[Federal Register Volume 60, Number 160 (Friday, August 18, 1995)]
[Rules and Regulations]
[Pages 43244-43297]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-20252]
[[Page 43243]]
_______________________________________________________________________
Part III
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 9, et al.
National Emission Standards for Hazardous Air Pollutants: Petroleum
Refineries; Final Rule
Federal Register / Vol. 60, No. 160 / Friday, August 18, 1995 / Rules
and Regulations
[[Page 43244]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 9, 60 and 63
[AD-FRL-5272-1]
RIN 2060-AD94
National Emission Standards for Hazardous Air Pollutants:
Petroleum Refineries
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule promulgates national emission standards for
hazardous air pollutants (NESHAP) for petroleum refineries. This rule
implements section 112 of the Clean Air Act (Act) and are based on the
Administrator's determination that petroleum refineries emit organic
hazardous air pollutants (HAPs) identified on the EPA's list of 189
HAPs. The health effects of exposure to HAPs can include cancer,
respiratory irritation and damage to the nervous system. The petroleum
refinery NESHAP requires petroleum refineries located at major sources
to meet emission standards reflecting the application of the maximum
achievable control technology (MACT), consistent with sections 112(d)
and (h) of the Act. The petroleum refinery affected source is defined
to include petroleum refinery process units, marine tank vessel loading
operations, and gasoline loading rack operations classified under
Standard Industrial Classification (SIC) code 2911 emission points
located at petroleum refineries. The petroleum refinery affected source
and source category description are revised to reflect the inclusion of
these emission points. This action also amends two standards of
performance for two stationary sources: Standards of performance for
equipment leaks of volatile organic compounds (VOC) in the synthetic
organic chemicals manufacturing industry (SOCMI); and standards of
performance for VOC emissions from petroleum refinery wastewater
systems. The amended standards were previously promulgated under
section 111 of the Act.
EFFECTIVE DATE: August 18, 1995. See the Supplementary Information
section concerning judicial review.
ADDRESSES: Docket. Docket No. A-93-48, containing information
considered by the EPA in development of the promulgated standards, is
available for public inspection between 8 a.m. and 4 p.m., Monday
through Friday except for Federal holidays, at the following address:
U.S. Environmental Protection Agency, Air and Radiation Docket and
Information Center (MC-6102), 401 M Street SW, Washington, DC 20460;
telephone: (202) 260-7548. The docket is located at the above address
in Room M-1500, Waterside Mall (ground floor). A reasonable fee may be
charged for copying.
Response to Comment Document. The response to comment document for
the promulgated standards may be obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North Carolina 27711, telephone (919)
541-2777; or from the National Technical Information Services, 5285
Port Royal Road, Springfield, Virginia 22151, telephone (703) 487-4650.
Please refer to ``National Emission Standards for Hazardous Air
Pollutants, Petroleum Refineries-Background Information for Final
Standards, Summary of Public Comments and Responses'' (EPA No.-453/R-
95-015b). The document contains: (1) A summary of all the public
comments made on the proposed standards and the Administrator's
response to the comments; and (2) a summary of the changes made to the
standards since proposal. This document is also available for
downloading from the Technology Transfer Network (see below) under the
Clean Air Act, Recently Signed Rules.
Technology Transfer Network. The Technology Transfer Network is one
of the EPA's electronic bulletin boards. The Technology Transfer
Network provides information and technology exchange in various areas
of air pollution control. The service is free except for the cost of a
phone call. Dial (919) 541-5472 for up to a 14,400 bps modem. If more
information on the Technology Transfer Network is needed call the HELP
line at (919) 541-5384.
FOR FURTHER INFORMATION CONTACT: For information concerning the final
standards, contact Mr. James Durham, Waste and Chemical Processes
Group, Emission Standards Division (MD-13), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina, 27711,
telephone number (919) 541-5672.
SUPPLEMENTARY INFORMATION: Judicial Review. National emission standards
for HAP's for petroleum refineries were proposed in the Federal
Register (FR) on July 15, 1994 (59 FR 36130). This Federal Register
action announces the EPA's final decisions on the rule. Under section
307(b)(1) of the Act, judicial review of the NESHAP is available only
by the petition for review in the U.S. Court of Appeals for the
District of Columbia Circuit within 60 days of today's publication of
this final rule. Under section 307(b)(2) of the Act, the requirements
that are the subject of today's notice may not be challenged later in
civil or criminal proceedings brought by the EPA to enforce these
requirements.
The following outline is provided to aid in reading the preamble to
the final regulation.
I. Background
II. Summary of Considerations in Developing the Rule
A. Purpose of Regulation
B. Technical Basis of Regulation
C. Stakeholder and Public Participation
III. Summary of Promulgated Standards
A. Miscellaneous Process Vent Provisions
B. Storage Vessel Provisions
C. Wastewater Provisions
D. Equipment Leak Provisions
E. Marine Vessel Loading and Unloading, Bulk Gasoline Terminal
or Pipeline Breakout Station Storage Vessels, and Bulk Gasoline
Terminal Loading Rack Provisions
F. Recordkeeping and Reporting Provisions
G. Emissions Averaging
IV. Summary of Impacts
V. Significant Comments and Changes to the Proposed Standards
A. Process Vents Group Determination
B. Process Vent Impacts
C. Equipment Leaks Compliance Requirements
D. Storage Vessels
E. Overlapping Regulations
F. Source Category Definition
G. Emissions Averaging
H. Monitoring, Recordkeeping, and Reporting
I. Subcategorization
J. Economic Analysis
K. Benefits Analysis
L. Emissions Data
VI. Changes to NSPS
VII. Administrative Requirements
A. Docket
B. Paperwork Reduction Act
C. Executive Order 12866
D. Regulatory Flexibility Act
E. Unfunded Mandates
I. Background
Section 112(b) of the Act lists 189 HAP's and directs the EPA to
develop rules to control all major and some area sources emitting
HAP's. On July 16, 1992 (57 FR 31576), the EPA published a list of
major and area sources for which NESHAP are to be promulgated.
Petroleum refineries were listed as a category of major sources. On
December 3, 1993 (58 FR 83941), the EPA published a schedule for
promulgating standards for the listed major and area sources. Standards
for the petroleum refinery source category for sources not distinctly
listed were scheduled for promulgation on November 15, 1994. The EPA is
promulgating these standards under a July 28, 1995 court-ordered
deadline.
[[Page 43245]]
II. Summary of Considerations in Developing the Rule
A. Purpose of Regulation
The Act was developed, in part,
To protect and enhance the quality of the Nations air resources
so as to promote the public health and welfare and the productive
capacity of its population (the Act, section 101(b)(1)).
Petroleum refineries are major sources of HAP emissions. Individual
refineries emit over 23 megagrams per year (Mg/yr) (25 tons per year
(tpy)) of organic HAP's including benzene, toluene, ethyl benzene, and
other HAP's. The HAP's controlled by this rule are associated with a
variety of adverse health effects. The range of adverse health effects
include cancer and a number of other chronic health disorders (e.g.,
aplastic anemia, pancytopenia, pernicious anemia, pulmonary (lung)
structural changes) and a number of acute health disorders (e.g.,
dyspnea (difficulty in breathing), upper respiratory tract irritation
with cough, conjunctivitis, neurotoxic effects (e.g., visual blurring,
tremors, delirium, unconsciousness, coma, convulsions). Table 1
presents the 11 most significant organic HAP's emitted from the
petroleum refineries. Petroleum refineries also emit inorganic HAP's
(e.g., hydrogen fluoride, hydrogen chloride). Inorganic HAP emissions
from the emission points covered under this rule are low relative to
organic HAP emissions. Emission points emitting inorganic HAP's are
included in a separate source category under a separate schedule.
Table 1.--Significant Hazardous Air Pollutants From Petroleum Refineries
[Hazardous Air Pollutant]
2,2,4-Trimethylpentane Methyl
tert
butyl
ether.
Benzene Naphthalen
e.
Cresols/cresylic acid Phenol.
Ethylbenzene Toluene.
Hexane Xylenes.
Methyl ethyl ketone
The catalytic cracking unit catalyst regeneration vent emits
primarily metal HAP's, which would be controlled using particulate
controls. Catalytic reformer catalyst regeneration vents emit hydrogen
chloride, and sulfur plant vents emit carbonyl sulfide and carbon
disulfide. Because of these compounds' unique characteristics, the EPA
concluded that these emission points warranted separate consideration
for control of inorganic HAP's. Because limited data are currently
available, these emission points are included in a separate source
category under a separate schedule.
The Regulatory Impacts Analysis (RIA) presents the results of an
examination of the potential health and welfare benefits associated
with air emission reductions projected as a result of implementation of
the petroleum refinery NESHAP. Of the pollutants emitted by petroleum
refineries, some are classified as VOC, which are ozone precursors.
Benefits from HAP emission reductions are presented separately from the
benefits associated specifically with VOC emission reductions.
The predicted emissions of a few HAP's associated with this
regulation have been classified as possible, probable, or known human
carcinogens. Benzene and cresols are the two HAP's identified as
carcinogens.
Benzene is classified as a class A or a known human carcinogen.
Benzene is a concern to the EPA because long term exposure to this
chemical causes an increased risk of cancer in humans, and is also
associated with aplastic anemia, pancytopenia, chromosomal breakages,
and weakening of the bone marrow.
Cresols are classified as class C or possible human carcinogens.
For this HAP, there is either inadequate data or no data on human
carcinogenicity. Therefore, while cancer risk is a possibility, there
is not sufficient evidence to quantify the increased cancer risk to
humans caused by these chemicals.
There are serious health effects reported from exposure to some of
the noncarcinogenic HAP's. These serious health effects typically occur
at higher levels of exposure than estimated for the regulatory
baseline. Exposure to phenol is very toxic to animals and increases
mortality, but there is little human data. Exposure to n-hexane can
cause polyneuropathy (muscle weakness and numbness) in humans, and
exposure to naphthalene is linked to cataracts and anemia in human
infants. It is also possible that there are less serious health effects
in the regulatory baseline from exposure to these HAP's.
Emissions of VOC have been associated with a variety of health and
welfare impacts. Volatile organic compound emissions, together with
nitrogen oxides (NOX), are precursors to the formation of
tropospheric ozone. Exposure to ambient ozone is responsible for a
series of health impacts, such as alterations in lung capacity; eye,
nose, and throat irritation; malaise and nausea; and aggravation of
existing respiratory disease. Among the welfare impacts from exposure
to ambient ozone include damage to selected commercial timber species
and economic losses for commercially valuable crops such as soybeans
and cotton.
Based on existing data, the benefits associated with reduced HAP
and VOC emissions were quantified. The quantification of dollar
benefits for all benefit categories is not possible at this time
because of limitations in both data and available methodologies.
Although an estimate of the total reduction in HAP emissions for
various regulatory alternatives has been developed for the RIA, it has
not been possible to identify the speciation of the HAP emission
reductions for each type of emission point. However, an estimate of HAP
speciation for equipment leaks has been made. Using emissions data for
equipment leaks and the Human Exposure Model (version 1), the annual
cancer risk caused by HAP emissions from petroleum refineries was
estimated. Generally, this benefit category is calculated as the
difference in estimated annual cancer incidence before and after
implementation of each regulatory alternative. Since the annual cancer
incidence associated with baseline conditions was less than one life
per year, the cancer benefits associated with HAP reductions for the
petroleum refinery NESHAP were determined to be low. Therefore, these
quantified benefits are not part of the overall quantified benefits
estimate for the analysis.
The benefits of reduced emissions of VOC from a MACT regulation of
petroleum refineries were quantified using the technique of ``benefits
transfer.'' Because analysis by the Office of Technology Assessment
from which benefits transfer values were obtained only estimated acute
health benefits in ozone nonattainment areas, the transfer values can
be applied to VOC reductions occurring only in ozone nonattainment
areas. The range of benefit transfer values used in this analysis is
from $25 to $1,574 per megagram (Mg) ($23 to $1,431 per ton) of VOC
with an average of $800/Mg ($727/ton) of VOC.
In order to quantify benefits from VOC emission reductions, the
average value is multiplied by VOC emission reductions from petroleum
refineries in ozone nonattainment areas. Estimated annual benefits for
VOC reductions are $108.8 million for selected regulatory alternatives.
The quantified annual
[[Page 43246]]
benefits exceed annual compliance costs by $29.8 million (1992
dollars).
The promulgated NESHAP will reduce HAP emissions from petroleum
refineries by 59 percent. Table 2 presents the national baseline
emissions and emission reductions for petroleum refinery process vents,
storage vessels, wastewater, and equipment leaks. The emissions
reductions for controlling gasoline loading racks and the marine vessel
loading emission points are discussed in supporting material for the
Gasoline Distribution (Stage I) and the Marine Vessel Loading
Operations rules.
Table 2.--National Primary Air Pollution Impact in the Fifth Year
----------------------------------------------------------------------------------------------------------------
Baseline emissions (Mg/ Emission reductions
yr) ---------------------------------------------------
Source -------------------------- (Mg/yr) (Percent)
---------------------------------------------------
HAP VOC HAP VOC HAP VOC
----------------------------------------------------------------------------------------------------------------
Miscellaneous process vents....... 10,000 109,000 6,700 85,000 67 78
Equipment leaks................... 52,000 189,000 40,000 146,000 77 77
Storage vessels................... 9,300 111,000 1,300 21,000 14 19
Wastewater collection and
treatment........................ 10,000 10,000 (a) (a) (a) (a)
-----------------------------------------------------------------------------
Total....................... 81,300 419,000 48,000 252,000 59 60
----------------------------------------------------------------------------------------------------------------
a The MACT level of control is no additional control.
B. Technical Basis of Regulation
National emission standards for major sources of HAP's established
under section 112 of the Act reflect MACT or:
* * * the maximum degree of reduction in emissions of the HAP *
* * that the Administrator, taking into consideration the cost of
achieving such emission reduction, and any nonair quality health and
environmental impacts and energy requirements, determine is
achievable for new or existing sources in the category or
subcategory to which such emission standard applies * * * (the Act
section 112(d)(2)).
Prior to proposal, section 114 questionnaires, information
collection requests (ICR's), and telephone surveys were used to obtain
information on emissions, emissions control, and emissions control
costs for petroleum refinery emission points. Section 114
questionnaires were sent out to nine large refineries, of approximately
130 existing petroleum refineries nationally, to obtain emissions and
emissions control information for equipment leaks, wastewater, process
vents, and storage vessel emission points located in a petroleum
refinery. The ICR's were sent out to the refineries that were not sent
section 114 questionnaires to obtain information on emissions control
equipment and emissions for process vents, storage vessels, and
equipment leaks emission points. A telephone survey of equipment
vendors was conducted to obtain leak detection and repair (LDAR) cost
information.
Data and information were received for approximately 130 petroleum
refineries. This information was used, in part, as the technical basis
in determining the MACT level of control for the process units covered
under this rule. In addition to information collected from industry,
the EPA used information on refinery locations and processes available
in the general literature. The EPA also used control technology
performance and cost information developed under previous rulemakings
for the petroleum and chemical industries, such as the petroleum
refinery new source performance standard (NSPS), benzene NESHAP, and
synthetic organic chemical manufacturing industry (SOCMI) standards.
The EPA also considered existing State regulations and additional
information received during the public comment period for the proposed
rule in developing the final rule.
C. Stakeholder and Public Participation
In the development of this rule, numerous representatives of the
petroleum refinery industry were consulted prior to proposal. Industry
representatives have included trade associations, and refiners
responding to section 114 questionnaires, ICR's, and telephone surveys.
Representatives from State agencies and the EPA regions were also
consulted and participated in the development of the rule.
The standards were proposed and published in the Federal Register
on July 15, 1994 (59 FR 36130). The preamble to the proposed standard
describes the rationale for the proposed rule. Public comments were
solicited at the time of proposal.
To provide interested persons the opportunity for oral presentation
of data, views, or arguments concerning the proposed standards, a
public hearing was offered at proposal. A public hearing was held in
Research Triangle Park, North Carolina, on August 5, 1994. The hearing
was open to the public and four persons presented oral testimony. The
public comment period was from July 15, 1994 to September 13, 1994.
Sixty-two comment letters were received. Commenters included industry
representatives, States, environmental organizations, and others. The
comments have been carefully considered, and changes have been made in
the proposed standards when determined by the Administrator to be
appropriate. A detailed discussion of these comments and responses can
be found in the Response of Comment Document, which is referenced in
the ADDRESSES section of this preamble. The summary of comments and
responses in the document serve as the basis for the revisions that
have been made to the standards between proposal and promulgation.
Section V of this preamble discusses the major comments that resulted
in changes to the standards.
III. Summary of Promulgated Standards
The promulgated standard applies to petroleum refining process
units as well as other colocated emission points that are part of a
plant site that is a major source as defined in section 112 of the Act.
The determination of potential to emit, and therefore major source
status, is based on the total of all HAP emissions from all activities
at the plant site. The applicability section of the regulation
specifies what is included in the petroleum refining source category
and defines the sources regulated by the NESHAP.
The general standards consist of compliance dates for new and
existing sources, require sources to be properly operated and
maintained at all times, and clarify the applicability of the NESHAP
General Provisions (40 Code of Federal Regulations (CFR) part 63,
subpart A) to sources subject to subpart CC.
[[Page 43247]]
The affected source comprises the miscellaneous process vents,
storage vessels, wastewater streams, and equipment leaks associated
with petroleum refining process units, and marine tank vessel loading
operations and gasoline loading racks classified under SIC code 2911
located at a refinery. The inclusion of marine tank vessel loading
operations and gasoline loading racks in the definition of the
petroleum refinery affected source and source category is a revision
from the proposal. These emission points have been included as part of
the petroleum refinery affected source and source category to permit an
owner or operator of a petroleum refinery to average emissions among
emission points collocated at the refinery to comply with the
standards. These standards do not apply to distillation units located
at pipeline pumping stations whose primary purpose is to produce fuel
to operate turbines and internal combustion engines at the pipeline
pumping stations. A summary of the specific provisions that apply to
each of the emission points contained within a petroleum refinery
affected source follows. All of the specified provisions for each of
the covered emission points allow for, or are based on and encourage,
pollution prevention.
These standards do not address three vents that will be subject to
future NESHAP standards. These are the catalyst regeneration vents on
catalytic cracking units and catalytic reforming units (CRU's) and
vents from sulfur recovery units (SRU's). Industry is concerned that
standards for these three vents will require the use of control
technologies designed to reduce non-HAP emissions and will preclude the
use of alternatives that can achieve comparable HAP control at a lower
cost. The EPA recognizes that standards should be structured on a
performance basis wherever possible to ensure that industry is provided
the flexibility to seek out and implement cost-effective controls. The
EPA's existing standards for sulfur dioxide and particular matter
emissions from new FCCU catalyst regenerator vents demonstrate such
recognition. The allowable emissions were expressed in terms of the
amount of coke burned off the catalyst in order to provide industry
with the flexibility to comply through operational changes or through
traditional end-of-pipe controls or a combination of the two. The EPA
has every intention to ensure that future rules also provide similar
flexibility.
A. Miscellaneous Process Vent Provisions
Miscellaneous process vents include vents from petroleum refining
process units that emit organic HAP's. Vents that are routed to the
refinery fuel gas system are considered to be part of the process and
are not subject to the standard. The miscellaneous process vent
provisions define two groups of vents. Group 1 process vents are those
with VOC emissions greater than or equal to 33 kilograms per day (kg/
day) (72 pounds per day (lb/day)) for existing sources and 6.8 kg/day
(15 lb/day) for new sources. Group 2 vents are vents with emissions
below these levels.
The miscellaneous process vent provisions for new and existing
sources require the owner or operator of a Group 1 miscellaneous
process vent to reduce organic HAP emissions by 98 percent or to less
than 20 parts per million by volume (ppmv), or to reduce emissions
using a flare meeting the requirements of Sec. 63.11(b) of the NESHAP
General Provisions (40 CFR part 63, subpart A).
Monitoring requirements for Group 1 vents include an initial
performance demonstration and monitoring of control device operating
parameters. The owner could also comply by reducing emissions from a
Group 1 process vent to less than 33 kg/day (72 lb/day) for existing
sources and 6.8 kg/day (15 day) for new sources, thereby converting it
to a Group 2 process vent. No controls or monitoring are required for
Group 2 process vents.
B. Storage Vessel Provisions
The storage vessel provisions define two groups of vessels: Group 1
vessels are vessels with a design storage capacity and a maximum true
vapor pressure above the values specified in the regulation. Group 2
vessels are all storage vessels that are not Group 1 vessels. The
storage vessel provisions require that one of the following control
systems be applied to Group 1 storage vessels: (1) An internal floating
roof (IFR) with proper seals; (2) an external floating roof (EFR) with
proper seals; (3) an EFR converted to an IFR with proper seals; or (4)
a closed vent system to a control device that reduces HAP emissions by
95 percent or to 20 ppmv. The storage provisions give details on the
type of seals required. Monitoring and compliance provisions for Group
1 vessels include periodic external visual inspections of vessels and
roof seals, as well as less frequent internal inspections. If a closed
vent system and control device is used for venting emissions from Group
1 storage vessels, the owner or operator must establish appropriate
monitoring procedures. No controls or inspections are required for
Group 2 storage vessels.
For existing sources, the final rule requires that fixed roof tanks
with capacities greater than or equal to 177 cubic meters (m3)
(47,000 gallons (gal)) that store liquids containing more than 4
percent organic HAP with vapor pressures greater than 10.4 kilopascals
(kPa) (1.5 pounds per square inch absolute (psia)) comply fully with
the rule within 3 years. If an owner or operator must replace an
existing fixed roof tank in order to comply with the rule, it would be
reasonable for the State to grant an additional year to comply as
authorized under section 112(i)(3)(B) of the Act (a total of four
years). This additional time would allow time to design and construct
tanks without disrupting refinery operations that could create
additional emissions. Owners or operators of IFR or EFR tanks are
allowed to defer upgrading of their seals to meet the NESHAP
requirements until the next scheduled inspection and maintenance
activity or within 10 years, whichever comes first.
For new sources, the final rule requires that vessels with
capacities greater than or equal to 151 m3 (40,000 gal), that
store liquids containing more than 2 percent organic HAP with vapor
pressures equal to or greater than 3.4 kPa (0.5 psia), and vessels with
capacities equal to or greater than 76 m3 (20,000 gal) storing
liquids containing more than 2 percent organic HAP with vapor pressures
equal to or greater than 77 kPa (11.1 psia) comply with the level of
control required by 40 CFR part 63, subpart G (including the controlled
fitting requirements).
C. Wastewater Provisions
The wastewater provisions define two groups of wastewater streams.
Group 1 streams are those that are located at a refinery with a total
annual benzene loading of at least 10 megagrams per year (Mg/yr) (11
tpy) and are not exempt from control requirements under 40 CFR part 61,
subpart FF (the benzene waste operations NESHAP or BWON). In general,
streams are not exempt from 40 CFR part 61 subpart FF if they contain a
concentration of at least 10 parts per million by weight (ppmw)
benzene, and have a flow rate of at least 0.02 liters per minute (L/
min) (0.005 gallons per minute (gal/min)). Group 2 streams are
wastewater streams that are not Group 1.
The wastewater provisions of the final rule refer to the BWON for
both new and existing sources, which requires owners or operators of a
Group 1 wastewater stream to reduce benzene
[[Page 43248]]
mass emissions by 99 percent using suppression followed by steam
stripping, biotreatment, or other treatment processes. Vents from steam
strippers and other waste management or treatment units are required to
be controlled by a control device achieving 95 percent emissions
reduction or 20 ppmv at the outlet of the control device. The
performance tests, monitoring, reporting, and recordkeeping provisions
required to demonstrate compliance are included in the BWON. No
controls or monitoring are required for Group 2 wastewater streams.
D. Equipment Leak Provisions
The equipment leak standards for the petroleum refinery NESHAP
allow owners or operators of existing sources to choose between
complying with equipment leaks provisions in 40 CFR part 60, subpart VV
(NSPS for Equipment Leaks) or complying with a modified negotiated
regulation for equipment leaks presented in 40 CFR part 63, subpart H
(Hazardous Organic NESHAP or HON equipment leaks). The differences in
the NSPS equipment leak requirements and the HON equipment leak
requirements are in the leak definitions and connector monitoring
provisions.
