[Federal Register Volume 79, Number 125 (Monday, June 30, 2014)]
[Proposed Rules]
[Pages 36879-37075]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-12167]



[[Page 36879]]

Vol. 79

Monday,

No. 125

June 30, 2014

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; Proposed Rule

Federal Register / Vol. 79 , No. 125 / Monday, June 30, 2014 / 
Proposed Rules

[[Page 36880]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0682; FRL-9720-4]
RIN 2060-AQ75


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

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

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SUMMARY: This action proposes amendments to the national emission 
standards for hazardous air pollutants for petroleum refineries to 
address the risk remaining after application of the standards 
promulgated in 1995 and 2002. This action also proposes amendments to 
the national emission standards for hazardous air pollutants for 
petroleum refineries based on the results of the Environmental 
Protection Agency (EPA) review of developments in practices, processes 
and control technologies and includes new monitoring, recordkeeping and 
reporting requirements. The EPA is also proposing new requirements 
related to emissions during periods of startup, shutdown and 
malfunction to ensure that the standards are consistent with court 
opinions issued since promulgation of the standards. This action also 
proposes technical corrections and clarifications for new source 
performance standards for petroleum refineries to improve consistency 
and clarity and address issues raised after the 2008 rule promulgation. 
Implementation of this proposed rule will result in projected 
reductions of 1,760 tons per year (tpy) of hazardous air pollutants 
(HAP), which will reduce cancer risk and chronic health effects.

DATES: 
    Comments. Comments must be received on or before August 29, 2014. A 
copy of comments on the information collection provisions should be 
submitted to the Office of Management and Budget (OMB) on or before 
July 30, 2014.
    Public Hearing. The EPA will hold public hearings on this proposed 
rule on July 16, 2014, at Banning's Landing Community Center, 100 E. 
Water Street, Wilmington, California 90744, and on August 5, 2014, at 
the Alvin D. Baggett Recreation Building 1302 Keene Street in Galena 
Park, Texas, 77547.

ADDRESSES: 
    Comments. Submit your comments, identified by Docket ID Number EPA-
HQ-OAR-2010-0682, by one of the following methods:
     http://www.regulations.gov: Follow the on-line 
instructions for submitting comments.
     Email: a-and-r-docket@epa.gov. Attention Docket ID Number 
EPA-HQ-OAR-2010-0682.
     Fax: (202) 566-9744. Attention Docket ID Number EPA-HQ-
OAR-2010-0682.
     Mail: U.S. Postal Service, send comments to: EPA Docket 
Center, William Jefferson Clinton (WJC) West Building (Air Docket), 
Attention Docket ID Number EPA-HQ-OAR-2010-0682, U.S. Environmental 
Protection Agency, Mailcode: 28221T, 1200 Pennsylvania Ave. NW., 
Washington, DC 20460. Please include a total of two copies. In 
addition, please mail a copy of your comments on the information 
collection provisions to the Office of Information and Regulatory 
Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for 
EPA, 725 17th Street NW., Washington, DC 20503.
     Hand Delivery: U.S. Environmental Protection Agency, WJC 
West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., 
Washington, DC 20004. Attention Docket ID Number EPA-HQ-OAR-2010-0682. 
Such deliveries are only accepted during the Docket's normal hours of 
operation, and special arrangements should be made for deliveries of 
boxed information.
    Instructions. Direct your comments to Docket ID Number EPA-HQ-OAR-
2010-0682. The EPA's policy is that all comments received will be 
included in the public docket without change and may be made available 
online at http://www.regulations.gov, including any personal 
information provided, unless the comment includes information claimed 
to be confidential business information (CBI) or other information 
whose disclosure is restricted by statute. Do not submit information 
that you consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means the EPA will not know 
your identity or contact information unless you provide it in the body 
of your comment. If you send an email comment directly to the EPA 
without going through http://www.regulations.gov, your email address 
will be automatically captured and included as part of the comment that 
is placed in the public docket and made available on the Internet. If 
you submit an electronic comment, the EPA recommends that you include 
your name and other contact information in the body of your comment and 
with any disk or CD-ROM you submit. If the EPA cannot read your comment 
due to technical difficulties and cannot contact you for clarification, 
the EPA may not be able to consider your comment. Electronic files 
should not include special characters or any form of encryption and be 
free of any defects or viruses. For additional information about the 
EPA's public docket, visit the EPA Docket Center homepage at: http://www.epa.gov/dockets.
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID Number EPA-HQ-OAR-2010-0682. All documents in the docket are 
listed in the regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, is not placed on the Internet and will be 
publicly available only in hard copy. Publicly available docket 
materials are available either electronically in regulations.gov or in 
hard copy at the EPA Docket Center, WJC West Building, Room 3334, 1301 
Constitution Ave. NW., Washington, DC. The Public Reading Room is open 
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal 
holidays. The telephone number for the Public Reading Room is (202) 
566-1744, and the telephone number for the EPA Docket Center is (202) 
566-1742.
    Public Hearing. The public hearing will be held in Wilmington, 
California on July 16, 2014 at Banning's Landing Community Center, 100 
E. Water Street, Wilmington, California 90744. The hearing will convene 
at 9 a.m. and end at 8 p.m. A lunch break will be held from 1 p.m. 
until 2 p.m. A dinner break will be held from 5 p.m. until 6 p.m. The 
public hearing in Galena Park, Texas will be held on August 5, 2014, at 
the Alvin D. Baggett Recreation Building 1302 Keene Street Galena Park, 
Texas 77547. The hearing will convene at 9 a.m. and will end at 8 p.m. 
A lunch break will be held from noon until 1 p.m. A dinner break will 
be held from 5 p.m. until 6 p.m. Please contact Ms. Virginia Hunt at 
(919) 541-0832 or at hunt.virginia@epa.gov to register to speak at the 
hearing. The last day to pre-register in advance to speak at the 
hearing is July 11, 2014, for the Wilmington, California hearing and 
August 1, 2014, for the Galena Park, Texas hearing. Additionally, 
requests to speak will be taken the day of the hearing at the hearing 
registration desk, although preferences on speaking times may not be 
able to be fulfilled. If you require the service of a translator or

[[Page 36881]]

special accommodations such as audio description, please let us know at 
the time of registration.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed 
action, contact Ms. Brenda Shine, Sector Policies and Programs Division 
(E143-01), Office of Air Quality Planning and Standards (OAQPS), U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; telephone number: (919) 541-3608; fax number: (919) 541-0246; 
and email address: shine.brenda@epa.gov. For specific information 
regarding the risk modeling methodology, contact Mr. Ted Palma, Health 
and Environmental Impacts Division (C539-02), Office of Air Quality 
Planning and Standards (OAQPS), U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711; telephone number: (919) 
541-5470; fax number: (919) 541-0840; and email address: 
palma.ted@epa.gov. For information about the applicability of the 
National Emissions Standards for Hazardous Air Pollutants (NESHAP) or 
the New Source Performance Standards (NSPS) to a particular entity, 
contact Maria Malave, Office of Enforcement and Compliance Assurance 
(OECA), telephone number: (202) 564-7027; fax number: (202) 564-0050; 
and email address: malave.maria@epa.gov.

SUPPLEMENTARY INFORMATION:

Preamble Acronyms and Abbreviations

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

10/25 tpy emissions equal to or greater than 10 tons per year of a 
single pollutant or 25 tons per year of cumulative pollutants
ACGIH American Conference of Governmental Industrial Hygienists
ADAF age-dependent adjustment factors
AEGL acute exposure guideline levels
AERMOD air dispersion model used by the HEM-3 model
APCD air pollution control devices
API American Petroleum Institute
BDT best demonstrated technology
BLD bag leak detectors
BSER best system of emission reduction
Btu/ft\2\ British thermal units per square foot
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CalEPA California EPA
CBI confidential business information
CCU catalytic cracking units
Ccz combustion zone combustibles concentration
CDDF chlorinated dibenzodioxins and furans
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emissions monitoring system
CFR Code of Federal Regulations
CO carbon monoxide
CO2 carbon dioxide
CO2e carbon dioxide equivalents
COMS continuous opacity monitoring system
COS carbonyl sulfide
CPMS continuous parameter monitoring system
CRU catalytic reforming units
CS2 carbon disulfide
DCU delayed coking units
DIAL differential absorption light detection and ranging
EBU enhanced biological unit
EPA Environmental Protection Agency
ERPG emergency response planning guidelines
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FCCU fluid catalytic cracking units
FGCD fuel gas combustion devices
FR Federal Register
FTIR Fourier transform infrared spectroscopy
g PM/kg grams particulate matter per kilogram
GC gas chromatograph
GHG greenhouse gases
GPS global positioning system
H2S hydrogen sulfide
HAP hazardous air pollutants
HCl hydrogen chloride
HCN hydrogen cyanide
HEM-3 Human Exposure Model, Version 1.1.0
HF hydrogen fluoride
HFC highest fenceline concentration
HI hazard index
HQ hazard quotient
ICR Information Collection Request
IRIS Integrated Risk Information System
km kilometers
lb/day pounds per day
LDAR leak detection and repair
LFL lower flammability limit
LFLcz combustion zone lower flammability limit
LMC lowest measured concentration
LOAEL lowest-observed-adverse-effect level
LTD long tons per day
MACT maximum achievable control technology
mg/kg-day milligrams per kilogram per day
mg/L milligrams per liter
mg/m\3\ milligrams per cubic meter
Mg/yr megagrams per year
MFC measured fenceline concentration
MFR momentum flux ratio
MIR maximum individual risk
mph miles per hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NATA National Air Toxics Assessment
NEI National Emissions Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
NFS near-field interfering source
NHVcz combustion zone net heating value
Ni nickel
NIOSH National Institutes for Occupational Safety and Health
NOAEL no-observed-adverse-effect level
NOX nitrogen oxides
NRC National Research Council
NRDC Natural Resources Defense Council
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OECA Office of Enforcement and Compliance Assurance
OMB Office of Management and Budget
OSC off-site source contribution
OTM other test method
PAH polycyclic aromatic hydrocarbons
PB-HAP hazardous air pollutants known to be persistent and bio-
accumulative in the environment
PBT persistent, bioaccumulative, and toxic
PCB polychlorinated biphenyls
PEL probable effect level
PM particulate matter
PM2.5 particulate matter 2.5 micrometers in diameter and 
smaller
POM polycyclic organic matter
ppm parts per million
ppmv parts per million by volume
ppmw parts per million by weight
psia pounds per square inch absolute
psig pounds per square inch gauge
REL reference exposure level
REM Model Refinery Emissions Model
RFA Regulatory Flexibility Act
RfC reference concentration
RfD reference dose
RTR residual risk and technology review
SAB Science Advisory Board
SBA Small Business Administration
SBAR Small Business Advocacy Review
SCR selective catalytic reduction
SISNOSE significant economic impact on a substantial number of small 
entities
S/L/Ts state, local and tribal air pollution control agencies
SO2 sulfur dioxide
SRU sulfur recovery unit
SSM startup, shutdown and malfunction
STEL short-term exposure limit
TEQ toxicity equivalent
TLV threshold limit value
TOC total organic carbon
TOSHI target organ-specific hazard index
tpy tons per year
TRIM.FaTE Total Risk Integrated Methodology.Fate, Transport, and 
Ecological Exposure model
UB uniform background
UF uncertainty factor
UMRA Unfunded Mandates Reform Act
URE unit risk estimate
UV-DOAS ultraviolet differential optical absorption spectroscopy
VCS voluntary consensus standards
VOC volatile organic compounds
WJC William Jefferson Clinton
[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

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


[[Page 36882]]


AWP Alternative Work Practice To Detect Leaks From Equipment (40 CFR 
63.11(c), (d) and (e))
Benzene NESHAP National Emission Standards for Hazardous Air 
Pollutants: Benzene Emissions from Maleic Anhydride Plants, 
Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene 
Equipment Leaks, and Coke By-Product Recovery Plants (40 CFR part 
61, subpart L as of publication in the Federal Register at 54 FR 
38044, September 14, 1989)
BWON National Emission Standard for Benzene Waste Operations (40 CFR 
part 61, subpart FF)
Generic MACT National Emission Standards for Storage Vessels (40 CFR 
part 63, subpart WW)
HON National Emission Standards for Organic Hazardous Air Pollutants 
(40 CFR part 63, subparts F, G and H)
Marine Vessel MACT National Emission Standards for Marine Tank 
Vessel Loading Operations (40 CFR part 63, subpart Y)
Refinery MACT 1 National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC)
Refinery MACT 2 National Emission Standards for Hazardous Air 
Pollutants for Petroleum Refineries: Catalytic Cracking Units, 
Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 
63, subpart UUU)
Refinery NSPS J Standards of Performance for Petroleum Refineries 
(40 CFR part 60, subpart J)
Refinery NSPS Ja Standards of Performance for Petroleum Refineries 
for which Construction, Reconstruction, or Modification Commenced 
After May 14, 2007 (40 CFR part 60, subpart Ja)

    Organization of This Document. The information in this preamble is 
organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document and other related 
information?
    C. What should I consider as I prepare my comments for the EPA?
    D. Public Hearing
II. Background
    A. What is the statutory authority for this action?
    B. What are the source categories and how do the NESHAP and NSPS 
regulate emissions?
    C. What data collection activities were conducted to support 
this action?
    D. What other relevant background information and data are 
available?
III. Analytical Procedures
    A. How did we estimate post-MACT risks posed by the source 
categories?
    B. How did we consider the risk results in making decisions for 
this proposal?
    C. How did we perform the technology review?
IV. Analytical Results and Proposed Decisions
    A. What actions are we taking pursuant to CAA sections 112(d)(2) 
and 112(d)(3)?
    B. What are the results and proposed decisions based on our 
technology review?
    C. What are the results of the risk assessment and analyses?
    D. What are our proposed decisions regarding risk acceptability, 
ample margin of safety and adverse environmental effects?
    E. What other actions are we proposing?
    F. What compliance dates are we proposing?
V. Summary of Cost, Environmental and Economic Impacts
    A. What are the affected sources, the air quality impacts and 
cost impacts?
    B. What are the economic impacts?
    C. What are the benefits?
VI. Request for Comments
VII. Submitting Data Corrections
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

    A redline version of the regulatory language that incorporates the 
proposed changes in this action is available in the docket for this 
action (Docket ID No. EPA-HQ-OAR-2010-0682).

I. General Information

A. Does this action apply to me?

    Table 1 of this preamble lists the industries that are the subject 
of this proposal. Table 1 is not intended to be exhaustive but rather 
to provide a guide for readers regarding the entities that this 
proposed action is likely to affect. These proposed standards, once 
promulgated, will be directly applicable to the affected sources. Thus, 
federal, state, local and tribal government entities would not be 
affected by this proposed action. As defined in the ``Initial List of 
Categories of Sources Under Section 112(c)(1) of the Clean Air Act 
Amendments of 1990'' (see 57 FR 31576, July 16, 1992), the ``Petroleum 
Refineries--Catalytic Cracking (Fluid and other) Units, Catalytic 
Reforming Units, and Sulfur Plant Units'' source category and the 
``Petroleum Refineries--Other Sources Not Distinctly Listed'' both 
consist of any facility engaged in producing gasoline, naphthas, 
kerosene, jet fuels, distillate fuel oils, residual fuel oils, 
lubricants, or other products from crude oil or unfinished petroleum 
derivatives. The first of these source categories includes process 
vents associated with the following refinery process units: Catalytic 
cracking (fluid and other) units, catalytic reforming units and sulfur 
plant units. The second source category includes all emission sources 
associated with refinery process units except the process vents listed 
in the Petroleum Refineries--Catalytic Cracking (Fluid and Other) 
Units, Catalytic Reforming Units, and Sulfur Plant Units Source 
Category. The emission sources included in this source category 
include, but are not limited to, miscellaneous process vents (vents 
other than those listed in Petroleum Refineries--Catalytic Cracking 
(Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant 
Units Source Category), equipment leaks, storage vessels, wastewater, 
gasoline loading, marine vessel loading, and heat exchange systems.

                              Table 1--Industries Affected by This Proposed Action
----------------------------------------------------------------------------------------------------------------
                                                                    NAICS\a\
                            Industry                                  Code       Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Petroleum Refining Industry.....................................       324110  Petroleum refinery sources that
                                                                                are subject to 40 CFR part 60,
                                                                                subpart J and Ja and 40 CFR part
                                                                                63, subparts CC and UUU.
----------------------------------------------------------------------------------------------------------------
\a\ North American Industry Classification System.


[[Page 36883]]

B. Where can I get a copy of this document and other related 
information?

    Following signature by the EPA Administrator, the EPA will post a 
copy of this proposed action at: http://www.epa.gov/ttn/atw/petref.html. Following publication in the Federal Register, the EPA 
will post the Federal Register version of the proposal and key 
technical documents at the Web site. Information on the overall 
residual risk and technology review (RTR) program is available at the 
following Web site: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html.

C. What should I consider as I prepare my comments for the EPA?

    Submitting CBI. Do not submit information containing CBI to the EPA 
through http://www.regulations.gov or email. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
a disk or CD-ROM that you mail to the EPA, mark the outside of the disk 
or CD-ROM as CBI and then identify electronically within the disk or 
CD-ROM the specific information that is claimed as CBI. In addition to 
one complete version of the comments that includes information claimed 
as CBI, you must submit a copy of the comments that does not contain 
the information claimed as CBI for inclusion in the public docket. If 
you submit a CD-ROM or disk that does not contain CBI, mark the outside 
of the disk or CD-ROM clearly that it does not contain CBI. Information 
not marked as CBI will be included in the public docket and the EPA's 
electronic public docket without prior notice. Information marked as 
CBI will not be disclosed except in accordance with procedures set 
forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver 
information identified as CBI only to the following address: Roberto 
Morales, OAQPS Document Control Officer (C404-02), OAQPS, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711, Attention Docket ID Number EPA-HQ-OAR-2010-0682.

D. Public Hearing

    The hearing will provide interested parties the opportunity to 
present data, views or arguments concerning the proposed action. The 
EPA will make every effort to accommodate all speakers who arrive and 
register. The EPA may ask clarifying questions during the oral 
presentations but will not respond to the presentations at that time. 
Written statements and supporting information submitted during the 
comment period will be considered with the same weight as oral comments 
and supporting information presented at the public hearing. Written 
comments on the proposed rule must be postmarked by August 29, 2014. 
Commenters should notify Ms. Virginia Hunt if they will need specific 
equipment, or if there are other special needs related to providing 
comments at the hearing. Oral testimony will be limited to 5 minutes 
for each commenter. The EPA encourages commenters to provide the EPA 
with a copy of their oral testimony electronically (via email or CD) or 
in hard copy form. Verbatim transcripts of the hearings and written 
statements will be included in the docket for the rulemaking. The EPA 
will make every effort to follow the schedule as closely as possible on 
the day of the hearing; however, please plan for the hearing to run 
either ahead of schedule or behind schedule. Information regarding the 
hearing will be available at: http://www.epa.gov/ttnatw01/petrefine/petrefpg.html.

II. Background

A. What is the statutory authority for this action?

1. NESHAP
    Section 112 of the Clean Air Act (CAA) establishes a two-stage 
regulatory process to address emissions of HAP from stationary sources. 
In the first stage, after the EPA has identified categories of sources 
emitting one or more of the HAP listed in CAA section 112(b), CAA 
section 112(d) requires us to promulgate technology-based national 
emissions standards for hazardous air pollutants (NESHAP) for those 
sources. ``Major sources'' are those that emit or have the potential to 
emit 10 tpy or more of a single HAP or 25 tpy or more of any 
combination of HAP. For major sources, the technology-based NESHAP must 
reflect the maximum degree of emissions reductions of HAP achievable 
(after considering cost, energy requirements and non-air quality health 
and environmental impacts) and are commonly referred to as maximum 
achievable control technology (MACT) standards.
    MACT standards must reflect the maximum degree of emissions 
reduction achievable through the application of measures, processes, 
methods, systems or techniques, including, but not limited to, measures 
that (1) reduce the volume of or eliminate pollutants through process 
changes, substitution of materials or other modifications; (2) enclose 
systems or processes to eliminate emissions; (3) capture or treat 
pollutants when released from a process, stack, storage or fugitive 
emissions point; (4) are design, equipment, work practice or 
operational standards (including requirements for operator training or 
certification); or (5) are a combination of the above. CAA section 
112(d)(2)(A)-(E). The MACT standards may take the form of design, 
equipment, work practice or operational standards where the EPA first 
determines either that (1) a pollutant cannot be emitted through a 
conveyance designed and constructed to emit or capture the pollutant, 
or that any requirement for, or use of, such a conveyance would be 
inconsistent with law; or (2) the application of measurement 
methodology to a particular class of sources is not practicable due to 
technological and economic limitations. CAA section 112(h)(1)-(2).
    The MACT ``floor'' is the minimum control level allowed for MACT 
standards promulgated under CAA section 112(d)(3) and may not be based 
on cost considerations. For new sources, the MACT floor cannot be less 
stringent than the emissions control that is achieved in practice by 
the best-controlled similar source. The MACT floor for existing sources 
can be less stringent than floors for new sources but not less 
stringent than the average emissions limitation achieved by the best-
performing 12 percent of existing sources in the category or 
subcategory (or the best-performing five sources for categories or 
subcategories with fewer than 30 sources). In developing MACT 
standards, the EPA must also consider control options that are more 
stringent than the floor. We may establish standards more stringent 
than the floor based on considerations of the cost of achieving the 
emission reductions, any non-air quality health and environmental 
impacts and energy requirements.
    The EPA is then required to review these technology-based standards 
and revise them ``as necessary (taking into account developments in 
practices, processes, and control technologies)'' no less frequently 
than every eight years. CAA section 112(d)(6). In conducting this 
review, the EPA is not required to recalculate the MACT floor. Natural 
Resources Defense Council (NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 
2008). Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667 
(D.C. Cir. 2013).
    The second stage in standard-setting focuses on reducing any 
remaining (i.e., ``residual'') risk according to CAA section 112(f). 
Section 112(f)(1) required that the EPA by November 1996 prepare a 
report to Congress discussing (among

[[Page 36884]]

other things) methods of calculating the risks posed (or potentially 
posed) by sources after implementation of the MACT standards, the 
public health significance of those risks and the EPA's recommendations 
as to legislation regarding such remaining risk. The EPA prepared and 
submitted the Residual Risk Report to Congress, EPA-453/R-99-001 (Risk 
Report) in March 1999. CAA section 112(f)(2) then provides that if 
Congress does not act on any recommendation in the Risk Report, the EPA 
must analyze and address residual risk for each category or subcategory 
of sources 8 years after promulgation of such standards pursuant to CAA 
section 112(d).
    Section 112(f)(2) of the CAA requires the EPA to determine for 
source categories subject to MACT standards whether the emission 
standards provide an ample margin of safety to protect public health. 
Section 112(f)(2)(B) of the CAA expressly preserves the EPA's use of 
the two-step process for developing standards to address any residual 
risk and the agency's interpretation of ``ample margin of safety'' 
developed in the National Emissions Standards for Hazardous Air 
Pollutants: Benzene Emissions from Maleic Anhydride Plants, 
Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment 
Leaks, and Coke By-Product Recovery Plants (Benzene NESHAP) (54 FR 
38044, September 14, 1989). The EPA notified Congress in the Risk 
Report that the agency intended to use the Benzene NESHAP approach in 
making CAA section 112(f) residual risk determinations (EPA-453/R-99-
001, p. ES-11). The EPA subsequently adopted this approach in its 
residual risk determinations and in a challenge to the risk review for 
the Synthetic Organic Chemical Manufacturing source category, the 
United States Court of Appeals for the District of Columbia Circuit 
upheld as reasonable the EPA's interpretation that subsection 112(f)(2) 
incorporates the standards established in the Benzene NESHAP. See NRDC 
v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008) (``[S]ubsection 
112(f)(2)(B) expressly incorporates the EPA's interpretation of the 
Clean Air Act from the Benzene standard, complete with a citation to 
the Federal Register.''); see also A Legislative History of the Clean 
Air Act Amendments of 1990, vol. 1, p. 877 (Senate debate on Conference 
Report).
    The first step in the process of evaluating residual risk is the 
determination of acceptable risk. If risks are unacceptable, the EPA 
cannot consider cost in identifying the emissions standards necessary 
to bring risks to an acceptable level. The second step is the 
determination of whether standards must be further revised in order to 
provide an ample margin of safety to protect public health. The ample 
margin of safety is the level at which the standards must be set, 
unless an even more stringent standard is necessary to prevent, taking 
into consideration costs, energy, safety and other relevant factors, an 
adverse environmental effect.
a. Step 1--Determining Acceptability
    The agency in the Benzene NESHAP concluded ``that the acceptability 
of risk under section 112 is best judged on the basis of a broad set of 
health risk measures and information'' and that the ``judgment on 
acceptability cannot be reduced to any single factor.'' Id. at 38046. 
The determination of what represents an ``acceptable'' risk is based on 
a judgment of ``what risks are acceptable in the world in which we 
live'' (Risk Report at 178, quoting NRDC v. EPA, 824 F. 2d 1146, 1165 
(D.C. Cir. 1987) (en banc) (``Vinyl Chloride''), recognizing that our 
world is not risk-free.
    In the Benzene NESHAP, we stated that ``EPA will generally presume 
that if the risk to [the maximum exposed] individual is no higher than 
approximately one in 10 thousand, that risk level is considered 
acceptable.'' 54 FR at 38045, September 14, 1989. We discussed the 
maximum individual lifetime cancer risk (or maximum individual risk 
(MIR)) as being ``the estimated risk that a person living near a plant 
would have if he or she were exposed to the maximum pollutant 
concentrations for 70 years.'' Id. We explained that this measure of 
risk ``is an estimate of the upper bound of risk based on conservative 
assumptions, such as continuous exposure for 24 hours per day for 70 
years.'' Id. We acknowledged that maximum individual lifetime cancer 
risk ``does not necessarily reflect the true risk, but displays a 
conservative risk level which is an upper-bound that is unlikely to be 
exceeded.'' Id.
    Understanding that there are both benefits and limitations to using 
the MIR as a metric for determining acceptability, we acknowledged in 
the Benzene NESHAP that ``consideration of maximum individual risk * * 
* must take into account the strengths and weaknesses of this measure 
of risk.'' Id. Consequently, the presumptive risk level of 100-in-1 
million (1-in-10 thousand) provides a benchmark for judging the 
acceptability of maximum individual lifetime cancer risk, but does not 
constitute a rigid line for making that determination. Further, in the 
Benzene NESHAP, we noted that:

[p]articular attention will also be accorded to the weight of 
evidence presented in the risk assessment of potential 
carcinogenicity or other health effects of a pollutant. While the 
same numerical risk may be estimated for an exposure to a pollutant 
judged to be a known human carcinogen, and to a pollutant considered 
a possible human carcinogen based on limited animal test data, the 
same weight cannot be accorded to both estimates. In considering the 
potential public health effects of the two pollutants, the Agency's 
judgment on acceptability, including the MIR, will be influenced by 
the greater weight of evidence for the known human carcinogen.

Id. at 38046. The agency also explained in the Benzene NESHAP that:

[i]n establishing a presumption for MIR, rather than a rigid line 
for acceptability, the Agency intends to weigh it with a series of 
other health measures and factors. These include the overall 
incidence of cancer or other serious health effects within the 
exposed population, the numbers of persons exposed within each 
individual lifetime risk range and associated incidence within, 
typically, a 50 km exposure radius around facilities, the science 
policy assumptions and estimation uncertainties associated with the 
risk measures, weight of the scientific evidence for human health 
effects, other quantified or unquantified health effects, effects 
due to co-location of facilities, and co-emission of pollutants.

Id. at 38045. In some cases, these health measures and factors taken 
together may provide a more realistic description of the magnitude of 
risk in the exposed population than that provided by maximum individual 
lifetime cancer risk alone.
    As noted earlier, in NRDC v. EPA, the court held that section 
112(f)(2) ``incorporates the EPA's interpretation of the Clean Air Act 
from the Benzene Standard.'' The court further held that Congress' 
incorporation of the Benzene standard applies equally to carcinogens 
and non-carcinogens. 529 F.3d at 1081-82. Accordingly, we also consider 
non-cancer risk metrics in our determination of risk acceptability and 
ample margin of safety.
b. Step 2--Determination of Ample Margin of Safety
    CAA section 112(f)(2) requires the EPA to determine, for source 
categories subject to MACT standards, whether those standards provide 
an ample margin of safety to protect public health. As explained in the 
Benzene NESHAP, ``the second step of the inquiry, determining an `ample 
margin of safety,' again includes consideration of all of the health 
factors, and whether to reduce the risks even further. . . .

[[Page 36885]]

Beyond that information, additional factors relating to the appropriate 
level of control will also be considered, including costs and economic 
impacts of controls, technological feasibility, uncertainties and any 
other relevant factors. Considering all of these factors, the agency 
will establish the standard at a level that provides an ample margin of 
safety to protect the public health, as required by section 112.'' 54 
FR at 38046, September 14, 1989.
    According to CAA section 112(f)(2)(A), if the MACT standards for 
HAP ``classified as a known, probable, or possible human carcinogen do 
not reduce lifetime excess cancer risks to the individual most exposed 
to emissions from a source in the category or subcategory to less than 
one in one million,'' the EPA must promulgate residual risk standards 
for the source category (or subcategory), as necessary to provide an 
ample margin of safety to protect public health. In doing so, the EPA 
may adopt standards equal to existing MACT standards if the EPA 
determines that the existing standards (i.e., the MACT standards) are 
sufficiently protective. NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 
2008) (``If EPA determines that the existing technology-based standards 
provide an `ample margin of safety,' then the Agency is free to readopt 
those standards during the residual risk rulemaking.'') The EPA must 
also adopt more stringent standards, if necessary, to prevent an 
adverse environmental effect,\1\ but must consider cost, energy, safety 
and other relevant factors in doing so.
---------------------------------------------------------------------------

    \1\ ``Adverse environmental effect'' is defined as any 
significant and widespread adverse effect, which may be reasonably 
anticipated to wildlife, aquatic life or natural resources, 
including adverse impacts on populations of endangered or threatened 
species or significant degradation of environmental qualities over 
broad areas. CAA section 112(a)(7).
---------------------------------------------------------------------------

    The CAA does not specifically define the terms ``individual most 
exposed,'' ``acceptable level'' and ``ample margin of safety.'' In the 
Benzene NESHAP, 54 FR at 38044-38045, September 14, 1989, we stated as 
an overall objective:

In protecting public health with an ample margin of safety under 
section 112, EPA strives to provide maximum feasible protection 
against risks to health from hazardous air pollutants by (1) 
protecting the greatest number of persons possible to an individual 
lifetime risk level no higher than approximately 1-in-1 million and 
(2) limiting to no higher than approximately 1-in-10 thousand [i.e., 
100-in-1 million] the estimated risk that a person living near a 
plant would have if he or she were exposed to the maximum pollutant 
concentrations for 70 years.

The agency further stated that ``[t]he EPA also considers incidence 
(the number of persons estimated to suffer cancer or other serious 
health effects as a result of exposure to a pollutant) to be an 
important measure of the health risk to the exposed population. 
Incidence measures the extent of health risks to the exposed population 
as a whole, by providing an estimate of the occurrence of cancer or 
other serious health effects in the exposed population.'' Id. at 38045.
    In the ample margin of safety decision process, the agency again 
considers all of the health risks and other health information 
considered in the first step, including the incremental risk reduction 
associated with standards more stringent than the MACT standard or a 
more stringent standard that EPA has determined is necessary to ensure 
risk is acceptable. In the ample margin of safety analysis, the agency 
considers additional factors, including costs and economic impacts of 
controls, technological feasibility, uncertainties and any other 
relevant factors. Considering all of these factors, the agency will 
establish the standard ``at a level that provides an ample margin of 
safety to protect the public health,'' as required by CAA section 
112(f). 54 FR 38046, September 14, 1989.
2. NSPS
    Section 111 of the CAA establishes mechanisms for controlling 
emissions of air pollutants from stationary sources. Section 111(b) of 
the CAA provides authority for the EPA to promulgate new source 
performance standards (NSPS) which apply only to newly constructed, 
reconstructed and modified sources. Once the EPA has elected to set 
NSPS for new and modified sources in a given source category, CAA 
section 111(d) calls for regulation of existing sources, with certain 
exceptions explained below.
    Specifically, section 111(b) of the CAA requires the EPA to 
establish emission standards for any category of new and modified 
stationary sources that the Administrator, in his or her judgment, 
finds ``causes, or contributes significantly to, air pollution which 
may reasonably be anticipated to endanger public health or welfare.'' 
The EPA has previously made endangerment findings under this section of 
the CAA for more than 60 stationary source categories and subcategories 
that are now subject to NSPS.
    Section 111 of the CAA gives the EPA significant discretion to 
identify the affected facilities within a source category that should 
be regulated. To define the affected facilities, the EPA can use size 
thresholds for regulation and create subcategories based on source 
type, class or size. Emission limits also may be established either for 
equipment within a facility or for an entire facility. For listed 
source categories, the EPA must establish ``standards of performance'' 
that apply to sources that are constructed, modified or reconstructed 
after the EPA proposes the NSPS for the relevant source category.\2\
---------------------------------------------------------------------------

    \2\ Specific statutory and regulatory provisions define what 
constitutes a modification or reconstruction of a facility. 40 CFR 
60.14 provides that an existing facility is modified and, therefore, 
subject to an NSPS, if it undergoes ``any physical change in the 
method of operation . . . which increases the amount of any air 
pollutant emitted by such source or which results in the emission of 
any air pollutant not previously emitted.'' 40 CFR 60.15, in turn, 
provides that a facility is reconstructed if components are replaced 
at an existing facility to such an extent that the capital cost of 
the new equipment/components exceed 50 percent of what is believed 
to be the cost of a completely new facility.
---------------------------------------------------------------------------

    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.

[[Page 36886]]

B. What are the source categories and how do the NESHAP and NSPS 
regulate emissions?

    The source categories include petroleum refineries engaged in 
converting crude oil into refined products, including liquefied 
petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel 
oils, lubricating oils and feedstocks for the petrochemical industry. 
Petroleum refinery activities start with the receipt of crude oil for 
storage at the refinery, include all petroleum handling and refining 
operations, and terminate with loading of refined products into 
pipelines, tank or rail cars, tank trucks, or ships or barges that take 
products from the refinery to distribution centers. Petroleum refinery-
specific process units include fluid catalytic cracking units (FCCU) 
and catalytic reforming units (CRU), as well as units and processes 
found at many types of manufacturing facilities (including petroleum 
refineries), such as storage vessels and wastewater treatment plants. 
HAP emitted by this industry include organics (e.g., acetaldehyde, 
benzene, formaldehyde, hexane, phenol, naphthalene, 2-
methylnaphthalene, dioxins, furans, ethyl benzene, toluene and xylene); 
reduced sulfur compounds (i.e., carbonyl sulfide (COS), carbon 
disulfide (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). Criteria pollutants and other non-
hazardous air pollutants that are also emitted include nitrogen oxides 
(NOX), particulate matter (PM), sulfur dioxide 
(SO2), volatile organic compounds (VOC), carbon monoxide 
(CO), greenhouse gases (GHG), and total reduced sulfur.
    The federal emission standards that are the primary subject of this 
proposed rulemaking are:
     National Emission Standards for Hazardous Air Pollutants 
from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT 
1);
     National Emission Standards for Hazardous Air Pollutants 
for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming 
Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) 
(Refinery MACT 2);
     Standards of Performance for Petroleum Refineries (40 CFR 
part 60, subpart J) (Refinery NSPS J); and
     Standards of Performance for Petroleum Refineries for 
which Construction, Reconstruction, or Modification Commenced After May 
14, 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja).
1. Refinery MACT Standards
    The EPA promulgated MACT standards pursuant to CAA section 
112(d)(2) and (3) for refineries located at major sources in three 
separate rules. On August 18, 1995, the first Petroleum Refinery MACT 
standard was promulgated in 40 CFR part 63, subpart CC (60 FR 43620). 
This rule is known as ``Refinery MACT 1'' and covers the ``Sources Not 
Distinctly Listed,'' meaning it includes all emission sources from 
petroleum refinery process units, except those listed separately under 
the section 112(c) source category list expected to be regulated by 
other MACT standards. Some of the emission sources regulated in 
Refinery MACT 1 include miscellaneous process vents, storage vessels, 
wastewater, equipment leaks, gasoline loading racks, marine tank vessel 
loading and heat exchange systems.
    Certain process vents that were listed as a separate source 
category under CAA section 112(c) and that were not addressed as part 
of the Refinery MACT 1 were subsequently regulated under a second MACT 
standard specific to these petroleum refinery process vents, codified 
as 40 CFR part 63, subpart UUU, which we promulgated on April 11, 2002 
(67 FR 17762). This standard, which is referred to as ``Refinery MACT 
2,'' covers process vents on catalytic cracking units (CCU) (including 
FCCU), CRU and sulfur recovery units (SRU).
    Finally, on October 28, 2009, we promulgated MACT standards for 
heat exchange systems, which the EPA had not addressed in the original 
1995 Refinery MACT 1 rule (74 FR 55686). In this same 2009 action, we 
updated cross-references to the General Provisions in 40 CFR part 63. 
On June 20, 2013 (78 FR 37133), we promulgated minor revisions to the 
heat exchange provisions of Refinery MACT 1.
    On September 27, 2012, Air Alliance Houston, California Communities 
Against Toxics and other environmental and public health groups filed a 
lawsuit alleging that the EPA missed statutory deadlines to review and 
revise Refinery MACT 1 and 2.
    The EPA has reached an agreement to settle that litigation. In a 
consent decree filed January 13, 2014 in the U.S. District Court for 
the District of Columbia, the EPA commits to perform the risk and 
technology review for Refinery MACT 1 and 2 and by May 15, 2014, either 
propose any regulations or propose that additional regulations are not 
necessary. Under the Consent Decree, the EPA commits to take final 
action by April 17, 2015, establishing regulations pursuant to the risk 
and technology review or to issue a final determination that revision 
to the existing rules is not necessary.
2. Refinery NSPS
    Refinery NSPS subparts J and Ja regulate criteria pollutant 
emissions, including PM, SO2, NOX and CO from 
FCCU catalyst regenerators, fuel gas combustion devices (FGCD) and 
sulfur recovery plants. Refinery NSPS Ja also regulates criteria 
pollutant emissions from fluid coking units and delayed coking units 
(DCU).
    The NSPS for petroleum refineries (40 CFR part 60, subpart J; 
Refinery NSPS J) were promulgated in 1974, amended in 1976 and amended 
again in 2008, following a review of the standards. As part of the 
review that led to the 2008 amendments to Refinery NSPS J, the EPA 
developed separate standards of performance for new process units (40 
CFR part 60, subpart Ja; Refinery NSPS Ja). However, the EPA received 
petitions for reconsideration and granted reconsideration on issues 
related to those standards. On December 22, 2008, the EPA addressed 
petition issues related to process heaters and flares by proposing 
amendments to certain provisions. Final amendments to Refinery NSPS Ja 
were promulgated on September 12, 2012 (77 FR 56422).
    In this action, we are proposing amendments to address technical 
corrections and clarifications raised in a 2008 industry petition for 
reconsideration applicable to Refinery NSPS Ja. We are addressing these 
issues in this proposal because they also affect sources included 
within these proposed amendments to Refinery MACT 1 and 2.

C. What data collection activities were conducted to support this 
action?

    In 2010, the EPA began a significant effort to gather additional 
information and perform analyses to determine how to address statutory 
obligations for the Refinery MACT standards and the NSPS. This effort 
focused on gathering comprehensive information through an industry-wide 
Information Collection Request (ICR) on petroleum refineries, conducted 
under CAA section 114 authority. The information not claimed as CBI by 
respondents is available in the docket (see Docket Item Nos. EPA-HQ-
OAR-2010-0682-0064 through 0069). The EPA issued a single ICR (OMB 
Control Number 2060-0657) for sources covered under Refinery MACT 1 and 
2 and Refinery NSPS J and Ja.
    On April 1, 2011, the ICR was sent out to the petroleum refining 
industry. In a comprehensive manner, the ICR

[[Page 36887]]

collected information on processing characteristics, crude slate 
characteristics, emissions inventories and source testing to fill known 
data gaps. The ICR had four components: (1) A questionnaire on 
processes and controls to be completed by all petroleum refineries 
(Component 1); (2) an emissions inventory to be developed by all 
petroleum refineries using the emissions estimation protocol developed 
for this effort (Component 2); (3) distillation feed sampling and 
analysis to be conducted by all petroleum refineries (Component 3); and 
(4) emissions source testing to be completed in accordance with an EPA-
approved protocol for specific sources at specific petroleum refineries 
(Component 4). We received responses from 149 refineries. We have since 
learned that seven refineries are synthetic minor sources, bringing the 
total number of major source refineries operating in 2010 to 142.
    Information collected through the ICR was used to establish the 
baseline emissions and control levels for purposes of the regulatory 
reviews, to identify the most effective control measures, and to 
estimate the environmental and cost impacts associated with the 
regulatory options considered. As part of the information collection 
process, we provided a protocol for survey respondents to follow in 
developing the emissions inventories under Component 2 (Emission 
Estimation Protocol for Petroleum Refineries, available as Docket Item 
Number EPA-HQ-OAR-2010-0682-0060). The protocol contained detailed 
guidance for estimating emissions from typical refinery emission 
sources and was intended to provide a measure of consistency and 
replicability for emission estimates across the refining industry. 
Prior to issuance of the ICR, the protocol was publicly disseminated 
and underwent several revisions after public comments were received. 
Draft and final versions of the emission estimation protocol are 
provided in the docket to this rule (Docket ID Number EPA-HQ-OAR-2010-
0682). The protocol provided a hierarchy of methodologies available for 
estimating emissions that corresponded to the level of information 
available at refineries. For each emission source, the various emission 
measurement or estimation methods specific to that source were ranked 
in order of preference, with ``Methodology Rank 1'' being the preferred 
method, followed by ``Methodology Rank 2,'' and so on. Refinery owners 
and operators were requested through the ICR to use the highest ranked 
method (with Methodology Rank 1 being the highest) for which data were 
available. Methodology Ranks 1 or 2 generally relied on continuous 
emission measurements. When continuous measurement data were not 
available, engineering calculations or site-specific emission factors 
(Methodology Ranks 3 and 4) were specified in the protocol by EPA; 
these methods generally needed periodic, site-specific measurements. 
When site-specific measurement or test data were not available, default 
emission factors (Methodology Rank 5) were provided in the protocol by 
EPA.
    As we reviewed the ICR-submitted emissions inventories, we 
determined that, in some cases, refiners either did not follow the 
protocol methodology or made an error in their calculations. This was 
evident because pollutants that we expected to be reported from certain 
emission sources were either not reported or were reported in amounts 
that were not consistent with the protocol methodology. In these cases, 
we contacted the refineries and, based on their replies, made 
corrections to emission estimates. The original Component 2 submittals, 
documentation of the changes as a result of our review, and the final 
emissions inventories we relied on for our analyses are available in 
the technical memorandum entitled Emissions Data Quality Memorandum and 
Development of the Risk Model Input File, in Docket ID Number EPA-HQ-
OAR-2010-0682.
    Collected emissions test data (test reports, continuous emissions 
monitoring system (CEMS) data and other continuous monitoring system 
data) were used to assess the effectiveness of existing control 
measures, to fill data gaps and to examine variability in emissions. 
The ICR requested source testing for a total of 90 specific process 
units at 75 particular refineries across the industry. We received a 
total of 72 source tests; in some cases, refinery sources claimed that 
units we requested to be tested were no longer in operation, did not 
exist or did not have an emission point to the atmosphere (this was the 
case for hydrocrackers). In other cases, refiners claimed they were not 
able to conduct testing because of process characteristics. For 
example, source testing of DCU proved to be difficult because the 
moisture content of the steam vent required a significant amount of gas 
to be sampled to account for dilution. Venting periods of less than 20 
minutes did not accommodate this strategy and, therefore, if refiners 
vented for less than 20 minutes, they did not sample their steam vent. 
As a result, only two DCU tests out of eight requested were received as 
part of Component 4. Results of the stack test data are compiled and 
available in Docket ID Number EPA-HQ-OAR-2010-0682.

D. What other relevant background information and data are available?

    Over the past several years, the EPA has worked with the Texas 
Commission on Environmental Quality and industry representatives to 
better characterize proper flare performance. Flares are used to 
control emissions from various vents at refineries as well as at other 
types of facilities not in the petroleum refinery source categories, 
such as chemical and petrochemical manufacturing facilities. In April 
2012, we released a technical report for peer review that discussed our 
observations regarding the operation and performance of flares. The 
report was a result of the analysis of several flare efficiency studies 
and flare performance test reports. To provide an objective evaluation 
of our analysis, we asked a third party to facilitate an ad hoc peer 
review process of the technical report. This third party established a 
balanced peer review panel of reviewers from outside the EPA. These 
reviewers consisted of individuals that could be considered ``technical 
combustion experts'' within four interest groups: the refinery 
industry, industrial flare consultants, academia, and environmental 
stakeholders.
    The EPA developed a charge statement with ten charge questions for 
the review panel. The peer reviewers were asked to perform a thorough 
review of the technical report and answer the charge questions to the 
extent possible, based on their technical expertise. The details of the 
peer review process and the charge questions, as well as comments 
received from the peer review process, were posted online to the 
Consolidated Petroleum Refinery Rulemaking Repository at the EPA's 
Technology Transfer Network Air Toxics Web site (see http://www.epa.gov/ttn/atw/petref.html). These items are also provided in a 
memorandum entitled Peer Review of ``Parameters for Properly Designed 
and Operated Flares'' (see Docket ID Number EPA-HQ-OAR-2010-0682). 
After considering the comments received from the peer review process, 
we developed a final technical memorandum (see technical memorandum, 
Flare Performance Data: Summary of Peer Review Comments and Additional 
Data Analysis for Steam-

[[Page 36888]]

Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).

III. Analytical Procedures

    In this section, we describe the analyses performed to support the 
proposed decisions for the RTR and other issues addressed in this 
proposal.

A. How did we estimate post-MACT risks posed by the source categories?

    The EPA conducted a risk assessment that provided estimates of the 
MIR posed by the HAP emissions from each source in the source 
categories, the hazard index (HI) for chronic exposures to HAP with the 
potential to cause non-cancer health effects, and the hazard quotient 
(HQ) for acute exposures to HAP with the potential to cause non-cancer 
health effects. The assessment also provided estimates of the 
distribution of cancer risks within the exposed populations, cancer 
incidence and an evaluation of the potential for adverse environmental 
effects for each source category. The eight sections that follow this 
paragraph describe how we estimated emissions and conducted the risk 
assessment. The docket for this rulemaking (Docket ID Number EPA-HQ-
OAR-2010-0682) contains the following document which provides more 
information on the risk assessment inputs and models: Draft Residual 
Risk Assessment for the Petroleum Refining Source Sector. The methods 
used to assess risks (as described in the eight primary steps below) 
are consistent with those peer-reviewed by a panel of the EPA's Science 
Advisory Board (SAB) in 2009 and described in their peer review report 
issued in 2010 \3\; they are also consistent with the key 
recommendations contained in that report.
---------------------------------------------------------------------------

    \3\ U.S. EPA SAB. Risk and Technology Review (RTR) Risk 
Assessment Methodologies: For Review by the EPA's Science Advisory 
board with Case Studies--MACT I Petroleum Refining Sources and 
Portland Cement Manufacturing, May 2010.
---------------------------------------------------------------------------

1. How did we estimate actual emissions and identify the emissions 
release characteristics?
    We compiled data sets using the ICR emission inventory submittals 
as a starting point. The data sets were refined following an extensive 
quality assurance check of source locations, emission release 
characteristics, annual emission estimates and FCCU release parameters. 
They were then updated based on additional information received from 
refineries. In addition, we supplemented these data with results from 
stack testing, which were required later than the inventories under the 
ICR. As the stack test information was received, we compared these data 
against the refined emission inventories and the default emission 
factors provided in the Emission Estimation Protocol for Petroleum 
Refineries (Docket Item Number EPA-HQ-OAR-2010-0682-0060).
    Based on the stack test data for FCCU, we calculated that, on 
average, HCN emissions were a factor of 10 greater than the average 
emission factor of 770 pounds per barrel FCCU feed provided in the 
protocol. Therefore, we revised the HCN emissions for FCCU in the 
emissions inventory used for the risk modeling runs (the results are 
presented in this preamble). For the 10 facilities that performed a 
stack test to determine HCN emissions from their FCCU, we used the 
actual emissions measured during the stack tests in place of the 
inventories originally supplied in response to the ICR. For those 
facilities that did not perform a stack test, but reported HCN 
emissions in the emissions inventory portion of the ICR, we increased 
the emissions of HCN by a factor of 10, assuming the original emission 
inventory estimates for FCCU HCN emissions were based on the default 
emission factor in the protocol. The emissions inventory from the ICR 
and documentation of the changes made to the file as a result of our 
review are contained in the technical memorandum entitled Emissions 
Data Quality Memorandum and Development of the Risk Model Input File, 
in Docket ID Number EPA-HQ-OAR-2010-0682 and available on our Web 
site.\4\
---------------------------------------------------------------------------

    \4\ The emissions inventory and the revised emissions modeling 
file can also be found at http://www.epa.gov/ttn/atw/petref.htm.
---------------------------------------------------------------------------

2. How did we estimate MACT-allowable emissions?
    The available emissions data in the RTR dataset (i.e., the 
emissions inventory) include estimates of the mass of HAP emitted 
during the specified annual time period. In some cases, these 
``actual'' emission levels are lower than the emission levels required 
to comply with the MACT standards. The emissions level allowed to be 
emitted by the MACT standards is referred to as the ``MACT-allowable'' 
emissions level. We discussed the use of both MACT-allowable and actual 
emissions in the final Coke Oven Batteries residual risk rule (70 FR 
19998-19999, April 15, 2005) and in the proposed and final Hazardous 
Organic NESHAP residual risk rules (71 FR 34428, June 14, 2006, and 71 
FR 76609, December 21, 2006, respectively). In those previous actions, 
we noted that assessing the risks at the MACT-allowable level is 
inherently reasonable since these risks reflect the maximum level 
facilities could emit and still comply with national emission 
standards. We also explained that it is reasonable to consider actual 
emissions, where such data are available, in both steps of the risk 
analysis, in accordance with the Benzene NESHAP approach. (54 FR 38044, 
September 14, 1989.)
    We requested allowable emissions data in the ICR. However, unlike 
for actual emissions, where the ICR specified the use of the Emission 
Estimation Protocol for Petroleum Refineries (available as Docket Item 
Number EPA-HQ-OAR-2010-0682-0060), we did not specify a method to 
calculate allowable emissions. As a result, in our review of these data 
and when comparing estimates between facilities, we found that 
facilities did not estimate allowable emissions consistently across the 
industry. In addition, facilities failed to report allowable emissions 
for many emission points, likely because they did not know how to 
translate a work practice or performance standard into an allowable 
emission estimate and they did not know how to speciate individual HAP 
where the MACT standard is based on a surrogate, such as PM or VOC. 
Therefore, the ICR-submitted information for allowable emissions did 
not include emission estimates for all HAP and sources of interest. 
Consequently, we used our Refinery Emissions Model (REM Model) to 
estimate allowable emissions. The REM model relies on model plants that 
vary based on throughput capacity. Each model plant contains process-
specific default emission factors, adjusted for compliance with the 
Refinery MACT 1 and 2 emission standards.
    The risks associated with the allowable emissions were evaluated 
using the same dispersion modeling practices, exposure assumptions and 
health benchmarks as the actual risks. However, because each refinery's 
allowable emissions were calculated by using model plants, selected 
based on each refinery's actual capacities and throughputs, emission 
estimates for point sources are not specific to a particular latitude/
longitude location. Therefore, for risk modeling purposes, all 
allowable emissions were assumed to be released from the centroid of 
the facility. (Note: for fugitive (area) sources, the surface area was 
selected by the size of the model plant and the release point was 
shifted to the southwest so the center of the fugitive area was near 
the centroid of the facility). The emission and risk estimates for the 
actual emission inventory were compared to the

[[Page 36889]]

allowable emissions and risk estimates. For most work practices, where 
allowable emission estimates are difficult to predict, the actual risk 
estimates were higher than those projected using the REM Model 
estimates. Consequently, we post-processed the two risk files, taking 
the higher risk estimates from the actual emissions inventory for 
sources subject to work practice standards, such as process equipment 
leaks, and sources that were not covered in the REM Model, combining 
them with the risk estimates from sources with more readily determined 
allowable emissions. The combined post-processed allowable risk 
estimates provide a high estimate of the risk allowed under Refinery 
MACT 1 and 2. The REM Model assumptions and emission estimates, along 
with the post-processing of risk estimate results that produced the 
final risk estimates for the allowable emissions, are provided in the 
docket (see Refinery Emissions and Risk Estimates for Modeled 
``Allowable'' Emissions in Docket ID Number EPA-HQ-OAR-2010-0682).
3. How did we conduct dispersion modeling, determine inhalation 
exposures and estimate individual and population inhalation risks?
    Both long-term and short-term inhalation exposure concentrations 
and health risks from the source categories addressed in this proposal 
were estimated using the Human Exposure Model (Community and Sector 
HEM-3 version 1.1.0). The HEM-3 performs three primary risk assessment 
activities: (1) Conducting dispersion modeling to estimate the 
concentrations of HAP in ambient air, (2) estimating long-term and 
short-term inhalation exposures to individuals residing within 50 
kilometers (km) of the modeled sources \5\, and (3) estimating 
individual and population-level inhalation risks using the exposure 
estimates and quantitative dose-response information.
---------------------------------------------------------------------------

    \5\ This metric comes from the Benzene NESHAP. See 54 FR 38046, 
September 14, 1989.
---------------------------------------------------------------------------

    The air dispersion model used by the HEM-3 model (AERMOD) is one of 
the EPA's preferred models for assessing pollutant concentrations from 
industrial facilities.\6\ To perform the dispersion modeling and to 
develop the preliminary risk estimates, HEM-3 draws on three data 
libraries. The first is a library of meteorological data, which is used 
for dispersion calculations. This library includes 1 year (2011) of 
hourly surface and upper air observations for 824 meteorological 
stations, selected to provide coverage of the United States and Puerto 
Rico. A second library of United States Census Bureau census block \7\ 
internal point locations and populations provides the basis of human 
exposure calculations (U.S. Census, 2010). In addition, for each census 
block, the census library includes the elevation and controlling hill 
height, which are also used in dispersion calculations. A third library 
of pollutant unit risk factors and other health benchmarks is used to 
estimate health risks. These risk factors and health benchmarks are the 
latest values recommended by the EPA for HAP and other toxic air 
pollutants. These values are available at: http://www.epa.gov/ttn/atw/toxsource/summary.html and are discussed in more detail later in this 
section.
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    \6\ U.S. EPA. Revision to the Guideline on Air Quality Models: 
Adoption of a Preferred General Purpose (Flat and Complex Terrain) 
Dispersion Model and Other Revisions (70 FR 68218, November 9, 
2005).
    \7\ A census block is the smallest geographic area for which 
census statistics are tabulated.
---------------------------------------------------------------------------

    In developing the risk assessment for chronic exposures, we used 
the estimated annual average ambient air concentrations of each HAP 
emitted by each source for which we have emissions data in the source 
category. The air concentrations at each nearby census block centroid 
were used as a surrogate for the chronic inhalation exposure 
concentration for all the people who reside in that census block. We 
calculated the MIR for each facility as the cancer risk associated with 
a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks 
per year for a 70-year period) exposure to the maximum concentration at 
the centroid of inhabited census blocks. Individual cancer risks were 
calculated by multiplying the estimated lifetime exposure to the 
ambient concentration of each of the HAP (in micrograms per cubic meter 
([micro]g/m\3\)) by its unit risk estimate (URE). The URE is an upper 
bound estimate of an individual's probability of contracting cancer 
over a lifetime of exposure to a concentration of 1 microgram of the 
pollutant per cubic meter of air. For residual risk assessments, we 
generally use URE values from the EPA's Integrated Risk Information 
System (IRIS). For carcinogenic pollutants without EPA IRIS values, we 
look to other reputable sources of cancer dose-response values, often 
using California EPA (CalEPA) URE values, where available. In cases 
where new, scientifically credible dose-response values have been 
developed in a manner consistent with the EPA guidelines and have 
undergone a peer review process similar to that used by the EPA, we may 
use such dose-response values in place of, or in addition to, other 
values, if appropriate.
    We note here that several carcinogens emitted by facilities in 
these source categories have a mutagenic mode of action. For these 
compounds, we applied the age-dependent adjustment factors (ADAF) 
described in the EPA's Supplemental Guidance for Assessing 
Susceptibility from Early-Life Exposure to Carcinogens.\8\ This 
adjustment has the effect of increasing the estimated lifetime risks 
for these pollutants by a factor of 1.6. Although only a small fraction 
of the total polycyclic organic matter (POM) emissions were reported as 
individual compounds, the EPA expresses carcinogenic potency of POM 
relative to the carcinogenic potency of benzo[a]pyrene, based on 
evidence that carcinogenic POM have the same mutagenic mode of action 
as does benzo[a]pyrene. The EPA's Science Policy Council recommends 
applying the ADAF to all carcinogenic polycyclic aromatic hydrocarbons 
(PAH) for which risk estimates are based on potency relative to 
benzo[a]pyrene. Accordingly, we have applied the ADAF to the 
benzo[a]pyrene-equivalent mass portion of all POM mixtures.
---------------------------------------------------------------------------

    \8\ Supplemental Guidance for Assessing Susceptibility from 
Early-Life Exposure to Carcinogens. Risk Assessment Forum, U.S. 
Environmental Protection Agency, Washington, DC. EPA/630/R-03/003F. 
March 2005. Available at http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf.
---------------------------------------------------------------------------

    The EPA estimated incremental individual lifetime cancer risks 
associated with emissions from the facilities in the source categories 
as the sum of the risks for each of the carcinogenic HAP (including 
those classified as carcinogenic to humans, likely to be carcinogenic 
to humans, and suggestive evidence of carcinogenic potential \9\) 
emitted by the modeled sources. Cancer incidence and the distribution 
of individual cancer risks for the population within 50 km of the 
sources were also estimated for the source categories as part of this 
assessment by summing individual risks. A distance of 50 km is 
consistent with both the analysis supporting the

[[Page 36890]]

1989 Benzene NESHAP (54 FR 38044, September 14, 1989) and the 
limitations of Gaussian dispersion models, including AERMOD.
---------------------------------------------------------------------------

    \9\ These classifications also coincide with the terms ``known 
carcinogen, probable carcinogen, and possible carcinogen,'' 
respectively, which are the terms advocated in the EPA's previous 
Guidelines for Carcinogen Risk Assessment, published in 1986 (51 FR 
33992, September 24, 1986). Summing the risks of these individual 
compounds to obtain the cumulative cancer risks is an approach that 
was recommended by the EPA's SAB in their 2002 peer review of EPA's 
National Air Toxics Assessment (NATA) entitled, NATA--Evaluating the 
National-scale Air Toxics Assessment 1996 Data--an SAB Advisory, 
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
214C6E915BB04E14852570CA007A682C/$File/ecadv02001.pdf.
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    To assess the risk of non-cancer health effects from chronic 
exposures, we summed the HQ for each of the HAP that affects a common 
target organ system to obtain the HI for that target organ system (or 
target organ-specific HI, TOSHI). The HQ is the estimated exposure 
divided by the chronic reference level, which is a value selected from 
one of several sources. First, the chronic reference level can be the 
EPA Reference Concentration (RfC) (http://www.epa.gov/riskassessment/glossary.htm), defined as ``an estimate (with uncertainty spanning 
perhaps an order of magnitude) of a continuous inhalation exposure to 
the human population (including sensitive subgroups) that is likely to 
be without an appreciable risk of deleterious effects during a 
lifetime.'' Alternatively, in cases where an RfC from the EPA's IRIS 
database is not available or where the EPA determines that using a 
value other than the RfC is appropriate, the chronic reference level 
can be a value from the following prioritized sources: (1) The Agency 
for Toxic Substances and Disease Registry Minimum Risk Level (http://www.atsdr.cdc.gov/mrls/index.asp), which is defined as ``an estimate of 
daily human exposure to a hazardous substance that is likely to be 
without an appreciable risk of adverse non-cancer health effects (other 
than cancer) over a specified duration of exposure''; (2) the CalEPA 
Chronic Reference Exposure Level (REL) (http://www.oehha.ca.gov/air/hot_spots/pdf/HRAguidefinal.pdf), which is defined as ``the 
concentration level (that is expressed in units of [micro]g/m\3\ for 
inhalation exposure and in a dose expressed in units of milligram per 
kilogram per day (mg/kg-day) for oral exposures), at or below which no 
adverse health effects are anticipated for a specified exposure 
duration''; or (3), as noted above, a scientifically credible dose-
response value that has been developed in a manner consistent with the 
EPA guidelines and has undergone a peer review process similar to that 
used by the EPA, in place of or in concert with other values.
    The EPA also evaluated screening estimates of acute exposures and 
risks for each of the HAP at the point of highest off-site exposure for 
each facility (i.e., not just the census block centroids), assuming 
that a person is located at this spot at a time when both the peak 
(hourly) emissions rate and worst-case dispersion conditions occur. The 
acute HQ is the estimated acute exposure divided by the acute dose-
response value. In each case, the EPA calculated acute HQ values using 
best available, short-term dose-response values. These acute dose-
response values, which are described below, include the acute REL, 
acute exposure guideline levels (AEGL) and emergency response planning 
guidelines (ERPG) for 1-hour exposure durations. As discussed below, we 
used realistic assumptions based on knowledge of the emission point 
release characteristics for emission rates, and conservative 
assumptions for meteorology and exposure location for our acute 
analysis.
    As described in the CalEPA's Air Toxics Hot Spots Program Risk 
Assessment Guidelines, Part I, The Determination of Acute Reference 
Exposure Levels for Airborne Toxicants, an acute REL value (http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as ``the 
concentration level at or below which no adverse health effects are 
anticipated for a specified exposure duration.'' Id. at page 2. Acute 
REL values are based on the most sensitive, relevant, adverse health 
effect reported in the peer-reviewed medical and toxicological 
literature. Acute REL values are designed to protect the most sensitive 
individuals in the population through the inclusion of margins of 
safety. Because margins of safety are incorporated to address data gaps 
and uncertainties, exceeding the REL value does not automatically 
indicate an adverse health impact.
    AEGL values were derived in response to recommendations from the 
National Research Council (NRC). As described in Standing Operating 
Procedures (SOP) of the National Advisory Committee on Acute Exposure 
Guideline Levels for Hazardous Substances (http://www.epa.gov/oppt/aegl/pubs/sop.pdf),\10\ ``the NRC's previous name for acute exposure 
levels--community emergency exposure levels--was replaced by the term 
AEGL to reflect the broad application of these values to planning, 
response, and prevention in the community, the workplace, 
transportation, the military, and the remediation of Superfund sites.'' 
Id. at 2.
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    \10\ National Academy of Sciences (NAS), 2001. Standing 
Operating Procedures for Developing Acute Exposure Levels for 
Hazardous Chemicals, page 2.
---------------------------------------------------------------------------

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

[[Page 36891]]

chemicals.'' \11\ Id. at 1. The ERPG-1 value is defined as ``the 
maximum airborne concentration below which it is believed that nearly 
all individuals could be exposed for up to 1 hour without experiencing 
other than mild transient adverse health effects or without perceiving 
a clearly defined, objectionable odor.'' Id. at 2. Similarly, the ERPG-
2 value is defined as ``the maximum airborne concentration below which 
it is believed that nearly all individuals could be exposed for up to 
one hour without experiencing or developing irreversible or other 
serious health effects or symptoms which could impair an individual's 
ability to take protective action.'' Id. at 1.
---------------------------------------------------------------------------

    \11\ ERP Committee Procedures and Responsibilities. November 1, 
2006. American Industrial Hygiene Association. Available at https://www.aiha.org/get-involved/AIHAGuidelineFoundation/EmergencyResponsePlanningGuidelines/Documents/ERP-SOPs2006.pdf.
---------------------------------------------------------------------------

    As can be seen from the definitions above, the AEGL and ERPG values 
include the similarly-defined severity levels 1 and 2. For many 
chemicals, a severity level 1 value AEGL or ERPG has not been developed 
because the types of effects for these chemicals are not consistent 
with the AEGL-1/ERPG-1 definitions; in these instances, we compare 
higher severity level AEGL-2 or ERPG-2 values to our modeled exposure 
levels to screen for potential acute concerns. When AEGL-1/ERPG-1 
values are available, they are used in our acute risk assessments.
    Acute REL values for 1-hour exposure durations are typically lower 
than their corresponding AEGL-1 and ERPG-1 values. Even though their 
definitions are slightly different, AEGL-1 values are often the same as 
the corresponding ERPG-1 values, and AEGL-2 values are often equal to 
ERPG-2 values. Maximum HQ values from our acute screening risk 
assessments typically result when basing them on the acute REL value 
for a particular pollutant. In cases where our maximum acute HQ value 
exceeds 1, we also report the HQ value based on the next highest acute 
dose-response value (usually the AEGL-1 and/or the ERPG-1 value).
    To develop screening estimates of acute exposures in the absence of 
hourly emissions data, generally we first develop estimates of maximum 
hourly emissions rates by multiplying the average actual annual hourly 
emissions rates by a default factor to cover routinely variable 
emissions. However, for the petroleum refineries category, we 
incorporated additional information and process knowledge in order to 
better characterize acute emissions, as described below. The ICR 
included input fields for both annual emissions and maximum hourly 
emissions. The maximum hourly emission values were often left blank or 
appeared to be reported in units other than those required for this 
emissions field (pounds per hour). Consequently, instead of relying on 
the inadequate data provided in response to the ICR, we elected to 
estimate the hourly emissions based on the reported annual emissions 
(converted to average hourly emissions in terms of pounds per hour) and 
then to apply an escalation factor, considering the different types of 
emission sources and their inherent variability, in order to calculate 
maximum hourly rates. For sources with relatively continuous operations 
and steady state emissions, such as FCCU, sulfur recovery plants, and 
continuous catalytic reformers, a factor of 2 was used to estimate the 
maximum hourly rates from the average hourly emission rates. For 
sources with relatively continuous emissions, but with more 
variability, like storage tanks and wastewater systems, a factor of 4 
was used to estimate the maximum hourly rates from the average hourly 
emission rates. For non-continuous emission sources with more 
variability, such as DCU, cyclic CRU, semi-regenerative CRU, and 
transfer and loading operations, the number of hours in the venting 
cycle and the variability of emissions expected in that cycle were used 
to determine the escalation factor for each emissions source. The 
escalation factors for these processes range from 10 to 60. For more 
detail regarding escalation factors and the rationale for their 
selection, see Derivation of Hourly Emission Rates for Petroleum 
Refinery Emission Sources Used in the Acute Risk Analysis, available in 
the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).
    As part of our acute risk assessment process, for cases where acute 
HQ values from the screening step were less than or equal to 1 (even 
under the conservative assumptions of the screening analysis), acute 
impacts were deemed negligible and no further analysis was performed. 
In cases where an acute HQ from the screening step was greater than 1, 
additional site-specific data were considered to develop a more refined 
estimate of the potential for acute impacts of concern. For these 
source categories, the data refinements employed consisted of using the 
site-specific facility layout to distinguish facility property from an 
area where the public could be exposed. These refinements are discussed 
more fully in the Draft Residual Risk Assessment for the Petroleum 
Refining Source Sector, which is available in the docket for this 
rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682). Ideally, we would 
prefer to have continuous measurements over time to see how the 
emissions vary by each hour over an entire year. Having a frequency 
distribution of hourly emissions rates over a year would allow us to 
perform a probabilistic analysis to estimate potential threshold 
exceedances and their frequency of occurrence. Such an evaluation could 
include a more complete statistical treatment of the key parameters and 
elements adopted in this screening analysis. Recognizing that this 
level of data is rarely available, we instead rely on the multiplier 
approach.
    To better characterize the potential health risks associated with 
estimated acute exposures to HAP, and in response to a key 
recommendation from the SAB's peer review of the EPA's RTR risk 
assessment methodologies,\12\ we generally examine a wider range of 
available acute health metrics (e.g., REL, AEGL) than we do for our 
chronic risk assessments. This is in response to the SAB's 
acknowledgement that there are generally more data gaps and 
inconsistencies in acute reference values than there are in chronic 
reference values. In some cases, e.g., when Reference Value Arrays \13\ 
for HAP have been developed, we consider additional acute values (i.e., 
occupational and international values) to provide a more complete risk 
characterization.
---------------------------------------------------------------------------

    \12\ The SAB peer review of RTR Risk Assessment Methodologies is 
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf.
    \13\ U.S. EPA. (2009) Chapter 2.9 Chemical Specific Reference 
Values for Formaldehyde in Graphical Arrays of Chemical-Specific 
Health Effect Reference Values for Inhalation Exposures (Final 
Report). U.S. Environmental Protection Agency, Washington, DC, EPA/
600/R-09/061, and available on-line at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=211003.
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4. How did we conduct the multipathway exposure and risk screening?
    The EPA conducted a screening analysis examining the potential for 
significant human health risks due to exposures via routes other than 
inhalation (i.e., ingestion). We first determined whether any sources 
in the source categories emitted any hazardous air pollutants known to 
be persistent and bio-accumulative in the environment (PB-HAP). The PB-
HAP compounds or compound classes are

