[Federal Register Volume 59, Number 135 (Friday, July 15, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-17130]


[[Page Unknown]]

[Federal Register: July 15, 1994]


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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63

[AD-FRL-5012-3]

 

National Emission Standards for Hazardous Air Pollutants for 
Source Categories: Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule and notice of public hearing.

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SUMMARY: The EPA is proposing to regulate the emissions of certain 
hazardous air pollutants from petroleum refineries that are major 
sources under section 112 of the Clean Air Act as amended in 1990. The 
proposed rule, the national emission standards for hazardous air 
pollutants for petroleum refineries, would require sources to achieve 
emission limits reflecting the application of the maximum achievable 
control technology, consistent with sections 112(d) and 112(h) of the 
Clean Air Act as amended in 1990. The proposed rule would regulate the 
emissions of the organic hazardous air pollutants identified on the 
list of 189 hazardous air pollutants in the Clean Air Act at both new 
and existing petroleum refinery sources.
    The EPA is also proposing to amend two standards of performance for 
new stationary sources: standards of performance for equipment leaks of 
volatile organic compounds in the synthetic organic chemicals 
manufacturing industry; and standards of performance for volatile 
organic compounds emissions from petroleum refinery wastewater systems. 
These standards were previously promulgated under section 111 of the 
Clean Air Act.

DATES: Comments. Comments must be received on or before September 13, 
1994.
    Public Hearing. If anyone contacts the EPA requesting to speak at a 
public hearing by August 5, 1994, a public hearing will be held on 
August 15, 1994, beginning at 9 a.m. Persons wishing to present oral 
testimony must contact Ms. Lina Hanzely of the EPA at (919) 541-5673 by 
August 5, 1994. Persons interested in attending the hearing should call 
Ms. Hanzely at (919) 541-5673 to verify that a hearing will be held.

ADDRESSES: Comments. Comments should be submitted (in duplicate, if 
possible), to: The Air and Radiation Docket and Information Center (LE-
131), ATTN: Docket No. A-93-48, Room M1500, U.S. Environmental 
Protection Agency, 401 M Street, SW., Washington, DC 20460.
    Public Hearing. If anyone contacts the EPA requesting a public 
hearing, it will be held at the EPA's Office of Administration 
auditorium, Research Triangle Park, North Carolina. Persons interested 
in attending the hearing or wishing to present oral testimony should 
notify Ms. Hanzely, Chemicals and Petroleum Branch, Emission Standards 
Division (MD-13), U.S. Environmental Protection Agency, Research 
Triangle Park, North Carolina 27711, telephone number (919) 541-5673.
    Docket. The docket listed above under ADDRESSES contains supporting 
information used in developing the proposed rule. The docket includes 
several memoranda documenting the estimation of impacts of the 
regulatory alternatives and the technical basis of the proposed 
standards. Dockets are available for public inspection and copying 
between 8 a.m. and 4 p.m., Monday through Friday, at the Air and 
Radiation Docket and Information Center, Room M1500, U.S. Environmental 
Protection Agency, 401 M Street, SW., Washington, DC 20460. A 
reasonable fee may be charged for copying.

FOR FURTHER INFORMATION CONTACT: For information concerning the 
proposed standards, contact Mr. James F. Durham, at (919) 541-5672, 
Chemicals and Petroleum Branch (MD-13), Emission Standards Division, 
U.S. Environmental Protection Agency, Research Triangle Park, North 
Carolina 27711.

SUPPLEMENTARY INFORMATION: The following outline is provided to aid in 
reading the preamble to the proposed regulation.

I. Acronyms, Abbreviations and Measurement Units
    A. Acronyms
    B. Abbreviations and Measurement Units
II. Background
    A. Statutory Authority
    B. Previous Regulations
III. Summary of Proposed Rule
    A. Applicability and General Standards
    B. Miscellaneous Process Vent Provisions
    C. Storage Vessel Provisions
    D. Wastewater Provisions
    E. Equipment Leak Provisions
    F. Recordkeeping and Reporting Provisions
    G. Emissions Averaging
IV. Summary of Impacts of Proposed Rule
    A. Environmental Impact
    B. Energy Impact
    C. Cost Impact
    D. Economic Impact
    E. Benefits Analysis
V. Emission and Impact Estimation Methods
VI. Rationale for Proposed Standard
    A. Selection of Source Category, Sources, and Pollutants
    B. Selection of Miscellaneous Process Vent Provisions
    C. Selection of Storage Vessel Provisions
    D. Selection of Wastewater Collection and Treatment Operation 
Provisions
    E. Selection of Equipment Leak Provisions
    F. Use of Continuous Monitoring to Determine Compliance
    G. Selection of Reporting and Recordkeeping Provisions
    H. Rationale for Emissions Averaging Provisions
VII. Amendments to Previous Regulations
    A. Amendment to 40 CFR Part 60 Subpart QQQ
    B. Amendment to 40 CFR Part 60 Subpart VV
VIII. Administrative Requirements
    A. Executive Order 12866
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Review

    The proposed regulatory text is not included in this Federal 
Register notice, but is available in Docket No. A-93-48, or by written 
or telephone request from the Air and Radiation Docket Information 
Center (see ADDRESSES). The proposed regulatory language is also 
available on the Technology Transfer Network (TTN), on the EPA's 
electronic bulletin boards. This bulletin board provides information 
and technology exchange in various areas of air pollution control. The 
service is free, except for the cost of a telephone call. Dial (919) 
541-5742 for up to a 14,400 bps modem. If more information on TTN is 
needed call the HELP line at (919) 541-5384.

I. Acronyms, Abbreviations and Measurement Units

    The following acronyms, abbreviations and measurement units are 
provided to clarify the preamble to the proposed rule.

A. Acronyms

Act--Clean Air Act
BWON--Benzene Waste Operations NESHAP
CEMS--continuous emission monitoring system
CFR--Code of Federal Regulations
CTG--control techniques guideline
E.O.--Executive Order
EFR--External Floating Roof
EPA--U.S. Environmental Protection Agency
FCCU--fluidized catalytic cracking unit
FR--Federal Register
HAP--hazardous air pollutant
HON--hazardous organic national emission standards for hazardous air 
pollutants for the SOCMI source category
ICR--information collection request
IFR--internal floating roof
LDAR--leak detection and repair
MACT--maximum achievable control technology
NESHAP--national emission standards for hazardous air pollutants
NSPS--new source performance standards
OMB--Office of Management and Budget
QIP--quality improvement program
RCT--reference control technology
RIA--Regulatory Impact Analysis
SOCMI--synthetic organic chemical manufacturing industry
TAB--total annual benzene
TOC--total organic compounds
VOC--volatile organic compounds

B. Abbreviations and Measurement Units

Btu--British thermal unit
CO--carbon monoxide
hr--hour
kPa--kilopascals
Kw-hr/yr--kilowatt-hour per year
lb--pound
l/min--liters per minute
m\3\--cubic meters
Mg--megagrams
MEK--methyl ethyl ketone
MTBE--methyl tertiary butyl ether
NOX--nitrogen oxides
PM--particulate matter
ppm--parts per million
ppmv--parts per million by volume
ppmw--parts per million by weight
psia--pounds per square inch absolute
SO2--sulfur dioxide
yr--year

II. Background

    This section provides background about the legal and policy 
criteria that the Administrator took into consideration in selecting 
the provisions of this proposed rule. It is included to give the reader 
a sense of the rule as a whole. To that end, this section includes 
background about the rule, the statutory authority of the rule, 
including some statutory history, a summary of the current statutory 
requirements for standards developed under section 112 of the Act, and 
a summary of previous regulations.
    The regulation being proposed today, under section 112 of the Act, 
is the petroleum refineries NESHAP, which would set MACT for petroleum 
refineries. The petroleum refineries industry group includes any 
facility engaged in producing gasoline, naphthas, kerosene, jet fuels, 
distillate fuel oils, residual fuel oils, lubricants, or other products 
made from crude oil or unfinished petroleum derivatives.
    Some components of the petroleum refining industry have already 
been subject to various Federal, State, and local air pollution control 
rules. Although these existing rules will remain in effect, the 
petroleum refinery NESHAP will provide comprehensive coverage of the 
petroleum refinery sources not covered by the existing rules. The 
petroleum refinery NESHAP, as proposed today, regulates emissions of 
all the organic HAP's emitted from emission points at both new and 
existing petroleum refinery sources. The proposed NESHAP reflects the 
EPA's regulatory experience from previous NESHAP and NSPS rulemakings 
involving similar kinds of sources and emission points. Information on 
control technology applicability, performance, and cost was developed 
to support these NESHAP and NSPS. This information was carefully 
reconsidered in light of the Act and used in the selection of MACT and 
the other provisions of the proposed rule, such as monitoring, 
recordkeeping, and reporting requirements.

A. Statutory Authority

    This section provides a brief history of section 112 of the Act and 
background regarding the definition of source categories and source for 
section 112 standards. This information is included to give the reader 
a sense of the statutory, judicial, and Congressional guidance that the 
Administrator took into consideration in developing the source category 
and source definitions for the petroleum refinery NESHAP.
    Section 112 of the Act provides a list of 189 HAP's and directs the 
EPA to develop rules to control HAP emissions. The Act requires that 
the rules be established for categories of sources of the emissions, 
rather than being set by pollutant. In addition, the Act sets out 
specific criteria for establishing a minimum level of control and 
criteria to be considered in evaluating control options more stringent 
than the minimum control level. Assessment and control of any remaining 
unacceptable health or environmental risk is to occur 8 years after the 
rules are promulgated.
    Specifically, section 112(c), as amended, directs the Administrator 
to develop a list of all categories or subcategories of major sources 
and such categories or subcategories of area sources that meet the 
requirements of section 112(c)(3) and emit the HAP's listed pursuant to 
section 112(b). Section 112(d) directs the Administrator to promulgate 
emission standards for each listed category or subcategory of HAP 
sources. Such standards will be applicable to both new and existing 
sources and shall require:

the maximum degree of reduction in emissions of the hazardous air 
pollutants subject to this section (including a prohibition on such 
emissions, where achievable) that the Administrator, taking into 
consideration the cost of achieving such emission reduction, and any 
nonair quality health and environmental impacts and energy 
requirements, determines is achievable for new and existing sources 
in the category or subcategory to which such emission standard 
applies. . . .

42 U.S.C. 7412(d)(2).

    The Act further provides that ``the maximum degree of reduction in 
emissions that is deemed achievable'' shall be subject to a ``floor,'' 
which is determined differently for new and existing sources. For new 
sources, the standards set shall not be any less stringent than ``the 
emission control that is achieved in practice by the best controlled 
similar source.'' For existing sources, the standards may not be less 
stringent than the average emission limitation achieved by the best 
performing 12 percent of existing sources in each category or 
subcategory of 30 or more sources. (For smaller categories or 
subcategories, the standards may not be less stringent than the average 
emission limitation achieved by the best performing five sources in the 
category or subcategory.)
    In determining whether the standard should be more stringent than 
the floor and by how much, the Administrator is to consider, among 
other things, the cost of achieving such additional reductions. The 
statutory provisions do not limit how the standard is to be set beyond 
requiring that it be applicable to all sources in a category and be at 
least as stringent as the floor.

B. Previous Regulations and Guidance

    The regulations affecting the petroleum refining industry that have 
already been promulgated include a number of NSPS in 40 CFR part 60: 
subpart J--Standards of Performance for Petroleum Refineries; subparts 
K, Ka, and Kb--various standards of performance for storage vessels for 
petroleum liquids; subpart GGG--Standards of Performance for Equipment 
Leaks of VOC in Petroleum Refineries; and subpart QQQ--Standards of 
Performance for VOC Emissions from Petroleum Refinery Wastewater 
Systems.
    The regulations that have already been promulgated also include a 
number of NESHAP in 40 CFR part 61: subpart J--NESHAP for Equipment 
Leaks (Fugitive Emission Sources) of Benzene; subpart Y--NESHAP for 
Benzene Emissions from Benzene Storage Vessels; and subpart FF--NESHAP 
for Benzene Waste Operations.
    The EPA has also issued guidance on controlling equipment leaks at 
refineries in the refinery CTG. Guideline Series: Control of Volatile 
Organic Compound Leaks from Petroleum Refinery Equipment. U.S. 
Environmental Protection Agency. Office of Air Quality Planning and 
Standards. EPA-450/2-78-036. June 1978.

III. Summary of Proposed Rule

    This section of this preamble summarizes the proposed rule (40 CFR 
part 63, subpart CC). The rule is made up of seven different subjects: 
applicability, definitions, and general standards; miscellaneous 
process vent provisions; storage vessel provisions; wastewater 
provisions; equipment leak provisions; recordkeeping and reporting 
provisions; and emissions averaging. This summary is divided into seven 
subsections corresponding to these parts of the regulation.
    The discussion in this section briefly summarizes the requirements 
of the rule, without accounting for how the provisions were selected or 
how applicability criteria were determined. Specific discussion of the 
rationale upon which the provisions of the rule are based can be found 
in section VI of this preamble.
    It should be noted that State rules for VOC (and/or HAP's) may be 
more stringent than the rules being proposed today for refineries. 
Organic HAP's are only a subset of the VOC emitted from refineries. 
This means that the magnitude of VOC emissions from a refinery can be 
substantially greater than the HAP emissions, and the cost per unit of 
emission reduction of any particular control strategy would be less.

A. Applicability and General Standards

    The rule applies to petroleum refining process units 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. For example, at some integrated facilities there may 
be operations from multiple source categories (e.g., petroleum 
refining, SOCMI production, pesticide production). The potential to 
emit for such a plant site would include HAP emissions from all source 
categories. If that plant-site total potential to emit exceeds 10 tons 
per year of a single HAP or 25 tons per year of a combination of HAP's, 
the petroleum refinery process units would be subject to the proposed 
Petroleum Refinery NESHAP, even if the emissions from the petroleum 
refinery process units were below the 10/25 threshold.
    The applicability section of the regulation specifies what is 
included in the petroleum refining source category and the source 
within the source category.
    Petroleum refineries are facilities engaged in producing gasoline, 
naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel 
oils, or other transportation fuels, heating fuels, or lubricants from 
crude oil or unfinished petroleum derivatives.
    The source comprises the miscellaneous process vents, storage 
vessels, wastewater streams, and equipment leaks associated with 
petroleum refining process units within a refinery. The rationale for 
selecting this source definition is discussed in section VI.A of this 
preamble.
    The general standards section of the regulation establishes the 
compliance dates for new and existing sources and requires that sources 
be properly operated and maintained at all times. The general standards 
clarify the applicability of the NESHAP General Provisions (40 CFR part 
63 subpart A) to sources subject to subpart CC.

B. Miscellaneous Process Vent Provisions

    Miscellaneous process vents are defined to include streams 
containing greater than 20 ppmv organic HAP that are continuously or 
periodically discharged from petroleum refining process units. 
Miscellaneous process vents exclude vents that are routed to the 
refinery fuel gas system and vents from fluidized catalytic cracking 
unit catalyst regeneration, catalytic reformer catalyst regeneration, 
and sulfur plants. The vents included in miscellaneous process vents 
are defined specifically in the definitions section (Sec. 63.641) of 
the proposed rule.
    The miscellaneous process vent provisions require the owner or 
operator of a miscellaneous process vent to reduce emissions of organic 
HAP by 98 percent or to 20 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). The process vent provisions 
allow for pollution prevention in that pollution prevention could be 
used to reduce organic HAP concentrations to less than 20 ppmv, and the 
stream would not be subject to control requirements.

C. Storage Vessel Provisions

    A storage vessel means a tank or other vessel storing feed or 
product for a petroleum refining process unit that contains organic 
HAP's. The storage vessel provisions do not apply to the following: (1) 
vessels permanently attached to mobile vehicles, (2) pressure vessels 
designed to operate in excess of 204.9 kPa (29.7 psia), (3) vessels 
with capacities smaller than 40 m\3\ (10,500 gal), and (4) wastewater 
tanks.
    The storage 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 proposed regulation 
and in section VI.C. of this notice; Group 2 vessels are all storage 
vessels that are not Group 1 vessels. The storage provisions require 
that one of the following control systems be applied to Group 1 storage 
vessels: (1) an IFR with proper seals; (2) an EFR with proper seals; 
(3) an EFR converted to an IFR with proper seals; or (4) a closed vent 
system with a 95-percent efficient control device. The storage 
provisions give details on the types of seals required. The EPA is co- 
proposing an option that would also require controlled fittings on 
existing floating roof tanks. Vessels at new sources that are equipped 
with floating roofs are required to meet specifications for seals and 
fittings. Monitoring and compliance provisions for Group 1 vessels 
include periodic visual inspections of vessels and roof seals, as well 
as 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. The storage 
vessel provisions are based on and encourage pollution prevention. The 
pollution prevention options specifically listed by the standard are: 
IFR, EFR, and a closed vent system routed to a recovery device.

D. Wastewater Provisions

    The wastewater provisions of this rule are based on the BWON, using 
benzene as a surrogate for all organic HAP's from wastewater in 
petroleum refineries. As explained in section VI.D of this preamble, 
benzene is a good indicator of the presence of other HAP's in 
wastewater. The wastewater streams subject to this rule include water, 
raw material, intermediate, product, by-product, co-product, or waste 
material that contains organic HAP's and is discharged into an 
individual drain system. The wastewater provisions define two groups of 
wastewater streams. Group 1 streams are those that contain a 
concentration of at least 10 ppmw benzene, have a flow rate of at least 
0.02 l/min, are located at a refinery with a total annual benzene 
loading of at least 10 megagrams per year and are not exempt from 
control requirements under 40 CFR part 61 subpart FF (the BWON). Group 
2 streams are wastewater streams that are not Group 1.
    The wastewater provisions of the rule refer to the BWON, which 
requires owners or operators of a Group 1 wastewater stream to reduce 
benzene mass 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 required for wastewater streams and treatment 
operations to verify that the control devices achieve the desired 
performance are included in the BWON, as are the monitoring, reporting, 
and recordkeeping provisions necessary to demonstrate compliance. No 
controls or monitoring are required for Group 2 wastewater streams. The 
wastewater provisions promote pollution prevention in that pollution 
prevention measures could be used to reduce the benzene concentration 
to below the criteria for Group 1 wastewater streams. Once the stream 
is a Group 2 wastewater stream, control is not required. Pollution 
prevention measures may also be taken to reduce the refinery-wide TAB 
quantity in waste to below 10 Mg/yr or to reduce the refinery-wide TAB 
quantity in wastewater to below 1 Mg/yr, beyond which no further 
control would be required. Furthermore, the emissions suppression 
requirements of the provisions are pollution prevention measures.

