 
standard

[[Page 75221]]

of 500 ppm CO on a 1-hour basis, and this level of control does not 
qualify as the MACT floor. The commenter gave examples of facilities 
where FCCU, including those equipped with post-combustion control 
systems, do not consistently demonstrate compliance with a 500 ppm CO 
concentration standard during all startup and shutdown events.
    Commenters stated that reliable boiler operation is critical to the 
overall refinery steam system and refineries must avoid jeopardizing 
boiler operation to prevent major upsets of process operations. A major 
upset or site-wide shutdown could result in flaring and emissions of 
HAP far in excess of that emitted while bypassing the CO boiler.
    Commenters stated that combustion of torch oil in the FCCU 
regenerator during startup is one of the primary reasons the CO limit 
cannot be met during these operations. Torch oil is also used during 
shutdown to control the cooling rate (and potential equipment damage) 
and during hot standby and, thus, the normal CO standard cannot be met 
at these times either. Hot standby is used to hold an FCCU regenerator 
at operating temperature for outages where a regenerator shutdown is 
not needed and to avoid full FCCU shutdowns. Full cold shutdown also 
increases personnel exposures associated with removing catalyst and 
securing equipment. Additionally, this can produce additional emissions 
over maintaining the unit in hot standby. Commenters claimed that 
because of the variability of CO during torch oil operations, it is not 
possible for the EPA to establish a CAA section 112(d) standard for 
startup and shutdown activities at FCCU because refineries cannot 
measure a constant level of emissions reductions.
    The commenters recommended expansion of the proposed standard of 
greater than 1-percent hourly average excess regenerator oxygen to all 
FCCU, including units with fired boilers. These commenters suggested 
that maintaining an adequate level of excess oxygen for the combustion 
of fuel in the regenerator is the best way to minimize CO and organic 
HAP emissions from FCCU during these periods.
    Response: After reviewing the comments and discussing CO boiler 
operations with facility operators, we agree that the 1-percent minimum 
oxygen limit should be more broadly applicable to FCCU startup and 
shutdown regardless of the control device configuration and have 
revised the final rule accordingly.
    Comment: Several commenters stated that the proposed alternative 
standards for SRP shutdowns should be extended to startups as well 
since the normal SRP emission limitation cannot always be achieved 
during SRP startups. Several commenters gave examples of startup 
activities where this relief is needed, and noted there may be other 
startup activities that also need this relief.
    Response: For the control of sulfur HAP, we determined that 
incineration effectively controls these HAP. We were not aware that 
there would be unusual sulfur loads in the SRU tail gas during startup. 
We agree that the alternative standard we proposed for periods of 
shutdown is also the MACT floor for periods of startup because 
incineration meeting the limits proposed will achieve the MACT control 
requirements for sulfur HAP during periods of either startup or 
shutdown even though sulfur loadings during these periods may be 
elevated. For many SRU configurations, compliance during normal 
operations is demonstrated by monitoring SO2 emissions. 
However, during startup and shutdown, high sulfur loadings in the SRU 
tail gas entering the incinerator will cause high SO2 
emissions even though sulfur HAP emissions are well controlled. 
Consequently, the proposed incinerator operating limits provide a 
better indication of sulfur HAP control during startup and shutdown 
than SO2 emissions. Owners or operators that use 
incinerators or thermal oxidizers during normal operations may meet the 
site-specific temperature and excess oxygen operating limits that were 
determined based on their performance test during periods of startup 
and shutdown.
4. What is the rationale for our final approach and final decisions to 
address emissions during periods of SSM?
a. Refinery MACT 1
    We did not receive comments regarding the proposed amendments to 
Table 6 of subpart CC of 40 CFR part 63; therefore, for the reasons 
provided in the preamble to the proposed rule, we finalizing these 
amendments as proposed.
    We determined that it was overly burdensome and in most cases 
technically infeasible to consider every potential equipment or vessel 
opening and classify these ``openings'' (newly classified as MPV in the 
proposal) as either Group 1 or Group 2 MPV. We also determined that it 
is not always technically feasible, depending on the opening, to 
demonstrate compliance with the MPV emissions limitations. After 
considering the public comments, we determined it was appropriate to 
establish separate startup and shutdown provisions for MPV associated 
with process equipment openings. We reviewed state and local 
requirements and based the final rule requirements on the emissions 
limitations required to be followed by the best performing sources. 
Therefore, we are finalizing requirements for refinery owners or 
operators to open process equipment during these startup and shutdown 
events without directly permitting these ``vents'' as Group 1 or Group 
2 MPV provided that the equipment is drained and purged to a closed 
system until the hydrocarbon content is less than or equal to 10-
percent of the LEL. As described in further detail previously in this 
section, we have provided provisions for special cases where the 10-
percent LEL limit cannot be demonstrated and provisions for less 
significant equipment openings, consistent with the practices used by 
the best performing facilities.
b. Refinery MACT 2
    We did not receive significant comments regarding the proposed 
amendments to Table 44 to subpart UUU of 40 CFR part 63; therefore, we 
finalizing these amendments as proposed.
    In response to comments, we determined that the limited provisions 
that were provided for startup only or for shutdown only were too 
limited and we have expanded the proposed provisions to both startup 
and shutdown regardless of control device used. For the FCCU organic 
HAP emissions limit, we are finalizing an alternative limit for periods 
of startup of no less than 1-percent oxygen in the exhaust gas as 
proposed, but we are extending that alternative limit to shutdown and 
to all FCCU in this final rule.
    For the FCCU metal HAP emissions limit, we proposed a specific 
startup limit for FCCU controlled be an ESP of 30-percent opacity. We 
received comments along with limited data suggesting that this limit 
was not achievable. Commenters suggested that the best performing units 
maintain a minimum face velocity of at least 20 feet/second to minimize 
catalyst PM losses during startup and shutdowns. Operators of wet 
scrubbers also noted that they cannot maintain pressure drops and that 
one cannot meet the PM emissions limit normalized by coke burn-off rate 
when the coke burn-off rate approaches zero. Consequently, commenters 
stated that the alternative limits should be provided for startup and 
shutdown regardless of control device. Upon consideration of the 
comments, we determined that it was necessary to revise the proposed

[[Page 75222]]

alternative to be based on minimum inlet face velocity to the FCCU 
regenerator internal cyclones and provide the alternative for both 
startup and shutdown. We also expanded this limit to all FCCU; however, 
we also required FCCU with wet scrubbers to meet only the liquid to gas 
ratio operating limit during periods of startup and shutdown to allow 
wet scrubbers to use a consistent compliance method at all times.
    For SRU, we are finalizing an alternative standard during periods 
of startup and shutdown to use a flare that meets the operating limits 
included in the final rule or a thermal oxidizer or incinerator 
operated at a minimum hourly average temperature of 1,200 [deg]F and a 
minimum hourly average outlet oxygen concentration of 2 volume percent 
(dry basis). We proposed these alternatives for periods of shutdown 
only, but based on comments received regarding startup issues, we 
determined that high sulfur loadings can occur during periods of 
startup and that the alternative limit proposed was appropriate for 
both startup and shutdown.

E. Technical Amendments to Refinery MACT 1 and 2

1. What other amendments did we propose for Refinery MACT 1 and 2?
    We proposed a number of amendments to Refinery MACT 1 and 2 to 
address technical issues such as rule language clarifications and 
reference corrections. First, we proposed to amend Refinery MACT 1 to 
clarify what is meant by ``seal'' for open-ended valves and lines that 
are ``sealed'' by the cap, blind flange, plug, or second valve by 
stating that sealed means when there are no detectable emissions from 
the open-ended valve or line at or above an instrument reading of 500 
ppm. Second, we also proposed electronic reporting requirements where 
owners or operators of petroleum refineries must submit electronic 
copies of required performance test and performance evaluation reports 
for compliance with Refinery MACT 1 and 2 by direct computer-to-
computer electronic transfer using EPA-provided software. Third, we 
proposed to update the General Provisions Tables 6 (for Refinery MACT 
1) and 44 (for Refinery MACT 2) to correct cross references and to 
incorporate additional sections of the General Provisions that are 
necessary to implement these rules.
2. How did the other amendments for Refinery MACT 1 and 2 change since 
proposal?
    We are not finalizing the definition of ``seal'' for open-ended 
lines as proposed. We are finalizing changes to update the General 
Provisions cross-reference tables as proposed, with one minor change to 
provide an option for the administrator to issue guidance on 
performance test reporting timeframes in order to address issues 
relating to submittal of data to the ERT.
3. What key comments did we receive on the other amendments for 
Refinery MACT 1 and 2 and what are our responses?
    Comment: Numerous commenters objected to the proposal to clarify 
the meaning of ``seal'' as it relates to open-ended line (OEL) 
standards. Commenters contend that there is no basis for the EPA to 
assert that the proposed definition merely ``clarifies'' an established 
interpretation of the term ``seal'' and stated that the proposed 
revision constitutes an illegal change in the requirements for OELs, 
and the clarification should not be finalized.
    One commenter stated that none of the MACT standards in place 
before this proposal have stated or suggested that a ``sealed'' OEL is 
one with detectable emissions below 500 ppm. This commenter added this 
unique interpretation of the requirement to ``seal'' an OEL with a cap 
or plug is incompatible with the historical interpretation of this 
requirement by affected facilities and by the EPA, and the EPA has not 
issued any sort of definitive guidance or interpretation setting out 
this position. The commenter detailed numerous references to 
considerations the EPA has made relative to OEL requirements in LDAR 
programs. In addition to the examples cited, the commenter noted that 
in 2006, the EPA proposed to add a ``no detectible emissions'' limit 
and monitoring requirement for OELs to NSPS VV (71 FR 65317, November 
7, 2006). Two commenters noted that the proposed monitoring was not 
finalized in either NSPS VV or VVa (72 FR 64860, November 16, 2007) 
because it was not considered BDT due to the low emission reductions 
and the cost effectiveness of the requirement. Another commenter agreed 
that there is no explanation provided for why this information could 
now support the need for a new OEL seal standard that requires 
monitoring to ensure compliance when it was deemed to be unjustified 
previously.
    In addition, the commenter collected OEL monitoring data and 
submitted it to the EPA (see Docket Item No. EPA-HQ-OAR-2010-0869-
0058). Based on these data, the commenter asserted that the existence 
of leaks from OELs that are not properly sealed is extremely low.
    The commenter noted that the EPA is claiming this change is only a 
clarification of current requirements, allowing the EPA to bypass the 
need to cite a CAA authorization for this change to the existing CAA 
section 112(d)(2) standard or meet the process requirements associated 
with such a change, including providing emission reduction, cost and 
burden estimates in the record and the associated PRA Information 
Collection Request (ICR).
    Several commenters claimed that this clarification would result in 
retroactive impact and also addressed the implication of the proposed 
change on other fugitive emissions standards. One commenter stated that 
the EPA cannot retroactively reinterpret the OEL requirements or define 
the word ``seal'' and added that the EPA should account for the 
thousands of additional monitoring events per year per refinery that 
this new requirement would add to LDAR programs and provide proper cost 
justification under CAA sections 112(d)(6) or 112(f)(2).
    Several commenters also stated that the proposed definition will 
effectively change all equipment leak rules in parts 40 CFR parts 60, 
61 and 63 and the change should not be finalized. One commenter added 
that by claiming this change is only a clarification of current 
requirements, the EPA would set a precedent applicable to all OELs in 
all industries subject to any similar OEL equipment leak requirement.
    Response: We have decided not to finalize the proposed 
clarification of the term ``seal'' for OELs at this time. The fenceline 
monitoring requirements we are finalizing will detect any significant 
leaks from a cap, blind flange, plug or second valve that does not 
properly seal an OEL, as well as significant leaks from numerous other 
types of fugitive emission sources.
    Comment: A few commenters stated that the proposed use of the ERT 
is not appropriate because the costs and burdens imposed are additive 
to the costs of producing and submitting the written report, and there 
is no benefit that justifies the additional cost. One commenter also 
stated that the EPA has not developed or articulated a reasonable 
approach to using information that would be uploaded to the ERT. The 
commenters recommended that the EPA remove this portion of the proposal 
until the ERT is demonstrated to handle all the information from 
refinery performance

[[Page 75223]]

tests (rather than only portions), thereby eliminating the need for 
both written and electronic reporting and until the Agency demonstrates 
that it is using the electronic data to develop improved air quality 
emission factors.
    Other commenters stated that the ERT requirement does not supersede 
or replace any state reporting requirements and thus the regulated 
industry will be subject to dual reporting requirements. These 
commenters disagreed with the preamble claim that eliminating the 
recordkeeping requirements for performance test reports is a burden 
savings, and stated that it may duplicate burdens already borne by the 
regulated community.
    The commenters expressed further concern that duplicative reporting 
requirements will strain the regulated industry to comply with 
deadlines established by rule for report submittals. One commenter 
stated that there is no mechanism for obtaining extensions for special 
circumstances. Under proposed 40 CFR 63.655(h)(9)(i), all reports are 
due in 60 days. The commenter claimed that by not referencing reporting 
requirements to the General Provisions in 40 CFR 63.10(d)(2), there is 
no allowance for obtaining additional time due to unforeseen 
circumstances or due to the difficulties involved with completing 
particularly complex reports.
    One commenter stated that the primary performance test method 
(Method 18) required for determining compliance is not currently 
included in the list of methods supported by the ERT. The commenter 
stated that the regulated community's experience with Method 18 is that 
it is a very broad methodology and can be exceptionally complex to 
execute and to report. The commenter stated that the EPA is aware that 
Method 18 reporting is complex, that it may be difficult to incorporate 
into the ERT, and that no time schedule has been defined for 
development or implementation for this method.
    The commenter also stated that without formal notice of changes to 
the ERT, the regulated community is at risk of non-compliance. The only 
way for the regulated community to know that changes have occurred in 
the ERT is to monitor the Web site directly because the EPA does not 
formally announce changes to the ERT in the Federal Register. As such, 
it would be possible for a regulated entity to be unaware of changes 
made such as the incorporation of Method 18. The commenter expressed 
concern that the proposal language is an open-ended commitment subject 
to change without notice. The commenter stated that the EPA should 
clearly indicate when facilities would be required to use the ERT when 
new test methods are included in the ERT.
    Response: We disagree that use of the ERT for completing stack test 
reports is an added cost and burden. While the requirement to report 
the results of stack tests with the ERT does not supersede state 
reporting requirements, we are aware of several states that already 
require the use of the ERT, and we are aware of more states that are 
considering requiring its use. We note that where states will not 
accept an electronic ERT submittal, the ERT provides an option to print 
the report, and the printed report can be mailed to the state agency. 
We have no reason to believe that the time savings in the ability to 
reuse data elements within reports does not, at a minimum, offset the 
cost incurred by printing out and mailing a copy of the report and the 
commenters have provided no support for their cost claims.
    Furthermore, based on the analysis performed for the Electronic 
Reporting and Recordkeeping Requirements for the New Source Performance 
Standards Rulemaking (ERRRNSPS) (80 FR 15100), electronic reporting 
results in an overall cost savings to industry when annualized over a 
20-year period. The cost savings is achieved through means such as 
standardization of data, embedded quality assurance checks, automatic 
calculation routines and reduced data entry through the ability to 
reuse data in files instead of starting from scratch with each test. As 
outlined in the ERRRNSPS, there are many benefits to electronic 
reporting. These benefits span all users of the data--the EPA, state 
and local regulators, the regulated entities and the public. We note 
that in the preamble to this proposed rule we provided a number of 
reasons why the use of the ERT will provide benefit going forward and 
that most of the benefits we outlined were longer-term benefits (e.g., 
reducing burden of future information collection requests). 
Additionally, we note that in 2011, in response to Executive Order 
13563, the EPA developed a plan \13\ to periodically review its 
regulations to determine if they should be modified, streamlined, 
expanded or repealed in an effort to make regulations more effective 
and less burdensome. The plan includes replacing outdated paper 
reporting with electronic reporting. In keeping with this plan and the 
White House's Digital Government Strategy, \14\ in 2013 the EPA issued 
an agency-wide policy specifying that new regulations will require 
reports to be electronic to the maximum extent possible. By requiring 
electronic submission of stack test reports in this rule, we are taking 
steps to implement this policy. We also disagree that we have not 
developed or articulated a reasonable approach to using information 
that would be uploaded to the ERT. To the contrary, we have discussed 
at length our plans for the use of stack test data collected via the 
ERT. In 2009, we published an advanced notice of proposed rulemaking 
(74 FR 52723) for the Emissions Factors Program Improvements. In that 
notice, we first outlined our intended approach for revising our 
emissions factors development procedures. This approach included using 
stack test data collected with the ERT. We reiterated this position in 
our ``Recommended Procedures for the Development of Emissions Factors 
and Use of the WebFIRE Database'' (http://www.epa.gov/ttn/chief/efpac/procedures/procedures81213.pdf), which was subject to public notice and 
comment before being finalized in 2013. Finally, we discussed uses of 
these data in the preamble to the proposed rule and at length in the 
preamble to the ERRRNSPS.
---------------------------------------------------------------------------

    \13\ EPA's ``Final Plan for Periodic Retrospective Reviews,'' 
August 2011. Available at: http://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf.
    \14\ Digital Government: Building a 21st Century Platform to 
Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf.
---------------------------------------------------------------------------

    We think that it is a circular argument to say that the agency 
should eliminate the use of the ERT until it demonstrates that it is 
using the electronic data. It would be impossible for the agency to use 
data that it does not have. We can only use electronic data once we 
have electronic data. We do note that we are nearing completion of 
programming the WebFIRE database with our new emissions factor 
development procedures and anticipate running the routines on existing 
data sets in the near future.
    We continue to improve and upgrade the ERT on an ongoing basis. The 
current version of the ERT supports 41 methods, including EPA Methods 
1-4, 5, 5B, 5F, 25A 26, and 26A. We note that the ERT does not 
currently support EPA Method 18, and for performance tests using Method 
18, the source will still have to produce a paper report. However, we 
are aware of the need to add Method 18 to the ERT, and we are currently 
looking at developing this capability. As noted in the ERRRNSPS, when 
new methods are added to the

[[Page 75224]]

ERT, we will not only post them to the Web site; we will also send out 
a listserv notice to the Clearinghouse for Inventories and Emissions 
Factors (CHIEF) listserv. Information on joining the CHIEF listserv can 
be found at http://www.epa.gov/ttn/chief/listserv.html#chief. We are 
requiring the use of the ERT if the method is supported by the ERT, as 
listed on the ERT Web site (http://www.epa.gov/ttn/chief/ert/ert_info.html) at the time of the test. We do not agree that it is 
overly burdensome to check a Web site for updates prior to conducting a 
performance test.
    We did revise the MACT 1 and 2 tables referencing reporting 
requirements to the general provisions (Table 6 for Refinery MACT 1 and 
Table 44 for Refinery MACT 2) to provide flexibility in the 60-day 
reporting timeline to accommodate unforeseen circumstances or 
difficulties involved with completing particularly complex reports.
4. What is the rationale for our final approach and final decisions for 
the other amendments for Refinery MACT 1 and 2?
    We are not finalizing the definition of seal, as proposed. The 
fenceline monitoring work practice standard will detect any significant 
leaks from a cap, blind flange, plug or second valve that does not 
properly seal an OEL, as well as significant leaks from numerous other 
types of fugitive emission sources.
    We are finalizing requirements for electronic reporting, as 
proposed, with a minor clarification. Specifically, we are revising 
Tables 6 in subpart CC and 44 in subpart UUU, which cross-reference the 
applicable provisions in the General Provisions to provide flexibility 
in the ERT 60-day reporting timeline. Refiners can seek approval from 
the EPA or a delegated state additional time for submittal of data due 
to unforeseen circumstances or due to the difficulties involved with 
completing particularly complex reports.

F. Technical Amendments to Refinery NSPS Subparts J and Ja

1. What amendments did we propose for Refinery NSPS Subparts J and Ja?
    We proposed a number of amendments to Refinery NSPS subparts J and 
Ja to address reconsideration issues and minor technical 
clarifications. First, we proposed revisions to 40 CFR 60.100a(b) to 
include a provision that sources subject to Refinery NSPS subpart J 
could elect to comply instead with the provisions of Refinery NSPS 
subpart Ja.
    Second, we proposed a series of amendments to the requirements for 
SRP in 40 CFR 60.102a, to clarify the applicable emission limits for 
different types of SRP based on whether oxygen enrichment is used. The 
amendments proposed also clarified that emissions averaging across a 
group of emission points within a given SRP is allowed for each of the 
different types of SRP, and that emissions averaging is specific to the 
SO2 or reduced sulfur standards (and not to the 10 ppmv 
hydrogen sulfide (H2S) limit). We also proposed a series of 
corresponding amendments in 40 CFR 60.106a to clarify the monitoring 
requirements, particularly when oxygen enrichment or emissions 
averaging is used. We also proposed clarifications in 40 CFR 60.106a to 
consistently use the term ``reduced sulfur compounds'' when referring 
to the emission limits and monitoring devices needed to comply with the 
reduced sulfur compound emission limits for sulfur recovery plants with 
reduction control systems not followed by incineration.
    Third, we proposed amendments to 40 CFR 60.102a(g)(1) to clarify 
that CO boilers, while part of the FCCU affected facility, can also be 
FGCD.
    Fourth, we proposed several revisions to 40 CFR 60.104a to clarify 
the performance testing requirements. We proposed revision to 40 CFR 
60.104a(a) to clarify that an initial compliance demonstration is 
needed for the H2S concentration limit in 40 CFR 60.103a(h). 
We proposed revisions to the annual PM testing requirement in 40 CFR 
60.104a(b) to clarify that annually means once per calendar year, with 
an interval of at least 8 months but no more than 16 months between 
annual tests. We also proposed to amend 40 CFR 60.104a(f) to clarify 
that the provisions of that paragraph are specific to owners or 
operators of an FCCU or FCU that use a cyclone to comply with the PM 
emissions limit in 40 CFR 60.102a(b)(1) and not to facilities electing 
to comply with the PM emissions limit using a PM CEMS. We also proposed 
to amend 40 CFR 60.104a(j) to delete the requirements to measure flow 
for the H2S concentration limit for fuel gas.
    Fifth, we proposed several amendments to clarify the requirements 
for control device operating parameters in 40 CFR 60.105a. 
Specifically, we proposed amendments to 40 CFR 60.105a(b)(1)(ii)(A) to 
require corrective action be completed to repair faulty (leaking or 
plugged) air or water lines within 12 hours of identification of an 
abnormal pressure reading during the daily checks. We also proposed 
revisions to 40 CFR 60.105a(i) to specify that periods when abnormal 
pressure readings for a jet ejector-type wet scrubber (or other type of 
wet scrubber equipped with atomizing spray nozzles) are not corrected 
within 12 hours of identification and periods when a bag leak detection 
system alarm (for a fabric filter) is not alleviated within the time 
period specified in the rule are considered to be periods of excess 
emissions.
    We also proposed amendments to 40 CFR 60.105(b)(1)(iv) and 
60.107a(b)(1)(iv) to provide flexibility in span range to accommodate 
different manufacturers of the length-of-stain tubes. We also proposed 
to delete the last sentence in 40 CFR 60.105(b)(3)(iii).
    Finally, we proposed clarification to the performance test 
requirements for the H2S concentration limit for affected 
flares in 40 CFR 60.107a(e)(1)(ii) and (e)(2)(ii) to remove the 
distinction between flares with or without routine flow.
2. How did the amendments to Refinery NSPS Subparts J and Ja change 
since proposal?
    We are making very few changes to the amendments proposed for 
Refinery NSPS subparts J and Ja. In response to comments, we are 
revising the NSPS requirements to replace the ``measurement 
sensitivity'' requirements with accuracy requirements consistent with 
those used in Refinery MACT 1 and 2. Specifically, we are revising 40 
CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to require use of a flow sensor 
meeting an accuracy requirement of 5-percent over the 
normal range of flow measured or 10-cubic-feet-per-minute, whichever is 
greater. We are also revising the flare accuracy requirements in 40 CFR 
60.107a(f)(1)(ii) to require use of a flow sensor meeting an accuracy 
requirement of 20-percent of the flow rate at velocities 
ranging from 0.1 to 1 feet per second and an accuracy of 5-
percent of the flow rate for velocities greater than 1-feet-per-second.
    Finally, we are revising 40 CFR 60.101a(b) to correct an 
inadvertent error where the phrase ``and delayed coking units'' was not 
included in the proposed sentence revision.
3. What key comments did we receive on the amendments to Refinery NSPS 
Subparts J and Ja and what are our responses?
    Comment: Two commenters noted concern with the term ``measurement 
sensitivity'' in proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) 
for sulfur recovery unit monitoring alternatives and in existing 
regulations 40 CFR 60.107a(f)(1)(ii) for flares because ``sensitivity'' 
is not a term

[[Page 75225]]

found on typical monitoring system data sheets. Typical flow meter 
characteristics include terms such as accuracy and resolution and the 
commenters requested that the EPA revise the terminology to match the 
wording found in 40 CFR part 63, subpart CC, Table 13 for flow meters 
(i.e., accuracy requirements). Additionally, several commenters 
suggested that the EPA flow monitor accuracy specifications are 
inconsistent with those in the SCAQMD Flare Rule and many refinery 
consent decrees. The commenters recommended revising both the flare 
flow meter sensitivity specification and accuracy specification in 
Refinery MACT 1 Table 13 and in Refinery NSPS subpart Ja to be 
consistent with the accuracy specification from the Shell Deer Park 
Consent Decree, Appendix 1.10, which specifies the required flare flow 
meter accuracy as ``20% of reading over the velocity range 
of 0.1-1 feet per second (ft/s) and 5% of reading over the 
velocity range of 1-250 ft/s.''
    Response: We proposed the term ``measurement sensitivity'' in 
proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) to be internally 
consistent within Refinery NSPS subpart Ja [i.e., consistent with the 
existing language in Sec.  60.107a(f)(1)(ii)]. However, we agree with 
the commenters that this term may be unclear. This term is not defined 
in Refinery NSPS subpart Ja and it is not commonly used in the flow 
monitoring system's technical specification sheets. Therefore, to be 
consistent with the terminology used by instrument vendors and used in 
Refinery MACT 1 and 2, we are revising these sections to replace the 
term ``measurement sensitivity'' with ``accuracy.'' We are also 
revising the flow rate accuracy provisions specific for flares to 
provide an accuracy requirement of 20-percent over the 
velocity range of 0.1-1 ft/s and 5% for velocities 
exceeding 1 ft/s in 40 CFR 60.107a(f)(1)(ii) and in Table 13 of subpart 
CC. We are providing this provision specifically for flares because 
they commonly operate at high turndown ratios. For other flow 
measurements, we are retaining the 10-cubic-foot-per-minute accuracy 
requirement. We are also clarifying that the 5-percent 
accuracy requirement for the SRU alternatives apply to the ``the normal 
range of flow measured'' consistent with the requirements in Refinery 
MACT 1 and 2.
    Comment: One commenter stated that in the proposed revisions to 40 
CFR 60.100a, (79 FR 36956), the EPA proposes to remove the phrase ``and 
delayed coker units'' from 40 CFR 60.100a(b). However, we state the 
compliance date for both flares and delayed coker units separately in 
the same paragraph. The commenter believes the EPA should explain the 
reason for and implications of the removal of this phrase.
    Response: The removal of the phrase ``and delayed coking units'' 
from the first sentence in 40 CFR 60.100a(b) was an inadvertent error. 
The only revision that we intended to make in 40 CFR 60.100a was to 
allow owners or operators subject to subpart J to elect to comply with 
the requirements in subpart Ja. In the final amendments, we have 
included the phrase ``and delayed coking units'' in the first sentence 
in 40 CFR 60.100a(b).
4. What is the rationale for our final approach and final decisions for 
the amendments to Refinery NSPS Subparts J and Ja?
    We are finalizing amendments for Refinery NSPS subparts J and Ja as 
proposed with minor revisions. In response to comments, we are revising 
the ``measurement sensitivity'' requirements to be an ``accuracy'' 
requirement. This change will make the requirements more clear and 
consistent between the flow meter requirements in the NSPS and the MACT 
standards since the same flow meter will be subject to each of these 
requirements. We are also providing a dual accuracy requirement for 
flare flow meters. This accuracy requirement is necessary because 
flares, which can have large diameters to accommodate high flows, are 
commonly operated at low flow rates. Together, this makes it 
technically infeasible for many flares to meet the lower flow 10 cfm 
accuracy requirement. Therefore, we are providing specific accuracy 
requirements for flares of 20-percent over the velocity 
range of 0.1-1 ft/s and 5-percent for velocities exceeding 
1 ft/s, consistent with recent consent decrees and equipment vendor 
specifications.
    Finally, we are revising the introductory phrase in the first 
sentence in 40 CFR 60.101a(b) to read ``Except for flares and delayed 
coking units . . .'' to correct an inadvertent error. We intended to 
revise this sentence only to include the proposed provision to allow 
sources subject to Refinery NSPS subpart J to comply with Refinery NSPS 
subpart Ja. The redline text posted on our Web site showed no revisions 
to this introductory phrase, but the amendatory text did not include 
the words ``and delayed coking units'' in this phrase. This was an 
inadvertent error, which we are correcting in the final rule.

V. Summary of Cost, Environmental and Economic Impacts and Additional 
Analyses Conducted

A. What are the affected facilities, the air quality impacts and cost 
impacts?

    The sources affected by significant amendments to the petroleum 
refinery standards include flares, storage vessels, pressure relief 
devices, fugitive emissions and DCU. The amendments for other sources 
subject to one or more of the petroleum refinery standards are expected 
to have minimal air quality and cost impacts.
    The total capital investment cost of the final amendments and 
standards is estimated at $283 million, $112 million from the final 
amendments for storage vessels, DCU and fenceline monitoring and $171 
million from standards to ensure compliance. We estimate annualized 
costs of the final amendments for storage vessels, DCU and fenceline 
monitoring to be approximately $13.0 million, which includes an 
estimated $11.0 million for recovery of lost product and the annualized 
cost of capital. We also estimated annualized costs of the final 
standards to ensure compliance to be approximately $50.2 million. The 
final amendments for storage vessels, DCU and fenceline monitoring 
would achieve a nationwide HAP emission reduction of 1,323 tpy, with a 
concurrent reduction in VOC emissions of 16,660 tpy and a reduction in 
methane emissions of 8,700 metric tonnes per year. Table 2 of this 
preamble summarizes the cost and emission reduction impacts of the 
final amendments, and Table 3 of this preamble summarizes the costs of 
the final standards to ensure compliance.

[[Page 75226]]



                                                 Table 2--Nationwide Impacts of Final Amendments (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                 Total
                                               annualized    Product       Total       Methane
                                    Total         cost       recovery    annualized    emission       VOC           Cost          HAP           Cost
        Affected source            capital      without       credit       costs      reductions    emission   effectiveness    emission   effectiveness
                                  investment     credit    (million $/  (million $/    (metric     reductions   ($/ton VOC)    reductions   ($/ton HAP)
                                 (million $)  (million $/      yr)          yr)          tpy)        (tpy)                       (tpy)
                                                  yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................         18.5         3.13       (8.16)       (5.03)  ...........       14,600         (345)           910       (5,530)
Delayed Coking Units...........           81         14.5       (2.80)         11.7        8,700        2,060         5,680           413        28,330
Fugitive Emissions (Fenceline           12.5         6.36  ...........         6.36  ...........  ...........  .............  ...........  .............
 Monitoring)...................
                                ------------------------------------------------------------------------------------------------------------------------
    Total......................          112         24.0       (11.0)         13.0        8,700       16,660           780         1,323         9,830
--------------------------------------------------------------------------------------------------------------------------------------------------------


                   Table 3--Nationwide Costs of Final Amendments To Ensure Compliance (2010$)
----------------------------------------------------------------------------------------------------------------
                                                                       Total
                                                   Total capital    annualized        Product          Total
                 Affected Source                    investment     cost without      recovery       annualized
                                                    (million $)       credit          credit      costs (million
                                                                  (million $/yr)  (million $/yr)       $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Device Monitoring........................            11.1             3.3  ..............             3.3
Flare Monitoring................................             160            46.5  ..............            46.5
FCCU Testing....................................  ..............             0.4  ..............             0.4
                                                 ---------------------------------------------------------------
    Total.......................................             171            50.2  ..............            50.2
----------------------------------------------------------------------------------------------------------------

    The impacts shown in Table 2 do not include costs, product recovery 
credits, or emissions reductions associated with any root cause 
analysis or corrective action taken in response to the final amendments 
for fenceline monitoring. The impacts shown in Table 3 do not include 
(i) the costs or emissions reductions associated with any root cause 
analysis and corrective action taken in response to the final source 
performance testing at the FCCUs, or (ii) emissions reductions 
associated with corrective action taken in response to pressure relief 
device or (iii) emissions reductions associated with the flare 
operating and monitoring provisions. The operational and monitoring 
requirements for flares at refineries have the potential to reduce 
excess emissions from flares by up to approximately 3,900 tpy of HAP 
and 33,000 tpy of VOC. The operational and monitoring requirements for 
flares also have the potential to reduce methane emissions by 25,800 
metric tonnes per year while increasing emissions of carbon dioxide 
(CO2) and nitrous oxide by 267,000 metric tonnes per year and 2 metric 
tonnes per year, respectively, yielding a net reduction in GHG 
emissions of 377,000 metric tonnes per year of CO2 equivalents 
(CO2e).

B. What are the economic impacts?

    We performed a national economic impact analysis for petroleum 
product producers. All petroleum product refiners will incur annual 
compliance costs of less than 1-percent of their sales. For all firms, 
the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-
sales ratio is 0.87-percent; and the mean cost-to-sales ratio is 0.03-
percent. Therefore, the overall economic impact of this proposed rule 
should be minimal for the refining industry and its consumers.
    In addition, the EPA performed a screening analysis for impacts on 
small businesses by comparing estimated annualized engineering 
compliance costs at the firm-level to firm sales. The screening 
analysis found that the ratio of compliance cost to firm revenue falls 
below 1-percent for the 28 small companies likely to be affected by the 
proposal. For small firms, the minimum cost-to-sales ratio is <0.01-
percent; the maximum cost-to-sales ratio is 0.62-percent; and the mean 
cost-to-sales ratio is 0.07-percent.
    More information and details of this analysis is provided in the 
technical document ``Economic Impact Analysis for Petroleum Refineries 
Proposed Amendments to the National Emissions Standards for Hazardous 
Air Pollutants'', which is available in the docket for this rule 
(Docket ID No. EPA-HQ-OAR-2010-0682).

C. What are the benefits?

    The final rule is anticipated to result in a reduction of 1,323 tpy 
of HAP (based on allowable emissions under the MACT standards) and 
16,660 tpy of VOC, not including potential emission reductions that may 
occur as a result of the operating and monitoring requirements for 
flares and fugitive emission sources via fenceline monitoring. These 
avoided emissions will result in improvements in air quality and 
reduced negative health effects associated with exposure to air 
pollution of these emissions; however, we have not quantified or 
monetized the benefits of reducing these emissions for this rulemaking.

D. Impacts of This Rulemaking on Environmental Justice Populations

    To examine the potential impacts on vulnerable populations 
(minority, low-income and indigenous communities) that might be 
associated with the Petroleum Refinery source categories addressed in 
this final rule, we evaluated the percentages of various social, 
demographic and economic groups in the at-risk populations living near 
the facilities where these sources are located and compared them to 
national averages. Our analysis of the demographics of the population 
with estimated risks greater than 1-in-1 million indicates potential 
disparities in risks between demographic groups including the African 
American, Other and Multiracial, Hispanic, Below the Poverty Level, and 
Over 25 without a High School Diploma when compared to the nationwide 
percentages of those groups. These groups will benefit the most from 
the emission reductions achieved by this final rulemaking, which is 
projected to result in 1 million fewer people exposed to risks greater 
than 1-in-1 million.
    Additionally, these communities will benefit from this rulemaking, 
as this rulemaking for the first time ever requires fenceline 
monitoring, and reporting of fenceline data. The agency during the pre-
proposal period and

[[Page 75227]]

during the comment period received feedback from communities on the 
importance of having fenceline monitoring in their communities and the 
importance of communities having access to this data. The EPA believes 
that vulnerable communities will benefit from this data and the 
requirements that EPA has put in place in this rulemaking to manage 
fugitive emissions.

E. Impacts of This Rulemaking on Children's Health

    Under Executive Order 13045 the EPA must evaluate the effects of 
the planned regulation on children's health and safety. This action's 
health and risk assessments are contained in section IV.A of this 
preamble. We believe we have adequately estimated risk for children, 
and we do not believe that the environmental health risks addressed by 
this action present a disproportionate risk to children. When the EPA 
derives exposure reference concentrations and unit risk estimates (URE) 
for HAP, it also considers the most sensitive populations identified 
(i.e., children) in the available literature, and importantly, these 
are the values used in our risk assessments. With regard to children's 
potentially greater susceptibility to non-cancer toxicants, the 
assessments rely on the EPA (or comparable) hazard identification and 
dose-response values which have been developed to be protective for all 
subgroups of the general population, including children. With respect 
to cancer, the EPA uses the age-dependent adjustment factor approach, 
and applies these factors to carcinogenic pollutants that are known to 
act via mutagenic mode of action. Further details are provided in the 
``Final Residual Risk Assessment for the Petroleum Refining Source 
Sector'', Docket ID No. EPA-HQ-OAR-2010-0682.

VI. Statutory and Executive Order Reviews

A. Executive Orders 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is an economically significant regulatory action that 
was submitted to the Office of Management and Budget (OMB) for review. 
Any changes made in response to OMB recommendations have been 
documented in the docket. The EPA prepared an analysis of the potential 
costs and benefits associated with this action. This analysis, 
``Economic Impact Analysis: Petroleum Refineries--Final Amendments to 
the National Emissions Standards for Hazardous Air Pollutants and New 
Source Performance Standards'' is available in Docket ID Number EPA-HQ-
OAR-2010-0682.

B. Paperwork Reduction Act (PRA)

    The information collection requirements in this rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the Paperwork Reduction Act, 44 U.S.C. 3501 et se. The 
information collection requirements are not enforceable until OMB 
approves them.
    Adequate recordkeeping and reporting are necessary to ensure 
compliance with these standards as required by the CAA. The ICR 
information collected from recordkeeping and reporting requirements is 
also used for prioritizing inspections and is of sufficient quality to 
be used as evidence in court.
    The ICR document prepared by the EPA for the amendments to the 
Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has 
been assigned the EPA ICR number 1692.08. Burden changes associated 
with these amendments would result from new monitoring, recordkeeping 
and reporting requirements. The estimated annual increase in 
recordkeeping and reporting burden hours is 99,722 hours; the frequency 
of response is quarterly and semiannual for reports for all respondents 
that must comply with the rule's reporting requirements; and the 
estimated average number of likely respondents per year is 95 (this is 
the average in the second year). The cost burden to respondents 
resulting from the collection of information includes the total capital 
cost annualized over the equipment's expected useful life (about $18 
million, which includes monitoring equipment for fenceline monitoring, 
pressure relief devices, and flares), a total operation and maintenance 
component (about $21 million per year for fenceline and flare 
monitoring), and a labor cost component (about $8.3 million per year, 
the cost of the additional 99,722 labor hours). Burden is defined at 5 
CFR 1320.3(b).
    The ICR document prepared by the EPA for the amendments to the 
Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has 
been assigned the EPA ICR number 1844.06. Burden changes associated 
with these amendments would result from new testing, recordkeeping and 
reporting requirements being finalized with this action. The estimated 
average burden per response is 25 hours; the frequency of response 
ranges from annually up to every 5 years for respondents that have 
FCCU, and the estimated average number of likely respondents per year 
is 67. The cost burden to respondents resulting from the collection of 
information includes the performance testing costs (approximately 
$778,000 per year over the first 3 years for the initial PM and one-
time HCN performance tests and $235,000 per year starting in the fourth 
year), and a labor cost component (approximately $410,000 per year for 
4,940 additional labor hours). Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is 
approved by OMB, the Agency will publish a technical amendment to 40 
CFR part 9 in the Federal Register to display the OMB control number 
for the approved information collection requirements contained in this 
final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities (SISNOSE) under the 
RFA. The small entities subject to the requirements of this action are 
small businesses, small organizations and small governmental 
jurisdictions. For purposes of assessing the impacts of this rule on 
small entities, a small entity is defined as: (1) A small business in 
the petroleum refining industry having 1,500 or fewer employees (Small 
Business Administration (SBA), 2011); (2) a small governmental 
jurisdiction that is a government of a city, county, town, school 
district or special district with a population of less than 50,000; and 
(3) a small organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field. 
Details of this analysis are presented in the economic impact analysis 
which can be found in the docket for this rule (Docket ID No. EPA-HQ-
OAR-2010-0682).

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. As discussed 
earlier in this preamble, these amendments result in nationwide costs 
of $63.2 million per year for the private sector. Additionally, the 
rule contains no requirements that apply to small

[[Page 75228]]

governments and does not impose obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175. The final amendments impose no requirements on 
tribal governments. Thus, Executive Order 13175 does not apply to this 
action. Consistent with the EPA Policy on Consultation and Coordination 
with Indian Tribes, the EPA consulted with tribal officials during the 
development of the proposed rule and specifically solicited comment on 
the proposed amendments from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because the EPA 
does not believe the environmental health or safety risks addressed by 
this action present a disproportionate risk to children. This action's 
health and risk assessments are contained in section IV.A of this 
preamble.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution or use of energy. The overall economic impact of this 
final rule should be minimal for the refining industry and its 
consumers.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This rulemaking involves technical standards. Therefore, the EPA 
conducted searches for the Petroleum Refinery Sector Risk and 
Technology Review and New Source Performance Standards through the 
Enhanced National Standards Systems Network (NSSN) Database managed by 
the American National Standards Institute (ANSI). We also contacted 
voluntary consensus standards (VCS) organizations and accessed and 
searched their databases. We conducted searches for EPA Methods 18, 22, 
320, 325A, and 325B of 40 CFR parts 60 and 63, appendix A. No 
applicable VCS were identified for EPA Method 22.
    The following voluntary consensus standards were identified as 
acceptable alternatives to the EPA test methods for the purpose of this 
rule.
    The voluntary consensus standard ISO 16017-2:2003(E) ``Air 
quality--Sampling and analysis of volatile organic compounds in ambient 
air, indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography. Part 2: Diffusive sampling'' is an 
acceptable alternative to Method 325A, Sections 1.2, 6.1 and 6.5 and 
Method 325B Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and 
A.2. This voluntary consensus standard gives general guidance for the 
sampling and analysis of volatile organic compounds in air. It is 
applicable to indoor, ambient and workplace air. This standard is 
available at International Organization for Standardization, ISO 
Central Secretariat, Chemin de Blandonnet 8, CP 401, 1214 Vernier, 
Geneva, Switzerland. See https://www.iso.org.
    The voluntary consensus standard BS EN 14662-4:2005 ``Ambient Air 
Quality: Standard Method for the Measurement of Benzene 
Concentrations--Part 4: Diffusive Sampling Followed By Thermal 
Desorption and Gas Chromatography'' is an acceptable alternative to 
Method 325A, Section 1.2 and Method 325B, Sections 1.3, 7.1.3, 7.1.4, 
12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives 
general guidance for the sampling and analysis of benzene in air by 
diffusive sampling, thermal desorption and capillary gas 
chromatography. This standard is available the European Committee for 
Standardization, Avenue Marnix 17--B-1000 Brussels. See https://www.cen.eu.
    The voluntary consensus standard ASTM D6420-99 (2010) ``Test Method 
for Determination of Gaseous Organic Compounds by Direct Interface Gas 
Chromatography/Mass Spectrometry'' is an acceptable alternative to EPA 
Method 18. This voluntary consensus standard employs a direct interface 
gas chromatography/mass spectrometer (GCMS) to identify and quantify a 
list of 36 volatile organic compounds (the compounds are listed in the 
method).
    The voluntary consensus standard ASTM D6196-03 (Reapproved 2009) 
``Standard Practice for Selection of Sorbents, Sampling, and Thermal 
Desorption Analysis Procedures for Volatile Organic Compounds in Air'' 
is an acceptable alternative to Method 325A, Sections 1.2 and 6.1, and 
Method 325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 13.0, A.1.1, and A.2. 
This voluntary consensus standard is intended to assist in the 
selection of sorbents and procedures for the sampling and analysis of 
ambient, indoor, and workplace atmospheres for a variety of common 
volatile organic compounds.
    The voluntary consensus standards ASTM D1945-03 and later revision 
ASTM D1945-14 ``Standard Test Method for Analysis of Natural Gas by Gas 
Chromatography'' are acceptable for natural gas analysis. This 
voluntary consensus standard covers the determination of the chemical 
composition of natural gases and similar gaseous mixtures. This test 
method may be abbreviated for the analysis of lean natural gases 
containing negligible amounts of hexanes and higher hydrocarbons, or 
for the determination of one or more components, as required.
    The voluntary consensus standard ASTM UOP539-12 ``Refinery Gas 
Analysis by GC'' is acceptable for refinery gas analysis. This 
voluntary consensus standard is for determining the composition of 
refinery gas streams or vaporized liquefied petroleum gas using a 
preconfigured, commercially available gas chromatograph.
    The voluntary consensus standard ASTM D6348-03 (Reapproved 2010) 
including Annexes A1 through A8, ``Determination of Gaseous Compounds 
by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy'' 
is an acceptable alternative to EPA Method 320. This voluntary 
consensus standard is a field test method that employs an extractive 
sampling system to direct stationary source effluent to an FTIR 
spectrometer for the identification and quantification of gaseous 
compounds. This field test method provides near real time analysis of 
extracted gas samples from stationary sources.
    The voluntary consensus standard ASTM D6348-12e1 ``Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
(FTIR) Spectroscopy'' is an acceptable alternative to EPA Method 320 
with the following two caveats: (1) The test plan preparation and 
implementation in the Annexes to ASTM D 6348-03 (Reapproved 2010), 
Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03 
(Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%) 
R must be determined for each target analyte (Equation A5.5). In order 
for the test data to be acceptable for a compound, %R must be 70% >= R 
<= 130%. If the %R value does not meet this criterion for a target 
compound, the test data is not acceptable for that compound and the 
test must be repeated

[[Page 75229]]

for that analyte (i.e., the sampling and/or analytical procedure should 
be adjusted before a retest). The %R value for each compound must be 
reported in the test report, and all field measurements must be 
corrected with the calculated %R value for that compound by using the 
following equation:

Reported Result = (Measured Concentration in the Stack x 100)/% R.

    This voluntary consensus standard is a field test method that 
employs an extractive sampling system to direct stationary source 
effluent to an FTIR spectrometer for the identification and 
quantification of gaseous compounds. This field test method provides 
near real time analysis of extracted gas samples from stationary 
sources.
    The EPA solicited comments on VCS and invited the public to 
identify potentially-applicable VCS; however, we did not receive 
comments regarding this aspect of 40 CFR part 60, subparts J and Ja, 
and part 63, subparts CC, UUU, and Y. Under 40 CFR 63.7(f) and 63.8(f), 
a source may apply to the EPA for permission to use alternative test 
methods or alternative monitoring requirements in place of any required 
testing methods, performance specifications, or procedures in this 
final rule.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies and activities on minority populations and low-income 
populations in the U.S. The EPA defines environmental justice as the 
fair treatment and meaningful involvement of all people regardless of 
race, color, national origin or income with respect to the development, 
implementation and enforcement of environmental laws, regulations and 
policies. The EPA has this goal for all communities and persons by 
working to ensure that everyone enjoys the same degree of protection 
from environmental and health hazards and equal access to the decision-
making process to have a healthy environment in which to live, learn 
and work.
    The EPA believes the human health or environmental risk addressed 
by this action will not have potential disproportionately high and 
adverse human health or environmental effects on minority, low-income 
or indigenous populations. As discussed in section V.D. of this 
preamble, the EPA conducted an analysis of the characteristics of the 
population with greater than 1-in-1 million risk living within 50 km of 
the 142 refineries affected by this rulemaking and determined that 
there are more African-Americans, Other and multiracial groups, 
Hispanics, low-income individuals, individuals with less than a high 
school diploma compared to national averages. Therefore, these 
populations are expected to experience the benefits of the risk 
reductions associated with this rule. The results of this evaluation 
are contained in two technical reports, ``Risk and Technology Review--
Analysis of Socio-Economic Factors for Populations Living Near 
Petroleum Refineries'', available in the docket for this action (See 
Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227). Additionally, a 
discussion of the final risk analysis is included in Sections IV.A and 
V.D of this preamble.
    The EPA has determined that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority, low-income or indigenous populations because it 
maintains or increases the level of environmental protection for all 
affected populations without having any disproportionately high and 
adverse human health or environmental effects on any population, 
including any minority, low-income or indigenous populations. Further, 
the EPA believes that implementation of this rule will provide an ample 
margin of safety to protect public health of all demographic groups.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is 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: September 29, 2015.
Gina McCarthy,
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

0
1. The authority citation for part 60 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart J--Standards of Performance for Petroleum Refineries

0
2. Section 60.105 is amended by revising paragraphs (b)(1)(iv) and 
(b)(3)(iii) to read as follows:


Sec.  60.105  Monitoring of emissions and operations.

* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel 
gas stream/system demonstrating that the sulfur content is less than 5 
ppmv. Sampling data must include, at minimum, 2 weeks of daily 
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems, seven grab 
samples must be collected unless other additional information would 
support reduced sampling. The owner or operator shall use detector 
tubes (``length-of-stain tube'' type measurement) following the ``Gas 
Processors Association Standard 2377-86 (incorporated by reference--see 
Sec.  60.17), using tubes with a maximum span between 10 and 40 ppmv 
inclusive when 1<=N<=10, where N = number of pump strokes, to test the 
applicant fuel gas stream for H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application and the owner or operator chooses not to submit new 
information to support an exemption, the owner or operator must begin 
H2S monitoring using daily stain sampling to demonstrate 
compliance using length-of

[[Page 75230]]

stain tubes with a maximum span between 200 and 400 ppmv inclusive when 
1<=N<=5, where N = number of pump strokes. The owner or operator must 
begin monitoring according to the requirements in paragraph (a)(1) or 
(2) of this section as soon as practicable but in no case later than 
180 days after the operation change. During daily stain tube sampling, 
a daily sample exceeding 162 ppmv is an exceedance of the 3-hour 
H2S concentration limit.
* * * * *

Subpart Ja--Standards of Performance for Petroleum Refineries for 
Which Construction, Reconstruction, or Modification Commenced After 
May 14, 2007

0
3. Section 60.100a is amended by revising the first sentence of 
paragraph (b) to read as follows:


Sec.  60.100a  Applicability, designation of affected facility, and 
reconstruction.

* * * * *
    (b) Except for flares and delayed coking units, the provisions of 
this subpart apply only to affected facilities under paragraph (a) of 
this section which either commence construction, modification or 
reconstruction after May 14, 2007, or elect to comply with the 
provisions of this subpart in lieu of complying with the provisions in 
subpart J of this part. * * *
* * * * *

0
4. Section 60.101a is amended by:
0
a. Revising the definition of ``Corrective action''; and
0
b. Adding, in alphabetical order, a definition for ``Sour water''.
    The revision and addition read as follows:


Sec.  60.101a  Definitions.

* * * * *
    Corrective action means the design, operation and maintenance 
changes that one takes consistent with good engineering practice to 
reduce or eliminate the likelihood of the recurrence of the primary 
cause and any other contributing cause(s) of an event identified by a 
root cause analysis as having resulted in a discharge of gases from an 
affected facility in excess of specified thresholds.
* * * * *
    Sour water means water that contains sulfur compounds (usually 
H2S) at concentrations of 10 parts per million by weight or 
more.
* * * * *

0
5. Section 60.102a is amended by revising paragraphs (b)(1)(i) and 
(iii), (f), and (g)(1) introductory text to read as follows:


Sec.  60.102a  Emissions limitations.

* * * * *
    (b) * * *
    (1) * * *
    (i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke 
burn-off or, if a PM continuous emission monitoring system (CEMS) is 
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 
percent excess air for each modified or reconstructed FCCU.
* * * * *
    (iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is 
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 
percent excess air for each affected FCU.
* * * * *
    (f) Except as provided in paragraph (f)(3) of this section, each 
owner or operator of an affected sulfur recovery plant shall comply 
with the applicable emission limits in paragraph (f)(1) or (2) of this 
section.
    (1) For a sulfur recovery plant with a design production capacity 
greater than 20 long tons per day (LTD), the owner or operator shall 
comply with the applicable emission limit in paragraph (f)(1)(i) or 
(ii) of this section. If the sulfur recovery plant consists of multiple 
process trains or release points, the owner or operator shall comply 
with the applicable emission limit for each process train or release 
point individually or comply with the applicable emission limit in 
paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group 
of release points from the sulfur recovery plant provided that flow is 
monitored as specified in Sec.  60.106a(a)(7); if flow is not monitored 
as specified in Sec.  60.106a(a)(7), the owner or operator shall comply 
with the applicable emission limit in paragraph (f)(1)(i) or (ii) for 
each process train or release point individually. For a sulfur recovery 
plant with a design production capacity greater than 20 long LTD and a 
reduction control system not followed by incineration, the owner or 
operator shall also comply with the H2S emission limit in 
paragraph (f)(1)(iii) of this section for each individual release 
point.
    (i) For a sulfur recovery plant with an oxidation control system or 
a reduction control system followed by incineration, the owner or 
operator shall not discharge or cause the discharge of any gases into 
the atmosphere (SO2) in excess of the emission limit 
calculated using Equation 1 of this section. For Claus units that use 
only ambient air in the Claus burner or that elect not to monitor 
O2 concentration of the air/oxygen mixture used in the Claus 
burner or for non-Claus sulfur recovery plants, this SO2 
emissions limit is 250 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.000


Where:

ELS = Emission limit for large sulfur recovery plant, 
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion: 
k1 = 1 for converting to the SO2 limit for a 
sulfur recovery plant with an oxidation control system or a 
reduction control system followed by incineration and k1 
= 1.2 for converting to the reduced sulfur compounds limit for a 
sulfur recovery plant with a reduction control system not followed 
by incineration; and
%O2 = O2 concentration of the air/oxygen 
mixture supplied to the Claus burner, percent by volume (dry basis). 
If only ambient air is used for the Claus burner or if the owner or 
operator elects not to monitor O2 concentration of the 
air/oxygen mixture used in the Claus burner or for non-Claus sulfur 
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system 
not followed by incineration, the owner or operator shall not discharge 
or cause the discharge of any gases into the atmosphere containing 
reduced sulfur compounds in excess of the emission limit calculated 
using Equation 1 of this section. For Claus units that use only ambient 
air in the Claus burner or for non-Claus sulfur recovery plants, this 
reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv 
SO2 (dry basis) at 0-percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system 
not followed by incineration, the owner or operator shall not discharge 
or cause the discharge of any gases into the atmosphere containing 
hydrogen sulfide (H2S) in excess of 10 ppmv calculated as 
ppmv SO2 (dry basis) at zero percent excess air.