Under either of the two options, existing refineries subject to the
rule will be required to implement a LDAR program with the same leak
definitions (10,000 parts per million (ppm)) and frequencies as
specified in 40 CFR part 60, subpart VV within 3 years after
promulgation of the petroleum refineries NESHAP. Refineries that choose
to comply with the modified negotiated regulation would implement the
Phase II leak definitions and frequencies at the end of the fourth
year, and comply with Phase III requirements 5\1/2\ years after
promulgation. Phase III defines a leak at a lower level, but allows
less frequent monitoring for good performers. Although the modified
negotiated regulation is not required in the final rule, the EPA
believes that it would provide greater emission reductions and, in many
cases, would be more cost effective than 40 CFR part 60, subpart VV and
could even provide cost savings. Cost savings would occur because it
would reduce equipment leak product loss, and facilities with a low
percentage of leaking valves would be able to monitor less frequently,
thereby reducing monitoring costs.
New sources must comply at startup with the modified negotiated
regulation; pumps and valves at new sources must be in compliance with
the Phase II requirements at startup rather than Phase I. This is
consistent with the negotiated rule (40 CFR part 63, subpart H).
E. Marine Tank Vessel Loading and Gasoline Loading Rack Provisions
The final refineries NESHAP requires marine tank vessel loading
operations at refineries to comply with the marine loading NESHAP (40
CFR part 63, subpart Y) unless they are included in an emissions
average. Gasoline loading racks classified under SIC code 2911 at
refineries are required to comply with the 40 CFR part 63, subpart R
loading rack provisions unless they are included in an emissions
average.
F. Recordkeeping and Reporting Provisions
The final rule requires that petroleum refineries subject to 40 CFR
part 63, subpart CC maintain required records for a period of at least
5 years. The final rule requires that the following reports be
submitted: (1) A Notification of compliance status report, (2) periodic
reports, and (3) other reports (e.g., notifications of storage vessel
internal inspections; startup, shutdown, and malfunction reports).
G. Emissions Averaging
The EPA is allowing emissions averaging among existing
miscellaneous process vents, storage vessels, wastewater streams,
marine tank vessel loading operations, and gasoline loading racks
classified under SIC code 2911 located at a refinery. New sources are
not allowed to use emissions averaging. Under emissions averaging, a
system of emission ``credits'' and ``debits'' is allowed to determine
whether a source is achieving the required emission reductions.
IV. Summary of Impacts
The impacts presented in this section include process vents,
storage vessels, equipment leaks, and wastewater streams from petroleum
refinery process units. Impacts for control of marine tank vessel
loading operations and gasoline loading rack operations classified
under SIC code 2911 located at refineries are presented in the
background documentation for 40 CFR part 63, subparts Y and R.
These standards will reduce nationwide emissions of HAP from
petroleum refineries by 48,000 Mg/yr (53,000 tpy), or 59 percent by
1998 compared to the emissions that would result in the absence of
standards. No adverse secondary air impacts, water or solid waste
impacts are anticipated from the promulgation of these standards.
The national electric usage required to comply with the rule is
expected to increase by 48 million kilowatt-hours per year, which is
equivalent to approximately 77,500 barrels of oil.
The implementation of this regulation is expected to result in an
overall annual national cost of $79 million. This includes a cost of
$59 million from operation of control devices, and a monitoring,
recordkeeping, and reporting cost of $20 million. The monitoring,
reporting, and recordkeeping cost has been reduced by 25 percent from
proposal. Table 3 presents the national control cost impacts for
petroleum refinery process vents, storage vessels, wastewater, and
equipment leaks. The control costs for gasoline loading racks and
marine tank vessel loading operations are discussed in supporting
material for the Gasoline Distribution (Stage I) and the Marine Vessel
Loading Operations rules.
Table 3.--National Control Cost Impacts in the Fifth Year
----------------------------------------------------------------------------------------------------------------
Average HAP Average VOC
Total a Total a annual cost cost
Source capital costs costs ($10 \6\/ effectiveness effectiveness
b ($10 \6\) yr) ($/Mg HAP) ($/Mg VOC)
----------------------------------------------------------------------------------------------------------------
Miscellaneous process vents..................... 21 (2) 12 (1) 1,800 140
Equipment leaks................................. 142 (16) 58 (17) 1,500 400
Storage vessels................................. 48 (1) 8 (1) 6,100 380
Wastewater collection and treatment............. (c) (c) (c) (c)
Other recordkeeping and reporting............... 2 1 (d) (d)
---------------------------------------------------------------
[[Page 43249]]
Total..................................... 213 (21) 79 (20) 1,600 310
----------------------------------------------------------------------------------------------------------------
a Numbers in parentheses are recordkeeping and reporting costs included in total annual cost and total capital
cost estimates. For equipment leaks, activities associated with setting up and operating a LDAR program (e.g.,
tagging and identifying, monitoring, data entry, setting up a data management system, etc.) are not reflected
in the equipment leak recordkeeping and reporting costs, but are included in the equipment leak total annual
cost and total capital cost estimate.
b Total capital costs incurred in the 5-year period.
c The MACT level of control is no additional control.
d Not applicable.
The EPA estimates that changes in the compliance times for storage
vessels with floating roofs and changes to the process vents Group 1
applicability cutoff will provide substantial cost savings and
emissions reductions for refineries. Estimates of degassing and
cleaning storage tank costs provided by the refining industry indicate
that premature (within 3 years of promulgation) degassing and cleaning
activities would cost between $34,000 and $213,000 per floating roof
tank depending on the type of material stored. If extrapolated to the
entire refining industry for floating roof tanks, the cost savings from
allowing floating roofs to comply at the next scheduled maintenance
would be $6.6 million per year.
The EPA determined that substantial HAP emissions occur when
storage vessels are degassed and cleaned. Typically, storage vessels
are inspected and maintained on a 10-year schedule, at which time tanks
are degassed and cleaned. If a 3-year compliance schedule were
required, storage vessels would be degassed and cleaned prematurely,
resulting in substantial HAP emissions caused by the rule. These HAP
emissions could not be balanced in less than 5 years for floating roof
tanks by the emission reduction achieved from complying with the rule.
By changing the proposed rule to allow floating roof tanks to comply
with the storage vessel requirements 10 years after promulgation of the
rule or at the next scheduled inspection, the EPA estimates that 3,000
Mg/yr (2,700 tpy) of HAP, or 8,000 Mg (7,200 tpy) of HAP over 3 years,
would be prevented from being emitted.
The existing source process vent applicability cutoff (33 kg of
VOC/day (72 lb of VOC/day) per vent) will exclude 3,000 vents from
requiring control at a total annual cost savings of $4.5 million. The
new source process vent applicability cutoff (7 kg of VOC/day (15 lb of
VOC/day) per vent) will exclude 35 vents from requiring control at a
total annual cost savings of $25,000. The total annual cost reduction
of these changes in the rule is a reduction of approximately $11
million.
The economic impact analysis for the selected regulatory
alternatives shows that the estimated price increases for affected
products range from 0.24 percent for residual fuel oil to 0.53 percent
for jet fuel. Estimated decreases in product output range from 0.13
percent for jet fuel to 0.50 percent for residual fuel oil. Annual net
exports (exports minus imports) are predicted to decrease by 2.3
million barrels, with the range of reductions varying from 0.21 million
barrels for liquid petroleum gas to 0.91 million barrels for residual
fuel oil.
Between zero and seven refineries, all of which are classified as
small, may close due to the regulation. For more information, consult
the ``Economic Impact Analysis for the Petroleum Refinery NESHAP'' in
the docket (see ADDRESSES section of this preamble).
V. Significant Comments and Changes to the Proposed Standards
In response to comments received on the proposed standards, several
changes have been made to the final rule. While several of these
changes are clarifications designed to make the Agency's intent
clearer, a number of them are significant changes to the proposed
standard requirements. A summary of the substantive comments and/or
changes made since the proposal are described in the following
sections. Detailed Agency responses to public comments and the revised
analysis for the final rule are contained in the BID and docket (see
ADDRESSES section of this preamble).
A. Process Vents Group Determination
The proposed NESHAP would have required control of all
miscellaneous process vents with HAP concentrations over 20 ppmv. This
level was based on the fact that combustion control technologies can
reduce organic emissions by 98 percent or to 20 ppmv, but cannot
necessarily achieve lower concentrations. Several commenters suggested
that other applicability criteria were needed to determine which
process vents are required to apply control. They pointed out that the
HON and State regulations use a total resource effectiveness (TRE) or
emission rate cutoff to exclude small vents that have low emission
potential and high costs from control requirements. The commenters
contended that the MACT floor does not include control of such vents.
In response to these comments, the EPA examined potential control
applicability criteria. The EPA reevaluated the miscellaneous process
vents data base. The EPA's information on miscellaneous process vent
streams was insufficient to establish an emission rate cutoff. This was
because industry did not have sufficient information on the HAP and VOC
content of vent streams requested by the section 114 questionnaires and
ICR's and it would have been impractical to obtain this information.
Therefore, as suggested by a number of commenters, and after
consultations with industry and others, the EPA decided to use State
regulations.
The EPA evaluated the current level of control for miscellaneous
process vents in eight States and two air districts that contain the
majority of refineries and were expected to have the most stringent
regulations. Of the refineries in the United States, the 12 percent
that are subject to the most stringent regulations are located in three
States. In these three States, miscellaneous process vents emitting
greater than 6.8 to 45 kg/day (15 to 100 lb/day) of VOC are required to
be controlled. The median applicability cutoff level for the 12 percent
of U.S. refineries subject to the most stringent regulations is 33 kg/
day (72 lb/day VOC). Thus, control of vents with VOC emissions greater
than 33 kg/day (72 lb/day) is the MACT floor for existing sources and
6.8 kg/day (15 lb/day) is the
[[Page 43250]]
MACT floor level of control for new sources. The primary organic HAP's
at refineries are also VOC. Additionally, a VOC-based applicability
criteria is most reflective of the current level of control required
for miscellaneous process vents as the majority of State regulations
are expressed in terms of VOC. Therefore, the EPA has adopted these
emission levels in the final rule to distinguish Group 1 from Group 2
vents. Group 1 vents are those that emit over 33 kg/day (72 lb/day) for
existing sources and over 6.8 kg/day (15 lb/day) for new sources. Group
1 vents must be controlled, whereas Group 2 vents (which emit less than
33 kg/day (72 lb/day) for existing sources and less than 6.8 kg/day (15
lb/day) for new sources) are not required to apply controls under the
final rule. The 33 kg/day (72 lb/day) and 6.8 kg/day (15 lb/day)
applicability limits are to be determined as the gases exit from
process unit equipment (including any recovery devices) and prior to
any non-recovery emission control device.
B. Process Vent Impacts
At proposal, the EPA estimated that the baseline HAP and VOC
emissions from process vents were 9,800 Mg/yr (10,780 tpy) and 190,000
Mg/yr (209,000 tpy), respectively. Several commenters contended that
the impacts analysis for process vents should be redone because: (1)
The data base used in the analysis contained several errors, and (2)
the emission estimation methodology was incorrect. The commenters
asserted that these inaccuracies resulted in overestimates of
emissions. Some of the commenters asserted that the data base flaws
included: (1) A lack of data concerning the number, flowrates, and HAP
concentrations of miscellaneous process vents, and (2) an erroneously
high percentage of controlled vents because many uncontrolled vents
were not reported. Some of the commenters contended that the emission
estimation methodology was flawed because (1) It included wastewater
and maintenance emissions, (2) emission factors were calculated from a
HAP-to-VOC ratio that included reformer emissions, and (3) alkylation
emissions and crude unit emissions were based on one refinery where
vents were uncontrolled at the time of the questionnaire and are now
controlled.
The EPA agrees with the commenters that the process vents emission
impacts estimate has several assumptions that needed to be reanalyzed.
The EPA also agrees that the data base used at proposal should be
reevaluated to consider the commenters' concerns. Therefore, the EPA
has reestimated the emissions and cost impacts of the process vents
provisions using the commenters' recommendations.
The emissions at proposal were estimated using responses from only
the section 114 questionnaires extrapolated to the entire refining
industry. Because the section 114 questionnaires were sent to the
largest companies, the data obtained from them skewed the results based
on what the largest refineries did. The revised emissions were
estimated using data from both the section 114 and ICR responses. The
ICR questionnaires were sent to refineries not receiving the section
114 questionnaires. This additional data increased the number of vents
in the data base by 1,300. The increase in vents resulted in a decrease
in controlled vents from 40 percent to 24 percent. However, information
on the HAP and VOC content of vent streams remained limited as no new
data was provided by the ICR respondents. Additionally, no new HAP
information was provided by industry after proposal of the rule.
Additionally, errors in the data base were corrected and non-
miscellaneous process vents were removed from the data base (e.g.,
vents from wastewater, maintenance, catalytic reformer regeneration
vents, etc). In the revised emission estimates, emissions from
alkylation and crude units were estimated from a number of different
data points (not just one, as the commenters have stated).
Additionally, the one data point the commenters have referred to has
been changed to reflect the change in control status. The revised
baseline miscellaneous process vents HAP and VOC emissions are 10,000
Mg/yr (11,000 tpy) and 109,000 Mg/yr (119,900 tpy), respectively.
The EPA agrees that the data on HAP concentrations is limited.
However, no new data was supplied by the commenters. The EPA's revised
emission estimates are based on technically sound methods and the best
available information.
C. Equipment Leaks Compliance Requirements
The proposed rule for equipment leaks at existing sources was an
above-the-floor option modeled after the HON negotiated rule for
equipment leaks. The floor level of control for equipment leaks from
existing sources was determined to be control equal to the petroleum
refinery NSPS. The modified negotiated rule was chosen as an above-the-
floor option because it was estimated to be cost effective. The option
chosen in the proposed rule differed from the HON in that: (1) Existing
sources were not required to monitor connectors, and (2) the leak
definitions were higher to reflect the different volatility of
materials found in refinery process lines as opposed to SOCMI process
lines. The proposed rule required one-third of the refinery to be in
compliance 6 months after promulgation of the rule, two-thirds of the
refinery to be in compliance 1 year after promulgation of the rule, and
the entire refinery to be in compliance 18 months after promulgation of
the rule.
Several commenters contended that the emissions and cost
information used to determine the cost effectiveness of going from the
floor level of control to the modified negotiated rule were inaccurate
and did not consider recent changes to the equipment leak correlation
equations for petroleum refineries. The commenters concluded that using
the most recent information for refineries would show that it is not
cost effective to go beyond the floor level of control.
The cost information used in the analysis was the best data
available, and is based on surveys of vendors and established costs
presented in previous projects. No new cost information was submitted
by the industry. The equipment leak emission factors that are being
used to estimate the emissions and emission reductions of the rule were
developed in 1980. These are the only complete and accurate emission
factors available for this purpose. To accurately estimate emissions
from equipment leaks, two sets of information are needed. These include
the amount of emissions generated per piece of equipment leaking at a
given concentration and the percent of equipment that are actually
leaking at these concentrations. The 1980 study that was used to
estimate the impacts of the refinery MACT rule used a consistent
sampling methodology to address both of these factors based on sampling
at uncontrolled refineries. The 1993 API study developed new
information only on emissions per piece of leaking equipment using a
different methodology. As stated in API's report, this information was
developed from refineries in California for use with other information
to estimate facility-specific equipment leak emissions. Thus, this
study was not designed to provide information on industry average
percent leaking equipment. Therefore, it was not possible to redefine
average emission factors. To actually use this information, however,
the EPA would need corresponding new information on the percent of
equipment leaking. The EPA does not believe that it would be
appropriate to combine 1993
[[Page 43251]]
information with the 1980 data to develop new emission factors because
sampling methodologies were different and because the 1993 study
collected information from information from well-controlled facilities
while the 1980 study collected information from uncontrolled
facilities. However, the EPA agrees that new correlation equations
developed for the refining industry indicate that the refinery factors
may overestimate emissions by as much as a factor of two, which may
make the modified negotiated rule option less cost effective. This
cannot be accurately determined because the appropriate information to
update average emission factors is not available. The EPA recognizes
that enough uncertainty exists in the emission and cost estimates to
question the results of the cost-effectiveness analysis.
In recognition of this uncertainty and to provide compliance
flexibility, the EPA has changed the final rule to provide each
existing refinery with a choice of complying with either: (1) The
equipment leaks NSPS requirements (40 CFR part 60, subpart VV) or (2) a
modified version of the negotiated rule (40 CFR part 63, subpart H).
The NSPS represents the MACT floor for existing sources. The modified
negotiated regulation is the same as what was contained in the proposed
petroleum refinery NESHAP except that the compliance dates have been
extended for reasons described below. Although not required in the
final rule, the EPA promotes use of the modified negotiated rule option
because it is believed to provide considerable product, emissions, and
cost savings to a refinery.
Under either option, existing refineries will be required to
implement an LDAR program with the same leak definitions (10,000 ppm)
and the same leak frequencies as contained in the NSPS by 3 years after
promulgation. A refinery may opt to remain at this level of control and
do the monitoring, recordkeeping, and reporting specified in the NSPS.
This option allows refineries that are familiar with the NSPS to
continue to implement that standard without needing to change their
procedures.
Alternatively, a refinery may choose to comply with Phase I of the
negotiated rule (10,000 ppm leak definition) 3 years after
promulgation, comply with Phase II 4 years after promulgation, and
comply with Phase III 5\1/2\ years after promulgation. Each phase has
lower leak definitions for pumps and valves. In Phase III, monitoring
frequencies for valves are dependent on performance (percent leakers),
providing an incentive (less frequent monitoring and reduced monitoring
costs) for good performance. Refineries choosing to comply with the
modified negotiated rule are subject to monitoring, recordkeeping, and
reporting requirements of subpart H. The EPA has included this
compliance alternative to add flexibility and opportunities for
adjustment for differences among facilities.
The compliance dates for equipment leaks were revised to address
commenter concerns that contended that small refineries and refineries
in ozone attainment areas would be at a disadvantage if they were
required to comply with the proposed equipment leak regulations because
they would not have the experience to implement an equipment leaks
control program within 6 to 18 months.
The EPA agrees that small refineries may not have the experience to
implement an LDAR program for equipment leaks in a short timeframe
without significant expense. The EPA also contends that other
refineries that do not currently have LDAR programs may also have
trouble implementing the rule in 6 to 18 months. In response to these
comments, the EPA has changed the final rule to require that existing
refineries, regardless of size, comply with an LDAR program with the
same leak definitions (10,000 ppm) and monitoring frequencies as the
petroleum refinery NSPS within 3 years of promulgation of the rule. At
the end of the third year, the entire refinery must be in compliance
with the petroleum refinery NSPS level of control; there will not be
interim deadlines during the 3-year period by which portions of the
refinery are required to comply during this time. A refinery owner or
operator who chooses to comply with the modified negotiated rule must
then implement Phase II within 4 years and Phase III within 5\1/2\
years of promulgation. The total annual cost estimates for the rule
have been revised in accordance with the changes made to the equipment
leak requirements.
D. Storage Vessels
The proposed rule required existing storage vessels containing
liquids with vapor pressures greater than or equal to 8 kPa (1.2 psia)
to comply with storage vessel requirements within 3 years. For tanks
that were already controlled with internal or external floating roofs,
the proposed rule allowed operators to defer upgrading of seals until
the next scheduled maintenance with the following exceptions: (1) Fixed
roof tanks, (2) EFR tanks with only a vapor-mounted primary seal, and
(3) all tanks storing a liquid with a true vapor pressure greater than
34 kPa (5.0 psia).
Commenters to the proposed rule maintained that before additional
emission controls (e.g., secondary seals) can be installed, tanks must
be removed from service, degassed, and cleaned. Storage tanks are
currently emptied and cleaned roughly every 10 years for inspection and
maintenance. The commenters contended that removing storage tanks that
already have floating roofs from service before scheduled maintenance
would have adverse environmental impacts that could not be overcome by
the emissions reductions from upgrading the seals on the tank. The
commenters further stated that tank owners or operators would incur
substantial costs as a result of degassing and cleaning a tank before
scheduled maintenance. The commenters contended that a 3-year
compliance schedule could not be met because there would not be enough
trained and capable fabricators and contractors to support the tank
modification work. Commenters stated that the reason was that the
refinery rule compliance period overlaps with the implementation of
other EPA rules and that a 10-year compliance schedule would be
consistent with other EPA rulemakings such as the HON and the benzene
storage NESHAP.
The EPA agrees with the commenters that the HON and the benzene
storage NESHAP allow floating roof tanks to achieve compliance in 10
years or at the time of the next scheduled degassing. Most existing
floating roof storage vessels at refineries also fall under the 10-year
compliance schedule. Therefore, these storage vessels will be inspected
within 5 to 10 years after promulgation of the rule. This is consistent
with industry practice.
In response to these comments, the EPA analyzed the emissions
resulting from degassing and cleaning storage vessels using empirical
mass-transfer models. The analysis indicated that degassing and
cleaning of floating roof vessels generally results in substantial
volatilization of HAP's to the air. These emissions could not be
balanced in less than 5 years by the emission reductions achieved by
controlling the tank to the requirements in the rule. Additionally, the
degassing and cleaning information submitted by the refining industry
indicated substantial costs for each degassing and cleaning activity if
required within 3 years after promulgation of the rule. Based on
information provided by industry and the EPA's empirical analysis, the
EPA determined that the proposed storage vessel provisions would, in
many cases,
[[Page 43252]]
result in increased overall emissions because of the extra degassing
emissions.
The final rule allows owners or operators of storage vessels
subject to the rule to defer installation of better seals on floating
roof tanks storing any liquid until the next scheduled maintenance or
within 10 years, whichever comes first. This change addresses the
commenters' concerns about emissions and costs as well as their concern
about the availability of trained fabricators and contractors to modify
the tanks within a 3-year period. The final rule maintains the
requirement to retrofit IFR tanks at existing sources with secondary
seals that meet 40 CFR part 60 subpart Kb requirements because it is
the MACT floor for IFR vessels.
Based on the EPA's analysis, the emissions from degassing and
cleaning fixed roof tanks can be balanced within 1 year (justifying a
3-year compliance date) by the emission reductions achieved by
controlling the tank to the requirements in the rule. Therefore, the
final rule maintains the proposed compliance times (within 3 years) for
fixed roof tanks. The EPA believes that in certain situations, such as
when replacement of a tank is required, it would be reasonable for
States to grant an additional year to comply as authorized under
section 112(i)(3)(B) of the Act. The additional year would provide time
to design and construct the tanks without disrupting refinery
operations which could cause additional emissions. The EPA will work
with the industry and States to find ways to use the emissions
averaging program to deal with cases where tanks have to replaced or
where it is extremely difficult or costly to install the required
controls.
Several commenters contended that the Group 1 definition of 8 kPa
(1.2 psia) in the proposed NESHAP was based on data requests in section
114 and ICR questionnaires that were misinterpreted by respondents. The
commenters stated that the questionnaires did not specify whether
respondents were to provide maximum true vapor pressures or average
annual true vapor pressures. The commenters elaborated that because
other data were provided to estimate emissions on an annual basis, it
was reasonable to assume that respondents provided average annual true
vapor pressures instead of maximum true vapor pressures. The commenters
concluded that vapor pressures based on the maximum monthly
temperatures may be 0.3 psia higher than the average annual true vapor
pressure. The commenters recommended that the EPA either change the
applicability cutoff to 10 kPa (1.5 psia) maximum true vapor pressure
to account for this difference or specify that the 8 kPa (1.2 psia)
cutoff is the average annual true vapor pressure instead of the maximum
true vapor pressure.
The EPA agrees with the commenters that because the questionnaires
did not specify the type of vapor pressure, the respondents may have
provided annual average true vapor pressures instead of maximum true
vapor pressures. In order to reflect the uncertainty of the type of
vapor pressure provided in the questionnaires, the EPA has decided to
change the storage vessel applicability cutoff in the final rule from a
maximum true vapor pressure of 8 kPa (1.2 psia) to 10 kPa (1.5 psia).
An analysis of the storage vessel data base indicated that a change
from 8.3 kPa (1.2 psia) to 10 kPa (1.5 psia) will not affect the
impacts analysis.