E. Equipment Leak Provisions

    The equipment leak standards for the petroleum refinery NESHAP 
refer to the negotiated equipment leak regulation included in the HON 
(40 CFR part 63 subpart H). These standards are summarized in the 
preamble to the promulgated HON (59 FR 19402, April 22, 1994). The 
standards for the petroleum refinery NESHAP differ from the HON in the 
following ways: only one leak definition for pumps in phase III; leak 
definition for pumps is equal to or greater than 2,000 ppmv; leak 
definitions for valves in phases II and III; monitoring frequencies for 
valves; connectors are not required to be monitored, but sources may 
choose to monitor valves less frequently in exchange for monitoring of 
connectors. More details and a discussion of the rationale for these 
differences are contained in section VI.E. The equipment leaks 
standards further the goals of pollution prevention, because many of 
the requirements, such as leak detection and repair, are pollution 
prevention measures.

F. Recordkeeping and Reporting Provisions

    The rule requires petroleum refineries complying with subpart CC to 
keep records of information necessary to document compliance for 5 
years and to submit the following four types of reports to the 
Administrator: (1) An Initial Notification, (2) a Notification of 
Compliance Status, (3) Periodic Reports, and (4) other reports. There 
are no requirements for reporting compliance with the wastewater 
provisions other than the reports already required by the BWON.
1. Initial Notification
    The Initial Notification is due 120 days after the date of 
promulgation for existing petroleum refinery sources. For new sources 
that have an initial start-up more than 90 days after promulgation, the 
application for approval of construction or reconstruction required 
under the General Provisions (40 CFR part 63 subpart A) must be 
submitted in lieu of the Initial Notification. This application is due 
as soon as practicable before construction or reconstruction is planned 
to commence but it need not be sooner than 90 days after promulgation 
of subpart CC. For new sources that have an initial start-up less than 
90 days after promulgation, no application for approval of construction 
is required, and the Initial Notification is due within 90 days after 
promulgation.
    The Initial Notification must list the petroleum refining process 
units that are subject to the rule. The Initial Notification is not 
required if a Title V operating permit application has been submitted 
that provides the required information.
2. Notification of Compliance Status
    The Notification of Compliance Status must be submitted 150 days 
after the sources's compliance date. It contains the information 
necessary to demonstrate that compliance has been achieved, such as: 
the results of any performance tests for miscellaneous process vents; 
design analyses for control devices applied to storage vessels; a 
description of equipment subject to the equipment leaks provisions and 
the number of pieces of equipment in each equipment type; and the 
method of compliance with the equipment leak standard. For emission 
points subject to continuous monitoring requirements, the notification 
must contain site-specific ranges for each monitored parameter and the 
rationale for selection of the ranges. If the information required in 
the Notification of Compliance Status has already been submitted to the 
operating permit authority, it does not need to be resubmitted.
3. Periodic Reports
    Periodic Reports must be submitted semiannually, except that the 
implementing agency can request quarterly submittal for emission points 
where monitored parameter values are outside their permitted ranges 
more than 1 percent or monitors are out of service more than 5 percent 
of the total operating time in a semiannual reporting period.
    All Periodic Reports must include information required to be 
reported under the recordkeeping and reporting provisions for each 
emission point. For continuously monitored parameters, the data on 
those periods when the parameters are outside their established ranges 
are included in the reports. Periodic Reports must also include results 
of any performance tests conducted during the reporting period and 
reports of equipment failures, leaks, or improper work practices that 
are discovered during required inspections.
4. Other Reports
    A very limited number of other reports must be submitted as 
required by the provisions for each kind of emission point. Other 
reports include notifications of storage vessel internal inspections, 
and reports of start-up, shut-down, and malfunction required by the 
General Provisions (40 CFR part 63 subpart A).

G. Emissions Averaging

    The EPA is proposing that emissions averaging be allowed among 
existing miscellaneous process vents, storage vessels, and wastewater 
streams within a refinery. New sources would not be allowed to use 
emissions averaging. Under emissions averaging, a system of emission 
``credits'' and ``debits'' would be used to determine whether the 
source is achieving the required emission reductions. An owner or 
operator who generates an emission debit must control other emission 
points to a level more stringent than is required by the regulation to 
generate an emission credit. Annual emission credits must exceed 
emission debits for a source to be in compliance. The proposed rule 
contains specific equations and procedures for calculating credits and 
debits. Monitoring of control device operation would be required and 
Periodic Reports would be submitted quarterly instead of semiannually 
for emission points in emissions averages.

IV. Summary of Impacts of Proposed Rule

    This section presents the environmental, energy, cost, and economic 
impacts resulting from the control of HAP emissions under the proposed 
rule. It is estimated that approximately 190 petroleum refineries would 
be required to apply controls by the proposed standards.
    Impacts are presented relative to a baseline, the level of control 
in the absence of the proposed rule. The estimates include the impacts 
of applying control to: (1) existing process units and (2) additional 
process units that are expected to begin operation over a 5-year 
period. Thus, the estimates represent annual impacts occurring in the 
fifth year. Based on a review of annual construction projects over the 
years 1988 to 1992 listed in the Oil and Gas Journal, it was assumed 
that 34 new process units would be constructed each year over a 5-year 
period.
    For regulatory purposes, some of the process units constructed in 
the first 5 years of the rule may be considered new sources, while 
others may be considered part of an existing source. However, for the 
purpose of presenting total impacts, this distinction has not been 
made.

A. Environmental Impact

    The environmental impact of the rule includes the reduction of HAP 
and VOC emissions, increases in other air pollutants, and decreases in 
water pollution and solid waste resulting from the proposed rule.
    Under the proposed rule, it is estimated that the emissions of HAP 
from refineries would be reduced by 54,000 Mg/yr, and the emissions of 
VOC would be reduced by 350,000 Mg/yr (see table 1). Estimates of 
baseline HAP and VOC emissions are presented in conjunction with 
emissions reductions estimates to illustrate the level of control being 
achieved by the rule. Baseline HAP and VOC emissions take into account 
the current estimated level of emissions control, based on previous 
regulations and questionnaire responses submitted by refineries. As a 
result, baseline HAP and VOC emissions reflect the level of control 
that would be achieved in the absence of the proposed rule. The 
proposed rule would achieve a 68 percent reduction in HAP emissions and 
a 72 percent reduction in VOC emissions relative to the baseline. Table 
1 presents the baseline emissions and emission reduction for each of 
the four kinds of emission points controlled by this proposed rule.

                        Table 1.--National Primary Air Pollution Impact in the Fifth Year                       
----------------------------------------------------------------------------------------------------------------
                                                 Baseline emissions               Emission reductions           
                                                       (Mg/yr)       -------------------------------------------
                    Source                     ----------------------        (Mg/yr)              (Percent)     
                                                                     -------------------------------------------
                                                   HAP        VOC        HAP        VOC        HAP        VOC   
----------------------------------------------------------------------------------------------------------------
Miscellaneous process vents...................      9,800    190,000      8,400    180,000         86         95
Equipment leaks...............................     52,000    190,000     45,000    160,000         87         85
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.....................................     81,000    500,000     55,000    360,000         68         72
----------------------------------------------------------------------------------------------------------------
aThe MACT level of control is no additional control.                                                            

    Emission levels of other air pollutants (CO, NOX, SO2) 
were not quantified. However, slight increases above existing emission 
levels would result from the combustion of fossil fuel as part of 
control device operations. Additional emissions of CO, NOX, and 
SO2 would result from fuel burned to generate energy for operation 
of compressors for ducting miscellaneous process vent streams to 
control devices.
    Impacts for water pollution and solid waste were judged to be 
negligible and were not quantified as part of the impact analysis.

B. Energy Impact

    Increases in energy use were estimated for operating control 
equipment that would be required by the proposed standards (i.e., 
compressors for ducting miscellaneous process vent streams to control 
devices). The estimated energy use increase in the fifth year would be 
13 million kw-hr/yr of electricity or 21,000 barrels of oil equivalent.

C. Cost Impact

    The cost impact of the rule includes the capital cost of new 
control equipment, the cost of energy (supplemental fuel, steam, and 
electricity) required to operate control equipment, and operation and 
maintenance cost. Generally, the cost impact also includes any cost 
savings generated by reducing the loss of valuable product in the form 
of emissions. The average cost effectiveness of the regulation ($/Mg of 
pollutant removed) is also presented as part of the cost impact. The 
average cost effectiveness is determined by dividing the annual cost by 
the annual emission reduction.
    Under the proposed rule, it is estimated that total capital costs 
would be $207 million (first quarter 1992 dollars) and total annual 
costs would be $84 million (first quarter 1992 dollars) per year. Table 
2 presents the capital and annual cost impact of the proposed 
regulation for each of the four kinds of emission points as well as the 
national totals. In addition to the cost impact shown in Table 2, it is 
estimated that monitoring, recordkeeping, and reporting activities 
would cost about $26 million/yr, bringing the total national annual 
costs to about $110 million. 

        Table 2.--National Control Cost Impacts in the Fifth Year       
------------------------------------------------------------------------
                        Total                                           
                       capital     Total     Average HAP    Average VOC 
       Source          costsa     annual         cost           cost    
                      (106 $ )  costs (106  effectiveness  effectiveness
                                  $/yr)      ($/Mg HAP)      ($/Mg VOC) 
------------------------------------------------------------------------
Miscellaneous                                                           
 process vents......        31          12         1,400             66 
Equipment leaks.....       130          66         1,500            410 
Storage vessels.....        46           6         4,600            340 
Wastewater                                                              
 collection and                                                         
 treatment..........       (b)         (b)           (b)            (b) 
                     ---------------------------------------------------
    Total...........       207          84  .............  .............
------------------------------------------------------------------------
aTotal capital costs incurred in the 5-year period.                     
bThe MACT level of control is no additional control.                    

D. Economic Impacts

    The preliminary economic impact analysis for the selected 
regulatory alternatives shows that the estimated price increases for 
affected products range from 0.18 percent for residual fuel oil to 0.51 
percent for jet fuel. Estimated decreases in product output range from 
0.12 percent for jet fuel to 0.37 percent for residual fuel oil. Total 
net exports (exports minus imports) for all petroleum liquids are 
predicted to decrease by 1.8 million barrels annually, approximately 1 
percent, as a result of the standard.
    Industry has expressed concern that the proposed rule could cause 
some small refineries to shut down. Using conservative (i.e., worst 
case) assumptions, the economic analysis indicates that from none to 
seven small refineries are at risk of closure under the proposed rule. 
The majority of the closures would occur in refineries that process 
less than 10,000 to 20,000 barrels of crude oil per day. Also, the 
regulatory flexibility analysis showed that compliance costs as a 
percentage of sales are more than twice as high for small refiners 
compared to other refiners. For more information, consult ``Economic 
Impacts Analysis of the Petroleum Refinery NESHAP'' in the docket.

E. Benefits Analysis

    The 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. The proposed regulation regulates HAP emissions from storage 
tanks, process vents, equipment leaks, and wastewater emission points 
at refining sites. Of the HAP's emitted by petroleum refineries, some 
are classified as VOC, which are ozone precursors. Hazardous air 
pollutant benefits 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 probable or known human carcinogens. 
As a result, one of the benefits of the proposed regulation is a 
reduction in the risk of cancer mortality. Other benefit categories 
include reduced exposure to noncarcinogenic HAP's, and reduced exposure 
to VOC.
    Emissions of VOC have been associated with a variety of health and 
welfare impacts. Volatile organic compound emissions, together with 
NOX, are precursors to the formation of tropospheric ozone. 
Exposure to ambient ozone is responsible for a series of respiratory 
related adverse impacts.
    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 control options 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, 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 benefits associated 
with the petroleum refinery NESHAP were determined to be small. 
Therefore, these benefits are not incorporated into this benefit 
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 health 
benefits in nonattainment areas, the transfer values can be applied to 
VOC reductions occurring only in nonattainment areas. (Nonattainment 
areas are geographical locations in which the National Ambient Air 
Quality Standard for ozone has been violated.) The benefit transfer 
ratio range for acute health impacts used in this analysis is from $25 
to $1,574 per megagram of VOC with an average of $800 per megagram of 
VOC. In order to quantify VOC emission reductions, these ratios were 
multiplied by VOC emission reductions from petroleum refineries located 
in ozone nonattainment areas. Estimated benefits for VOC reductions are 
$148.3 million for the proposed regulation and $153.9 million for a 
more stringent alternative.
    The quantified benefits exceed costs by $15.9 million 1992 dollars 
per year for the proposed alternative. The quantified benefits exceed 
costs by $5.5 million 1992 dollars per year for the more stringent 
alternative. Thus, a comparison of the incremental difference in the 
two alternatives indicates that the incremental net benefits are 
negative for the more stringent alternative.

V. Emission and Impact Estimation Methods

    Emissions from petroleum refineries and the impact of controlling 
emissions were estimated using information published in the Oil and Gas 
Journal and provided by petroleum refineries in response to information 
collection requests and questionnaires sent out under section 114 of 
the Act. For a general discussion of the estimation methods for 
existing and new petroleum refinery sources and references for 
memoranda on the specific methods used for each kind of emission point, 
refer to the memorandum, Emission and Impact Estimation Methods, 
available in the Docket. It is noted that API provided the EPA with 
emissions data that it has collected relatively recently on leaking 
equipment. The EPA is evaluating this data. Once this review is 
complete, the EPA intends to incorporate it into documents which are 
used for estimating emissions, particularly on an individual plant 
basis. It could also affect the emission reduction estimates provided 
for the promulgated standard.