[[Page 75231]]

    (2) For a sulfur recovery plant with a design production capacity 
of 20 LTD or less, the owner or operator shall comply with the 
applicable emission limit in paragraph (f)(2)(i) or (ii) of this 
section. If the sulfur recovery plant consists of multiple process 
trains or release points, the owner or operator may comply with the 
applicable emission limit for each process train or release point 
individually or comply with the applicable emission limit in paragraph 
(f)(2)(i) or (ii) as a flow rate weighted average for a group of 
release points from the sulfur recovery plant provided that flow is 
monitored as specified in Sec.  60.106a(a)(7); if flow is not monitored 
as specified in Sec.  60.106a(a)(7), the owner or operator shall comply 
with the applicable emission limit in paragraph (f)(2)(i) or (ii) for 
each process train or release point individually. For a sulfur recovery 
plant with a design production capacity of 20 LTD or less and a 
reduction control system not followed by incineration, the owner or 
operator shall also comply with the H2S emission limit in 
paragraph (f)(2)(iii) of this section for each individual release 
point.
    (i) For a sulfur recovery plant with an oxidation control system or 
a reduction control system followed by incineration, the owner or 
operator shall not discharge or cause the discharge of any gases into 
the atmosphere containing SO2 in excess of the emission 
limit calculated using Equation 2 of this section. For Claus units that 
use only ambient air in the Claus burner or that elect not to monitor 
O2 concentration of the air/oxygen mixture used in the Claus 
burner or for non-Claus sulfur recovery plants, this SO2 
emission limit is 2,500 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.001

Where:

ESS = Emission limit for small sulfur recovery plant, 
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion: 
k1 = 1 for converting to the SO2 limit for a 
sulfur recovery plant with an oxidation control system or a 
reduction control system followed by incineration and k1 
= 1.2 for converting to the reduced sulfur compounds limit for a 
sulfur recovery plant with a reduction control system not followed 
by incineration; and
%O2 = O2 concentration of the air/oxygen 
mixture supplied to the Claus burner, percent by volume (dry basis). 
If only ambient air is used in the Claus burner or if the owner or 
operator elects not to monitor O2 concentration of the 
air/oxygen mixture used in the Claus burner or for non-Claus sulfur 
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system 
not followed by incineration, the owner or operator shall not discharge 
or cause the discharge of any gases into the atmosphere containing 
reduced sulfur compounds in excess of the emission limit calculated 
using Equation 2 of this section. For Claus units that use only ambient 
air in the Claus burner or for non-Claus sulfur recovery plants, this 
reduced sulfur compounds emission limit is 3,000 ppmv calculated as 
ppmv SO2 (dry basis) at zero percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system 
not followed by incineration, the owner or operator shall not discharge 
or cause the discharge of any gases into the atmosphere containing 
H2S in excess of 100 ppmv calculated as ppmv SO2 
(dry basis) at zero percent excess air.
    (3) The emission limits in paragraphs (f)(1) and (2) of this 
section shall not apply during periods of maintenance of the sulfur 
pit, which shall not exceed 240 hours per year. The owner or operator 
must document the time periods during which the sulfur pit vents were 
not controlled and measures taken to minimize emissions during these 
periods. Examples of these measures include not adding fresh sulfur or 
shutting off vent fans.
    (g) * * *
    (1) Except as provided in (g)(1)(iii) of this section, for each 
fuel gas combustion device, the owner or operator shall comply with 
either the emission limit in paragraph (g)(1)(i) of this section or the 
fuel gas concentration limit in paragraph (g)(1)(ii) of this section. 
For CO boilers or furnaces that are part of a fluid catalytic cracking 
unit or fluid coking unit affected facility, the owner or operator 
shall comply with the fuel gas concentration limit in paragraph 
(g)(1)(ii) for all fuel gas streams combusted in these units.
* * * * *

0
6. Section 60.104a is amended by:
0
a. Revising the first sentence of paragraph (a) and paragraphs (b), (f) 
introductory text, and (h) introductory text;
0
b. Adding paragraph (h)(6); and
0
c. Removing and reserving paragraphs (j)(1) through (3).
    The revisions and additions read as follows:


Sec.  60.104a  Performance tests.

    (a) The owner or operator shall conduct a performance test for each 
FCCU, FCU, sulfur recovery plant and fuel gas combustion device to 
demonstrate initial compliance with each applicable emissions limit in 
Sec.  60.102a and conduct a performance test for each flare to 
demonstrate initial compliance with the H2S concentration 
requirement in Sec.  60.103a(h) according to the requirements of Sec.  
60.8. * * *
    (b) The owner or operator of a FCCU or FCU that elects to monitor 
control device operating parameters according to the requirements in 
Sec.  60.105a(b), to use bag leak detectors according to the 
requirements in Sec.  60.105a(c), or to use COMS according to the 
requirements in Sec.  60.105a(e) shall conduct a PM performance test at 
least annually (i.e., once per calendar year, with an interval of at 
least 8 months but no more than 16 months between annual tests) and 
furnish the Administrator a written report of the results of each test.
* * * * *
    (f) The owner or operator of an FCCU or FCU that uses cyclones to 
comply with the PM per coke burn-off emissions limit in Sec.  
60.102a(b)(1) shall establish a site-specific opacity operating limit 
according to the procedures in paragraphs (f)(1) through (3) of this 
section.
* * * * *
    (h) The owner or operator shall determine compliance with the 
SO2 emissions limits for sulfur recovery plants in Sec.  
60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and 
H2S emissions limits for sulfur recovery plants in Sec.  
60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the 
following methods and procedures:
* * * * *
    (6) If oxygen or oxygen-enriched air is used in the Claus burner 
and either Equation 1 or 2 of this subpart is used to determine the 
applicable emissions limit, determine the average O2 
concentration of the air/oxygen mixture supplied to the Claus burner, 
in percent by volume (dry basis), for the performance test using all 
hourly average O2 concentrations determined

[[Page 75232]]

during the test runs using the procedures in Sec.  60.106a(a)(5) or 
(6).
* * * * *

0
7. Section 60.105a is amended by:
0
a. Revising paragraphs (b)(1)(i), (b)(1)(ii)(A), (b)(2), (h)(1), 
(h)(3)(i), and (i)(1);
0
b. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
c. Adding paragraph (i)(2); and
0
d. Revising newly redesignated paragraph (i)(7).
    The revisions and additions read as follows:


Sec.  60.105a  Monitoring of emissions and operations for fluid 
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
    (b) * * *
    (1) * * *
    (i) For units controlled using an electrostatic precipitator, the 
owner or operator shall use CPMS to measure and record the hourly 
average total power input and secondary current to the entire system.
    (ii) * * *
    (A) As an alternative to pressure drop, the owner or operator of a 
jet ejector type wet scrubber or other type of wet scrubber equipped 
with atomizing spray nozzles must conduct a daily check of the air or 
water pressure to the spray nozzles and record the results of each 
check. Faulty (e.g., leaking or plugged) air or water lines must be 
repaired within 12 hours of identification of an abnormal pressure 
reading.
* * * * *
    (2) For use in determining the coke burn-off rate for an FCCU or 
FCU, the owner or operator shall install, operate, calibrate, and 
maintain an instrument for continuously monitoring the concentrations 
of CO2, O2 (dry basis), and if needed, CO in the 
exhaust gases prior to any control or energy recovery system that burns 
auxiliary fuels. A CO monitor is not required for determining coke 
burn-off rate when no auxiliary fuel is burned and a continuous CO 
monitor is not required in accordance with paragraph (h)(3) of this 
section.
    (i) The owner or operator shall install, operate, and maintain each 
CO2 and O2 monitor according to Performance 
Specification 3 of appendix B to this part.
    (ii) The owner or operator shall conduct performance evaluations of 
each CO2 and O2 monitor according to the 
requirements in Sec.  60.13(c) and Performance Specification 3 of 
appendix B to this part. The owner or operator shall use Method 3 of 
appendix A-3 to this part for conducting the relative accuracy 
evaluations.
    (iii) If a CO monitor is required, the owner or operator shall 
install, operate, and maintain each CO monitor according to Performance 
Specification 4 or 4A of appendix B to this part. If this CO monitor 
also serves to demonstrate compliance with the CO emissions limit in 
Sec.  60.102a(b)(4), the span value for this instrument is 1,000 ppm; 
otherwise, the span value for this instrument should be set at 
approximately 2 times the typical CO concentration expected in the FCCU 
of FCU flue gas prior to any emission control or energy recovery system 
that burns auxiliary fuels.
    (iv) If a CO monitor is required, the owner or operator shall 
conduct performance evaluations of each CO monitor according to the 
requirements in Sec.  60.13(c) and Performance Specification 4 of 
appendix B to this part. The owner or operator shall use Method 10, 
10A, or 10B of appendix A-3 to this part for conducting the relative 
accuracy evaluations.
    (v) The owner or operator shall comply with the quality assurance 
requirements of procedure 1 of appendix F to this part, including 
quarterly accuracy determinations for CO2 and CO monitors, 
annual accuracy determinations for O2 monitors, and daily 
calibration drift tests.
* * * * *
    (h) * * *
    (1) The owner or operator shall install, operate, and maintain each 
CO monitor according to Performance Specification 4 or 4A of appendix B 
to this part. The span value for this instrument is 1,000 ppmv CO.
* * * * *
    (3) * * *
    (i) The demonstration shall consist of continuously monitoring CO 
emissions for 30 days using an instrument that meets the requirements 
of Performance Specification 4 or 4A of appendix B to this part. The 
span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative 
accuracy limit shall be 10 percent of the average CO emissions or 5 
ppmv CO, whichever is greater. For instruments that are identical to 
Method 10 of appendix A-4 to this part and employ the sample 
conditioning system of Method 10A of appendix A-4 to this part, the 
alternative relative accuracy test procedure in section 10.1 of 
Performance Specification 2 of appendix B to this part may be used in 
place of the relative accuracy test.
* * * * *
    (i) * * *
    (1) If a CPMS is used according to paragraph (b)(1) of this 
section, all 3-hour periods during which the average PM control device 
operating characteristics, as measured by the continuous monitoring 
systems under paragraph (b)(1), fall below the levels established 
during the performance test. If the alternative to pressure drop CPMS 
is used for the owner or operator of a jet ejector type wet scrubber or 
other type of wet scrubber equipped with atomizing spray nozzles, each 
day in which abnormal pressure readings are not corrected within 12 
hours of identification.
    (2) If a bag leak detection system is used according to paragraph 
(c) of this section, each day in which the cause of an alarm is not 
alleviated within the time period specified in paragraph (c)(3) of this 
section.
* * * * *
    (7) All 1-hour periods during which the average CO concentration as 
measured by the CO continuous monitoring system under paragraph (h) of 
this section exceeds 500 ppmv or, if applicable, all 1-hour periods 
during which the average temperature and O2 concentration as 
measured by the continuous monitoring systems under paragraph (h)(4) of 
this section fall below the operating limits established during the 
performance test.

0
8. Section 60.106a is amended by:
0
a. Revising paragraph (a)(1)(i);
0
b. Adding paragraphs (a)(1)(iv) through (vii);
0
c. Revising paragraphs (a)(2) introductory text, (a)(2)(i) and (ii), 
and the first sentence of paragraph (a)(2)(iii);
0
d. Removing paragraphs (a)(2)(iv) and (v);
0
e. Redesignating paragraphs (a)(2)(vi) through (ix) as (a)(2)(iv) 
through (vii);
0
f. Revising the first sentence of paragraph (a)(3) introductory text 
and paragraph (a)(3)(i);
0
g. Adding paragraphs (a)(4) through (7); and
0
h. Revising paragraphs (b)(2) and (3).
    The revisions and additions read as follows:


Sec.  60.106a  Monitoring of emissions and operations for sulfur 
recovery plants.

    (a) * * *
    (1) * * *
    (i) The span value for the SO2 monitor is two times the 
applicable SO2 emission limit at the highest O2 
concentration in the air/oxygen stream used in the Claus burner, if 
applicable.
* * * * *
    (iv) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
appendix B to this part.
    (v) The span value for the O2 monitor must be selected 
between 10 and 25 percent, inclusive.

[[Page 75233]]

    (vi) The owner or operator shall conduct performance evaluations 
for the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of appendix B to this part. 
The owner or operator shall use Methods 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 (incorporated by reference--see Sec.  60.17) 
is an acceptable alternative to EPA Method 3B of appendix A-2 to this 
part.
    (vii) The owner or operator shall comply with the applicable 
quality assurance procedures of appendix F to this part for each 
monitor, including annual accuracy determinations for each 
O2 monitor, and daily calibration drift determinations.
    (2) For sulfur recovery plants that are subject to the reduced 
sulfur compounds emission limit in Sec.  60.102a(f)(1)(ii) or 
(f)(2)(ii), the owner or operator shall install, operate, calibrate, 
and maintain an instrument for continuously monitoring and recording 
the concentration of reduced sulfur compounds and O2 
emissions into the atmosphere. The reduced sulfur compounds emissions 
shall be calculated as SO2 (dry basis, zero percent excess 
air).
    (i) The span value for the reduced sulfur compounds monitor is two 
times the applicable reduced sulfur compounds emission limit as 
SO2 at the highest O2 concentration in the air/
oxygen stream used in the Claus burner, if applicable.
    (ii) The owner or operator shall install, operate, and maintain 
each reduced sulfur compounds CEMS according to Performance 
Specification 5 of appendix B to this part.
    (iii) The owner or operator shall conduct performance evaluations 
of each reduced sulfur compounds monitor according to the requirements 
in Sec.  60.13(c) and Performance Specification 5 of appendix B to this 
part. * * *
* * * * *
    (3) In place of the reduced sulfur compounds monitor required in 
paragraph (a)(2) of this section, the owner or operator may install, 
calibrate, operate, and maintain an instrument using an air or 
O2 dilution and oxidation system to convert any reduced 
sulfur to SO2 for continuously monitoring and recording the 
concentration (dry basis, 0 percent excess air) of the total resultant 
SO2. * * *
    (i) The span value for this monitor is two times the applicable 
reduced sulfur compounds emission limit as SO2 at the 
highest O2 concentration in the air/oxygen stream used in 
the Claus burner, if applicable.
* * * * *
    (4) For sulfur recovery plants that are subject to the 
H2S emission limit in Sec.  60.102a(f)(1)(iii) or 
(f)(2)(iii), the owner or operator shall install, operate, calibrate, 
and maintain an instrument for continuously monitoring and recording 
the concentration of H2S, and O2 emissions into 
the atmosphere. The H2S emissions shall be calculated as 
SO2 (dry basis, zero percent excess air).
    (i) The span value for this monitor is two times the applicable 
H2S emission limit.
    (ii) The owner or operator shall install, operate, and maintain 
each H2S CEMS according to Performance Specification 7 of 
appendix B to this part.
    (iii) The owner or operator shall conduct performance evaluations 
for each H2S monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 7 of appendix B to this part. 
The owner or operator shall use Methods 11 or 15 of appendix A-5 to 
this part or Method 16 of appendix A-6 to this part for conducting the 
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 15A of appendix A-5 to this part.
    (iv) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
appendix B to this part.
    (v) The span value for the O2 monitor must be selected 
between 10 and 25 percent, inclusive.
    (vi) The owner or operator shall conduct performance evaluations 
for the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of appendix B to this part. 
The owner or operator shall use Methods 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 (incorporated by reference--see Sec.  60.17) 
is an acceptable alternative to EPA Method 3B of appendix A-2 to this 
part.
    (vii) The owner or operator shall comply with the applicable 
quality assurance procedures of appendix F to this part for each 
monitor, including annual accuracy determinations for each 
O2 monitor, and daily calibration drift determinations.
    (5) For sulfur recovery plants that use oxygen or oxygen enriched 
air in the Claus burner and that elects to monitor O2 
concentration of the air/oxygen mixture supplied to the Claus burner, 
the owner or operator shall install, operate, calibrate, and maintain 
an instrument for continuously monitoring and recording the 
O2 concentration of the air/oxygen mixture supplied to the 
Claus burner in order to determine the allowable emissions limit.
    (i) The owner or operator shall install, operate, and maintain each 
O2 monitor according to Performance Specification 3 of 
appendix B to this part.
    (ii) The span value for the O2 monitor shall be 100 
percent.
    (iii) The owner or operator shall conduct performance evaluations 
for the O2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 3 of appendix B to this part. 
The owner or operator shall use Methods 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 (incorporated by reference--see Sec.  60.17) 
is an acceptable alternative to EPA Method 3B of appendix A-2 to this 
part.
    (iv) The owner or operator shall comply with the applicable quality 
assurance procedures of appendix F to this part for each monitor, 
including annual accuracy determinations for each O2 
monitor, and daily calibration drift determinations.
    (v) The owner or operator shall use the hourly average 
O2 concentration from this monitor for use in Equation 1 or 
2 of Sec.  60.102a(f), as applicable, for each hour and determine the 
allowable emission limit as the arithmetic average of 12 contiguous 1-
hour averages (i.e., the rolling 12-hour average).
    (6) As an alternative to the O2 monitor required in 
paragraph (a)(5) of this section, the owner or operator may install, 
calibrate, operate, and maintain a CPMS to measure and record the 
volumetric gas flow rate of ambient air and oxygen-enriched gas 
supplied to the Claus burner and calculate the hourly average 
O2 concentration of the air/oxygen mixture used in the Claus 
burner as specified in paragraphs (a)(6)(i) through (iv) of this 
section in order to determine the allowable emissions limit as 
specified in paragraphs (a)(6)(v) of this section.
    (i) The owner or operator shall install, calibrate, operate and 
maintain each flow monitor according to the manufacturer's procedures 
and specifications and the following requirements.
    (A) Locate the monitor in a position that provides a representative 
measurement of the total gas flow rate.

[[Page 75234]]

    (B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet 
per minute, whichever is greater.
    (C) Use a flow monitor that is maintainable online, is able to 
continuously correct for temperature, pressure and, for ambient air 
flow monitor, moisture content, and is able to record dry flow in 
standard conditions (as defined in Sec.  60.2) over one-minute 
averages.
    (D) At least quarterly, perform a visual inspection of all 
components of the monitor for physical and operational integrity and 
all electrical connections for oxidation and galvanic corrosion if the 
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the 
manufacturer's procedures and specifications biennially (every two 
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall use 20.9 percent as the oxygen 
content of the ambient air.
    (iii) The owner or operator shall use product specifications (e.g., 
as reported in material safety data sheets) for percent oxygen for 
purchased oxygen. For oxygen produced onsite, the percent oxygen shall 
be determined by periodic measurements or process knowledge.
    (iv) The owner or operator shall calculate the hourly average 
O2 concentration of the air/oxygen mixture used in the Claus 
burner using Equation 10 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.002

Where:

%O2 = O2 concentration of the air/oxygen 
mixture used in the Claus burner, percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry basis;
Qair = Volumetric flow rate of ambient air used in the 
Claus burner, dscfm;
%O2,oxy = O2 concentration in the enriched 
oxygen stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched oxygen stream 
used in the Claus burner, dscfm.

    (v) The owner or operator shall use the hourly average 
O2 concentration determined using Equation 8 of Sec.  
60.104a(d)(8) for use in Equation 1 or 2 of Sec.  60.102a(f), as 
applicable, for each hour and determine the allowable emission limit as 
the arithmetic average of 12 contiguous 1-hour averages (i.e., the 
rolling 12-hour average).
    (7) Owners or operators of a sulfur recovery plant that elects to 
comply with the SO2 emission limit in Sec.  60.102a(f)(1)(i) 
or (f)(2)(i) or the reduced sulfur compounds emission limit in Sec.  
60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a 
group of release points from the sulfur recovery plant rather than for 
each process train or release point individually shall install, 
calibrate, operate, and maintain a CPMS to measure and record the 
volumetric gas flow rate of each release point within the group of 
release points from the sulfur recovery plant as specified in 
paragraphs (a)(7)(i) through (iv) of this section.
    (i) The owner or operator shall install, calibrate, operate and 
maintain each flow monitor according to the manufacturer's procedures 
and specifications and the following requirements.
    (A) Locate the monitor in a position that provides a representative 
measurement of the total gas flow rate.
    (B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet 
per minute, whichever is greater.
    (C) Use a flow monitor that is maintainable online, is able to 
continuously correct for temperature, pressure, and moisture content, 
and is able to record dry flow in standard conditions (as defined in 
Sec.  60.2) over one-minute averages.
    (D) At least quarterly, perform a visual inspection of all 
components of the monitor for physical and operational integrity and 
all electrical connections for oxidation and galvanic corrosion if the 
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the 
manufacturer's procedures and specifications biennially (every two 
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall correct the flow to 0 percent 
excess air using Equation 11 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.003

Where:

Qadj = Volumetric flow rate adjusted to 0 percent excess 
air, dry standard cubic feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the flow meter 
corrected to dry standard conditions, dscfm;
20.9c = 20.9 percent O2-0.0 percent 
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry 
basis, percent.

    (iii) The owner or operator shall calculate the flow weighted 
average SO2 or reduced sulfur compounds concentration for 
each hour using Equation 12 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.004


[[Page 75235]]


Where:

Cave = Flow weighted average concentration of the 
pollutant, ppmv (dry basis, zero percent excess air). The pollutant 
is either SO2 (if complying with the SO2 
emission limit in Sec.  60.102a(f)(1)(i) or (f)(2)(i)) or reduced 
sulfur compounds (if complying with the reduced sulfur compounds 
emission limit in Sec.  60.102a(f)(1)(ii) or (f)(2)(ii));
N = Number of release points within the group of release points from 
the sulfur recovery plant for which emissions averaging is elected;
Cn = Pollutant concentration in the nth 
release point within the group of release points from the sulfur 
recovery plant for which emissions averaging is elected, ppmv (dry 
basis, zero percent excess air);
Qadj,n = Volumetric flow rate of the nth 
release point within the group of release points from the sulfur 
recovery plant for which emissions averaging is elected, dry 
standard cubic feet per minute (dscfm, adjusted to 0 percent excess 
air).

    (iv) For sulfur recovery plants that use oxygen or oxygen enriched 
air in the Claus burner, the owner or operator shall use Equation 10 of 
this section and the hourly emission limits determined in paragraph 
(a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant 
concentration to determine the flow weighted average hourly emission 
limit for each hour. The allowable emission limit shall be calculated 
as the arithmetic average of 12 contiguous 1-hour averages (i.e., the 
rolling 12-hour average).
    (b) * * *
    (2) All 12-hour periods during which the average concentration of 
reduced sulfur compounds (as SO2) as measured by the reduced 
sulfur compounds continuous monitoring system required under paragraph 
(a)(2) or (3) of this section exceeds the applicable emission limit; or
    (3) All 12-hour periods during which the average concentration of 
H2S as measured by the H2S continuous monitoring 
system required under paragraph (a)(4) of this section exceeds the 
applicable emission limit (dry basis, 0 percent excess air).

0
9. Section 60.107a is amended by revising paragraphs (a)(1)(i) and 
(ii), (b)(1)(iv), the first sentence of paragraph (b)(3)(iii), (d)(3), 
(e)(1) introductory text, (e)(1)(ii), (e)(2) introductory text, 
(e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii), and (h)(5) to read as 
follows:


Sec.  60.107a  Monitoring of emissions and operations for fuel gas 
combustion devices and flares.

    (a) * * *
    (1) * * *
    (i) The owner or operator shall install, operate, and maintain each 
SO2 monitor according to Performance Specification 2 of 
appendix B to this part. The span value for the SO2 monitor 
is 50 ppmv SO2.
    (ii) The owner or operator shall conduct performance evaluations 
for the SO2 monitor according to the requirements of Sec.  
60.13(c) and Performance Specification 2 of appendix B to this part. 
The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to 
this part for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17) 
is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to 
this part. Samples taken by Method 6 of appendix A-4 to this part shall 
be taken at a flow rate of approximately 2 liters/min for at least 30 
minutes. The relative accuracy limit shall be 20 percent or 4 ppmv, 
whichever is greater, and the calibration drift limit shall be 5 
percent of the established span value.
* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel 
gas stream/system demonstrating that the sulfur content is less than 5 
ppmv H2S. Sampling data must include, at minimum, 2 weeks of 
daily monitoring (14 grab samples) for frequently operated fuel gas 
streams/systems; for infrequently operated fuel gas streams/systems, 
seven grab samples must be collected unless other additional 
information would support reduced sampling. The owner or operator shall 
use detector tubes (``length-of-stain tube'' type measurement) 
following the ``Gas Processors Association Standard 2377-86 
(incorporated by reference--see Sec.  60.17), using tubes with a 
maximum span between 10 and 40 ppmv inclusive when 1<=N<=10, where N = 
number of pump strokes, to test the applicant fuel gas stream for 
H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is 
outside the range of concentrations included in the original 
application and the owner or operator chooses not to submit new 
information to support an exemption, the owner or operator must begin 
H2S monitoring using daily stain sampling to demonstrate 
compliance using length-of-stain tubes with a maximum span between 200 
and 400 ppmv inclusive when 1<=N<=5, where N = number of pump strokes. 
* * *
* * * * *
    (d) * * *
    (3) As an alternative to the requirements in paragraph (d)(2) of 
this section, the owner or operator of a gas-fired process heater shall 
install, operate and maintain a gas composition analyzer and determine 
the average F factor of the fuel gas using the factors in Table 1 of 
this subpart and Equation 13 of this section. If a single fuel gas 
system provides fuel gas to several process heaters, the F factor may 
be determined at a single location in the fuel gas system provided it 
is representative of the fuel gas fed to the affected process 
heater(s).
[GRAPHIC] [TIFF OMITTED] TR01DE15.005

Where:

Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
    Xi = mole or volume fraction of each component in the 
fuel gas.
    MEVi = molar exhaust volume, dry standard cubic feet 
per mole (dscf/mol).
    MHCi = molar heat content, Btu per mole (Btu/mol).
    1,000,000 = unit conversion, Btu per MMBtu.
* * * * *
    (e) * * *
    (1) Total reduced sulfur monitoring requirements. The owner or 
operator shall install, operate, calibrate and maintain an instrument 
or instruments for continuously monitoring and recording the 
concentration of total reduced sulfur in gas discharged to the flare.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of 
each total reduced sulfur monitor according to the requirements in 
Sec.  60.13(c) and Performance Specification 5 of appendix B to this 
part. The owner or operator of each total

[[Page 75236]]

reduced sulfur monitor shall use EPA Method 15A of appendix A-5 to this 
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference-see Sec.  60.17) is an 
acceptable alternative to EPA Method 15A of appendix A-5 to this part. 
The alternative relative accuracy procedures described in section 16.0 
of Performance Specification 2 of appendix B to this part (cylinder gas 
audits) may be used for conducting the relative accuracy evaluations, 
except that it is not necessary to include as much of the sampling 
probe or sampling line as practical.
* * * * *
    (2) H2S monitoring requirements. The owner or operator shall 
install, operate, calibrate, and maintain an instrument or instruments 
for continuously monitoring and recording the concentration of 
H2S in gas discharged to the flare according to the 
requirements in paragraphs (e)(2)(i) through (iii) of this section and 
shall collect and analyze samples of the gas and calculate total sulfur 
concentrations as specified in paragraphs (e)(2)(iv) through (ix) of 
this section.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of 
each H2S monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 7 of appendix B to this part. 
The owner or operator shall use EPA Method 11, 15 or 15A of appendix A-
5 to this part for conducting the relative accuracy evaluations. The 
method ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  
60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 
to this part. The alternative relative accuracy procedures described in 
section 16.0 of Performance Specification 2 of appendix B to this part 
(cylinder gas audits) may be used for conducting the relative accuracy 
evaluations, except that it is not necessary to include as much of the 
sampling probe or sampling line as practical.
* * * * *
    (vi) * * *
    (C) Determine the acceptable range for subsequent weekly samples 
based on the 95-percent confidence interval for the distribution of 
daily ratios based on the 10 individual daily ratios using Equation 14 
of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.006

Where:

    AR = Acceptable range of subsequent ratio determinations, 
unitless.
    RatioAvg = 10-day average total sulfur-to-
H2S concentration ratio, unitless.
    2.262 = t-distribution statistic for 95-percent 2-sided 
confidence interval for 10 samples (9 degrees of freedom).
    SDev = Standard deviation of the 10 daily average total sulfur-
to-H2S concentration ratios used to develop the 10-day 
average total sulfur-to-H2S concentration ratio, 
unitless.
* * * * *
    (3) SO2 monitoring requirements. The owner or operator shall 
install, operate, calibrate, and maintain an instrument for 
continuously monitoring and recording the concentration of 
SO2 from a process heater or other fuel gas combustion 
device that is combusting gas representative of the fuel gas in the 
flare gas line according to the requirements in paragraph (a)(1) of 
this section, determine the F factor of the fuel gas at least daily 
according to the requirements in paragraphs (d)(2) through (4) of this 
section, determine the higher heating value of the fuel gas at least 
daily according to the requirements in paragraph (d)(7) of this 
section, and calculate the total sulfur content (as SO2) in 
the fuel gas using Equation 15 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.007

Where:

    TSFG = Total sulfur concentration, as SO2, 
in the fuel gas, ppmv.
    CSO2 = Concentration of SO2 in the exhaust 
gas, ppmv (dry basis at 0-percent excess air).
    Fd = F factor gas on dry basis at 0-percent excess 
air, dscf/MMBtu.
    HHVFG = Higher heating value of the fuel gas, MMBtu/
scf.
* * * * *
    (f) * * *
    (1) * * *
    (ii) Use a flow sensor meeting an accuracy requirement of 20 percent of the flow rate at velocities ranging from 0.1 to 1 
feet per second and an accuracy of 5 percent of the flow 
rate for velocities greater than 1 feet per second.
* * * * *
    (h) * * *
    (5) Daily O2 limits for fuel gas combustion devices. Each day 
during which the concentration of O2 as measured by the 
O2 continuous monitoring system required under paragraph 
(c)(6) or (d)(8) of this section exceeds the O2 operating 
limit or operating curve determined during the most recent biennial 
performance test.

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

0
10. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401 et se.

Subpart A--General Provisions

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (h)(14);
0
b. Redesignating paragraphs (h)(82) through (99) as (h)(86) through 
(103), paragraphs (h)(77) through (81) as (h)(80) through (84), 
paragraphs (h)(73) through (76) as paragraphs (h)(75) through (78), and 
paragraphs (h)(15) through (72) as (16) through (73), respectively;
0
c. Revising newly redesignated paragraph (h)(78);
0
d. Adding paragraphs (h)(15), (74), (79), (85), (104) and (j)(2);
0
e. Redesignating paragraph (m)(3) through (21) as (m)(5) through (23), 
respectively, and paragraph (m)(2) as (m)(3).
0
f. Adding paragraphs (m)(2) and (4) and (n)(3); and
0
g. Revising paragraph (s)(1).
    The revisions and additions read as follows:


Sec.  63.14  Incorporation by reference.

* * * * *
    (h) * * *
    (14) ASTM D1945-03 (Reapproved 2010), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography, Approved January 1, 
2010, IBR approved for Sec. Sec.  63.670(j), 63.772(h), and 63.1282(g).
    (15) ASTM D1945-14, Standard Test Method for Analysis of Natural 
Gas by Gas Chromatography, Approved

[[Page 75237]]

November 1, 2014, IBR approved for Sec.  63.670(j).
* * * * *
    (74) ASTM D6196-03 (Reapproved 2009), Standard Practice for 
Selection of Sorbents, Sampling, and Thermal Desorption Analysis 
Procedures for Volatile Organic Compounds in Air, Approved March 1, 
2009, IBR approved for appendix A to this part: Method 325A and Method 
325B.
* * * * *
    (78) ASTM D6348-03 (Reapproved 2010), Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 
through A8, Approved October 1, 2010, IBR approved for Sec.  
63.1571(a), tables 4 and 5 to subpart JJJJJ, tables 4 and 6 to subpart 
KKKKK, tables 1, 2, and 5 to subpart UUUUU and appendix B to subpart 
UUUUU.
* * * * *
    (79) ASTM D6348-12e1, Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy, Approved February 1, 2012, IBR approved 
for Sec.  63.1571(a).
* * * * *
    (85) ASTM D6420-99 (Reapproved 2010), Standard Test Method for 
Determination of Gaseous Organic Compounds by Direct Interface Gas 
Chromatography-Mass Spectrometry, Approved October 1, 2010, IBR 
approved for Sec.  63.670(j) and appendix A to this part: Method 325B.
* * * * *
    (104) ASTM UOP539-12, Refinery Gas Analysis by GC, Copyright 2012 
(to UOP), IBR approved for Sec.  63.670(j).
* * * * *
    (j) * * *
    (2) BS EN 14662-4:2005, Ambient air quality standard method for the 
measurement of benzene concentrations--Part 4: Diffusive sampling 
followed by thermal desorption and gas chromatography, Published June 
27, 2005, IBR approved for appendix A to this part: Method 325A and 
Method 325B.
* * * * *
    (m) * * *
    (2) EPA-454/B-08-002, Office of Air Quality Planning and Standards 
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), 
March 24, 2008, IBR approved for Sec.  63.658(d) and appendix A to this 
part: Method 325A.
* * * * *
    (4) EPA-454/R-99-005, Office of Air Quality Planning and Standards 
(OAQPS), Meteorological Monitoring Guidance for Regulatory Modeling 
Applications, February 2000, IBR approved for appendix A to this part: 
Method 325A.
* * * * *
    (n) * * *
    (3) ISO 16017-2:2003(E): Indoor, ambient and workplace air--
sampling and analysis of volatile organic compounds by sorbent tube/
thermal desorption/capillary gas chromatography--Part 2: Diffusive 
sampling, May 15, 2003, IBR approved for appendix A to this part: 
Method 325A and Method 325B.
* * * * *
    (s) * * *
    (1) ``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, January 31, 2003, IBR 
approved for Sec. Sec.  63.654(c) and (g), 63.655(i), and 63.11920.
* * * * *

Subpart Y--National Emission Standards for Marine Tank Vessel 
Loading Operations

0
12. Section 63.560 is amended by revising paragraph (a)(4) to read as 
follows:


Sec.  63.560  Applicability and designation of affected source.

    (a) * * *
    (4) Existing sources with emissions less than 10 and 25 tons must 
meet the submerged fill standards of 46 CFR 153.282.
* * * * *

Subpart CC--National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries

0
13. Section 63.640 is amended by:
0
a. Revising paragraphs (a) introductory text and (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraphs (d)(5), (h), (k)(1), (l) introductory text, 
(l)(2) introductory text, (l)(2)(i), (l)(3) introductory text, (m) 
introductory text, (n) introductory text, (n)(1) through (5), (n)(8) 
introductory text, and (n)(8)(ii);
0
e. Adding paragraphs (n)(8)(vii) and (viii);
0
f. Revising paragraph (n)(9)(i);
0
g. Adding paragraph (n)(10);
0
h. Revising paragraph (o)(2)(i) introductory text;
0
i. Adding paragraph (o)(2)(i)(D);
0
j. Revising paragraph (o)(2)(ii) introductory text; and
0
k. Adding paragraphs (o)(2)(ii)(C) and (s).
    The revisions and additions read as follows:


Sec.  63.640  Applicability and designation of affected source.

    (a) This subpart applies to petroleum refining process units and to 
related emissions points that are specified in paragraphs (c)(1) 
through (9) of this section that are located at a plant site and that 
meet the criteria in paragraphs (a)(1) and (2) of this section:
* * * * *
    (c) For the purposes of this subpart, the affected source shall 
comprise all emissions points, in combination, listed in paragraphs 
(c)(1) through (9) of this section that are located at a single 
refinery plant site.
* * * * *
    (9) All releases associated with the decoking operations of a 
delayed coking unit, as defined in this subpart.
    (d) * * *
    (5) Emission points routed to a fuel gas system, as defined in 
Sec.  63.641, provided that on and after January 30, 2019, any flares 
receiving gas from that fuel gas system are subject to Sec.  63.670. No 
other testing, monitoring, recordkeeping, or reporting is required for 
refinery fuel gas systems or emission points routed to refinery fuel 
gas systems.
* * * * *
    (h) Sources subject to this subpart are required to achieve 
compliance on or before the dates specified in table 11 of this 
subpart, except as provided in paragraphs (h)(1) through (3) of this 
section.
    (1) Marine tank vessels at existing sources shall be in compliance 
with this subpart, except for Sec. Sec.  63.657 through 63.660, no 
later than August 18, 1999, unless the vessels are included in an 
emissions average to generate emission credits. Marine tank vessels 
used to generate credits in an emissions average shall be in compliance 
with this subpart no later than August 18, 1998, unless an extension 
has been granted by the Administrator as provided in Sec.  63.6(i).
    (2) Existing Group 1 floating roof storage vessels meeting the 
applicability criteria in item 1 of the definition of Group 1 storage 
vessel shall be in compliance with Sec.  63.646 at the first degassing 
and cleaning activity after August 18, 1998, or August 18, 2005, 
whichever is first.

[[Page 75238]]

    (3) An owner or operator may elect to comply with the provisions of 
Sec.  63.648(c) through (i) as an alternative to the provisions of 
Sec.  63.648(a) and (b). In such cases, the owner or operator shall 
comply no later than the dates specified in paragraphs (h)(3)(i) 
through (iii) of this section.
    (i) Phase I (see table 2 of this subpart), beginning on August 18, 
1998;
    (ii) Phase II (see table 2 of this subpart), beginning no later 
than August 18, 1999; and
    (iii) Phase III (see table 2 of this subpart), beginning no later 
than February 18, 2001.
* * * * *
    (k) * * *
    (1) The reconstructed source, addition, or change shall be in 
compliance with the new source requirements in item (1), (2), or (3) of 
table 11 of this subpart, as applicable, upon initial startup of the 
reconstructed source or by August 18, 1995, whichever is later; and
* * * * *
    (l) If an additional petroleum refining process unit is added to a 
plant site or if a miscellaneous process vent, storage vessel, gasoline 
loading rack, marine tank vessel loading operation, heat exchange 
system, or decoking operation that meets the criteria in paragraphs 
(c)(1) through (9) of this section is added to an existing petroleum 
refinery or if another deliberate operational process change creating 
an additional Group 1 emissions point(s) (as defined in Sec.  63.641) 
is made to an existing petroleum refining process unit, and if the 
addition or process change is not subject to the new source 
requirements as determined according to paragraph (i) or (j) of this 
section, the requirements in paragraphs (l)(1) through (4) of this 
section shall apply. Examples of process changes include, but are not 
limited to, changes in production capacity, or feed or raw material 
where the change requires construction or physical alteration of the 
existing equipment or catalyst type, or whenever there is replacement, 
removal, or addition of recovery equipment. For purposes of this 
paragraph (l) and paragraph (m) of this section, process changes do not 
include: Process upsets, unintentional temporary process changes, and 
changes that are within the equipment configuration and operating 
conditions documented in the Notification of Compliance Status report 
required by Sec.  63.655(f).
* * * * *
    (2) The added emission point(s) and any emission point(s) within 
the added or changed petroleum refining process unit shall be in 
compliance with the applicable requirements in item (4) of table 11 of 
this subpart by the dates specified in paragraph (l)(2)(i) or (ii) of 
this section.
    (i) If a petroleum refining process unit is added to a plant site 
or an emission point(s) is added to any existing petroleum refining 
process unit, the added emission point(s) shall be in compliance upon 
initial startup of any added petroleum refining process unit or 
emission point(s) or by the applicable compliance date in item (4) of 
table 11 of this subpart, whichever is later.
* * * * *
    (3) The owner or operator of a petroleum refining process unit or 
of a storage vessel, miscellaneous process vent, wastewater stream, 
gasoline loading rack, marine tank vessel loading operation, heat 
exchange system, or decoking operation meeting the criteria in 
paragraphs (c)(1) through (9) of this section that is added to a plant 
site and is subject to the requirements for existing sources shall 
comply with the reporting and recordkeeping requirements that are 
applicable to existing sources including, but not limited to, the 
reports listed in paragraphs (l)(3)(i) through (vii) of this section. A 
process change to an existing petroleum refining process unit shall be 
subject to the reporting requirements for existing sources including, 
but not limited to, the reports listed in paragraphs (l)(3)(i) through 
(vii) of this section. The applicable reports include, but are not 
limited to:
* * * * *
    (m) If a change that does not meet the criteria in paragraph (l) of 
this section is made to a petroleum refining process unit subject to 
this subpart, and the change causes a Group 2 emission point to become 
a Group 1 emission point (as defined in Sec.  63.641), then the owner 
or operator shall comply with the applicable requirements of this 
subpart for existing sources, as specified in item (4) of table 11 of 
this subpart, for the Group 1 emission point as expeditiously as 
practicable, but in no event later than 3 years after the emission 
point becomes Group 1.
* * * * *
    (n) Overlap of this subpart with other regulations for storage 
vessels. As applicable, paragraphs (n)(1), (3), (4), (6), and (7) of 
this section apply for Group 2 storage vessels and paragraphs (n)(2) 
and (5) of this section apply for Group 1 storage vessels.
    (1) After the compliance dates specified in paragraph (h) of this 
section, a Group 2 storage vessel that is subject to the provisions of 
40 CFR part 60, subpart Kb, is required to comply only with the 
requirements of 40 CFR part 60, subpart Kb, except as provided in 
paragraph (n)(8) of this section. After the compliance dates specified 
in paragraph (h) of this section, a Group 2 storage vessel that is 
subject to the provisions of 40 CFR part 61, subpart Y, is required to 
comply only with the requirements of 40 CFR part 61, subpart Y, except 
as provided in paragraph (n)(10) of this section.
    (2) After the compliance dates specified in paragraph (h) of this 
section, a Group 1 storage vessel that is also subject to 40 CFR part 
60, subpart Kb, is required to comply only with either 40 CFR part 60, 
subpart Kb, except as provided in paragraph (n)(8) of this section or 
this subpart. After the compliance dates specified in paragraph (h) of 
this section, a Group 1 storage vessel that is also subject to 40 CFR 
part 61, subpart Y, is required to comply only with either 40 CFR part 
61, subpart Y, except as provided in paragraph (n)(10) of this section 
or this subpart.
    (3) After the compliance dates specified in paragraph (h) of this 
section, a Group 2 storage vessel that is part of a new source and is 
subject to 40 CFR 60.110b, but is not required to apply controls by 40 
CFR 60.110b or 60.112b, is required to comply only with this subpart.
    (4) After the compliance dates specified in paragraph (h) of this 
section, a Group 2 storage vessel that is part of a new source and is 
subject to 40 CFR 61.270, but is not required to apply controls by 40 
CFR 61.271, is required to comply only with this subpart.
    (5) After the compliance dates specified in paragraph (h) of this 
section, a Group 1 storage vessel that is also subject to the 
provisions of 40 CFR part 60, subpart K or Ka, is required to only 
comply with the provisions of this subpart.
* * * * *
    (8) Storage vessels described by paragraph (n)(1) of this section 
are to comply with 40 CFR part 60, subpart Kb, except as provided in 
paragraphs (n)(8)(i) through (vi) of this section. Storage vessels 
described by paragraph (n)(2) electing to comply with part 60, subpart 
Kb of this chapter shall comply with subpart Kb except as provided in 
paragraphs (n)(8)(i) through (viii) of this section.
* * * * *
    (ii) If the owner or operator determines that it is unsafe to 
perform the seal gap measurements required in Sec.  60.113b(b) of this 
chapter or to inspect the vessel to determine compliance with

[[Page 75239]]

Sec.  60.113b(a) of this chapter because the roof appears to be 
structurally unsound and poses an imminent danger to inspecting 
personnel, the owner or operator shall comply with the requirements in 
either Sec.  63.120(b)(7)(i) or (ii) of subpart G (only up to the 
compliance date specified in paragraph (h) of this section for 
compliance with Sec.  63.660, as applicable) or either Sec.  
63.1063(c)(2)(iv)(A) or (B) of subpart WW.
* * * * *
    (vii) To be in compliance with Sec.  60.112b(a)(1)(iv) or 
(a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels 
must be equipped with covers and/or controls (e.g., pole float system, 
pole sleeve system, internal sleeve system or flexible enclosure 
system) as appropriate to comply with the ``no visible gap'' 
requirement.
    (viii) If a flare is used as a control device for a storage vessel, 
on and after January 30, 2019, the owner or operator must meet the 
requirements of Sec.  63.670 instead of the requirements referenced 
from part 60, subpart Kb of this chapter for that flare.
    (9) * * *
    (i) If the owner or operator determines that it is unsafe to 
perform the seal gap measurements required in Sec.  60.113a(a)(1) of 
this chapter because the floating roof appears to be structurally 
unsound and poses an imminent danger to inspecting personnel, the owner 
or operator shall comply with the requirements in either Sec.  
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date 
specified in paragraph (h) of this section for compliance with Sec.  
63.660, as applicable) or either Sec.  63.1063(c)(2)(iv)(A) or (B) of 
subpart WW.
* * * * *
    (10) Storage vessels described by paragraph (n)(1) of this section 
are to comply with 40 CFR part 61, subpart Y, except as provided in 
paragraphs (n)(10)(i) through (vi) of this section. Storage vessels 
described by paragraph (n)(2) electing to comply with 40 CFR part 61, 
subpart Y, shall comply with subpart Y except as provided for in 
paragraphs (n)(10)(i) through (viii) of this section.
    (i) Storage vessels that are to comply with Sec.  61.271(b) of this 
chapter are exempt from the secondary seal requirements of Sec.  
61.271(b)(2)(ii) of this chapter during the gap measurements for the 
primary seal required by Sec.  61.272(b) of this chapter.
    (ii) If the owner or operator determines that it is unsafe to 
perform the seal gap measurements required in Sec.  61.272(b) of this 
chapter or to inspect the vessel to determine compliance with Sec.  
61.272(a) of this chapter because the roof appears to be structurally 
unsound and poses an imminent danger to inspecting personnel, the owner 
or operator shall comply with the requirements in either Sec.  
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date 
specified in paragraph (h) of this section for compliance with Sec.  
63.660, as applicable) or either Sec.  63.1063(c)(2)(iv)(A) or (B) of 
subpart WW.
    (iii) If a failure is detected during the inspections required by 
Sec.  61.272(a)(2) of this chapter or during the seal gap measurements 
required by Sec.  61.272(b)(1) of this chapter, and the vessel cannot 
be repaired within 45 days and the vessel cannot be emptied within 45 
days, the owner or operator may utilize up to two extensions of up to 
30 additional calendar days each. The owner or operator is not required 
to provide a request for the extension to the Administrator.
    (iv) If an extension is utilized in accordance with paragraph 
(n)(10)(iii) of this section, the owner or operator shall, in the next 
periodic report, identify the vessel, provide the information listed in 
Sec.  61.272(a)(2) or (b)(4)(iii) of this chapter, and describe the 
nature and date of the repair made or provide the date the storage 
vessel was emptied.
    (v) Owners and operators of storage vessels complying with 40 CFR 
part 61, subpart Y, may submit the inspection reports required by Sec.  
61.275(a), (b)(1), and (d) of this chapter as part of the periodic 
reports required by this subpart, rather than within the 60-day period 
specified in Sec.  61.275(a), (b)(1), and (d) of this chapter.
    (vi) The reports of rim seal inspections specified in Sec.  
61.275(d) of this chapter are not required if none of the measured gaps 
or calculated gap areas exceed the limitations specified in Sec.  
61.272(b)(4) of this chapter. Documentation of the inspections shall be 
recorded as specified in Sec.  61.276(a) of this chapter.
    (vii) To be in compliance with Sec.  61.271(a)(6) or (b)(3) of this 
chapter, guidepoles in floating roof storage vessels must be equipped 
with covers and/or controls (e.g., pole float system, pole sleeve 
system, internal sleeve system or flexible enclosure system) as 
appropriate to comply with the ``no visible gap'' requirement.
    (viii) If a flare is used as a control device for a storage vessel, 
on and after January 30, 2019, the owner or operator must meet the 
requirements of Sec.  63.670 instead of the requirements referenced 
from part 61, subpart Y of this chapter for that flare.
    (o) * * *
    (2) * * *
    (i) Comply with paragraphs (o)(2)(i)(A) through (D) of this 
section.
* * * * *
    (D) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of 40 CFR part 61, subpart FF, and subpart G of this part, or the 
requirements of Sec.  63.670.
    (ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this 
section.
* * * * *
    (C) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of 40 CFR part 61, subpart FF, and subpart G of this part, or the 
requirements of Sec.  63.670.
* * * * *
    (s) Overlap of this subpart with other regulation for flares. On 
January 30, 2019, flares that are subject to the provisions of 40 CFR 
60.18 or 63.11 and subject to this subpart are required to comply only 
with the provisions specified in this subpart. Prior to January 30, 
2019, flares that are subject to the provisions of 40 CFR 60.18 or 
63.11 and elect to comply with the requirements in Sec. Sec.  63.670 
and 63.671 are required to comply only with the provisions specified in 
this subpart.
0
14. Section 63.641 is amended by:
0
a. Adding, in alphabetical order, definitions of ``Assist air,'' 
``Assist steam,'' ``Center steam,'' ``Closed blowdown system,'' 
``Combustion zone,'' ``Combustion zone gas,'' ``Decoking operations,'' 
``Delayed coking unit,'' ``Flare,'' ``Flare purge gas,'' ``Flare 
supplemental gas,'' ``Flare sweep gas,'' ``Flare vent gas,'' ``Flexible 
enclosure device,'' ``Force majeure event,'' ``Lower steam,'' ``Net 
heating value,'' ``Perimeter assist air,'' ``Pilot gas,'' ``Premix 
assist air,'' ``Regulated material,'' ``Thermal expansion relief 
valve,'' ``Total steam,'' and ``Upper steam''; and
0
b. Revising the definitions of ``Delayed coker vent,'' ``Emission 
point,'' ``Group 1 storage vessel,'' ``Miscellaneous process vent,'' 
``Periodically discharged,'' and ``Reference control technology for 
storage vessels.''
    The revisions and additions read as follows:


Sec.  63.641  Definitions.