[[Page 36892]]

identified for the screening from the EPA's Air Toxics Risk Assessment 
Library (available at http://www.epa.gov/ttn/fera/risk_atra_vol1.html).
    For the petroleum refinery source categories, we identified 
emissions of cadmium compounds, chlorinated dibenzodioxins and furans 
(CDDF), lead compounds, mercury compounds, polychlorinated biphenyls 
(PCB), and polycylic organic matter (POM). Because PB-HAP are emitted 
by at least one facility, we proceeded to the second step of the 
evaluation. In this step, we determined whether the facility-specific 
emission rates of each of the emitted PB-HAP were large enough to 
create the potential for significant non-inhalation human health risks 
under reasonable worst-case conditions. To facilitate this step, we 
developed emissions rate screening levels for each PB-HAP using a 
hypothetical upper-end screening exposure scenario developed for use in 
conjunction with the EPA's ``Total Risk Integrated Methodology. Fate, 
Transport, and Ecological Exposure'' (TRIM.FaTE) model. We conducted a 
sensitivity analysis on the screening scenario to ensure that its key 
design parameters would represent the upper end of the range of 
possible values, such that it would represent a conservative but not 
impossible scenario. The facility-specific emissions rates of each of 
the PB-HAP were compared to their corresponding emission rate screening 
values to assess the potential for significant human health risks via 
non-inhalation pathways. We call this application of the TRIM.FaTE 
model the Tier I TRIM- Screen or Tier I screen.
    For the purpose of developing emissions rates for our Tier I TRIM-
Screen, we derived emission levels for each PB-HAP (other than lead) at 
which the maximum excess lifetime cancer risk would be 1-in-1 million 
or, for HAP that cause non-cancer health effects, the maximum HQ would 
be 1. If the emissions rate of any PB-HAP exceeds the Tier I screening 
emissions rate for any facility, we conduct a second screen, which we 
call the Tier II TRIM-screen or Tier II screen. In the Tier II screen, 
the location of each facility that exceeded the Tier I emission rate is 
used to refine the assumptions associated with the environmental 
scenario while maintaining the exposure scenario assumptions. We then 
adjust the risk-based Tier I screening level for each PB-HAP for each 
facility based on an understanding of how exposure concentrations 
estimated for the screening scenario change with meteorology and 
environmental assumptions. PB-HAP emissions that do not exceed these 
new Tier II screening levels are considered to pose no unacceptable 
risks. When facilities exceed the Tier II screening levels, it does not 
mean that multi-pathway impacts are significant, only that we cannot 
rule out that possibility based on the results of the screen. These 
facilities may be further evaluated for multi-pathway risks using the 
TRIM.FaTE model.
    In evaluating the potential for multi-pathway risk from emissions 
of lead compounds, rather than developing a screening emissions rate 
for them, we compared modeled maximum estimated chronic inhalation 
exposures with the level of the current National Ambient Air Quality 
Standards (NAAQS) for lead.\14\ Values below the level of the primary 
(health-based) lead NAAQS were considered to have a low potential for 
multi-pathway risk.
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    \14\ In doing so, EPA notes that the legal standard for a 
primary NAAQS--that a standard is requisite to protect public health 
and provide an adequate margin of safety (CAA Section 109(b))--
differs from the Section 112(f) standard (requiring among other 
things that the standard provide an ``ample margin of safety''). 
However, the lead NAAQS is a reasonable measure of determining risk 
acceptability (i.e., the first step of the Benzene NESHAP analysis) 
since it is designed to protect the most susceptible group in the 
human population--children, including children living near major 
lead emitting sources. 73 FR 67002/3; 73 FR 67000/3; 73 FR 67005/1, 
November 12, 2008. In addition, applying the level of the primary 
lead NAAQS at the risk acceptability step is conservative, since 
that primary lead NAAQS reflects an adequate margin of safety.
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    For further information on the multi-pathway analysis approach, see 
the Draft Residual Risk Assessment for the Petroleum Refining Source 
Sector, which is available in the docket for this action (Docket ID 
Number EPA-HQ-OAR-2010-0682).
5. How did we assess risks considering emissions control options?
    In addition to assessing baseline inhalation risks and screening 
for potential multipathway risks, we also estimated risks considering 
the potential emission reductions that would be achieved by the control 
options under consideration. We used the same emissions inventory that 
we used for the risk modeling and applied emission reduction estimates 
for the control options we are proposing to calculate the post-control 
risk. We note that for storage vessels, in response to the ICR some 
facilities reported emissions for their tank farm or a group of storage 
vessels rather than for each individual storage vessel. In order to 
calculate emissions for each storage vessel, we used unit-specific data 
from the ICR to estimate the pre- and post-control emissions based on 
the operating characteristics and controls reported for each unit. For 
example, HAP emissions from each storage vessel were estimated based on 
the size, contents, and controls reported for that storage vessel. If 
additional controls would be necessary to comply with proposed 
requirements for storage vessels, the HAP emissions were again 
estimated based on the upgraded controls. The pre- and post-control 
emissions were summed across all storage vessels at the facility to 
determine a facility-specific emission reduction factor. The facility-
specific emission reduction factor was then used to adjust the 
emissions for each of the pollutants reported for storage vessels at 
that facility to account for the post-control emissions. In this 
manner, the expected emission reductions were applied to the specific 
HAP and emission points in the source category dataset to develop 
corresponding estimates of risk and incremental risk reductions. The 
resulting emission file used for post-control risk analysis is 
available in the docket for this action (Docket ID Number EPA-HQ-OAR-
2010-0682).
6. How did we conduct the environmental risk screening assessment?
a. Adverse Environmental Effect
    The EPA has developed a screening approach to examine the potential 
for adverse environmental effects as required under section 
112(f)(2)(A) of the CAA. Section 112(a)(7) of the CAA defines ``adverse 
environmental effect'' as ``any significant and widespread adverse 
effect, which may reasonably be anticipated, to wildlife, aquatic life, 
or other natural resources, including adverse impacts on populations of 
endangered or threatened species or significant degradation of 
environmental quality over broad areas.''
b. Environmental HAP
    The EPA focuses on seven HAP, which we refer to as ``environmental 
HAP,'' in its screening analysis: five PB-HAP and two acid gases. The 
five PB-HAP are cadmium, dioxins/furans, POM, mercury (both inorganic 
mercury and methyl mercury) and lead compounds. The two acid gases are 
HCl and HF. The rationale for including these seven HAP in the 
environmental risk screening analysis is presented below.
    HAP that persist and bioaccumulate are of particular environmental 
concern because they accumulate in the soil, sediment and water. The 
PB-HAP are

[[Page 36893]]

taken up, through sediment, soil, water, and/or ingestion of other 
organisms, by plants or animals (e.g., small fish) at the bottom of the 
food chain. As larger and larger predators consume these organisms, 
concentrations of the PB-HAP in the animal tissues increases as does 
the potential for adverse effects. The five PB-HAP we evaluate as part 
of our screening analysis account for 99.8 percent of all PB-HAP 
emissions nationally from stationary sources (on a mass basis from the 
2005 National Emissions Inventory (NEI)).
    In addition to accounting for almost all of the mass of PB-HAP 
emitted, we note that the TRIM.Fate model that we use to evaluate 
multipathway risk allows us to estimate concentrations of cadmium 
compounds, dioxins/furans, POM and mercury in soil, sediment and water. 
For lead compounds, we currently do not have the ability to calculate 
these concentrations using the TRIM.Fate model. Therefore, to evaluate 
the potential for adverse environmental effects from lead, we compare 
the estimated HEM-modeled exposures from the source category emissions 
of lead with the level of the secondary NAAQS for lead.\15\ We consider 
values below the level of the secondary lead NAAQS to be unlikely to 
cause adverse environmental effects.
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    \15\ The secondary lead NAAQS is a reasonable measure of 
determining whether there is an adverse environmental effect since 
it was established considering ``effects on soils, water, crops, 
vegetation, man-made materials, animals, wildlife, weather, 
visibility and climate, damage to and deterioration of property, and 
hazards to transportation, as well as effects on economic values and 
on personal comfort and well-being.''
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    Due to their well-documented potential to cause direct damage to 
terrestrial plants, we include two acid gases, HCl and HF, in the 
environmental screening analysis. According to the 2005 NEI, HCl and HF 
account for about 99 percent (on a mass basis) of the total acid gas 
HAP emitted by stationary sources in the U.S. In addition to the 
potential to cause direct damage to plants, high concentrations of HF 
in the air have been linked to fluorosis in livestock. Air 
concentrations of these HAP are already calculated as part of the human 
multipathway exposure and risk screening analysis using the HEM3-AERMOD 
air dispersion model, and we are able to use the air dispersion 
modeling results to estimate the potential for an adverse environmental 
effect.
    The EPA acknowledges that other HAP beyond the seven HAP discussed 
above may have the potential to cause adverse environmental effects. 
Therefore, the EPA may include other relevant HAP in its environmental 
risk screening in the future, as modeling science and resources allow. 
The EPA invites comment on the extent to which other HAP emitted by the 
source categories may cause adverse environmental effects. Such 
information should include references to peer-reviewed ecological 
effects benchmarks that are of sufficient quality for making regulatory 
decisions, as well as information on the presence of organisms located 
near facilities within the source categories that such benchmarks 
indicate could be adversely affected.
c. Ecological Assessment Endpoints and Benchmarks for PB-HAP
    An important consideration in the development of the EPA's 
screening methodology is the selection of ecological assessment 
endpoints and benchmarks. Ecological assessment endpoints are defined 
by the ecological entity (e.g., aquatic communities including fish and 
plankton) and its attributes (e.g., frequency of mortality). Ecological 
assessment endpoints can be established for organisms, populations, 
communities or assemblages, and ecosystems.
    For PB-HAP, we evaluated the following community-level ecological 
assessment endpoints to screen for organisms directly exposed to HAP in 
soils, sediment and water:
     Local terrestrial communities (i.e., soil invertebrates, 
plants) and populations of small birds and mammals that consume soil 
invertebrates exposed to PB-HAP in the surface soil.
     Local benthic (i.e., bottom sediment dwelling insects, 
amphipods, isopods and crayfish) communities exposed to PB-HAP in 
sediment in nearby water bodies.
     Local aquatic (water-column) communities (including fish 
and plankton) exposed to PB-HAP in nearby surface waters.
    For PB-HAP, we also evaluated the following population-level 
ecological assessment endpoint to screen for indirect HAP exposures of 
top consumers via the bioaccumulation of HAP in food chains.
     Piscivorous (i.e., fish-eating) wildlife consuming PB-HAP-
contaminated fish from nearby water bodies.
    For cadmium compounds, dioxins/furans, POM and mercury, we 
identified the available ecological benchmarks for each assessment 
endpoint. An ecological benchmark represents a concentration of HAP 
(e.g., 0.77 micrograms of HAP per liter of water) that has been linked 
to a particular environmental effect level (e.g., a no-observed-
adverse-effect level (NOAEL)) through scientific study. For PB-HAP we 
identified, where possible, ecological benchmarks at the following 
effect levels:
     Probable effect level (PEL): Level above which adverse 
effects are expected to occur frequently.
     Lowest-observed-adverse-effect level (LOAEL): The lowest 
exposure level tested at which there are biologically significant 
increases in frequency or severity of adverse effects.
     No-observed-adverse-effect level (NOAEL): The highest 
exposure level tested at which there are no biologically significant 
increases in the frequency or severity of adverse effect.
    We established a hierarchy of preferred benchmark sources to allow 
selection of benchmarks for each environmental HAP at each ecological 
assessment endpoint. In general, the EPA sources that are used at a 
programmatic level (e.g., Office of Water, Superfund Program) were 
used, if available. If not, the EPA benchmarks used in regional 
programs (e.g., Superfund) were used. If benchmarks were not available 
at a programmatic or regional level, we used benchmarks developed by 
other federal agencies (e.g., NOAA) or state agencies.
    Benchmarks for all effect levels are not available for all PB-HAP 
and assessment endpoints. In cases where multiple effect levels were 
available for a particular PB-HAP and assessment endpoint, we use all 
of the available effect levels to help us to determine whether 
ecological risks exist and, if so, whether the risks could be 
considered significant and widespread.
d. Ecological Assessment Endpoints and Benchmarks for Acid Gases
    The environmental screening analysis also evaluated potential 
damage and reduced productivity of plants due to direct exposure to 
acid gases in the air. For acid gases, we evaluated the following 
ecological assessment endpoint:
     Local terrestrial plant communities with foliage exposed 
to acidic gaseous HAP in the air.
    The selection of ecological benchmarks for the effects of acid 
gases on plants followed the same approach as for PB-HAP (i.e., we 
examine all of the available chronic benchmarks). For HCl, the EPA 
identified chronic benchmark concentrations. We note that the benchmark 
for chronic HCl exposure to plants is greater than the reference 
concentration for chronic inhalation exposure for human health. This 
means

[[Page 36894]]

that where EPA includes regulatory requirements to prevent an 
exceedance of the reference concentration for human health, additional 
analyses for adverse environmental effects of HCl would not be 
necessary.
    For HF, EPA identified chronic benchmark concentrations for plants 
and evaluated chronic exposures to plants in the screening analysis. 
High concentrations of HF in the air have also been linked to fluorosis 
in livestock. However, the HF concentrations at which fluorosis in 
livestock occur are higher than those at which plant damage begins. 
Therefore, the benchmarks for plants are protective of both plants and 
livestock.
e. Screening Methodology
    For the environmental risk screening analysis, the EPA first 
determined whether any petroleum refineries emitted any of the seven 
environmental HAP. For the petroleum refinery source categories, we 
identified emissions of cadmium, dioxins/furans, POM, mercury (both 
inorganic mercury and methyl mercury), lead, HCl and HF.
    Because one or more of the seven environmental HAP evaluated are 
emitted by at least one petroleum refinery, we proceeded to the second 
step of the evaluation.
f. PB-HAP Methodology
    For cadmium, mercury, POM and dioxins/furans, the environmental 
screening analysis consists of two tiers, while lead is analyzed 
differently as discussed earlier. In the first tier, we determined 
whether the maximum facility-specific emission rates of each of the 
emitted environmental HAP were large enough to create the potential for 
adverse environmental effects under reasonable worst-case environmental 
conditions. These are the same environmental conditions used in the 
human multipathway exposure and risk screening analysis.
    To facilitate this step, TRIM.FaTE was run for each PB-HAP under 
hypothetical environmental conditions designed to provide 
conservatively high HAP concentrations. The model was set to maximize 
runoff from terrestrial parcels into the modeled lake, which in turn, 
maximized the chemical concentrations in the water, the sediments, and 
the fish. The resulting media concentrations were then used to back-
calculate a screening threshold emission rate that corresponded to the 
relevant exposure benchmark concentration value for each assessment 
endpoint. To assess emissions from a facility, the reported emission 
rate for each PB-HAP was compared to the screening threshold emission 
rate for that PB-HAP for each assessment endpoint. If emissions from a 
facility do not exceed the Tier I threshold, the facility ``passes'' 
the screen, and therefore, is not evaluated further under the screening 
approach. If emissions from a facility exceed the Tier I threshold, we 
evaluate the facility further in Tier II.
    In Tier II of the environmental screening analysis, the screening 
emission thresholds are adjusted to account for local meteorology and 
the actual location of lakes in the vicinity of facilities that did not 
pass the Tier I screen. The modeling domain for each facility in the 
Tier II analysis consists of eight octants. Each octant contains five 
modeled soil concentrations at various distances from the facility (5 
soil concentrations x 8 octants = total of 40 soil concentrations per 
facility) and one lake with modeled concentrations for water, sediment 
and fish tissue. In the Tier II environmental risk screening analysis, 
the 40 soil concentration points are averaged to obtain an average soil 
concentration for each facility for each PB-HAP. For the water, 
sediment and fish tissue concentrations, the highest value for each 
facility for each pollutant is used. If emission concentrations from a 
facility do not exceed the Tier II threshold, the facility passes the 
screen, and is typically not evaluated further. If emissions from a 
facility exceed the Tier II threshold, the facility does not pass the 
screen and, therefore, may have the potential to cause adverse 
environmental effects. Such facilities are evaluated further to 
investigate factors such as the magnitude and characteristics of the 
area of exceedance.
g. Acid Gas Methodology
    The environmental screening analysis evaluates the potential 
phytotoxicity and reduced productivity of plants due to chronic 
exposure to acid gases. The environmental risk screening methodology 
for acid gases is a single-tier screen that compares the average off-
site ambient air concentration over the modeling domain to ecological 
benchmarks for each of the acid gases. Because air concentrations are 
compared directly to the ecological benchmarks, emission-based 
thresholds are not calculated for acid gases as they are in the 
ecological risk screening methodology for PB-HAP.
    For purposes of ecological risk screening, EPA identifies a 
potential for adverse environmental effects to plant communities from 
exposure to acid gases when the average concentration of the HAP around 
a facility exceeds the LOAEL ecological benchmark. In such cases, we 
further investigate factors such as the magnitude and characteristics 
of the area of exceedance (e.g., land use of exceedance area, size of 
exceedance area) to determine if there is an adverse environmental 
effect.
    For further information on the environmental screening analysis 
approach, see section IV.C.5 of this preamble and the Draft Residual 
Risk Assessment for the Petroleum Refining Source Sector, which is 
available in the docket for this action (Docket ID Number EPA-HQ-OAR-
2010-0682).
7. How did we conduct facility-wide assessments?
    To put the source category risks in context, following the 
assessment approach outlined in the SAB (2010) review, we examine the 
risks from the entire ``facility,'' where the facility includes all 
HAP-emitting operations within a contiguous area and under common 
control. In other words, we examine the HAP emissions not only from the 
source category emission points of interest, but also emissions of HAP 
from all other emission sources at the facility for which we have data.
    The emissions inventories provided in response to the ICR included 
emissions information for all emission sources at the facilities that 
are part of the refineries source categories. Generally, only a few 
emission sources located at refineries are not subject to either 
Refinery MACT 1 or 2; the most notable are boilers, process heaters and 
internal combustion engines, which are addressed by other MACT 
standards.
    We analyzed risks due to the inhalation of HAP that are emitted 
``facility-wide'' for the populations residing within 50 km of each 
facility, consistent with the methods used for the source category 
analysis described above. For these facility-wide risk analyses, the 
modeled source category risks were compared to the facility-wide risks 
to determine the portion of facility-wide risks that could be 
attributed to each of the source categories addressed in this proposal. 
We specifically examined the facility that was associated with the 
highest estimates of risk and determined the percentage of that risk 
attributable to the source category of interest. The Draft Residual 
Risk Assessment for the Petroleum Refining Source Sector available 
through the docket for this action (Docket ID Number EPA-HQ-OAR-2010-
0682) provides the methodology and results of the facility-wide 
analyses, including all facility-wide risks and the percentage of 
source category contribution to facility-wide risks.

[[Page 36895]]

8. How did we consider uncertainties in risk assessment?
    In the Benzene NESHAP we concluded that risk estimation uncertainty 
should be considered in our decision-making under the ample margin of 
safety framework. Uncertainty and the potential for bias are inherent 
in all risk assessments, including those performed for this proposal. 
Although uncertainty exists, we believe that our approach, which used 
conservative tools and assumptions, ensures that our decisions are 
health protective and environmentally protective. A brief discussion of 
the uncertainties in the emissions datasets, dispersion modeling, 
inhalation exposure estimates and dose-response relationships follows 
below. A more thorough discussion of these uncertainties is included in 
the Draft Residual Risk Assessment for the Petroleum Refining Source 
Sector, which is available in the docket for this action (Docket ID 
Number EPA-HQ-OAR-2010-0682).
a. Uncertainties in the Emission Datasets
    Although the development of the RTR datasets involved quality 
assurance/quality control processes, the accuracy of emissions values 
will vary depending on the source of the data, the degree to which data 
are incomplete or missing, the degree to which assumptions made to 
complete the datasets are accurate, errors in emission estimates and 
other factors. The emission estimates considered in this analysis are 
annual totals for 2010, and they do not reflect short-term fluctuations 
during the course of a year or variations from year to year. The 
estimates of peak hourly emissions rates for the acute effects 
screening assessment were based on emission adjustment factors applied 
to the average annual hourly emission rates, which are intended to 
account for emission fluctuations due to normal facility operations.
    As discussed previously, we attempted to provide a consistent 
framework for reporting of emissions information by developing the 
refinery emissions estimation protocol and requesting that refineries 
follow the protocol when reporting emissions inventory data in response 
to the ICR. This protocol, called Emission Estimation Protocol for 
Petroleum Refineries, is available in the docket for this rulemaking 
(Docket Item Number EPA-HQ-OAR-2010-0682-0060). Additionally, we 
developed our own estimates of emissions that are based on the factors 
provided in the protocol and the REM Model. We developed emission 
estimates based on refinery unit capacities, which also provided an 
estimate of allowable emissions. We then conducted risk modeling using 
REM Model estimates and by locating emissions at the centroid of each 
refinery in an attempt to understand the risk associated with emissions 
from each refinery. Therefore, even if there were errors in the 
emission inventories reported in the ICR, as was the case in many 
instances, emissions for those facilities were also modeled using the 
protocol emission factors. The risk modeling of allowable emissions 
based on emission factors and unit capacities did not result in 
significantly different risk results than the actual emissions modeling 
runs. Results of the allowable emissions risk estimates are provided in 
the Draft Residual Risk Assessment for the Petroleum Refining Source 
Sector, which is available in Docket ID Number EPA-HQ-OAR-2010-0682.
b. Uncertainties in Dispersion Modeling
    We recognize there is uncertainty in ambient concentration 
estimates associated with any model, including the EPA's recommended 
regulatory dispersion model, AERMOD. In using a model to estimate 
ambient pollutant concentrations, the user chooses certain options to 
apply. For RTR assessments, we select some model options that have the 
potential to overestimate ambient air concentrations (e.g., not 
including plume depletion or pollutant transformation). We select other 
model options that have the potential to underestimate ambient impacts 
(e.g., not including building downwash). Other options that we select 
have the potential to either under- or overestimate ambient levels 
(e.g., meteorology and receptor locations). On balance, considering the 
directional nature of the uncertainties commonly present in ambient 
concentrations estimated by dispersion models, the approach we apply in 
the RTR assessments should yield unbiased estimates of ambient HAP 
concentrations.
c. Uncertainties in Inhalation Exposure
    The EPA did not include the effects of human mobility on exposures 
in the assessment. Specifically, short-term mobility and long-term 
mobility between census blocks in the modeling domain were not 
considered.\16\ The approach of not considering short- or long-term 
population mobility does not bias the estimate of the theoretical MIR 
(by definition), nor does it affect the estimate of cancer incidence 
because the total population number remains the same. It does, however, 
affect the shape of the distribution of individual risks across the 
affected population, shifting it toward higher estimated individual 
risks at the upper end and reducing the number of people estimated to 
be at lower risks, thereby increasing the estimated number of people at 
specific high-risk levels (e.g., 1-in-10 thousand or 1-in-1 million).
---------------------------------------------------------------------------

    \16\ Short-term mobility is movement from one micro-environment 
to another over the course of hours or days. Long-term mobility is 
movement from one residence to another over the course of a 
lifetime.
---------------------------------------------------------------------------

    In addition, the assessment predicted the chronic exposures at the 
centroid of each populated census block as surrogates for the exposure 
concentrations for all people living in that block. Using the census 
block centroid to predict chronic exposures tends to over-predict 
exposures for people in the census block who live further from the 
facility and under-predict exposures for people in the census block who 
live closer to the facility. Thus, using the census block centroid to 
predict chronic exposures may lead to a potential understatement or 
overstatement of the true maximum impact, but is an unbiased estimate 
of average risk and incidence. We reduce this uncertainty by analyzing 
large census blocks near facilities using aerial imagery and adjusting 
the location of the block centroid to better represent the population 
in the block, as well as adding additional receptor locations where the 
block population is not well represented by a single location.
    The assessment evaluates the cancer inhalation risks associated 
with pollutant exposures over a 70-year period, which is the assumed 
lifetime of an individual. In reality, both the length of time that 
modeled emission sources at facilities actually operate (i.e., more or 
less than 70 years) and the domestic growth or decline of the modeled 
industry (i.e., the increase or decrease in the number or size of 
domestic facilities) will influence the future risks posed by a given 
source or source category. Depending on the characteristics of the 
industry, these factors will, in most cases, result in an overestimate 
both in individual risk levels and in the total estimated number of 
cancer cases. However, in the unlikely scenario where a facility 
maintains, or even increases, its emissions levels over a period of 
more than 70 years, residents live beyond 70 years at the same 
location, and the residents spend most of their days at that location, 
then the cancer inhalation risks could potentially be underestimated. 
However, annual cancer incidence estimates from exposures to emissions 
from these

[[Page 36896]]

sources would not be affected by the length of time an emissions source 
operates.
    The exposure estimates used in these analyses assume chronic 
exposures to ambient (outdoor) levels of pollutants. Because most 
people spend the majority of their time indoors, actual exposures may 
not be as high, depending on the characteristics of the pollutants 
modeled. For many of the HAP, indoor levels are roughly equivalent to 
ambient levels, but for very reactive pollutants or larger particles, 
indoor levels are typically lower. This factor has the potential to 
result in an overestimate of 25 to 30 percent of exposures.\17\
---------------------------------------------------------------------------

    \17\ U.S. EPA. National-Scale Air Toxics Assessment for 1996. 
(EPA 453/R-01-003; January 2001; page 85.)
---------------------------------------------------------------------------

    In addition to the uncertainties highlighted above, there are 
several factors specific to the acute exposure assessment that should 
be highlighted. The accuracy of an acute inhalation exposure assessment 
depends on the simultaneous occurrence of independent factors that may 
vary greatly, such as hourly emissions rates, meteorology and human 
activity patterns. In this assessment, we assume that individuals 
remain for 1 hour at the point of maximum ambient concentration as 
determined by the co-occurrence of peak emissions and worst-case 
meteorological conditions. These assumptions would tend to be worst-
case actual exposures as it is unlikely that a person would be located 
at the point of maximum exposure during the time when peak emissions 
and worst-case meteorological conditions occur simultaneously.
d. Uncertainties in Dose-Response Relationships
    There are uncertainties inherent in the development of the dose-
response values used in our risk assessments for cancer effects from 
chronic exposures and non-cancer effects from both chronic and acute 
exposures. Some uncertainties may be considered quantitatively, and 
others generally are expressed in qualitative terms. We note as a 
preface to this discussion a point on dose-response uncertainty that is 
brought out in the EPA's 2005 Cancer Guidelines; namely, that ``the 
primary goal of EPA actions is protection of human health; accordingly, 
as an Agency policy, risk assessment procedures, including default 
options that are used in the absence of scientific data to the 
contrary, should be health protective'' (EPA 2005 Cancer Guidelines, 
pages 1-7). This is the approach followed here as summarized in the 
next several paragraphs. A complete detailed discussion of 
uncertainties and variability in dose-response relationships is given 
in the Draft Residual Risk Assessment for the Petroleum Refining Source 
Sector, which is available in the docket for this action (Docket ID 
Number EPA-HQ-OAR-2010-0682).
    Cancer URE values used in our risk assessments are those that have 
been developed to generally provide an upper bound estimate of risk. 
That is, they represent a ``plausible upper limit to the true value of 
a quantity'' (although this is usually not a true statistical 
confidence limit).\18\ In some circumstances, the true risk could be as 
low as zero; however, in other circumstances, the risk could also be 
greater.\19\ When developing an upper-bound estimate of risk and to 
provide risk values that do not underestimate risk, health-protective 
default approaches are generally used. To err on the side of ensuring 
adequate health-protection, the EPA typically uses the upper bound 
estimates rather than lower bound or central tendency estimates in our 
risk assessments, an approach that may have limitations for other uses 
(e.g., priority-setting or expected benefits analysis).
---------------------------------------------------------------------------

    \18\ IRIS glossary (http://ofmpub.epa.gov/sor_internet/registry/termreg/searchandretrieve/glossariesandkeywordlists/search.do?details=&glossaryName=IRIS%20Glossary).
    \19\ An exception to this is the URE for benzene, which is 
considered to cover a range of values, each end of which is 
considered to be equally plausible, and which is based on maximum 
likelihood estimates.
---------------------------------------------------------------------------

    Chronic non-cancer RfC and reference dose (RfD) values represent 
chronic exposure levels that are intended to be health-protective 
levels. Specifically, these values provide an estimate (with 
uncertainty spanning perhaps an order of magnitude) of a continuous 
inhalation exposure (RfC) or a daily oral exposure (RfD) to the human 
population (including sensitive subgroups) that is likely to be without 
an appreciable risk of deleterious effects during a lifetime. To derive 
values that are intended to be ``without appreciable risk,'' the 
methodology relies upon an uncertainty factor (UF) approach (U.S. EPA, 
1993, 1994) which considers uncertainty, variability and gaps in the 
available data. The UF are applied to derive reference values that are 
intended to protect against appreciable risk of deleterious effects. 
The UF are commonly default values,\20\ e.g., factors of 10 or 3, used 
in the absence of compound-specific data; where data are available, UF 
may also be developed using compound-specific information. When data 
are limited, more assumptions are needed and more UF are used. Thus, 
there may be a greater tendency to overestimate risk in the sense that 
further study might support development of reference values that are 
higher (i.e., less potent) because fewer default assumptions are 
needed. However, for some pollutants, it is possible that risks may be 
underestimated.
---------------------------------------------------------------------------

    \20\ According to the NRC report, Science and Judgment in Risk 
Assessment (NRC, 1994) ``[Default] options are generic approaches, 
based on general scientific knowledge and policy judgment, that are 
applied to various elements of the risk assessment process when the 
correct scientific model is unknown or uncertain.'' The 1983 NRC 
report, Risk Assessment in the Federal Government: Managing the 
Process, defined default option as ``the option chosen on the basis 
of risk assessment policy that appears to be the best choice in the 
absence of data to the contrary'' (NRC, 1983a, p. 63). Therefore, 
default options are not rules that bind the Agency; rather, the 
Agency may depart from them in evaluating the risks posed by a 
specific substance when it believes this to be appropriate. In 
keeping with EPA's goal of protecting public health and the 
environment, default assumptions are used to ensure that risk to 
chemicals is not underestimated (although defaults are not intended 
to overtly overestimate risk). See EPA, 2004, An Examination of EPA 
Risk Assessment Principles and Practices, EPA/100/B-04/001 available 
at: http://www.epa.gov/osa/pdfs/ratf-final.pdf.
---------------------------------------------------------------------------

    While collectively termed ``UF,'' these factors account for a 
number of different quantitative considerations when using observed 
animal (usually rodent) or human toxicity data in the development of 
the RfC. The UF are intended to account for: (1) Variation in 
susceptibility among the members of the human population (i.e., inter-
individual variability); (2) uncertainty in extrapolating from 
experimental animal data to humans (i.e., interspecies differences); 
(3) uncertainty in extrapolating from data obtained in a study with 
less-than-lifetime exposure (i.e., extrapolating from sub-chronic to 
chronic exposure); (4) uncertainty in extrapolating the observed data 
to obtain an estimate of the exposure associated with no adverse 
effects; and (5) uncertainty when the database is incomplete or there 
are problems with the applicability of available studies.
    Many of the UF used to account for variability and uncertainty in 
the development of acute reference values are quite similar to those 
developed for chronic durations, but they more often use individual UF 
values that may be less than 10. The UF are applied based on chemical-
specific or health effect-specific information (e.g., simple irritation 
effects do not vary appreciably between human individuals, hence a 
value of 3 is typically used), or based on the purpose for the 
reference value (see the following paragraph). The UF

[[Page 36897]]

applied in acute reference value derivation include: (1) Heterogeneity 
among humans; (2) uncertainty in extrapolating from animals to humans; 
(3) uncertainty in lowest observable adverse effect (exposure) level to 
no observed adverse effect (exposure) level adjustments; and (4) 
uncertainty in accounting for an incomplete database on toxic effects 
of potential concern. Additional adjustments are often applied to 
account for uncertainty in extrapolation from observations at one 
exposure duration (e.g., 4 hours) to derive an acute reference value at 
another exposure duration (e.g., 1 hour).
    Not all acute reference values are developed for the same purpose 
and care must be taken when interpreting the results of an acute 
assessment of human health effects relative to the reference value or 
values being exceeded. Where relevant to the estimated exposures, the 
lack of short-term dose-response values at different levels of severity 
should be factored into the risk characterization as potential 
uncertainties.
    Although every effort is made to identify appropriate human health 
effect dose-response assessment values for all pollutants emitted by 
the sources in this risk assessment, some HAP emitted by these source 
categories are lacking dose-response assessments. Accordingly, these 
pollutants cannot be included in the quantitative risk assessment, 
which could result in quantitative estimates understating HAP risk. To 
help to alleviate this potential underestimate, where we conclude 
similarity with a HAP for which a dose-response assessment value is 
available, we use that value as a surrogate for the assessment of the 
HAP for which no value is available. To the extent use of surrogates 
indicates appreciable risk, we may identify a need to increase priority 
for new IRIS assessment of that substance. We additionally note that, 
generally speaking, HAP of greatest concern due to environmental 
exposures and hazard are those for which dose-response assessments have 
been performed, reducing the likelihood of understating risk. Further, 
HAP not included in the quantitative assessment are assessed 
qualitatively and considered in the risk characterization that informs 
the risk management decisions, including with regard to consideration 
of HAP reductions achieved by various control options.
    For a group of compounds that are unspeciated (e.g., glycol 
ethers), we conservatively use the most protective reference value of 
an individual compound in that group to estimate risk. Similarly, for 
an individual compound in a group (e.g., ethylene glycol diethyl ether) 
that does not have a specified reference value, we also apply the most 
protective reference value from the other compounds in the group to 
estimate risk.
e. Uncertainties in the Multipathway Assessment
    For each source category, we generally rely on site-specific levels 
of PB-HAP emissions to determine whether a refined assessment of the 
impacts from multipathway exposures is necessary. This determination is 
based on the results of a two-tiered screening analysis that relies on 
the outputs from models that estimate environmental pollutant 
concentrations and human exposures for four PB-HAP. Two important types 
of uncertainty associated with the use of these models in RTR risk 
assessments and inherent to any assessment that relies on environmental 
modeling are model uncertainty and input uncertainty.\21\
---------------------------------------------------------------------------

    \21\ In the context of this discussion, the term ``uncertainty'' 
as it pertains to exposure and risk encompasses both variability in 
the range of expected inputs and screening results due to existing 
spatial, temporal, and other factors, as well as uncertainty in 
being able to accurately estimate the true result.
---------------------------------------------------------------------------

    Model uncertainty concerns whether the selected models are 
appropriate for the assessment being conducted and whether they 
adequately represent the actual processes that might occur for that 
situation. An example of model uncertainty is the question of whether 
the model adequately describes the movement of a pollutant through the 
soil. This type of uncertainty is difficult to quantify. However, based 
on feedback received from previous EPA SAB reviews and other reviews, 
we are confident that the models used in the screen are appropriate and 
state-of-the-art for the multipathway risk assessments conducted in 
support of RTR.
    Input uncertainty is concerned with how accurately the models have 
been configured and parameterized for the assessment at hand. For Tier 
I of the multipathway screen, we configured the models to avoid 
underestimating exposure and risk. This was accomplished by selecting 
upper-end values from nationally-representative data sets for the more 
influential parameters in the environmental model, including selection 
and spatial configuration of the area of interest, lake location and 
size, meteorology, surface water and soil characteristics and structure 
of the aquatic food web. We also assume an ingestion exposure scenario 
and values for human exposure factors that represent reasonable maximum 
exposures.
    In Tier II of the multipathway assessment, we refine the model 
inputs to account for meteorological patterns in the vicinity of the 
facility versus using upper-end national values and we identify the 
actual location of lakes near the facility rather than the default lake 
location that we apply in Tier I. By refining the screening approach in 
Tier II to account for local geographical and meteorological data, we 
decrease the likelihood that concentrations in environmental media are 
overestimated, thereby increasing the usefulness of the screen. The 
assumptions and the associated uncertainties regarding the selected 
ingestion exposure scenario are the same for Tier I and Tier II.
    For both Tiers I and II of the multipathway assessment, our 
approach to addressing model input uncertainty is generally cautious. 
We choose model inputs from the upper end of the range of possible 
values for the influential parameters used in the models, and we assume 
that the exposed individual exhibits ingestion behavior that would lead 
to a high total exposure. This approach reduces the likelihood of not 
identifying high risks for adverse impacts.
    Despite the uncertainties, when individual pollutants or facilities 
do screen out, we are confident that the potential for adverse 
multipathway impacts on human health is very low. On the other hand, 
when individual pollutants or facilities do not screen out, it does not 
mean that multipathway impacts are significant, only that we cannot 
rule out that possibility and that a refined multipathway analysis for 
the site might be necessary to obtain a more accurate risk 
characterization for the source categories.
    For further information on uncertainties and the Tier I and II 
screening methods, refer to the risk document Appendix 4, Technical 
Support Document for TRIM-Based Multipathway Tiered Screening 
Methodology for RTR.
f. Uncertainties in the Environmental Risk Screening Assessment
    For each source category, we generally rely on site-specific levels 
of environmental HAP emissions to perform an environmental screening 
assessment. The environmental screening assessment is based on the 
outputs from models that estimate environmental HAP concentrations. The 
same models, specifically the TRIM.FaTE multipathway model and the 
AERMOD air dispersion model, are used to estimate environmental HAP

[[Page 36898]]

concentrations for both the human multipathway screening analysis and 
for the environmental screening analysis. Therefore, both screening 
assessments have similar modeling uncertainties.
    Two important types of uncertainty associated with the use of these 
models in RTR environmental screening assessments--and inherent to any 
assessment that relies on environmental modeling--are model uncertainty 
and input uncertainty.\22\
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    \22\ In the context of this discussion, the term 
``uncertainty,'' as it pertains to exposure and risk assessment, 
encompasses both variability in the range of expected inputs and 
screening results due to existing spatial, temporal, and other 
factors, as well as uncertainty in being able to accurately estimate 
the true result.
---------------------------------------------------------------------------

    Model uncertainty concerns whether the selected models are 
appropriate for the assessment being conducted and whether they 
adequately represent the movement and accumulation of environmental HAP 
emissions in the environment. For example, does the model adequately 
describe the movement of a pollutant through the soil? This type of 
uncertainty is difficult to quantify. However, based on feedback 
received from previous EPA SAB reviews and other reviews, we are 
confident that the models used in the screen are appropriate and state-
of-the-art for the environmental risk assessments conducted in support 
of our RTR analyses.
    Input uncertainty is concerned with how accurately the models have 
been configured and parameterized for the assessment at hand. For Tier 
I of the environmental screen for PB-HAP, we configured the models to 
avoid underestimating exposure and risk to reduce the likelihood that 
the results indicate the risks are lower than they actually are. This 
was accomplished by selecting upper-end values from nationally-
representative data sets for the more influential parameters in the 
environmental model, including selection and spatial configuration of 
the area of interest, the location and size of any bodies of water, 
meteorology, surface water and soil characteristics and structure of 
the aquatic food web. In Tier I, we used the maximum facility-specific 
emissions for cadmium compounds, dioxins/furans, POM, and mercury and 
each of the media when comparing to ecological benchmarks. This is 
consistent with the conservative design of Tier I of the screen. In 
Tier II of the environmental screening analysis for PB-HAP, we refine 
the model inputs to account for meteorological patterns in the vicinity 
of the facility versus using upper-end national values, and we identify 
the locations of water bodies near the facility location. By refining 
the screening approach in Tier II to account for local geographical and 
meteorological data, we decrease the likelihood that concentrations in 
environmental media are overestimated, thereby increasing the 
usefulness of the screen. To better represent widespread impacts, the 
modeled soil concentrations are averaged in Tier II to obtain one 
average soil concentration value for each facility and for each PB-HAP. 
For PB-HAP concentrations in water, sediment and fish tissue, the 
highest value for each facility for each pollutant is used.
    For the environmental screening assessment for acid gases, we 
employ a single-tiered approach. We use the modeled air concentrations 
and compare those with ecological benchmarks.
    For both Tiers I and II of the environmental screening assessment, 
our approach to addressing model input uncertainty is generally 
cautious. We choose model inputs from the upper end of the range of 
possible values for the influential parameters used in the models, and 
we assume that the exposed organism (e.g., invertebrate, fish) exhibits 
ingestion behavior that would lead to a high total exposure. This 
approach reduces the likelihood of not identifying potential risks for 
adverse environmental impacts.
    Uncertainty also exists in the ecological benchmarks for the 
environmental risk screening analysis. We established a hierarchy of 
preferred benchmark sources to allow selection of benchmarks for each 
environmental HAP at each ecological assessment endpoint. In general, 
EPA benchmarks used at a programmatic level (e.g., Office of Water, 
Superfund Program) were used if available. If not, we used EPA 
benchmarks used in regional programs (e.g., Superfund). If benchmarks 
were not available at a programmatic or regional level, we used 
benchmarks developed by other agencies (e.g., NOAA) or by state 
agencies.
    In all cases (except for lead, which was evaluated through a 
comparison to the NAAQS), we searched for benchmarks at the following 
three effect levels, as described in section III.A.6 of this preamble:
    1. A no-effect level (i.e., NOAEL).
    2. Threshold-effect level (i.e., LOAEL).
    3. Probable effect level (i.e., PEL).
    For some ecological assessment endpoint/environmental HAP 
combinations, we could identify benchmarks for all three effect levels, 
but for most, we could not. In one case, where different agencies 
derived significantly different numbers to represent a threshold for 
effect, we included both. In several cases, only a single benchmark was 
available. In cases where multiple effect levels were available for a 
particular PB-HAP and assessment endpoint, we used all of the available 
effect levels to help us to determine whether risk exists and if the 
risks could be considered significant and widespread.
    The EPA evaluated the following seven HAP in the environmental risk 
screening assessment: Cadmium, dioxins/furans, POM, mercury (both 
inorganic mercury and methyl mercury), lead compounds, HCl and HF. 
These seven HAP represent pollutants that can cause adverse impacts for 
plants and animals either through direct exposure to HAP in the air or 
through exposure to HAP that is deposited from the air onto soils and 
surface waters. These seven HAP also represent those HAP for which we 
can conduct a meaningful environmental risk screening assessment. For 
other HAP not included in our screening assessment, the model has not 
been parameterized such that it can be used for that purpose. In some 
cases, depending on the HAP, we may not have appropriate multipathway 
models that allow us to predict the concentration of that pollutant. 
The EPA acknowledges that other HAP beyond the seven HAP that we are 
evaluating may have the potential to cause adverse environmental 
effects and, therefore, the EPA may evaluate other relevant HAP in the 
future, as modeling science and resources allow.
    Further information on uncertainties and the Tier I and II 
environmental screening methods is provided in Appendix 5 of the 
document Technical Support Document for TRIM-Based Multipathway Tiered 
Screening Methodology for RTR: Summary of Approach and Evaluation. 
Also, see the Draft Residual Risk Assessment for the Petroleum Refining 
Source Sector, available in the docket for this action (Docket ID 
Number EPA-HQ-OAR-2010-0682).

B. How did we consider the risk results in making decisions for this 
proposal?

    As discussed in section II.A.1 of this preamble, in evaluating and 
developing standards under CAA section 112(f)(2), we apply a two-step 
process to address residual risk. In the first step, the EPA determines 
whether risks are acceptable. This determination ``considers all health 
information, including risk estimation uncertainty, and includes a 
presumptive limit on maximum individual lifetime

[[Page 36899]]

[cancer] risk (MIR) \23\ of approximately [1-in-10 thousand] [i.e., 
100-in-1 million].'' 54 FR 38045, September 14, 1989. If risks are 
unacceptable, the EPA must determine the emissions standards necessary 
to bring risks to an acceptable level without considering costs. In the 
second step of the process, the EPA considers whether the emissions 
standards provide an ample margin of safety ``in consideration of all 
health information, including the number of persons at risk levels 
higher than approximately 1-in-1 million, as well as other relevant 
factors, including costs and economic impacts, technological 
feasibility, and other factors relevant to each particular decision.'' 
Id. The EPA must promulgate tighter emission standards if necessary to 
provide an ample margin of safety.
---------------------------------------------------------------------------

    \23\ Although defined as ``maximum individual risk,'' MIR refers 
only to cancer risk. MIR, one metric for assessing cancer risk, is 
the estimated risk were an individual exposed to the maximum level 
of a pollutant for a lifetime.
---------------------------------------------------------------------------

    In past residual risk actions, the EPA considered a number of human 
health risk metrics associated with emissions from the categories under 
review, including the MIR, the number of persons in various risk 
ranges, cancer incidence, the maximum non-cancer HI and the maximum 
acute non-cancer hazard. See, e.g., 72 FR 25138, May 3, 2007; 71 FR 
42724, July 27, 2006. The EPA considered this health information for 
both actual and allowable emissions. See, e.g., 75 FR 65068, October 
21, 2010, and 75 FR 80220, December 21, 2010). The EPA also discussed 
risk estimation uncertainties and considered the uncertainties in the 
determination of acceptable risk and ample margin of safety in these 
past actions. The EPA considered this same type of information in 
support of this action.
    The agency is considering these various measures of health 
information to inform our determinations of risk acceptability and 
ample margin of safety under CAA section 112(f). As explained in the 
Benzene NESHAP, ``the first step of judgment on acceptability cannot be 
reduced to any single factor,'' and thus ``[t]he Administrator believes 
that the acceptability of risk under [previous] section 112 is best 
judged on the basis of a broad set of health risk measures and 
information.'' 54 FR 38046, September 14, 1989. Similarly, with regard 
to making the ample margin of safety determination, ``the Agency again 
considers all of the health risk and other health information 
considered in the first step. Beyond that information, additional 
factors relating to the appropriate level of control will also be 
considered, including cost and economic impacts of controls, 
technological feasibility, uncertainties, and any other relevant 
factors.'' Id.
    The Benzene NESHAP approach provides flexibility regarding factors 
the EPA may consider in making determinations and how the EPA may weigh 
those factors for each source category. In responding to comment on our 
policy under the Benzene NESHAP, the EPA explained that:

[t]he policy chosen by the Administrator permits consideration of 
multiple measures of health risk. Not only can the MIR figure be 
considered, but also incidence, the presence of non-cancer health 
effects, and the uncertainties of the risk estimates. In this way, 
the effect on the most exposed individuals can be reviewed as well 
as the impact on the general public. These factors can then be 
weighed in each individual case. This approach complies with the 
Vinyl Chloride mandate that the Administrator ascertain an 
acceptable level of risk to the public by employing [her] expertise 
to assess available data. It also complies with the Congressional 
intent behind the CAA, which did not exclude the use of any 
particular measure of public health risk from the EPA's 
consideration with respect to CAA section 112 regulations, and 
thereby implicitly permits consideration of any and all measures of 
health risk which the Administrator, in [her] judgment, believes are 
appropriate to determining what will `protect the public health.'

See 54 FR at 38057, September 14, 1989. Thus, the level of the MIR is 
only one factor to be weighed in determining acceptability of risks. 
The Benzene NESHAP explained that ``an MIR of approximately one in 10 
thousand should ordinarily be the upper end of the range of 
acceptability. As risks increase above this benchmark, they become 
presumptively less acceptable under CAA section 112, and would be 
weighed with the other health risk measures and information in making 
an overall judgment on acceptability. Or, the Agency may find, in a 
particular case, that a risk that includes MIR less than the 
presumptively acceptable level is unacceptable in the light of other 
health risk factors.'' Id. at 38045. Similarly, with regard to the 
ample margin of safety analysis, the EPA stated in the Benzene NESHAP 
that: ``EPA believes the relative weight of the many factors that can 
be considered in selecting an ample margin of safety can only be 
determined for each specific source category. This occurs mainly 
because technological and economic factors (along with the health-
related factors) vary from source category to source category.'' Id. at 
38061. We also consider the uncertainties associated with the various 
risk analyses, as discussed earlier in this preamble, in our 
determinations of acceptability and ample margin of safety.
    The EPA notes that it has not considered certain health information 
to date in making residual risk determinations. At this time, we do not 
attempt to quantify those HAP risks that may be associated with 
emissions from other facilities that do not include the source 
categories in question, mobile source emissions, natural source 
emissions, persistent environmental pollution or atmospheric 
transformation in the vicinity of the sources in these categories.
    The agency understands the potential importance of considering an 
individual's total exposure to HAP in addition to considering exposure 
to HAP emissions from the source category and facility. We recognize 
that such consideration may be particularly important when assessing 
non-cancer risks, where pollutant-specific health reference levels 
(e.g., RfCs) are based on the assumption that thresholds exist for 
adverse health effects. For example, the agency recognizes that, 
although exposures attributable to emissions from a source category or 
facility alone may not indicate the potential for increased risk of 
adverse non-cancer health effects in a population, the exposures 
resulting from emissions from the facility in combination with 
emissions from all of the other sources (e.g., other facilities) to 
which an individual is exposed may be sufficient to result in increased 
risk of adverse non-cancer health effects. In May 2010, the SAB advised 
the EPA ``that RTR assessments will be most useful to decision makers 
and communities if results are presented in the broader context of 
aggregate and cumulative risks, including background concentrations and 
contributions from other sources in the area.'' \24\
---------------------------------------------------------------------------

    \24\ EPA's responses to this and all other key recommendations 
of the SAB's advisory on RTR risk assessment methodologies (which is 
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf) 
are outlined in a memo to this rulemaking docket from David Guinnup 
entitled, EPA's Actions in Response to the Key Recommendations of 
the SAB Review of RTR Risk Assessment Methodologies.
---------------------------------------------------------------------------

    In response to the SAB recommendations, the EPA is incorporating 
cumulative risk analyses into its RTR risk assessments, including those 
reflected in this proposal. The agency is: (1) Conducting facility-wide 
assessments, which include source category emission points as well as 
other emission points within the facilities; (2) considering sources in 
the same category whose emissions result in exposures to the same 
individuals; and (3) for some persistent and

[[Page 36900]]

bioaccumulative pollutants, analyzing the ingestion route of exposure. 
In addition, the RTR risk assessments have always considered aggregate 
cancer risk from all carcinogens and aggregate non-cancer hazard 
indices from all non-carcinogens affecting the same target organ 
system.
    Although we are interested in placing source category and facility-
wide HAP risks in the context of total HAP risks from all sources 
combined in the vicinity of each source, we are concerned about the 
uncertainties of doing so. Because we have not conducted in-depth 
studies of risks due to emissions from sources other those at 
refineries subject to this RTR review, such estimates of total HAP 
risks would have significantly greater associated uncertainties than 
the source category or facility-wide estimates. Such aggregate or 
cumulative assessments would compound those uncertainties, making the 
assessments too unreliable.

C. How did we perform the technology review?

    Our technology review focused on the identification and evaluation 
of developments in practices, processes and control technologies that 
have occurred since the MACT standards were promulgated. Where we 
identified such developments, in order to inform our decision of 
whether it is ``necessary'' to revise the emissions standards, we 
analyzed the technical feasibility of applying these developments, and 
the estimated costs, energy implications, non-air environmental 
impacts, as well as considering the emission reductions. We also 
considered the appropriateness of applying controls to new sources 
versus retrofitting existing sources.
    Based on our analyses of the available data and information, we 
identified potential developments in practices, processes and control 
technologies. For this exercise, we considered any of the following to 
be a ``development'':
     Any add-on control technology or other equipment that was 
not identified and considered during development of the original MACT 
standards.
     Any improvements in add-on control technology or other 
equipment (that were identified and considered during development of 
the original MACT standards) that could result in additional emissions 
reduction.
     Any work practice or operational procedure that was not 
identified or considered during development of the original MACT 
standards.
     Any process change or pollution prevention alternative 
that could be broadly applied to the industry and that was not 
identified or considered during development of the original MACT 
standards.
     Any significant changes in the cost (including cost 
effectiveness) of applying controls (including controls the EPA 
considered during the development of the original MACT standards).
    We reviewed a variety of data sources in our investigation of 
potential practices, processes or controls to consider. Among the 
sources we reviewed were the NESHAP for various industries that were 
promulgated since the MACT standards being reviewed in this action. We 
reviewed the regulatory requirements and/or technical analyses 
associated with these regulatory actions to identify any practices, 
processes and control technologies considered in these efforts that 
could be applied to emission sources subject to Refinery MACT 1 or 2, 
as well as the costs, non-air impacts and energy implications 
associated with the use of these technologies. Additionally, we 
requested information from facilities as described in section II.C of 
this preamble. Finally, we reviewed information from other sources, 
such as state and/or local permitting agency databases and industry-
supported databases.

IV. Analytical Results and Proposed Decisions

A. What actions are we taking pursuant to CAA sections 112(d)(2) and 
112(d)(3)?

    In this action, we are proposing the following revisions to the 
Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and 
(3) \25\: (1) Adding MACT standards for DCU decoking operations; (2) 
revising the CRU purge vent pressure exemption; (3) adding operational 
requirements for flares used as air pollution control devices (APCD) in 
Refinery MACT 1 and 2; and (4) adding requirements and clarifications 
for vent control bypasses in Refinery MACT 1. The results and proposed 
decisions based on the analyses performed pursuant to CAA section 
112(d)(2) and (3) are presented below.
---------------------------------------------------------------------------

    \25\ 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).
---------------------------------------------------------------------------

1. Delayed Coking Units
a. Description of Delayed Coker Process Operations and Emissions
    We are proposing to establish MACT standards specific to the DCU 
pursuant to CAA section 112(d)(2) and (3). The DCU uses thermal 
cracking to upgrade heavy feedstocks and to produce petroleum coke. 
Unlike most other refinery operations that are continuous, the DCU 
operates in a semi-batch system. Most DCU consist of a large process 
heater, two or more coking drums, and a single product distillation 
column. The DCU feed is actually fed to the unit's distillation column. 
Bottoms from the distillation column are heated to near cracking 
temperatures and the resulting heavy oil is fed to one of the coking 
drums. As the cracking reactions occur, coke is produced in the drum 
and begins to fill the drum with sponge-like solid coke material. 
During this process, the DCU is a closed system, with the produced gas 
streams piped to the unit's distillation column for product recovery.
    When the first coke drum becomes filled with coke, the feed is 
diverted to the second coke drum and processing continues via the 
second coke drum. The full coke drum, which is no longer receiving oil 
feed, is taken through a number of steps, collectively referred to as 
decoking operations, to remove the coke from the drum and prepare the 
drum for subsequent oil feed processing. The decoking steps include: 
purging, cooling/quenching, venting, draining, deheading, and coke 
cutting. A description of these steps and the potential emissions from 
these activities are provided in the next several paragraphs. Once the 
coke is removed, the vessel is re-sealed (i.e., the drain valve is 
closed and the ``head'' is re-attached), pressure tested (typically 
using steam), purged to remove oxygen, then slowly heated to processing 
temperatures so it can go back on-line. When the second coke drum 
becomes filled with coke, feed is diverted back to the first coke drum 
and the second drum is then decoked. In this manner, the DCU allows for 
continuous processing of oil even though the individual coke drums 
operate in cyclical batch fashion.
    The first step in decoking operations is to purge the coke drum 
with steam. This serves to cool the coke bed and to flush oil or 
reaction products from the coke bed. The steam purge is initially sent 
to the product distillation column and then diverted to the unit's 
blowdown system. The blowdown system serves to condense the steam and 
other liquids entrained in the

[[Page 36901]]

steam. Nearly all DCU operate a ''closed blowdown'' system, such that 
uncondensed gases from the blowdown system are sent to the product 
distillation column or the facility's light gas plant, recovered as 
fuel gas, or combusted in a flare. In an open blowdown system, these 
uncondensed gases would be vented directly to atmosphere. The DCU vent 
discharge to the blowdown system is specifically defined in Refinery 
MACT 1 as the ``delayed coker vent.''
    The next step in the decoking process is cooling/quenching the coke 
drum and its contents via the addition of water, commonly referred to 
as quench water, at the bottom of the coke drum. The water added to the 
vessel quickly turns to steam due to the high temperature of the coke 
bed. The water/steam helps to further cool the coke bed and ``quench'' 
any residual coking reactions that may still occur within the hot coke 
bed. As with the steam purge, steam off-gas from the cooling/quenching 
cycle is recovered in the unit's blowdown system and this vent 
discharge is specifically defined in Refinery MACT 1 as the ``delayed 
coker vent.''
    After several hours, the coke drum is sufficiently cooled so that 
the water level in the drum can be raised to entirely cover the coke 
bed. Although water covers the coke bed, the upper portion of the coke 
bed may still be well above 212 degrees Fahrenheit ([deg]F) and will 
continue to generate steam. In fact, since the coke drum vessel 
pressure is greater than atmospheric pressure, the equilibrium boiling 
point of water in the vessel is greater than 212[emsp14][deg]F. 
Therefore, the water at the top of the coke drum is typically well 
above 212[emsp14][deg]F (superheated water). As the coke drum and its 
contents continue to cool from the evaporative cooling effect of the 
steam generation, the steam generation rate and the pressure within the 
vessel will decrease.
    Owners or operators of DCU may use different indicators or set 
points to determine when the system has cooled sufficiently to move to 
the venting step; however, one of the most common indicators monitored 
is the pressure of the coke drum vessel (or steam vent line just above 
the coke drum, where steam exits the coke drum en route to the blowdown 
system). When the vessel has cooled sufficiently (e.g., when the coke 
drum vessel pressure reaches the desired set point), valves are opened 
to allow the steam generated in the coke drum to vent directly to the 
atmosphere rather than the closed blowdown system. This vent is 
commonly referred to as the ``coker steam vent'' and is typically the 
first direct atmospheric emission release during the decoking 
operations when an enclosed blowdown system is used. While this vent 
gas contains predominately steam, methane and ethane, a variety of HAP 
are also emitted with this steam. These HAP include light aromatics 
(e.g., benzene, toluene, and xylene) and light POM (predominately 
naphthalene and 2-methyl naphthalene). The level of HAP emitted from 
the DCU has been found to be a function of the quantity of steam 
generated (see the technical memorandum entitled Impacts Estimates for 
Delayed Coking Units in Docket ID Number EPA-HQ-OAR-2010-0682).
    In general, the next step in the decoking process is draining the 
water from the coke drum by opening a large valve at the bottom of the 
coke drum. The drain water typically falls from the coke drum onto a 
slanted concrete pad that directs the water to the coke pit area (where 
water and coke are collected and separated). Some DCU owners or 
operators initiate draining at the same time they initiate venting; 
other owners or operators may allow the vessel to vent for 20 or more 
minutes prior to initiating draining. While draining immediately may 
reduce the amount of steam exiting the unit via the stack, as explained 
below, it is not expected to alter the overall emissions from the unit. 
During the venting and draining process, the pressure of the system 
falls to atmospheric. Steam will be generated until the evaporative 
cooling effect of that steam generation cools the coker quench water to 
212[emsp14][deg]F. If draining is initiated immediately, some of the 
superheated water may drain from the DCU before being cooled. A portion 
of that drained water will then convert to steam during the draining 
process as that superheated water contacts the open atmosphere. 
Therefore, draining quickly is not expected to alter the total amount 
of steam generated from the unit nor alter the overall emissions from 
the unit. It will, however, alter the relative proportion of the 
emissions that are released via the vent versus the quench water drain 
area.
    The next step in the decoking process is ``deheading'' the coke 
drum. At the top of the coke drum is a large 3- to 5-foot diameter 
opening, which is sealed with a gasketed lid during normal operations. 
When the steam generation rate from the coke drum has sufficiently 
subsided, this gasketed lid is removed to allow access for a water 
drill that will be used to remove coke from the drum. The process of 
removing this lid is referred to as ``deheading'' the coke drum. 
Different DCU owners or operators may use different criteria for when 
to dehead the coke drum. If the coke drum is deheaded soon after 
venting is initiated, some steam and associated HAP emissions may be 
released from this opening. As with draining, it is anticipated that 
the total volume of steam generated will be a function of the 
temperature/pressure of the coke drum. Deheading the coke drum prior to 
the coke drum contents reaching 212[emsp14][deg]F will generally mean 
that some of the steam will be released from the coke drum head 
opening. However, this will not alter the total amount of steam 
generated; it merely alters the location of the release (coke drum head 
opening versus steam vent). The HAP emissions from the deheading 
process are expected to be proportional to the amount of steam released 
in the same manner as the emissions from the steam vent.
    The final step of the decoking process is coke cutting. A high-
pressure water jet is used to drill or cut the coke out of the vessel. 
The drilling water and coke slurry exits the coke drum via the drain 
opening and collects in the coke pit. Generally, the coke drum and its 
contents are sufficiently cooled so that this process is not expected 
to yield significant HAP emissions. However, if the other decoking 
steps are performed too quickly, hot spots may exist within the coke 
bed and HAP emissions may occur as water contacts these hot spots and 
additional steam and emissions are released.
    Once the coke is cut out of the drum, the drum is closed and 
prepared to go back on-line. This process includes pressurizing with 
steam to ensure there are no leaks (i.e., that the head is properly 
attached and sealed and the drain valve is fully closed). The vessel is 
then purged to remove any oxygen and heated by diverting the produced 
gas from the processing coke drum through the empty drum prior to 
sending it to the unit's distillation column. A coke drum cycle is 
typically 28 to 36 hours from start of feed to start of the next feed.
b. How Delayed Coker Vents Are Addressed in Refinery MACT 1
    Delayed coker vents are specifically mentioned as an example within 
the first paragraph of the definition of ``miscellaneous process vent'' 
in 40 CFR 63.641 of Refinery MACT 1. However, the definition of 
``miscellaneous process vent'' also excludes coking unit vents 
associated with coke drum depressuring (at or below a coke drum outlet 
pressure of 15 pounds per square inch gauge [psig]), deheading, 
draining, or decoking (coke cutting) or pressure testing after 
decoking. Refinery MACT 1 also

[[Page 36902]]

includes a definition of ``delayed coker vent'' in 40 CFR 63.641. This 
vent is typically intermittent in nature, and usually occurs only 
during the initiation of the depressuring cycle of the decoking 
operation when vapor from the coke drums cannot be sent to the 
fractionator column for product recovery, but instead is routed to the 
atmosphere through a closed blowdown system or directly to the 
atmosphere in an open blowdown system. The emissions from the decoking 
phases of DCU operations, which include coke drum deheading, draining, 
or decoking (coke cutting), are not considered to be delayed coker 
vents.
    The first paragraph of the definition of ``miscellaneous process 
vent'' also includes blowdown condensers/accumulators as an example of 
a miscellaneous process vent. Therefore, the DCU blowdown system is a 
miscellaneous process vent regardless of whether or not the blowdown 
system is associated with a DCU or another process unit. Further, the 
inclusion of the ``delayed coker vent'' as an example of a 
miscellaneous process vent makes it clear that the DCU's blowdown 
system vent (if an open blowdown system is used) is considered a 
miscellaneous process vent. It is less clear from the regulatory text 
whether the direct venting of the coke drum to the atmosphere via the 
steam vent during the final depressurization is considered to be a 
``delayed coker vent'' (i.e., whether direct venting to the atmosphere 
is equivalent to venting ``directly to the atmosphere in an open 
blowdown system'').
    The regulatory text is clear that this steam vent is exempt from 
the definition of ``miscellaneous process vent'' when the pressure of 
the vessel is less than 15 psig. It is also clear that the subsequent 
release points from the decoking operations (i.e., deheading, draining, 
and coke cutting) are excluded from both the definition of ``delayed 
coker vent'' and the definition of ``miscellaneous process vent.'' 
Further, based on the statements in the background information document 
for the August 1995 final Refinery MACT 1 rule,\26\ the 15 psig 
pressure limit for the direct venting of the DCU to the atmosphere was 
not established as a MACT floor control level; it was established to 
accommodate all DCU at whatever pressure they typically switched from 
venting to the closed blowdown system to venting directly to the 
atmosphere. Based on this information, as well as the data from the 
2011 Refinery ICR, refinery enforcement settlements and other 
information available, which indicate that all refineries depressurize 
the coke drum below 15 psig, we have determined that the direct 
atmospheric releases from the DCU decoking operations are currently 
unregulated emissions. These unregulated releases include emissions 
during atmospheric depressuring (i.e., the steam vent), deheading, 
draining, and coke cutting.
---------------------------------------------------------------------------

    \26\ National Emission Standards for Hazardous Air Pollutants 
Petroleum Refineries--Background Information for Final Standards; 
EPA-453/R-95-015b.
---------------------------------------------------------------------------

c. Evaluation of MACT Emission Limitations for Delayed Coking Units
    We evaluated emissions and controls during DCU decoking operations 
in order to identify appropriate MACT emission limitations pursuant to 
CAA section 112(d)(2) and (3). Establishing a lower pressure set point 
at which a DCU owner or operator can switch from venting to an enclosed 
blowdown system to venting to the atmosphere is the control technique 
identified for reducing emissions from delayed coking operations. 
Essentially, there is a fixed quantity of steam that will be generated 
as the coke drum and its contents cool. The lower pressure set point 
will require the DCU to vent to the closed blowdown system longer, 
where the organic HAP can be recovered or controlled. This will result 
in fewer emissions released during the venting, draining and deheading 
process.
    We consider this control technique, which is a work practice 
standard, appropriate for the DCU for the reasons discussed below for 
each of the four possible emission points at the DCU: draining, 
deheading, coke cutting and the steam vent. For the first three steps, 
the emissions cannot be emitted through a conveyance designed and 
constructed to emit or capture such pollutant. For example, during 
draining, the drain water typically falls from the coke drum onto a 
slanted concrete pad that directs the water to an open coke pit area 
(where water and coke are collected and separated). When the coke drum 
is deheaded, the coke drum head must be removed to provide an 
accessible opening in the drum so the coke cutting equipment can be 
lowered into the drum. This opening cannot be sealed during coke 
cutting because the drilling shaft will occupy the opening and the 
shaft must be free to be lowered or raised during the coke cutting 
process.
    While the emissions from the fourth point, the DCU steam vent, are 
released via a conveyance designed and constructed to emit or capture 
such pollutant, as provided in CAA section 112(h)(2)(B), it is not 
feasible to prescribe or enforce an emission standard for the DCU steam 
vent because the application of a measurement methodology for this 
source is not practicable due to technological and economic 
limitations.
    First, it is not practicable to use a measurement methodology for 
the DCU steam vent. The emissions from the vent typically contain 99 
percent water, which interferes with common sample collection and 
analysis techniques. Also, the flow rate from this vent is not 
constant; rather, it decreases during the venting process as the 
pressure in the DCU coke drum approaches atmospheric pressure. 
Additionally, the venting time can be very short. As part of the ICR, 
we requested stack testing of eight DCU. After discussions with stack 
testing experts within the agency and with outside contractors used by 
industry to perform the tests, we concluded that sources with venting 
times less than 20 minutes would not be able to perform an emissions 
test that would yield valid results. Therefore, only two of the eight 
facilities actually performed the tests. We anticipate all units 
complying with the proposed standards for DCU steam vents would vent 
for less than 20 minutes.
    Second, it is not feasible to enforce an emission standard only on 
the steam vent because the timing of drainage and deheading can alter 
the portion of the decoking emissions that are released from the actual 
steam vent. If draining and deheading are initiated quickly after 
venting, this will reduce the emissions discharged from the vent 
(although as explained above, it does not reduce the emissions from the 
collective set of decoking operations release points).
    Consequently, due to the unique nature of DCU emissions, the 
difficulties associated with monitoring the DCU steam vent, and the 
inability to construct a conveyance to capture emissions from all 
decoking release points, we are proposing that it is appropriate to 
develop work practice standards in place of emission limits for the 
DCU.
    To establish the MACT floor, we then reviewed regulations, permits 
and consent decrees that require coke controls. Refinery NSPS Ja 
establishes a pressure limit of 5 psig prior to allowing the coke drum 
to be vented to the atmosphere. Based on a review of permit limits and 
consent decrees, we found that coke drum vessel pressure limits have 
been established (and achieved) as low as 2 psig. There are 75 
operating DCU according to the Refinery ICR responses, so the sixth 
percentile is represented by the fifth-best performing DCU. We 
identified eight DCU with

[[Page 36903]]

permit requirements or consent decrees specifying a coke drum venting 
pressure limit of 2 psig; we did not identify any permit or consent 
decree requirements more stringent than 2 psig. Refinery owners and 
operators were asked to provide the ``typical coke drum pressure just 
prior to venting'' for each DCU in their responses to the Refinery ICR, 
and the responses indicate that four DCU operate such that the typical 
venting pressure is 1 psig or less. However, this ``typical coke drum 
pressure'' does not represent a not-to-be-exceeded pressure limit; it 
is expected that these units are operated this way to meet a pressure 
limit of 2 psig. We do not have information to indicate whether these 
facilities are always depressurized at 1 psig or less. Moreover, there 
were only four units for which a typical venting pressure of 1 psig was 
identified and the MACT floor for existing sources is represented by 
the fifth-best operating DCU, not the best-performing unit. Therefore, 
we are proposing that the MACT floor for DCU decoking operations is to 
depressure at 2 psig or less prior to venting to the atmosphere for 
existing sources. We are also proposing that the MACT floor for new 
sources is 2 psig, since the best-performing source is permitted to 
depressure at 2 psig or less. For additional details on the MACT floor 
analysis, see memorandum entitled MACT Analysis for Delayed Coking Unit 
Decoking Operations in Docket ID Number EPA-HQ-OAR-2010-0682.
    We then considered control options beyond the floor level of 2 psig 
to determine if additional emission reductions could be cost-
effectively achieved. We considered establishing a venting pressure 
limit of 1 psig or less, since four facilities reported in the ICR that 
the typical coke drum pressure prior to depressurizing was 1 psig. 
There are several technical difficulties associated with establishing a 
pressure limit at this lower level. First, the lowest pressure at any 
point in a closed blowdown system is generally designed to be no lower 
than 0.5 psig. Consequently, the DCU compressor system would operate 
with an inlet pressure of no less than 0.5 psig. Second, there are 
several valves and significant piping (for cooling and condensing 
steam) between the DCU drum and the recovery compressor. There is an 
inherent pressure drop when a fluid flows through a pipe or valve. Two 
valves are used for all DCU lines to make sure that the unit is either 
blocked off from the processing fluids or blocked in so there are no 
product losses out the steam line during processing. Considering the 
need for two valves and piping needed in the cooling system, DCU 
designed for a minimal pressure loss will generally still have a 0.5 to 
1 psig pressure drop between the DCU drum and the recovery compressor 
inlet, even for a new DCU designed to minimize this pressure drop. 
Finally, in order to meet a 1 psig pressure limit at all times, the DCU 
closed vent system would need to be designed to achieve a vessel 
pressure of approximately 0.5 psig. Given the above considerations, it 
is not technically feasible for new or existing DCU to routinely 
achieve a vessel pressure of 0.5 psig in order to comply with a never-
to-be-exceeded drum vessel pressure of 1 psig. As noted previously, 
facilities that ``typically'' achieve vessel pressures of about 1 psig 
or less are expected to do so in order to meet a never-to-be-exceeded 
drum vessel pressure limit of 2 psig and they are not expected to be 
able to comply with a never-to-be-exceeded drum vessel pressure limit 
of 1 psig.
    We considered setting additional work practice standards regarding 
draining, deheading, and coke cutting. The decoking emissions can be 
released from a variety of locations, and the 2-psig-or-less limit for 
depressurizing the coke drum will effectively reduce the emissions from 
all of these emission points, provided that atmospheric venting via the 
DCU steam vent is the first step in the decoking process. However, it 
is possible to start draining water prior to opening the steam vent. We 
are concerned that owners or operators may adopt this practice as a 
means to reduce pressure in the coke drum prior to venting the drum to 
the atmosphere. Initiating water draining prior to reaching 2 psig 
would result in draining water that is hotter than it would be had the 
drum been sufficiently cooled (i.e., the pressure limit achieved) prior 
to draining the vessel, effectively diverting HAP emissions to the 
water drain area rather than capturing these HAP in the enclosed 
blowdown system, where they can be either recovered or controlled. 
Therefore, we are proposing that the coke drum must reach 2 psig or 
less prior to any decoking operations, which includes atmospheric 
venting, draining, deheading, and coke cutting.
    We could not identify any other emission reduction options that 
could lower the emissions from the DCU decoking operations. Since we 
could not identify a technically feasible control option beyond the 
MACT floor, we determined that the MACT floor pressure limit of 2 psig 
is MACT for existing sources. We also determined that the same 
technical limitations of going beyond the 2 psig pressure limit for 
existing sources exist for new sources; therefore we determined that 
the MACT floor pressure limit of 2 psig is MACT for new sources. We 
request comment on whether depressurizing to 2 psig prior to venting to 
the atmosphere is the appropriate MACT floor and whether it is 
appropriate to include restrictions for the other three decoking 
operations draining, deheading and coke cutting, in the MACT 
requirements. We request comments on whether we have adequately 
interpreted the information that indicates that there is currently no 
applicable MACT floor for delayed coking. If Refinery MACT 1 currently 
provided standards for DCU based on the MACT floor, we would evaluate 
whether it is necessary to revise such delayed coking standards under 
the risk and technology review requirements of the Act (i.e., CAA 
section 112(f) and 112(d)(6)) as discussed later in this preamble.
    Finally, we request comment and supporting information on any other 
practices that may be used to limit emissions during the decoking 
operations.
d. Evaluation of Cost and Environmental Impacts of MACT Emission 
Limitations for Delayed Coking Units
    DCU that cannot currently meet the 2 psig pressure limit would be 
expected to install a device (compressor or steam ejector system) to 
lower the DCU vessel pressure. In the Refinery NSPS Ja impact analysis, 
facilities not able to meet the pressure threshold were assumed to 
purchase and install a larger compressor to lower the blowdown system 
pressure. Other approaches to lowering blowdown system (and coke drum) 
pressure exist. Specifically, steam ejectors have been identified as a 
method to help existing units depressurize more fully in order to 
achieve a set vessel pressure or drum bed temperature. Upgrading the 
closed vent system to reduce pressure losses or to increase steam 
condensing capacity may also allow the DCU to depressurize more quickly 
while the emissions are still vented to the closed blowdown system. 
This is important because delays in the decoking operations may impact 
process feed rates. That is, if the decoking and drum preparation steps 
take too long, the feed rate to the other coke unit must be reduced to 
prevent overfilling one coke drum prior to being able to switch to the 
other coke drum. This issue is less critical for DCU that operate with 
3 or 4 drums per distillation column, but a consistent increase in the 
decoking times across all

[[Page 36904]]

drums may still limit the capacity of the DCU at some petroleum 
refineries.
    For existing sources, we assumed all DCU that reported a ``typical 
drum pressure prior to venting'' of more than 2 psig would install and 
operate a steam ejector system to reduce the coke drum pressure to 2 
psig prior to venting to atmosphere or draining.
    The operating costs of the steam ejector system are offset, to some 
extent, by the additional recovered vapors. Vapors from the additional 
gases routed to the blowdown system contain high levels of methane 
(approximately 70 percent by volume on a dry basis) based on DCU steam 
vent test data. If these vapors are directed to the closed blowdown 
system rather than to the atmosphere, generally the dry gas can be 
recovered in the refinery fuel gas system or light-ends gas plant. This 
recovered methane is expected to off-set natural gas purchases for the 
fuel gas system.
    For new sources, it is anticipated that the DCU's closed vent 
system could be designed to achieve a 2 psig vessel pressure with no 
significant increase in capital or operating costs. Designing the 
system to vent at a lower pressure would also result in additional 
vapor recovery, which is expected to off-set any additional capital 
costs associated with the low pressure design closed vent system.
    The costs of complying with the 2 psig coke drum threshold prior to 
venting or draining are summarized in Table 2 of this preamble. The 
costs are approximately $1,000 per ton of VOC reduced and approximately 
$5,000 per ton of organic HAP reduced when considering VOC and methane 
recovery credits. In addition to VOC and HAP reductions, the proposed 
control option will result in a reduction in methane emissions of 
18,000 tpy or 343,000 metric tonnes per year of carbon dioxide 
equivalents (CO2e), assuming a global warming potential of 
21 for methane.