VI. Rationale for Proposed Standard

A. Selection of Source Category, Sources, and Pollutants

    This section of the preamble describes the rationale for the 
selection and definition of the petroleum refinery source category and 
for the factors that the Administrator took into consideration in 
defining the sources within the petroleum refinery source category.
1. Selection of Source Category
    The definition of the source category is important in setting 
standards because it sets the boundary for what emission points will be 
regulated under this standard. A large plant site such as a refinery 
could comprise multiple source categories. For example, a refinery is 
likely to contain equipment that would be regulated under the 
industrial cooling tower source category, the process heater source 
category, the industrial boiler source category, or the SOCMI source 
category. The petroleum refinery source category regulated under this 
NESHAP is defined to include equipment specifically used to produce 
fuels, heating oils, or lubricants by separating petroleum or 
separating, cracking, or reforming unfinished petroleum derivatives.
    The EPA's source category list (57 FR 31576, July 16, 1992), 
required by section 112(c) of the Act, identifies categories of sources 
for which NESHAP are to be established. This list includes all 
categories of major sources of HAP's known to the EPA at this time, and 
all area source categories for which findings of adverse effects 
warranting regulation have been made. Two categories of sources are 
listed for petroleum refineries: (1) catalytic cracking (fluid and 
other) units, catalytic reforming units, and sulfur plant units, 
scheduled for promulgation in 1997, and (2) other sources not 
distinctly listed, scheduled for promulgation in 1995 (58 FR 63952, 
December 3, 1993).
    Based on review of information on petroleum refineries during 
development of the proposed standards, it was determined that some of 
the emissions points from the two listed categories of sources have 
similar characteristics and can be controlled by the same control 
techniques. In particular, miscellaneous process vents emitting organic 
HAP's, storage vessels, wastewater streams, and leaks from equipment in 
organic HAP service within catalytic cracking units, catalytic 
reforming units, and sulfur plant units are similar to emission points 
from the other process units at petroleum refineries (i.e., units in 
the category of ``other sources not distinctly listed''). Because it is 
most effective to regulate these emission points in a single 
regulation, the EPA intends to amend the source category list when the 
standards proposed today are promulgated. Upon revision, all emission 
points from petroleum refining units included in today's proposed 
standards will be in a single source category.
    The petroleum refinery source category selected for regulation by 
subpart CC includes process units for catalytic cracking (fluid and 
other), catalytic reforming, sulfur plants, and other petroleum 
refinery units not distinctly listed. The other units not distinctly 
listed include, but are not limited to, process units for thermal 
cracking, vacuum distillation, crude distillation, hydrotreating/
hydrorefining, alkylation, isomerization, polymerization, lube oil 
processing, and hydrogen production. Units for processing natural gas 
liquids, refining units for recycling discarded oil, and shale oil 
extraction units are not covered by this rule. Ethylene processes are 
not covered by this rule because they are included in a separate source 
category.
    Miscellaneous process vents, as defined in Sec. 63.641 of the 
proposed rule, from the process units subject to this rule are part of 
the petroleum refinery source category. Three kinds of vents at 
petroleum refineries would not be included in the source category for 
today's proposed rule. These vents--the catalytic cracking catalyst 
regeneration vent, the catalytic reformer catalyst regeneration vent, 
and the sulfur plant vents--will be included in a separate category 
subject to a 1997 deadline. These vents have significantly different 
HAP emission characteristics and would be controlled with different 
controls than the rest of the refinery emission points. The standard 
proposed today addresses emissions of organic HAP's. The FCCU 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 their unique 
characteristics, the EPA concluded that these emission points warranted 
separate consideration. Because limited data are currently available, 
these emission points will be included in a separate source category 
under a separate schedule. (However, the EPA would like to clarify that 
miscellaneous process vents (as defined in Sec. 63.641 of the proposed 
rule) from catalytic cracking, catalytic reforming, and sulfur plant 
units that emit organic HAP's would be subject to subpart CC.)
    a. Distinction between petroleum refinery and SOCMI source 
categories. This petroleum refineries NESHAP generally covers refinery 
processes that produce petroleum liquids (such as gasoline, naphthas, 
and kerosene) for use as fuels. Often, products of refinery processes 
are used to make synthetic organic chemicals other than fuels. The 
petroleum refineries NESHAP will not cover chemical manufacturing 
process units that are covered under the SOCMI source category, even if 
these units are located at a refinery site. A SOCMI chemical 
manufacturing process unit that is located at a refinery and produces 
one or more of the chemicals listed in the HON (40 CFR part 63 subpart 
F, table 1) as a single chemical product or as a mixed chemical used to 
produce other chemicals would be considered a SOCMI process and would 
be subject to the HON rather than to the petroleum refineries NESHAP.
    For example, MTBE, an additive used for octane enhancement in 
gasoline, is a SOCMI chemical that can be produced at some petroleum 
refineries and is made from a petroleum refinery product. The feedstock 
for MTBE is a mixed C4, C5 hydrocarbon stream produced in an FCCU; the 
FCCU is subject to the petroleum refineries NESHAP. However, MTBE is on 
the list of SOCMI chemicals in the HON (40 part 63 subpart F), so the 
process unit used to produce MTBE from the C4, C5 hydrocarbon feedstock 
is regulated under the HON, not under the petroleum refineries NESHAP.
    b. Exclusion of area sources. A petroleum refining process would be 
subject to the proposed standard only if it is part of a major source. 
A major source is any stationary source or group of stationary sources 
located within a contiguous area and under common control that emits or 
has the potential to emit, considering controls, more than 10 tons per 
year of any HAP or more than 25 tons per year of total HAP. An area 
source is any stationary source or group of stationary sources that are 
not major sources. The General Provisions for the NESHAP (40 CFR part 
63 subpart A), provide a definition of potential to emit. The General 
Provisions apply to the petroleum refinery source category.
    Based on the information available on petroleum refineries and 
emission estimates developed for this standard, the EPA has no 
information that can be used to determine whether area sources in the 
petroleum refinery source category would present a threat of adverse 
effects to human health or to the environment. It is believed that most 
refineries are major sources, and that there are few, if any, area 
sources. The EPA requests comments containing information on whether 
there are area sources within the petroleum refining source category 
and on the emissions from such sources. Commenters should provide the 
basis for any emission estimates.
    c. Exclusion of research and development facilities. The proposed 
standard would not apply to research and development facilities, such 
as laboratories and pilot plants, regardless of whether the facilities 
are located on the same site as a commercial petroleum refinery. 
Research and development facilities connected with petroleum refineries 
are believed to be small, and the EPA has limited information about 
their operations or about the appropriate controls for these 
facilities. The EPA concluded, therefore, that it would not be 
appropriate to include research and development facilities in this 
regulation. In accordance with section 112(c)(7) of the Act, a separate 
source category for research and development facilities may be 
established at a later date if more comprehensive information becomes 
available. Standards for such facilities may be developed at a later 
date, if the EPA determines that such action is warranted.
    d. Exclusion of transfer operations. Transfer operations at 
petroleum refineries, that is, loading products into tank trucks, 
railcars, or marine vessels, is not included in the source category 
regulated by this rule. Loading of marine vessels will be regulated 
under the Federal Standards for marine tank vessel for loading and 
unloading operations and NESHAP for marine tank vessel for loading and 
unloading operations. Emissions from loading tank trucks and railcars 
will be regulated under the NESHAP for the gasoline distribution and 
organic liquids distribution (nongasoline) source categories in the 
liquids distribution industry group. The NESHAP for the gasoline 
distribution source category was proposed in February 1994; the NESHAP 
for the organic liquids distribution source category is scheduled to be 
promulgated by 2000.
    e. Small refineries. The standard proposed today would apply to all 
refineries that are major sources including small refineries. Small 
refineries maintain that they will be more severely affected by the 
proposed rule than large refineries and therefore should be given 
separate regulatory consideration. Small refiners point out that they 
are predominately located in rural areas that are in compliance with 
the Federal ambient air quality standard for ozone. Therefore, many of 
them have not implemented LDAR programs and other control procedures 
that have been started by large refiners to control VOC in ozone 
nonattainment areas. As a result they will be confronted with 
relatively high costs for starting LDAR programs and retrofitting 
storage tanks. Moreover, small refiners point out that LDAR costs are 
related more to refinery complexity than size. Therefore, refineries 
that differ in size but have similar processing configurations will 
incur similar costs. However, the costs on a per-barrel basis will be 
higher for the small refineries.
    The proposed rule does not treat small refineries as a separate 
subcategory because the EPA could not identify fundamental technical 
differences between small and large refineries. In addition, even if 
small refineries were in a separate source category it appears that the 
minimum control levels (floors) would not be much different from those 
for the larger refineries. Comments are requested on whether a basis 
exists for subcategorizing small refineries, and if so, at what size, 
along with supporting data and rationale.
2. Selection of Source
    The definition of source is an important element of this NESHAP 
because it describes the specific grouping of emission points within 
the source category to which each standard applies.
    The EPA has broad discretion in defining ``sources.'' Section 
112(d) directs the Administrator to set standards for all ``major 
sources'' within every listed category. Area sources meeting the 
requirements of sections 112(c)(3) or 112(k) must also be regulated. 
Major sources are ``stationary sources,'' or groups of stationary 
sources, of a given size, as defined in section 112(a)(1). The 
definition of ``stationary source'' included in section 112 is 
identical to the definition used in section 111(a), which is ``any 
building, structure, facility, or installation which emits or may emit 
any air pollutant.'' 42 U.S.C. 7411(a). However, section 112, as 
amended, does not require that the standards set under section 112(d) 
be set for the same components of the categories as was done under 
section 111. Thus, there is no requirement that the section 112(d) 
NESHAP for stationary sources be set for precisely the same portions of 
the industry as the section 111 NSPS.
    As the Supreme Court has recognized in Chevron, USA, Inc., versus 
Natural Resources Defense Council, 467 U.S. 837 (1984) (hereafter 
referred to as Chevron), EPA has broad discretion to define ``source.'' 
The Court recognized in Chevron that if any Congressional intent can be 
discerned from the statutory language of section 111(a)(3) (the 
definition of source that is used in section 112), ``the listing of 
overlapping, illustrative terms was intended to enlarge, rather than 
confine, the scope of the EPA's power to regulate particular sources in 
order to best effectuate the policies of the Act.'' Chevron. Thus, the 
court found that a ``source'' can encompass ``any discrete, but 
integrated operation, which pollutes.'' Chevron. As such, the EPA has 
flexibility, within the broad definition of ``stationary source,'' to 
define the source for each section 112(d) standard as broadly or 
narrowly as is appropriate for the particular industry being regulated. 
Previous regulations have, in light of this flexibility, defined source 
in a variety of ways, ranging from narrow to broad definitions. For 
example, for BWON, the source was defined as the plant site, for the 
petroleum refinery equipment leaks NSPS (40 CFR part 60, subpart GGG) 
the source was the process unit, and for the petroleum refinery 
wastewater NSPS (40 CFR part 60 subpart QQQ) the source was more 
narrowly defined. There is no presumptive definition.
    The proposed standard defines source as the collection of emission 
points in HAP-emitting petroleum refining processes within the source 
category that are part of a major source. The source comprises all 
miscellaneous process vents, storage vessels, wastewater streams, and 
equipment leaks associated with petroleum refining process units that 
are located at a single plant site covering a contiguous area under 
common control.
    The way the source is defined has implications for setting MACT and 
for compliance with the proposed rule. Emission standards for new and 
for existing sources promulgated under section 112(d) of the Act must 
represent the maximum degree of emission reduction achievable; this is 
typically referred to as MACT. The EPA considered two possible 
definitions of source for the petroleum refinery NESHAP. The source 
could be defined narrowly as each individual process vent, storage 
vessel, or wastewater stream or piece of equipment; or the source could 
be defined broadly, as the collection of all such emission points at 
the refinery.
    The narrow definition of the petroleum refinery source, defining 
the source as each individual emission point, was rejected because a 
narrow definition is more appropriate when all emission points have 
consistent characteristics and because it would not allow compliance 
flexibility. For example, if each storage vessel were comparable to 
each other storage vessel, so that the same performance level could 
apply to them all, a narrow definition might be appropriate. In fact, 
storage vessels can vary widely in size and material stored, and the 
emission performance level appropriate for one may be inappropriate for 
another. In addition, the control strategy for a refinery is decided at 
a refinery level. Often, individual emission points within a refinery 
are controlled together (e.g., multiple miscellaneous process vents can 
be routed to one control system). Thus, it is reasonable to look at the 
overall level of control a refinery is achieving because the size, 
level of emissions, and significance of emissions can vary from point 
to point.
    A broad definition of source allows consideration of site-specific 
differences and compliance flexibility, including emissions averaging. 
With a broad definition, a source may exercise some choice in the level 
of control of each individual emission point as long as the sourcewide 
MACT level of emission reduction is met. This flexibility results in 
benefits of achieving maximum emission reductions in a more efficient 
and cost-effective manner.
    Another reason for selection of the broad definition of source is 
compatibility with the BWON source definition. This compatibility 
allows the standards to be consistent and eliminates the burden of 
overlapping standards and implementation problems that would arise if 
the source for today's proposed rule was defined much more narrowly 
than the BWON source.
    The definition of source also affects refineries making changes to 
existing facilities. Under the Act, sources that are constructed or 
reconstructed after proposal of a standard are considered to be new 
sources. Reconstructions are defined in Sec. 63.2 of the NESHAP General 
Provisions (59 FR 12408, March 16, 1994) as the replacement of 
components of an affected source to such an extent that the fixed 
capital cost of the new component exceeds 50 percent of the fixed 
capital cost that would be required to construct a comparable new 
source. Upon reconstruction, an affected source is subject to standards 
for new sources, including compliance dates, irrespective of any change 
in emissions of hazardous air pollutants from that source.
    With a narrower source definition, enforcement of the standard 
would be difficult because any change to any emission point could 
trigger regulatory provisions governing reconstruction. Reconstructed 
sources are treated as new sources, so many small ``new'' sources could 
be scattered throughout an existing refinery. Determining requirements 
for different emission points would be complex, and the new or 
reconstructed sources (which are treated as new sources) may require 
control systems separate from the control systems for existing sources. 
This could increase the cost and economic impact of the regulation.
    With a broad source definition, the replacement or addition of new 
equipment would be unlikely to exceed 50 percent of the fixed capital 
cost of the source.
3. Determining New Source Status
    The proposed rule clarifies the process for determining if new or 
existing source requirements would apply to a particular petroleum 
refining process unit or emission point. The requirements and 
definitions used by the proposed petroleum refineries rule to 
distinguish new and existing sources are consistent with section 112(a) 
and the related components of the subpart A General Provisions. The 
following would be subject to the subpart CC requirements for new 
sources: (1) Petroleum refining process units constructed after the 
date of proposal of subpart CC and having the potential to emit major 
quantities (10 tons per year of any HAP or 25 tons per year of any 
combination of HAP's); (2) existing sources reconstructed after that 
date; and (3) ``greenfield'' petroleum refining process units that 
constitute all or part of a major source constructed after that date. 
(New source requirements would not be triggered by the addition of an 
individual emission point, such as a storage vessel.) Thus, any change 
or addition to an existing petroleum refinery plant site must meet the 
same three criteria as a ``greenfield'' plant to be considered a new 
source. The EPA proposes this approach for determining what is subject 
to new source requirements to avoid providing an incentive for 
petroleum refinery owners and operators to construct processes as area 
sources. Also, EPA wanted to ensure that new sources built at existing 
plant sites are subject to the same requirements as new sources that 
are ``greenfield'' sites. Additions to an existing plant that do not 
meet the requirements of being a petroleum refining process unit and do 
not have the potential to emit major amounts, would be subject to 
existing source requirements.
4. Selection of Pollutants
    The HAP's that are emitted from the emission points that make up 
the source in this source category are all organic HAP's; the 
predominant HAP's are benzene, toluene, xylene, ethylbenzene, and 
hexane. Therefore, the provisions of this NESHAP apply to the organic 
HAP's listed in section 112(b) of the Act.

B. Selection of Miscellaneous Process Vent Provisions

    The definition in Sec. 63.641 of the proposed rule describes the 
vents that are considered to be ``miscellaneous process vents.'' The 
available data indicated that these vents have similar emission 
characteristics and can be controlled by the same type of control 
technologies.
1. Selection of Emission Control Requirements
    The Act specifies that the EPA, in determining the MACT level of 
control for sources regulated under section 112, must select emission 
control requirements that are at least as stringent as, or more 
stringent than, the emission control level identified as the floor. As 
a result, the EPA began the process of selecting control requirements 
for miscellaneous process vents by determining MACT floors for existing 
and new sources. The MACT floor determinations are fully described in a 
memorandum ``Determination of the Petroleum Refinery MACT Floors for 
Existing and New Sources,'' available in the docket. This section 
summarizes the MACT floors as they relate to miscellaneous process 
vents, and the selection of the proposed process vent provisions.
    The Act requires that the EPA determine MACT based on consideration 
of cost, energy requirements and nonair quality health and 
environmental impacts. The EPA maintains that the requirements of this 
proposed rule were determined based on these statutorily-specified 
criteria. The EPA requests comment on the appropriateness of 
considering additional criteria such as pollution prevention, 
environmental equity, affordability, and technology innovation.
    a. Existing sources. Based on information contained in industry 
responses to the EPA's ICR and section 114 questionnaires, it was 
determined that the average emission limitation achieved by the best 
performing 12 percent of sources is combustion control of all 
miscellaneous process vents. Data analyses conducted in developing 
previous NSPS and the HON determined that combustion controls can 
achieve 98 percent organic HAP reduction or an outlet organic HAP 
concentration of 20 ppmv for all vent streams. The selection of these 
numerical levels is described in the preamble for the proposed reactor 
processes NSPS (55 FR 26953, June 29, 1990).
    The MACT floor level of control for existing sources, therefore, 
includes reduction of organic HAP emissions from miscellaneous process 
vents by 98 percent or to a level of 20 ppmv for miscellaneous process 
vents with concentrations that exceed de minimis levels. A de minimis 
level of 20 ppmv was selected. Process vents with organic HAP emission 
levels below this concentration would not be subject to the proposed 
rule because the available technologies may not be able to reduce 
organic emissions below this level. Regulatory options more stringent 
than the floor were not investigated for miscellaneous process vents 
because no available technology that is generally applicable can 
achieve a more stringent level of control than the MACT floor. 
Therefore, the standard being proposed for miscellaneous process vents 
at existing sources is the MACT floor.
    The estimated emission reductions and cost impacts for the proposed 
standards for all emission points are shown in table 3. The 
miscellaneous process vent costs are based on routing the vents to the 
refinery fuel gas or flare systems. Some industry representatives have 
expressed concerns that the costs may be underestimated. The EPA 
requests specific cost data and information on how miscellaneous 
process vents at existing sources would be controlled and what the cost 
would be.

                                      Table 3.--Control Options and Impacts                                     
----------------------------------------------------------------------------------------------------------------
                                                            HAP                         Cost effectiveness ($/Mg
                      Baseline                  --------------------------                        HAP)          
      Source         emissions       Control       Emission     Percent    Annual cost -------------------------
                      (Mg/yr)        optiona      reduction     emission   ($1,000/yr)                          
                                                   (Mg/yr)     reduction                  Average    Incremental
----------------------------------------------------------------------------------------------------------------
Miscellaneous                                                                                                   
 Process Vents:                                                                                                 
    Existing              8,900  Floor*........        7,600           85       13,000        1,700          N/A
     sources.                                                                                                   
    New sourcesb..          900  Floor*........          770           85          370          480          N/A
Storage Vessels:                                                                                                
    Existing              9,000  Floor*........        1,300           14       11,400        8,500          N/A
     sourcesc.                                                                                                  
                                 Option 1*.....        1,800           20       13,600        7,800        4,400
                                 Option 2......        2,600           29       37,000       14,000       30,000
    New sourcesb..          290  Floor*........            4          1.4           98       24,000          N/A
                                 Option 1......           14          4.8          550       39,000       45,000
Wastewater:                                                                                                     
    Existing              9,200  Floor*........  ...........          N/A  ...........          N/A          N/A
     sources.                                                                                                   
                                 Option 1......        7,700           93      120,000       15,000       15,000
    New sourcesb..          960  Floor*........  ...........          N/A  ...........          N/A          N/A
                                 Option 1......          930           97       18,000       20,000       20,000
Equipment Leaks:                                                                                                
    Existing             50,000  Floord........       35,000           69       69,000        2,000          N/A
     sources.                                                                                                   
                                 Option 1*.....       44,000           87       66,000        1,500         -330
                                 Option 2......       46,000           91       78,000        1,700        6,000
    New sources...        1,300  Floor*,d......          640           49         -210         -330         -330
                                 Option 1......          760           59          840        1,100        8,300
----------------------------------------------------------------------------------------------------------------
aExplanation of control options:                                                                                
Storage Vessels                                                                                                 
Existing Sources                                                                                                
Floor=Subpart Kb floating roof with specified seals or closed vent systems and control devices for vessels  177 m3 storing liquid with the vapor pressures  8.3 kPa.                                   
Option 1=Floating roof with subpart Kb specified seals and fittings for vessels  151 m3 storing      
  liquids with true vapor pressure  5.2 kPa.                                                         
Option 2=Floating roof with subpart Kb specified seals and fittings for vessels  151 m3 storing      
  liquids with true vapor pressure  0.014 kPa.                                                       
New Sources                                                                                                     
Floor=Floating roof with subpart Kb specified seals and fittings for vessels  151 m3 storing liquid  
  with the vapor pressures  3.4 kPa, and vessels  76 m3 storing liquids with vapor        
  pressures equal to or greater than 77 kPa.                                                                    
Option 1=Floating roof with specified seals and fittings for vessels  151 m3 storing liquids with    
  true vapor pressures  0.014 kPa, and vessels  76 m3 storing liquids with vapor pressures
  equal to or greater than 77 kPa.                                                                              
Equipment Leaks                                                                                                 
Existing Sources                                                                                                
Floor=Compliance with the petroleum refinery NSPS.                                                              
Option 1=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63, without        
  connectors.                                                                                                   
Option 2=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63.                
New Sources                                                                                                     
Floor=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63, without           
  connectors.                                                                                                   
Option 1=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63.                
Wastewater                                                                                                      
Existing and New Sources                                                                                        
Floor=Compliance with the BWON for any refinery with > 10 Mg/yr of benzene loading in waste. Controlling waste  
  streams > 10 ppm benzene by weight with flow rates > 0.02 1/min.                                              
Option 1=Compliance with the BWON for all refinery wastewater streams.                                          
Miscellaneous Process Vents Existing and New Sources                                                            
Floor=Control to 20 ppm HAP or 98 percent reduction of HAP by combustion.                                       
bImpacts were estimated for new process units constructed in the 5 years after promulgation. For regulatory     
  purposes, some of these units may be considered new sources while others may be considered part of an existing
  source.                                                                                                       
cThe floor and option 1 are being co-proposed for storage vessels at existing sources and the EPA is requesting 
  comment on which should be selected.                                                                          
dFor equipment leaks at both new and existing sources the option identified as the ``floor'' is slightly more   
  stringent than the actual floor. For ease of costing, these options were chosen to represent the floor. See   
  footnote ``a'' for an explanation of the control options.                                                     
*=Control option chosen.                                                                                        
N/A=Not applicable.                                                                                             