Several commenters requested that a minimum HAP content be
considered as well as a vapor pressure cut-off for storage vessels
because some liquids may have very low HAP concentrations and high
vapor pressures due to the volatility of non-HAP compounds in the
material. The EPA agrees that several products, such as asphalt, have
minimal HAP's that may have vapor pressures greater than 10 kPa (1.5
psia) if stored at elevated temperatures. To determine HAP weight
percent applicability criteria, the EPA reviewed the MACT floor
analysis for storage vessels to determine the HAP weight percents in
controlled storage vessels at the best-controlled sources. The MACT
floor for new sources is based on the best-controlled source, while the
floor for existing sources is the average of the best-controlled 12
percent of sources (or 16 refineries). The HAP weight percent
applicability criterion was determined using the same population of
storage tanks used to determine the vapor pressure applicability cut-
off (i.e., the best-controlled 16 refineries). The minimum HAP
concentrations for materials stored in the tanks meeting subpart Kb at
the 16 best-controlled sources ranged from 2 weight percent to 22
weight percent. The average HAP weight percent in the liquids stored in
these tanks is 4 percent. The best-controlled tanks contain liquids
with a HAP weight percent in the liquid of 2 percent. Therefore, the
HAP weight percent criterion for existing sources is 4 percent HAP in
the liquid; the HAP weight percent for new sources is 2 percent HAP in
the liquid.
E. Overlapping Regulations
Several commenters contended that the petroleum refinery NESHAP
will lead to overlap with other existing and future regulations such as
the 40 CFR part 60 NSPS, 40 CFR parts 61 and 63 NESHAP, and State and
local regulations. Commenters stated that the overlap between
regulations will lead to confusion, uncertainty, and frustration for
sources and regulators.
The EPA has clarified the applicability of subpart CC as it relates
to other NSPS and parts 61 and 63 NESHAP that apply to the same source
in Sec. 63.640 of the final rule.
The final rule clarifies the applicability of 40 CFR part 63,
subpart CC storage vessel provisions to storage vessels at existing and
new petroleum refinery sources subject to 40 CFR part 60, subparts K,
Ka, or Kb. The specific provisions are structured such that each vessel
is subject to only the more stringent rule. For example, a Group 1
storage vessel at an existing refinery that is also subject to subpart
K or Ka is required only to comply with the petroleum refinery NESHAP
storage vessel provisions.
The final rule clarifies the applicability of 40 CFR part 63,
subpart CC wastewater provisions by stating that a Group 1 wastewater
stream managed in a piece of equipment that is also subject to the
provisions of 40 CFR part 60, subpart QQQ is required only to comply
with 40 CFR part 63, subpart CC. The final rule also clarifies that a
Group 2 wastewater stream managed in equipment that is also subject to
the provisions of 40 CFR part 60, subpart QQQ is required only to
comply with subpart QQQ. Clarification of the applicable provisions for
a wastewater stream that is conveyed, stored, or treated in a
wastewater stream management unit that also receives streams subject to
the provisions of 40 CFR part 63, subpart F has been included in the
final rule.
There should not be any process vent applicability overlap between
subpart CC and any other Federal rule. Process vents regulated under
the HON are not subject to the petroleum refinery NESHAP.
The EPA clarifies the applicability of subpart CC equipment leak
provisions in the final rule by stating that petroleum refinery sources
subject to subpart CC and 40 CFR parts 60 or 61 equipment leaks
regulations are required to comply only with the petroleum refinery
NESHAP (40 CFR part 63, subpart CC) equipment leak provisions.
[[Page 43253]]
The EPA has also included a Standard Industrial Classification
(SIC) code definition for petroleum refining (2911) to the petroleum
refinery process units definition in the final rule in order to clarify
which provisions of the rule apply to storage vessels and equipment
leaks. The EPA believes that the inclusion of the SIC code reference in
the definition of refinery process unit will alleviate confusion about
applicability of this rule (reducing potential confusion regarding
process unit regulatory overlap) and other source categories scheduled
for the development of NESHAP under the Act. The EPA has also added a
list of pollutants covered under the rule to assist facilities in the
determination of whether emission points are covered under the rule.
Another issue raised by several commenters was the potential for
overlap between the petroleum refinery MACT and other MACT standards
such as the HON. These commenters requested that the EPA clarify the
distinction between process units subject to the HON or other MACT
standards and process units subject to the petroleum refinery MACT
standard. These commenters thought that the description of refinery
process units was too general and could include chemical processes
subject to the HON or other MACT standards.
The final rule provides that 40 CFR part 63, subpart CC does not
apply to units that are also subject to the provisions of the HON. The
applicability of subpart CC versus the HON or other MACT standard to an
emission point is determined by the primary product produced in the
unit. The primary product is the product that is produced in the
greatest mass or volume that the unit produces. For example, if a
refinery operates a unit that produces upgraded feedstock for the
alkylation unit and this unit also produces a small quantity (less than
20 percent) of the chemical methyl tert butyl ether (MTBE), that unit
is considered to be subject to the petroleum refinery MACT standard and
not to the HON. In contrast, if a facility operated a process unit that
produced MTBE as the primary product and also produced small quantities
of a mixed hydrocarbon stream, the unit would be subject to the HON
because the unit produces MTBE as the primary product and the HON
applies to chemical manufacturing units that produce MTBE. The
distinction between the units is the difference in the primary product
produced in the different units. In the first case, the unit is
integral to the petroleum refinery's operations and the MTBE is a by-
product of the unit. In the second case, the unit's operation could be
replaced by purchased MTBE and the operation is not integral to the
petroleum refinery's operations.
The EPA believes that including the concept of primary use in the
petroleum refining process unit definition clarifies the applicability
of the petroleum refinery MACT standard, and that including the primary
product concept in HON and other MACT standards will avoid the same
emission point from the same process unit being subject to multiple
MACT standards. The EPA also believes that by directly stating in the
rule that process units subject to the HON are not subject to this
rule, the commenter's concerns over applicability issues have been
addressed.
F. Source Category Definition
In the July 1994 notice of proposed rulemaking, the proposed rule
preamble provided notice of and sought comment on the issues of a broad
affected source definition and source category; source-wide averaging;
and the relationship between the gasoline distribution affected source
definition and source category and refineries. In the preamble of the
proposed refinery rule, the EPA noted that it did not intend to include
emission points that are subject to the gasoline distribution standard
in the refinery source category, that all emission points within the
refinery source category would be treated as one stationary source for
purposes of the refinery standard, and that the EPA intended to permit
averaging among all emission points within the source category except
for equipment leaks.
Comments on both the gasoline distribution rule and the refinery
proposal indicated that the Agency needed to clarify which rule applied
to which emissions points and whether averaging would apply to
collocated emission points. Both proposed rules addressed similar
emission points; for example, both proposed rules addressed storage
tanks and equipment leaks where refineries were collocated with
gasoline distribution operations. In the preamble accompanying the
final gasoline distribution rule, the EPA indicated the intent to rely
on SIC codes to distinguish between emission points at refineries
covered by the gasoline distribution standard and those covered by the
refinery standard. The Agency noted that the SIC code for particular
equipment would indicate the department with managerial oversight
responsibility for each emission point. However, the EPA specifically
provided that this rule, if appropriate, would modify the gasoline
distribution standard to incorporate SIC code limits.
Today's rule identifies petroleum refinery process units and the
gasoline loading rack emission points by SIC code for purposes of
identifying the appropriate control requirements. A broad source
category and affected source definition increases the opportunity to
use flexible compliance options such as emissions averaging. Because
the control technology under today's rule for gasoline loading racks is
the same as the requirements under the gasoline distribution NESHAP,
the required emissions reductions from gasoline loading racks would be
at least as great as would have been required had gasoline loading
racks been excluded from the petroleum refinery source category and
affected source; due to the credit discount factors, overall emissions
may be less than otherwise would be required if gasoline loading racks
are included in an emissions averaging plan.
G. Emissions Averaging
The preamble to the proposed petroleum refinery rule requested
comments on whether marine loading operations at refineries should be
included in emissions averaging. The EPA also reopened the comment
period for the proposed NESHAP for marine tank vessel loading
operations (59 FR 44955) to request comment on whether marine terminals
collocated at refineries should be moved to the petroleum refinery
source category. In addition, as noted above, issues related to
including gasoline distribution emissions in averaging at refineries
were also raised in the proposed rule preamble.
During the comment period for the gasoline distribution NESHAP,
commenters requested that gasoline bulk terminals contiguous to a
refinery be regulated by the petroleum refinery NESHAP. Several
commenters on the proposed petroleum refinery NESHAP and proposed
marine tank vessel loading operations NESHAP supported averaging of
refinery process unit emissions with emissions from marine terminals
and gasoline distribution operations that are located at refineries.
The commenters cited more cost-effective emission reduction as the
advantage of including these emission points in emissions averaging,
and specifically commented that the costs per megagram emission
reduction of the marine loading controls are high. These commenters
also claimed that emission calculation procedures for loading are well
established and that adding marine loading to the averaging provisions
will not appreciably increase the complexity
[[Page 43254]]
of enforcement. Other commenters opposed including marine loading and
gasoline distribution emission points in emissions averaging. Some
commenters claimed that these are separate source categories and that
the Act does not permit averaging across source categories. Other
commenters were of the opinion that the EPA has the flexibility to
allow trading within a facility that includes units in different source
categories. These commenters argued that it is unnecessary to redefine
the source category to include marine loading operations and gasoline
distribution operations collocated at refineries.
In the final rule, the definitions of the petroleum refinery source
category and affected source have been changed to include gasoline
loading racks classified under SIC code 2911 (Petroleum Refineries) and
marine tank vessel loading operations that are located at refinery
plant sites. Because marine loading operations and bulk gasoline
transfer operations located at refineries are supplying raw materials
to, or transferring products from, petroleum refinery process units,
they are logically considered to be part of the same source as the
petroleum refinery process units. The EPA considers this definition to
be the most appropriate definition and, as noted by several commenters,
to present fewer implementation problems.
A gasoline loading rack classified under SIC code 2911 or a marine
tank vessel loading operation that is located at a petroleum refinery
may be included in an emissions average with other refinery process
unit emission points. Because these operations are included as part of
a single source within one source category intersource averaging is not
an issue.
In keeping with the EPA's stated goal of increasing flexibility in
rulemakings, this decision has been made to provide more opportunities
to average. This increases the opportunities for refiners to find cost-
effective emission reductions from overall facility operations onsite.
Costs and cost effectiveness of controlling a particular kind of
emission point, such as marine loading, will vary depending on many
site-specific factors. Emissions averaging allows the owner and
operator to find the optimal control strategy for their particular
situation.
The EPA is presently reviewing the emission averaging policy and
considering whether any more flexibility can be provided while
maintaining environmental protection. The issue of intersource
averaging will be considered along with other aspects of the emissions
averaging policy such as limitations on the number of points allowed in
an average. The EPA believes that any decision to provide additional
flexibility must be based on careful consideration of enforcement
issues as well as equity in environmental protection. Given the
complexity of these issues, the EPA does not believe that the Refinery
MACT standard is the appropriate place to address these issues. The EPA
plans to examine the issue independently of any specific rulemaking. In
this, the EPA plans to work closely with both the refining and chemical
industries and other interested parties to determine if there are
opportunities for increasing flexibility and reducing the burden
associated with demonstrating compliance with the MACT rules while
remaining within the law.
The EPA would like to clarify that the emissions averaging program
was designed to result in equal or greater environmental protection
while providing sources flexibility to reduce emissions in the most
cost-effective manner. Specifically, allowing marine loading
operations, and gasoline loading racks classified under SIC code 2911,
located at a refinery to be included in emissions averages will result
in equivalent or greater overall HAP emission reduction at each
refinery. The averaging provisions are structured such that ``debits''
generated by not controlling an emission point that otherwise would
require control must be balanced by achieving extra control at other
refinery emission points covered by the NESHAP. The averaging
provisions also require that a source demonstrate that compliance
through averaging will not result in greater risk or hazard than
compliance without averaging.
Some commenters were concerned that including marine loading in
averages could result in uncontrolled peak emissions. With regard to
the commenters' concerns about peak emissions, the quarterly cap on the
ratio of debits to credits is intended to limit the possibility of
exposure peaks. Furthermore, because loading occurs fairly frequently,
and emissions from an individual vessel filling or loading event are
relatively small, such emissions are not expected to cause significant
exposure peaks. Moreover, no evidence has been presented that emissions
averaging would permit a very different mix of emissions to occur than
would point-by-point compliance. That is, peaks of exposures from batch
streams, storage, and loading operations should be equally likely under
point-by-point compliance as under emissions averaging, so emissions
averaging does not represent a less effective control strategy.
Furthermore, in order to receive approval for an emissions average, the
owner or operator is required to demonstrate that the emissions average
does not increase the risk or hazard relative to compliance without
averaging.
H. Monitoring, Recordkeeping, and Reporting
Several commenters alleged that the recordkeeping and reporting
requirements of the proposed rule were extremely burdensome. The
commenters requested that the EPA reduce the monitoring, recordkeeping,
and reporting burden associated with the proposed rule. Commenters also
requested that provisions be added to the final rule to avoid
duplicative reporting for equipment subject to multiple NESHAP and
NSPS. Other commenters requested that flexibility to allow alternative
monitoring, recordkeeping, and reporting be incorporated into the final
rule.
The EPA recognizes that unnecessary monitoring, recordkeeping, and
reporting requirements would burden both the source and enforcement
agencies. Prior to proposal, the EPA attempted to reduce the amount of
monitoring, recordkeeping, and reporting to only that which is
necessary to demonstrate compliance. For example, at proposal almost
all reports were consolidated into the Notification of Compliance
Status and the Periodic Reports. This was done to simplify and reduce
the frequency of reporting. Sources also have the option of retaining
records either in paper copy or in computer-readable formats, whichever
is less burdensome. If multiple performance tests are conducted for the
same kind of emission point using the same test method, only one
complete test report is submitted along with summaries of the results
of other tests. This reduces the number of lengthy test reports to be
copied, reviewed, and submitted.
Site-specific test plans describing quality assurance in
Sec. 63.7(c) of 40 CFR part 63, subpart A are not required because the
test methods cited in subpart CC already contain applicable quality
assurance protocols. The quality assurance provisions in the individual
test methods remain applicable and are not superseded by the
nonapplicability of Sec. 63.7(c) of subpart A. For continuously
monitored parameters, periodic reporting is limited to excursions
outside the established ranges and the in-range values are not required
to be reported.
[[Page 43255]]
In response to the commenters, the EPA reevaluated whether
monitoring, recordkeeping, and reporting requirements could be further
reduced while maintaining the enforceability of the rule. The EPA has
made the following changes in the promulgated rule to further reduce
the monitoring, recordkeeping, and reporting burden:
(1) The requirement to submit an Initial Notification has been
eliminated;
(2) Periodic reports are required to be submitted semiannually for
all facilities that do not use emissions averaging (the proposal
required quarterly reports if monitored parameters were out of range
more than a specified percentage of the time);
(3) A reduction in the frequency for parameter monitoring and
recording. The proposal required values of monitored parameters to be
recorded every 15 minutes and all 15-minute records had to be retained
for those days when excess emissions occurred. The final rule allows
hourly monitoring and recording;
(4) Recordkeeping and reporting provisions that eliminate duplicate
reporting for equipment subject to multiple NESHAP and NSPS were added
to the applicability section (Sec. 63.640) of the final rule. The
additions specify which rule applies and overrides the less stringent
NSPS or NESHAP. For State and local regulation applicability
determination, the final rule has been amended to state that the local
regulatory authority (e.g., State or permitting authority) can decide
how monitoring, recordkeeping, and reporting requirements can be
consolidated, and can approve alternative monitoring, recordkeeping,
and reporting requirements.
These reductions reduce the proposal monitoring, recordkeeping, and
reporting burden by 25 percent. The EPA plans to continue to work with
the industry as well as with other interested parties to identify
further opportunities for reduction of the monitoring, recordkeeping,
and reporting burden of the rule. The EPA will consider ways to
eliminate overlapping requirements and to address any inconsistencies
among the rules. The EPA will investigate the possibility of
consolidating and simplifying the various rules while maintaining the
same level of environmental protection. Assuming that the pilot project
with the chemical industry is successful, the EPA expects to be able to
complete the review of the Refinery rule monitoring, recordkeeping, and
reporting requirements before the compliance date.
I. Subcategorization
Several commenters to the proposed petroleum refinery NESHAP
requested that the EPA subcategorize refineries by size and/or location
in an ozone attainment area. Other commenters stated that
subcategorizing small refineries because of an arbitrary size exemption
can result in an unfair competitive advantage. These commenters further
elaborated that large refineries should not be penalized for an economy
of scale achieved through its own effective competitiveness.
In response to these comments, the refinery data bases were
subcategorized based on crude charge capacity. The refineries were also
subcategorized by ozone attainment status and by refineries containing
processes that are used to produce gasoline (such as catalytic
cracking, coking, and catalytic reforming). Within each subcategory,
the process vents, storage vessels, and equipment leaks data bases were
sorted from most stringent control to least stringent. The MACT floor
(average of the top 12 percent of sources) for each subcategory was
identified.
The MACT floors for small refineries are not significantly
different from the industry as a whole. The floor for process vents is
the same for small refiners as for the entire industry. The floor for
storage tanks would increase the materials vapor pressure cutoff from
10 kPa (1.5 psia) to 11 kPa (1.7 psia), which would result in a minimal
cost savings since there are few petroleum liquids in this volatility
range. The floor for equipment leaks would reduce the monitoring
frequency; however, small refiners would still incur the cost of
setting up and implementing an LDAR program.
Based on the EPA's analysis and the comments received during the
public comment period, a separate subcategory for small refineries has
not been included in the final rule. This decision was based on there
being no clear relationship between refinery size or design and
emission potential.
J. Economic Analysis
Comments were received on both the methodology of the economic
analysis and the potential impacts of the analysis results. The EPA's
economic model focused on estimating changes in product price and
quantity of production for several petroleum products. Once the effects
on price and quantity were evaluated, other impacts were estimated. The
model the EPA used is predicated on neoclassical microeconomic theory.
The model assumed that those refineries with the highest per-unit
control are marginal (i.e., near the margin between shutdown and
continuing operation) in the post-control markets, and that they also
have the highest underlying per-unit cost of production. This
assumption may result in an overstatement of the adverse impacts, such
as closure, since the assumed relationship between per-unit control
cost and per-unit production cost may not hold for all refineries. For
more information, consult the ``Economic Impact Analysis for the
Petroleum Refinery NESHAP'' in the docket.
Most of the comments about the economic analyses methodology were
focused on possible impacts on other parts of the petroleum industry
other than refineries. The economic analysis for this rule, like most
of the EPA's economic analyses, focuses on the impacts on the industry
being regulated and does not calculate impacts to other industries
indirectly affected unless those impacts are significant. In this case,
the impacts to indirectly affected industries were not calculated since
the impacts estimated for the petroleum refinery industry were not
significant, impacts to indirectly affected industries would likely be
insignificant also.
K. Benefits Analysis
Comments noted that naphthalene is classified as a possible
carcinogen, not a known carcinogen, and therefore should not be
included in the risk analysis. Commenters also argued that the
estimates for monetized VOC benefits were too high, since the VOC
reductions claimed in the regulation would occur as a result of State
Implementation Plans (SIP's) required by the Act. Other commenters
wrote that the level of benefits from HAP emissions reduction was not
of sufficient justification for pursuing the regulation.
When the rule was proposed, naphthalene was classified as a
possible human carcinogen. Naphthalene is no longer classified as a
possible human carcinogen and is not included in the risk analysis for
the final rule.
To estimate the benefits of reducing VOC, the EPA used a 1989 study
conducted by the Office of Technology Assessment (OTA). The study
examined a variety of acute health impacts related to ozone exposure as
well as the benefits of reduced ozone concentrations for selected
agricultural crops. A number of factors were not considered in the
analysis, including chronic health effects and health impacts for
attainment areas.
As to the comment about some of the benefits being attributable to
VOC
[[Page 43256]]
emission reductions brought about by implementing SIP's, the EPA
attempted to include in the baseline all possible impacts from SIP
implementation. Control of VOC in this rule will be incorporated into
future SIP's by affecting their baselines, thus making the emission
reductions needed to meet them less, and leading to lower costs for
petroleum refineries to meet those SIP's. Therefore, control of VOC
emissions in this rule will lead to lower costs to future SIP
implementation. Also, the emission streams from petroleum refineries
are primarily VOC, with a small fraction of VOC being HAP. Control of
any petroleum refinery emission stream involves control of VOC as well
as HAP. Thus, any benefits estimated to occur from a rule that controls
VOC, though their control is of secondary importance, should be
included as benefits of the rule.
L. Emissions Data
Commenters raised concerns about the amount and quality of the data
on HAP emissions, and the uncertainties in the emission estimates.
Throughout the rulemaking, the EPA has been aware of these concerns.
During the course of this rulemaking, the EPA requested information
from the petroleum refining industry on emissions and emission control
technologies. The industry provided sufficient information on the
emission control technologies to determine the best controlled
facilities, as required by section 112 of the Act. However, the
information received on existing emission control levels was limited
because it was not available. Thus, there is uncertainty in the
refinery baseline emission estimates, and emission reductions and other
benefits achieved from the emission controls required to comply with
the rule. The EPA and the petroleum refinery industry are unable to
reduce this uncertainty at this time. The Agency has characterized the
costs and emission reductions of the requirements of this rule as
accurately as possible. While there is a great deal of qualitative
information on the benefits of this rule, the uncertainty in the
emission estimates and the monetary value that can be placed on the
emission reductions limits the Agency's ability to directly quantify
all the benefits of the refinery MACT rule. The EPA does know, however,
that the controls required in this rulemaking are in widespread use in
the refining industry and that they provide substantial emission
reductions.
Under section 112(f) of the Act, the EPA must determine whether
further control of refinery emissions is necessary to protect the
health of the general public. This determination will require more
accurate emission estimates than currently exist. The EPA has made a
commitment to work cooperatively with industry to identify the data
needed to improve the emission estimates and any other information that
is required to determine the health risks that may remain after
implementation of the refinery MACT rule.
VI. Changes to NSPS
The changes to 40 CFR part 60, subparts VV and QQQ are promulgated
with minor edits for clarity and consistency.
VII. Administrative Requirements
A. Docket
The docket is an organized and complete file of all the information
considered by the EPA in the development of this rulemaking. The docket
is a dynamic file, since material is added throughout the rulemaking
development. The docketing system is intended to allow members of the
public and industries involved to readily identify and locate documents
so that they can effectively participate in the rulemaking process.
Along with the proposed and promulgated standards and their preambles,
and the BID containing the EPA's responses to significant comments, the
contents of the docket will serve as the record in case of judicial
review (section 307(d)(7)(A)).
B. Paperwork Reduction Act
The information collection requirements in this rule have been
approved by the Office of Management and Budget (OMB) under the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq and have been assigned
control number 2060-0340. This collection of information has an
estimated annual reporting burden averaging 320 hours per respondent
and an estimated annual recordkeeping burden averaging 2,880 hours per
respondent. These estimates include time for reviewing instructions,
searching existing data sources, gathering and maintaining the data
needed, and completing and reviewing the collection of information.
This reflects a reduction of the proposal monitoring,
recordkeeping, and reporting burden of 25 percent. The EPA plans to
continue to work with the industry as well as with other interested
parties to identify further opportunities for reduction of the
monitoring, recordkeeping, and reporting burden of the rule. The EPA
will consider ways to eliminate overlapping requirements and to address
any inconsistencies among the rules. The EPA will investigate the
possibility of consolidating and simplifying the various rules while
maintaining the same level of environmental protection. Assuming that
the pilot project with the chemical industry is successful, the EPA
expects to be able to complete the review of the Refinery rule
monitoring, recordkeeping, and reporting requirements before the
compliance date.
Send comments regarding the burden estimate or any other aspect of
this collection of information, including suggestions for reducing this
burden to Chief, Information Policy Branch; EPA; 401 M St. SW., (Mail
Code 2136); Washington, DC 20460; and to the Office of Information and
Regulatory Affairs, Office of Management and Budget, Washington, DC
20503, marked ``Attention: Desk Officer for EPA.''
C. Executive Order 12866
Under Executive Order 12866 (58 FR 5173 (October 4, 1993)), the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to OMB review and the requirements of the
Executive Order. The Order defines ``significant regulatory action'' as
one that is likely to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
This action is a ``significant regulatory action'' within the
meaning of Executive Order 12866. The EPA has submitted this action to
OMB for review. Changes made in response to OMB suggestions or
recommendations will be documented in the public record.
D. Regulatory Flexibility Act
Pursuant to the Regulatory Flexibility Act of 1980, 5 U.S.C. 601 et
seq., when an agency publishes a notice of rulemaking, for a rule that
will have a significant effect on a substantial number of small
entities, the agency
[[Page 43257]]
must prepare and make available for public comment a regulatory
flexibility analysis (RFA) that considers the effect of the rule on
small entities (i.e., small businesses, small organizations, and small
governmental jurisdictions). In assessing the regulatory approach for
dealing with small entities in today's final rule, the EPA guidelines
indicate that an economic impact should be considered significant if it
meets one of the following criteria:
(1) Compliance increases annual production costs by more than 5
percent, assuming costs are passed on to consumers;
(2) Compliance costs as a percentage of sales for small entities
are at least 10 percent more than compliance costs as a percentage of
sales for large entities;
(3) Capital costs of compliance represent a ``significant'' portion
of capital available to small entities, considering internal cash flow
plus external financial capabilities, or
(4) Regulatory requirements are likely to result in closure of
small entities.