* * * * *
    Assist air means all air that intentionally is introduced prior to 
or at

[[Page 75240]]

a flare tip through nozzles or other hardware conveyance for the 
purposes including, but not limited to, protecting the design of the 
flare tip, promoting turbulence for mixing or inducing air into the 
flame. Assist air includes premix assist air and perimeter assist air. 
Assist air does not include the surrounding ambient air.
    Assist steam means all steam that intentionally is introduced prior 
to or at a flare tip through nozzles or other hardware conveyance for 
the purposes including, but not limited to, protecting the design of 
the flare tip, promoting turbulence for mixing or inducing air into the 
flame. Assist steam includes, but is not necessarily limited to, center 
steam, lower steam and upper steam.
* * * * *
    Center steam means the portion of assist steam introduced into the 
stack of a flare to reduce burnback.
    Closed blowdown system means a system used for depressuring process 
vessels that is not open to the atmosphere and is configured of piping, 
ductwork, connections, accumulators/knockout drums, and, if necessary, 
flow inducing devices that transport gas or vapor from process vessel 
to a control device or back into the process.
* * * * *
    Combustion zone means the area of the flare flame where the 
combustion zone gas combines for combustion.
    Combustion zone gas means all gases and vapors found just after a 
flare tip. This gas includes all flare vent gas, total steam, and 
premix air.
* * * * *
    Decoking operations means the sequence of steps conducted at the 
end of the delayed coking unit's cooling cycle to open the coke drum to 
the atmosphere in order to remove coke from the coke drum. Decoking 
operations begin at the end of the cooling cycle when steam released 
from the coke drum is no longer discharged via the unit's blowdown 
system but instead is vented directly to the atmosphere. Decoking 
operations include atmospheric depressuring (venting), deheading, 
draining, and decoking (coke cutting).
    Delayed coker vent means a miscellaneous process vent that contains 
uncondensed vapors from the delayed coking unit's blowdown system. 
Venting from the delayed coker vent is typically intermittent in 
nature, and occurs primarily during the cooling cycle of a delayed 
coking unit coke drum when vapor from the coke drums cannot be sent to 
the fractionator column for product recovery. The emissions from the 
decoking operations, which include direct atmospheric venting, 
deheading, draining, or decoking (coke cutting), are not considered to 
be delayed coker vents.
    Delayed coking unit means a refinery process unit in which high 
molecular weight petroleum derivatives are thermally cracked and 
petroleum coke is produced in a series of closed, batch system 
reactors. A delayed coking unit includes, but is not limited to, all of 
the coke drums associated with a single fractionator; the fractionator, 
including the bottoms receiver and the overhead condenser; the coke 
drum cutting water and quench system, including the jet pump and coker 
quench water tank; and the coke drum blowdown recovery compressor 
system.
* * * * *
    Emission point means an individual miscellaneous process vent, 
storage vessel, wastewater stream, equipment leak, decoking operation 
or heat exchange system associated with a petroleum refining process 
unit; an individual storage vessel or equipment leak associated with a 
bulk gasoline terminal or pipeline breakout station classified under 
Standard Industrial Classification code 2911; a gasoline loading rack 
classified under Standard Industrial Classification code 2911; or a 
marine tank vessel loading operation located at a petroleum refinery.
* * * * *
    Flare means a combustion device lacking an enclosed combustion 
chamber that uses an uncontrolled volume of ambient air to burn gases. 
For the purposes of this rule, the definition of flare includes, but is 
not necessarily limited to, air-assisted flares, steam-assisted flares 
and non-assisted flares.
    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. 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 in 
order to improve the combustible characteristics of combustion zone 
gas.
    Flare sweep gas means, for a flare with a flare gas recovery 
system, the gas intentionally introduced into the flare header system 
to maintain a constant flow of gas through the flare header in order to 
prevent oxygen buildup in the flare header; flare sweep gas in these 
flares is introduced prior to and recovered by the flare gas recovery 
system. For a flare without a flare gas recovery system, flare sweep 
gas means the gas intentionally introduced into the flare header system 
to maintain a constant flow of gas through the flare header and out the 
flare tip in order to prevent oxygen buildup in the flare header and to 
prevent oxygen infiltration (backflow) into the flare tip.
    Flare vent gas means all gas found just prior to the flare tip. 
This gas includes all flare waste gas (i.e., gas from facility 
operations that is directed to a flare for the purpose of disposing of 
the gas), that portion of flare sweep gas that is not recovered, flare 
purge gas and flare supplemental gas, but does not include pilot gas, 
total steam or assist air.
    Flexible enclosure device means a seal made of an elastomeric 
fabric (or other material) which completely encloses a slotted 
guidepole or ladder and eliminates the vapor emission pathway from 
inside the storage vessel through the guidepole slots or ladder slots 
to the outside air.
* * * * *
    Force majeure event means a release of HAP, either directly to the 
atmosphere from a relief valve or discharged via a flare, that is 
demonstrated to the satisfaction of the Administrator to result from an 
event beyond the refinery owner or operator's control, such as natural 
disasters; acts of war or terrorism; loss of a utility external to the 
refinery (e.g., external power curtailment), excluding power 
curtailment due to an interruptible service agreement; and fire or 
explosion originating at a near or adjoining facility outside of the 
refinery owner or operator's control that impacts the refinery's 
ability to operate.
* * * * *
    Group 1 storage vessel means:
    (1) Prior to February 1, 2016:
    (i) A storage vessel at an existing source that has a design 
capacity greater than or equal to 177 cubic meters and stored-liquid 
maximum true vapor pressure greater than or equal to 10.4 kilopascals 
and stored-liquid annual average true vapor pressure greater than or 
equal to 8.3 kilopascals and annual average HAP liquid concentration 
greater than 4 percent by weight total organic HAP;
    (ii) A storage vessel at a new source that has a design storage 
capacity greater than or equal to 151 cubic meters and stored-liquid 
maximum true vapor pressure greater than or equal to 3.4 kilopascals 
and annual average HAP liquid concentration greater than 2 percent by 
weight total organic HAP; or
    (iii) A storage vessel at a new source that has a design storage 
capacity greater than or equal to 76 cubic meters and less than 151 
cubic meters and stored-

[[Page 75241]]

liquid maximum true vapor pressure greater than or equal to 77 
kilopascals and annual average HAP liquid concentration greater than 2 
percent by weight total organic HAP.
    (2) On and after February 1, 2016:
    (i) A storage vessel at an existing source that has a design 
capacity greater than or equal to 151 cubic meters (40,000 gallons) and 
stored-liquid maximum true vapor pressure greater than or equal to 5.2 
kilopascals (0.75 pounds per square inch) and annual average HAP liquid 
concentration greater than 4 percent by weight total organic HAP;
    (ii) A storage vessel at an existing source that has a design 
storage capacity greater than or equal to 76 cubic meters (20,000 
gallons) and less than 151 cubic meters (40,000 gallons) and stored-
liquid maximum true vapor pressure greater than or equal to 13.1 
kilopascals (1.9 pounds per square inch) and annual average HAP liquid 
concentration greater than 4 percent by weight total organic HAP;
    (iii) A storage vessel at a new source that has a design storage 
capacity greater than or equal to 151 cubic meters (40,000 gallons) and 
stored-liquid maximum true vapor pressure greater than or equal to 3.4 
kilopascals (0.5 pounds per square inch) and annual average HAP liquid 
concentration greater than 2 percent by weight total organic HAP; or
    (iv) A storage vessel at a new source that has a design storage 
capacity greater than or equal to 76 cubic meters (20,000 gallons) and 
less than 151 cubic meters (40,000 gallons) and stored-liquid maximum 
true vapor pressure greater than or equal to 13.1 kilopascals (1.9 
pounds per square inch) and annual average HAP liquid concentration 
greater than 2 percent by weight total organic HAP.
* * * * *
    Lower steam means the portion of assist steam piped to an exterior 
annular ring near the lower part of a flare tip, which then flows 
through tubes to the flare tip, and ultimately exits the tubes at the 
flare tip.
* * * * *
    Miscellaneous process vent means a gas stream containing greater 
than 20 parts per million by volume organic HAP that is continuously or 
periodically discharged from a petroleum refining process unit meeting 
the criteria specified in Sec.  63.640(a). Miscellaneous process vents 
include gas streams that are discharged directly to the atmosphere, gas 
streams that are routed to a control device prior to discharge to the 
atmosphere, or gas streams that are diverted through a product recovery 
device prior to control or discharge to the atmosphere. Miscellaneous 
process vents include vent streams from: Caustic wash accumulators, 
distillation tower condensers/accumulators, flash/knockout drums, 
reactor vessels, scrubber overheads, stripper overheads, vacuum pumps, 
steam ejectors, hot wells, high point bleeds, wash tower overheads, 
water wash accumulators, blowdown condensers/accumulators, and delayed 
coker vents. Miscellaneous process vents do not include:
    (1) Gaseous streams routed to a fuel gas system, provided that on 
and after January 30, 2019, any flares receiving gas from the fuel gas 
system are in compliance with Sec.  63.670;
    (2) Pressure relief device discharges;
    (3) Leaks from equipment regulated under Sec.  63.648;
    (4) [Reserved]
    (5) In situ sampling systems (onstream analyzers) until January 30, 
2019. After this date, these sampling systems will be included in the 
definition of miscellaneous process vents;
    (6) Catalytic cracking unit catalyst regeneration vents;
    (7) Catalytic reformer regeneration vents;
    (8) Sulfur plant vents;
    (9) Vents from control devices such as scrubbers, boilers, 
incinerators, and electrostatic precipitators applied to catalytic 
cracking unit catalyst regeneration vents, catalytic reformer 
regeneration vents, and sulfur plant vents;
    (10) Vents from any stripping operations applied to comply with the 
wastewater provisions of this subpart, subpart G of this part, or 40 
CFR part 61, subpart FF;
    (11) Emissions associated with delayed coking unit decoking 
operations;
    (12) Vents from storage vessels;
    (13) Emissions from wastewater collection and conveyance systems 
including, but not limited to, wastewater drains, sewer vents, and sump 
drains; and
    (14) Hydrogen production plant vents through which carbon dioxide 
is removed from process streams or through which steam condensate 
produced or treated within the hydrogen plant is degassed or deaerated.
    Net heating value means the energy released as heat when a compound 
undergoes complete combustion with oxygen to form gaseous carbon 
dioxide and gaseous water (also referred to as lower heating value).
* * * * *
    Perimeter assist air means the portion of assist air introduced at 
the perimeter of the flare tip or above the flare tip. Perimeter assist 
air includes air intentionally entrained in lower and upper steam. 
Perimeter assist air includes all assist air except premix assist air.
    Periodically discharged means discharges that are intermittent and 
associated with routine operations, maintenance activities, startups, 
shutdowns, malfunctions, or process upsets.
* * * * *
    Pilot gas means gas introduced into a flare tip that provides a 
flame to ignite the flare vent gas.
* * * * *
    Premix assist air means the portion of assist air that is 
introduced to the flare vent gas, whether injected or induced, prior to 
the flare tip. Premix assist air also includes any air intentionally 
entrained in center steam.
* * * * *
    Reference control technology for storage vessels means either:
    (1) For Group 1 storage vessels complying with Sec.  63.660:
    (i) An internal floating roof, including an external floating roof 
converted to an internal floating roof, meeting the specifications of 
Sec.  63.1063(a)(1)(i) and (b);
    (ii) An external floating roof meeting the specifications of Sec.  
63.1063(a)(1)(ii), (a)(2), and (b); or
    (iii) [Reserved]
    (iv) A closed-vent system to a control device that reduces organic 
HAP emissions by 95 percent, or to an outlet concentration of 20 parts 
per million by volume (ppmv).
    (v) For purposes of emissions averaging, these four technologies 
are considered equivalent.
    (2) For all other storage vessels:
    (i) An internal floating roof meeting the specifications of Sec.  
63.119(b) of subpart G except for Sec.  63.119(b)(5) and (6);
    (ii) An external floating roof meeting the specifications of Sec.  
63.119(c) of subpart G except for Sec.  63.119(c)(2);
    (iii) An external floating roof converted to an internal floating 
roof meeting the specifications of Sec.  63.119(d) of subpart G except 
for Sec.  63.119(d)(2); or
    (iv) A closed-vent system to a control device that reduces organic 
HAP emissions by 95 percent, or to an outlet concentration of 20 parts 
per million by volume.
    (v) For purposes of emissions averaging, these four technologies 
are considered equivalent.
* * * * *
    Regulated material means any stream associated with emission 
sources listed

[[Page 75242]]

in Sec.  63.640(c) required to meet control requirements under this 
subpart as well as any stream for which this subpart or a cross-
referencing subpart specifies that the requirements for flare control 
devices in Sec.  63.670 must be met.
* * * * *
    Thermal expansion relief valve means a pressure relief valve 
designed to protect equipment from excess pressure due to thermal 
expansion of blocked liquid-filled equipment or piping due to ambient 
heating or heat from a heat tracing system. Pressure relief valves 
designed to protect equipment from excess pressure due to blockage 
against a pump or compressor or due to fire contingency are not thermal 
expansion relief valves.
* * * * *
    Total steam means the total of all steam that is supplied to a 
flare and includes, but is not limited to, lower steam, center steam 
and upper steam.
    Upper steam means the portion of assist steam introduced via 
nozzles located on the exterior perimeter of the upper end of the flare 
tip.
* * * * *

0
15. Section 63.642 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraphs (d)(3), (e), (i), (k) introductory text, (k)(1), 
(l) introductory text, and (l)(2); and
0
c. Adding paragraph (n).
    The revisions and additions read as follows:


Sec.  63.642  General standards.

* * * * *
    (b) The emission standards set forth in this subpart shall apply at 
all times.
* * * * *
    (d) * * *
    (3) Performance tests shall be conducted according to the 
provisions of Sec.  63.7(e) except that performance tests shall be 
conducted at maximum representative operating capacity for the process. 
During the performance test, an owner or operator shall operate the 
control device at either maximum or minimum representative operating 
conditions for monitored control device parameters, whichever results 
in lower emission reduction. An owner or operator shall not conduct a 
performance test during startup, shutdown, periods when the control 
device is bypassed or periods when the process, monitoring equipment or 
control device is not operating properly. The owner/operator may not 
conduct performance tests during periods of malfunction. The owner or 
operator must record the process information that is necessary to 
document operating conditions during the test and include in such 
record an explanation to support that the test was conducted at maximum 
representative operating capacity. Upon request, the owner or operator 
shall make available to the Administrator such records as may be 
necessary to determine the conditions of performance tests.
* * * * *
    (e) All applicable records shall be maintained as specified in 
Sec.  63.655(i).
* * * * *
    (i) The owner or operator of an existing source shall demonstrate 
compliance with the emission standard in paragraph (g) of this section 
by following the procedures specified in paragraph (k) of this section 
for all emission points, or by following the emissions averaging 
compliance approach specified in paragraph (l) of this section for 
specified emission points and the procedures specified in paragraph 
(k)(1) of this section.
* * * * *
    (k) The owner or operator of an existing source may comply, and the 
owner or operator of a new source shall comply, with the applicable 
provisions in Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 
63.647, 63.650, and 63.651, as specified in Sec.  63.640(h).
    (1) The owner or operator using this compliance approach shall also 
comply with the requirements of Sec. Sec.  63.648 and/or 63.649, 
63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable.
* * * * *
    (l) The owner or operator of an existing source may elect to 
control some of the emission points within the source to different 
levels than specified under Sec. Sec.  63.643 through 63.645, 63.646 or 
63.660, 63.647, 63.650, and 63.651, as applicable according to Sec.  
63.640(h), by using an emissions averaging compliance approach as long 
as the overall emissions for the source do not exceed the emission 
level specified in paragraph (g) of this section. The owner or operator 
using emissions averaging shall meet the requirements in paragraphs 
(l)(1) and (2) of this section.
* * * * *
    (2) Comply with the requirements of Sec. Sec.  63.648 and/or 
63.649, 63.654, 63.652, 63.653, 63.655, 63.657, 63.658, 63.670 and 
63.671, as applicable.
* * * * *
    (n) At all times, the owner or operator must operate and maintain 
any affected source, including associated air pollution control 
equipment and monitoring equipment, in a manner consistent with safety 
and good air pollution control practices for minimizing emissions. The 
general duty to minimize emissions does not require the owner operator 
to make any further efforts to reduce emissions if levels required by 
the applicable standard have been achieved. Determination of whether a 
source is operating in compliance with operation and maintenance 
requirements will be based on information available to the 
Administrator which may include, but is not limited to, monitoring 
results, review of operation and maintenance procedures, review of 
operation and maintenance records, and inspection of the source.

0
16. Section 63.643 is amended by revising paragraphs (a) introductory 
text and (a)(1) and adding paragraph (c) to read as follows:


Sec.  63.643  Miscellaneous process vent provisions.

    (a) The owner or operator of a Group 1 miscellaneous process vent 
as defined in Sec.  63.641 shall comply with the requirements of either 
paragraph (a)(1) or (2) of this section or, if applicable, paragraph 
(c) of this section. The owner or operator of a miscellaneous process 
vent that meets the conditions in paragraph (c) of this section is only 
required to comply with the requirements of paragraph (c) of this 
section and Sec.  63.655(g)(13) and (i)(12) for that vent.
    (1) Reduce emissions of organic HAP's using a flare. On and after 
January 30, 2019, the flare shall meet the requirements of Sec.  
63.670. Prior to January 30, 2019, the flare shall meet the 
requirements of Sec.  63.11(b) of subpart A or the requirements of 
Sec.  63.670.
* * * * *
    (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 of 
operator does not need to designate a maintenance vent as a Group 1 or 
Group 2 miscellaneous process vent. The owner or operator must comply 
with the applicable requirements in paragraphs (c)(1) through (3) of 
this section for each maintenance vent.
    (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, fuel gas system, or back to the 
process until one of the following conditions, as applicable, is met.
    (i) The vapor in the equipment served by the maintenance vent has a 
lower

[[Page 75243]]

explosive limit (LEL) of less than 10 percent.
    (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 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) equipment is less than 10 percent.
    (iii) The equipment served by the maintenance vent contains less 
than 72 pounds of VOC.
    (iv) If the maintenance vent is associated with equipment 
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) 
at refineries that do not have a pure hydrogen supply, 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.
    (2) Except for maintenance vents complying with the alternative in 
paragraph (c)(1)(iii) of this section, the owner or operator must 
determine the LEL or, if applicable, equipment pressure using process 
instrumentation or portable measurement devices and follow procedures 
for calibration and maintenance according to manufacturer's 
specifications.
    (3) For maintenance vents complying with the alternative in 
paragraph (c)(1)(iii) of this section, the owner or operator shall 
determine mass of VOC in the equipment served by the maintenance vent 
based on the equipment size and contents after considering any contents 
drained or purged from the equipment. Equipment size may be determined 
from equipment design specifications. Equipment contents may be 
determined using process knowledge.

0
17. Section 63.644 is amended by revising paragraphs (a) introductory 
text, (a)(2), and (c) to read as follows:


Sec.  63.644  Monitoring provisions for miscellaneous process vents.

    (a) Except as provided in paragraph (b) of this section, each owner 
or operator of a Group 1 miscellaneous process vent that uses a 
combustion device to comply with the requirements in Sec.  63.643(a) 
shall install the monitoring equipment specified in paragraph (a)(1), 
(2), (3), or (4) of this section, depending on the type of combustion 
device used. All monitoring equipment shall be installed, calibrated, 
maintained, and operated according to manufacturer's specifications or 
other written procedures that provide adequate assurance that the 
equipment will monitor accurately and, except for CPMS installed for 
pilot flame monitoring, must meet the applicable minimum accuracy, 
calibration and quality control requirements specified in table 13 of 
this subpart.
* * * * *
    (2) Where a flare is used prior to January 30, 2019, a device 
(including but not limited to a thermocouple, an ultraviolet beam 
sensor, or an infrared sensor) capable of continuously detecting the 
presence of a pilot flame is required, or the requirements of Sec.  
63.670 shall be met. Where a flare is used on and after January 30, 
2019, the requirements of Sec.  63.670 shall be met.
* * * * *
    (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 Sec.  63.643(a) 
shall comply with either paragraph (c)(1) or (2) 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 Sec.  63.643(a) is an emissions 
standards violation. Equipment such as low leg drains and equipment 
subject to Sec.  63.648 are not subject to this paragraph (c).
    (1) Install, calibrate and maintain a flow indicator that 
determines whether a vent stream flow is present at least once every 
hour. A manual block valve equipped with a valve position indicator may 
be used in lieu of a flow indicator, as long as the valve position 
indicator is monitored continuously. Records shall be generated as 
specified in Sec.  63.655(h) and (i). The flow indicator shall be 
installed at the entrance to any bypass line that could divert the vent 
stream away from the control device to the atmosphere; or
    (2) Secure the bypass line valve in the non-diverting position with 
a car-seal or a lock-and-key type configuration. A visual inspection of 
the seal or closure mechanism shall be performed at least once every 
month to ensure that the valve is maintained in the non-diverting 
position and that the vent stream is not diverted through the bypass 
line.
* * * * *

0
18. Section 63.645 is amended by revising paragraphs (e)(1) and (f)(2) 
to read as follows:


Sec.  63.645  Test methods and procedures for miscellaneous process 
vents.

* * * * *
    (e) * * *
    (1) Methods 1 or 1A of 40 CFR part 60, appendix A-1, as 
appropriate, shall be used for selection of the sampling site. For 
vents smaller than 0.10 meter in diameter, sample at the center of the 
vent.
* * * * *
    (f) * * *
    (2) The gas volumetric flow rate shall be determined using Methods 
2, 2A, 2C, 2D, or 2F of 40 CFR part 60, appendix A-1 or Method 2G of 40 
CFR part 60, appendix A-2, as appropriate.
* * * * *

0
19. Section 63.646 is amended by adding introductory text and revising 
paragraph (b)(2) to read as follows:


Sec.  63.646  Storage vessel provisions.

    Upon a demonstration of compliance with the standards in Sec.  
63.660 by the compliance dates specified in Sec.  63.640(h), the 
standards in this section shall no longer apply.
* * * * *
    (b) * * *
    (2) When an owner or operator and the Administrator do not agree on 
whether the annual average weight percent organic HAP in the stored 
liquid is above or below 4 percent for a storage vessel at an existing 
source or above or below 2 percent for a storage vessel at a new 
source, an appropriate method (based on the type of liquid stored) as 
published by EPA or a consensus-based standards organization shall be 
used. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International (100 Barr Harbor Drive, 
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute 
(ANSI, 1819 L Street NW., 6th floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400 
North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.naesb.org).
* * * * *

[[Page 75244]]


0
20. Section 63.647 is amended by:
0
a. Revising paragraph (a);
0
b. Redesignating paragraph (c) as paragraph (d); and
0
c. Adding paragraph (c).
    The revisions and additions read as follows:


Sec.  63.647  Wastewater provisions.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each owner or operator of a Group 1 wastewater stream shall comply with 
the requirements of Sec. Sec.  61.340 through 61.355 of this chapter 
for each process wastewater stream that meets the definition in Sec.  
63.641.
* * * * *
    (c) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of part 61, subpart FF of this chapter, or the requirements of Sec.  
63.670.
* * * * *

0
21. Section 63.648 is amended by:
0
a. Adding paragraph (a)(3);
0
b. Revising paragraph (c) introductory text; and
0
c. Adding paragraphs (c)(11) and (12) and (j).
    The revisions and additions read as follows:


Sec.  63.648  Equipment leak standards.

    (a) * * *
    (3) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of part 60, subpart VV of this chapter, or the requirements of Sec.  
63.670.
* * * * *
    (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 Sec. Sec.  63.161 through 63.169, 63.171, 
63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except 
as provided in paragraphs (c)(1) through (12) and (e) through (i) of 
this section.
* * * * *
    (11) [Reserved]
    (12) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of Sec. Sec.  63.172 and 63.180, or the requirements of Sec.  63.670.
* * * * *
    (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 Sec.  
60.482-4 or Sec.  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.
    (1) Operating requirements. Except during a pressure release, 
operate each pressure relief device in organic HAP gas or vapor service 
with an instrument reading of less than 500 ppm above background as 
detected by Method 21 of 40 CFR part 60, appendix A-7.
    (2) Pressure release requirements. For pressure relief devices in 
organic HAP gas or vapor service, the owner or operator must comply 
with the applicable requirements in paragraphs (j)(2)(i) through (iii) 
of this section following a pressure release.
    (i) If the pressure relief device does not consist of or include a 
rupture disk, conduct instrument monitoring, as specified in Sec.  
60.485(b) or Sec.  63.180(c), as applicable, no later than 5 calendar 
days after the pressure relief device returns to organic HAP gas or 
vapor service following a pressure release to verify that the pressure 
relief device is operating with an instrument reading of less than 500 
ppm.
    (ii) If the pressure relief device includes a rupture disk, either 
comply with the requirements in paragraph (j)(2)(i) of this section 
(not replacing the rupture disk) or install a replacement disk as soon 
as practicable after a pressure release, but no later than 5 calendar 
days after the pressure release. The owner or operator must conduct 
instrument monitoring, as specified in Sec.  60.485(b) or Sec.  
63.180(c), as applicable, no later than 5 calendar days after the 
pressure relief device returns to organic HAP gas or vapor service 
following a pressure release to verify that the pressure relief device 
is operating with an instrument reading of less than 500 ppm.
    (iii) If the pressure relief device consists only of a rupture 
disk, install a replacement disk as soon as practicable after a 
pressure release, but no later than 5 calendar days after the pressure 
release. The owner or operator may not initiate startup of the 
equipment served by the rupture disk until the rupture disc is 
replaced. The owner or operator must conduct instrument monitoring, as 
specified in Sec.  60.485(b) or Sec.  63.180(c), as applicable, no 
later than 5 calendar days after the pressure relief device returns to 
organic HAP gas or vapor service following a pressure release to verify 
that the pressure relief device is operating with an instrument reading 
of less than 500 ppm.
    (3) Pressure release management. Except as specified in paragraphs 
(j)(4) and (5) of this section, the owner or operator shall comply with 
the requirements specified in paragraphs (j)(3)(i) through (v) of this 
section for all pressure relief devices in organic HAP service no later 
than January 30, 2019.
    (i) The owner or operator must equip each affected pressure relief 
device with a device(s) or use a monitoring system that is capable of:
    (A) Identifying the pressure release;
    (B) Recording the time and duration of each pressure release; and
    (C) Notifying operators immediately that a pressure release is 
occurring. The device or monitoring system may be either specific to 
the pressure relief device itself or may be associated with the process 
system or piping, sufficient to indicate a pressure release to the 
atmosphere. Examples of these types of devices and systems include, but 
are not limited to, a rupture disk indicator, magnetic sensor, motion 
detector on the pressure relief valve stem, flow monitor, or pressure 
monitor.
    (ii) The owner or operator must apply at least three redundant 
prevention measures to each affected pressure relief device and 
document these measures. Examples of prevention measures 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.
    (E) Staged relief system where initial pressure relief valve (with 
lower set release pressure) discharges to a flare or other closed vent 
system and control device.
    (iii) If any affected pressure relief device releases to atmosphere 
as a result of a pressure release event, the owner or operator must 
perform root cause analysis and corrective action analysis according to 
the requirement in paragraph (j)(6) of this section and implement 
corrective actions according to the requirements in paragraph (j)(7) of 
this section. The owner or operator must also calculate the quantity of 
organic HAP released during each pressure

[[Page 75245]]

release event and report this quantity as required in Sec.  
63.655(g)(10)(iii). Calculations may be based on data from the pressure 
relief device monitoring alone or in combination with process parameter 
monitoring data and process knowledge.
    (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 majeureevent, 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 are a 
violation of the pressure release management work practice standards.
    (A) Any release event for which the root cause of the event was 
determined to be operator error or poor maintenance.
    (B) A second release event not including force majeure events from 
a single pressure relief device in a 3 calendar year period for the 
same root cause for the same equipment.
    (C) A third release event not including force majeure events from a 
single pressure relief device in a 3 calendar year period for any 
reason.
    (4) Pressure relief devices routed to a control device. 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. Both the closed vent system and control device (if applicable) 
must meet the requirements of Sec.  63.644. When complying with this 
paragraph (j)(4), all references to ``Group 1 miscellaneous process 
vent'' in Sec.  63.644 mean ``pressure relief device.'' 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 
Sec.  63.670.
    (5) Pressure relief devices exempted from pressure release 
management requirements. The following types of pressure relief devices 
are not subject to the pressure release management requirements in 
paragraph (j)(3) of this section.
    (i) Pressure relief devices in heavy liquid service, as defined in 
Sec.  63.641.
    (ii) Pressure relief devices that only release material that is 
liquid at standard conditions (1 atmosphere and 68 degrees Fahrenheit) 
and that are hard-piped to a controlled drain system (i.e., a drain 
system meeting the requirements for Group 1 wastewater streams in Sec.  
63.647(a)) or piped back to the process or pipeline.
    (iii) Thermal expansion relief valves.
    (iv) Pressure relief devices designed with a set relief pressure of 
less than 2.5 psig.
    (v) Pressure relief devices that do not have the potential to emit 
72 lbs/day or more of VOC based on the valve diameter, the set release 
pressure, and the equipment contents.
    (vi) Pressure relief devices on mobile equipment.
    (6) Root cause analysis and corrective action analysis. A root 
cause analysis and corrective action analysis must be completed as soon 
as possible, but no later than 45 days after a release event. Special 
circumstances affecting the number of root cause analyses and/or 
corrective action analyses are provided in paragraphs (j)(6)(i) through 
(iv) of this section.
    (i) You may conduct a single root cause analysis and corrective 
action analysis for a single emergency event that causes two or more 
pressure relief devices installed on the same equipment to release.
    (ii) You may conduct a single root cause analysis and corrective 
action analysis for a single emergency event that causes two or more 
pressure relief devices to release, regardless of the equipment served, 
if the root cause is reasonably expected to be a force majeure event, 
as defined in this subpart.
    (iii) Except as provided in paragraphs (j)(6)(i) and (ii) of this 
section, if more than one pressure relief device has a release during 
the same time period, an initial root cause analysis shall be conducted 
separately for each pressure relief device that had a release. If the 
initial root cause analysis indicates that the release events have the 
same root cause(s), the initially separate root cause analyses may be 
recorded as a single root cause analysis and a single corrective action 
analysis may be conducted.
    (7) Corrective action implementation. Each owner or operator 
required to conduct a root cause analysis and corrective action 
analysis as specified in paragraphs (j)(3)(iii) and (j)(6) of this 
section shall implement the corrective action(s) identified in the 
corrective action analysis in accordance with the applicable 
requirements in paragraphs (j)(7)(i) through (iii) of this section.
    (i) All corrective action(s) must be implemented within 45 days of 
the event for which the root cause and corrective action analyses were 
required or as soon thereafter as practicable. If an owner or operator 
concludes that no corrective action should be implemented, the owner or 
operator shall record and explain the basis for that conclusion no 
later than 45 days following the event.
    (ii) For corrective actions that cannot be fully implemented within 
45 days following the event for which the root cause and corrective 
action analyses were required, the owner or operator shall develop an 
implementation schedule to complete the corrective action(s) as soon as 
practicable.
    (iii) No later than 45 days following the event for which a root 
cause and corrective action analyses were required, the owner or 
operator shall record the corrective action(s) completed to date, and, 
for action(s) not already completed, a schedule for implementation, 
including proposed commencement and completion dates.

0
22. Section 63.649 is amended by revising definition of Cc 
term in the equation in paragraph (c)(6)(i) to read as follows:


Sec.  63.649  Alternative means of emission limitation: Connectors in 
gas/vapor service and light liquid service.

* * * * *
    (c) * * *
    (6) * * *
    (i) * * *

Cc = Optional credit for removed connectors = 0.67 x net 
number (i.e., the total number of connectors removed minus the total 
added) of connectors in organic HAP service removed from the process 
unit after the applicability date set forth in Sec.  
63.640(h)(3)(iii) for existing process units, and after the date of 
start-up for new process units. If credits are not taken, then 
Cc = 0.

* * * * *

0
23. Section 63.650 is amended by revising paragraph (a) and adding 
paragraph (d) to read as follows:


Sec.  63.650  Gasoline loading rack provisions.

    (a) Except as provided in paragraphs (b) through (d) of this 
section, each owner or operator of a Group 1 gasoline loading rack 
classified under Standard Industrial Classification code 2911 located 
within a contiguous area and under common control with a petroleum 
refinery shall comply with subpart R of this part, Sec. Sec.  63.421, 
63.422(a) through (c) and (e), 63.425(a) through (c) and (e) through 
(i), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), 
and (k).
* * * * *

[[Page 75246]]

    (d) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of subpart R of this part, or the requirements of Sec.  63.670.

0
24. Section 63.651 is amended by revising paragraphs (a) and (d) and 
adding paragraph (e) to read as follows:


Sec.  63.651  Marine tank vessel loading operation provisions.

    (a) Except as provided in paragraphs (b) through (e) of this 
section, each owner or operator of a marine tank vessel loading 
operation located at a petroleum refinery shall comply with the 
requirements of Sec. Sec.  63.560 through 63.568.
* * * * *
    (d) The compliance time of 4 years after promulgation of 40 CFR 
part 63, subpart Y, does not apply. The compliance time is specified in 
Sec.  63.640(h)(1).
    (e) If a flare is used as a control device, on and after January 
30, 2019, the flare shall meet the requirements of Sec.  63.670. Prior 
to January 30, 2019, the flare shall meet the applicable requirements 
of subpart Y of this part, or the requirements of Sec.  63.670.

0
25. Section 63.652 is amended by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (f)(2); and
0
c. Revising paragraphs (g)(2)(iii)(B)(1), (h)(3), (k) introductory 
text, and (k)(3).
    The revisions and additions read as follows:


Sec.  63.652  Emissions averaging provisions.

    (a) This section applies to owners or operators of existing sources 
who seek to comply with the emission standard in Sec.  63.642(g) by 
using emissions averaging according to Sec.  63.642(l) rather than 
following the provisions of Sec. Sec.  63.643 through 63.645, 63.646 or 
63.660, 63.647, 63.650, and 63.651. Existing marine tank vessel loading 
operations located at the Valdez Marine Terminal source may not comply 
with the standard by using emissions averaging.
* * * * *
    (g) * * *
    (2) * * *
    (iii) * * *
    (B) * * *
    (1) The percent reduction shall be measured according to the 
procedures in Sec.  63.116 of subpart G if a combustion control device 
is used. For a flare meeting the criteria in Sec.  63.116(a) of subpart 
G or Sec.  63.670, as applicable, or a boiler or process heater meeting 
the criteria in Sec.  63.645(d) or Sec.  63.116(b) of subpart G, the 
percentage of reduction shall be 98 percent. If a noncombustion control 
device is used, percentage of reduction shall be demonstrated by a 
performance test at the inlet and outlet of the device, or, if testing 
is not feasible, by a control design evaluation and documented 
engineering calculations.
* * * * *
    (h) * * *
    (3) Emissions from storage vessels shall be determined as specified 
in Sec.  63.150(h)(3) of subpart G, except as follows:
    (i) For storage vessels complying with Sec.  63.646:
    (A) All references to Sec.  63.119(b) in Sec.  63.150(h)(3) of 
subpart G shall be replaced with: Sec.  63.119(b) or Sec.  63.119(b) 
except for Sec.  63.119(b)(5) and (6).
    (B) All references to Sec.  63.119(c) in Sec.  63.150(h)(3) of 
subpart G shall be replaced with: Sec.  63.119(c) or Sec.  63.119(c) 
except for Sec.  63.119(c)(2).
    (C) All references to Sec.  63.119(d) in Sec.  63.150(h)(3) of 
subpart G shall be replaced with: Sec.  63.119(d) or Sec.  63.119(d) 
except for Sec.  63.119(d)(2).
    (ii) For storage vessels complying with Sec.  63.660:
    (A) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.  
63.1063(a)(1)(i) and (b) shall apply instead of Sec.  63.119(b) in 
Sec.  63.150(h)(3) of subpart G.
    (B) Section 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead 
of Sec.  63.119(c) in Sec.  63.150(h)(3) of subpart G.
    (C) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.  
63.1063(a)(1)(i) and (b) shall apply instead of Sec.  63.119(d) in 
Sec.  63.150(h)(3) of subpart G.
* * * * *
    (k) The owner or operator shall demonstrate that the emissions from 
the emission points proposed to be included in the average will not 
result in greater hazard or, at the option of the State or local 
permitting authority, greater risk to human health or the environment 
than if the emission points were controlled according to the provisions 
in Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, 
and 63.651, as applicable.
* * * * *
    (3) An emissions averaging plan that does not demonstrate an 
equivalent or lower hazard or risk to the satisfaction of the State or 
local permitting authority shall not be approved. The State or local 
permitting authority may require such adjustments to the emissions 
averaging plan as are necessary in order to ensure that the average 
will not result in greater hazard or risk to human health or the 
environment than would result if the emission points were controlled 
according to Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 
63.647, 63.650, and 63.651, as applicable.
* * * * *

0
26. Section 63.653 is amended by revising paragraphs (a) introductory 
text, (a)(3)(i) and (ii), and (a)(7) to read as follows:


Sec.  63.653  Monitoring, recordkeeping, and implementation plan for 
emissions averaging.

    (a) For each emission point included in an emissions average, the 
owner or operator shall perform testing, monitoring, recordkeeping, and 
reporting equivalent to that required for Group 1 emission points 
complying with Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 
63.647, 63.650, and 63.651, as applicable. The specific requirements 
for miscellaneous process vents, storage vessels, wastewater, gasoline 
loading racks, and marine tank vessels are identified in paragraphs 
(a)(1) through (7) of this section.
* * * * *
    (3) * * *
    (i) Perform the monitoring or inspection procedures in Sec.  63.646 
and either Sec.  63.120 of subpart G or Sec.  63.1063 of subpart WW, as 
applicable; and
    (ii) For closed vent systems with control devices, conduct an 
initial design evaluation as specified in Sec.  63.646 and either Sec.  
63.120(d) of subpart G or Sec.  63.985(b) of subpart SS, as applicable.
* * * * *
    (7) If an emission point in an emissions average is controlled 
using a pollution prevention measure or a device or technique for which 
no monitoring parameters or inspection procedures are specified in 
Sec. Sec.  63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 
63.651, as applicable, the owner or operator shall establish a site-
specific monitoring parameter and shall submit the information 
specified in Sec.  63.655(h)(4) in the Implementation Plan.
* * * * *

0
27. Section 63.655 is amended by:
0
a. Revising paragraphs (f) introductory text, (f)(1) introductory text, 
(f)(1)(i)(A) introductory text, (f)(1)(i)(A)(2) and (3), (f)(1)(i)(B) 
introductory text, (f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv) 
introductory text, and (f)(1)(iv)(A);
0
b. Adding paragraphs (f)(1)(vii) and (viii);
0
c. Revising paragraphs (f)(2) introductory text, (f)(3) introductory 
text, the first sentence of (f)(6), (g) introductory text, (g)(1) 
through (5), (g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i);

[[Page 75247]]

0
d. Adding paragraphs (g)(10) through (14);
0
e. Removing and reserving paragraph (h)(1);
0
f. Revising paragraphs (h)(2) introductory text, (h)(2)(i)(B), 
(h)(2)(ii), and (h)(5)(iii);
0
g. Adding paragraphs (h)(8) and (9) and (i) introductory text;
0
h. Revising paragraph (i)(1) introductory text and paragraph 
(i)(1)(ii);
0
i. Adding paragraphs (i)(1)(v) and (vi);
0
j. Redesignating paragraphs (i)(4) and (5) as paragraphs (i)(5) and 
(6), respectively;
0
k. Adding paragraph (i)(4);
0
l. Revising newly redesignated paragraph (i)(5) introductory text; and
0
m. Adding paragraphs (i)(7) through (12).
    The revisions and additions read as follows:


Sec.  63.655  Reporting and recordkeeping requirements.

* * * * *
    (f) Each owner or operator of a source subject to this subpart 
shall submit a Notification of Compliance Status report within 150 days 
after the compliance dates specified in Sec.  63.640(h) with the 
exception of Notification of Compliance Status reports submitted to 
comply with Sec.  63.640(l)(3) and for storage vessels subject to the 
compliance schedule specified in Sec.  63.640(h)(2). Notification of 
Compliance Status reports required by Sec.  63.640(l)(3) and for 
storage vessels subject to the compliance dates specified in Sec.  
63.640(h)(2) shall be submitted according to paragraph (f)(6) of this 
section. This information may be submitted in an operating permit 
application, in an amendment to an operating permit application, in a 
separate submittal, or in any combination of the three. If the required 
information has been submitted before the date 150 days after the 
compliance date specified in Sec.  63.640(h), a separate Notification 
of Compliance Status report is not required within 150 days after the 
compliance dates specified in Sec.  63.640(h). If an owner or operator 
submits the information specified in paragraphs (f)(1) through (5) of 
this section at different times, and/or in different submittals, later 
submittals may refer to earlier submittals instead of duplicating and 
resubmitting the previously submitted information. Each owner or 
operator of a gasoline loading rack classified under Standard 
Industrial Classification Code 2911 located within a contiguous area 
and under common control with a petroleum refinery subject to the 
standards of this subpart shall submit the Notification of Compliance 
Status report required by subpart R of this part within 150 days after 
the compliance dates specified in Sec.  63.640(h).
    (1) The Notification of Compliance Status report shall include the 
information specified in paragraphs (f)(1)(i) through (viii) of this 
section.
    (i) * * *
    (A) Identification of each storage vessel subject to this subpart, 
and for each Group 1 storage vessel subject to this subpart, the 
information specified in paragraphs (f)(1)(i)(A)(1) through (3) of this 
section. This information is to be revised each time a Notification of 
Compliance Status report is submitted for a storage vessel subject to 
the compliance schedule specified in Sec.  63.640(h)(2) or to comply 
with Sec.  63.640(l)(3).
* * * * *
    (2) For storage vessels subject to the compliance schedule 
specified in Sec.  63.640(h)(2) that are not complying with Sec.  
63.646, the anticipated compliance date.
    (3) For storage vessels subject to the compliance schedule 
specified in Sec.  63.640(h)(2) that are complying with Sec.  63.646 
and the Group 1 storage vessels described in Sec.  63.640(l), the 
actual compliance date.
    (B) If a closed vent system and a control device other than a flare 
is used to comply with Sec.  63.646 or Sec.  63.660, the owner or 
operator shall submit:
* * * * *
    (2) The design evaluation documentation specified in Sec.  
63.120(d)(1)(i) of subpart G or Sec.  63.985(b)(1)(i) of subpart SS (as 
applicable), if the owner or operator elects to prepare a design 
evaluation; or
* * * * *
    (D) * * *
    (2) All visible emission readings, heat content determinations, 
flow rate measurements, and exit velocity determinations made during 
the compliance determination required by Sec.  63.120(e) of subpart G 
or Sec.  63.987(b) of subpart SS or Sec.  63.670(h), as applicable; and
* * * * *
    (iv) For miscellaneous process vents controlled by flares, initial 
compliance test results including the information in paragraphs 
(f)(1)(iv)(A) and (B) of this section.
    (A) All visible emission readings, heat content determinations, 
flow rate measurements, and exit velocity determinations made during 
the compliance determination required by Sec. Sec.  63.645 and 
63.116(a) of subpart G or Sec.  63.670(h), as applicable; and
* * * * *
    (vii) For pressure relief devices in organic HAP service subject to 
the requirements in Sec.  63.648(j)(3)(i) and (ii), this report shall 
include the information specified in paragraphs (f)(1)(vii)(A) and (B) 
of this section.
    (A) A description of the monitoring system to be implemented, 
including the relief devices and process parameters to be monitored, 
and a description of the alarms or other methods by which operators 
will be notified of a pressure release.
    (B) A description of the prevention measures to be implemented for 
each affected pressure relief device.
    (viii) For each delayed coking unit, identification of whether the 
unit is an existing affected source or a new affected source and 
whether monitoring will be conducted as specified in Sec.  63.657(b) or 
(c).
    (2) If initial performance tests are required by Sec. Sec.  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, performance tests 
shall be submitted according to paragraph (h)(9) of this section.
* * * * *
    (3) For each monitored parameter for which a range is required to 
be established under Sec.  63.120(d) of subpart G or Sec.  63.985(b) of 
subpart SS for storage vessels or Sec.  63.644 for miscellaneous 
process vents, the Notification of Compliance Status report shall 
include the information in paragraphs (f)(3)(i) through (iii) of this 
section.
* * * * *
    (6) Notification of Compliance Status reports required by Sec.  
63.640(l)(3) and for storage vessels subject to the compliance dates 
specified in Sec.  63.640(h)(2) shall be submitted no later than 60 
days after the end of the 6-month period during which the change or 
addition was made that resulted in the Group 1 emission point or the 
existing Group 1 storage vessel was brought into compliance, and may be 
combined with the periodic report. * * *
    (g) The owner or operator of a source subject to this subpart shall 
submit Periodic Reports no later than 60 days after the end of each 6-
month period when any of the information specified in paragraphs (g)(1) 
through (7) of this section or paragraphs (g)(9) through (14) of this 
section is collected. The first 6-month period shall begin on the date 
the Notification of Compliance Status report is required to be 
submitted. A Periodic Report is not required if none of the events 
identified in paragraphs (g)(1)

[[Page 75248]]

through (7) of this section or paragraphs (g)(9) through (14) of this 
section occurred during the 6-month period unless emissions averaging 
is utilized. Quarterly reports must be submitted for emission points 
included in emission averages, as provided in paragraph (g)(8) of this 
section. An owner or operator may submit reports required by other 
regulations in place of or as part of the Periodic Report required by 
this paragraph (g) if the reports contain the information required by 
paragraphs (g)(1) through (14) of this section.
    (1) For storage vessels, Periodic Reports shall include the 
information specified for Periodic Reports in paragraphs (g)(2) through 
(5) of this section. Information related to gaskets, slotted membranes, 
and sleeve seals is not required for storage vessels that are part of 
an existing source complying with Sec.  63.646.
    (2) Internal floating roofs. (i) An owner or operator who elects to 
comply with Sec.  63.646 by using a fixed roof and an internal floating 
roof or by using an external floating roof converted to an internal 
floating roof shall submit the results of each inspection conducted in 
accordance with Sec.  63.120(a) of subpart G in which a failure is 
detected in the control equipment.
    (A) For vessels for which annual inspections are required under 
Sec.  63.120(a)(2)(i) or (a)(3)(ii) of subpart G, the specifications 
and requirements listed in paragraphs (g)(2)(i)(A)(1) through (3) of 
this section apply.
    (1) A failure is defined as any time in which the internal floating 
roof is not resting on the surface of the liquid inside the storage 
vessel and is not resting on the leg supports; or there is liquid on 
the floating roof; or the seal is detached from the internal floating 
roof; or there are holes, tears, or other openings in the seal or seal 
fabric; or there are visible gaps between the seal and the wall of the 
storage vessel.
    (2) Except as provided in paragraph (g)(2)(i)(A)(3) of this 
section, each Periodic Report shall include the date of the inspection, 
identification of each storage vessel in which a failure was detected, 
and a description of the failure. The Periodic Report shall also 
describe the nature of and date the repair was made or the date the 
storage vessel was emptied.
    (3) If an extension is utilized in accordance with Sec.  
63.120(a)(4) of subpart G, the owner or operator shall, in the next 
Periodic Report, identify the vessel; include the documentation 
specified in Sec.  63.120(a)(4) of subpart G; and describe the date the 
storage vessel was emptied and the nature of and date the repair was 
made.
    (B) For vessels for which inspections are required under Sec.  
63.120(a)(2)(ii), (a)(3)(i), or (a)(3)(iii) of subpart G (i.e., 
internal inspections), the specifications and requirements listed in 
paragraphs (g)(2)(i)(B)(1) and (2) of this section apply.
    (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.
    (2) Each Periodic Report shall include the date of the inspection, 
identification of each storage vessel in which a failure was detected, 
and a description of the failure. The Periodic Report shall also 
describe the nature of and date the repair was made.
    (ii) An owner or operator who elects to comply with Sec.  63.660 by 
using a fixed roof and an internal floating roof shall submit the 
results of each inspection conducted in accordance with Sec.  
63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is 
detected in the control equipment. For vessels for which inspections 
are required under Sec.  63.1063(c) and (d), the specifications and 
requirements listed in paragraphs (g)(2)(ii)(A) through (C) of this 
section apply.
    (A) A failure is defined in Sec.  63.1063(d)(1) of subpart WW.
    (B) Each Periodic Report shall include a copy of the inspection 
record required by Sec.  63.1065(b) of subpart WW when a failure 
occurs.
    (C) An owner or operator who elects to use an extension in 
accordance with Sec.  63.1063(e)(2) of subpart WW shall, in the next 
Periodic Report, submit the documentation required by Sec.  
63.1063(e)(2).
    (3) External floating roofs. (i) An owner or operator who elects to 
comply with Sec.  63.646 by using an external floating roof shall meet 
the periodic reporting requirements specified in paragraphs 
(g)(3)(i)(A) through (C) of this section.
    (A) The owner or operator shall submit, as part of the Periodic 
Report, documentation of the results of each seal gap measurement made 
in accordance with Sec.  63.120(b) of subpart G in which the seal and 
seal gap requirements of Sec.  63.120(b)(3), (4), (5), or (6) of 
subpart G are not met. This documentation shall include the information 
specified in paragraphs (g)(3)(i)(A)(1) through (4) of this section.
    (1) The date of the seal gap measurement.
    (2) The raw data obtained in the seal gap measurement and the 
calculations described in Sec.  63.120(b)(3) and (4) of subpart G.
    (3) A description of any seal condition specified in Sec.  
63.120(b)(5) or (6) of subpart G that is not met.
    (4) A description of the nature of and date the repair was made, or 
the date the storage vessel was emptied.
    (B) If an extension is utilized in accordance with Sec.  
63.120(b)(7)(ii) or (b)(8) of subpart G, the owner or operator shall, 
in the next Periodic Report, identify the vessel; include the 
documentation specified in Sec.  63.120(b)(7)(ii) or (b)(8) of subpart 
G, as applicable; and describe the date the vessel was emptied and the 
nature of and date the repair was made.
    (C) The owner or operator shall submit, as part of the Periodic 
Report, documentation of any failures that are identified during visual 
inspections required by Sec.  63.120(b)(10) of subpart G. This 
documentation shall meet the specifications and requirements in 
paragraphs (g)(3)(i)(C)(1) and (2) of this section.
    (1) A failure is defined as any time in which the external floating 
roof has defects; or the primary seal has holes or other openings in 
the seal or the seal fabric; or the secondary seal 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 10 percent 
open area.
    (2) Each Periodic Report shall include the date of the inspection, 
identification of each storage vessel in which a failure was detected, 
and a description of the failure. The Periodic Report shall also 
describe the nature of and date the repair was made.
    (ii) An owner or operator who elects to comply with Sec.  63.660 by 
using an external floating roof shall meet the periodic reporting 
requirements specified in paragraphs (g)(3)(ii)(A) and (B) of this 
section.
    (A) For vessels for which inspections are required under Sec.  
63.1063(c)(2), (d)(1), and (d)(3) of subpart WW, the owner or operator 
shall submit, as part of the Periodic Report, a copy of the inspection 
record required by Sec.  63.1065(b) of subpart WW when a failure 
occurs. A failure is defined in Sec.  63.1063(d)(1).

[[Page 75249]]

    (B) An owner or operator who elects to use an extension in 
accordance with Sec.  63.1063(e)(2) or (c)(2)(iv)(B) of subpart WW 
shall, in the next Periodic Report, submit the documentation required 
by those paragraphs.
    (4) [Reserved]
    (5) An owner or operator who elects to comply with Sec.  63.646 or 
Sec.  63.660 by installing a closed vent system and control device 
shall submit, as part of the next Periodic Report, the information 
specified in paragraphs (g)(5)(i) through (v) of this section, as 
applicable.
    (i) The Periodic Report shall include the information specified in 
paragraphs (g)(5)(i)(A) and (B) of this section for those planned 
routine maintenance operations that would require the control device 
not to meet the requirements of either Sec.  63.119(e)(1) or (2) of 
subpart G, Sec.  63.985(a) and (b) of subpart SS, or Sec.  63.670, as 
applicable.
    (A) A description of the planned routine maintenance that is 
anticipated to be performed for the control device during the next 6 
months. This description shall include the type of maintenance 
necessary, planned frequency of maintenance, and lengths of maintenance 
periods.
    (B) A description of the planned routine maintenance that was 
performed for the control device during the previous 6 months. This 
description shall include the type of maintenance performed and the 
total number of hours during those 6 months that the control device did 
not meet the requirements of either Sec.  63.119(e)(1) or (2) of 
subpart G, Sec.  63.985(a) and (b) of subpart SS, or Sec.  63.670, as 
applicable, due to planned routine maintenance.
    (ii) If a control device other than a flare is used, the Periodic 
Report shall describe each occurrence when the monitored parameters 
were outside of the parameter ranges documented in the Notification of 
Compliance Status report. The description shall include: Identification 
of the control device for which the measured parameters were outside of 
the established ranges, and causes for the measured parameters to be 
outside of the established ranges.
    (iii) If a flare is used prior to January 30, 2019 and prior to 
electing to comply with the requirements in Sec.  63.670, the Periodic 
Report shall describe each occurrence when the flare does not meet the 
general control device requirements specified in Sec.  63.11(b) of 
subpart A and shall include: Identification of the flare that does not 
meet the general requirements specified in Sec.  63.11(b) of subpart A, 
and reasons the flare did not meet the general requirements specified 
in Sec.  63.11(b) of subpart A.
    (iv) If a flare is used on or after the date for which compliance 
with the requirements in Sec.  63.670 is elected, which can be no later 
than January 30, 2019, the Periodic Report shall include the items 
specified in paragraph (g)(11) of this section.
    (v) An owner or operator who elects to comply with Sec.  63.660 by 
installing an alternate control device as described in Sec.  63.1064 of 
subpart WW shall submit, as part of the next Periodic Report, a written 
application as described in Sec.  63.1066(b)(3) of subpart WW.
    (6) * * *
    (i) * * *
    (D) For data compression systems under paragraph (h)(5)(iii) of 
this section, an operating day when the monitor operated for less than 
75 percent of the operating hours or a day when less than 18 monitoring 
values were recorded.
* * * * *
    (iii) For periods in closed vent systems when a Group 1 
miscellaneous process vent stream was detected in the bypass line or 
diverted from the control device and either directly to the atmosphere 
or to a control device that does not comply with the requirements in 
Sec.  63.643(a), report the date, time, duration, estimate of the 
volume of gas, the concentration of organic HAP in the gas and the 
resulting mass emissions of organic HAP that bypassed the control 
device. For periods when the flow indicator is not operating, report 
the date, time, and duration.
    (7) * * *
    (i) Results of the performance test shall include the 
identification of the source tested, the date of the test, the 
percentage of emissions reduction or outlet pollutant concentration 
reduction (whichever is needed to determine compliance) for each run 
and for the average of all runs, and the values of the monitored 
operating parameters.
* * * * *
    (10) For pressure relief devices subject to the requirements Sec.  
63.648(j), Periodic Reports must include the information specified in 
paragraphs (g)(10)(i) through (iii) of this section.
    (i) For pressure relief devices in organic HAP gas or vapor 
service, pursuant to Sec.  63.648(j)(1), report any instrument reading 
of 500 ppm or greater.
    (ii) For pressure relief devices in organic HAP gas or vapor 
service subject to Sec.  63.648(j)(2), report confirmation that any 
monitoring required to be done during the reporting period to show 
compliance was conducted.
    (iii) For pressure relief devices in organic HAP service subject to 
Sec.  63.648(j)(3), report each pressure release to the atmosphere, 
including duration of the pressure release and estimate of the mass 
quantity of each organic HAP released, and the results of any root 
cause analysis and corrective action analysis completed during the 
reporting period, including the corrective actions implemented during 
the reporting period and, if applicable, the implementation schedule 
for planned corrective actions to be implemented subsequent to the 
reporting period.
    (11) For flares subject to Sec.  63.670, Periodic Reports must 
include the information specified in paragraphs (g)(11)(i) through (iv) 
of this section.
    (i) Records as specified in paragraph (i)(9)(i) of this section for 
each 15-minute block during which there was at least one minute when 
regulated material is routed to a flare and no pilot flame is present.
    (ii) Visible emission records as specified in paragraph 
(i)(9)(ii)(C) of this section for each period of 2 consecutive hours 
during which visible emissions exceeded a total of 5 minutes.
    (iii) The 15-minute block periods for which the applicable 
operating limits specified in Sec.  63.670(d) through (f) are not met. 
Indicate the date and time for the period, the net heating value 
operating parameter(s) determined following the methods in Sec.  
63.670(k) through (n) as applicable.
    (iv) For flaring events meeting the criteria in Sec.  63.670(o)(3):
    (A) The start and stop time and date of the flaring event.
    (B) The length of time for which emissions were visible from the 
flare during the event.
    (C) The periods of time that the flare tip velocity exceeds the 
maximum flare tip velocity determined using the methods in Sec.  
63.670(d)(2) and the maximum 15-minute block average flare tip velocity 
recorded during the event.
    (D) Results of the root cause and corrective actions analysis 
completed during the reporting period, including the corrective actions 
implemented during the reporting period and, if applicable, the 
implementation schedule for planned corrective actions to be 
implemented subsequent to the reporting period.
    (12) For delayed coking units, the Periodic Report must include the 
information specified in paragraphs (g)(12)(i) through (iv) of this 
section.
    (i) For existing source delayed coking units, any 60-cycle average 
exceeding the applicable limit in Sec.  63.657(a)(1).
    (ii) For new source delayed coking units, any direct venting event

[[Page 75250]]

exceeding the applicable limit in Sec.  63.657(a)(2).
    (iii) The total number of double quenching events performed during 
the reporting period.
    (iv) For each double quenching draining event when the drain water 
temperature exceeded 210 [deg]F, report the drum, date, time, the coke 
drum vessel pressure or temperature, as applicable, when pre-vent 
draining was initiated, and the maximum drain water temperature during 
the pre-vent draining period.
    (13) For maintenance vents subject to the requirements in Sec.  
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 Sec.  63.643(c)(1). For the purposes 
of this reporting requirement, owners or operators complying with Sec.  
63.643(c)(1)(iv) must report each venting event for which the lower 
explosive limit is 20 percent or greater.
    (i) Identification of the maintenance vent and the equipment served 
by the maintenance vent.
    (ii) The date and time the maintenance vent was opened to the 
atmosphere.
    (iii) The lower explosive limit, vessel pressure, or mass of VOC in 
the equipment, as applicable, at the start of atmospheric venting. If 
the 5 psig vessel pressure option in Sec.  63.643(c)(1)(ii) was used 
and active purging was initiated while the lower explosive limit was 10 
percent or greater, also include the lower explosive limit of the 
vapors at the time active purging was initiated.
    (iv) An estimate of the mass of organic HAP released during the 
entire atmospheric venting event.
    (14) Any changes in the information provided in a previous 
Notification of Compliance Status report.
    (h) * * *
    (2) For storage vessels, notifications of inspections as specified 
in paragraphs (h)(2)(i) and (ii) of this section.
    (i) * * *
    (B) Except as provided in paragraph (h)(2)(i)(C) of this section, 
if the internal inspection required by Sec.  63.120(a)(2), (a)(3), or 
(b)(10) of subpart G or Sec.  63.1063(d)(1) of subpart WW is not 
planned and the owner or operator could not have known about the 
inspection 30 calendar days in advance of refilling the vessel with 
organic HAP, the owner or operator shall notify the Administrator at 
least 7 calendar days prior to refilling of the storage vessel. 
Notification may be made by telephone and immediately followed by 
written documentation demonstrating why the inspection was unplanned. 
This notification, including the written documentation, may also be 
made in writing and sent so that it is received by the Administrator at 
least 7 calendar days prior to the refilling.
* * * * *
    (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 
Sec.  63.120(b)(1) or (2) of subpart G or Sec.  63.1062(d)(3) of 
subpart WW. 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.
* * * * *
    (5) * * *
    (iii) An owner or operator may use an automated data compression 
recording system that does not record monitored operating parameter 
values at a set frequency (for example, once every hour) but records 
all values that meet set criteria for variation from previously 
recorded values.
    (A) The system shall be designed to:
    (1) Measure the operating parameter value at least once every hour.
    (2) Record at least 24 values each day during periods of operation.
    (3) Record the date and time when monitors are turned off or on.
    (4) Recognize unchanging data that may indicate the monitor is not 
functioning properly, alert the operator, and record the incident.
    (5) Compute daily average values of the monitored operating 
parameter based on recorded data.
    (B) 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 demonstrations that they 
system meets all criteria of paragraph (h)(5)(iii)(A) of this section.
* * * * *
    (8) For fenceline monitoring systems subject to Sec.  63.658, 
within 45 calendar days after the end of each quarterly reporting 
period covered by the periodic report, each owner or operator shall 
submit the following information to the EPA's Compliance and Emissions 
Data Reporting Interface (CEDRI). (CEDRI can be accessed through the 
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The owner or 
operator need not transmit this data prior to obtaining 12 months of 
data.
    (i) Individual sample results for each monitor for each sampling 
period during the quarterly reporting period. For the first reporting 
period and for any period in which a passive monitor is added or moved, 
the owner or operator shall report the coordinates of all of the 
passive monitor locations. 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.
    (ii) The biweekly annual average concentration difference 
([Delta]c) values for benzene for the quarterly reporting period.
    (iii) Notation for each biweekly value that indicates whether 
background correction was used, all measurements in the sampling period 
were below detection, or whether an outlier was removed from the 
sampling period data set.
    (9) On and after February 1, 2016, if required to submit the 
results of a performance test or CEMS performance evaluation, the owner 
or operator shall submit the results according to the procedures in 
paragraphs (h)(9)(i) and (ii) of this section.
    (i) 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.
    (A) For data collected using test methods supported by the EPA's 
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site 
(http://www.epa.gov/ttn/chief/ert/index.html) at the time of the test, 
the owner or operator must submit the results of the performance test 
to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's 
CDX.) Performance test data must be submitted in a file format 
generated through the use of the EPA's ERT or an alternate electronic 
file format consistent with the extensible markup language (XML) schema 
listed on the EPA's ERT Web site. If an owner or operator claims that 
some of the performance test information being submitted is 
confidential business information (CBI), the owner or operator must 
submit a complete file generated through the use of the EPA's ERT or an 
alternate electronic file consistent with the XML schema listed on the 
EPA's ERT Web site, including information claimed to be CBI, on a 
compact disc, flash drive or other commonly used electronic storage 
media to the EPA. The electronic storage media must be clearly marked 
as CBI and mailed to U.S. EPA/OAQPS/