    Industry has commented that the control requirements for the 
process vents should be based on a cost-effectiveness method similar to 
the TRE approach used in the HON rule. Industry recommendations are 
based on limited information which indicates that the control cost per 
ton of HAP reduction can differ by several hundred percent. As in the 
HON, the differences are apparently due to wide variations in the 
control costs and the HAP content of the process vents.
    The EPA requests comment on whether or not the control requirements 
for the miscellaneous process vents should be based on a cost-
effectiveness approach similar to the TRE method used in the HON. The 
EPA does not have the information to determine if a cost-effectiveness 
approach is needed or to develop one and to relate it to the floor. The 
required information includes descriptions of the sources of emissions 
and the emission controls. The vent stream characteristics such as flow 
rate, heating value, VOC, and HAP contents are also required. 
Information provided by industry in response to two formal EPA 
questionnaires contained little information with respect to the vent 
stream characteristics. It is not possible to develop TRE equations 
that are specific to petroleum refineries without this information. In 
the event that the EPA develops a TRE, the Agency requests the 
information that is needed to develop cost-effectiveness equations for 
the refining industry similar to those in the HON. The information is 
requested for a representative segment of the refining industry. If 
this information is received, the EPA will analyze it before 
promulgation of this rule and will utilize a TRE approach if such an 
approach appears appropriate.
    Industry has commented that the cost equations for the TRE 
requirements in the HON rule may be applicable to the refining 
industry. The EPA solicits comment with supporting information on the 
applicability of the HON cost equations to the refining industry such 
as information on the similarity or differences between the refining 
industry and the SOCMI in terms of vent stream characteristics (flow, 
concentration, heating value) and for combustion control device designs 
in use.
    Industry has commented that the applicability levels for the HAP 
concentration (50 ppmv) and the flow rate (0.005 standard cubic meter 
per minute) in the process vents provisions of the HON should be 
applicable to the refining industry. The purpose of the applicability 
levels is to avoid affecting large numbers of small vents whose 
cumulative emissions are small relative to the control costs and the 
costs of monitoring, recordkeeping and reporting. The EPA requests 
information to determine if there are large numbers of small vents with 
low HAP concentrations in the refining industry, and whether such vents 
are controlled. If such vents exist, the EPA also requests information 
to determine the applicability levels that would avoid affecting vents 
where the emission control and administrative costs are inordinately 
high relative to the emission reductions. If sufficient data are 
received and the MACT floor does not require control of such vents, the 
EPA will include appropriate applicability levels in the final rule.
    Industry has commented that the EPA has overestimated the HAP and 
VOC emissions from the miscellaneous process vents--particularly from 
the alkylation and vacuum distillation units. The estimates are based 
on: (1) Information submitted by the petroleum refining industry in 
response to the EPA questionnaires, and (2) emission estimation 
extrapolations and assumptions by the EPA where reported data were 
insufficient. Industry has questioned the assumptions made by the EPA 
in their analysis. Industry maintained that part of the reported 
emissions may be from water blowdowns, equipment leaks or from other 
emission sources that are not true process vents. The EPA will consider 
revising the emission estimates if the EPA receives new data 
demonstrating that revisions are appropriate.
    Industry has commented that since the HAP to VOC ratio for 
reformers is dissimilar to other process units, the EPA should not use 
it to estimate HAP emissions from process units other than reformers. 
The EPA agrees with industry on this point and plans to revise the 
estimates after considering any new information submitted.
    b. New sources. Because the best performing source controls all 
miscellaneous process vents by combustion, the new source MACT floor 
includes reduction of emissions from miscellaneous process vents by 98 
percent or to a level of 20 ppmv. A 20 ppmv de minimis concentration 
was selected for the same reason as existing sources. There are no 
available control options that are generally applicable that can 
achieve emission levels more stringent than the floor. Therefore, the 
standard being proposed for miscellaneous process vents at new sources 
is the MACT floor. The cost and emission reduction for new source are 
presented in table 3.
2. Selection of Format
    The format of the regulation for miscellaneous process vent streams 
depends on the kind of control device the refinery selects. For vent 
streams controlled by control devices other than flares, the format of 
the regulation is a combination of a weight-percent reduction and an 
outlet concentration. A weight-percent reduction format is appropriate 
for process vent streams with HAP concentrations above 1,000 ppmv, 
because a weight-percent limit is the best measure of the performance 
of combustion control devices and will assure that MACT is applied. For 
process vent streams with HAP concentrations below 1,000 ppmv, the 
format of the regulation is a 20 ppmv outlet concentration, because 98 
percent HAP reduction may not be achievable.
    For vent streams controlled by a flare, the proposal refers to the 
performance specifications in the General Provisions (40 CFR part 63, 
subpart A, section 63.11). An emission limit or percent reduction 
format was not selected because it is very difficult to measure the 
emissions from a flare to determine its efficiency.
    The petroleum refinery fuel gas system is considered part of the 
refinery processes; therefore, any vent stream being recovered and 
routed to the fuel gas system is also considered part of the process. 
These vent streams are not considered miscellaneous process vents and 
are not subject to subpart CC. Furthermore, these vents are already 
controlled to the most stringent levels achievable.
3. Selection of Performance Tests, Monitoring Requirements, and Test 
Methods
    The standard specifies the performance tests, monitoring 
requirements, and test methods necessary to determine whether a 
miscellaneous process vent stream is required to apply control devices 
and to demonstrate that the allowed emission levels are achieved when 
controls are applied. The format of these requirements, as with the 
format of the miscellaneous process vent provisions, depends on the 
control device selected.
    a. Performance test. Performance tests ensure that a control device 
can achieve the required control level and help establish operating 
parameters that indicate proper operation and maintenance. Initial 
performance tests are required for control devices other than flares 
and certain boilers and process heaters. Specifically, testing would be 
required for incinerators, and for boilers and process heaters smaller 
than 44 MW (150 million Btu/hr) where the vent stream is not used as 
the primary fuel or mixed with the primary fuel prior to being 
introduced into the boiler.
    As previously stated, miscellaneous process vent streams routed to 
the refinery fuel gas system are not subject to these standards, and 
boilers and process heaters that use refinery fuel gas are not required 
to be tested.
    An initial performance test is not required for boilers and process 
heaters larger than 44 MW (150 million Btu/hr) because they operate at 
high temperatures and residence times. Analysis shows that when vent 
streams are introduced into the flame zone of these boilers and process 
heaters, over 98 percent reduction or an outlet concentration of 20 
ppmv is achieved. Therefore, a performance test is not necessary.
    Because percent reduction and outlet concentration cannot feasibly 
be measured at flares, the flare must meet the requirements for 
operating conditions in Sec. 63.11 of 40 CFR part 63 subpart A.
    b. Test methods. The proposed miscellaneous process vent provisions 
would require the use of approved test methods to ensure consistent and 
verifiable results for initial performance tests and compliance 
demonstrations. The proposed regulation refers to the HON (40 CFR part 
63, subpart G) for performance test provisions; but the rationale for 
the use of these provisions for petroleum refineries is presented 
below. For performance tests, Methods 2, 2A, 2C, or 2D of 40 CFR part 
60, appendix A, are specified for measuring vent stream flow rate. 
Method 18 of 40 CFR part 60, appendix A, is specified for measuring 
total vent stream HAP or TOC concentration at the outlet of the control 
device to determine whether outlet HAP concentration is below 20 ppmv 
or at both the inlet and outlet of the control device to determine if 
HAP emissions are reduced by 98 percent. In order to allow owners or 
operators greater flexibility, the proposed provisions also allow the 
use of any test method or test results validated according to the 
protocol in Method 301 of 40 CFR part 63, appendix A.
    The EPA considered allowing Method 25A as an alternative to Method 
18 for demonstrating compliance of control devices applied to process 
vents; however, Method 25A is not included as an alternative for 
demonstrating compliance with the emissions reduction. The basis for 
the decision was that the EPA determined that the results obtained with 
Method 25A would not consistently demonstrate HAP control efficiency. 
Miscellaneous process vent streams often contain mixtures of multiple 
organic HAP's and other organic compounds. The TOC measurements 
obtained with Method 25A would vary depending on how the method is 
calibrated, because response factors for individual compounds vary. 
Furthermore, some compounds are not well detected by Method 25A. 
Another concern is that the relative proportion of individual organic 
compounds may change across the combustor. Therefore, specifying 
calibration with the principal HAP in the inlet would not necessarily 
produce reliable results.
    c. Monitoring. Control devices used to comply with the proposed 
standard need to be maintained and operated properly if either a 98 
percent reduction or outlet concentration of 20 ppmv is to be achieved 
on a continuing basis. Monitoring of the control device operating 
parameters can be used to determine if the emission limit is being met 
on a continuous basis. The monitoring of operating parameters 
constitutes enhanced monitoring, as discussed in section VI.F of this 
notice.
    The EPA considered two monitoring options: (1) the use of CEMS to 
measure HAP's and (2) continuous monitoring of control device operating 
parameter. Continuous emission monitoring systems are not currently 
available for all of the organic HAP's found in miscellaneous process 
vent streams. Thus, direct monitoring of HAP emission reduction or 
concentration is not possible for every stream. Furthermore, for those 
HAP's where CEMS are available, the costs of installing, calibrating, 
operating, and maintaining CEMS and flow monitors at both the inlets 
and outlets of every control device (which would be needed to determine 
percent reduction) would be much higher than the costs of parameter 
monitoring. The use of CEM's would, therefore, increase the cost 
impacts of the rule.
    It is proposed that the continuous monitoring of control device 
operating parameters be used to determine whether continuous compliance 
is achieved. The proposed standard lists the parameters that can be 
monitored for the common types of combustion devices: thermal 
incinerators, catalytic incinerators, boilers and process heaters, and 
flares. These parameters were selected because they are good indicators 
of combustion device performance, and instruments are available at a 
reasonable cost to monitor these parameters continuously. The proposed 
rule also allows the owner or operator to request to monitor parameters 
not listed in the proposed standard on a site-specific basis.
    The proposed standard would require the owner or operator to 
establish site-specific parameter ranges through the Notification of 
Compliance Status report or the operating permit submitted to comply 
with Title V of the Act. Site-specific parameter ranges accommodate 
site-specific differences in control design and process vent stream 
characteristics. Failure to maintain the established values of the 
monitored parameters would be an enforceable violation of the emission 
limits of the standard.
    The proposed petroleum refineries NESHAP does not require 
monitoring boilers or process heaters with a heat capacity of 44 MW 
(150 million Btu/hr) or greater, or boilers or process heaters with a 
heat capacity less than 44 MW (150 million Btu/hr) that introduce the 
process vent stream as a primary fuel or mix it with the primary fuel 
and introduce it through the same burner. These devices operate at 
temperatures and residence times that the EPA has concluded will ensure 
compliance with the emission limits (at least 98 percent reduction of 
total HAP). Therefore, if the vent stream is routed to the devices as 
described above and enters at the specified locations, continuous 
compliance is demonstrated.

C. Selection of Storage Vessel Provisions

1. Selection of Emission Control Requirements
    This section summarizes the MACT floors for new and existing 
sources as they relate to storage vessels, regulatory alternatives more 
stringent than the floors, and the rationale for the selected 
alternatives for storage vessels.
    a. Existing sources. Based on information on storage vessel control 
levels and vessel capacities and vapor pressures submitted to the EPA 
by petroleum refineries, the MACT floor level of control was determined 
to be: storage vessels with capacities greater than or equal to 177 
m3 storing liquids with true vapor pressures greater than or equal 
to 8.3 kPa must control to the level of 40 CFR part 60 subpart Kb with 
the exception of fitting requirements for floating roof vessels. This 
represents the average level of storage vessel control achieved at the 
best-performing 12 percent of sources. The control applicability 
criterion of 177 m3 (1,115 barrels or 47,000 gallons) was selected 
because the best-performing sources do not control storage vessels with 
capacities below this size. The vapor pressure of 8.3 kPa (1.2 psia) 
was determined by screening the data set for controlled tanks (tanks 
that met subpart Kb seal requirements) at increasing vapor pressures 
until the cumulative number of tanks identified as controlled equalled 
12 percent of the entire data set. The average vapor pressure of the 
petroleum liquids in these controlled tanks was 8.3 kPa.
    The EPA also considered two alternative levels of emission 
limitation. Each required control to subpart Kb levels including 
controlled fittings for floating roof vessels and were for control of 
vessels with capacities greater than or equal to 151 m3 (950 
barrels or 40,000 gallons). However, each of the alternatives had a 
different true vapor pressure applicability criterion. The first 
alternative required that vessels storing liquids with a true vapor 
pressure greater than or equal to 5.2 kilopascals (0.75 psia) be 
controlled. This alternative was analyzed because it also corresponds 
to one of the applicability tiers of subpart Kb of 40 CFR part 60. The 
second alternative was for controls being required for vessels storing 
liquids with a true vapor pressure greater than or equal to 0.014 
kilopascals (0.002 psia). This alternative was chosen in order to 
assess the impact of control of vessels storing low vapor pressure 
liquids such as diesel/distillate, jet kerosene/kerosene, heavy gas 
oil, residual fuel oil, and asphalt. Table 3 presents the emission 
reductions and cost for the MACT floor level of control and the two 
options above the floor.
    The EPA is co-proposing the floor level of control, and option 1, 
for storage tanks in order to promote comment on both options. The 
floor requires that petroleum liquids with true vapor pressures of 8.3 
kPa (1.2 psia) or higher be placed in floating roof storage tanks 
equipped with seals that comply with the NSPS for volatile organic 
liquids (subpart Kb of 40 CFR part 60). The floor control will reduce 
the current HAP emissions from storage tanks by 14 percent. This 
relatively small emission reduction is due to the fact that most 
volatile petroleum liquids are stored in floating roof tanks to reduce 
product losses or to comply with VOC control requirements in ozone 
nonattainment areas. The emission reductions associated with upgrading 
the seals on such tanks to comply with subpart Kb requirements are, in 
many cases, modest.
    Controlling both the fittings and the seals to subpart Kb 
requirements was evaluated as option 1. The EPA seeks comment on 
whether the floor level or control or option 1 should be selected. In 
particular, the EPA requests comment on whether or not the incremental 
cost effectiveness of option 1--$4,400 per ton of HAP emissions 
reduced--should be viewed as making that option unachievable 
considering cost. The EPA also requests comment on whether option 1 
should be selected because of a combination of factors. Specifically, 
option 1 achieves a greater degree of pollution prevention because even 
less product is lost due to evaporation. In addition, the vapor 
pressure and storage tank size applicability levels for option 1 
correspond to the HON's applicability levels for large storage tanks. 
Also, since HAP emissions represent roughly 10 percent of VOC 
emissions, additional cost-effective VOC reductions would result from 
option 1. Finally, option 1 would provide a 20 percent reduction, 
rather than a 14 percent reduction, in emissions of the types of HAP 
emitted from petroleum refinery storage tanks.
    No nonair quality health impacts, energy, or other environmental 
impacts were expected from any of the alternatives. Thus, these 
considerations did not affect the choice of the proposed rule. The 
controls required by the proposed requirements are not expected to 
create any secondary emissions of carbon monoxide or nitrogen oxides.
    b. New sources. The MACT floor for new sources is control of 
vessels equal to or greater than 151 m3 (950 barrels or 40,000 
gallons) 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 
(475 barrels or 20,000 gallons) storing liquids with vapor pressures 
equal to or greater than 77 kPa (11.1 psia). Such vessels would be 
required to meet requirements essentially equivalent to 40 CFR part 60 
subpart Kb (i.e., use of floating roofs with proper seals and 
controlled fittings, or a closed vent system with a 95 percent 
efficient control device). The applicability criteria are based on the 
most stringent regulations that apply to petroleum refinery storage 
vessels including Rule 463 of California's South Coast Air Quality 
Management District and the storage vessel NSPS (subpart Kb).
    The MACT floor and an option more stringent than the floor 
requiring control of storage vessels with vapor pressures above 0.014 
kPa (0.002 psia) (which is the same as option 3 for existing sources) 
was also considered. The proposed level of control for new sources is 
the MACT floor. Vessels with capacities greater than or equal to 151 m3 
(950 barrels or 40,000 gallons) storing liquids with true vapor 
pressures greater than or equal to 3.4 kPa (0.5 psia), and vessels with 
capacities greater than or equal to 76 m\3\ (475 barrels or 20,000 
gallons) storing liquids with vapor pressures equal to or greater than 
77 kPa (11.1 psia) would be required to comply with the subpart Kb 
(including the controlled fitting requirements). The option more 
stringent than the floor was not selected because it would result in 
high costs relative to HAP emission reduction.
2. Selection of Format
    The storage vessel provisions in the HON rule are very similar to 
the requirements of subpart Kb. The HON storage provisions are clearer 
and give more details in explaining the controlled fitting requirements 
than subpart Kb. The HON provisions have an allowance for existing 
source owners and operators to wait for the next scheduled maintenance 
for the upgrading of certain seals and installation of fittings on 
vessels already equipped with floating roofs; this provision is not in 
subpart Kb because it applies only to new storage vessels. In addition, 
the HON storage vessel provisions clarify the provisions that apply 
when an EFR is converted to an IFR as a means of compliance. Because of 
all these reasons, the EPA elected to refer directly to the 
requirements in the HON. The format of the HON includes equipment and 
work practice standards; if control devices are used, there is an 
emission standard (percent reduction) format. For storage vessels at 
existing sources the HON storage vessel provisions are referred to 
without the controlled fitting requirements. For storage vessels at new 
sources all of the requirements in the HON storage vessel provisions 
are referred to.
    The proposed regulation differs from the HON in that storage 
vessels that contain petroleum liquids with true vapor pressures of 5.0 
psia or greater are required to comply with the proposed rule within 3 
years. That is, refiners are not permitted to wait until the next 
scheduled maintenance to install the emission controls if such 
maintenance is beyond the compliance date. Calculations indicate that 
when the true vapor pressure of the material in the tanks exceeds 5.0 
psia, the emission reductions that result from installing controls 
within 3 years more than offset the HAP emissions created from cleaning 
and degassing the storage vessels. The EPA requests comment on this 
conclusion with supporting data and calculations.
3. Selection of Compliance Determination Provisions
    The proposed compliance determination provisions for storage 
vessels include inspections of floating roofs and design evaluations 
and monitoring of closed vent systems and control devices. The use of 
monitoring and inspections to determine continuous compliance 
constitute enhanced monitoring.
    For storage vessels controlled with floating roofs, it is not 
feasible to capture and continuously monitor emissions. Therefore, 
periodic inspection of roof seals for IFR's and EFR's and seal gap 
measurements for EFR's are used to determine compliance with the 
storage vessel equipment and work practice standards. If defects are 
found during inspections they must be repaired within specified times. 
There are provisions for requests for extensions and delay of repair of 
certain conditions are met. These inspection and repair provisions are 
similar to the HON, and the proposed rule cross-references the HON 
where appropriate. Failure to perform inspections or to complete 
repairs as specified constitutes an enforceable violation of the 
standards.
    For storage vessels controlled by closed vent systems and control 
devices, the EPA considered the use of CEMS to measure HAP's and 
control device operating parameter monitoring. Continuous emissions 
monitoring was determined to be infeasible for the same reasons 
described in the miscellaneous process vents section. Furthermore, 
emissions from storage vessels have low flow rates and also have highly 
variable flows and concentrations with the majority of emissions 
occurring during filling. These characteristics would complicate 
emission monitoring. Control device operating parameter monitoring is 
proposed as a means of determining continuous compliance with the 
percent reduction specified for control devices. The petroleum 
refineries rule, which cross-references the HON, provides for sources 
to establish site-specific control device operating parameters and 
ranges appropriate to their storage vessel control system.