Data were not readily available to determine if criteria (1) and
(3) were met or not, so the analysis focused on the other two. Results
from the economic impact analysis indicate that between zero and seven
refiners, all of which are classified as small, are at risk of closure
(refer to the ``Economic Impact Analysis of the Regulatory Alternatives
for the Petroleum Refineries NESHAP'' in the Background Information
Documents section). While this percentage of net closures is less than
20 percent of the total number of small refineries (88), it was deemed
high enough for carrying out an RFA on that basis alone. Criterion (2),
however, was satisfied. The compliance costs-to-sales ratio for the
small refiners was more than 10 percent greater than the same ratio
calculated for all other refiners.
There are four reasons why small entities are disproportionately
affected by the regulation. The first is the fact that they tend to own
smaller facilities, and therefore have smaller economics of scale.
Because of the smaller economies of scale, per-unit costs of production
and compliance are higher for the small refiners compared to others.
Related to this is the fact that small refiners have less ability to
produce differentiated products. This ability, called complexity,
increases with increasing refinery capacity. A large refinery can
respond to a relative increase in production costs for one product by
increasing production of a product now relatively cheaper to produce,
an ability most small refiners rarely enjoy.
A second reason is they have fewer capital resources. Small
refineries have less ability to finance the capital expenditures needed
to purchase the equipment required to comply with the regulation. A
third reason is the difference in internal structure. None of the small
refiners are vertically or horizontally integrated, and in all but a
few cases are not the subsidiary of a large parent company. The small
refiners are typically independent owners and operators of their
facilities, and most are owners of a single refinery. They do not
possess the ability to shift production between different refineries
and have less market power than their large competitors.
A fourth reason why smaller refiners experience greater economic
impacts than other refiners is due to the small industry-level price
increases (less than 1 percent in all cases). It is unlikely that small
refiners will be able to recover annualized control costs by increasing
product prices, since the large refiners will not be significantly
impacted. As seen in the examination of criterion (2), the large
refiners will not be significantly affected from compliance with the
regulation.
In calculating the number of closures, the assumption was made that
those refineries with the highest per-unit control costs were marginal
after compliance with the regulation. While this assumption is often
useful in closure analysis, it is not always true. The assumption is
consistent with perfect competition theory that presumes all firms are
price-takers. If a refiner does have some monopoly power in a
particular market, then it is possible a refiner experiencing some
economic distress could continue to operate for some period while
complying with the regulation. It is a conservative assumption that
likely biases the results to overstate the number of refinery closures
and other impacts of the proposed regulation.
To mitigate the economic impacts on small refiners, the Agency has
considered whether to subcategorize the MACT floors for the various
emission sources or to allow refiners more time to comply with the
regulation. The Agency has decided not to include a separate
subcategory for small refiners, but has decided to allow refiners more
time to comply with various requirements for control of equipment leak
and storage vessel emissions (refer to section V, ``Significant
Comments and Changes to the Proposed Standards'').
The definition of small refinery used in the analysis is 50,000 bbl
per stream day production capacity. This differs from the definition of
75,000 barrels per stream current as of May 1, 1992, a definition
announced by the Small Business Administration that day in the Federal
Register (57 FR 18808).
E. Unfunded Mandates
Under section 202 of the Unfunded Mandates Reform Act of 1995
(``Unfunded Mandates Act''), signed into law on March 22, 1995, the EPA
must prepare a budgetary impact statement to accompany any proposed or
final rule that includes a Federal mandate that may result in estimated
costs to State, local, or tribal governments in the aggregate, or to
the private sector, of $100 million or more. Under section 205, the EPA
must select the most cost effective and least burdensome alternative
that achieves the objectives of the rule and is consistent with
statutory requirements. Section 203 requires the EPA to establish a
plan for informing and advising any small governments that may be
significantly or uniquely impacted by the rule.
The EPA has determined that the action promulgated today does not
include a Federal mandate that may result in estimated costs of $100
million or more to either State, local, or tribal governments in the
aggregate, or to the private sector. Therefore, the requirements of the
Unfunded Mandates Act do not apply to this action.
List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Gasoline, Intergovernmental relations, Natural
gas, Volatile organic compounds.
40 CFR Part 63
Air pollution control, Hazardous air pollutants, Petroleum
refineries, Reporting and recordkeeping requirements.
Dated: July 28, 1995.
Carol M. Browner,
Administrator.
For the reasons set out in the preamble, parts 9, 60, and 63 of
title 40, chapter I, of the Code of Federal Regulations are amended as
follows:
PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT
1. The authority citation for part 9 continues to read as follows:
Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,
2005, 2006, 2601-2671; 21 U.S.C. 331, 346a, 348; 31 U.S.C. 9701; 33
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1321, 1326, 1330, 1344,
1345(d), and (e), 1381; E.O. 11735, 38 FR 21243, 3 CFR, 1971-1975
[[Page 43258]]
Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 300g-i, 300j-
2, 300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q,
7542, 9601-9657, 11023, 11048.
2. Section 9.1 is amended by adding the new entries to the table
under the indicated heading in numerical order to read as follows:
Sec. 9.1 OMB approvals under the paperwork reduction act.
* * * * *
------------------------------------------------------------------------
OMB control
40 CFR citation No.
------------------------------------------------------------------------
* * * * *
National Emission Standards for Hazardous Air Pollutants
for Source Categories
* * * * *
63.653..................................................... 2060-0340
63.654..................................................... 2060-0340
* * * * *
------------------------------------------------------------------------
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401-7601.
Subpart VV--[Amended]
2. Section 60.481 is amended by revising the definition of ``closed
vent system'' to read as follows:
Sec. 60.481 Definitions.
* * * * *
Closed vent system means a system that is not open to the
atmosphere and that is composed of piping, connections, and, if
necessary, flow-inducing devices that transport gas or vapor from a
piece or pieces of equipment to a control device. If gas or vapor from
regulated equipment is routed to a process (e.g., to a petroleum
refinery fuel gas system), the process shall not be considered a closed
vent system and is not subject to the closed vent system standards.
* * * * *
3. Section 60.482-5 is revised to read as follows:
Sec. 60.482-5 Standards: Sampling connection systems.
(a) Each sampling connection system shall be equipped with a
closed-purged, closed-loop, or closed-vent system, except as provided
in Sec. 60.482-1(c).
(b) Each closed-purge, closed-loop, or closed-vent system as
required in paragraph (a) of this section shall comply with the
requirements specified in paragraphs (b)(1) through (b)(3) of this
section:
(1) Return the purged process fluid directly to the process line;
or
(2) Collect and recycle the purged process fluid to a process; or
(3) Be designed and operated to capture and transport all the
purged process fluid to a control device that complies with the
requirements of Sec. 60.482-10.
(c) In situ sampling systems and sampling systems without purges
are exempt from the requirements of paragraphs (a) and (b) of this
section.
4. Section 60.482-10 is amended by revising paragraphs (f) and (g)
and adding paragraphs (h) through (l) to read as follows:
Sec. 60.482-10 Standards: Closed vent systems and control devices.
* * * * *
(f) Except as provided in paragraphs (i) through (k) of this
section, each closed vent system shall be inspected according to the
procedures and schedule specified in paragraphs (f)(1) and (f)(2) of
this section.
(1) If the vapor collection system or closed vent system is
constructed of hard-piping, the owner or operator shall comply with the
requirements specified in paragraphs (f)(1)(i) and (f)(1)(ii) of this
section:
(i) Conduct an initial inspection according to the procedures in
Sec. 60.485(b); and
(ii) Conduct annual visual inspections for visible, audible, or
olfactory indications of leaks.
(2) If the vapor collection system or closed vent system is
constructed of ductwork, the owner or operator shall:
(i) Conduct an initial inspection according to the procedures in
Sec. 60.485(b); and
(ii) Conduct annual inspections according to the procedures in
Sec. 60.485(b).
(g) Leaks, as indicated by an instrument reading greater than 500
parts per million by volume above background or by visual inspections,
shall be repaired as soon as practicable except as provided in
paragraph (h) of this section.
(1) A first attempt at repair shall be made no later than 5
calendar days after the leak is detected.
(2) Repair shall be completed no later than 15 calendar days after
the leak is detected.
(h) Delay of repair of a closed vent system for which leaks have
been detected is allowed if the repair is technically infeasible
without a process unit shutdown or if the owner or operator determines
that emissions resulting from immediate repair would be greater than
the fugitive emissions likely to result from delay of repair. Repair of
such equipment shall be complete by the end of the next process unit
shutdown.
(i) If a vapor collection system or closed vent system is operated
under a vacuum, it is exempt from the inspection requirements of
paragraphs (f)(1)(i) and (f)(2) of this section.
(j) Any parts of the closed vent system that are designated, as
described in paragraph (k)(1) of this section, as unsafe to inspect are
exempt from the inspection requirements of paragraphs (f)(1)(i) and
(f)(2) of this section if they comply with the requirements specified
in paragraphs (j)(1) and (j)(2) of this section:
(1) The owner or operator determines that the equipment is unsafe
to inspect because inspecting personnel would be exposed to an imminent
or potential danger as a consequence of complying with paragraphs
(f)(1)(i) or (f)(2) of this section; and
(2) The owner or operator has a written plan that requires
inspection of the equipment as frequently as practicable during safe-
to-inspect times.
(k) Any parts of the closed vent system that are designated, as
described in paragraph (l)(2) of this section, as difficult to inspect
are exempt from the inspection requirements of paragraphs (f)(1)(i) and
(f)(2) of this section if they comply with the requirements specified
in paragraphs (k)(1) through (k)(3) of this section:
(1) The owner or operator determines that the equipment cannot be
inspected without elevating the inspecting personnel more than 2 meters
above a support surface; and
(2) The process unit within which the closed vent system is located
becomes an affected facility through Secs. 60.14 or 60.15, or the owner
or operator designates less than 3.0 percent of the total number of
closed vent system equipment as difficult to inspect; and
(3) The owner or operator has a written plan that requires
inspection of the equipment at least once every 5 years. A closed vent
system is exempt from inspection if it is operated under a vacuum.
(l) The owner or operator shall record the information specified in
paragraphs (l)(1) through (l)(5) of this section.
(1) Identification of all parts of the closed vent system that are
designated as unsafe to inspect, an explanation of why the equipment is
unsafe to inspect, and the plan for inspecting the equipment.
(2) Identification of all parts of the closed vent system that are
designated
[[Page 43259]]
as difficult to inspect, an explanation of why the equipment is
difficult to inspect, and the plan for inspecting the equipment.
(3) For each inspection during which a leak is detected, a record
of the information specified in Sec. 60.486(c).
(4) For each inspection conducted in accordance with Sec. 60.485(b)
during which no leaks are detected, a record that the inspection was
performed, the date of the inspection, and a statement that no leaks
were detected.
(5) For each visual inspection conducted in accordance with
paragraph (f)(1)(ii) of this section during which no leaks are
detected, a record that the inspection was performed, the date of the
inspection, and a statement that no leaks were detected.
(m) Closed vent systems and control devices used to comply with
provisions of this subpart shall be operated at all times when
emissions may be vented to them.
* * * * *
Subpart QQQ--[Amended]
* * * * *
5. Section 60.691 is amended by revising the definition of ``closed
vent system'' to read as follows:
Sec. 60.691 Definitions.
* * * * *
Closed vent system means a system that is not open to the
atmosphere and that is composed of piping, connections, and, if
necessary, flow-inducing devices that transport gas or vapor from an
emission source to a control device. If gas or vapor from regulated
equipment are routed to a process (e.g., to a petroleum refinery fuel
gas system), the process shall not be considered a closed vent system
and is not subject to the closed vent system standards.
* * * * *
6. Section 60.692-3 is amended by revising paragraph (d) to read as
follows:
Sec. 60.692-3 Standards: Oil-water separators.
* * * * *
(d) Storage vessels, including slop oil tanks and other auxiliary
tanks that are subject to the standards in Secs. 60.112, 60.112a, and
60.112b and associated requirements, 40 CFR part 60, subparts K, Ka, or
Kb are not subject to the requirements of this section.
* * * * *
7. Section 60.693-2 is amended by revising paragraphs (a)(1)(i)
introductory text and (a)(1)(i)(A) to read as follows:
Sec. 60.693-2 Alternative standards for oil-water separators.
* * * * *
(a) * * *
(1) * * *
(i) The primary seal shall be a liquid-mounted seal or a mechanical
shoe seal.
(A) A liquid-mounted seal means a foam- or liquid-filled seal
mounted in contact with the liquid between the wall of the separator
and the floating roof. A mechanical shoe seal means a metal sheet held
vertically against the wall of the separator by springs or weighted
levers and is connected by braces to the floating roof. A flexible
coated fabric (envelope) spans the annular space between the metal
sheet and the floating roof.
* * * * *
8. Section 60.695 is amended by adding paragraphs (a)(3)(i) and
(a)(3)(ii) to read as follows:
Sec. 60.695 Monitoring of operations.
* * * * *
(a) * * *
(3) * * *
(i) For a carbon adsorption system that regenerates the carbon bed
directly onsite, a monitoring device that continuously indicates and
records the volatile organic compound concentration level or reading of
organics in the exhaust gases of the control device outlet gas stream
or inlet and outlet gas stream shall be used.
(ii) For a carbon adsorption system that does not regenerate the
carbon bed directly onsite in the control device (e.g., a carbon
canister), the concentration level of the organic compounds in the
exhaust vent stream from the carbon adsorption system shall be
monitored on a regular schedule, and the existing carbon shall be
replaced with fresh carbon immediately when carbon breakthrough is
indicated. The device shall be monitored on a daily basis or at
intervals no greater than 20 percent of the design carbon replacement
interval, whichever is greater. As an alternative to conducting this
monitoring, an owner or operator may replace the carbon in the carbon
adsorption system with fresh carbon at a regular predetermined time
interval that is less than the carbon replacement interval that is
determined by the maximum design flow rate and organic concentration in
the gas stream vented to the carbon adsorption system.
* * * * *
9. Section 60.697 is amended by revising paragraphs (f)(3)(i),
(f)(3)(ii); and by adding paragraphs (f)(3)(x) (A) and (B) to read as
follows:
Sec. 60.697 Recordkeeping requirements.
* * * * *
(f) * * *
(3) * * *
(i) Documentation demonstrating that the control device will
achieve the required control efficiency during maximum loading
conditions shall be kept for the life of the facility. This
documentation is to include a general description of the gas streams
that enter the control device, including flow and volatile organic
compound content under varying liquid level conditions (dynamic and
static) and manufacturer's design specifications for the control
device. If an enclosed combustion device with a minimum residence time
of 0.75 seconds and a minimum temperature of 816 deg.C (1,500 deg.F)
is used to meet the 95-percent requirement, documentation that those
conditions exist is sufficient to meet the requirements of this
paragraph.
(ii) For a carbon adsorption system that does not regenerate the
carbon bed directly onsite in the control device such as a carbon
canister, the design analysis shall consider the vent stream
composition, constituent concentrations, flow rate, relative humidity,
and temperature. The design analysis shall also establish the design
exhaust vent stream organic compound concentration level, capacity of
carbon bed, type and working capacity of activated carbon used for
carbon bed, and design carbon replacement interval based on the total
carbon working capacity of the control device and source operating
schedule.
* * * * *
(x) * * *
(A) Each owner or operator of an affected facility that uses a
carbon adsorber which is regenerated directly onsite shall maintain
continuous records of the volatile organic compound concentration level
or reading of organics of the control device outlet gas stream or inlet
and outlet gas stream and records of all 3-hour periods of operation
during which the average volatile organic compound concentration level
or reading of organics in the exhaust gases, or inlet and outlet gas
stream, is more than 20 percent greater than the design exhaust gas
concentration level, and shall keep such records for 2 years after the
information is recorded.
(B) If a carbon adsorber that is not regenerated directly onsite in
the control device is used, then the owner or operator shall maintain
records of dates and times when the control device is monitored, when
breakthrough is measured, and shall record the date and
[[Page 43260]]
time that the existing carbon in the control device is replaced with
fresh carbon.
* * * * *
10. Section 60.698 is amended by adding paragraphs (d)(3)(i) and
(d)(3)(ii) to read as follows:
Sec. 60.698 Reporting requirements.
* * * * *
(d) * * *
(3) * * *
(i) Each 3-hour period of operation during which the average
volatile organic compound concentration level or reading of organics in
the exhaust gases from a carbon adsorber which is regenerated directly
onsite is more than 20 percent greater than the design exhaust gas
concentration level or reading.
(ii) Each occurrence when the carbon in a carbon adsorber system
that is not regenerated directly onsite in the control device is not
replaced at the predetermined interval specified in
Sec. 60.695(a)(3)(ii).
* * * * *
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart R--[Amended]
2. Section 63.420 is amended by adding paragraph (i) to read as
follows:
Sec. 63.420 Applicability.
* * * * *
(i) A bulk gasoline terminal or pipeline breakout station with a
Standard Industrial Classification code 2911 located within a
contiguous area and under common control with a refinery complying with
subpart CC, Secs. 63.646, 63.648, 63.649, and 63.650 is not subject to
subpart R standards, except as specified in subpart CC, Sec. 63.650.
* * * * *
3. Part 63 is amended by adding subpart CC consisting of
Secs. 63.640 through 63.679 to read as follows:
Subpart CC--National Emission Standards for Hazardous Air Pollutants
From Petroleum Refineries
Sec.
63.640 Applicability and designation of affected source.
63.641 Definitions.
63.642 General standards.
63.643 Miscellaneous process vents provisions.
63.644 Monitoring provisions for miscellaneous process vents.
63.645 Test methods and procedures for miscellaneous process vents.
63.646 Storage vessel provisions.
63.647 Wastewater provisions.
63.648 Equipment leak standards.
63.649 Alternative means of emission limitation: Connectors in gas/
vapor service and light liquid service.
63.650 Gasoline loading rack provisions.
63.651 Marine vessel tank loading operations provisions.
63.652 Emissions averaging provisions.
63.653 Monitoring, recordkeeping, and implementation plan for
emissions averaging.
63.654 Reporting and recordkeeping requirements.
63.655 through 63.679 [Reserved]
Appendix to Subpart CC--Tables
Subpart CC--National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries
Sec. 63.640 Applicability and designation of affected source.
(a) This subpart applies to petroleum refining process units and to
related emission points that are specified in paragraphs (c)(5) through
(c)(7) of this section that are located at a plant site that meet the
criteria in paragraphs (a)(1) and (a)(2) of this section;
(1) Are located at a plant site that is a major source as defined
in section 112(a) of the Clean Air Act; and
(2) Emit or have equipment containing or contacting one or more of
the hazardous air pollutants listed in table 1 of this subpart.
(b) For process units that are designed and operated as flexible
operation units, the applicability of this subpart shall be determined
for existing sources based on the expected utilization for the first 5
years after startup.
(1) If the predominant use of the flexible operation unit, as
described in paragraphs (b)(1)(i) and (b)(1)(ii) of this section, is as
a petroleum refining process unit, as defined in Sec. 63.641, then the
flexible operation unit shall be subject to the provisions of this
subpart.
(i) Except as provided in paragraph (b)(1)(ii) of this section, the
predominant use of the flexible operation unit shall be the use
representing the greatest annual operating time.
(ii) If the flexible operation unit is used as a petroleum refining
process unit and for another purpose equally based on operating time,
then the predominant use of the flexible operation unit shall be the
use that produces the greatest annual production on a mass basis.
(2) The determination of applicability of this subpart to petroleum
refining process units that are designed and operated as flexible
operation units shall be reported as specified in Sec. 63.654(h)(6)(i).
(c) For the purpose of this subpart, the affected source shall
comprise all emission points, in combination, listed in paragraphs
(c)(1) through (c)(7) of this section that are located at a single
refinery plant site.
(1) All miscellaneous process vents from petroleum refining process
units meeting the criteria in paragraph (a) of this section;
(2) All storage vessels associated with petroleum refining process
units meeting the criteria in paragraph (a) of this section;
(3) All wastewater streams and treatment operations associated with
petroleum refining process units meeting the criteria in paragraph (a)
of this section;
(4) All equipment leaks from petroleum refining process units
meeting the criteria in paragraph (a) of this section;
(5) All gasoline loading racks classified under Standard Industrial
Classification code 2911 meeting the criteria in paragraph (a) of this
section;
(6) All marine vessel loading operations located at a petroleum
refinery meeting the criteria in paragraph (a) of this section and the
applicability criteria of subpart Y, Sec. 63.560; and
(7) All storage vessels and equipment leaks associated with a bulk
gasoline terminal or pipeline breakout station classified under
Standard Industrial Classification code 2911 located within a
contiguous area and under common control with a refinery meeting the
criteria in paragraph (a) of this section.
(d) The affected source subject to this subpart does not include
the emission points listed in paragraphs (d)(1) through (d)(4) of this
section.
(1) Stormwater from segregated stormwater sewers;
(2) Spills; and
(3) Equipment that is intended to operate in organic hazardous air
pollutant service, as defined in Sec. 63.641 of this subpart, for less
than 300 hours during the calendar year.
(4) Catalytic cracking unit and catalytic reformer catalyst
regeneration vents, and sulfur plant vents.
(e) The owner or operator shall follow the procedures specified in
paragraphs (e)(1) and (e)(2) of this section to determine whether a
storage vessel is part of a source to which this subpart applies.
(1) Where a storage vessel is used exclusively by a process unit,
the
[[Page 43261]]
storage vessel shall be considered part of that process unit.
(i) If the process unit is a petroleum refining process unit
subject to this subpart, then the storage vessel is part of the
affected source to which this subpart applies.
(ii) If the process unit is not subject to this subpart, then the
storage vessel is not part of the affected source to which this subpart
applies.
(2) If a storage vessel is not dedicated to a single process unit,
then the applicability of this subpart shall be determined according to
the provisions in paragraphs (e)(2)(i) through (e)(2)(iii) of this
section.
(i) If a storage vessel is shared among process units and one of
the process units has the predominant use, as determined by paragraphs
(e)(2)(i)(A) and (e)(2)(i)(B) of this section, then the storage vessel
is part of that process unit.
(A) If the greatest input on a volume basis into the storage vessel
is from a process unit that is located on the same plant site, then
that process unit has the predominant use.
(B) If the greatest input on a volume basis into the storage vessel
is provided from a process unit that is not located on the same plant
site, then the predominant use shall be the process unit that receives
the greatest amount of material on a volume basis from the storage
vessel at the same plant site.
(ii) If a storage vessel is shared among process units so that
there is no single predominant use, and at least one of those process
units is a petroleum refining process unit subject to this subpart, the
storage vessel shall be considered to be part of the petroleum refining
process unit that is subject to this subpart. If more than one
petroleum refining process unit is subject to this subpart, the owner
or operator may assign the storage vessel to any of the petroleum
refining process units subject to this subpart.
(iii) If the predominant use of a storage vessel varies from year
to year, then the applicability of this subpart shall be determined
based on the utilization of that storage vessel during the year
preceding promulgation of this subpart. This determination shall be
reported as specified in Sec. 63.654(h)(6)(ii) of this subpart.
(f) The owner or operator shall follow the procedures specified in
paragraphs (f)(1) through (f)(5) of this section to determine whether a
miscellaneous process vent from a distillation unit is part of a source
to which this subpart applies.
(1) If the greatest input to the distillation unit is from a
process unit located on the same plant site, then the distillation unit
shall be assigned to that process unit.
(2) If the greatest input to the distillation unit is provided from
a process unit that is not located on the same plant site, then the
distillation unit shall be assigned to the process unit located at the
same plant site that receives the greatest amount of material from the
distillation unit.
(3) If a distillation unit is shared among process units so that
there is no single predominant use, as described in paragraphs (f)(1)
and (f)(2) of this section, and at least one of those process units is
a petroleum refining process unit subject to this subpart, the
distillation unit shall be assigned to the petroleum refining process
unit that is subject to this subpart. If more than one petroleum
refining process unit is subject to this subpart, the owner or operator
may assign the distillation unit to any of the petroleum refining
process units subject to this rule.