               Table 2--Nationwide Emissions Reduction and Cost Impacts of Control Option for Delayed Coking Units at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                 Total
                                                                         Annualized                                            annualized   Overall cost
                                                                           costs                                               costs with  effectiveness
                                                             Capital      without     Emissions    Emissions        Cost          VOC         with VOC
                      Control option                           cost       recovery    reduction,   reduction,  effectiveness    recovery      recovery
                                                           (million $)    credits     VOC  (tpy)   HAP  (tpy)    ($/ton HAP)     credit     credit  ($/
                                                                        (million $/                                           (million $/     ton HAP)
                                                                            yr)                                                   yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2 psig...................................................           52         10.2        4,250          850        12,000          3.98         4,700
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. CRU Vents
    A CRU is designed to reform (i.e., change the chemical structure 
of) naphtha into higher-octane aromatics. Over time, coke deposits form 
on the reforming catalyst, which reduces the catalyst activity. When 
catalyst activity is reduced to a certain point, the catalyst is 
regenerated by burning the coke off of the catalyst. Prior to this coke 
burn-off process, the catalyst (or reactor vessel containing the 
catalyst) must be removed from active service and organics remaining on 
the catalyst (or in the reactor) must be purged from the system. This 
is generally accomplished by depressurizing the vessel to a certain 
vessel pressure, then re-pressurizing the vessel with nitrogen and 
depressurizing the vessel again. The re-pressurization and 
depressurization process is repeated several times until all organics 
have been purged from the system. The organic HAP emissions from this 
depressurization/purge cycle vent are typically controlled by directing 
the purge gas directly to the CRU process heater or venting the gas to 
a flare.
    Refinery MACT 2 requires a 98-percent reduction of organic HAP 
measured as total organic carbon (TOC) or non-methane TOC or an outlet 
concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-
percent oxygen), whichever is less stringent, for this CRU 
depressurization/purge cycle vent (purging prior to coke-burn-off). The 
emission limits for organic HAP for the CRU do not apply to emissions 
from process vents during depressuring and purging operations when the 
reactor vent pressure is 5 psig or less. The Refinery MACT 2 
requirements were based on the typical operation of CRU utilizing 
sequential pressurization and passive depressurization. The 5 psig 
pressure limit exclusion was provided based on state permit conditions, 
which recognized that depressurization to an APCD (without other active 
motive of flow) is limited by the back pressure of the control system, 
which is often a flare or process heater. Source testing information 
collected from the 2011 Refinery ICR indicates that facilities have 
interpreted the rule to allow the 5 psig pressure limit exclusion to be 
used by units using active purging techniques (such as continuous 
nitrogen purge or vacuum pump on the CRU reactor at low pressures) to 
discharge to the atmosphere without emission controls. The information 
collected indicates that HAP emissions from a continuous, active 
purging technique could result in emissions of HAP from CRU 
depressurization vents much higher than expected to be allowed under 
the Refinery MACT 2 requirements, which presumed sequential re-
pressurization and purging cycles. The testing information received 
indicated that at one facility, the active purge vent had non-methane 
TOC concentrations of 700 to 10,000 ppmv (dry basis, as hexane, 
corrected to 3-percent oxygen) compared to less than 10 ppmv for the 
typical passive purge vent tested. The annual HAP emissions for the CRU 
with the active purge vent were estimated to exceed 10 tpy, while a 
comparable unit using the cyclic re-pressurization and passive 
depressurization purge technique is projected to have HAP emissions of 
less than 0.1 tpy.
    Therefore, we are proposing to amend the exclusion in 40 CFR 
63.1566(a)(4) to clarify the application of the 5 psig exclusion, 
consistent with the MACT floor under CAA section 112(d)(2) and (3). 
Specifically, we are limiting the vessel pressure limit exclusion to 
apply only to passive vessel depressurization. Units utilizing active 
purging techniques have a motive of flow that can be used to direct the 
purge gas to a control system, regardless of the CRU vessel pressure. 
If a CRU owner or operator uses active purging techniques (e.g., a 
continual nitrogen purge) or active vessel depressurization (e.g., 
vacuum pump), then the 98-percent reduction or 20 ppmv TOC emission 
limits would apply to these discharges regardless of the vessel 
pressure.
3. Refinery Flares
    The EPA is proposing under CAA section 112(d)(2) and (3) to amend 
the operating and monitoring requirements for petroleum refinery 
flares. We have determined that the current requirements for flares are 
not adequate to ensure compliance with the Refinery MACT standards. In 
the development of Refinery MACT 1, the EPA determined that the average 
emission limitation achieved by the best-performing 12

[[Page 36905]]

percent of existing sources was established as the use of combustion 
controls for miscellaneous process vents. Further, the EPA stated that 
``data analyses conducted in developing previous NSPS and the [National 
Emission Standards for Organic Hazardous Air Pollutants (40 CFR part 
63, subparts F, G, and H)] HON determined that combustion controls can 
achieve 98-percent organic HAP reduction or an outlet organic HAP 
concentration of 20 ppmv for all vent streams'' (59 FR 36139, July 15, 
1994). The requirements applicable to flares at refineries are set 
forth in the General Provisions to 40 CFR part 63 and are cross-
referenced in Refinery MACT 1 and 2. In general, flares used as APCD 
were expected to achieve 98-percent HAP destruction efficiencies when 
designed and operated according to the requirements in the General 
Provisions. Recent studies on flare performance, however, indicate that 
these General Provisions requirements are inadequate to ensure proper 
performance of refinery flares, particularly when assist steam or 
assist air is used. Over the last decade, flare minimization efforts at 
petroleum refineries have led to an increasing number of flares 
operating at well below their design capacity, and while this effort 
has resulted in reduced flaring of gases at refineries, situations of 
over-assisting with steam or air have become exacerbated, leading to 
the degradation of flare combustion efficiency. Therefore, these 
amendments are necessary to ensure that refineries that use flares as 
APCD meet the MACT standards at all times when controlling HAP 
emissions.
    Refinery MACT 1 and 2 require flares used as an APCD to meet the 
operational requirements set forth in the General Provisions at 40 CFR 
63.11(b). These General Provisions requirements specify that flares 
shall be: (1) Steam-assisted, air-assisted, or non-assisted; (2) 
operated at all times when emissions may be vented to them; (3) 
designed for and operated with no visible emissions (except for periods 
not to exceed a total of 5 minutes during any 2 consecutive hours); and 
(4) operated with the presence of a pilot flame at all times. The 
General Provisions also specify requirements for both the minimum heat 
content of gas combusted in the flare and maximum exit velocity at the 
flare tip. The General Provisions only specify monitoring requirements 
for the presence of the pilot flame and the operation of a flare with 
no visible emissions. For all other operating limits, Refinery MACT 1 
and 2 require an initial performance evaluation to demonstrate 
compliance but there are no specific monitoring requirements to ensure 
continuous compliance. As noted previously, flare performance tests 
conducted over the past few years suggest that the current regulatory 
requirements are insufficient to ensure that refinery flares are 
operating consistently with the 98-percent HAP destruction efficiencies 
that we determined were the MACT floor.
    In 2012, the EPA compiled information and test data collected on 
flares and summarized its preliminary findings on operating parameters 
that affect flare combustion efficiency (see technical report, 
Parameters for Properly Designed and Operated Flares, in Docket ID 
Number EPA-HQ-OAR-2010-0682). The EPA submitted the report, along with 
a charge statement and a set of charge questions to an external peer 
review panel.\27\ The panel concurred with the EPA's assessment that 
three primary factors affect flare performance: (1) The flow of the 
vent gas to the flare; (2) the amount of assist media (e.g., steam or 
air) added to the flare; and (3) the combustibility of the vent gas/
assist media mixture in the combustion zone (i.e., the net heating 
value, lower flammability, and/or combustibles concentration) at the 
flare tip.
---------------------------------------------------------------------------

    \27\ These documents can also be found at http://www.epa.gov/ttn/atw/petref.html.
---------------------------------------------------------------------------

    Following is a discussion of requirements we are proposing for 
refinery flares, along with impacts and costs associated with these new 
requirements. Specifically, this action proposes that refinery flares 
operate pilot flame systems continuously and with automatic re-ignition 
systems and that refinery flares operate with no visible emissions. In 
addition, this action also consolidates requirements related to flare 
tip velocity and proposes new operational and monitoring requirements 
related to the combustion zone gas. Prior to these proposed amendments, 
Refinery MACT 1 and 2 cross-reference the General Provisions 
requirements at 40 CFR 63.11(b) for the operational requirements for 
flares used as APCD. Rather than revising the General Provisions 
requirements for flares, which would impact dozens of different source 
categories, this proposal will specify all refinery flare operational 
and monitoring requirements specifically in Refinery MACT 1 and cross-
reference these same requirements in Refinery MACT 2. All of the 
requirements for flares operating at petroleum refineries in this 
proposed rulemaking are intended to ensure compliance with the Refinery 
MACT 1 and 2 standards when using a flare as an APCD.
a. Pilot Flames
    Refinery MACT 1 and 2 reference the flare requirements in the 
General Provisions, which require a flare used as an APCD device to 
operate with a pilot flame present at all times. Pilot flames are 
proven to improve flare flame stability; even short durations of an 
extinguished pilot could cause a significant reduction in flare 
destruction efficiency. In this action, we are proposing to remove the 
cross-reference to the General Provisions and instead include the 
requirement that flares operate with a pilot flame at all times and be 
continuously monitored for using a thermocouple or any other equivalent 
device in Refinery MACT 1 and 2. We are also proposing to amend 
Refinery MACT 1 and 2 to add a new operational requirement to use 
automatic relight systems for all flare pilot flames. An automatic 
relight system provides a quicker response time to relighting a 
snuffed-out flare compared to manual methods and thereby results in 
improved flare flame stability. In comparison, manual relighting is 
much more likely to result in a longer period where the pilot remains 
unlit. Because of safety issues with manual relighting, we anticipate 
that nearly all refinery flares are already equipped with an automated 
device to relight the pilot flame in the event it is extinguished. 
Also, due to the possibility that a delay in relighting the pilot could 
result in a flare not meeting the 98-percent destruction efficiency for 
the period when the pilot flame is out, we are proposing to amend 
Refinery MACT 1 and 2 to add this requirement to ensure that the pilot 
operates at all times.
b. Visible Emissions
    Refinery MACT 1 and 2 reference the flare requirements in the 
General Provisions, which require a flare used as an APCD to operate 
with visible emissions for no more than 5 minutes in a 2-hour period. 
Owners or operators of these flares are required to conduct an initial 
performance demonstration for visible emissions using EPA Method 22 of 
40 CFR part 60, Appendix A-7. We are proposing to remove the cross-
reference to the General Provisions and include the limitation on 
visible emissions in Refinery MACT 1 and 2. In addition, we are 
proposing to amend Refinery MACT 1 and 2 to add a requirement that a 
visible emissions test be conducted each day and whenever visible 
emissions are observed from the flare. We are proposing that owners or

[[Page 36906]]

operators of flares monitor visible emissions at a minimum of once per 
day using an observation period of 5 minutes and EPA Method 22 of 40 
CFR part 60, Appendix A-7. Additionally, any time there are visual 
emissions from the flare, we are proposing that another 5-minute 
visible emissions observation period be performed using EPA Method 22 
of 40 CFR part 60, Appendix A-7, even if the minimum required daily 
visible emission monitoring has already been performed. For example, if 
an employee observes visual emissions or receives notification of such 
by the community, the owner or operator of the flare would be required 
to perform a 5-minute EPA Method 22 observation in order to check for 
compliance upon initial observation or notification of such event. We 
are also proposing that if visible emissions are observed for greater 
than one continuous minute during any of the required 5-minute 
observation periods, the monitoring period shall be extended to 2 
hours.
    Industry representatives have suggested to the EPA that flare 
combustion efficiency is highest at the incipient smoke point (the 
point at which black smoke begins to form within the flame). They 
stated that the existing limit for visible emissions could be increased 
from 5 minutes to 10 minutes in a 2-hour period to encourage operation 
near the incipient smoke point (see memorandum, Meeting Minutes for 
February 19, 2013, Meeting Between the U.S. EPA and Representatives 
from the Petroleum Refining Industry, in Docket ID Number EPA-HQ-OAR-
2010-0682). While we agree that operating near the incipient smoke 
point results in good combustion at the flare tip, we disagree that the 
allowable period for visible emissions be increased from 5 to 10 
minutes for a 2-hour period. Smoking flares can contribute 
significantly to emissions of particulate matter 2.5 micrometers in 
diameter and smaller (PM2.5) emissions, and we are concerned 
that increasing the allowable period of visible emissions from 5 
minutes to 10 minutes for every 2-hour period could result in an 
increase in the PM2.5 emissions from flares.
    As discussed later in this section, we are proposing additional 
operational and monitoring requirements for refinery flares which we 
expect will result in refineries installing equipment that can be used 
to fine-tune and control the amount of assist steam or air introduced 
at the flare tip such that combustion efficiency of the flare will be 
maximized. These monitoring and control systems will assist refinery 
flare owners or operators operating near the incipient smoke point 
without exceeding the visible emissions limit. While combustion 
efficiency may be highest at the incipient smoke point, it is not 
significantly higher than the combustion efficiency achieved by these 
proposed operating limits, discussed in section IV.A.3.d of this 
preamble. As seen in the performance curves for flares (see technical 
memorandum, Petroleum Refinery Sector Rule: Operating Limits for 
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682), there is very 
limited improvement in flare performance beyond the performance 
achieved at these proposed operating limits. We solicit comments and 
data on appropriate periods of visible emissions that would encourage 
operation at the incipient smoke point while not significantly 
increasing PM2.5 emissions.
c. Flare Tip Velocity
    The General Provisions at 40 CFR 63.11(b) specify maximum flare tip 
velocities based on flare type (non-assisted, steam-assisted, or air-
assisted) and the net heating value of the flare vent gas. These 
maximum flare tip velocities are required to ensure that the flame does 
not ``lift off'' the flare, which could cause flame instability and/or 
potentially result in a portion of the flare gas being released without 
proper combustion. We are proposing to remove the cross-reference to 
the General Provisions and consolidate the requirements for maximum 
flare tip velocity into Refinery MACT 1 and 2 as a single equation, 
irrespective of flare type (i.e., steam-assisted, air-assisted or non-
assisted). Based on our analysis of the various studies for air-
assisted flares, we identified air-assisted test runs with high flare 
tip velocities that had high combustion efficiencies (see technical 
memorandum, Petroleum Refinery Sector Rule: Evaluation of Flare Tip 
Velocity Requirements, in Docket ID Number EPA-HQ-OAR-2010-0682). These 
test runs exceeded the maximum flare tip velocity limits for air-
assisted flares using the linear equation in 40 CFR 63.11(b)(8). When 
these test runs were compared with the test runs for non-assisted and 
steam-assisted flares, the air-assisted flares appeared to have the 
same operating envelope as the non-assisted and steam-assisted flares. 
Therefore, we are proposing that air-assisted flares at refineries use 
the same equation that non-assisted and steam-assisted flares currently 
use to establish the flare tip velocity operating limit.
    In developing these proposed flare tip velocity requirements, we 
considered whether any adjustments to these velocity equations were 
necessary. The flare tip velocity equations require the input of the 
net heating value of the vent gas going to the flare, as opposed to the 
net heating value of the gas mixture at the flare tip (i.e., the 
combustion zone gas). As discussed later in this section, we found that 
the performance of the flare was much more dependent on the net heating 
value of the gas mixture in the combustion zone than on the net heating 
value of only the vent gas going into the flare (excluding all assist 
media). We considered replacing the term in the velocity equation for 
the net heating value of the vent gas going into the flare with the net 
heating value of the gas mixture in the combustion zone. However, the 
steam addition rates were not reported for the tests conducted to 
evaluate flame stability as a function of flare tip velocity, so direct 
calculation of all the terms needed for calculating the net heating 
value in the combustion zone could not be made. At higher flare tip 
velocities, we expect that the steam assist rates would be small in 
comparison to the total vent gas flow rate, so there would not be a 
significant difference between the net heating value of the vent gas 
going into the flare and the combustion zone gas net heating value for 
the higher velocity flame stability tests. We request comment on the 
need and/or scientific reasons to use the flare vent gas net heating 
value versus the combustion zone net heating value when determining the 
maximum allowable flare tip velocity.
    In the 2012 flare peer review, we also discussed the effect of 
flame lift off and velocity on flare flame stability (see technical 
report, Parameters for Properly Designed and Operated Flares, in Docket 
ID Number EPA-HQ-OAR-2010-0682). In looking at ways of trying to 
prohibit flame instability, we examined the use of the Shore equation 
as a means to limit flare tip velocity. However, after receiving many 
comments on use of this equation from the peer reviewers, the 
uncertainty with how well the Shore equation models the large range of 
flare operation, and the limited dataset with which recent testing used 
high velocities (all recent test runs were performed at 10 feet per 
second or less), we determined that use of the existing velocity 
equation discussed above was still warranted.
    We are also proposing for Refinery MACT 1 and 2 to not include the 
special flare tip velocity equation in the General Provisions at 40 CFR 
63.11(b)(6)(i)(A) for non-assisted flares with hydrogen content greater 
than 8 percent. This equation, which was developed based on limited 
data from a chemicals manufacturer, has very limited

[[Page 36907]]

applicability for petroleum refinery flares in that it only provides an 
alternative for non-assisted flares with large quantities of hydrogen. 
Approximately 90 percent of all refinery flares are either steam- or 
air-assisted. Furthermore, we are proposing compliance alternatives in 
this section that we believe provide a better way for flares at 
petroleum refineries with high hydrogen content to comply with the rule 
while ensuring proper destruction performance of the flare (see section 
IV.A.3.d of this preamble for additional details). Therefore, we are 
proposing to not include this special flare tip velocity equation as a 
compliance alternative for refinery flares. We request comment on the 
need to include this equation. If a commenter supports inclusion of 
this equation, we request that the commenter submit supporting 
documentation regarding the vent gas composition and flows and, if 
available, combustion efficiency determinations that indicate that this 
additional equation is needed and is appropriate for refinery flares. 
We also request documentation that the maximum allowable flare tip 
velocity predicted by this equation adequately ensures proper 
combustion efficiency.
    The General Provisions require an initial demonstration that a 
flare used as an APCD meets the applicable flare tip velocity 
requirement in 40 CFR 63.11(b). However, most refinery flares can have 
highly variable vent gas flows and a single initial demonstration is 
insufficient to demonstrate continuous compliance with the flare tip 
velocity requirement. Consequently, we are proposing to amend Refinery 
MACT 1 and 2 to require continuous monitoring to determine flare tip 
velocity, calculated by monitoring the flare vent gas volumetric flow 
rate and dividing by the cross-sectional area of the flare tip. As an 
alternative to installing continuous volumetric flow rate monitors, we 
are proposing that the owner or operator may elect to install a 
pressure- and temperature-monitoring system and use engineering 
calculations to determine the flare tip velocity.
d. Refinery Flare Operating and Monitoring Requirements
    The current requirements for flares in the General Provisions 
specify that the flare vent gas must meet a minimum net heating value 
of 200 British thermal units per standard cubic foot (Btu/scf) for non-
assisted flares and 300 Btu/scf for air- and steam-assisted flares. 
Refinery MACT 1 and 2 reference these requirements, but neither the 
General Provisions nor Refinery MACT 1 and 2 include specific 
monitoring requirements to monitor the net heating value of the vent 
gas. Moreover, recent flare testing results indicate that this 
parameter alone does not adequately address instances when the flare 
may be over-assisted since it only considers the gas being combusted in 
the flare and nothing else (e.g., no assist media). However, many 
industrial flares use steam or air as an assist medium to protect the 
design of the flare tip, promote turbulence for the mixing, induce air 
into the flame and operate with no visible emissions. Using excessive 
steam or air results in dilution and cooling of flared gases and can 
lead to operating a flare outside its stable flame envelope, reducing 
the destruction efficiency of the flare. In extreme cases, over-
steaming or excess aeration can actually snuff out a flame and allow 
regulated material to be released into the atmosphere completely 
uncombusted. Since approximately 90 percent of all flares at refineries 
are either steam- or air-assisted, it is critical that we ensure the 
assist media be accounted for in some form or fashion. Recent flare 
test data have shown that the best way to account for situations of 
over-assisting is to consider the properties of the mixture of all 
gases at the flare tip in the combustion zone when evaluating the 
ability to combust efficiently. As discussed in the introduction to 
this section, the external peer review panel concurred with our 
assessment that the combustion zone properties at the flare tip are 
critical parameters to know in determining whether a flare will achieve 
good combustion. The General Provisions, however, solely rely on the 
net heating value of the flare vent gas.
    We are proposing to add definitions of two key terms relevant to 
refinery flare performance. First, we are proposing to define ``flare 
vent gas'' to include all waste gas, sweep gas, purge gas and 
supplemental gas, but not include pilot gas or assist media. We are 
proposing this definition because information about ``flare vent gas'' 
(e.g., flow rate and composition) is one of the necessary inputs needed 
to evaluate the make-up of the combustion zone gas. To that end, we are 
also proposing to define the ``combustion zone gas'' as flare vent gas 
plus the total steam-assist media and premix assist air that is 
supplied to the flare.
    Based on our review of the recent flare test data, we have 
determined that the following combustion zone operational limits can be 
used to determine good combustion: Net heating value (Btu/scf), lower 
flammability limit (LFL) or a total combustibles fraction (e.g., a 
simple carbon count). In this action, we are proposing these new 
operational limits, along with methods for determining these limits in 
the combustion zone at the flare tip for steam-assisted, air-assisted 
and non-assisted flares to ensure that there is enough combustible 
material readily available to achieve good combustion.
    For air-assisted flares, use of too much perimeter assist air can 
lead to poor flare performance. Based on our analysis, we found that 
including the flow rate of perimeter assist air in the calculation of 
combustion zone operational limits in itself does not identify all 
instances of excess aeration. The data suggest that the diameter of the 
flare tip, in concert with the amount of perimeter assist air, provides 
the inputs necessary to calculate whether or not this type of flare is 
over-assisted. Therefore, we are proposing that in addition to 
complying with combustion zone operational limits to ensure that there 
is enough combustible material available to adequately combust the gas 
and pass through the flammability region, air-assisted flares would 
also comply with an additional dilution parameter that factors in the 
flow rate of the flare vent gas, flow rates of all assist media 
(including perimeter assist air), and diameter of flare tip to ensure 
that degradation of flare performance from excess aeration does not 
occur. This dilution parameter is consistent with the combustion theory 
that the more ``time'' the gas spends in the flammability region above 
the flare tip, the better it will combust. Also, since both the volume 
of the combustion zone (represented by the diameter here) and how 
quickly this gas is diluted to a point below the flammability region 
(represented by perimeter assist air flow rate) characterize this 
``time,'' it makes sense that we propose such a term (see technical 
memorandum, Petroleum Refinery Sector Rule: Operating Limits for 
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
    It should be noted that in the 2012 flare peer review report, we 
considered a limit for perimeter assist air via the stoichiometric air 
ratio. This stoichiometric air ratio is the ratio of the actual mass 
flow rate of assist air to the theoretical stoichiometric mass flow 
rate of air (based on complete chemical combustion of fuel to carbon 
dioxide (CO2) and water) needed to combust the flare vent 
gas. However, we are not proposing to include this term as part of the 
calculation methodology, as we have determined that the dilution 
parameter discussed in this section better assures that air-assisted 
flare performance is not degraded due to excess aeration.

[[Page 36908]]

    The proposed rule allows the owner or operator flexibility to 
select the form of the combustion zone operational limit (i.e., net 
heating value, LFL, or total combustibles fraction) with which to 
comply in order to provide facilities the option of using monitors they 
may already have in place. The monitoring methods we are proposing take 
into account the combustible properties of all gas going to the flare 
(i.e., flare vent gas, assist gas, and premix air) that affects 
combustion efficiency, and they can be used to determine whether a 
flare has enough combustible material to achieve the desired level of 
control (and whether it is being over-assisted). These methods require 
the owner or operator to input the flow of the vent gas to the flare, 
the characteristics of the vent gas going to the flare (i.e., either a 
heat content (Btu/scf), LFL, or total combustible fuel content, 
depending on how the operational limit is expressed), and the flow of 
assist media added to the flare.
    To estimate the LFL, we are proposing to use a calculation method 
based on the Le Chatelier equation. The Le Chatelier calculation uses 
the reciprocal of the volume-weighted average over the LFL of the 
individual compounds in the gas mixture to estimate the LFL of the gas 
mixture. Although Le Chatelier's equation was originally limited to 
binary mixtures of combustible gases, we are proposing a method that 
was developed by Karim, et al. (1985) and assumes a LFL of infinity for 
inert gases. We are also aware of other methods and/or adjustments that 
can be made to the Le Chatelier equation in order to calculate a more 
accurate estimate of the LFL of a gas mixture (see technical 
memorandum, Parameters for Properly Designed and Operated Flares, in 
Docket ID Number EPA-HQ-OAR-2010-0682). We are soliciting comment on 
the use of this proposed method.
    Recent data indicate that one set of operational limits may not be 
sufficient for all refinery flares. Flares that receive vent gas 
containing significant levels of both hydrogen and olefins often 
exhibit lower combustion efficiencies than flares that receive vent gas 
with only one (or none) of these compounds. Therefore, we are proposing 
more stringent operational limits for flares that simultaneously 
receive vent gas containing significant levels of both hydrogen and 
olefins (see technical memorandum, Petroleum Refinery Sector Rule: 
Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). 
Although the minimum net heating value in the combustion zone (i.e., 
Btu/scf) is a good indicator of combustion efficiency, as noted in the 
flare peer review report, the LFL and combustibles concentration (or 
total combustibles) in the combustion zone are also good indicators of 
flare combustion efficiency. For some gas mixtures, such as gases with 
high hydrogen content, the LFL or combustibles concentration in the 
combustion zone may be better indicators of performance than net 
heating value. Consequently, we are proposing operational limits 
expressed all three ways, along with associated monitoring requirements 
discussed later in this section.
    The three operating limits were established in such a way that each 
limit is protective on its own. As such, the owner or operator may 
elect to comply with any of the three alternative operating limits at 
any time, provided they use a monitoring system capable of determining 
compliance with each of the proposed alternative operating limits on 
which they rely (see technical memorandum, Petroleum Refinery Sector 
Rule: Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-
0682). For example, the owner or operator may elect to install 
monitoring for only one of the three alternative operating limits, in 
which case the owner or operator must comply with that selected 
operating limit at all times. If the owner or operator installs a 
system capable of monitoring for all three of the alternative operating 
limits, the owner or operator can choose which of the three operating 
limits the source will rely on to demonstrate compliance.
    A summary of the operating limits specified in this proposed rule 
is provided in Table 3 of this preamble. We are proposing that owners 
or operators of flares used as APCD would conduct an initial 
performance test to determine the values of the parameters to be 
monitored (e.g., the flow rate and heat content of the incoming flare 
vent gas, the assist media flow rate, and pre-mix air flow rate, if 
applicable) in order to demonstrate continuous compliance with the 
operational limits in Table 3. We are proposing to require owners or 
operators to record and calculate 15-minute block average values for 
these parameters. Our rationale for selecting a 15-minute block 
averaging period is provided in section IV.A.3.e of this preamble.

      Table 3--Operating Limits for Flares in This Proposed Action
------------------------------------------------------------------------
                                Operating limits:     Operating limits:
                                 Flares without          Flares with
   Operating parameter \a\       hydrogen-olefin       hydrogen-olefin
                                 interaction \b\       interaction \b\
------------------------------------------------------------------------
                Combustion zone parameters for all flares
------------------------------------------------------------------------
NHVcz.......................  >=270 Btu/scf.......  >=380 Btu/scf.
LFLcz.......................  <=0.15 volume         <=0.11 volume
                               fraction.             fraction.
Ccz.........................  >=0.18 volume         >=0.23 volume
                               fraction.             fraction.
------------------------------------------------------------------------
        Dilution parameters for flares using perimeter assist air
------------------------------------------------------------------------
NHVdil......................  >=22 Btu/ft\2\......  >=32 Btu/ft\2\.
LFLdil......................  <=2.2 volume          <=1.6 volume
                               fraction/ft.          fraction/ft.
Cdil........................  >=0.012 volume        >=0.015 volume
                               fraction-ft.          fraction-ft.
------------------------------------------------------------------------
\a\ The operating parameters are:
NHVcz = combustion zone net heating value.
LFLcz = combustion zone lower flammability limit.
Ccz = combustion zone combustibles concentration.
NHVdil = net heating value dilution parameter.
LFLdil = lower flammability limit dilution parameter.
Cdil = combustibles concentration dilution parameter.
\b\ Hydrogen-Olefin interactions are assumed to be present when the
  concentration of hydrogen and olefins in the combustion zone exceed
  all three of the following criteria:
(1) The concentration of hydrogen in the combustion zone is greater than
  1.2 percent by volume.
(2) The cumulative concentration of olefins in the combustion zone is
  greater than 2.5 percent by volume.

[[Page 36909]]

 
(3) The cumulative concentration of olefins in the combustion zone plus
  the concentration of hydrogen in the combustion zone is greater than
  7.4 percent by volume.
Btu/ft\2\ = British thermal units per square foot.

    We are soliciting comment on the appropriateness of the operating 
limits and dilution parameters in Table 3 of this preamble and whether 
they ensure that refinery flares operate in a manner that that will 
ensure compliance with the MACT requirements for vents to achieve a 98-
percent organic HAP reduction.
    Combustion zone gas monitoring alternatives. As discussed 
previously in this section, we are proposing to define the combustion 
zone gas as the mixture of gas at the flare tip consisting of the flare 
vent gas, the total steam-assist media and premix assist air. In order 
to demonstrate compliance with the three combustion zone parameter 
operating limits of net heating value, LFL and total combustibles 
fraction, the owner or operator would need to monitor four things: (1) 
Flow rate of the flare vent gas; (2) flow rate of total steam assist 
media; (3) flow rate of premix assist air and (4) specific 
characteristics associated with the flare vent gas (e.g., heat content, 
composition). In order to monitor the flow rates of the flare vent gas, 
total steam assist media, and premix assist air, we are proposing that 
refinery owners or operators use a continuous volumetric flow rate 
monitoring system or a pressure- and temperature-monitoring system with 
use of engineering calculations. We are also proposing use of either of 
these monitoring methods for purposes of determining the flow rate of 
perimeter assist air (for compliance with the dilution parameter). 
However, the one component that will determine how many combustion zone 
parameter operating limits an owner or operator can comply with is the 
specific type of monitor used to characterize the flare vent gas.
    Monitoring the individual component concentrations of the flare 
vent gas using an on-line gas chromatograph (GC) along with monitoring 
vent gas and assist gas flow rates will allow the owner or operator to 
determine compliance with any of the three proposed combustion zone 
operating limits and any of the three proposed dilution operating 
limits (if using air-assisted flares). We considered requiring all 
refinery owners or operators of flares to only use a GC to monitor the 
flare vent gas composition but since facilities may have other non-GC 
monitors already in place (e.g., calorimeters), we are not proposing 
such a requirement at this time. However, use of a GC can improve 
refinery flare operation and management of resources. For example, use 
of a GC to characterize the flare vent gas can lead to product/cost 
savings for refiners because they could more readily identify and 
correct instances of product being unintentionally sent to a flare, 
either through a leaking pressure relief valve or other conveyance that 
is ultimately routed to the flare header system. In addition, an owner 
or operator that chooses to use a GC (in lieu of one of the other 
proposed monitoring alternatives) will be more likely to benefit from 
the ability to continuously fine-tune their operations (by reducing 
assist gas addition and/or supplemental gas to the flare) in order to 
meet any one of the three operating limits. Furthermore, some 
facilities are already required to use a GC to demonstrate compliance 
with state flare requirements. We are soliciting comment on the 
additional benefits that using a GC offers and whether it would be 
reasonable to require a GC on all refinery flares.
    As an alternative to a continuous compositional monitoring system, 
we are proposing to allow the use of grab samples along with 
engineering calculations to determine the individual component 
concentration. Like the on-line GC, the grab sampling option relies on 
compound speciation and is therefore flexible to use with any form of 
the operational limits we are proposing. The disadvantage of this 
option is that if a grab sample indicates non-compliance with the 
operational limits, the permitting authority could presume non-
compliance from the time of the previous grab sample indicating 
compliance, which would include all 15-minute periods in that time 
period. However, there are a number of situations where the refinery 
owner or operator may find this option advantageous. For example, some 
flares receive flows only from a specific process with a consistent 
composition and high heat content. In this case, the owner or operator 
may elect to actively adjust the assist gas flow rates using the 
expected vent gas composition and rely on the analysis of the grab 
sample to confirm the expected vent gas composition. This alternative 
may also be preferred for flares that are used infrequently (non-
routine flow flares) or that have flare gas recovery systems designed 
and operated to recover 100 percent of the flare gas under typical 
conditions. For these flares, flaring events may be so seldom that the 
refinery owner or operator may prefer the uncertainty in proactive 
control to the higher cost of continuous monitors that would seldom be 
used.
    As an alternative to performing a compositional analysis with use 
of a GC (through either on-line monitoring or analysis of the grab 
sample), we are proposing that owners or operators of flares may elect 
to install a device that directly monitors vent gas net heating value 
(i.e., a calorimeter). If the owner or operator elects this monitoring 
method, we are proposing that they must comply with the operating 
limits that are based on the net heating value operating limit. 
Similarly, we are also proposing that owners or operators of flares may 
elect to install a device that directly monitors the total hydrocarbon 
content of the flare vent gas (as a measure of the combustibles 
concentration). If the owner or operator elects this monitoring method, 
they must comply with the operating limits that are based on the 
combustibles concentration.
e. Data Averaging Periods for Flare Gas Operating Limits
    We are proposing to use a 15-minute block averaging period for each 
proposed flare operating parameter (including flare tip velocity) to 
ensure that the flare is operated within the appropriate operating 
conditions. As flare vent gas flow rates and composition can change 
significantly over short periods of time, a short averaging time was 
considered to be the most appropriate for assessing proper flare 
performance. Furthermore, since flare destruction efficiencies can fall 
precipitously fast below the proposed operating limits, short time 
periods where the operating limits are not met could seriously impact 
the overall performance of the flare. With longer averaging times, 
there may be too much opportunity to mask these short periods of poor 
performance (i.e., to achieve the longer-term average operating limit 
while not achieving a high destruction efficiency over that time period 
because of short periods of poor performance).
    Moreover, a 15-minute averaging period is in line with the test 
data and the analysis used to establish the operating limits in this 
proposed rule. Ninety-three percent of the flare test runs used as a 
basis for establishing the proposed operating limits ranged in duration 
from 5 to 30 minutes, and 77

[[Page 36910]]

percent of the runs ranged in duration from 5 to 20 minutes. The 
failure analysis (discussed in section IV.A.3.f of this preamble) 
considered minute-by-minute test run data, but as there are limitations 
on how quickly compositional analyses can be conducted, many of the 
compositional data still reflect set values over 10- to 15-minute time 
intervals. Because the GC compositional analyses generally require 10 
to 15 minutes to conduct, shorter averaging times are not practical. To 
be consistent with the available test data and to ensure there are no 
short periods of significantly poor performance, we are proposing 15-
minute block averaging times.
    Given the short averaging times for the operating limits, we are 
proposing special calculation methodologies to enable refinery owners 
or operators to use ``feed forward'' calculations to ensure compliance 
with the operating limits on a 15-minute block average. Specifically, 
the results of the compositional analysis determined just prior to a 
15-minute block period are to be used for the next 15-minute block 
average. Owners or operators of flares will then know the vent gas 
properties for the upcoming 15-minute block period and can adjust 
assist gas flow rates relative to vent gas flow rates to comply with 
the proposed operating limits.
    Owners or operators of flares that elect to use grab sampling and 
engineering calculations to determine compliance must still assess 
compliance on a 15-minute block average. The composition of each grab 
sample is to be used for the duration of the episode or until the next 
grab sample is taken. We are soliciting comment on whether this 
approach is appropriate, and whether grab samples are needed on a more 
frequent basis to ensure compliance with the operating limits.
f. Other Peer Review Considerations
    In an effort to better inform the proposed new requirements for 
refinery flares, in the spring of 2012 the EPA summarized its 
preliminary findings on operating parameters that affect flare 
combustion efficiency in a technical report and put this report out for 
a letter review. Based on the feedback received, the EPA considered 
many of the concerns peer reviewers expressed in their comments in the 
development of this proposal for refinery flares (see memorandum, Peer 
Review of ``Parameters for Properly Designed and Operated Flares'', in 
Docket ID Number EPA-HQ-OAR-2010-0682). While the more substantive 
issues have been previously discussed in sections IV.A.3.a through e of 
this preamble, the following discussion addresses other peer review 
considerations that the EPA either discussed in the peer review 
technical document or considered from comments received by the peer 
review panel that played a role in the development of this proposal.
    Test data quality and analysis. For steam-assisted flares, we asked 
peer reviewers to comment on our criteria for excluding available flare 
test data from our analyses. In general, peer reviewers considered the 
EPA's reasons for removing certain test data (prior to performing any 
final analysis) to be appropriate; however, one reviewer suggested the 
EPA complete an analysis of quality on the data before applying any 
criteria, and several reviewers commented on the level of scrutiny of 
the 10 data points specifically discussed in the technical report for 
not meeting the combustion zone LFL trend. These reviewers stated it 
appeared the EPA had scrutinized test data more if it were inconsistent 
with the LFL threshold conclusions made in the report. Although we felt 
it was appropriate to discuss specific test data not fitting the trend, 
we do agree with the reviewers that a more general and standard set of 
criteria should be applied to all test data prior to making any 
conclusion. In addition, other peer reviewers saw no reason why the EPA 
should exclude 0-percent combustion efficiency data points, or data 
points where smoking occurs, or single test runs when there was also a 
comparable average test run. Therefore, in response to these peer 
review comments, the EPA performed a validation and usability analysis 
on all available test data. This resulted in a change to the population 
of test data used in our final analysis (see technical memorandum, 
Flare Performance Data: Summary of Peer Review Comments and Additional 
Data Analysis for Steam-Assisted Flares, in Docket ID Number EPA-HQ-
OAR-2010-0682 for a more detailed discussion of the data quality and 
analysis).
    To help determine appropriate operating limits, several peer 
reviewers suggested the EPA perform a false-positive-to-false-negative 
comparison (or failure type) analysis between the potential parameters 
discussed in the technical report as indicators of flare performance. 
The reviewers suggested that the EPA attempt to minimize the standard 
error of all false positives (i.e., poor observed combustion efficiency 
when the correlation would predict good combustion) and false negatives 
(i.e., good observed combustion efficiency when the correlation would 
predict poor combustion). In response to these comments, the EPA has 
conducted a failure analyses of these parameters which helped form the 
basis for the operating limits we are proposing for flares (see 
technical memorandum, Petroleum Refinery Sector Rule: Operating Limits 
for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
    Some peer reviewers contended that it is appropriate for the EPA to 
round each established operating limit to the nearest whole number, 
because using a decimal implies far more accuracy and reliability than 
can be determined from the test data. Based on these comments, we have 
given more consideration to the number of significant figures used in 
the operating limits, and we are proposing to use two significant 
figures for the flare operating limits in these proposed amendments.
    Multiple peer reviewers performed additional analyses to try and 
determine the appropriateness of the limits raised in the technical 
report. Some peer reviewers tried to fit the data to a curve, others 
performed various failure analyses, while others looked at different 
metrics not discussed in the technical report (see memorandum, Peer 
Review of ``Parameters for Properly Designed and Operated Flares'', in 
Docket ID Number EPA-HQ-OAR-2010-0682). Based on the conclusions drawn 
from these various analyses, a range of combustion zone net heating 
value targets from 200 Btu/scf to 450 Btu/scf were identified as 
metrics that would provide a high level of certainty regarding good 
combustion in flares (Note: 450 Btu/scf was the assumed to be 
approximately equivalent to a combustion zone LFL of 10 percent). We 
solicit comment on this range and the appropriateness for which the 
operating limits selected in this proposal will ensure compliance with 
the MACT requirements for vents at petroleum refineries.
    Effect of supplemental gas use. Most flares normally operate at a 
high turndown ratio, which means the actual flare gas flow rate is much 
lower than what the flare is designed to handle. In addition, steam-
assisted flares have a manufacturers' minimum steam requirement in 
order to protect the flare tip. A combination of high turndown ratio 
and minimum steam requirement will likely require some owners or 
operators to add supplemental gas to achieve one of the combustion zone 
gas operating limits we are proposing here (e.g., combustion zone 
combustibles concentration (Ccz) >= 18 volume percent; 
combustion zone lower flammability limit (LFLcz) <= 15 
volume percent; or combustion zone net heating value (NHVcz) 
>= 270 Btu/scf). However, fine-

[[Page 36911]]

tuning the actual steam flow to the flare should significantly reduce 
the need for supplemental gas. We considered proposing a steam-to-vent 
gas ratio limitation on steam-assisted flares. However, a steam-to-vent 
gas ratio alone cannot fully address over-steaming because it would not 
account for the variability of chemical properties within the flare 
gas. We request that commenters on this issue provide supporting 
documentation on their potential to reduce steam as well as their use 
of supplemental gas to achieve the proposed operating limit(s), and how 
it could affect cost and potential emissions. We emphasize that the 
amount and cost of supplemental gas should be reflective of conditions 
after any excess steam use has been rectified. It would not be valuable 
to consider situations where large amounts of supplemental gas are 
added, while steam is simultaneously added far in excess of the amount 
recommended by the flare manufacturer or other guidance documents.
    In assessing the combustion zone gas and looking at all the gas at 
the flare tip, another potential source of added heat content comes 
from the gas being used as fuel to maintain a continuously lit pilot 
flame. However, since pilot gas is being used as fuel for a continuous 
ignition source and is burned to create a flame prior to (or at the 
periphery of) the combustion zone, this gas does not directly 
contribute to the heat content or flammability of the gas being sent to 
the flare to be controlled under Refinery MACT 1 or 2. In addition, in 
looking at available test data, the pilot gas flow rate is generally so 
small that it does not significantly impact the combustion zone 
properties at all. Furthermore, by leaving pilot gas out of the 
combustion zone operating limit calculations, the equations become 
simplified and a requirement to continuously monitor pilot gas flow 
rate can be avoided. Therefore, we are proposing that the owner or 
operator not factor in the pilot gas combustible component (or net 
heating value) contribution when determining any of the three proposed 
combustion zone gas operating limits (Ccz, LFLcz, 
or NHVcz).
    Effects of wind on flame performance. Several published studies 
have investigated the significance of wind on the fluid mechanics of a 
flare flame (see technical memorandum, Parameters for Properly Designed 
and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). These 
studies were conducted in wind tunnels at crosswind velocities up to 
about 60 miles per hour (mph) and have illustrated that increased 
crosswind velocity can have a strong effect on flare flame dimensions 
and shape, causing the flame to become segmented or discontinuous, and 
wake-dominated (i.e., where the flame is bent over on the downwind side 
of a flare pipe and is imbedded in the wake of the flare tip), which 
may lead to poor flare performance due to fuel stripping. However, the 
majority of this research is confined to laboratory studies on flares 
with effective diameters less than 3 inches, which have been shown not 
to be representative of industrial-sized flares. Research that does 
include performance tests conducted on flares scalable to refinery 
flares (i.e., 3-inch, 4-inch, and 6-inch pipe flares) was conducted 
with flare tip velocities as low as 0.49 feet per second and crosswind 
velocities of about 26 mph and less; all tests resulted in good flare 
performance. Furthermore, there is no indication that crosswind 
velocities negatively impact flare performance in the recent flare 
performance tests. These tests were conducted on various sizes of 
industrial flares (i.e., effective diameters ranging between 12 and 54 
inches) in winds of about 22 mph and less, and at relatively low flare 
tip velocities (i.e., 10 feet per second or less). (See Parameters for 
Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-
2010-0682.)
    We are aware of flare operating parameters that consider crosswind 
velocity; however, using the available flare performance test data, we 
were unable to determine a clear correlation that would be appropriate 
for all refinery flares. For example, the momentum flux ratio (MFR) is 
a measure of momentum strength of the flare exit gas relative to the 
crosswind (i.e., the product of flare exit gas density and velocity 
squared divided by the product of air density and crosswind velocity 
squared). The plume buoyancy factor is the ratio of crosswind velocity 
to the flare exit gas velocity, and considers the area of the flare 
pipe. The power factor is the ratio of the power of the crosswind to 
the power of combustion of the flare gas. Because the available flare 
performance test data have relatively low flare tip velocities, and 
crosswind velocities were relatively constant during each test run, we 
are unable to examine these parameters to the fullest extent.
    In light of the data available from performance tests (Gogolek et 
al., 2010), we asked peer reviewers whether the MFR could be used in 
crosswind velocities greater than 22 mph at the flare tip to indicate 
wake-dominated flame situations. We also asked for comment on 
observations that in the absence of crosswind greater than 22 mph, a 
low MFR does not necessarily indicate poor flare performance. Peer 
reviewers suggested that there are no data available from real 
industrial flares in winds greater than 22 mph to support that MFR 
could be used to identify wake-dominated flame situations. In addition, 
we received no further peer review comments that have caused us to 
reconsider the observation we made in the April 2012 technical report 
that in the absence of crosswind greater than 22 mph, a low MFR does 
not necessarily indicate poor flare performance. We request comment 
with supporting data and rationale on any of these, or other 
parameters, as a measure of wind effects on flare combustion 
efficiency.
    We considered including observation requirements for detecting 
segmented or discontinuous wake-dominated flames, especially for winds 
greater than 22 mph (where limited test data is available). However, 
owners or operators of flares cannot control the wind speed, and it 
would be detrimental to increase the quantity of flared gases in high 
crosswind conditions in efforts to improve the MFR and reduce wake-
dominated flow conditions. Furthermore, there is no indication that 
crosswind velocities negatively impact flare performance in the recent 
flare performance tests. For these reasons, we are not proposing any 
flare operating parameter(s) to minimize wind effects on flare 
combustion efficiency.
g. Impacts of the Flare Operating and Monitoring Requirements
    The EPA expects that the newly proposed requirements for refinery 
flares discussed in this section will affect all flares at petroleum 
refineries. Based on data received as a result of the Refinery ICR, we 
estimate that there are 510 flares operating at petroleum refineries 
and that 285 of these receive flare vent gas flow on a regular basis 
(i.e., other than during periods of startup, shutdown, and 
malfunction). Costs were estimated for each flare for a given refinery, 
considering operational type (e.g., receive flare vent gas flow on a 
regular basis, use flare gas recovery systems to recover 100 percent of 
routine flare flow, handle events during startup, shutdown, or 
malfunction only, etc.) and current monitoring systems already 
installed on each individual flare. Costs for any additional monitoring 
systems needed were estimated based on installed costs received from 
petroleum refineries and, if installed costs were unavailable, costs 
were estimated based on vendor-purchased equipment. The baseline 
emission estimate and the emission

[[Page 36912]]

reductions achieved by the proposed rule were estimated based on 
current vent gas and steam flow data submitted by industry 
representatives. The results of the impact estimates are summarized in 
Table 4 of this preamble. We note that the requirements for refinery 
flares we are proposing in this action will ensure compliance with the 
Refinery MACT standards when flares are used as an APCD. As such, these 
proposed operational and monitoring requirements for flares at 
refineries have the potential to reduce excess emissions from flares by 
approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric 
tonnes per year of CO2e. The VOC compounds are non-methane, 
non-ethane total hydrocarbons. According to the Component 2 database 
from the Refinery ICR, there are approximately 50 individual HAP 
compounds included in the emission inventory for flares, but many of 
these are emitted in trace quantities. A little more than half of the 
HAP emissions from flares are attributable to hexane, followed next by 
benzene, toluene, xylenes, and 1,3-butadiene. For more detail on the 
impact estimates, see the technical memorandum Petroleum Refinery 
Sector Rule: Flare Impact Estimates in Docket ID Number EPA-HQ-OAR-
2010-0682.

Table 4--Nationwide Cost Impacts of Proposed Amendments To Ensure Proper
                            Flare Performance
------------------------------------------------------------------------
                                                              Total
                                         Total capital      annualized
            Affected source                investment     costs (million
                                          (million $)         $/yr)
------------------------------------------------------------------------
Flare Monitoring......................             147             36.3
------------------------------------------------------------------------

4. Vent Control Bypasses
a. Relief Valve Discharges
    Refinery MACT 1 recognized relief valve discharges to be the result 
of malfunctions. Relief valves are designed to remain closed during 
normal operation and only release as the result of unplanned and/or 
unpredictable events. A release from a relief valve usually occurs 
during an over pressurization of the system. However, emissions vented 
directly to the atmosphere by relief valves in organic HAP service 
contain HAP that are otherwise regulated under Refinery MACT 1.
    Refinery MACT 1 regulated relief valves through equipment leak 
provisions that applied only after the pressure relief occurred. In 
addition the rule followed the EPA's then-practice of exempting 
startup, shutdown and malfunction (SSM) events from otherwise 
applicable emission standards. Consequently, with relief valve releases 
defined as unplanned and nonroutine and the result of malfunctions, 
Refinery MACT 1 did not restrict relief valve releases to the 
atmosphere but instead treated them the same as all malfunctions 
through the SSM exemption provision.
    In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court 
determined that the SSM exemption violates the CAA. See section IV.E of 
this preamble for additional discussion. To ensure this standard is 
consistent with that decision, these proposed amendments remove the 
malfunction exemption in Refinery MACT 1 and 2 and provide that 
emissions of HAP may not be discharged to the atmosphere from relief 
valves in organic HAP service. To ensure compliance with this 
amendment, we are also proposing to require that sources monitor relief 
valves using a system that is capable of identifying and recording the 
time and duration of each pressure release and of notifying operators 
that a pressure release has occurred. Pressure release events from 
relief valves to the atmosphere have the potential to emit large 
quantities of HAP. Where a pressure release occurs, it is important to 
identify and mitigate it as quickly as possible. For purposes of 
estimating the costs of this requirement, we assumed that operators 
would install electronic monitors on each relief valve that vents to 
the atmosphere to identify and record the time and duration of each 
pressure release. However, we are proposing to allow owners and 
operators to use a range of methods to satisfy these requirements, 
including the use of a parameter monitoring system (that may already be 
in place) on the process operating pressure that is sufficient to 
indicate that a pressure release has occurred as well as record the 
time and duration of that pressure release. Based on our cost 
assumptions, the nationwide capital cost of installing these electronic 
monitors is $9.54 million and the annualized capital cost is $1.36 
million per year.
    As defined in the Refinery MACT standards, relief valves are valves 
used only to release unplanned, nonroutine discharges. A relief valve 
discharge results from an operator error, a malfunction such as a power 
failure or equipment failure, or other unexpected cause that requires 
immediate venting of gas from process equipment in order to avoid 
safety hazards or equipment damage. Even so, to the extent that there 
are atmospheric HAP emissions from relief valves, we are required to 
follow the Sierra Club ruling to address those emissions in our rule, 
and we can no longer exempt them as permitted malfunction emissions as 
we did under Refinery MACT 1. Our information indicates that there are 
approximately 12,000 pressure relief valves that vent to the atmosphere 
(based on the ICR responses) and that the majority of relief valves in 
the refining industry are not atmospheric, but instead are routed to 
flares (see letter from API, Docket Item Number EPA-HQ-OAR-2010-0682-
0012). We request comment on our approach and on alternatives to our 
approach to regulating releases from pressure relief valves and also 
request commenters to provide information supporting any such comments.
b. Bypass Lines
    For a closed vent system containing bypass lines that can divert 
the stream away from the APCD to the atmosphere, Refinery MACT 1 
requires the owner or operator to either: (1) Install, maintain and 
operate a continuous parametric monitoring system (CPMS) for flow on 
the bypass line that is capable of detecting whether a vent stream flow 
is present at least once every hour, or (2) secure the bypass line 
valve in the non-diverting position with a car-seal or a lock-and-key 
type configuration. Under option 2, the owner or operator is also 
required to inspect the seal or closure mechanism at least once per 
month to verify the valve is maintained in the non-diverting position 
(see 40 CFR 63.644(c) for more details). We are proposing under CAA 
section 112(d)(2) and (3) that the use of a bypass at any time to 
divert a Group 1 miscellaneous process vent is a violation of the 
emission standard, and to specify that if option 1 is chosen, the owner 
or operator would be required to install,

[[Page 36913]]

maintain and operate a CPMS for flow that is capable of recording the 
volume of gas that bypasses the APCD. The CMPS must be equipped with an 
automatic alarm system that will alert an operator immediately when 
flow is detected in the bypass line. We are proposing this revision 
because, as noted above, APCD are not to be bypassed because doing so 
could result in a release of regulated organic HAP to the atmosphere. 
In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court 
determined that standards under CAA section 112(d) must provide for 
compliance at all times and a release of uncontrolled HAP to the 
atmosphere is inconsistent with that requirement.
c. In Situ Sampling Systems (Onstream Analyzers)
    The current Refinery MACT 1 definition of ``miscellaneous process 
vent'' states that ``in situ sampling systems (onstream analyzers)'' 
are not miscellaneous process vents. 40 CFR 63.641. For several 
reasons, we are proposing to remove ``in situ sampling systems 
(onstream analyzers)'' from the list of vents not considered 
miscellaneous process vents. First, the language used in this exclusion 
is inconsistent. We generally consider ``in situ sampling systems'' to 
be non-extractive samplers or in-line samplers. There are certain in 
situ sampling systems where the measurement is determined directly via 
a probe placed in the process stream line. Such sampling systems do not 
have an atmospheric vent, so excluding these from the definition of 
``miscellaneous process vent'' is not meaningful. The parenthetical 
term ``onstream analyzers'' generally refers to sampling systems that 
feed directly to an analyzer located at the process unit, and has been 
interpreted to exclude the ``onstream'' analyzer's vent from the 
definition of miscellaneous process vents. As these two terms do not 
consistently refer to the same type of analyzer, the provision is not 
clear.
    Second, we find that there is no technical reason to include 
analyzer vents in a list of vents not considered miscellaneous process 
vents. For extractive sampling systems and systems with purges, the 
equipment leak standards in Refinery MACT 1 require that the material 
be returned to the process or controlled. Thus, the only potential 
emissions from any sampling system compliant with the Refinery MACT 1 
equipment leak provisions would be from the analyzer's ``exhaust gas'' 
vent. The parenthetical term ``onstream analyzers'' indicates that the 
focus of the exemption is primarily on the analyzer (or analyzer vent) 
rather than the sampling system. This phrase has been interpreted to 
exclude the ``onstream'' analyzer's vent from the definition of 
miscellaneous process vents. Analyzer venting is expected to be routine 
(continuous or daily intermittent venting).
    We are proposing to delete this exclusion from the definition of 
``miscellaneous process vent'' and to require these vents to meet the 
standards applicable to miscellaneous process vents at all times. We 
expect most analyzer vents to be Group 2 miscellaneous process vents 
because analyzer vents are not expected to exceed the 72 pounds per day 
(lb/day) emissions threshold for Group 1 miscellaneous process vents. 
However, if there are larger analyzer vents that exceed the 72 lb/day 
emissions threshold for Group 1 miscellaneous process vents, these 
emission sources would need to be controlled as a Group 1 miscellaneous 
process vent under this proposal. We solicit comment on the existence 
of any onstream analyzers that have VOC emissions greater than 72 lb/
day and why such vents are not amenable to control.
d. Refinery Flares and Fuel Gas Systems
    The current definition of ``miscellaneous process vent'' in 
Refinery MACT 1 states that ``gaseous streams routed to a fuel gas 
system'' are not miscellaneous process vents. Furthermore, the affected 
source subject to Refinery MACT 1 does not specifically include 
``emission points routed to a fuel gas system, as defined in Sec.  
63.641 of this subpart.'' The EPA allowed these exemptions for streams 
routed to fuel gas systems because according to the 1994 preamble for 
Refinery MACT 1, ``these vents are already controlled to the most 
stringent levels achievable'' (59 FR 36141, July 15, 1994). Since 
gaseous streams routed to a fuel gas system are eventually burned as 
fuel, typically in a boiler or process heater, these combustion 
controls burning the gaseous streams as fuel effectively achieve this 
most stringent level of control (i.e., 98-percent organic HAP reduction 
or an outlet organic HAP concentration of 20 ppmv for all vent 
streams). However, there can be instances when gaseous streams from the 
fuel gas system that would otherwise be combusted in a boiler or 
process heater are instead routed to a flare (e.g., overpressure in the 
fuel gas system, used as flare sweep gas, used as flare purge gas). In 
cases where an emission source is required to be controlled in Refinery 
MACT 1 and 2 but is routed to a fuel gas system, we are proposing that 
any flare receiving gases from that fuel gas system must comply with 
the flare operating and monitoring requirements discussed in section 
IV.A.3 of this preamble.

B. What are the results and proposed decisions based on our technology 
review?

1. Refinery MACT 1--40 CFR Part 63, Subpart CC
    Refinery MACT 1 sources include miscellaneous process vents, 
storage vessels, equipment leaks, gasoline loading racks, marine vessel 
loading operations, cooling towers/heat exchange systems, and 
wastewater.
a. Miscellaneous Process Vents
    Many unit operations at petroleum refineries generate gaseous 
streams containing HAP. These streams may be routed to other unit 
operations for additional processing (e.g., a gas stream from a reactor 
that is routed to a distillation unit for separation) or they may be 
sent to a blowdown system or vented to the atmosphere. Miscellaneous 
process vents emit gases to the atmosphere, either directly or after 
passing through recovery and/or APCD. Under 40 CFR 63.643, the owner or 
operator must reduce organic HAP emissions from miscellaneous process 
vents using a flare that meets the equipment specifications in 40 CFR 
63.11 of the General Provisions (subpart A) or use APCD (e.g., thermal 
oxidizers, carbon adsorbers) to reduce organic HAP emissions by 98 
weight-percent or to a concentration of 20 parts per million by volume 
(ppmv) dry basis, corrected to 3-percent oxygen.
    In the technology review, we did not identify any practices, 
processes or control technologies beyond those already required by 
Refinery MACT 1. Therefore, we are proposing that it is not necessary 
to revise Refinery MACT 1 requirements for miscellaneous process vents 
pursuant to CAA section 112(d)(6).
b. Storage Vessels
    Storage vessels (also known as storage tanks) are used to store 
liquid and gaseous feedstocks for use in a process, as well as liquid 
and gaseous products coming from a process. Most storage vessels are 
designed for operation at atmospheric or near atmospheric pressures; 
high-pressure vessels are used to store compressed gases and liquefied 
gases. Atmospheric storage vessels are typically cylindrical with a 
vertical orientation, and they are constructed with either a fixed roof 
or a floating roof. Some, generally small,

[[Page 36914]]

atmospheric storage vessels are oriented horizontally. High pressure 
vessels are either spherical or horizontal cylinders.
    Section 63.646(a) requires certain existing and new storage vessels 
to comply with 40 CFR 63.119 through 40 CFR 63.121 of the HON. Under 40 
CFR 63.119 through 63.121, storage vessels must be equipped with an 
internal floating roof with proper seals, an external floating roof 
with proper seals, an external floating roof converted to an internal 
floating roof with proper seals or a closed vent system routed to an 
APCD that reduces HAP emissions by 95 percent. Storage vessels at 
existing sources that use floating roofs are not required under 
Refinery MACT 1 to install certain fitting controls included in 40 CFR 
63.1119 of the HON (e.g., gaskets for automatic bleeder vents, slit 
fabric covers for sample wells, flexible fabric seals or gasketed 
sliding covers for guidepoles and gasketed covers for other roof 
openings). See 40 CFR 63.646(c).
    In 2012, we conducted a general analysis to identify the latest 
developments in practices, processes and control technologies for 
storage vessels at chemical manufacturing facilities and petroleum 
refineries, and we estimated the impacts of applying those practices, 
processes and technologies to model storage vessels. (See Survey of 
Control Technology for Storage Vessels and Analysis of Impacts for 
Storage Vessel Control Options, January 20, 2012, Docket Item Number 
EPA-HQ-OAR-2010-0871-0027.) We used this analysis as a starting point 
for conducting the technology review for storage vessels at refineries. 
In this analysis, we identified fitting controls, particularly controls 
for floating roof guidepoles, and monitoring equipment (liquid level 
monitors and leak monitors) as developments in practices, processes and 
control technologies for storage vessels. In our refinery-specific 
review, we also noted that the Group 1 storage vessel size and vapor 
pressure thresholds in Refinery MACT 1 were higher than those for 
storage vessels in MACT standards for other similar industries. 
Therefore, we also evaluated revising the Group 1 storage vessel 
thresholds as a development in practices for storage vessels in the 
refining industry.
    We used data from our 2011 ICR to evaluate the impacts of requiring 
the additional controls identified in the technology review for the 
petroleum refinery source category. The emission reduction options 
identified during the technology review are: (1) Requiring guidepole 
controls and other fitting controls for existing external or internal 
floating roof tanks as required in the Generic MACT for storage vessels 
(40 CFR part 63, subpart WW) in 40 CFR 63.1063; (2) option 1 plus 
revising the definition of Group 1 storage vessel to include smaller 
capacity storage vessels and/or storage vessels containing materials 
with lower vapor pressures and (3) option 2 plus requiring additional 
monitoring to prevent roof landings, liquid level overfills and to 
identify leaking vents and fittings from tanks. We identified options 1 
and 2 as developments in practices, processes and control technologies 
because these options are required for similar tanks in some chemical 
manufacturing MACT standards and we believe they are technologically 
feasible for storage vessels at refineries (e.g., Generic MACT, the 
HON). Option 3 is also an improvement in practices because these 
monitoring methods have been required for refineries by other 
regulatory agencies.
    Under option 1, we considered the impacts of requiring improved 
deck fittings and controls for guidepoles as is required for other 
chemical manufacturing sources in the Generic MACT. Specifically, we 
considered these controls for storage vessels with existing internal or 
external floating roof tanks. This option also includes the inspection, 
recordkeeping, and reporting requirements set forth in the Generic MACT 
to account for the additional requirements for fitting controls. We are 
aware of recent waiver requests to EPA to allow in-service, top-side 
inspections instead of the out-of-service inspections required on a 10-
year basis for internal floating roof tanks for facilities that are 
currently subject to 40 CFR part 60, subpart Kb and Refinery MACT 1. 
The requirements of Generic MACT allow for this option if there is 
visual access to all the deck components. Under option 1, we considered 
the Generic MACT provisions for in-service, top-side inspection. We are 
requesting comment on whether or not these in-service inspections are 
adequate for identifying conditions that are indicative of deck, 
fitting, and rim seal failures; we are also requesting comment on 
methods to effectively accomplish top-side inspections.
    For option 2, we evaluated revising the definition of Group 1 
storage vessels to include smaller capacity storage vessels and/or 
storage vessels with lower vapor pressure, such that these additional 
storage vessels would be subject to the Group 1 control requirements. 
For storage vessels at existing sources, Refinery MACT 1 currently 
defines Group 1 storage vessels to be those with a capacity of 177 
cubic meters (46,760 gallons) or greater, and a true vapor pressure of 
10.4 kilopascals (1.5 pounds per square inch absolute (psia)) or 
greater. Under option 2, we evaluated the impacts of changing the 
definition of Group 1 storage vessels to include storage vessels with a 
capacity of 151 cubic meters (40,000 gallons) or greater and a true 
vapor pressure of 5.2 kilopascals (0.75 psia) or greater, and also 
evaluated including storage vessels with a capacity of 76 cubic meters 
(20,000 gallons) or greater (but less than 151 cubic meters), provided 
the true vapor pressure of the stored liquid is 13.1 kilopascals (1.9 
psia) or greater. These thresholds are consistent with storage vessel 
standards already required for the chemical industry (e.g., the HON). 
We believe the predominant effect of changing these thresholds will be 
fixed roof tanks at existing petroleum refineries shifting from Group 2 
storage vessels to Group 1 storage vessels. These fixed roof tanks 
would thus need to be retrofitted with floating roofs or vented to an 
APCD in order to comply with the provisions for Group 1 storage 
vessels. We estimated the impacts of option 2 by assuming all 
uncontrolled fixed roof storage vessels that meet or exceed the 
proposed new applicability requirements for Group 1 storage vessels 
(based on the information collected in the Refinery ICR) would install 
an internal floating roof with a single rim seal and deck fittings to 
the existing fixed roof tank. The costs of these fixed roof retrofits 
were added to the costs determined for option 1 to determine the cost 
of option 2.
    Under option 3, we considered the impacts of including additional 
monitoring requirements for Group 1 storage vessels (in addition to 
fitting controls and fixed roof retrofits considered under options 1 
and 2). The monitoring requirements evaluated include monitoring of 
internal or external floating roof tanks with EPA Method 21 (of 40 CFR 
part 60, Appendix A-7) or optical gas imaging for fittings, and 
requiring the use of liquid level overfill warning monitors and roof 
landing warning monitors. These costs were estimated based on the total 
number of Group 1 storage vessels considering the change in the 
applicability thresholds included in option 2. For further details on 
the assumptions and methodologies used in this analysis, see the 
technical memorandum titled Impacts for Control Options for Storage 
Vessels at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-
0682.

[[Page 36915]]

    Table 5 of this preamble presents the impacts for the three options 
considered. Although the options were considered cumulatively, the 
calculation of the incremental cost effectiveness allows us to assess 
the impacts of the incremental change between the options. As seen by 
the incremental cost effectiveness column in Table 5, both options 1 
and 2 result in a net cost savings considering the VOC recovery credit 
for product not lost to the atmosphere from the storage vessel.\28\ We 
seek comment on the appropriateness of the VOC recovery credit we used. 
The incremental cost effectiveness for option 3 exceeds $60,000 per ton 
of HAP removed. We consider option 3 not to be cost effective and are 
not proposing to require this additional monitoring.
---------------------------------------------------------------------------

    \28\ The VOC recovery credit is $560 per ton, based on $1.75/gal 
price for generic refinery product (gasoline/diesel fuel). (See the 
technical memorandum titled Impacts for Control Options for Storage 
Vessels at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-
2010-0682 for more details.)
---------------------------------------------------------------------------

    Based on this analysis, we consider option 2 to be cost effective. 
We are, therefore, proposing to revise Refinery MACT 1 to cross-
reference the corresponding storage vessel requirements in the Generic 
MACT (including requirements for guidepole controls and other fittings 
as well as inspection requirements), and to revise the definition of 
Group 1 storage vessels to include storage vessels with capacities 
greater than or equal to 20,000 gallons but less than 40,000 gallons if 
the maximum true vapor pressure is 1.9 psia or greater and to include 
storage tanks greater than 40,000 gallons if the maximum true vapor 
pressure is 0.75 psia or greater.

                 Table 5--Nationwide Emissions Reduction and Cost Impacts of Control Options for Storage Vessels at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                  Total
                                                          Annualized                                            annualized   Overall cost   Incremental
                                                            costs                                               costs with  effectiveness       cost
                                              Capital      without     Emissions    Emissions        Cost          VOC         with VOC    effectiveness
              Control option                    cost       recovery    reduction,   reduction,  effectiveness    recovery      Rrcovery       with VOC
                                            (million $)    credits     VOC (tpy)    HAP (tpy)    ($/ton HAP)      credit     credit  ($/      recovery
                                                         (million $/                                           (million $/     ton HAP)     credit  ($/
                                                             yr)                                                   yr)                        ton HAP)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1.........................................         11.9          1.8       11,800          720         2,470         (4.8)       (6,690)
2.........................................         18.5          3.1       14,600          910         3,430         (5.0)       (5,530)        (1,140)
3.........................................         36.4          9.6       16,000        1,000         9,580          0.56           560         61,500
--------------------------------------------------------------------------------------------------------------------------------------------------------

c. Equipment Leaks
    Equipment leaks are releases of process fluid or vapor from 
processing equipment, including pump and compressor seals, process 
valves, relief devices, open-ended valves and lines, flanges and other 
connectors, agitators and instrumentation systems. These releases occur 
primarily at the interface between connected components of equipment or 
in sealing mechanisms.
    Refinery MACT 1 requires the owner or operator of an existing 
source to comply with the equipment leak provisions in 40 CFR part 60, 
subpart VV (Standards of Performance for Equipment Leaks of VOC in the 
Synthetic Organic Chemicals Manufacturing Industry) for all equipment 
in organic HAP service. The term ``in organic HAP service'' means that 
a piece of equipment either contains or contacts a fluid (liquid or 
gas) that is at least 5 percent by weight of total organic HAP. 
Refinery MACT 1 specifies that the owner or operator of a new source 
must comply with the HON, as modified by Refinery MACT 1. The 
provisions for both new and existing sources require inspection (either 
through instrument monitoring using EPA Method 21 of 40 CFR part 60, 
Appendix A-7, or other method such as visible inspection) and repair of 
leaking equipment. For existing sources, the leak definition under 40 
CFR part 60, subpart VV triggers repair at an instrument reading of 
10,000 parts per million (ppm) for all equipment monitored using EPA 
Method 21 of 40 CFR part 60, Appendix A-7 (i.e., pumps and valves; 
instrument monitoring of equipment in heavy liquid service and 
connectors is optional). For new sources, the Refinery MACT 1-modified 
version of the HON triggers repair of leaks for pumps at 2,000 ppm and 
for valves at 1,000 ppm. Refinery MACT 1 requires new and existing 
sources to install a cap, plug or blind flange, as appropriate, on 
open-ended valves or lines. Refinery MACT 1 does not require instrument 
monitoring of connectors for either new or existing sources.
    We conducted a general analysis to identify the latest developments 
in practices, processes and control technologies applicable to 
equipment leaks at chemical manufacturing facilities and petroleum 
refineries, and we estimated the impacts of applying the identified 
practices, processes and technologies to several model plants. (See 
Analysis of Emissions Reduction Techniques for Equipment Leaks, 
December 21, 2011, Docket Item Number EPA-HQ-OAR-2010-0869-0029.) We 
used this general analysis as a starting point for conducting the 
technology review for equipment leaks at refineries, but did not 
identify any developments beyond those in the general analysis. We 
estimated the impacts of applying the practices, processes and 
technologies identified in the general analysis to equipment leaks in 
petroleum refinery processes using the information we collected through 
the 2011 Refinery ICR. In general, leak detection and repair (LDAR) 
programs have been used by many industries for years to control 
emissions from equipment leaks. Over the years, repair methods have 
improved and owners and operators have become more proficient at 
implementing these programs. The specific developments identified 
include: (1) Requiring repair of leaks at a concentration of 500 ppm 
for valves and 2,000 ppm for pumps for new and existing sources (rather 
than 10,000 ppm for valves and pumps at existing sources and 1,000 for 
valves at new sources); (2) requiring monitoring of connectors using 
EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair of leaks for 
valves and pumps at a concentration of 500 ppm; and (3) allowing the 
use of optical gas imaging devices as an alternative method of 
monitoring.
    The first option we evaluated was to require repair based on a leak 
definition of 500 ppm for valves and a leak definition of 2,000 ppm for 
pumps at both new and existing sources. The nationwide costs and 
emission reduction impacts of applying those lower leak definitions to 
equipment leaks at petroleum refineries are shown in Table 6 of this 
preamble. For further details on the assumptions and methodologies used 
in this analysis, see the technical memorandum titled Impacts for 
Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-
OAR-2010-0682.