D. Selection of Wastewater Collection and Treatment Operation 
Provisions

1. Selection of Emission Control Requirements
    This section summarizes the determination of the MACT floors for 
new and existing sources as they apply to wastewater, regulatory 
alternatives more stringent than the floors, and the rationale for the 
selected alternative for wastewater.
    The alternative selected for proposal is the floor level of control 
(compliance with BWON). The BWON controls 75 percent of the benzene in 
refinery wastewater nationwide and 76 percent of the volatile organic 
HAP in refinery wastewater. (For more information, refer to the 
memorandum in the docket entitled ``The Effectiveness of the Benzene 
Waste Operations NESHAP for Controlling Volatile HAP Loading in 
Petroleum Refinery Wastewater''). The EPA believes that benzene is an 
effective surrogate for indicating the presence of all HAP compounds in 
petroleum refinery wastewater because data show that the majority of 
the total HAP compound loading in wastewater consists of compounds that 
are very similar to benzene in terms of both chemical structure and 
volatility (from the water phase to the air phase). Volatile HAP 
compounds are present in a fairly constant ratio to benzene 
(approximately four-to-one on a mass basis) except in two 
circumstances, product blending and MEK dewaxing units. Because of the 
different nature of these processes, different ratios would be 
expected. In both of these process units HAP's are added. In the case 
of MEK dewaxing units the benzene concentration is relatively low, less 
than 1 ppmw on average; however, the baseline volatile HAP emissions 
from MEK dewaxing units are also relatively low, less than 1 percent of 
the HAP baseline emissions. For product blending, the benzene 
concentration is relatively high, greater than 10 ppmw on average; 
therefore, even though the HAP-to-benzene ratio is not the same as with 
other process units, wastewater streams from product blending process 
units have a sufficient benzene concentration that control would be 
required at applicable facilities. Thus, the EPA maintains that benzene 
is a good surrogate for all HAP compounds. The EPA requests comment on 
this position and any supporting data.
    Because the proposed standard for wastewater requires compliance 
with the existing BWON, no additional emission reduction, cost, energy, 
or other environmental or health impacts are associated with the 
proposed standard.
    a. Wastewater: Existing sources. The best performing wastewater 
control systems are those that are in place to comply with the BWON. 
These systems control not only benzene, but are also expected to 
control the other organic HAP's in petroleum refinery wastewater. The 
BWON applies to wastewater streams that contain 10 ppmw benzene or 
greater, have a flow of 0.02 l/min or greater, and are located at 
facilities with a TAB loading of at least 10 Mg/yr in waste and 
wastewater. Based on data provided to the EPA through the BWON 90-day 
reports, the EPA determined that the BWON was applicable to 43 percent 
of the refineries. No refineries are known to have more stringent 
controls than the BWON. Therefore, the MACT floor, or the average of 
the top performing 12 percent of sources, is control to the BWON level 
of control.
    The EPA considered an alternative level of emission reduction more 
stringent than the MACT floor that would be achieved by controlling all 
wastewater streams with at least 10 ppmw benzene at any refinery 
regardless of the size of its annual benzene loading. Table 3 presents 
the cost and emission reductions for the MACT floor and the alternative 
more stringent than the floor.
    Alternative control option 1 was not selected because the 
additional emission reduction achieved through further control was not 
significant, given the associated costs (see table 3). Also, this 
option would primarily affect small refineries and it is expected that 
it could have significant impact on small businesses. There may be some 
additional nonair quality benefits, such as reduced generation of 
hazardous waste and reduced water contamination, and air quality 
benefits from reduction of non-HAP VOC; however, these benefits could 
not be quantified.
    b. Wastewater: New sources. The analysis of the data base also 
showed that the maximum emission reduction being achieved at any source 
is determined by the control requirements for the BWON. Thus, the floor 
for new sources is control to the BWON level of control. The floor 
alternative was selected as the proposed level of control for new 
sources. As with existing sources, the option more stringent than the 
floor was considered, and the impacts are shown in table 3. Option 1 
was rejected for new sources for the same reasons described above for 
existing sources.
2. Selection of Format
    Because the BWON is the basis of the selected level of control for 
both new and existing sources, the EPA elected to refer directly to 
those requirements. The provisions for controlling air emissions from 
wastewater streams are a combination of equipment, operational, work 
practice, and emission standards. The reasons for selection of these 
formats are described in the preamble to the proposed BWON standards 
(54 FR 38083, September 14, 1989).
3. Selection of Testing and Monitoring Provisions
    Because the proposed refineries NESHAP refers directly to the BWON 
equipment, operational, work practice, and emission standards, it is 
also appropriate to refer to the testing and monitoring requirements of 
BWON for compliance determination. The monitoring procedures required 
by the BWON would be used to determine compliance with the standard. 
Failure to maintain the established values of monitored parameters, or 
failure to conduct the required measurements and inspections would be 
an enforceable violation of the standards.

E. Selection of Equipment Leak Provisions

1. Selection of Emission Control Requirements
    This section of the preamble summarizes the MACT floors as they 
relate to equipment leaks within new and existing sources, regulatory 
alternatives more stringent than the floors, and the rationale for the 
selected alternative for equipment leaks. As mentioned in section 
VI.B.1 of this preamble, the EPA requests comment on consideration of 
pollution prevention, environmental equity, affordability, and 
technology innovation as additional criteria in the selection of MACT.
    a. Equipment leaks: Existing sources. The EPA's analysis indicated 
that the average control level of the best-controlled 12 percent of 
sources, the MACT floor level of control, is between the level of 
control required by the petroleum refinery CTG and the petroleum 
refinery NSPS. For costing purposes, the petroleum refinery NSPS level 
of control was used for the MACT floor option. This was done because it 
would have been difficult to determine the requirements for an option 
in between the two levels of control. Also by using the NSPS the 
results were a conservative estimate of the cost of the MACT floor; and 
the option was not less stringent than the floor.
    Two options above the floor were also considered based on the 
negotiated rule for equipment leaks (40 CFR part 63, subpart H). As 
discussed in the preamble presenting the rationale for the negotiated 
rule (57 FR 62659 and 57 FR 62660), the framework developed in the 
regulatory negotiation was the presumptive basis for the refinery 
standard. The EPA also agreed in the negotiation to consider whether 
the numerical standards and leak definitions established for SOCMI 
sources were achievable by refineries. While both options 1 and 2 are 
based on the negotiated rule, option 1 does not include the connector 
provisions. Table 3 presents the estimated cost and emission reduction 
for the floor and the two additional options.
    The proposed standard is the negotiated rule without the connector 
provisions and with a few exceptions. (The exceptions to the negotiated 
rule are discussed in the remainder of this subsection.) This option, 
which is similar to option 1, was selected because it is consistent 
with the negotiated rule, and it achieves significant emission 
reduction at a reasonable cost relative to the MACT floor. As discussed 
later in this section, more frequent valve monitoring is allowed in 
place of connector monitoring because, as shown in the table for option 
2, the cost of connector monitoring is high relative to the emission 
reduction achieved, and additional valve control is a more cost 
effective way to reduce emissions.
    No nonair quality health impacts, energy, or other environmental 
impacts were expected from any of the alternatives. Thus, these 
considerations did not affect the choice of the proposed requirements.
    In light of the agreements made during the negotiation, the EPA 
considered whether leaks should be defined differently in the proposed 
refinery standard than in subpart H, what performance level should be 
established in phase III of the pump and valve standards, and which 
provisions in the negotiated rule were relevant and applicable to 
refinery operations. Available monitoring data from a few refineries 
and differences between typical refinery operations and SOCMI 
operations (e.g., turnaround schedules, line sizes, percent HAP in 
process fluids, line pressures) were considered. The differences were 
found to affect the availability of some low emission technologies and 
the achievable performance levels. The EPA concluded that a few changes 
to the provisions of the negotiated rule (40 CFR part 63 subpart H) 
were necessary to ensure that the proposed standard for refineries is 
achievable. The changes to the provisions and the reasons for the 
changes are discussed below.
    One change that was considered was a change to the definition of 
``in organic hazardous air pollutant service.'' Using the definition 
from the negotiated rule, equipment that contains or comes in contact 
with fluid that is less than 5 percent by weight total organic HAP's 
would not be subject to the equipment leak provisions.
    Pump standard. The negotiated rule for equipment leaks implements 
the leak detection and repair program for pumps in three phases, with 
lower leak definitions in the later phases. The EPA considered the 
available information on emission performance of mechanical seals and 
concluded that the negotiated standard for pumps was achievable. The 
proposed standard for refineries, however, has been simplified to 
specify only one leak definition in phase III. The negotiated 
provisions for pumps in polymerizing monomer service and food/medical 
service are not relevant to this category, and therefore have not been 
included in the refinery standard. In addition, to simplify the rule, a 
leak has been defined as a concentration of 2,000 ppm or greater. This 
change makes the level at which repair is required the same as the leak 
definition. Additionally, low emission single seal technology has 
progressed to the point where these seals can achieve a 2,000 ppm leak 
definition for certain process services. It is expected that this will 
result in lower costs to comply than if dual seals were necessary.
    Additionally, in examining the appropriateness of the pump standard 
to refinery operations, the EPA considered whether to extend some of 
the concepts of the negotiated valve standard to the pump standard for 
refineries. Specifically, the EPA considered whether to allow reduced 
monitoring frequency for better performance and to allow increased 
monitoring frequency as an alternative to the QIP for poor performance. 
The negotiated valve standard included incentive provisions to 
encourage better performance and two forms of penalty options to 
consider differences among facilities' ability to undertake a QIP. 
After considering the predicted differences in effectiveness of 
different monitoring intervals for pumps, the EPA concluded that an 
incentive for better performance could be included in the pump standard 
and still assure better emission performance. The pump standard for 
refineries thus would allow facilities that achieve less than 3 percent 
of pumps leaking, or one pump leaking, to monitor pumps quarterly; and 
facilities that have greater than 3 percent (or 1 pump) but fewer than 
10 percent, or 3 pumps, leaking would be required to conduct monthly 
monitoring of pumps. The EPA considered whether an alternative to the 
QIP could be provided for those facilities that have greater than 10 
percent, or 3 pumps, leaking. It was determined that in such 
situations, the only alternative is an engineering analysis to 
determine the cause of the high leak frequency. Therefore, facilities 
with 10 percent, or 3 pumps, leaking or greater will still be required 
to implement a QIP for pumps.
    The EPA also considered whether LDAR should be required for 
reciprocating pumps in heavy liquid service. In most cases when drips 
are observed, monitored concentration is below the leak definition, and 
elimination of such drips would be infeasible due to spare or design 
limitations. The replacement of such pumps would be very expensive, and 
would result in little emission reduction. Therefore, the EPA concluded 
that requirements to monitor and repair such pumps would be 
unproductive.
    The proposed rule would require monitoring and repair for 
reciprocating pumps in light liquid service. The EPA requests comment 
on the feasibility and cost of controlling leaks from reciprocating 
pumps in light liquid service. Commenters are requested to include 
technical information to support their comments.
    Similarly, comment is requested on the feasibility and cost of 
control measures for reciprocating compressors. As with pumps, there 
may be space and design constraints that may preclude adding seals and 
repair or replacement could be costly.
    Valve standard. The EPA considered whether the negotiated standard 
was appropriate for values, and proposes to adjust the leak definition 
for phases II and III. The proposed leak definition of 1,000 ppm for 
phases II and III was selected based on consideration of monitoring 
data from a few facilities, existing state programs, and the expected 
emission reduction and cost associated with different leak definitions. 
The EPA considered but rejected using 10,000 ppm as the concentration 
that defines a leak because several state programs recently established 
leak definitions of 500 to 1,000 ppm. However, there is only one State 
program that has a leak definition/performance standard framework 
consistent with subpart H and leak definition lower than 10,000 ppm. 
This program has been in effect for a number of years and controls 
refineries with a leak definition of 1,000 ppm. This program has shown 
that a valve performance standard for refineries can be reliably 
implemented and is achievable with a leak definition of 1,000 ppm. This 
program and the fact that significant additional emission reduction can 
be achieved cost-effectively, led the EPA to conclude that a 1,000 ppm 
leak definition was practical and achievable. A leak definition lower 
than 1,000 ppm was not selected because the additional emission 
reduction achievable was small (<1 percent) and the lack of data from 
refineries with performance standards utilizing a leak definition of 
less than 1,000 ppm.
    Owing to the limited data available in this rulemaking, the EPA 
selected the performance levels considering the differences in total 
HAP content of process fluids in SOCMI processes and refinery processes 
and the performance levels selected in the equipment leak negotiation. 
It was determined that with an equipment leak definition of 1,000 ppm, 
a performance standard based on 5 percent allowable leaking valves for 
petroleum refineries is equivalent to the subpart H performance 
standard for the SOCMI. This determination was based on the calculation 
procedures in ``Protocol for Equipment Leak Emission Estimates,'' (EPA-
453/R-93-026) and average HAP/VOC ratios for process fluids.
    The EPA also evaluated what monitoring frequencies should be 
established for given performance levels (i.e., percent leaking 
valves). Using the average HAP to VOC ratio estimated for HON, the EPA 
concluded that equivalent performance requirements would be established 
if the refinery standard required quarterly monitoring for facilities 
achieving less than 5 percent leaking valves. Similarly, semiannual 
monitoring would be allowed for facilities achieving less than 4 
percent leaking valves; and annual monitoring for facilities achieving 
less than 3 percent leaking valves.
    In addition to the basic valve program described above, EPA 
developed an optional, more stringent performance standard, that can be 
used by facility owners or operators electing not to implement a 
connector program. EPA has concluded a connector LDAR program is a 
costlier way to achieve emission reductions, as compared with a more 
stringent valve standard. The EPA, thus concluded that a more cost 
effective approach would be to allow facilities the option to elect 
lower performance levels for valves in lieu of implementing a connector 
LDAR program.
    Based on the Protocol document, an equivalent emissions reduction 
can be achieved by a one percent differential of the allowable leakers 
at the 1,000 ppm leak definition. Therefore, a facility electing not to 
implement the connectors LDAR program can elect to comply with a valve 
performance standard of 4 percent leaking valves with quarterly LDAR, 3 
percent leaking valves with semi-annual LDAR and 2 percent leaking 
valves with annual LDAR program.
    The nonrepairable valve allowance was also adjusted to consider 
differences between refinery operations and SOCMI operations. The 
proposed standard would allow exclusion of 1 percent per year up to a 
maximum of 3 percent of the valves in HAP service from the calculation 
of percent leaking valves. The nonrepairables provision is structured 
in this manner to take into consideration the typically longer 
turnaround schedules in refineries than in SOCMI process units, while 
recognizing that some refinery units may operate on shorter schedules.
    Connectors in gas/vapor and light liquid service. The EPA 
considered whether application of the negotiated standard for 
connectors to refinery operators was appropriate. In this evaluation, 
the EPA considered differences between designs, capacities, and 
operations of refinery and SOCMI units and how these might alter the 
cost of a LDAR program for connectors. Because the existing connector 
emission factor predicts very low emission rates from connectors, it 
appears that a connector LDAR program is relatively costly to achieve 
additional emission reductions. Table 3 provides a comparison of the 
costs and emission reductions for control alternatives that include and 
control alternatives that exclude the negotiated rule's connector 
standard. The EPA, thus, concluded that a more cost effective approach 
would be to allow sources the option to elect less frequent monitoring 
for valves if a connector LDAR program is implemented.
    The proposed equipment leak provisions give three options for a 
connector LDAR program which, if any of these are implemented, would 
allow for less frequent monitoring of valves. The three options are: 
(1) A random 200 connector survey; (2) a connector inspection program, 
and (3) the negotiated rule's connector program. In the random 200 
connector survey, the monitoring frequency depends on the percent 
leaking connectors identified in 200 randomly chosen connectors. At 
higher leak frequencies, the owner or operator has to survey connectors 
more frequently and repair any leaking connectors detected. In the 
connector inspection program, all connectors of 2 in. or greater 
nominal diameter in gas/vapor service are to be monitored using Method 
21 of 40 CFR part 60, appendix A, and all connectors of 2 in. or 
greater nominal diameter in light liquid service are to be inspected 
for indications of liquids dripping. This alternative was developed 
because the majority of connectors in refinery process units that will 
be subject to the equipment leak provisions of the standard are in 
light liquid service and a visual inspection program should be less 
costly to implement than Method 21 monitoring of these connectors. The 
monitoring frequency of this program also varies with the percentage of 
leaking connectors. The negotiated rule's program is included as a 
third option, because some refinery units may be required under their 
state program to implement these provisions.
    A nonrepairable connector allowance is included because increased 
monitoring frequency, if triggered by nonrepairable components, would 
be of little benefit. The proposed alternative standard for connectors 
allows for excluding 1 percent of the connectors per year up to a 
maximum of 3 percent of the connectors from the calculation of the 
percentage of leaking connectors. The nonrepairable allowance was 
selected considering the need to provide an incentive to limit the 
number of nonrepairable connectors while also trying to avoid 
imposition of unproductive costs.
    b. Equipment leaks: New sources. The floor for new sources is 
between the NSPS and the rule proposed for existing sources. Available 
data shows that many refineries are complying with the NSPS and several 
are also complying with State rules that have lower leak definitions 
(i.e., 1,000 ppm for values). The EPA therefore did not consider the 
NSPS as an option for new sources because it would be below the floor. 
For costing purposes, the same requirements as option 1 for existing 
sources were considered the floor for new sources. The EPA considered 
option 2 for existing sources as another option for new sources (option 
1 for new sources). (See table 3 and the text in section VI.E.1.a of 
this preamble.) The proposed standard for new sources, which is similar 
to the option costed as the new source floor, is the negotiated rule 
(40 CFR part 63 subpart H) without the connector provisions and with a 
few other differences. This is the same as the standard proposed for 
existing sources. This option was selected because it is at least as 
stringent as the floor and achieves significant emission reduction at a 
more reasonable cost than option 1 for new sources. No nonair quality 
health impacts, energy, or other environmental impacts were expected 
from either of the alternatives, so these considerations did not affect 
the choice of the proposed requirements. The rationale for not 
requiring connector LDAR and the rationale for the differences between 
the proposed rule and subpart H are discussed in section VI.E.1.a.
    One difference between the proposed rule for new and existing 
sources is that pumps and valves at new sources must be in compliance 
with phase II at start-up, rather than phase I. This is consistent with 
the negotiated rule. It is reasonable to expect new sources to be 
designed to achieve the phase II level of control because they do not 
experience retrofit constraints that affect existing sources.
    c. Equipment leaks: Small refineries. The EPA is considering 
whether it is appropriate to establish a different standard for small 
refineries. As proposed, the equipment leaks provisions would be the 
same for small and large refineries, except that all equipment at small 
refineries would be allowed 18 months to begin compliance (instead of 
requiring one-third of the equipment to comply in 6 months, one-third 
in 12 months, and the remainder in 18 months). Compliance in 6 or 12 
months could be infeasible for many small refineries. Many are located 
in attainment areas and have never been required to implement LDAR 
programs and their owners or operators do not have expertise in setting 
up and operating such programs. It will require more time for these 
refineries to develop and implement LDAR programs and the associated 
recordkeeping and reporting systems.
    The EPA is also considering a less stringent standard and a longer 
compliance time for small refineries. In particular, small refinery 
existing sources could be required to comply with the provisions of the 
equipment leaks NSPS 40 CFR part 60 subpart GGG instead of the proposed 
option. As discussed in section VI.E.1.a, the MACT floor for equipment 
leaks at existing sources is between the CTG and the NSPS, so the NSPS 
is at least as stringent as the MACT floor. The NSPS has a leak 
detection level of 10,000 ppm and does not have the phased-in lower 
leak definitions and performance levels or the QIP provisions of the 
proposed rule. Thus, the NSPS would be simpler and less costly for 
small refiners to implement. There is also concern that because of 
start-up costs for the LDAR program and the relationship of costs to 
refinery complexity, the cost per Mg of emission reduction for options 
above the floor could be somewhat higher for small refiners. The EPA 
solicits comments on whether the standard for small refineries should 
be based on the NSPS instead of the negotiated rule. In particular, 
documentation of the control level of small refineries, and the costs 
of complying with the NSPS versus the proposed rule would be helpful. 
Commenters should provide the technical bases for their cost estimates 
and other comments.
    The EPA is also considering allowing small refineries 3 years to 
achieve compliance with the NSPS level of control. As previously 
stated, small refineries may need additional time to design and 
implement LDAR programs. Section 112 of the Act allows the EPA to 
establish compliance times up to a maximum of 3 years for existing 
sources. New sources would be required to comply upon start-up or 
promulgation of the rule, whichever is later, as required by the Act. 
The EPA requests comments and supporting rationale on what compliance 
times are reasonable for small refineries.
2. Selection of Format
    Because it is not practical to measure emissions from equipment 
leaks, an equipment and work practice format was chosen for the 
standards. Format selection is discussed in the preamble to the 
proposed HON (57 FR 62608). Because the HON negotiated rule for 
equipment leaks is the basis of the standard chosen to regulate 
petroleum refinery equipment leaks for both new and existing sources, 
the EPA elected to refer directly to the requirements in the negotiated 
rule. The differences for pumps, valves, and connectors are specified 
in the proposed subpart CC.
3. Selection of Monitoring and Compliance
    Determination Provisions. Because the equipment leak provisions of 
the proposed rule are work practice and equipment standards, 
monitoring, repairing leaks, and maintaining the required records 
constitutes compliance with the rule. The HON equipment leak provisions 
are appropriate to determine continuous compliance with the petroleum 
refinery equipment leak standards. In summary, these provisions require 
periodic monitoring with a portable hydrocarbon detector to determine 
if equipment is leaking. If leaks are detected, repair is required 
within specified time periods. There are provisions for delay of repair 
in certain circumstances. Failure to perform the required monitoring or 
to repair leaking equipment within the specified time period or 
document a delay of repair would constitute an enforceable violation of 
the standards.