(4) If the process unit to which the distillation unit is assigned
is a petroleum refining process unit subject to this subpart and the
vent stream contains greater than 20 parts per million by volume total
organic hazardous air pollutants, then the vent from the distillation
unit is considered a miscellaneous process vent (as defined in
Sec. 63.641 of this subpart) and is part of the source to which this
subpart applies.
(5) If the predominant use of a distillation unit varies from year
to year, then the applicability of this subpart shall be determined
based on the utilization of that distillation unit during the year
preceding promulgation of this subpart. This determination shall be
reported as specified in Sec. 63.654(f)(1)(ii).
(g) The provisions of this subpart do not apply to the processes
specified in paragraphs (g)(1) through (g)(7) of this section.
(1) Research and development facilities, regardless of whether the
facilities are located at the same plant site as a petroleum refining
process unit that is subject to the provisions of this subpart;
(2) Equipment that does not contain any of the hazardous air
pollutants listed in table 1 of this subpart that is located within a
petroleum refining process unit that is subject to this subpart;
(3) Units processing natural gas liquids;
(4) Units that are used specifically for recycling discarded oil;
(5) Shale oil extraction units;
(6) Ethylene processes; and
(7) Process units and emission points subject to subparts F, G, H,
and I of this part.
(h) Except as provided in paragraphs (k), (l), or (m) of this
section, sources subject to this subpart are required to achieve
compliance on or before the dates specified in paragraphs (h)(1)
through (h)(4) of this section.
(1) New sources that commence construction or reconstruction after
July 14, 1994 shall be in compliance with this subpart upon initial
startup or the date of promulgation of this subpart, whichever is
later, as provided in Sec. 63.6(b) of subpart A of this part.
(2) Except as provided in paragraphs (h)(3) through (h)(5) of this
section, existing sources shall be in compliance with this subpart no
later than August 18, 1998, except as provided in Sec. 63.6(c) 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.
(3) [Reserved].
(4) Existing Group 1 floating roof storage vessels shall be in
compliance with Sec. 63.646 at the next degassing and cleaning activity
or within 10 years after promulgation of the rule, whichever is first.
(5) An owner or operator may elect to comply with the provisions of
Sec. 63.648 (c) through (f) 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)(5)(i)
through (h)(5)(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 June 18, 2001.
(i) If an additional petroleum refining process unit is added to a
plant site that is a major source as defined in section 112(a) of the
Clean Air Act, the addition shall be subject to the requirements for a
new source if it meets the criteria specified in paragraphs (i)(1)
through (i)(3) of this section:
(1) It is an addition that meets the definition of construction in
Sec. 63.2 of subpart A of this part;
(2) Such construction commenced after July 14, 1994; and
(3) The addition has the potential to emit 10 tons per year or more
of any hazardous air pollutant or 25 tons per year or more of any
combination of hazardous air pollutants.
(j) If any change is made to a petroleum refining process unit
subject to this subpart, the change shall be
[[Page 43262]]
subject to the requirements for a new source if it meets the criteria
specified in paragraphs (j)(1) and (j)(2) of this section:
(1) It is a change that meets the definition of reconstruction in
Sec. 63.2 of subpart A of this part; and
(2) Such reconstruction commenced after July 14, 1994.
(k) If an additional petroleum refining process unit is added to a
plant site or a change is made to a petroleum refining process unit and
the addition or change is determined to be subject to the new source
requirements according to paragraphs (i) or (j) of this section it must
comply with the requirements specified in paragraphs (k)(1) and (k)(2)
of this section:
(1) The reconstructed source, addition, or change shall be in
compliance with the new source requirements upon initial startup of the
reconstructed source or by the date of promulgation of this subpart,
whichever is later; and
(2) The owner or operator of the reconstructed source, addition, or
change shall comply with the reporting and recordkeeping requirements
that are applicable to new sources. The applicable reports include, but
are not limited to:
(i) The application for approval of construction or reconstruction
shall be submitted as soon as practical before the construction or
reconstruction is planned to commence (but it need not be sooner than
90 days after the date of promulgation of this subpart);
(ii) The Notification of Compliance Status report as required by
Sec. 63.654(f) for a new source, addition, or change;
(iii) Periodic Reports and Other Reports as required by Sec. 63.654
(g) and (h);
(iv) Reports and notifications required by Sec. 60.487 of subpart
VV of part 60 or Sec. 63.182 of subpart H of this part. The
requirements for subpart H are summarized in table 3 of this subpart;
(v) Reports required by 40 CFR 61.357 of subpart FF;
(vi) Reports and notifications required by Sec. 63.428 (b), (c),
(g)(1), and (h)(1) through (h)(3) of subpart R. These requirements are
summarized in table 4 of this subpart; and
(vii) Reports and notifications required by Secs. 63.566 and 63.567
of subpart Y of this part. These requirements are summarized in table 5
of this subpart.
(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, or marine tank vessel loading operation that meets the
criteria in paragraphs (c)(1) through (c)(7) of this section is added
to an existing petroleum refinery or if another deliberate operational
process change creating an additional Group 1 emission 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
(l)(3) of this section shall apply. Examples of process changes
include, but are not limited to, changes in production capacity, or
feed or raw material where the change requires construction or physical
alteration of the existing equipment or catalyst type, or whenever
there is replacement, removal, or addition of recovery equipment. For
purposes of this paragraph 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. 63.654(f).
(1) The added emission point(s) and any emission point(s) within
the added or changed petroleum refining process unit are subject to the
requirements for an existing source.
(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 this subpart by the dates specified in paragraphs
(l)(2)(i) or (l)(2)(ii) of this section, as applicable.
(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 3 years after the date of promulgation of this
subpart, whichever is later.
(ii) If a deliberate operational process change to an existing
petroleum refining process unit causes a Group 2 emission point to
become a Group 1 emission point (as defined in Sec. 63.641), the owner
or operator shall be in compliance upon initial startup or by 3 years
after the date of promulgation of this subpart, whichever is later,
unless the owner or operator demonstrates to the Administrator that
achieving compliance will take longer than making the change. If this
demonstration is made to the Administrator's satisfaction, the owner or
operator shall follow the procedures in paragraphs (m)(1) through
(m)(3) of this section to establish a compliance date.
(3) The owner or operator of a petroleum refining process unit or
of a storage vessel, miscellaneous process vent, wastewater stream,
gasoline loading rack, or marine tank vessel loading operation meeting
the criteria in paragraphs (c)(1) through (c)(7) 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
(l)(3)(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:
(i) The Notification of Compliance Status report as required by
Sec. 63.654(f) for the emission points that were added or changed;
(ii) Periodic Reports and other reports as required by Sec. 63.654
(g) and (h);
(iii) Reports and notifications required by sections of subpart A
of this part that are applicable to this subpart, as identified in
table 6 of this subpart.
(iv) Reports and notifications required by Sec. 63.182 of subpart H
of this part, or Sec. 60.407 of subpart VV of part 60. The requirements
of subpart H are summarized in table 3 of this subpart;
(v) Reports required by Sec. 61.357 of subpart FF;
(vi) Reports and notifications required by Sec. 63.428 (b), (c),
(g)(1), and (h)(1) through (h)(3) of subpart R of this part. These
requirements are summarized in table 4 of this subpart; and
(vii) Reports and notifications required by Sec. 63.567 of subpart
Y of this part. These requirements are summarized in table 5 of this
subpart.
(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 requirements of this subpart for
existing sources 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.
(1) The owner or operator shall submit to the Administrator for
approval a compliance schedule, along with a justification for the
schedule.
[[Page 43263]]
(2) The compliance schedule shall be submitted within 180 days
after the change is made or the information regarding the change is
known to the source, unless the compliance schedule has been previously
submitted to the permitting authority. The compliance schedule may be
submitted in the next Periodic Report if the change is made after the
date the Notification of Compliance Status report is due.
(3) The Administrator shall approve or deny the compliance schedule
or request changes within 120 calendar days of receipt of the
compliance schedule and justification. Approval is automatic if not
received from the Administrator within 120 calendar days of receipt.
(n) Overlap of subpart CC with other regulations for storage
vessels.
(1) After the compliance dates specified in paragraph (h) of this
section, a Group 1 or Group 2 storage vessel that is part of an
existing source and is also 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.
(2) After the compliance dates specified in paragraph (h) of this
section a Group 1 storage vessel that is part of a new source and is
subject to 40 CFR part 60, subpart Kb is required to comply only with
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 the control requirements in Sec. 60.112b of 40 CFR part 60,
subpart Kb is required to comply only with 40 CFR part 60, subpart Kb.
(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 the Sec. 60.110b subpart Kb, but is not required to apply
controls by Sec. 63.110b or 63.112b of subpart Kb 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.
(6) After compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is subject to the control
requirements of 40 CFR part 60, subparts K or Ka is required to only
comply with the provisions of 40 CFR part 60, subparts K or Ka.
(7) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is subject to 40 CFR part 60,
subparts K or Ka, but not to the control requirements of 40 CFR part
60, subparts K or Ka, is required to comply only with this subpart.
(o) Overlap of this subpart CC with other regulations for
wastewater.
(1) After the compliance dates specified in paragraph (h) of this
section a Group 1 wastewater stream managed in a piece of equipment
that is also subject to the provisions of 40 CFR part 60, subpart QQQ
is required to comply only with this subpart.
(2) After the compliance dates specified in paragraph (h) of this
section a Group 1 or Group 2 wastewater stream that is conveyed,
stored, or treated in a wastewater stream management unit that also
receives streams subject to the provisions of Secs. 63.133 through
63.147 of subpart G wastewater provisions of this part shall comply as
specified in paragraphs (o)(2)(i) through (o)(2)(iii) of this section.
Compliance with the provisions of paragraph (o)(2) of this section
shall constitute compliance with the requirements of this subpart for
that wastewater stream.
(i) The provisions in Secs. 63.133 through 63.137 and Sec. 63.140
of subpart G for all equipment used in the storage and conveyance of
the Group 1 or Group 2 wastewater stream.
(ii) The provisions in both 40 CFR part 61, subpart FF and in
Secs. 63.138 and 63.139 of subpart G for the treatment and control of
the Group 1 or Group 2 wastewater stream.
(iii) The provisions in Secs. 63.143 through 63.148 of subpart G
for monitoring and inspections of equipment and for recordkeeping and
reporting requirements. The owner or operator is not required to comply
with the monitoring, recordkeeping, and reporting requirements
associated with the treatment and control requirements in 40 CFR part
61, subpart FF, Secs. 61.355 through 61.357.
(p) Overlap of subpart CC with other regulations for equipment
leaks. After the compliance dates specified in paragraph (h) of this
section equipment leaks that are also subject to the provisions of 40
CFR parts 60 and 61 are required to comply only with the provisions
specified in this subpart.
(q) For overlap of subpart CC with local or State regulations, the
permitting authority for the affected source may allow consolidation of
the monitoring, recordkeeping, and reporting requirements under this
subpart with the monitoring, recordkeeping, and reporting requirements
under other applicable requirements in 40 CFR parts 60, 61, or 63, and
in any 40 CFR part 52 approved State implementation plan provided the
implementation plan allows for approval of alternative monitoring,
reporting, or recordkeeping requirements and provided that the permit
contains an equivalent degree of compliance and control.
Sec. 63.641 Definitions.
All terms used in this subpart shall have the meaning given them in
the Clean Air Act, subpart A of this part, and in this section. 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.
Affected source means the collection of emission points to which
this subpart applies as determined by the criteria in Sec. 63.640. The
term ``affected source,'' as used in this subpart, has the same meaning
as the term ``affected source'' in subpart A of this part.
Aliphatic means open-chained structure consisting of paraffin,
olefin and acetylene hydrocarbons and derivatives.
Boiler means any enclosed combustion device that extracts useful
energy in the form of steam and is not an incinerator.
By compound means by individual stream components, not by carbon
equivalents.
Car-seal means a seal that is placed on a device that is used to
change the position of a valve (e.g., from opened to closed) in such a
way that the position of the valve cannot be changed without breaking
the seal.
Closed vent system means a system that is not open to the
atmosphere and is configured of piping, ductwork, connections, and, if
necessary, flow inducing devices that transport gas or vapor from an
emission point to a control device or back into the process. If gas or
vapor from regulated equipment is routed to a process (e.g., to a
petroleum refinery fuel gas system), the process shall not be
considered a closed vent system and is not subject to closed vent
system standards.
Combustion device means an individual unit of equipment such as a
flare, incinerator, process heater, or boiler used for the combustion
of organic hazardous air pollutant vapors.
Connector means flanged, screwed, or other joined fittings used to
connect two pipe lines or a pipe line and a piece of equipment. A
common connector is a flange. Joined fittings welded completely around
the circumference of the interface are not considered connectors for
the purpose of this regulation. For the purpose of reporting and
recordkeeping, connector means joined fittings that are accessible.
Continuous record means documentation, either in hard copy or
[[Page 43264]]
computer readable form, of data values measured at least once every
hour and recorded at the frequency specified in Sec. 63.654(i).
Continuous recorder means a data recording device recording an
instantaneous data value or an average data value at least once every
hour.
Control device means any equipment used for recovering, removing,
or oxidizing organic hazardous air pollutants. Such equipment includes,
but is not limited to, absorbers, carbon adsorbers, condensers,
incinerators, flares, boilers, and process heaters. For miscellaneous
process vents (as defined in this section), recovery devices (as
defined in this section) are not considered control devices.
Delayed coker vent means a vent that is typically intermittent in
nature, and usually occurs only during the initiation of the
depressuring cycle of the decoking operation when vapor from the coke
drums cannot be sent to the fractionator column for product recovery,
but instead is routed to the atmosphere through a closed blowdown
system or directly to the atmosphere in an open blowdown system. The
emissions from the decoking phases of delayed coker operations, which
include coke drum deheading, draining, or decoking (coke cutting), are
not considered to be delayed coker vents.
Distillate receiver means overhead receivers, overhead
accumulators, reflux drums, and condenser(s) including ejector-
condenser(s) associated with a distillation unit.
Distillation unit means a device or vessel in which one or more
feed streams are separated into two or more exit streams, each exit
stream having component concentrations different from those in the feed
stream(s). The separation is achieved by the redistribution of the
components between the liquid and the vapor phases by vaporization and
condensation as they approach equilibrium within the distillation unit.
Distillation unit includes the distillate receiver, reboiler, and any
associated vacuum pump or steam jet.
Emission point means an individual miscellaneous process vent,
storage vessel, wastewater stream, or equipment leak associated with a
petroleum refinery process unit; an individual storage vessel or
equipment leak associated with a bulk gas 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.
Equipment leak means emissions of organic hazardous air pollutants
from a pump, compressor, pressure relief device, sampling connection
system, open-ended valve or line, valve, or instrumentation system ``in
organic hazardous air pollutant service'' as defined in this section.
Vents from wastewater system drains, tank mixers, and sample valves on
storage tanks are not equipment leaks.
Flame zone means the portion of a combustion chamber of a boiler or
process heater occupied by the flame envelope created by the primary
fuel.
Flexible operation unit means a process unit that manufactures
different products periodically by alternating raw materials or
operating conditions. These units are also referred to as campaign
plants or blocked operations.
Flow indicator means a device that indicates whether gas is
flowing, or whether the valve position would allow gas to flow, in a
line.
Fuel gas system means the offsite and onsite piping and control
system that gathers gaseous streams generated by refinery operations,
may blend them with sources of gas, if available, and transports the
blended gaseous fuel at suitable pressures for use as fuel in heaters,
furnaces, boilers, incinerators, gas turbines, and other combustion
devices located within or outside of the refinery. The fuel is piped
directly to each individual combustion device, and the system typically
operates at pressures over atmospheric. The gaseous streams can contain
a mixture of methane, light hydrocarbons, hydrogen and other
miscellaneous species.
Gasoline loading rack means the loading arms, pumps, meters,
shutoff valves, relief valves, and other piping and valves necessary to
fill gasoline cargo tanks.
Group 1 gasoline loading rack means any gasoline loading rack
classified under Standard Industrial Classification code 2911 that
emits from the vapor collection and processing system 10 milligrams of
total organic compounds per liter of gasoline loaded.
Group 1 marine tank vessel means a vessel loaded at any land- or
sea-based terminal or structure that loads liquid commodities with
vapor pressures greater than or equal to 10.3 kilopascals in bulk onto
marine tank vessels, that emits greater than 9.1 megagrams of any
individual HAP or 13.6 megagrams of any combination of HAP annually
after August 18, 1999.
Group 1 miscellaneous process vent means a miscellaneous process
vent for which the volatile organic compound concentration, or the
total organic concentration (minus ethane and methane), is greater than
or equal to 20 parts per million by volume, and the total volatile
organic compound emissions are greater than or equal to 33 kilograms
per day for existing and 7 kilograms per day for new sources at the
outlet of the final recovery device (if any) and prior to any control
device and prior to discharge to the atmosphere.
Group 1 storage vessel means a storage vessel at an existing source
that has a design storage 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 HAP liquid concentration greater than 4
percent by weight total organic HAP; 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 HAP liquid concentration greater than 2
percent by weight total organic HAP; or 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 HAP
liquid concentration greater than 2 percent by weight total organic
HAP.
Group 1 wastewater stream means a wastewater stream at a petroleum
refinery with a total annual benzene loading of 10 megagrams per year
or greater as calculated according to the procedures in 40 CFR 61.342
of subpart FF of part 61 that has a flow rate of 0.02 liters per minute
or greater, a benzene concentration of 10 parts per million by weight
or greater, and is not exempt from control requirements under the
provisions of 40 CFR part 61, subpart FF.
Group 2 gasoline loading rack means a gasoline loading rack
classified under Standard Industrial Classification code 2911 that does
not meet the definition of a Group 1 gasoline loading rack.
Group 2 marine tank vessel means a marine tank vessel that does not
meet the definition of a Group 1 marine tank vessel.
Group 2 miscellaneous process vent means a miscellaneous process
vent that does not meet the definition of a Group 1 miscellaneous
process vent.
Group 2 storage vessel means a storage vessel that does not meet
the definition of a Group 1 storage vessel.
Group 2 wastewater stream means a wastewater stream that does not
meet the definition of Group 1 wastewater stream.
[[Page 43265]]
Hazardous air pollutant or HAP means one of the chemicals listed in
section 112(b) of the Clean Air Act.
Incinerator means an enclosed combustion device that is used for
destroying organic compounds. Auxiliary fuel may be used to heat waste
gas to combustion temperatures. Any energy recovery section present is
not physically formed into one manufactured or assembled unit with the
combustion section; rather, the energy recovery section is a separate
section following the combustion section and the two are joined by
ducts or connections carrying flue gas.
In heavy liquid service means that the piece of equipment is not in
gas/vapor service or in light liquid service.
In light liquid service means that the piece of equipment contains
a liquid that meets the conditions specified in Sec. 60.593(d) of part
60, subpart GGG.
In organic hazardous air pollutant 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's as determined
according to the provisions of Sec. 63.180(d) of subpart H of this part
and table 1 of this subpart. The provisions of Sec. 63.180(d) of
subpart H also specify how to determine that a piece of equipment is
not in organic HAP service.
Maximum true vapor pressure means the equilibrium partial pressure
exerted by the stored liquid at the temperature equal to the highest
calendar-month average of the liquid storage temperature for liquids
stored above or below the ambient temperature or at the local maximum
monthly average temperature as reported by the National Weather Service
for liquids stored at the ambient temperature, as determined:
(1) In accordance with methods specified in Sec. 63.111 of subpart
G of this part;
(2) From standard reference texts; or
(3) By any other method approved by the Administrator.
Miscellaneous process vent means a gas stream containing greater
than 20 parts per million by volume organic HAP that is continuously or
periodically discharged during normal operation of 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 (steam) ejectors, 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;
(2) Relief valve discharges;
(3) Leaks from equipment regulated under Sec. 63.648;
(4) Episodic or nonroutine releases such as those associated with
startup, shutdown, malfunction, maintenance, depressuring, and catalyst
transfer operations;
(5) In situ sampling systems (onstream analyzers);
(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) Coking unit vents associated with coke drum depressuring at or
below a coke drum outlet pressure of 15 pounds per square inch gauge,
deheading, draining, or decoking (coke cutting) or pressure testing
after decoking; and
(12) Vents from storage vessels.
Operating permit means a permit required by 40 CFR parts 70 or 71.
Organic hazardous air pollutant or organic HAP in this subpart,
means any of the organic chemicals listed in table 1 of this subpart.
Petroleum-based solvents means mixtures of aliphatic hydrocarbons
or mixtures of one and two ring aromatic hydrocarbons.
Periodically discharged means discharges that are intermittent and
associated with routine operations. Discharges associated with
maintenance activities or process upsets are not considered
periodically discharged miscellaneous process vents and are therefore
not regulated by the petroleum refinery miscellaneous process vent
provisions.
Petroleum refining process unit means a process unit used in an
establishment primarily engaged in petroleum refining as defined in the
Standard Industrial Classification code for petroleum refining (2911),
and used primarily for the following:
(1) Producing transportation fuels (such as gasoline, diesel fuels,
and jet fuels), heating fuels (such as kerosene, fuel gas distillate,
and fuel oils), or lubricants;
(2) Separating petroleum; or
(3) Separating, cracking, reacting, or reforming intermediate
petroleum streams.
(4) Examples of such units include, but are not limited to,
petroleum-based solvent units, alkylation units, catalytic
hydrotreating, catalytic hydrorefining, catalytic hydrocracking,
catalytic reforming, catalytic cracking, crude distillation, lube oil
processing, hydrogen production, isomerization, polymerization, thermal
processes, and blending, sweetening, and treating processes. Petroleum
refining process units also include sulfur plants.
Plant site means all contiguous or adjoining property that is under
common control including properties that are separated only by a road
or other public right-of-way. Common control includes properties that
are owned, leased, or operated by the same entity, parent entity,
subsidiary, or any combination thereof.
Primary fuel means the fuel that provides the principal heat input
(i.e., more than 50 percent) to the device. To be considered primary,
the fuel must be able to sustain operation without the addition of
other fuels.
Process heater means an enclosed combustion device that primarily
transfers heat liberated by burning fuel directly to process streams or
to heat transfer liquids other than water.
Process unit means the equipment assembled and connected by pipes
or ducts to process raw and/or intermediate materials and to
manufacture an intended product. A process unit includes any associated
storage vessels. For the purpose of this subpart, process unit
includes, but is not limited to, chemical manufacturing process units
and petroleum refining process units.
Process unit shutdown means a work practice or operational
procedure that stops production from a process unit or part of a
process unit during which it is technically feasible to clear process
material from a process unit or part of a process unit consistent with
safety constraints and during which repairs can be accomplished. An
unscheduled work practice or operational procedure that stops
production from a process unit or part of a process unit for less than
24 hours is not considered a process unit shutdown. An unscheduled
[[Page 43266]]
work practice or operational procedure that would stop production from
a process unit or part of a process unit for a shorter period of time
than would be required to clear the process unit or part of the process
unit of materials and start up the unit, or would result in greater
emissions than delay of repair of leaking components until the next
scheduled process unit shutdown is not considered a process unit
shutdown. The use of spare equipment and technically feasible bypassing
of equipment without stopping production are not considered process
unit shutdowns.
Recovery device means an individual unit of equipment capable of
and used for the purpose of recovering chemicals for use, reuse, or
sale. Recovery devices include, but are not limited to, absorbers,
carbon adsorbers, and condensers.
Reference control technology for gasoline loading racks means a
vapor collection and processing system used to reduce emissions due to
the loading of gasoline cargo tanks to 10 milligrams of total organic
compounds per liter of gasoline loaded or less.
Reference control technology for marine vessels means a vapor
collection system and a control device that reduces captured HAP
emissions by 97 percent.
Reference control technology for miscellaneous process vents means
a combustion device used to reduce organic HAP emissions by 98 percent,
or to an outlet concentration of 20 parts per million by volume.
Reference control technology for storage vessels means either:
(1) 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);
(2) An external floating roof meeting the specifications of
Sec. 63.119(c) of subpart G except for Sec. 63.119(c)(2);
(3) 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
(4) 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.
(5) For purposes of emissions averaging, these four technologies
are considered equivalent.
Reference control technology for wastewater means the use of:
(1) Controls specified in Secs. 61.343 through 61.347 of subpart FF
of part 61;
(2) A treatment process that achieves the emission reductions
specified in table 7 of this subpart for each individual HAP present in
the wastewater stream or is a steam stripper that meets the
specifications in Sec. 63.138(g) of subpart G of this part; and
(3) A control device to reduce by 95 percent (or to an outlet
concentration of 20 parts per million by volume for combustion devices)
the organic HAP emissions in the vapor streams vented from treatment
processes (including the steam stripper described in paragraph (2) of
this definition) managing wastewater.