[[Page 36916]]

The emissions reduction results in product not being lost by a leak; 
this additional product can be sold to generate revenue, referred to as 
a VOC recovery credit. Table 6 shows costs and cost effectiveness both 
with and without the VOC recovery credit. Based on the estimated 
organic HAP emission reductions of 24 tpy and the cost effectiveness of 
$14,100 per ton of organic HAP (including VOC recovery credit), we 
consider lowering the leak definition not to be a cost-effective option 
for reducing HAP emissions. We are, therefore, proposing that it is not 
necessary to revise Refinery MACT 1 pursuant to CAA section 112(d)(6) 
to require repair of leaking valves at 500 ppm or greater and repair of 
leaking pumps at 2,000 ppm or greater.

                                    Table 6--Nationwide Emissions Reduction and Cost Impacts of Monitoring and Repair Requirements at Lower Leak Definitions
                                                                            [500 ppm for valves; 2,000 ppm for pumps]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                               Overall cost       Overall cost
                                           Annualized costs      Emissions          Emissions             Cost               Cost         Total annualized    effectiveness      effectiveness
        Capital cost (million $)           without recovery    reduction, VOC     reduction, HAP   effectiveness ($/  effectiveness ($/    costs with VOC   with VOC recovery  with VOC recovery
                                           credits (million        (tpy)              (tpy)             ton VOC)           ton HAP)       recovery credit     credit ($/ton      credit  ($/ton
                                                $/yr)                                                                                      (million $/yr)          VOC)               HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1.22....................................              0.53                342                 24              1,550             22,100               0.34                987             14,100
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    We note that we are aware that some owners and operators are 
required to repair leaking valves as low as 100 ppm and pumps as low as 
500 ppm. However, we consider requiring repair of leaking valves at 500 
ppm or greater and repair of leaking pumps at 2,000 ppm or greater not 
to be cost effective. As documented in Analysis of Emissions Reduction 
Techniques for Equipment Leaks (December 21, 2011, in Docket ID Number 
EPA-HQ-OAR-2010-0869), the cost effectiveness for this option would be 
even higher than the values shown in Table 6 of this preamble.
    The second option we considered was connector monitoring and 
repair. Several standards applying to chemical manufacturing 
facilities, including the HON, include requirements for connector 
monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A-7) and 
requirements for repair of any connector leaks above 500 ppm VOC. 
Neither the Refinery MACT 1 nor the NSPS for equipment leaks from 
refineries (40 CFR part 60, subpart GGG and 40 CFR part 60, subpart 
GGGa) currently require connector monitoring and repair (provisions are 
provided for connector monitoring in Refinery MACT 1, but they are 
optional). We evaluated the costs and emissions reduction of requiring 
connector monitoring and repair requirements for equipment leaks at 
refineries. The nationwide costs and emission reduction impacts, both 
with and without VOC recovery credit, are shown in Table 7 of this 
preamble. For further details on the assumptions and methodologies used 
in this analysis, see the technical memorandum titled Impacts for 
Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-
OAR-2010-0682. Based on the high annualized cost ($13.9 million per 
year) and high cost effectiveness ($153,000 per ton of HAP) of 
connector monitoring and repair for equipment leaks at refineries, we 
are proposing that it is not necessary to revise Refinery MACT 1 
pursuant to CAA section 112(d)(6) to require connector monitoring using 
EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair.

                          Table 7--Nationwide Emissions Reduction and Cost Impacts of Applying Monitoring and Repair Requirements to Connectors at Petroleum Refineries
                                                                                            [500 ppm]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                               Overall cost       Overall cost
                                           Annualized costs      Emissions          Emissions             Cost               Cost         Total annualized    effectiveness      effectiveness
        Capital cost (million $)           without recovery    reduction, VOC     reduction, HAP   effectiveness ($/  effectiveness ($/    costs with VOC   with VOC recovery  with VOC recovery
                                           credits (million        (tpy)              (tpy)             ton VOC)           ton HAP)       recovery credit     credit ($/ton      credit  ($/ton
                                                $/yr)                                                                                      (million $/yr)          VOC)               HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
52.1....................................              13.9              1,230                 86             11,300            161,000               13.2             10,700            153,000
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    Another development identified was to provide optical gas imaging 
provisions (including the required instrument specifications, 
monitoring frequency, and repair threshold) as an alternative 
monitoring option where instrument monitoring using EPA Method 21 of 40 
CFR part 60, Appendix A-7, is required in Refinery MACT 1. Since 
Refinery MACT 1 was issued, there have been developments in LDAR work 
practices using remote sensing technology for detecting leaking 
equipment. In this method of detecting leaks, an operator scans 
equipment using a device or system specially designed to use one of 
several types of remote sensing techniques, including optical gas 
imaging of infrared wavelengths, differential absorption light 
detection and ranging (DIAL), and solar occultation flux.
    The most common remote sensing instrument is a passive system that 
creates an image based on the absorption of infrared wavelengths (also 
referred to as a ``camera''). A gas cloud containing certain 
hydrocarbons (i.e., leaks) will show up as black or white plumes 
(depending on the instrument settings and characteristics of the leak) 
on the optical gas imaging instrument screen. This type of instrument 
is the device on which our evaluation of optical gas imaging 
instruments is based, and the instrument to which we are referring when 
we use the term ``optical gas imaging instrument.'' These optical gas 
imaging instruments can be used to identify specific pieces of 
equipment that are leaking. Other optical methods, such as DIAL and 
solar occultation flux, are used primarily to assess emissions downwind 
of a source. These methods cannot be used to identify specific leaking 
equipment; they would only measure the aggregate emissions from all 
equipment and any other source up-wind of the measurement location. 
While we did review these technologies as discussed further (see the 
discussion under fenceline monitoring, section IV.B.1.h of this 
preamble), we do not consider DIAL and solar occultation flux methods 
to be suitable alternatives to EPA Method 21 for monitoring equipment 
leaks and are not considering them further in our technology review for 
equipment leaks.

[[Page 36917]]

    We expect that all refinery streams ``in organic HAP service'' will 
include at least one of the compounds visible with an optical gas 
imaging instrument, such as benzene, methane, propane or butane. 
Therefore, it is technically feasible to use an optical gas imaging 
instrument to detect leaks at petroleum refineries. The optical gas 
imaging device can monitor many more pieces of equipment than can be 
monitored using instrument monitoring over the same period of time, and 
we expect that specific requirements for using an optical gas imaging 
device to detect leaks without accompanying instrument monitoring could 
be an appropriate alternative to traditional leak detection methods 
(EPA Method 21, as specified in 40 CFR part 60, Appendix A-7).
    Owners and operators currently have the option to use the 
Alternative Work Practice To Detect Leaks From Equipment (AWP) at 40 
CFR 63.11(c), (d) and (e). This AWP includes provisions for using 
optical gas imaging in combination with annual monitoring using EPA 
Method 21 of 40 CFR part 60, Appendix A-7. In this proposal, we are 
considering the use of optical gas imaging without an accompanying 
requirement to conduct annual monitoring using EPA Method 21, and 
developing a protocol for using optical gas imaging techniques. We 
anticipate proposing the protocol as Appendix K to 40 CFR part 60. 
Rather than specifying the exact instrument that must be used, this 
protocol would outline equipment specifications, calibration 
techniques, required performance criteria, procedures for conducting 
surveys and training requirements for optical gas imaging instrument 
operators. This protocol would also contain techniques to verify that 
the instrument selected can image the most prevalent chemical in the 
monitored process unit. Because field conditions greatly impact 
detection of the regulated material using optical gas imaging, the 
protocol would describe the impact these field conditions may have on 
readings, how to address them and instances when monitoring with this 
technique is inappropriate. Finally, the protocol would also address 
difficulties with identifying equipment and leaks in dense industrial 
areas.
    Pursuant to CAA section 112(d)(6), we are proposing to allow 
refineries to meet the LDAR requirements in Refinery MACT 1 by 
monitoring for leaks via optical gas imaging in place of EPA Method 21 
(of 40 CFR part 60, Appendix A-7), using the monitoring requirements to 
be specified in Appendix K to 40 CFR part 60. When Appendix K is 
proposed, we will request comments on that appendix and how those 
requirements would apply for purposes of this proposed action. We will 
not take final action adopting use of Appendix K to 40 CFR part 60 for 
optical gas imaging for refineries subject to Refinery MACT 1 until 
such time as we have considered any comments on that protocol as it 
would apply to refineries. We do not yet know the exact requirements of 
Appendix K to 40 CFR part 60, and this cannot provide a reliable 
estimate of potential costs at this time. However, we have calculated 
an initial estimate of the potential costs and emission reduction 
impacts, assuming that Appendix K to 40 CFR part 60 is similar to the 
AWP without the annual monitoring using EPA Method 21 of 40 CFR part 
60, Appendix A-7. For more information on these potential impacts, see 
the technical memorandum titled Impacts for Equipment Leaks at 
Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682.
d. Gasoline Loading Racks
    Loading racks are the equipment used to fill gasoline cargo tanks, 
including loading arms, pumps, meters, shutoff valves, relief valves 
and other piping and valves. Emissions from loading racks may be 
released when gasoline loaded into cargo tanks displaces vapors inside 
these containers. Refinery MACT 1 specifies that Group 1 gasoline 
loading racks at refineries must comply with the requirements of the 
National Emission Standards for Gasoline Distribution Facilities (Bulk 
Gasoline Terminals and Pipeline Breakout Stations) in 40 CFR part 63, 
subpart R. The standard specified in 40 CFR part 63, subpart R is an 
emission limit of 10 milligrams of total organic compounds per liter of 
gasoline loaded (mg/L). Additionally, 40 CFR part 63, subpart R 
requires all tank trucks and railcars that are loaded with gasoline to 
undergo annual vapor tightness testing in accordance with EPA Method 27 
of 40 CFR part 60, Appendix A-8.
    For our technology review of Group 1 gasoline loading racks subject 
to Refinery MACT 1, we relied on two separate analyses. First, we 
previously conducted a technology review for gasoline distribution 
facilities (71 FR 17353, April 6, 2006), in which no new control 
systems were identified. Second, more recently, we conducted a general 
analysis to identify any developments in practices, processes and 
control technologies for transfer operations at chemical manufacturing 
facilities and petroleum refineries. (See Survey of Control Technology 
for Transfer Operations and Analysis of Impacts for Transfer Operation 
Control Options, January 20, 2012, Docket Item Number EPA-HQ-OAR-2010-
0871-0021.) We identified several developments as part of this analysis 
and evaluated the impacts of applying the developments to gasoline 
loading racks subject to Refinery MACT 1. We have not identified any 
developments beyond those in the second analysis. The identified 
developments include controlling loading racks above specific 
throughput thresholds by submerged loading and by venting displaced 
emissions from the transport vehicles through a closed vent system to 
an APCD that reduces organic regulated material emissions by at least 
95 percent.
    We evaluated the emissions projected using this control technique 
for a range of different gasoline vapor pressures (to consider the 
different seasonal formulations of gasoline). We determined that 
submerged loading in combination with 95-percent control of displaced 
vapors would allow emissions of 12 to 42 mg/L of gasoline loaded, 
depending on the vapor pressure of the gasoline (see Evaluation of the 
Stringency of Potential Standards for Gasoline Loading Racks at 
Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.) The 
current Refinery MACT 1 emission limit for gasoline loading is 10 mg/L 
of gasoline loaded. We did not identify any developments in practices, 
process and control technologies for gasoline loading racks that would 
reduce emissions beyond the levels already in Refinery MACT 1. 
Therefore, we are proposing that it is not necessary to revise Refinery 
MACT 1 requirements for gasoline loading racks pursuant to CAA section 
112(d)(6).
e. Marine Vessel Loading Operations
    Marine vessel loading operations load and unload liquid commodities 
in bulk, such as crude oil, gasoline and other fuels, and naphtha. The 
cargo is pumped from the terminal's large, above-ground storage tanks 
through a network of pipes and into a storage compartment (tank) on the 
vessel. The HAP emissions are the vapors that are displaced during the 
filling operation. Refinery MACT 1 specifies that marine tank vessel 
loading operations at refineries must comply with the requirements in 
40 CFR part 63, subpart Y (National Emission Standards for Marine Tank 
Vessel Loading Operations, ``Marine Vessel MACT'').
    We previously completed a technology review of the Marine Vessel 
MACT (40 CFR part 63, subpart Y) and issued amendments to subpart Y in

[[Page 36918]]

2011 (76 FR 22595, Apr. 21, 2011). The analysis conducted for the 
marine vessel loading source category specifically considered loading 
of petroleum products such as conventional and reformulated gasoline. 
As such, the conclusions drawn from this analysis are directly 
applicable to marine vessel loading operations at petroleum refineries. 
We have not identified any developments beyond those addressed in that 
analysis.
    The Marine Vessel MACT required add-on APCD for loading operations 
with HAP emissions equal to or greater than 10 tpy of a single 
pollutant or 25 tpy of cumulative pollutants (referred to as ``10/25 
tpy''). In our technology review of the Marine Vessel MACT standards, 
we considered the use of add-on APCD for marine vessel loading 
operations with HAP emissions less than 10/25 tpy. We also evaluated 
the costs for lean oil absorption systems as add-on APCD under the 
Marine Vessel MACT technology review. Depending on the throughput of 
the vessel, costs ranged from $77,000 per ton HAP removed for barges to 
$510,000 per ton HAP removed for ships ($3,900 per ton VOC removed to 
$25,000 per ton VOC removed) (see Cost Effectiveness and Impacts of 
Lean Oil Absorption for Control of Hazardous Air Pollutants from 
Gasoline Loading--Promulgation in Docket Item Number EPA-HQ-OAR-2010-
0600-0401). We consider requiring add-on APCD for these smaller marine 
vessel loading operations not to be cost effective.
    As part of the technology review of 40 CFR part 63, subpart Y, we 
also considered requiring marine vessel loading operations with 
emissions less than 10/25 tpy and offshore operations to use submerged 
loading (also referred to as submerged filling). We did include this 
requirement in the Marine Vessel MACT. However, when we amended the 
Marine Vessel MACT, we specifically excluded marine vessel loading 
operations at petroleum refineries from these provisions, deferring the 
decisions to include this requirement until we performed the technology 
review for Refinery MACT 1. The submerged filling requirement in 40 CFR 
part 63, subpart Y cites the cargo filling line requirements developed 
by the Coast Guard in 46 CFR 153.282. We project that applying the 
submerged filling requirements to marine vessel loading operations at 
petroleum refineries will have no costs or actual emission reductions 
because marine vessels carrying bulk liquids, liquefied gases or 
compressed gas hazardous materials are already required by 46 CFR 
153.282 to have compliant ``submerged fill'' cargo lines that also meet 
the requirements of the Marine Vessel MACT. While we do not anticipate 
that this requirement will affect actual emissions, it will lower the 
allowable emissions for these sources under Refinery MACT 1. Therefore, 
we are proposing, pursuant to CAA section 112(d)(6), to amend 40 CFR 
part 63, subpart Y to delete the exclusion for marine vessel loading 
operations at petroleum refineries, which would require small marine 
vessel loading operations (i.e., operations with HAP emissions less 
than 10/25 tpy) and offshore marine vessel loading operations to use 
submerged filling based on the cargo filling line requirements in 46 
CFR 153.282.
f. Cooling Towers/Heat Exchange Systems
    Heat exchange systems include equipment necessary to cool heated 
non-contact cooling water prior to returning the cooling water to a 
heat exchanger or discharging the water to another process unit, waste 
management unit or to a receiving water body. Heat exchange systems are 
designed as closed-loop recirculation systems with cooling towers or 
once-through systems that do not recirculate the cooling water through 
a cooling tower. Heat exchangers in heat exchange systems are 
constructed with tubes designed to prevent contact between hot process 
fluids and cooling water. Heat exchangers occasionally develop leaks 
that allow process fluids to enter the cooling water. The volatile HAP 
and other volatile compounds in these process fluids are then emitted 
to the atmosphere due to stripping in a cooling tower or volatilization 
from a cooling water pond or receiving water body.
    We established MACT standards for heat exchange systems at 
refineries in 2009 (see 74 FR 55686, October 28, 2009, as amended at 75 
FR 37731, June 30, 2010). The EPA received a petition for 
reconsideration from the American Petroleum Institute (API) and granted 
reconsideration on certain issues. On June 20, 2013, we issued a final 
rule addressing the petition, clarifying rule provisions, and revising 
the monitoring provisions to provide additional flexibility (78 FR 
37133). We are not aware of any developments in processes, practices or 
control technologies beyond those we recently considered in our 
analysis of emission reduction techniques for heat exchange systems, 
which can be found in the docket (Docket Item Number EPA-HQ-OAR-2003-
0146-0229). Therefore, we are proposing that it is not necessary to 
revise Refinery MACT 1 requirements for heat exchange systems pursuant 
to CAA section 112(d)(6).
g. Wastewater Treatment
    Wastewater collection includes components such as drains, manholes, 
trenches, junction boxes, sumps, lift stations and sewer lines. 
Wastewater treatment systems are divided into three categories: primary 
treatment operations, which include oil-water separators and 
equalization basins; secondary treatment systems, such as biological 
treatment units or steam strippers; and tertiary treatment systems, 
which further treat or filter wastewater prior to discharge to a 
receiving body of water or reuse in a process.
    Refinery MACT 1 requires wastewater streams at a new or existing 
refinery to comply with 40 CFR 61.340 through 61.355 of the NESHAP for 
Benzene Waste Operations (BWON) in 40 CFR part 61, subpart FF. The BWON 
requires control of wastewater collection and treatment units for 
facilities with a total annual benzene quantity of greater than or 
equal to 10 megagrams per year (Mg/yr). Individual waste streams at 
refineries with a total annual benzene quantity greater than or equal 
to 10 Mg/yr are not required to adopt controls if the flow-weighted 
annual average benzene concentration is less than 10 parts per million 
by weight (ppmw) or the flow rate is less than 0.02 liters per minute 
at the point of generation. The BWON requires affected waste streams to 
comply with one of several options for controlling benzene emissions 
from waste management units and for treating the wastes containing 
benzene (55 FR 8346, March 7, 1990; 58 FR 3095, January 7, 1993).
    Although the BWON specifically regulates benzene only, benzene is 
considered a surrogate for organic HAP from wastewater treatment 
systems at petroleum refineries. Benzene is present in nearly all 
refinery process streams. It is an excellent surrogate for wastewater 
pollutants because its unique chemical properties cause it to partition 
into the wastewater more readily than most other organic chemicals 
present at petroleum refineries. We stated our rationale regarding the 
use of benzene as a surrogate for refinery HAP emissions from 
wastewater in the original preamble to Refinery MACT 1 (59 FR 36133, 
July 15, 1994).
    We performed a technology review for wastewater treatment systems 
to identify different control technologies for reducing emissions from 
wastewater treatment systems. We also reviewed the current standards 
for wastewater treatment systems in different rules

[[Page 36919]]

including the HON, the proposed NSPS for wastewater systems at 
petroleum refineries, and the BWON (See Technology Review for 
Industrial Wastewater Collection and Treatment Operations at Petroleum 
Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682.) We identified 
several developments in processes, practices and control technologies 
for wastewater treatment, and evaluated the cost and cost effectiveness 
of each of those developments: (1) requiring wastewater drain and tank 
controls at refineries with a total annual benzene (TAB) quantity of 
less than 10 Mg/yr; (2) requiring specific performance parameters for 
an enhanced biological unit (EBU) beyond those required in the BWON; 
and (3) requiring wastewater streams with a VOC content of 750 ppmv or 
higher to be treated by steam-stripping prior to any other treatment 
process for facilities with high organic loading rates (i.e., 
facilities with total annualized benzene quantity of 10 Mg/yr or more). 
These options are, for the most part, independent of each other, so the 
costs and cost effectiveness of each option are considered separately.
    Option 1 was evaluated because refineries with a total annual 
benzene quantity of less than 10 Mg/yr are not required to install 
additional controls on their wastewater treatment system. Thus, these 
refineries are limiting the amount of benzene produced in wastewater 
streams to less than 10 Mg/yr, which effectively limits their benzene 
emissions from wastewater to less than 10 Mg/yr.
    Option 2 is intended to improve the performance of wastewater 
treatment systems that use an EBU, and thereby achieve additional 
emission reductions. The BWON, as it applies under Refinery MACT 1, has 
limited operational requirements for an EBU. Available data suggest 
that these systems are generally effective for degrading benzene and 
other organic HAP; however, without specific performance or operational 
requirements, the effectiveness of the EBU to reduce emissions can be 
highly variable. Under option 2, more stringent operating requirements 
are considered for the EBU at refineries.
    Option 3 considers segregated treatment of wastewater streams with 
a volatile organic content of greater than 750 ppmw, or high-strength 
wastewater streams, directly in a steam stripper (i.e., not allowing 
these streams to be mixed and treated in the EBU). Preliminary 
investigations revealed direct treatment of wastewater by steam-
stripping is only cost effective for high-strength wastewater streams 
of sufficient quantities. For more detail regarding the impact analysis 
for these control options, see Technology Review for Industrial 
Wastewater Collection and Treatment Operations at Petroleum Refineries, 
in Docket ID Number EPA-HQ-OAR-2010-0682.
    Table 8 provides the nationwide impacts for the control options. 
Based on the costs and emission reductions for each of the options, we 
consider none of the options identified to be cost effective for 
reducing emissions from petroleum refinery wastewater treatment 
systems. We are proposing that it is not necessary to revise Refinery 
MACT 1 to require additional controls for wastewater treatment systems 
pursuant to CAA section 112(d)(6).

     Table 8--Nationwide Emissions Reduction and Cost Impacts of Control Options Considered for Wastewater Treatment Systems at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                      Emissions         Emissions           Cost              Cost
               Control option                   Capital cost    Annualized costs   reduction, VOC    reduction, HAP   effectiveness ($/ effectiveness ($/
                                                 (million $)     (million $/yr)         (tpy)             (tpy)           ton VOC)          ton HAP)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1...........................................              19.7               4.2               592               158             7,100            26,600
2...........................................               223              28.6             2,060               549            13,900            52,100
3...........................................               142              50.7             3,480               929            14,500            54,500
--------------------------------------------------------------------------------------------------------------------------------------------------------

h. Fugitive Emissions

    The EPA recognizes that, in many cases, it is impractical to 
directly measure emissions from fugitive emission sources at 
refineries. Direct measurement of fugitive emissions from sources such 
as wastewater collection and treatment operations, equipment leaks and 
storage vessels can be costly and difficult, especially if required to 
be deployed on all sources of fugitives within a refinery and certainly 
on a national scale. This is a major reason why fugitive emissions 
associated with refinery processes are generally estimated using 
factors and correlations rather than by direct measurement. For 
example, equipment leak emissions are estimated using factors and 
correlations between leak rates and concentrations from EPA Method 21 
instrument monitoring. Fugitive emissions from wastewater collection 
and treatment are estimated based on process data, material balances 
and empirical correlations. Relying on these kinds of approaches 
introduces uncertainty into the emissions inventory for fugitive 
emission sources.
    For each of the individual fugitive emission points, we evaluated 
developments in processes, practices and control technologies for 
measuring and controlling fugitive emissions from these sources. For 
storage vessels, as discussed in section IV.B.1.b of this preamble, we 
are proposing to lower the size and vapor pressure threshold and to 
require additional fittings on tanks, similar to requirements for tanks 
in the chemical industry because we project a cost savings due to 
recovered product. However, we considered but are not proposing to 
require EPA Method 21 of 40 CFR part 60, Appendix A-7 or optical gas 
imaging monitoring to identify fugitive emissions from each individual 
storage vessel. For equipment leaks, as discussed in section IV.B.1.c 
of this preamble, we considered lowering the leak definition for 
equipment at petroleum refineries from the current Refinery MACT 1 
level of 10,000 ppm for pumps and valves down to the 500 ppm definition 
that is used in all the other MACT standards applying to the chemical 
industry, as well as adding a requirement for connectors to be included 
in the LDAR program because we consider these more stringent LDAR 
requirements to be technically feasible for the petroleum refining 
industry. Nevertheless, we rejected these options under the technology 
review as not being cost effective, based on costs projected by using 
the industry-reported emissions inventories. We are, however, proposing 
to adopt the use of optical gas imaging devices following 40 CFR part 
60, Appendix K as an alternative to using EPA Method 21, which will be 
an alternative available to petroleum refiners that could offer cost 
savings, once the monitoring protocol set forth in Appendix K is 
promulgated. For wastewater treatment systems, as discussed in section 
IV.B.1.g of this

[[Page 36920]]

preamble, we considered both lowering the threshold for refinery 
wastewater streams requiring control, as well as requiring refineries 
to comply with enhanced monitoring and operating limits for EBU, such 
as the requirements contained in most of the chemical sector MACT 
standards, because we consider these requirements to be technically 
feasible for the refining industry. However, like equipment leaks, we 
are rejecting further controls for wastewater because using the 
industry-reported emissions inventory, we determined that further 
wastewater requirements are not cost effective.
    Although we are not proposing to require a number of additional 
control options for fugitive emission sources because we determined 
them not cost effective, we remain concerned regarding the potential 
for high emissions from these fugitive sources due to the difficulties 
in monitoring actual emission levels. For example, the regulations 
require infrequent monitoring of storage tank floating roof seals 
(visual inspections are required annually and direct inspections of 
primary seals are required only when the vessel is emptied and 
degassed, or no less frequently than once every 5 years for internal 
floating roofs or 10 years for external floating roofs with secondary 
seals). Given these inspection frequencies, tears or failures in 
floating roof seals may exist for years prior to being noticed, 
resulting in much higher emissions than expected or estimated for these 
sources in the emissions inventory. Similarly, water seals, which are 
commonly used to control emissions from wastewater collection drain 
systems, may be difficult to monitor (e.g., some are underground so 
visible emissions tests cannot be performed) and are subject only to 
infrequent inspections. During hot, dry months, these water seals may 
dry out, leaving an open pathway of vapors to escape from the 
collection system to the atmosphere. Significant emission releases may 
occur from these ``dry'' drains, which could persist for long periods 
of time prior to the next required inspection.
    Because the requirements and decisions that we are proposing in 
this action are based upon the emissions inventory reported by 
facilities in response to the 2011 Refinery ICR, and considering the 
uncertainty with estimating emissions from fugitive emission sources, 
we believe that it is appropriate under CAA section 112(d)(6) to 
require refiners to monitor, and if necessary, take corrective action 
to minimize fugitive emissions, to ensure that facilities appropriately 
manage emissions of HAP from fugitive sources. In other words, in this 
action, we are proposing a HAP concentration to be monitored in the 
ambient air around a refinery, that if exceeded, would trigger 
corrective action to minimize fugitive emissions. The fenceline 
concentration action level would be set at a level such that no 
facility in the category would need to undertake additional corrective 
measures if the facility's estimate of emissions from fugitive 
emissions is consistent with the level of fugitive emissions actually 
emitted. On the other hand, if a facility's estimate of fugitive HAP 
emissions was not accurate, the owner or operator may need to take some 
corrective action to minimize fugitive emissions. This approach would 
provide the owner or operator with the flexibility to determine how 
best to reduce HAP emissions to ensure levels remain below the 
fenceline concentration action level. The details of this proposed 
approach are set forth in more detail in the following discussions in 
this preamble section.
    In light of the impracticality of directly monitoring many of these 
fugitive emission sources on a regular basis, which would help ensure 
these fugitive sources are properly functioning to the extent 
practical, we evaluated a fenceline monitoring program under CAA 
section 112(d)(6). In this section, we evaluate the developments in 
processes, practices and control technologies for measuring and 
controlling fugitive emissions from the petroleum refinery as a whole 
through fenceline monitoring techniques. Fenceline monitoring will 
identify a significant increase in emissions in a timely manner (e.g., 
a large equipment leak or a significant tear in a storage vessel seal), 
which would allow corrective action measures to occur more rapidly than 
it would if a source relied solely on the traditional infrequent 
monitoring and inspection methods. Small increases in emissions are not 
likely to impact the fenceline concentration, so a fenceline monitoring 
approach will generally target larger emission sources that have the 
most impact on the ambient pollutant concentration near the refinery.
    Historically, improved information through measurement data has 
often led to emission reductions. However, without a specific emission 
limitation, there may be no incentive for owners or operators to act on 
the additional information. Therefore, as part of the fenceline 
monitoring approach, we seek to develop a not-to-be exceeded annual 
fenceline concentration, above which refinery owners or operators would 
be required to implement corrective action to reduce their fenceline 
concentration. We sought to develop a maximum fenceline concentration 
action level that is consistent with the emissions projected from 
fugitive sources compliant with the provisions of the refinery MACT 
standards as modified by the additional controls proposed in this 
action (e.g., additional fittings on storage vessels).
    This section details our technology review to identify developments 
in processes, practices and technologies for measuring air toxics at 
the fenceline of a facility. Upon selection of a specific fenceline 
monitoring method, we provide our rationale for the specific details 
regarding the fenceline monitoring approach, including requirements for 
siting the monitors, procedures for adjusting for background 
interferences, selection of the fenceline action level, and 
requirements for corrective action.
    Developments in monitoring technology and practices. The EPA 
reviewed the available literature and identified several different 
methods for measuring fugitive emissions around a petroleum refinery. 
These methods include: (1) Passive diffusive tube monitoring networks; 
(2) active monitoring station networks; (3) ultraviolet differential 
optical absorption spectroscopy (UV-DOAS) fenceline monitoring; (4) 
open-path Fourier transform infrared spectroscopy (FTIR); (5) DIAL 
monitoring; and (6) solar occultation flux monitoring. We considered 
these monitoring methods as developments in practices under CAA section 
112(d)(6) for purposes of all fugitive emission sources at petroleum 
refineries. Each of these methods has its own strengths and weaknesses, 
which are discussed in the following paragraphs.
    Fenceline passive diffusive tube monitoring networks employ a 
series of diffusive tube samplers at set intervals along the fenceline 
to measure a time-integrated ambient air concentration at each sampling 
location. A diffusive tube sampler consists of a small tube filled with 
an adsorbent, selected based on the pollutant(s) of interest, and 
capped with a specially designed cover with small holes that allow 
ambient air to diffuse into the tube at a small, fixed rate. Diffusive 
tube samplers have been demonstrated to be a cost-effective, accurate 
technique for measuring ambient concentrations of pollutants resulting 
from fugitive emissions in a number of studies.29 30 In 
addition,

[[Page 36921]]

diffusive samplers are used in the European Union to monitor and 
maintain air quality, as described in European Union directives 2008/
50/EC and Measurement Standard EN 14662-4:2005 for benzene. The 
International Organization for Standardization developed a standard 
method for diffusive sampling (ISO/FDIS 16017-2).
---------------------------------------------------------------------------

    \29\ McKay, J., M. Molyneux, G. Pizzella, V. Radojcic. 
Environmental Levels of Benzene at the Boundaries of Three European 
Refineries, prepared by the CONCAWE Air Quality Management Group's 
Special Task Force on Benzene Monitoring at Refinery Fenceline (AQ/
STF-45), Brussels, June 1999.
    \30\ Thoma, E.D., M.C. Miller, K.C. Chung, N.L. Parsons, B.C. 
Shine. 2011. Facility Fenceline Monitoring using Passive Sampling, 
J. Air & Waste Manage Assoc. 61: 834-842.
---------------------------------------------------------------------------

    In 2009, the EPA conducted a year-long fenceline monitoring pilot 
project at Flint Hills West Refinery in Corpus Christi, Texas, to 
evaluate the viability and performance of passive diffusive sampling 
technology. Overall, we found the technology to be capable of providing 
cost effective, high spatial-density long-term monitoring. This 
approach was found to be relatively robust and implementable by 
modestly trained personnel and provided useful information on overall 
concentration levels and source identification using simple upwind and 
downwind comparisons.\31\ Combined with on-site meteorological 
measurements, 2-week time-integrated passive monitoring has been shown 
to provide useful facility emission diagnostics.
---------------------------------------------------------------------------

    \31\ Thoma, et al., 2011.
---------------------------------------------------------------------------

    There are several drawbacks of time-integrated sampling, including 
the lack of immediate feedback on the acquired data and the loss of 
short-term temporal information. Additionally, time-integrated 
monitoring usually requires the collected sample to be transported to 
another location for analysis, leading to possible sample integrity 
problems (e.g., sample deterioration, loss of analytes, and 
contamination from the surrounding environment). However, time-
integrated monitoring systems are generally lower-cost and require less 
labor than time-resolved monitoring systems. Furthermore, while passive 
diffusive tube monitoring employs time-integrated sampling, these time-
integrated samples still represent much shorter time intervals (2 
weeks) than many of the current source-specific monitoring and 
inspection requirements (annually or less frequently). Consequently, 
passive diffusive tube monitoring still allows earlier detection of 
significant fugitive emissions than conventional source-specific 
monitoring.
    Active monitoring station networks are similar to passive diffusive 
tube monitoring networks in that a series of discrete sampling sites 
are established; however, each sampling location uses a pump to 
actively draw ambient air at a known rate through an adsorption tube. 
Because of the higher sampling rate, adsorption tubes can be analyzed 
on a daily basis, providing additional time resolution compared to 
diffusive tube sampling systems. Alternatively, the active sampling 
system can directly feed an analyzer for even more time resolution. 
However, this direct analysis of ambient air generally has higher 
detection limits than when the organic vapors are collected and 
concentrated on an adsorption matrix prior to analysis. Active 
monitoring stations have been used for a variety of pollutants in a 
variety of settings and the methods are well-established. However, 
compared to the passive diffusive tube monitoring stations, the 
sampling system is more expensive, more labor-intensive, and generally 
requires highly-trained staff to operate.
    UV-DOAS fenceline monitoring is an ``open-path'' technology. An 
electromagnetic energy source is used to emit a beam of electromagnetic 
energy (ultraviolet radiation) into the air towards a detection system 
some distance from the energy source (typically 100 to 500 meters). The 
electromagnetic energy beam interacts with components in the air in the 
open path between the energy source and the detector. The detector 
measures the disruptions in the energy beam to determine an average 
pollutant concentration across the open path length. Because the UV-
DOAS system can monitor integrated concentrations over a fairly long 
path-length, fewer monitoring ``stations'' (energy source/detector 
systems) would be needed to measure the ambient concentration around an 
entire refinery. However, each UV-DOAS monitoring system is more 
expensive than an active or passive monitoring station and generally 
requires significant instrumentation shelter to protect the energy 
source and analyzer when used for long-term (ongoing) measurements. 
Advantages of UV-DOAS systems include providing real-time measurement 
data with detection limits in the low parts per billion range for 
certain compounds. Fog or other visibility issues (e.g., dust storm, 
high pollen, wildfire smoke) will interfere with the measurements. UV-
DOAS systems have been used for fenceline monitoring at several U.S. 
petroleum refineries and petrochemical plants. UV-DOAS monitoring 
systems are specifically included as one of the measurement techniques 
suitable under EPA's Other Test Method 10 (OTM-10).\32\
---------------------------------------------------------------------------

    \32\ ``Optical Remote Sensing for Emission Characterization from 
Non-Point Sources.'' Final ORS Protocol, June 14, 2006. Available 
at: http://www.epa.gov/ttn/emc/prelim/otm10.pdf.
---------------------------------------------------------------------------

    Open-path FTIR is similar to UV-DOAS monitoring except that an 
infrared light source and detector system are used. Like the UV-DOAS 
monitoring approach, the open-path FTIR monitoring system will measure 
the average pollutant concentration across the open path length between 
the infrared source and detector. Path lengths and equipment costs for 
an open-path FTIR system are similar to those for a UV-DOAS system, and 
the open-path FTIR system provides real-time measurement data. The 
open-path FTIR system has spectral interferences with water vapor, CO 
and CO2, which can impact the lower detection limit for 
organic vapors. Open-path FTIR fenceline monitoring has also been used 
to measure ambient air concentrations around several petroleum 
refineries and petrochemical plants. Open-path FTIR is specifically 
included as a measurement technique in EPA's OTM-10. Although open-path 
FTIR can be used to measure a larger number of compounds than UV-DOAS, 
the detection limit of open-path FTIR for benzene is higher than for 
UV-DOAS, as noted in OTM-10. In other words, open-path FTIR is not as 
sensitive to benzene levels as is UV-DOAS. As benzene is an important 
pollutant from fugitive sources at petroleum refineries and can often 
be used as a surrogate for other organic HAP emissions, this high 
detection limit for benzene is a significant disadvantage. Thus, for 
the purposes of measuring organic HAP from fugitive sources at the 
fenceline of a petroleum refinery, a UV-DOAS monitoring system is 
expected to be more sensitive than an open-path FTIR system. As the 
cost and operation of open-path FTIR and UV-DOAS systems are very 
comparable, the benzene detection limit issue is a significant 
differentiator between these two methods when considering fenceline 
monitoring to measure fugitives around a petroleum refinery.
    DIAL monitoring systems employ a pulsed laser beam across the 
measurement path. Small portions of the light are backscattered due to 
particles and aerosols in the measurement path. This backscattered 
light is collected through a telescope system adjacent to the laser and 
measured via a sensitive light detector. The timing of the received 
light provides a measure of the distance of

[[Page 36922]]

the emission plume. Two different wavelengths of light are pulsed in 
quick succession: one wavelength that is absorbed strongly by the 
pollutant of interest and one that is not absorbed. The difference in 
the returned signal strength between these two light pulses provides a 
measure of the concentration of the pollutant. Thus, a unique advantage 
of the DIAL monitoring system is that it can provide spatially resolved 
pollutant concentrations in two dimensions. Measurements can be made in 
a relatively short period of time, so the method also provides good 
time resolution.
    The DIAL monitoring system has been used in a variety of studies to 
measure emissions from petroleum refinery and petrochemical sources. It 
is typically used for specific, shorter-term studies (one to several 
weeks in duration). The equipment is expensive, has limited 
availability in the U.S., and requires highly trained professionals to 
operate. Although DIAL monitoring is included as an appropriate method 
for EPA's OTM-10, there are no known long-term applications of this 
technology for the purpose of fenceline monitoring. Given the limited 
availability of the equipment and qualified personnel to operate the 
equipment, we do not consider DIAL monitoring to be technically 
feasible for the purposes of ongoing, long-term fenceline monitoring.
    The last fenceline monitoring method evaluated was solar 
occultation flux. Solar occultation flux uses the sun as the light 
source and uses an FTIR or UV detector to measure the average pollutant 
concentration across the measurement path. In this case, the 
measurement path is vertical. In order to measure the concentrations 
around an industrial source, the measurement device is installed in a 
specially equipped van, which is slowly driven along the perimeter of 
the facility. Measurement signal strength and a global positioning 
system (GPS) enables determination of pollutant concentrations along 
the perimeter of the site. This method provides more spatial resolution 
of the emissions than the UV-DOAS or open-path FTIR methods and is less 
expensive than a DIAL system. It has the advantage that only one 
monitoring system is needed per facility, assuming a mobile device is 
used. Disadvantages of this method include the need of full-time 
personnel to drive the equipment around the perimeter of the facility 
(or the need to buy a detector for each measurement location around the 
perimeter of the facility, if set locations are used), potential 
accessibility issues for some fenceline locations (e.g., no road near 
the fenceline), and the measurement method cannot be used at night or 
during cloudy periods. It would be possible to purchase numerous 
detection devices and establish fixed monitoring stations similar to 
the passive or active monitoring approaches described earlier, but this 
would be very expensive. Furthermore, any application of solar 
occultation flux is dependent on the sun, so this approach would mean 
significant periods each calendar day when the monitoring system would 
not be able to provide data. Based on our evaluation of this 
technology, we determined that this method is not a reasonable approach 
for monitoring fenceline concentrations of pollutants around a 
petroleum refinery on a long-term, ongoing basis. We are soliciting 
comment on the application of alternative monitoring techniques 
previously discussed for purposes of fenceline monitoring at 
refineries.
    Costs associated with fenceline monitoring alternatives. Based on 
our review of available monitoring methods, we determined that the 
following monitoring methods were technically feasible and appropriate 
for monitoring organic HAP from fugitive emission sources at the 
fenceline of a petroleum refinery on a long-term basis: (1) Passive 
diffusive tube monitoring networks; (2) active monitoring station 
networks; (3) UV-DOAS fenceline monitoring; and (4) open-path FTIR. 
While DIAL monitoring and solar occultation flux monitoring can be used 
for short-term studies, we determined that these methods were not 
appropriate for continuous monitoring at petroleum refineries. This 
section evaluates the costs of these technically feasible monitoring 
methods. As noted previously, the cost identified for the open-path 
monitoring methods (UV-DOAS and FTIR) are very similar. Therefore, we 
developed costs for only the UV-DOAS system because this method 
provides lower detection limits for pollutants of interest 
(specifically, benzene).
    Costs for the fenceline monitoring methods are dependent on the 
sampling frequency (for passive and active monitoring locations) and 
the number of monitoring locations needed based on the size and 
geometry of the facility. For the open-path methods, we estimated that 
four monitoring systems (along the east, west, north and south 
fencelines) would be needed, regardless of the size of the refinery. 
Some fencelines at larger refineries may be too long for a single open 
path length, but we did not vary the number of detectors needed for the 
open-path systems based on refinery size in order to provide a 
reasonable lower-cost estimate for the open-path monitoring option. For 
small petroleum refineries (less than 750 acres), we estimated 12 
passive or active monitoring stations would be sufficient. For medium-
sized refineries (750 to 1,500 acres), we estimated 18 monitoring 
stations would be required; for large refineries (greater than 1,500 
acres), we estimated that 24 monitoring stations would be needed. For 
the passive diffusive tube monitoring we assumed a 2-week sampling 
interval; for active monitoring stations, we assumed a daily sampling 
frequency.
    We estimated the first year installation and equipment costs for 
the passive tube monitoring system could cost up to $100,000 for larger 
refineries (i.e., 24 sampling locations). Annualized costs for ongoing 
monitoring are projected to be approximately $40,000 per year, assuming 
the ongoing sample analyses are performed in-house. Capital costs for 
active sampling systems were estimated to be approximately twice that 
of the passive system for the larger refinery. Ongoing costs were more 
than 10 times higher, however, due to the daily sampling frequency. 
Equipment costs for a single UV-DOAS system were estimated to be about 
$100,000, so a complete fenceline monitoring system (four systems plus 
shelters) was estimated to cost more than $500,000. A refinery using 
this technology for two fenceline locations estimated the annualized 
cost of calibrating and maintaining these systems approaches $1-million 
per year. (See Fenceline Monitoring Technical Support Document, in 
Docket ID Number EPA-HQ-OAR-2010-0682).
    Table 9 provides the nationwide costs of the monitoring approaches 
as applied to all U.S. petroleum refineries.

[[Page 36923]]



            Table 9--Nationwide Cost Impacts of Fenceline Monitoring Options at Petroleum Refineries
----------------------------------------------------------------------------------------------------------------
                                                                              Annual operating  Total annualized
         Monitoring option             Monitoring option      Capital cost    costs (million $/ costs (million $/
                                          description          (million $)           yr)               yr)
----------------------------------------------------------------------------------------------------------------
1..................................  Passive diffusive                  12.2              3.83              5.58
                                      tube monitoring
                                      network.
2..................................  Active sampling                    20.6              30.2              33.1
                                      monitoring network.
3..................................  Open-path monitoring               71.0              35.5              45.6
                                      (UV-DOAS, FTIR).
----------------------------------------------------------------------------------------------------------------

    The primary goal of a fenceline monitoring network is to ensure 
that owners and operators properly monitor and manage fugitive HAP 
emissions. As explained further in this preamble section, we are 
proposing a concentration action level that was derived by modeling 
fenceline benzene concentrations (as a surrogate for HAP) at each 
facility after full compliance with the refinery MACT standards, as 
amended by this proposed action. As such, we are proposing a fenceline 
benzene concentration that all facilities in the category can meet, 
according to the emissions inventories reported in response to the 2011 
Refinery ICR. Therefore, we do not project a HAP emission reduction 
that the fenceline monitoring network will achieve. However, if an 
owner or operator has underestimated the fugitive emissions from one or 
more sources, or if a leak develops or a tank seal or fitting fails, a 
fenceline monitoring system would provide for identification of such 
leaks much earlier than current monitoring requirements and, where 
emissions are beyond those projected from implementation of the MACT 
standards, would help ensure that such emissions are quickly addressed. 
We note that any costs for a fugitive monitoring system would be 
offset, to some extent, by product recovery since addressing these 
leaks more quickly than would otherwise occur based on the more 
infrequent monitoring required would reduce product losses.
    Based on the low cost and relative benefits of passive monitoring, 
which include the ability to generate time-integrated concentration 
measurements at low detection limits, coupled with relative ease of 
deployment and analysis, the EPA is proposing to require refineries to 
deploy passive time-integrated samplers at the fenceline. These 
samplers would monitor the level of fugitive emissions that reach the 
fenceline from all fugitive emission sources at the facility. The EPA 
is proposing to require fugitive emission reductions if fenceline 
concentrations exceed a specified concentration action level, as 
described further below. These proposed fenceline monitoring 
requirements complement the EPA's proposal to allow the use of the 
optical gas imaging camera as described in Appendix K of 40 CFR part 60 
as an alternative work practice for measuring emissions from equipment 
leaks, in lieu of monitoring with EPA Method 21 of 40 CFR part 60, 
Appendix A-7 (see section IV.B.1.c of this preamble for further 
discussion). Both approaches utilize low-cost methods to help ensure 
that total fugitives from a facility are adequately controlled.
    Because there is no current EPA test method for passive diffusive 
tube monitoring, as part of this action we are proposing specific 
monitor citing and sample collection requirements as EPA Method 325A of 
40 CFR part 63, Appendix A, and specific methods for analyzing the 
sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A. 
We are proposing to establish an ambient concentration of benzene at 
the fenceline that would trigger required corrective action. A brief 
summary of the proposed fenceline sampling requirements and our 
rationale for selecting the corrective action concentration levels are 
provided below.
    Siting, design and sampling requirements for fenceline monitors. 
The EPA is proposing that passive fenceline monitors collecting 2-week 
time-integrated samples be deployed to measure fenceline concentrations 
at refineries. We are proposing that refineries deploy passive samplers 
at 12 to 24 points circling the refinery perimeter. A primary 
requirement for a fenceline monitoring system is that it provides 
adequate spatial coverage for determination of representative pollutant 
concentrations at the boundary of the facility or operation. In an 
ideal scenario, fenceline monitors would be placed so that any fugitive 
plume originating within the facility would have a high probability of 
intersecting one or more monitors, regardless of wind direction. This 
proposed monitoring program would require that monitors be placed at 15 
to 30 degree intervals along the perimeter of the refinery, depending 
on the size of the facility. For small refineries (less than 750 
acres), monitors should be placed at 30 degree intervals, for a total 
of 12 locations; for facilities that are larger than 750 acres and less 
than 1,500 acres, monitors should be placed at 20 degree intervals, at 
18 locations; and for facilities greater than 1,500 acres, monitors 
should be placed at 15 degree intervals, accounting for 24 locations. 
We have also established an alternative siting procedure where monitors 
can be placed every 2,000 feet along the fenceline of the refinery, 
which may be easier to implement, especially for irregularly-shaped 
facilities. In proposing these requirements for the number and location 
of required monitors, the EPA assumes that all portions of the facility 
are contiguous such that it is possible to define a single facility 
boundary or perimeter, although this perimeter may be irregular in 
shape. We request comment on how these monitoring requirements should 
be adapted for instances where one or more portions of the facility are 
not contiguous, and on the number and location of facilities for which 
special fenceline monitoring requirements to accommodate non-contiguous 
operations might apply.
    We are proposing that the highest concentration of benzene, as an 
annual rolling average measured at any individual monitor and adjusted 
for background (see below), would be compared against the concentration 
action level in order to determine if there are significant excess 
emissions of fugitive emissions that need to be addressed. Existing 
sources would be required to deploy samplers no later than 3 years 
after the effective date of the final rule; new sources would be 
required to deploy samplers by the effective date of the final rule or 
startup, whichever is later. Because the proposed concentration action 
level is composed of 1 year's worth of data, we are proposing that 
refinery owners and operators would be required to demonstrate 
compliance with the concentration action level for the first time 1 
year following the compliance date, and thereafter on a 1-year rolling 
annual average basis (i.e., considering results from the most recent 26 
consecutive 2-week sampling intervals and recalculating the average 
every 2 weeks).

[[Page 36924]]

    Benzene as an appropriate target analyte. Passive diffusive tube 
monitors can be used to determine the ambient concentration of a large 
number of compounds. However, different sorbent materials are typically 
needed to collect compounds with significantly different properties. 
Rather than require multiple tubes per monitoring location and require 
a full analytical array of compounds to be determined, which would 
significantly increase the cost of the proposed fenceline monitoring 
program, we are proposing that the fenceline monitors be analyzed 
specifically for benzene. Refinery owners or operators may elect to do 
more detailed speciation of the emissions, which could help identify 
the process unit that may be contributing to a high fenceline 
concentration, but we are only establishing monitoring requirements and 
action level requirements for benzene. We consider benzene to be an 
excellent surrogate for organic HAP from fugitive sources for multiple 
reasons. First, benzene is ubiquitous at refineries, and is present in 
nearly all refinery process streams such that leaking components 
generally will leak benzene at some level (in addition to other 
compounds). Benzene is also present in crude oil and gasoline, so most 
storage tank emissions include benzene. As described previously in our 
discussion of wastewater treatment systems, benzene is also a very good 
surrogate for organic HAP emissions from wastewater and is already 
considered a surrogate for organic HAP emissions in the wastewater 
treatment system control requirements in Refinery MACT 1. Second, the 
primary releases of benzene occur at ground level as fugitive emissions 
from process equipment, storage vessels and wastewater collection and 
treatment systems, and the highest ambient benzene concentrations 
outside the facility will likely occur near the property boundary near 
ground level, so fugitive releases of benzene will be effectively 
detected at the ground-level monitoring sites. According to the 
emissions inventory we have relied on for this proposed action, 85 
percent of benzene emissions from refineries result from ground-level 
fugitive emissions from equipment and wastewater collection and 
treatment (see the Component 2 database contained in Docket ID Number 
EPA-HQ-OAR-2010-0682). Finally, benzene is present in nearly all 
process streams. Therefore, the presence of benzene at the fenceline is 
also an indicator of other air toxics emitted from fugitive sources at 
refineries.
    For the reasons discussed above, we believe that benzene is the 
most appropriate pollutant to monitor. We believe that other compounds, 
such as PAH or naphthalene, would be less suitable indicators of total 
fugitive HAP for a couple of reasons. First, they are prevalent in 
stack emissions as well as fugitive emissions, so there is more 
potential for fenceline monitors to pick up contributions from non-
fugitive sources. In contrast, almost all benzene comes from fugitive 
sources, so monitoring for benzene increases our confidence that the 
concentration detected at the fenceline is from fugitives. Second, as 
compared to benzene, these other compounds are expected to be present 
at lower concentrations and, therefore, would be more difficult to 
measure accurately using fenceline monitoring. We request comments on 
the suitability of selecting benzene or other HAP, including PAH or 
naphthalene, as the indicator to be monitored by fenceline samplers. We 
also request comment on whether it would be appropriate to require 
multiple HAP to be monitored at the fenceline considering the capital 
and annual cost for additional monitors, and if so, which pollutants 
should be monitored.
    Adjusting for background benzene concentrations. Under this 
proposed approach, absolute measurements along a facility fenceline 
cannot completely characterize which emissions are associated with the 
refinery and which are associated with other background sources. The 
EPA recognizes that sources outside the refinery boundaries may 
influence benzene levels monitored at the fenceline. Furthermore, 
background levels driven by local upwind sources are spatially 
variable. Both of these factors could result in inaccurate estimates of 
the actual contribution of fugitive emissions from the facility itself 
to the concentration measured at the fenceline. Many refineries and 
petrochemical industries are found side-by-side along waterways or 
transport corridors. With this spatial positioning, there is a 
possibility that the local upwind neighbors of a facility could cause 
different background levels on different sides of the facility. To 
account for background concentrations (i.e., to remove the influence of 
benzene emissions from sources outside the refinery on monitored 
fenceline values), we are proposing to adjust monitored fenceline 
values to account for background concentrations as described below. We 
solicit comments on alternative approaches for making these adjustments 
for background benzene.
    Fenceline-deployed passive samplers measure concentrations that 
originate from both the observed facility and from off-site sources. 
The relative contribution of the facility versus off-site source(s) to 
the measured concentration depends on the emission levels of the 
observed facility and off-site sources (including both near-field and 
remote sources), transporting wind direction and atmospheric 
dispersion. The ability to identify facility and off-site source 
contributions is reliant on the measurement scheme selected. The most 
basic (and lowest cost) approach involves different calculations using 
2-week deployed samplers located only at the facility fenceline. 
Greater discrimination capability is found by adding passive samplers 
to specific areas of the facility, reducing the time duration of the 
passive samplers, and coupling measured meteorology information to the 
passive sampler analysis. Selective use of time-resolved monitoring or 
wind sector sampling approaches provides the highest source and 
background discrimination capability. The approach we are proposing 
seeks to remove off-site source contributions to the measured fenceline 
concentrations to the greatest extent possible using the most cost-
effective measurement solutions.
    The highest fenceline concentration (HFC) for each 2-week sampling 
period can be expressed as:

HFC = Maximum x (MFC-OSCi)

Where:

HFC = highest fenceline concentration, corrected for background.
MFCi = measured fenceline concentration for the sampling 
period at monitoring location i.
OSCi = estimated off-site source contribution for the 
sampling period at monitoring location i.

    The off-site source contribution (OSC) consists of two primary 
components: (1) A slowly varying, spatially uniform background (UB) 
concentration and, in some cases, (2) potential near-field interfering 
sources.

OSCi = UB + NFSi

Where:

UB = uniform background concentration.
NFSi = near-field interfering source concentration 
contribution at monitoring location i.

    In some deployment scenarios (such as spatially isolated 
facilities), the major off-site source component can be identified as 
background concentrations that are uniform across the facility 
fenceline and neighboring area. In this

[[Page 36925]]

scenario, a UB concentration level can be determined and subtracted 
from the measured fenceline concentrations for each sampling period. 
This can be accomplished through use of facility-measured or otherwise 
available, quality assured time-resolved (or wind sector-resolved) 
background monitoring data, or from placement of additional passive 
samplers at upwind locations away from the facility fenceline and other 
sources.
    In other scenarios, such as where other industrial sources or a 
highway are located nearby, background concentrations are likely not 
uniform. These outside sources would influence some, but not perhaps 
not all, fenceline monitors and, therefore, the true ``background'' 
concentration would vary, depending where on the fenceline the 
measurement was taken. In this case, background is not uniform, and 
monitoring location-specific near-field interfering source (NFS) values 
would need to be determined.
    Due to the difficulties associated with determining location-
specific NFS values, we are proposing to approximate OSC by using the 
lowest measured concentration (LMC) at the facility fenceline for that 
period. In this case, the HFC for the monitoring period, corrected for 
background, would be calculated as:

HFC [ap] [Delta]C = HMC-LMC

Where:

[Delta]C = concentration difference between the highest and lowest 
measured concentrations for the sampling period.
HMC = highest measured fenceline concentration for the sampling 
period.
LMC = lowest measured fenceline concentration for the sampling 
period.

    This alternative is directly applicable for all refinery locations 
and requires no additional, off-site, upwind monitors, the placement of 
which is impossible to prescribe a priori. Use of LMC provides a 
reasonable proxy for OSC in most cases, but can over- or underestimate 
OSC in some cases. In locations where there are few upwind source 
contributions and where wind direction is relatively consistent, upwind 
passive samples on the fenceline can provide a realistic approximation 
of the actual off-site background levels. As the meteorology becomes 
more complicated (e.g., mixed wind directions, higher percentage of 
calm winds), the LMC will reflect a progressively larger amount of 
emissions from the facility itself, so differential calculations may 
underestimate the true HFC for some monitoring periods (by 
inadvertently allowing some facility emissions to be subtracted as part 
of ``background''). On the other hand, if a near-field source impacts 
the highest measured concentration monitoring location significantly, 
but contributes little to the monitoring location with the LMC, the LMC 
differential calculation (i.e., [Delta]C) could lead to an artificially 
elevated assessment of the highest fenceline concentration, corrected 
for background.
    Based on our examination of previous fenceline monitoring results, 
we expect that the use of the LMC differential will provide an accurate 
method by which to determine HFC. Therefore, we are not proposing to 
limit the use of the LMC differential calculation in cases where there 
are no near-field sources and where mixed wind direction (or calm wind) 
is common. In these special cases, use of the UB concentration alone 
(no NFS term) may be more accurate than using LMC. We are seeking 
comment on how to identify conditions under which the LMC differential 
may underestimate the highest fenceline concentration, corrected for 
background, and the need to require facilities to determine and use UB 
rather than LMC in these cases.
    We also recognize that under different site-specific conditions, 
the NFS contribution may affect certain fenceline monitoring stations 
more than others, causing the LMC differential calculation to 
overestimate the facility's contribution to the highest fenceline 
concentration. Therefore, we are also proposing to allow owners or 
operators of petroleum refineries to develop site-specific monitoring 
plans to determine UB and NFSi.
    If standard 2-week passive fenceline data and site analysis 
indicate potential near-field off-site source interferences at a 
section of the refinery, the proposal allows the owner or operator to 
conduct additional sampling strategies to determine a local background 
(OSC term) for use in the HFC calculation. The owner or operator would 
be required to report the basis for this correction, including analyses 
used to identify the sources and contribution of benzene concentration 
to the passive sampler concentration, within 45 days of the date the 
owner or operator first measures an exceedance of the concentration 
action level.
    We envision that facilities would implement these additional 
strategies to refine fenceline concentration estimates only if 
appropriate given site-specific characteristics and only if HFC 
determined by the LMC approach is likely to exceed the concentration 
action level (see discussion below regarding this action level). 
Facilities with HFC below the concentration action level based on the 
simple LMC differential calculation would not be required to make any 
further demonstration of the influence of background sources on 
concentrations measured at the fenceline. For facilities where 
additional background adjustment is appropriate, optional strategies 
could include deployment of additional passive samplers at distances 
from the fenceline (toward and away from suspected NFS) and reducing 
the time intervals of passive deployments to increase time resolution 
and wind direction-comparison capability. In complex cases, such as two 
refineries sharing a common fenceline, wind-sector sampling or various 
forms of time-resolved monitoring may be required to ascertain the 
fenceline concentrations.
    We are proposing that owners or operators of petroleum refineries 
electing to determine monitoring location-specific NFS concentrations 
must prepare and submit a site-specific monitoring plan. The monitoring 
plan is required to identify specific near-field sources, identify the 
location and type of monitors used to determine UB and NFS 
concentrations, identify the monitoring location(s) for which the NFS 
concentrations would apply, and delineate the calculations to be used 
to determine monitoring location specific NFS concentrations (for those 
monitoring locations impacted by the near-field source). We are 
proposing that the site-specific monitoring plan must be submitted to 
the Administrator for approval and receive approval prior to its use 
for determining HFC values.
    The EPA requests comment on the most appropriate approach(es) for 
adjusting measured fenceline concentrations for background 
contributions, including (in complex cases) where meteorology is highly 
variable or where one or more near-field off-site sources affect the 
measured fenceline concentration (MFC) at a refinery. We are also 
seeking comment on the adequacy of the proposed requirements for 
developing and approving site-specific monitoring plans.
    Concentration action level. As mentioned above, the EPA is 
proposing to require refineries to take corrective action to reduce 
fugitive emissions if monitored fenceline concentrations exceed a 
specific concentration action level on a rolling annual average basis 
(recalculated every two weeks). We selected this proposed fenceline 
action level by modeling fenceline benzene concentrations using the 
emissions inventories reported in response to the 2011 Refinery ICR, 
assuming that those reported emissions represented full compliance with 
all refinery MACT requirements, adjusted for additional control 
requirements we are proposing

[[Page 36926]]

in today's action. Thus, if the reported inventories are accurate, all 
facilities should be able to meet the fenceline concentration action 
level. We estimated the long-term ambient post-control benzene 
concentrations at each petroleum refinery using the post-control 
emission inventory and EPA's American Meteorological Society/EPA 
Regulatory Model dispersion modeling system (AERMOD). Concentrations 
were estimated by the model at a set of polar grid receptors centered 
on each facility, as well as surrounding census block centroid 
receptors extending from the facility outward to 50 km. For purposes of 
this modeling analysis, we assumed that the nearest off-site polar grid 
receptor was the best representation of each facility's fenceline 
concentration in the post-control case, unless there was a census block 
centroid nearer to the fenceline than the nearest off-site polar grid 
receptor or an actual receptor was identified from review of the site 
map. In those instances, we estimated the fenceline concentration as 
the concentration at the census block centroid. Only receptors (either 
the polar or census block) that were estimated to be outside the 
facility fenceline were considered in determining the maximum benzene 
level for each facility. We note that this analysis does not correlate 
to any particular metric related to risk. The maximum post-control 
benzene concentration modeled at the fenceline for any facility is 9 
micrograms per cubic meter ([micro]g/m\3\) (annual average). (For 
further details of the analysis, see memo entitled Fenceline Ambient 
Benzene Concentrations Surrounding Petroleum Refineries in Docket ID 
Number EPA-HQ-OAR-2010-0682.)
    The facility inventories generally project emissions with the 
required fugitive controls working as designed (e.g., no tears in seals 
for storage vessel floating roofs and water in all water drain seals). 
If facility inventories are correct, annual average benzene 
concentrations would not exceed 9 [micro]g/m\3\ at the fenceline of any 
facility. Because the modeling approach considers only the emissions 
from the refinery, with no contribution from background or near-field 
sources, this concentration is comparable to the highest modeled 
fenceline concentration after correcting for background concentrations, 
as described previously. The EPA is proposing to set the standard at 
this concentration action level. We also note that this modeling effort 
evaluated the annual average benzene concentration at the fenceline, so 
that this action level applies to the annual average fenceline 
concentration measured at the facility.
    The EPA recognizes that, because it is difficult to directly 
measure emissions from fugitive sources, there is significant 
uncertainty in current emissions inventories for fugitives. Thus, there 
is the potential for benzene concentrations monitored at the fenceline 
to exceed modeled concentrations. However, given the absence of 
fenceline monitors at most facilities, there is very limited 
information available at present about fenceline concentrations and the 
extent to which they may exceed concentrations modeled from 
inventories. In the absence of additional data regarding the 
concentration of fugitive emissions of benzene at the fenceline, the 
EPA believes it is reasonable to rely on the maximum modeled fenceline 
value as the concentration action level. We are soliciting comment on 
alternative concentration action levels and other approaches for 
establishing the concentration action level.
    Due to differences in short-term meteorological conditions, short-
term (i.e., two-week average) concentrations at the fenceline can vary 
greatly. Given the high variability in short-term fenceline 
concentrations and the difficulties and uncertainties associated with 
estimating a maximum 2-week fenceline concentration given a limited 
number of years of meteorological data used in the modeling exercise, 
we determined that it would be inappropriate and ineffective to propose 
a short-term concentration action level that would trigger corrective 
action based on a single 2-week sampling event.
    One objective for this monitoring program is to identify fugitive 
emission releases more quickly, so that corrective action can be 
implemented in a more timely fashion than might otherwise occur without 
the fenceline monitoring requirement. We believe the proposed fenceline 
monitoring approach and a rolling annual average concentration action 
limit (i.e., using results from the most recent 26 consecutive 2-week 
samples and recalculating the average every 2 weeks) will achieve this 
objective. The proposed fenceline monitoring will provide the refinery 
owner or operator with fenceline concentration information once every 2 
weeks. Therefore, the refinery owner or operator will be able to timely 
identify emissions leading to elevated fenceline concentrations. We 
anticipate that the refinery owners or operators will elect to identify 
and correct these sources early, in efforts to avoid exceeding the 
annual benzene concentration action level.
    An ``exceedance'' of the benzene concentration action level would 
occur when the rolling annual average highest fenceline concentration, 
corrected for background (determined as described previously), exceeds 
9 [micro]g/m\3\. Upon exceeding the concentration action level, we 
propose that refinery owners or operators would be required to conduct 
analyses to identify sources contributing to fenceline concentrations 
and take corrective action to reduce fugitive emissions to ensure 
fenceline benzene concentrations remain at or below 9 [micro]g/m\3\ 
(rolling annual average).
    Corrective action requirements. As described previously, the EPA is 
proposing that the owner or operator analyze the samples and compare 
the rolling annual average fenceline concentration, corrected for 
background, to the concentration action level. This section summarizes 
the corrective action requirements in this proposed rule. First, we are 
proposing that the calculation of the rolling annual average fenceline 
concentration must be completed within 30 days after the completion of 
each sampling episode. If the rolling annual average fenceline benzene 
concentration, corrected for background, exceeds the proposed 
concentration action level (i.e., 9 [mu]g/m\3\), the facility must, 
within 5 days of comparing the rolling annual average concentration to 
the concentration action level, initiate a root cause analysis to 
determine the primary cause, and any other contributing cause(s), of 
the exceedance. The facility must complete the root cause analysis and 
implement corrective action within 45 days of initiating the root cause 
analysis. We are not proposing specific controls or corrections that 
would be required when the concentration action level is exceeded 
because the cause of an exceedance could vary greatly from facility to 
facility and episode to episode, since many different sources emit 
fugitive emissions. Rather, we are proposing to allow facilities to 
determine, based on their own analysis of their operations, the action 
that must be taken to reduce air concentrations at the fenceline to 
levels at or below the concentration action level, representing full 
compliance with all refinery MACT requirements, adjusted for additional 
control requirements we are proposing in today's action.
    If, upon completion of the corrective action described above, the 
owner or operator exceeds the action level for the next two-week 
sampling episode following the completion of a first set of corrective 
actions, the owner or operator

[[Page 36927]]

would be required to develop and submit to EPA a corrective action plan 
that would describe the corrective actions completed to date. This plan 
would include a schedule for implementation of emission reduction 
measures that the owner or operator can demonstrate is as soon as 
practical. This plan would be submitted to the Administrator for 
approval within 30 days of an exceedance occurring during the next two-
week sampling episode following the completion of the initial round of 
corrective action. The EPA would evaluate this plan based on the 
ambient concentrations measured, the sources identified as contributing 
to the high fenceline concentration, the potential emission reduction 
measures identified, and the emission reduction measures proposed to be 
implemented in light of the costs of the options considered and the 
reductions needed to reduce the ambient concentration below the action 
level threshold. To minimize burden on the state implementing agencies 
and provide additional resources for identifying potential emission 
sources, we are proposing not to delegate approval of this plan. The 
refinery owner or operator is not deemed out of compliance with the 
proposed concentration action level, provided that the appropriate 
corrective action measures are taken according to the time-frame 
detailed in an approved corrective action plan.
    The EPA requests comment on whether it is appropriate to establish 
a standard time frame for compliance with actions listed in a 
corrective action plan. We also request comment on whether the approval 
of the corrective action plan should be delegated to state, local and 
tribal governments.
    The EPA's post-control dispersion modeling (described in section 
III.A of this preamble), which relies on reported emissions inventories 
from the 2011 Refinery ICR, adjusted to reflect compliance with the 
existing refinery MACT standards as modified by the additional controls 
proposed in this rulemaking, indicates that fugitive emissions at all 
refineries are low enough to ensure that fenceline concentrations of 
benzene do not exceed the proposed concentration action level. Assuming 
the reported inventories and associated modeling are accurate, we 
expect that few, if any, facilities will need to engage in required 
corrective action. We do, however, expect that facilities may identify 
``poor-performing'' sources (e.g., unusual leaks) from the fenceline 
monitoring data and, based on this additional information, will take 
action to reduce HAP emissions before they would have otherwise been 
aware of the issue through existing inspection and enforcement 
measures.
    By selecting a fenceline monitoring approach and by selecting 
benzene as the surrogate for organic HAP emissions, we believe that the 
proposed monitoring approach will effectively target refinery MACT-
regulated fugitive emission sources. However, there may be instances 
where the fenceline concentration is impacted by a low-level 
miscellaneous process vent, heat exchange system or other similar 
source. As these sources are regulated under Refinery MACT 1 and the 
emissions from these sources were included in our post-control modeling 
file (from which the 9 [mu]g/m\3\ fenceline concentration action level 
was developed), sources would not be able to avoid taking corrective 
action by claiming the exceedance of the fenceline concentration was 
from one of these emission points rather than from fugitive emission 
sources.
    There may be instances in which the high fenceline concentration is 
impacted by a non-refinery emission source. The most likely instance of 
this would be leaks from HON equipment or HON storage vessels co-
located at the refinery. However, we consider the fenceline monitoring 
requirement to be specific to refinery emission sources. Therefore, we 
are proposing to allow refinery owners or operators to develop site-
specific monitoring plans to determine the impact of these non-Refinery 
emission sources on the ambient benzene concentration measured at the 
fenceline. This monitoring plan would be identical to those used by 
refinery owners or operators that elect to determine monitoring 
location-specific NFS values for nearby off-site sources. In this case, 
however, the NFS is actually within the refinery fenceline. Upon 
approval and implementation of the monitoring plan, the refinery owner 
or operator would determine the highest fenceline concentration 
corrected for background; the background correction in this case 
includes a correction for the co-located non-Refinery emission 
source(s).
    The EPA requests comment on whether the corrective action 
requirements should be limited to exceedances of the fenceline 
concentration solely from refinery emission sources and whether a 
refinery owner or operator should be allowed to exceed the annual 
average fenceline concentration action level if they can demonstrate 
the exceedance of the action level is due to a non-refinery emissions 
source. We also request comment on the requirements proposed for 
refinery owners or operators to demonstrate that the exceedance is 
caused by a non-refinery emissions source. Specifically, we request 
comment on whether the ``near-field source'' correction is appropriate 
for on-site sources and whether there are other methods by which 
refinery owners or operators with co-located, non-refinery emission 
sources can demonstrate that their benzene concentrations do not exceed 
the proposed fenceline concentration action level.
    Additional requirements of the fenceline monitoring program. We are 
proposing that fenceline data at each monitor location be reported 
electronically for each semiannual period's worth of sampling periods 
(i.e., 13 to 14 2-week sampling periods per semiannual period). These 
data would be reported within 45 days of the end of each semiannual 
period, and will be made available to the public through the EPA's 
electronic reporting and data retrieval portal, in keeping with the 
EPA's efforts to streamline and reduce reporting burden and to move 
away from hard copy submittals of data where feasible.
    We are proposing to require the reporting of raw fenceline 
monitoring data, and not just the HFC, on a semiannual basis; 
considering the fact that the fenceline monitoring standard is a new 
approach for fugitive emissions control, and it involves the use of new 
methods, both analytical and siting methods, this information is 
necessary for the EPA to evaluate whether this standard has been 
implemented correctly. Further, the information provided by the raw 
data, such as the need for additional or less monitoring sites, the 
range of measured concentrations, the influence of background sources, 
and the ability to collect and compare data from all refineries, will 
inform us of further improvements we can make to the fenceline 
standard, monitoring and analytical methods, approaches for estimating 
refinery fugitive emissions, and guidance that may be helpful to 
improve implementation of the fenceline monitoring approach. We seek 
comment on suggestions for other ways we can monitor and improve the 
fenceline monitoring requirement.
    We are proposing that facilities be required to conduct fenceline 
monitoring on a continuous basis, in accordance with the specific 
methods described above, even if benzene concentrations, as measured at 
the fenceline, routinely are substantially lower than the concentration 
action level. In light of the low annual