[[Page 75251]]

CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD 
C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate 
file with the CBI omitted must be submitted to the EPA via the EPA's 
CDX as described earlier in this paragraph (h)(9)(i)(A).
    (B) For data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT Web site at the time of the 
test, the owner or operator must submit the results of the performance 
test to the Administrator at the appropriate address listed in Sec.  
63.13.
    (ii) 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.
    (A) For performance evaluations of continuous monitoring systems 
measuring relative accuracy test audit (RATA) pollutants that are 
supported by the EPA's ERT as listed on the EPA's ERT Web site at the 
time of the evaluation, the owner or operator must submit the results 
of the performance evaluation to the EPA via the CEDRI. (CEDRI can be 
accessed through the EPA's CDX.) Performance evaluation data must be 
submitted in a file format generated through the use of the EPA's ERT 
or an alternate file format consistent with the XML schema listed on 
the EPA's ERT Web site. If an owner or operator claims that some of the 
performance evaluation information being submitted is CBI, the owner or 
operator must submit a complete file generated through the use of the 
EPA's ERT or an alternate electronic file consistent with the XML 
schema listed on the EPA's ERT Web site, including information claimed 
to be CBI, on a compact disc, flash drive or other commonly used 
electronic storage media to the EPA. The electronic storage media must 
be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, 
Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old 
Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI 
omitted must be submitted to the EPA via the EPA's CDX as described 
earlier in this paragraph (h)(9)(ii)(A).
    (B) For any performance evaluations of continuous monitoring 
systems measuring RATA pollutants that are not supported by the EPA's 
ERT as listed on the EPA's ERT Web site at the time of the evaluation, 
the owner or operator must submit the results of the performance 
evaluation to the Administrator at the appropriate address listed in 
Sec.  63.13.
    (i) Recordkeeping. Each owner or operator of a source subject to 
this subpart shall keep copies of all applicable reports and records 
required by this subpart for at least 5 years except as otherwise 
specified in paragraphs (i)(1) through (12) of this section. All 
applicable records shall be maintained in such a manner that they can 
be readily accessed within 24 hours. Records may be maintained in hard 
copy or computer-readable form including, but not limited to, on paper, 
microfilm, computer, flash drive, floppy disk, magnetic tape, or 
microfiche.
    (1) Each owner or operator subject to the storage vessel provisions 
in Sec.  63.646 shall keep the records specified in Sec.  63.123 of 
subpart G except as specified in paragraphs (i)(1)(i) through (iv) of 
this section. Each owner or operator subject to the storage vessel 
provisions in Sec.  63.660 shall keep records as specified in 
paragraphs (i)(1)(v) and (vi) of this section.
* * * * *
    (ii) All references to Sec.  63.122 in Sec.  63.123 of subpart G 
shall be replaced with Sec.  63.655(e).
* * * * *
    (v) Each owner or operator of a Group 1 storage vessel subject to 
the provisions in Sec.  63.660 shall keep records as specified in Sec.  
63.1065 or Sec.  63.998, as applicable.
    (vi) Each owner or operator of a Group 2 storage vessel shall keep 
the records specified in Sec.  63.1065(a) of subpart WW. If a storage 
vessel is determined to be Group 2 because the weight percent total 
organic HAP of the stored liquid is less than or equal to 4 percent for 
existing sources or 2 percent for new sources, a record of any data, 
assumptions, and procedures used to make this determination shall be 
retained.
* * * * *
    (4) For each closed vent system that contains bypass lines that 
could divert a vent stream away from the control device and either 
directly to the atmosphere or to a control device that does not comply 
with the requirements in Sec.  63.643(a), the owner or operator shall 
keep a record of the information specified in either paragraph 
(i)(4)(i) or (ii) of this section, as applicable.
    (i) The owner or operator shall maintain records of periods when 
flow was detected in the bypass line, including the date and time and 
the duration of the flow in the bypass line. For each flow event, the 
owner or operator shall maintain records sufficient to determine 
whether or not the detected flow included flow of a Group 1 
miscellaneous process vent stream requiring control. For periods when 
the Group 1 miscellaneous process vent stream requiring control is 
diverted from the control device and released either directly to the 
atmosphere or to a control device that does not comply with the 
requirements in Sec.  63.643(a), the owner or operator shall include an 
estimate of the volume of gas, the concentration of organic HAP in the 
gas and the resulting emissions of organic HAP that bypassed the 
control device using process knowledge and engineering estimates.
    (ii) Where a seal mechanism is used to comply with Sec.  
63.644(c)(2), hourly records of flow are not required. In such cases, 
the owner or operator shall record the date that the monthly visual 
inspection of the seals or closure mechanisms is completed. The owner 
or operator shall also record the occurrence of all periods when the 
seal or closure mechanism is broken, the bypass line valve position has 
changed or the key for a lock-and-key type lock has been checked out. 
The owner or operator shall include an estimate of the volume of gas, 
the concentration of organic HAP in the gas and the resulting mass 
emissions of organic HAP from the Group 1 miscellaneous process vent 
stream requiring control that bypassed the control device or records 
sufficient to demonstrate that there was no flow of a Group 1 
miscellaneous process vent stream requiring control during the period.
    (5) The owner or operator of a heat exchange system subject to this 
subpart shall comply with the recordkeeping requirements in paragraphs 
(i)(5)(i) through (v) of this section and retain these records for 5 
years.
* * * * *
    (7) Each owner or operator subject to the delayed coking unit 
decoking operations provisions in Sec.  63.657 must maintain records 
specified in paragraphs (i)(7)(i) through (iii) of this section.
    (i) The average pressure or temperature, as applicable, for the 5-
minute period prior to venting to the atmosphere, draining, or 
deheading the coke drum for each cooling cycle for each coke drum.
    (ii) If complying with the 60-cycle rolling average, each 60-cycle 
rolling average pressure or temperature, as applicable, considering all 
coke drum venting events in the existing affected source.
    (iii) For double-quench cooling cycles:

[[Page 75252]]

    (A) The date, time and duration of each pre-vent draining event.
    (B) The pressure or temperature of the coke drum vessel, as 
applicable, for the 15 minute period prior to the pre-vent draining.
    (C) The drain water temperature at 1-minute intervals from the 
start of pre-vent draining to the complete closure of the drain valve.
    (8) For fenceline monitoring systems subject to Sec.  63.658, each 
owner or operator shall keep the records specified in paragraphs 
(i)(8)(i) through (x) of this section on an ongoing basis.
    (i) Coordinates of all passive monitors, including replicate 
samplers and field blanks, and if applicable, the meteorological 
station. The owner or operator shall determine the coordinates using an 
instrument with an accuracy of at least 3 meters. The coordinates shall 
be in decimal degrees with at least five decimal places.
    (ii) The start and stop times and dates for each sample, as well as 
the tube identifying information.
    (iii) Sampling period average temperature and barometric pressure 
measurements.
    (iv) For each outlier determined in accordance with Section 9.2 of 
Method 325A of appendix A of this part, the sampler location of and the 
concentration of the outlier and the evidence used to conclude that the 
result is an outlier.
    (v) For samples that will be adjusted for a background, the 
location of and the concentration measured simultaneously by the 
background sampler, and the perimeter samplers to which it applies.
    (vi) Individual sample results, the calculated [Delta]c for benzene 
for each sampling period and the two samples used to determine it, 
whether background correction was used, and the annual average [Delta]c 
calculated after each sampling period.
    (vii) Method detection limit for each sample, including co-located 
samples and blanks.
    (viii) Documentation of corrective action taken each time the 
action level was exceeded.
    (ix) Other records as required by Methods 325A and 325B of appendix 
A of this part.
    (x) If a near-field source correction is used as provided in Sec.  
63.658(i), records of hourly meteorological data, including 
temperature, barometric pressure, wind speed and wind direction, 
calculated daily unit vector wind direction and daily sigma theta, and 
other records specified in the site-specific monitoring plan.
    (9) For each flare subject to Sec.  63.670, each owner or operator 
shall keep the records specified in paragraphs (i)(9)(i) through (xii) 
of this section up-to-date and readily accessible, as applicable.
    (i) Retain records of the output of the monitoring device used to 
detect the presence of a pilot flame as required in Sec.  63.670(b) for 
a minimum of 2 years. Retain records of each 15-minute block during 
which there was at least one minute that no pilot flame is present when 
regulated material is routed to a flare for a minimum of 5 years.
    (ii) Retain records of daily visible emissions observations or 
video surveillance images required in Sec.  63.670(h) as specified in 
the paragraphs (i)(9)(ii)(A) through (C), as applicable, for a minimum 
of 3 years.
    (A) If visible emissions observations are performed using Method 22 
at 40 CFR part 60, appendix A-7, the record must identify whether the 
visible emissions observation was performed, the results of each 
observation, total duration of observed visible emissions, and whether 
it was a 5-minute or 2-hour observation. If the owner or operator 
performs visible emissions observations more than one time during a 
day, the record must also identify the date and time of day each 
visible emissions observation was performed.
    (B) If video surveillance camera is used, the record must include 
all video surveillance images recorded, with time and date stamps.
    (C) For each 2 hour period for which visible emissions are observed 
for more than 5 minutes in 2 consecutive hours, the record must include 
the date and time of the 2 hour period and an estimate of the 
cumulative number of minutes in the 2 hour period for which emissions 
were visible.
    (iii) The 15-minute block average cumulative flows for flare vent 
gas and, if applicable, total steam, perimeter assist air, and premix 
assist air specified to be monitored under Sec.  63.670(i), along with 
the date and time interval for the 15-minute block. If multiple 
monitoring locations are used to determine cumulative vent gas flow, 
total steam, perimeter assist air, and premix assist air, retain 
records of the 15-minute block average flows for each monitoring 
location for a minimum of 2 years, and retain the 15-minute block 
average cumulative flows that are used in subsequent calculations for a 
minimum of 5 years. If pressure and temperature monitoring is used, 
retain records of the 15-minute block average temperature, pressure and 
molecular weight of the flare vent gas or assist gas stream for each 
measurement location used to determine the 15-minute block average 
cumulative flows for a minimum of 2 years, and retain the 15-minute 
block average cumulative flows that are used in subsequent calculations 
for a minimum of 5 years.
    (iv) The flare vent gas compositions specified to be monitored 
under Sec.  63.670(j). Retain records of individual component 
concentrations from each compositional analyses for a minimum of 2 
years. If NHVvg analyzer is used, retain records of the 15-minute block 
average values for a minimum of 5 years.
    (v) Each 15-minute block average operating parameter calculated 
following the methods specified in Sec.  63.670(k) through (n), as 
applicable.
    (vi) [Reserved]
    (vii) All periods during which operating values are outside of the 
applicable operating limits specified in Sec.  63.670(d) through (f) 
when regulated material is being routed to the flare.
    (viii) All periods during which the owner or operator does not 
perform flare monitoring according to the procedures in Sec.  63.670(g) 
through (j).
    (ix) Records of periods when there is flow of vent gas to the 
flare, but when there is no flow of regulated material to the flare, 
including the start and stop time and dates of periods of no regulated 
material flow.
    (x) Records when the flow of vent gas exceeds the smokeless 
capacity of the flare, including start and stop time and dates of the 
flaring event.
    (xi) Records of the root cause analysis and corrective action 
analysis conducted as required in Sec.  63.670(o)(3), including an 
identification of the affected facility, the date and duration of the 
event, a statement noting whether the event resulted from the same root 
cause(s) identified in a previous analysis and either a description of 
the recommended corrective action(s) or an explanation of why 
corrective action is not necessary under Sec.  63.670(o)(5)(i).
    (xii) For any corrective action analysis for which implementation 
of corrective actions are required in Sec.  63.670(o)(5), a description 
of the corrective action(s) completed within the first 45 days 
following the discharge and, for action(s) not already completed, a 
schedule for implementation, including proposed commencement and 
completion dates.
    (10) [Reserved]
    (11) For each pressure relief device subject to the pressure 
release management work practice standards in Sec.  63.648(j)(3), the 
owner or operator shall keep the records specified in paragraphs 
(i)(11)(i) through (iii) of this section.
    (i) Records of the prevention measures implemented as required in 
Sec.  63.648(j)(3)(ii), if applicable.

[[Page 75253]]

    (ii) Records of the number of releases during each calendar year 
and the number of those releases for which the root cause was 
determined to be a force majeure event. Keep these records for the 
current calendar year and the past five calendar years.
    (iii) For each release to the atmosphere, the owner or operator 
shall keep the records specified in paragraphs (i)(11)(iii)(A) through 
(D) of this section.
    (A) The start and end time and date of each pressure release to the 
atmosphere.
    (B) Records of any data, assumptions, and calculations used to 
estimate of the mass quantity of each organic HAP released during the 
event.
    (C) Records of the root cause analysis and corrective action 
analysis conducted as required in Sec.  63.648(j)(3)(iii), including an 
identification of the affected facility, the date and duration of the 
event, a statement noting whether the event resulted from the same root 
cause(s) identified in a previous analysis and either a description of 
the recommended corrective action(s) or an explanation of why 
corrective action is not necessary under Sec.  63.648(j)(7)(i).
    (D) For any corrective action analysis for which implementation of 
corrective actions are required in Sec.  63.648(j)(7), a description of 
the corrective action(s) completed within the first 45 days following 
the discharge and, for action(s) not already completed, a schedule for 
implementation, including proposed commencement and completion dates.
    (12) For each maintenance vent opening subject to the requirements 
in Sec.  63.643(c), the owner or operator shall keep the applicable 
records specified in (i)(12)(i) through (v) of this section.
    (i) The owner or operator shall maintain standard site procedures 
used to deinventory equipment for safety purposes (e.g., hot work or 
vessel entry procedures) to document the procedures used to meet the 
requirements in Sec.  63.643(c). The current copy of the procedures 
shall be retained and available on-site at all times. Previous versions 
of the standard site procedures, is applicable, shall be retained for 
five years.
    (ii) If complying with the requirements of Sec.  63.643(c)(1)(i) 
and the lower explosive limit at the time of the vessel opening exceeds 
10 percent, identification of the maintenance vent, the process units 
or equipment associated with the maintenance vent, the date of 
maintenance vent opening, and the lower explosive limit at the time of 
the vessel opening.
    (iii) If complying with the requirements of Sec.  63.643(c)(1)(ii) 
and either the vessel pressure at the time of the vessel opening 
exceeds 5 psig or the lower explosive limit at the time of the active 
purging was initiated exceeds 10 percent, identification of the 
maintenance vent, the process units or equipment associated with the 
maintenance vent, the date of maintenance vent opening, the pressure of 
the vessel or equipment at the time of discharge to the atmosphere and, 
if applicable, the lower explosive limit of the vapors in the equipment 
when active purging was initiated.
    (iv) If complying with the requirements of Sec.  63.643(c)(1)(iii), 
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 
for each applicable maintenance vent opening.
    (v) If complying with the requirements of Sec.  63.643(c)(1)(iv), 
identification of the maintenance vent, the process units or equipment 
associated with the maintenance vent, records documenting the lack of a 
pure hydrogen supply, the date of maintenance vent opening, and the 
lower explosive limit of the vapors in the equipment at the time of 
discharge to the atmosphere for each applicable maintenance vent 
opening.

0
28. Section 63.656 is amended by revising paragraph (c)(1) to read as 
follows:


Sec.  63.656  Implementation and enforcement.

* * * * *
    (c) * * *
    (1) Approval of alternatives to the requirements in Sec. Sec.  
63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 63.654, 
63.657 through 63.660, and 63.670. Where these standards reference 
another subpart, the cited provisions will be delegated according to 
the delegation provisions of the referenced subpart. Where these 
standards reference another subpart and modify the requirements, the 
requirements shall be modified as described in this subpart. Delegation 
of the modified requirements will also occur according to the 
delegation provisions of the referenced subpart.
* * * * *

0
29. Section 63.657 is added to read as follows:


Sec.  63.657  Delayed coking unit decoking operation standards.

    (a) Except as provided in paragraphs (e) and (f) of this section, 
each owner or operator of a delayed coking unit shall depressure each 
coke drum to a closed blowdown system until the coke drum vessel 
pressure or temperature measured at the top of the coke drum or in the 
overhead line of the coke drum as near as practical to the coke drum 
meets the applicable limits specified in paragraph (a)(1) or (2) of 
this section prior to venting to the atmosphere, draining or deheading 
the coke drum at the end of the cooling cycle.
    (1) For delayed coking units at an existing affected source, meet 
either:
    (i) An average vessel pressure of 2 psig determined on a rolling 
60-event average; or
    (ii) An average vessel temperature of 220 degrees Fahrenheit 
determined on a rolling 60-event average.
    (2) For delayed coking units at a new affected source, meet either:
    (i) A vessel pressure of 2.0 psig for each decoking event; or
    (ii) A vessel temperature of 218 degrees Fahrenheit for each 
decoking event.
    (b) Each owner or operator of a delayed coking unit complying with 
the pressure limits in paragraph (a)(1)(i) or (a)(2)(i) of this section 
shall install, operate, calibrate, and maintain a monitoring system, as 
specified in paragraphs (b)(1) through (5) of this section, to 
determine the coke drum vessel pressure.
    (1) The pressure monitoring system must be in a representative 
location (at the top of the coke drum or in the overhead line as near 
as practical to the coke drum) that minimizes or eliminates pulsating 
pressure, vibration, and, to the extent practical, internal and 
external corrosion.
    (2) The pressure monitoring system must be capable of measuring a 
pressure of 2.0 psig within 0.5 psig.
    (3) The pressure monitoring system must be verified annually or at 
the frequency recommended by the instrument manufacturer. The pressure 
monitoring system must be verified following any period of more than 24 
hours throughout which the pressure exceeded the maximum rated pressure 
of the sensor, or the data recorder was off scale.
    (4) All components of the pressure monitoring system must be 
visually inspected for integrity, oxidation and galvanic corrosion 
every 3 months, unless the system has a redundant pressure sensor.
    (5) The output of the pressure monitoring system must be reviewed

[[Page 75254]]

daily 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.
    (c) Each owner or operator of a delayed coking unit complying with 
the temperature limits in paragraph (a)(1)(ii) or (a)(2)(ii) of this 
section shall install, operate, calibrate, and maintain a continuous 
parameter monitoring system to measure the coke drum vessel temperature 
(at the top of the coke drum or in the overhead line as near as 
practical to the coke drum) according to the requirements specified in 
table 13 of this subpart.
    (d) The owner or operator of a delayed coking unit shall determine 
the coke drum vessel pressure or temperature, as applicable, on a 5-
minute rolling average basis while the coke drum is vented to the 
closed blowdown system and shall use the last complete 5-minute rolling 
average pressure or temperature just prior to initiating steps to 
isolate the coke drum prior to venting, draining or deheading to 
demonstrate compliance with the requirements in paragraph (a) of this 
section. Pressure or temperature readings after initiating steps to 
isolate the coke drum from the closed blowdown system just prior to 
atmospheric venting, draining, or deheading the coke drum shall not be 
used in determining the average coke drum vessel pressure or 
temperature for the purpose of compliance with the requirements in 
paragraph (a) of this section.
    (e) The owner or operator of a delayed coking unit using the 
``water overflow'' method of coke cooling must hardpipe the overflow 
water 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 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. The owner or operator of a delayed coking unit using the 
``water overflow'' method of coke cooling shall determine the coke drum 
vessel temperature as specified in paragraphs (c) and (d) of this 
section regardless of the compliance method used to demonstrate 
compliance with the requirements in paragraph (a) of this section.
    (f) The owner or operator of a delayed coking unit may partially 
drain a coke drum prior to achieving the applicable limits in paragraph 
(a) of this section in order to double-quench a coke drum that did not 
cool adequately using the normal cooling process steps provided that 
the owner or operator meets the conditions in paragraphs (f)(1) and (2) 
of this section.
    (1) The owner or operator shall install, operate, calibrate, and 
maintain a continuous parameter monitoring system to measure the drain 
water temperature at the bottom of the coke drum or in the drain line 
as near as practical to the coke drum according to the requirements 
specified in table 13 of this subpart.
    (2) The owner or operator must maintain the drain water temperature 
below 210 degrees Fahrenheit during the partial drain associated with 
the double-quench event.

0
30. Section 63.658 is added to read as follows:


Sec.  63.658  Fenceline monitoring provisions.

    (a) The owner or operator shall conduct sampling along the facility 
property boundary and analyze the samples in accordance with Methods 
325A and 325B of appendix A of this part and paragraphs (b) through (k) 
of this section.
    (b) The target analyte is benzene.
    (c) The owner or operator shall determine passive monitor locations 
in accordance with Section 8.2 of Method 325A of appendix A of this 
part.
    (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 treatment unit, process unit, or 
any emission source requiring control according to the requirements of 
this subpart, including marine vessel loading operations. For marine 
loading operations that are located offshore, one passive monitor 
should be sited on the shoreline adjacent to the dock.
    (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 Sec.  63.640(g) may influence the 
sampler measurements. If the owner or operator elects to collect one or 
more background samples, the owner of 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) The owner or operator shall collect at least one co-located 
duplicate sample for every 10 field samples per sampling period and at 
least two field blanks per sampling period, as described in Section 9.3 
in Method 325A of appendix A of this part. The co-located duplicates 
may be collected at any one of the perimeter sampling locations.
    (4) The owner or operator shall follow the procedure in Section 9.6 
of Method 325B of appendix A of this part to determine the detection 
limit of benzene for each sampler used to collect samples, background 
samples (if the owner or operator elects to do so), co-located samples 
and blanks.
    (d) The owner or operator shall collect and record meteorological 
data according to the applicable requirements in paragraphs (d)(1) 
through (3) of this section.
    (1) If a near-field source correction is used as provided in 
paragraph (i)(1) of this section or if an alternative test method is 
used that provides time-resolved measurements, the owner or operator 
shall:
    (i) Use an on-site meteorological station in accordance with 
Section 8.3 of Method 325A of appendix A of this part.
    (ii) Collect and record hourly average meteorological data, 
including temperature, barometric pressure, wind speed and wind 
direction and calculate daily unit vector wind direction and daily 
sigma theta.
    (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 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.
    (3) If an on-site meteorological station is used, the owner or 
operator shall follow the calibration and standardization procedures 
for meteorological measurements in EPA-454/B-08-002 (incorporated by 
reference--see Sec.  63.14).
    (e) The owner of operator shall use a sampling period and sampling 
frequency as specified in paragraphs (e)(1) through (3) of this 
section.
    (1) Sampling period. A 14-day sampling period shall be used, unless 
a shorter sampling period is determined to be necessary under paragraph 
(g) or (i) of this section. A sampling period is defined as the period 
during which sampling tube is deployed at a specific sampling location 
with the diffusive

[[Page 75255]]

sampling end cap in-place and does not include the time required to 
analyze the sample. For the purpose of this subpart, a 14-day sampling 
period may be no shorter than 13 calendar days and no longer than 15 
calendar days, but the routine sampling period shall be 14 calendar 
days.
    (2) Base sampling frequency. Except as provided in paragraph (e)(3) 
of this section, the frequency of sample collection shall be once each 
contiguous 14-day sampling period, such that the beginning of the next 
14-day sampling period begins immediately upon the completion of the 
previous 14-day sampling period.
    (3) Alternative sampling frequency for burden reduction. When an 
individual monitor consistently achieves results at or below 0.9 [mu]g/
m\3\, the owner or operator may elect to use the applicable minimum 
sampling frequency specified in paragraphs (e)(3)(i) through (v) of 
this section for that monitoring site. When calculating [Delta]c for 
the monitoring period when using this alternative for burden reduction, 
zero shall be substituted for the sample result for the monitoring site 
for any period where a sample is not taken.
    (i) If every sample at a monitoring site is at or below 0.9 [mu]g/
m3 for 2 years (52 consecutive samples), every other 
sampling period can be skipped for that monitoring site, i.e., sampling 
will occur approximately once per month.
    (ii) If every sample at a monitoring site that is monitored at the 
frequency specified in paragraph (e)(3)(i) of this section is at or 
below 0.9 [mu]g/m3 for 2 years (i.e., 26 consecutive 
``monthly'' samples), five 14-day sampling periods can be skipped for 
that monitoring site following each period of sampling, i.e., sampling 
will occur approximately once per quarter.
    (iii) If every sample at a monitoring site that is monitored at the 
frequency specified in paragraph (e)(3)(ii) of this section is at or 
below 0.9 [mu]g/m3 for 2 years (i.e., 8 consecutive 
quarterly samples), twelve 14-day sampling periods can be skipped for 
that monitoring site following each period of sampling, i.e., sampling 
will occur twice a year.
    (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 [mu]g/m3 for an 2 years (i.e., 4 consecutive semi-
annual 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.
    (v) If at any time a sample for a monitoring site that is monitored 
at the frequency specified in paragraphs (e)(3)(i) through (iv) of this 
section returns a result that is above 0.9 [mu]g/m\3\, the sampling 
site must return to the original sampling requirements of contiguous 
14-day sampling periods with no skip periods for one quarter (six 14-
day sampling periods). If every sample collected during this quarter is 
at or below 0.9 [mu]g/m3 , the owner or operator may revert 
back to the reduced monitoring schedule applicable for that monitoring 
site prior to the sample reading exceeding 0.9 [mu]g/m3 If 
any sample collected during this quarter is above 0.9 [mu]g/m\3\, that 
monitoring site must return to the original sampling requirements of 
contiguous 14-day sampling periods with no skip periods for a minimum 
of two years. The burden reduction requirements can be used again for 
that monitoring site once the requirements of paragraph (e)(3)(i) of 
this section are met again, i.e., after 52 contiguous 14-day samples 
with no results above 0.9 [mu]g/m3 .
    (f) Within 45 days of completion of each sampling period, the owner 
or operator shall determine whether the results are above or below the 
action level as follows:
    (1) The owner or operator shall determine the facility impact on 
the benzene concentration ([Delta]c) for each 14-day sampling period 
according to either paragraph (f)(1)(i) or (ii) of this section, as 
applicable.
    (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 [Delta]c as the difference in these 
concentrations. 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:
    (A) If the lowest detected value of benzene is below detection, the 
owner or operator shall use zero as the lowest sample result when 
calculating [Delta]c.
    (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.
    (ii) When near-field source correction is used as provided in 
paragraph (i) of this section, the owner or operator shall determine 
[Delta]c using the calculation protocols outlined in the approved site-
specific monitoring plan and in paragraph (i) of this section.
    (2) The owner or operator shall calculate the annual average 
[Delta]c based on the average of the 26 most recent 14-day sampling 
periods. The owner or operator shall update this annual average value 
after receiving the results of each subsequent 14-day sampling period.
    (3) The action level for benzene is 9 micrograms per cubic meter 
([mu]g/m3) on an annual average basis. If the annual average [Delta]c 
value for benzene is less than or equal to 9 [mu]g/m\3\, the 
concentration is below the action level. If the annual average [Delta]c 
value for benzene is greater than 9 [mu]g/m\3\, the concentration is 
above the action level, and the owner or operator shall conduct a root 
cause analysis and corrective action in accordance with paragraph (g) 
of this section.
    (g) Within 5 days of determining that the action level has been 
exceeded for any annual average [Delta]c and no longer than 50 days 
after completion of the sampling period, the owner or operator shall 
initiate a root cause analysis to determine the cause of such 
exceedance and to determine appropriate corrective action, such as 
those described in paragraphs (g)(1) through (4) of this section. The 
root cause analysis and initial corrective action analysis shall be 
completed and initial corrective actions taken no later than 45 days 
after determining there is an exceedance. Root cause analysis and 
corrective action may include, but is not limited to:
    (1) Leak inspection using Method 21 of part 60, appendix A-7 of 
this chapter and repairing any leaks found.
    (2) Leak inspection using optical gas imaging and repairing any 
leaks found.
    (3) Visual inspection to determine the cause of the high benzene 
emissions and implementing repairs to reduce the level of emissions.
    (4) Employing progressively more frequent sampling, analysis and 
meteorology (e.g., using shorter sampling periods for Methods 325A and 
325B of appendix A of this part, or using active sampling techniques).
    (h) If, upon completion of the corrective action analysis and 
corrective actions such as those described in paragraph (g) of this 
section, the [Delta]c value for the next 14-day sampling period for 
which the sampling start time begins after the completion of the 
corrective actions is greater than 9 [mu]g/m\3\ or if all corrective 
action measures identified require more than 45 days to implement, the 
owner or operator shall develop a corrective action plan that describes 
the corrective action(s) completed to date, additional measures that 
the owner or operator proposes to employ to reduce fenceline 
concentrations below the action level, and a schedule for completion of 
these measures. The owner or operator shall submit the corrective 
action plan to the

[[Page 75256]]

Administrator within 60 days after receiving the analytical results 
indicating that the [Delta]c value for the 14-day sampling period 
following the completion of the initial corrective action is greater 
than 9 [mu]g/m\3\ or, if no initial corrective actions were identified, 
no later than 60 days following the completion of the corrective action 
analysis required in paragraph (g) of this section.
    (i) An owner or operator may request approval from the 
Administrator for a site-specific monitoring plan to account for 
offsite upwind sources or onsite sources excluded under Sec.  63.640(g) 
according to the requirements in paragraphs (i)(1) through (4) of this 
section.
    (1) The owner or operator shall prepare and submit a site-specific 
monitoring plan and receive approval of the site-specific monitoring 
plan prior to using the near-field source alternative calculation for 
determining [Delta]c provided in paragraph (i)(2) of this section. The 
site-specific monitoring plan shall include, at a minimum, the elements 
specified in paragraphs (i)(1)(i) through (v) of this section. The 
procedures in Section 12 of Method 325A of appendix A of this part are 
not required, but may be used, if applicable, when determining near-
field source contributions.
    (i) Identification of the near-field source or sources. For onsite 
sources, documentation that the onsite source is excluded under Sec.  
63.640(g) and identification of the specific provision in Sec.  
63.640(g) that applies to the source.
    (ii) Location of the additional monitoring stations that shall be 
used to determine the uniform background concentration and the near-
field source concentration contribution.
    (iii) Identification of the fenceline monitoring locations impacted 
by the near-field source. If more than one near-field source is 
present, identify the near-field source or sources that are expected to 
contribute to the concentration at that monitoring location.
    (iv) A description of (including sample calculations illustrating) 
the planned data reduction and calculations to determine the near-field 
source concentration contribution for each monitoring location.
    (v) If more frequent monitoring or a monitoring station other than 
a passive diffusive tube monitoring station is proposed, provide a 
detailed description of the measurement methods, measurement frequency, 
and recording frequency for determining the uniform background or near-
field source concentration contribution.
    (2) When an approved site-specific monitoring plan is used, the 
owner or operator shall determine [Delta]c for comparison with the 9 
[mu]g/m\3\ action level using the requirements specified in paragraphs 
(i)(2)(i) through (iii) of this section.
    (i) For each monitoring location, calculate [Delta]ci 
using the following equation.

[Delta]ci = MFCi - NFSi - UB

Where:

[Delta]ci = The fenceline concentration, corrected for 
background, at measurement location i, micrograms per cubic meter 
([mu]g/m\3\).
MFCi = The measured fenceline concentration at 
measurement location i, [mu]g/m\3\.
NFSi = The near-field source contributing concentration 
at measurement location i determined using the additional 
measurements and calculation procedures included in the site-
specific monitoring plan, [mu]g/m\3\. For monitoring locations that 
are not included in the site-specific monitoring plan as impacted by 
a near-field source, use NFSi = 0 [mu]g/m\3\.
UB = The uniform background concentration determined using the 
additional measurements included in the site-specific monitoring 
plan, [mu]g/m\3\. If no additional measurements are specified in the 
site-specific monitoring plan for determining the uniform background 
concentration, use UB = 0 [mu]g/m\3\.

    (ii) When one or more samples for the sampling period are below the 
method detection limit for benzene, adhere to the following procedures:
    (A) If the benzene concentration at the monitoring location used 
for the uniform background concentration is below the method detection 
limit, the owner or operator shall use zero for UB for that monitoring 
period.
    (B) If the benzene concentration at the monitoring location(s) used 
to determine the near-field source contributing concentration is below 
the method detection limit, the owner or operator shall use zero for 
the monitoring location concentration when calculating NFSi 
for that monitoring period.
    (C) If a fenceline monitoring location sample result is below the 
method detection limit, the owner or operator shall use the method 
detection limit as the sample result.
    (iii) Determine [Delta]c for the monitoring period as the maximum 
value of [Delta]ci from all of the fenceline monitoring 
locations for that monitoring period.
    (3) The site-specific monitoring plan shall be submitted and 
approved as described in paragraphs (i)(3)(i) through (iv) of this 
section.
    (i) The site-specific monitoring plan must be submitted to the 
Administrator for approval.
    (ii) The site-specific monitoring plan shall also be submitted to 
the following address: U.S. Environmental Protection Agency, Office of 
Air Quality Planning and Standards, Sector Policies and Programs 
Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead, 
109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic 
copies in lieu of hard copies may also be submitted to 
[email protected].
    (iii) The Administrator shall approve or disapprove the plan in 90 
days. The plan shall be considered approved if the Administrator either 
approves the plan in writing, or fails to disapprove the plan in 
writing. The 90-day period shall begin when the Administrator receives 
the plan.
    (iv) If the Administrator finds any deficiencies in the site-
specific monitoring plan and disapproves the plan in writing, the owner 
or operator may revise and resubmit the site-specific monitoring plan 
following the requirements in paragraphs (i)(3)(i) and (ii) of this 
section. The 90-day period starts over with the resubmission of the 
revised monitoring plan.
    (4) The approval by the Administrator of a site-specific monitoring 
plan will be based on the completeness, accuracy and reasonableness of 
the request for a site-specific monitoring plan. Factors that the 
Administrator will consider in reviewing the request for a site-
specific monitoring plan include, but are not limited to, those 
described in paragraphs (i)(4)(i) through (v) of this section.
    (i) The identification of the near-field source or sources. For 
onsite sources, the documentation provided that the onsite source is 
excluded under Sec.  63.640(g).
    (ii) The monitoring location selected to determine the uniform 
background concentration or an indication that no uniform background 
concentration monitor will be used.
    (iii) The location(s) selected for additional monitoring to 
determine the near-field source concentration contribution.
    (iv) The identification of the fenceline monitoring locations 
impacted by the near-field source or sources.
    (v) The appropriateness of the planned data reduction and 
calculations to determine the near-field source concentration 
contribution for each monitoring location.
    (vi) If more frequent monitoring is proposed, the adequacy of the 
description of the measurement and

[[Page 75257]]

recording frequency proposed and the adequacy of the rationale for 
using the alternative monitoring frequency.
    (j) The owner or operator shall comply with the applicable 
recordkeeping and reporting requirements in Sec.  63.655(h) and (i).
    (k) As outlined in Sec.  63.7(f), the owner or operator may submit 
a request for an alternative test method. At a minimum, the request 
must follow the requirements outlined in paragraphs (k)(1) through (7) 
of this section.
    (1) The alternative method may be used in lieu of all or a partial 
number of passive samplers required in Method 325A of appendix A of 
this part.
    (2) The alternative method must be validated according to Method 
301 in appendix A of this part or contain performance based procedures 
and indicators to ensure self-validation.
    (3) The method detection limit must nominally be at least an order 
of magnitude below the action level, i.e., 0.9 [micro]g/m3 
benzene. The alternate test method must describe the procedures used to 
provide field verification of the detection limit.
    (4) The spatial coverage must be equal to or better than the 
spatial coverage provided in Method 325A of appendix A of this part.
    (i) For path average concentration open-path instruments, the 
physical path length of the measurement shall be no more than a passive 
sample footprint (the spacing that would be provided by the sorbent 
traps when following Method 325A). For example, if Method 325A requires 
spacing monitors A and B 610 meters (2000 feet) apart, then the 
physical path length limit for the measurement at that portion of the 
fenceline shall be no more than 610 meters (2000 feet).
    (ii) For range resolved open-path instrument or approach, the 
instrument or approach must be able to resolve an average concentration 
over each passive sampler footprint within the path length of the 
instrument.
    (iii) The extra samplers required in Sections 8.2.1.3 of Method 
325A may be omitted when they fall within the path length of an open-
path instrument.
    (5) At a minimum, non-integrating alternative test methods must 
provide a minimum of one cycle of operation (sampling, analyzing, and 
data recording) for each successive 15-minute period.
    (6) For alternative test methods capable of real time measurements 
(less than a 5 minute sampling and analysis cycle), the alternative 
test method may allow for elimination of data points corresponding to 
outside emission sources for purpose of calculation of the high point 
for the two week average. The alternative test method approach must 
have wind speed, direction and stability class of the same time 
resolution and within the footprint of the instrument.
    (7) For purposes of averaging data points to determine the [Delta]c 
for the 14-day average high sample result, all results measured under 
the method detection limit must use the method detection limit. For 
purposes of averaging data points for the 14-day average low sample 
result, all results measured under the method detection limit must use 
zero.

0
31. Section 63.660 is added to read as follows:


Sec.  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 Sec.  
63.640(h), the owner or operator of a Group 1 storage vessel that is 
part of a new or existing source shall comply with the requirements in 
subpart WW or SS of this part according to the requirements in 
paragraphs (a) through (i) of this section.
    (a) As used in this section, all terms not defined in Sec.  63.641 
shall have the meaning given them in subpart A, WW, or SS of this part. 
The definitions of ``Group 1 storage vessel'' (paragraph (2)) and 
``Storage vessel'' in Sec.  63.641 shall apply in lieu of the 
definition of ``Storage vessel'' in Sec.  63.1061.
    (1) An owner or operator may use good engineering judgment or test 
results to determine the stored liquid weight percent total organic HAP 
for purposes of group determination. Data, assumptions, and procedures 
used in the determination shall be documented.
    (2) When an owner or operator and the Administrator do not agree on 
whether the annual average weight percent organic HAP in the stored 
liquid is above or below 4 percent for a storage vessel at an existing 
source or above or below 2 percent for a storage vessel at a new 
source, an appropriate method (based on the type of liquid stored) as 
published by EPA or a consensus-based standards organization shall be 
used. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International (100 Barr Harbor Drive, 
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute 
(ANSI, 1819 L Street NW., 6th Floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400 
North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.naesb.org).
    (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.
    (1) In addition to the options presented in Sec. Sec.  
63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage 
vessel may comply with Sec.  63.1063(a)(2)(vii) using a flexible 
enclosure device and either a gasketed or welded cap on the top of the 
guidepole.
    (2) Each opening through a floating roof for a ladder having at 
least one slotted leg shall be equipped with one of the configurations 
specified in paragraphs (b)(2)(i) through (iii) of this section.
    (i) A pole float in the slotted leg and pole wipers for both legs. 
The wiper or seal of the pole float must be at or above the height of 
the pole wiper.
    (ii) A ladder sleeve and pole wipers for both legs of the ladder.
    (iii) A flexible enclosure device and either a gasketed or welded 
cap on the top of the slotted leg.
    (c) For the purposes of this subpart, references shall apply as 
specified in paragraphs (c)(1) through (6) of this section.
    (1) All references to ``the proposal date for a referencing 
subpart'' and ``the proposal date of the referencing subpart'' in 
subpart WW of this part mean June 30, 2014.
    (2) All references to ``promulgation of the referencing subpart'' 
and ``the promulgation date of the referencing subpart'' in subpart WW 
of this part mean February 1, 2016.
    (3) All references to ``promulgation date of standards for an 
affected source or affected facility under a referencing subpart'' in 
subpart SS of this part mean February 1, 2016.
    (4) All references to ``the proposal date of the relevant standard 
established pursuant to CAA section 112(f)'' in

[[Page 75258]]

subpart SS of this part mean June 30, 2014.
    (5) All references to ``the proposal date of a relevant standard 
established pursuant to CAA section 112(d)'' in subpart SS of this part 
mean July 14, 1994.
    (6) All references to the ``required control efficiency'' in 
subpart SS of this part mean reduction of organic HAP emissions by 95 
percent or to an outlet concentration of 20 ppmv.
    (d) For an uncontrolled fixed roof storage vessel that commenced 
construction on or before June 30, 2014, and that meets the definition 
of ``Group 1 storage vessel'', paragraph (2), in Sec.  63.641 but not 
the definition of ``Group 1 storage vessel'', paragraph (1), in Sec.  
63.641, the requirements of Sec.  63.982 and/or Sec.  63.1062 do not 
apply until the next time the storage vessel is completely emptied and 
degassed, or January 30, 2026, whichever occurs first.
    (e) Failure to perform inspections and monitoring required by this 
section shall constitute a violation of the applicable standard of this 
subpart.
    (f) References in Sec.  63.1066(a) to initial startup notification 
requirements do not apply.
    (g) References to the Notification of Compliance Status in Sec.  
63.999(b) mean the Notification of Compliance Status required by Sec.  
63.655(f).
    (h) References to the Periodic Reports in Sec. Sec.  63.1066(b) and 
63.999(c) mean the Periodic Report required by Sec.  63.655(g).
    (i) Owners or operators electing to comply with the requirements in 
subpart SS of this part for a Group 1 storage vessel must comply with 
the requirements in paragraphs (i)(1) through (3) of this section.
    (1) If a flare is used as a control device, the flare shall meet 
the requirements of Sec.  63.670 instead of the flare requirements in 
Sec.  63.987.
    (2) If a closed vent system contains a bypass line, the owner or 
operator shall comply with the provisions of either Sec.  
63.983(a)(3)(i) or (ii) 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 to 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 
Sec.  63.648 are not subject to this paragraph (i)(2).
    (i) If planned routine maintenance of the control device cannot be 
performed during periods that storage vessel emissions are vented to 
the control device or when the storage vessel is taken out of service 
for inspections or other planned maintenance reasons, the owner or 
operator may bypass the control device.
    (ii) Periods for which storage vessel control device may be 
bypassed for planned routine maintenance of the control device shall 
not exceed 240 hours per calendar year.
    (3) If storage vessel emissions are routed to a fuel gas system or 
process, the fuel gas system or process shall be operating at all times 
when regulated emissions are routed to it. The exception in Sec.  
63.984(a)(1) does not apply.

0
32. Section 63.670 is added to read as follows:


Sec.  63.670  Requirements for flare control devices.

    On or before January 30, 2019, the owner or operator of a flare 
used as a control device for an emission point subject to this subpart 
shall meet the applicable requirements for flares as specified in 
paragraphs (a) through (q) of this section and the applicable 
requirements in Sec.  63.671. The owner or operator may elect to comply 
with the requirements of paragraph (r) of this section in lieu of the 
requirements in paragraphs (d) through (f) of this section, as 
applicable.
(a) [Reserved]
    (b) Pilot flame presence. The owner or operator shall operate each 
flare with a pilot flame present at all times when regulated material 
is routed to the flare. Each 15-minute block during which there is at 
least one minute where no pilot flame is present when regulated 
material is routed to the flare is a deviation of the standard. 
Deviations in different 15-minute blocks from the same event are 
considered separate deviations. The owner or operator shall monitor for 
the presence of a pilot flame as specified in paragraph (g) of this 
section.
    (c) Visible emissions. The owner or operator shall specify the 
smokeless design capacity of each flare and operate with no visible 
emissions, except for periods not to exceed a total of 5 minutes during 
any 2 consecutive hours, when regulated material is routed to the flare 
and the flare vent gas flow rate is less than the smokeless design 
capacity of the flare. The owner or operator shall monitor for visible 
emissions from the flare as specified in paragraph (h) of this section.
    (d) Flare tip velocity. For each flare, the owner or operator shall 
comply with either paragraph (d)(1) or (2) of this section, provided 
the appropriate monitoring systems are in-place, whenever regulated 
material is routed to the flare for at least 15-minutes and the flare 
vent gas flow rate is less than the smokeless design capacity of the 
flare.
    (1) Except as provided in paragraph (d)(2) of this section, the 
actual flare tip velocity (Vtip) must be less than 60 feet 
per second. The owner or operator shall monitor Vtipusing 
the procedures specified in paragraphs (i) and (k) of this section.
    (2) Vtip must be less than 400 feet per second and also 
less than the maximum allowed flare tip velocity (Vmax) as 
calculated according to the following equation. The owner or operator 
shall monitor Vtip using the procedures specified in paragraphs (i) and 
(k) of this section and monitor gas composition and determine 
NHVvg using the procedures specified in paragraphs (j) and 
(l) of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.008

Where:

Vmax = Maximum allowed flare tip velocity, ft/sec.
NHVvg = Net heating value of flare vent gas, as 
determined by paragraph (l)(4) of this section, Btu/scf.
1,212 = Constant.
850 = Constant.

    (e) Combustion zone operating limits. For each flare, the owner or 
operator shall operate the flare to maintain the net heating value of 
flare combustion zone gas (NHVcz) at or above 270 British 
thermal units per standard cubic feet (Btu/scf) determined on a 15-
minute block period basis when regulated material is routed to the 
flare for at least 15-minutes. The owner or operator shall monitor and 
calculate NHVcz as specified in paragraph (m) of this 
section.
    (f) Dilution operating limits for flares with perimeter assist air. 
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/ft2) 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 
NHVdil as specified in paragraph (n) of this section.

[[Page 75259]]

    (g) Pilot flame monitoring. The owner or operator shall 
continuously monitor the presence of the pilot flame(s) using a device 
(including, but not limited to, a thermocouple, ultraviolet beam 
sensor, or infrared sensor) capable of detecting that the pilot 
flame(s) is present.
    (h) Visible emissions monitoring. The owner or operator shall 
monitor visible emissions while regulated materials are vented to the 
flare. An initial visible emissions demonstration must be conducted 
using an observation period of 2 hours using Method 22 at 40 CFR part 
60, appendix A-7. 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 Sec.  63.655(g)(11)(ii).
    (1) At least once per day, 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, 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.
    (2) Use a video surveillance camera to continuously record (at 
least one frame every 15 seconds with time and date stamps) images of 
the flare flame and a reasonable distance above the flare flame at an 
angle suitable for visual emissions observations. The owner or operator 
must provide real-time video surveillance camera output to the control 
room or other continuously manned location where the camera images may 
be viewed at any time.
    (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 supplemental natural 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 flare. Continuously monitoring fan speed or 
power and using fan curves is an acceptable method for continuously 
monitoring assist air flow rates.
    (1) The flow rate monitoring systems must be able to correct for 
the temperature and pressure of the system and output parameters in 
standard conditions (i.e., a temperature of 20 [deg]C 
(68[emsp14][deg]F) and a pressure of 1 atmosphere).
    (2) Mass flow monitors may be used for determining volumetric flow 
rate of flare vent gas provided the molecular weight of the flare vent 
gas is determined using compositional analysis as specified in 
paragraph (j) of this section so that the mass flow rate can be 
converted to volumetric flow at standard conditions using the following 
equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.009

Where:

Qvol = Volumetric flow rate, standard cubic feet per 
second.
Qmass = Mass flow rate, pounds per second.
385.3 = Conversion factor, standard cubic feet per pound-mole.
MWt = Molecular weight of the gas at the flow monitoring location, 
pounds per pound-mole.

    (3) Mass flow monitors may be used for determining volumetric flow 
rate of assist air or assist steam. Use equation in paragraph (i)(2) of 
this section to convert mass flow rates to volumetric flow rates. Use a 
molecular weight of 18 pounds per pound-mole for assist steam and use a 
molecular weight of 29 pounds per pound-mole for assist air.
    (4) Continuous pressure/temperature monitoring system(s) and 
appropriate engineering calculations may be used in lieu of a 
continuous volumetric flow monitoring systems provided the molecular 
weight of the gas is known. For assist steam, use a molecular weight of 
18 pounds per pound-mole. For assist air, use a molecular weight of 29 
pounds per pound-mole. For flare vent gas, molecular weight must be 
determined using compositional analysis as specified in paragraph (j) 
of this section.
    (j) Flare vent gas composition monitoring. The owner or operator 
shall determine the concentration of individual components in the flare 
vent gas using either the methods provided in paragraph (j)(1) or (2) 
of this section, to assess compliance with the operating limits in 
paragraph (e) of this section and, if applicable, paragraphs (d) and 
(f) of this section. Alternatively, the owner or operator may elect to 
directly monitor the net heating value of the flare vent gas following 
the methods provided in paragraphs (j)(3) of this section and, if 
desired, may directly measure the hydrogen concentration in the flare 
vent gas following the methods provided in paragraphs (j)(4) of this 
section. The owner or operator may elect to use different monitoring 
methods for different gaseous streams that make up the flare vent gas 
using different methods provided the composition or net heating value 
of all gas streams that contribute to the flare vent gas are 
determined.
    (1) Except as provided in paragraphs (j)(5) and (6) of this 
section, the owner or operator shall install, operate, calibrate, and 
maintain a monitoring system capable of continuously measuring (i.e., 
at least once every 15-minutes), calculating, and recording the 
individual component concentrations present in the flare vent gas.
    (2) Except as provided in paragraphs (j)(5) and (6) of this 
section, the owner or operator shall install, operate, and maintain a 
grab sampling system capable of collecting an evacuated canister sample 
for subsequent compositional analysis at least once every eight hours 
while there is flow of regulated material to the flare. Subsequent 
compositional analysis of the samples must be performed according to 
Method 18 of 40 CFR part 60, appendix A-6, ASTM D6420-99 (Reapproved 
2010), ASTM D1945-03 (Reapproved 2010), ASTM D1945-14 or ASTM UOP539-12 
(all incorporated by reference--see Sec.  63.14).
    (3) Except as provided in paragraphs (j)(5) and (6) of this 
section, the owner or operator shall install, operate, calibrate, and 
maintain a calorimeter capable of continuously measuring, calculating, 
and recording NHVvg at standard conditions.
    (4) If the owner or operator uses a continuous net heating value 
monitor according to paragraph (j)(3) of this section, the owner or 
operator may, at their discretion, install, operate, calibrate, and 
maintain a monitoring

[[Page 75260]]

system capable of continuously measuring, calculating, and recording 
the hydrogen concentration in the flare vent gas.
    (5) Direct compositional or net heating value monitoring is not 
required for purchased (``pipeline quality'') natural gas streams. The 
net heating value of purchased natural gas streams may be determined 
using annual or more frequent grab sampling at any one representative 
location. Alternatively, the net heating value of any purchased natural 
gas stream can be assumed to be 920 Btu/scf.
    (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 (v) of this section.
    (i) The owner or operator shall submit to the Administrator a 
written application for an exemption from monitoring. The application 
must contain the following information:
    (A) A description of the flare gas stream/system to be considered, 
including submission of a portion of the appropriate piping diagrams 
indicating the boundaries of the flare gas stream/system and the 
affected flare(s) to be considered;
    (B) A statement that there are no crossover or entry points to be 
introduced into the flare gas stream/system (this should be shown in 
the piping diagrams) prior to the point where the flow rate of the gas 
streams is measured;
    (C) An explanation of the conditions that ensure that the flare gas 
net heating value is consistent and, if flare gas net heating value is 
expected to vary (e.g., due to product loading of different material), 
the conditions expected to produce the flare gas with the lowest net 
heating value;
    (D) The supporting test results from sampling the requested flare 
gas stream/system for the net heating value. Sampling data must 
include, at minimum, 2 weeks of daily measurement values (14 grab 
samples) for frequently operated flare gas streams/systems; for 
infrequently operated flare gas streams/systems, seven grab samples 
must be collected unless other additional information would support 
reduced sampling. If the flare gas stream composition can vary, samples 
must be taken during those conditions expected to result in lowest net 
heating value identified in paragraph (j)(6)(i)(C) of this section. The 
owner or operator shall determine net heating value for the gas stream 
using either gas composition analysis or net heating value monitor 
(with optional hydrogen concentration analyzer) according to the method 
provided in paragraph (l) of this section; and
    (E) A description of how the 2 weeks (or seven samples for 
infrequently operated flare gas streams/systems) of monitoring results 
compares to the typical range of net heating values expected for the 
flare gas stream/system going to the affected flare (e.g., ``the 
samples are representative of typical operating conditions of the flare 
gas stream going to the loading rack flare'' or ``the samples are 
representative of conditions expected to yield the lowest net heating 
value of the flare gas stream going to the loading rack flare'').
    (F) The net heating value to be used for all flows of the flare 
vent gas from the flare gas stream/system covered in the application. A 
single net heating value must be assigned to the flare vent gas either 
by selecting the lowest net heating value measured in the sampling 
program or by determining the 95th percent confidence interval on the 
mean value of all samples collected using the t-distribution statistic 
(which is 1.943 for 7 grab samples or 1.771 for 14 grab samples).
    (ii) The effective date of the exemption is the date of submission 
of the information required in paragraph (j)(6)(i) of this section.
    (iii) No further action is required unless refinery operating 
conditions change in such a way that affects the exempt fuel gas 
stream/system (e.g., the stream composition changes). If such a change 
occurs, the owner or operator shall follow the procedures in paragraph 
(j)(6)(iii)(A), (B), or (C) of this section.
    (A) If the operation change results in a flare vent gas net heating 
value that is still within the range of net heating values included in 
the original application, the owner or operator shall determine the net 
heating value on a grab sample and record the results as proof that the 
net heating value assigned to the vent gas stream in the original 
application is still appropriate.
    (B) If the operation change results in a flare vent gas net heating 
value that is lower than the net heating value assigned to the vent gas 
stream in the original application, the owner or operator may submit 
new information following the procedures of paragraph (j)(6)(i) of this 
section within 60 days (or within 30 days after the seventh grab sample 
is tested for infrequently operated process units).
    (C) If the operation change results in a flare vent gas net heating 
value has greater variability in the flare gas stream/system such the 
owner or operator chooses not to submit new information to support an 
exemption, the owner or operator must begin monitoring the composition 
or net heat content of the flare vent gas stream using the methods in 
this section (i.e., grab samples every 8 hours until such time a 
continuous monitor, if elected, is installed).
    (k) Calculation methods for cumulative flow rates and determining 
compliance with Vtip operating limits. The owner or operator shall 
determine Vtip on a 15-minute block average basis according 
to the following requirements.
    (1) The owner or operator shall use design and engineering 
principles to determine the unobstructed cross sectional area of the 
flare tip. The unobstructed cross sectional area of the flare tip is 
the total tip area that vent gas can pass through. This area does not 
include any stability tabs, stability rings, and upper steam or air 
tubes because flare vent gas does not exit through them.
    (2) The owner or operator shall determine the cumulative volumetric 
flow of flare vent gas for each 15-minute block average period using 
the data from the continuous flow monitoring system required in 
paragraph (i) of this section according to the following requirements, 
as applicable. If desired, the cumulative flow rate for a 15-minute 
block period only needs to include flow during those periods when 
regulated material is sent to the flare, but owners or operators may 
elect to calculate the cumulative flow rates across the entire 15-
minute block period for any 15-minute block period where there is 
regulated material flow to the flare.
    (i) Use set 15-minute time periods starting at 12 midnight to 12:15 
a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to 
midnight when calculating 15-minute block average flow volumes.
    (ii) If continuous pressure/temperature monitoring system(s) and 
engineering calculations are used as allowed under paragraph (i)(4) of 
this section, the owner or operator shall, at a minimum, determine the 
15-minute block average temperature and pressure from the monitoring 
system and use those values to perform the engineering calculations to 
determine the cumulative flow over the 15-minute block average period. 
Alternatively, the owner or operator may divide the 15-minute block 
average period into equal duration subperiods (e.g., three 5-minute 
periods) and determine the average temperature and pressure for each 
subperiod, perform engineering calculations to determine the flow for 
each subperiod, then add the volumetric

[[Page 75261]]

flows for the subperiods to determine the cumulative volumetric flow of 
vent gas for the 15-minute block average period.
    (3) The 15-minute block average Vtip shall be calculated 
using the following equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.010

Where:

Vtip = Flare tip velocity, feet per second.
Qcum = Cumulative volumetric flow over 15-minute block 
average period, actual cubic feet.
Area = Unobstructed area of the flare tip, square feet.
900 = Conversion factor, seconds per 15-minute block average.