Refinery fuel gas means a gaseous mixture of methane, light
hydrocarbons, hydrogen, and other miscellaneous species (nitrogen,
carbon dioxide, hydrogen sulfide, etc.) that is produced in the
refining of crude oil and/or petrochemical processes and that is
separated for use as a fuel in boilers and process heaters throughout
the refinery.
Relief valve means a valve used only to release an unplanned,
nonroutine discharge. A relief valve discharge can result 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.
Research and development facility means laboratory and pilot plant
operations whose primary purpose is to conduct research and development
into new processes and products, where the operations are under the
close supervision of technically trained personnel, and is not engaged
in the manufacture of products for commercial sale, except in a de
minimis manner.
Storage vessel means a tank or other vessel that is used to store
organic liquids that are in organic HAP service. Storage vessel does
not include:
(1) Vessels permanently attached to motor vehicles such as trucks,
railcars, barges, or ships;
(2) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere;
(3) Vessels with capacities smaller than 40 cubic meters;
(4) Bottoms receiver tanks; or
(5) Wastewater storage tanks. Wastewater storage tanks are covered
under the wastewater provisions.
Temperature monitoring device means a unit of equipment used to
monitor temperature and having an accuracy of 1 percent of
the temperature being monitored expressed in degrees Celsius or
0.5 deg.C), whichever is greater.
Total annual benzene means the total amount of benzene in waste
streams at a facility on an annual basis as determined in Sec. 61.342
of 40 CFR part 61, subpart FF.
Total organic compounds or TOC, as used in this subpart, means
those compounds excluding methane and ethane measured according to the
procedures of Method 18 of 40 CFR part 60, appendix A. Method 25A may
be used alone or in combination with Method 18 to measure TOC as
provided in Sec. 63.645 of this subpart.
Wastewater means water or wastewater that, during production or
processing, comes into direct contact with or results from the
production or use of any raw material, intermediate product, finished
product, byproduct, or waste product and is discharged into any
individual drain system. Examples are feed tank drawdown; water formed
during a chemical reaction or used as a reactant; water used to wash
impurities from organic products or reactants; water used to cool or
quench organic vapor streams through direct contact; and condensed
steam from jet ejector systems pulling vacuum on vessels containing
organics.
Sec. 63.642 General standards.
(a) Each owner or operator of a source subject to this subpart is
required to apply for a part 70 or part 71 operating permit from the
appropriate permitting authority. If the EPA has approved a State
operating permit program under part 70, the permit shall be obtained
from the State authority. If the State operating permit program has not
been approved, the source shall apply to the EPA Regional Office
pursuant to part 71.
(b) [Reserved]
(c) Table 6 of this subpart specifies the provisions of subpart A
of this part that apply and those that do not apply to owners and
operators of sources subject to this subpart.
(d) Initial performance tests and initial compliance determinations
shall be required only as specified in this subpart.
(1) Performance tests and compliance determinations shall be
conducted according to the schedule and procedures specified in this
subpart.
(2) The owner or operator shall notify the Administrator of the
intention to conduct a performance test at least 30 days before the
performance test is scheduled.
(3) Performance tests shall be conducted according to the
provisions of Sec. 63.7(e) except that performance tests shall be
conducted at maximum representative operating capacity for the process.
During the performance test, an owner or operator shall operate the
control device at either maximum or minimum representative operating
conditions for monitored control device
[[Page 43267]]
parameters, whichever results in lower emission reduction.
(4) Data shall be reduced in accordance with the EPA-approved
methods specified in the applicable section or, if other test methods
are used, the data and methods shall be validated according to the
protocol in Method 301 of appendix A of this part.
(e) 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 this
subpart. All applicable records shall be maintained in such a manner
that they can be readily accessed. Records for the most recent 2 years
shall be retained onsite at the source or shall be accessible from a
central location by computer. The remaining 3 years of records may be
retained offsite. Records may be maintained in hard copy or computer-
readable form including, but not limited to, on paper, microfilm,
computer, floppy disk, magnetic tape, or microfiche.
(f) All reports required under this subpart shall be sent to the
Administrator at the addresses listed in Sec. 63.13 of subpart A of
this part. If acceptable to both the Administrator and the owner or
operator of a source, reports may be submitted on electronic media.
(g) The owner or operator of an existing source subject to the
requirements of this subpart shall control emissions of organic HAP's
to the level represented by the following equation:
EA = 0.02EPV1 + EPV2 +
0.025ES1 + ES2 + EGLR1C +
EGLR2 + (R)EMV1 + EMV2 +
EWW1C + EWW2
where:
EA=Emission rate, megagrams per year, allowed for the source.
0.02EPV1=Sum of the residual emissions, megagrams per
year, from all Group 1 miscellaneous process vents, as defined in
Sec. 63.641.
EPV2=Sum of the emissions, megagrams per year, from all
Group 2 process vents, as defined in Sec. 63.641.
0.05ES1=Sum of the residual emissions, megagrams per
year, from all Group 1 storage vessels, as defined in Sec. 63.641.
ES2=Sum of the emissions, megagrams per year, from all
Group 2 storage vessels, as defined in Sec. 63.641.
EGLR1C=Sum of the residual emissions, megagrams per year,
from all Group 1 gasoline loading racks, as defined in Sec. 63.641.
EGLR2=Sum of the emissions, megagrams per year, from all
Group 2 gasoline loading racks, as defined in Sec. 63.641.
(R)EMV1=Sum of the residual emissions, megagrams per
year, from all Group 1 marine tank vessels, as defined in Sec. 63.641.
R=0.03 for existing sources, 0.02 for new sources except offshore
loading terminals, and 0.05 for new offshore loading terminals.
EMV2=Sum of the emissions, megagrams per year, from all
Group 2 marine tank vessels, as defined in Sec. 63.641.
EWW1C=Sum of the residual emissions from all Group 1
wastewater streams, as defined in Sec. 63.641. This term is calculated
for each Group 1 stream according to the equation for EWWic in
Sec. 63.652(h)(6).
EWW2=Sum of emissions from all Group 2 wastewater
streams, as defined in Sec. 63.641.
The emissions level represented by this equation is dependent on
the collection of emission points in the source. The level is not fixed
and can change as the emissions from each emission point change or as
the number of emission points in the source change.
(h) The owner or operator of a new source subject to the
requirements of this subpart shall control emissions of organic HAP's
to the level represented by the equation in paragraph (g) of this
section.
(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)
of this section for all other emission points within the source.
(j) The owner or operator of a new source shall demonstrate
compliance with the emission standard in paragraph (h) of this section
only by following the procedures in paragraph (k) of this section. The
owner or operator of a new source may not use the emissions averaging
compliance approach.
(k) The owner or operator of an existing source may comply, and the
owner or operator of a new source shall comply, with the miscellaneous
process vent provisions in Secs. 63.643 through 63.645, the storage
vessel provisions in Sec. 63.646, the wastewater provisions in
Sec. 63.647, the gasoline loading rack provisions in Sec. 63.650, and
the marine tank vessel loading operation provisions in Sec. 63.651 of
this subpart.
(1) The owner or operator using this compliance approach shall also
comply with the requirements of Sec. 63.654 as applicable.
(2) The owner or operator using this compliance approach is not
required to calculate the annual emission rate specified in paragraph
(g) of this section.
(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 Secs. 63.643 through 63.647, Secs. 63.650
and 63.651 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 (l)(2) of this section.
(1) Calculate emission debits and credits for those emission points
involved in the emissions average according to the procedures specified
in Sec. 63.652; and
(2) Comply with the requirements of Secs. 63.652, 63.653, and
63.654, as applicable.
(m) A State may restrict the owner or operator of an existing
source to using only the procedures in paragraph (k) of this section to
comply with the emission standard in paragraph (g) of this section.
Such a restriction would preclude the source from using an emissions
averaging compliance approach.
Sec. 63.643 Miscellaneous process vent provisions.
(a) The owner or operator of a Group 1 miscellaneous process vent
as defined in Sec. 63.641 shall comply with the requirements of either
paragraphs (a)(1) or (a)(2) of this section.
(1) Reduce emissions of organic HAP's using a flare that meets the
requirements of Sec. 63.11(b) of subpart A of this part.
(2) Reduce emissions of organic HAP's, using a control device, by
98 weight-percent or to a concentration of 20 parts per million by
volume, on a dry basis, corrected to 3 percent oxygen, whichever is
less stringent. Compliance can be determined by measuring either
organic HAP's or TOC's using the procedures in Sec. 63.645.
(b) If a boiler or process heater is used to comply with the
percentage of reduction requirement or concentration limit specified in
paragraph (a)(2) of this section, then the vent stream shall be
introduced into the flame zone of such
[[Page 43268]]
a device, or in a location such that the required percent reduction or
concentration is achieved. Testing and monitoring is required only as
specified in Sec. 63.644(a) and Sec. 63.645 of this subpart.
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.
(1) Where an incinerator is used, a temperature monitoring device
equipped with a continuous recorder is required.
(i) Where an incinerator other than a catalytic incinerator is
used, a temperature monitoring device shall be installed in the firebox
or in the ductwork immediately downstream of the firebox in a position
before any substantial heat exchange occurs.
(ii) Where a catalytic incinerator is used, temperature monitoring
devices shall be installed in the gas stream immediately before and
after the catalyst bed.
(2) Where a flare is used, 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.
(3) Any boiler or process heater with a design heat input capacity
greater than or equal to 44 megawatt or any boiler or process heater in
which all vent streams are introduced into the flame zone is exempt
from monitoring.
(4) Any boiler or process heater less than 44 megawatts design heat
capacity where the vent stream is not introduced into the flame zone is
required to use a temperature monitoring device in the firebox equipped
with a continuous recorder.
(b) An owner or operator of a Group 1 miscellaneous process vent
may request approval to monitor parameters other than those listed in
paragraph (a) of this section. The request shall be submitted according
to the procedures specified in Sec. 63.654(h). Approval shall be
requested if the owner or operator:
(1) Uses a control device other than an incinerator, boiler,
process heater, or flare; or
(2) Uses one of the control devices listed in paragraph (a) of this
section, but seeks to monitor a parameter other than those specified in
paragraph (a) of this section.
(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 (c)(2) of
this section. Equipment such as low leg drains, high point bleeds,
analyzer vents, open-ended valves or lines, pressure relief valves
needed for safety reasons, and equipment subject to Sec. 63.648 are not
subject to this paragraph.
(1) Install, calibrate, maintain, and operate a flow indicator that
determines whether a vent stream flow is present at least once every
hour. Records shall be generated as specified in Sec. 63.654(h) and
(i). The flow indicator shall be installed at the entrance to any
bypass line that could divert the vent stream away from the control
device to the atmosphere; or
(2) Secure the bypass line valve in the closed 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 closed position and the
vent stream is not diverted through the bypass line.
(d) The owner or operator shall establish a range that ensures
compliance with the emissions standard for each parameter monitored
under paragraphs (a) and (b) of this section. In order to establish the
range, the information required in Sec. 63.654(f)(1)(ii) shall be
submitted in the Notification of Compliance Status report.
(e) Each owner or operator of a control device subject to the
monitoring provisions of this section shall operate the control device
in a manner consistent with the minimum and/or maximum operating
parameter value or procedure required to be monitored under paragraphs
(a) and (b) of this section. Operation of the control device in a
manner that constitutes a period of excess emissions, as defined in
Sec. 63.654(g)(6), or failure to perform procedures required by this
section shall constitute a violation of the applicable emission
standard of this subpart.
Sec. 63.645 Test methods and procedures for miscellaneous process
vents.
(a) To demonstrate compliance with Sec. 63.643, an owner or
operator shall follow Sec. 63.116 except for Sec. 63.116(d) and (e) of
subpart G of this part except as provided in paragraphs (b) through (d)
of this section.
(b) All references to Sec. 63.113(a)(1) or (a)(2) in Sec. 63.116 of
subpart G of this part shall be replaced with Sec. 63.643(a)(1) or
(a)(2), respectively.
(c) In Sec. 63.116(c)(4)(ii)(C) of subpart G of this part, organic
HAP's in the list of HAP's in table 1 of this subpart shall be
considered instead of the organic HAP's in table 2 of subpart F of this
part.
(d) All references to Sec. 63.116(b)(1) or (b)(2) shall be replaced
with paragraphs (d)(1) and (d)(2) of this section, respectively.
(1) Any boiler or process heater with a design heat input capacity
of 44 megawatts or greater.
(2) Any boiler or process heater in which all vent streams are
introduced into the flame zone.
(e) For purposes of determining the TOC emission rate, as specified
under paragraph (f) of this section, the sampling site shall be after
the last product recovery device (as defined in Sec. 63.641 of this
subpart) (if any recovery devices are present) but prior to the inlet
of any control device (as defined in Sec. 63.641 of this subpart) that
is present, prior to any dilution of the process vent stream, and prior
to release to the atmosphere.
(1) Methods 1 or 1A of 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling site.
(2) No traverse site selection method is needed for vents smaller
than 0.10 meter in diameter.
(f) Except as provided in paragraph (g) of this section, an owner
or operator seeking to demonstrate that a process vent TOC mass flow
rate is less than 33 kilograms per day for an existing source or less
than 6.8 kilograms per day for a new source in accordance with the
Group 2 process vent definition of this subpart shall determine the TOC
mass flow rate by the following procedures:
(1) The sampling site shall be selected as specified in paragraph
(e) of this section.
(2) The gas volumetric flow rate shall be determined using Methods
2, 2A, 2C, or 2D of 40 CFR part 60, appendix A, as appropriate.
(3) Method 18 or Method 25A of 40 CFR part 60, appendix A shall be
used to measure concentration; alternatively, any other method or data
that has been validated according to the protocol in Method 301 of
appendix A of this part may be used. If Method 25A is used, and the TOC
mass flow rate calculated from the Method 25A measurement is greater
than or equal to 33 kilograms per day for an existing source or 6.8
kilograms per day for a new source, Method 18 may be used to determine
[[Page 43269]]
any non-VOC hydrocarbons that may be deducted to calculate the TOC
(minus non-VOC hydrocarbons) concentration and mass flow rate. The
following procedures shall be used to calculate parts per million by
volume concentration:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or four grab samples shall be taken. If
grab sampling is used, then the samples shall be taken at approximately
equal intervals in time, such as 15-minute intervals during the run.
(ii) The TOC concentration (CTOC) is the sum of the
concentrations of the individual components and shall be computed for
each run using the following equation if Method 18 is used:
[GRAPHIC][TIFF OMITTED]TR18AU95.000
where:
CTOC=Concentration of TOC (minus methane and ethane), dry basis,
parts per million by volume.
Cji=Concentration of sample component j of the sample i, dry
basis, parts per million by volume.
n=Number of components in the sample.
x=Number of samples in the sample run.
(4) The emission rate of TOC (minus methane and ethane) (ETOC)
shall be calculated using the following equation if Method 18 is used:
[GRAPHIC][TIFF OMITTED]TR18AU95.001
where:
E=Emission rate of TOC (minus methane and ethane) in the sample,
kilograms per day.
K2=Constant, 2.494 x 10-6 (parts per million)-1 (gram-
mole per standard cubic meter) (kilogram per gram) (minutes per hour),
where the standard temperature (standard cubic meter) is at 20 deg.C.
Cj=Concentration on a dry basis of organic compound j in parts per
million as measured by Method 18 of 40 CFR part 60, appendix A, as
indicated in paragraph (f)(3) of this section. Cj includes all
organic compounds measured minus methane and ethane.
Mj=Molecular weight of organic compound j, gram per gram-mole.
Qs=Vent stream flow rate, dry standard cubic meters per minute, at
a temperature of 20 deg.C.
(5) If Method 25A is used the emission rate of TOC (ETOC) shall be
calculated using the following equation:
E=K2 CTOC Qs
where:
E=Emission rate of TOC (minus methane and ethane) in the sample,
kilograms per day.
K2=Constant, 2.494 x 10-6 (parts per million)-1 (gram-
mole per standard cubic meter) (kilogram per gram) (minutes per hour),
where the standard temperature (standard cubic meter) is at 20 deg.C.
CTOC=Concentration of TOC on a dry basis in parts per million
volume as measured by Method 25A of 40 CFR part 60, appendix A, as
indicated in paragraph (f)(3) of this section.
Qs=Vent stream flow rate, dry standard cubic meters per minute, at
a temperature of 20 deg.C.
(g) Engineering assessment may be used to determine the TOC
emission rate for the representative operating condition expected to
yield the highest daily emission rate.
(1) Engineering assessment includes, but is not limited to, the
following:
(i) Previous test results provided the tests are representative of
current operating practices at the process unit.
(ii) Bench-scale or pilot-scale test data representative of the
process under representative operating conditions.
(iii) TOC emission rate specified or implied within a permit limit
applicable to the process vent.
(iv) Design analysis based on accepted chemical engineering
principles, measurable process parameters, or physical or chemical laws
or properties. Examples of analytical methods include, but are not
limited to:
(A) Use of material balances based on process stoichiometry to
estimate maximum TOC concentrations;
(B) Estimation of maximum flow rate based on physical equipment
design such as pump or blower capacities; and
(C) Estimation of TOC concentrations based on saturation
conditions.
(v) All data, assumptions, and procedures used in the engineering
assessment shall be documented.
(h) The owner or operator of a Group 2 process vent shall
recalculate the TOC emission rate for each process vent, as necessary,
whenever process changes are made to determine whether the vent is in
Group 1 or Group 2. Examples of process changes include, but are not
limited to, changes in production capacity, production rate, or
catalyst type, or whenever there is replacement, removal, or addition
of recovery equipment. For purposes of this paragraph, process changes
do not include: process upsets; unintentional, temporary process
changes; and changes that are within the range on which the original
calculation was based.
(1) The TOC emission rate shall be recalculated based on
measurements of vent stream flow rate and TOC as specified in
paragraphs (e) and (f) of this section, as applicable, or on best
engineering assessment of the effects of the change. Engineering
assessments shall meet the specifications in paragraph (g) of this
section.
(2) Where the recalculated TOC emission rate is greater than 33
kilograms per day for an existing source or greater than 6.8 kilograms
per day for a new source, the owner or operator shall submit a report
as specified in Sec. 63.654 (c), (d), (e), (f), or (g), or (h) and
shall comply with the appropriate provisions in Sec. 63.643 by the
dates specified in Sec. 63.640.
Sec. 63.646 Storage vessel provisions.
(a) Each owner or operator of a Group 1 storage vessel subject to
this subpart shall comply with the requirements of Secs. 63.119 through
63.121 of subpart G of this part except as provided in paragraphs (b)
through (m) of this section.
(b) As used in this section, all terms not defined in Sec. 63.641
shall have the meaning given them in 40 CFR part 63, subparts A or G.
The Group 1 storage vessel definition presented in Sec. 63.641 shall
apply in lieu of the Group 1 storage vessel definitions presented in
tables 5 and 6 of Sec. 63.119 of subpart G of this part.
(1) An owner or operator may use good engineering judgement 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 weight percent organic HAP in the stored liquid is above or
below 4 percent for existing sources and 2 percent for new sources,
Method 18 of 40 CFR part 60, appendix A shall be used.
(c) The following paragraphs do not apply to storage vessels at
existing sources subject to this subpart: Sec. 63.119 (b)(5), (b)(6),
(c)(2), and (d)(2).
(d) References shall be replaced as specified in paragraphs (d)(1)
through (d)(9) of this section.
(1) All references to Sec. 63.100(k) of subpart F of this part (or
the schedule provisions and the compliance date) shall be replaced with
Sec. 63.640(h),
(2) All references to April 22, 1994 shall be replaced with August
18, 1995.
[[Page 43270]]
(3) All references to December 31, 1992 shall be replaced with July
15, 1994.
(4) All references to the compliance dates specified in Sec. 63.100
of subpart F shall be replaced with Sec. 63.640 (h) through (m).
(5) All references to Sec. 63.150 in Sec. 63.119 of subpart G of
this part shall be replaced with Sec. 63.652.
(6) All references to Sec. 63.113(a)(2) of subpart G shall be
replaced with Sec. 63.643(a)(2) of this subpart.
(7) All references to Sec. 63.126(b)(1) of subpart G shall be
replaced with Sec. 63.422(b) of subpart R of this part.
(8) All references to Sec. 63.128(a) of subpart G shall be replaced
with Sec. 63.425, paragraphs (a) through (c) and (e) through (h) of
subpart R of this part.
(9) All references to Sec. 63.139(d)(1) in Sec. 63.120(d)(1)(iii)
of subpart G shall be replaced with Sec. 61.355 of subpart FF of part
61.
(e) When complying with the inspection requirements of Sec. 63.120
of subpart G of this part, owners and operators of storage vessels at
existing sources subject to this subpart are not required to comply
with the provisions for gaskets, slotted membranes, and sleeve seals.
(f) The following paragraphs (f)(1), (f)(2), and (f)(3) of this
section apply to Group 1 storage vessels at existing sources:
(1) If a cover or lid is installed on an opening on a floating
roof, the cover or lid shall remain closed except when the cover or lid
must be open for access.
(2) Rim space vents are to be set to open only when the floating
roof is not floating or when the pressure beneath the rim seal exceeds
the manufacturer's recommended setting.
(3) Automatic bleeder vents are to be closed at all times when the
roof is floating except when the roof is being floated off or is being
landed on the roof leg supports.
(g) Failure to perform inspections and monitoring required by this
section shall constitute a violation of the applicable standard of this
subpart.
(h) References in Secs. 63.119 through 63.121 to Sec. 63.122(g)(1),
Sec. 63.151, and references to initial notification requirements do not
apply.
(i) References to the Implementation Plan in Sec. 63.120,
paragraphs (d)(2) and (d)(3)(i) shall be replaced with the Notification
of Compliance Status report.
(j) References to the Notification of Compliance Status report in
Sec. 63.152(b) shall be replaced with Sec. 63.654(f).
(k) References to the Periodic Reports in Sec. 63.152(c) shall be
replaced with Sec. 63.654(g).
(l) The State or local permitting authority can waive the
notification requirements of Secs. 63.120(a)(5), 63.120(a)(6),
63.120(b)(10)(ii), and 63.120(b)(10)(iii) for all or some storage
vessels at petroleum refineries subject to this subpart. The State or
local permitting authority may also grant permission to refill storage
vessels sooner than 30 days after submitting the notifications in
Secs. 63.120(a)(6) or 63.120(b)(10)(iii) for all storage vessels at a
refinery or for individual storage vessels on a case-by-case basis.
Sec. 63.647 Wastewater provisions.
(a) Except as provided in paragraph (b) of this section, each owner
or operator of a Group 1 wastewater stream shall comply with the
requirements of Secs. 61.340 through 61.355 of 40 CFR part 61, subpart
FF for each process wastewater stream that meets the definition in
Sec. 63.641.
(b) As used in this section, all terms not defined in Sec. 63.641
shall have the meaning given them in the Clean Air Act or in 40 CFR
part 61, subpart FF, Sec. 61.341.
(c) Each owner or operator required under subpart FF of 40 CFR part
61 to perform periodic measurement of benzene concentration in
wastewater, or to monitor process or control device operating
parameters shall operate in a manner consistent with the minimum or
maximum (as appropriate) permitted concentration or operating parameter
values. Operation of the process, treatment unit, or control device
resulting in a measured concentration or operating parameter value
outside the permitted limits shall constitute a violation of the
emission standards. Failure to perform required leak monitoring for
closed vent systems and control devices or failure to repair leaks
within the time period specified in subpart FF of 40 CFR part 61 shall
constitute a violation of the standard.
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 40 CFR
part 60 subpart VV 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.
(1) For purposes of compliance with this section, the provisions of
40 CFR part 60, subpart VV apply only to equipment in organic HAP
service, as defined in Sec. 63.641 of this subpart.
(2) Calculation of percentage leaking equipment components for
subpart VV of 40 CFR part 60 may be done on a process unit basis or a
sourcewide basis. Once the owner or operator has decided, all
subsequent calculations shall be on the same basis unless a permit
change is made.
(b) The use of monitoring data generated before August 18, 1995 to
qualify for less frequent monitoring of valves and pumps as provided
under 40 CFR part 60 subpart VV or subpart H of this part and paragraph
(c) of this section (i.e., quarterly or semiannually) is governed by
the requirements of paragraphs (b)(1) and (b)(2) of this section.