[[Page 36928]]

monitoring and reporting costs associated with the fenceline monitors 
(as described in the next section), and the importance of the fenceline 
monitors as a means of ensuring the control of fugitives achieves the 
expected emission levels, we believe it is appropriate to require 
collection of fenceline monitoring data on a continuous basis. However, 
the EPA recognizes that fugitive benzene emissions from some facilities 
may be so low as to make it improbable that exceedances of the 
concentration action level would ever occur.
    In the interest of reducing the cost burden on facilities to comply 
with this rule, the EPA solicits comment on approaches for reducing or 
eliminating fenceline monitoring requirements for facilities that 
consistently measure fenceline concentrations below the concentration 
action level, and the measurement level that should be used to provide 
such relief. Such an approach would be consistent with graduated 
requirements for valve leak monitoring in Refinery MACT 1 and other 
equipment leak standards, where the frequency of required monitoring 
varies depending on the percent of leaking valves identified during the 
previous monitoring period (see, for example, 40 CFR 63.648(c) and 40 
CFR 63.168(d)). The EPA requests comment on the minimum time period 
facilities should be required to conduct fenceline monitoring; the 
level of performance, in terms of monitored fenceline concentrations, 
that would enable a facility to discontinue use of fenceline monitors 
or reduce the frequency of data collection and reporting; and any 
adjustments to the optical gas imaging camera requirements that would 
be necessary in conjunction with such changes to the fenceline 
monitoring requirements.
i. Delayed Coking Units
    As noted in section IV.A of this preamble, we are soliciting 
comments on the need to establish MACT standards for DCU under CAA 
section 112(d)(2) and (3). Even if we were to assume that there is 
already an applicable MACT standard for DCU, a technology review of 
this emission source, as prescribed under CAA section 112(d)(6), would 
lead us to propose a depressurization limit of 2 psig because of 
technology advancements since the MACT standards were originally issued 
and because it is cost effective. Industry representatives have pointed 
out that Refinery NSPS Ja requires DCU at new and modified sources to 
depressure to 5 psig, and they have indicated that EPA should not 
require a lower depressurization limit under a CAA section 112(d)(6) 
technology review. Further, industry representatives also provided 
summary-level information (available in Docket ID Number EPA-HQ-OAR-
2010-0682 as correspondence from API entitled Coker Vent Potential 
Release Limit Preliminary Emission, Cost and Cost Effectiveness 
Estimates) on costs to depressure to 5 psig versus 2 psig. While the 
cost information does not show large differences for any particular 
facility to depressure at 5 psig versus 2 psig, the information does 
show a large range in potential costs between refineries. At this time, 
we do not have the detailed, refinery-specific cost breakdowns to 
compare against our cost assumptions, which were derived from data 
obtained for a facility that did install the necessary equipment to 
meet a 2 psig limit. We also do not have detailed information on the 
design and operation of the DCU in industry's cost study to evaluate 
whether there are any differences that would warrant subcategories. We 
solicit information on designs, operational factors, detailed costs and 
emissions data for DCU, and we specifically solicit comments on what 
should be the appropriate DCU depressurization limit if we were to 
adopt such a requirement pursuant to CAA section 112(d)(6) rather than 
pursuant to CAA section 112(d)(2) and (3).
2. Refinery MACT 2--40 CFR Part 63, Subpart UUU
    The Refinery MACT 2 source category regulates HAP emissions from 
FCCU, CRU and SRU process vents. Criteria pollutant emissions from FCCU 
and SRU are regulated under 40 CFR part 60, subparts J and Ja (Refinery 
NSPS J and Refinery NSPS Ja, respectively). We conducted a technology 
review of Refinery NSPS J emission limits from 2005 to 2008 and 
promulgated new standards for FCCU and SRU (among other sources) in 
Refinery NSPS Ja on June 24, 2008 (73 FR 35838). Our current technology 
review of Refinery MACT 2 relies upon, but is not limited to, 
consideration of this recent technology review of Refinery NSPS J for 
FCCU and SRU.
a. FCCU Process Vent
    The FCCU has one large atmospheric vent, the coke burn-off exhaust 
stream for the unit's catalyst regenerator. HAP emissions from this 
FCCU process vent include metal HAP associated with entrained catalyst 
particles and organic HAP, mostly by-products of incomplete combustion 
from the coke burn-off process. As the control technologies associated 
with each of these classes of pollutants are very different, the 
controls associated with each of these classes of pollutants are 
considered separately.
    Metal HAP emission controls. The current Refinery MACT 2 includes 
several different compliance options, some based on PM as a surrogate 
for total metal HAP and some based on nickel (Ni) as a surrogate for 
total metal HAP. Refinery NSPS J was the basis of the PM emission 
limits and the metal HAP MACT floor in Refinery MACT 2. Refinery NSPS J 
limits PM from FCCU catalyst regeneration vents to 1.0 gram particulate 
matter per kilogram (g PM/kg) of coke burn-off, with an additional 
incremental PM allowance for liquid or solid fuel burned in an 
incinerator, waste heat boiler, or similar device. Refinery MACT 2 
states that FCCU subject to Refinery NSPS J PM emission limits are 
required to demonstrate compliance with Refinery NSPS J PM emission 
limits as specified in Refinery NSPS J. As provided in Refinery NSPS J, 
ongoing compliance with the PM emission limits is determined by 
compliance with a 30-percent opacity limit, except for one 6-minute 
average per hour not to exceed 60-percent opacity. FCCU not subject to 
Refinery NSPS J may elect to comply with the FCCU PM provisions in 
Refinery NSPS J. Alternatively, they may comply with a 1.0 g PM/kg of 
coke burn-off emission limit in Refinery MACT 2 (with no provision for 
an additional incremental PM allowance for liquid or solid fuel burned 
in an incinerator, waste heat boiler, or similar device). Compliance 
with this limit in Refinery MACT 2 is demonstrated by either a 1-hour 
average site-specific opacity limit using a continuous opacity 
monitoring system (COMS) or APCD-specific daily average operating 
limits using CPMS.
    Refinery MACT 2 also includes two emission limit alternatives that 
use Ni, rather than PM, as the surrogate for metal HAP. The first of 
these Ni alternatives is a mass emission limit of 13 grams Ni per hour; 
the second nickel alternative is an emission limit of 1.0 milligrams Ni 
per kilogram of coke burn-off. Compliance with the Ni emission limits 
in Refinery MACT 2 is demonstrated by either a daily average site-
specific Ni operating limit (using a COMS and weekly determination of 
Ni concentration on equilibrium FCCU catalyst), or APCD-specific daily 
average operating limits using CPMS and monthly average Ni 
concentration operating limit for the equilibrium FCCU catalyst.
    Under Refinery MACT 2, an initial performance demonstration (source 
test) is required to show that FCCU is

[[Page 36929]]

compliant with the emission limits selected by the refinery owner or 
operator. No additional performance test is required for facilities 
already complying with Refinery NSPS J. The performance test is a one-
time requirement; additional performance tests are only required if the 
owner or operator elects to establish new operating limits, or to 
modify the FCCU or control system in such a manner that could affect 
the control system's performance.
    Under the review for Refinery NSPS J, we conducted a literature 
review as well as a review of the EPA's refinery settlements and state 
and local regulations affecting refineries to identify developments in 
practices, processes and control technologies to reduce PM emissions 
from refinery sources (see Summary of Data Gathering Efforts: Emission 
Control and Emission Reduction Activities, August 19, 2005, and Review 
of PM Emission Sources at Refineries, December 20, 2005, Docket Item 
Number EPA-HQ-OAR-2007-0011-0042). At that time, we identified 
regulations for PM from FCCU that were more stringent than the Refinery 
NSPS J requirements for PM, and we promulgated more stringent PM limits 
in Refinery NSPS Ja. Refinery NSPS Ja limits PM from FCCU catalyst 
regeneration vents to 1.0 g PM/kg of coke burn-off for modified or 
reconstructed FCCU, with no incremental allowance for PM-associated 
liquid or solid fuels burned in a post-combustion device. Furthermore, 
an emission limit of 0.5 g PM/kg of coke burn-off was established for 
FCCU constructed after May 14, 2007.
    In addition, the Refinery NSPS J review identified improvements in 
APCD monitoring practices, which were included in the Refinery NSPS Ja 
standards. Refinery NSPS J includes a 30-percent opacity limit as the 
only ongoing monitoring requirements for PM from the FCCU. This 30-
percent opacity limit has shown to be lenient and high in comparison to 
recent federal rules that have included more stringent opacity limits 
(e.g., 40 CFR part 60, subpart Db with 20-percent opacity), and recent 
state and local agency rules that omit opacity limits altogether in 
favor of operating limits for the emission control systems. Based on 
the Refinery NSPS J review, Refinery NSPS Ja does not include an 
opacity limit, but includes updated and more appropriate monitoring 
approaches, such as requiring bag leak detectors (BLD) for fabric 
filter control systems, and requiring CPMS for electrostatic 
precipitators (ESP) and wet scrubbers. Additionally, Refinery NSPS Ja 
includes an option to measure PM emissions directly using a PM CEMS. 
For this monitoring alternative, a direct PM concentration limit 
(equivalent to the conventional FCCU PM emission limit in terms of g 
PM/kg of coke burn-off) is included in the rule. Finally, in our review 
for Refinery NSPS J, we noted that, even with improved monitoring 
methods, periodic source testing is needed to verify the performance of 
the control system as it ages. In Refinery NSPS Ja, annual performance 
demonstrations are required for affected FCCU. The Refinery NSPS Ja 
standards for PM from FCCU reflect the latest developments in 
practices, processes and control technologies. In our current review of 
Refinery MACT 2, we did not identify any other developments in 
practices, processes or control technologies since we promulgated 
Refinery NSPS Ja in 2008.
    The conclusions of the technology review conducted for the Refinery 
NSPS J PM emission limits are directly applicable to Refinery MACT 2; 
the initial Refinery MACT 2 rule recognized this by providing that 
compliance with Refinery NSPS J would also be compliance with Refinery 
MACT 2. We considered the impacts of proposing to revise Refinery MACT 
2 to incorporate the developments in monitoring practices and control 
technologies reflected in the Refinery NSPS Ja limits and monitoring 
provisions.
    As noted above, Refinery NSPS Ja includes a limit of 0.5 g PM/kg of 
coke burn-off for newly constructed sources. There would be no costs 
associated with requiring the lower emission limit of 0.5 g PM/kg of 
coke burn-off for Refinery MACT 2 new sources under CAA section 
112(d)(6) because these sources would already be required to comply 
with that limit under Refinery NSPS Ja. Therefore, we are proposing 
that it is necessary pursuant to CAA section 112(d)(6) to revise 
Refinery MACT 2 to incorporate the Refinery NSPS Ja PM limit for new 
sources.
    We are also proposing to establish emission limits and monitoring 
requirements in Refinery MACT 2 that are consistent with those in 
Refinery NSPS Ja. This option would not impose any additional cost on 
sources already subject to Refinery NSPS Ja. We note that for 
facilities subject to Refinery NSPS J, this would not lead to 
duplicative or conflicting monitoring requirements because Refinery 
NSPS J already includes a provision that allows affected facilities 
subject to Refinery NSPS J to instead comply with the provisions in 
Refinery NSPS Ja (see 40 CFR 60.100(e)).
    In addition, in conjunction with our proposal to revise Refinery 
MACT 2 to include the more stringent requirements in Refinery NSPS Ja, 
we are proposing to remove the less stringent compliance option of 
meeting the requirements of Refinery NSPS J. As described previously, 
Refinery NSPS J includes an incremental PM emissions allowance for 
post-combustion devices and relies on a 30-percent opacity limit that 
is outdated and has been demonstrated to be ineffective at identifying 
exceedances of the 1.0 g PM/kg coke burn-off emissions limit.
    We also reviewed the compliance monitoring requirements for the 
Refinery MACT 2 PM and Ni-based emission limits. As described 
previously, Refinery MACT 2 includes operating limits based on APCD 
operating parameters or site-specific opacity limits. There are 
differences between the monitoring approaches in Refinery MACT 2 for 
these limits and Refinery NSPS Ja monitoring approaches for the NSPS PM 
limit, so we evaluated whether it is necessary, pursuant to CAA section 
112(d)(6), to revise the monitoring provisions in Refinery MACT 2 
consistent with the requirements in Refinery NSPS Ja.
    The first significant difference is in the averaging times used for 
the different operating limits. Refinery NSPS Ja requires a 3-hour 
rolling average for the operating limits for parametric monitoring 
systems; Refinery MACT 2 includes daily averaging of the operating 
limits. Typically, the averaging time for operating limits is based on 
the duration of the performance test used to establish those operating 
limits. As the performance test duration is 3 hours (three 1-hour test 
runs) and compliance with the PM (or Ni) emission limit is based on the 
average emissions during this 3-hour period, the most appropriate 
averaging period for these operating limits is 3 hours. Using a daily 
average could allow poor performance (i.e., control equipment for 
shorter periods (e.g., 3-hour averages that are higher than the PM 
emissions limit in Refinery NSPS Ja). For example, assume an operating 
limit developed from a performance test has a value of 1 and that 
values exceeding this level would suggest that the control system is 
not operating as well as during the performance test (i.e., potentially 
exceeding the PM emission limit). If the control system is run for 18 
hours operating at a level of 0.9 and 6 hours at a level of 1.2, the 
unit would be in compliance with the daily operating limit even though 
the unit may have 6 consecutive hours during which the operating limit 
was exceeded.

[[Page 36930]]

Reducing the averaging time does not impact the types of monitors 
required; it merely requires the owner or operator of the unit to pay 
more careful attention to the APCD operating parameters. We are 
proposing that it is necessary, pursuant to CAA section 112(d)(6), to 
incorporate the use of 3-hour averages rather than daily averages for 
parameter operating limits in Refinery MACT 2 for both the PM and Ni 
limits, because this is a cost-effective development in monitoring 
practice.
    The site-specific opacity operating limit for PM in Refinery MACT 2 
(for units not electing to comply with Refinery NSPS J) has a 1-hour 
averaging period, but the Ni operating limits (which use opacity 
monitoring) have a 24-hour averaging period. These averaging periods 
are inconsistent with the duration of the performance test, which is 
over a 3-hour period. We are proposing, pursuant to CAA section 
112(d)(6), to incorporate the use of 3-hour averages for the site-
specific opacity operating limit and the Ni operating limits rather 
than daily averages because this is a cost-effective development in 
monitoring practice.
    We also compared the APCD-specific operating parameters used in 
Refinery MACT 2 to those that we promulgated for Refinery NSPS Ja. The 
Refinery NSPS Ja rule includes monitoring approaches that are not 
included in Refinery MACT 2. These include the option of using PM CEMS 
and requiring BLD for fabric filter control systems. Adding a PM CEMS 
as an option for demonstrating compliance with the Refinery MACT 2 PM 
limit (similar to what is provided in Refinery NSPS Ja) would not 
impact the costs of complying with Refinery MACT 2 because sources can 
choose whether or not to adopt this monitoring method. With respect to 
BLD, there is only one refinery that currently uses a baghouse (fabric 
filter) to control emissions from its FCCU (although one additional 
unit has indicated that it has plans to install a fabric filter control 
within the next few years). Under the existing requirements in Refinery 
MACT 2 (assuming that the FCCU currently operating with a fabric filter 
has not elected to comply with the Refinery NSPS J PM emission limit 
option), it is required to comply with a site-specific opacity 
operating limit. For new, reconstructed, or modified FCCU, Refinery 
NSPS Ja requires use of BLD. While we generally consider the BLD to be 
superior to opacity monitors for ensuring fabric filter control systems 
are operating efficiently, it is difficult to determine what, if any, 
increment in assurance that the unit is properly controlled would be 
achieved by requiring the one facility currently operating a fabric 
filter control system and complying with a site-specific opacity 
operating limit to switch from a COMS to BLD. Therefore, we are 
proposing that it is not necessary to require the one existing FCCU 
with a fabric filter control system to switch from COMS to a BLD system 
because this would require additional monitoring equipment (with 
additional costs) and little to no associated increase in assurance 
that the unit is properly controlled. Although we are not proposing to 
require existing sources using a fabric filter to use BLD, we are 
proposing to include BLD as an option to COMS; owners or operators of 
FCCU using fabric filter-type control systems at existing sources can 
elect (but are not required) to use BLD in lieu of COMS and the site-
specific opacity operating limit.
    The Refinery NSPS Ja monitoring requirements for ESP include CPMS 
for monitoring and recording the total power and the secondary current 
to the entire system. The current MACT requires monitoring voltage and 
secondary current or monitoring only the total power to the APCD. While 
these monitoring requirements are similar, we consider that the 
Refinery NSPS Ja requirements will provide improved operation of the 
ESP. As the monitors required to measure these parameters are a routine 
part of ESP installations, we project no additional costs for 
monitoring equipment. We expect that a new performance test would be 
needed to ensure that both total power and secondary current are 
recorded during the source test. As discussed later in this section, we 
are proposing to require ongoing performance tests regardless of the 
monitoring option, so we are not projecting any additional costs 
specific to revising the monitoring requirements for ESP. Because the 
Refinery NSPS Ja monitoring and operating requirements for ESP are 
expected to provide improved performance of the APCD with no 
incremental costs, we propose that it is necessary, pursuant to CAA 
section 112(d)(6), to incorporate the total power and the secondary 
current operating limits into Refinery MACT 2.
    Refinery NSPS Ja provides a specific monitoring alternative to 
pressure drop for jet ejector-type wet scrubbers or any other type of 
wet scrubbers equipped with atomizing spray nozzles. Owners or 
operators of FCCU controlled by these types of wet scrubbers can elect 
to perform daily checks of the air or water pressure to the spray 
nozzle rather than monitor pressure. Refinery MACT 2 currently excludes 
these types of control systems from monitoring pressure drop but 
includes no specific monitoring to ensure the jet ejectors or atomizing 
spray nozzle systems are properly operating. Since proper functioning 
of the jet ejectors or atomizing spray nozzles is critical to ensuring 
these control systems operate at the level contemplated by the MACT, 
some monitoring/inspection requirement of these components is necessary 
to ensure compliance with the FCCU PM or Ni emission limit. The owner 
or operator of a jet ejector-type wet scrubber or other type of wet 
scrubber equipped with atomizing spray nozzles should be performing 
routine checks of these systems, such as the daily checks of the air or 
water pressure to the spray nozzles, as required in Refinery NSPS Ja. 
These daily checks are consistent with good operational practices for 
wet scrubbers and should not add significant burden to the FCCU wet 
scrubber owner or operator. For these reasons, we propose it is 
necessary to require owners or operators of a jet ejector-type wet 
scrubber or other type of wet scrubber equipped with atomizing spray 
nozzles to perform daily checks of the air or water pressure to the 
spray nozzles pursuant to CAA section 112(d)(6).
    Finally, in our action promulgating Refinery NSPS Ja, we noted 
that, even with improved monitoring methods, periodic source testing is 
needed to verify the performance of the control system as it ages. In 
Refinery NSPS Ja, annual performance demonstrations are required for 
new sources. FCCU subject to Refinery MACT 2 as new sources would also 
be subject to Refinery NSPS Ja and would have to comply with the annual 
testing requirements in Refinery NSPS Ja. However, Refinery MACT 2 does 
not include periodic performance tests for any FCCU. We considered 
adding an annual testing requirement for FCCU subject to Refinery MACT 
2. The annual nationwide cost burden exceeds $1 million per year and we 
project only modest improvement in control performance resulting from 
the performance demonstrations. We considered requiring FCCU 
performance tests once every 5 years (i.e., once per title V permit 
period). The nationwide annual cost of this additional testing 
requirement for FCCU is projected to be, on average, $213,000 per year. 
We consider this to be a reasonable minimum frequency for which 
affected sources should demonstrate direct compliance with the FCCU 
emission limits and that this cost is reasonable. Therefore, we propose 
that it is

[[Page 36931]]

necessary, pursuant to CAA section 112(d)(6), to require a performance 
test once every 5 years for all FCCU under to Refinery MACT 2.
    Organic HAP. Refinery MACT 2 uses CO as a surrogate for organic HAP 
and establishes an emission limit of 500 ppmv CO (dry basis). Some 
FCCU, referred to as complete-combustion FCCU, employ excess oxygen in 
the FCCU regenerator and are able to meet this emission limit without 
the need for a post-combustion device. Other FCCU, referred to as 
partial-combustion FCCU, do not supply enough air/oxygen for complete 
combustion of the coke to CO2 and, therefore, produce a 
significant quantity of CO in the regenerator exhaust. Partial-
combustion FCCU are typically followed by a post-combustion unit, 
commonly referred to as a CO boiler, to burn the CO in the regenerator 
exhaust in order to meet the 500 ppmv CO limit (and to recover useful 
heat from the exhaust stream).
    In our review of Refinery NSPS J, we conducted a review of state 
and local regulations affecting refineries to identify control 
strategies to reduce CO emissions or VOC emissions from refinery 
sources (see Review of VOC Emission Sources at Refineries, December 14, 
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0043). We also conducted 
a review of federal, state and local regulations affecting refineries 
to identify control strategies to reduce CO emissions from refinery 
sources (see Review of CO Emission Sources at Refineries, December 22, 
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0044). We did not 
identify any developments in practices, processes and control 
technologies to reduce CO or VOC emissions from FCCU as part of the 
review of Refinery NSPS J, and we have not identified any developments 
in practices, processes and control technologies for FCCU that would 
reduce organic HAP since promulgation of Refinery MACT 2. We are 
proposing that it is not necessary to revise the regulatory provisions 
for organic HAP in the current MACT standards for FCCU, pursuant to CAA 
section 112(d)(6).
    Inorganic HAP. As mentioned previously, Refinery MACT 2 includes a 
CO emission limit of 500 ppmv. Although this limit is expressly 
provided as a limit addressing organic HAP emissions, this emission 
limit is also expected to limit the emissions of oxidizable inorganic 
HAP, such as HCN. That is, the CO concentration limit was developed as 
an indicator of complete combustion for all oxidizable pollutants 
typically found in exhaust gas from the FCCU regenerator operated in 
partial burn mode. We note that HCN concentrations in FCCU regenerator 
exhaust with high CO levels also have high HCN concentrations and that 
HCN concentrations in the regenerator exhaust from complete-combustion 
FCCU (those meeting the 500 ppmv CO limit without the need for a post-
combustion device) are much lower than those from partial burn FCCU 
prior to a post-combustion device. Thus, we consider that the CO 
emission limit also acts as a surrogate for the control of oxidizable 
inorganic HAP, such as HCN.
    The source test data from the ICR effort revealed that HCN 
emissions from FCCU are greater than previous tests indicated, 
particularly for complete-combustion FCCU. The increase in HCN 
emissions was observed at units meeting lower NOX emission 
limits, which have recently been required by consent decrees, state and 
local requirements and Refinery NSPS Ja. The higher HCN emissions from 
complete-combustion FCCU appear to be directly related to operational 
changes made in efforts to meet these lower NOX emission 
limits (e.g., reduced excess oxygen levels in the regenerator and 
reduced regenerator bed temperatures). These higher HCN emissions were 
only observed in complete-combustion FCCU; FCCU that operated in 
partial burn mode followed by a CO boiler or similar post-combustion 
device had significantly lower HCN emissions subsequent to the post-
combustion device.
    Based on our review of the available ICR data and the technologies 
used in practice, we considered establishing specific emission limits 
for HCN. In order to comply with emission limits for HCN, owners or 
operators of complete-combustion FCCU would either have to operate 
their FCCU regenerator at slightly higher temperatures and excess 
oxygen concentrations (to limit the formation of HCN in the 
regenerator) or employ a post-combustion device or thermal oxidizer to 
destroy HCN exhausted from the FCCU regenerator. However, each of these 
options comes with significant secondary energy and environmental 
impacts. First, both of these control strategies would yield a 
significant increase in NOX emissions. We anticipate that 
most FCCU owners or operators would have to install a selective 
catalytic reduction (SCR) system to meet their NOX emission 
limits, if applicable. Operation of the SCR would have energy impacts 
and may have additional secondary PM2.5 impacts (associated 
with ammonia slip from the SCR). We expect that modifying the 
regenerator operating characteristics is the most cost-effective 
option, although installing and using a thermal oxidizer may be 
necessary, depending on the operational characteristics of the 
regenerator and the HCN control requirement. Using a thermal oxidizer 
to treat FCCU regenerator exhaust, a gas stream that has limited 
heating value (due to the already low CO concentrations) would be much 
more expensive and would have additional energy and secondary impacts 
associated with the auxiliary fuel needed for the device, as compared 
to modifying regenerator operating conditions.
    We first performed a screening analysis of the impacts of making 
only operational changes to the FCCU with the highest HCN 
concentrations. If this control option is not cost effective for these 
FCCU, it would not be cost effective for units that have lower HCN 
concentrations and lower HCN emissions. Similarly, if operating changes 
in the FCCU regenerator alone are not cost effective, then we can 
assume that installing a thermal oxidizer to achieve this same level of 
HCN emission reductions would also not be cost effective. We calculated 
the cost of changing the regenerator parameters and adding an SCR for 
the FCCU with the highest HCN emissions rate reported in the ICR, which 
is an annual emissions rate of 460 tpy. This is also the largest FCCU 
in operation in the United States and its territories. Based on the 
size of this unit, we project that an SCR would be expected to cost 
approximately $13-million and have annualized costs of approximately 
$4.0-million/yr. Thus, if the HCN emissions can be reduced by 95 
percent, the cost effectiveness would be approximately $9,000 per ton 
of HCN. A smaller FCCU had similar HCN concentrations and annual HCN 
emissions of 141 tpy. Based on the size of this unit, we project an SCR 
would be expected to cost approximately $7-million and have annualized 
costs of approximately $1.5-million/yr. Assuming a 95-percent reduction 
in HCN emissions, the cost effectiveness would be approximately $11,000 
per ton of HCN. The second-highest emitting FCCU was larger than this 
unit, but had lower HCN concentrations. This third unit had emissions 
of 184 tpy. Based on the size of this unit, we expect that an SCR would 
cost approximately $9-million and have annualized costs of 
approximately $2.2-million/yr. Assuming a 95-percent reduction in HCN 
emissions, the cost effectiveness would be approximately $12,600 per 
ton of HCN.
    These costs are for the FCCU with the largest HCN emissions and the 
lowest control cost (assuming operational

[[Page 36932]]

changes alone are insufficient to significantly reduce HCN emissions), 
and the average cost effectiveness for these units exceeds $10,000 per 
ton HCN emissions reduced. Based on the economies of scale and 
considering lower HCN concentrations for all other units, the costs per 
ton of HCN removed for a nationwide standard would be higher. If a 
post-combustion device is needed to achieve a specific HCN emissions 
limit, the costs would be even higher.
    Based on the cost, secondary energy and secondary environmental 
impacts of an HCN emission limit beyond that achieved by the CO 
emission limit as a surrogate for HCN, we are proposing, at this time, 
that it is not necessary, pursuant to CAA section 112(d)(6), to revise 
the MACT standard to establish a separate HCN standard. As our 
understanding of the mechanisms of HCN and NOX formation 
improves and as catalyst additives evolve, it may be possible to 
achieve both low NOX and low HCN emissions without the use 
of an SCR and/or post-combustion controls. However, at this time our 
test data indicate an inverse correlation between these two pollutants. 
The three facilities with the highest HCN concentrations were the 
facilities with the lowest NOX concentrations, all of which 
were below 20 ppmv (dry basis, 0-percent excess air) during the 
performance tests. While a 20 ppmv NOX limit may be 
achievable, we anticipate that further reducing the NOX new 
source performance limits for FCCU would either increase 
PM2.5 secondary emissions (via the use of an SCR and its 
associated ammonia slip) or further increase HCN emissions (if 
combustion controls are used).
b. CRU Process Vents
    A CRU is designed to reform (i.e., change the chemical structure 
of) naphtha into higher-octane aromatics. The reforming process uses a 
platinum or bimetal (e.g., platinum and rhenium) catalyst material. 
Small amounts of coke deposit on the catalyst during the catalytic 
reaction and this coke is burned off the catalyst to regenerate 
catalyst activity. There are three types of CRU classified by 
differences in how the units are designed and operated to effect 
reforming catalyst regeneration. Semi-regenerative reforming is 
characterized by shutting down the reforming unit at specified 
intervals, or at the operator's convenience, for in situ catalyst 
regeneration. Semi-regenerative CRU typically regenerate catalyst once 
every 8 to 18 months, with the regeneration cycle lasting approximately 
2 weeks. Cyclic-regeneration reforming is characterized by continuous 
or continual reforming operation with periodic (but frequent) 
regeneration of catalyst in situ by isolating one of the reactors in 
the series, regenerating the catalyst, then returning the reactor to 
the reforming operation. The regeneration of the catalyst in a single 
reactor may occur numerous times per year (e.g., once a month), and the 
regeneration of each reactor may take 3 to 5 days to complete. 
Continuous-regeneration reforming units use moving catalyst bed 
reactors situated vertically (which is why they are often referred to 
as platforming units). Catalyst flows down the series of reactors. At 
the bottom of the last reactor, catalyst is continually isolated and 
sent to a special regenerator. After regeneration, the regenerated 
catalyst is continually fed to the first (top) reactor. Thus, 
continuous-regeneration reforming units are characterized by 
continuous-reforming operation along with continuous-regeneration 
operation.
    The catalytic reforming reaction is performed in a closed reactor 
system; there are no emissions associated with the processing portion 
of the CRU. There is a series of emission points associated with the 
CRU catalyst regenerator. Regardless of the type of CRU used, there is 
a series of steps conducted to effect catalyst regeneration. These 
steps are: (1) Initial depressurization/purge; (2) coke burn-off; (3) 
catalyst rejuvenation; and (4) reduction/final purge. The primary 
emissions during the depressurization/purge cycle are organic HAP. 
Inorganic HAP, predominately HCl and chlorine, are emitted during the 
coke burn-off and rejuvenation cycles. The reduction purge is mostly 
inert materials (nitrogen and/or hydrogen). Refinery MACT 2 contains 
organic HAP emission limits for the depressurization/purge cycle 
(purging prior to coke-burn-off) and inorganic HAP emission limits for 
the coke burn-off and catalyst rejuvenation cycles. Our technology 
review, summarized below, considers each of these emission limits 
separately. For additional details on the technology review for CRU, 
see Technology Review Memorandum for Catalytic Reforming Units at 
Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.
    Organic HAP. Refinery MACT 2 requires the owner or operator to 
comply with either a 98-percent reduction of TOC or non-methane TOC, or 
an outlet concentration of 20 ppmv or less (dry basis, as hexane, 
corrected to 3-percent oxygen). The emission limits for organic HAP for 
the CRU do not apply to emissions from process vents during 
depressuring and purging operations when the reactor vent pressure is 5 
psig or less. Control technologies used include directing the purge gas 
directly to the CRU process heater to be burned, recovering the gas to 
the facility's fuel gas system, or venting to a flare or other APCD. 
The pressure limit exclusion was provided to allow atmospheric venting 
of the emissions when the pressure of the vessel fell below that needed 
to passively direct the purge gas to the APCD (most commonly the CRU 
process heater or flare).
    We did not identify any developments in practices, processes and 
control technologies for reducing organic HAP emissions from CRU. 
However, as noted in section IV.A.2 of this preamble, we are proposing 
to amend the pressure limit exclusion pursuant to CAA sections 
112(d)(2) and (3) to clarify that this limit only applies during 
passive vessel depressuring. Also, as described in section IV.A.3 of 
this preamble, we are proposing revisions to Refinery MACT 1 and 2, 
pursuant to CAA sections 112(d)(2) and (3), to ensure flares used as 
APCD meet the required destruction efficiency, which includes flares 
used to control the organic HAP emissions from the CRU 
depressurization/purge vent streams.
    Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for 
inorganic HAP during the coke burn-off and rejuvenation cycles. 
Refinery MACT 2 requires owners or operators of existing semi-
regenerative CRU to reduce uncontrolled emissions of HCl by 92-percent 
by weight or to a concentration of 30 ppmv (dry basis, corrected to 3-
percent oxygen) during the coke burn-off and rejuvenation cycles. 
Owners or operators of new semi-regenerative CRU, new or existing 
cyclic CRU, or new or existing continuous CRU are required to reduce 
uncontrolled emissions of HCl by 97-percent by weight or to a 
concentration of 10 ppmv (dry basis, corrected to 3-percent oxygen) 
during the coke burn-off and rejuvenation cycles. Technologies used to 
achieve these limits include caustic spray injection, wet scrubbers, 
and solid adsorption systems. We conducted a technology review for CRU 
by reviewing the ICR responses and scientific literature. We did not 
identify any developments in practices, processes and control 
technologies for reducing inorganic HAP emissions from CRU. We are 
proposing that it is not necessary to revise the current inorganic HAP 
MACT standards for CRU, pursuant to CAA section 112(d)(6).

[[Page 36933]]

c. SRU Process Vents
    Most sulfur recovery plants at petroleum refineries use the Claus 
reaction to produce elemental sulfur. In the Claus reaction, two moles 
of hydrogen sulfide (H2S) react with one mole of 
SO2 in a catalytic reactor to form elemental sulfur and 
water vapor. Prior to the Claus reactors, one-third of the 
H2S in the sour gas feed to the sulfur plant must be 
oxidized to SO2 to have the correct proportion of 
H2S and SO2 for the Claus reaction. This 
oxidation step is performed in the ``Claus burner.'' The remaining gas 
stream, after the elemental sulfur is condensed, is referred to as 
``tail gas.'' HAP emissions in tail gas from sulfur recovery plants are 
predominately COS and CS2, which are primarily formed as 
side reactions of the Claus process.
    Refinery MACT 2 contains HAP standards for SRU that were based on 
the Refinery NSPS J SO2 and reduced sulfur compounds 
emission limits. Refinery NSPS J includes an emission limit of 300 ppmv 
reduced sulfur compounds for a reduction control system not followed by 
an incinerator, and an emission limit of 250 ppmv SO2 (dry 
basis, 0-percent excess air) for oxidative control systems or reductive 
control systems followed by incineration. These Refinery NSPS J limits 
apply only to Claus sulfur recovery plants with a sulfur recovery 
capacity greater than 20 long tons per day (LTD). These emission limits 
effectively required sulfur recovery plants to achieve 99.9-percent 
sulfur recovery.
    Refinery MACT 2 defines SRU as a process unit that recovers 
elemental sulfur from gases that contain reduced sulfur compounds and 
other pollutants, usually by a vapor-phase catalytic reaction of sulfur 
dioxide and hydrogen sulfide (see 40 CFR 63.1579). This definition 
specifically excludes sulfur recovery processes that do not recover 
elemental sulfur, such as the LO-CAT II process, but does not 
necessarily limit applicability to Claus SRU. Refinery MACT 2 requires 
owners or operators of an SRU that is subject to Refinery NSPS J to 
meet the Refinery NSPS J limits. Owners or operators of an SRU that is 
not subject to Refinery NSPS J can elect to meet the emission limits in 
Refinery NSPS J or meet a reduced sulfur compound limit of 300 ppmv 
(dry basis, 0-percent excess air) regardless of the type of control 
system or the presence of an incinerator. Unlike Refinery NSPS J, 
Refinery MACT 2 does not have a capacity applicability limit, so this 
300 ppmv reduced sulfur compound limit is applicable to all SRU (as 
that term is defined), regardless of size.
    Upon completion of our technology review for Refinery NSPS J, we 
promulgated Refinery NSPS Ja, which includes new provisions for the 
sulfur recovery plant. First, Refinery NSPS Ja limits are now 
applicable to all sulfur recovery plants, not just Claus sulfur 
recovery plants. Second, emission limits were added for sulfur recovery 
plants with a capacity of 20 LTD or less, to require new, small sulfur 
recovery plants to achieve a target sulfur recovery efficiency of 99-
percent. These limits are a factor of 10 higher than the emission 
limits for larger sulfur recovery plants (i.e., 3,000 ppmv reduced 
sulfur compounds for a reduction control system not followed by an 
incinerator and 2,500 ppmv SO2 for oxidative control systems 
or reductive control systems followed by incineration). Refinery NSPS J 
did not include emission limits for these smaller sulfur recovery 
plants. Third, new correlations were introduced to provide equivalent 
emission limits for systems that use oxygen-enriched air in their Claus 
burner.
    The technology review conducted for Refinery NSPS J focused on 
SO2 emissions. Under our current technology review for 
Refinery MACT 2, we considered the developments in practices, processes 
or control technologies identified in the Refinery NSPS J technology 
review as they pertain to HAP emissions and the existing Refinery MACT 
2 requirements.
    We considered the new Refinery NSPS Ja limits for small sulfur 
recovery plants. While Refinery NSPS Ja establishes criteria pollutant 
emission limits for these smaller sulfur recovery plants that were 
previously unregulated for such emissions, these sources are already 
covered under Refinery MACT 2. Refinery MACT 2 requires these SRU to 
meet a 300 ppmv reduced sulfur compound limit, which is more stringent 
than the 3,000 ppmv limit established in Refinery NSPS Ja.
    We also considered the new correlations in Refinery NSPS Ja for SRU 
that use oxygen-enriched air in their Claus burner. In the technology 
review under Refinery NSPS J, we identified a change in practice in the 
operation of certain Claus SRU. At the time we promulgated Refinery 
MACT 2, we assumed that all units were using ambient air in the Claus 
burner, and we established the same emission limits as in Refinery NSPS 
J. Now, however, we understand that some facilities are using oxygen-
enriched air. This practice lowers the amount of inert gases introduced 
into the SRU and improves operational performance and reliability of 
the sulfur recovery plant. Air is approximately 20.9 percent by volume 
oxygen and 79.1-percent inert gases (predominately nitrogen with 1-
percent argon and other inert gases). The inert gases introduced in the 
Claus burner become a significant portion of the overall tail gas flow. 
When oxygen enrichment is used in the Claus burner, there are fewer 
inert gases in the tail gas and a lower overall tail gas flow rate. The 
same molar flow rate of reduced sulfur compounds will be present in the 
tail gas, but without the additional flow of inerts from the ambient 
air, the concentration of the reduced sulfur compounds (or 
SO2) in the tail gas is higher.
    In developing Refinery NSPS Ja, we included a correlation equation 
that facilities can use to adjust the concentration limit based on the 
enriched-oxygen concentration used in the Claus burner. This equation 
is designed to allow the same mass of emissions for these units as is 
allowed for units using only ambient air. That is, the emission 
equation establishes a concentration limit for units using oxygen 
enrichment so that the mass emissions from the unit do not exceed the 
mass emissions allowed under the 250 ppmv SO2 (or 300 ppmv 
reduced sulfur compounds) emissions limits in Refinery NSPS J and in 
Refinery MACT 2. The new equation in Refinery NSPS Ja for large sulfur 
recovery plants (those with sulfur recovery greater than 20 LTD) 
provides an equivalent mass emissions rate of reduced sulfur HAP from 
the SRU as is currently required in Refinery MACT 2 while allowing a 
practice that improves the operational reliability of the unit. There 
are no costs to providing this option for units using oxygen-enriched 
air because: (1) It is an option that the owner or operator can elect 
to meet instead of the xisting 250 ppmv SO2 emissions limit 
and (2) owners or operators of SRU that use oxygen-enriched air are 
expected to already routinely monitor the inlet air oxygen 
concentration for operational purposes. Therefore, we are proposing 
that it is necessary, pursuant to CAA section 112(d)(6), to amend 
Refinery MACT 2 sulfur recovery requirements to include this equation 
that addresses the use of oxygen-enriched air as a development in 
practice in SRU process operations.
    The emission limits for large sulfur recovery plants (those with 
sulfur recovery greater than 20 LTD) in Refinery NSPS Ja are equivalent 
to those in Refinery MACT 2. We are proposing to allow owners or 
operators subject to Refinery NSPS Ja limits for sulfur

[[Page 36934]]

recovery plants with a capacity greater than 20 LTD to comply with 
Refinery NSPS Ja as a means of complying with Refinery MACT 2.
    We have not identified any additional developments in practices, 
processes or control technologies for HAP from SRU since development of 
Refinery NSPS Ja.

C. What are the results of the risk assessment and analyses?

1. Inhalation Risk Assessment Results
    Table 10 of this preamble provides an overall summary of the 
results of the inhalation risk assessment.

                  Table 10--Petroleum Refining Source Sector Inhalation Risk Assessment Results
----------------------------------------------------------------------------------------------------------------
                                   Estimated population  Estimated annual   Maximum chronic   Maximum screening
Maximum individual cancer risk  (-   at increased risk   cancer incidence  non-cancer TOSHI  acute non-cancer HQ
        in-1 million) \a\            levels of cancer    (cases per year)         \b\                \c\
----------------------------------------------------------------------------------------------------------------
                                                Actual Emissions
----------------------------------------------------------------------------------------------------------------
60...............................  >= 1-in-1 million:                 0.3               0.9  HQREL = 5
                                    5,000,000.                                               (Nickel Compounds).
                                   >= 10-in-1 million:
                                    100,000.
                                   >= 100-in-1 million:
                                    0.
----------------------------------------------------------------------------------------------------------------
                                             Allowable Emissions \d\
----------------------------------------------------------------------------------------------------------------
100..............................  >= 1-in-1 million:                 0.6                 1  --
                                    7,000,000 \e\.
                                   >= 10-in-1 million:
                                    Greater than 90,000
                                    \e\.
                                   >= 100-in-1 million:
                                    0.
----------------------------------------------------------------------------------------------------------------
\a\ Estimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category.
\b\ Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the
  thyroid system for actual emissions and the neurological system for allowable emissions.
\c\ The maximum off-site HQ acute value of 5 is driven by emissions of nickel from CCU. See section III.A.3 of
  this preamble for explanation of acute dose-response values. Acute assessments are not performed on allowable
  emissions because of a lack of detailed hourly emissions data. However, because of the conservative nature of
  the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be
  comparable to actual acute estimates.
\d\ The development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates
  for Modeled ``Allowable'' Emissions, which can be found in Docket ID Number EPA-HQ-OAR-2010-0682.
\e\ Population risks from allowable emissions were only calculated for the model plant emissions (REM) approach.
  For the 138 facilities modeled using the modeled plant approach the population risks greater than 10-in-1
  million was estimated to be 90,000. If we consider the second approach to determining allowable emissions
  (combined the results of the actual and REM emissions estimates) we estimate that the allowable population
  risks greater than 10-in-1 million would be greater than 90,000 people. Further, the number of people above 1-
  in-1 million would also be higher than the 7,000,000 estimated using the REM model.

    The inhalation risk modeling performed to estimate risks based on 
actual emissions relied primarily on emissions data from the ICR, 
updated based on our quality assurance review as described in section 
III.A.1 of this preamble.
    The results of the chronic baseline inhalation cancer risk 
assessment indicate that, based on estimates of current actual 
emissions, the maximum individual lifetime cancer risk (MIR) posed by 
the refinery source category is 60-in-1 million, with benzene and 
naphthalene emissions from equipment leaks and storage tanks accounting 
for 98 percent of the MIR risk. The total estimated cancer incidence 
from refinery emission sources based on actual emission levels is 0.3 
excess cancer cases per year or one case in every 3.3 years, with 
emissions of naphthalene, benzene, and 2-methylnaphthalene contributing 
22 percent, 21 percent and 13 percent, respectively, to this cancer 
incidence. In addition, we note that approximately 100,000 people are 
estimated to have cancer risks greater than 10-in-1 million, and 
approximately 5,000,000 people are estimated to have risks greater than 
1-in-1 million as a result of actual emissions from these source 
categories. When considering the MACT-allowable emissions, the maximum 
individual lifetime cancer risk is estimated to be up to 100-in-1 
million, driven by emissions of benzene and naphthalene from refinery 
fugitives (e.g., storage tanks, equipment leaks and wastewater) and the 
estimated cancer incidence is estimated to be 0.6 excess cancer cases 
per year or one excess case in every 1.5 years. Greater than 90,000 
people were estimated to have cancer risks above 10-in-1 million and 
approximately 7,000,000 people were estimated to have cancer risks 
above 1-in-1 million considering allowable emissions from all petroleum 
refineries.
    The maximum modeled chronic non-cancer HI (TOSHI) value for the 
source sector based on actual emissions was estimated to be less than 
1. When considering MACT-allowable emissions, the maximum chronic non-
cancer TOSHI value was estimated to be about 1.
2. Acute Risk Results
    Our screening analysis for worst-case acute impacts based on actual 
emissions indicates the potential for five pollutants--acetaldehyde, 
acrolein, arsenic, benzene and nickel--to exceed an HQ value of 1, with 
an estimated worst-case maximum HQ of 5 for nickel based on the REL 
values. This REL occurred at a facility reporting nickel emissions from 
the FCCU vent. One hundred thirty-six of the 142 petroleum refineries 
had an estimated worst-case HQ less than or equal to 1 for all HAP; 
except for the one facility that had an estimated REL of 5, the 
remaining 5 refineries with an REL above 1 had an estimated worst-case 
HQ less than or equal to 3.
    To better characterize the potential health risks associated with 
estimated worst-case acute exposures to HAP, and in response to a key 
recommendation from the SAB's peer review of EPA's RTR risk assessment 
methodologies, we examine a wider range of available acute health 
metrics than we do for our chronic risk assessments. This is in 
acknowledgement that there are generally more data gaps and 
inconsistencies in acute reference values than there are in chronic 
reference values. By definition, the acute CalEPA REL represents a 
health-

[[Page 36935]]

protective level of exposure, with no risk anticipated below those 
levels, even for repeated exposures; however, the health risk from 
higher-level exposures is unknown. Therefore, when a CalEPA REL is 
exceeded and an AEGL-1 or ERPG-1 level is available (i.e., levels at 
which mild effects are anticipated in the general public for a single 
exposure), we have used them as a second comparative measure. 
Historically, comparisons of the estimated maximum off-site 1-hour 
exposure levels have not been typically made to occupational levels for 
the purpose of characterizing public health risks in RTR assessments. 
This is because occupational ceiling values are not generally 
considered protective for the general public since they are designed to 
protect the worker population (presumed healthy adults) for short-
duration increases in exposure (less than 15 minutes). As a result, for 
most chemicals, the 15-minute occupational ceiling values are set at 
levels higher than a 1-hour AEGL-1, making comparisons to them 
irrelevant unless the AEGL-1 or ERPG-1 levels are also exceeded. Such 
is not the case when comparing the available acute inhalation health 
effect reference values for some of the pollutants considered in this 
analysis.
    The worst-case maximum estimated 1-hour exposure to acetaldehyde 
outside the facility fence line for the source categories is 1 mg/m\3\. 
This estimated worst-case exposure exceeds the 1-hour REL by a factor 
of 2 (HQREL=2) and is well below the 1-hour AEGL-1 
(HQAEGL-1=0.01) and the ERPG-1 (HQERPG-1=0.05).
    The worst-case maximum estimated 1-hour exposure to acrolein 
outside the facility fence line for the source categories is 0.005 mg/
m\3\. This estimated worst-case exposure exceeds the 1-hour REL by a 
factor of 2 (HQREL=2) and is below the 1-hour AEGL-1 
(HQAEGL-1=0.1) and the ERPG-1 (HQERPG-1=0.04).
    The worst-case maximum estimated 1-hour exposure to nickel 
compounds outside the facility fence line for the source categories is 
0.001 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour 
REL by a factor of 5 (HQREL=5). There are no AEGL, ERPG or 
short-term occupational values for nickel to use as comparison to the 
acute 1-hour REL value.
    The worst-case maximum estimated 1-hour exposure to arsenic 
compounds outside the facility fence line for the source categories is 
0.0004 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour 
REL by a factor of 2 (HQREL=2). There are no AEGL, ERPG or 
short-term occupational values for arsenic to use as comparison to the 
acute 1-hour REL value.
    The maximum estimated 1-hour exposure to benzene outside the 
facility fence line is 2.7 mg/m\3\. This estimated exposure exceeds the 
REL by a factor of 2 (HQREL=2), but is significantly below 
both the 1-hour ERPG-1 and AEGL-1 value (HQ ERPG-1 (or AEGL-1) = 0.02). 
This exposure estimate neither exceeds the AEGL-1/ERPG-1 values, nor 
does it exceed workplace ceiling level guidelines designed to protect 
the worker population for short-duration exposure (less than 15 
minutes) to benzene, as discussed below. The occupational short-term 
exposure limit (STEL) standard for benzene developed by the 
Occupational Safety and Health Administration is 16 mg/m\3\, ``as 
averaged over any 15-minute period.'' \33\ Occupational guideline STEL 
for exposures to benzene have also been developed by the American 
Conference of Governmental Industrial Hygienists (ACGIH) \34\ for less 
than 15 minutes \35\ (ACGIH threshold limit value (TLV)-STEL value of 
8.0 mg/m\3\), and by the National Institute for Occupational Safety and 
Health (NIOSH) \36\ ``for any 15 minute period in a work day'' (NIOSH 
REL-STEL of 3.2 mg/m\3\). These shorter duration occupational values 
indicate potential concerns regarding health effects at exposure levels 
below the 1-hour AEGL-1 value.
---------------------------------------------------------------------------

    \33\ 29 CFR 1910.1028, Benzene.
    \34\ ACGIH (2001) Benzene. In Documentation of the TLVs[supreg] 
and BEIs[supreg] with Other Worldwide Occupational Exposure Values. 
ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-
882417-74-1) and available online at http://www.acgih.org.
    \35\ The ACGIH definition of a TLV-STEL states that ``Exposures 
above the TLV-TWA up to the TLV-STEL should be less than 15 minutes, 
should occur no more than four times per day, and there should be at 
least 60 minutes between successive exposures in this range.''
    \36\ NIOSH. Occupational Safety and Health Guideline for 
Benzene; http://www.cdc.gov/niosh/docs/81-123/pdfs/0049.pdf.
---------------------------------------------------------------------------

    All other HAP and facilities modeled had worst-case acute HQ values 
less than 1, indicating that the HAP emissions are believed to be 
without appreciable risk of acute health effects. In characterizing the 
potential for acute non-cancer risks of concern, it is important to 
remember the upward bias of these exposure estimates (e.g., worst-case 
meteorology coinciding with a person located at the point of maximum 
concentration during the hour) and to consider the results along with 
the conservative estimates used to develop hourly emissions as 
described earlier, as well as the screening methodology. Refer to the 
memo in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-
2010-0682, Derivation of hourly emission rates for petroleum refinery 
emission sources used in the acute risk analysis) for a detailed 
description of how the hourly emissions were developed for this source 
sector.
3. Multipathway Risk Screening Results
    Results of the worst-case Tier I screening analysis indicate that 
PB-HAP emissions (based on estimates of actual emissions) from several 
facilities in this source sector exceed the screening emission rates 
for POM (PAH), CDDF, mercury compounds, and cadmium compounds. For the 
compounds and facilities that did not screen out at Tier I, we 
conducted a Tier II screen. The Tier II screen replaces some of the 
assumptions used in Tier I with site-specific data, including the land 
use around the facilities, the location of fishable lakes, and local 
wind direction and speed. The Tier II screen continues to rely on high-
end assumptions about consumption of local fish and locally grown or 
raised foods (adult female angler at 99th consumption for fish \37\ and 
90th percentile for consumption of locally grown or raised foods \38\) 
and uses an assumption that the same individual consumes each of these 
foods in high end quantities (i.e., that an individual has high end 
ingestion rates for each food). The result of this analysis was the 
development of site-specific emission screening levels for POM, CDDF, 
mercury compounds, and cadmium compounds. It is important to note that, 
even with the inclusion of some site-specific information in the Tier 
II analysis, the multi-pathway screening analysis is a still a very 
conservative, health-protective assessment (e.g., upper-bound 
consumption of local fish, locally grown, and/or raised foods) and in 
all likelihood will yield results that serve as an upper-bound multi-
pathway risk associated with a facility.
---------------------------------------------------------------------------

    \37\ Burger, J. 2002. Daily consumption of wild fish and game: 
Exposures of high end recreationists. International Journal of 
Environmental Health Research 12:343-354.
    \38\ U.S. EPA. Exposure Factors Handbook 2011 Edition (Final). 
U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/
052F, 2011.
---------------------------------------------------------------------------

    While the screening analysis is not designed to produce a 
quantitative risk result, the factor by which the emissions exceed the 
screening value serves as a rough gauge of the ``upper-limit'' risks we 
would expect from a facility. Thus, for example, if a facility emitted 
a PB-HAP carcinogen at a level 2 times the screening value, we can say 
with a high degree of confidence that the actual maximum cancer risks 
will be less than

[[Page 36936]]

2-in-1 million. Likewise, if a facility emitted a noncancer PB-HAP at a 
level 2 times the screening level, the maximum noncancer risks would 
represent a HQ less than 2. The high degree of confidence comes from 
the fact that the screens are developed using the very conservative 
(health-protective) assumptions that we describe above.
    Based on the Tier II screening analysis, one facility emits cadmium 
compounds above the Tier II screening level and exceeds that level by 
about a factor of 2. Twenty-three facilities emit CDDF as 2,3,7,8-
tetrachlorodibenzo-p-dioxin toxicity equivalent (TEQ) above the Tier II 
screening level, and the facility with the highest emissions of dioxins 
exceeds the Tier II screening level by about a factor of 40. No 
facilities emit mercury compounds above the Tier II screening levels. 
Forty-four facilities emit POM as benzo(a)pyrene TEQ above the Tier II 
screening level, and the facility with the highest emissions of POM as 
benzo(a)pyrene TEQ exceeds its screening level by a factor of 30.
    Polychlorinated biphenyls (PCB) are PB-HAP that do not currently 
have multi-pathway screening values and so are not evaluated for 
potential non-inhalation risks. These HAP, however, are not emitted in 
appreciable quantities (0.001 tpy) from refinery operations, and we do 
not believe they contribute to multi-pathway risks for this source 
category.
    Results of the analysis for lead indicate that the maximum annual 
off-site ambient lead concentration was only 2 percent of the NAAQS for 
lead, and even if the total annual emissions occurred during a 3-month 
period, the maximum 3-month rolling average concentrations would still 
be less than 8 percent of the NAAQS, indicating that there is no 
concern for multi-pathway risks due to lead emissions.
4. Refined Multipathway Case Study
    To gain a better understanding of the uncertainty associated with 
the multipathway Tier I and II screening analysis, a refined 
multipathway case study using the TRIM.Fate model was conducted for a 
single petroleum refinery. The site, a refinery in St. John the Baptist 
Parish, Louisiana, was selected based upon its close proximity to 
nearby lakes and farms as well as having one of the highest potential 
multipathway risks for PAH based on the Tier II analysis. The refined 
analysis for this facility showed that the Tier II screen for each 
pollutant over-predicted the potential risk when compared to the 
refined analysis results. For this site, the Tier II screen for mercury 
indicated that mercury emissions were 3 times lower than the screening 
value, indicating a potential maximum HQ for mercury of 0.3. In the 
refined analysis, the potential HQ was 0.04 or about 7 times lower than 
that predicted by the Tier II screen. For cadmium emissions, the Tier 
II screen for this facility indicated that cadmium emissions were about 
20 times lower than the screening value, indicating a potential maximum 
HQ for mercury of 0.05. The results of the refined analysis for the 
selected site in Louisiana show a maximum cadmium HQ of 0.02 or about 3 
times lower than that predicted by the Tier II screen. For PAH 
emissions, the site selected for the refined analysis had PAH emissions 
20 times the PAH Tier II screening value, indicating a potential cancer 
risk of 20-in-1 million. When the more refined analysis was conducted 
for this site, the potential cancer risks were estimated to be 2-in-1 
million or about 14 times lower than predicted by the Tier II analysis. 
Finally, for the facility selected for the refined assessment, the 
emissions of CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin TEQ are 5 
times higher than the dioxin Tier II screening value, indicating a 
potential maximum cancer risk of 5-in-1 million. In the refined 
assessment, the cancer risk from dioxins was estimated to be 2-in-1 
million, about one-third of the estimate from the Tier II screen.
    Overall, the refined analysis predicts a potential lifetime cancer 
risk of 4-in-1 million to the maximum most exposed individual (MIR). 
The non-cancer HQ is predicted to be well below 1 for all target 
organs. The chronic inhalation cancer risk assessment estimated 
inhalation cancer risk around this same facility to be approximately 
10-in-1 million, due in large part to emissions of naphthalene and 2-
methylnaphthalene (both non-persistent, bioaccumulative, and toxic 
(PBT) HAP). Thus, although highly unlikely, if around this facility the 
person with the highest chronic inhalation cancer risk is also the same 
person with the highest individual multipathway cancer risk, then the 
combined, worst-case MIR for that facility could theoretically be 10-
in-1 million (risk estimates are expressed as 1 significant figure).
    While this refined assessment was performed on only a single 
facility, the results of this single refined analysis indicate that if 
refined analyses were performed for other sites, the risk estimates 
would consistently be lower than those estimated by the Tier II 
analysis. In addition, the risks predicted by the multipathway analyses 
at most facilities are considerably lower than the risk estimates 
predicted by the inhalation assessment, indicating that the inhalation 
risk results are in all likelihood the primary factor in our residual 
risk determination for this source category.
    Further details on the site-specific case study can be found in 
Appendix 10 of the Draft Residual Risk Assessment for the Petroleum 
Refining Source Sector, which is available in Docket ID Number EPA-HQ-
OAR-2010-0682.
5. Environmental Risk Screening Results
    As described in the Draft Residual Risk Assessment for the 
Petroleum Refining Source Sector, which is available in Docket ID 
Number EPA-HQ-OAR-2010-0682, we conducted an environmental risk 
screening assessment for the petroleum refineries source category. In 
the Tier I screening analysis for PB-HAP (other than lead, which was 
evaluated differently, as noted in section III.A.6 of this preamble), 
the individual modeled Tier I concentrations for one facility in the 
source category exceeded some of the ecological benchmarks for mercury. 
In addition, Tier I modeled concentrations for four facilities exceeded 
sediment and soil ecological benchmarks for PAH. Therefore, we 
conducted a Tier II assessment.
    In the Tier II screening analysis for PB-HAP, none of the 
individual modeled concentrations for any facility in the source 
category exceeded any of the ecological benchmarks (either the LOAEL or 
NOAEL).
    For lead compounds, we did not estimate any exceedances of the 
secondary lead NAAQS. Therefore, we did not conduct further assessment 
for lead compounds.
    For acid gases, the average modeled concentration around each 
facility (i.e., the average concentration of all off-site data points 
in the modeling domain) did not exceed any ecological benchmark. In 
addition, for both HCL and HF, each individual concentration (i.e., 
each off-site data point in the modeling domain) was below the 
ecological benchmarks for all facilities.
6. Facility-Wide Risk Results
    Table 11 of this preamble displays the results of the facility-wide 
risk assessment.

[[Page 36937]]



   Table 11--Petroleum Refining Facility-Wide Risk Assessment Results
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Number of facilities analyzed.........................               142
Cancer Risk:
    Estimated maximum facility-wide individual cancer                 70
     risk ([dash]in-1 million)........................
    Number of facilities with estimated facility-wide                 54
     individual cancer risk of 10-in-1 million or more
    Number of petroleum refining operations                           50
     contributing 50 percent or more to facility-wide
     individual cancer risk of 10-in-1 million or more
    Number of facilities with facility-wide individual               115
     cancer risk of 1-in-1 million or more............
    Number of petroleum refining operations                          107
     contributing 50 percent or more to facility-wide
     individual cancer risk of 1-in-1 million or more.
Chronic Non-cancer Risk:
Maximum facility-wide chronic non-cancer TOSHI........                 4
    Number of facilities with facility-wide maximum                    5
     non-cancer TOSHI greater than 1..................
    Number of petroleum refining operations                            0
     contributing 50 percent or more to facility-wide
     maximum non-cancer TOSHI of 1 or more............
------------------------------------------------------------------------

    The maximum individual cancer whole-facility risk from all HAP 
emissions at any petroleum refinery is estimated to be 70-in-1 million, 
based on actual emissions. Of the 142 facilities included in this 
analysis, 54 have facility-wide maximum individual cancer risks of 10-
in-1 million or greater. At the majority of these facilities (50 of 
54), the petroleum refinery operations account for over 50 percent of 
the risk.
    There are 115 facilities with facility-wide maximum individual 
cancer risks of 1-in-1 million or greater. At the majority of these 
facilities (107 of 115), the petroleum refinery operations account for 
over 50 percent of the risk. The facility-wide maximum individual 
chronic non-cancer TOSHI is estimated to be 4, based on actual 
emissions. Of the 142 refineries included in this analysis, five have a 
TOSHI value greater than 1. The highest non-cancer TOSHI results from 
emissions of chlorine from cooling towers. In each case, the petroleum 
refinery operations account for less than 20 percent of the TOSHI 
values greater than 1.
    Additional detail regarding the methodology and the results of the 
facility-wide analyses are included in the risk assessment 
documentation (Draft Residual Risk Assessment for the Petroleum 
Refining Source Sector), which is available in the docket for this 
rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).
7. What demographic groups might benefit from this regulation?
    To examine the potential for any environmental justice issues that 
might be associated with the source categories, we performed a 
demographic analysis of the population close to the facilities. In this 
analysis, we evaluated the distribution of HAP-related cancer and non-
cancer risks from petroleum refineries across different social, 
demographic, and economic groups within the populations living near 
facilities identified as having the highest risks. The methodology and 
the results of the demographic analyses are included in a technical 
report, Draft Risk and Technology Review--Analysis of Socio-Economic 
Factors for Populations Living Near Petroleum Refineries, available in 
the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).
    The results of the demographic analysis are summarized in Table 12 
of this preamble. These results, for various demographic groups, are 
based on the estimated risks from actual emissions levels for the 
population living within 50 km of the facilities.

                         Table 12--Petroleum Refining Demographic Risk Analysis Results
----------------------------------------------------------------------------------------------------------------
                                                                             Population with
                                                                            cancer risk at or   Population with
                                                             Nationwide        above 1-in-1      chronic hazard
                                                                                 million         index above 1
----------------------------------------------------------------------------------------------------------------
Total Population.......................................        312,861,265          5,204,234                  0
----------------------------------------------------------------------------------------------------------------
                                                 Race by Percent
----------------------------------------------------------------------------------------------------------------
White..................................................                 72                 50                  0
All Other Races........................................                 28                 50                  0
----------------------------------------------------------------------------------------------------------------
                                                 Race by Percent
----------------------------------------------------------------------------------------------------------------
White..................................................                 72                 50                  0
African American.......................................                 13                 28                  0
Native American........................................                  1                  1                  0
Other and Multiracial..................................                 14                 21                  0
----------------------------------------------------------------------------------------------------------------
                                              Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
Hispanic...............................................                 17                 29                  0
Non-Hispanic...........................................                 83                 71                  0
----------------------------------------------------------------------------------------------------------------
                                                Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level....................................                 14                 21                  0
Above Poverty Level....................................                 86                 79                  0
----------------------------------------------------------------------------------------------------------------

[[Page 36938]]

 
                                              Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without High School Diploma................                 15                 23                  0
Over 25 and with a High School Diploma.................                 85                 77                  0
----------------------------------------------------------------------------------------------------------------

    The results of the demographic analysis indicate that emissions 
from petroleum refineries expose approximately 5,000,000 people to a 
cancer risk at or above 1-in-1 million. Implementation of the 
provisions included in this proposal is expected to reduce the number 
of people estimated to have a cancer risk greater than 1-in-1 million 
due to HAP emissions from these sources from 5,000,000 people to about 
4,000,000. Our analysis of the demographics of the population within 50 
km of the facilities indicates potential disparities in certain 
demographic groups, including the African American, Other and 
Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a 
High School Diploma. The population living within 50 km of the 142 
petroleum refineries has a higher percentage of minority, lower income 
and lower education persons when compared to the nationwide percentages 
of those groups. For example, 50 percent are in one or more minority 
demographic group, compared to 28 percent nationwide. As noted above, 
approximately 5,000,000 people currently living within 50 km of a 
petroleum refinery have a cancer risk greater than 1-in-1 million. We 
would expect that half of those people are in one or more minority 
demographic groups.
    Because minority groups make up a large portion of the population 
living near refineries, as compared with their representation 
nationwide, those groups would similarly see a greater benefit from the 
implementation of the controls proposed in this rule, if finalized. For 
example, we estimate that after implementation of the controls proposed 
in this action (i.e., post-controls), about 1,000,000 fewer people will 
be exposed to cancer risks greater than 1-in-1 million (i.e., 4,000,000 
people). Further, we estimate that approximately 500,000 people no 
longer exposed to a cancer risk greater than 1-in-1 million would be in 
a minority demographic group. The post-control risk estimates are 
discussed further in section III.A.5 of this preamble.
    Although the EPA's proposed fenceline monitoring requirement is 
intended to ensure that owners and operators monitor, manage and, if 
necessary, reduce fugitive emissions of HAP, we also expect the 
collected fenceline data to help the EPA understand and identify 
emissions of benzene and other fugitive emissions that are impacting 
communities in close proximity to the facility. While currently-
available emissions and monitoring data do not indicate that risks to 
nearby populations are unacceptable (see section IV.D.1 of this 
preamble), we recognize that the collection of additional data through 
routine fenceline monitoring can provide important information to 
communities concerned with potential risks associated with emissions 
from fugitive sources. We note that the data we are proposing to 
collect on a semiannual basis may include exceedances of the fenceline 
action level that a facility could have addressed or could still be 
actively addressing at the time of the report. As noted in section 
IV.B.1.h of this preamble, directly monitoring fugitive emissions from 
each potential emissions source at the facility is impractical. 
Fenceline monitoring offers a cost-effective alternative for monitoring 
fugitive emissions from the entire facility. The EPA's proposal to 
require the electronic reporting of fenceline monitoring data on a 
semiannual basis will ensure that communities have access to data on 
benzene levels near the facility, which is directly relevant to the 
potential health risks posed by the facility. The proposed requirements 
for fenceline monitoring and corrective action when fugitive emissions 
from a facility exceed the specified corrective action level will serve 
as an important backstop to protect the health of the populations 
surrounding the facility, including minority and low-income 
populations.

D. What are our proposed decisions regarding risk acceptability, ample 
margin of safety and adverse environmental effects?

1. Risk Acceptability
    As noted in section II.A.1 of this preamble, the EPA sets standards 
under CAA section 112(f)(2) using ``a two-step standard-setting 
approach, with an analytical first step to determine an `acceptable 
risk' that considers all health information, including risk estimation 
uncertainty, and includes a presumptive limit on maximum individual 
lifetime risk (MIR) of approximately 1 in 10 thousand.\[39]\ '' (54 FR 
38045, September 14, 1989).
---------------------------------------------------------------------------

    \39\ 1-in-10 thousand is equivalent to 100-in-1 million. The EPA 
currently describes cancer risks as `n-in-1 million'.
---------------------------------------------------------------------------

    In this proposal, we estimate risks based on actual emissions from 
petroleum refineries. We also estimate risks from allowable emissions; 
as discussed earlier, we consider our analysis of risk from allowable 
emissions to be conservative and as such to represent an upper bound 
estimate on risk from emissions allowed under the current MACT 
standards for the source categories.
a. Estimated Risks From Actual Emissions
    The baseline inhalation cancer risk to the individual most exposed 
to emissions from sources regulated by Refinery MACT 1 and 2 is 60-in-1 
million based on actual emissions. The estimated incidence of cancer 
due to inhalation exposures is 0.3 excess cancer cases per year, or 1 
case every 3.3 years. Approximately 5,000,000 people face an increased 
cancer risk greater than 1-in-1 million due to inhalation exposure to 
actual HAP emissions from these source categories, and approximately 
100,000 people face an increased risk greater than 10-in-1 million and 
up to 60-in-1 million. The agency estimates that the maximum chronic 
non-cancer TOSHI from inhalation exposure is 0.9 due to actual 
emissions of HCN from FCCU.