F. Use of Continuous Monitoring to Determine Compliance

    The EPA has considered how sources subject to this NESHAP should 
demonstrate continuous compliance with the standards. The EPA has 
concluded that where CEMS were not feasible operating parameter 
monitoring can be used for this purpose. As explained under 
miscellaneous process vents in section VI.B of this notice, use of CEMS 
is not feasible for measuring emissions from petroleum refineries; 
however, continuous operating parameter monitoring is required for some 
emission points. An excursion of a parameter outside the established 
range would constitute a violation of the emission standards. Owners or 
operators are required to establish site-specific ranges for operating 
parameters based on performance test data and/or other information. 
This allows owners or operators to demonstrate the parameter ranges 
that correspond to meeting the emission limits for their particular 
emission points and control devices. If a parameter is outside the 
range it would be considered a violation of the emission limits unless 
the excursion is caused by a start-up, shut-down, or malfunction that 
meets the criteria for a malfunction specified in the NESHAP general 
provisions (40 CFR part 63 subpart A).
    A daily averaging period for monitored parameters was selected for 
determining whether an excursion has occurred. This averaging period 
allows for short-term (e.g., 15-minute or hourly) parameter 
fluctuations that are expected and unavoidable for the types of control 
devices required, and gives the owner or operator a reasonable period 
of time to take action if there is a problem. If a shorter averaging 
period (for example 3 hours) were selected, sources would be likely to 
have multiple excursions caused by the same operational problem because 
it would not be possible to correct problems in one 3-hour reporting 
period.
    The EPA requests comment on the proposed approach for determination 
of compliance based on continuous parameter monitoring, and on possible 
alternative approaches.
    As explained in section VI.B, (Miscellaneous Process Vents section) 
not all vents are required to use continuous monitors. Most 
miscellaneous process vents would probably be ducted to the refinery 
fuel gas system for combustion in boilers, and such vents would not be 
regulated under the proposed rule and would not be required to perform 
any monitoring.
    For some emission points, such as storage vessels equipped with 
floating roofs and equipment leaks, continuous monitoring is not 
feasible. In such cases, failure to comply with the required inspection 
and repair procedures would constitute a violation of the equipment and 
work practice standards.

G. Selection of Reporting and Recordkeeping Provisions

    The proposed rule would require sources to submit up to four types 
of reports: Initial Notification, Notification of Compliance Status, 
Periodic Reports, and Other reports. The purpose and contents of each 
of these reports are described in this section. The wording of the 
proposed rule requires all draft reports to be submitted to the 
``Administrator''. The term Administrator means either the 
Administrator of the EPA, an EPA regional office, a State agency, or 
other authority that has been delegated the authority to implement this 
rule. In most cases, reports will be sent to State agencies. Addresses 
are provided in the General Provisions (subpart A) of 40 CFR part 63.
    Records of reported information and other information necessary to 
document compliance with the regulation are generally required to be 
kept for 5 years. A few records pertaining to equipment design would be 
kept for the life of the equipment.
1. Initial Notification
    The proposed rule would require owners or operators who are subject 
to subpart CC to submit an Initial Notification. This report 
establishes early communication between the source and the regulatory 
agency, allowing both to plan for regulatory compliance. If the 
information contained in the Initial Notification has already been 
submitted to the operating permit authority, no Initial Notification is 
required for this rule. For existing sources, the Initial Notification 
is due 120 days after the date of promulgation. For new sources, the 
Initial Notification is due as soon as practicable before construction 
or reconstruction is planned to commence but it need not be sooner than 
90 days after promulgation of subpart CC.
    The Initial Notification must include a list of the petroleum 
refining processes at the source that are subject to subpart CC, and 
which provisions may apply (e.g., the provisions for miscellaneous 
process vents, storage vessels, or equipment leaks). A detailed 
identification of emission points is not required, because these data 
would be included in the operating permit application.
2. Notification of Compliance Status
    The Notification of Compliance Status would be submitted 150 days 
after the source's compliance date. For new sources, the compliance 
date is at start-up or the promulgation date of subpart CC, whichever 
is later. For existing sources, the proposed compliance date is 3 years 
after promulgation, except that equipment leaks compliance would be 
staggered, with one-third of the equipment complying 6 months after 
promulgation, another third in 12 months, and the remainder in 18 
months. The timing of compliance-related reporting for equipment leaks 
is specified in 40 CFR part 63 subpart H, which was referenced by 
subpart CC. The Notification of Compliance Status contains the 
information necessary to demonstrate that compliance has been achieved, 
such as the results of performance tests and design analyses. If this 
information has already been submitted as part of a Title V operating 
permit program it does not have to be repeated in a Notification of 
Compliance Status. If it is not already submitted, however, it must be 
submitted as specified in this rule.
    Sources with a large number of emission points are likely to submit 
results of multiple performance tests for each kind of emission point. 
For each test method used for a particular kind of emission point 
(e.g., a process vent), one complete test report would be submitted. 
For additional tests performed for the same kind of emission point 
using the same method, the results would be submitted, but a complete 
test report is not required. Results would include values needed to 
determine compliance (e.g., inlet and outlet concentrations, flow 
rates, and percent emission reduction) as well as the values of 
monitored parameters averaged over the period of the test. Submitting 
one test report will allow the regulatory authority to verify that the 
source has followed the correct sampling and analytical procedures and 
has done calculations correctly. Complete test reports for other 
emission points may be kept at the plant rather than submitted. This 
reporting system was established to ensure that reviewing authorities 
have sufficient information to evaluate the monitoring and testing used 
to demonstrate compliance with the petroleum refineries NESHAP, while 
minimizing the reporting burden.
    Another type of information to be included in the Notification of 
Compliance Status is the specific range for each monitored parameter 
for each emission point, and the rationale for why this range indicates 
compliance with the emission standards. (If this range has already been 
established in the operating permit, it does not need to be repeated in 
the Notification of Compliance Status.)
    Although in some previous NSPS and NESHAP, the EPA has specified a 
pre-determined range of operating parameter values, such values could 
be considered inadequate given the increased importance of parameter 
monitoring in determining and certifying compliance due to the new 
requirements in section 114 of the Act. For the proposed petroleum 
refinery NESHAP, the EPA is requiring sources to establish site-
specific ranges. Allowing site-specific ranges for monitored parameters 
accommodates site-specific variation in emission point characteristics 
and control device designs. Based on the information available at 
proposal, it appeared to be difficult to establish ranges or minimum or 
maximum values that would be applicable in all cases.
    The proposed system for establishing operating parameter ranges 
attempts to balance the need for technical certainty and operational 
feasibility. The ranges may be established by performance testing 
supplemented by engineering assessments and manufacturer's 
recommendations. However, the performance test is not required to be 
conducted over the entire range of permitted parameter values because 
such a requirement could impose significant technical difficulties and 
costs on the source. The EPA believes that a performance test conducted 
for a smaller, yet representative, range of operating conditions can 
still provide a range for the operating parameters that ensures 
compliance with the emission limit. For emission points and control 
devices where a performance test is not required (for example, a closed 
vent system and control device on a storage vessel), the range may be 
established by engineering assessment.
    As an example, for a miscellaneous process vent controlled by an 
incinerator, the notification of compliance status would include the 
site-specific minimum firebox temperature that will ensure that the 
emission limit is met and the data and rationale to support this 
minimum temperature.
3. Periodic Reports and Records of Monitoring Data
    Periodic Reports are required to ensure that the standards continue 
to be met and that control devices are operated and maintained 
properly. Generally, Periodic Reports would be submitted semiannually. 
If monitoring results show that the parameter values for a particular 
emission point are outside the established range for more than 1 
percent of the operating time in a reporting period, or the monitor is 
out of service for more than 5 percent of the time, the implementing 
agency may request that the owner or operator submit quarterly reports 
for that emission point. After 1 year, the source can return to 
semiannual reporting, unless the regulatory authority requests 
continuation of quarterly reports.
    The EPA has established this reporting system in order to provide 
an incentive (less frequent reporting) for good performance. Because of 
uncertainty about the periods of time over which sources are likely to 
experience excursions outside the parameter ranges or monitoring system 
failures, the EPA is seeking comment on the 1 and 5 percent criteria 
triggering more frequent reporting. In particular, data are requested 
on both the frequency of excursions and monitoring system downtime.
    Periodic Reports specify periods when the values of monitored 
parameters are outside the ranges established in the Notification of 
Compliance Status or operating permit. If the values of the monitored 
parameters are within the established range, records are kept, but the 
values are not reported. This will reduce the volume of information in 
reports and will reduce the reporting burden while still allowing 
determination of continuous compliance.
    For continuous parameter monitoring, records must be kept of the 
parameter recorded once every 15 minutes. If a parameter is monitored 
more frequently than once every 15 minutes, 15-minute or more frequent 
averages may be recorded instead of the individual values. For days 
when the monitored values are not outside their ranges, the owner or 
operator may convert the 15-minute values to hourly averages and then 
discard the 15-minute values. These provisions ensure that there will 
be enough monitoring values recorded and retained to be representative 
of the monitoring period, while reducing by a factor of four the burden 
that would be associated with digital conversion of data, transferring 
data to tape or hard copy, copying, and storing the data if all the 15-
minute values had to be retained.
    The proposed rule would allow sources to request approval to use 
alternative monitoring and recordkeeping systems. This will reduce the 
burden by allowing greater use of existing systems. Alternative 
monitoring systems specifically discussed in the rule include 
nonautomated systems and data compression systems. These systems will 
be allowed on a site-specific basis, dependent upon approval of the 
implementing agency. The proposed rule includes specific minimum 
requirements for applications to use nonautomated systems. For example, 
parameters must be manually read and recorded at least once per hour 
and the source must demonstrate that the frequency is sufficient to 
represent control device operating conditions. Data compression systems 
do not record monitored operating parameter values at a set frequency, 
but record all values that meet set criteria for variation from 
previously recorded values. The proposed rule would require sources 
applying to use such systems to show that they are designed to: Measure 
and record at least four representative values per hour, recognize and 
alert the operator to unchanging data, and calculate daily averages. 
Additional details and rationale for these provisions are contained in 
the preamble to the promulgated HON (59 FR 19402, April 22, 1994).
    For some types of emission points and controls, periodic (e.g., 
monthly, quarterly, or annual) inspections or measurements are required 
instead of continuous monitoring. Records that such inspections or 
measurements were done must be kept; but results are included in 
Periodic Reports only if a problem is found. This requirement is 
designed to minimize the recordkeeping and reporting burden of the 
proposed rule.
4. Other Reports
    There are a very limited number of other reports. Where possible, 
subpart CC is structured to allow information to be reported in the 
Periodic Reports. However, in a few cases, it is necessary for the 
source to provide information to the regulatory authority shortly 
before or after a specific event. For example, for storage vessels, 
notification prior to internal tank inspections is required to allow 
the regulatory authority to have an observer present. Requests for 
approval to monitor control device operating parameters other than 
those listed in the rule and requests for approval to use alternatives 
to continuous monitoring must be submitted 18 months prior to the 
compliance date for existing sources. This will allow the regulatory 
authority and the source to reach agreement on monitoring requirements 
prior to the compliance date. Certain notifications and reports 
required by the part 63 General Provisions must also be submitted.