(1) Monitoring data must meet the test methods and procedures
specified in Sec. 60.485(b) of 40 CFR part 60, subpart VV or
Sec. 63.180(b)(1) through (b)(5) of subpart H of this part except for
minor departures.
(2) Departures from the criteria specified in Sec. 60.485(b) of 40
CFR part 60 subpart VV or Sec. 63.180(b)(1) through (b)(5) of subpart H
of this part or from the monitoring frequency specified in subpart VV
or in paragraph (c) of this section (such as every 6 weeks instead of
monthly or quarterly) are minor and do not significantly affect the
quality of the data. An example of a minor departure is monitoring at a
slightly different frequency (such as every 6 weeks instead of monthly
or quarterly). Failure to use a calibrated instrument is not considered
a minor departure.
(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 Secs. 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)(10) and (e) through
(i) of this section.
(1) The instrument readings that define a leak for light liquid
pumps subject to Sec. 63.163 of subpart H of this part and gas/vapor
and light liquid valves subject to Sec. 63.168 of subpart H of this
part are specified in table 2 of this subpart.
(2) In phase III of the valve standard, the owner or operator may
monitor valves for leaks as specified in paragraphs (c)(2)(i) or
(c)(2)(ii) of this section.
(i) If the owner or operator does not elect to monitor connectors,
then the owner or operator shall monitor valves according to the
frequency specified in table 8 of this subpart.
(ii) If an owner or operator elects to monitor connectors according
to the provisions of Sec. 63.649, paragraphs (b),
[[Page 43271]]
(c), or (d), then the owner or operator shall monitor valves at the
frequencies specified in table 9 of this subpart.
(3) The owner or operator shall decide no later than the first
required monitoring period after the phase I compliance date specified
in Sec. 63.640(h) whether to calculate the percentage leaking valves on
a process unit basis or on a sourcewide basis. Once the owner or
operator has decided, all subsequent calculations shall be on the same
basis unless a permit change is made.
(4) The owner or operator shall decide no later than the first
monitoring period after the phase III compliance date specified in
Sec. 63.640(h) whether to monitor connectors according to the
provisions in Sec. 63.649, paragraphs (b), (c), or (d).
(5) Connectors in gas/vapor service or light liquid service are
subject to the requirements for connectors in heavy liquid service in
Sec. 63.169 of subpart H of this part (except for the agitator
provisions). The leak definition for valves, connectors, and
instrumentation systems subject to Sec. 63.169 is 1,000 parts per
million.
(6) In phase III of the pump standard, except as provided in
paragraph (c)(7) of this section, owners or operators that achieve less
than 10 percent of light liquid pumps leaking or three light liquid
pumps leaking, whichever is greater, shall monitor light liquid pumps
monthly.
(7) Owners or operators that achieve less than 3 percent of light
liquid pumps leaking or one light liquid pump leaking, whichever is
greater, shall monitor light liquid pumps quarterly.
(8) An owner or operator may make the election described in
paragraphs (c)(3) and (c)(4) of this section at any time except that
any election to change after the initial election shall be treated as a
permit modification according to the terms of part 70 of this chapter.
(9) When complying with the requirements of Sec. 63.138(e)(3)(i) of
subpart H of this part, non-repairable valves shall be included in the
calculation of percent leaking valves the first time the valve is
identified as leaking and non-repairable. Otherwise, a number of non-
repairable valves up to a maximum of 1 percent per year of the total
number of valves in organic HAP service up to a maximum of 3 percent
may be excluded from calculation of percent leaking valves for
subsequent monitoring periods. When the number of non-repairable valves
exceeds 3 percent of the total number of valves in organic HAP service,
the number of non-repairable valves exceeding 3 percent of the total
number shall be included in the calculation of percent leaking valves.
(10) If in phase III of the valve standard any valve is designated,
as described in 40 CFR 60.4685(e)(2), as having no detectable emissions
the owner or operator has the option of following the provisions of
Sec. 60.482-7(f) of subpart VV of part 60. If an owner or operator
chooses to comply with the provisions of 40 CFR 60.482-7(f), the valve
is exempt from the valve monitoring provisions of Sec. 63.168 of
subpart H of this part.
(d) Upon startup of new sources, the owner or operator shall comply
with Sec. 63.163(a)(1)(ii) of subpart H of this part for light liquid
pumps and Sec. 63.168(a)(1)(ii) of subpart H of this part for gas/vapor
and light liquid valves.
(e) For reciprocating pumps in heavy liquid service, owners and
operators are not required to comply with the requirements in
Sec. 63.169 of subpart H of this part.
(f) Reciprocating pumps in light liquid service are exempt from
Secs. 63.163 and 60.482 if recasting the distance piece or
reciprocating pump replacement is required.
(g) Compressors in hydrogen service are exempt from the
requirements of paragraphs (a) and (c) of this section if an owner or
operator demonstrates that a compressor is in hydrogen service.
(1) Each compressor is presumed not to be in hydrogen service
unless an owner or operator demonstrates that the piece of equipment is
in hydrogen service.
(2) For a piece of equipment to be considered in hydrogen service,
it must be determined that the percentage hydrogen content can be
reasonably expected always to exceed 50 percent by volume.
(i) For purposes of determining the percentage hydrogen content in
the process fluid that is contained in or contacts a compressor, the
owner or operator shall use either:
(A) Procedures that conform to those specified in Sec. 60.593(b)(2)
of 40 part 60, subpart GGG.
(B) Engineering judgment to demonstrate that the percentage content
exceeds 50 percent by volume, provided the engineering judgment
demonstrates that the content clearly exceeds 50 percent by volume.
(1) When an owner or operator and the Administrator do not agree on
whether a piece of equipment is in hydrogen service, the procedures in
paragraph (g)(2)(i)(A) of this section shall be used to resolve the
disagreement.
(2) If an owner or operator determines that a piece of equipment is
in hydrogen service, the determination can be revised only by following
the procedures in paragraph (g)(2)(i)(A) of this section.
(h) Each owner or operator of a source subject to the provisions of
this subpart must maintain all records for a minimum of 5 years.
(i) Reciprocating compressors are exempt from seal requirements if
recasting the distance piece or compressor replacement is required.
Sec. 63.649 Alternative means of emission limitation: Connectors in
gas/vapor service and light liquid service.
(a) If an owner or operator elects to monitor valves according to
the provisions of Sec. 63.648(c)(2)(ii), the owner or operator shall
implement one of the connector monitoring programs specified in
paragraphs (b), (c), or (d) of this section.
(b) Random 200 connector alternative. The owner or operator shall
implement a random sampling program for accessible connectors of 2.0
inches nominal diameter or greater. The program does not apply to
inaccessible or unsafe-to-monitor connectors, as defined in Sec. 63.174
of subpart H. The sampling program shall be implemented source-wide.
(1) Within the first 12 months after the phase III compliance date
specified in Sec. 63.640(h), a sample of 200 connectors shall be
randomly selected and monitored using Method 21 of 40 CFR part 60,
appendix A.
(2) The instrument reading that defines a leak is 1,000 parts per
million.
(3) When a leak is detected, it shall be repaired as soon as
practicable, but no later than 15 calendar days after the leak is
detected except as provided in paragraph (e) of this section. A first
attempt at repair shall be made no later than 5 calendar days after the
leak is detected.
(4) If a leak is detected, the connector shall be monitored for
leaks within the first 3 months after its repair.
(5) After conducting the initial survey required in paragraph
(b)(1) of this section, the owner or operator shall conduct subsequent
monitoring of connectors at the frequencies specified in paragraphs
(b)(5)(i) through (b)(5)(iv) of this section.
(i) If the percentage leaking connectors is 2.0 percent or greater,
the owner or operator shall survey a random sample of 200 connectors
once every 6 months.
(ii) If the percentage leaking connectors is 1.0 percent or greater
but less than 2.0 percent, the owner or
[[Page 43272]]
operator shall survey a random sample of 200 connectors once per year.
(iii) If the percentage leaking connectors is 0.5 percent or
greater but less than 1.0 percent, the owner or operator shall survey a
random sample of 200 connectors once every 2 years.
(iv) If the percentage leaking connectors is less than 0.5 percent,
the owner or operator shall survey a random sample of 200 connectors
once every 4 years.
(6) Physical tagging of the connectors to indicate that they are
subject to the monitoring provisions is not required. Connectors may be
identified by the area or length of pipe and need not be individually
identified.
(c) Connector inspection alternative. The owner or operator shall
implement a program to monitor all accessible connectors in gas/vapor
service that are 2.0 inches (nominal diameter) or greater and inspect
all accessible connectors in light liquid service that are 2 inches
(nominal diameter) or greater as described in paragraphs (c)(1) through
(c)(7) of this section. The program does not apply to inaccessible or
unsafe-to-monitor connectors.
(1) Within 12 months after the phase III compliance date specified
in Sec. 63.640(h), all connectors in gas/vapor service shall be
monitored using Method 21 of 40 CFR part 60 appendix A. The instrument
reading that defines a leak is 1,000 parts per million.
(2) All connectors in light liquid service shall be inspected for
leaks. A leak is detected if liquids are observed to be dripping at a
rate greater than three drops per minute.
(3) When a leak is detected, it shall be repaired as soon as
practicable, but no later than 15 calendar days after the leak is
detected except as provided in paragraph (e) of this section. A first
attempt at repair shall be made no later than 5 calendar days after the
leak is detected.
(4) If a leak is detected, connectors in gas/vapor service shall be
monitored for leaks within the first 3 months after repair. Connectors
in light liquid service shall be inspected for indications of leaks
within the first 3 months after repair. A leak is detected if liquids
are observed to be dripping at a rate greater than three drops per
minute.
(5) After conducting the initial survey required in paragraphs
(c)(1) and (c)(2) of this section, the owner or operator shall conduct
subsequent monitoring at the frequencies specified in paragraphs
(c)(5)(i) through (c)(5)(iii) of this section.
(i) If the percentage leaking connectors is 2.0 percent or greater,
the owner or operator shall monitor or inspect, as applicable, the
connectors once per year.
(ii) If the percentage leaking connectors is 1.0 percent or greater
but less than 2.0 percent, the owner or operator shall monitor or
inspect, as applicable, the connectors once every 2 years.
(iii) If the percentage leaking connectors is less than 1.0
percent, the owner or operator shall monitor or inspect, as applicable,
the connectors once every 4 years.
(6) The percentage leaking connectors shall be calculated for
connectors in gas/vapor service and for connectors in light liquid
service. The data for the two groups of connectors shall not be pooled
for the purpose of determining the percentage leaking connectors.
(i) The percentage leaking connectors shall be calculated as
follows:
% CL=[(CL-CAN)/Ct+Cc)] x 100
where:
% CL=Percentage leaking connectors.
CL=Number of connectors including nonrepairables, measured at
1,000 parts per million or greater, by Method 21 of 40 CFR part 60,
Appendix A.
CAN=Number of allowable nonrepairable connectors, as determined by
monitoring, not to exceed 3 percent of the total connector population,
Ct.
Ct=Total number of monitored connectors, including nonrepairables,
in the process unit.
Cc=Optional credit for removed connectors=0.67 x net number (i.e.,
the total number of connectors removed minus the total added) of
connectors in organic HAP service removed from the process unit after
the applicability date set forth in Sec. 63.640(h)(4)(iii) for existing
process units, and after the date of start-up for new process units. If
credits are not taken, then Cc=0.
(ii) Nonrepairable connectors shall be included in the calculation
of percentage leaking connectors the first time the connector is
identified as leaking and nonrepairable. Otherwise, a number of
nonrepairable connectors up to a maximum of 1 percent per year of the
total number of connectors in organic HAP service up to a maximum of 3
percent may be excluded from calculation of percentage leaking
connectors for subsequent monitoring periods.
(iii) If the number of nonrepairable connectors exceeds 3 percent
of the total number of connectors in organic HAP service, the number of
nonrepairable connectors exceeding 3 percent of the total number shall
be included in the calculation of the percentage leaking connectors.
(7) Physical tagging of the connectors to indicate that they are
subject to the monitoring provisions is not required. Connectors may be
identified by the area or length of pipe and need not be individually
identified.
(d) Subpart H program. The owner or operator shall implement a
program to comply with the provisions in Sec. 63.174 of this part.
(e) Delay of repair of connectors for which leaks have been
detected is allowed if repair is not technically feasible by normal
repair techniques without a process unit shutdown. Repair of this
equipment shall occur by the end of the next process unit shutdown.
(1) Delay of repair is allowed for equipment that is isolated from
the process and that does not remain in organic HAP service.
(2) Delay of repair for connectors is also allowed if:
(i) The owner or operator determines that emissions of purged
material resulting from immediate repair would be greater than the
fugitive emissions likely to result from delay of repair, and
(ii) When repair procedures are accomplished, the purged material
would be collected and destroyed or recovered in a control device.
(f) Any connector that is designated as an unsafe-to-repair
connector is exempt from the requirements of paragraphs (b)(3) and
(b)(4), (c)(3) and (c)(4), or (d) of this section if:
(1) The owner or operator determines that repair personnel would be
exposed to an immediate danger as a consequence of complying with
paragraphs (b)(3) and (b)(4), (c)(3) and (c)(4), of this section; or
(2) The connector will be repaired before the end of the next
scheduled process unit shutdown.
(g) The owner or operator shall maintain records to document that
the connector monitoring or inspections have been conducted as required
and to document repair of leaking connectors as applicable.
Sec. 63.650 Gasoline loading rack provisions.
(a) Except as provided in paragraphs (b) through (c) of this
section, 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
shall comply with subpart R, Secs. 63.421, 63.422(a) through (d),
63.425(a) through (c), 63.425(e) through (h), 63.427(a) and (b), and
[[Page 43273]]
63.428(b), (c), (g)(1), and (h)(1) through (h)(3).
(b) As used in this section, all terms not defined in Sec. 63.641
shall have the meaning given them in subpart A or in 40 CFR part 63,
subpart R. The Sec. 63.641 definition of ``affected source'' applies
under this section.
(c) Gasoline loading racks regulated under this subpart are subject
to the compliance dates specified in Sec. 63.640(h).
Sec. 63.651 Marine tank vessel loading operation provisions.
(a) Except as provided in paragraphs (b) through (c) of this
section, each owner or operator of a marine tank vessel loading
operation located at a petroleum refinery shall comply with the
requirements of Secs. 63.560 through 63.567 of 40 CFR part 63, subpart
Y.
(b) As used in this section, all terms not defined in Sec. 63.641
shall have the meaning given them in subpart A or in 40 CFR part 63,
subpart Y. The Sec. 63.641 definition of ``affected source'' applies
under this section.
(c) The Initial Notification Report under Sec. 63.567(b) is not
required.
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 Secs. 63.643 through 63.647, and
Secs. 63.650 and 63.651. Existing marine tank vessel loading operations
unable to comply with the standard by using emissions averaging are
those marine tank vessels subject to 40 CFR 63.562(e) of this part and
the Valdez Marine Terminal source.
(b) The owner or operator shall develop and submit for approval an
Implementation Plan containing all of the information required in
Sec. 63.653(d) for all points to be included in an emissions average.
The Implementation Plan shall identify all emission points to be
included in the emissions average. This must include any Group 1
emission points to which the reference control technology (defined in
Sec. 63.641) is not applied and all other emission points being
controlled as part of the average.
(c) The following emission points can be used to generate emissions
averaging credits if control was applied after November 15, 1990 and if
sufficient information is available to determine the appropriate value
of credits for the emission point:
(1) Group 2 emission points;
(2) Group 1 storage vessels, Group 1 wastewater streams, Group 1
gasoline loading racks, Group 1 marine tank vessels, and Group 1
miscellaneous process vents that are controlled by a technology that
the Administrator or permitting authority agrees has a higher nominal
efficiency than the reference control technology. Information on the
nominal efficiencies for such technologies must be submitted and
approved as provided in paragraph (i) of this section; and
(3) Emission points from which emissions are reduced by pollution
prevention measures. Percentages of reduction for pollution prevention
measures shall be determined as specified in paragraph (j) of this
section.
(i) For a Group 1 emission point, the pollution prevention measure
must reduce emissions more than the reference control technology would
have had the reference control technology been applied to the emission
point instead of the pollution prevention measure except as provided in
paragraph (c)(3)(ii) of this section.
(ii) If a pollution prevention measure is used in conjunction with
other controls for a Group 1 emission point, the pollution prevention
measure alone does not have to reduce emissions more than the reference
control technology, but the combination of the pollution prevention
measure and other controls must reduce emissions more than the
reference control technology would have had it been applied instead.
(d) The following emission points cannot be used to generate
emissions averaging credits:
(1) Emission points already controlled on or before November 15,
1990 unless the level of control is increased after November 15, 1990,
in which case credit will be allowed only for the increase in control
after November 15, 1990;
(2) Group 1 emission points that are controlled by a reference
control technology unless the reference control technology has been
approved for use in a different manner and a higher nominal efficiency
has been assigned according to the procedures in paragraph (i) of this
section. For example, it is not allowable to claim that an internal
floating roof meeting only the specifications stated in the reference
control technology definition in Sec. 63.641 (i.e., that meets the
specifications of Sec. 63.119(b) of subpart G but does not have
controlled fittings per Sec. 63.119 (b)(5) and (b)(6) of subpart G)
applied to a storage vessel is achieving greater than 95 percent
control;
(3) Emission points on shutdown process units. Process units that
are shut down cannot be used to generate credits or debits;
(4) Wastewater that is not process wastewater or wastewater streams
treated in biological treatment units. These two types of wastewater
cannot be used to generate credits or debits. Group 1 wastewater
streams cannot be left undercontrolled or uncontrolled to generate
debits. For the purposes of this section, the terms ``wastewater'' and
``wastewater stream'' are used to mean process wastewater; and
(5) Emission points controlled to comply with a State or Federal
rule other than this subpart, unless the level of control has been
increased after November 15, 1990 above what is required by the other
State or Federal rule. Only the control above what is required by the
other State or Federal rule will be credited. However, if an emission
point has been used to generate emissions averaging credit in an
approved emissions average, and the point is subsequently made subject
to a State or Federal rule other than this subpart, the point can
continue to generate emissions averaging credit for the purpose of
complying with the previously approved average.
(e) For all points included in an emissions average, the owner or
operator shall:
(1) Calculate and record monthly debits for all Group 1 emission
points that are controlled to a level less stringent than the reference
control technology for those emission points. Equations in paragraph
(g) of this section shall be used to calculate debits.
(2) Calculate and record monthly credits for all Group 1 or Group 2
emission points that are overcontrolled to compensate for the debits.
Equations in paragraph (h) of this section shall be used to calculate
credits. Emission points and controls that meet the criteria of
paragraph (c) of this section may be included in the credit
calculation, whereas those described in paragraph (d) of this section
shall not be included.
(3) Demonstrate that annual credits calculated according to
paragraph (h) of this section are greater than or equal to debits
calculated for the same annual compliance period according to paragraph
(g) of this section.
(i) The initial demonstration in the Implementation Plan that
credit-generating emission points will be capable of generating
sufficient credits to offset the debits from the debit-generating
emission points must be made under representative operating conditions.
(ii) After the compliance date, actual operating data will be used
for all debit and credit calculations.
[[Page 43274]]
(4) Demonstrate that debits calculated for a quarterly (3-month)
period according to paragraph (g) of this section are not more than
1.30 times the credits for the same period calculated according to
paragraph (h) of this section. Compliance for the quarter shall be
determined based on the ratio of credits and debits from that quarter,
with 30 percent more debits than credits allowed on a quarterly basis.
(5) Record and report quarterly and annual credits and debits in
the Periodic Reports as specified in Sec. 63.654(g)(8). Every fourth
Periodic Report shall include a certification of compliance with the
emissions averaging provisions as required by Sec. 63.654(g)(8)(iii).
(f) Debits and credits shall be calculated in accordance with the
methods and procedures specified in paragraphs (g) and (h) of this
section, respectively, and shall not include emissions from the
following:
(1) More than 20 individual emission points. Where pollution
prevention measures (as specified in paragraph (j)(1) of this section)
are used to control emission points to be included in an emissions
average, no more than 25 emission points may be included in the
average. For example, if two emission points to be included in an
emissions average are controlled by pollution prevention measures, the
average may include up to 22 emission points.
(2) Periods of startup, shutdown, and malfunction as described in
the source's startup, shutdown, and malfunction plan required by
Sec. 63.6(e)(3) of subpart A of this part.
(3) For emission points for which continuous monitors are used,
periods of excess emissions as defined in Sec. 63.654(g)(6)(i). For
these periods, the calculation of monthly credits and debits shall be
adjusted as specified in paragraphs (f)(3)(i) through (f)(3)(iii) of
this section.
(i) No credits would be assigned to the credit-generating emission
point.
(ii) Maximum debits would be assigned to the debit-generating
emission point.
(iii) The owner or operator may use the procedures in paragraph (l)
of this section to demonstrate to the Administrator that full or
partial credits or debits should be assigned.
(g) Debits are generated by the difference between the actual
emissions from a Group 1 emission point that is uncontrolled or is
controlled to a level less stringent than the reference control
technology, and the emissions allowed for Group 1 emission point.
Debits shall be calculated as follows:
(1) The overall equation for calculating sourcewide debits is:
[GRAPHIC][TIFF OMITTED]TR18AU95.002
where:
Debits and all terms of the equation are in units of megagrams per
month, and
EPViACTUAL=Emissions from each Group 1 miscellaneous process vent
i that is uncontrolled or is controlled to a level less stringent than
the reference control technology. This is calculated according to
paragraph (g)(2) of this section.
(0.02) EPViu=Emissions from each Group 1 miscellaneous process
vent i if the reference control technology had been applied to the
uncontrolled emissions, calculated according to paragraph (g)(2) of
this section.
ESiACTUAL=Emissions from each Group 1 storage vessel i that is
uncontrolled or is controlled to a level less stringent than the
reference control technology. This is calculated according to paragraph
(g)(3) of this section.
(0.05) ESiu=Emissions from each Group 1 storage vessel i if the
reference control technology had been applied to the uncontrolled
emissions, calculated according to paragraph (g)(3) of this section.
EGLRiACTUAL=Emissions from each Group 1 gasoline loading rack i
that is uncontrolled or is controlled to a level less stringent than
the reference control technology. This is calculated according to
paragraph (g)(4) of this section.
EGLRic=Emissions from each Group 1 gasoline loading rack i if the
reference control technology had been applied to the uncontrolled
emissions. This is calculated according to paragraph (g)(4) of this
section.
EMVACTUAL=Emissions from each Group 1 marine tank vessel i that is
uncontrolled or is controlled to a level less stringent than the
reference control technology. This is calculated according to paragraph
(g)(5) of this section.
(0.03) EMViu=Emissions from each Group 1 marine tank vessel i if
the reference control technology had been applied to the uncontrolled
emissions calculated according to paragraph (g)(5) of this section.
n=The number of Group 1 emission points being included in the emissions
average. The value of n is not necessarily the same for each kind of
emission point.
(2) Emissions from miscellaneous process vents shall be calculated
as follows:
(i) For purposes of determining miscellaneous process vent stream
flow rate, organic HAP concentrations, and temperature, the sampling
site shall be after the final product recovery device, if any recovery
devices are present; before any control device (for miscellaneous
process vents, recovery devices shall not be considered control
devices); and before discharge to the atmosphere. Method 1 or 1A of
part 60, appendix A shall be used for selection of the sampling site.
(ii) The following equation shall be used for each miscellaneous
process vent i to calculate EPViu:
[GRAPHIC][TIFF OMITTED]TR18AU95.003
where:
EPViu=Uncontrolled process vent emission rate from miscellaneous
process vent i, megagrams per month.
Q=Vent stream flow rate, dry standard cubic meters per minute, measured
using Methods 2, 2A, 2C, or 2D of part 60 appendix A, as appropriate.
h=Monthly hours of operation during which positive flow is present in
the vent, hours per month.
Cj=Concentration, parts per million by volume, dry basis, of
organic HAP j as measured by Method 18 of part 60 appendix A.
[[Page 43275]]
Mj=Molecular weight of organic HAP j, gram per gram-mole.
n=Number of organic HAP's in the miscellaneous process vent stream.
(A) The values of Q, Cj, and Mj shall be determined
during a performance test conducted under representative operating
conditions. The values of Q, Cj, and Mj shall be established
in the Notification of Compliance Status report and must be updated as
provided in paragraph (g)(2)(ii)(B) of this section.
(B) If there is a change in capacity utilization other than a
change in monthly operating hours, or if any other change is made to
the process or product recovery equipment or operation such that the
previously measured values of Q, Cj, and Mj are no longer
representative, a new performance test shall be conducted to determine
new representative values of Q, Cj, and Mj. These new values
shall be used to calculate debits and credits from the time of the
change forward, and the new values shall be reported in the next
Periodic Report.