    (4) If the owner or operator chooses to comply with paragraph 
(d)(2) of this section, the owner or operator shall also determine the 
net heating value of the flare vent gas following the requirements in 
paragraphs (j) and (l) of this section and calculate Vmax 
using the equation in paragraph (d)(2) of this section in order to 
compare Vtip to Vmax on a 15-minute block average 
basis.
    (l) Calculation methods for determining flare vent gas net heating 
value. The owner or operator shall determine the net heating value of 
the flare vent gas (NHVvg) based on the composition 
monitoring data on a 15-minute block average basis according to the 
following requirements.
    (1) If compositional analysis data are collected as provided in 
paragraph (j)(1) or (2) of this section, the owner or operator shall 
determine NHVvg of a specific sample by using the following 
equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.011

Where:

NHVvg = Net heating value of flare vent gas, Btu/scf.
i = Individual component in flare vent gas.
n = Number of components in flare vent gas.
xi = Concentration of component i in flare vent gas, 
volume fraction.
NHVi = Net heating value of component i according to 
table 12 of this subpart, Btu/scf. If the component is not specified 
in table 12 of this subpart, the heats of combustion may be 
determined using any published values where the net enthalpy per 
mole of offgas is based on combustion at 25 [deg]C and 1 atmosphere 
(or constant pressure) with offgas water in the gaseous state, but 
the standard temperature for determining the volume corresponding to 
one mole of vent gas is 20 [deg]C.

    (2) If direct net heating value monitoring data are collected as 
provided in paragraph (j)(3) of this section but a hydrogen 
concentration monitor is not used, the owner or operator shall use the 
direct output of the monitoring system(s) (in Btu/scf) to determine the 
NHVvg for the sample.
    (3) If direct net heating value monitoring data are collected as 
provided in paragraph (j)(3) of this section and hydrogen concentration 
monitoring data are collected as provided in paragraph (j)(4) of this 
section, the owner or operator shall use the following equation to 
determine NHVvg for each sample measured via the net heating 
value monitoring system.


NHVvg = NHVmeasured + 938xH2

Where:

NHVvg = Net heating value of flare vent gas, Btu/scf.

NHVmeasured = Net heating value of flare vent gas stream 
as measured by the continuous net heating value monitoring system, 
Btu/scf.
xH2 = Concentration of hydrogen in flare vent gas at the time the 
sample was input into the net heating value monitoring system, 
volume fraction.
938 = Net correction for the measured heating value of hydrogen 
(1,212 - 274), Btu/scf.

    (4) Use set 15-minute time periods starting at 12 midnight to 12:15 
a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to 
midnight when calculating 15-minute block averages.
    (5) When a continuous monitoring system is used as provided in 
paragraph (j)(1) or (3) of this section and, if applicable, paragraph 
(j)(4) of this section, the owner or operator may elect to determine 
the 15-minute block average NHVvg using either the 
calculation methods in paragraph (l)(5)(i) of this section or the 
calculation methods in paragraph (l)(5)(ii) of this section. The owner 
or operator may choose to comply using the calculation methods in 
paragraph (l)(5)(i) of this section for some flares at the petroleum 
refinery and comply using the calculation methods (l)(5)(ii) of this 
section for other flares. However, for each flare, the owner or 
operator must elect one calculation method that will apply at all 
times, and use that method for all continuously monitored flare vent 
streams associated with that flare. If the owner or operator intends to 
change the calculation method that applies to a flare, the owner or 
operator must notify the Administrator 30 days in advance of such a 
change.
    (i) Feed-forward calculation method. When calculating 
NHVvg for a specific 15-minute block:
    (A) Use the results from the first sample collected during an 
event, (for periodic flare vent gas flow events) for the first 15-
minute block associated with that event.
    (B) If the results from the first sample collected during an event 
(for periodic flare vent gas flow events) are not available until after 
the second 15-minute block starts, use the results from the first 
sample collected during an event for the second 15-minute block 
associated with that event.
    (C) For all other cases, use the results that are available from 
the most recent sample prior to the 15-minute block period for that 15-
minute block period for all flare vent gas steams. For the purpose of 
this requirement, use the time that the results become available rather 
than the time the sample was collected. For example, if a sample is 
collected at 12:25 a.m. and the analysis is completed at 12:38 a.m., 
the results are available at 12:38 a.m. and these results would be used 
to determine compliance during the 15-minute block period from 12:45 
a.m. to 1:00 a.m.
    (ii) Direct calculation method. When calculating NHVvg 
for a specific 15-minute block:
    (A) If the results from the first sample collected during an event 
(for periodic flare vent gas flow events) are not available until after 
the second 15-minute block starts, use the results from the first 
sample collected during an event for the first 15-minute block 
associated with that event.
    (B) For all other cases, use the arithmetic average of all 
NHVvg measurement data results that become available during 
a 15-minute block to calculate the 15-minute block average for that 
period. For the purpose of this requirement, use the time that the 
results become available rather than the time the sample was collected. 
For example, if a sample is collected at 12:25 a.m. and the analysis is 
completed at 12:38 a.m., the results are available at 12:38 a.m. and 
these results would be used to determine compliance during the 15-
minute block period from 12:30 a.m. to 12:45 a.m.
    (6) When grab samples are used to determine flare vent gas 
composition:
    (i) Use the analytical results from the first grab sample collected 
for an event for all 15-minute periods from the start of the event 
through the 15-minute block prior to the 15-minute block in which a 
subsequent grab sample is collected.
    (ii) Use the results from subsequent grab sampling events for all 
15 minute periods starting with the 15-minute block in which the sample 
was collected and ending with the 15-minute block prior to the 15-
minute block in which the next grab sample is collected. For

[[Page 75262]]

the purpose of this requirement, use the time the sample was collected 
rather than the time the analytical results become available.
    (7) If the owner or operator monitors separate gas streams that 
combine to comprise the total flare vent gas flow, the 15-minute block 
average net heating value shall be determined separately for each 
measurement location according to the methods in paragraphs (l)(1) 
through (6) of this section and a flow-weighted average of the gas 
stream net heating values shall be used to determine the 15-minute 
block average net heating value of the cumulative flare vent gas.
    (m) Calculation methods for determining combustion zone net heating 
value. The owner or operator shall determine the net heating value of 
the combustion zone gas (NHVcz) as specified in paragraph 
(m)(1) or (2) of this section, as applicable.
    (1) Except as specified in paragraph (m)(2) of this section, 
determine the 15-minute block average NHVcz based on the 15-
minute block average vent gas and assist gas flow rates using the 
following equation. For periods when there is no assist steam flow or 
premix assist air flow, NHVcz = NHVvg.
[GRAPHIC] [TIFF OMITTED] TR01DE15.012

Where:

NHVcz = Net heating value of combustion zone gas, Btu/
scf.
NHVvg = Net heating value of flare vent gas for the 15-
minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during 
the 15-minute block period, scf.
Qs = Cumulative volumetric flow of total steam during the 
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist 
air during the 15-minute block period, scf.

    (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 supplemental natural gas flow additions to the flare must 
determine the 15-minute block average NHVcz using the 
following equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.013

Where:

NHVcz = Net heating value of combustion zone gas, Btu/
scf.
NHVvg = Net heating value of flare vent gas for the 15-
minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during 
the 15-minute block period, scf.
QNG2 = Cumulative volumetric flow of supplemental natural 
gas to the flare during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of supplemental natural 
gas to the flare 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., 
QNG1=QNG2.
NHVNG = Net heating value of supplemental natural gas to 
the flare for the 15-minute block period determined according to the 
requirements in paragraph (j)(5) of this section, Btu/scf.
Qs = Cumulative volumetric flow of total steam during the 
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist 
air during the 15-minute block period, scf.

    (n) Calculation methods for determining the net heating value 
dilution parameter. The owner or operator shall determine the net 
heating value dilution parameter (NHVdil) as specified in 
paragraph (n)(1) or (2) of this section, as applicable.
    (1) Except as specified in paragraph (n)(2) of this section, 
determine the 15-minute block average NHVdil based on the 
15-minute block average vent gas and perimeter assist air flow rates 
using 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 
NHVdil parameter does not need to be calculated.
[GRAPHIC] [TIFF OMITTED] TR01DE15.014


Where:

NHVdil = Net heating value dilution parameter, Btu/
ft2.
NHVvg = Net heating value of flare vent gas determined 
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during 
the 15-minute block period, scf.
Diam = Effective diameter of the unobstructed area of the flare tip 
for flare vent gas flow, ft. Use the area as determined in paragraph 
(k)(1) of this section and determine the diameter as
[GRAPHIC] [TIFF OMITTED] TR01DE15.015

Qs = Cumulative volumetric flow of total steam during the 
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist 
air during the 15-minute block period, scf.
Qa,perimeter = Cumulative volumetric flow of perimeter 
assist air during the 15-minute block period, scf.

    (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 supplemental natural gas flow additions to the flare must 
determine the 15-minute block average NHVdil using the 
following equation only during periods when perimeter assist air is 
used. For 15-minute block periods when there is no cumulative

[[Page 75263]]

volumetric flow of perimeter assist air, the 15-minute block average 
NHVdil parameter does not need to be calculated.
[GRAPHIC] [TIFF OMITTED] TR01DE15.016


Where:

NHVdil = Net heating value dilution parameter, Btu/
ft2.
NHVvg = Net heating value of flare vent gas determined 
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during 
the 15-minute block period, scf.
QNG2 = Cumulative volumetric flow of supplemental natural 
gas to the flare during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of supplemental natural 
gas to the flare 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., 
QNG1 =QNG2.
NHVNG = Net heating value of supplemental natural gas to 
the flare for the 15-minute block period determined according to the 
requirements in paragraph (j)(5) of this section, Btu/scf.
Diam = Effective diameter of the unobstructed area of the flare tip 
for flare vent gas flow, ft. Use the area as determined in paragraph 
(k)(1) of this section and determine the diameter as
[GRAPHIC] [TIFF OMITTED] TR01DE15.017

Qs = Cumulative volumetric flow of total steam during the 
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist 
air during the 15-minute block period, scf.
Qa,perimeter = Cumulative volumetric flow of perimeter 
assist air during the 15-minute block period, 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 (8) of this section.
    (1) Develop a flare management plan to minimize flaring during 
periods of startup, shutdown, or emergency releases. The flare 
management plan must include the information described in paragraphs 
(o)(1)(i) through (vii) of this section.
    (i) A listing of all refinery process units, ancillary equipment, 
and fuel gas systems connected to the flare for each affected flare.
    (ii) An assessment of whether discharges to affected flares from 
these process units, ancillary equipment and fuel gas systems can be 
minimized or prevented during periods of startup, shutdown, or 
emergency releases. The flare minimization assessment must (at a 
minimum) consider the items in paragraphs (o)(1)(ii)(A) through (C) of 
this section. The assessment must provide clear rationale in terms of 
costs (capital and annual operating), natural gas offset credits (if 
applicable), technical feasibility, secondary environmental impacts and 
safety considerations for the selected minimization alternative(s) or a 
statement, with justifications, that flow reduction could not be 
achieved. Based upon the assessment, each owner or operator of an 
affected flare shall identify the minimization alternatives that it has 
implemented by the due date of the flare management plan and shall 
include a schedule for the prompt implementation of any selected 
measures that cannot reasonably be completed as of that date.
    (A) Modification in startup and shutdown procedures to reduce the 
quantity of process gas discharge to the flare.
    (B) Implementation of prevention measures listed for pressure 
relief devices in Sec.  63.648(j)(5) for each pressure relief valve 
that can discharge to the flare.
    (C) Installation of a flare gas recovery system or, for facilities 
that are fuel gas rich, a flare gas recovery system and a co-generation 
unit or combined heat and power unit.
    (iii) A description of each affected flare containing the 
information in paragraphs (o)(1)(iii)(A) through (G) of this section.
    (A) A general description of the flare, including whether it is a 
ground flare or elevated (including height), the type of assist system 
(e.g., air, steam, pressure, non-assisted), whether the flare is used 
on a routine basis or if it is only used during periods of startup, 
shutdown or emergency release, and whether the flare is equipped with a 
flare gas recovery system.
    (B) The smokeless capacity of the flare based on design conditions. 
Note: A single value must be provided for the smokeless capacity of the 
flare.
    (C) The maximum vent gas flow rate (hydraulic load capacity).
    (D) The maximum supplemental gas flow rate.
    (E) For flares that receive assist steam, the minimum total steam 
rate and the maximum total steam rate.
    (F) For flares that receive assist air, an indication of whether 
the fan/blower is single speed, multi-fixed speed (e.g., high, medium, 
and low speeds), or variable speeds. For fans/blowers with fixed 
speeds, provide the estimated assist air flow rate at each fixed speed. 
For variable speeds, provide the design fan curve (e.g., air flow rate 
as a function of power input).
    (G) Simple process flow diagram showing the locations of the flare 
following components of the flare: Flare tip (date installed, 
manufacturer, nominal and effective tip diameter, tip drawing); 
knockout or surge drum(s) or pot(s) (including dimensions and design 
capacities); flare header(s) and subheader(s); assist system; and 
ignition system.
    (iv) Description and simple process flow diagram showing all gas 
lines (including flare waste gas, purge or sweep gas (as applicable), 
supplemental gas) that are associated with the flare. For purge, sweep, 
supplemental gas, identify the type of gas used. Designate which lines 
are exempt from composition or net heating value monitoring and why 
(e.g., natural gas, gas streams that have been demonstrated to have 
consistent composition, pilot gas). Designate which lines are monitored 
and identify on the process flow diagram the location and type of each 
monitor. Designate the pressure relief devices that are vented to the 
flare.
    (v) For each flow rate, gas composition, net heating value or 
hydrogen concentration monitor identified in paragraph (o)(1)(iv) of 
this section, provide a detailed description of the manufacturer's 
specifications, including, but not limited to, make, model, type, 
range, precision, accuracy, calibration, maintenance and quality 
assurance procedures.
    (vi) For each pressure relief valve vented to the flare identified 
in paragraph (o)(1)(iv) of this section, provide a detailed description 
of each pressure release valve, including type of relief device 
(rupture disc, valve type) diameter of the relief valve, set pressure 
of the relief valve and listing of the prevention measures implemented. 
This

[[Page 75264]]

information may be maintained in an electronic database on-site and 
does not need to be submitted as part of the flare management plan 
unless requested to do so by the Administrator.
    (vii) Procedures to minimize or eliminate discharges to the flare 
during the planned startup and shutdown of the refinery process units 
and ancillary equipment that are connected to the affected flare, 
together with a schedule for the prompt implementation of any 
procedures that cannot reasonably be implemented as of the date of the 
submission of the flare management plan.
    (2) Each owner or operator required to develop and implement a 
written flare management plan as described in paragraph (o)(1) of this 
section must submit the plan to the Administrator as described in 
paragraphs (o)(2)(i) through (iii) of this section.
    (i) The owner or operator must develop and implement the flare 
management plan no later than January 30, 2019 or at startup for a new 
flare that commenced construction on or after February 1, 2016.
    (ii) The owner or operator must comply with the plan as submitted 
by the date specified in paragraph (o)(2)(i) of this section. The plan 
should be updated periodically to account for changes in the operation 
of the flare, such as new connections to the flare or the installation 
of a flare gas recovery system, but the plan need be re-submitted to 
the Administrator only if the owner or operator alters the design 
smokeless capacity of the flare. The owner or operator must comply with 
the updated plan as submitted.
    (iii) All versions of the plan submitted to the Administrator shall 
also be submitted to the following address: U.S. Environmental 
Protection Agency, Office of Air Quality Planning and Standards, Sector 
Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention: 
Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, 
NC 27711. Electronic copies in lieu of hard copies may also be 
submitted to [email protected]
    (3) The owner or operator of a flare subject to this subpart shall 
conduct a root cause analysis and a corrective action analysis for each 
flow event that contains regulated material and that meets either the 
criteria in paragraph (o)(3)(i) or (ii) of this section.
    (i) The vent gas flow rate exceeds the smokeless capacity of the 
flare and visible emissions are present from the flare for more than 5 
minutes during any 2 consecutive hours during the release event.
    (ii) The vent gas flow rate exceeds the smokeless capacity of the 
flare and the 15-minute block average flare tip velocity exceeds the 
maximum flare tip velocity determined using the methods in paragraph 
(d)(2) of this section.
    (4) A root cause analysis and corrective action analysis must be 
completed as soon as possible, but no later than 45 days after a flare 
flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this 
section. Special circumstances affecting the number of root cause 
analyses and/or corrective action analyses are provided in paragraphs 
(o)(4)(i) through (v) of this section.
    (i) You may conduct a single root cause analysis and corrective 
action analysis for a single continuous flare flow event that meets 
both of the criteria in paragraphs (o)(3)(i) and (ii) of this section.
    (ii) You may conduct a single root cause analysis and corrective 
action analysis for a single continuous flare flow event regardless of 
the number of 15-minute block periods in which the flare tip velocity 
was exceeded or the number of 2 hour periods that contain more the 5 
minutes of visible emissions.
    (iii) You may conduct a single root cause analysis and corrective 
action analysis for a single event that causes two or more flares that 
are operated in series (i.e., cascaded flare systems) to have a flow 
event meeting the criteria in paragraph (o)(3)(i) or (ii) of this 
section.
    (iv) You may conduct a single root cause analysis and corrective 
action analysis for a single event that causes two or more flares to 
have a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) 
of this section, regardless of the configuration of the flares, if the 
root cause is reasonably expected to be a force majeure event, as 
defined in this subpart.
    (v) Except as provided in paragraphs (o)(4)(iii) and (iv) of this 
section, if more than one flare has a flow event that meets the 
criteria in paragraph (o)(3)(i) or (ii) of this section during the same 
time period, an initial root cause analysis shall be conducted 
separately for each flare that has a flow event meeting the criteria in 
paragraph (o)(3)(i) or (ii) of this section. If the initial root cause 
analysis indicates that the flow events have the same root cause(s), 
the initially separate root cause analyses may be recorded as a single 
root cause analysis and a single corrective action analysis may be 
conducted.
    (5) Each owner or operator of a flare required to conduct a root 
cause analysis and corrective action analysis as specified in 
paragraphs (o)(3) and (4) of this section shall implement the 
corrective action(s) identified in the corrective action analysis in 
accordance with the applicable requirements in paragraphs (o)(5)(i) 
through (iii) of this section.
    (i) All corrective action(s) must be implemented within 45 days of 
the event for which the root cause and corrective action analyses were 
required or as soon thereafter as practicable. If an owner or operator 
concludes that no corrective action should be implemented, the owner or 
operator shall record and explain the basis for that conclusion no 
later than 45 days following the event.
    (ii) For corrective actions that cannot be fully implemented within 
45 days following the event for which the root cause and corrective 
action analyses were required, the owner or operator shall develop an 
implementation schedule to complete the corrective action(s) as soon as 
practicable.
    (iii) No later than 45 days following the event for which a root 
cause and corrective action analyses were required, the owner or 
operator shall record the corrective action(s) completed to date, and, 
for action(s) not already completed, a schedule for implementation, 
including proposed commencement and completion dates.
    (6) The owner or operator shall determine the total number of 
events for which a root cause and corrective action analyses was 
required during the calendar year for each affected flare separately 
for events meeting the criteria in paragraph (o)(3)(i) of this section 
and those meeting the criteria in paragraph (o)(3)(ii) of this section. 
For the purpose of this requirement, a single root cause analysis 
conducted for an event that met both of the criteria in paragraphs 
(o)(3)(i) and (ii) of this section would be counted as an event under 
each of the separate criteria counts for that flare. Additionally, if a 
single root cause analysis was conducted for an event that caused 
multiple flares to meet the criteria in paragraph (o)(3)(i) or (ii) of 
this section, that event would count as an event for each of the flares 
for each criteria in paragraph (o)(3) of this section that was met 
during that event. The owner or operator shall also determine the total 
number of events for which a root cause and correct action analyses was 
required and the analyses concluded that the root cause was a force 
majeure event, as defined in this subpart.
    (7) The following events would be a violation of this emergency 
flaring work practice standard.
    (i) Any flow event for which a root cause analysis was required and 
the root

[[Page 75265]]

cause was determined to be operator error or poor maintenance.
    (ii) Two visible emissions exceedance events meeting the criteria 
in paragraph (o)(3)(i) of this section that were not caused by a force 
majeure event from a single flare in a 3 calendar year period for the 
same root cause for the same equipment.
    (iii) Two flare tip velocity exceedance events meeting the criteria 
in paragraph (o)(3)(ii) of this section that were not caused by a force 
majeure event from a single flare in a 3 calendar year period for the 
same root cause for the same equipment.
    (iv) Three visible emissions exceedance events meeting the criteria 
in paragraph (o)(3)(i) of this section that were not caused by a force 
majeure event from a single flare in a 3 calendar year period for any 
reason.
    (v) Three flare tip velocity exceedance events meeting the criteria 
in paragraph (o)(3)(ii) of this section that were not caused by a force 
majeure event from a single flare in a 3 calendar year period for any 
reason.
    (p) Flare monitoring records. The owner or operator shall keep the 
records specified in Sec.  63.655(i)(9).
    (q) Reporting. The owner or operator shall comply with the 
reporting requirements specified in Sec.  63.655(g)(11).
    (r) Alternative means of emissions limitation. An owner or operator 
may request approval from the Administrator for site-specific operating 
limits that shall apply specifically to a selected flare. Site-specific 
operating limits include alternative threshold values for the 
parameters specified in paragraphs (d) through (f) of this section as 
well as threshold values for operating parameters other than those 
specified in paragraphs (d) through (f) of this section. The owner or 
operator must demonstrate that the flare achieves 96.5 percent 
combustion efficiency (or 98 percent destruction efficiency) using the 
site-specific operating limits based on a performance evaluation as 
described in paragraph (r)(1) of this section. The request shall 
include information as described in paragraph (r)(2) of this section. 
The request shall be submitted and followed as described in paragraph 
(r)(3) of this section.
    (1) The owner or operator shall prepare and submit a site-specific 
test plan and receive approval of the site-specific performance 
evaluation plan prior to conducting any flare performance evaluation 
test runs intended for use in developing site-specific operating 
limits. The site-specific performance evaluation plan shall include, at 
a minimum, the elements specified in paragraphs (r)(1)(i) through (ix) 
of this section. Upon approval of the site-specific performance 
evaluation plan, the owner or operator shall conduct performance 
evaluation test runs for the flare following the procedures described 
in the site-specific performance evaluation plan.
    (i) The design and dimensions of the flare, flare type (air-
assisted only, steam-assisted only, air- and steam-assisted, pressure-
assisted, or non-assisted), and description of gas being flared, 
including quantity of gas flared, frequency of flaring events (if 
periodic), expected net heating value of flare vent gas, minimum total 
steam assist rate.
    (ii) The operating conditions (vent gas compositions, vent gas flow 
rates and assist flow rates, if applicable) likely to be encountered by 
the flare during normal operations and the operating conditions for the 
test period.
    (iii) A description of (including sample calculations illustrating) 
the planned data reduction and calculations to determine the flare 
combustion or destruction efficiency.
    (iv) Site-specific operating parameters to be monitored 
continuously during the flare performance evaluation. These parameters 
may include but are not limited to vent gas flow rate, steam and/or air 
assist flow rates, and flare vent gas composition. If new operating 
parameters are proposed for use other than those specified in 
paragraphs (d) through (f) of this section, an explanation of the 
relevance of the proposed operating parameter(s) as an indicator of 
flare combustion performance and why the alternative operating 
parameter(s) can adequately ensure that the flare achieves the required 
combustion efficiency.
    (v) A detailed description of the measurement methods, monitored 
pollutant(s), measurement locations, measurement frequency, and 
recording frequency proposed for both emission measurements and flare 
operating parameters.
    (vi) A description of (including sample calculations illustrating) 
the planned data reduction and calculations to determine the flare 
operating parameters.
    (vii) The minimum number and length of test runs and range of 
operating values to be evaluated during the performance evaluation. A 
sufficient number of test runs shall be conducted to identify the point 
at which the combustion/destruction efficiency of the flare 
deteriorates.
    (viii) [Reserved]
    (ix) Test schedule.
    (2) The request for flare-specific operating limits shall include 
sufficient and appropriate data, as determined by the Administrator, to 
allow the Administrator to confirm that the selected site-specific 
operating limit(s) adequately ensures that the flare destruction 
efficiency is 98 percent or greater or that the flare combustion 
efficiency is 96.5 percent or greater at all times. At a minimum, the 
request shall contain the information described in paragraphs (r)(2)(i) 
through (iv) of this section.
    (i) The design and dimensions of the flare, flare type (air-
assisted only, steam-assisted only, air- and steam-assisted, pressure-
assisted, or non-assisted), and description of gas being flared, 
including quantity of gas flared, frequency of flaring events (if 
periodic), expected net heating value of flare vent gas, minimum total 
steam assist rate.
    (ii) Results of each performance evaluation test run conducted, 
including, at a minimum:
    (A) The measured combustion/destruction efficiency.
    (B) The measured or calculated operating parameters for each test 
run. If operating parameters are calculated, the raw data from which 
the parameters are calculated must be included in the test report.
    (C) Measurement location descriptions for both emission 
measurements and flare operating parameters.
    (D) Description of sampling and analysis procedures (including 
number and length of test runs) and any modifications to standard 
procedures. If there were deviations from the approved test plan, a 
detailed description of the deviations and rationale why the test 
results or calculation procedures used are appropriate.
    (E) Operating conditions (e.g., vent gas composition, assist rates, 
etc.) that occurred during the test.
    (F) Quality assurance procedures.
    (G) Records of calibrations.
    (H) Raw data sheets for field sampling.
    (I) Raw data sheets for field and laboratory analyses.
    (J) Documentation of calculations.
    (iii) The selected flare-specific operating limit values based on 
the performance evaluation test results, including the averaging time 
for the operating limit(s), and rationale why the selected values and 
averaging times are sufficiently stringent to ensure proper flare 
performance. If new operating parameters or averaging times are 
proposed for use other than those specified in paragraphs (d) through 
(f) of this section, an explanation of why the

[[Page 75266]]

alternative operating parameter(s) or averaging time(s) adequately 
ensures the flare achieves the required combustion efficiency.
    (iv) The means by which the owner or operator will document on-
going, continuous compliance with the selected flare-specific operating 
limit(s), including the specific measurement location and frequencies, 
calculation procedures, and records to be maintained.
    (3) The request shall be submitted as described in paragraphs 
(r)(3)(i) through (iv) of this section.
    (i) The owner or operator may request approval from the 
Administrator at any time upon completion of a performance evaluation 
conducted following the methods in an approved site-specific 
performance evaluation plan for an operating limit(s) that shall apply 
specifically to that flare.
    (ii) The request must be submitted to the Administrator for 
approval. The owner or operator must continue to comply with the 
applicable standards for flares in this subpart until the requirements 
in Sec.  63.6(g)(1) are met and a notice is published in the Federal 
Register allowing use of such an alternative means of emission 
limitation.
    (iii) The request shall also be submitted to the following address: 
U.S. Environmental Protection Agency, Office of Air Quality Planning 
and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom 
(E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, 
Research Triangle Park, NC 27711. Electronic copies in lieu of hard 
copies may also be submitted to [email protected].
    (iv) If the Administrator finds any deficiencies in the request, 
the request must be revised to address the deficiencies and be re-
submitted for approval within 45 days of receipt of the notice of 
deficiencies. The owner or operator must comply with the revised 
request as submitted until it is approved.
    (4) The approval process for a request for a flare-specific 
operating limit(s) is described in paragraphs (r)(4)(i) through (iii) 
of this section.
    (i) Approval by the Administrator of a flare-specific operating 
limit(s) request will be based on the completeness, accuracy and 
reasonableness of the request. Factors that the EPA will consider in 
reviewing the request for approval include, but are not limited to, 
those described in paragraphs (r)(4)(i)(A) through (C) of this section.
    (A) The description of the flare design and operating 
characteristics.
    (B) If a new operating parameter(s) other than those specified in 
paragraphs (d) through (f) of this section is proposed, the explanation 
of how the proposed operating parameter(s) serves a good indicator(s) 
of flare combustion performance.
    (C) The results of the flare performance evaluation test runs and 
the establishment of operating limits that ensures that the flare 
destruction efficiency is 98 percent or greater or that the flare 
combustion efficiency is 96.5 percent or greater at all times.
    (D) The completeness of the flare performance evaluation test 
report.
    (ii) If the request is approved by the Administrator, a flare-
specific operating limit(s) will be established at the level(s) 
demonstrated in the approved request.
    (iii) If the Administrator finds any deficiencies in the request, 
the request must be revised to address the deficiencies and be re-
submitted for approval.

0
33. Section 63.671 is added to read as follows:


Sec.  63.671  Requirements for flare monitoring systems.

    (a) Operation of CPMS. For each CPMS installed to comply with 
applicable provisions in Sec.  63.670, the owner or operator shall 
install, operate, calibrate, and maintain the CPMS as specified in 
paragraphs (a)(1) through (8) of this section.
    (1) Except for CPMS installed for pilot flame monitoring, all 
monitoring equipment must meet the applicable minimum accuracy, 
calibration and quality control requirements specified in table 13 of 
this subpart.
    (2) The owner or operator shall ensure the readout (that portion of 
the CPMS that provides a visual display or record) or other indication 
of the monitored operating parameter from any CPMS required for 
compliance is readily accessible onsite for operational control or 
inspection by the operator of the source.
    (3) All CPMS must complete a minimum of one cycle of operation 
(sampling, analyzing and data recording) for each successive 15-minute 
period.
    (4) Except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions and required monitoring 
system quality assurance or quality control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
the owner or operator shall operate all CPMS and collect data 
continuously at all times when regulated emissions are routed to the 
flare.
    (5) The owner or operator shall operate, maintain, and calibrate 
each CPMS according to the CPMS monitoring plan specified in paragraph 
(b) of this section.
    (6) For each CPMS except for CPMS installed for pilot flame 
monitoring, the owner or operator shall comply with the out-of-control 
procedures described in paragraph (c) of this section.
    (7) The owner or operator shall reduce data from a CPMS as 
specified in paragraph (d) of this section.
    (8) The CPMS must be capable of measuring the appropriate parameter 
over the range of values expected for that measurement location. The 
data recording system associated with each CPMS must have a resolution 
that is equal to or better than the required system accuracy.
    (b) CPMS monitoring plan. The owner or operator shall develop and 
implement a CPMS quality control program documented in a CPMS 
monitoring plan that covers each flare subject to the provisions in 
Sec.  63.670 and each CPMS installed to comply with applicable 
provisions in Sec.  63.670. The owner or operator shall have the CPMS 
monitoring plan readily available on-site at all times and shall submit 
a copy of the CPMS monitoring plan to the Administrator upon request by 
the Administrator. The CPMS monitoring plan must contain the 
information listed in paragraphs (b)(1) through (5) of this section.
    (1) Identification of the specific flare being monitored and the 
flare type (air-assisted only, steam-assisted only, air- and steam-
assisted, pressure-assisted, or non-assisted).
    (2) Identification of the parameter to be monitored by the CPMS and 
the expected parameter range, including worst case and normal 
operation.
    (3) Description of the monitoring equipment, including the 
information specified in paragraphs (b)(3)(i) through (vii) of this 
section.
    (i) Manufacturer and model number for all monitoring equipment 
components installed to comply with applicable provisions in Sec.  
63.670.
    (ii) Performance specifications, as provided by the manufacturer, 
and any differences expected for this installation and operation.
    (iii) The location of the CPMS sampling probe or other interface 
and a justification of how the location meets the requirements of 
paragraph (a)(1) of this section.
    (iv) Placement of the CPMS readout, or other indication of 
parameter values, indicating how the location meets the requirements of 
paragraph (a)(2) of this section.

[[Page 75267]]

    (v) Span of the CPMS. The span of the CPMS sensor and analyzer must 
encompass the full range of all expected values.
    (vi) How data outside of the span of the CPMS will be handled and 
the corrective action that will be taken to reduce and eliminate such 
occurrences in the future.
    (vii) Identification of the parameter detected by the parametric 
signal analyzer and the algorithm used to convert these values into the 
operating parameter monitored to demonstrate compliance, if the 
parameter detected is different from the operating parameter monitored.
    (4) Description of the data collection and reduction systems, 
including the information specified in paragraphs (b)(4)(i) through 
(iii) of this section.
    (i) A copy of the data acquisition system algorithm used to reduce 
the measured data into the reportable form of the standard and to 
calculate the applicable averages.
    (ii) Identification of whether the algorithm excludes data 
collected during CPMS breakdowns, out-of-control periods, repairs, 
maintenance periods, instrument adjustments or checks to maintain 
precision and accuracy, calibration checks, and zero (low-level), mid-
level (if applicable) and high-level adjustments.
    (iii) If the data acquisition algorithm does not exclude data 
collected during CPMS breakdowns, out-of-control periods, repairs, 
maintenance periods, instrument adjustments or checks to maintain 
precision and accuracy, calibration checks, and zero (low-level), mid-
level (if applicable) and high-level adjustments, a description of the 
procedure for excluding this data when the averages calculated as 
specified in paragraph (e) of this section are determined.
    (5) Routine quality control and assurance procedures, including 
descriptions of the procedures listed in paragraphs (b)(5)(i) through 
(vi) of this section and a schedule for conducting these procedures. 
The routine procedures must provide an assessment of CPMS performance.
    (i) Initial and subsequent calibration of the CPMS and acceptance 
criteria.
    (ii) Determination and adjustment of the calibration drift of the 
CPMS.
    (iii) Daily checks for indications that the system is responding. 
If the CPMS system includes an internal system check, the owner or 
operator may use the results to verify the system is responding, as 
long as the system provides an alarm to the owner or operator or the 
owner or operator checks the internal system results daily for proper 
operation and the results are recorded.
    (iv) Preventive maintenance of the CPMS, including spare parts 
inventory.
    (v) Data recording, calculations and reporting.
    (vi) Program of corrective action for a CPMS that is not operating 
properly.
    (c) Out-of-control periods. For each CPMS installed to comply with 
applicable provisions in Sec.  63.670 except for CPMS installed for 
pilot flame monitoring, the owner or operator shall comply with the 
out-of-control procedures described in paragraphs (c)(1) and (2) of 
this section.
    (1) A CPMS is out-of-control if the zero (low-level), mid-level (if 
applicable) or high-level calibration drift exceeds two times the 
accuracy requirement of table 13 of this subpart.
    (2) When the CPMS is out of control, the owner or operator shall 
take the necessary corrective action and repeat all necessary tests 
that indicate the system is out of control. The owner or operator shall 
take corrective action and conduct retesting until the performance 
requirements are below the applicable limits. The beginning of the out-
of-control period is the hour a performance check (e.g., calibration 
drift) that indicates an exceedance of the performance requirements 
established in this section is conducted. The end of the out-of-control 
period is the hour following the completion of corrective action and 
successful demonstration that the system is within the allowable 
limits. The owner or operator shall not use data recorded during 
periods the CPMS is out of control in data averages and calculations, 
used to report emissions or operating levels, as specified in paragraph 
(d)(3) of this section.
    (d) CPMS data reduction. The owner or operator shall reduce data 
from a CPMS installed to comply with applicable provisions in Sec.  
63.670 as specified in paragraphs (d)(1) through (3) of this section.
    (1) The owner or operator may round the data to the same number of 
significant digits used in that operating limit.
    (2) Periods of non-operation of the process unit (or portion 
thereof) resulting in cessation of the emissions to which the 
monitoring applies must not be included in the 15-minute block 
averages.
    (3) Periods when the CPMS is out of control must not be included in 
the 15-minute block averages.
    (e) Additional requirements for gas chromatographs. For monitors 
used to determine compositional analysis for net heating value per 
Sec.  63.670(j)(1), the gas chromatograph must also meet the 
requirements of paragraphs (e)(1) through (3) of this section.
    (1) The quality assurance requirements are in table 13 of this 
subpart.
    (2) The calibration gases must meet one of the following options:
    (i) The owner or operator must use a calibration gas or multiple 
gases that include all of compounds listed in paragraphs (e)(2)(i)(A) 
through (K) of this section that may be reasonably expected to exist in 
the flare gas stream and optionally include any of the compounds listed 
in paragraphs (e)(2)(i)(L) through (O) of this section. All of the 
calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, the owner or 
operator must calibrate the instrument on all of the gases.
    (A) Hydrogen.
    (B) Methane.
    (C) Ethane.
    (D) Ethylene.
    (E) Propane.
    (F) Propylene.
    (G) n-Butane.
    (H) iso-Butane.
    (I) Butene (general). It is not necessary to separately speciate 
butene isomers, but the net heating value of trans-butene must be used 
for co-eluting butene isomers.
    (J) 1,3-Butadiene. It is not necessary to separately speciate 
butadiene isomers, but you must use the response factor and net heating 
value of 1,3-butadiene for co-eluting butadiene isomers.
    (K) n-Pentane. Use the response factor for n-pentane to quantify 
all C5+ hydrocarbons.
    (L) Acetylene (optional).
    (M) Carbon monoxide (optional).
    (N) Propadiene (optional).
    (O) Hydrogen sulfide (optional).
    (ii) The owner or operator must use a surrogate calibration gas 
consisting of hydrogen and C1 through C5 normal hydrocarbons. All of 
the calibration gases may be combined in one cylinder. If multiple 
calibration gases are necessary to cover all compounds, the owner or 
operator must calibrate the instrument on all of the gases.
    (3) If the owner or operator chooses to use a surrogate calibration 
gas under paragraph (e)(2)(ii) of this section, the owner or operator 
must comply with paragraphs (e)(3)(i) and (ii) of this section.
    (i) Use the response factor for the nearest normal hydrocarbon 
(i.e., n-alkane) in the calibration mixture to quantify unknown 
components detected in the analysis.
    (ii) Use the response factor for n-pentane to quantify unknown

[[Page 75268]]

components detected in the analysis that elute after n-pentane.

0
34. The appendix to subpart CC is amended in table 6 by:
0
a. Revising the entries ``63.5(d)(1)(ii)'' and ``63.5(f)'';
0
b. Removing the entry ``63.6(e)(1)'';
0
c. Adding, in numerical order, the entries ``63.6(e)(1)(i) and (ii)'' 
and ``63.6(e)(1)(iii)'';
0
d. Revising the entries ``63.6(e)(3)(i),'' ``63.6(e)(3)(iii)-
63.6(e)(3)(ix),'' and ``63.6(f)(1)'';
0
e. Removing the entry ``63.6(f)(2) and (3)'';
0
f. Adding, in numerical order, the entries ``63.6(f)(2)'' and 
``63.6(f)(3)'';
0
g. Removing the entry ``63.6(h)(1) and 63.6(h)(2)'';
0
h. Adding, in numerical order, the entries ``63.6(h)(1)'' and 
``63.6(h)(2)'';
0
i. Revising the entries ``63.7(b)'' and ``63.7(e)(1)'';
0
j. Removing the entry ``63.8(a)'';
0
k. Adding, in numerical order, the entries ``63.8(a)(1) and (2),'' 
``63.8(a)(3),'' and ``63.8(a)(4)'';
0
l. Revising the entry ``63.8(c)(1)'';
0
m. Adding, in numerical order, the entries ``63.8(c)(1)(i)'' and 
``63.8(c)(1)(iii)'';
0
n. Revising the entries ``63.8(c)(4),'' ``63.8(c)(5)-63.8(c)(8),'' 
``63.8(d),'' ``63.8(e),'' ``63.8(g),'' ``63.10(b)(2)(i),'' 
``63.10(b)(2)(ii),'' ``63.10(b)(2)(iv),'' ``63.10(b)(2)(v),'' and 
``63.10(b)(2)(vii)'';
0
o. Removing the entry ``63.10(c)(9)-63.10(c)(15)'';
0
p. Adding, in numerical order, the entries ``63.10(c)(9),'' 
``63.10(c)(10)-63.10(c)(11),'' and ``63.10(c)(12)-63.10(c)(15)'';
0
q. Revising the entry ``63.10(d)(2)'';
0
r. Removing the entries ``63.10(d)(5)(i)'' and ``63.10(d)(5)(ii)'';
0
s. Adding, in numerical order, the entry ``63.10(d)(5)'';
0
t. Removing the entry ``63.11-63.16'';
0
u. Adding, in numerical order, the entries ``63.11'' and ``63.12-
63.16'';
0
v. Revising footnote a.
0
w. Removing footnote b.
    The revisions and additions read as follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

       Table 6--General Provisions Applicability to Subpart CC \a\
------------------------------------------------------------------------
                               Applies to  subpart
          Reference                    CC                  Comment
------------------------------------------------------------------------
 
                              * * * * * * *
63.5(d)(1)(ii)..............  Yes.................  Except that for
                                                     affected sources
                                                     subject to this
                                                     subpart, emission
                                                     estimates specified
                                                     in Sec.
                                                     63.5(d)(1)(ii)(H)
                                                     are not required,
                                                     and Sec.
                                                     63.5(d)(1)(ii)(G)
                                                     and (I) are
                                                     Reserved and do not
                                                     apply.
 
                              * * * * * * *
63.5(f).....................  Yes.................  Except that the
                                                     cross-reference in
                                                     Sec.   63.5(f)(2)
                                                     to Sec.
                                                     63.9(b)(2) does not
                                                     apply.
 
                              * * * * * * *
63.6(e)(1)(i) and (ii)......  No..................  See Sec.   63.642(n)
                                                     for general duty
                                                     requirement.
63.6(e)(1)(iii).............  Yes.                  ....................
 
                              * * * * * * *
63.6(e)(3)(i)...............  No.                   ....................
 
                              * * * * * * *
63.6(e)(3)(iii)-63.6(e)(3)(i  No.                   ....................
 x).
63.6(f)(1)..................  No.                   ....................
63.6(f)(2)..................  Yes.................  Except the phrase
                                                     ``as specified in
                                                     Sec.   63.7(c)'' in
                                                     Sec.
                                                     63.6(f)(2)(iii)(D)
                                                     does not apply
                                                     because this
                                                     subpart does not
                                                     require a site-
                                                     specific test plan.
63.6(f)(3)..................  Yes.................  Except the cross-
                                                     references to Sec.
                                                      63.6(f)(1) and
                                                     (e)(1)(i) are
                                                     changed to Sec.
                                                     63.642(n).
 
                              * * * * * * *
63.6(h)(1)..................  No.                   ....................
63.6(h)(2)..................  Yes.................  Except Sec.
                                                     63.6(h)(2)(ii),
                                                     which is reserved.
 
                              * * * * * * *
63.7(b).....................  Yes.................  Except this subpart
                                                     requires
                                                     notification of
                                                     performance test at
                                                     least 30 days
                                                     (rather than 60
                                                     days) prior to the
                                                     performance test.
 
                              * * * * * * *
63.7(e)(1)..................  No..................  See Sec.
                                                     63.642(d)(3).
 
                              * * * * * * *
63.8(a)(1) and (2)..........  Yes.                  ....................
63.8(a)(3)..................  No..................  Reserved.
63.8(a)(4)..................  Yes.................  Except that for a
                                                     flare complying
                                                     with Sec.   63.670,
                                                     the cross-reference
                                                     to Sec.   63.11 in
                                                     this paragraph does
                                                     not include Sec.
                                                     63.11(b).
 
                              * * * * * * *
63.8(c)(1)..................  Yes.................  Except Sec.
                                                     63.8(c)(1)(i) and
                                                     (iii).
63.8(c)(1)(i)...............  No..................  See Sec.
                                                     63.642(n).
63.8(c)(1)(iii).............  No.                   ....................
 

[[Page 75269]]

 
                              * * * * * * *
63.8(c)(4)..................  Yes.................  Except that for
                                                     sources other than
                                                     flares, this
                                                     subpart specifies
                                                     the monitoring
                                                     cycle frequency
                                                     specified in Sec.
                                                     63.8(c)(4)(ii) is
                                                     ``once every hour''
                                                     rather than ``for
                                                     each successive 15-
                                                     minute period.''
63.8(c)(5)-63.8(c)(8).......  No..................  This subpart
                                                     specifies
                                                     continuous
                                                     monitoring system
                                                     requirements.
63.8(d).....................  No..................  This subpart
                                                     specifies quality
                                                     control procedures
                                                     for continuous
                                                     monitoring systems.
63.8(e).....................  Yes.                  ....................
 
                              * * * * * * *
63.8(g).....................  No..................  This subpart
                                                     specifies data
                                                     reduction
                                                     procedures in Sec.
                                                     Sec.   63.655(i)(3)
                                                     and 63.671(d).
 
                              * * * * * * *
63.10(b)(2)(i)..............  No.                   ....................
63.10(b)(2)(ii).............  No..................  Sec.   63.655(i)
                                                     specifies the
                                                     records that must
                                                     be kept.
 
                              * * * * * * *
63.10(b)(2)(iv).............  No.                   ....................
63.10(b)(2)(v)..............  No.                   ....................
 
                              * * * * * * *
63.10(b)(2)(vii)............  No..................  Sec.   63.655(i)
                                                     specifies records
                                                     to be kept for
                                                     parameters measured
                                                     with continuous
                                                     monitors.
 
                              * * * * * * *
63.10(c)(9).................  No..................  Reserved.
63.10(c)(10)-63.10(c)(11)...  No..................  Sec.   63.655(i)
                                                     specifies the
                                                     records that must
                                                     be kept.
63.10(c)(12)-63.10(c)(15)...  No.                   ....................
 
                              * * * * * * *
63.10(d)(2).................  No..................  Although Sec.
                                                     63.655(f) specifies
                                                     performance test
                                                     reporting, EPA may
                                                     approve other
                                                     timeframes for
                                                     submittal of
                                                     performance test
                                                     data.
 
                              * * * * * * *
63.10(d)(5).................  No..................  Sec.   63.655(g)
                                                     specifies the
                                                     reporting
                                                     requirements.
 
                              * * * * * * *
63.11.......................  Yes.................  Except that flares
                                                     complying with Sec.
                                                       63.670 are not
                                                     subject to the
                                                     requirements of
                                                     Sec.   63.11(b).
63.12-63.16.................  Yes.
------------------------------------------------------------------------
\a\ Wherever subpart A of this part specifies ``postmark'' dates,
  submittals may be sent by methods other than the U.S. Mail (e.g., by
  fax or courier). Submittals shall be sent by the specified dates, but
  a postmark is not required.


0
35. The appendix to subpart CC is amended in table 10 by:
0
a. Redesignating the entry ``Flare'' as ``Flare (if meeting the 
requirements of Sec. Sec.  63.643 and 63.644)'';
0
b. Adding the entry ``Flare (if meeting the requirements of Sec. Sec.  
63.670 and 63.671)'' after newly redesignated entry ``Flare (if meeting 
the requirements of Sec. Sec.  63.643 and 63.644)'';
0
c. Revising the entry ``All control devices''; and
0
d. Revising footnote i.
    The revisions and additions read as follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

  Table 10--Miscellaneous Process Vents--Monitoring, Recordkeeping and
Reporting Requirements for Complying With 98 Weight-Percent Reduction of
Total Organic HAP Emissions or a Limit of 20 Parts per Million by Volume
------------------------------------------------------------------------
                                                     Recordkeeping and
                                 Parameters to be        reporting
        Control device            monitored \a\       requirements for
                                                    monitored parameters
------------------------------------------------------------------------
 
                              * * * * * * *
Flare (if meeting the           The parameters     1. Records as
 requirements of Sec.  Sec.      specified in       specified in Sec.
 63.670 and 63.671).             Sec.   63.670.     63.655(i)(9).
                                                   2. Report information
                                                    as specified in Sec.
                                                      63.655(g)(11)--
                                                    PR.\g\
All control devices...........  Presence of flow   1. Hourly records of
                                 diverted to the    whether the flow
                                 atmosphere from    indicator was
                                 the control        operating and
                                 device (Sec.       whether flow was
                                 63.644(c)(1)) or   detected at any time
                                                    during each hour.
                                                    Record and report
                                                    the times and
                                                    durations of all
                                                    periods when the
                                                    vent stream is
                                                    diverted through a
                                                    bypass line or the
                                                    monitor is not
                                                    operating--PR.\g\

[[Page 75270]]

 
                                Monthly            1. Records that
                                 inspections of     monthly inspections
                                 sealed valves      were performed.
                                 (Sec.             2. Record and report
                                 63.644(c)(2)).     all monthly
                                                    inspections that
                                                    show the valves are
                                                    not closed or the
                                                    seal has been
                                                    changed--PR.\g\
------------------------------------------------------------------------
\a\ Regulatory citations are listed in parentheses.
 * * * * * * *
\g\ PR = Periodic Reports described in Sec.   63.655(g).
 * * * * * * *
\i\ Process vents that are routed to refinery fuel gas systems are not
  regulated under this subpart provided that on and after January 30,
  2019, any flares receiving gas from that fuel gas system are in
  compliance with Sec.   63.670. No monitoring, recordkeeping, or
  reporting is required for boilers and process heaters that combust
  refinery fuel gas.


0
36. The appendix to subpart CC is amended by adding table 11 to read as 
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

                                   Table 11--Compliance Dates and Requirements
----------------------------------------------------------------------------------------------------------------
                                          Then the owner or         And the owner or
  If the construction/reconstruction     operator must comply    operator must achieve   Except as provided in .
          date \a\ is . . .                   with . . .            compliance . . .               . .
----------------------------------------------------------------------------------------------------------------
(1) After June 30, 2014..............  (i) Requirements for     Upon initial startup or  Sec.   63.640(k), (l)
                                        new sources in Sec.      February 1, 2016,        and (m).
                                        Sec.   63.640 through    whichever is later.
                                        63.642, 63.647, 63.650
                                        through 63.653, and
                                        63.656 through 63.660.
                                       (ii) The new source      Upon initial startup or  Sec.   63.640(k), (l)
                                        requirements in Sec.     October 28, 2009,        and (m).
                                        63.654 for heat          whichever is later.
                                        exchange systems.
(2) After September 4, 2007 but on or  (i) Requirements for     Upon initial startup...  Sec.   63.640(k), (l)
 before June 30, 2014.                  new sources in Sec.                               and (m).
                                        Sec.   63.640 through
                                        63.653 and 63.656 \b\
                                        \c\.
                                       (ii) Requirements for    On or before January     Sec.   63.640(k), (l)
                                        new sources in Sec.      30, 2019.                and (m).
                                        Sec.   63.640 through
                                        63.645, Sec.  Sec.
                                        63.647 through 63.653,
                                        and Sec.  Sec.
                                        63.656 and 63.657 \b\.
                                       (iii) Requirements for   On or before January     Sec.   63.640(k), (l)
                                        existing sources in      30, 2018.                and (m).
                                        Sec.   63.658.
                                       (iv) Requirements for    On or before April 29,   Sec.   63.640(k), (l)
                                        new sources in Sec.      2016.                    and (m).
                                        63.660 \c\.
                                       (v) The new source       Upon initial startup or  Sec.   63.640(k), (l)
                                        requirements in Sec.     October 28, 2009,        and (m).
                                        63.654 for heat          whichever is later.
                                        exchange systems.
(3) After July 14, 1994 but on or      (i) Requirements for     Upon initial startup or  Sec.   63.640(k), (l)
 before September 4, 2007.              new sources in Sec.      August 18, 1995,         and (m).
                                        Sec.   63.640 through    whichever is later.
                                        63.653 and 63.656 \d\
                                        \e\.
                                       (ii) Requirements for    On or before January     Sec.   63.640(k), (l)
                                        new sources in Sec.      30, 2019.                and (m).
                                        Sec.   63.640 through
                                        63.645, 63.647 through
                                        63.653, and 63.656 and
                                        63.657 \d\.
                                       (iii) Requirements for   On or before January     Sec.   63.640(k), (l)
                                        existing sources in      30, 2018.                and (m).
                                        Sec.   63.658.
                                       (iv) Requirements for    On or before April 29,   Sec.   63.640(k), (l)
                                        new sources in Sec.      2016.                    and (m).
                                        63.660 \e\.
                                       (v) The existing source  On or before October     Sec.   63.640(k), (l)
                                        requirements in Sec.     29, 2012.                and (m).
                                        63.654 for heat
                                        exchange systems.
(4) On or before July 14, 1994.......  (i) Requirements for     (a) On or before August  (1) Sec.   63.640(k),
                                        existing sources in      18, 1998.                (l) and (m).
                                        Sec.  Sec.   63.640                              (2) Sec.   63.6(c)(5)
                                        through 63.653 and                                of subpart A of this
                                        63.656 \f\ \g\.                                   part or unless an
                                                                                          extension has been
                                                                                          granted by the
                                                                                          Administrator as
                                                                                          provided in Sec.
                                                                                          63.6(i) of subpart A
                                                                                          of this part.
                                       (ii) Requirements for    On or before January     Sec.   63.640(k), (l)
                                        existing sources in      30, 2019.                and (m).
                                        Sec.  Sec.   63.640
                                        through 63.645, 63.647
                                        through 63.653, and
                                        63.656 and 63.657 \f\.