H. Rationale for Emissions Averaging Provisions

    The EPA is proposing that emissions averaging be allowed for 
miscellaneous process vents, storage tanks, and wastewater streams 
within petroleum refineries. The EPA requests comments on whether 
emissions averaging should be included in the final rule, and on 
specific features of the proposed emissions averaging provisions. 
Commenters should provide the reasons for their recommendations and 
supporting information.
    The EPA proposed a NESHAP for Marine Tank Vessel Loading and 
Unloading Operations in the Federal Register Vol. 59, No. 92 on Friday, 
May 13, 1994. Marine Tank Vessel Loading and Unloading Operations is a 
source category included on the list of source categories for 
regulation under Section 112. The NESHAP addresses HAP from these 
operations; loading and unloading operations can occur at refineries as 
well as other types of plants.
    Today's proposed rule addresses only the 4 emission points in 
refinery operations discussed earlier in this notice. Although no 
regulatory text is included in today's proposal, the EPA requests 
comments on the concept of expanding the petroleum refinery source 
category covered by today's rule to include marine vessel loading and 
unloading operations subject to the requirements of section 112 that 
occur at refineries. The marine vessel requirements proposed for 
purposes of compliance with section 183(f), however, would remain 
unchanged. If the above change is made to the petroleum refinery source 
category, the source category currently listed in accordance with 
section 112(c) as Marine Tank Vessel Loading and Unloading Operations 
would be split into two parts--those which are collocated at refineries 
and those which are not. The ones collocated at refineries would be 
combined with and become part of the refinery source category addressed 
by today's proposed rule. The source category list would be amended 
accordingly. The purpose would be to allow emissions averaging between 
the HAP emissions from marine vessel loading and unloading and the HAP 
emissions from the refinery emission points identified in today's rule 
as suitable for emissions averaging. It appears that in some cases, 
there may be opportunities to control some of these emission points 
(e.g. storage tanks) more cost-effectively than marine vessel loading 
and unloading operations. In other cases, it may be more cost-effective 
to control marine vessel operation emissions than the refinery emission 
points. Integrating marine loading and unloading operations into the 
refinery category and utilizing emissions averaging may provide an 
opportunity for more emissions reductions at a lower cost than would 
occur if the categories remain separate. In addition, because of the 10 
percent discount factor, additional emissions reductions will be 
achieved if emissions averaging is used. The EPA requests comments on 
whether there would be additional regulatory and enforcement 
complexities if this approach were adopted.
    If the suggested approach were adopted, the limitations of the 
proposed emissions averaging provisions included in today's proposal 
would also apply to the loading and unloading operations. With regard 
to calculating the emissions for purposes of averaging, the May 13 
proposal included procedures for determining HAP emissions from marine 
vessel loading operations for purposes of determining applicability of 
the rule; the EPA solicited comment on these procedures. These emission 
estimating procedures will also be considered for the purpose of 
emission averaging. The promulgation date, and thus the compliance 
date, for the marine vessel loading and unloading standard is currently 
expected to be earlier than the petroleum refinery standard. The EPA 
requests comments on whether and how these compliance dates should be 
made consistent, and what legal factors should be considered.
    The EPA's database which serves as the basis for the May 13 
proposed rule for marine vessels does not identify which loading and 
unloading operations occur at refineries as opposed to other types of 
plants. However, the EPA has no data to indicate that marine vessel 
loading operations at refineries are dissimilar to marine vessel 
loading operations located at other facilities or that their control 
levels differ. Therefore, the EPA anticipates that the floors for 
neither the petroleum refinery nor the marine vessel rules would be 
affected by redefining the source categories as described. If any data 
were received which could lead to changes in the floor calculations, 
the public would be given an opportunity to review the data as well as 
an opportunity to comment on any proposed changes to the floors.
    If the EPA expands the refinery source category to include marine 
vessel loading and unloading operations, loading operations at 
refineries would have an opportunity to average emissions and reduce 
costs. In addition, they would be required to achieve additional 
emission reductions in accordance with the 10 percent discount 
requirement contained in the emissions averaging provisions. Loading 
operations that stand alone would not have this same opportunity to 
reduce costs. Public comment is solicited on the magnitude of these 
impacts and the appropriateness of this distinction.
    Some marine terminals handle products with low concentrations of 
HAP's but high concentrations of non-HAP VOC. In such circumstances, it 
may be cost-effective to forego control of HAP's from marine terminals 
by overcontrolling HAP's from another emission point. If, however, the 
emission point being controlled does not offset the non-HAP VOC 
foregone by not controlling the marine terminals, a net increase in 
non-HAP VOC could result. The EPA solicits comments on what 
considerations should be given to this type of situation in deciding to 
combine marine terminals and refineries for the purpose of emission 
averaging.
    The EPA requests comment on the extent to which emissions averaging 
between marine vessel loading and unloading operations and other 
refinery operations could result in exposure spikes. This could occur 
if batch emission streams were left uncontrolled in exchange for 
control of continuous emission streams, or vice versa.
    Several regulatory alternatives were considered for each emission 
point covered by today's rule. In some cases, more stringent 
alternatives than those selected as the basis of the proposal were 
rejected based on cost considerations. If the EPA were to decide to 
allow emissions averaging between marine vessel loading and unloading 
operations and those emission points allowed to average by today's 
proposal, sources would likely have an opportunity to reduce compliance 
costs. It is possible that reduction in compliance costs could make 
other control options more affordable. Public comment is solicited on 
whether the 10 percent discount factor included in the emissions 
averaging provisions adequately addresses this issue or how the 
potential cost savings resulting from the redefinition of the source 
category should be considered when the EPA reevaluates the regulatory 
alternatives as part of the final rule.
    The EPA also requests that commenters submit data on possible 
emission factors and/or alternative emission calculation procedures for 
marine vessel operations for consideration in the final rule.
    The EPA will consider all comments and data received on this issue 
in publishing a final rule. If the EPA decides to promulgate a final 
rule allowing emissions averaging between marine vessel loading and 
unloading operations and other emission points at refineries, the 
Administrator may decide to publish a supplemental proposal or notice 
of data availability to provide the public an opportunity to comment, 
particularly on the specific averaging provisions of the rule.
1. Reasons for Proposing Averaging for the Four Emission Points
    Emissions averaging is proposed as a means of providing sources 
flexibility to comply in the least costly manner while still 
maintaining a regulation that is workable and enforceable. Recently, 
the EPA and Amoco Corporation conducted a joint study of environmental 
releases at the Amoco facility in Yorktown, Virginia. A focus of the 
study was to identify cost-effective pollution prevention and control 
opportunities. Specific emission estimates and control strategies for 
the Yorktown facility may not apply to other refineries due to site-
specific differences. However, the study did highlight the importance 
of compliance flexibility and the potential of pollution prevention 
strategies to achieve cost-effective emission reductions. Emissions 
averaging is one way to allow compliance flexibility within the 
statutory limitations of section 112 of the Act.
    The EPA has included emissions averaging provisions in this rule as 
one way of providing operational flexibility, however, implementing 
agencies can seek approval of the State rules or authorities which 
differ in form from the federal rule developed under section 112 of the 
CAA. An implementing agency could submit a formal request under 40 CFR 
part 63, subpart E demonstrating that the State rule, among other 
criteria, is at least as stringent for each affected source as the 
federal rule. Therefore, implementing agencies have the option of 
developing their own rule that provides operational flexibility through 
the State program approval and delegation process.
    For some facilities, including small refineries, use of emissions 
averaging could prevent serious economic impacts or potential closures. 
For example, economic impacts could be caused by removing fixed roof 
storage vessels from service to retrofit controls when the number of 
products is increasing due to the upcoming reformulated gasoline rules, 
and all the vessels may need to be in service to maintain production 
levels. Facilities in Northern climates have a limited season during 
which retrofits could be done, which corresponds to the gasoline 
production season. Averaging would provide some flexibility to not 
retrofit all storage vessels if other emission points could be more 
easily over-controlled. Similarly, due to site-specific equipment 
configurations and emission characteristics, it may be infeasible to 
route a particular miscellaneous process vent to the existing fuel gas 
or flare system. Control of such a vent could be costly. Another case 
where averaging would be useful is where facilities already control 
storage vessels or process vents, but the controls do not fully meet 
the specifications of the regulation. It could be costly to retrofit 
such emission points, and might only result in a few percent emission 
reduction. Emissions averaging might allow facilities to retain the 
current control levels for such points and balance this by over-control 
of emission points that can be controlled more cost effectively.
    The EPA requests comment on the usefulness of emissions averaging 
provisions for the petroleum refinery industry.
    The EPA is also interested in making sure that any flexibility 
provisions be appropriately tailored to each particular source category 
so that environmental protection is continually assured, and real 
flexibility provided. For that reason, the EPA is requesting comment on 
the specific provisions of the emissions averaging approach discussed 
below (recordkeeping and reporting, monitoring, compliance periods, 
debits, credits, credit discount factors, limits on averaging, 
interpollutant trading and averaging, and scope).
    This request for comment includes the threshold criteria (hazard or 
risk equivalency, discount factor) established in the HON for the use 
of averaging, and its appropriateness for this source category. For 
example, during discussions on the HON rule, concerns were raised about 
interpollutant trades resulting from the use of averaging provisions. 
As a result of these concerns, threshold criteria were added to ensure 
equal or greater environmental protection by requiring a demonstration 
of equivalent protection, and by requiring a 10 percent increase in 
reductions resulting from the use of averaging. Given that emission 
points in SOCMI sources and refinery sources have similar emission 
characteristics (multiple pollutant streams) which make interpollutant 
trading virtually inescapable under any averaging system, the EPA is 
seeking comment on these threshold criteria for use with this MACT 
standard.
    For the purposes of this MACT standard, the EPA would also like to 
solicit comment on cost as a threshold criteria for the use of an 
interpollutant averaging scheme. The Agency's assumption is that cost 
would likely be a prime motivator for the use of any averaging. It may 
be, however, that an explicit criteria for the demonstration of extreme 
costs (e.g., related to space constraints, safety concerns, near term 
plans for process changes, or additional control of well controlled 
points), as a pre-condition for the use of an interpollutant averaging 
scheme, would better protect against potential risk increases. This 
criteria would also likely result in less flexibility for the source.
    An alternative method of providing for operational flexibility 
would be to establish a case-by-case waiver system. This approach would 
allow sources that meet specific threshold criteria to determine an 
alternative compliance option for certain emission points. A source 
would need to demonstrate, to the satisfaction of the implementing 
agency, that MACT cannot be met for certain emission points because of 
extreme costs related to space constraints, safety concerns, near term 
process changes, or additional control of well controlled emission 
points. The alternative compliance option would, at a minimum, have to 
ensure that the control level for the entire source is at least as 
stringent as the MACT level of control. Some of the provisions of the 
HON averaging system (e.g., hazard [risk] equivalency, discount factor) 
could also be incorporated into this approach. While this approach only 
allows flexibility for those facilities that make the required 
demonstration, it provides sources and implementing agencies more 
flexibility to design a more tailored control scenario.
    The EPA requests comment on the concept of a case-by-case waiver 
system, the specific threshold criteria and the appropriateness of 
adopting HON-based provisions.
2. Overview of Averaging
    In the emissions averaging scheme proposed for petroleum 
refineries, a system of emissions ``credits'' and ``debits'' is used to 
determine whether the required emission reductions are achieved. 
Basically, the petroleum refineries provisions for each kind of 
emission point require Group 1 points (those meeting certain 
applicability criteria) to achieve a particular emissions reduction or 
apply a certain control technology. These technologies are called the 
``reference control technologies,'' or RCT's, and the EPA has 
established a control efficiency (percent emission reduction) for the 
RCT for each kind of emission point. If an owner or operator does not 
achieve the control efficiency of the RCT for a Group 1 emission point, 
an emission debit is generated.
    An owner or operator who generates an emission debit must control 
other emission points to a level more stringent than is required for 
that kind of point to generate emission credits. Credits may come from: 
(1) control of Group 1 emission points using technologies that the EPA 
has rated as being more effective than the appropriate RCT, (2) control 
of Group 2 emission points, and (3) pollution prevention projects that 
result in greater emission reduction than the standard requires for the 
relevant point or points.
    Emission credits would need to exceed debits on an annual basis for 
a source to be in compliance. Monitoring and quarterly credit/debit 
ratio checks would also be used to determine compliance, as described 
in section H.3 below. Furthermore, prior to using emissions averaging, 
a source would need to demonstrate to the satisfaction of the 
implementing agency that the planned emissions average would not result 
in increased risk or hazard relative to compliance without averaging.
3. Selection of Averaging Provisions
    This section describes the rationale for specific aspects of the 
proposed emissions averaging provisions and the alternative policies 
that were considered in developing these provisions.
    a. The scope of emissions averaging. The EPA proposes to allow 
emissions averaging across miscellaneous process vents, storage 
vessels, and wastewater streams within a single existing source, as 
defined for the petroleum refining source category. This proposed scope 
allows as much flexibility as possible while adhering to statutory 
requirements and maintaining an enforceable standard.
    The EPA decided against allowing equipment leaks to be included in 
emissions averaging. While there are methods available for quantifying 
emissions from equipment leaks, equipment leaks cannot be included in 
emissions averages at this time because the proposed standard for 
equipment leaks has no fixed performance level. Although it would be 
possible to establish site-specific emission levels, the cost would be 
high, and it would also be costly to maintain the documentation 
necessary to demonstrate compliance.
    Based on the complexity and cost of developing a scheme to include 
equipment leaks in emissions averaging and the likelihood of a high 
compliance determination burden for both the industry and enforcement 
agencies, the EPA decided the public cost of including equipment leaks 
in emissions averaging is not warranted at this time.
    The EPA proposes not to allow emissions averaging at new sources. 
New sources have historically been held to a stricter standard than 
existing sources because it is most cost-effective to integrate state-
of-the art controls into equipment design and to install the technology 
during construction of new sources. One reason for allowing averaging 
is to permit existing sources flexibility to achieve compliance at 
diverse points with varying degrees of control already in place in the 
most economically and technically reasonable fashion. This concern does 
not apply to new sources which can be designed and constructed with 
compliance in mind. Also, because new sources will have to comply with 
applicable NSPS (e.g., 40 CFR part 60 subpart Kb), there would be 
little opportunity for emissions averaging at new sources.
    Averaging would be permitted only among emission points within the 
petroleum refineries source category. Other emission points (e.g., 
SOCMI emission points) located within the contiguous facility could not 
be averaged with petroleum refinery emission points. The fundamental 
problem with allowing averaging among different source categories is 
that it allows averaging among multiple sources. The proposed petroleum 
refineries NESHAP defines the source as the collection of emission 
points within petroleum refinery processes within a major source. Many 
major sources containing such points will also contain other points 
that are not covered by this standard but are covered by different MACT 
standards (e.g., the HON). Each of these standards may have a separate 
floor, and the statute requires that each standard be no less stringent 
than its floor.
    It would be inconsistent with section 112(d) to allow averaging to 
be used to permit a source subject to a MACT standard to avoid 
compliance with that standard. In addition, different sources would 
have different compliance deadlines. Section 112(i) requires compliance 
by a source within a set timeframe. Transferring emission reduction 
obligations to points outside of the source would be inconsistent with 
the requirement of section 112(d) that standards be set for sources in 
a listed category and the requirement of section 112(i) that compliance 
with such standard be achieved by sources in the category.
    b. Interpollutant trading and risk analysis. The majority of HAP 
emissions at refineries are composed of a few chemicals, including 
benzene, toluene, xylenes, ethylbenzene, and hexane. There is a 
narrower range of variation in emission stream composition among 
petroleum refinery emission points than there is in some other source 
categories (e.g., SOCMI emission points regulated by the HON). However, 
the different HAP's emitted have different toxicities, and there are 
some variations in the concentrations of individual HAP's and the 
emission release characteristics of different emission points. 
Therefore, there is a potential that some emissions averaging scenarios 
could increase the health risk to the public relative to the risk of 
compliance without emissions averaging. For this reason, the EPA 
proposes that sources who elect to use averaging must demonstrate, to 
the satisfaction of the implementing agency, that compliance through 
averaging would not result in greater risk or hazard than compliance 
without averaging. The EPA would provide guidance for making the 
demonstration based on existing procedures, but the actual methodology 
to be used by the source would be chosen by the implementing agency. 
The EPA believes that this approach provides assurance of health 
protection while allowing for site-specific evaluations. This approach 
also gives all implementing agencies the authority to consider risk in 
approving averages. A more complete discussion of the reasons for this 
decision and the alternatives considered is provided in the preamble to 
the promulgated HON (59 FR 19402, April 22, 1994). The EPA requests 
comment on whether the provisions regarding risk or hazard 
demonstration should be the same for petroleum refineries as for the 
HON.
    The EPA also requests comment on whether sources should be required 
to use the hazard ranking system developed for the purposes of section 
112(g) to demonstrate that compliance through averaging would not 
result in greater hazard. States would still have the option of also 
requiring a risk analysis.
    c. Limits on averaging. The EPA proposes that emissions averages be 
limited to 20 points at a source, or 25 points if pollution prevention 
measures are used to control some points in the average. A limitation 
on the number of points is proposed because the complexity of averaging 
across a large number of points would raise significant enforcement 
concerns, as well as concerns about the resource burden on implementing 
agencies. The EPA anticipates that most sources will not find a large 
number of opportunities to generate cost-effective credits. Hence, it 
can be anticipated that most averages will involve a limited number of 
emission points, and imposing a limit should not affect most sources. 
The limit of 20 points in an average, 25 points if pollution prevention 
measures are used, was chosen because the EPA anticipates that most 
sources will rarely want to include more than 20 points in an average. 
In addition, allowing much more than 20 points would make enforcement 
increasingly untenable. Thus, the competing interests of flexibility 
for sources and enforceability were balanced in this decision. A higher 
number of points is allowed where pollution prevention is used in order 
to encourage pollution prevention strategies, and because the same 
pollution prevention measure may reduce emissions from multiple points.
    The proposed rule would grant State and local agencies the 
discretion to preclude sources from using emissions averaging to comply 
with the petroleum refineries NESHAP, without using the section 112(l) 
rule delegation process. Without this provision, if a State or local 
agency wished to receive delegation of authority to implement and 
enforce the NESHAP without averaging, a review by the EPA would be 
required. Including this provision in the NESHAP will reduce paperwork 
burdens on States, expedite delegation of the rule to States, and 
remove a potential source of uncertainty for sources subject to the 
rule. Even though the EPA supports the use of emissions averaging where 
it may be appropriate, its use must be balanced by the individual needs 
of States and local agencies that bear the responsibility for 
administering and enforcing the rule. A detailed rationale for allowing 
agencies discretion to implement the NESHAP without emissions averaging 
is contained in the preamble for the promulgated HON (59 FR 19402, 
April 22, 1994).
    d. Credits. The equations and procedures for calculating source 
wide credits are contained in Sec. 63.650 of the proposed rule. The 
proposed emissions averaging would allow credits only for control or 
pollution prevention actions taken after November 15, 1990, the date of 
the 1990 Amendments. The EPA proposes not to allow actions taken before 
passage of the 1990 Amendments to be used to generate emission credits 
because such reductions would have occurred anyway, for reasons 
unrelated to the 1990 Amendments or the proposed rule. If the EPA 
allowed these actions to generate emission credits, then the source 
would be able to generate more emission debits and, thus, more total 
emissions. Emissions averaging is a method for complying with subpart 
CC and should not result in more emissions than the other compliance 
options.
    Credits could be generated if miscellaneous process vents, Group 1 
storage vessels, or Group 1 wastewater streams are controlled using 
equipment that EPA agrees has a higher efficiency than the RCT for 
those points. Credits can also be generated if a pollution prevention 
measure is used on a Group 1 point or a miscellaneous process vent, 
alone or in combination with a control technology, and it results in 
lower emissions than would use of the RCT alone. In order to take 
credit for reductions beyond the RCT level, the source would need to 
demonstrate the efficiency or level of emission reduction achievable 
through use of the control technology or pollution prevention measure. 
The process for application and approval of a ``nominal efficiency'' 
higher than the RCT efficiency is contained in Sec. 63.650 of the 
proposed rule.
    The EPA proposes not to allow credits for use of an RCT above its 
designated reference efficiency rating. (The RCT's for process vents, 
storage vessels, and wastewater, and their efficiencies are listed in 
the definitions section of the proposed rule.) Reference control 
efficiency ratings for RCT were established because each RCT has a 
minimum level of emissions reduction that can generally be achieved. 
The EPA acknowledges that RCT's can sometimes achieve greater emission 
reductions. However, providing credits for these instances is 
inappropriate because the magnitude of debits, not just credits, is 
based on the RCT's reference efficiency ratings. If it could be 
determined that the RCT on a debit generator could achieve greater 
reductions than its rated efficiency, the magnitude of debits from the 
point would be greater. Thus, to give credit for reductions above an 
RCT's rated efficiency and not to increase the magnitude of debits as 
well would represent a windfall from averaging, and result in greater 
emissions than under point-by-point compliance.
    Credit could be generated by applying a control technique or 
pollution prevention measure to a Group 2 storage vessel or wastewater 
stream. There are no Group 2 miscellaneous process vents under the 
refineries NESHAP because all miscellaneous process vents subject to 
the rule are required to apply control (i.e., are Group 1). The 
procedures for determining the efficiency of controls or pollution 
prevention measures applied to Group 2 storage vessels and wastewater 
streams are contained in Sec. 63.650 of the proposed rule.
    e. Credit discount factors. A discount factor of 10 percent is 
proposed for calculating credits. A discount factor would reduce the 
value of credits in the emissions average by a certain percentage 
before the credits are compared to the debits. In considering a 
discount factor, the EPA examined the requirements for determining MACT 
in section 112(d) of the Act. Section 112(d)(2) specifies that MACT 
standards shall require the maximum degree of reduction in emissions of 
HAP's, taking into consideration, among other things, the cost of 
achieving those reductions. By defining the source broadly and 
including the option for emissions averaging in the proposed rule, it 
could be argued that the EPA is providing flexibility for source owners 
and operators that would lower the costs of compliance. The EPA is 
persuaded that, to carry out the mandate of Sec. 112(d)(2) of the Act, 
some portion of these cost savings should be shared with the 
environment by requiring sources using averaging to achieve more 
emission reductions than they would otherwise. The 10 percent discount 
factor is consistent with the HON and other programs. While realizing 
environmental benefits, the 10 percent factor is not so high as to 
preclude or strongly discourage emissions averaging.
    Credits generated through use of a pollution prevention measure 
would not be discounted, because the EPA recognizes that encouraging 
pollution prevention will result in more overall emission reductions, 
possibly including multimedia reductions and lower overall releases 
into the environment.
    f. Debits. The equations and procedures for calculating source-wide 
debits are contained in Sec. 63.650 of the proposed rule. Debits would 
be generated when a miscellaneous process vent or a Group 1 storage 
vessel is not controlled to the level required by the miscellaneous 
process vent or storage vessel provisions of the NESHAP. Debits could 
not be generated for Group 1 wastewater streams.
    g. Compliance period. The EPA proposes that the credits and debits 
generated in emissions averages balance on an annual basis, and that 
debits do not exceed credits by more than 30 percent in any one quarter 
of the year. These two requirements are used together to establish an 
emissions averaging system that provides flexibility for changes in 
production over time without allowing for wide-ranging fluctuations in 
HAP emissions over time. The annual compliance period was selected for 
proposal to accommodate seasonal changes in production and provide 
sources flexibility in selecting points for inclusion in emissions 
averages. Annual averaging accommodates seasonal changes in feedstocks, 
product mix, and operating conditions. Seasonal changes in product mix 
are common at refineries which, for example, may maximize gasoline 
production during some parts of the year and maximize fuel oil (heating 
oil) during other seasons. With an annual compliance period, sources 
can average emission points that may not have the same emission rates 
during some periods of the year, as long as they are similar on an 
annual basis. This latitude will also be useful to accommodate averages 
with points that must undergo temporary maintenance shutdowns at 
different times during the year.
    In selecting a compliance period for averaging, the EPA also 
considered the need to verify compliance and, when appropriate, take 
enforcement action in a timely fashion. One concern about an annual 
compliance period is that the EPA's authority to take administrative 
enforcement actions would be reduced because section 113(d) of the Act 
limits assessment of administrative penalties to violations that occur 
no more than 12 months prior to the initiation of the administrative 
proceeding. Administrative proceedings are far less costly than 
judicial proceedings for both the EPA and the regulated community. The 
requirement that debits not exceed credits by more than 30 percent in 
any quarter enables the EPA to use this administrative enforcement 
authority by providing a shorter period in which to verify compliance.
    The EPA is, however, also considering compliance periods that are 
shorter than annual. The EPA has concerns about the ability to take 
enforcement actions for violations that cover an entire year and thus 
involve the analysis and presentation of an entire year's data, which 
may make litigation complex. Specific alternatives could include a 
quarterly or semiannual block averaging period, where credits would 
need to equal or exceed debits for each 3-month or each 6-month period. 
Alternatively, a quarterly or semiannual block averaging period with 
banking for an additional 3-month or 6-month period could be specified. 
If banking were allowed across blocks, the source could reserve or 
``bank'' extra emission credits from one period to offset debits in the 
next averaging period. At the end of the next averaging period, any 
unused banked credits would expire. Banking could avoid some 
noncompliance scenarios and accommodate seasonal variations; however, 
it could make compliance determination more complex. The EPA requests 
comments on whether one of these alternatives should be selected 
instead of the proposed annual compliance period.
    h. Banking. The EPA considered ``banking'' of credits, which would 
allow excess credits generated in one compliance period to be saved and 
used to offset debits in a subsequent compliance period. The EPA 
proposes not to allow banking if an annual compliance period is 
selected for emissions averaging. While banking could provide 
additional compliance flexibility for sources, it would greatly 
increase the administrative burden of emissions averaging and would 
also increase the likelihood of peak HAP exposures. In years when 
banked credits were used, sources could be emitting beyond the 
standard. Banking is more fully discussed in the preambles to the 
proposed and promulgated HON (57 FR 62608, December 31, 1992 and 59 FR 
19402 April 22, 1994).
    i. Monitoring. Emission points in emissions averages would be 
subject to the same performance testing and monitoring requirements as 
the proposed rule requires for other emission points that are not 
included in averages. If monitoring shows that the controls in place on 
any given emission point in the emission average are not being operated 
to achieve their specified emission reduction, this would be separately 
enforceable from the credit/debit balance.
    If a continuously monitored emission point in an emissions average 
experiences a period of excess emissions, the proposed presumption is 
that the point should be assigned either no credits or maximum debits. 
It is proposed that either no credits and maximum debits, as 
applicable, will be assigned for periods of excess emissions because 
any other assumption would result in emission reductions that could not 
be verified or adequately enforced. However, if the source has data 
indicating that some partial credits or debits may be warranted, it can 
submit that information to the implementing agency with the next 
Periodic Report. Thus, partial credits and debits can be assigned with 
the approval of the implementing agency.
    j. Recordkeeping and reporting. Under emissions averaging, sources 
would submit a detailed description of the planned emissions average in 
an implementation plan. The plan can be submitted in the operating 
permit application, an amendment to the application, or as a separate 
submittal. The emissions averaging plan would be approved by the 
operating permit authority, except that sources applying for credits 
for controls with nominal efficiencies beyond the RCT level would need 
to obtain EPA approval for the nominal efficiency rating.
    The Notification of Compliance Status would contain performance 
test results for emission points in averages and first quarter debit 
and credit calculations. Periodic reports for points in emission 
averages would be submitted quarterly, instead of semiannually. 
Quarterly reporting of credits and debits would allow timely 
enforcement of the quarterly emissions check provisions previously 
described. Periods when monitoring data for an emission point indicate 
excess emissions would also be identified in the quarterly reports.
    Recordkeeping for emission points in emissions averages would be 
similar to that for other emission points. In addition, records of 
monthly credit and debit calculations would be maintained.
    These recordkeeping and reporting provisions were selected for 
proposal because they are as consistent as possible with the provisions 
for emission points that are not in averages, while also providing the 
additional credit and debit information needed to determine whether the 
emissions average is achieving the required level of emissions 
reduction.