(iii) The following procedures and equations shall be used to
calculate EPViACTUAL:
(A) If the vent is not controlled by a control device or pollution
prevention measure, EPViACTUAL = EPViu, where EPViu is
calculated according to the procedures in paragraphs (g)(2)(i) and
(g)(2)(ii) of this section.
(B) If the vent is controlled using a control device or a pollution
prevention measure achieving less than 98-percent reduction,
[GRAPHIC][TIFF OMITTED]TR18AU95.004
(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 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.
(2) For determining debits from miscellaneous process vents,
product recovery devices shall not be considered control devices and
cannot be assigned a percentage of reduction in calculating
EPViACTUAL. The sampling site for measurement of uncontrolled
emissions is after the final product recovery device.
(3) Procedures for calculating the percentage of reduction of
pollution prevention measures are specified in paragraph (j) of this
section.
(3) Emissions from storage vessels shall be calculated as specified
in Sec. 63.150(g)(3) of subpart G.
(4) Emissions from gasoline loading racks shall be calculated as
follows:
(i) The following equation shall be used for each gasoline loading
rack i to calculate EGLRiu:
[GRAPHIC][TIFF OMITTED]TR18AU95.005
where:
EGLRiu=Uncontrolled transfer HAP emission rate from gasoline
loading rack i, megagrams per month
S=Saturation factor, dimensionless (see table 33 of subpart G).
P=Weighted average rack partial pressure of organic HAP's transferred
at the rack during the month, kilopascals.
M=Weighted average molecular weight of organic HAP's transferred at the
gasoline loading rack during the month, gram per gram-mole.
G=Monthly volume of gasoline transferred from gasoline loading rack,
liters per month.
T=Weighted rack bulk liquid loading temperature during the month,
degrees kelvin (degrees Celsius deg.C + 273).
(ii) The following equation shall be used for each gasoline loading
rack i to calculate the weighted average rack partial pressure:
[GRAPHIC][TIFF OMITTED]TR18AU95.006
where:
Pj=Maximum true vapor pressure of individual organic HAP
transferred at the rack, kilopascals.
G=Monthly volume of organic HAP transferred, liters per month, and
[GRAPHIC][TIFF OMITTED]TR18AU95.007
Gj=Monthly volume of individual organic HAP transferred at the
gasoline loading rack, liters per month.
n=Number of organic HAP's transferred at the gasoline loading rack.
[[Page 43276]]
(iii) The following equation shall be used for each gasoline
loading rack i to calculate the weighted average rack molecular weight:
[GRAPHIC][TIFF OMITTED]TR18AU95.008
where:
Mj=Molecular weight of individual organic HAP transferred at the
rack, gram per gram-mole.
G, Gj, and n are as defined in paragraph (g)(4)(ii) of this
section.
(iv) The following equation shall be used for each gasoline loading
rack i to calculate the monthly weighted rack bulk liquid loading
temperature:
[GRAPHIC][TIFF OMITTED]TR18AU95.009
Tj=Average annual bulk temperature of individual organic HAP
loaded at the gasoline loading rack, kelvin (degrees Celsius
deg.C+273).
G, Gj, and n are as defined in paragraph (g)(4)(ii) of this
section.
(v) The following equation shall be used to calculate EGLRic:
[GRAPHIC][TIFF OMITTED]TR18AU95.010
G is as defined in paragraph (g)(4)(ii) of this section.
(vi) The following procedures and equations shall be used to
calculate EGLRiACTUAL:
(A) If the gasoline loading rack is not controlled,
EGLRiACTUAL=EGLRiu, where EGLRiu is calculated using the
equations specified in paragraphs (g)(4)(i) through (g)(4)(iv) of this
section.
(B) If the gasoline loading rack is controlled using a control
device or a pollution prevention measure not achieving the requirement
of less than 10 milligrams of TOC per liter of gasoline loaded,
[GRAPHIC][TIFF OMITTED]TR18AU95.012
(1) The percent reduction for a control device shall be measured
according to the procedures and test methods specified in
Sec. 63.128(a) of subpart G. If testing is not feasible, the percentage
of reduction shall be determined through a design evaluation according
to the procedures specified in Sec. 63.128(h) of subpart G.
(2) Procedures for calculating the percentage of reduction for
pollution prevention measures are specified in paragraph (j) of this
section.
(5) Emissions from marine tank vessel loading shall be calculated
as follows:
(i) The following equation shall be used for each marine tank
vessel i to calculate EMViu:
[GRAPHIC][TIFF OMITTED]TR18AU95.012
where:
EMViu=Uncontrolled marine tank vessel HAP emission rate from
marine tank vessel i, megagrams per month.
Qi=Quantity of commodity loaded (per vessel type), liters.
Fi=Emission factor, megagrams per liter.
Pi=Percent HAP.
m=Number of combinations of commodities and vessel types loaded.
Emission factors shall be based on test data or emission estimation
procedures specified in Sec. 63.565(l) of subpart Y.
(ii) The following procedures and equations shall be used to
calculate EMViACTUAL:
(A) If the marine tank vessel is not controlled,
EMViACTUAL=EMViu, where EMViu is calculated using the
equations specified in paragraph (g)(5)(i) of this section.
(B) If the marine tank vessel is controlled using a control device
or a pollution prevention measure achieving less than 97-percent
reduction,
[GRAPHIC][TIFF OMITTED]TR18AU95.013
(1) The percent reduction for a control device shall be measured
according to the procedures and test methods specified in
Sec. 63.565(c) of subpart Y. If testing is not feasible, the percentage
of reduction shall be determined through a design evaluation according
to the procedures specified in Sec. 63.128(h) of subpart G.
(2) Procedures for calculating the percentage of reduction for
pollution prevention measures are specified in paragraph (j) of this
section.
(h) Credits are generated by the difference between emissions that
are allowed for each Group 1 and Group 2 emission point and the actual
emissions from a Group 1 or Group 2 emission point that has been
controlled after November 15, 1990 to a level more stringent than what
is required by this subpart or any other State or Federal rule or
statute. Credits shall be calculated as follows:
(1) The overall equation for calculating sourcewide credits is:
[GRAPHIC][TIFF OMITTED]TR18AU95.014
[[Page 43277]]
where:
Credits and all terms of the equation are in units of megagrams per
month, the baseline date is November 15, 1990, and
D=Discount factor=0.9 for all credit-generating emission points except
those controlled by a pollution prevention measure, which will not be
discounted.
EPV1iACTUAL=Emissions for each Group 1 miscellaneous process vent
i that is controlled to a level more stringent than the reference
control technology, calculated according to paragraph (h)(2) of this
section.
(0.02) EPV1iu=Emissions from each Group 1 miscellaneous process
vent i if the reference control technology had been applied to the
uncontrolled emissions. EPV1iu is calculated according to
paragraph (h)(2) of this section.
EPV2iBASE=Emissions from each Group 2 miscellaneous process vent;
at the baseline date, as calculated in paragraph (h)(2) of this
section.
EPV2iACTUAL=Emissions from each Group 2 miscellaneous process vent
that is controlled, calculated according to paragraph (h)(2) of this
section.
ES1iACTUAL=Emissions from each Group 1 storage vessel i that is
controlled to a level more stringent than the reference control
technology, calculated according to paragraph (h)(3) of this section.
(0.05) ES1iu=Emissions from each Group 1 storage vessel i if the
reference control technology had been applied to the uncontrolled
emissions. ES1iu is calculated according to paragraph (h)(3) of
this section.
ES2iACTUAL=Emissions from each Group 2 storage vessel i that is
controlled, calculated according to paragraph (h)(3) of this section.
ES2iBASE=Emissions from each Group 2 storage vessel i at the
baseline date, as calculated in paragraph (h)(3) of this section.
EGLR1iACTUAL=Emissions from each Group 1 gasoline loading rack i
that is controlled to a level more stringent than the reference control
technology, calculated according to paragraph (h)(4) of this section.
EGLRic=Emissions from each Group 1 gasoline loading rack i if the
reference control technology had been applied to the uncontrolled
emissions. EGLRiu is calculated according to paragraph (h)(4) of
this section.
EGRL2iACTUAL=Emissions from each Group 2 gasoline loading rack i
that is controlled, calculated according to paragraph (h)(4) of this
section.
EGLR2iBASE=Emissions from each Group 2 gasoline loading rack i at
the baseline date, as calculated in paragraph (h)(4) of this section.
EMV1iACTUAL=Emissions from each Group 1 marine tank vessel i that
is controlled to a level more stringent than the reference control
technology, calculated according to paragraph (h)(4) of this section.
(0.03)EMV1iu=Emissions from each Group 1 marine tank vessel i if
the reference control technology had been applied to the uncontrolled
emissions. EMV1iu is calculated according to paragraph (h)(5) of
this section.
EMV2iACTUAL=Emissions from each Group 2 marine tank vessel i that
is controlled, calculated according to paragraph (h)(5) of this
section.
EMV2iBASE=Emissions from each Group 2 marine tank vessel i at the
baseline date, as calculated in paragraph (h)(5) of this section.
EWW1iACTUAL=Emissions from each Group 1 wastewater stream i that
is controlled to a level more stringent than the reference control
technology, calculated according to paragraph (h)(6) of this section.
EWW1ic=Emissions from each Group 1 wastewater stream i if the
reference control technology had been applied to the uncontrolled
emissions, calculated according to paragraph (h)(6) of this section.
EWW2iACTUAL=Emissions from each Group 2 wastewater stream i that
is controlled, calculated according to paragraph (h)(6) of this
section.
EWW2iBASE=Emissions from each Group 2 wastewater stream i at the
baseline date, calculated according to paragraph (h)(6) of this
section.
n=Number of Group 1 emission points included in the emissions average.
The value of n is not necessarily the same for each kind of emission
point.
m=Number of Group 2 emission points included in the emissions average.
The value of m is not necessarily the same for each kind of emission
point.
(i) For an emission point controlled using a reference control
technology, the percentage of reduction for calculating credits shall
be no greater than the nominal efficiency associated with the reference
control technology, unless a higher nominal efficiency is assigned as
specified in paragraph (h)(1)(ii) of this section.
(ii) For an emission point controlled to a level more stringent
than the reference control technology, the nominal efficiency for
calculating credits shall be assigned as described in paragraph (i) of
this section. A reference control technology may be approved for use in
a different manner and assigned a higher nominal efficiency according
to the procedures in paragraph (i) of this section.
(iii) For an emission point controlled using a pollution prevention
measure, the nominal efficiency for calculating credits shall be
determined as described in paragraph (j) of this section.
(2) Emissions from process vents shall be determined as follows:
(i) Uncontrolled emissions from miscellaneous process vents,
EPV1iu, shall be calculated according to the procedures and
equation for EPViu in paragraphs (g)(2)(i) and (g)(2)(ii) of this
section.
(ii) Actual emissions from miscellaneous process vents controlled
using a technology with an approved nominal efficiency greater than 98
percent or a pollution prevention measure achieving greater than 98
percent emission reduction, EPV1iACTUAL, shall be calculated
according to the following equation:
[GRAPHIC][TIFF OMITTED]TR18AU95.015
(iii) The following procedures shall be used to calculate actual
emissions from Group 2 process vents, EPV2iACTUAL:
(A) For a Group 2 process vent controlled by a control device, a
recovery device applied as a pollution prevention project, or a
pollution prevention measure, if the control achieves a percentage of
reduction less than or equal to a 98 percent reduction,
[[Page 43278]]
[GRAPHIC][TIFF OMITTED]TR18AU95.016
(1) EPV2iu shall be calculated according to the equations and
procedures for EPViu in paragraphs (g)(2)(i) and (g)(2)(ii) of
this section except as provided in paragraph (h)(2)(iii)(A)(3) of this
section.
(2) The percentage of reduction shall be calculated according to
the procedures in paragraphs (g)(2)(iii)(B)(1) through
(g)(2)(iii)(B)(3) of this section except as provided in paragraph
(h)(2)(iii)(A)(4) of this section.
(3) If a recovery device was added as part of a pollution
prevention project, EPV2iu shall be calculated prior to that
recovery device. The equation for EPViu in paragraph (g)(2)(ii) of
this section shall be used to calculate EPV2iu; however, the
sampling site for measurement of vent stream flow rate and organic HAP
concentration shall be at the inlet of the recovery device.
(4) If a recovery device was added as part of a pollution
prevention project, the percentage of reduction shall be demonstrated
by conducting a performance test at the inlet and outlet of that
recovery device.
(B) For a Group 2 process vent controlled using a technology with
an approved nominal efficiency greater than a 98 percent or a pollution
prevention measure achieving greater than 98 percent reduction,
[GRAPHIC][TIFF OMITTED]TR18AU95.017
(iv) Emissions from Group 2 process vents at baseline,
EPV2iBASE, shall be calculated as follows:
(A) If the process vent was uncontrolled on November 15, 1990,
EPV2iBASE=EPV2iu, and shall be calculated according to the
procedures and equation for EPViu in paragraphs (g)(2)(i) and
(g)(2)(ii) of this section.
(B) If the process vent was controlled on November 15, 1990,
[GRAPHIC][TIFF OMITTED]TR18AU95.018
where EPV2iu is calculated according to the procedures and
equation for EPViu in paragraphs (g)(2)(i) and (g)(2)(ii) of this
section. The percentage of reduction shall be calculated according to
the procedures specified in paragraphs (g)(2)(iii)(B)(1) through
(g)(2)(iii)(B)(3) of this section.
(C) If a recovery device was added to a process vent as part of a
pollution prevention project initiated after November 15, 1990,
EPV2iBASE=EPV2iu, where EPV2iu is calculated according
to paragraph (h)(2)(iii)(A)(3) of this section.
(3) Emissions from storage vessels shall be determined as specified
in Sec. 63.150(h)(3) of subpart G, except as follows:
(i) 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).
(ii) 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).
(iii) 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).
(4) Emissions from gasoline loading racks shall be determined as
follows:
(i) Uncontrolled emissions from Group 1 gasoline loading racks,
EGLR1iu, shall be calculated according to the procedures and
equations for EGLRiu as described in paragraphs (g)(4)(i) through
(g)(4)(iv) of this section.
(ii) Emissions from Group 1 gasoline loading racks if the reference
control technology had been applied, EGLRic, shall be calculated
according to the procedures and equations in paragraph (g)(4)(v) of
this section.
(iii) Actual emissions from Group 1 gasoline loading racks
controlled to less than 10 milligrams of TOC per liter of gasoline
loaded; EGLRiACTUAL, shall be calculated according to the
following equation:
[GRAPHIC][TIFF OMITTED]TR18AU95.019
(iv) The following procedures shall be used to calculate actual
emissions from Group 2 gasoline loading racks, EGLR2iACTUAL:
(A) For a Group 2 gasoline loading rack controlled by a control
device or a pollution prevention measure achieving emissions reduction
but where emissions are greater than the 10 milligrams of TOC per liter
of gasoline loaded requirement,
[GRAPHIC][TIFF OMITTED]TR18AU95.020
[[Page 43279]]
(1) EGLR2iu shall be calculated according to the equations and
procedures for EGLRiu in paragraphs (g)(4)(i) through (g)(4)(iv)
of this section.
(2) The percentage of reduction shall be calculated according to
the procedures in paragraphs (g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of
this section.
(B) For a Group 2 gasoline loading rack controlled by using a
technology with an approved nominal efficiency greater than 98 percent
or a pollution prevention measure achieving greater than a 98-percent
reduction,
[GRAPHIC][TIFF OMITTED]TR18AU95.021
(v) Emissions from Group 2 gasoline loading racks at baseline,
EGLR2iBASE, shall be calculated as follows:
(A) If the gasoline loading rack was uncontrolled on November 15,
1990, EGLR2iBASE=EGLR2iu, and shall be calculated according
to the procedures and equations for EGLRiu in paragraphs (g)(4)(i)
through (g)(4)(iv) of this section.
(B) If the gasoline loading rack was controlled on November 15,
1990,
[GRAPHIC][TIFF OMITTED]TR18AU95.022
where EGLR2iu is calculated according to the procedures and
equations for EGLRiu in paragraphs (g)(4)(i) through (g)(4)(iv) of
this section. Percentage of reduction shall be calculated according to
the procedures in paragraphs (g)(4)(vi)(B)(1) and (g)(4)(vi)(B)(2) of
this section.
(5) Emissions from marine tank vessels shall be determined as
follows:
(i) Uncontrolled emissions from Group 1 marine tank vessels,
EMV1iu, shall be calculated according to the procedures and
equations for EMViu as described in paragraph (g)(5)(i) of this
section.
(ii) Actual emissions from Group 1 marine tank vessels controlled
using a technology or pollution prevention measure with an approved
nominal efficiency greater than 97 percent, EMViACTUAL, shall be
calculated according to the following equation:
[GRAPHIC][TIFF OMITTED]TR18AU95.023
(iii) The following procedures shall be used to calculate actual
emissions from Group 2 marine tank vessels, EMV2iACTUAL:
(A) For a Group 2 marine tank vessel controlled by a control device
or a pollution prevention measure achieving a percentage of reduction
less than or equal to 97 percent reduction,
[GRAPHIC][TIFF OMITTED]TR18AU95.024
(1) EMV2iu shall be calculated according to the equations and
procedures for EMViu in paragraph (g)(5)(i) of this section.
(2) The percentage of reduction shall be calculated according to
the procedures in paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of
this section.
(B) For a Group 2 marine tank vessel controlled using a technology
or a pollution prevention measure with an approved nominal efficiency
greater than 97 percent,
[GRAPHIC][TIFF OMITTED]TR18AU95.025
(iv) Emissions from Group 2 marine tank vessels at baseline,
EMV2iBASE, shall be calculated as follows:
(A) If the marine terminal was uncontrolled on November 15, 1990,
EMV2iBASE equals EMV2iu, and shall be calculated according to
the procedures and equations for EMViu in paragraph (g)(5)(i) of
this section.
(B) If the marine tank vessel was controlled on November 15, 1990,
[[Page 43280]]
[GRAPHIC][TIFF OMITTED]TR18AU95.026
where EMV2iu is calculated according to the procedures and
equations for EMViu in paragraph (g)(5)(i) of this section.
Percentage of reduction shall be calculated according to the procedures
in paragraphs (g)(5)(ii)(B)(1) and (g)(5)(ii)(B)(2) of this section.
(6) Emissions from wastewater shall be determined as follows:
(i) For purposes of paragraphs (h)(4)(ii) through (h)(4)(vi) of
this section, the following terms will have the meaning given them in
paragraphs (h)(6)(i)(A) through (h)(6)(i)(C) of this section.
(A) Correctly suppressed means that a wastewater stream is being
managed according to the requirements of Secs. 61.343 through 61.347 or
Sec. 61.342(c)(l)(iii) of 40 CFR part 61, subpart FF, as applicable,
and the emissions from the waste management units subject to those
requirements are routed to a control device that reduces HAP emissions
by 95 percent or greater.
(B) Treatment process has the meaning given in Sec. 61.341 of 40
CFR part 61, subpart FF except that it does not include biological
treatment units.
(C) Vapor control device means the control device that receives
emissions vented from a treatment process or treatment processes.
(ii) The following equation shall be used for each wastewater
stream i to calculate EWWic:
[GRAPHIC][TIFF OMITTED]TR18AU95.027
where:
EWWic = Monthly wastewater stream emission rate if wastewater
stream i were controlled by the reference control technology, megagrams
per month.
Qi = Average flow rate for wastewater stream i, liters per minute.
Hi = Number of hours during the month that wastewater stream i was
generated, hours per month.
Frm=Fraction removed of organic HAP m in wastewater, from table 7
of this subpart, dimensionless.
Fem=Fraction emitted of organic HAP m in wastewater from table 7
of this subpart, dimensionless.
s=Total number of organic HAP's in wastewater stream i.
HAPim=Average concentration of organic HAP m in wastewater stream
i, parts per million by weight.
(A) HAPim shall be determined for the point of generation or
at a location downstream of the point of generation. Wastewater samples
shall be collected using the sampling procedures specified in Method
25D of 40 CFR part 60, appendix A. Where feasible, samples shall be
taken from an enclosed pipe prior to the wastewater being exposed to
the atmosphere. When sampling from an enclosed pipe is not feasible, a
minimum of three representative samples shall be collected in a manner
to minimize exposure of the sample to the atmosphere and loss of
organic HAP's prior to sampling. The samples collected may be analyzed
by either of the following procedures:
(1) A test method or results from a test method that measures
organic HAP concentrations in the wastewater, and that has been
validated pursuant to section 5.1 or 5.3 of Method 301 of appendix A of
this part may be used; or
(2) Method 305 of appendix A of this part may be used to determine
Cim, the average volatile organic HAP concentration of organic HAP
m in wastewater stream i, and then HAPim may be calculated using
the following equation: HAPim=Cim/Fmm, where Fmm
for organic HAP m is obtained from table 7 of this subpart.
(B) Values for Qi, HAPim, and Cim shall be
determined during a performance test conducted under representative
conditions. The average value obtained from three test runs shall be
used. The values of Qi, HAPim, and Cim shall be
established in the Notification of Compliance Status report and must be
updated as provided in paragraph (h)(6)(i)(C) of this section.
(C) If there is a change to the process or operation such that the
previously measured values of Qi, HAPim, and Cim are no
longer representative, a new performance test shall be conducted to
determine new representative values of Qi, HAPim, and
Cim. These new values shall be used to calculate debits and
credits from the time of the change forward, and the new values shall
be reported in the next Periodic Report.
(iii) The following equations shall be used to calculate
EWW1iACTUAL for each Group 1 wastewater stream i that is correctly
suppressed and is treated to a level more stringent than the reference
control technology.
(A) If the Group 1 wastewater stream i is controlled using a
treatment process or series of treatment processes with an approved
nominal reduction efficiency for an individually speciated HAP that is
greater than that specified in table 7 of this subpart, and the vapor
control device achieves a percentage of reduction equal to 95 percent,
the following equation shall be used:
[GRAPHIC][TIFF OMITTED]TR18AU95.028
Where:
EWWiACTUAL=Monthly wastewater stream emission rate if wastewater
stream i is treated to a level more stringent than the reference
control technology, megagrams per month.
PRim=The efficiency of the treatment process, or series of
treatment processes, that treat wastewater stream i in reducing the
emission potential of organic HAP m in wastewater, dimensionless, as
calculated by:
[[Page 43281]]
[GRAPHIC][TIFF OMITTED]TR18AU95.029
Where:
HAPim-in=Average concentration of organic HAP m, parts per million
by weight, as defined and determined according to paragraph
(h)(6)(ii)(A) of this section, in the wastewater entering the first
treatment process in the series.
HAPim-out=Average concentration of organic HAP m, parts per
million by weight, as defined and determined according to paragraph
(h)(6)(ii)(A) of this section, in the wastewater exiting the last
treatment process in the series.
All other terms are as defined and determined in paragraph (h)(6)(ii)
of this section.
(B) If the Group 1 wastewater stream i is not controlled using a
treatment process or series of treatment processes with an approved
nominal reduction efficiency for an individually speciated HAP that is
greater than that specified in table 7 of this subpart, but the vapor
control device has an approved nominal efficiency greater than 95
percent, the following equation shall be used:
[GRAPHIC][TIFF OMITTED]TR18AU95.030
Where:
Nominal efficiency=Approved reduction efficiency of the vapor control
device, dimensionless, as determined according to the procedures in
Sec. 63.652(i).
Am=The efficiency of the treatment process, or series of treatment
processes, that treat wastewater stream i in reducing the emission
potential of organic HAP m in wastewater, dimensionless.
All other terms are as defined and determined in paragraphs (h)(6)(ii)
and (h)(6)(iii)(A) of this section.
(1) If a steam stripper meeting the specifications in the
definition of reference control technology for wastewater is used,
Am shall be equal to the value of Frm given in table 7 of
this subpart.
(2) If an alternative control device is used, the percentage of
reduction must be determined using the equation and methods specified
in paragraph (h)(6)(iii)(A) of this section for determining PRim.
If the value of PRim is greater than or equal to the value of
Frm given in table 7 of this subpart, then Am equals Frm
unless a higher nominal efficiency has been approved. If a higher
nominal efficiency has been approved for the treatment process, the
owner or operator shall determine EWW1iACTUAL according to
paragraph (h)(6)(iii)(B) of this section rather than paragraph
(h)(6)(iii)(A) of this section. If PRim is less than the value of
FR