[[Page 75271]]

 
                                       (iii) Requirements for   On or before January     Sec.   63.640(k), (l)
                                        existing sources in      30, 2018.                and (m).
                                        Sec.   63.658.
                                       (iv) Requirements for    On or before April 29,   Sec.   63.640(k), (l)
                                        existing sources in      2016.                    and (m).
                                        Sec.   63.660 \g\.
 (v) The existing source requirements  On or before October     Sec.   63.640(k), (l)
 in Sec.   63.654 for heat exchange     29, 2012.                and (m).
 systems
----------------------------------------------------------------------------------------------------------------
\a\ For purposes of this table, the construction/reconstruction date means the date of construction or
  reconstruction of an entire affected source or the date of a process unit addition or change meeting the
  criteria in Sec.   63.640(i) or (j). If a process unit addition or change does not meet the criteria in Sec.
  63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources.
\b\ Between the compliance dates in items (2)(i) and (2)(ii) of this table, the owner or operator may elect to
  comply with either the requirements in item (2)(i) or item (2)(ii) of this table. The requirements in item
  (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(ii) of
  this table.
\c\ Between the compliance dates in items (2)(i) and (2)(iv) of this table, the owner or operator may elect to
  comply with either the requirements in item (2)(i) or item (2)(iv) of this table. The requirements in item
  (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iv) of
  this table.
\d\ Between the compliance dates in items (3)(i) and (3)(ii) of this table, the owner or operator may elect to
  comply with either the requirements in item (3)(i) or item (3)(ii) of this table. The requirements in item
  (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(ii) of
  this table.
\e\ Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or operator may elect to
  comply with either the requirements in item (3)(i) or item (3)(iv) of this table. The requirements in item
  (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iv) of
  this table.
\f\ Between the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator may elect to
  comply with either the requirements in item (4)(i) or item (4)(ii) of this table. The requirements in item
  (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(ii) of
  this table.
\g\ Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or operator may elect to
  comply with either the requirements in item (4)(i) or item (4)(iv) of this table. The requirements in item
  (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iv) of
  this table.


0
37. The appendix to subpart CC is amended by adding table 12 to read as 
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

                                    Table 12--Individual Component Properties
----------------------------------------------------------------------------------------------------------------
                                                                                  NHVi  (British
                                                   MWi  (pounds     CMNi  (mole    thermal units   LFLi  (volume
          Component           Molecular  formula    per pound-       per mole)      per standard        %)
                                                       mole)                        cubic foot)
----------------------------------------------------------------------------------------------------------------
Acetylene...................  C2H2..............           26.04               2           1,404             2.5
Benzene.....................  C6H6..............           78.11               6           3,591             1.3
1,2-Butadiene...............  C4H6..............           54.09               4           2,794             2.0
1,3-Butadiene...............  C4H6..............           54.09               4           2,690             2.0
iso-Butane..................  C4H10.............           58.12               4           2,957             1.8
n-Butane....................  C4H10.............           58.12               4           2,968             1.8
cis-Butene..................  C4H8..............           56.11               4           2,830             1.6
iso-Butene..................  C4H8..............           56.11               4           2,928             1.8
trans-Butene................  C4H8..............           56.11               4           2,826             1.7
Carbon Dioxide..............  CO2...............           44.01               1               0         [infin]
Carbon Monoxide.............  CO................           28.01               1             316            12.5
Cyclopropane................  C3H6..............           42.08               3           2,185             2.4
Ethane......................  C2H6..............           30.07               2           1,595             3.0
Ethylene....................  C2H4..............           28.05               2           1,477             2.7
Hydrogen....................  H2................            2.02               0        1,212\a\             4.0
Hydrogen Sulfide............  H2S...............           34.08               0             587             4.0
Methane.....................  CH4...............           16.04               1             896             5.0
Methyl-Acetylene............  C3H4..............           40.06               3           2,088             1.7
Nitrogen....................  N2................           28.01               0               0         [infin]
Oxygen......................  O2................           32.00               0               0         [infin]
Pentane+ (C5+)..............  C5H12.............           72.15               5           3,655             1.4
Propadiene..................  C3H4..............           40.06               3           2,066            2.16
Propane.....................  C3H8..............           44.10               3           2,281             2.1
Propylene...................  C3H6..............           42.08               3           2,150             2.4
Water.......................  H2O...............           18.02               0               0         [infin]
----------------------------------------------------------------------------------------------------------------
\a\ The theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the flare requirement
  in this subpart, a net heating value of 1,212 Btu/scf shall be used.


[[Page 75272]]


0
38. The appendix to subpart CC is amended by adding table 13 to read as 
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

     Table 13--Calibration and Quality Control Requirements for CPMS
------------------------------------------------------------------------
                                 Minimum accuracy       Calibration
           Parameter               requirements         requirements
------------------------------------------------------------------------
Temperature...................  1      Conduct calibration
                                 percent over the   checks at least
                                 normal range of    annually; conduct
                                 temperature        calibration checks
                                 measured,          following any period
                                 expressed in       of more than 24
                                 degrees Celsius    hours throughout
                                 (C), or 2.8        which the
                                 degrees C,         temperature exceeded
                                 whichever is       the manufacturer's
                                 greater.           specified maximum
                                                    rated temperature or
                                                    install a new
                                                    temperature sensor.
                                                   At least quarterly,
                                                    inspect all
                                                    components for
                                                    integrity and all
                                                    electrical
                                                    connections for
                                                    continuity,
                                                    oxidation, and
                                                    galvanic corrosion,
                                                    unless the CPMS has
                                                    a redundant
                                                    temperature sensor.
                                                   Record the results of
                                                    each calibration
                                                    check and
                                                    inspection.
                                                   Locate the
                                                    temperature sensor
                                                    in a position that
                                                    provides a
                                                    representative
                                                    temperature; shield
                                                    the temperature
                                                    sensor system from
                                                    electromagnetic
                                                    interference and
                                                    chemical
                                                    contaminants.
Flow Rate for All Flows Other   5      Conduct a flow sensor
 Than Flare Vent Gas.            percent over the   calibration check at
                                 normal range of    least biennially
                                 flow measured or   (every two years);
                                 1.9 liters per     conduct a
                                 minute (0.5        calibration check
                                 gallons per        following any period
                                 minute),           of more than 24
                                 whichever is       hours throughout
                                 greater, for       which the flow rate
                                 liquid flow.       exceeded the
                                                    manufacturer's
                                                    specified maximum
                                                    rated flow rate or
                                                    install a new flow
                                                    sensor.
                                5      At least quarterly,
                                 percent over the   inspect all
                                 normal range of    components for
                                 flow measured or   leakage, unless the
                                 280 liters per     CPMS has a redundant
                                 minute (10 cubic   flow sensor.
                                 feet per
                                 minute),
                                 whichever is
                                 greater, for gas
                                 flow.
                                5      Record the results of
                                 percent over the   each calibration
                                 normal range       check and
                                 measured for       inspection.
                                 mass flow.        Locate the flow
                                                    sensor(s) and other
                                                    necessary equipment
                                                    (such as
                                                    straightening vanes)
                                                    in a position that
                                                    provides
                                                    representative flow;
                                                    reduce swirling flow
                                                    or abnormal velocity
                                                    distributions due to
                                                    upstream and
                                                    downstream
                                                    disturbances.
Flare Vent Gas Flow Rate......  20     Conduct a flow sensor
                                 percent of flow    calibration check at
                                 rate at            least biennially
                                 velocities         (every two years);
                                 ranging from       conduct a
                                 0.03 to 0.3        calibration check
                                 meters per         following any period
                                 second (0.1 to 1   of more than 24
                                 feet per second).  hours throughout
                                5       which the flow rate
                                 percent of flow    exceeded the
                                 rate at            manufacturer's
                                 velocities         specified maximum
                                 greater than 0.3   rated flow rate or
                                 meters per         install a new flow
                                 second (1 feet     sensor.
                                 per second).      At least quarterly,
                                                    inspect all
                                                    components for
                                                    leakage, unless the
                                                    CPMS has a redundant
                                                    flow sensor.
                                                   Record the results of
                                                    each calibration
                                                    check and
                                                    inspection.
                                                   Locate the flow
                                                    sensor(s) and other
                                                    necessary equipment
                                                    (such as
                                                    straightening vanes)
                                                    in a position that
                                                    provides
                                                    representative flow;
                                                    reduce swirling flow
                                                    or abnormal velocity
                                                    distributions due to
                                                    upstream and
                                                    downstream
                                                    disturbances.
Pressure......................  5      Review pressure
                                 percent over the   sensor readings at
                                 normal operating   least once a week
                                 range or 0.12      for straightline
                                 kilopascals (0.5   (unchanging)
                                 inches of water    pressure and perform
                                 column),           corrective action to
                                 whichever is       ensure proper
                                 greater.           pressure sensor
                                                    operation if
                                                    blockage is
                                                    indicated.
                                                   Using an instrument
                                                    recommended by the
                                                    sensor's
                                                    manufacturer, check
                                                    gauge calibration
                                                    and transducer
                                                    calibration
                                                    annually; conduct
                                                    calibration checks
                                                    following any period
                                                    of more than 24
                                                    hours throughout
                                                    which the pressure
                                                    exceeded the
                                                    manufacturer's
                                                    specified maximum
                                                    rated pressure or
                                                    install a new
                                                    pressure sensor.
                                                   At least quarterly,
                                                    inspect all
                                                    components for
                                                    integrity, all
                                                    electrical
                                                    connections for
                                                    continuity, and all
                                                    mechanical
                                                    connections for
                                                    leakage, unless the
                                                    CPMS has a redundant
                                                    pressure sensor.
                                                   Record the results of
                                                    each calibration
                                                    check and
                                                    inspection.
                                                   Locate the pressure
                                                    sensor(s) in a
                                                    position that
                                                    provides a
                                                    representative
                                                    measurement of the
                                                    pressure and
                                                    minimizes or
                                                    eliminates pulsating
                                                    pressure, vibration,
                                                    and internal and
                                                    external corrosion.
Net Heating Value by            2      Specify calibration
 Calorimeter.                    percent of span.   requirements in your
                                                    site specific CPMS
                                                    monitoring plan.
                                                    Calibration
                                                    requirements should
                                                    follow
                                                    manufacturer's
                                                    recommendations at a
                                                    minimum.
                                                   Temperature control
                                                    (heated and/or
                                                    cooled as necessary)
                                                    the sampling system
                                                    to ensure proper
                                                    year-round
                                                    operation.
                                                   Where feasible,
                                                    select a sampling
                                                    location at least
                                                    two equivalent
                                                    diameters downstream
                                                    from and 0.5
                                                    equivalent diameters
                                                    upstream from the
                                                    nearest disturbance.
                                                    Select the sampling
                                                    location at least
                                                    two equivalent duct
                                                    diameters from the
                                                    nearest control
                                                    device, point of
                                                    pollutant
                                                    generation, air in-
                                                    leakages, or other
                                                    point at which a
                                                    change in the
                                                    pollutant
                                                    concentration or
                                                    emission rate
                                                    occurs.

[[Page 75273]]

 
Net Heating Value by Gas        As specified in    Follow the procedure
 Chromatograph.                  Performance        in Performance
                                 Specification 9    Specification 9 of
                                 of 40 CFR part     40 CFR part 60,
                                 60, appendix B     appendix B, except
                                                    that a single daily
                                                    mid-level
                                                    calibration check
                                                    can be used (rather
                                                    than triplicate
                                                    analysis), the multi-
                                                    point calibration
                                                    can be conducted
                                                    quarterly (rather
                                                    than monthly), and
                                                    the sampling line
                                                    temperature must be
                                                    maintained at a
                                                    minimum temperature
                                                    of 60 [deg]C (rather
                                                    than 120 [deg]C).
Hydrogen analyzer.............  2      Specify calibration
                                 percent over the   requirements in your
                                 concentration      site specific CPMS
                                 measured or 0.1    monitoring plan.
                                 volume percent,    Calibration
                                 whichever is       requirements should
                                 greater.           follow
                                                    manufacturer's
                                                    recommendations at a
                                                    minimum.
                                                   Select the sampling
                                                    location at least
                                                    two equivalent duct
                                                    diameters from the
                                                    nearest control
                                                    device, point of
                                                    pollutant
                                                    generation, air in-
                                                    leakages, or other
                                                    point at which a
                                                    change in the
                                                    pollutant
                                                    concentration
                                                    occurs.
------------------------------------------------------------------------

Subpart UUU---National Emission Standards for Hazardous Air 
Pollutants for Petroleum Refineries: Catalytic Cracking Units, 
Catalytic Reforming Units, and Sulfur Recovery Units

0
39. Section 63.1562 is amended by revising paragraphs (b)(3) and (f)(5) 
to read as follows:


Sec.  63.1562  What parts of my plant are covered by this subpart?

* * * * *
    (b) * * *
    (3) The process vent or group of process vents on Claus or other 
types of sulfur recovery plant units or the tail gas treatment units 
serving sulfur recovery plants that are associated with sulfur 
recovery.
* * * * *
    (f) * * *
    (5) Gaseous streams routed to a fuel gas system, provided that on 
and after January 30, 2019, any flares receiving gas from the fuel gas 
system are subject to Sec.  63.670.

0
40. Section 63.1564 is amended by:
0
a. Revising paragraphs (a)(1) and (2);
0
b. Adding paragraph (a)(5);
0
c. Removing the equation following paragraph (b)(4)(ii) and adding it 
after paragraph (b)(4)(iii) introductory text;
0
d. Revising paragraphs (b)(2), (b)(4)(i) and (ii), and (b)(4)(iv); and
0
e. Adding paragraph (c)(5).
    The revisions and additions read as follows:


Sec.  63.1564  What are my requirements for metal HAP emissions from 
catalytic cracking units?

    (a) * * *
    (1) Except as provided in paragraph (a)(5) of this section, meet 
each emission limitation in Table 1 of this subpart that applies to 
you. If your catalytic cracking unit is subject to the NSPS for PM in 
Sec.  60.102 of this chapter or is subject to Sec.  60.102a(b)(1) of 
this chapter, you must meet the emission limitations for NSPS units. If 
your catalytic cracking unit is not subject to the NSPS for PM, you can 
choose from the four options in paragraphs (a)(1)(i) through (vi) of 
this section:
    (i) You can elect to comply with the NSPS for PM in Sec.  60.102 of 
this chapter (Option 1a);
    (ii) You can elect to comply with the NSPS for PM coke burn-off 
emission limit in Sec.  60.102a(b)(1) of this chapter (Option 1b);
    (iii) You can elect to comply with the NSPS for PM concentration 
limit in Sec.  60.102a(b)(1) of this chapter (Option 1c);
    (iv) You can elect to comply with the PM per coke burn-off emission 
limit in Sec.  60.102a(b)(1) of this chapter (Option 2);
    (v) You can elect to comply with the Nickel (Ni) lb/hr emission 
limit (Option 3); or
    (vi) You can elect to comply with the Ni per coke burn-off emission 
limit (Option 4).
    (2) Comply with each operating limit in Table 2 of this subpart 
that applies to you. When a specific control device may be monitored 
using more than one continuous parameter monitoring system, you may 
select the parameter with which you will comply. You must provide 
notice to the Administrator (or other designated authority) if you 
elect to change the monitoring option.
* * * * *
    (5) During periods of startup, shutdown and hot standby, you can 
choose from the two options in paragraphs (a)(5)(i) and (ii) of this 
section:
    (i) You can elect to comply with the requirements in paragraphs 
(a)(1) and (2) of this section, except catalytic cracking units 
controlled using a wet scrubber must maintain only the liquid to gas 
ratio operating limit (the pressure drop operating limit does not 
apply); or
    (ii) You can elect to maintain the inlet velocity to the primary 
internal cyclones of the catalytic cracking unit catalyst regenerator 
at or above 20 feet per second.
    (b) * * *
    (2) Conduct a performance test for each catalytic cracking unit 
according to the requirements in Sec.  63.1571 and under the conditions 
specified in Table 4 of this subpart.
* * * * *
    (4) * * *
    (i) If you elect Option 1b or Option 2 in paragraph (a)(1)(ii) or 
(iv) of this section, compute the PM emission rate (lb/1,000 lb of coke 
burn-off) for each run using Equations 1, 2, and 3 (if applicable) of 
this section and the site-specific opacity limit, if applicable, using 
Equation 4 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR01DE15.018


Where:

Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from catalyst 
regenerator before adding air or gas streams. Example: You may 
measure upstream or downstream of an

[[Page 75274]]

electrostatic precipitator, but you must measure upstream of a 
carbon monoxide boiler, dscm/min (dscf/min). You may use the 
alternative in either Sec.  63.1573(a)(1) or (2), as applicable, to 
calculate Qr;
Qa = Volumetric flow rate of air to catalytic cracking 
unit catalyst regenerator, as determined from instruments in the 
catalytic cracking unit control room, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in regenerator 
exhaust, percent by volume (dry basis);
%CO = Carbon monoxide concentration in regenerator exhaust, percent 
by volume (dry basis);
%O2 = Oxygen concentration in regenerator exhaust, 
percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) (0.0186 (lb-min)/(hr-dscf-%));
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm) (0.1303 (lb-min)/(hr-dscf));
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) (0.0062 (lb-min)/(hr-dscf-%));
Qoxy = Volumetric flow rate of oxygen-enriched air stream 
to regenerator, as determined from instruments in the catalytic 
cracking unit control room, dscm/min (dscf/min); and
%Oxy = Oxygen concentration in oxygen-enriched air 
stream, percent by volume (dry basis).
[GRAPHIC] [TIFF OMITTED] TR01DE15.019


Where:

E = Emission rate of PM, kg/1,000 kg (lb/1,000 lb) of coke burn-off;
Cs = Concentration of PM, g/dscm (lb/dscf);
Qsd = Volumetric flow rate of the catalytic cracking unit 
catalyst regenerator flue gas as measured by Method 2 in appendix A-
1 to part 60 of this chapter, dscm/hr (dscf/hr);
Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr); 
and
K = Conversion factor, 1.0 (kg2/g)/(1,000 kg) (1,000 lb/
(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TR01DE15.020


Where:

Es = Emission rate of PM allowed, kg/1,000 kg (1b/1,000 
lb) of coke burn-off in catalyst regenerator;
1.0 = Emission limitation, kg coke/1,000 kg (lb coke/1,000 lb);
A = Allowable incremental rate of PM emissions. Before August 1, 
2017, A = 0.18 g/million cal (0.10 lb/million Btu). On or after 
August 1, 2017, A = 0 g/million cal (0 lb/million Btu);
H = Heat input rate from solid or liquid fossil fuel, million cal/hr 
(million Btu/hr). Make sure your permitting authority approves 
procedures for determining the heat input rate;
Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr) 
determined using Equation 1 of this section; and
K' = Conversion factor to units to standard, 1.0 (kg2/g)/
(1,000 kg) (103 lb/(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TR01DE15.021


Where:

Opacity Limit = Maximum permissible hourly average opacity, percent, 
or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the 
source test, percent; and
PMEmRst = PM emission rate measured during the source 
test, lb/1,000 lb coke burn.

    (ii) If you elect Option 1c in paragraph (a)(1)(iii) of this 
section, the PM concentration emission limit, determine the average PM 
concentration from the initial performance test used to certify your PM 
CEMS.
* * * * *
    (iv) If you elect Option 4 in paragraph (a)(1)(vi) of this section, 
the Ni per coke burn-off emission limit, compute your Ni emission rate 
using Equations 1 and 8 of this section and your site-specific Ni 
operating limit (if you use a continuous opacity monitoring system) 
using Equations 9 and 10 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR01DE15.022


Where:

ENi2 = Normalized mass emission rate of Ni, mg/kg coke 
(lb/1,000 lb coke).
[GRAPHIC] [TIFF OMITTED] TR01DE15.023



[[Page 75275]]


Where:

Opacity2 = Opacity value for use in Equation 10 of this 
section, percent, or 10 percent, whichever is greater; and
NiEmR2st = Average Ni emission rate calculated as the 
arithmetic average Ni emission rate using Equation 8 of this section 
for each of the performance test runs, mg/kg coke.

[GRAPHIC] [TIFF OMITTED] TR01DE15.024


Where:

Ni Operating Limit2 = Maximum permissible hourly average 
Ni operating limit, percent-ppmw-acfm-hr/kg coke, i.e., your site-
specific Ni operating limit; and
Rc,st = Coke burn rate from Equation 1 of this section, 
as measured during the initial performance test, kg coke/hr.

* * * * *
    (c) * * *
    (5) If you elect to comply with the alternative limit in paragraph 
(a)(5)(ii) of this section during periods of startup, shutdown, and hot 
standby, demonstrate continuous compliance by:
    (i) Collecting the volumetric flow rate from the catalyst 
regenerator (in acfm) and determining the average flow rate for each 
hour. For events lasting less than one hour, determine the average flow 
rate during the event.
    (ii) Determining the cumulative cross-sectional area of the primary 
internal cyclone inlets in square feet (ft2) using design 
drawings of the primary (first-stage) internal cyclones to determine 
the inlet cross-sectional area of each primary internal cyclone and 
summing the cross-sectional areas for all primary internal cyclones in 
the catalyst regenerator or, if primary cyclones. If all primary 
internal cyclones are identical, you may alternatively determine the 
inlet cross-sectional area of one primary internal cyclone using design 
drawings and multiply that area by the total number of primary internal 
cyclones in the catalyst regenerator.
    (iii) Calculating the inlet velocity to the primary internal 
cyclones in square feet per second (ft2/sec) by dividing the 
average volumetric flow rate (acfm) by the cumulative cross-sectional 
area of the primary internal cyclone inlets (ft2) and by 60 
seconds/minute (for unit conversion).
    (iv) Maintaining the inlet velocity to the primary internal 
cyclones at or above 20 feet per second for each hour during the 
startup, shutdown, or hot standby event or, for events lasting less 
than 1 hour, for the duration of the event.
0
41. Section 63.1565 is amended by revising paragraph (a)(1) 
introductory text and adding paragraph (a)(5) to read as follows:


Sec.  63.1565  What are my requirements for organic HAP emissions from 
catalytic cracking units?

    (a) * * *
    (1) Except as provided in paragraph (a)(5) of this section, meet 
each emission limitation in Table 8 of this subpart that applies to 
you. If your catalytic cracking unit is subject to the NSPS for carbon 
monoxide (CO) in Sec.  60.103 of this chapter or is subject to Sec.  
60.102a(b)(4) of this chapter, you must meet the emission limitations 
for NSPS units. If your catalytic cracking unit is not subject to the 
NSPS for CO, you can choose from the two options in paragraphs 
(a)(1)(i) through (ii) of this section:
* * * * *
    (5) During periods of startup, shutdown and hot standby, you can 
choose from the two options in paragraphs (a)(5)(i) and (ii) of this 
section:
    (i) You can elect to comply with the requirements in paragraphs 
(a)(1) and (2) of this section; or
    (ii) You can elect to maintain the oxygen (O2) 
concentration in the exhaust gas from your catalyst regenerator at or 
above 1 volume percent (dry basis).
* * * * *

0
42. Section 63.1566 is amended by revising paragraphs (a)(1) 
introductory text, (a)(1)(i), and (a)(4) to read as follows:


Sec.  63.1566  What are my requirements for organic HAP emissions from 
catalytic reforming units?

    (a) * * *
    (1) Meet each emission limitation in Table 15 of this subpart that 
applies to you. You can choose from the two options in paragraphs 
(a)(1)(i) and (ii) of this section.
    (i) You can elect to vent emissions of total organic compounds 
(TOC) to a flare (Option 1). On and after January 30, 2019, the flare 
must meet the requirements of Sec.  63.670. Prior to January 30, 2019, 
the flare must meet the control device requirements in Sec.  63.11(b) 
or the requirements of Sec.  63.670.
* * * * *
    (4) The emission limitations in Tables 15 and 16 of this subpart do 
not apply to emissions from process vents during passive depressuring 
when the reactor vent pressure is 5 pounds per square inch gauge (psig) 
or less. The emission limitations in Tables 15 and 16 of this subpart 
do apply to emissions from process vents during active purging 
operations (when nitrogen or other purge gas is actively introduced to 
the reactor vessel) or active depressuring (using a vacuum pump, 
ejector system, or similar device) regardless of the reactor vent 
pressure.
* * * * *

0
43. Section 63.1568 is amended by revising paragraphs (a)(1) 
introductory text and (a)(1)(i) and adding paragraph (a)(4) to read as 
follows:


Sec.  63.1568  What are my requirements for HAP emissions from sulfur 
recovery units?

    (a) * * *
    (1) Meet each emission limitation in Table 29 of this subpart that 
applies to you. If your sulfur recovery unit is subject to the NSPS for 
sulfur oxides in Sec.  60.104 or Sec.  60.102a(f)(1) of this chapter, 
you must meet the emission limitations for NSPS units. If your sulfur 
recovery unit is not subject to one of these NSPS for sulfur oxides, 
you can choose from the options in paragraphs (a)(1)(i) through (ii) of 
this section:
    (i) You can elect to meet the NSPS requirements in Sec.  
60.104(a)(2) or Sec.  60.102a(f)(1) of this chapter (Option 1); or
* * * * *
    (4) During periods of startup and shutdown, you can choose from the 
three options in paragraphs (a)(4)(i) through (iii) of this section.
    (i) You can elect to comply with the requirements in paragraphs 
(a)(1) and (2) of this section.
    (ii) You can elect to send any startup or shutdown purge gases to a 
flare. On and after January 30, 2019, the flare must meet the 
requirements of Sec.  63.670. Prior to January 30, 2019, the flare must 
meet the design and operating requirements in Sec.  63.11(b) or the 
requirements of Sec.  63.670.
    (iii) You can elect to send any startup or shutdown purge gases to 
a thermal oxidizer or incinerator operated at a

[[Page 75276]]

minimum hourly average temperature of 1,200 degrees Fahrenheit in the 
firebox and a minimum hourly average outlet oxygen (O2) 
concentration of 2 volume percent (dry basis).
* * * * *

0
44. Section 63.1570 is amended by revising paragraphs (a) through (d) 
and removing paragraph (g) to read as follows:


Sec.  63.1570  What are my general requirements for complying with this 
subpart?

    (a) You must be in compliance with all of the non-opacity standards 
in this subpart at all times.
    (b) You must be in compliance with the opacity and visible emission 
limits in this subpart at all times.
    (c) At all times, you must operate and maintain any affected 
source, including associated air pollution control equipment and 
monitoring equipment, in a manner consistent with safety and good air 
pollution control practices for minimizing emissions. The general duty 
to minimize emissions does not require you to make any further efforts 
to reduce emissions if levels required by the applicable standard have 
been achieved. Determination of whether a source is operating in 
compliance with operation and maintenance requirements will be based on 
information available to the Administrator which may include, but is 
not limited to, monitoring results, review of operation and maintenance 
procedures, review of operation and maintenance records, and inspection 
of the source.
    (d) During the period between the compliance date specified for 
your affected source and the date upon which continuous monitoring 
systems have been installed and validated and any applicable operating 
limits have been set, you must maintain a log that documents the 
procedures used to minimize emissions from process and emissions 
control equipment according to the general duty in paragraph (c) of 
this section.
* * * * *

0
45. Section 63.1571 is amended by:
0
a. Adding paragraphs (a)(5) and (6);
0
b. Revising paragraph (b)(1);
0
c. Removing paragraph (b)(4);
0
d. Redesignating paragraph (b)(5) as paragraph (b)(4); and
0
e. Revising the first sentence of paragraph (d)(2) and paragraph 
(d)(4).
    The revisions and additions read as follows:


Sec.  63.1571  How and when do I conduct a performance test or other 
initial compliance demonstration?

    (a) * * *
    (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.
    (i) Catalytic cracking units monitoring PM concentration with a PM 
CEMS are not required to conduct a periodic PM performance test.
    (ii) Conduct a performance test annually if you comply with the 
emission limits in Item 1 (NSPS subpart J) or Item 4 (Option 1a) in 
Table 1 of this subpart and the PM emissions measured during the most 
recent performance source test are greater than 0.80 g/kg coke burn-
off.
    (6) One-time performance testing for HCN. Conduct a performance 
test for HCN from each catalytic cracking unit no later than August 1, 
2017 according to the applicable requirements in paragraphs (a)(6)(i) 
and (ii) of this section.
    (i) If you conducted a performance test for HCN for a specific 
catalytic cracking unit between March 31, 2011 and February 1, 2016, 
you may submit a request to the Administrator to use the previously 
conducted performance test results to fulfill the one-time performance 
test requirement for HCN for each of the catalytic cracking units 
tested according to the requirements in paragraphs (a)(6)(i)(A) through 
(D) of this section.
    (A) The request must include a copy of the complete source test 
report, the date(s) of the performance test and the test methods used. 
If available, you must also indicate whether the catalytic cracking 
unit catalyst regenerator was operated in partial or complete 
combustion mode during the test, the control device configuration, 
including whether platinum or palladium combustion promoters were used 
during the test, and the CO concentration (measured using CO CEMS or 
manual test method) for each test run.
    (B) You must submit a separate request for each catalytic cracking 
unit tested and you must submit each request to the Administrator no 
later than March 30, 2016.
    (C) The Administrator will evaluate each request with respect to 
the completeness of the request, the completeness of the submitted test 
report and the appropriateness of the test methods used. The 
Administrator will notify the facility within 60 days of receipt of the 
request if it is approved or denied. If the Administrator fails to 
respond to the facility within 60 days of receipt of the request, the 
request will be automatically approved.
    (D) If the request is approved, you do not need to conduct an 
additional HCN performance test. If the request is denied, you must 
conduct an additional HCN performance test following the requirements 
in (a)(6)(ii) of this section.
    (ii) Unless you receive approval to use a previously conducted 
performance test to fulfill the one-time performance test requirement 
for HCN for your catalytic cracking unit as provided in paragraph 
(a)(6)(i) of this section, conduct a performance test for HCN for each 
catalytic cracking unit no later than August 1, 2017 according to 
following requirements:
    (A) Select sampling port location, determine volumetric flow rate, 
conduct gas molecular weight analysis and measure moisture content as 
specified in either Item 1 of Table 4 of this subpart or Item 1 of 
Table 11 of this subpart.
    (B) Measure HCN concentration using Method 320 of appendix A of 
this part. The method ASTM D6348-03 (Reapproved 2010) including Annexes 
A1 through A8 (incorporated by reference--see Sec.  63.14) is an 
acceptable alternative to EPA Method 320 of appendix A of this part. 
The method ASTM D6348-12e1 (incorporated by reference--see Sec.  63.14) 
is an acceptable alternative to EPA Method 320 of appendix A of this 
part with the following two caveats:
    (1) The test plan preparation and implementation in the Annexes to 
ASTM D6348-03 (Reapproved 2010), Sections A1 through A8 are mandatory; 
and
    (2) In ASTM D6348-03 (Reapproved 2010) Annex A5 (Analyte Spiking 
Technique), the percent (%) R must be determined for each target 
analyte (Equation A5.5). In order for the test data to be acceptable 
for a compound, %R must be 70% >= R <= 130%. If the %R value does not 
meet this criterion for a target compound, the test data is not 
acceptable for that compound and the test must be repeated for that 
analyte (i.e., the sampling and/or analytical procedure should be 
adjusted before a retest). The %R value for each compound must be 
reported in the test report, and all field measurements must be 
corrected with the calculated %R value for that compound by using the 
following equation:


[[Page 75277]]


Reported Result = (Measured Concentration in the Stack x 100//% R.

    (C) Measure CO concentration as specified in either Item 2 or 3a of 
Table 11 of this subpart.
    (D) Record and include in the test report an indication of whether 
the catalytic cracking unit catalyst regenerator was operated in 
partial or complete combustion mode and the control device 
configuration, including whether platinum or palladium combustion 
promoters were used during the test.
    (b) * * *
    (1) Performance tests shall be conducted according to the 
provisions of Sec.  63.7(e) except that performance tests shall be 
conducted at maximum representative operating capacity for the process. 
During the performance test, you must operate the control device at 
either maximum or minimum representative operating conditions for 
monitored control device parameters, whichever results in lower 
emission reduction. You must not conduct a performance test during 
startup, shutdown, periods when the control device is bypassed or 
periods when the process, monitoring equipment or control device is not 
operating properly. You may not conduct performance tests during 
periods of malfunction. You must record the process information that is 
necessary to document operating conditions during the test and include 
in such record an explanation to support that the test was conducted at 
maximum representative operating capacity. Upon request, you must make 
available to the Administrator such records as may be necessary to 
determine the conditions of performance tests.
* * * * *
    (d) * * *
    (2) If you must meet the HAP metal emission limitations in Sec.  
63.1564, you elect the option in paragraph (a)(1)(iv) in Sec.  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. * * *
* * * * *
    (4) Except as specified in paragraph (d)(3) of this section, if you 
use continuous parameter monitoring systems, you may adjust one of your 
monitored operating parameters (flow rate, total power and secondary 
current, pressure drop, liquid-to-gas ratio) from the average of 
measured values during the performance test to the maximum value (or 
minimum value, if applicable) representative of worst-case operating 
conditions, if necessary. This adjustment of measured values may be 
done using control device design specifications, manufacturer 
recommendations, or other applicable information. You must provide 
supporting documentation and rationale in your Notification of 
Compliance Status, demonstrating to the satisfaction of your permitting 
authority, that your affected source complies with the applicable 
emission limit at the operating limit based on adjusted values.
* * * * *

0
46. Section 63.1572 is amended by revising paragraphs (c) introductory 
text, (c)(1), (3), and (4) and (d)(1) and (2) to read as follows:


Sec.  63.1572  What are my monitoring installation, operation, and 
maintenance requirements?

* * * * *
    (c) Except for flare monitoring systems, you must install, operate, 
and maintain each continuous parameter monitoring system according to 
the requirements in paragraphs (c)(1) through (5) of this section. For 
flares, on and after January 30, 2019, you must install, operate, 
calibrate, and maintain monitoring systems as specified in Sec. Sec.  
63.670 and 63.671. Prior to January 30, 2019, you must either meet the 
monitoring system requirements in paragraphs (c)(1) through (5) of this 
section or meet the requirements in Sec. Sec.  63.670 and 63.671.
    (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 install, operate, and maintain each 
continuous parameter monitoring system according to the requirements in 
Table 41 of this subpart. 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.
* * * * *
    (3) Each continuous parameter monitoring system must have valid 
hourly average data from at least 75 percent of the hours during which 
the process operated, except for BLD systems.
    (4) Each continuous parameter monitoring system must determine and 
record the hourly average of all recorded readings and if applicable, 
the daily average of all recorded readings for each operating day, 
except for BLD systems. The daily average must cover a 24-hour period 
if operation is continuous or the number of hours of operation per day 
if operation is not continuous, except for BLD systems.
* * * * *
    (d) * * *
    (1) You must conduct all monitoring in continuous operation (or 
collect data at all required intervals) at all times the affected 
source is operating.
    (2) You may not use data recorded during required quality assurance 
or control activities (including, as applicable, calibration checks and 
required zero and span adjustments) for purposes of this regulation, 
including data averages and calculations, for fulfilling a minimum data 
availability requirement, if applicable. You must use all the data 
collected during all other periods in assessing the operation of the 
control device and associated control system.

0
47. Section 63.1573 is amended by:
0
a. Redesignating paragraphs (b), (c), (d), (e), and (f) as paragraphs 
(c), (d), (e), (f), and (g);
0
b. Adding paragraph (b); and
0
c. Revising newly redesignated paragraphs (c) introductory text, (d) 
introductory text, (f) introductory text, and (g)(1) introductory text.
    The revisions and additions read as follows:


Sec.  63.1573  What are my monitoring alternatives?

* * * * *
    (b) What is the approved alternative for monitoring pressure drop? 
You may use this alternative to a continuous parameter monitoring 
system for pressure drop if you operate a jet ejector type wet scrubber 
or other type of wet scrubber equipped with atomizing spray nozzles. 
You shall:
    (1) Conduct a daily check of the air or water pressure to the spray 
nozzles;
    (2) Maintain records of the results of each daily check; and
    (3) Repair or replace faulty (e.g., leaking or plugged) air or 
water lines within 12 hours of identification of an abnormal pressure 
reading.
    (c) What is the approved alternative for monitoring pH or 
alkalinity levels? You may use the alternative in

[[Page 75278]]

paragraph (c)(1) or (2) of this section for a catalytic reforming unit.
* * * * *
    (d) Can I use another type of monitoring system? You may use an 
automated data compression system. An automated data compression system 
does not record monitored operating parameter values at a set frequency 
(e.g., once every hour) but records all values that meet set criteria 
for variation from previously recorded values. You must maintain a 
record of the description of the monitoring system and data 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 of the criteria in 
paragraphs (d)(1) through (5) of this section:
* * * * *
    (f) How do I request to monitor alternative parameters? You must 
submit a request for review and approval or disapproval to the 
Administrator. The request must include the information in paragraphs 
(f)(1) through (5) of this section.
* * * * *
    (g) * * *
    (1) You may request alternative monitoring requirements according 
to the procedures in this paragraph if you meet each of the conditions 
in paragraphs (g)(1)(i) through (iii) of this section:
* * * * *

0
48. Section 63.1574 is amended by revising paragraphs (a)(3) 
introductory text and (f)(1) to read as follows:


Sec.  63.1574  What notifications must I submit and when?

    (a) * * *
    (3) If you are required to conduct an initial performance test, 
performance evaluation, design evaluation, opacity observation, visible 
emission observation, or other initial compliance demonstration, you 
must submit a notification of compliance status according to Sec.  
63.9(h)(2)(ii). You can submit this information in an operating permit 
application, in an amendment to an operating permit application, in a 
separate submission, or in any combination. In a State with an approved 
operating permit program where delegation of authority under section 
112(l) of the CAA has not been requested or approved, you must provide 
a duplicate notification to the applicable Regional Administrator. If 
the required information has been submitted previously, you do not have 
to provide a separate notification of compliance status. Just refer to 
the earlier submissions instead of duplicating and resubmitting the 
previously submitted information.
* * * * *
    (f) * * *
    (1) You must submit the plan to your permitting authority for 
review and approval along with your notification of compliance status. 
While you do not have to include the entire plan in your permit under 
part 70 or 71 of this chapter, you must include the duty to prepare and 
implement the plan as an applicable requirement in your part 70 or 71 
operating permit. You must submit any changes to your permitting 
authority for review and approval and comply with the plan as submitted 
until the change is approved.
* * * * *

0
49. Section 63.1575 is amended by:
0
a. Revising paragraphs (d) introductory text and (d)(1) and (2);
0
b. Adding paragraph (d)(4);
0
c. Revising paragraph (e) introductory text;
0
d. Removing and reserving paragraph (e)(1);
0
e. Revising paragraphs (e)(4) and (6) and (f)(1) and (2);
0
f. Removing and reserving paragraph (h); and
0
g. Adding paragraph (k).
    The revisions and additions read as follows:


Sec.  63.1575  What reports must I submit and when?

* * * * *
    (d) For each deviation from an emission limitation and for each 
deviation from the requirements for work practice standards that occurs 
at an affected source where you are not using a continuous opacity 
monitoring system or a continuous emission monitoring system to comply 
with the emission limitation or work practice standard in this subpart, 
the semiannual compliance report must contain the information in 
paragraphs (c)(1) through (3) of this section and the information in 
paragraphs (d)(1) through (4) of this section.
    (1) The total operating time of each affected source during the 
reporting period and identification of the sources for which there was 
a deviation.
    (2) Information on the number, date, time, duration, and cause of 
deviations (including unknown cause, if applicable).
* * * * *
    (4) The applicable operating limit or work practice standard from 
which you deviated and either the parameter monitor reading during the 
deviation or a description of how you deviated from the work practice 
standard.
    (e) For each deviation from an emission limitation occurring at an 
affected source where you are using a continuous opacity monitoring 
system or a continuous emission monitoring system to comply with the 
emission limitation, you must include the information in paragraphs 
(c)(1) through (3) of this section, in paragraphs (d)(1) through (3) of 
this section, and in paragraphs (e)(2) through (13) of this section.
* * * * *
    (4) An estimate of the quantity of each regulated pollutant emitted 
over the emission limit during the deviation, and a description of the 
method used to estimate the emissions.
* * * * *
    (6) A breakdown of the total duration of the deviations during the 
reporting period and into those that are due to control equipment 
problems, process problems, other known causes, and other unknown 
causes.
* * * * *
    (f) * * *
    (1) You must include the information in paragraph (f)(1)(i) or (ii) 
of this section, if applicable.
    (i) If you are complying with paragraph (k)(1) of this section, a 
summary of the results of any performance test done during the 
reporting period on any affected unit. Results of the performance test 
include the identification of the source tested, the date of the test, 
the percentage of emissions reduction or outlet pollutant concentration 
reduction (whichever is needed to determine compliance) for each run 
and for the average of all runs, and the values of the monitored 
operating parameters.
    (ii) If you are not complying with paragraph (k)(1) of this 
section, a copy of any performance test done during the reporting 
period on any affected unit. The report may 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

[[Page 75279]]

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.
    (2) Any requested change in the applicability of an emission 
standard (e.g., you want to change from the PM standard to the Ni 
standard for catalytic cracking units or from the HCl concentration 
standard to percent reduction for catalytic reforming units) in your 
compliance report. You must include all information and data necessary 
to demonstrate compliance with the new emission standard selected and 
any other associated requirements.
* * * * *
    (k) Electronic submittal of performance test and CEMS performance 
evaluation data. For performance tests or CEMS performance evaluations 
conducted on and after February 1, 2016, if required to submit the 
results of a performance test or CEMS performance evaluation, you must 
submit the results according to the procedures in paragraphs (k)(1) and 
(2) of this section.
    (1) 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.
    (i) For data collected using test methods supported by the EPA's 
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site 
(http://www.epa.gov/ttn/chief/ert/index.html) at the time of the test, 
you must submit the results of the performance test to the EPA via the 
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can 
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance test data must be submitted in a file 
format generated through use of the EPA's ERT or an alternate 
electronic file format consistent with the extensible markup language 
(XML) schema listed on the EPA's ERT Web site. If you claim that some 
of the performance test information being submitted is confidential 
business information (CBI), you must submit a complete file generated 
through the use of the EPA's ERT or an alternate electronic file 
consistent with the XML schema listed on the EPA's ERT Web site, 
including information claimed to be CBI, on a compact disc, flash drive 
or other commonly used electronic storage media to the EPA. The 
electronic storage media must be clearly marked as CBI and mailed to 
U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement 
Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same 
ERT or alternate file with the CBI omitted must be submitted to the EPA 
via the EPA's CDX as described earlier in this paragraph (k)(1)(i).
    (ii) For data collected using test methods that are not supported 
by the EPA's ERT as listed on the EPA's ERT Web site at the time of the 
test, you must submit the results of the performance test to the 
Administrator at the appropriate address listed in Sec.  63.13.
    (2) Within 60 days after the date of completing each CEMS 
performance evaluation required by Sec.  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.
    (i) For performance evaluations of continuous monitoring systems 
measuring relative accuracy test audit (RATA) pollutants that are 
supported by the EPA's ERT as listed on the EPA's ERT Web site at the 
time of the evaluation, you must submit the results of the performance 
evaluation to the EPA via the CEDRI. (CEDRI is accessed through the 
EPA's CDX.) Performance evaluation data must be submitted in a file 
format generated through the use of the EPA's ERT or an alternate file 
format consistent with the XML schema listed on the EPA's ERT Web site. 
If you claim that some of the performance evaluation information being 
submitted is CBI, you must submit a complete file generated through the 
use of the EPA's ERT or an alternate electronic file consistent with 
the XML schema listed on the EPA's ERT Web site, including information 
claimed to be CBI, on a compact disc, flash drive or other commonly 
used electronic storage media to the EPA. The electronic storage media 
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI 
Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 
4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file 
with the CBI omitted must be submitted to the EPA via the EPA's CDX as 
described earlier in this paragraph (k)(2)(i).
    (ii) For any performance evaluations of continuous monitoring 
systems measuring RATA pollutants that are not supported by the EPA's 
ERT as listed on the EPA's ERT Web site at the time of the evaluation, 
you must submit the results of the performance evaluation to the 
Administrator at the appropriate address listed in Sec.  63.13.

0
50. Section 63.1576 is amended by revising paragraphs (a)(2) and (b)(3) 
and (5) to read as follows:


Sec.  63.1576  What records must I keep, in what form, and for how 
long?

    (a) * * *
    (2) The records specified in paragraphs (a)(2)(i) through (iv) of 
this section.
    (i) Record the date, time, and duration of each startup and/or 
shutdown period, recording the periods when the affected source was 
subject to the standard applicable to startup and shutdown.
    (ii) In the event that an affected unit fails to meet an applicable 
standard, record the number of failures. For each failure record the 
date, time and duration of each failure.
    (iii) For each failure to meet an applicable standard, record and 
retain a list of the affected sources or equipment, an estimate of the 
volume of each regulated pollutant emitted over any emission limit and 
a description of the method used to estimate the emissions.
    (iv) Record actions taken to minimize emissions in accordance with 
Sec.  63.1570(c) and any corrective actions taken to return the 
affected unit to its normal or usual manner of operation.
* * * * *
    (b) * * *
    (3) The performance evaluation plan as described in Sec.  
63.8(d)(2) for the life of the affected source or until the affected 
source is no longer subject to the provisions of this part, to be made 
available for inspection, upon request, by the Administrator. If the 
performance evaluation plan is revised, you must keep previous (i.e., 
superseded) versions of the performance evaluation plan on record to be 
made available for inspection, upon request, by the Administrator, for 
a period of 5 years after each revision to the plan. The program of 
corrective action should be included in the plan required under Sec.  
63.8(d)(2).
* * * * *
    (5) Records of the date and time that each deviation started and 
stopped.
* * * * *

0
51. Section 63.1579 is amended by:
0
a. Revising the introductory text;
0
b. Adding, in alphabetical order, a new definition of ``Hot standby''; 
and
0
c. Revising the definitions of ``Deviation'' and ``PM''.
    The revisions read as follows:


Sec.  63.1579  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act (CAA), 
in 40 CFR 63.2, the General Provisions of

[[Page 75280]]

this part (Sec. Sec.  63.1 through 63.15), and in this section as 
listed. If the same term is defined in subpart A of this part and in 
this section, it shall have the meaning given in this section for 
purposes of this subpart.
* * * * *
    Deviation means any instance in which an affected source subject to 
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this 
subpart, including but not limited to any emission limit, operating 
limit, or work practice standard; or
    (2) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit.
* * * * *
    Hot standby means periods when the catalytic cracking unit is not 
receiving fresh or recycled feed oil but the catalytic cracking unit is 
maintained at elevated temperatures, typically using torch oil in the 
catalyst regenerator and recirculating catalyst, to prevent a complete 
shutdown and cold restart of the catalytic cracking unit.
* * * * *
    PM means, for the purposes of this subpart, emissions of 
particulate matter that serve as a surrogate measure of the total 
emissions of particulate matter and metal HAP contained in the 
particulate matter, including but not limited to: Antimony, arsenic, 
beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and 
selenium as measured by Methods 5, 5B or 5F in appendix A-3 to part 60 
of this chapter or by an approved alternative method.
* * * * *

0
52. Table 1 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(a)(1), you shall meet each emission 
limitation in the following table that applies to you.

    Table 1 to Subpart UUU of Part 63--Metal HAP Emission Limits for
                        Catalytic Cracking Units
------------------------------------------------------------------------
                                           You shall meet the following
   For each new or existing catalytic       emission limits for  each
          cracking unit . . .            catalyst regenerator vent . . .
------------------------------------------------------------------------
1. Subject to new source performance     PM emissions must not exceed
 standard (NSPS) for PM in 40 CFR         1.0 gram per kilogram (g/kg)
 60.102 and not electing Sec.             (1.0 lb/1,000 lb) of coke burn-
 60.100(e).                               off, and the opacity of
                                          emissions must not exceed 30
                                          percent, except for one 6-
                                          minute average opacity reading
                                          in any 1-hour period. Before
                                          August 1, 2017, if the
                                          discharged gases pass through
                                          an incinerator or waste heat
                                          boiler in which you burn
                                          auxiliary or in supplemental
                                          liquid or solid fossil fuel,
                                          the incremental rate of PM
                                          emissions must not exceed 43.0
                                          grams per Gigajoule (g/GJ) or
                                          0.10 pounds per million
                                          British thermal units (lb/
                                          million Btu) of heat input
                                          attributable to the liquid or
                                          solid fossil fuel; and the
                                          opacity of emissions must not
                                          exceed 30 percent, except for
                                          one 6-minute average opacity
                                          reading in any 1-hour period.
2. Subject to NSPS for PM in 40 CFR      PM emissions must not exceed
 60.102a(b)(1)(i); or 40 CFR 60.102 and   1.0 g/kg (1.0 lb PM/1,000 lb)
 electing Sec.   60.100(e).               of coke burn-off or, if a PM
                                          CEMS is used, 0.040 grain per
                                          dry standard cubic feet (gr/
                                          dscf) corrected to 0 percent
                                          excess air.
3. Subject to NSPS for PM in 40 CFR      PM emissions must not exceed
 60.102a(b)(1)(ii).                       0.5 g/kg coke burn-off (0.5 lb/
                                          1000 lb coke burn-off) or, if
                                          a PM CEMS is used, 0.020 gr/
                                          dscf corrected to 0 percent
                                          excess air.
4. Option 1a: Elect NSPS subpart J       PM emissions must not exceed
 requirements for PM per coke burn        the limits specified in Item 1
 limit and 30% opacity, not subject to    of this table.
 the NSPS for PM in 40 CFR 60.102 or
 60.102a(b)(1).
5. Option 1b: Elect NSPS subpart Ja      PM emissions must not exceed
 requirements for PM per coke burn-off    1.0 g/kg (1.0 lb PM/1000 lb)
 limit, not subject to the NSPS for PM    of coke burn-off.
 in 40 CFR 60.102 or 60.102a(b)(1).
6. Option 1c: Elect NSPS subpart Ja      PM emissions must not exceed
 requirements for PM concentration        0.040 gr/dscf corrected to 0
 limit, not subject to the NSPS for PM    percent excess air.
 in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off        PM emissions must not exceed
 limit, not subject to the NSPS for PM    1.0 g/kg (1.0 lb PM/1000 lb)
 in 40 CFR 60.102 or 60.102a(b)(1).       of coke burn-off in the
                                          catalyst regenerator.
8. Option 3: Ni lb/hr limit, not         Nickel (Ni) emissions must not
 subject to the NSPS for PM in 40 CFR     exceed 13,000 milligrams per
 60.102 or 60.102a(b)(1).                 hour (mg/hr) (0.029 lb/hr).
9. Option 4: Ni per coke burn-off        Ni emissions must not exceed
 limit, not subject to the NSPS for PM    1.0 mg/kg (0.001 lb/1,000 lb)
 in 40 CFR 60.102 or 60.102a(b)(1).       of coke burn-off in the
                                          catalyst regenerator.
------------------------------------------------------------------------


0
53. Table 2 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(a)(2), you shall meet each operating 
limit in the following table that applies to you.

    Table 2 to Subpart UUU of Part 63--Operating Limits for Metal HAP Emissions From Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
                                           For this type of
  For each new or existing catalytic    continuous  monitoring      For this type of       You shall meet this
         cracking unit . . .                 system . . .        control  device . . .    operating  limit . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for PM in 40    Continuous opacity       Any....................  Maintain the 3-hour
 CFR 60.102 and not electing Sec.       monitoring system.                                rolling average
 60.100(e).                                                                               opacity of emissions
                                                                                          from your catalyst
                                                                                          regenerator vent no
                                                                                          higher than 20
                                                                                          percent.

[[Page 75281]]

 
2. Subject to NSPS for PM in 40 CFR    a. PM CEMS.............  Any....................  Not applicable.
 60.102a(b)(1)(i) or electing Sec.
 60.100(e).
                                       b. Continuous opacity    Cyclone or               Maintain the 3-hour
                                        monitoring system used   electrostatic            rolling average
                                        to comply with a site-   precipitator.            opacity of emissions
                                        specific opacity limit.                           from your catalyst
                                                                                          regenerator vent no
                                                                                          higher than the site-
                                                                                          specific opacity limit
                                                                                          established during the
                                                                                          performance test.
                                       c. Continuous parameter  Electrostatic            i. Maintain the daily
                                        monitoring systems.      precipitator.            average coke burn-off
                                                                                          rate or daily average
                                                                                          flow rate no higher
                                                                                          than the limit
                                                                                          established in the
                                                                                          performance test.
                                                                                         ii. Maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                       d. Continuous parameter  Wet scrubber...........  i. Maintain the 3-hour
                                        monitoring systems.                               rolling average liquid-
                                                                                          to-gas ratio above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                         ii. Except for periods
                                                                                          of startup, shutdown,
                                                                                          and hot standby,
                                                                                          maintain the 3-hour
                                                                                          rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test.\1\
                                       e. Bag leak detection    Fabric filter..........  Maintain particulate
                                        (BLD) system.                                     loading below the BLD
                                                                                          alarm set point
                                                                                          established in the
                                                                                          initial adjustment of
                                                                                          the BLD system or
                                                                                          allowable seasonal
                                                                                          adjustments.
3. Subject to NSPS for PM in 40 CFR    Any....................  Any....................  The applicable
 60.102a(b)(1)(ii).                                                                       operating limits in
                                                                                          Item 2 of this table.
4. Option 1a: Elect NSPS subpart J     Any....................  Any....................  See Item 1 of this
 requirements for PM per coke burn                                                        table.
 limit, not subject to the NSPS for
 PM in 40 CFR 60.102 or 60.102a(b)(1).
5. Option 1b: Elect NSPS subpart Ja    Any....................  Any....................  The applicable
 requirements for PM per coke burn-                                                       operating limits in
 off limit, not subject to the NSPS                                                       Item 2.b, 2.c, 2.d,
 for PM in 40 CFR 60.102 or                                                               and 2.e of this table.
 60.102a(b)(1).
6. Option 1c: Elect NSPS subpart Ja    PM CEMS................  Any....................  Not applicable.
 requirements for PM concentration
 limit, not subject to the NSPS for
 PM in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off      a. Continuous opacity    Cyclone, fabric filter,  See Item 2.b of this
 limit not subject to the NSPS for PM   monitoring system used   or electrostatic         table. Alternatively,
 in 40 CFR 60.102 or 60.102a(b)(1).     to comply with a site-   precipitator.            before August 1, 2017,
                                        specific opacity limit.                           you may maintain the
                                                                                          hourly average opacity
                                                                                          of emissions from your
                                                                                          catalyst generator
                                                                                          vent no higher than
                                                                                          the site-specific
                                                                                          opacity limit
                                                                                          established during the
                                                                                          performance test.
                                       b. Continuous parameter  i. Electrostatic         (1) See Item 2.c.i of
                                        monitoring systems.      precipitator.            this table.
                                                                                         (2) See item 2.c.ii of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average voltage and
                                                                                          secondary current
                                                                                          above the limit
                                                                                          established in the
                                                                                          performance test.