[[Page 36939]]

    The screening assessment of worst-case acute inhalation impacts 
from actual emissions indicates the potential for five pollutants--
nickel, arsenic, acrolein, benzene and acetaldehyde--to exceed an HQ 
value of 1, with an estimated worst-case maximum HQ of 5 for nickel 
based on the REL values. One hundred thirty-six of the 142 petroleum 
refineries had an estimated worst-case HQ less than or equal to 1 for 
all HAP. One facility had an estimated worst-case maximum HQ of 5 and 
the remaining five refineries with an HQ above 1 had an estimated 
worst-case HQ less than or equal to 3. Considering the conservative, 
health-protective nature of the approach that is used to develop these 
acute estimates, it is highly unlikely that an individual would have an 
acute exposure above the REL. Specifically, the analysis is based on 
the assumption that worst-case emissions and meteorology would coincide 
with a person being at this exact location for a period of time long 
enough to have an exposure level above the conservative REL value.
    The Tier II multipathway screening analysis of actual emissions 
indicated the potential for PAH emissions that are about 30 times the 
screening level for cancer, dioxin and furans emissions that are about 
40 times the cancer screening level and cadmium emissions that are 
about 2 times the screening level for non-cancer health effects. No 
facility's emissions were above the screening level for mercury. As we 
note above, the Tier II multipathway screen is conservative in that it 
incorporates many health-protective assumptions. For example, we choose 
inputs from the upper end of the range of possible values for the 
influential parameters used in the Tier II screen and we assume that 
the exposed individual exhibits ingestion behavior that would lead to a 
high total exposure. A Tier II exceedance cannot be equated with a risk 
value or a HQ or HI. Rather, it represents a high-end estimate of what 
the risk or hazard may be. For example, an exceedance of 2 for a non-
carcinogen can be interpreted to mean that we have high confidence that 
the HI would be lower than 2. Similarly, an exceedance of 30 for a 
carcinogen means that we have high confidence that the risk is lower 
than 30-in-1-million. Our confidence comes from the conservative, or 
health-protective, assumptions that are used in the Tier II screen.
    The refined analysis that we conducted for a specific facility 
showed that the Tier II screen for each pollutant over-predicted the 
potential risk when compared to the refined analysis results. That 
refined multipathway assessment showed that the Tier II screen resulted 
in estimated risks that are higher than the risks estimated by the 
refined analysis by 14 times for PAH, 3 times for dioxins and furans, 
and 3 times for cadmium. The refined assessment results indicate that 
the multipathway risks are considerably lower than the estimated 
inhalation risks, and our refined multipathway analysis indicates that 
multipathway risks are low enough that, while they are considered in 
our proposed decisions, they do not weigh heavily into those decisions 
because risks for the source category are driven by inhalation.
b. Estimated Risks From Allowable Emissions
    We estimate that the baseline inhalation cancer risk to the 
individual most exposed to emissions from sources regulated by Refinery 
MACT 1 and 2 is as high as 100-in-1 million based on allowable 
emissions. The EPA estimates that the incidence of cancer due to 
inhalation exposures could be as high as 0.6 excess cancer cases per 
year, or 1 case approximately every 1.5 years. About 7,000,000 people 
face an increased cancer risk greater than 1-in-1 million due to 
inhalation exposure to allowable HAP emissions from these source 
categories, and greater than 90,000 people face an increased risk 
greater than 10-in-1 million, and as high as 100-in-1 million. Further, 
we estimate that the maximum chronic non-cancer TOSHI from inhalation 
exposure values at all refineries is less than 1 based on allowable 
emissions.
    The baseline risks summarized above do not account for additional 
risk reductions that we anticipate due to the MACT standards or the 
technology review requirements we are proposing in this action.
c. Acceptability Determination
    In determining whether risk is acceptable, the EPA considered all 
available health information and risk estimation uncertainty as 
described above. As noted above, the agency estimated risk from actual 
and allowable emissions. While there are uncertainties associated with 
both the actual and allowable emissions, we consider the allowable 
emissions to be an upper bound, based on the conservative methods we 
used to calculate allowable emissions.
    The results indicate that both the actual and allowable inhalation 
cancer risks to the individual most exposed are no greater than 
approximately 100-in-1 million, which is the presumptive limit of 
acceptability. The MIR based on actual emissions is 60-in-1 million, 
approximately 60 percent of the presumptive limit. Based on the results 
of the refined site-specific multipathway analysis summarized above and 
described in section IV.C.3 of this preamble, we also conclude that the 
ingestion cancer risk to the individual most exposed is significantly 
less than 100-in-1 million. In addition, the maximum chronic non-cancer 
TOSHI due to inhalation exposures is less than 1, and our refined 
multipathway analysis indicates that non-cancer ingestion risks are 
estimated to be less than non-cancer risk from inhalation. Finally, the 
evaluation of acute non-cancer risks was very conservative, and showed 
acute risks below a level of concern.
    In determining risk acceptability, we also evaluated population 
impacts because of the large number of people living near facilities in 
the source category. The analysis indicates that there are 
approximately 5 million people exposed to actual emissions resulting in 
a cancer risk greater than 1-in-1 million, and a substantially smaller 
number of people (100,000) are exposed to a cancer risk of greater than 
10-in-1 million but less than 100-in-1 million (with a maximum risk of 
60-in-1 million). The inhalation cancer incidence is approximately one 
case in every 3 years based on actual emissions. More detail on this 
risk analysis is presented in section IV.C and summarized in Tables 10 
and 11 of this preamble. The results of the demographic analysis for 
petroleum refineries indicate that a greater proportion of certain 
minority groups and low-income populations live near refineries than 
the national demographic profile. More detail on these population 
impacts is presented in section IV.C.7 of this preamble. We did not 
identify any sensitivity to pollutants emitted from these source 
categories particular to minority and low income populations. 
Considering the above information, we propose that the risks remaining 
after implementation of the existing NESHAP for the Refinery MACT 1 and 
2 source categories is acceptable.
    We also note that the estimated baseline risks for the refineries 
source categories include risks from emissions from DCU, which are a 
previously unregulated emission source. As discussed in section IV.A. 
of this preamble, we are proposing new MACT standards for these sources 
that would reduce emissions of HAP by 850 tpy. We estimate that these 
new standards would not affect the MIR, but would

[[Page 36940]]

reduce the source category cancer incidence by 15 percent.
    We solicit comment on all aspects of our proposed acceptability 
determination. We note that while we are proposing that the risks 
estimated from actual and allowable emissions are acceptable, the risks 
based on allowable emissions are at the presumptive limit of acceptable 
risk. Furthermore, a significant number of people live in relative 
proximity to refineries across the country, and therefore a large 
population is exposed to risks greater than 1-in-1 million. In 
particular, we solicit comment on the methodology used to estimate 
allowable emissions. As noted above, we consider the allowable 
emissions to be an upper bound estimate based on the conservative 
methods used to calculate such emissions. We recognize, however, that 
some of the health information concerning allowable emissions arguably 
borders on the edge of acceptability. Specifically, the analysis of 
allowable emissions resulted in a MIR of 100-in-1 million, which is the 
presumptive limit of acceptability, a large number of people 
(7,000,000) estimated to be exposed at a cancer risk above 1-in-1 
million, and an estimated high cancer incidence (one case approximately 
every 1.5 years). Although we believe that our allowable emissions 
represent an upper end estimate, we nonetheless solicit comment on 
whether the health information currently before the Agency should be 
deemed unacceptable. We also solicit comment on whether our allowable 
emissions analysis reflects a reasonable estimate of emissions allowed 
under the current MACT standards. Lastly, we solicit comment on the 
acceptability of risk considering individuals' potential cumulative 
inhalation and ingestion pathway exposure. Please provide comments and 
data supporting your position. Such information will aid the Agency to 
make an informed decision on risk acceptability as it moves forward 
with this rulemaking.
2. Ample Margin of Safety
    We next considered whether the existing MACT standards provide an 
ample margin of safety to protect public health. In addition to 
considering all of the health risks and other health information 
considered in the risk acceptability determination, in the ample margin 
of safety analysis we evaluated the cost and feasibility of available 
control technologies and other measures that could be applied in these 
source categories to further reduce the risks due to emissions of HAP. 
For purposes of the ample margin of safety analysis, we evaluated the 
changes in risk that would occur through adoption of a specific 
technology by looking at the changes to the risk due to actual 
emissions. Due to the nature of the allowable risk analysis, which is 
based on model plants and post processing to combine risk results,\40\ 
we did not evaluate the risk reductions resulting from reducing 
allowable emissions at individual emission sources. Such an approach 
would require an unnecessarily complex analysis that would not provide 
any more useful information than the analysis we undertook using actual 
emissions. We note that while we did not conduct a specific analysis 
for allowable emissions, it is reasonable to expect reductions in risk 
similar to those for actual emissions.
---------------------------------------------------------------------------

    \40\ As described in the memorandum entitled Refinery Emissions 
and Risk Estimates for Modeled ``Allowable'' Emissions, available in 
Docket EPA-HQ-OAR-2010-0682, the use of model plants and post-
processing was for the purpose of ensuring that our analysis would 
provide a conservative estimate of actual emissions and thus a 
conservative estimate of risk.
---------------------------------------------------------------------------

    As noted in our discussion of the technology review in section IV.B 
of this preamble, we identified a number of developments in practices, 
processes or control technologies for reducing HAP emissions from 
petroleum refinery processes. As part of the risk review, we evaluated 
these developments to determine if any of them could reduce risks and 
whether it is necessary to require any of these developments to provide 
an ample margin of safety to protect public health.
    We evaluated the health information and control options for all of 
the emission sources located at refineries, including: Storage vessels, 
equipment leaks, gasoline loading racks, marine vessel loading 
operations, cooling towers/heat exchange systems, wastewater collection 
and treatment, FCCU, flares, miscellaneous process vents, CRU and SRU. 
For each of these sources, we considered chronic cancer and non-cancer 
risk metrics as well as acute risk. Regarding our ample margin of 
safety analyses for chronic non-cancer risk for the various emission 
sources, we note that the baseline TOSHIs are less than 1 for the 
entire source category and considerably less than 1 for all of the 
emission sources except for the FCCU (which had an TOSHI of 0.9). 
Therefore, we did not quantitatively evaluate reductions in the chronic 
non-cancer TOSHI for sources other than FCCU in the ample margin of 
safety analysis. Regarding our ample margin of safety analyses for 
acute risk for all of the various emission sources, we note that our 
analyses did not identify acute risks at a level of concern and, 
therefore, we did not quantitatively evaluate reductions in the acute 
HQ values for each individual emission source in the ample margin of 
safety analysis. Accordingly, the following paragraphs focus on cancer 
risk in the determination of whether the standards provide an ample 
margin of safety to protect public health.
    For storage vessels, as discussed in section IV.B of this preamble, 
we identified and evaluated three control options. Under the technology 
review, we determined that two of the options, which we call options 1 
and 2, are cost effective. We are proposing option 2, which includes 
all of the requirements of option 1, as part of the technology review. 
The option 2 controls that we are proposing under the technology review 
would result in approximately 910 tpy reduction in HAP (a 40-percent 
reduction from this emission source). As described in section IV.B of 
this preamble, not only are these controls cost effective, but we 
estimate a net cost savings because the emission reductions translate 
into reduced product loss. These controls would reduce the cancer risk 
to the individual most exposed from 60-in-1 million to 50-in-1 million 
based on actual emissions at the facility where storage tank emissions 
were driving the risk. However, the MIR remains unchanged for the 
refinery source categories, at 60-in 1-million, because the facility 
with the next highest cancer risk is 60-in-1 million and this risk is 
driven by another emission source. The option 2 controls also would 
reduce cancer incidence by approximately 2 percent. Finally, we 
estimate that the option 2 controls reduce the number of people with a 
cancer risk greater than 10-in-1 million storage tanks from 3,000 to 60 
and reduce the number of people with a cancer risk greater than 1-in-1 
million from storage tanks from 140,000 to 72,000. Since these controls 
reduce cancer incidence, and reduce the number of people exposed to 
cancer risks greater than 1-in-10 million and 1-in-1 million from 
storage tank emissions, and are cost effective, we propose that these 
controls are necessary to provide an ample margin of safety to protect 
public health. We also evaluated one additional control option for 
storage vessels, option 3, which incorporated both options 1 and 2 
along with additional monitoring requirements. We estimate incremental 
HAP emission reductions (beyond those provided by option 2) of 90 tpy. 
The

[[Page 36941]]

incremental cost effectiveness for option 3 exceeds $60,000 per ton, 
which we do not consider cost effective. In addition, the option 3 
controls do not result in quantifiable reductions in the cancer risk to 
the individual most exposed or the cancer incidence beyond the 
reductions estimated for the option 2 controls. For these reasons, we 
propose that it is not necessary to require the option 3 controls in 
order to provide an ample margin of safety to protect public health.
    For equipment leaks, we identified and evaluated three control 
options discussed previously in the technology review section of this 
preamble (section IV.B). These options are:
     Option 1--monitoring and repair at lower leak definitions;
     Option 2--applying monitoring and repair requirements to 
connectors; and
     Option 3--optical gas imaging and repair.
    We estimate that these three independent control options reduce 
industry-wide emissions of organic HAP by 24 tpy, 86 tpy, and 24 tpy, 
respectively. We estimate that none of the control options would reduce 
the risk to the individual most exposed. We also estimate that the 
cancer incidence would not change perceptively if these controls were 
required. Finally, we estimate that the control options do not reduce 
the number of people with a cancer risk greater than 10-in-1 million or 
the number of people with a cancer risk greater than 1-in-1 million. As 
discussed above, the available control options for equipment leaks do 
not provide quantifiable risk reductions and, therefore, we propose 
that these controls are not necessary to provide an ample margin of 
safety.
    For gasoline loading racks, we identified and evaluated one control 
option discussed previously in the technology review section of this 
preamble (section IV.B). As discussed earlier, this option is a new 
development that results in emissions that are higher than the current 
level required under Refinery MACT 1. Since we estimate that no 
emission reductions would result from this new technology and thus no 
reduction in risk, we propose that this control option is not necessary 
to provide an ample margin of safety.
    For marine vessel loading operations, we identified and evaluated 
two control options discussed previously in the technology review 
section of this preamble (section IV.B). The first option would be to 
require submerged fill for small and offshore marine vessel loading 
operations. Based on actual emissions, we project no HAP emission 
reductions for this option, as all marine vessels that are used to 
transport bulk refinery liquids are expected to already have the 
required submerged fill pipes. Accordingly, we do not project any 
changes in risk. While we are proposing this option under the 
technology review, because the option is not projected to reduce 
emissions or risk, we propose that a submerged loading requirement is 
not necessary to provide an ample margin of safety. We also identified 
and evaluated the use of add-on controls for gasoline loading at small 
marine vessel loading operations. In the technology review, we rejected 
this control option because the cost effectiveness exceeded $70,000 ton 
of HAP reduced. We estimate that this option would not result in 
quantifiable changes to any of the risk metrics. Because add-on 
controls would not result in quantifiable risk reductions and we do not 
consider the controls to be cost effective, we are proposing that add-
on controls for gasoline loading at small marine vessel loading 
operations are not necessary to provide an ample margin of safety.
    For cooling towers and heat exchangers, we did not identify as part 
of our technology review any developments in processes, practices or 
controls beyond those that we considered in our beyond-the-floor 
analysis at the time we set the MACT standards. We note that we issued 
MACT standards for heat exchange systems in a final rule on October 28, 
2009 (74 FR 55686), but existing sources were not required to comply 
until October 29, 2012. As a result, the reductions were not reflected 
in the inventories submitted in response to the ICR for refineries and 
therefore were not included in our risk analysis based on actual 
emissions. We estimate that these MACT standards will result in an 
industry-wide reduction of over 600 tons HAP per year (or 85 percent). 
The projected contribution to risk associated with cooling tower 
emissions after implementation of these MACT standards for heat 
exchange systems is approximately 1 percent. Because we did not 
identify any control options beyond those required by the current 
standards for cooling towers and heat exchange systems, we are 
proposing that additional controls for these systems are not necessary 
to provide an ample margin of safety.
    For wastewater collection and treatment systems, we identified and 
evaluated three options for reducing emissions. We estimate 
implementing these independent control options would result in emission 
reductions of 158 tpy (4 percent), 549 tpy (15 percent), and 929 tpy 
(25 percent), respectively. None of the control options would reduce 
the cancer risk to the individual most exposed from 60-in-1 million. 
Option 1 would reduce the cancer incidence by less than 1 percent, and 
we expect any reduction in cancer incidence that would result from 
options 2 or 3 to be small because this source accounts for about 10 
percent of the cancer incidence from refineries as a whole and the most 
stringent control option would reduce emissions from these source by 
only 25 percent. Finally, we estimate that control option 1 would not 
reduce the number of people with a cancer risk greater than 10-in-1 
million or the number of people with a cancer risk greater than 1-in-1 
million. We expect any changes to the number of people with a cancer 
risk greater than 1-in-1 million from implementation of options 2 or 3 
to be small for the same reasons mentioned above for cancer incidence. 
We estimate the cost effectiveness of these options to be $26,600 per 
ton, $52,100 per ton, and $54,500 per ton of organic HAP reduced, and 
we do not consider any of these options to be cost effective. Because 
of the very small reductions in risk and the lack of cost-effective 
control options, we propose that these controls are not necessary to 
provide an ample margin of safety.
    For FCCU, we did not identify any developments in processes, 
practices or control technologies for organic HAP. For inorganic HAP 
from FCCU, in the technology review, we identified and evaluated one 
control option for an HCN emissions limit and one control option for a 
PM emissions limit. The PM limit was adopted for new sources in 
Refinery NSPS Ja as part of our review of Refinery NSPS J. We 
considered the costs and emission reductions associated with requiring 
existing sources to meet the new source level for PM under Refinery 
NSPS Ja (i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg). 
As indicated in our promulgation of Refinery NSPS Ja, the cost 
effectiveness of lowering the PM limit for existing sources to the 
level we are requiring for new sources was projected to be $21,000 per 
ton of PM reduced (see 73 FR 35845, June 24, 2008). Based on the 
typical metal HAP concentration in PM from FCCU, the cost effectiveness 
of this option for HAP metals is approximately $1 million per ton of 
HAP reduced. We estimate that this control option would not reduce the 
cancer risk to the individual most exposed, would not change the cancer 
incidence, and would not change the number of people with estimated 
cancer

[[Page 36942]]

risk greater than 1-in-1 million or 10-in-1 million. For the HCN 
emissions limit, we evaluated the costs of controlling HCN using 
combustion controls in combination with SCR. The cost effectiveness of 
this option was approximately $9,000 per ton of HCN. This control 
option would reduce the non-cancer HI from 0.9 to 0.8 and would not 
change any of the cancer risk metrics. Based on the cost effectiveness 
of these options and the limited reduction in cancer and non-cancer 
risk (the non-cancer risk is below a level of concern based on the 
existing standards), we propose that additional controls for FCCU are 
not necessary to provide an ample margin of safety.
    Flares are used as APCD to control emissions from several emission 
sources covered by Refinery MACT 1 and 2. In this proposed rule, under 
CAA sections 112(d)(2) and (3), we are proposing operating and 
monitoring requirements to ensure flares achieve the 98-percent HAP 
destruction efficiency identified as the MACT Floor in the initial MACT 
rulemaking in 1995. Flares are critical safety devices that effectively 
reduce emissions during startup, shutdown, and process upsets or 
malfunctions. In most cases, flares are the only means by which 
emissions from pressure relief devices can be controlled. Thus, we find 
that properly-functioning flares act to reduce HAP emissions, and 
thereby risk, from petroleum refinery operations. The changes to the 
flare requirements that we are proposing under CAA sections 112(d)(2) 
and (3) will result in sources meeting the level required by the 
original standards, and we did not identify any control options that 
would further reduce the HAP emissions from flares. Therefore, we are 
proposing that additional controls for flares are not necessary to 
provide an ample margin of safety.
    For the remaining emission sources within the Refinery MACT 1 and 
Refinery MACT 2 source categories, including miscellaneous process 
vents, CRU, and SRU, we did not identify any developments in processes 
practices and control technologies. Therefore, we are proposing that 
additional controls for these three Refinery MACT 1 and 2 emission 
sources are not necessary to provide an ample margin of safety.
    In summary, we propose that the original Refinery MACT 1 and 2 MACT 
standards, along with the proposed requirements for storage vessels 
described above, provide an ample margin of safety to protect public 
health. We are specifically requesting comment on whether there are 
additional control measures for emission sources subject to Refinery 
MACT 1 and Refinery MACT 2 that are necessary to provide an ample 
margin of safety to protect public health. In particular, we are 
requesting that states identify any controls they have already required 
for these facilities, controls they are currently considering, or other 
controls of which they may be aware.
    While not part of our decisions regarding residual risk, we note 
that DCU are an important emission source with respect to risk from 
refineries. As described in section IV.A of this preamble, we are 
proposing new MACT standards under CAA sections 112(d)(2) and (3) for 
DCU. For informational purposes, we also looked at the risk reductions 
that would result from implementation of those standards. We estimate 
no reduction in the cancer risk to the individual most exposed and a 
decrease in cancer incidence of 0.05 cases per year, or approximately 
15 percent. While our decisions on risk acceptability and ample margin 
of safety are supported even in the absence of these reductions, if we 
finalize the proposed requirements for DCU, they would further 
strengthen our conclusions that the standards provide an ample margin 
of safety to protect public health.
3. Adverse Environmental Effects
    We conducted an environmental risk screening assessment for the 
petroleum refineries source category for lead, mercury, cadmium, PAH, 
dioxins and furans, HF, and HCl. For mercury, cadmium, PAH, and dioxins 
and furans, none of the individual modeled concentrations for any 
facility in the source category exceeded any of the Tier II ecological 
benchmarks (either the LOAEL or NOAEL). For lead, we did not estimate 
any exceedances of the secondary lead NAAQS. For HF and HCl, the 
average modeled concentration around each facility (i.e., the average 
concentration of all off-site data points in the modeling domain) did 
not exceed any ecological benchmark. Based on these results, EPA 
proposes 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.

E. What other actions are we proposing?

    We are proposing the following changes to Refinery MACT 1 and 2 as 
described below: (1) Revising the SSM provisions in order to ensure 
that the subparts are consistent with the court decision in Sierra Club 
v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), which vacated two provisions 
that exempted sources from the requirement to comply with otherwise 
applicable section 112(d) emission standards during periods of SSM; (2) 
proposing to clarify requirements related to open-ended valves or 
lines; (3) adding electronic reporting requirements in Refinery MACT 1 
and 2; and (4) updating the General Provisions cross-reference tables.
1. SSM
    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. 
Cir. 2008), the United States Court of Appeals for the District of 
Columbia Circuit vacated portions of two provisions in the EPA's CAA 
section 112 regulations governing the emissions of HAP during periods 
of SSM. Specifically, the Court vacated the SSM exemption contained in 
40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section 
302(k) of the CAA, emissions standards or limitations must be 
continuous in nature and that the SSM exemption violates the CAA's 
requirement that some section 112 standards apply continuously.
    We are proposing the elimination of the SSM exemption in 40 CFR 
part 63, subparts CC and UUU. Consistent with Sierra Club v. EPA, we 
are proposing standards in these rules that apply at all times. We are 
also proposing several revisions to Table 6 of subpart CC of 40 CFR 
part 63 and to Table 44 to subpart UUU of 40 CFR part 63 (the General 
Provisions Applicability tables for each subpart) as explained in more 
detail below. For example, we are proposing to eliminate the 
incorporation of the General Provisions' requirement that the source 
develop an SSM plan. We also are proposing to eliminate and revise 
certain recordkeeping and reporting requirements related to the SSM 
exemption as further described below.
    The EPA has attempted to ensure that the provisions we are 
proposing to eliminate are inappropriate, unnecessary, or redundant in 
the absence of the SSM exemption. We are specifically seeking comment 
on whether we have successfully done so.
    In proposing the standards in this rule, the EPA has taken into 
account startup and shutdown periods and, for the reasons explained 
below, we are proposing alternate standards for those periods for a few 
select emission sources. We expect facilities can meet nearly all of 
the emission standards in Refinery MACT 1 and 2 during startup and 
shutdown, including the amendments we are proposing in this action. For 
most of the emission sources, APCD are operating prior to process 
startup and continue to operate through process shutdown.

[[Page 36943]]

    For Refinery MACT 1 and 2, we identified three emission sources for 
which specific startup and shutdown provisions may be needed. First, as 
noted above, most APCD used to control metal HAP emissions from FCCU 
under Refinery MACT 2 (e.g., wet scrubber, fabric filter, cyclone) 
would be operating before emissions are routed to them and would be 
operating during startup and shutdown events in a manner consistent 
with normal operating periods, such that the monitoring parameter 
operating limits set during the performance test are maintained and 
met. However, we recognize that there are safety concerns associated 
with operating an ESP during startup of the FCCU, as described in the 
following paragraphs. Therefore, we are proposing specific PM standards 
for startup of FCCU controlled with an ESP under Refinery MACT 2.
    During startup of the FCCU, ``torch oil'' (heavy oil typically used 
as feed to the unit via the riser) is injected directly into the 
regenerator and burned to raise the temperature of the regenerator and 
catalyst to levels needed for normal operation. Given the poor mixing 
of fuel and air in the regenerator during this initial startup, it is 
difficult to maintain optimal combustion characteristics, and high CO 
concentrations are common. Elevated CO levels pose an explosion threat 
due to the high electric current and potential for sparks within the 
ESP. Consequently, it is common practice to bypass the ESP during 
startup of the FCCU. Once torch oil is shut off and the regenerator is 
fueled by catalyst coke burn-off, the CO levels in the FCCU regenerator 
off-gas will stabilize and the gas can be sent to the ESP safely.
    When the ESP is offline, the operating limits for the ESP are 
meaningless. During much of the startup process, either catalyst is not 
circulating between the FCCU regenerator and reactor or the catalyst 
circulation rate is much lower than during normal operations. While the 
catalyst is not circulating or is circulating at reduced rates, the PM 
and metal HAP emissions are expected to be much lower than during 
normal operations. Therefore, the cyclone separators that are internal 
to the FCCU regenerator should provide reasonable PM control during 
this initial startup. To ensure the internal cyclones are operating 
efficiently, we are proposing that FCCU using an ESP as the APCD meet a 
30-percent opacity limit (on a 6-minute rolling average basis) during 
the period that torch oil is used during FCCU startup. This opacity 
limit was selected because it has been used historically to assess 
compliance with the PM emission limit for FCCU in Refinery NSPS J and 
because the emission limit can be assessed using manual opacity 
readings, eliminating the need to install a COMS. We note that Refinery 
NSPS J includes the exception for one 6-minute average of up to 60-
percent opacity in a 1-hour period primarily to accommodate soot 
blowing events. As no soot blowing should be performed prior to the ESP 
coming on-line, we are not including this exception to the proposed 30-
percent opacity limit during startup for FCCU that are controlled by an 
ESP.
    Second, for emissions of organic HAP from FCCU under Refinery MACT 
2, we also expect that APCD would be operating before emissions are 
routed to them, and would be operating during startup and shutdown 
events in a manner consistent with normal operating periods, such that 
the monitoring parameter operating limits set during the performance 
test are maintained and met. However, many FCCU operate in ``complete 
combustion'' mode without a post-combustion device. In other words, for 
FCCU without a post-combustion device, organic HAP are controlled by 
the FCCU itself, so there is no separate APCD that could be operating 
during startup and demonstrating continuous compliance with the 
monitoring parameter operating limits. Therefore, we are proposing 
specific CO standards for startup of FCCU without a post-combustion 
device under Refinery MACT 2.
    As mentioned previously, ``torch oil'' is injected directly into 
the regenerator and burned during FCCU startup to raise the temperature 
of the regenerator and catalyst to levels needed for normal operation. 
During this period, CO concentrations often will exceed the 500 ppm 
emissions limit due to the poor mixing of fuel and air in the 
regenerator. The emissions limit is based on CO emissions, as a 
surrogate for organic HAP emissions, and the emission limit is 
evaluated using a 1-hour averaging period. This 1-hour averaging period 
does not provide adequate time for short-term excursions that occur 
during startup to be offset by lower emissions during normal 
operational periods.
    Based on available data during normal operations, ensuring adequate 
combustion (indicated by CO concentration levels below 500 ppmv) 
minimizes organic HAP emissions. Low levels of CO in the exhaust gas 
are consistently achieved during normal operations when oxygen 
concentrations in the exhaust gas exceed 1-percent by volume (dry 
basis). Thus, maintaining an adequate level of excess oxygen for the 
combustion of fuel in the FCCU is expected to minimize organic HAP 
emissions. Emissions of CO during startup result from a series of 
reactions with the fuel source and are dependent on mixing, local 
oxygen concentrations, and temperature. While the refinery owner or 
operator has direct control over air blast rates, CO emissions may not 
always directly correlate with the air blast rate. Exhaust oxygen 
concentrations are expected to be more directly linked with air blast 
rates and are, therefore, more directly under control of the refinery 
owner or operator. We are proposing an excess oxygen concentration of 1 
volume percent (dry basis) based on a 1-hour average during startup. We 
consider the 1-hour averaging period for the oxygen concentration in 
the exhaust gas from the FCCU to be appropriate during periods of FCCU 
startup because air blast rates can be directly controlled to ensure 
adequate oxygen supply on a short-term basis.
    Third, we note that the SRU is unique in that it essentially is the 
APCD for the fuel gas system at the facility. The SRU would be 
operating if the refinery is operating, including during startup and 
shutdown events. There are typically multiple SRU trains at a facility. 
Different trains can be taken off-line as sour gas production decreases 
to maintain optimal operating characteristics of the operating SRU 
during startup or shutdown of a set of process units. Thus, the sulfur 
recovery plant is expected to run continuously and would only shut down 
its operation during a complete turnaround or shutdown of the facility. 
For these limited situations, the 12-hour averaging time provided for 
the SRU emissions limitation under Refinery MACT 2 may not be adequate 
time in which to shut down the unit without exceeding the emissions 
limitation. Therefore, we are proposing specific standards for SRU 
during periods of shutdown.
    We note also that, for SRU subject to Refinery NSPS J or electing 
to comply with Refinery NSPS J as provided in Refinery MACT 2, the 
emissions limit is in terms of SO2 concentration for SRU 
with oxidative control systems or reductive control systems followed by 
an incinerator. While the SO2 concentration limit provides a 
reasonable proxy of the reduced sulfur HAP emissions during normal 
operations, it does not necessarily provide a good indication of 
reduced sulfur HAP emissions during periods of shutdown. During periods 
of shutdown, the sulfur remaining in the unit is purged and combusted 
generally in a thermal oxidizer or a flare. Although the sulfur loading 
to the thermal oxidizer

[[Page 36944]]

during shutdown may be higher than during normal operations (thereby 
causing an increase in the SO2 concentration and exceedance 
of the SO2 emissions limitation), appropriate operation of 
the thermal oxidizer will adequately control emissions of reduced 
sulfur HAP. Thus, during periods of shutdown, the 300 ppmv reduced 
sulfur compound emission limit alternative (provided for SRU not 
subject to Refinery NSPS J) is a better indicator of reduced sulfur HAP 
emissions. In Refinery MACT 2, SRU that elect to comply with the 300 
ppmv reduced sulfur compound emission limit (i.e., those not subject to 
Refinery NSPS J or electing to comply with Refinery NSPS J) and that 
use a thermal incinerator for sulfur HAP control are required to 
maintain a minimum temperature and excess oxygen level (as determined 
through a source test of the unit) to demonstrate compliance with the 
reduced sulfur compound emission limitation.
    In Refinery MACT 2, SRU subject to Refinery NSPS J (or that elect 
to comply with Refinery NSPS J) that use an incinerator to control 
sulfur HAP emissions are required to install an SO2 CEMS to 
demonstrate compliance with the SO2 emission limitation. For 
these units, it is impractical to require installation of a reduced 
sulfur compound monitor or to require a source test to establish 
operating parameters during shutdown of the SRU because of the few 
hours per year that the entire series of SRU trains are shutdown. 
Although the autoignition temperature of COS is unknown, based on the 
autoignition temperature of CS2 (between 200 and 250 [deg]F) 
and the typical operating characteristics of thermal oxidizers used to 
control emissions from SRU, we are proposing that, for periods of SRU 
shutdown, diverting the purge gases to a flare meeting the design and 
operating requirements in 40 CFR 63.670 (or, for a limited transitional 
time period, 40 CFR 63.11) or to a thermal oxidizer operated at a 
minimum temperature of 1200 [deg]F and a minimum outlet oxygen 
concentration of 2 volume percent (dry basis). We believe that this 
provides adequate assurance of compliance with the 300 ppmv reduced 
sulfur compound emission limitation for SRU because incineration at 
these temperatures was determined to be the MACT floor in cases where 
no tail gas treatment units were used (i.e., units not subject to 
Refinery NSPS J).
    For all other emission sources, we believe that the requirements 
that apply during normal operations should apply during startup and 
shutdown. For Refinery MACT 1, these emission sources include process 
vents, transfer operations, storage tanks, equipment leaks, heat 
exchange systems, and wastewater. Emission reductions for process vents 
and transfer operations, such as gasoline loading racks and marine tank 
vessel loading, are typically achieved by routing vapors to thermal 
oxidizers, carbon adsorbers, absorbers and flares. It is common 
practice to start an APCD prior to startup of the emissions source it 
is controlling, so the APCD would be operating before emissions are 
routed to it. We expect APCD would be operating during startup and 
shutdown events in a manner consistent with normal operating periods, 
and that these APCD will be operated to maintain and meet the 
monitoring parameter operating limits set during the performance test. 
We do not expect startup and shutdown events to affect emissions from 
equipment leaks, heat exchange systems, wastewater, or storage tanks. 
Leak detection programs associated with equipment leaks and heat 
exchange systems are in place to detect leaks, and, therefore, it is 
inconsequential whether the process is operating under normal operating 
conditions or is in startup or shutdown. Wastewater emissions are also 
not expected to be significantly affected by startup or shutdown events 
because the control systems used can operate while the wastewater 
treatment system is in startup or shutdown. Working and breathing 
losses from storage tanks are the same regardless of whether the 
process is operating under normal operating conditions or if it is in a 
startup or shutdown event. Degassing of a storage tank is common for 
shutdown of a process; the residual emissions in a storage tank are 
vented as part of the cleaning of the storage tank. We evaluated 
degassing controls as a control alternative for storage vessels and do 
not consider these controls to be cost effective (see memorandum Survey 
of Control Technology for Storage Vessels and Analysis of Impacts for 
Storage Vessel Control Options, Docket Item Number EPA-HQ-OAR-2010-
0871-0027). Based on this review, we are not proposing specific 
standards for storage vessels during startup or shutdown.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is defined as a sudden, infrequent, and not 
reasonably preventable failure of air pollution control and monitoring 
equipment, process equipment or a process to operate in a normal or 
usual manner (see 40 CFR 63.2). The EPA has determined that CAA section 
112 does not require that emissions that occur during periods of 
malfunction be factored into development of section 112 standards. 
Under section 112, emissions standards for new sources must be no less 
stringent than the level ``achieved'' by the best-controlled similar 
source and for existing sources generally must be no less stringent 
than the average emission limitation ``achieved'' by the best-
performing 12 percent of sources in the category. There is nothing in 
section 112 that directs the EPA to consider malfunctions in 
determining the level ``achieved'' by the best-performing sources when 
setting emission standards. As the D.C. Circuit has recognized, the 
phrase ``average emissions limitation achieved by the best performing 
12 percent of'' sources ``says nothing about how the performance of the 
best units is to be calculated.'' Nat'l Ass'n of Clean Water Agencies 
v. EPA, 734 F.3d 1115, 1141 (D.C. Cir. 2013). While the EPA accounts 
for variability in setting emissions standards, nothing in section 112 
requires the EPA to consider malfunctions as part of that analysis. A 
malfunction should not be treated in the same manner as the type of 
variation in performance that occurs during routine operations of a 
source. A malfunction is a failure of the source to perform in a 
``normal or usual manner'' and no statutory language compels EPA to 
consider such events in setting standards based on ``best performers.''
    Further, accounting for malfunctions in setting emissions standards 
would be difficult, if not impossible, given the myriad different types 
of malfunctions that can occur across all sources in the category, and 
given the difficulties associated with predicting or accounting for the 
frequency, degree, and duration of various malfunctions that might 
occur. As such, the performance of units that are malfunctioning is not 
``reasonably'' foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 
658, 662 (D.C. Cir. 1999) (the EPA typically has wide latitude in 
determining the extent of data-gathering necessary to solve a problem. 
We generally defer to an agency's decision to proceed on the basis of 
imperfect scientific information, rather than to ``invest the resources 
to conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590 
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general 
limit, individual permit, or even any upset provision can anticipate 
all upset situations. After a certain point, the transgression of 
regulatory limits caused by

[[Page 36945]]

`uncontrollable acts of third parties,' such as strikes, sabotage, 
operator intoxication or insanity, and a variety of other 
eventualities, must be a matter for the administrative exercise of 
case-by-case enforcement discretion, not for specification in advance 
by regulation.''). In addition, emissions during a malfunction event 
can be significantly higher than emissions at any other time of source 
operation, and thus, accounting for malfunctions in setting standards 
could lead to standards that are significantly less stringent than 
levels that are achieved by a well-performing non-malfunctioning 
source. It is reasonable to interpret section 112 to avoid such a 
result. The EPA's approach to malfunctions is consistent with CAA 
section 112 and is a reasonable interpretation of the statute.
    In the event that a source fails to comply with the applicable CAA 
section 112(d) standards as a result of a malfunction event, the EPA 
would determine an appropriate response based on, among other things, 
the good-faith efforts of the source to minimize emissions during 
malfunction periods, including preventative and corrective actions, as 
well as root cause analyses to ascertain and rectify excess emissions. 
The EPA would also consider whether the source's failure to comply with 
the CAA section 112(d) standard was, in fact, sudden, infrequent, not 
reasonably preventable and was not instead caused in part by poor 
maintenance or careless operation, as described in the definition of 
malfunction (see 40 CFR 63.2). Further, to the extent the EPA files an 
enforcement action against a source for violation of an emission 
standard, the source can raise any and all defenses in that enforcement 
action and the federal district court will determine what, if any, 
relief is appropriate. The same is true for citizen enforcement 
actions. Similarly, the presiding officer in an administrative 
proceeding can consider any defense raised and determine whether 
administrative penalties are appropriate.
    In several prior rules, the EPA had included an affirmative defense 
to civil penalties for violations caused by malfunctions in an effort 
to create a system that incorporates some flexibility, recognizing that 
there is a tension, inherent in many types of air regulation, to ensure 
adequate compliance while simultaneously recognizing that despite the 
most diligent of efforts, emission standards may be violated under 
circumstances entirely beyond the control of the source. Although the 
EPA recognized that its case-by-case enforcement discretion provides 
sufficient flexibility in these circumstances, it included the 
affirmative defense to provide a more formalized approach and more 
regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 
1057-58 (D.C. Cir. 1978) (holding that an informal case-by-case 
enforcement discretion approach is adequate); but see Marathon Oil Co. 
v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more 
formalized approach to consideration of ``upsets beyond the control of 
the permit holder.''). Under the EPA's regulatory affirmative defense 
provisions, if a source could demonstrate in a judicial or 
administrative proceeding that it had met the requirements of the 
affirmative defense in the regulation, civil penalties would not be 
assessed. Recently, the United States Court of Appeals for the District 
of Columbia Circuit vacated such an affirmative defense in one of the 
EPA's section 112(d) regulations. NRDC v. EPA, No. 10-1371 (D.C. Cir. 
April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense 
provisions in section 112(d) rule establishing emission standards for 
Portland cement kilns). The court found that the EPA lacked authority 
to establish an affirmative defense for private civil suits and held 
that under the CAA, the authority to determine civil penalty amounts 
lies exclusively with the courts, not the EPA. Specifically, the Court 
found: ``As the language of the statute makes clear, the courts 
determine, on a case-by-case basis, whether civil penalties are 
`appropriate.' '' See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (``[U]nder 
this statute, deciding whether penalties are `appropriate' in a given 
private civil suit is a job for the courts, not EPA.'').\41\ In light 
of NRDC, the EPA is not including a regulatory affirmative defense 
provision in this rulemaking. As explained above, if a source is unable 
to comply with emissions standards as a result of a malfunction, the 
EPA may use its case-by-case enforcement discretion to provide 
flexibility, as appropriate. Further, as the D.C. Circuit recognized, 
in an EPA or citizen enforcement action, the court has the discretion 
to consider any defense raised and determine whether penalties are 
appropriate. Cf. NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments 
that violation were caused by unavoidable technology failure can be 
made to the courts in future civil cases when the issue arises). The 
same logic applies to EPA administrative enforcement actions.
---------------------------------------------------------------------------

    \41\ The court's reasoning in NRDC focuses on civil judicial 
actions. The Court noted that ``EPA's ability to determine whether 
penalties should be assessed for Clean Air Act violations extends 
only to administrative penalties, not to civil penalties imposed by 
a court.'' Id.
---------------------------------------------------------------------------

a. General Duty
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.6(e)(1)(i) by changing the 
``Yes'' in the second column to a ``No.'' Similarly, we are proposing 
to revise the 40 CFR part 63, subpart UUU General Provisions table 
(Table 44) entry for Sec.  63.6(e)(1)(i) by changing the ``Yes'' in the 
third column to a ``No.'' We are making this change because section 
63.6(e)(1)(i) describes the general duty to minimize emissions and the 
current characterizes what the general duty entails during periods of 
SSM and that language is no longer necessary or appropriate in light of 
the elimination of the SSM exemption. We are proposing instead to add 
general duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c) 
that reflects the general duty to minimize emissions while eliminating 
the reference to periods covered by an SSM exemption. With the 
elimination of the SSM exemption, there is no need to differentiate 
between normal operations, startup and shutdown, and malfunction events 
in describing the general duty. Therefore the language the EPA is 
proposing does not include that language from 40 CFR 63.6(e)(1).
    We are also proposing to revise the 40 CFR part 63, subpart CC 
General Provisions table (Table 6) entry for 63.6(e)(1)(ii) by changing 
the ``Yes'' in the second column to a ``No.'' Similarly, we are also 
proposing to revise the 40 CFR part 63, subpart UUU General Provisions 
table (Table 44) entry for Sec.  63.6(e)(1)(ii) by changing the ``Yes'' 
in the third column to a ``No.'' Section 63.6(e)(1)(ii) imposes 
requirements that are not necessary with the elimination of the SSM 
exemption or are redundant of the general duty requirement being added 
at 40 CFR 63.642(n) and 40 CFR 63.1570(c).
b. SSM Plan
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entries for 63.6(e)(3)(i) and 
63.6(e)(3)(iii)-63.6(e)(3)(ix) by changing the ``Yes'' in the second 
column to a ``No.'' Similarly, we are proposing to revise the 40 CFR 
part 63, subpart UUU General Provisions table (Table 44) entries for 
Sec.  63.6(e)(3)(i)-(iii), Sec.  63.6(e)(3)(iv), Sec.  63.6(e)(3)(v)-
(viii), Sec.  63.6(e)(3)(ix) to be entries for 63.6(e)(3)(i) and 
63.6(e)(3)(iii)-63.6(e)(3)(ix) with ``No'' in the third column and 
Sec.  63.6(e)(3)(ii) with ``Not

[[Page 36946]]

Applicable'' in the third column (that section is reserved). Generally, 
these paragraphs require development of an SSM plan and specify SSM 
recordkeeping and reporting requirements related to the SSM plan. As 
noted, the EPA is proposing to remove the SSM exemptions. Therefore, 
affected units will be subject to an emission standard during such 
events. The applicability of a standard during such events will ensure 
that sources have ample incentive to plan for and achieve compliance 
and thus the SSM plan requirements are no longer necessary.
c. Compliance With Standards
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.6(f)(1) by changing the ``Yes'' 
in the second column to a ``No.'' Similarly, we are proposing to revise 
the 40 CFR part 63, subpart UUU General Provisions table (Table 44) 
entry for Sec.  63.6(f)(1) by changing the ``Yes'' in the third column 
to a ``No.'' The current language of 40 CFR 63.6(f)(1) exempts sources 
from non-opacity standards during periods of SSM. As discussed above, 
the court in Sierra Club vacated the exemptions contained in this 
provision and held that the CAA requires that some section 112 standard 
apply continuously. Consistent with Sierra Club, the EPA is proposing 
to revise standards in this rule to apply at all times.
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.6(h)(1) by changing the ``Yes'' 
in the second column to a ``No.'' Similarly, we are proposing to revise 
the 40 CFR part 63, subpart UUU General Provisions table (Table 44) 
entry for Sec.  63.6(h)(1) by changing the ``Yes'' in the third column 
to a ``No.'' The current language of 40 CFR 63.6(h)(1) exempts sources 
from opacity standards during periods of SSM. As discussed above, the 
court in Sierra Club vacated the exemptions contained in this provision 
and held that the CAA requires that some section 112 standard apply 
continuously. Consistent with Sierra Club, the EPA is proposing to 
revise standards in this rule to apply at all times.
d. Performance Testing
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.7(e)(1) by changing the ``Yes'' 
in the second column to a ``No.'' Similarly, we are proposing to revise 
the 40 CFR part 63, subpart UUU General Provisions table (Table 44) 
entry for Sec.  63.7(e)(1) by changing the ``Yes'' in the third column 
to a ``No.'' Section 63.7(e)(1) describes performance testing 
requirements. The EPA is instead proposing to add performance testing 
requirements at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1). The 
performance testing requirements we are proposing differ from the 
General Provisions performance testing provisions in several respects. 
The regulatory text does not include the language in 40 CFR 63.7(e)(1) 
that restated the SSM exemption. The regulatory text also does not 
preclude startup and shutdown periods from being considered 
``representative'' for purposes of performance testing, however, the 
testing. However, the specific testing provisions proposed at 40 CFR 
63.642(d)(3) and 40 CFR 63.1571(b)(1) do not allow performance testing 
during startup or shutdown. As in 40 CFR 63.7(e)(1), performance tests 
conducted under this subpart may not be conducted during malfunctions 
because conditions during malfunctions are often not representative of 
normal operating conditions. The EPA is proposing to add language that 
requires the owner or operator to record the process information that 
is necessary to document operating conditions during the test and 
include in such record an explanation to support that such conditions 
represent normal operation. Section 63.7(e) requires that the owner or 
operator make available to the Administrator such records ``as may be 
necessary to determine the condition of the performance test'' 
available to the Administrator upon request, but does not specifically 
require the information to be recorded. The regulatory text EPA is 
proposing to add to Refinery MACT 1 and 2 builds on that requirement 
and makes explicit the requirement to record the information.
e. Monitoring
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entries for 63.8(c)(1)(i) and 
63.8(c)(1)(iii) by changing the ``Yes'' in the second column to a 
``No.'' Similarly, we are proposing to revise the 40 CFR part 63, 
subpart UUU General Provisions table (Table 44) entry for Sec.  
63.8(c)(1)(i) and Sec.  63.8(c)(1)(iii) by changing the ``Yes'' in the 
third column to a ``No.'' The cross-references to the general duty and 
SSM plan requirements in those subparagraphs are not necessary in light 
of other requirements of 40 CFR 63.8 that require good air pollution 
control practices (40 CFR 63.8(c)(1)) and that set out the requirements 
of a quality control program for monitoring equipment (40 CFR 63.8(d)).
    We are proposing to revise the 40 CFR part 63, subpart UUU General 
Provisions table (Table 44) entry for Sec.  63.8(d) to include separate 
entries for specific paragraphs of 40 CFR 63.8(d), including an entry 
for Sec.  63.10(d)(3) with ``No'' in the third column. The final 
sentence in 40 CFR 63.8(d)(3) refers to the General Provisions' SSM 
plan requirement which is no longer applicable. The EPA is proposing to 
add to the rule at 40 CFR 63.1576(b)(3) text that is identical to 40 
CFR 63.8(d)(3) except that the final sentence is replaced with the 
following sentence: ``The program of corrective action should be 
included in the plan required under Sec.  63.8(d)(2).''
f. Recordkeeping
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.10(b)(2)(i) by changing the 
``Yes'' in the second column to a ``No.'' Section 63.10(b)(2)(i) 
describes the recordkeeping requirements during startup and shutdown. 
These recording provisions are no longer necessary because the EPA is 
proposing that recordkeeping and reporting applicable to normal 
operations will apply to startup and shutdown. In the absence of 
special provisions applicable to startup and shutdown, such as a 
startup and shutdown plan, there is no reason to retain additional 
recordkeeping for startup and shutdown periods.
    We are proposing to revise the 40 CFR part 63, subpart UUU General 
Provisions table (Table 44) entry for Sec.  63.10(b) to include 
separate entries for specific paragraphs of 40 CFR 63.10(b), including 
an entry for Sec.  63.10(b)(2)(i) with ``No'' in the third column. 
Section 63.10(b)(2)(i) describes the recordkeeping requirements during 
startup and shutdown. We are instead proposing to add recordkeeping 
requirements to 40 CFR 63.1576(a)(2). When a source is subject to a 
different standard during startup and shutdown, it will be important to 
know when such startup and shutdown periods begin and end in order to 
determine compliance with the appropriate standard. Thus, the EPA is 
proposing to add language to 40 CFR 63.1576(a)(2) requiring that 
sources subject to an emission standard during startup or shutdown that 
differs from the emission standard that applies at all other times must 
record the date, time, and duration of such periods.
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.10(b)(2)(ii) by changing the 
``Yes'' in the second column to a ``No.'' Similarly, we are proposing 
to revise the 40 CFR part 63,

[[Page 36947]]

subpart UUU General Provisions table (Table 44) entry for Sec.  
63.10(b) to include separate entries for specific paragraphs of 40 CFR 
63.10(b), including an entry for Sec.  63.10(b)(2)(ii) with ``No'' in 
the third column. Section 63.10(b)(2)(ii) describes the recordkeeping 
requirements during a malfunction. The EPA is proposing to add such 
requirements to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2). The 
regulatory text we are proposing to add differs from the General 
Provisions language that was cross-referenced, which provides the 
creation and retention of a record of the occurrence and duration of 
each malfunction of process, air pollution control, and monitoring 
equipment. The proposed text would apply to any failure to meet an 
applicable standard and would require the source to record the date, 
time, and duration of the failure. The EPA is also proposing to add to 
40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that 
sources keep records that include a list of the affected source or 
equipment and actions taken to minimize emissions, an estimate of the 
quantity of each regulated pollutant emitted over the standard for 
which the source failed to meet a standard, and a description of the 
method used to estimate the emissions. Examples of such methods would 
include product-loss calculations, mass balance calculations, 
measurements when available, or engineering judgment based on known 
process parameters. The EPA is proposing to require that sources keep 
records of this information to ensure that there is adequate 
information to allow the EPA to determine the severity of any failure 
to meet a standard, and to provide data that may document how the 
source met the general duty to minimize emissions when the source has 
failed to meet an applicable standard.
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.10(b)(2)(iv) by changing the 
``Yes'' in the second column to a ``No.'' Similarly, we are proposing 
to revise the 40 CFR part 63, subpart UUU General Provisions table 
(Table 44) entry for Sec.  63.10(b) to include separate entries for 
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.  
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable, 
40 CFR 63.10(b)(2)(iv) requires sources to record actions taken during 
SSM events when actions were inconsistent with their SSM plan. The 
requirement is no longer appropriate because SSM plans will no longer 
be required. The requirement previously applicable under 40 CFR 
63.10(b)(2)(iv)(B) to record actions to minimize emissions and record 
corrective actions is now applicable by reference to 40 CFR 
63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii).
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entry for 63.10(b)(2)(v) by changing the 
``Yes'' in the second column to a ``No.'' Similarly, we are proposing 
to revise the 40 CFR part 63, subpart UUU General Provisions table 
(Table 44) entry for Sec.  63.10(b) to include separate entries for 
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.  
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable, 
40 CFR 63.10(b)(2)(v) requires sources to record actions taken during 
SSM events to show that actions taken were consistent with their SSM 
plan. The requirement is no longer appropriate because SSM plans would 
no longer be required.
    We are proposing to revise the 40 CFR part 63, subpart UUU General 
Provisions table (Table 44) entry for Sec.  63.10(c)(9)-(15) to include 
separate entries for specific paragraphs of 40 CFR 63.10(c), including 
an entry for Sec.  63.10(c)(15) with ``No'' in the third column. The 
EPA is proposing that 40 CFR 63.10(c)(15) no longer apply. When 
applicable, the provision allows an owner or operator to use the 
affected source's SSM plan or records kept to satisfy the recordkeeping 
requirements of the SSM plan, specified in 40 CFR 63.6(e), to also 
satisfy the requirements of 40 CFR 63.10(c)(10) through (12). The EPA 
is proposing to eliminate this requirement because SSM plans would no 
longer be required, and therefore 40 CFR 63.10(c)(15) no longer serves 
any useful purpose for affected units.
g. Reporting
    We are proposing to revise the 40 CFR part 63, subpart CC General 
Provisions table (Table 6) entries for 63.10(d)(5)(i) and 
63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a 
``No'' in the second column. Similarly, we are proposing to revise the 
40 CFR part 63, subpart UUU General Provisions table (Table 44) entries 
for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry 
for 63.10(d)(5) with a ``No'' in the third column. Section 63.10(d)(5) 
describes the reporting requirements for startups, shutdowns, and 
malfunctions. To replace the General Provisions reporting requirement, 
the EPA is proposing to add reporting requirements to 40 CFR 
63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 63.1575(d), and 40 CFR 
63.1575(e). The General Provisions requirement that was cross-
referenced requires periodic SSM reports as a stand-alone report. In 
its place, we are proposing language that requires sources that fail to 
meet an applicable standard at any time to report the information 
concerning such events in the periodic report already required under 
each of these rules. We are proposing that the report must contain the 
number, date, time, duration, and the cause of such events (including 
unknown cause, if applicable), a list of the affected source or 
equipment, an estimate of the quantity of each regulated pollutant 
emitted over any emission limit, and a description of the method used 
to estimate the emissions.
    Examples of methods that can be used to estimate emissions would 
include product-loss calculations, mass balance calculations, 
measurements when available, or engineering judgment based on known 
process parameters. The EPA is proposing this requirement to ensure 
that there is adequate information to determine compliance, to allow 
the EPA to determine the severity of the failure to meet an applicable 
standard, and to provide data that may document how the source met the 
general duty to minimize emissions during a failure to meet an 
applicable standard.
    We will no longer require owners or operators to determine whether 
actions taken to correct a malfunction are consistent with an SSM plan, 
because SSM plans would no longer be required. The proposed rule 
eliminates the cross-reference to 40 CFR 63.10(d)(5)(i) that contains 
the description of the previously required SSM report format and 
submittal schedule from this section. These specifications are no 
longer necessary because the events will be reported in otherwise 
required reports with similar format and submittal requirements.
    As noted above, we are proposing to revise the 40 CFR part 63, 
subpart CC General Provisions table (Table 6) entries for 
63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 
63.10(d)(5) with a ``No'' in the second column. Similarly, we are 
proposing to revise the 40 CFR part 63, subpart UUU General Provisions 
table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by 
combining them into one entry for 63.10(d)(5) with a ``No'' in the 
third column. Section 63.10(d)(5)(ii) describes an immediate report for 
startups, shutdown, and malfunctions when a source fails to meet an 
applicable standard but does not follow the SSM plan. We are proposing 
to no longer require owners and operators to report when actions taken 
during a startup, shutdown, or malfunction were not consistent with an 
SSM plan,

[[Page 36948]]

because such plans would no longer be required.
2. Electronic Reporting
    In this proposal, the EPA is describing a process to increase the 
ease and efficiency of performance test data submittal while improving 
data accessibility. Specifically, the EPA is proposing that owners and 
operators of petroleum refineries submit electronic copies of required 
performance test and performance evaluation reports by direct computer-
to-computer electronic transfer using EPA-provided software. The direct 
computer-to-computer electronic transfer is accomplished through the 
EPA's Central Data Exchange (CDX) using the Compliance and Emissions 
Data Reporting Interface (CEDRI). The CDX is EPA's portal for submittal 
of electronic data. The EPA-provided software is called the Electronic 
Reporting Tool (ERT) which is used to generate electronic reports of 
performance tests and evaluations. The ERT generates an electronic 
report package which will be submitted using the CEDRI. The submitted 
report package will be stored in the CDX archive (the official copy of 
record) and the EPA's public database called WebFIRE. All stakeholders 
will have access to all reports and data in WebFIRE and accessing these 
reports and data will be very straightforward and easy (see the WebFIRE 
Report Search and Retrieval link at http://cfpub.epa.gov/webfire/index.cfm?action=fire.searchERTSubmission). A description and 
instructions for use of the ERT can be found at http://www.epa.gov/ttn/chief/ert/index.html and CEDRI can be accessed through the CDX Web site 
(www.epa.gov/cdx). A description of the WebFIRE database is available 
at: http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
    The proposal to submit performance test data electronically to the 
EPA applies only to those performance tests (and/or performance 
evaluations) conducted using test methods that are supported by the 
ERT. The ERT supports most of the commonly used EPA reference methods. 
A listing of the pollutants and test methods supported by the ERT is 
available at: http://www.epa.gov/ttn/chief/ert/index.html.
    We believe that industry would benefit from this proposed approach 
to electronic data submittal. Specifically, by using this approach, 
industry will save time in the performance test submittal process. 
Additionally, the standardized format that the ERT uses allows sources 
to create a more complete test report resulting in less time spent on 
data backfilling if a source failed to include all data elements 
required to be submitted. Also through this proposal industry may only 
need to submit a report once to meet the requirements of the applicable 
subpart because stakeholders can readily access these reports from the 
WebFIRE database. This also benefits industry by cutting back on 
recordkeeping costs as the performance test reports that are submitted 
to the EPA using CEDRI are no longer required to be retained in hard 
copy, thereby reducing staff time needed to coordinate these records.
    Since the EPA will already have performance test data in hand, 
another benefit to industry is that fewer or less substantial data 
collection requests in conjunction with prospective required residual 
risk assessments or technology reviews will be needed. This would 
result in a decrease in staff time needed to respond to data collection 
requests.
    State, local and tribal air pollution control agencies (S/L/Ts) may 
also benefit from having electronic versions of the reports they are 
now receiving. For example, S/L/Ts may be able to conduct a more 
streamlined and accurate review of electronic data submitted to them. 
For example, the ERT would allow for an electronic review process, 
rather than a manual data assessment, therefore, making review and 
evaluation of the source provided data and calculations easier and more 
efficient. In addition, the public stands to benefit from electronic 
reporting of emissions data because the electronic data will be easier 
for the public to access. How the air emissions data are collected, 
accessed and reviewed will be more transparent for all stakeholders.
    One major advantage of the proposed submittal of performance test 
data through the ERT is a standardized method to compile and store much 
of the documentation required to be reported by this rule. The ERT 
clearly states what testing information would be required by the test 
method and has the ability to house additional data elements that might 
be required by a delegated authority.
    In addition the EPA must have performance test data to conduct 
effective reviews of CAA sections 111 and 112 standards, as well as for 
many other purposes including compliance determinations, emission 
factor development and annual emission rate determinations. In 
conducting these required reviews, the EPA has found it ineffective and 
time consuming, not only for us, but also for regulatory agencies and 
source owners and operators, to locate, collect and submit performance 
test data. In recent years, stack testing firms have typically 
collected performance test data in electronic format, making it 
possible to move to an electronic data submittal system that would 
increase the ease and efficiency of data submittal and improve data 
accessibility.
    A common complaint heard from industry and regulators is that 
emission factors are outdated or not representative of a particular 
source category. With timely receipt and incorporation of data from 
most performance tests, the EPA would be able to ensure that emission 
factors, when updated, represent the most current range of operational 
practices. Finally, another benefit of the proposed data submittal to 
WebFIRE electronically is that these data would greatly improve the 
overall quality of existing and new emissions factors by supplementing 
the pool of emissions test data for establishing emissions factors.
    In summary, in addition to supporting regulation development, 
control strategy development and other air pollution control 
activities, having an electronic database populated with performance 
test data would save industry, state, local and tribal agencies and the 
EPA significant time, money and effort while also improving the quality 
of emission inventories and air quality regulations.
    In addition, we are proposing that the fenceline data at each 
monitor location (as proposed above) would be reported electronically 
on a semiannual basis. All data reported electronically would be 
submitted to CDX through CEDRI and made available to the public.
3. Technical Amendments to Refinery MACT 1 and 2
a. Open-Ended Valves and Lines
    Refinery MACT 1 requires an owner or operator to control emissions 
from equipment leaks according to the requirements of either 40 CFR 
part 60, subpart VV or 40 CFR part 63, subpart H. For open-ended valves 
and lines, both subparts require that the open end be equipped with a 
cap, blind flange, plug or second valve that ``shall seal the open end 
at all times.'' However, neither subpart defines ``seal'' or explains 
in practical and enforceable terms what constitutes a sealed open-ended 
valve or line. This has led to uncertainty on the part of the owner or 
operator as to whether compliance is being achieved. Inspections under 
the EPA's Air Toxics LDAR initiative have provided evidence that while 
certain open-ended lines may be equipped with a cap, blind flange, plug 
or second valve, they are not

[[Page 36949]]

operating in a ``sealed'' manner as the EPA interprets that term.
    In response to this uncertainty, we are proposing to amend 40 CFR 
63.648 to clarify what is meant by ``seal.'' This proposed amendment 
clarifies that, for the purpose of complying with the requirements of 
40 CFR 63.648, open-ended valves and lines are ``sealed'' by the cap, 
blind flange, plug, or second valve when there are no detectable 
emissions from the open-ended valve or line at or above an instrument 
reading of 500 ppm. We solicit comment on this approach to reducing the 
compliance uncertainty associated with open-ended valves and lines and 
our proposed amendment.
b. General Provisions Cross-Referencing
    We have reviewed the application of 40 CFR part 63, subpart A 
(General Provisions) to Refinery MACT 2. The applicable requirements of 
40 CFR part 63, subpart A are contained in Table 44 of 40 CFR part 63, 
subpart UUU. As a result of our review, we are proposing several 
amendments to Table 44 of 40 CFR part 63, subpart UUU (in addition to 
those discussed in section IV.E.1 of this preamble that address SSM) to 
bring the table up-to-date with requirements of the General Provisions 
that have been amended since this table was created, to correct cross-
references, and to incorporate additional sections of the General 
Provisions that are necessary to implement other subparts that are 
cross-referenced by this rule.
    Although we reviewed the application of the General Provisions to 
Refinery MACT 1 and amended Table 6 of 40 CFR part 63, subpart CC in 
2009, we are proposing a few additional technical corrections to this 
table (in addition to those discussed in section IV.E.1 of this 
preamble that address SSM). We are not discussing the details of these 
proposed technical corrections in this preamble but the rationale for 
each change to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40 
CFR part 63, subpart UUU (including the proposed amendments to address 
SSM discussed above), is included in Docket ID Number EPA-HQ-OAR-2010-
0682.
4. Amendments to Refinery NSPS J and Ja
    As discussed in section II.B.2 of this preamble, we are addressing 
a number of technical corrections and clarifications for Refinery NSPS 
J and Ja to address some of the issues raised in the petition for 
reconsideration and to improve consistency and clarity of the rule 
requirements. These issues are addressed in detail in API's amended 
petition, dated August 21, 2008 (see Docket Item Number EPA-HQ-OAR-
2007-0011-0246) and the meeting minutes for a September 11, 2008 
meeting between EPA and API (see Docket Item Number EPA-HQ-OAR-2007-
0011-0266).
a. The Depressurization Work Practice Standard for Delayed Coking Units
    HOVENSA and the Industry Petitioners raised several issues with the 
analysis conducted to support the DCU work practice standard in 
Refinery NSPS Ja. With the promulgation and implementation of the 
standards we are proposing for the DCU under Refinery MACT 1, the DCU 
work practice standards in Refinery NSPS Ja are not expected to result 
in any further decreases in emissions from the DCU. Any DCU that 
becomes subject to Refinery NSPS Ja would already be in compliance with 
Refinery MACT 1, which is a more stringent standard than the DCU work 
practice standards in Refinery NSPS Ja. As such, we are contemplating 
various ideas for harmonizing the requirements for the DCU in these two 
regulations. One option is to amend Refinery NSPS Ja to incorporate the 
same requirements being proposed for Refinery MACT 1 (the DCU work 
practice standard in Refinery NSPS Ja is less stringent than the 
proposed requirements for Refinery MACT 1). Another option we are 
contemplating is deleting the DCU work practice standard within 
Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are 
promulgated and fully implemented. We believe deletion of this work 
practice standard is consistent with the objectives of Executive Order 
13563, ``Improving Regulation and Regulatory Review.'' We solicit 
comment on these options as well as any other comments regarding the 
interaction between the DCU requirements in these two rules (i.e., the 
need to keep the DCU work practice standard in Refinery NSPS Ja after 
promulgation of these revisions to Refinery MACT 1.)
b. Technical Corrections and Clarifications
    In addition to their primary issues, the Industry Petitioners 
enumerated several points of clarification and recommended amendments 
to Refinery NSPS J and Ja. These issues are addressed in detail in 
API's amended petition for reconsideration, dated August 21, 2008 (see 
Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting minutes 
for a September 11, 2008 meeting between EPA and API (see Docket Item 
Number EPA-HQ-OAR-2007-0011-0266). We are including several proposed 
amendments in this rulemaking to specifically address these issues. 
These amendments are discussed in the remainder of this section. We are 
addressing these issues now while we are proposing amendments for 
Refinery MACT 2 in an effort to improve consistency and clarity for 
sources regulated under both the NSPS and Refinery MACT 2.
    We are proposing a series of amendments to the requirements for 
sulfur recovery plants in 40 CFR 60.102a, to clarify the applicable 
emission limits for different types of sulfur recovery plants based on 
whether oxygen enrichment is used. These amendments also clarify that 
emissions averaging across a group of emission points within a given 
sulfur recovery plant is allowed from each of the different types of 
sulfur recovery plants, and that emissions averaging is specific to the 
SO2 or reduced sulfur standards (and not to the 
H2S limit). The 10 ppmv H2S limit for reduction 
control systems not followed by incineration must be met on a release 
point-specific basis. These amendments are being made to clarify the 
original intent of the Refinery NSPS Ja requirements for sulfur 
recovery plants.
    We are proposing a series of corresponding amendments in 40 CFR 
60.106a to clarify the monitoring requirements, particularly when 
oxygen enrichment or emissions averaging is used. The monitoring 
requirements in Refinery NSPS Ja were incomplete for these provisions 
and did not specify all of the types of monitoring devices needed for 
implementation. We are also proposing in 40 CFR 60.106a to use the term 
``reduced sulfur compounds'' when referring to the emission limits and 
monitoring devices needed to comply with the reduced sulfur compound 
emission limits for sulfur recovery plants with reduction control 
systems not followed by incineration. The term ``reduced sulfur 
compounds'' is a defined term in Refinery NSPS Ja, and the emissions 
limit for sulfur recovery plants with reduction control systems not 
followed by incineration is specific to ``reduced sulfur compounds.'' 
Therefore, the proposed amendments to the monitoring provisions provide 
clarification of the requirements by using a consistent, defined term.
    We are proposing amendments to 40 CFR 60.102a(g)(1) to clarify that 
CO boilers, while part of the FCCU affected facility, can also be fuel 
gas combustion devices (FGCD). Industry Petitioners suggested that the 
CO boiler should only be subject to the FCCU NOX and 
SO2

[[Page 36950]]

limits and should not be considered a FGCD. While Refinery NSPS Ja 
clearly states that the coke burn-off exhaust from the FCCU catalyst 
regenerator is not considered to be fuel gas, other fuels combusted in 
the CO boiler must meet the H2S concentration requirements 
for fuel gas like any other FGCD. This amendment is provided to clarify 
our original intent with respect to fuel gas. Industry Petitioners also 
noted that some CO boiler ``furnaces'' may be used as process heaters 
rather than steam-generating boilers. While we did not originally 
contemplate that CO furnaces would be used as process heaters, 
available data from the detailed ICR suggests that there are a few CO 
furnaces used as process heaters. These CO furnaces are all forced-
draft process heaters, and the newly amended NOX emissions 
limit in Refinery NSPS Ja for forced-draft process heaters is 60 ppmv, 
averaged over a 30-day period. Given the longer averaging time of the 
process heater NOX limits, these two emission limits (for 
FCCU NOX and for process heater NOX) are 
reasonably comparable and are not expected to result in a significant 
difference in the control systems selected for compliance. As such, we 
are not amending or clarifying the NOX standards for the 
FCCU or process heaters at this time. We are, however, clarifying 
(through this response) that if an emission source meets the definition 
of more than one affected facility, that source would need to comply 
with all requirements applicable to the emissions source.
    We are proposing to revise the annual testing requirement in 40 CFR 
60.104a(b) to clarify our original intent. Instead of requiring a PM 
performance test at least once every 12 months, the rule would require 
a PM performance test annually and specify that annually means once per 
calendar year, with an interval of at least 8 months but no more than 
16 months between annual tests. This provision will ensure that testing 
is conducted at a reasonable interval while giving owners and operators 
flexibility in scheduling the testing. We are also proposing to amend 
40 CFR 60.104a(f) to clarify that the provisions of that paragraph are 
specific to owners or operators of an FCCU or FCU that use a cyclone to 
comply with the PM per coke burn-off emissions limit (rather than just 
the PM limit) in 40 CFR 60.102a(b)(1), to clarify that facilities 
electing to comply with the concentration limit using a PM CEMS would 
not also be required to install a COMS. We are also proposing to amend 
40 CFR 60.104a(j) to delete the requirements to measure flow for the 
H2S concentration limit for fuel gas, as these are not 
needed in the performance evaluation.
    We are proposing amendments to 40 CFR 60.105a(b)(1)(ii)(A) to 
require corrective action be completed to repair faulty (leaking or 
plugged) air or water lines within 12 hours of identification of an 
abnormal pressure reading during the daily checks. We are also 
proposing amendments to 40 CFR 60.105a(i) to include periods when 
abnormal pressure readings for a jet ejector-type wet scrubber (or 
other type of wet scrubber equipped with atomizing spray nozzles) are 
not corrected within 12 hours of identification, and periods when a bag 
leak detection system alarm (for a fabric filter) is not alleviated 
within the time period specified in the rule. These proposed amendments 
are necessary so that periods when the APCD operation is compromised 
are properly managed and/or reported.
    We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and 
60.107a(b)(1)(iv) to allow using tubes with a maximum span between 10 
and 40 ppmv, inclusive, when 1<=N<=10, where N = number of pump strokes 
rather than requiring use of tubes with ranges 0-10/0-100 ppm (N = 10/
1) because different length-of-stain tube manufacturers have different 
span ranges, and none of the commercially-available tubes have a 
specific span of 0-10/0-100 ppm (N = 10/1). We are also proposing to 
amend 40 CFR 60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify 
that the temporary daily stain sampling must be made using length-of 
stain tubes with a maximum span between 200 and 400 ppmv, inclusive, 
when 1<=N<=5, where N = number of pump strokes. This proposed amendment 
clarifies this monitoring requirement, ensures the proper tube range is 
used, and provides some flexibility in span range to accommodate 
different manufacturers of the length-of-stain tubes. We also propose 
to delete the last sentence in 40 CFR 60.105(b)(3)(iii), as there is no 
long-term H2S concentration limit in Refinery NSPS J.
    We are proposing to clarify that flares are subject to the 
performance test requirements. We are also proposing to clarify those 
performance test requirements in 40 CFR 60.107a(e)(1)(ii) and 40 CFR 
60.107a(e)(2)(ii) to remove the distinction between flares with or 
without routine flow. The term ``routine flow'' is not defined and it 
is difficult to make this distinction in practice.

F. What compliance dates are we proposing?

    Amendments to Refinery MACT 1 and 2 proposed in this rulemaking for 
adoption under CAA section 112(d)(2) and (3) and CAA section 112(d)(6) 
are subject to the compliance deadlines outlined in the CAA under 
section 112(i). For all of the requirements we are proposing under CAA 
section 112(d)(2) and (3) or CAA section 112(d)(6) except for storage 
vessels, which we are also requiring under 112 (f)(2), we are proposing 
the following compliance dates. As provided in CAA section 112(i), new 
sources would be required to comply with these requirements by the 
effective date of the final amendments to Refinery MACT 1 and 2 or 
startup, whichever is later.
    For existing sources, CAA section 112(i) provides that the 
compliance date shall be as expeditiously as practicable, but no later 
than 3 years after the effective date of the standard. In determining 
what compliance period is as expeditious as practicable, we consider 
the amount of time needed to plan and construct projects and change 
operating procedures. Under CAA section 112(d)(2) and (3), we are 
proposing new operating requirements for DCU. In order to comply with 
these new requirements, we project that most DCU owners or operators 
would need to install additional controls (e.g., steam ejector 
systems). Similarly, the proposed revision in the CRU pressure limit 
exclusions would require operational changes and, in some cases, 
additional controls. The addition of new control equipment would 
require engineering design, solicitation and review of vendor quotes, 
contracting and installation of the equipment, which would need to be 
timed with process unit outage and operator training. Therefore, we are 
proposing that it is necessary to provide 3 years after the effective 
date of the final rule for these sources to comply with the DCU and CRU 
requirements.
    We are proposing new operating and monitoring requirements for 
flares under CAA section 112(d)(2) and (3). We anticipate that these 
requirements would require the installation of new flare monitoring 
equipment and we project most refineries would install new control 
systems to monitor and adjust assist gas (air or steam) addition rates. 
Similar to the addition of new control equipment, these new monitoring 
requirements for flares would require engineering evaluations, 
solicitation and review of vendor quotes, contracting and installation 
of the equipment, and operator training.