VII. Amendments to Previous Regulations

    Amendments to two previous regulations are being proposed along 
with the proposal of the Petroleum Refinery NESHAP: The Petroleum 
Refinery Wastewater NSPS, 40 CFR part 60 subpart QQQ; and the SOCMI 
Equipment Leak NSPS, 40 CFR 60 subpart VV.

A. Amendment to 40 CFR Part 60 Subpart QQQ

    Two amendments to subpart QQQ are being proposed. One clarifies a 
confusion regarding an exemption for tanks. The other allows the use of 
mechanical shoe seals on tanks.
    Section 60.692-3(d), Standards: Oil-water separator, of subpart QQQ 
exempts tanks that are subject to the requirements of K, Ka, or Kb from 
the requirements of Sec. 60.692-3. This exemption was placed in the 
standards section of the subpart with the intent that the exemption 
applied to tanks subject to the control and associated requirements of 
K, Ka, or Kb. There has been confusion regarding whether the exemption 
applies to tanks subject to the control requirements or to affected 
facilities as defined in K, Ka, and Kb.
    The affected facilities to which K and Ka apply are storage vessels 
with capacities greater than or equal to 151 cubic meters. Subparts K 
and Ka require controls on affected facilities containing liquids with 
vapor pressures equal to or greater than 10.3 kPa.
    The affected facility to which Kb applies is each storage vessel 
with a capacity greater than or equal to 40 cubic meters. However, each 
storage vessel with a capacity less than 75 cubic meters is exempt from 
the General Provisions (part 60 subpart A) and from the provisions of 
subpart Kb, except for the requirement that the operator keep records 
showing dimensions and capacity of vessel [Sec. 60.116b(b)]. Subpart Kb 
requires controls on affected facilities with capacities greater than 
or equal to 151 cubic meters containing liquids with vapor pressures 
greater than or equal to 5.2 kPa.
    The intent of subpart QQQ is to control emissions from the 
wastewater system down to and including primary treatment. The control 
technique is to prevent exposure to the atmosphere of the oily 
wastewater in the drain system and the oil-water separator. Subpart QQQ 
requires that each drain be equipped with a water seal control and each 
junction box and sewer line be covered. Subpart QQQ also requires each 
oil water separator tank, slop oil tank, storage vessel, or other 
auxiliary equipment be equipped and operated with a tightly sealed 
fixed roof.
    Questions have arisen regarding whether Sec. 60.692-3(d) would 
allow an open-top tank in the wastewater system at or upstream of the 
oil-water separator. For example, assume a tank is an affected facility 
under subpart QQQ and Subpart K, Ka, or Kb and contains an organic 
liquid with a vapor pressure less than 5.2 kPa. The operator would have 
to meet recordkeeping requirements but the tank would not be required 
to have a fixed roof to comply with K, Ka, or Kb. This is obviously 
inconsistent with the intent of the control technology based standards 
of subpart QQQ.
    The second proposed amendment is to allow use of mechanical shoe 
seals on oil/water separators. As described in the proposal preamble 
for subpart QQQ, 52 FR 16338 (May 4, 1987), the EPA only had 
information on the availability of two basic designs for primary seals 
that are applicable to oil-water separators. The two designs were 
vapor-mounted and liquid-mounted primary seals. The EPA solicited 
comments on the effectiveness of different types of seals applicable to 
oil-water separators. The EPA received no comments on the use or 
availability of mechanical shoe seals.
    Since promulgation of subpart QQQ, the EPA has received several 
requests to allow the use of mechanical shoe seals to meet the 
requirements of subpart QQQ. Subpart Kb allows the use of liquid-
mounted primary seals or mechanical shoe seals on external floating 
roofs on storage tanks.
    According to the proposal preamble for subpart Kb, 49 FR 29702 
(July 23, 1984), data from tests conducted on external floating roof 
tanks by the American Petroleum Institute show that a mechanical shoe 
primary seal in conjunction with a rim-mounted secondary seal is as 
effective as a liquid-mounted primary seal with a secondary seal. These 
same data were used to evaluate the efficiency of vapor-mounted primary 
seals in response to comments received on the proposed rule.
    Since liquid-mounted primary seals and mechanical shoe primary 
seals both meet the requirements of the equipment standards in subpart 
Kb, it is determined, by analogy, that these two primary seal types 
meet the requirements of the alternative equipment standards in subpart 
QQQ. Thus, it is proposed that Sec. 60.693-2 of subpart QQQ be amended 
to allow use of mechanical shoe seals.

B. Amendment to 40 CFR Part 60 Subpart VV

    The EPA proposes to amend the definition of closed vent system in 
40 CFR part 60 subpart VV to clarify that if equipment leak emissions 
are routed back to the process, this does not make the process subject 
to the closed vent system standards that require operation with no 
detectable leaks above 50 ppmv. In the case of petroleum refineries, 
equipment leaks may be sent to the refinery-wide fuel gas system. It 
was not EPA's intent to require the entire fuel gas system to be 
subject to the 500 ppm requirement because the fuel gas system is an 
integral part of the process. Furthermore, the EPA's cost impact 
estimates did not include the large monitoring, recordkeeping, and 
reporting burden of complying with the 500 ppm limit, or the leak 
detection and repair requirements for the hundreds or thousands of 
valves, connectors, and other equipment associated with the refinery 
fuel gas system and the dozens of boilers or process heaters combusting 
the refinery fuel gas.
    The EPA proposes to amend 40 CFR part 60 subpart VV Sec. 60.482-5 
to match the language in the equivalent section of the equipment leaks 
negotiated rule (40 CFR part 63, subpart H, Sec. 63.166). The language 
from the negotiated rule more clearly represents the EPA's intentions. 
The current language in subpart VV requires sampling connection systems 
to be equipped with a closed purge system or a closed vent system. The 
negotiated rule requires closed purge sampling, closed-loop sampling, 
or a closed vent system. Closed-purge sampling systems eliminate 
emissions due to purging by either returning the purge material 
directly to the process or by collecting the purge in a collection 
system which is not open to the atmosphere for recycle or disposal. 
Closed-loop sampling systems also eliminate emissions due to purging by 
returning process fluid to the process through an enclosed system that 
is not directly vented to the atmosphere. Closed vent vacuum systems 
capture and transport the purged process fluid to a control device. In 
situ sampling systems would be exempted from these regulations.
    It is proposed that paragraph (f) of Sec. 60.482-10 of subpart VV 
be revised to be consistent with the requirements for closed vent 
systems developed for the HON (40 CFR part 63, subpart G, Sec. 63.148). 
These revisions more clearly reflect the EPA's intent and specify the 
monitoring and recordkeeping necessary to demonstrate compliance with 
the requirement to operate with no detectable leaks above 500 ppmv. For 
closed vent systems constructed of hard-piping, compliance would be 
determined by an initial Method 21 inspection and an annual visual 
inspection. Because such systems are extremely unlikely to leak, an 
annual Method 21 inspection is considered to be overly burdensome. For 
systems constructed of ductwork, annual Method 21 inspections would be 
required. The proposed revisions specify the time period for repairs if 
leaks are detected. Provisions are included for delay of repair, 
equipment that is unsafe to inspect, and equipment that is difficult to 
inspect. These provisions are very similar to those currently included 
in other sections of subpart VV (such as the valve standards), so they 
provide consistency.

VIII. Administrative Requirements

A. Executive Order 12866

    Under Executive Order 12866, [58 Federal Register 51735 (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 fourth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, it has been 
determined that this rule is a ``significant regulatory action'' rule 
because it will have an annual effect on the economy of more than $100 
million, and is therefore subject to the requirements of Executive 
Order 12866. As such, this action was submitted to OMB for review. 
Changes made in response to OMB suggestions or recommendations are 
documented in the public record.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the OMB under the Paperwork Reduction 
Act, 44 U.S.C. 3501 et seq. An Information Collection Request document 
has been prepared by the EPA (ICR No. 1692.01), and a copy may be 
obtained from Sandy Farmer, Information Policy Branch, EPA, 401 M 
Street, SW (2136), Washington, DC 20460, or by calling (202) 260-2740. 
The public reporting burden for this collection of information is 
estimated to average 4,281 hrs per recordkeeper annually. This includes 
time for reviewing instructions, searching existing data sources, 
gathering and maintaining the data needed, and completing and reviewing 
the collection of information.
    Send comments regarding the burden estimate or any other aspect of 
this collection of information, including suggestions for reducing this 
burden, to: (1) Chief, Information Policy Branch (2136), U.S. 
Environmental Protection Agency, 401 M Street, SW., Washington, DC 
20460; and (2) the Office of Information and Regulatory Affairs, Office 
of Management and Budget, Washington, DC 20503, marked ``Attention: 
Desk Officer for EPA.'' The final rule will respond to any OMB or 
public comments on the information collection requirements contained in 
this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601 et seq.) 
requires the EPA to consider potential impacts of proposed regulations 
on small business entities. If a preliminary analysis (known as the 
initial regulatory flexibility analysis) would have a significant 
economic impact on a substantial number (usually taken as at least 20 
percent) of small entities, then a final regulatory flexibility 
analysis must be prepared.
    Regulatory Flexibility Act guidelines for regulations like this one 
whose start action notifications were filed before April 1992 indicated 
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 potential closures 
range from none to a maximum of seven. The closures would occur in 
refineries that process less than 10,000 to 20,000 barrels of crude oil 
per day (refer to the ``Economic Impact Analysis of the Regulatory 
Alternatives for the Petroleum Refineries NESHAP'' in the Docket). 
While this percentage of net closures is less than 20 percent of the 
total number of small refineries (90), it was deemed high enough for 
carrying out a Regulatory Flexibility Analysis 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 three 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 economies 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. The 
third 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.
    Another 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 the refiners 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 these economic impacts on small refiners, the Agency is 
considering whether to subcategorize and develop separate MACT floors. 
As stated in section VI.A.1.e, comments are requested on whether a 
basis exists for subcategorizing small refineries, and if so, at what 
size, along with supporting data and rationale. In addition, the EPA 
would like to better understand the impact of the proposed rule on 
small refineries. To assist the EPA in assessing the impact of the 
proposed rule on small refiners, the Agency requests comment with 
supporting information on the level of competition between refiners 
that process less than 10,000 to 20,000 barrels of crude oil per day 
and the larger refiners. Moreover, there is additional uncertainty in 
predicting the economic impact since the EPA does not have the 
information to determine if or how small refineries will actually be 
affected by the proposed rule. For example, they would not be affected 
if the HAP emissions are below the 25 ton per year cutoff specified in 
the statute or they are processing crude oils or producing products 
whose vapor pressures and HAP contents are below the applicability 
levels specified in the rule. The EPA seeks comment and better 
information on these very small refineries as follows:
    (1) Are refineries that process less than 10,000 to 20,000 barrels 
per day of crude oil ``major sources'' as defined in section 112 of the 
Act?
    (2) Are the HAP contents of the process vents below the 20 ppmv 
applicability level?
    (3) Are the HAP contents of the petroleum liquids in the processing 
lines below the 5 percent (by weight) applicability level in the 
equipment leak provisions?
    (4) Are the true vapor pressures of the petroleum liquids in the 
storage vessels below the 1.2 psia applicability level?
    Supporting data should be included with the responses to these 
questions.

D. Review

    This regulation will be reviewed 8 years from the date of 
promulgation. This review will include an assessment of such factors as 
evaluation of the residual health and environmental risks, any overlap 
with other programs, the existence of alternative methods, 
enforceability, improvements in emission control technology and health 
data, and the recordkeeping and reporting requirements.

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 substances, Incorporation by 
reference, Petroleum refineries, Reporting and recordkeeping 
requirements.

    Dated: June 30, 1994.
Carol M. Browner,
Administrator.
[FR Doc. 94-17130 Filed 7-14-94; 8:45 am]
BILLING CODE 6560-50-P