[[Page 75282]]

 
                                                                ii. Wet scrubber.......  (1) See Item 2.d.i of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established in the
                                                                                          performance test.
                                                                                         (2) See Item 2.d.ii of
                                                                                          the table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average pressure drop
                                                                                          above the limit
                                                                                          established in the
                                                                                          performance test (not
                                                                                          applicable to a wet
                                                                                          scrubber of the non-
                                                                                          venturi jet-ejector
                                                                                          design).
                                       c. Bag leak detection    Fabric filter..........  See item 2.e of this
                                        (BLD) system.                                     table.
8. Option 3: Ni lb/hr limit not        a. Continuous opacity    Cyclone, fabric filter,  Maintain the 3-hour
 subject to the NSPS for PM in 40 CFR   monitoring system.       or electrostatic         rolling average Ni
 60.102.                                                         precipitator.            operating value no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average Ni operating
                                                                                          value no higher than
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.
                                       b. Continuous parameter  i. Electrostatic         (1) See Item 2.c.i of
                                        monitoring systems.      precipitator.            this table.
                                                                                         (2) Maintain the
                                                                                          monthly rolling
                                                                                          average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (3) See Item 2.c.ii of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average voltage and
                                                                                          secondary current (or
                                                                                          total power input)
                                                                                          above the established
                                                                                          during the performance
                                                                                          test.
                                                                ii. Wet scrubber.......  (1) Maintain the
                                                                                          monthly rolling
                                                                                          average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (2) See Item 2.d.i of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (3) See Item 2.d.ii of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average pressure drop
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test (not
                                                                                          applicable to a non-
                                                                                          venturi wet scrubber
                                                                                          of the jet-ejector
                                                                                          design).
                                       c. Bag leak detection    Fabric filter..........  See item 2.e of this
                                        (BLD) system.                                     table.

[[Page 75283]]

 
9. Option 4: Ni per coke burn-off      a. Continuous opacity    Cyclone, fabric filter,  Maintain the 3-hour
 limit not subject to the NSPS for PM   monitoring system.       or electrostatic         rolling average Ni
 in 40 CFR 60.102.                                               precipitator.            operating value no
                                                                                          higher than Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may elect to maintain
                                                                                          the daily average Ni
                                                                                          operating value no
                                                                                          higher than the Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test.
                                       b. Continuous parameter  i. Electrostatic         (1) Maintain the
                                        monitoring systems.      precipitator.            monthly rolling
                                                                                          average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (2) See Item 2.c.ii of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average voltage and
                                                                                          secondary current (or
                                                                                          total power input)
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                ii. Wet scrubber.......  (1) Maintain the
                                                                                          monthly rolling
                                                                                          average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (2) See Item 2.d.i of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (3) See Item 2.d.ii of
                                                                                          this table.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may maintain the daily
                                                                                          average pressure drop
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test (not
                                                                                          applicable to a non-
                                                                                          venturi wet scrubber
                                                                                          of the jet-ejector
                                                                                          design).
                                       c. Bag leak detection    Fabric filter..........  See item 2.e of this
                                        (BLD) system.                                     table.
10. During periods of startup,         Any....................  Any....................  Meet the requirements
 shutdown, or hot standby.                                                                in Sec.
                                                                                          63.1564(a)(5).
----------------------------------------------------------------------------------------------------------------
\1\ If 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 Sec.   63.1573(b), and comply with the daily inspections,
  recordkeeping, and repair provisions, instead of a continuous parameter monitoring system for pressure drop
  across the scrubber.


0
54. Table 3 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(b)(1), you shall meet each requirement 
in the following table that applies to you.

  Table 3 to Subpart UUU of Part 63--Continuous Monitoring Systems for
            Metal HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
                                 If you use this
   For each new or existing      type of control     You shall install,
catalytic  cracking unit . . .   device for your   operate, and maintain
                                    vent . . .            a . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM   Any..............  Continuous opacity
 in 40 CFR 60.102 and not                           monitoring system to
 electing Sec.   60.100(e).                         measure and record
                                                    the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent.

[[Page 75284]]

 
2. Subject to NSPS for PM in    a. Cyclone.......  Continuous opacity
 40 CFR 60.102a(b)(1)(i); or    b. Electrostatic    monitoring system to
 in Sec.   60.102 and electing   precipitator.      measure and record
 Sec.   60.100(e); electing to                      the opacity of
 meet the PM per coke burn-off                      emissions from each
 limit.                                             catalyst regenerator
                                                    vent.
                                                   Continuous opacity
                                                    monitoring system to
                                                    measure and record
                                                    the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent; or continuous
                                                    parameter monitoring
                                                    systems to measure
                                                    and record the coke
                                                    burn-off rate or the
                                                    gas flow rate
                                                    entering or exiting
                                                    the control
                                                    device,\1\ the
                                                    voltage, current,
                                                    and secondary
                                                    current to the
                                                    control device.
                                c. Wet scrubber..  Continuous parameter
                                                    monitoring system to
                                                    measure and record
                                                    the pressure drop
                                                    across the
                                                    scrubber,\2\ the
                                                    coke burn-off rate
                                                    or the gas flow rate
                                                    entering or exiting
                                                    the control
                                                    device,\3\ and total
                                                    liquid (or scrubbing
                                                    liquor) flow rate to
                                                    the control device.
                                d. Fabric Filter.  Continuous bag leak
                                                    detection system to
                                                    measure and record
                                                    increases in
                                                    relative particulate
                                                    loading from each
                                                    catalyst regenerator
                                                    vent.
3. Subject to NSPS for PM in    Any..............  Continuous emission
 40 CFR 60.102a(b)(1)(i); or                        monitoring system to
 in Sec.   60.102 and electing                      measure and record
 Sec.   60.100(e); electing to                      the concentration of
 meet the PM concentration                          PM and oxygen from
 limit.                                             each catalyst
                                                    regenerator vent.
4. Subject to NSPS for PM in    Any..............  The applicable
 40 CFR 60.102a(b)(1)(ii)                           continuous
 electing to meet the PM per                        monitoring systems
 coke burn-off limit.                               in item 2 of this
                                                    table.
5. Subject to NSPS for PM in    Any..............  See item 3 of this
 40 CFR 60.102a(b)(1)(ii)                           table.
 electing to meet the PM
 concentration limit.
6. Option 1a: Elect NSPS        Any..............  See item 1 of this
 subpart J, PM per coke burn-                       table.
 off limit, not subject to the
 NSPS for PM in 40 CFR 60.102
 or 60.120a(b)(1).
7. Option 1b: Elect NSPS        Any..............  The applicable
 subpart Ja, PM per coke burn-                      continuous
 off limit, not subject to the                      monitoring systems
 NSPS for PM in 40 CFR 60.102                       in item 2 of this
 or 60.120a(b)(1).                                  table.
8. Option 1c: Elect NSPS        Any..............  See item 3 of this
 subpart Ja, PM concentration                       table.
 limit not subject to the NSPS
 for PM in 40 CFR 60.102 or
 60.120a(b)(1).
9. Option 2: PM per coke burn-  Any..............  The applicable
 off limit, not subject to the                      continuous
 NSPS for PM in 40 CFR 60.102                       monitoring systems
 or 60.120a(b)(1).                                  in item 2 of this
                                                    table.
10. Option 3: Ni lb/hr limit    a. Cyclone.......  Continuous opacity
 not subject to the NSPS for                        monitoring system to
 PM in 40 CFR 60.102 or                             measure and record
 60.102a(b)(1).                                     the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent and continuous
                                                    parameter monitoring
                                                    system to measure
                                                    and record the gas
                                                    flow rate entering
                                                    or exiting the
                                                    control device.\1\
                                b. Electrostatic   Continuous opacity
                                 precipitator.      monitoring system to
                                                    measure and record
                                                    the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent and continuous
                                                    parameter monitoring
                                                    system to measure
                                                    and record the gas
                                                    flow rate entering
                                                    or exiting the
                                                    control device \1\;
                                                    or continuous
                                                    parameter monitoring
                                                    systems to measure
                                                    and record the coke
                                                    burn-off rate or the
                                                    gas flow rate
                                                    entering or exiting
                                                    the control device
                                                    \1\ and the voltage
                                                    and current (to
                                                    measure the total
                                                    power to the system)
                                                    and secondary
                                                    current to the
                                                    control device.
                                c. Wet scrubber..  Continuous parameter
                                                    monitoring system to
                                                    measure and record
                                                    the pressure drop
                                                    across the
                                                    scrubber,\2\ gas
                                                    flow rate entering
                                                    or exiting the
                                                    control device,\1\
                                                    and total liquid (or
                                                    scrubbing liquor)
                                                    flow rate to the
                                                    control device.
                                d. Fabric Filter.  Continuous bag leak
                                                    detection system to
                                                    measure and record
                                                    increases in
                                                    relative particulate
                                                    loading from each
                                                    catalyst regenerator
                                                    vent or the
                                                    monitoring systems
                                                    specified in item
                                                    10.a of this table.
11. Option 4: Ni per coke burn- a. Cyclone.......  Continuous opacity
 off limit not subject to the                       monitoring system to
 NSPS for PM in 40 CFR 60.102                       measure and record
 or 60.102a(b)(1).                                  the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent and continuous
                                                    parameter monitoring
                                                    system to measure
                                                    and record the coke
                                                    burn-off rate and
                                                    the gas flow rate
                                                    entering or exiting
                                                    the control
                                                    device.\1\

[[Page 75285]]

 
                                b. Electrostatic   Continuous opacity
                                 precipitator.      monitoring system to
                                                    measure and record
                                                    the opacity of
                                                    emissions from each
                                                    catalyst regenerator
                                                    vent and continuous
                                                    parameter monitoring
                                                    system to measure
                                                    and record the coke
                                                    burn-off rate and
                                                    the gas flow rate
                                                    entering or exiting
                                                    the control device
                                                    \1\; or continuous
                                                    parameter monitoring
                                                    systems to measure
                                                    and record the coke
                                                    burn-off rate or the
                                                    gas flow rate
                                                    entering or exiting
                                                    the control device
                                                    \1\ and voltage and
                                                    current (to measure
                                                    the total power to
                                                    the system) and
                                                    secondary current to
                                                    the control device.
                                c. Wet scrubber..  Continuous parameter
                                                    monitoring system to
                                                    measure and record
                                                    the pressure drop
                                                    across the
                                                    scrubber,\2\ gas
                                                    flow rate entering
                                                    or exiting the
                                                    control device,\1\
                                                    and total liquid (or
                                                    scrubbing liquor)
                                                    flow rate to the
                                                    control device.
                                d. Fabric Filter.  Continuous bag leak
                                                    detection system to
                                                    measure and record
                                                    increases in
                                                    relative particulate
                                                    loading from each
                                                    catalyst regenerator
                                                    vent or the
                                                    monitoring systems
                                                    specified in item
                                                    11.a of this table.
12. Electing to comply with     Any..............  Continuous parameter
 the operating limits in Sec.                       monitoring system to
  63.1566(a)(5)(iii) during                         measure and record
 periods of startup, shutdown,                      the gas flow rate
 or hot standby.                                    exiting the catalyst
                                                    regenerator.\1\
------------------------------------------------------------------------
\1\ If applicable, you can use the alternative in Sec.   63.1573(a)(1)
  instead of a continuous parameter monitoring system for gas flow rate.
\2\ If 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 Sec.   63.1573(b) instead of a continuous parameter
  monitoring system for pressure drop across the scrubber.


0
55. Table 4 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec. Sec.  63.1564(b)(2) and 63.1571(a)(5), you shall 
meet each requirement in the following table that applies to you.

  Table 4 to Subpart UUU of Part 63--Requirements for Performance Tests for Metal HAP Emissions From Catalytic
                                                 Cracking Units
----------------------------------------------------------------------------------------------------------------
  For each new or existing catalytic
  cracking unit catalyst regenerator        You must . . .            Using . . .           According to these
              vent . . .                                                                    requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Any...............................  a. Select sampling       Method 1 or 1A in        Sampling sites must be
                                        port's location and      appendix A-1 to part     located at the outlet
                                        the number of traverse   60 of this chapter.      of the control device
                                        ports.                                            or the outlet of the
                                                                                          regenerator, as
                                                                                          applicable, and prior
                                                                                          to any releases to the
                                                                                          atmosphere.
                                       b. Determine velocity    Method 2, 2A, 2C, 2D,    .......................
                                        and volumetric flow      or 2F in appendix A-1
                                        rate.                    to part 60 of this
                                                                 chapter, or Method 2G
                                                                 in appendix A-2 to
                                                                 part 60 of this
                                                                 chapter, as applicable.
                                       c. Conduct gas           Method 3, 3A, or 3B in   .......................
                                        molecular weight         appendix A-2 to part
                                        analysis.                60 of this chapter, as
                                                                 applicable.
                                       d. Measure moisture      Method 4 in appendix A-  .......................
                                        content of the stack     3 to part 60 of this
                                        gas.                     chapter.
                                       e. If you use an                                  .......................
                                        electrostatic
                                        precipitator, record
                                        the total number of
                                        fields in the control
                                        system and how many
                                        operated during the
                                        applicable performance
                                        test.
                                       f. If you use a wet                               .......................
                                        scrubber, record the
                                        total amount (rate) of
                                        water (or scrubbing
                                        liquid) and the amount
                                        (rate) of make-up
                                        liquid to the scrubber
                                        during each test run.

[[Page 75286]]

 
2. Subject to the NSPS for PM in 40    a. Measure PM emissions  Method 5, 5B, or 5F (40  You must maintain a
 CFR 60.102 and not elect Sec.                                   CFR part 60, appendix    sampling rate of at
 60.100(e).                                                      A-3) to determine PM     least 0.15 dry
                                                                 emissions and            standard cubic meters
                                                                 associated moisture      per minute (dscm/min)
                                                                 content for units        (0.53 dry standard
                                                                 without wet scrubbers.   cubic feet per minute
                                                                 Method 5 or 5B (40 CFR   (dscf/min)).
                                                                 part 60, appendix A-3)
                                                                 to determine PM
                                                                 emissions and
                                                                 associated moisture
                                                                 content for unit with
                                                                 wet scrubber.
                                       b. Compute coke burn-    Equations 1, 2, and 3    .......................
                                        off rate and PM          of Sec.   63.1564 (if
                                        emission rate (lb/       applicable).
                                        1,000 lb of coke burn-
                                        off).
                                       c. Measure opacity of    Continuous opacity       You must collect
                                        emissions.               monitoring system.       opacity monitoring
                                                                                          data every 10 seconds
                                                                                          during the entire
                                                                                          period of the Method
                                                                                          5, 5B, or 5F
                                                                                          performance test and
                                                                                          reduce the data to 6-
                                                                                          minute averages.
3. Subject to the NSPS for PM in 40    a. Measure PM emissions  Method 5, 5B, or 5F (40  You must maintain a
 CFR 60.102a(b)(1) or elect Sec.                                 CFR part 60, appendix    sampling rate of at
 60.100(e), electing the PM for coke                             A-3) to determine PM     least 0.15 dscm/min
 burn-off limit.                                                 emissions and            (0.53 dscf/min).
                                                                 associated moisture
                                                                 content for units
                                                                 without wet scrubbers.
                                                                 Method 5 or 5B (40 CFR
                                                                 part 60, appendix A-3)
                                                                 to determine PM
                                                                 emissions and
                                                                 associated moisture
                                                                 content for unit with
                                                                 wet scrubber.
                                       b. Compute coke burn-    Equations 1, 2, and 3    .......................
                                        off rate and PM          of Sec.   63.1564 (if
                                        emission rate (lb/       applicable).
                                        1,000 lb of coke burn-
                                        off).
                                       c. Establish site-       Continuous opacity       If you elect to comply
                                        specific limit if you    monitoring system.       with the site-specific
                                        use a COMS.                                       opacity limit in Sec.
                                                                                           63.1564(b)(4)(i), you
                                                                                          must collect opacity
                                                                                          monitoring data every
                                                                                          10 seconds during the
                                                                                          entire period of the
                                                                                          Method 5, 5B, or 5F
                                                                                          performance test. For
                                                                                          site specific opacity
                                                                                          monitoring, reduce the
                                                                                          data to 6-minute
                                                                                          averages; determine
                                                                                          and record the average
                                                                                          opacity for each test
                                                                                          run; and compute the
                                                                                          site-specific opacity
                                                                                          limit using Equation 4
                                                                                          of Sec.   63.1564.
4. Subject to the NSPS for PM in 40    a. Measure PM emissions  Method 5, 5B, or 5F (40  You must maintain a
 CFR 60.102a(b)(1) or elect Sec.                                 CFR part 60, appendix    sampling rate of at
 60.100(e).                                                      A-3) to determine PM     least 0.15 dscm/min
                                                                 emissions and            (0.53 dscf/min).
                                                                 associated moisture
                                                                 content for units
                                                                 without wet scrubbers.
                                                                 Method 5 or 5B (40 CFR
                                                                 part 60, appendix A-3)
                                                                 to determine PM
                                                                 emissions and
                                                                 associated moisture
                                                                 content for unit with
                                                                 wet scrubber.
5. Option 1a: Elect NSPS subpart J     See item 2 of this       .......................  .......................
 requirements for PM per coke burn-     table.
 off limit, not subject to the NSPS
 for PM in 40 CFR 60.102 or
 60.102a(b)(1).
6. Option 1b: Elect NSPS subpart Ja    See item 3 of this
 requirements for PM per coke burn-     table.
 off limit, not subject to the NSPS
 for PM in 40 CFR 60.102 or
 60.102a(b)(1).

[[Page 75287]]

 
7. Option 1c: Elect NSPS requirements  See item 4 of this
 for PM concentration, not subject to   table.
 the NSPS for PM in 40 CFR 60.102 or
 60.102a(b)(1).
8. Option 2: PM per coke burn-off      See item 3 of this
 limit, not subject to the NSPS for     table.
 PM in 40 CFR 60.102 or 60.102a(b)(1).
9. Option 3: Ni lb/hr limit, not       a. Measure               Method 29 (40 CFR part
 subject to the NSPS for PM in 40 CFR   concentration of Ni.     60, appendix A-8).
 60.102 or 60.102a(b)(1).              .......................  Equation 5 of Sec.
                                       b. Compute Ni emission    63.1564.
                                        rate (lb/hr).
                                       c. Determine the         XRF procedure in         You must obtain 1
                                        equilibrium catalyst     appendix A to this       sample for each of the
                                        Ni concentration.        subpart1; or EPA         3 test runs; determine
                                                                 Method 6010B or 6020     and record the
                                                                 or EPA Method 7520 or    equilibrium catalyst
                                                                 7521 in SW-8462; or an   Ni concentration for
                                                                 alternative to the SW-   each of the 3 samples;
                                                                 846 method               and you may adjust the
                                                                 satisfactory to the      laboratory results to
                                                                 Administrator.           the maximum value
                                                                                          using Equation 2 of
                                                                                          Sec.   63.1571.
                                       d. If you use a          i. Equations 6 and 7 of  (1) You must collect
                                        continuous opacity       Sec.   63.1564 using     opacity monitoring
                                        monitoring system,       data from continuous     data every 10 seconds
                                        establish your site-     opacity monitoring       during the entire
                                        specific Ni operating    system, gas flow rate,   period of the initial
                                        limit.                   results of equilibrium   Ni performance test;
                                                                 catalyst Ni              reduce the data to 6-
                                                                 concentration            minute averages; and
                                                                 analysis, and Ni         determine and record
                                                                 emission rate from       the average opacity
                                                                 Method 29 test.          from all the 6-minute
                                                                                          averages for each test
                                                                                          run.
                                                                                         (2) You must collect
                                                                                          gas flow rate
                                                                                          monitoring data every
                                                                                          15 minutes during the
                                                                                          entire period of the
                                                                                          initial Ni performance
                                                                                          test; measure the gas
                                                                                          flow as near as
                                                                                          practical to the
                                                                                          continuous opacity
                                                                                          monitoring system; and
                                                                                          determine and record
                                                                                          the hourly average
                                                                                          actual gas flow rate
                                                                                          for each test run.
10. Option 4: Ni per coke burn-off     a. Measure               Method 29 (40 CFR part
 limit, not subject to the NSPS for     concentration of Ni.     60, appendix A-8).
 PM in 40 CFR 60.102 or 60.102a(b)(1). .......................  Equations 1 and 8 of
                                       b. Compute Ni emission    Sec.   63.1564.
                                        rate (lb/1,000 lb of
                                        coke burn-off).
                                       c. Determine the         See item 6.c. of this    You must obtain 1
                                        equilibrium catalyst     table.                   sample for each of the
                                        Ni concentration.                                 3 test runs; determine
                                                                                          and record the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration for
                                                                                          each of the 3 samples;
                                                                                          and you may adjust the
                                                                                          laboratory results to
                                                                                          the maximum value
                                                                                          using Equation 2 of
                                                                                          Sec.   63.1571.
                                       d. If you use a          i. Equations 9 and 10    (1) You must collect
                                        continuous opacity       of Sec.   63.1564 with   opacity monitoring
                                        monitoring system,       data from continuous     data every 10 seconds
                                        establish your site-     opacity monitoring       during the entire
                                        specific Ni operating    system, coke burn-off    period of the initial
                                        limit.                   rate, results of         Ni performance test;
                                                                 equilibrium catalyst     reduce the data to 6-
                                                                 Ni concentration         minute averages; and
                                                                 analysis, and Ni         determine and record
                                                                 emission rate from       the average opacity
                                                                 Method 29 test.          from all the 6-minute
                                                                                          averages for each test
                                                                                          run.

[[Page 75288]]

 
                                                                                         (2) You must collect
                                                                                          gas flow rate
                                                                                          monitoring data every
                                                                                          15 minutes during the
                                                                                          entire period of the
                                                                                          initial Ni performance
                                                                                          test; measure the gas
                                                                                          flow rate as near as
                                                                                          practical to the
                                                                                          continuous opacity
                                                                                          monitoring system; and
                                                                                          determine and record
                                                                                          the hourly average
                                                                                          actual gas flow rate
                                                                                          for each test run.
                                       e. Record the catalyst                            .......................
                                        addition rate for each
                                        test and schedule for
                                        the 10-day period
                                        prior to the test.
11. If you elect item 5 Option 1b in   a. Establish each        Data from the            .......................
 Table 1, item 7 Option 2 in Table 1,   operating limit in       continuous parameter
 item 8 Option 3 in Table 1, or item    Table 2 of this          monitoring systems and
 9 Option 4 in Table 1 of this          subpart that applies     applicable performance
 subpart and you use continuous         to you.                  test methods.
 parameter monitoring systems.
                                       b. Electrostatic         i. Data from the         (1) You must collect
                                        precipitator or wet      continuous parameter     gas flow rate
                                        scrubber: Gas flow       monitoring systems and   monitoring data every
                                        rate.                    applicable performance   15 minutes during the
                                                                 test methods.            entire period of the
                                                                                          initial performance
                                                                                          test; determine and
                                                                                          record the average gas
                                                                                          flow rate for each
                                                                                          test run.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average gas flow rate
                                                                                          from the test runs.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may determine and
                                                                                          record the maximum
                                                                                          hourly average gas
                                                                                          flow rate from all the
                                                                                          readings.
                                       c. Electrostatic         i. Data from the         (1) You must collect
                                        precipitator: Total      continuous parameter     voltage, current, and
                                        power (voltage and       monitoring systems and   secondary current
                                        current) and secondary   applicable performance   monitoring data every
                                        current.                 test methods.            15 minutes during the
                                                                                          entire period of the
                                                                                          performance test; and
                                                                                          determine and record
                                                                                          the average voltage,
                                                                                          current, and secondary
                                                                                          current for each test
                                                                                          run. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          you may collect
                                                                                          voltage and secondary
                                                                                          current (or total
                                                                                          power input)
                                                                                          monitoring data every
                                                                                          15 minutes during the
                                                                                          entire period of the
                                                                                          initial performance
                                                                                          test.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average total power to
                                                                                          the system for the
                                                                                          test runs and the 3-hr
                                                                                          average secondary
                                                                                          current from the test
                                                                                          runs. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          you may determine and
                                                                                          record the minimum
                                                                                          hourly average voltage
                                                                                          and secondary current
                                                                                          (or total power input)
                                                                                          from all the readings.

[[Page 75289]]

 
                                       d. Electrostatic         Results of analysis for  You must determine and
                                        precipitator or wet      equilibrium catalyst     record the average
                                        scrubber: Equilibrium    Ni concentration.        equilibrium catalyst
                                        catalyst Ni                                       Ni concentration for
                                        concentration.                                    the 3 runs based on
                                                                                          the laboratory
                                                                                          results. You may
                                                                                          adjust the value using
                                                                                          Equation 1 or 2 of
                                                                                          Sec.   63.1571 as
                                                                                          applicable.
                                       e. Wet scrubber:         i. Data from the         (1) You must collect
                                        Pressure drop (not       continuous parameter     pressure drop
                                        applicable to non-       monitoring systems and   monitoring data every
                                        venturi scrubber of      applicable performance   15 minutes during the
                                        jet ejector design).     test methods.            entire period of the
                                                                                          initial performance
                                                                                          test; and determine
                                                                                          and record the average
                                                                                          pressure drop for each
                                                                                          test run.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average pressure drop
                                                                                          from the test runs.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may determine and
                                                                                          record the minimum
                                                                                          hourly average
                                                                                          pressure drop from all
                                                                                          the readings.
                                       f. Wet scrubber: Liquid- i. Data from the         (1) You must collect
                                        to-gas ratio.            continuous parameter     gas flow rate and
                                                                 monitoring systems and   total water (or
                                                                 applicable performance   scrubbing liquid) flow
                                                                 test methods.            rate monitoring data
                                                                                          every 15 minutes
                                                                                          during the entire
                                                                                          period of the initial
                                                                                          performance test;
                                                                                          determine and record
                                                                                          the average gas flow
                                                                                          rate for each test
                                                                                          run; and determine the
                                                                                          average total water
                                                                                          (or scrubbing liquid)
                                                                                          flow for each test
                                                                                          run.
                                                                                         (2) You must determine
                                                                                          and record the hourly
                                                                                          average liquid-to-gas
                                                                                          ratio from the test
                                                                                          runs. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          you may determine and
                                                                                          record the hourly
                                                                                          average gas flow rate
                                                                                          and total water (or
                                                                                          scrubbing liquid) flow
                                                                                          rate from all the
                                                                                          readings.
                                                                                         (3) You must determine
                                                                                          and record the 3-hr
                                                                                          average liquid-to-gas
                                                                                          ratio. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          you may determine and
                                                                                          record the minimum
                                                                                          liquid-to-gas ratio.
                                       g. Alternative           i. Data from the         (1) You must collect
                                        procedure for gas flow   continuous parameter     air flow rate
                                        rate.                    monitoring systems and   monitoring data or
                                                                 applicable performance   determine the air flow
                                                                 test methods.            rate using control
                                                                                          room instrumentation
                                                                                          every 15 minutes
                                                                                          during the entire
                                                                                          period of the initial
                                                                                          performance test.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average rate of all
                                                                                          the readings from the
                                                                                          test runs.
                                                                                          Alternatively, before
                                                                                          August 1, 2017, you
                                                                                          may determine and
                                                                                          record the hourly
                                                                                          average rate of all
                                                                                          the readings.
                                                                                         (3) You must determine
                                                                                          and record the maximum
                                                                                          gas flow rate using
                                                                                          Equation 1 of Sec.
                                                                                          63.1573.
----------------------------------------------------------------------------------------------------------------
\1\ Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure).

[[Page 75290]]

 
\2\ EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively
  Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method
  7521, Nickel Atomic Absorption, Direct Aspiration are included in ``Test Methods for Evaluating Solid Waste,
  Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates (document
  number 955-001-00000-1) are available for purchase from the Superintendent of Documents, U.S. Government
  Publishing Office, Washington, DC 20402, (202) 512-1800; and from the National Technical Information Services
  (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket
  Center, William Jefferson Clinton (WJC) West Building, (Air Docket), Room 3334, 1301 Constitution Ave. NW.,
  Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington,
  DC.


0
56. Table 5 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(b)(5), you shall meet each requirement 
in the following table that applies to you.

  Table 5 to Subpart UUU of Part 63--Initial Compliance With Metal HAP
              Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
   For each new and existing    For the following
    catalytic cracking unit      emission limit .  You have demonstrated
 catalyst regenerator vent . .         . .         initial compliance if
               .                                           . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM   PM emissions must  You have already
 in 40 CFR 60.102 and not        not exceed 1.0 g/  conducted a
 electing Sec.   60.100(e).      kg (1.0 lb/1,000   performance test to
                                 lb) of coke burn-  demonstrate initial
                                 off, and the       compliance with the
                                 opacity of         NSPS and the
                                 emissions must     measured PM emission
                                 not exceed 30      rate is less than or
                                 percent, except    equal to 1.0 g/kg
                                 for one 6-minute   (1.0 lb/1,000 lb) of
                                 average opacity    coke burn-off in the
                                 reading in any 1-  catalyst
                                 hour period.       regenerator. As part
                                 Before August 1,   of the Notification
                                 2017, if the       of Compliance
                                 discharged gases   Status, you must
                                 pass through an    certify that your
                                 incinerator or     vent meets the PM
                                 waste heat         limit. You are not
                                 boiler in which    required to do
                                 you burn           another performance
                                 auxiliary or       test to demonstrate
                                 supplemental       initial compliance.
                                 liquid or solid    You have already
                                 fossil fuel, the   conducted a
                                 incremental rate   performance test to
                                 of PM must not     demonstrate initial
                                 exceed 43.0 g/GJ   compliance with the
                                 or 0.10 lb/        NSPS and the average
                                 million Btu of     hourly opacity is no
                                 heat input         more than 30
                                 attributable to    percent, except that
                                 the liquid or      one 6-minute average
                                 solid fossil       in any 1-hour period
                                 fuel; and the      can exceed 30
                                 opacity of         percent. As part of
                                 emissions must     the Notification of
                                 not exceed 30      Compliance Status,
                                 percent, except    you must certify
                                 for one 6-minute   that your vent meets
                                 average opacity    the 30 percent
                                 reading in any 1-  opacity limit. As
                                 hour period.       part of your
                                                    Notification of
                                                    Compliance Status,
                                                    you certify that
                                                    your continuous
                                                    opacity monitoring
                                                    system meets the
                                                    requirements in Sec.
                                                      63.1572.
2. Subject to NSPS for PM in    PM emissions must  You have already
 40 CFR 60.102a(b)(1)(i); or     not exceed 1.0 g/  conducted a
 in Sec.   60.102 and electing   kg (1.0 lb PM/     performance test to
 Sec.   60.100(e); electing to   1,000 lb) of       demonstrate initial
 meet the PM per coke burn-off   coke burn-off.     compliance with the
 limit.                                             NSPS and the
                                                    measured PM emission
                                                    rate is less than or
                                                    equal to 1.0 g/kg
                                                    (1.0 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; CO2, O2,
                                                    or CO monitor; or
                                                    continuous opacity
                                                    monitoring system
                                                    meets the
                                                    requirements in Sec.
                                                      63.1572.
3. Subject to NSPS for PM in    PM emissions must  You have already
 40 CFR 60.102a(b)(1)(i),        not exceed 0.5 g/  conducted a
 electing to meet the PM per     kg (0.5 lb PM/     performance test to
 coke burn-off limit.            1,000 lb) of       demonstrate initial
                                 coke burn-off).    compliance with the
                                                    NSPS and the
                                                    measured PM emission
                                                    rate is less than or
                                                    equal to 1.0 g/kg
                                                    (1.0 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; CO2, O2,
                                                    or CO monitor; or
                                                    continuous opacity
                                                    monitoring system
                                                    meets the
                                                    requirements in Sec.
                                                      63.1572.
4. Subject to NSPS for PM in    If a PM CEMS is    You have already
 40 CFR 60.102a(b)(1)(i),        used, 0.040        conducted a
 electing to meet the PM         grain per dry      performance test to
 concentration limit.            standard cubic     demonstrate initial
                                 feet (gr/dscf)     compliance with the
                                 corrected to 0     NSPS and the
                                 percent excess     measured PM
                                 air.               concentration is
                                                    less than or equal
                                                    to 0.040 grain per
                                                    dry standard cubic
                                                    feet (gr/dscf)
                                                    corrected to 0
                                                    percent excess air.
                                                    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 PM CEMS
                                                    meets the
                                                    requirements in Sec.
                                                      63.1572.

[[Page 75291]]

 
5. Subject to NSPS for PM in    If a PM CEMS is    You have already
 40 CFR 60.102a(b)(1)(ii),       used, 0.020 gr/    conducted a
 electing to meet the PM         dscf corrected     performance test to
 concentration limit.            to 0 percent       demonstrate initial
                                 excess air.        compliance with the
                                                    NSPS and the
                                                    measured PM
                                                    concentration is
                                                    less than or equal
                                                    to 0.020 gr/dscf
                                                    corrected to 0
                                                    percent excess air.
                                                    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 PM CEMS
                                                    meets the
                                                    requirements in Sec.
                                                      63.1572.
6. Option 1a: Elect NSPS        PM emissions must  The average PM
 subpart J requirements for PM   not exceed 1.0     emission rate,
 per coke burn-off limit, not    gram per           measured using EPA
 subject to the NSPS for PM in   kilogram (g/kg)    Method 5, 5B, or 5F
 40 CFR 60.102 or                (1.0 lb/1,000      (for a unit without
 60.102a(b)(1).                  lb) of coke burn-  a wet scrubber) or 5
                                 off, and the       or 5B (for a unit
                                 opacity of         with a wet scrubber)
                                 emissions must     (40 CFR part 60,
                                 not exceed 30      appendix A-3), over
                                 percent, except    the period of the
                                 for one 6-minute   initial performance
                                 average opacity    test, is no higher
                                 reading in any 1-  than 1.0 g/kg coke
                                 hour period.       burn-off (1.0 lb/
                                 Before August 1,   1,000 lb) in the
                                 2017, PM           catalyst
                                 emission must      regenerator. The PM
                                 not exceed 1.0 g/  emission rate is
                                 kg (1.0 lb/1,000   calculated using
                                 lb) of coke burn-  Equations 1, 2, and
                                 off in the         3 of Sec.   63.1564.
                                 catalyst           As part of the
                                 regenerator; if    Notification of
                                 the discharged     Compliance Status,
                                 gases pass         you must certify
                                 through an         that your vent meets
                                 incinerator or     the PM limit. The
                                 waste heat         average hourly
                                 boiler in which    opacity is no more
                                 you burn           than 30 percent,
                                 auxiliary or       except that one 6-
                                 supplemental       minute average in
                                 liquid or solid    any 1-hour period
                                 fossil fuel, the   can exceed 30
                                 incremental rate   percent. As part of
                                 of PM must not     the Notification of
                                 exceed 43.0 g/GJ   Compliance Status,
                                 (0.10 lb/million   you must certify
                                 Btu) of heat       that your vent meets
                                 input              the 30 percent
                                 attributable to    opacity limit. If
                                 the liquid or      you use a continuous
                                 solid fossil       opacity monitoring
                                 fuel; and the      system, your
                                 opacity of         performance
                                 emissions must     evaluation shows the
                                 not exceed 30      system meets the
                                 percent, except    applicable
                                 for one 6-minute   requirements in Sec.
                                 average opacity      63.1572.
                                 reading in any 1-
                                 hour period.
7. Option 1b: Elect NSPS        PM emissions must  The average PM
 subpart Ja requirements for     not exceed 1.0 g/  emission rate,
 PM per coke burn-off limit,     kg (1.0 lb/1,000   measured using EPA
 not subject to the NSPS for     lb) of coke burn-  Method 5, 5B, or 5F
 PM in 40 CFR 60.102 or          off.               (for a unit without
 60.102a(b)(1).                                     a wet scrubber) or 5
                                                    or 5B (for a unit
                                                    with a wet scrubber)
                                                    (40 CFR part 60,
                                                    appendix A-3), over
                                                    the period of the
                                                    initial performance
                                                    test, is no higher
                                                    than 1.0 g/kg coke
                                                    burn-off (1.0 lb/
                                                    1,000 lb) in the
                                                    catalyst
                                                    regenerator. The PM
                                                    emission rate is
                                                    calculated using
                                                    Equations 1, 2, and
                                                    3 of Sec.   63.1564.
                                                    If you use a BLD;
                                                    CO2, O2, CO monitor;
                                                    or continuous
                                                    opacity monitoring
                                                    system, your
                                                    performance
                                                    evaluation shows the
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572.
8. Option 1c: Elect NSPS        PM emissions must  The average PM
 subpart Ja requirements for     not exceed 0.040   concentration,
 PM concentration limit, not     gr/dscf            measured using EPA
 subject to the NSPS for PM in   corrected to 0     Method 5, 5B, or 5F
 40 CFR 60.102 or                percent excess     (for a unit without
 60.102a(b)(1).                  air.               a wet scrubber) or
                                                    Method 5 or 5B (for
                                                    a unit with a wet
                                                    scrubber) (40 CFR
                                                    part 60, appendix A-
                                                    3), over the period
                                                    of the initial
                                                    performance test, is
                                                    less than or equal
                                                    to 0.040 gr/dscf
                                                    corrected to 0
                                                    percent excess air.
                                                    Your performance
                                                    evaluation shows
                                                    your PM CEMS meets
                                                    the applicable
                                                    requirements in Sec.
                                                      63.1572.
9. Option 2: PM per coke burn-  PM emissions must  The average PM
 off limit, not subject to the   not exceed 1.0 g/  emission rate,
 NSPS for PM in 40 CFR 60.102    kg (1.0 lb/1,000   measured using EPA
 or 60.102a(b)(1).               lb) of coke burn-  Method 5, 5B, or 5F
                                 off.               (for a unit without
                                                    a wet scrubber) or 5
                                                    or 5B (for a unit
                                                    with a wet scrubber)
                                                    (40 CFR part 60,
                                                    appendix A-3), over
                                                    the period of the
                                                    initial performance
                                                    test, is no higher
                                                    than 1.0 g/kg coke
                                                    burn-off (1.0 lb/
                                                    1,000 lb) in the
                                                    catalyst
                                                    regenerator. The PM
                                                    emission rate is
                                                    calculated using
                                                    Equations 1, 2, and
                                                    3 of Sec.   63.1564.
                                                    If you use a BLD;
                                                    CO2, O2, CO monitor;
                                                    or continuous
                                                    opacity monitoring
                                                    system, your
                                                    performance
                                                    evaluation shows the
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572.
10. Option 3: Ni lb/hr limit,   Nickel (Ni)        The average Ni
 not subject to the NSPS for     emissions from     emission rate,
 PM in 40 CFR 60.102 or          your catalyst      measured using
 60.102a(b)(1).                  regenerator vent   Method 29 (40 CFR
                                 must not exceed    part 60, appendix A-
                                 13,000 mg/hr       8) over the period
                                 (0.029 lb/hr).     of the initial
                                                    performance test, is
                                                    not more than 13,000
                                                    mg/hr (0.029 lb/hr).
                                                    The Ni emission rate
                                                    is calculated using
                                                    Equation 5 of Sec.
                                                    63.1564; and if you
                                                    use a BLD; CO2, O2,
                                                    or CO monitor; or
                                                    continuous opacity
                                                    monitoring system,
                                                    your performance
                                                    evaluation shows the
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572.

[[Page 75292]]

 
11. Option 4: Ni per coke burn- Ni emissions from  The average Ni
 off limit not subject to the    your catalyst      emission rate,
 NSPS for PM.                    regenerator vent   measured using
                                 must not exceed    Method 29 (40 CFR
                                 1.0 mg/kg (0.001   part 60, appendix A-
                                 lb/1,000 lb) of    8) over the period
                                 coke burn-off in   of the initial
                                 the catalyst       performance test, is
                                 regenerator.       not more than 1.0 mg/
                                                    kg (0.001 lb/1,000
                                                    lb) of coke burn-off
                                                    in the catalyst
                                                    regenerator. The Ni
                                                    emission rate is
                                                    calculated using
                                                    Equation 8 of Sec.
                                                    63.1564; and if you
                                                    use a BLD; CO2, O2,
                                                    or CO monitor; or
                                                    continuous opacity
                                                    monitoring system,
                                                    your performance
                                                    evaluation shows the
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572.
------------------------------------------------------------------------


0
57. Table 6 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(c)(1), you shall meet each requirement 
in the following table that applies to you.

 Table 6 to Subpart UUU of Part 63--Continuous Compliance With Metal HAP
              Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
                                 Subject to this
                                  emission limit   You shall demonstrate
   For each new and existing    for your catalyst  continuous compliance
 catalytic cracking unit . . .   regenerator vent         by . . .
                                      . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM   a. PM emissions    i. Determining and
 in 40 CFR 60.102 and not        must not exceed    recording each day
 electing Sec.   60.100(e).      1.0 g/kg (1.0 lb/  the average coke
                                 1,000 lb) of       burn-off rate
                                 coke burn-off,     (thousands of
                                 and the opacity    kilograms per hour)
                                 of emissions       using Equation 1 in
                                 must not exceed    Sec.   63.1564 and
                                 30 percent,        the hours of
                                 except for one 6-  operation for each
                                 minute average     catalyst
                                 opacity reading    regenerator.
                                 in any 1-hour
                                 period. Before
                                 August 1, 2017,
                                 if the
                                 discharged gases
                                 pass through an
                                 incinerator or
                                 waste heat
                                 boiler in which
                                 you burn
                                 auxiliary or
                                 supplemental
                                 liquid or solid
                                 fossil fuel, the
                                 incremental rate
                                 of PM must not
                                 exceed 43.0 g/GJ
                                 (0.10 lb/million
                                 Btu) of heat
                                 input
                                 attributable to
                                 the liquid or
                                 solid fossil
                                 fuel; and the
                                 opacity of
                                 emissions must
                                 not exceed 30
                                 percent, except
                                 for one 6-minute
                                 average opacity
                                 reading in any 1-
                                 hour period.
                                                   ii. Conducting a
                                                    performance test
                                                    before August 1,
                                                    2017 and thereafter
                                                    following the
                                                    testing frequency in
                                                    Sec.   63.1571(a)(5)
                                                    as applicable to
                                                    your unit.
                                                   iii. Collecting the
                                                    continuous opacity
                                                    monitoring data for
                                                    each catalyst
                                                    regenerator vent
                                                    according to Sec.
                                                    63.1572 and
                                                    maintaining each 6-
                                                    minute average at or
                                                    below 30 percent,
                                                    except that one 6-
                                                    minute average
                                                    during a 1-hour
                                                    period can exceed 30
                                                    percent.
                                                   iv. Before August 1,
                                                    2017, if applicable,
                                                    determining and
                                                    recording each day
                                                    the rate of
                                                    combustion of liquid
                                                    or solid fossil
                                                    fuels (liters/hour
                                                    or kilograms/hour)
                                                    and the hours of
                                                    operation during
                                                    which liquid or
                                                    solid fossil-fuels
                                                    are combusted in the
                                                    incinerator-waste
                                                    heat boiler; if
                                                    applicable,
                                                    maintaining the
                                                    incremental rate of
                                                    PM at or below 43 g/
                                                    GJ (0.10 lb/million
                                                    Btu) of heat input
                                                    attributable to the
                                                    solid or liquid
                                                    fossil fuel.
2. Subject to NSPS for PM in    PM emissions must  Determining and
 40 CFR 60.102a(b)(1)(i),        not exceed 1.0 g/  recording each day
 electing to meet the PM per     kg (1.0 lb PM/     the average coke
 coke burn-off limit.            1,000 lb) of       burn-off rate
                                 coke burn-off.     (thousands of
                                                    kilograms per hour)
                                                    using Equation 1 in
                                                    Sec.   63.1564 and
                                                    the hours of
                                                    operation for each
                                                    catalyst
                                                    regenerator;
                                                    maintaining PM
                                                    emission rate below
                                                    1.0 g/kg (1.0 lb PM/
                                                    1,000 lb) of coke
                                                    burn-off; and
                                                    conducting a
                                                    performance test
                                                    once every year.
3. Subject to NSPS for PM in    PM emissions must  Determining and
 40 CFR 60.102a(b)(1)(ii),       not exceed 0.5 g/  recording each day
 electing to meet the PM per     kg coke burn-off   the average coke
 coke burn-off limit.            (0.5 lb/1000 lb    burn-off rate
                                 coke burn-off).    (thousands of
                                                    kilograms per hour)
                                                    using Equation 1 in
                                                    Sec.   63.1564 and
                                                    the hours of
                                                    operation for each
                                                    catalyst
                                                    regenerator;
                                                    maintaining PM
                                                    emission rate below
                                                    0.5 g/kg (0.5 lb/
                                                    1,000 lb) of coke
                                                    burn-off; and
                                                    conducting a
                                                    performance test
                                                    once every year.

[[Page 75293]]

 
4. Subject to NSPS for PM in    If a PM CEMS is    Maintaining PM
 40 CFR 60.102a(b)(1)(i),        used, 0.040        concentration below
 electing to meet the PM         grain per dry      0.040 gr/dscf
 concentration limit.            standard cubic     corrected to 0
                                 feet (gr/dscf)     percent excess air.
                                 corrected to 0
                                 percent excess
                                 air.
5. Subject to NSPS for PM in    If a PM CEMS is    Maintaining PM
 40 CFR 60.102a(b)(1)(ii),       used, 0.020 gr/    concentration below
 electing to meet the PM         dscf corrected     0.020 gr/dscf
 concentration limit.            to 0 percent       corrected to 0
                                 excess air.        percent excess air.
6. Option 1a: Elect NSPS        See item 1 of      See item 1 of this
 subpart J requirements for PM   this table.        table.
 per coke burn-off limit, not
 subject to the NSPS for PM in
 40 CFR 60.102 or
 60.102a(b)(1).
7. Option 1b: Elect NSPS        PM emissions must  See item 2 of this
 subpart Ja requirements for     not exceed 1.0 g/  table.
 PM per coke burn-off limit      kg (1.0 lb PM/
 and 30% opacity, not subject    1,000 lb) of
 to the NSPS for PM in 40 CFR    coke burn-off.
 60.102 or 60.102a(b)(1).
8. Option 1c: Elect NSPS        PM emissions must  See item 4 of this
 subpart Ja requirements for     not exceed 0.040   table.
 PM concentration limit, not     gr/dscf
 subject to the NSPS for PM in   corrected to 0
 40 CFR 60.102 or                percent excess
 60.102a(b)(1).                  air.
9. Option 2: PM per coke burn-  PM emissions must  Determining and
 off limit, not subject to the   not exceed 1.0 g/  recording each day
 NSPS for PM in 40 CFR 60.102    kg (1.0 lb PM/     the average coke
 or 60.102a(b)(1).               1,000 lb) of       burn-off rate and
                                 coke burn-off.     the hours of
                                                    operation and the
                                                    hours of operation
                                                    for each catalyst
                                                    regenerator by
                                                    Equation 1 of Sec.
                                                    63.1564 (you can use
                                                    process data to
                                                    determine the
                                                    volumetric flow
                                                    rate); maintaining
                                                    PM emission rate
                                                    below 1.0 g/kg (1.0
                                                    lb PM/1,000 lb) of
                                                    coke burn-off; and
                                                    conducting a
                                                    performance test
                                                    before August 1,
                                                    2017 and thereafter
                                                    following the
                                                    testing frequency in
                                                    Sec.   63.1571(a)(5)
                                                    as applicable to
                                                    your unit.
10. Option 3: Ni lb/hr limit,   Ni emissions must  Maintaining Ni
 not subject to the NSPS for     not exceed         emission rate below
 PM in 40 CFR 60.102 or          13,000 mg/hr       13,000 mg/hr (0.029
 60.102a(b)(1).                  (0.029 lb/hr).     lb/hr); and
                                                    conducting a
                                                    performance test
                                                    before August 1,
                                                    2017 and thereafter
                                                    following the
                                                    testing frequency in
                                                    Sec.   63.1571(a)(5)
                                                    as applicable to
                                                    your unit.
11. Option 4: Ni per coke burn- Ni emissions must  Determining and
 off limit, not subject to the   not exceed 1.0     recording each day
 NSPS for PM in 40 CFR 60.102    mg/kg (0.001 lb/   the average coke
 or 60.102a(b)(1).               1,000 lb) of       burn-off rate
                                 coke burn-off in   (thousands of
                                 the catalyst       kilograms per hour)
                                 regenerator.       and the hours of
                                                    operation for each
                                                    catalyst regenerator
                                                    by Equation 1 of
                                                    Sec.   63.1564 (you
                                                    can use process data
                                                    to determine the
                                                    volumetric flow
                                                    rate); and
                                                    maintaining Ni
                                                    emission rate below
                                                    1.0 mg/kg (0.001 lb/
                                                    1,000 lb) of coke
                                                    burn-off in the
                                                    catalyst
                                                    regenerator; and
                                                    conducting a
                                                    performance test
                                                    before August 1,
                                                    2017 and thereafter
                                                    following the
                                                    testing frequency in
                                                    Sec.   63.1571(a)(5)
                                                    as applicable to
                                                    your unit.
------------------------------------------------------------------------


0
58. Table 7 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(c)(1), you shall meet each requirement 
in the following table that applies to you.

   Table 7 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Metal HAP Emissions From
                                            Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
                                                                                          You shall demonstrate
  For each new or existing catalytic       If you use . . .        For this operating     continuous compliance
         cracking unit . . .                                          limit . . .                by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to NSPS for PM in 40 CFR    Continuous opacity       The 3-hour average       Collecting the
 60.102 and not electing Sec.           monitoring system.       opacity of emissions     continuous opacity
 60.100(e).                                                      from your catalyst       monitoring data for
                                                                 regenerator vent must    each regenerator vent
                                                                 not exceed 20 percent.   according to Sec.
                                                                                          63.1572 and maintain
                                                                                          each 3-hour rolling
                                                                                          average opacity of
                                                                                          emissions no higher
                                                                                          than 20 percent.

[[Page 75294]]

 
2. Subject to NSPS for PM in 40 CFR    a. Continuous opacity    The average opacity      Collecting the hourly
 60.102a(b)(1); or 40 CFR 60.102 and    monitoring system,       must not exceed the      and 3-hr rolling
 elect Sec.   60.100(e), electing to    used for site-specific   opacity established      average opacity
 meet the PM per coke burn-off limit.   opacity limit--Cyclone   during the performance   monitoring data
                                        or electrostatic         test.                    according to Sec.
                                        precipitator.                                     63.1572; maintaining
                                                                                          the 3-hr rolling
                                                                                          average opacity at or
                                                                                          above the site-
                                                                                          specific limit
                                                                                          established during the
                                                                                          performance test.
                                       b. Continuous            i. The average gas flow  Collecting the hourly
                                        parametric monitoring    rate entering or         and daily average coke
                                        systems--electrostatic   exiting the control      burn-off rate or
                                        precipitator.            device must not exceed   average gas flow rate
                                                                 the operating limit      monitoring data
                                                                 established during the   according to Sec.
                                                                 performance test.        63.1572; and
                                                                                          maintaining the daily
                                                                                          average coke burn-off
                                                                                          rate or average gas
                                                                                          flow rate at or below
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.
                                                                ii. The average total    Collecting the hourly
                                                                 power and secondary      and 3-hr rolling
                                                                 current to the control   average total power
                                                                 device must not fall     and secondary current
                                                                 below the operating      monitoring data
                                                                 limit established        according to Sec.
                                                                 during the performance   63.1572; and
                                                                 test.                    maintaining the 3-hr
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current at or above
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.
                                       c. Continuous            i. The average liquid-   Collecting the hourly
                                        parametric monitoring    to-gas ratio must not    and 3-hr rolling
                                        systems--wet scrubber.   fall below the           average gas flow rate
                                                                 operating limit          and scrubber liquid
                                                                 established during the   flow rate monitoring
                                                                 performance test.        data according to Sec.
                                                                                            63.1572; determining
                                                                                          and recording the 3-hr
                                                                                          liquid-to-gas ratio;
                                                                                          and maintaining the 3-
                                                                                          hr rolling average
                                                                                          liquid-to-gas ratio at
                                                                                          or above the limit
                                                                                          established during the
                                                                                          performance test.
 
                                                                ii. Except for periods   Collecting the hourly
                                                                 of startup, shutdown     and 3-hr rolling
                                                                 and hot standby, the     average pressure drop
                                                                 average pressure drop    monitoring data
                                                                 across the scrubber      according to Sec.
                                                                 must not fall below      63.1572; and except
                                                                 the operating limit      for periods of
                                                                 established during the   startup, shutdown and
                                                                 performance test.        hot standby,
                                                                                          maintaining the 3-hr
                                                                                          rolling average
                                                                                          pressure drop at or
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test.
                                       d. BLD--fabric filter..  Increases in relative    Collecting and
                                                                 particulate.             maintaining records of
                                                                                          BLD system output;
                                                                                          determining the cause
                                                                                          of the alarm within 1
                                                                                          hour of the alarm; and
                                                                                          alleviating the cause
                                                                                          of the alarm within 3
                                                                                          hours by corrective
                                                                                          action.
3. Subject to NSPS for PM in 40 CFR    PM CEMS................  Not applicable.........  Complying with Table 6
 60.102a(b)(1), electing to meet the                                                      of this subpart, item
 PM concentration limit.                                                                  4 or 5.
4. Option 1a: Elect NSPS subpart J     Continuous opacity       The 3-hour average       Collecting the 3-hr
 requirements for PM per coke burn-     monitoring system.       opacity of emissions     rolling average
 off limit, not subject to the NSPS                              from your catalyst       continuous opacity
 for PM in 40 CFR 60.102 or                                      regenerator vent must    monitoring system data
 60.102a(b)(1).                                                  not exceed 20 percent.   according to Sec.
                                                                                          63.1572; and
                                                                                          maintaining the 3-hr
                                                                                          rolling average
                                                                                          opacity no higher than
                                                                                          20 percent.
5. Option 1b: Elect NSPS subpart Ja    a. Continuous opacity    The opacity of           Collecting the 3-hr
 requirements for PM per coke burn-     monitoring system.       emissions from your      rolling average
 off limit, not subject to the NSPS                              catalyst regenerator     continuous opacity
 for PM in 40 CFR 60.102 or                                      vent must not exceed     monitoring system data
 60.102a(b)(1).                                                  the site-specific        according to Sec.
                                                                 opacity operating        63.1572; maintaining
                                                                 limit established        the 3-hr rolling
                                                                 during the performance   average opacity at or
                                                                 test.                    below the site-
                                                                                          specific limit.