[[Page 36951]]

Installation of new monitoring and control equipment on flares will 
require the flare to be taken out of service. Depending on the 
configuration of the flares and flare header system, taking the flare 
out of service may also require a significant portion of the refinery 
operations to be shut down. Therefore, we are proposing that it is 
necessary to provide 3 years after the effective date of the final rule 
for owners or operators to comply with the new operating and monitoring 
requirements for flares.
    Under CAA section 112(d)(2) and (3), we are proposing new vent 
control requirements for bypasses. These requirements would typically 
require the addition of piping and potentially new control 
requirements. As these vent controls would most likely be routed to the 
flare, we are proposing to provide 3 years after the effective date of 
the final rule for owners or operators to afford coordination of these 
bypass modifications with the installation of the new monitoring 
equipment for the flares.
    Under our technology review, we are proposing to require fenceline 
monitoring pursuant to CAA section 112(d)(6). These proposed provisions 
would require refinery owners or operators to install a number of 
monitoring stations around the facility fenceline. While the diffusive 
tube sampling system is relatively low-tech and is easy to install, 
site-specific factors must be considered in the placement of the 
monitoring systems. We also assume all refinery owners or operators 
would invest in the analytical equipment needed to perform automated 
sample analysis on-site and time is needed to select an appropriate 
vendor for this equipment. Furthermore, additional monitoring systems 
may be needed to account for near-field contributing sources, for which 
the development and approval of a site-specific monitoring plan. 
Considering all of the requirements needed to implement the fenceline 
monitoring system, we are proposing to provide 3 years from the 
effective date of the final rule for refinery owners or operators to 
install and begin collecting ambient air samples around the fenceline 
of their facility following an approved (if necessary) site-specific 
monitoring plan.
    As a result of our technology review for equipment leaks, we are 
proposing to allow the use of optical gas imaging devices in lieu of 
using EPA Method 21 of 40 CFR part 60, Appendix A-7 without the annual 
compliance demonstration with EPA Method 21 as required in the AWP (see 
73 FR 73202, December 22, 2008), provided that the owner and operator 
follows the provisions of Appendix K to 40 CFR part 60. Facilities 
could begin to comply with the optical gas imaging alternative as soon 
as Appendix K to 40 CFR part 60 is promulgated. Alternatively, as is 
currently provided in the AWP, the refinery owner or operator can elect 
to use the optical gas imaging monitoring option prior to installation 
and use of the fenceline monitoring system, provided they conduct an 
annual compliance demonstration using EPA Method 21 as required in the 
AWP.
    Under our technology review for marine vessel loading operations, 
we are proposing to add a requirement for submerged filling for small 
and for offshore marine vessel loading operations. We anticipate that 
the submerged fill pipes are already in place on all marine vessels 
used to transport petroleum refinery liquids, so we are proposing that 
existing sources comply with this requirement on the effective date of 
the final rule. We request comment regarding the need to provide 
additional time to comply with the submerged filling requirement; 
please provide in your comment a description of the vessels loaded that 
do not already have a submerged fill pipe, how these vessels comply 
with (or are exempt from) the Coast Guard requirements at 46 CFR 
153.282, and an estimate of the time needed to add the required 
submerged fill pipes to these vessels.
    We are also proposing to require FCCU owners and operators 
currently subject to Refinery NSPS J (or electing that compliance 
option in Refinery MACT 2) to transition from the Refinery NSPS J 
option to one of the alternatives included in the proposed rule. We are 
also proposing altering the averaging times for some of the operating 
limits. A PM performance test is needed in order to establish these new 
operating limits prior to transitioning to the proposed requirements. 
Additionally, we are proposing that a PM performance test be conducted 
for each FCCU once every 5 years. We do not project any new control or 
monitoring equipment will be needed in order to comply with the 
proposed provisions; however, compliance with the proposed provisions 
is dependent on conducting a performance test. Establishing an early 
compliance date for the first performance test can cause scheduling 
issues as refinery owners or operators compete for limited number of 
testing contractors. Considering these scheduling issues, we propose to 
require the first performance test for PM and compliance with the new 
operating limits be completed no later than 18 months after the 
effective date of the final rule.
    In this action, we are proposing revisions to the SSM provisions of 
Refinery MACT 1 and 2, including specific startup or shutdown standards 
for certain emission sources, and we are proposing electronic reporting 
requirements in Refinery MACT 1 and 2. The proposed monitoring 
requirements associated with the new startup and shutdown standards are 
expected to be present on the affected source, so we do not expect that 
owners or operators will need additional time to transition to these 
requirements. Similarly, the electronic reporting requirements are not 
expected to require a significant change in operation or equipment, so 
these requirements should be able to be implemented more quickly than 
those that require installation of new control or monitoring equipment. 
Based on our review of these requirements, we propose that these 
requirements become effective upon the effective date of the final 
rule.
    Finally, we are proposing additional requirements for storage 
vessels under CAA sections 112(d)(6) and (f)(2). The compliance 
deadlines for standards developed under CAA section 112(f)(2) are 
delineated in CAA sections 112(f)(3) and (4). As provided in CAA 
section 112(f)(4), risk standards shall not apply to existing sources 
until 90 days after the effective date of the rule, but the 
Administrator may grant a waiver for a particular source for a period 
of up to 2 years after the effective date. While additional controls 
will be necessary to comply with the proposed new control and fitting 
requirements for storage vessels, the timing for installation of these 
controls is specified within the Generic MACT (40 CFR part 63, subpart 
WW). Therefore, we propose that these new requirements for storage 
vessels become effective 90 days following the effective date of the 
final rule.

V. Summary of Cost, Environmental and Economic Impacts

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

    The sources affected by significant amendments to the petroleum 
refinery standards include storage vessels, equipment leaks, fugitive 
emissions and DCU subject to Refinery MACT 1. The proposed amendments 
for other sources subject to one or more of the petroleum refinery 
standards are expected to have minimal air quality and cost impacts.
    The total capital investment cost of the proposed amendments and 
standards is estimated at $239 million, $82.8 million from proposed 
amendments and $156 million from

[[Page 36952]]

standards to ensure compliance. We estimate annualized costs to be 
approximately $4.53 million, which includes an estimated $14.4 million 
credit for recovery of lost product and the annualized cost of capital. 
We also estimate annualized costs of the proposed standards to ensure 
compliance to be approximately $37.9 million. The proposed amendments 
would achieve a nationwide HAP emission reduction of 1,760 tpy, with a 
concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of this 
preamble summarizes the cost and emission reduction impacts of the 
proposed amendments, and Table 14 of this preamble summarizes the costs 
of the proposed standards to ensure compliance.

                                                                       Table 13--Nationwide Impacts of Proposed Amendments
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Total annualized
                                                   Total capital      cost without    Product recovery  Total annualized    VOC emission          Cost          HAP emission          Cost
                Affected source                     investment     credit (million $/  credit (million  costs (million $/ reductions (tpy)  effectiveness ($/ reductions (tpy)  effectiveness ($/
                                                    (million $)           yr)               $/yr)              yr)                              ton VOC)                            ton HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................................              18.5               3.13            (8.16)            (5.03)            14,600             (345)               910           (5,530)
Delayed Coking Units...........................              52.0              10.2             (6.20)              3.98             4,250               937               850             4,680
Fugitive Emissions (Fenceline Monitoring)......              12.2               5.58  ................              5.58  ................  ................  ................  ................
                                                ------------------------------------------------------------------------------------------------------------------------------------------------
    Total......................................              82.8              18.9             (14.4)              4.53            18,800               241             1,760             2,570
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


                     Table 14--Nationwide Costs of Proposed Amendments to Ensure Compliance
----------------------------------------------------------------------------------------------------------------
                                                                       Total
                                                   Total capital    annualized        Product          Total
                 Affected source                    investment     cost without      recovery       annualized
                                                    (million $)       credit          credit      costs (million
                                                                  (million $/yr)  (million $/yr)       $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Valve Monitoring.........................            9.54            1.36  ..............            1.36
Flare Monitoring................................          147              36.3   ..............           36.3
FCCU Testing....................................           --               0.21  ..............            0.21
                                                 ---------------------------------------------------------------
    Total.......................................          156              37.9               --           37.9
----------------------------------------------------------------------------------------------------------------

    Note that any corrective actions taken in response to the fenceline 
monitoring program are not included in the impacts shown in Table 13. 
Any corrective actions associated with fenceline monitoring will result 
in additional emission reductions and additional costs.
    The impacts shown in Table 14 do not consider emission reductions 
associated with relief valve or flare monitoring provisions or emission 
reductions that may occur as a result of the additional FCCU testing 
requirements. The proposed operational and monitoring requirements for 
flares at refineries have the potential to reduce excess emissions from 
flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 
327,000 metric tonnes per year of CO2e. When added to the 
reductions in CO2e achieved from proposed controls on DCU, 
these proposed amendments are projected to result in reductions of 
670,000 metric tonnes of CO2e due to reductions of methane 
emissions.\42\
---------------------------------------------------------------------------

    \42\ The flare operational and monitoring requirements are 
projected to reduce methane emissions by 29,500 tpy while increasing 
CO2 emissions by 260,000 tpy, resulting in a net GHG 
reduction of 327,000 metric tonnes per year of CO2e, 
assuming a global warming potential of 21 for methane. Combined with 
methane emissions reduction of 18,000 tpy from the proposed controls 
on DCU, the overall GHG reductions of the proposed amendments is 
670,000 metric tonnes per year of CO2e assuming a global 
warming potential of 21 for methane.
---------------------------------------------------------------------------

B. What are the economic impacts?

    We performed a national economic impact analysis for petroleum 
product producers. All petroleum product refiners will incur annual 
compliance costs of much less than 1 percent of their sales. For all 
firms, the minimum cost-to-sales ratio is <0.01 percent; the maximum 
cost-to-sales ratio is 0.87 percent; and the mean cost-to-sales ratio 
is 0.03 percent. Therefore, the overall economic impact of this 
proposed rule should be minimal for the refining industry and its 
consumers.
    In addition, the EPA performed a screening analysis for impacts on 
small businesses by comparing estimated annualized engineering 
compliance costs at the firm-level to firm sales. The screening 
analysis found that the ratio of compliance cost to firm revenue falls 
below 1 percent for the 28 small companies likely to be affected by the 
proposal. For small firms, 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 are provided in the 
technical document Economic Impact Analysis for Petroleum Refineries 
Proposed Amendments to the National Emissions Standards for Hazardous 
Air Pollutants, which is available in the docket for this proposed rule 
(Docket ID Number EPA-HQ-OAR-2010-0682).

C. What are the benefits?

    The proposed rule is anticipated to result in a reduction of 1,760 
tons of HAP (based on allowable emissions under the MACT standards) and 
18,800 tons of VOC emissions per year, not including potential emission 
reductions that may occur as a result of the proposed provisions for 
flares or fenceline monitoring. These avoided emissions will result in 
improvements in air quality and reduced negative health effects 
associated with exposure to air pollution of these emissions; however, 
we have not quantified or monetized the benefits of reducing these 
emissions for this rulemaking.

VI. Request for Comments

    We solicit comments on all aspects of this proposed action. In 
addition to general comments on this proposed action, we are also 
interested in additional data that may improve the risk assessments and 
other analyses. We are specifically interested in receiving any 
improvements to the data used in the site-specific emissions profiles 
used for risk modeling. Such data should include supporting 
documentation in sufficient detail to allow characterization of the 
quality and representativeness of the data or information. Section VII 
of this preamble provides more information on submitting data.

[[Page 36953]]

VII. Submitting Data Corrections

    The site-specific emissions profiles used in the source category 
risk and demographic analyses and instructions are available on the RTR 
Web page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. The data 
files include detailed information for each HAP emissions release point 
for the facilities in the source categories.
    If you believe that the data are not representative or are 
inaccurate, please identify the data in question, provide your reason 
for concern and provide any ``improved'' data that you have, if 
available. When you submit data, we request that you provide 
documentation of the basis for the revised values to support your 
suggested changes. To submit comments on the data downloaded from the 
RTR page, complete the following steps:
    1. Within this downloaded file, enter suggested revisions to the 
data fields appropriate for that information.
    2. Fill in the commenter information fields for each suggested 
revision (i.e., commenter name, commenter organization, commenter email 
address, commenter phone number and revision comments).
    3. Gather documentation for any suggested emissions revisions 
(e.g., performance test reports, material balance calculations).
    4. Send the entire downloaded file with suggested revisions in 
Microsoft[supreg] Access format and all accompanying documentation to 
Docket ID Number EPA-HQ-OAR-2010-0682 (through one of the methods 
described in the ADDRESSES section of this preamble).
    5. If you are providing comments on a single facility or multiple 
facilities, you need only submit one file for all facilities. The file 
should contain all suggested changes for all sources at that facility. 
We request that all data revision comments be submitted in the form of 
updated Microsoft[supreg] Excel files that are generated by the 
Microsoft[supreg] Access file. These files are provided on the RTR Web 
page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html.

VIII. Statutory and Executive Order Reviews

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

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is a ``significant regulatory action'' because it raises novel 
legal and policy issues. Accordingly, the EPA submitted this action to 
the Office of Management and Budget (OMB) for review under Executive 
Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes 
made in response to OMB recommendations have been documented in the 
docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).

B. Paperwork Reduction Act

    The information collection requirements in this rule have been 
submitted for approval to OMB under the Paperwork Reduction Act, 44 
U.S.C. 3501, et seq.
    Revisions and burden associated with amendments to 40 CFR part 63, 
subparts CC and UUU are discussed in the following paragraphs. OMB has 
previously approved the information collection requirements contained 
in the existing regulations in 40 CFR part 63, subparts CC and UUU 
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et 
seq., OMB control numbers for the EPA's regulations in 40 CFR are 
listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b).
    The ICR document prepared by the EPA for the amendments to the 
Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has 
been assigned the EPA ICR number 1692.08. Burden changes associated 
with these amendments would result from new monitoring, recordkeeping 
and reporting requirements. The estimated annual increase in 
recordkeeping and reporting burden hours is 53,619 hours; the frequency 
of response is semiannual for all reports for all respondents that must 
comply with the rule's reporting requirements; and the estimated 
average number of likely respondents per year is 95 (this is the 
average in the second year). The cost burden to respondents resulting 
from the collection of information includes the total capital cost 
annualized over the equipment's expected useful life (about $17 
million, which includes monitoring equipment for bypass valves, 
fenceline monitoring, relief valves, and flares), a total operation and 
maintenance component (about $16 million per year for fenceline and 
flare monitoring), and a labor cost component (about $4.5 million per 
year, the cost of the additional 53,619 labor hours). An agency may not 
conduct or sponsor (and a person is not required to respond to) a 
collection of information unless it displays a currently-valid OMB 
control number.
    The ICR document prepared by the EPA for the amendments to the 
Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has 
been assigned the EPA ICR number 1844.07. Burden changes associated 
with these amendments would result from new testing, recordkeeping and 
reporting requirements being proposed with this action. The estimated 
average burden per response is 26 hours; the frequency of response is 
both once and every 5 years for respondents that have FCCU, and the 
estimated average number of likely respondents per year is 67. The cost 
burden to respondents resulting from the collection of information 
includes the performance testing costs (approximately $356,000 per year 
over the first 3 years for the initial performance test and $213,000 
per year starting in the fourth year), and a labor cost component 
(approximately $238,000 per year for 2,860 additional labor hours). 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.
    To comment on the agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, the EPA has established a public docket 
for this rule, which includes the ICR, under Docket ID Number EPA-HQ-
OAR-2010-0682. Submit any comments related to the ICR to the EPA and 
OMB. See the ADDRESSES section at the beginning of this preamble for 
where to submit comments to the EPA. Send comments to OMB at the Office 
of Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for 
the EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after June 30, 2014, a comment to OMB is best 
assured of having its full effect if OMB receives it by July 30, 2014. 
The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute, unless the agency certifies that 
the rule will not have a significant economic impact on a substantial 
number of small entities (SISNOSE). Small entities include small 
businesses, small organizations and small governmental jurisdictions. 
For purposes of assessing the impacts of this proposed rule on small 
entities, a small entity is defined as: (1) A small business in the 
petroleum refining industry

[[Page 36954]]

having 1,500 or fewer employees (Small Business Administration (SBA), 
2011); (2) a small governmental jurisdiction that is a government of a 
city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The small 
entities subject to the requirements of this proposed rule are small 
refiners. We have determined that 36 companies (59 percent of the 61 
total) employ fewer than 1,500 workers and are considered to be small 
businesses. For small businesses, the average cost-to-sales ratio is 
about 0.05 percent, the median cost-to-sales ratio is 0.02 percent and 
the maximum cost-to-sales ratio is 0.55 percent. The potential costs do 
not have a more significant impact on small refiners and because no 
small firms are expected to have cost-to-sales ratios greater than 1 
percent, we determined that the cost impacts for this rulemaking will 
not have a SISNOSE.
    Although not required by the RFA to convene a Small Business 
Advocacy Review (SBAR) Panel; because the EPA has determined that this 
proposal would not have a significant economic impact on a substantial 
number of small entities, the EPA originally convened a panel to obtain 
advice and recommendations from small entity representatives 
potentially subject to this rule's requirements. The panel was not 
formally concluded; however, a summary of the outreach conducted and 
the written comments submitted by the small entity representatives can 
be found in the docket for this proposed rule (Docket ID Number EPA-HQ-
OAR-2010-0682).
    We continue to be interested in the potential impacts of the 
proposed rule on small entities and welcome comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act

    This proposed rule does not contain a federal mandate under the 
provisions of Title II of the Unfunded Mandates Reform Act of 1995 
(UMRA), 2 U.S.C. 1531-1538 that may result in expenditures of $100 
million or more for state, local and tribal governments, in the 
aggregate, or the private sector in any one year. As discussed earlier 
in this preamble, these amendments result in nationwide costs of $42.4 
million per year for the private sector. Thus, this proposed rule is 
not subject to the requirements of sections 202 or 205 of the UMRA.
    This proposed rule is also not subject to the requirements of 
section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments because it 
contains no requirements that apply to such governments and does not 
impose obligations upon them.

E. Executive Order 13132: Federalism

    This rule does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. None of the facilities subject to 
this action are owned or operated by state governments, and, because no 
new requirements are being promulgated, nothing in this proposal will 
supersede state regulations. Thus, Executive Order 13132 does not apply 
to this rule.
    In the spirit of Executive Order 13132, and consistent with the EPA 
policy to promote communications between the EPA and state and local 
governments, the EPA specifically solicits comment on this proposed 
rule from state and local officials.

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

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have 
substantial direct effects on tribal governments, on the relationship 
between the federal government and Indian tribes, or on the 
distribution of power and responsibilities between the federal 
government and Indian tribes as specified in Executive Order 13175. 
Thus, Executive Order 13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, the 
EPA consulted with tribal officials in developing this action. The EPA 
sent out letters to tribes nationwide to invite them to participate in 
a tribal consultation meeting and solicit their input on this 
rulemaking. The EPA conducted the tribal consultation meeting on 
December 14, 2011. Participants from eight tribes attended the meeting, 
but they were interested only in outreach, and none of the tribes had 
delegation for consultation. The EPA presented all the information 
prepared for the consultation and conducted a question and answer 
session where participants asked clarifying questions about the 
information that was presented and generally expressed their support of 
the rulemaking requirements.
    The EPA specifically solicits additional comment on this proposed 
action from tribal officials.

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

    This action is not subject to Executive Order 13045 (62 FR 19885, 
April 23, 1997) because it is not economically significant as defined 
in Executive Order 12866, and because the agency does not believe the 
environmental health or safety risks addressed by this action present a 
disproportionate risk to children. This action's health and risk 
assessments are contained in sections III.A and B and sections IV.C and 
D of this preamble.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to 
emissions from petroleum refineries.

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

    This action is not a ``significant energy action'' as defined under 
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not 
likely to have significant adverse effect on the supply, distribution 
or use of energy. The overall economic impact of this proposed rule 
should be minimal for the refining industry and its consumers.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) 
directs the EPA to use voluntary consensus standards (VCS) in its 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. VCS are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by VCS bodies. The 
NTTAA directs the EPA to provide Congress, through OMB, explanations 
when the agency decides not to use available and applicable VCS.
    This proposed rulemaking involves technical standards. The EPA 
proposes to use ISO 16017-2, ``Air quality Sampling and analysis of 
volatile organic compounds in ambient air,

[[Page 36955]]

indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography Part 2: Diffusive sampling'' as an 
acceptable alternative to EPA Method 325A. This method is available at 
http://www.iso.org. This method was chosen because it meets the 
requirements of EPA Method 301 for equivalency, documentation and 
validation data for diffusive tube sampling.
    The EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this 
regulation.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies and activities on minority populations and low-income 
populations in the United States.
    The EPA has determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority, low-income or indigenous populations because it 
maintains or increases the level of environmental protection for all 
affected populations without having any disproportionately high and 
adverse human health or environmental effects on any population, 
including any minority, low-income or indigenous populations. Further, 
the EPA believes that implementation of the provisions of this rule 
will provide an ample margin of safety to protect public health of all 
demographic groups.
    To examine the potential for any environmental justice issues that 
might be associated with the refinery source categories associated with 
today's proposed rule, we evaluated the percentages of various social, 
demographic and economic groups within the at-risk populations living 
near the facilities where these source categories are located and 
compared them to national averages. Our analysis of the demographics of 
the population with estimated risks greater than 1-in-1 million 
indicates potential disparities in risks between demographic groups, 
including the African American, Other and Multiracial, Hispanic, Below 
the Poverty Level, and Over 25 without a High School Diploma groups. In 
addition, the population living within 50 km of the 142 petroleum 
refineries has a higher percentage of minority, lower income and lower 
education persons when compared to the nationwide percentages of those 
groups. These groups stand to benefit the most from the emission 
reductions achieved by this proposed rulemaking, and this proposed 
rulemaking is projected to result in 1 million fewer people exposed to 
risks greater than 1-in-1 million.
    The EPA defines ``Environmental Justice'' to include meaningful 
involvement of all people regardless of race, color, national origin or 
income with respect to the development, implementation and enforcement 
of environmental laws, regulations and policies. To promote meaningful 
involvement, the EPA conducted numerous outreach activities and 
discussions, including targeted outreach (such as conference calls and 
Webinars) to communities and environmental justice organizations. In 
addition, after the rule is proposed, the EPA will be conducting a 
webinar to inform the public about the proposed rule and to outline how 
to submit written comments to the docket. Further stakeholder and 
public input is expected through public comment and follow-up meetings 
with interested stakeholders.

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference, Intergovernmental 
relations, Reporting and recordkeeping requirements.

40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Incorporation by reference, Reporting and recordkeeping 
requirements, Volatile organic compounds.

    Dated: May 15, 2014.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is proposed to be 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--[AMENDED]

0
2. Section 60.105 is amended by:
0
a. Revising paragraph (b)(1)(iv) and
0
b. Revising paragraph (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, Test for Hydrogen Sulfide and 
Carbon Dioxide in Natural Gas Using Length of Stain Tubes,'' 1986 
Revision (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. 
The owner or operator must begin monitoring according to the 
requirements in paragraphs (a)(1) or (a)(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

[[Page 36956]]

exceedance of the 3-hour H2S concentration limit.
* * * * *

Subpart Ja--[AMENDED]

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, 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'' to 
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:
0
a. Revising paragraphs (b)(1)(i) and (iii);
0
b. Revising paragraph (f); and
0
c. Revising paragraph (g)(1).
    The revisions 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), each owner or operator 
of an affected sulfur recovery plant shall comply with the applicable 
emission limits in paragraphs (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 paragraphs (f)(1)(i) or 
(f)(1)(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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 
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] TP30JN14.058

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.
    (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 paragraphs (f)(2)(i) or (f)(2)(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 paragraphs 
(f)(2)(i) or (f)(2)(ii) of this

[[Page 36957]]

section 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 paragraphs (f)(2)(i) or (f)(2)(ii) of this 
section 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] TP30JN14.059

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) 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) of this section 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);
0
b. Revising paragraph (b);
0
c. Revising paragraph (f) introductory text;
0
d. Revising paragraph (h) introductory text;
0
e. Adding paragraph (h)(6); and
0
f. 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. Sec.  60.102a(f)(1)(i) and 60.102a(f)(2)(i) and the reduced sulfur 
compounds and H2S emissions limits for sulfur recovery 
plants in Sec. Sec.  60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 
60.102a(f)(2)(ii) and 60.102a(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 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 paragraph (b)(1)(i);
0
b. Revising paragraph (b)(1)(ii)(A);

[[Page 36958]]

0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (h)(1);
0
e. Revising paragraph (h)(3)(i);
0
f. Revising paragraph (i)(1);
0
g. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
h. Adding paragraph (i)(2); and
0
i. 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 Sec.  60.105a(h)(3).
    (i) The owner or operator shall install, operate, and maintain each 
CO2 and O2 monitor according to Performance 
Specification 3 of Appendix B to part 60.
    (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 part 60. The owner or operator shall use Method 3 of 
Appendix A-3 to part 60 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 part 60. 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 part 60. The owner or operator shall use Method 10, 10A, 
or 10B of Appendix A-3 to part 60 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 part 60, 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 part 60. 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 part 60. 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 part 60 and employ the sample conditioning 
system of Method 10A of appendix A-4 to part 60, the alternative 
relative accuracy test procedure in section 10.1 of Performance 
Specification 2 of appendix B to part 60 may be used in place of the 
relative accuracy test.
* * * * *
    (i) * * *
    (1) If a CPMS is used according to Sec.  60.105a(b)(1), all 3-hour 
periods during which the average PM control device operating 
characteristics, as measured by the continuous monitoring systems under 
Sec.  60.105a(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 Sec.  
60.105a(c), each day in which the cause of an alarm is not alleviated 
within the time period specified in Sec.  60.105a(c)(3).
* * * * *
    (7) All 1-hour periods during which the average CO concentration as 
measured by the CO continuous monitoring system under Sec.  60.105a(h) 
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 Sec.  60.105a(h)(4) 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 paragraph (a)(2) introductory text;
0
d. Revising paragraphs (a)(2)(i) and (ii);
0
e. Revising the first sentence of paragraph (a)(2)(iii);
0
f. Removing paragraphs (a)(2)(iv) and (v);
0
g. Redesignating (a)(2)(vi) through (ix) as (a)(2)(iv) through (vii);
0
h. Revising the first sentence of paragraph (a)(3) introductory text;
0
i. Revising paragraph (a)(3)(i);
0
j. Adding paragraphs (a)(4) through (7); and
0
k. 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 part 60.
    (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

[[Page 36959]]

O2 monitor according to the requirements of Sec.  60.13(c) 
and Performance Specification 3 of Appendix B to part 60. The owner or 
operator shall use Methods 3, 3A, or 3B of Appendix A-2 to part 60 for 
conducting the relative accuracy evaluations. The method ANSI/ASME PTC 
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by 
reference--see Sec.  60.17) is an acceptable alternative to EPA Method 
3B of Appendix A-2 to part 60.
    (vii) The owner or operator shall comply with the applicable 
quality assurance procedures of Appendix F to part 60 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 Sec.  
60.102a(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 part 60.
    (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 part 
60. * * *
* * * * *
    (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 Sec.  
60.102a(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 part 60.
    (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 part 60. The 
owner or operator shall use Methods 11 or 15 of appendix A-5 to part 60 
or Method 16 of appendix A-6 to part 60 for conducting the relative 
accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and 
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is 
an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
    (iv) The owner or operator shall install, operate, and maintain 
each O2 monitor according to Performance Specification 3 of 
appendix B to part 60.
    (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 part 60. The 
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of appendix A-2 to part 60.
    (vii) The owner or operator shall comply with the applicable 
quality assurance procedures of appendix F to part 60 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 part 60.
    (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 part 60. The 
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of appendix A-2 to part 60.
    (iv) The owner or operator shall comply with the applicable quality 
assurance procedures of appendix F to part 60 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) The owner or operator shall install locate the monitor in a 
position that

[[Page 36960]]

provides a representative measurement of the total gas flow rate.
    (B) Use a flow sensor with a measurement sensitivity of no more 
than 5 percent of the flow rate 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] TP30JN14.001

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 this section 
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 Sec.  60.102a(f)(2)(i) or the reduced sulfur compounds emission 
limit in Sec.  60.102a(f)(1)(ii) or Sec.  60.102a(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) The owner or operator shall install locate the monitor in a 
position that provides a representative measurement of the total gas 
flow rate.
    (B) Use a flow sensor with a measurement sensitivity of no more 
than 5 percent of the flow rate 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] TP30JN14.002

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] TP30JN14.003


[[Page 36961]]


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 Sec.  60.102a(f)(2)(i)] 
or reduced sulfur compounds [if complying with the reduced sulfur 
compounds emission limit in Sec.  60.102a(f)(1)(ii) or Sec.  
60.102a(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 paragraphs 
(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:
0
a. Revising paragraphs (a)(1)(i) and (ii);
0
b. Revising paragraph (b)(1)(iv);
0
c. Revising the first sentence of paragraph (b)(3)(iii);
0
d. Revising paragraph (d)(3);
0
e. Revising paragraph (e)(1) introductory text;
0
f. Revising paragraph (e)(1)(ii);
0
g. Revising paragraph (e)(2) introductory text;
0
h. Revising paragraph (e)(2)(ii);
0
i. Revising paragraph (e)(2)(vi)(C);
0
j. Revising paragraph (e)(3); and
0
k. Revising paragraph (h)(5).
    The revisions 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 part 60. 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 part 60. The 
owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to 
part 60 for conducting the relative accuracy evaluations. The method 
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples 
taken by Method 6 of appendix A-4 to part 60 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, Test for 
Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of 
Stain Tubes,'' 1986 Revision (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] TP30JN14.004

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

[[Page 36962]]

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 part 
60. The owner or operator of each total reduced sulfur monitor shall 
use EPA Method 15A of Appendix A-5 to part 60 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 part 60. The 
alternative relative accuracy procedures described in section 16.0 of 
Performance Specification 2 of Appendix B to part 60 (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 part 60. The 
owner or operator shall use EPA Method 11, 15 or 15A of Appendix A-5 to 
part 60 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 part 
60. The alternative relative accuracy procedures described in section 
16.0 of Performance Specification 2 of Appendix B to part 60 (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] TP30JN14.060

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.

    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.
* * * * *
    (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 seq.

Subpart A--[Amended]

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (g)(14);
0
b. Adding paragraphs (g)(95) and (96);
0
c. Adding paragraph (i)(2);
0
d. Adding paragraphs (l)(21) through (23); and
0
e. Adding paragraphs (m)(3) and (s).
    The revisions and additions read as follows:


Sec.  63.14  Incorporation by reference.

* * * * *
    (g) * * *
    (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).
* * * * *
    (95) ASTM D6196-03 (Reapproved 2009), Standard Practice for 
Selection of Sorbents, Sampling, and Thermal Desorption Analysis 
Procedures for Volatile Organic Compounds in Air, IBR approved for 
appendix A to part 63: Method 325A, Sections 1.2 and 6.1, and Method 
325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1.
    (96) ASTM UOP539-12, Refinery Gas Analysis by Gas Chromatography, 
IBR approved for Sec.  63.670(j).
* * * * *
    (i) * * *
    (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, IBR approved for 
appendix A to part 63: Method 325A, Section 1.2, and Method 325B, 
Sections 1.3, 7.1.3, and A.1.1.
* * * * *
    (l) * * *
    (21) EPA-454/R-99-005, Office of Air Quality Planning and Standards 
(OAQPS), Meteorological Monitoring

[[Page 36963]]

Guidance for Regulatory Modeling Applications, February 2000, IBR 
approved for appendix A to part 63: Method 325A, Section 8.3.
    (22) 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 2008, IBR approved for Sec.  63.658(d) and appendix A to part 63: 
Method 325A, Sections 8.1.4 and 10.0.
    (23) EPA-454/B-13-003, Office of Air Quality Planning and Standards 
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume II: Ambient Air Quality Monitoring Program, May 2013, 
IBR approved for Sec.  63.658(c) and appendix A to part 63: Method 
325A, Section 4.1.
    (m) * * *
    (3) ISO 16017-2:2003, Indoor, Ambient and Workplace Air--Sampling 
and Analysis of Volatile Organic Compounds by Sorbent Tube/Thermal 
Desorption/Capillary Gas Chromatography--Part 2: Diffusive Sampling, 
First edition, June 11, 2003, IBR approved for appendix A to part 63: 
Method 325A, Sections 1.2, 6.1, and 6.5, and Method 325B, Sections 1.3, 
7.1.2, 7.1.3, and A.1.1.
* * * * *
    (s) U.S. Department of the Interior, 1849 C Street NW., Washington, 
DC 20240, (202) 208-3100, www.doi.gov.
    (1) Bulletin 627, Bureau of Mines, Flammability Characteristics of 
Combustible Gases and Vapors, 1965, IBR approved for Sec.  63.670(l).
    (2) [Reserved]

Subpart Y--[Amended]

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--[Amended]

0
13. Section 63.640 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraph (d)(5);
0
e. Revising paragraph (h);
0
f. Revising paragraph (k)(1);
0
g. Revising paragraph (l) introductory text;
0
h. Revising paragraph (l)(2) introductory text;
0
i. Revising paragraph (l)(2)(i);
0
j. Revising paragraph (l)(3) introductory text;
0
k. Revising paragraph (m) introductory text;
0
l. Revising paragraph (n) introductory text;
0
m. Revising paragraphs (n)(1) through (5);
0
n. Revising paragraph (n)(8) introductory text;
0
o. Revising paragraph (n)(8)(ii);
0
p. Adding paragraphs (n)(8)(vii) and (viii);
0
q. Revising paragraph (n)(9)(i);
0
r. Adding paragraph (n)(10);
0
s. Revising paragraph (o)(2)(i) introductory text;
0
t. Adding paragraph (o)(2)(i)(D);
0
u. Revising paragraph (o)(2)(ii) introductory text;
0
v. Adding paragraph (o)(2)(ii)(C); and
0
w. Revising paragraph (p)(2).
    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 (c)(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 of this subpart, provided that on and after [THE DATE 3 
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 
FEDERAL REGISTER], any flares receiving gas from that fuel gas system 
are in compliance with 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 63.661, 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.
    (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 (h)(3)(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 paragraphs (i) or (j) of this 
section, the requirements in paragraphs (l)(1) through (4) of this

[[Page 36964]]

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 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 paragraphs (l)(2)(i) or 
(l)(2)(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 
(l)(3)(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 subpart CC with other regulations for storage 
vessels. As applicable, paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and 
(n)(7) of this section apply for Group 2 storage vessels and paragraphs 
(n)(2) and (n)(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 CFR part 61, subpart Y is required to 
comply only with the requirements of 40 CFR part 60, 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, subparts 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 (n)(8)(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 (n)(8)(vii) 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 
subpart Kb or to inspect the vessel to determine compliance with Sec.  
60.113b(a) of subpart Kb 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 Sec.  63.120(b)(7)(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 Sec.  63.1063(c)(2)(iv)(B) of subpart WW.
* * * * *
    (vii) To be in compliance with Sec.  60.112b(a)(2)(ii) of this 
chapter, floating roof storage vessels must be equipped with guidepole 
controls as described in Appendix I: Acceptable Controls for Slotted 
Guidepoles Under the Storage Tank Emissions Reduction Partnership 
Program (available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
    (viii) If a flare is used as a control device for a storage vessel, 
on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 
subpart Ka 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 Sec.  63.120(b)(7)(ii) of subpart G (only up to the 
compliance date specified in paragraph (h) of this section for

[[Page 36965]]

compliance with Sec.  63.660, as applicable) or either Sec.  
63.1063(c)(2)(iv)(A) or Sec.  63.1063(c)(2)(iv)(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 (n)(8)(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 (n)(10)(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 Sec.  63.120(b)(7)(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 Sec.  63.1063(c)(2)(iv)(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 Sec.  61.272(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(b)(3) of this chapter, 
floating roof storage vessels must be equipped with guidepole controls 
as described in Appendix I: Acceptable Controls for Slotted Guidepoles 
Under the Storage Tank Emissions Reduction Partnership Program 
(available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
    (viii) If a flare is used as a control device for a storage vessel, 
on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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.
    (p) * * *
    (2) Equipment leaks that are also subject to the provisions of 40 
CFR part 60, subpart GGGa, are required to comply only with the 
provisions specified in 40 CFR part 60, subpart GGGa. Owners and 
operators of equipment leaks that are subject to the provisions of 40 
CFR part 60, subpart GGGa and subject to this subpart may elect to 
monitor equipment leaks following the provisions in Sec.  63.661, 
provided that the equipment is in compliance with all other provisions 
of 40 CFR part 60, subpart GGGa.
* * * * *
0
14. Section 63.641 is amended by:
0
a. Adding, in alphabetical order, new 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,'' 
``Halogenated vent stream or halogenated stream,'' ``Halogens and 
hydrogen halides,'' ``Lower steam,'' ``Net heating value,'' ``Perimeter 
assist air,'' ``Pilot gas,'' ``Premix assist air,'' ``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 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.

[[Page 36966]]

    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 delayed coker vent 
to 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 vent that is typically intermittent in 
nature, and usually occurs only 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, but instead is routed to 
the atmosphere through the delayed coking unit's blowdown system. 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 minimum amount of gas necessary 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 minimum amount 
of gas necessary 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), flare sweep gas, flare purge gas and flare supplemental gas, 
but does not include pilot gas, total steam or assist air.
* * * * *
    Group 1 storage vessel means:
    (1) Prior to [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS 
IN THE FEDERAL REGISTER]:
    (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-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 [THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER]:
    (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

[[Page 36967]]

greater than 2 percent by weight total organic HAP.
* * * * *
    Halogenated vent stream or halogenated stream means a stream 
determined to have a mass rate of halogen atoms of 0.45 kilograms per 
hour or greater, determined by the procedures presented in Sec.  
63.115(d)(2)(v). The following procedures may be used as alternatives 
to the procedures in Sec.  63.115(d)(2)(v)(A):
    (1) Process knowledge that halogen or hydrogen halides are present 
in a vent stream and that the vent stream is halogenated, or
    (2) Concentration of compounds containing halogen and hydrogen 
halides measured by Method 26 or 26A of part 60, Appendix A-8 of this 
chapter, or
    (3) Concentration of compounds containing hydrogen halides measured 
by Method 320 of Appendix A of this part.
    Halogens and hydrogen halides means hydrogen chloride (HCl), 
chlorine (Cl2), hydrogen bromide (HBr), bromine 
(Br2), and hydrogen fluoride (HF).
* * * * *
    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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 
RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from 
the fuel gas system are in compliance with Sec.  63.670;
    (2) Relief valve discharges regulated under Sec.  63.648;
    (3) Leaks from equipment regulated under Sec.  63.648;
    (4) [Reserved];
    (5) In situ sampling systems (onstream analyzers) until [THE DATE 3 
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 
FEDERAL REGISTER]. 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 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 meeting the specifications of 
Sec. 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);
    (iii) An external floating roof converted to an internal floating 
roof meeting the specifications of Sec.  63.1063(a)(1)(i) and (b); 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 (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 (b)(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.
* * * * *
    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 paragraph (d)(3);

[[Page 36968]]

0
c. Revising paragraph (e);
0
d. Revising paragraph (i);
0
e. Revising paragraph (k) introductory text;
0
f. Revising paragraph (k)(1);
0
g. Revising paragraph (l) introductory text;
0
h. Revising paragraph (l)(2); and
0
i. 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 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 or 
63.661, 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 
or 63.661, 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 paragraph (a)(1) to read as 
follows:


Sec.  63.643  Miscellaneous process vent provisions.

    (a) * * *
    (1) Reduce emissions of organic HAP's using a flare. On and after 
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the 
requirements of Sec.  63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 
the flare shall meet the requirements of Sec.  63.11(b) of subpart A or 
the requirements of Sec.  63.670.
* * * * *
0
17. Section 63.644 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(2); and
0
c. Revising paragraph (c).
    The revisions 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), 
(a)(2), (a)(3), or (a)(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 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 [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3 
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE 
FEDERAL REGISTER], 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 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 is an emissions standards violation. 
Equipment such as low leg drains and equipment subject to Sec.  63.648 
are not subject to this paragraph.

[[Page 36969]]

    (1) Install, operate, calibrate, and maintain a continuous 
parameter monitoring system for flow, as specified in paragraphs 
(c)(1)(i) through (iii) of this section.
    (i) Install a continuous parameter monitoring system for flow at 
the entrance to any bypass line. The continuous parameter monitoring 
system must record the volume of the gas stream that bypassed the 
control device and must meet the applicable minimum accuracy, 
calibration and quality control requirements specified in table 13 of 
this subpart.
    (ii) Equip the continuous parameter monitoring system for flow with 
an alarm system that will alert an operator immediately and 
automatically when flow is detected in the bypass line. Locate the 
alarm such that an operator can easily detect and recognize the alert.
    (iii) Reports and records shall be generated as specified in Sec.  
63.655(g) and (i).
    (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:
0
a. Adding introductory text to Sec.  63.646; and
0
b. Revising paragraph (b)(2).
    The revisions and additions 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).
* * * * *
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 [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(3) and (4);
0
c. Revising paragraph (c) introductory text;
0
d. Revising paragraph (c)(2)(ii);
0
e. Adding paragraphs (c)(11) and (12); and
0
f. Adding paragraph (j).
    The revisions and additions read as follows:


Sec.  63.648  Equipment leak standards.

    (a) Each owner or operator of an existing source subject to the 
provisions of this subpart shall comply with the provisions of part 60, 
subpart VV of this chapter and paragraph (b) of this section except as 
provided in paragraphs (a)(1), (a)(2), and (c) through (i) of this 
section. Each owner or operator of a new source subject to the 
provisions of this subpart shall comply with subpart H of this part 
except as provided in paragraphs (c) through (i) of this section. As an 
alternative to the monitoring requirements of part 60, subpart VV of 
this chapter or subpart H of this part, as applicable, the owner or 
operator may elect to monitor equipment leaks following the provisions 
in Sec.  63.661.
* * * * *
    (3) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with 
the requirements of Sec.  60.482-6(a)(2) of this chapter, the term 
``seal'' or ``sealed'' means that instrument monitoring of the open-
ended valve or line conducted according to the method specified in 
Sec.  60.485(b) and, as applicable, Sec.  60.485(c) of this chapter 
indicates no readings of 500 parts per million or greater.
    (4) If a flare is used as a control device, on and after [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 
the applicable requirements of part 60, subpart VV of this chapter, or 
the requirements of Sec.  63.670.
* * * * *

[[Page 36970]]

    (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 of this 
part except as provided in paragraphs (c)(1) through (c)(12) and (e) 
through (i) of this section.
* * * * *
    (2) * * *
    (ii) If an owner or operator elects to monitor connectors according 
to the provisions of Sec.  63.649, paragraphs (b), (c), or (d), then 
the owner or operator shall monitor valves at the frequencies specified 
in table 9 of this subpart. If an owner or operator elects to comply 
with Sec.  63.649, the owner or operator cannot also elect to comply 
with Sec.  63.661.
* * * * *
    (11) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with 
the requirements of Sec.  63.167(a)(2), the term ``seal'' or ``sealed'' 
means that instrument monitoring of the open-ended valve or line 
conducted according to the method specified in Sec.  63.180(b) and, as 
applicable, Sec.  63.180(c) of this chapter indicates no readings of 
500 parts per million or greater.
    (12) If a flare is used as a control device, on and after [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 relief valves 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 paragraph (j)(4) of this section, the owner or operator 
must also comply with the requirements specified in paragraph (j)(3) of 
this section for all relief valves in organic HAP service.
    (1) Operating requirements. Except during a pressure release, 
operate each relief valve 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 relief valves in organic HAP 
gas or vapor service, the owner or operator must comply with either 
paragraph (j)(2)(i) or (ii) of this section following a pressure 
release.
    (i) If the relief valve 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 
relief valve returns to organic HAP gas or vapor service following a 
pressure release to verify that the relief valve is operating with an 
instrument reading of less than 500 ppm.
    (ii) If the relief valve consists of or includes 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 must also 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 relief valve returns to organic 
HAP gas or vapor service following a pressure release to verify that 
the relief valve is operating with an instrument reading of less than 
500 ppm.
    (3) Pressure release management. Except as specified in paragraph 
(j)(4) of this section, emissions of organic HAP may not be discharged 
to the atmosphere from relief valves in organic HAP service, and on or 
before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 
RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator shall 
comply with the requirements specified in paragraphs (j)(3)(i) and (ii) 
of this section for all relief valves in organic HAP service.
    (i) The owner or operator must equip each relief valve in organic 
HAP service with a device(s) or use a monitoring system that is capable 
of: (1) Identifying the pressure release; (2) recording the time and 
duration of each pressure release; and (3) 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) If any relief valve in organic HAP service vents or releases 
to atmosphere as a result of a pressure release event, the owner or 
operator must calculate the quantity of organic HAP released during 
each pressure release event and report this quantity as required in 
Sec.  63.655(g)(10)(iii). Calculations may be based on data from the 
relief valve monitoring alone or in combination with process parameter 
monitoring data and process knowledge.
    (4) Relief valves routed to a control device. If all releases and 
potential leaks from a relief valve in organic HAP service are routed 
through a closed vent system to a control device, the owner or operator 
is not required to comply with paragraphs (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, all references to ``Group 1 
miscellaneous process vent'' in 63.644 mean ``relief valve.''
0
22. 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, Sec. Sec.  63.421, 63.422(a) 
through (c) and (e), 63.425(a) through (c) and (i), 63.425(e) through 
(h), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), 
and (k).
* * * * *
    (d) If a flare is used as a control device, on and after [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 
the applicable requirements of subpart R of this part, or the 
requirements of Sec.  63.670.
0
23. Section 63.651 is amended by revising paragraph (a) 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

[[Page 36971]]

the requirements of Sec. Sec.  63.560 through 63.568.
* * * * *
    (e) If a flare is used as a control device, on and after [THE DATE 
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.  
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet 
the applicable requirements of subpart Y of this part, or the 
requirements of Sec.  63.670.
0
24. Section 63.652 is amended by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (f)(2);
0
c. Revising paragraph (g)(2)(iii)(B)(1);
0
d. Revising paragraph (h)(3);
0
e. Revising paragraph (k) introductory text; and
0
f. Revising paragraph (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 of this subpart, as applicable, or a boiler or 
process heater meeting the criteria in Sec.  63.645(d) of this subpart 
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 (b)(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) Sections 63.1063(a)(1)(i), (a)(2), and (b) or Sec. 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) Sections 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) Sections 63.1063(a)(1)(i), (a)(2), and (b) or Sec. 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
25. Section 63.653 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraphs (a)(3)(i) and (ii); and
0
c. Revising paragraph (a)(7).
    The revisions 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
26. Section 63.655 is amended by:
0
a. Revising paragraph (f) introductory text;
0
b. Revising paragraph (f)(1) introductory text;
0
c. Revising paragraph (f)(1)(i)(A) introductory text;
0
d. Revising paragraphs (f)(1)(i)(A)(2) and (3);
0
e. Revising paragraph (f)(1)(i)(B) introductory text;
0
f. Revising paragraph (f)(1)(i)(B)(2);
0
g. Revising paragraph (f)(1)(i)(D)(2);
0
h. Revising paragraph (f)(1)(iv) introductory text;
0
i. Revising paragraph (f)(1)(iv)(A);
0
j. Adding paragraph (f)(1)(vii);
0
k. Revising paragraph (f)(2) introductory text;
0
l. Revising paragraph (f)(3) introductory text;
0
m. Revising paragraph (f)(6);
0
n. Revising paragraph (g) introductory text;

[[Page 36972]]

0
o. Revising paragraphs (g)(1) through (5);
0
p. Revising paragraph (g)(6)(iii);
0
q. Revising paragraph (g)(7)(i);
0
r. Adding paragraphs (g)(10) through (13);
0
s. Removing and reserving paragraph (h)(1);
0
t. Revising paragraph (h)(2) introductory text;
0
u. Revising paragraph (h)(2)(i)(B);
0
v. Revising paragraph (h)(2)(ii);
0
w. Adding paragraphs (h)(8) and (9);
0
x. Adding paragraph (i) introductory text;
0
y. Revising paragraph (i)(1) introductory text;
0
z. Revising paragraph (i)(1)(ii);
0
aa. Adding paragraphs (i)(1)(v) and (vi);
0
bb. Redesignating paragraph (i)(4) and (5) as (i)(5) and (6) 
respectively;
0
cc. Adding paragraph (i)(4);
0
dd. Revising newly redesignated paragraph (i)(5) introductory text; and
0
ee. Adding paragraphs (i)(7) through (11).
    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 (f)(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) of this subpart.
    (1) The Notification of Compliance Status report shall include the 
information specified in paragraphs (f)(1)(i) through (f)(1)(vii) 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 
(f)(1)(i)(A)(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.  63.645 of this subpart 
and Sec.  63.116(a) of subpart G of this part or Sec.  63.670(h) of 
this subpart, as applicable, and
* * * * *
    (vii) For relief valves in organic HAP service, a description of 
the monitoring system to be implemented, including the relief valves 
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.
    (2) If initial performance tests are required by Sec. Sec.  63.643 
through 63.653 of this subpart, the Notification of Compliance Status 
report shall include one complete test report for each test method used 
for a particular source. On and after [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 
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 (f)(3)(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. Six-month periods shall be the same 
6-month periods specified in paragraph (g) of this section. The 
Notification of Compliance Status report shall include the information 
specified in paragraphs (f)(1) through (f)(5) 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, 
as part of the periodic report, or in any combination of these four. If 
the required information has been submitted before the date 60 days 
after the end of the 6-month period in which the addition of the Group 
1 emission

[[Page 36973]]

point took place, a separate Notification of Compliance Status report 
is not required within 60 days after the end of the 6-month period. If 
an owner or operator submits the information specified in paragraphs 
(f)(1) through (f)(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.
    (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 (12) 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 paragraph (g)(1) through (7) of this section or 
paragraphs (g)(9) through (12) 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 if the reports contain 
the information required by paragraphs (g)(1) through (12) of this 
section.
    (1) For storage vessels, Periodic Reports shall include the 
information specified for Periodic Reports in paragraph (g)(2) through 
(g)(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)(C) 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 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 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 (g)(2)(ii)(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) and (B) 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), (b)(4), (b)(5), or (b)(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 (b)(4) of subpart G.
    (3) A description of any seal condition specified in Sec.  
63.120(b)(5) or (b)(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

[[Page 36974]]

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).
    (B) An owner or operator who elects to use an extension in 
accordance with Sec.  63.1063(e)(2) or Sec.  63.1063(c)(2)(iv)(B) of 
subpart WW shall, in the next Periodic Report, submit the documentation 
required by those paragraphs.
    (4) An owner or operator who elects to comply with Sec.  63.646 or 
Sec.  63.660 by using an external floating roof converted to an 
internal floating roof shall comply with the periodic reporting 
requirements of paragraph (g)(2)(i) of this section.
    (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 (g)(5)(iii) 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 (e)(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 [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] 
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 of this part and shall include: Identification of 
the flare that does not meet the general requirements specified in 
Sec.  63.11(b) of subpart A of this part, and reasons the flare did not 
meet the general requirements specified in Sec.  63.11(b) of subpart A 
of this part.
    (iv) If a flare is used on and after compliance with the 
requirements in Sec.  63.670 is elected, which can be no later than 
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], 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) * * *
    (iii) For closed vent systems, include the records of periods when 
vent stream flow was detected in the bypass line or diverted from the 
control device, a flow indicator was not operating or a bypass of the 
system was indicated, as specified in paragraph (i)(4) of this section.
    (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 relief valves, Periodic Reports must include the 
information specified in paragraphs (g)(10)(i) through (iii) of this 
section.
    (i) For relief valves in organic HAP gas or vapor service, pursuant 
to Sec.  63.648(j), report any instrument reading of 500 ppm or 
greater, more than 5 days after the relief valve returns to service 
after a pressure release.
    (ii) For relief valves in organic HAP gas or vapor service subject 
to Sec.  63.648(j)(2), report confirmation that all monitoring to show 
compliance was conducted within the reporting period.
    (iii) For relief valves in organic HAP service, report each 
pressure release to the atmosphere, including duration of the pressure 
release and estimate of quantity of substances released.
    (11) For flares subject to Sec.  63.670, Periodic Reports must 
include the information specified in paragraphs (g)(11)(i) through 
(iii) of this section.
    (i) Records as specified in paragraph (i)(9)(i) of this section for 
each period when regulated material is routed to a flare and a pilot 
flame is not present.
    (ii) Visible emission records as specified in paragraph (i)(9)(ii) 
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 15-minute block average 
operating parameters determined following the methods in Sec.  
63.670(k) through (o) as applicable, and an indication of whether the 
three criteria in Sec.  63.670(e)(vi) were all met for that 15-minute 
block period.
    (iv) Records as specified in paragraph (i)(9)(x) of this section 
for each period when a halogenated vent stream as defined in Sec.  
63.641 is discharged to the flare.
    (12) If a source fails to meet an applicable standard, report such 
events in the Periodic Report. Report the number of failures to meet an 
applicable standard. For each instance, report the date, time and 
duration of each failure. For each failure the report must include a 
list of the affected sources or equipment, an estimate of the quantity 
of each regulated pollutant emitted over any emission limit, and a 
description of the method used to estimate the emissions.
    (13) Any changes in the information provided in a previous 
Notification of Compliance Status report.

[[Page 36975]]

    (h) * * *
    (2) For storage vessels, notifications of inspections as specified 
in paragraphs (h)(2)(i) and (h)(2)(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), Sec.  
63.120(a)(3), or Sec.  63.120(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 (b)(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.
* * * * *
    (8) For fenceline monitoring systems subject to Sec.  63.658, 
within 45 calendar days after the end of each semiannual reporting 
period, each owner or operator shall submit the following information 
to the EPA's Compliance and Emissions Data Reporting Interface (CEDRI) 
that is accessed through the EPA's Central Data Exchange (CDX) 
(www.epa.gov/cdx). 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 
episode during the semiannual 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 12-month rolling average concentration difference 
([Delta]c) values for benzene for the semiannual 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 [THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results 
of a performance test or CEMS performance evaluation, the owner or 
operator shall submit the results using EPA's Electronic Reporting Tool 
(ERT) 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 according to the method specified 
by either paragraph (h)(9)(i)(A) or (h)(9)(i)(B) of this section.
    (A) For data collected using test methods supported by the EPA's 
ERT as listed on the EPA's ERT Web site (http://www.epa.gov/ttn/chief/ert/index.html), the owner or operator must submit the results of the 
performance test to the CEDRI accessed through the EPA's CDX (http://cdx.epa.gov/epa_home.asp), unless the Administrator approves another 
approach. Performance test data must be submitted in a file format 
generated through the use of the EPA's ERT. 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, 
including information claimed to be CBI, on a compact disc or other 
commonly used electronic storage media (including, but not limited to, 
flash drives) by registered letter to the EPA. The electronic media 
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI 
Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page 
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be 
submitted to the EPA via CDX as described earlier in this paragraph.
    (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, 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 
according to the method specified by either paragraph (h)(9)(ii)(A) or 
(h)(9)(ii)(B) of this section.
    (A) For data collection of relative accuracy test audit (RATA) 
pollutants that are supported by the EPA's ERT as listed on the ERT Web 
site, the owner or operator must submit the results of the performance 
evaluation to the CEDRI that is accessed through the EPA's CDX, unless 
the Administrator approves another approach. Performance evaluation 
data must be submitted in a file format generated through the use of 
the EPA's ERT. 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, including information claimed to be CBI, on a compact disc 
or other commonly used electronic storage media (including, but not 
limited to, flash drives) by registered letter to the EPA. The 
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 
omitted must be submitted to the EPA via CDX as described earlier in 
this paragraph.
    (B) For any performance evaluation data with RATA pollutants that 
are not supported by the EPA's ERT as listed on the EPA's ERT Web site, 
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 (11) 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 of this part except as specified in paragraphs (i)(1)(i)

[[Page 36976]]

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 of 
this part 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.
    (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 to the 
atmosphere, or cause air intrusion into the control device, 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 any alarms 
triggered because flow was detected in the bypass line, including the 
date and time the alarm was triggered and the duration of the flow in 
the bypass line. The owner or operator shall also maintain records of 
all periods when the vent stream is diverted from the control device or 
air intrudes into the control device. 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.
    (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 emissions 
of organic HAP that bypassed the control device.
    (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 of 
the average pressure 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.
    (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 (ix) of this section on an ongoing basis.
    (i) Coordinates of all passive monitors, including replicate 
samplers and field blanks, and 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) Daily unit vector wind direction, calculated daily sigma 
theta, daily average temperature and daily average 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 episode and the two samples used to determine it, 
whether background correction was used, and the 12-month rolling 
average [Delta]c calculated after each sampling episode.
    (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.
    (9) For each flare subject to Sec.  63.670, each owner or operator 
shall keep the records specified in paragraphs (i)(9)(i) through (vii) 
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 periods during which the pilot 
flame is not present when regulated material is routed to a flare for a 
minimum of 5 years.
    (ii) Daily visible emissions observations, as required in Sec.  
63.670(c), as well as any observations required in Sec.  63.670(h). 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.
    (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 or total hydrocarbon 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 (m), as 
applicable.
    (vi) The 15-minute block average olefins, hydrogen, and olefins 
plus

[[Page 36977]]

hydrogen concentration in the combustion zone used to determine if the 
criteria in Sec.  63.670(e)(4) are met. If process knowledge and 
engineering calculations are used, retain records of the information 
used in the assessment and records of all compositional analyses 
required in Sec.  63.670(o)(ii). Identify all 15-minute block averages 
for which all three criteria in Sec.  63.670(e)(4) are met or are 
assumed to be met.
    (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) All periods during which a halogenated vent stream, as defined 
in Sec.  63.641, is discharged to the flare. Records shall include the 
start time and date of the event, the end time and date of the event, 
and an estimate of the cumulative flow of the halogenated vent stream 
over the duration of the event.
    (10) If the owner or operator elects to comply with Sec.  63.661, 
the owner or operator shall keep the records described in paragraphs 
(i)(10)(i) through (v) of this section.
    (i) The equipment and process units for which the owner or operator 
chooses to use the optical gas imaging instrument.
    (ii) All records required by part 60, Appendix K of this chapter, 
as applicable.
    (iii) A video record to document the leak survey results. The video 
record must include a time and date stamp for each monitoring event.
    (iv) Identification of the equipment screened and the time and date 
of the screening.
    (v) Documentation of repairs attempted and repairs delayed. If 
repair of a leak is confirmed using the optical gas imaging instrument, 
then instead of the maximum instrument reading measured by Method 21 of 
part 60, Appendix A-7 of this chapter, the owner or operator shall keep 
a video record following repair to confirm the equipment is repaired.
    (11) Other records must be kept as specified in paragraphs 
(i)(11)(i) through (iii) of this section.
    (i) 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.
    (ii) 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.
    (iii) Record actions taken to minimize emissions in accordance with 
Sec.  63.642(n), and any corrective actions taken to return the 
affected unit to its normal or usual manner of operation.
0
27. Section 63.656 is amended by:
0
a. Revising paragraph (c) introductory text;
0
b. Revising paragraph (c)(1); and
0
c. Adding paragraph (c)(5).
    The revisions and additions read as follows:


Sec.  63.656  Implementation and enforcement.

* * * * *
    (c) The authorities that cannot be delegated to state, local, or 
Tribal agencies are as specified in paragraphs (c)(1) through (5) of 
this section.
    (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 63.661, 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.
* * * * *
    (5) Approval of the corrective action plan under Sec.  63.658(h).
0
28. Section 63.657 is added to read as follows:


Sec.  63.657  Delayed coking unit decoking operation standards.

    (a) 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 is 2 pounds per square inch gauge (psig) or less 
prior to venting to the atmosphere, draining or deheading the coke drum 
at the end of the cooling cycle.
    (b) Each owner or operator of a delayed coking unit shall install, 
operate, calibrate, and maintain a continuous parameter monitoring 
system to determine the coke drum vessel pressure. The pressure 
monitoring system must be capable of measuring a pressure of 2 psig 
within 0.5 psig.
    (c) The owner or operator of a delayed coking unit shall determine 
the coke drum vessel pressure on a 5-minute rolling average basis while 
the coke drum is vented to the closed blowdown system to demonstrate 
compliance the requirement in paragraph (a) of this section. Pressure 
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 for the purpose of compliance with the 
requirement in paragraph (a) of this section.
0
29. 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.
    (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. General guidance for siting passive monitors can be found in EPA-
454/R-98-004, Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume II: Part 1: Ambient Air Quality Monitoring Program 
Quality System Development, August 1998 (incorporated by reference--see 
Sec.  63.14). Alternatively, the owner or operator may elect to place 
monitors at 2 kilometers intervals as measured along the property 
boundary, provided additional monitors are located, if necessary, as 
required in Section 8.2.2.5 in Method 325A of Appendix A of this part.
    (1) As it pertains to this subpart, known emission source, as used 
in Section 8.2.2.5 in Method 325A of Appendix A of this part for siting 
passive monitors means a wastewater treatment unit or a Group 1 storage 
vessel.
    (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 plant, the background sampler(s) should be

[[Page 36978]]

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 episode and at 
least two field blanks per sampling episode, 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 use a dedicated meteorological 
station in accordance with Section 8.3 of Method 325A of Appendix A of 
this part.
    (1) The owner or operator shall collect and record hourly average 
meteorological data, including wind speed, wind direction and 
temperature.
    (2) The owner or operator shall follow the calibration and 
standardization procedures for meteorological measurements in EPA-454/
B-08-002, Quality Assurance Handbook for Air Pollution Measurement 
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), 
March 2008 (incorporated by reference--see Sec.  63.14).
    (e) The length of the sampling episode must be fourteen days, 
unless a shorter sampling episode is determined to be necessary under 
paragraph (g) or (i) of this section. A sampling episode is defined as 
the period during which the owner or operator collects the sample and 
does not include the time required to analyze the sample.
    (f) Within 30 days of completion of each sampling episode, the 
owner or operator shall determine whether the results are above or 
below the action level as follows:
    (1) For each sampling episode, the owner or operator shall 
determine the highest and lowest sample results for benzene from the 
sample pool and calculate the difference in concentration ([Delta]c).
    (i) The owner or operator shall adhere to the following procedures 
when one or more samples for the sampling episode 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) If the owner or operator identifies an offsite upwind source 
or an onsite source excluded under Sec.  63.640(g) that contributes to 
the benzene concentration at any passive monitor and collects 
background samples according to an approved site-specific monitoring 
plan, 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 average the [Delta]c values 
collected over the twelve months prior to and including the most recent 
sampling episode. The owner or operator shall update this value after 
receiving the results of each sampling episode.
    (3) The action level for benzene is 9 micrograms per cubic meter 
([mu]g/m\3\). If the 12-month rolling average [Delta]c value for 
benzene is less than 9 [mu]g/m\3\, the concentration is below the 
action level. If the 12-month rolling average [Delta]c value for 
benzene is equal to or 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 12-month rolling average and no longer than 35 days 
after completion of the sampling episode, the owner or operator shall 
initiate a root cause analysis to determine the cause of such 
exceedance and to determine appropriate corrective action, as described 
in paragraphs (g)(1) through (4) of this section. The root cause 
analysis and corrective action analysis shall be completed 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 as specified in Sec.  
63.661 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 episodes for Methods 325A and 
325B of Appendix A of this part, or using active sampling techniques), 
or employing additional monitors to determine contributing offsite 
sources.
    (h) If, upon completion of the corrective actions described in 
paragraph (g) of this section, the action level is exceeded for the 
next sampling episode following the completion of the corrective 
action, 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 Administrator within 60 days after 
determining the action level was exceeded during the sampling episode 
following the completion of the initial corrective action. 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.
    (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.
    (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 for each monitoring location, the near field source 
or sources that are expected to contribute to fenceline 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

[[Page 36979]]

concentration contribution for each monitoring location.
    (v) If more frequent monitoring is proposed or if a monitoring 
station other than a passive diffusive tub monitoring station is 
proposed, provide a detailed description of the measurement methods, 
measurement frequency, and recording frequency proposed 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 
(2)(i) through (iii) of this section.
    (i) For each monitoring location, calculate [Delta]ci 
using the following equation.

[Delta]ci = MCFi - 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 specified included in the site-specific 
monitoring plan, [mu]g/m\3\. If no additional measurement location 
is 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 episode 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 detection, 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 
detection, 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 
refineryrtr@epa.gov.
    (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 process for a site-specific monitoring plan. Factors that 
the EPA 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 or if a monitoring 
station other than a passive diffusive tub monitoring station is 
proposed, the adequacy of the description of the measurement methods, 
measurement frequency, and recording frequency proposed and the 
adequacy of the rationale for using the alternative monitoring 
frequency or method.
    (j) The owner or operator shall comply with the applicable 
recordkeeping and reporting requirements in Sec.  63.655(h) and (i).
0
30. 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 subpart 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, subpart WW, or subpart 
SS of this part. The definitions of ``Group 1 storage vessel'' (item 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,

[[Page 36980]]

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) In addition to the options presented in Sec. Sec.  
63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), and 63.1064, an external 
floating roof storage vessel may comply with Sec.  63.1063(a)(2)(vii) 
using a flexible enclosure system as described in item 6 of Appendix I: 
Acceptable Controls for Slotted Guidepoles Under the Storage Tank 
Emissions Reduction Partnership Program (available at http://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
    (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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS 
IN THE FEDERAL REGISTER].
    (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 [THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER].
    (4) All references to ``the proposal date of the relevant standard 
established pursuant to CAA section 112(f)'' in 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 existing storage vessel fixed roof that meets the 
definition of Group 1 storage vessel (item 2) in Sec.  63.641 but not 
the definition of Group 1 storage vessel (item 1) in Sec.  63.641, the 
requirements of Sec.  63.1062 do not apply until the next time the 
storage vessel is completely emptied and degassed, or [THE DATE 10 
YEARS AFTER PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 
REGISTER], 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 (c)(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.  
63.985(a)(3)(i) or (ii) for each closed vent system that contains 
bypass lines that could divert a vent stream to the atmosphere. Use of 
the bypass at any time to divert a Group 1 storage vessel to the 
atmosphere is an emissions standards violation. Equipment such as low 
leg drains and equipment subject to Sec.  63.648 are not subject to 
this paragraph.
    (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 paragraph 
Sec.  63.984(a)(1) does not apply.
0
31. Section 63.661 is added to read as follows:


Sec.  63.661  Alternative means of emission limitation: Monitoring 
equipment leaks using optical gas imaging.

    (a) Applicability. The owner or operator may only use an optical 
gas imaging instrument to screen for leaking equipment, as required by 
Sec.  63.648, if the requirements in paragraphs (a)(1) through (3) of 
this section are met.
    (1) The owner or operator may only use the optical gas imaging 
instrument as an alternative to provisions in Sec.  63.648 that would 
otherwise require monitoring according to Sec.  60.485(b) or Sec.  
63.180(b)(1) through (5), as applicable. The owner or operator shall 
continue to comply with all other requirements in Sec.  63.648 (e.g., 
weekly inspections of pumps; for relief valves, installation of a 
device that is capable of identifying and recording the time and 
duration of each pressure release, if applicable; sampling connection 
system requirements).
    (2) The owner or operator must be in compliance with the fenceline 
monitoring provisions of Sec.  63.658.
    (3) The optical gas imaging instrument must be able to meet all of 
the criteria and requirements specified in part 60, Appendix K of this 
chapter, and the owner or operator shall conduct monitoring according 
to part 60, Appendix K of this chapter.
    (b) Compliance requirements. The owner or operator shall meet the 
requirements of paragraphs (b)(1) through (3) of this section.
    (1) The owner or operator shall identify the equipment and process 
units for which the optical gas imaging instrument will be used to 
identify leaks.
    (2) The owner or operator shall repair leaking equipment as 
required in the applicable section of part 60, subpart VV of this 
chapter or subpart H of this part.
    (3) Monitoring to confirm repair of leaking equipment must be 
conducted using the procedures referenced in paragraph (a)(2) of this 
section.
    (c) Recordkeeping. The owner or operator shall comply with the 
applicable requirements in Sec.  63.655(i).
0
32. Section 63.670 is added to read as follows:


Sec.  63.670  Requirements for flare control devices.

    On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Halogenated vent streams. The owner or operator shall not use a 
flare

[[Page 36981]]

to control halogenated vent streams as defined in Sec.  63.641.
    (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. The pilot system must be equipped with an 
automated device to relight the pilot if extinguished. The owner or 
operator shall monitor for the presence of a pilot flame as specified 
in paragraph (g) of this section.
    (c) Visible emissions. Each flare must be designed for and operated 
with no visible emissions, except for periods not to exceed a total of 
5 minutes during any 2 consecutive hours. The owner or operator shall 
monitor for visible emissions from the flare as specified in paragraph 
(b) of this section.
    (d) Flare tip velocity. For each flare, the owner or operator shall 
comply with either paragraph (d)(1) or (d)(2) of this section, provided 
the appropriate monitoring systems are in-place. If a total hydrocarbon 
analyzer is used for compositional analysis as allowed under section 
(j)(4) of this section, then the owner or operator must comply with 
paragraph (d)(1) of this section.
    (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 when regulated material is being routed to the flare. The 
owner or operator shall monitor Vtip using the procedures 
specified in paragraph (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 at all times regulated 
material is being routed to the flare. The owner or operator shall 
monitor Vtip using the procedures specified in paragraph (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] TP30JN14.005

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) Target combustion zone gas properties. For each flare, the 
owner or operator shall comply with the applicable requirements in 
either paragraph (e)(1), (2), or (3) of this section. The owner or 
operator may elect to comply with any of these applicable requirements 
at any time (e.g., may elect to comply with the requirements in 
paragraph (e)(1) during certain flow conditions and comply with the 
requirements in paragraph (e)(2) or (e)(3) under different flow 
conditions) provided that the owner or operator has the appropriate 
monitoring equipment to determine compliance with the specified 
requirement.
    (1) The net heating value of flare combustion zone gas 
(NHVcz) must be greater than or equal to the target values 
in paragraphs (e)(1)(i) or (ii), as applicable, when regulated material 
is being routed to the flare. The owner or operator shall monitor and 
calculate NHVcz as specified in paragraph (m) of this 
section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target NHVcz value is 380 British 
thermal units per standard cubic feet (Btu/scf).
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target NHVcz value 
is 270 Btu/scf.
    (2) The lower flammability limit of the combustion zone gas 
(LFLcz) must be less than or equal to the target values in 
paragraphs (e)(2)(i) or (ii), as applicable, when regulated material is 
being routed to the flare. The owner or operator shall monitor and 
calculate LFLcz as specified in paragraph (m) of this 
section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target LFLcz value is 0.11 volume 
fraction.
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target LFLcz value 
is 0.15 volume fraction.
    (3) The total volumetric fraction of hydrogen and combustible 
organic components present in the combustion zone gas (Ccz), 
as propane, must be greater than or equal to the target values in 
paragraphs (e)(3)(i) or (ii), as applicable, when regulated material is 
being routed to the flare. The owner or operator shall monitor and 
calculate Ccz as specified in paragraph (m) of this section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target Ccz value is 0.23 volume 
fraction as propane.
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target Ccz value is 
0.18 volume fraction as propane.
    (4) More stringent combustion zone gas target properties apply only 
during those flare flow periods when all three conditions in paragraphs 
(e)(4)(i) through (iii) simultaneously exist. The owner or operator 
shall monitor and calculate hydrogen and cumulative olefin combustion 
zone concentrations as specified in paragraph (o) of this section:
    (i) The concentration of hydrogen in the combustion zone is greater 
than 1.2 percent by volume.
    (ii) The cumulative concentration of olefins in the combustion zone 
is greater than 2.5 percent by volume.
    (iii) The cumulative concentration of olefins in the combustion 
zone plus the concentration of hydrogen in the combustion zone is 
greater than 7.4 percent by volume.
    (f) Target dilution parameters for flares with perimeter assist 
air. For each flare actively receiving perimeter assist air, the owner 
or operator shall comply with the applicable requirements in either 
paragraph (f)(1), (2), or (3) of this section in addition to complying 
with the target combustion zone gas properties as specified in 
paragraph (e) of this section. The owner or operator may elect to 
comply with any of these applicable requirements at any time (e.g., may 
elect to comply with the requirements in paragraph (f)(1) during 
certain flow conditions and comply with the requirements in paragraph 
(f)(2) or (f)(3) under different flow conditions) provided that the 
owner or operator has the appropriate monitoring equipment to determine 
compliance with the specified requirement.
    (1) The net heating value dilution parameter (NHVdil) 
must be greater than or equal to the target values in paragraphs 
(f)(1)(i) or (ii), as applicable, when regulated material is being 
routed to the flare. The owner or operator shall monitor and calculate 
NHVdil as specified in paragraph (n) of this section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target NHVdil value is 31

[[Page 36982]]

British thermal units per square foot (Btu/ft\2\).
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target NHVdil value 
is 22 Btu/ft\2\.
    (2) The lower flammability limit dilution parameter 
(LFLdil) must be less than or equal to the target values in 
paragraphs (f)(2)(i) or (ii), as applicable, when regulated material is 
being routed to the flare. The owner or operator shall monitor and 
calculate LFLdil as specified in paragraph (n) of this 
section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target LFLdil value is 1.6 volume 
fraction per foot (volume fraction/ft).
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target LFLdil value 
is 2.2 volume fraction/ft.
    (3) The combustibles concentration dilution parameter 
(Cdil) must be greater than or equal to the target values in 
paragraphs (f)(3)(i) or (ii), as applicable, when regulated material is 
being routed to the flare. The owner or operator shall monitor and 
calculate Cdil as specified in paragraph (n) of this 
section.
    (i) For flares meeting all three requirements in paragraph (e)(4) 
of this section, the target Cdil value is 0.015 volume 
fraction-ft.
    (ii) For all flares other than those meeting all three requirements 
in paragraph (e)(4) of this section, the target Ccz value is 
0.012 volume fraction-ft.
    (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 at a minimum of once per day 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.
    (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. 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.
    (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 [deg]F] and a 
pressure of 1 atm). The flare vent gas flow rate monitoring system(s) 
must also be able to output flow in actual conditions for use in the 
flare tip velocity calculation.
    (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] TP30JN14.006

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 paragraphs (j)(1) or 
(j)(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 or the 
combustibles concentration following the methods provided in paragraphs 
(j)(4) of this section.. The owner or operator electing to directly 
monitor the net heating value of the flare vent gas must comply with 
the net heating value operating limits in paragraph (e) and, if 
applicable, paragraph (f) of this section. The owner or operator 
electing to directly monitor the combustibles concentration in the 
flare vent gas must comply with the combustibles concentration 
operating limits in paragraph (e) and, if applicable, paragraph (f) of 
this section, and must comply with the maximum velocity requirements in 
paragraph (d)(1) of this section.
    (1) Except as provided in paragraph (j)(5) 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 paragraph (j)(5) 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

[[Page 36983]]

60, Appendix A-6, ASTM D1945-03 (Reapproved 2010) (incorporated by 
reference--see Sec.  63.14), or ASTM UOP539-12 (incorporated by 
reference--see Sec.  63.14).
    (3) The owner or operator shall install, operate, calibrate, and 
maintain a monitoring system capable of continuously measuring, 
calculating, and recording NHVvg. at standard conditions.
    (4) The owner or operator shall install, operate, calibrate, and 
maintain a monitoring system capable of continuously measuring, 
calculating, and recording total hydrocarbon content (as propane) as a 
surrogate for combustibles concentration.
    (5) Direct compositional monitoring is not required for pipeline 
quality natural gas streams. In lieu of monitoring the composition of a 
pipeline quality natural gas stream, the following composition can be 
used for any pipeline quality natural gas stream.
    (i) 93.2 volume percent (vol %) methane.
    (ii) 3.2 vol % ethane.
    (iii) 0.6 vol % propane.
    (iv) 0.3 vol % butane.
    (v) 2.0 vol % hydrogen.
    (vi) 0.7 vol % nitrogen.
    (k) Calculation methods for 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 vent gas does not exit through them.
    (2) The owner or operator shall determine the cumulative volumetric 
flow of 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.
    (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 of 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 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] TP30JN14.007

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 
paragraph (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 parameters. 
The owner or operator shall determine the net heating value, lower 
flammability limit, and/or combustibles concentration vent gas of the 
flare (NHVvg, LFLvg, and/or Cvg, 
respectively) based on the composition monitoring data on a 15-minute 
block average basis according to the following requirements.
    (1) 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.
    (2) When a continuous monitoring system is used to determine flare 
vent gas composition, net heating value, or total hydrocarbon content:
    (i) Use the results from the first sample collected during an 
event, (for periodic flare vent gas flow events) for the first and 
second 15-minute block associated with that event.
    (ii) For all other 15-minute block periods, 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 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.
    (3) 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 the 
purpose of this requirement, use the time the sample was collected 
rather than the time the analytical results become available.
    (4) The owner or operator shall determine NHVvg from 
compositional analysis data by using the following equation. If the 
owner or operator uses a monitoring system(s) capable of continuously 
measuring, calculating, and recording NHVvg, as provided in 
paragraph (j)(3) of this section, the owner or operator shall use the 
NHVvg as determined by the continuous NHVvg 
monitor.
[GRAPHIC] [TIFF OMITTED] TP30JN14.008


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.


[[Page 36984]]


    (5) The owner or operator shall calculate LFLvg using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.009


Where:

LFLvg = Lower flammability limit of flare vent gas, 
volume fraction.
n = Number of components in the vent gas.
i = Individual component in the vent gas.
[chi]i = Concentration of component i in the vent gas, 
volume percent (vol %).
LFLi = Lower flammability limit of component i according 
to table 12 of this subpart, vol %. If the component is not 
specified in table 12 of this subpart, the owner or operator shall 
use the LFL value as published in Appendix A of Flammability 
Characteristics of Combustible Gases and Vapors, U.S. Bureau of 
Mines, Bulletin 627, 1965 (incorporated by reference--see Sec.  
63.14). All inerts, including nitrogen, shall be assumed to have an 
infinite lower flammability limit (e.g., LFLN2 = [infin], 
so that [chi]N2/LFLN2 = 0).

    (6) The owner or operator shall calculate Cvg using the 
following equation. If the owner or operator uses a total hydrocarbon 
analyzer, the owner or operator may substitute the 
``[sum][chi]i'' term in the following equation with the 
total volumetric hydrocarbon concentration present in the flare vent 
gas (vol % as propane), and the owner or operator may choose to ignore 
the concentration of hydrogen in the flare vent gas.
[GRAPHIC] [TIFF OMITTED] TP30JN14.010

Where:

Cvg = Total volumetric fraction of hydrogen and 
combustible organic components present in the flare vent gas, volume 
fraction. For the purposes of Cvg, carbon dioxide is not 
considered to be a combustible organic component, but carbon 
monoxide may be included in Cvg.
n = Number of individual combustible organic components in flare 
vent gas.
i = Individual combustible organic component in flare vent gas.
[chi]i = Concentration of combustible organic component i 
in flare vent gas, vol %.
CMNi = Carbon mole number of combustible organic 
component i in flare vent gas, mole carbon atoms per mole of 
compound. E.g., CMN for ethane (C2H6) is 2; 
CMN for propane (C3H8) is 3.
[chi]h = Concentration of hydrogen in flare vent gas, vol 
%.
100% = Constant, used to convert volume percent to volume fraction.

    (m) Calculation methods for determining combustion zone parameters. 
The owner or operator shall determine the net heating value, lower 
flammability limit and combustibles concentration of the combustion 
zone gas (NHVcz, LFLcz, and Ccz, 
respectively) based on the vent gas and assist gas flow rates on a 15-
minute block average basis according to the following requirements. For 
periods when there is no assist steam flow or premix assist air flow, 
the combustion zone parameters are equal to the vent gas parameters.
    (1) The owner or operator shall calculate NHVcz using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.011

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) The owner or operator shall calculate LFLcz using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.012

Where:

LFLcz = Lower flammability limit of combustion zone gas, 
volume fraction.
LFLvg = Lower flammability limit of flare vent gas 
determined for the 15-minute block period, volume fraction.
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.

    (3) The owner or operator shall calculate Ccz using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.013

Where:

Ccz = Combustibles concentration in the combustion zone 
gas, volume fraction.
Cvg = Combustibles concentration of flare vent gas 
determined for the 15-minute block period, volume fraction.
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.

    (n) Calculation methods for determining dilution parameters. The 
owner or operator shall determine the net heating value, lower 
flammability limit and combustibles concentration dilution parameters 
(NHVdil, LFLdil, and Cdil, 
respectively) based on the vent gas and perimeter assist air flow rates 
on a 15-minute block average basis according to the following 
requirements 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 dilution parameters do not need to be 
calculated.

[[Page 36985]]

[GRAPHIC] [TIFF OMITTED] TP30JN14.014


[[Page 36986]]


[GRAPHIC] [TIFF OMITTED] TP30JN14.015

    (o) Special provisions for assessing olefins and hydrogen 
combustion zone concentrations. The owner or operator shall determine 
the olefins and hydrogen content of the flare vent gas and calculate 
the combustion zone

[[Page 36987]]

concentrations for the purposes of assessing the criteria in paragraph 
(e)(4) of this section on a 15-minute block average according to the 
following requirements.
    (1) The olefins concentration shall be determined as the cumulative 
sum of the following flare gas constituents: ethylene, acetylene, 
propylene, propadiene, all isomers of n- or iso-butene, and all isomers 
of butadiene.
    (2) If individual component concentrations are determined following 
the methods specified in paragraphs (j)(1) or (j)(2) of this section, 
the measured vent gas concentrations shall be used to determine the 
hydrogen, olefins, and hydrogen plus olefins concentration in the 
combustion zone using the following general equation. The methods 
specified in paragraphs (l)(1) through (3) of this section, as 
applicable, shall be used to assign the vent gas concentration results 
to a specific 15-minute block period.
[GRAPHIC] [TIFF OMITTED] TP30JN14.017

Where:

Acz = Concentration of target compound(s) ``A'' 
(representing either the olefins concentration, the hydrogen 
concentration, or the sum of the olefins and hydrogen concentration) 
in the combustion zone gas, volume fraction.
Avg = Concentration of target compound(s) ``A'' 
(representing either the olefins concentration, the hydrogen 
concentration, or the sum of the olefins and hydrogen concentration) 
in the flare vent gas determined for the 15-minute block period, 
volume fraction.
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.

    (3) If NHVvg or total hydrocarbon monitoring systems are 
used as provided in paragraphs (j)(3) or (j)(4) of this section, the 
owner or operator may elect to determine the hydrogen and olefins 
concentrations using any of the following methods.
    (i) The owner or operator may elect to assume the hydrogen 
concentration, the olefins concentration, and the olefins plus hydrogen 
concentration in the combustion zone gas exceed all three criteria in 
(e)(4) at all times without making specific measurements of olefins or 
hydrogen concentrations.
    (ii) The owner or operator may elect to use process knowledge and 
engineering calculations to determine the highest flare vent gas 
concentrations of olefins and hydrogen that can reasonably be expected 
to be discharged to the flare and the highest concentration of olefins 
plus hydrogen that can reasonably be expected to be discharged to the 
flare while the flare vent gas concentrations exceed the target 
combustion zone concentrations in paragraphs (e)(4)(i) and (ii) of this 
section at the same time. The owner or operator shall take daily flare 
vent gas samples for fourteen days or for 7 flaring events, whichever 
results in the greatest number of grab samples to verify that the 
calculated values are representative of the highest concentrations that 
reasonably be expected to be discharged to the flare.
    (A) If the highest flare vent gas concentrations of olefins, 
hydrogen, and olefins plus hydrogen that can reasonably be expected to 
be discharged to the flare do not exceed all three combustion zone 
concentration criteria in paragraph (e)(4) of this section, for 
example, if the flare does not service any process units that contain 
olefins, then the engineering assessment is sufficient to document that 
all three criteria in paragraph (e)(4) of this section are not met and 
that the more stringent operating limits do not apply at any time.
    (B) If the highest flare vent gas concentrations of olefins, 
hydrogen, and olefins plus hydrogen that can reasonably be expected to 
be discharged to the flare exceed all three combustion zone 
concentration criteria in paragraph (e)(4), then the owner or operator 
will use the concentrations determined from the engineering analysis as 
the vent gas concentrations that exist in the vent gas at all times and 
use the equation in paragraph (o)(2) of this section to determine the 
combustion zone concentrations of olefins.
    (C) If the operation of process units connected to the flares 
change or new connections are made to the flare and these changes can 
reasonably be expected to alter the highest vent gas concentrations of 
olefins, hydrogen, and/or olefins plus hydrogen received by the flare, 
a new engineering assessment and sampling period for verification will 
be conducted following the requirements of paragraph (o)(3)(ii) of this 
section.
    (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 test 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 test plan prior to 
conducting any flare performance test intended for use in developing 
site-specific operating limits. The site-specific test 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 test 
plan, the owner or operator shall conduct a performance test for the 
flare following the procedures described in the site-specific test 
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 test. 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

[[Page 36988]]

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 test. A 
sufficient number of test runs shall be conducted to identify the point 
at which the combustion/destruction efficiency of the flare 
deteriorates.
    (viii) If the flare can receive vent gases containing olefins and 
hydrogen above the levels specified for the combustion zone gas in 
paragraph (e)(4) of this section, a sufficient number of tests must be 
conducted while exceeding these limits to assess whether more stringent 
operating limits are required under these conditions.
    (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 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 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 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 test 
conducted following the methods in an approved site-specific test 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 40 CFR 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 refineryrtr@epa.gov.
    (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 test 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 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.
    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

[[Page 36989]]

specified in paragraphs (a)(1) through (8) of this section.
    (1) All monitoring equipment must meet the 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 maintenance periods, instrument adjustments or 
checks to maintain precision and accuracy, calibration checks, and zero 
and span adjustments, the owner or operator shall operate all CPMS and 
collect data continuously 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, the owner or operator shall comply with the out-
of-control procedures described in paragraphs (c) of this section. The 
CPMS monitoring plan must be submitted to the Administrator for 
approval upon request.
    (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. 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 (c)(3)(i) through (viii) of this section.
    (i) Manufacturer and model number for all monitoring equipment 
components.
    (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.
    (v) Span of the analyzer. The span must encompass all expected 
concentrations and meet the requirements of paragraph (b)(10) of this 
section.
    (vi) How data outside of the analyzer's span 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 (c)(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 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, 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

[[Page 36990]]

CPMS 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 the compounds that exist in the flare gas 
stream. 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.
    (ii) The owner or operator must use a surrogate calibration gas 
consisting of C1 through C7 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 the following paragraphs.
    (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) Unknown compounds that elute after n-heptane must either be 
identified and quantified using an identical compound standard, or the 
owner or operator must extend the calibration range to include the 
additional normal hydrocarbons necessary to perform the unknown 
hydrocarbon quantitation procedure.
0
34. Table 6 to Subpart CC is amended by:
0
a. Revising the entry ``63.5(d)(1)(ii)'';
0
b. Revising the entry ``63.5(f)'';
0
c. Removing the entry ``63.6(e)'';
0
d. Adding, in numerical order, the entries ``63.6(e)(1)(i) and (ii)'' 
and ``63.6(e)(1)(iii)'';
0
e. Revising the entries ``63.6(e)(3)(i)'' and ``63.6(e)(3)(iii)-
63.6(e)(3)(ix)'';
0
f. Revising the entry ``63.6(f)(1)'';
0
g. Removing the entry ``63.6(f)(2) and (3)'';
0
h. Adding, in numerical order, the entries ``63.6(f)(2)'' and 
``63.6(f)(3)'';
0
i. Removing the entry ``63.6(h)(1) and 63.6(h)(2)'';
0
j. Adding, in numerical order, the entries ``63.6(h)(1)'' and 
``63.6(h)(2)'';
0
k. Revising the entry ``63.7(b)'';
0
l. Revising the entry ``63.7(e)(1)'';
0
m. Removing the entry ``63.8(a)'';
0
n. Adding, in numerical order, the entries ``63.8(a)(1) and (2),'' 
``63.8(a)(3)'' and ``63.8(a)(4)'';
0
o. Revising the entry ``63.8(c)(1)'';
0
p. Adding, in numerical order, the entries ``63.8(c)(1)(i)'' and 
``63.8(c)(1)(iii)'';
0
q. Revising the entries ``63.8(c)(4)'' and ``63.8(c)(5)-63.8(c)(8)'';
0
r. Revising the entries ``63.8(d)'' and ``63.8(e)'';
0
s. Revising the entry ``63.8(g)'';
0
t. Revising the entries ``63.10(b)(2)(i)'' and ``63.10(b)(2)(ii)'';
0
u. Revising the entries ``63.10(b)(2)(iv)'' and ``63.10(b)(2)(v)'';
0
v. Revising the entry ``63.10(b)(2)(vii)'';
0
w. Removing the entry ``63.10(c)(9)-63.10(c)(15)'';
0
x. 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
y. Removing the entries ``63.10(d)(5)(i)'' and ``63.10(d)(5)(ii)'';
0
z. Adding, in numerical order, the entry ``63.10(d)(5)'';
0
aa. Removing the entry ``63.11-63.16'';
0
bb. Adding, in numerical order, the entries ``63.11'' and ``63.12-
63.16'';
0
cc. Removing footnote b.
    The revisions and additions read as follows:

                            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 subpart CC,
                                                          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)(ix)...  No..................
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
                                                          subpart CC does not require a site-specific test plan.
63.6(f)(3).......................  Yes.................  Except the cross-references to Sec.   63.6(f)(1) and
                                                          Sec.   63.6(e)(1)(i) are changed to Sec.   63.642(n).
 
                                                  * * * * * * *
63.6(h)(1).......................  No..................

[[Page 36991]]

 
63.6(h)(2).......................  Yes.................  Except Sec.   63.6(h)(2)(ii), which is reserved.
 
                                                  * * * * * * *
63.7(b)..........................  Yes.................  Except subpart CC 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 Sec.   63.8(c)(iii).
63.8(c)(1)(i)....................  No..................  See Sec.   63.642(n).
63.8(c)(1)(iii)..................  No..................
 
                                                  * * * * * * *
63.8(c)(4).......................  Yes.................  Except that for sources other than flares, subpart CC
                                                          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..................  Subpart CC specifies continuous monitoring system
                                                          requirements.
63.8(d)..........................  No..................  Subpart CC specifies quality control procedures for
                                                          continuous monitoring systems.
63.8(e)..........................  Yes.................
 
                                                  * * * * * * *
63.8(g)..........................  No..................  Subpart CC 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..................  See Sec.   63.655(i)(11) for recordkeeping of (1) date,
                                                          time and duration; (2) listing of affected source or
                                                          equipment, and an estimate of the volume of each
                                                          regulated pollutant emitted over the standard; and (3)
                                                          actions to minimize emissions and correct the failure.
 
                                                  * * * * * * *
63.10(b)(2)(iv)..................  No..................
63.10(b)(2)(v)...................  No..................
 
                                                  * * * * * * *
63.10(b)(2)(vii).................  No..................  Sec.   63.655(i) of subpart CC 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..................  See Sec.   63.655(i)(11) for malfunctions recordkeeping
                                                          requirements.
63.10(c)(12)-63.10(c)(15)........  No..................
 
                                                  * * * * * * *
63.10(d)(5)......................  No..................  See Sec.   63.655(g)(12) for malfunctions 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 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. Table 10 to Subpart CC is amended by:
0
a. Redesignating the entry ``Flare'' as ``Flare (if meeting the 
requirements of 63.643 and 63.644)'';
0
b. Adding the entry ``Flare (if meeting the requirements of 63.670 and 
63.671)'' after the newly redesignated entry ``Flare (if meeting the 
requirements of 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:

[[Page 36992]]



 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 reporting requirements
            Control device              Parameters to be monitored \a\          for monitored parameters
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Flare (if meeting the requirements of   The parameters specified in     1. Records as specified in 63.655(i)(9).
 63.670 and 63.671).                     63.670.
                                                                        2. Report information as specified in
                                                                         63.655(g)(11)--PR \g\.
All control devices...................  Volume of the gas stream        1. Continuous records \c\.
                                         diverted to the atmosphere
                                         from the control device
                                         (63.644(c)(1)) or
                                                                        2. 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\.
                                        Monthly inspections of sealed   1. Records that monthly inspections were
                                         valves (63.644(c)(2)).          performed.
                                                                        2. Record and report 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.
\c\ ``Continuous records'' is defined in Sec.   63.641.
\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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL
  REGISTER], 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. Table 11 is added to Subpart CC to read as follows:

                                   Table 11--Compliance Dates and Requirements
----------------------------------------------------------------------------------------------------------------
     If the construction/                                     And the owner or operator
reconstruction date \a\ is . .   Then the owner or operator  must achieve compliance . .   Except as provided in
               .                  must  comply with . . .                 .                        . . .
----------------------------------------------------------------------------------------------------------------
(1) After June 30, 2014.......  (i) Requirements for new     (a) Upon initial startup or  (1) Sec.   63.640(k),
                                 sources in Sec.  Sec.        [THE DATE OF PUBLICATION     (l) and (m).
                                 63.640 through 63.642,       OF THE FINAL RULE
                                 Sec.   63.647, Sec.  Sec.    AMENDMENTS IN THE FEDERAL
                                  63.650 through 63.653,      REGISTER], whichever is
                                 and Sec.  Sec.   63.656      later.
                                 through 63.660.
                                (ii) The new source          (a) Upon initial startup or  (1) Sec.   63.640(k),
                                 requirements in Sec.         October 28, 2009,            (l) and (m).
                                 63.654 for heat exchange     whichever is later.
                                 systems.
(2) After September 4, 2007     (i) Requirements for new     (a) Upon initial startup...  (1) Sec.   63.640(k),
 but on or before June 30,       sources in Sec.  Sec.                                     (l) and (m).
 2014.                           63.640 through 63.653 and
                                 63.656 b c.
                                (ii) Requirements for new    (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 sources in Sec.  Sec.        3 YEARS AFTER THE DATE OF    (l) and (m).
                                 63.640 through 63.645,       PUBLICATION OF THE FINAL
                                 Sec.  Sec.   63.647          RULE AMENDMENTS IN THE
                                 through 63.653, and Sec.     FEDERAL REGISTER].
                                 Sec.   63.656, through
                                 63.658 \b\.
                                (iii) Requirements for new   (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 sources in Sec.   63.660     90 DAYS AFTER THE DATE OF    (l) and (m).
                                 \c\.                         PUBLICATION OF THE FINAL
                                                              RULE AMENDMENTS IN THE
                                                              FEDERAL REGISTER].
                                (iv) The new source          (a) Upon initial startup or  (1) Sec.   63.640(k),
                                 requirements in Sec.         October 28, 2009,            (l) and (m).
                                 63.654 for heat exchange     whichever is later.
                                 systems.
(3) After July 14, 1994 but on  (i) Requirements for new     (a) Upon initial startup or  (1) Sec.   63.640(k),
 or before September 4, 2007.    sources in Sec.  Sec.        August 18, 1995, whichever   (l) and (m).
                                 63.640 through 63.653 and    is later.
                                 63.656 d e.
                                (ii) Requirements for new    (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 sources in Sec.  Sec.        3 YEARS AFTER THE DATE OF    (l) and (m).
                                 63.640 through 63.645,       PUBLICATION OF THE FINAL
                                 Sec.  Sec.   63.647          RULE AMENDMENTS IN THE
                                 through 63.653, and Sec.     FEDERAL REGISTER].
                                 Sec.   63.656, through
                                 63.658 \d\.
                                (iii) Requirements for new   (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 sources in Sec.   63.660     90 DAYS AFTER THE DATE OF    (l) and (m).
                                 \e\.                         PUBLICATION OF THE FINAL
                                                              RULE AMENDMENTS IN THE
                                                              FEDERAL REGISTER].

[[Page 36993]]

 
                                (iv) The existing source     (a) On or before October     (1) Sec.   63.640(k),
                                 requirements in Sec.         29, 2012.                    (l) and (m).
                                 63.654 for heat exchange
                                 systems.
(4) On or before July 14, 1994  (i) Requirements for         (a) On or before August 18,  (1) Sec.   63.640(k),
                                 existing sources in Sec.     1998.                        (l) and (m)
                                 Sec.   63.640 through
                                 63.653 and 63.656 f g.
                                                                                          (2) Sec.   63.6(c)(5)
                                                                                           of subpart A of this
                                                                                           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        (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 existing sources in Sec.     3 YEARS AFTER THE DATE OF    (l) and (m).
                                 Sec.   63.640 through        PUBLICATION OF THE FINAL
                                 63.645, Sec.  Sec.           RULE AMENDMENTS IN THE
                                 63.647 through 63.653, and   FEDERAL REGISTER].
                                 Sec.  Sec.   63.656
                                 through 63.658 \f\.
                                (iii) Requirements for       (a) On or before [THE DATE   (1) Sec.   63.640(k),
                                 existing sources in Sec.     90 DAYS AFTER THE DATE OF    (l) and (m).
                                 63.660 \g\.                  PUBLICATION OF THE FINAL
                                                              RULE AMENDMENTS IN THE
                                                              FEDERAL REGISTER].
                                (iii) The existing source    (a) On or before October     (1) Sec.   63.640(k),
                                 requirements in Sec.         29, 2012.                    (l) and (m).
                                 63.654 for heat exchange
                                 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)(a) and (2)(ii)(a) 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)(a) and (2)(iii)(a) of this table, the owner or operator may
  elect to comply with either the requirements in item (2)(i) or item (2)(iii) of this table. The requirements
  in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item
  (2)(iii) of this table.
\d\ Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) 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)(a) and (3)(iii)(a) of this table, the owner or operator may
  elect to comply with either the requirements in item (3)(i) or item (3)(iii) of this table. The requirements
  in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item
  (3)(iii) of this table.
\f\ Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) 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)(a) and (4)(iii)(a) of this table, the owner or operator may
  elect to comply with either the requirements in item (4)(i) or item (4)(iii) of this table. The requirements
  in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item
  (4)(iii) of this table.

0
37. Table 12 is added to Subpart CC to read as follows:

                                                        Table 12--Individual Component Properties
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                        NHVi (British
                                                                                   MWi (pounds per   CMNi (mole per     thermal units
                 Component                            Molecular formula              pound-mole)          mole)         per standard     LFLi (volume %)
                                                                                                                         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               274               4.0
Methane...................................  CH4.................................             16.04                 1               896               5.0

[[Page 36994]]

 
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]
--------------------------------------------------------------------------------------------------------------------------------------------------------

0
38. Table 13 is added to Subpart CC to read as follows:

                         Table 13--Calibration and Quality Control Requirements for CPMS
----------------------------------------------------------------------------------------------------------------
           Parameter               Accuracy requirements                   Calibration requirements
----------------------------------------------------------------------------------------------------------------
Temperature...................  1 percent over   Performance evaluation annually and following any
                                 the normal range of          period of more than 24 hours throughout which the
                                 temperature measured or      temperature exceeded the maximum rated temperature
                                 2.8 degrees Celsius (5       of the sensor, or the data recorder was off scale.
                                 degrees Fahrenheit),         Visual inspections and checks of CPMS operation
                                 whichever is greater, for    every 3 months, unless the CPMS has a redundant
                                 non-cryogenic temperature    temperature sensor.
                                 ranges.
                                2.5 percent      Select a representative measurement location.
                                 over the normal range of
                                 temperature measured or
                                 2.8 degrees Celsius (5
                                 degrees Fahrenheit),
                                 whichever is greater, for
                                 cryogenic temperature
                                 ranges.
Flow Rate.....................  5 percent over   Performance evaluation annually and following any
                                 the normal range of flow     period of more than 24 hours throughout which the
                                 measured or 1.9 liters per   flow rate exceeded the maximum rated flow rate of
                                 minute (0.5 gallons per      the sensor, or the data recorder was off scale.
                                 minute), whichever is        Checks of all mechanical connections for leakage
                                 greater, for liquid flow     monthly. Visual inspections and checks of CPMS
                                 rate.                        operation every 3 months, unless the CPMS has a
                                                              redundant flow sensor.
                                5 percent over   Select a representative measurement location where
                                 the normal range of flow     swirling flow or abnormal velocity distributions
                                 measured or 280 liters per   due to upstream and downstream disturbances at the
                                 minute (10 cubic feet per    point of measurement are minimized.
                                 minute), whichever is
                                 greater, for gas flow rate.
                                5 percent over
                                 the normal range measured
                                 for mass flow rate.
Pressure......................  5 percent over   Checks for obstructions at least once each process
                                 the normal range measured    operating day (e.g., pressure tap pluggage).
                                 or 0.12 kilopascals (0.5    Performance evaluation annually and following any
                                 inches of water column),     period of more than 24 hours throughout which the
                                 whichever is greater.        pressure exceeded the maximum rated pressure of
                                                              the sensor, or the data recorder was off scale.
                                                              Checks of all mechanical connections for leakage
                                                              monthly. Visual inspection of all components for
                                                              integrity, oxidation and galvanic corrosion every
                                                              3 months, unless the CPMS has a redundant pressure
                                                              sensor.
                                                             Select a representative measurement location that
                                                              minimizes or eliminates pulsating pressure,
                                                              vibration, and internal and external corrosion.
Net Heating Value by            2 percent of     Specify calibration requirements in your site
 Calorimeter.                    span.                        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.
Net Heating Value by Gas        As specified in Performance  Follow the procedure in Performance Specification 9
 Chromatograph.                  Specification 9 of 40 CFR    of 40 CFR part 60, Appendix B
                                 part 60, Appendix B.

[[Page 36995]]

 
Net Heating Value by Total      Calibration drift <=3% of    Calibration drift check daily. Follow the procedure
 Hydrocarbon Monitor.            instrument span at each      in Sections 4.1 and 4.2 of Procedure 1 in 40 CFR
                                 level.                       part 60, Appendix F.
                                Cylinder Gas Audit Accuracy  Cylinder gas audit quarterly. Follow the procedure
                                 <=5% of instrument span at   in Section 5.1.2 of Procedure 1 in 40 CFR part 60,
                                 each level.                  Appendix F, except the audit shall be performed
                                                              every quarter.
                                                             For both the calibration drift and error tests, the
                                                              calibration gases should be injected into the
                                                              sampling system as close to the sampling probe
                                                              outlet as practical and must pass through all
                                                              filters, scrubbers, conditioners, and other
                                                              monitor components used during normal sampling.
                                                             Select a measurement location that meets the
                                                              requirements of Section 3.1 of Performance
                                                              Specification 8A of Appendix B to 40 CFR part 60.
----------------------------------------------------------------------------------------------------------------

Subpart UUU--[Amended]

0
39. Section 63.1562 is amended by:
0
(a) Revising paragraph (b)(3) and
0
(b) Revising paragraph (f)(5).
    The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 
RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from 
the fuel gas system are in compliance with Sec.  63.670.
0
40. Section 63.1564 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Revising paragraph (a)(1)(ii);
0
d. Revising paragraph (a)(1)(iv);
0
e. Adding paragraph (a)(5);
0
f. Revising paragraph (b)(4)(i);
0
g. Revising paragraph (b)(4)(ii);
0
h. Revising paragraph (b)(4)(iv);
0
i. 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) 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 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 (iv) of 
this section:
    (i) You can elect to comply with the PM per coke burn-off emission 
limit (Option 1);
    (ii) You can elect to comply with the PM concentration emission 
limit (Option 2);
* * * * *
    (iv) You can elect to comply with the Ni per coke burn-off emission 
limit (Option 4).
* * * * *
    (5) During periods of startup only, if your catalytic cracking unit 
is followed by an electrostatic precipitator, 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 paragraphs (a)(1) 
and (2) of this section; or
    (ii) You can elect to maintain the opacity in the exhaust gas from 
your catalyst regenerator at or below 30 percent opacity on a 6-minute 
average basis.
    (b) * * *
    (4) * * *
    (i) If you elect Option 1 in paragraph (a)(1)(i) 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] TP30JN14.018


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 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 (a)(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).


[[Page 36996]]


[GRAPHIC] [TIFF OMITTED] TP30JN14.019


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 
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 (kg\2\/g)/(1,000 kg) (1,000 lb/(1,000 
lb)).

[GRAPHIC] [TIFF OMITTED] TP30JN14.020


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 [THE DATE 18 
MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN 
THE FEDERAL REGISTER], A=0.18 g/million cal (0.10 lb/million Btu). 
On or after [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE 
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 (kg\2\/g)/(1,000 
kg) (10\3\ lb/(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TP30JN14.021


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 2 in paragraph (a)(1)(ii) 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)(iv) 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] TP30JN14.022


Where:

ENi2 = Normalized mass emission rate of Ni, mg/kg coke 
(lb/1,000 lb coke).

[GRAPHIC] [TIFF OMITTED] TP30JN14.023


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] TP30JN14.024



[[Page 36997]]


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) During periods of startup only, if you elect to comply with the 
alternative limit in paragraph (a)(5)(ii) of this section, determine 
continuous compliance by: collecting opacity readings using either a 
continuous opacity monitoring system according to Sec.  63.1572 or 
manual opacity observations following EPA Method 9 in Appendix A-4 to 
part 60 of this chapter; and maintaining each 6-minute average opacity 
at or below 30 percent.
0
41. Section 63.1565 is amended by:
0
a. Adding paragraph (a)(5);
0
b. Adding paragraph (b)(1)(iv); and
0
c. Adding paragraph (c)(3).
    The additions read as follows:


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

    (a) * * *
    (5) During periods of startup only, if your catalytic cracking unit 
is not followed by a CO boiler, thermal oxidizer, incinerator, flare or 
similar combustion device, 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).
    (b) * * *
    (1) * * *
    (iv) If you elect to comply with the alternative limit for periods 
of startup in paragraph (a)(5)(ii) of this section, you must also 
install, operate, and maintain a continuous parameter monitoring system 
to measure and record the oxygen content (percent, dry basis) in the 
catalyst regenerator vent.
* * * * *
    (c) * * *
    (3) Demonstrate continuous compliance with the alternative limit in 
paragraph (a)(5)(ii) of this section by collecting the hourly average 
oxygen concentration monitoring data according to Sec.  63.1572 and 
maintaining the hourly average oxygen concentration at or above 1 
volume percent (dry basis).
0
42. Section 63.1566 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i); and
0
c. Revising paragraph (a)(4).
    The revisions 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 [THE DATE 3 YEARS AFTER THE 
DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL 
REGISTER], the flare must meet the requirements of Sec.  63.670. Prior 
to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], 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:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Adding paragraph (a)(4);
0
d. Revising paragraph (b)(1); and
0
e. Adding paragraphs (c)(3) and (4).
    The revisions and additions 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 in 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 in Sec.  60.102a(f)(1) of this chapter (Option 1); or
* * * * *
    (4) During periods of shutdown only, 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 shutdown purge gases to a flare. On 
and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL 
RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the 
requirements of Sec.  63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 
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 shutdown purge gases to a to a 
thermal oxidizer or incinerator operated at a minimum hourly average 
temperature of 1,200 degrees Fahrenheit and a minimum hourly average 
outlet oxygen (O2) concentration of 2 volume percent (dry 
basis).
    (b) * * *
    (1) Install, operate, and maintain a continuous monitoring system 
according to the requirements in Sec.  63.1572 and Table 31 of this 
subpart. Except:
    (i) If you elect to comply with the alternative limit for periods 
of shutdown in paragraph (a)(4)(ii) of this section, then on and after 
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE 
AMENDMENTS IN THE FEDERAL REGISTER], you must also install, operate, 
calibrate, and maintain monitoring systems as specified in Sec. Sec.  
63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF 
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you 
must either install, operate, and maintain continuous parameter 
monitoring systems following the requirements in Sec.  63.11 (to detect 
the presence of a flame; to measure and record the net heating value of 
the gas being combusted; and to measure and record the volumetric flow 
of the gas being combusted) or install, operate, calibrate, and 
maintain monitoring systems as specified in Sec. Sec.  63.670 and 
63.671.
    (ii) If you elect to comply with the alternative limit for periods 
of

[[Page 36998]]

shutdown in paragraph (a)(4)(iii) of this section, you must also 
install, operate, and maintain continuous parameter monitoring system 
to measure and record the temperature and oxygen content (percent, dry 
basis) in the vent from the thermal oxidizer or incinerator.
* * * * *
    (c) * * *
    (3) Demonstrate continuous compliance with the alternative limit in 
paragraph (a)(4)(ii) of this section by meeting the requirements of 
either paragraph (c)(3)(i) or (ii) of this section.
    (i) On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must meet the 
requirements of paragraphs (c)(3)(i)(A) through (C) of this section.
    (A) Collect the flare monitoring data according to Sec. Sec.  
63.670 and 63.671.
    (B) Keep the records specified in Sec.  63.655(i)(9).
    (C) Maintain the selected operating parameters as specified in 
Sec.  63.670.
    (ii) Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either 
meet the requirements of paragraph (c)(3)(i) of this section or meet 
the requirements of paragraphs (c)(3)(ii)(A) through (D) of this 
section.
    (A) Collect the flare monitoring data according to Sec.  63.1572.
    (B) Record for each 1-hour period whether the monitor was 
continuously operating and the pilot light was continuously present 
during each 1-hour period.
    (C) Maintain the net heating value of the gas being combusted at or 
above the applicable limits in Sec.  63.11.
    (D) Maintain the exit velocity at or below the applicable maximum 
exit velocity specified in Sec.  63.11.
    (4) Demonstrate continuous compliance with the alternative limit in 
paragraph (a)(4)(iii) of this section by collecting the hourly average 
temperature and oxygen concentration monitoring data according to Sec.  
63.1572; maintaining the hourly average temperature at or above 1,200 
degrees Fahrenheit; and maintaining the hourly average oxygen 
concentration at or above 2 volume percent (dry basis).
0
44. Section 63.1570 is amended by:
0
a. Revising paragraphs (a) through (d); and
0
b. Removing and reserving paragraph (g).
    The revisions 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 detailing the operation 
and maintenance of the process and emissions control equipment.
* * * * *
0
45. Section 63.1571 is amended by:
0
a. Adding paragraph (a)(5);
0
b. Revising paragraph (b)(1);
0
c. Removing paragraph (b)(4);
0
d. Redesignating paragraph (b)(5) as (b)(4);
0
e. Revising paragraphs (d)(2) and (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) Conduct a performance test for PM or Ni, as applicable, from 
catalytic cracking units at least once every 5 years for those units 
monitored with CPMS, BLD, or COMS. You must conduct the first periodic 
performance test no later than [THE DATE 18 MONTHS AFTER THE DATE OF 
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 
Those units monitoring PM concentration with a PM CEMS are not required 
to conduct a periodic PM performance test.
    (b) * * *
    (1) Conduct performance tests under such conditions as the 
Administrator specifies to you based on representative performance of 
the affected source for the period being tested. Representative 
conditions exclude periods of startup and shutdown unless specified by 
the Administrator or an applicable subpart. 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 such conditions represent normal operation. 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. Section 63.1564(b)(2) allows you to adjust the laboratory 
measurements of the equilibrium catalyst Ni concentration to the 
maximum level. You must make this adjustment using Equation 2 of this 
section as follows:
[GRAPHIC] [TIFF OMITTED] TP30JN14.025



[[Page 36999]]


Where:

NiEmR2st = Average Ni emission rate calculated as the 
arithmetic average Ni emission rate using Equation 8 of Sec.  
63.1564 for each performance test run, mg/kg coke burn-off.

* * * * *
    (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:
0
a. Revising paragraphs (c) introductory text, (c)(1), (c)(3) and 
(c)(4); and
0
b. Revising paragraphs (d)(1) and (2).
    The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must install, 
operate, calibrate, and maintain monitoring systems as specified in 
Sec. Sec.  63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE 
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 
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 meet the requirements in Table 41 of this 
subpart for BLD systems.
* * * * *
    (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);
0
c. Revising newly redesignated paragraph (c) introductory text;
0
d. Revising newly redesignated paragraph (d) introductory text;
0
e. Revising newly redesignated paragraph (f) introductory text; and
0
f. Revising newly redesignated paragraph (g)(1).
    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 paragraph (c)(1) or 
(2) of this section for a catalytic reforming unit.
* * * * *
    (d) Can I use another type of monitoring system? You may request 
approval from your permitting authority to 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. Your request must contain a 
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 (a)(3) 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

[[Page 37000]]

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.
* * * * *
0
49. Section 63.1575 is amended by:
0
a. Revising paragraphs (d) introductory text, (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 (e)(6);
0
f. Revising paragraphs (f)(1) and (2);
0
g. Removing and reserving paragraph (h); and
0
h. 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.
    (1) [Reserved]
* * * * *
    (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 (c)(1)(i) or 
(c)(1)(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 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. On and after [THE DATE 3 YEARS AFTER DATE OF 
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], if 
required to submit the results of a performance test or CEMS 
performance evaluation, you must submit the results using EPA's 
Electronic Reporting Tool (ERT) 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 according to the method specified by either paragraph 
(k)(1)(i) or (k)(1)(ii) of this section.
    (i) For data collected using test methods supported by the EPA's 
ERT as listed on the EPA's ERT Web site (http://www.epa.gov/ttn/chief/ert/index.html), you must submit the results of the performance test to 
the Compliance and Emissions Data Reporting Interface (CEDRI) accessed 
through the EPA's Central Data Exchange (CDX) (http://cdx.epa.gov/epa_home.asp), unless the Administrator approves another approach. 
Performance test data must be submitted in a file format generated 
through use of the EPA's ERT. 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, including information claimed to be CBI, on a compact disc 
or other commonly used electronic storage media (including, but not 
limited to, flash drives) by registered letter to the EPA. The 
electronic media must be clearly marked as CBI and mailed to

[[Page 37001]]

U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD 
C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with 
the CBI omitted must be submitted to the EPA via CDX as described 
earlier in this paragraph.
    (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, 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 test required by Sec.  63.1571(a) and (b), you 
must submit the results of the performance evaluation according to the 
method specified by either paragraph (k)(2)(i) or (k)(2)(ii) of this 
section.
    (i) For data collection of relative accuracy test audit (RATA) 
pollutants that are supported by the EPA's ERT as listed on the ERT Web 
site, the owner or operator must submit the results of the performance 
evaluation to the CEDRI that is accessed through the EPA's CDX, unless 
the Administrator approves another approach. Performance evaluation 
data must be submitted in a file format generated through the use of 
the EPA's ERT. 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, including information claimed to be CBI, on a compact disc 
or other commonly used electronic storage media (including, but not 
limited to, flash drives) by registered letter to the EPA. The 
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02, 
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 
omitted must be submitted to the EPA via CDX as described earlier in 
this paragraph.
    (ii) For any performance evaluation data with RATA pollutants that 
are not supported by the EPA's ERT as listed on the EPA's ERT Web site, 
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:
0
a. Revising paragraph (a)(2);
0
b. Revising paragraphs (b)(3) and (5).
    The revisions 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 section introductory text and
0
b. 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 this part (Sec. Sec.  63.1 
through 63.15), and in this section as listed. If the same term is 
defined in subpart A 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.
* * * * *
    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.

[[Page 37002]]



    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.                                  (1.0 lb/1,000 lb) of coke burn-
                                          off. Before [THE DATE 18
                                          MONTHS AFTER THE DATE OF
                                          PUBLICATION OF THE FINAL RULE
                                          AMENDMENTS IN THE FEDERAL
                                          REGISTER], 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).                        1.0 g/kg (1.0 lb PM/1,000 lb)
                                          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 1: PM per coke burn-off        PM emissions must not exceed
 limit, not subject to the NSPS for PM    the limits specified in Item 1
 in 40 CFR 60.102 or in 40 CFR            of this table.
 60.102a(b)(1).
5. Option 2: PM concentration limit,     PM emissions must not exceed
 not subject to the NSPS for PM in 40     0.040 gr/dscf corrected to 0
 CFR 60.102 or in 40 CFR 60.102a(b)(1).   percent excess air.
6. 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 in 40 CFR 60.102a(b)(1).       hour (mg/hr) (0.029 lb/hr).
7. 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 in 40 CFR            of coke burn-off in the
 60.102a(b)(1).                           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    a. Continuous opacity    Not applicable.........  Not applicable.
 CFR 60.102.                            monitoring system used
                                        to comply with the 30
                                        percent opacity limit
                                        in 40 CFR 60.102
                                        before [THE DATE 18
                                        MONTHS AFTER THE DATE
                                        OF PUBLICATION OF THE
                                        FINAL RULE AMENDMENTS
                                        IN THE FEDERAL
                                        REGISTER].
                                       b. Continuous opacity    Cyclone, fabric filter,  Maintain the 3-hour
                                        monitoring system used   or 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            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; and
                                                                                          maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                       d. Continuous parameter  Wet scrubber...........  Maintain the 3-hour
                                        monitoring systems.                               rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test; and maintain the
                                                                                          3-hour rolling average
                                                                                          liquid-to-gas ratio
                                                                                          above the limit
                                                                                          established in the
                                                                                          performance test.

[[Page 37003]]

 
                                       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.
2. Subject to NSPS for PM in 40 CFR    a. PM CEMS.............  Not applicable.........  Not applicable.
 60.102a(b)(1)(i).
                                       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            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; and
                                                                                          maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                       d. Continuous parameter  Wet scrubber...........  Maintain the 3-hour
                                        monitoring systems.                               rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test; and maintain the
                                                                                          3-hour rolling average
                                                                                          liquid-to-gas ratio
                                                                                          above the limit
                                                                                          established in the
                                                                                          performance test.
                                       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 1: PM per coke burn-off      a. Continuous opacity    Cyclone, fabric filter,  Maintain the 3-hour
 limit not subject to the NSPS for PM   monitoring system used   or electrostatic         rolling average
 in 40 CFR 60.102 or 40 CFR             to comply with a site-   precipitator.            opacity of emissions
 60.102a(b)(1).                         specific opacity limit.                           from your catalyst
                                                                                          regenerator vent no
                                                                                          higher than the site-
                                                                                          specific opacity limit
                                                                                          established during the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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) Maintain the daily
                                        monitoring systems.      precipitator.            average gas flow rate
                                                                                          or daily average coke
                                                                                          burn-off rate no
                                                                                          higher than the limit
                                                                                          established in the
                                                                                          performance test.

[[Page 37004]]

 
                                                                                         (2) Maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          maintain the daily
                                                                                          average voltage and
                                                                                          secondary current (or
                                                                                          total power input)
                                                                                          above the limit
                                                                                          established in the
                                                                                          performance test.
                                                                ii. Wet scrubber.......  (1) Maintain the 3-hour
                                                                                          rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test. Alternatively,
                                                                                          before [THE DATE 18
                                                                                          MONTHS AFTER THE DATE
                                                                                          OF PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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).
                                                                                         (2) Maintain the 3-hour
                                                                                          rolling average liquid-
                                                                                          to-gas ratio above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established in the
                                                                                          performance test.
                                       c. 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.
5. Option 2: PM concentration limit    PM CEMS................  Any....................  Not applicable.
 not subject to the NSPS for PM in 40
 CFR 60.102 or 40 CFR 60.102a(b)(1).
6. 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
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          maintain the daily
                                                                                          average Ni operating
                                                                                          value no higher than
                                                                                          the limit established
                                                                                          during the performance
                                                                                          test.

[[Page 37005]]

 
                                       b. Continuous parameter  i. Electrostatic         (1) Maintain the daily
                                        monitoring systems.      precipitator.            average gas flow rate
                                                                                          or daily average coke
                                                                                          burn-off rate no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (2) Maintain the
                                                                                          monthly rolling
                                                                                          average of the
                                                                                          equilibrium catalyst
                                                                                          Ni concentration no
                                                                                          higher than the limit
                                                                                          established during the
                                                                                          performance test.
                                                                                         (3) Maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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) Maintain the 3-hour
                                                                                          rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test. Alternatively,
                                                                                          before [THE DATE 18
                                                                                          MONTHS AFTER THE DATE
                                                                                          OF PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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).
                                                                                         (3) Maintain the 3-hour
                                                                                          rolling average liquid-
                                                                                          to-gas ratio above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established during the
                                                                                          performance test.

[[Page 37006]]

 
7. Option 4: Ni per coke burn-off      a. Continuous opacity    Cyclone, baghouse, or    Maintain the 3-hour
 limit not subject to the NSPS for PM   monitoring system.       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
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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) Maintain the 3-hour
                                                                                          rolling average total
                                                                                          power and secondary
                                                                                          current above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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) Maintain the 3-hour
                                                                                          rolling average
                                                                                          pressure drop above
                                                                                          the limit established
                                                                                          in the performance
                                                                                          test. Alternatively,
                                                                                          before [THE DATE 18
                                                                                          MONTHS AFTER THE DATE
                                                                                          OF PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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).
                                                                                         (3) Maintain the 3-hour
                                                                                          rolling average liquid-
                                                                                          to-gas ratio above the
                                                                                          limit established in
                                                                                          the performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          maintain the daily
                                                                                          average liquid-to-gas
                                                                                          ratio above the limit
                                                                                          established during the
                                                                                          performance test.
----------------------------------------------------------------------------------------------------------------


[[Page 37007]]

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   You shall install,
    For each new or existing        type of control      operate, and
 catalytic cracking  unit . . .     device for your    maintain a . . .
                                      vent . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM in  a. Cyclone........  Continuous opacity
 40 CFR 60.102.                                        monitoring system
                                                       to measure and
                                                       record the
                                                       opacity of
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
                                  b. Electrostatic    Continuous opacity
                                   precipitator.       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\ and the total
                                                       power 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\ coke
                                                       burn-off rate or
                                                       the gas flow rate
                                                       entering or
                                                       exiting the
                                                       control
                                                       device,\1\ and
                                                       total liquid (or
                                                       scrubbing liquor)
                                                       flow rate to the
                                                       control device.
                                                       Alternatively,
                                                       before [THE DATE
                                                       3 YEARS AFTER THE
                                                       DATE OF
                                                       PUBLICATION OF
                                                       THE FINAL RULE
                                                       AMENDMENTS IN THE
                                                       FEDERAL
                                                       REGISTER],
                                                       continuous
                                                       opacity
                                                       monitoring system
                                                       to measure and
                                                       record the
                                                       opacity of
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
                                  d. Fabric Filter..  Continuous bag
                                                       leak detection
                                                       system to measure
                                                       and record
                                                       increases in
                                                       relative
                                                       particulate
                                                       loading from each
                                                       catalyst
                                                       regenerator vent
                                                       or a continuous
                                                       opacity
                                                       monitoring system
                                                       to measure and
                                                       record the
                                                       opacity of
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
2. Subject to NSPS for PM in 40   a. Cyclone........  Continuous opacity
 CFR 60.102a(b)(1)(i) electing                         monitoring system
 to meet the PM per coke burn-                         to measure and
 off limit.                                            record the
                                                       opacity of
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent.
                                  b. Electrostatic    Continuous opacity
                                   precipitator.       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,\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.
3. Subject to NSPS for PM in 40   Any...............  Continuous
 CFR 60.102a(b)(1)(i) electing                         emission
 to meet the PM concentration                          monitoring system
 limit.                                                to measure and
                                                       record the
                                                       concentration of
                                                       PM and oxygen
                                                       from each
                                                       catalyst
                                                       regenerator vent.
4. Subject to NSPS for PM in 40   Any...............  See item 2 of this
 CFR 60.102a(b)(1)(ii) electing                        table.
 to meet the PM per coke burn-
 off limit.
5. Subject to NSPS for PM in 40   Any...............  See item 3 of this
 CFR 60.102a(b)(1)(ii) electing                        table.
 to meet the PM concentration
 limit.

[[Page 37008]]

 
6. Option 1: PM per coke burn-    Any...............  See item 1 of this
 off limit not subject to the                          table.
 NSPS for PM in 40 CFR 60.102 or
 40 CFR 60.120a(b)(1).
7. Option 2: PM concentration     Any...............  See item 3 of this
 limit not subject to the NSPS                         table.
 for PM in 40 CFR 60.102 or 40
 CFR 60.120a(b)(1).
8. Option 3: Ni lb/hr limit not   a. Cyclone........  Continuous opacity
 subject to the NSPS for PM in                         monitoring system
 40 CFR 60.102 or in 40 CFR                            to measure and
 60.102a(b)(1).                                        record the
                                                       opacity of
                                                       emissions from
                                                       each catalyst
                                                       regenerator vent
                                                       and continuous
                                                       parameter
                                                       monitoring system
                                                       to measure and
                                                       record the coke
                                                       burn-off rate or
                                                       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 coke
                                                       burn-off rate or
                                                       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 8.a of
                                                       this table.
9. Option 4: Ni lb/1,000 lbs of   a. Cyclone........  Continuous opacity
 coke burn-off limit not subject                       monitoring system
 to the NSPS for PM in 40 CFR                          to measure and
 60.102 or in 40 CFR                                   record the
 60.102a(b)(1).                                        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 coke
                                                       burn-off rate or
                                                       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 9.a of
                                                       this table.
------------------------------------------------------------------------
\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.


[[Page 37009]]

0
55. Table 4 to subpart UUU of part 63 is revised to read as follows:
    As stated in Sec.  63.1564(b)(2), 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 Not Subject to the New Source Performance Standard (NSPS) for Particulate Matter (PM)
----------------------------------------------------------------------------------------------------------------
  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      2F in Appendix A-1 to
                                        rate.                    part 60 of this
                                                                 chapter, or 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.
2. Option 1: PM per coke burn-off      a. Measure PM emissions  Method 5, 5B, or 5F (40  You must maintain a
 limit, not subject to the NSPS for                              CFR part 60, Appendix    sampling rate of at
 PM in 40 CFR 60.102 or in 40 CFR                                A-3) to determine PM     least 0.15 dry
 60.102a(b)(1).                                                  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. Option 2: PM concentration limit,   a. Measure PM            Method 5, 5B, or 5F (40  You must maintain a
 not subject to the NSPS for PM in 40   concentration.           CFR part 60, Appendix    sampling rate of at
 CFR 60.102 or in 40 CFR                                         A-3) to determine PM     least 0.15 dry
 60.102a(b)(1).                                                  concentration 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
                                                                 concentration and
                                                                 associated moisture
                                                                 content for unit with
                                                                 wet scrubber.

[[Page 37010]]

 
4. 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 in 40 CFR 60.102a(b)(1).
                                       b. Compute Ni emission   Equation 5 of Sec.
                                        rate (lb/hr).            63.1564.
                                       c. Determine the         XRF procedure in         You must obtain 1
                                        equilibrium catalyst     Appendix A to this       sample for each of the
                                        Ni concentration.        subpart; \1\ or EPA      3 runs; determine and
                                                                 Method 6010B or 6020     record the equilibrium
                                                                 or EPA Method 7520 or    catalyst Ni
                                                                 7521 in SW-846; \2\ or   concentration for each
                                                                 an alternative to the    of the 3 samples; and
                                                                 SW-846 method            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 hourly average
                                                                 Method 29 test.          opacity from all the 6-
                                                                                          minute averages.
                                                                                         (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
                                                                                          from all the readings.
5. 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 in 40 CFR
 60.102a(b)(1).
                                       b. Compute Ni emission   Equations 1 and 8 of
                                        rate (lb/1,000 lb of     Sec.   63.1564.
                                        coke burn-off).
                                       c. Determine the         See item 4.c. of this    You must obtain 1
                                        equilibrium catalyst     table.                   sample for each of the
                                        Ni concentration.                                 3 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 hourly average
                                                                 Method 29 test.          opacity from all the 6-
                                                                                          minute averages.
                                                                                         (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
                                                                                          from all the readings.

[[Page 37011]]

 
                                       e. Record the catalyst
                                        addition rate for each
                                        test and schedule for
                                        the 10-day period
                                        prior to the test.
6. If you elect Option 1 in item 4 in  a. Establish each        Data from the
 Table 1, Option 3 in item 6 in Table   operating limit in       continuous parameter
 1, or Option 4 in item 7 in Table 1    Table 2 of this          monitoring systems and
 of this subpart and you use            subpart that applies     applicable performance
 continuous parameter monitoring        to you.                  test methods.
 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.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average gas flow rate
                                                                                          from all the readings.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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: voltage    continuous parameter     voltage, current, and
                                        and secondary current    monitoring systems and   secondary current
                                        (or total power input).  applicable performance   monitoring data every
                                                                 test methods.            15 minutes during the
                                                                                          entire period of the
                                                                                          performance test.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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 and the 3-
                                                                                          hr average secondary
                                                                                          current.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          determine and record
                                                                                          the minimum hourly
                                                                                          average voltage and
                                                                                          secondary current (or
                                                                                          total power input)
                                                                                          from all the readings.
                                       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.

[[Page 37012]]

 
                                       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.
                                                                                         (2) You must determine
                                                                                          and record the 3-hr
                                                                                          average pressure drop
                                                                                          from all the readings.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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.
                                                                                         (2) You must determine
                                                                                          and record the hourly
                                                                                          average liquid-to-gas
                                                                                          ratio from all the
                                                                                          readings.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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 [THE DATE 18
                                                                                          MONTHS AFTER THE DATE
                                                                                          OF PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], 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.
                                                                                          Alternatively, before
                                                                                          [THE DATE 18 MONTHS
                                                                                          AFTER THE DATE OF
                                                                                          PUBLICATION OF THE
                                                                                          FINAL RULE AMENDMENTS
                                                                                          IN THE FEDERAL
                                                                                          REGISTER], you may
                                                                                          determine and record
                                                                                          the hourly average
                                                                                          rate of all the
                                                                                          readings.

[[Page 37013]]

 
                                                                                         (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).
\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
  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.

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
   catalytic cracking unit      For the following         You have
 catalyst regenerator vent .  emission limit . . .  demonstrated initial
             . .                                     compliance if . . .
------------------------------------------------------------------------
1. Subject to the NSPS for    PM emissions must     You have already
 PM in 40 CFR 60.102.          not exceed 1.0 gram   conducted a
                               per kilogram (g/kg)   performance test to
                               (1.0 lb/1,000 lb)     demonstrate initial
                               of coke burn-off.     compliance with the
                               Before [THE DATE 18   NSPS and the
                               MONTHS AFTER THE      measured PM
                               DATE OF PUBLICATION   emission rate is
                               OF THE FINAL RULE     less than or equal
                               AMENDMENTS IN THE     to 1.0 g/kg (1.0 lb/
                               FEDERAL REGISTER],    1,000 lb) of coke
                               if the discharged     burn-off in the
                               gases pass through    catalyst
                               an incinerator or     regenerator. As
                               waste heat boiler     part of the
                               in which you burn     Notification of
                               auxiliary or          Compliance Status,
                               supplemental liquid   you must certify
                               or solid fossil       that your vent
                               fuel, the             meets the PM limit.
                               incremental rate of   You are not
                               PM must not exceed    required to do
                               43.0 grams per        another performance
                               Gigajoule (g/GJ) or   test to demonstrate
                               0.10 pounds per       initial compliance.
                               million British       As part of your
                               thermal units (lb/    Notification of
                               million Btu) of       Compliance Status,
                               heat input            you certify that
                               attributable to the   your BLD; CO2, O2,
                               liquid or solid       or CO monitor; or
                               fossil fuel; and      continuous opacity
                               the opacity of        monitoring system
                               emissions must not    meets the
                               exceed 30 percent,    requirements in
                               except for one 6-     Sec.   63.1572.
                               minute average
                               opacity reading in
                               any 1-hour period.
2. Subject to NSPS for PM in  PM emissions must     You have already
 40 CFR 60.102a(b)(1)(i),      not exceed 0.5 g/kg   conducted a
 electing to meet the PM per   (0.5 lb PM/1,000      performance test to
 coke burn-off limit.          lb) of coke burn-     demonstrate initial
                               off or,               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.

[[Page 37014]]

 
3. Subject to NSPS for PM in  PM emissions must     You have already
 40 CFR 60.102a(b)(1)(ii),     not exceed 1.0 g/kg   conducted a
 electing to meet the PM per   coke burn-off (1 lb/  performance test to
 coke burn-off limit.          1000 lb coke burn-    demonstrate initial
                               off).                 compliance with the
                                                     NSPS and the
                                                     measured PM
                                                     emission rate is
                                                     less than or equal
                                                     to 0.5 kg/1,000 kg
                                                     (0.5 lb/1,000 lb)
                                                     of coke burn-off in
                                                     the catalyst
                                                     regenerator. As
                                                     part of the
                                                     Notification of
                                                     Compliance Status,
                                                     you must certify
                                                     that your vent
                                                     meets the PM limit.
                                                     You are not
                                                     required to do
                                                     another performance
                                                     test to demonstrate
                                                     initial compliance.
                                                     As part of your
                                                     Notification of
                                                     Compliance Status,
                                                     you certify that
                                                     your BLD; 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, 0.020 grain     conducted a
 electing to meet the PM       per dry standard      performance test to
 concentration limit.          cubic feet (gr/       demonstrate initial
                               dscf) corrected to    compliance with the
                               0 percent excess      NSPS and the
                               air.                  measured PM
                                                     concentration is
                                                     less than or equal
                                                     to 0.020 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.
5. Subject to NSPS for PM in  If a PM CEMS is       You have already
 40 CFR 60.102a(b)(1)(ii),     used, 0.040 gr/dscf   conducted a
 electing to meet the PM       corrected to 0        performance test to
 concentration limit.          percent excess air.   demonstrate initial
                                                     compliance with the
                                                     NSPS and the
                                                     measured PM
                                                     concentration is
                                                     less than or equal
                                                     to 0.040 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 1: PM per coke      PM emissions must     The average PM
 burn-off limit not subject    not exceed 1.0 gram   emission rate,
 to the NSPS for PM in 40      per kilogram (g/kg)   measured using EPA
 CFR 60.102 or 40 CFR          (1.0 lb/1,000 lb)     Method 5, 5B, or 5F
 60.120a(b)(1).                of coke burn-off.     (for a unit without
                               Before [THE DATE 3    a wet scrubber) or
                               YEARS AFTER THE       5 or 5B (for a unit
                               DATE OF PUBLICATION   with a wet
                               OF THE FINAL RULE     scrubber), over the
                               AMENDMENTS IN THE     period of the
                               FEDERAL REGISTER],    initial performance
                               PM emission must      test, is no higher
                               not exceed 1.0 g/kg   than 1.0 g/kg coke
                               (1.0 lb/1,000 lb)     burn-off (1.0 lb/
                               of coke burn-off in   1,000 lb) in the
                               the catalyst          catalyst
                               regenerator; if the   regenerator. The PM
                               discharged gases      emission rate is
                               pass through an       calculated using
                               incinerator or        Equations 1, 2, and
                               waste heat boiler     3 of Sec.
                               in which you burn     63.1564. If you use
                               auxiliary or          a BLD; CO2, O2, CO
                               supplemental liquid   monitor; or
                               or solid fossil       continuous opacity
                               fuel, the             monitoring system,
                               incremental rate of   your performance
                               PM must not exceed    evaluation shows
                               43.0 g/GJ (0.10 lb/   the system meets
                               million Btu) of       the applicable
                               heat input            requirements in
                               attributable to the   Sec.   63.1572.
                               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.
7. Option 2: PM               PM emissions must     The average PM
 concentration limit, not      not exceed 0.040 gr/  concentration,
 subject to the NSPS for PM    dscf corrected to 0   measured using EPA
 in 40 CFR 60.102 or in 40     percent excess air.   Method 5, 5B, or 5F
 CFR 60.102a(b)(1).                                  (for a unit without
                                                     a wet scrubber) or
                                                     Method 5 or 5B (for
                                                     a unit with a wet
                                                     scrubber), 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.

[[Page 37015]]

 
8. Option 3: not subject to   Nickel (Ni)           The average Ni
 the NSPS for PM.              emissions from your   emission rate,
                               catalyst              measured using
                               regenerator vent      Method 29 over the
                               must not exceed       period of the
                               13,000 mg/hr (0.029   initial performance
                               lb/hr).               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.
9. Option 4: Ni per coke      Ni emissions from     The average Ni
 burn-off limit not subject    your catalyst         emission rate,
 to the NSPS for PM.           regenerator vent      measured using
                               must not exceed 1.0   Method 29 over the
                               mg/kg (0.001 lb/      period of the
                               1,000 lb) of coke     initial performance
                               burn-off in the       test, is not more
                               catalyst              than 1.0 mg/kg
                               regenerator.          (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
  For each new and existing    emission limit for         You shall
 catalytic cracking unit . .      your catalyst          demonstrate
              .               regenerator vent . .       continuous
                                        .            compliance by . . .
------------------------------------------------------------------------
1. Subject to the NSPS for    a. PM emissions must  i. Determining and
 PM in 40 CFR 60.102.          not exceed 1.0 gram   recording each day
                               per kilogram (g/kg)   the average coke
                               (1.0 lb/1,000 lb)     burn-off rate
                               of coke burn-off.     (thousands of
                               Before [THE DATE 18   kilograms per hour)
                               MONTHS AFTER THE      using Equation 1 in
                               DATE OF PUBLICATION   Sec.   63.1564 and
                               OF THE FINAL RULE     the hours of
                               AMENDMENTS IN THE     operation for each
                               FEDERAL REGISTER],    catalyst
                               if the discharged     regenerator.
                               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. Maintaining PM
                                                     emission rate below
                                                     1.0 g/kg (1.0 lb/
                                                     1,000 lb) of coke
                                                     burn-off.
                                                    iii. Conducting a
                                                     performance test
                                                     before [THE DATE 18
                                                     MONTHS AFTER THE
                                                     DATE OF PUBLICATION
                                                     OF THE FINAL RULE
                                                     AMENDMENTS IN THE
                                                     FEDERAL REGISTER]
                                                     and once every five
                                                     years thereafter.
                                                    iv. Collecting the
                                                     applicable
                                                     continuous
                                                     parametric
                                                     monitoring system
                                                     data according to
                                                     Sec.   63.1572 and
                                                     maintaining each
                                                     rolling 3-hr
                                                     average above or
                                                     below (as
                                                     applicable) the
                                                     average determined
                                                     during the
                                                     performance test.

[[Page 37016]]

 
                                                    v. 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 the site-
                                                     specific opacity
                                                     determined during
                                                     the performance
                                                     test.
                                                     Alternatively,
                                                     before [THE DATE 18
                                                     MONTHS AFTER THE
                                                     DATE OF PUBLICATION
                                                     OF THE FINAL RULE
                                                     AMENDMENTS IN THE
                                                     FEDERAL REGISTER],
                                                     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.
                                                    vi. Before [THE DATE
                                                     18 MONTHS AFTER THE
                                                     DATE OF PUBLICATION
                                                     OF THE FINAL RULE
                                                     AMENDMENTS IN THE
                                                     FEDERAL REGISTER],
                                                     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 0.5 g/kg   recording each day
 electing to meet the PM per   (0.5 lb PM/1,000      the average coke
 coke burn-off limit..         lb) of coke burn-     burn-off rate
                               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 PM/
                                                     1,000 lb) of coke
                                                     burn-off;
                                                     conducting a
                                                     performance test
                                                     once every year;
                                                     collecting the
                                                     applicable
                                                     continuous
                                                     parametric
                                                     monitoring system
                                                     data according to
                                                     Sec.   63.1572 and
                                                     maintaining each
                                                     rolling 3-hr
                                                     average above or
                                                     below (as
                                                     applicable) the
                                                     average determined
                                                     during the
                                                     performance test;
                                                     collecting the
                                                     continuous opacity
                                                     monitoring data for
                                                     each regenerator
                                                     vent according to
                                                     Sec.   63.1572 and
                                                     maintaining each 6-
                                                     minute average at
                                                     or below the site-
                                                     specific opacity
                                                     determined during
                                                     the performance
                                                     test.
3. Subject to NSPS for PM in  PM emissions must     Determining and
 40 CFR 60.102a(b)(1)(ii),     not exceed 1.0 g/kg   recording each day
 electing to meet the PM per   coke burn-off (1 lb/  the average coke
 coke burn-off limit.          1,000 lb coke burn-   burn-off rate
                               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/
                                                     1,000 lb) of coke
                                                     burn-off;
                                                     conducting a
                                                     performance test
                                                     once every year;
                                                     collecting the
                                                     applicable
                                                     continuous
                                                     parametric
                                                     monitoring system
                                                     data according to
                                                     Sec.   63.1572 and
                                                     maintaining each
                                                     rolling 3-hr
                                                     average above or
                                                     below (as
                                                     applicable) the
                                                     average determined
                                                     during the
                                                     performance test;
                                                     collecting the
                                                     continuous opacity
                                                     monitoring data for
                                                     each regenerator
                                                     vent according to
                                                     Sec.   63.1572 and
                                                     maintaining each 6-
                                                     minute average at
                                                     or below the site-
                                                     specific opacity
                                                     determined during
                                                     the performance
                                                     test.
4. Subject to NSPS for PM in  If a PM CEMS is       Maintaining PM
 40 CFR 60.102a(b)(1)(i),      used, 0.020 grain     concentration below
 electing to meet the PM       per dry standard      0.020 gr/dscf
 concentration limit.          cubic feet (gr/       corrected to 0
                               dscf) corrected to    percent excess air.
                               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, 0.040 gr/dscf   concentration below
 electing to meet the PM       corrected to 0        0.040 gr/dscf
 concentration limit.          percent excess air.   corrected to 0
                                                     percent excess air.

[[Page 37017]]

 
6. Option 1: PM per coke      See item 1 of this    See item 1 of this
 burn-off limit, not subject   table.                table.
 to the NSPS for PM in 40
 CFR 60.102 or in 40 CFR
 60.102a(b)(1).
7. Option 2: PM               PM emissions must     See item 5 of this
 concentration limit, not      not exceed 0.040 gr/  table.
 subject to the NSPS for PM    dscf corrected to 0
 in 40 CFR 60.102 or in 40     percent excess air.
 CFR 60.102a(b)(1).
8. Option 3: Ni lb/hr limit,  Ni emissions must     Maintaining Ni
 not subject to the NSPS for   not exceed 13,000     emission rate below
 PM in 40 CFR 60.102 or in     mg/hr (0.029 lb/hr).  13,000 mg/hr (0.029
 40 CFR 60.102a(b)(1).                               lb/hr); conducting
                                                     a performance test
                                                     before [THE DATE 18
                                                     MONTHS AFTER THE
                                                     DATE OF PUBLICATION
                                                     OF THE FINAL RULE
                                                     AMENDMENTS IN THE
                                                     FEDERAL REGISTER]
                                                     and once every five
                                                     years thereafter;
                                                     and collecting the
                                                     applicable
                                                     continuous
                                                     parametric
                                                     monitoring system
                                                     data according to
                                                     Sec.   63.1572 and
                                                     maintaining each
                                                     rolling 3-hr
                                                     average above or
                                                     below (as
                                                     applicable) the
                                                     average determined
                                                     during the
                                                     performance test.
9. Option 4: Ni per coke      Ni emissions must     Determining and
 burn-off limit, not subject   not exceed 1.0 mg/    recording each day
 to the NSPS for PM in 40      kg (0.001 lb/1,000    the average coke
 CFR 60.102 or in 40 CFR       lb) of coke burn-     burn-off rate
 60.102a(b)(1).                off in the catalyst   (thousands of
                               regenerator.          kilograms per hour)
                                                     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;
                                                     conducting a
                                                     performance test
                                                     before [THE DATE 18
                                                     MONTHS AFTER THE
                                                     DATE OF PUBLICATION
                                                     OF THE FINAL RULE
                                                     AMENDMENTS IN THE
                                                     FEDERAL REGISTER]
                                                     and once every five
                                                     years thereafter;
                                                     and collecting the
                                                     applicable
                                                     continuous
                                                     parametric
                                                     monitoring system
                                                     data according to
                                                     Sec.   63.1572 and
                                                     maintaining each
                                                     rolling 3-hr
                                                     average above or
                                                     below (as