[[Page 75295]]

 
                                       b. Continuous            See item 2.b of this     See item 2.b of this
                                        parametric monitoring    table.                   table.
                                        systems--electrostatic
                                        precipitator.
                                       c. Continuous            See item 2.c of this     See item 2.c of this
                                        parametric monitoring    table.                   table.
                                        systems--wet scrubber.
                                       d. BLD--fabric filter..  See item 2.d of this     See item 2.d of this
                                                                 table.                   table.
6. Option 1c: Elect NSPS subpart Ja    PM CEMS................  Not applicable.........  Complying with Table 6
 requirements for PM concentration                                                        of this subpart, item
 limit, not subject to the NSPS for                                                       4.
 PM in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off      a. Continuous opacity    The opacity of           Collecting the hourly
 limit, not subject to the NSPS for     monitoring system.       emissions from your      and 3-hr rolling
 PM in 40 CFR 60.102 or 60.102a(b)(1).                           catalyst regenerator     average continuous
                                                                 vent must not exceed     opacity monitoring
                                                                 the site-specific        system data according
                                                                 opacity operating        to Sec.   63.1572; and
                                                                 limit established        maintaining the 3-hr
                                                                 during the performance   rolling average
                                                                 test.                    opacity at or below
                                                                                          the site-specific
                                                                                          limit established
                                                                                          during the performance
                                                                                          test. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          collecting the hourly
                                                                                          average continuous
                                                                                          opacity monitoring
                                                                                          system data according
                                                                                          to Sec.   63.1572; and
                                                                                          maintaining the hourly
                                                                                          average opacity at or
                                                                                          below the site-
                                                                                          specific limit.
                                       b. Continuous parameter  i. The average coke      Collecting the hourly
                                        monitoring systems--     burn-off rate or         and daily average coke
                                        electrostatic            average gas flow rate    burn-off rate or gas
                                        precipitator.            entering or exiting      flow rate monitoring
                                                                 the control device       data according to Sec.
                                                                 must not exceed the        63.1572; and
                                                                 operating limit          maintaining the daily
                                                                 established during the   coke burn-off rate or
                                                                 performance test.        average gas flow rate
                                                                                          at or below the limit
                                                                                          established during the
                                                                                          performance test.
                                                                ii. The average total    Collecting the hourly
                                                                 power (voltage and       and 3-hr rolling
                                                                 current) and secondary   average total power
                                                                 current to the control   and secondary current
                                                                 device must not fall     monitoring data
                                                                 below the operating      according to Sec.
                                                                 limit established        63.1572; and
                                                                 during the performance   maintaining the 3-hr
                                                                 test.                    rolling average total
                                                                                          power and secondary
                                                                                          current at or above
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test. Alternatively,
                                                                                          before August 1, 2017,
                                                                                          collecting the hourly
                                                                                          and daily average
                                                                                          voltage and secondary
                                                                                          current (or total
                                                                                          power input)
                                                                                          monitoring data
                                                                                          according to Sec.
                                                                                          63.1572; and
                                                                                          maintaining the daily
                                                                                          average voltage and
                                                                                          secondary current (or
                                                                                          total power input) at
                                                                                          or above the limit
                                                                                          established during the
                                                                                          performance test.

[[Page 75296]]

 
                                       c. Continuous parameter  i. The average liquid-   Collecting the hourly
                                        monitoring systems--     to-gas ratio must not    and 3-hr rolling
                                        wet scrubber.            fall below the           average gas flow rate
                                                                 operating limit          and scrubber liquid
                                                                 established during the   flow rate monitoring
                                                                 performance test.        data according to Sec.
                                                                                            63.1572; determining
                                                                                          and recording the 3-hr
                                                                                          liquid-to-gas ratio;
                                                                                          and maintaining the 3-
                                                                                          hr rolling average
                                                                                          liquid-to-gas ratio at
                                                                                          or above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          August 1, 2017,
                                                                                          collecting the hourly
                                                                                          average gas flow rate
                                                                                          and water (or
                                                                                          scrubbing liquid) flow
                                                                                          rate monitoring data
                                                                                          according to Sec.
                                                                                          63.1572 \1\;
                                                                                          determining and
                                                                                          recording the hourly
                                                                                          average liquid-to-gas
                                                                                          ratio; determining and
                                                                                          recording the daily
                                                                                          average liquid-to-gas
                                                                                          ratio; and maintaining
                                                                                          the daily average
                                                                                          liquid-to-gas ratio
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                ii. Except for periods   Collecting the hourly
                                                                 of startup, shutdown     and 3-hr rolling
                                                                 and hot standby, the     average pressure drop
                                                                 average pressure drop    monitoring data
                                                                 across the scrubber      according to Sec.
                                                                 must not fall below      63.1572; and except
                                                                 the operating limit      for periods of
                                                                 established during the   startup, shutdown and
                                                                 performance test.        hot standby,
                                                                                          maintaining the 3-hr
                                                                                          rolling average
                                                                                          pressure drop at or
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          August 1, 2017,
                                                                                          collecting the hourly
                                                                                          and daily average
                                                                                          pressure drop
                                                                                          monitoring data
                                                                                          according to Sec.
                                                                                          63.1572; and
                                                                                          maintaining the daily
                                                                                          average pressure drop
                                                                                          above the limit
                                                                                          established during the
                                                                                          performance test.
                                       d. BLD--fabric filter..  See item 2.d of this     See item 2.d of this
                                                                 table.                   table.
8. Option 3: Ni lb/hr limit not        a. Continuous opacity    i. The daily average Ni  (1) Collecting the
 subject to the NSPS for PM in 40 CFR   monitoring system.       operating value must     hourly average
 60.102.                                                         not exceed the site-     continuous opacity
                                                                 specific Ni operating    monitoring system data
                                                                 limit established        according to Sec.
                                                                 during the performance   63.1572; determining
                                                                 test.                    and recording
                                                                                          equilibrium catalyst
                                                                                          Ni concentration at
                                                                                          least once a week \2\;
                                                                                          collecting the hourly
                                                                                          average gas flow rate
                                                                                          monitoring data
                                                                                          according to Sec.
                                                                                          63.1572 \1\; and
                                                                                          determining and
                                                                                          recording the hourly
                                                                                          average Ni operating
                                                                                          value using Equation
                                                                                          11 of Sec.   63.1564.

[[Page 75297]]

 
                                                                                         (2) Determining and
                                                                                          recording the 3-hour
                                                                                          rolling average Ni
                                                                                          operating value and
                                                                                          maintaining the 3-hour
                                                                                          rolling average Ni
                                                                                          operating value below
                                                                                          the site-specific Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          August 1, 2017,
                                                                                          determining and
                                                                                          recording the daily
                                                                                          average Ni operating
                                                                                          value and maintaining
                                                                                          the daily average Ni
                                                                                          operating value below
                                                                                          the site-specific Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test.
                                       b. Continuous parameter  i. The average gas flow  See item 7.b.i of this
                                        monitoring systems--     rate entering or         table.
                                        electrostatic            exiting the control
                                        precipitator.            device must not exceed
                                                                 the operating limit
                                                                 established during the
                                                                 performance test.
                                                                ii. The average total    See item 7.b.ii of this
                                                                 power (voltage and       table.
                                                                 current) and secondary
                                                                 current must not fall
                                                                 below the level
                                                                 established in the
                                                                 performance test.
                                                                iii. The monthly         Determining and
                                                                 rolling average of the   recording the
                                                                 equilibrium catalyst     equilibrium catalyst
                                                                 Ni concentration must    Ni concentration at
                                                                 not exceed the level     least once a week \2\;
                                                                 established during the   determining and
                                                                 performance test.        recording the monthly
                                                                                          rolling average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration once
                                                                                          each week using the
                                                                                          weekly or most recent
                                                                                          value; and maintaining
                                                                                          the monthly rolling
                                                                                          average below the
                                                                                          limit established in
                                                                                          the performance test.
                                       c. Continuous parameter  i. The average liquid-   See item 7.c.i of this
                                        monitoring systems--     to-gas ratio must not    table.
                                        wet scrubber.            fall below the
                                                                 operating limit
                                                                 established during the
                                                                 performance test..
                                                                ii. Except for periods   See item 7.c.ii of this
                                                                 of startup, shutdown     table.
                                                                 and hot standby, the
                                                                 average pressure drop
                                                                 must not fall below
                                                                 the operating limit
                                                                 established in the
                                                                 performance test.
                                                                iii. The monthly         Determining and
                                                                 rolling average          recording the
                                                                 equilibrium catalyst     equilibrium catalyst
                                                                 Ni concentration must    Ni concentration at
                                                                 not exceed the level     least once a week \2\;
                                                                 established during the   determining and
                                                                 performance test.        recording the monthly
                                                                                          rolling average of
                                                                                          equilibrium catalyst
                                                                                          Ni concentration once
                                                                                          each week using the
                                                                                          weekly or most recent
                                                                                          value; and maintaining
                                                                                          the monthly rolling
                                                                                          average below the
                                                                                          limit established in
                                                                                          the performance test.
                                       d. BLD--fabric filter..  i. Increases in          See item 7.d of this
                                                                 relative particulate.    table.

[[Page 75298]]

 
                                                                ii. The monthly rolling  Determining and
                                                                 average of the           recording the
                                                                 equilibrium catalyst     equilibrium catalyst
                                                                 Ni concentration must    Ni concentration at
                                                                 not exceed the level     least once a week \2\;
                                                                 established during the   determining and
                                                                 performance test.        recording the monthly
                                                                                          rolling average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration once
                                                                                          each week using the
                                                                                          weekly or most recent
                                                                                          value; and maintaining
                                                                                          the monthly rolling
                                                                                          average below the
                                                                                          limit established in
                                                                                          the performance test.
9. Option 4: Ni per coke burn-off      a. Continuous opacity    i. The daily average Ni  (1) Collecting the
 limit not subject to the NSPS for PM   monitoring system.       operating value must     hourly average
 in 40 CFR 60.102.                                               not exceed the site-     continuous opacity
                                                                 specific Ni operating    monitoring system data
                                                                 limit established        according to Sec.
                                                                 during the performance   63.1572; collecting
                                                                 test.                    the hourly average
                                                                                          coke burn rate and
                                                                                          hourly average gas
                                                                                          flow rate monitoring
                                                                                          data according to Sec.
                                                                                            63.15721;
                                                                                          determining and
                                                                                          recording equilibrium
                                                                                          catalyst Ni
                                                                                          concentration at least
                                                                                          once a week \2\; and
                                                                                          determining and
                                                                                          recording the hourly
                                                                                          average Ni operating
                                                                                          value using Equation
                                                                                          12 of Sec.   63.1564.
                                                                                         (2) Determining and
                                                                                          recording the 3-hour
                                                                                          rolling average Ni
                                                                                          operating value and
                                                                                          maintaining the 3-hour
                                                                                          rolling average Ni
                                                                                          operating value below
                                                                                          the site-specific Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test
                                                                                          Alternatively, before
                                                                                          August 1, 2017,
                                                                                          determining and
                                                                                          recording the daily
                                                                                          average Ni operating
                                                                                          value and maintaining
                                                                                          the daily average Ni
                                                                                          operating value below
                                                                                          the site-specific Ni
                                                                                          operating limit
                                                                                          established during the
                                                                                          performance test.
                                       b. Continuous parameter  i. The average gas flow  See item 7.b.i of this
                                        monitoring systems--     rate to the control      table.
                                        electrostatic            device must not exceed
                                        precipitator.            the level established
                                                                 in the performance
                                                                 test.
                                                                ii. The average voltage  See item 7.b.ii of this
                                                                 and secondary current    table.
                                                                 (or total power input)
                                                                 must not fall below
                                                                 the level established
                                                                 in the performance
                                                                 test.
                                                                iii. The monthly         See item 8.b.iii of
                                                                 rolling average          this table.
                                                                 equilibrium catalyst
                                                                 Ni concentration must
                                                                 not exceed the level
                                                                 established during the
                                                                 performance test.
                                       c. Continuous parameter  i. The average liquid-   See item 7.c.i of this
                                        monitoring systems--     to-gas ratio must not    table.
                                        wet scrubber.            fall below the
                                                                 operating limit
                                                                 established during the
                                                                 performance test.
                                                                ii. Except for periods   See item 7.c.ii of this
                                                                 of startup, shutdown     table.
                                                                 and hot standby, the
                                                                 daily average pressure
                                                                 drop must not fall
                                                                 below the operating
                                                                 limit established in
                                                                 the performance test.

[[Page 75299]]

 
                                                                iii. The monthly         See item 8.c.iii of
                                                                 rolling average          this table.
                                                                 equilibrium catalyst
                                                                 Ni concentration must
                                                                 not exceed the level
                                                                 established during the
                                                                 performance test.
                                       d. BLD--fabric filter..  i. See item 2.d of this  See item 2.d of this
                                                                 table.                   table.
                                                                ii. The monthly rolling  Determining and
                                                                 average of the           recording the
                                                                 equilibrium catalyst     equilibrium catalyst
                                                                 Ni concentration must    Ni concentration at
                                                                 not exceed the level     least once a week \2\;
                                                                 established during the   determining and
                                                                 performance test.        recording the monthly
                                                                                          rolling average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration once
                                                                                          each week using the
                                                                                          weekly or most recent
                                                                                          value; and maintaining
                                                                                          the monthly rolling
                                                                                          average below the
                                                                                          limit established in
                                                                                          the performance test.
10. During periods of startup,         Any control device, if   The inlet velocity       Meeting the
 shutdown, or hot standby.              elected.                 limit to the primary     requirements in Sec.
                                                                 internal cyclones of     63.1564(c)(5).
                                                                 the catalytic cracking
                                                                 unit catalyst
                                                                 regenerator in Sec.
                                                                 63.1564(a)(5)(ii).
----------------------------------------------------------------------------------------------------------------
\1\ If applicable, you can use the alternative in Sec.   63.1573(a)(1) for gas flow rate instead of a continuous
  parameter monitoring system if you used the alternative method in the initial performance test.
\2\ The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal
  Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in appendix A to this subpart; or by EPA
  Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled
  Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or EPA Method 7521,
  Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521
  satisfactory to the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ``Test Methods
  for Evaluating Solid Waste, Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The
  SW-846 and Updates (document number 955-001-00000-1) are available for purchase from the Superintendent of
  Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512-1800; and from the National
  Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may
  be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334,
  1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street
  NW., Suite 700, Washington, DC. These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm.


0
59. Table 8 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1565(a)(1), you shall meet each emission 
limitation in the following table that applies to you.

   Table 8 to Subpart UUU of Part 63--Organic HAP Emission Limits for
                        Catalytic Cracking Units
------------------------------------------------------------------------
                                           You shall meet the following
  For each new and existing catalytic        emission limit for each
          cracking unit . . .             catalyst  regenerator vent . .
                                                        .
------------------------------------------------------------------------
1. Subject to the NSPS for carbon        CO emissions from the catalyst
 monoxide (CO) in 40 CFR 60.103 or        regenerator vent or CO boiler
 60.102a(b)(4).                           serving the catalytic cracking
                                          unit must not exceed 500 parts
                                          per million volume (ppmv) (dry
                                          basis).
2. Not subject to the NSPS for CO in 40  a. CO emissions from the
 CFR 60.103 or 60.102a(b)(4).             catalyst regenerator vent or
                                          CO boiler serving the
                                          catalytic cracking unit must
                                          not exceed 500 ppmv (dry
                                          basis).
                                         b. If you use a flare to meet
                                          the CO limit, then on and
                                          after January 30, 2019, the
                                          flare must meet the
                                          requirements of Sec.   63.670.
                                          Prior to January 30, 2019, the
                                          flare must meet the
                                          requirements for control
                                          devices in Sec.   63.11(b) and
                                          visible emissions must not
                                          exceed a total of 5 minutes
                                          during any 2 consecutive
                                          hours, or the flare must meet
                                          the requirements of Sec.
                                          63.670.
------------------------------------------------------------------------


0
60. Table 9 to subpart UUU of part 63 is revised to read as follows:

    As stated in Sec.  63.1565(a)(2), you shall meet each operating 
limit in the following table that applies to you.

[[Page 75300]]



   Table 9 to Subpart UUU of Part 63--Operating Limits for Organic HAP Emissions From Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
                                           For this type of
  For each new or existing catalytic    continuous  monitoring      For this type of       You shall meet this
         cracking unit . . .                 system . . .        control  device . . .    operating  limit . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for carbon      Continuous emission      Not applicable.........  Not applicable.
 monoxide (CO) in 40 CFR 60.103 or      monitoring system.
 60.102a(b)(4).
2. Not subject to the NSPS for CO in   a. Continuous emission   Not applicable.........  Not applicable.
 40 CFR 60.103 or 60.102a(b)(4).        monitoring system.
                                       b. Continuous parameter  i. Thermal incinerator.  Maintain the daily
                                        monitoring systems.                               average combustion
                                                                                          zone temperature above
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test; and maintain the
                                                                                          daily average oxygen
                                                                                          concentration in the
                                                                                          vent stream (percent,
                                                                                          dry basis) above the
                                                                                          limit established
                                                                                          during the performance
                                                                                          test.
                                                                ii. Boiler or process    Maintain the daily
                                                                 heater with a design     average combustion
                                                                 heat input capacity      zone temperature above
                                                                 under 44 MW or a         the limit established
                                                                 boiler or process        in the performance
                                                                 heater in which all      test.
                                                                 vent streams are not
                                                                 introduced into the
                                                                 flame zone.
                                                                iii. Flare.............  On and after January
                                                                                          30, 2019, the flare
                                                                                          must meet the
                                                                                          requirements of Sec.
                                                                                          63.670. Prior to
                                                                                          January 30, 2019, the
                                                                                          flare pilot light must
                                                                                          be present at all
                                                                                          times and the flare
                                                                                          must be operating at
                                                                                          all times that
                                                                                          emissions may be
                                                                                          vented to it, or the
                                                                                          flare must meet the
                                                                                          requirements of Sec.
                                                                                          63.670.
3. During periods of startup,          Any....................  Any....................  Meet the requirements
 shutdown or hot standby.                                                                 in Sec.
                                                                                          63.1565(a)(5).
----------------------------------------------------------------------------------------------------------------


0
61. Table 10 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1565(b)(1), you shall meet each requirement 
in the following table that applies to you.

  Table 10 to Subpart UUU of Part 63--Continuous Monitoring Systems for
           Organic HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
                                                      You shall install,
                                   And you use this      operate, and
    For each new or existing        type of control   maintain this type
 catalytic cracking  unit . . .     device for your      of continuous
                                      vent . . .       monitoring system
                                                             . . .
------------------------------------------------------------------------
1. Subject to the NSPS for        Not applicable....  Continuous
 carbon monoxide (CO) in 40 CFR                        emission
 60.103 or 60.102a(b)(4).                              monitoring system
                                                       to measure and
                                                       record the
                                                       concentration by
                                                       volume (dry
                                                       basis) of CO
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
2. Not subject to the NSPS for    a. Thermal          Continuous
 CO in 40 CFR 60.103 or            incinerator.        emission
 60.102a(b)(4).                                        monitoring system
                                                       to measure and
                                                       record the
                                                       concentration by
                                                       volume (dry
                                                       basis) of CO
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent;
                                                       or continuous
                                                       parameter
                                                       monitoring
                                                       systems to
                                                       measure and
                                                       record the
                                                       combustion zone
                                                       temperature and
                                                       oxygen content
                                                       (percent, dry
                                                       basis) in the
                                                       incinerator vent
                                                       stream.
                                  b. Process heater   Continuous
                                   or boiler with a    emission
                                   design heat input   monitoring system
                                   capacity under 44   to measure and
                                   MW or process       record the
                                   heater or boiler    concentration by
                                   in which all vent   volume (dry
                                   streams are not     basis) of CO
                                   introduced into     emissions from
                                   the flame zone.     each catalyst
                                                       regenerator vent;
                                                       or continuous
                                                       parameter
                                                       monitoring
                                                       systems to
                                                       measure and
                                                       record the
                                                       combustion zone
                                                       temperature.

[[Page 75301]]

 
                                  c. Flare..........  On and after
                                                       January 30, 2019,
                                                       the monitoring
                                                       systems required
                                                       in Sec.  Sec.
                                                       63.670 and
                                                       63.671. Prior to
                                                       January 30, 2019,
                                                       monitoring device
                                                       such as a
                                                       thermocouple, an
                                                       ultraviolet beam
                                                       sensor, or
                                                       infrared sensor
                                                       to continuously
                                                       detect the
                                                       presence of a
                                                       pilot flame, or
                                                       the monitoring
                                                       systems required
                                                       in Sec.  Sec.
                                                       63.670 and
                                                       63.671.
                                  d. No control       Continuous
                                   device.             emission
                                                       monitoring system
                                                       to measure and
                                                       record the
                                                       concentration by
                                                       volume (dry
                                                       basis) of CO
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
3. During periods of startup,     Any...............  Continuous
 shutdown or hot standby                               parameter
 electing to comply with the                           monitoring system
 operating limit in Sec.                               to measure and
 63.1565(a)(5)(ii).                                    record the
                                                       concentration by
                                                       volume (dry
                                                       basis) of oxygen
                                                       from each
                                                       catalyst
                                                       regenerator vent.
------------------------------------------------------------------------


0
62. Table 11 to subpart UUU of part 63 is amended by revising the entry 
for item 3 to read as follows:
* * * * *

 Table 11 to Subpart UUU of Part 63--Requirements for Performance Tests for Organic HAP Emissions From Catalytic
          Cracking Units Not Subject to New Source Performance Standard (NSPS) for Carbon Monoxide (CO)
----------------------------------------------------------------------------------------------------------------
                                                                                            According to these
              For . . .                     You must . . .            Using . . .           requirements . . .
----------------------------------------------------------------------------------------------------------------
 
                                                   * * * * * *
3. Each catalytic cracking unit        a. Measure the CO        Method 10, 10A, or 10B   .......................
 catalyst regenerator vent if you use   concentration (dry       in appendix A-4 to
 continuous parameter monitoring        basis) of emissions      part 60 of this
 systems.                               exiting the control      chapter, as applicable.
                                        device.
                                       b. Establish each        Data from the            .......................
                                        operating limit in       continuous parameter
                                        Table 9 of this          monitoring systems.
                                        subpart that applies
                                        to you.
                                       c. Thermal incinerator   Data from the            Collect temperature
                                        combustion zone          continuous parameter     monitoring data every
                                        temperature.             monitoring systems.      15 minutes during the
                                                                                          entire period of the
                                                                                          CO initial performance
                                                                                          test; and determine
                                                                                          and record the minimum
                                                                                          hourly average
                                                                                          combustion zone
                                                                                          temperature from all
                                                                                          the readings.
                                       d. Thermal incinerator:  Data from the            Collect oxygen
                                        oxygen, content          continuous parameter     concentration
                                        (percent, dry basis)     monitoring systems.      (percent, dry basis)
                                        in the incinerator                                monitoring data every
                                        vent stream.                                      15 minutes during the
                                                                                          entire period of the
                                                                                          CO initial performance
                                                                                          test; and determine
                                                                                          and record the minimum
                                                                                          hourly average percent
                                                                                          excess oxygen
                                                                                          concentration from all
                                                                                          the readings.
                                       e. If you use a process  Data from the            Collect the temperature
                                        heater or boiler with    continuous parameter     monitoring data every
                                        a design heat input      monitoring systems.      15 minutes during the
                                        capacity under 44 MW                              entire period of the
                                        or process heater or                              CO initial performance
                                        boiler in which all                               test; and determine
                                        vent streams are not                              and record the minimum
                                        introduced into the                               hourly average
                                        flame zone, establish                             combustion zone
                                        operating limit for                               temperature from all
                                        combustion zone                                   the readings.
                                        temperature.

[[Page 75302]]

 
                                       f. If you use a flare,   Method 22 (40 CFR part   On and after January
                                        conduct visible          60, appendix A-7).       30, 2019, meet the
                                        emission observations.                            requirements of Sec.
                                                                                          63.670. Prior to
                                                                                          January 30, 2019,
                                                                                          maintain a 2-hour
                                                                                          observation period;
                                                                                          and record the
                                                                                          presence of a flame at
                                                                                          the pilot light over
                                                                                          the full period of the
                                                                                          test or meet the
                                                                                          requirements of Sec.
                                                                                          63.670.
                                       g. If you use a flare,   40 CFR 63.11(b)(6)       On and after January
                                        determine that the       through (8).             30, 2019, the flare
                                        flare meets the                                   must meet the
                                        requirements for net                              requirements of Sec.
                                        heating value of the                              63.670. Prior to
                                        gas being combusted                               January 30, 2019, the
                                        and exit velocity.                                flare must meet the
                                                                                          control device
                                                                                          requirements in Sec.
                                                                                          63.11(b) or the
                                                                                          requirements of Sec.
                                                                                          63.670.
----------------------------------------------------------------------------------------------------------------


0
63. Table 12 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1565(b)(4), you shall meet each requirement 
in the following table that applies to you.

 Table 12 to Subpart UUU of Part 63--Initial Compliance With Organic HAP
              Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
                                For the following
   For each new and existing     emission limit .  You have demonstrated
 catalytic cracking unit . . .         . .         initial compliance if
                                                           . . .
------------------------------------------------------------------------
1. Subject to the NSPS for      CO emissions from  You have already
 carbon monoxide (CO) in 40      your catalyst      conducted a
 CFR 60.103, 60.100(e), or       regenerator vent   performance test to
 60.102a(b)(4).                  or CO boiler       demonstrate initial
                                 serving the        compliance with the
                                 catalytic          NSPS and the
                                 cracking unit      measured CO
                                 must not exceed    emissions are less
                                 500 ppmv (dry      than or equal to 500
                                 basis).            ppm (dry basis). As
                                                    part of the
                                                    Notification of
                                                    Compliance Status,
                                                    you must certify
                                                    that your vent meets
                                                    the CO limit. You
                                                    are not required to
                                                    conduct another
                                                    performance test to
                                                    demonstrate initial
                                                    compliance. You have
                                                    already conducted a
                                                    performance
                                                    evaluation to
                                                    demonstrate initial
                                                    compliance with the
                                                    applicable
                                                    performance
                                                    specification. As
                                                    part of your
                                                    Notification of
                                                    Compliance Status,
                                                    you must certify
                                                    that your continuous
                                                    emission monitoring
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572. You are
                                                    not required to
                                                    conduct another
                                                    performance
                                                    evaluation to
                                                    demonstrate initial
                                                    compliance.
2. Not subject to the NSPS for  a. CO emissions    i. If you use a
 CO in 40 CFR 60.103             from your          continuous parameter
 60.102a(b)(4).                  catalyst           monitoring system,
                                 regenerator vent   the average CO
                                 or CO boiler       emissions measured
                                 serving the        by Method 10 over
                                 catalytic          the period of the
                                 cracking unit      initial performance
                                 must not exceed    test are less than
                                 500 ppmv (dry      or equal to 500 ppmv
                                 basis).            (dry basis).
                                                   ii. If you use a
                                                    continuous emission
                                                    monitoring system,
                                                    the hourly average
                                                    CO emissions over
                                                    the 24-hour period
                                                    for the initial
                                                    performance test are
                                                    not more than 500
                                                    ppmv (dry basis);
                                                    and your performance
                                                    evaluation shows
                                                    your continuous
                                                    emission monitoring
                                                    system meets the
                                                    applicable
                                                    requirements in Sec.
                                                      63.1572.
                                b. If you use a    On and after January
                                 flare, visible     30, 2019, the flare
                                 emissions must     meets the
                                 not exceed a       requirements of Sec.
                                 total of 5           63.670. Prior to
                                 minutes during     January 30, 2019,
                                 any 2 operating    visible emissions,
                                 hours.             measured by Method
                                                    22 during the 2-hour
                                                    observation period
                                                    during the initial
                                                    performance test,
                                                    are no higher than 5
                                                    minutes, or the
                                                    flare meets the
                                                    requirements of Sec.
                                                      63.670.
------------------------------------------------------------------------


0
64. Table 13 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1565(c)(1), you shall meet each requirement 
in the following table that applies to you.

[[Page 75303]]



    Table 13 to Subpart UUU of Part 63--Continuous Compliance With Organic HAP Emission Limits for Catalytic
                                                 Cracking Units
----------------------------------------------------------------------------------------------------------------
                                           Subject to this
 For each new and existing  catalytic  emission limit for your                            You shall demonstrate
         cracking unit . . .             catalyst regenerator      If you must . . .      continuous compliance
                                              vent . . .                                         by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for carbon      CO emissions from your   Continuous emission      Collecting the hourly
 monoxide (CO) in 40 CFR 60.103,        catalyst regenerator     monitoring system.       average CO monitoring
 60.100(e), or 60.102a(b)(4).           vent or CO boiler                                 data according to Sec.
                                        serving the catalytic                               63.1572; and
                                        cracking unit must not                            maintaining the hourly
                                        exceed 500 ppmv (dry                              average CO
                                        basis).                                           concentration at or
                                                                                          below 500 ppmv (dry
                                                                                          basis).
2. Not subject to the NSPS for CO in   a. CO emissions from     Continuous emission      Same as item 1.
 40 CFR 60.103 or 60.102a(b)(4).        your catalyst            monitoring system.
                                        regenerator vent or CO
                                        boiler serving the
                                        catalytic cracking
                                        unit must not exceed
                                        500 ppmv (dry basis).
                                       b. CO emissions from     Continuous parameter     Maintaining the hourly
                                        your catalyst            monitoring system.       average CO
                                        regenerator vent or CO                            concentration below
                                        boiler serving the                                500 ppmv (dry basis).
                                        catalytic cracking
                                        unit must not exceed
                                        500 ppmv (dry basis).
                                       c. Visible emissions     Control device-flare...  On and after January
                                        from a flare must not                             30, 2019, meeting the
                                        exceed a total of 5                               requirements of Sec.
                                        minutes during any 2-                             63.670. Prior to
                                        hour period.                                      January 30, 2019,
                                                                                          maintaining visible
                                                                                          emissions below a
                                                                                          total of 5 minutes
                                                                                          during any 2-hour
                                                                                          operating period, or
                                                                                          meeting the
                                                                                          requirements of Sec.
                                                                                          63.670.
----------------------------------------------------------------------------------------------------------------


0
65. Table 14 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1565(c)(1), you shall meet each requirement 
in the following table that applies to you.

 Table 14 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Organic HAP Emissions From
                                            Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
                                                                                          You shall demonstrate
   For each new existing catalytic         If you use . . .        For this operating     continuous compliance
         cracking unit . . .                                          limit . . .                by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to NSPS for carbon          Continuous emission      Not applicable.........  Complying with Table 13
 monoxide (CO) in 40 CFR 60.103,        monitoring system.                                of this subpart, item
 60.100(e), 60.102a(b)(4).                                                                1.
2. Not subject to the NSPS for CO in   a. Continuous emission   Not applicable.........  Complying with Table 13
 40 CFR 60.103 or 60.102a(b)(4).        monitoring system.                                of this subpart, item
                                                                                          2.a.
                                       b. Continuous parameter  i. The daily average     Collecting the hourly
                                        monitoring systems--     combustion zone          and daily average
                                        thermal incinerator.     temperature must not     temperature monitoring
                                                                 fall below the level     data according to Sec.
                                                                 established during the     63.1572; and
                                                                 performance test.        maintaining the daily
                                                                                          average combustion
                                                                                          zone temperature above
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.
                                                                ii. The daily average    Collecting the hourly
                                                                 oxygen concentration     and daily average
                                                                 in the vent stream       oxygen concentration
                                                                 (percent, dry basis)     monitoring data
                                                                 must not fall below      according to Sec.
                                                                 the level established    63.1572; and
                                                                 during the performance   maintaining the daily
                                                                 test.                    average oxygen
                                                                                          concentration above
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.
                                       c. Continuous parameter  The daily combustion     Collecting the average
                                        monitoring systems--     zone temperature must    hourly and daily
                                        boiler or process        not fall below the       temperature monitoring
                                        heater with a design     level established in     data according to Sec.
                                        heat input capacity      the performance test.      63.1572; and
                                        under 44 MW or boiler                             maintaining the daily
                                        or process heater in                              average combustion
                                        which all vent streams                            zone temperature above
                                        are not introduced                                the limit established
                                        into the flame zone.                              during the performance
                                                                                          test.

[[Page 75304]]

 
                                       d. Continuous parameter  The flare pilot light    On and after January
                                        monitoring system--      must be present at all   30, 2019, meeting the
                                        flare.                   times and the flare      requirements of Sec.
                                                                 must be operating at     63.670. Prior to
                                                                 all times that           January 30, 2019,
                                                                 emissions may be         collecting the flare
                                                                 vented to it.            monitoring data
                                                                                          according to Sec.
                                                                                          63.1572 and recording
                                                                                          for each 1-hour period
                                                                                          whether the monitor
                                                                                          was continuously
                                                                                          operating and the
                                                                                          pilot light was
                                                                                          continuously present
                                                                                          during each 1-hour
                                                                                          period, or meeting the
                                                                                          requirements of Sec.
                                                                                          63.670.
3. During periods of startup,          Any control device.....  The oxygen               Collecting the hourly
 shutdown or hot standby electing to                             concentration limit in   average oxygen
 comply with the operating limit in                              Sec.                     concentration
 Sec.   63.1565(a)(5)(ii).                                       63.1565(a)(5)(ii).       monitoring data
                                                                                          according to Sec.
                                                                                          63.1572 and
                                                                                          maintaining the hourly
                                                                                          average oxygen
                                                                                          concentration at or
                                                                                          above 1 volume percent
                                                                                          (dry basis).
----------------------------------------------------------------------------------------------------------------


0
66. Table 15 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

   Table 15 to Subpart UUU of Part 63--Organic HAP Emission Limits for
                        Catalytic Reforming Units
------------------------------------------------------------------------
                                                     You shall meet this
                                                       emission limit
                                                       during initial
   For each applicable process vent for a new or          catalyst
     existing catalytic reforming  unit . . .         depressuring and
                                                      catalyst purging
                                                      operations . . .
------------------------------------------------------------------------
1. Option 1.......................................  On and after January
                                                     30, 2019, vent
                                                     emissions to a
                                                     flare that meets
                                                     the requirements of
                                                     Sec.   63.670.
                                                     Prior to January
                                                     30, 2019, vent
                                                     emissions to a
                                                     flare that meets
                                                     the requirements
                                                     for control devices
                                                     in Sec.   63.11(b)
                                                     and visible
                                                     emissions from a
                                                     flare must not
                                                     exceed a total of 5
                                                     minutes during any
                                                     2-hour operating
                                                     period, or vent
                                                     emissions to a
                                                     flare that meets
                                                     the requirements of
                                                     Sec.   63.670.
 
                              * * * * * * *
------------------------------------------------------------------------


0
67. Table 16 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

  Table 16 to Subpart UUU of Part 63--Operating Limits for Organic HAP
                Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
                                                    You shall meet this
                                                      operating limit
   For each new or existing      For this type of      during initial
catalytic reforming unit . . .   control device .  catalyst depressuring
                                       . .              and purging
                                                      operations. . .
------------------------------------------------------------------------
1. Option 1: Vent to flare....  Flare............  On and after January
                                                    30, 2019, the flare
                                                    must meet the
                                                    requirements of Sec.
                                                      63.670. Prior to
                                                    January 30, 2019,
                                                    the flare pilot
                                                    light must be
                                                    present at all times
                                                    and the flare must
                                                    be operating at all
                                                    times that emissions
                                                    may be vented to it,
                                                    or the flare must
                                                    meet the
                                                    requirements of Sec.
                                                      63.670.
 
                              * * * * * * *
------------------------------------------------------------------------


0
68. Table 17 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

[[Page 75305]]



  Table 17 to Subpart UUU of Part 63--Continuous Monitoring Systems for
          Organic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
                                                   You shall install and
  For each applicable process    If you use this    operate this type of
  vent for a new or existing     type of control   continuous monitoring
 catalytic  reforming unit . .     device . . .         system . . .
               .
------------------------------------------------------------------------
1. Option 1: Vent to a flare..  Flare............  On and after January
                                                    30, 2019, the
                                                    monitoring systems
                                                    required in Sec.
                                                    Sec.   63.670 and
                                                    63.671. Prior to
                                                    January 30, 2019,
                                                    monitoring device
                                                    such as a
                                                    thermocouple, an
                                                    ultraviolet beam
                                                    sensor, or infrared
                                                    sensor to
                                                    continuously detect
                                                    the presence of a
                                                    pilot flame, or the
                                                    monitoring systems
                                                    required in Sec.
                                                    Sec.   63.670 and
                                                    63.671.
 
                              * * * * * * *
------------------------------------------------------------------------


0
69. Table 18 to subpart UUU of part 63 is amended by revising the 
column headings and the entry for item 1 to read as follows:
* * * * *

 Table 18 to Subpart UUU of Part 63--Requirements for Performance Tests for Organic HAP Emissions From Catalytic
                                                 Reforming Units
----------------------------------------------------------------------------------------------------------------
  For each new or existing catalytic                                                        According to these
         reforming unit . . .               You must . . .            Using . . .           requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Option 1: Vent to a flare.........  a. Conduct visible       Method 22 (40 CFR part   On and after January
                                        emission observations.   60, appendix A-7).       30, 2019, the flare
                                                                                          must meet the
                                                                                          requirements of Sec.
                                                                                          63.670. Prior to
                                                                                          January 30, 2019, 2-
                                                                                          hour observation
                                                                                          period. Record the
                                                                                          presence of a flame at
                                                                                          the pilot light over
                                                                                          the full period of the
                                                                                          test, or the
                                                                                          requirements of Sec.
                                                                                          63.670.
                                       b. Determine that the    40 CFR 63.11(b)(6)       On and after January
                                        flare meets the          through (8).             30, 2019, the flare
                                        requirements for net                              must meet the
                                        heating value of the                              requirements of Sec.
                                        gas being combusted                               63.670. Prior to
                                        and exit velocity.                                January 30, 2019, the
                                                                                          flare must meet the
                                                                                          control device
                                                                                          requirements in Sec.
                                                                                          63.11(b) or the
                                                                                          requirements of Sec.
                                                                                          63.670.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


0
70. Table 19 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

 Table 19 to Subpart UUU of Part 63--Initial Compliance With Organic HAP
              Emission Limits for Catalytic Reforming Units
------------------------------------------------------------------------
 For each applicable process
 vent for a new or existing     For the following         You have
catalytic reforming unit . .  emission limit . . .  demonstrated initial
              .                                     compliance  if . . .
------------------------------------------------------------------------
Option 1....................  Visible emissions     On and after January
                               from a flare must     30, 2019, the flare
                               not exceed a total    meets the
                               of 5 minutes during   requirements of
                               any 2 consecutive     Sec.   63.670.
                               hours.                Prior to January
                                                     30, 2019, visible
                                                     emissions, measured
                                                     using Method 22
                                                     over the 2-hour
                                                     observation period
                                                     of the performance
                                                     test, do not exceed
                                                     a total of 5
                                                     minutes, or the
                                                     flare meets the
                                                     requirements of
                                                     Sec.   63.670.
 
                              * * * * * * *
------------------------------------------------------------------------


0
71. Table 20 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

[[Page 75306]]



 Table 20 to Subpart UUU of Part 63--Continuous Compliance With Organic
            HAP Emission Limits for Catalytic Reforming Units
------------------------------------------------------------------------
                                                          You shall
                                                         demonstrate
 For each applicable process                             continuous
 vent for a new or existing     For this emission     compliance during
catalytic reforming unit . .       limit . . .        initial catalyst
              .                                       depressuring and
                                                      catalyst purging
                                                     operations by . . .
------------------------------------------------------------------------
1. Option 1.................  Vent emissions from   On and after January
                               your process vent     30, 2019, meeting
                               to a flare.           the requirements of
                                                     Sec.   63.670.
                                                     Prior to January
                                                     30, 2019,
                                                     maintaining visible
                                                     emissions from a
                                                     flare below a total
                                                     of 5 minutes during
                                                     any 2 consecutive
                                                     hours, or meeting
                                                     the requirements of
                                                     Sec.   63.670.
 
                              * * * * * * *
------------------------------------------------------------------------


0
72. Table 21 to subpart UUU of part 63 is amended by revising the entry 
for item 1 to read as follows:
* * * * *

 Table 21 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Organic HAP Emissions From
                                            Catalytic Reforming Units
----------------------------------------------------------------------------------------------------------------
                                                                                          You shall demonstrate
                                                                                          continuous compliance
 For each applicable process vent for                              For this operating    during initial catalyst
a new or existing catalytic reforming      If you use . . .           limit . . .            depressuring and
              unit . . .                                                                  purging  operations by
                                                                                                  . . .
----------------------------------------------------------------------------------------------------------------
1. Option 1..........................  Flare..................  The flare pilot light    On and after January
                                                                 must be present at all   30, 2019, meeting the
                                                                 times and the flare      requirements of Sec.
                                                                 must be operating at     63.670. Prior to
                                                                 all times that           January 30, 2019,
                                                                 emissions may be         collecting flare
                                                                 vented to it.            monitoring data
                                                                                          according to Sec.
                                                                                          63.1572 and recording
                                                                                          for each 1-hour period
                                                                                          whether the monitor
                                                                                          was continuously
                                                                                          operating and the
                                                                                          pilot light was
                                                                                          continuously present
                                                                                          during each 1-hour
                                                                                          period, or meeting the
                                                                                          requirements of Sec.
                                                                                          63.670.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


0
73. Table 22 to subpart UUU of part 63 is amended by revising the 
entries for items 2 and 3 to read as follows:
* * * * *

  Table 22 to Subpart UUU of Part 63--Inorganic HAP Emission Limits for
                        Catalytic Reforming Units
------------------------------------------------------------------------
                                           You shall meet this emission
                                            limit for each applicable
                                            catalytic  reforming unit
               For . . .                  process vent during coke burn-
                                          off and catalyst  rejuvenation
                                                      . . .
------------------------------------------------------------------------
 
                              * * * * * * *
2. Each existing cyclic or continuous    Reduce uncontrolled emissions
 catalytic reforming unit.                of HCl by 97 percent by weight
                                          or to a concentration of 10
                                          ppmv (dry basis), corrected to
                                          3 percent oxygen.
3. Each new semi-regenerative, cyclic,   Reduce uncontrolled emissions
 or continuous catalytic reforming unit.  of HCl by 97 percent by weight
                                          or to a concentration of 10
                                          ppmv (dry basis), corrected to
                                          3 percent oxygen.
------------------------------------------------------------------------


0
74. Table 24 to subpart UUU of part 63 is amended by revising the 
entries for items 2 through 4 and footnote 2 to read as follows:
* * * * *

[[Page 75307]]



  Table 24 to Subpart UUU of Part 63--Continuous Monitoring Systems for
         Inorganic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
                                          You shall install and operate
 If you use this type of control device      this type of continuous
          for your vent . . .                monitoring system . . .
------------------------------------------------------------------------
 
                              * * * * * * *
2. Internal scrubbing system or no       Colormetric tube sampling
 control device (e.g., hot regen          system to measure the HCl
 system) to meet HCl outlet               concentration in the catalyst
 concentration limit.                     regenerator exhaust gas during
                                          coke burn-off and catalyst
                                          rejuvenation. The colormetric
                                          tube sampling system must meet
                                          the requirements in Table 41
                                          of this subpart.
3. Internal scrubbing system to meet     Continuous parameter monitoring
 HCl percent reduction standard.          system to measure and record
                                          the gas flow rate entering or
                                          exiting the internal scrubbing
                                          system during coke burn-off
                                          and catalyst rejuvenation; and
                                          continuous parameter
                                          monitoring system to measure
                                          and record the total water (or
                                          scrubbing liquid) flow rate
                                          entering the internal
                                          scrubbing system during coke
                                          burn-off and catalyst
                                          rejuvenation; and continuous
                                          parameter monitoring system to
                                          measure and record the pH or
                                          alkalinity of the water (or
                                          scrubbing liquid) exiting the
                                          internal scrubbing system
                                          during coke burn-off and
                                          catalyst rejuvenation.\2\
4. Fixed-bed gas-solid adsorption        Continuous parameter monitoring
 system.                                  system to measure and record
                                          the temperature of the gas
                                          entering or exiting the
                                          adsorption system during coke
                                          burn-off and catalyst
                                          rejuvenation; and colormetric
                                          tube sampling system to
                                          measure the gaseous HCl
                                          concentration in the
                                          adsorption system exhaust and
                                          at a point within the
                                          absorbent bed not to exceed 90
                                          percent of the total length of
                                          the absorbent bed during coke
                                          burn-off and catalyst
                                          rejuvenation. The colormetric
                                          tube sampling system must meet
                                          the requirements in Table 41
                                          of this subpart.
 
                              * * * * * * *
------------------------------------------------------------------------
 * * * * * * *
\2\ If applicable, you can use the alternative in Sec.   63.1573(c)(1)
  instead of a continuous parameter monitoring system for pH of the
  water (or scrubbing liquid) or the alternative in Sec.   63.1573(c)(2)
  instead of a continuous parameter monitoring system for alkalinity of
  the water (or scrubbing liquid).

* * * * *
0
75. Table 25 to subpart UUU of part 63 is amended by revising the 
entries for items 2.a and 4.a and footnote 1 to read as follows:
* * * * *

     Table 25 to Subpart UUU of Part 63--Requirements for Performance Tests for Inorganic HAP Emissions From
                                            Catalytic Reforming Units
----------------------------------------------------------------------------------------------------------------
 For each new and existing  catalytic                                                       According to these
     reforming unit  using . . .           You shall . . .            Using . . .           requirements . . .
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
2. Wet scrubber......................  a. Establish operating   i. Data from continuous  Measure and record the
                                        limit for pH level or    parameter monitoring     pH or alkalinity of
                                        alkalinity.              systems.                 the water (or
                                                                                          scrubbing liquid)
                                                                                          exiting scrubber every
                                                                                          15 minutes during the
                                                                                          entire period of the
                                                                                          performance test.
                                                                                          Determine and record
                                                                                          the minimum hourly
                                                                                          average pH or
                                                                                          alkalinity level from
                                                                                          the recorded values.
                                                                ii. Alternative pH       Measure and record the
                                                                 procedure in Sec.        pH of the water (or
                                                                 63.1573(b)(1).           scrubbing liquid)
                                                                                          exiting the scrubber
                                                                                          during coke burn-off
                                                                                          and catalyst
                                                                                          rejuvenation using pH
                                                                                          strips at least three
                                                                                          times during each test
                                                                                          run. Determine and
                                                                                          record the average pH
                                                                                          level for each test
                                                                                          run. Determine and
                                                                                          record the minimum
                                                                                          test run average pH
                                                                                          level.

[[Page 75308]]

 
                                                                iii. Alternative         Measure and record the
                                                                 alkalinity method in     alkalinity of the
                                                                 Sec.   63.1573(c)(2).    water (or scrubbing
                                                                                          liquid) exiting the
                                                                                          scrubber during coke
                                                                                          burn-off and catalyst
                                                                                          rejuvenation using
                                                                                          discrete titration at
                                                                                          least three times
                                                                                          during each test run.
                                                                                          Determine and record
                                                                                          the average alkalinity
                                                                                          level for each test
                                                                                          run. Determine and
                                                                                          record the minimum
                                                                                          test run average
                                                                                          alkalinity level.
 
                                                  * * * * * * *
4. Internal scrubbing system meeting   a. Establish operating   i. Data from continuous  Measure and record the
 HCl percent reduction standard.        limit for pH level or    parameter monitoring     pH alkalinity of the
                                        alkalinity.              system.                  water (or scrubbing
                                                                                          liquid) exiting the
                                                                                          internal scrubbing
                                                                                          system every 15
                                                                                          minutes during the
                                                                                          entire period of the
                                                                                          performance test.
                                                                                          Determine and record
                                                                                          the minimum hourly
                                                                                          average pH or
                                                                                          alkalinity level from
                                                                                          the recorded values.
                                                                ii. Alternative pH       Measure and in record
                                                                 method in Sec.           pH of the water (or
                                                                 63.1573(c)(1).           scrubbing liquid)
                                                                                          exiting the internal
                                                                                          scrubbing system
                                                                                          during coke burn-off
                                                                                          and catalyst
                                                                                          rejuvenation using pH
                                                                                          strips at least three
                                                                                          times during each test
                                                                                          run. Determine and
                                                                                          record the average pH
                                                                                          level for each test
                                                                                          run. Determine and
                                                                                          record the minimum
                                                                                          test run average pH
                                                                                          level.
                                                                iii. Alternative         Measure and record the
                                                                 alkalinity method in     alkalinity water (or
                                                                 Sec.   63.1573(c)(2).    scrubbing liquid)
                                                                                          exiting the internal
                                                                                          scrubbing system
                                                                                          during coke burn-off
                                                                                          and catalyst
                                                                                          rejuvenation using
                                                                                          discrete titration at
                                                                                          least three times
                                                                                          during each test run.
                                                                                          Determine and record
                                                                                          the average alkalinity
                                                                                          level for each test
                                                                                          run. Determine and
                                                                                          record the minimum
                                                                                          test run average
                                                                                          alkalinity level.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
\1\ The EPA Methods 5050, 9056, 9212 and 9253 are included in ``Test Methods for Evaluating Solid Waste,
  Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates (document
  number 955-001-00000-1) are available for purchase from the Superintendent of Documents, U.S. Government
  Printing Office, Washington, DC 20402, (202) 512-1800; and from the National Technical Information Services
  (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket
  Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW.,
  Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington,
  DC. These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm.

0
76. Table 28 to subpart UUU of part 63 is amended by revising the entry 
for item 5 and footnotes 1 and 3 to read as follows:
* * * * *

Table 28 to Subpart UUU of Part 63--Continuous Compliance With Operating
    Limits for Inorganic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
                                                          You shall
                                                         demonstrate
  For each new and existing                              continuous
  catalytic reforming unit     For this operating     compliance during
 using this type of control        limit . . .        coke burn-off and
   device or  system . . .                                catalyst
                                                     rejuvenation by . .
                                                              .
------------------------------------------------------------------------
 

[[Page 75309]]

 
                              * * * * * * *
5. Moving-bed gas-solid       a. The daily average  Collecting the
 adsorption system (e.g.,      temperature of the    hourly and daily
 ChlorsorbTM System).          gas entering or       average temperature
                               exiting the           monitoring data
                               adsorption system     according to Sec.
                               must not exceed the   63.1572; and
                               limit established     maintaining the
                               during the            daily average
                               performance test.     temperature below
                                                     the operating limit
                                                     established during
                                                     the performance
                                                     test.
                              b. The weekly         Collecting samples
                               average chloride      of the sorbent
                               level on the          exiting the
                               sorbent entering      adsorption system
                               the adsorption        three times per
                               system must not       week (on non-
                               exceed the design     consecutive days);
                               or manufacturer's     and analyzing the
                               recommended limit     samples for total
                               (1.35 weight          chloride\3\; and
                               percent for the       determining and
                               Chlorsorb\TM\         recording the
                               System).              weekly average
                                                     chloride
                                                     concentration; and
                                                     maintaining the
                                                     chloride
                                                     concentration below
                                                     the design or
                                                     manufacturer's
                                                     recommended limit
                                                     (1.35 weight
                                                     percent for the
                                                     Chlorsorb\TM\
                                                     System).
                              c. The weekly         Collecting samples
                               average chloride      of the sorbent
                               level on the          exiting the
                               sorbent exiting the   adsorption system
                               adsorption system     three times per
                               must not exceed the   week (on non-
                               design or             consecutive days);
                               manufacturer's        and analyzing the
                               recommended limit     samples for total
                               (1.8 weight percent   chloride
                               for the               concentration; and
                               Chlorsorb\TM\         determining and
                               System).              recording the
                                                     weekly average
                                                     chloride
                                                     concentration; and
                                                     maintaining the
                                                     chloride
                                                     concentration below
                                                     the design or
                                                     manufacturer's
                                                     recommended limit
                                                     (1.8 weight percent
                                                     Chlorsorb\TM\
                                                     System).
------------------------------------------------------------------------
\1\ If applicable, you can use either alternative in Sec.   63.1573(c)
  instead of a continuous parameter monitoring system for pH or
  alkalinity if you used the alternative method in the initial
  performance test.
 * * * * * * *
\3\ The total chloride concentration of the sorbent material must be
  measured by the procedure, ``Determination of Metal Concentration on
  Catalyst Particles (Instrumental Analyzer Procedure)'' in appendix A
  to this subpart; or by using EPA Method 5050, Bomb Preparation Method
  for Solid Waste, combined either with EPA Method 9056, Determination
  of Inorganic Anions by Ion Chromatography, or with EPA Method 9253,
  Chloride (Titrimetric, Silver Nitrate); or by using EPA Method 9212,
  Potentiometric Determination of Chloride in Aqueous Samples with Ion-
  Selective Electrode, and using the soil extraction procedures listed
  within the method. The EPA Methods 5050, 9056, 9212 and 9253 are
  included in ``Test Methods for Evaluating Solid Waste, Physical/
  Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998).
  The SW-846 and Updates (document number 955-001-00000-1) are available
  for purchase from the Superintendent of Documents, U.S. Government
  Printing Office, Washington, DC 20402, (202) 512-1800; and from the
  National Technical Information Services (NTIS), 5285 Port Royal Road,
  Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the
  EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air
  Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at
  the Office of the Federal Register, 800 North Capitol Street NW.,
  Suite 700, Washington, DC. These methods are also available at http://www.epa.gov/epaoswer/hazwaste/test/main.htm.


0
77. Table 29 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1568(a)(1), you shall meet each emission 
limitation in the following table that applies to you.

   Table 29 to Subpart UUU of Part 63--HAP Emission Limits for Sulfur
                             Recovery Units
------------------------------------------------------------------------
                                           You shall meet this emission
               For . . .                 limit for each process vent . .
                                                        .
------------------------------------------------------------------------
1. Subject to NSPS. Each new or          a. 250 ppmv (dry basis) of
 existing Claus sulfur recovery unit      sulfur dioxide (SO2) at zero
 part of a sulfur recovery plant with     percent excess air, or
 design capacity greater than 20 long     concentration determined using
 tons per day (LTD) and subject to the    Equation 1 of 40 CFR
 NSPS for sulfur oxides in 40 CFR         60.102a(f)(1)(i), if you use
 60.104(a)(2) or 60.102a(f)(1).           an oxidation control system or
                                          if you use a reduction control
                                          system followed by
                                          incineration.
                                         b. 300 ppmv of reduced sulfur
                                          compounds calculated as ppmv
                                          SO2 (dry basis) at zero
                                          percent excess air, or
                                          concentration determined using
                                          Equation 1 of 40 CFR
                                          60.102a(f)(1)(i), if you use a
                                          reduction control system
                                          without incineration.
2. Option 1: Elect NSPS. Each new or     a. 250 ppmv (dry basis) of SO2
 existing sulfur recovery unit (Claus     at zero percent excess air, or
 or other type, regardless of size) not   concentration determined using
 subject to the NSPS for sulfur oxides    Equation 1 of 40 CFR
 in 40 CFR 60.104(a)(2) or                60.102a(f)(1)(i), if you use
 60.102a(f)(1).                           an oxidation control system or
                                          if you use a reduction control
                                          system followed by
                                          incineration.
                                         b. 300 ppmv of reduced sulfur
                                          compounds calculated as ppmv
                                          SO2 (dry basis) at zero
                                          percent excess air, or
                                          concentration determined using
                                          Equation 1 of 40 CFR
                                          60.102a(f)(1)(i), if you use a
                                          reduction control system
                                          without incineration.
3. Option 2: TRS limit. Each new or      300 ppmv of total reduced
 existing sulfur recovery unit (Claus     sulfur (TRS) compounds,
 or other type, regardless of size) not   expressed as an equivalent SO2
 subject to the NSPS for sulfur oxides    concentration (dry basis) at
 in 40 CFR 60.104(a)(2) or                zero percent oxygen.
 60.102a(f)(1).
------------------------------------------------------------------------


[[Page 75310]]


0
78. Table 30 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1568(a)(2), you shall meet each operating 
limit in the following table that applies to you.

 Table 30 to Subpart UUU of Part 63--Operating Limits for HAP Emissions
                       From Sulfur Recovery Units
------------------------------------------------------------------------
                                                     You shall meet this
          For . . .            If use this type of   operating limit . .
                              control device . . .            .
------------------------------------------------------------------------
1. Subject to NSPS. Each new  Not applicable......  Not applicable.
 or existing Claus sulfur
 recovery unit part of a
 sulfur recovery plant with
 design capacity greater
 than 20 LTD and subject to
 the NSPS for sulfur oxides
 in 40 CFR 60.104(a)(2) or
 60.102a(f)(1).
2. Option 1: