[Federal Register Volume 63, Number 176 (Friday, September 11, 1998)]
[Proposed Rules]
[Pages 48890-48924]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-23508]



[[Page 48889]]

_______________________________________________________________________

Part III





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 63



National Emission Standards for Hazardous Air Pollutants for Source 
Categories; National Emission Standards for Hazardous Air Pollutants 
From Petroleum Refineries--Catalytic Cracking (Fluid and Other) Units, 
Catalytic Reforming Units, and Sulfur Plant Units; Proposed Rule

  Federal Register / Vol. 63, No. 176 / Friday, September 11, 1998 / 
Proposed Rules  

[[Page 48890]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[IL-64-2-5807; FRL-6154-3]
RIN 2060-AF28


National Emission Standards for Hazardous Air Pollutants for 
Source Categories; National Emission Standards for Hazardous Air 
Pollutants from Petroleum Refineries--Catalytic Cracking (Fluid and 
Other) Units, Catalytic Reforming Units, and Sulfur Plant Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule and notice of public hearing.

-----------------------------------------------------------------------

SUMMARY: This action proposes national emission standards for hazardous 
air pollutants (NESHAP) from process vents associated with certain new 
and existing affected sources at petroleum refineries. Hazardous air 
pollutants (HAP) that would be reduced by this proposed rule include 
organics (acetaldehyde, benzene, formaldehyde, hexane, phenol, dioxins, 
furans, toluene, and xylene) and reduced sulfur compounds (carbonyl 
sulfide, carbon disulfide); inorganics (hydrogen chloride, chlorine); 
and particulate metals (antimony, arsenic, beryllium, cadmium, 
chromium, cobalt, lead, manganese, and nickel). The health effects of 
exposure to these HAP can include cancer, respiratory irritation, and 
damage to the nervous system.
    The standards are proposed under the authority of section 112(d) of 
the Clean Air Act (the Act) as amended and are based on the 
Administrator's determination that petroleum refinery catalytic 
cracking units (CCU), catalytic reforming units (CRU), and sulfur plant 
units (SRU) may reasonably be anticipated to emit one or more of the 
HAP listed in section 112(b) of the Act from the various process vents 
found within these petroleum refinery process units. The proposed 
NESHAP would protect the public health and environment by requiring all 
petroleum refineries that are major sources to meet emission standards 
reflecting application of the maximum available control technology 
(MACT).

DATES: Comments. Comments on the proposed rule must be received on or 
before November 10, 1998.
    Public Hearing. If anyone contacts the EPA requesting to speak at a 
public hearing by October 2, 1998, a public hearing will be held on 
October 13, 1998, beginning at 10 a.m. For more information, see 
section VII.B of SUPPLEMENTARY INFORMATION.

ADDRESSES: Comments. Interested parties may submit written comments (in 
duplicate, if possible) to Docket No. A-97-36 at the following address: 
Air and Radiation Docket and Information Center (6102), U.S. 
Environmental Protection Agency, 401 M Street, SW., Washington, DC 
20460. The EPA requests that a separate copy of the comments also be 
sent to the contact person listed below. The docket is located at the 
above address in Room M-1500, Waterside Mall (ground floor).
    A copy of today's document, technical background information, and 
other materials related to this rulemaking are available for review in 
the docket. Copies of this information may be obtained by request from 
the Air Docket by calling (202) 260-7548. A reasonable fee may be 
charged for copying docket materials.
    Public Hearing. If anyone contacts the EPA requesting a public 
hearing by the required date (see DATES), the public hearing will be 
held at the EPA Office of Administration Auditorium, Research Triangle 
Park, NC. Persons interested in presenting oral testimony should notify 
Ms. Jolynn Collins, Waste and Chemical Process Group, Emission 
Standards Division (MD-13), U.S. Environmental Protection Agency, 
Research Triangle Park, NC 27711, telephone number (919) 547-5671.

FOR FURTHER INFORMATION CONTACT: For information concerning the 
proposed regulation, contact Robert B. Lucas, Waste and Chemical 
Process Group, Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, NC 27711, 
telephone number (919) 541-0884, facsimile number (919) 541-0246, 
electronic mail address, ``[email protected].''
SUPPLEMENTARY INFORMATION:
    Regulated Entities. Entities potentially regulated by this action 
are facilities (i.e., petroleum refineries) that utilize fluid or other 
CCU, CRU, or SRU in their refining processes. Regulated categories and 
entities include:

------------------------------------------------------------------------
                                                Examples of regulated   
                 Category                             entities          
------------------------------------------------------------------------
Industry..................................  Petroleum Refineries (SIC   
                                             2911).                     
Federal government........................  Not affected.               
State/local/tribal government.............  Not affected.               
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists the types of entities that the Agency is now 
aware could potentially be regulated by this action. Other types of 
entities not listed in the table also could be regulated. To determine 
whether your facility or company is regulated by this action, you 
should carefully examine the applicability criteria in section III.A of 
this document and in Sec. 63.1560 of the proposed rule. If you have 
questions regarding the applicability of this action to a particular 
entity, consult the person listed in the preceding FOR FURTHER 
INFORMATION CONTACT section.
    Internet. The text of today's document also is available on the 
EPA's web site on the Internet under recently signed rules at the 
following address: http://www.epa.gov/ttn/oarpg/rules.html. The EPA's 
Office of Air and Radiation (OAR) homepage on the Internet also 
contains a wide range of information on the air toxics program and many 
other air pollution programs and issues. The OAR's homepage address is: 
http://www.epa.gov/oar/.
    Electronic Access and Filing Addresses. The official record for 
this rulemaking, as well as the public version, has been established 
for this rulemaking under Docket No. A-97-36 (including comments and 
data submitted electronically). A public version of this record, 
including printed, paper versions of electronic comments, which does 
not include any information claimed as confidential business 
information (CBI), is available for inspection from 8 a.m. to 5:30 
p.m., Monday through Friday, excluding legal holidays. The official 
rulemaking record is located at the address in ADDRESSES at the 
beginning of this document.
    Electronic comments can be sent directly to the EPA's Air and 
Radiation Docket and Information Center at: ``A-and-R-
D[email protected].'' Electronic comments must be submitted as an 
ASCII file avoiding the use of special characters and any form of 
encryption. Comments and data will also be accepted on disks in 
WordPerfect in 5.1 file format or ASCII file format. All comments and 
data in electronic form must be identified by the docket number (A-97-
36). No CBI should be submitted through electronic mail. Electronic 
comments on this proposed rule may be filed online at many Federal 
Depository Libraries.
    Outline. The information in this preamble is organized as shown 
below.

I. Statutory Authority
II. Introduction
    A. Background
    B. NESHAP for Source Categories
    C. Health Effects of Pollutants

[[Page 48891]]

    D. Petroleum Refining Industry
    1. Catalytic Cracking Units
    2. Catalytic Reforming Units
    3. Sulfur Plant Units
III. Summary of the Proposed Rule
    A. Applicability
    B. Subcategories
    C. Emission Control Technology
    D. Emission Limits
    E. Emission Monitoring and Compliance Provisions
F. Notification, Reporting, and Recordkeeping Requirements
    1. Notifications
    2. Periodic Reports
    3. Recordkeeping
IV. Selection of Proposed Standards
    A. Selection of Source Category
    B. Selection of Emission Sources and Pollutants
    C. Selection of Proposed Standards for Existing and New Sources
    1. Background
    2. MACT Floor Technology and Emission Limits
    D. Selection of Monitoring Requirements
V. Summary of Impacts of Proposed Standards
    A. Air Quality Impacts
    B. Cost Impacts
    C. Economic Impacts
    D. Non-air Health and Environmental Impacts
    E. Energy Impacts
VI. Request for Comments
    A. Non-fluidized Catalytic Cracking Units and Non-Claus Sulfur 
Recovery Units
    B. Potential Emission Sources
    C. Catalytic Cracking Unit Control Device Maintenance
    D. Subcategorization of Catalytic Cracking Units
    E. Catalytic Reforming Unit Depressuring/Purging Cutoff Value
    F. Monitoring of Catalytic Reforming Units with Internal 
Scrubbing Systems
    G. Alternative CCU Standard
    H. Overlap with New Source Performance Standard
    I. Status of Exceedances and Excursions
VII. Administrative Requirements
    A. Docket
    B. Public Hearing
    C. Executive Order 12866
    D. Enhancing the Intergovernmental Partnership Under Executive 
Order 12875
    E. Unfunded Mandates Act
    A. Executive Order 13045
    G. Regulatory Flexibility
    H. Paperwork Reduction Act
    I. Pollution Prevention Act
    J. National Technology Transfer and Advancement Act
    K. Clean Air Act
    L. Executive Order 13084

I. Statutory Authority

    The statutory authority for this proposal is provided by sections 
101, 112, 114, 116, and 301 of the Clean Air Act, as amended (42 U.S.C. 
7401, 7412, 7414, 7416, and 7601).

II. Introduction

A. Background

    Section 112 of the Act lists HAP and directs the EPA to develop 
rules to control all major and some area sources emitting HAP. On July 
16, 1992 (57 FR 31576), the EPA published a list of major and area 
source categories for which NESHAP are to be promulgated. Petroleum 
refineries were listed under two source categories. On December 3, 1993 
(58 FR 83941), the EPA published a schedule for promulgating standards 
for the listed major and area sources. Standards for the first source 
category, ``Other Sources Not Distinctly Listed,'' were scheduled for 
promulgation on November 15, 1994. The EPA promulgated those standards 
under a July 28, 1995, court-ordered deadline; the regulations, 
``National Emission Standards for Hazardous Air Pollutants: Petroleum 
Refineries,'' were published on August 18, 1995 (60 FR 43244). Those 
standards, however, did not address three process unit vents which are 
the subject of today's proposed rulemaking. ``Petroleum Refineries: 
Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, 
and Sulfur Plant Units'' is the second listed source category and the 
published schedule requires the EPA to promulgate standards for this 
source category by November 15, 1997.
    The proposed NESHAP was developed by the EPA in concert with State 
regulators, industry representatives, individual States (California, 
Louisiana, Texas, and Illinois) and associated groups including STAPPA/
ALAPCO (State and Territorial Air Pollution Program Administrators 
Association/Association of Local Air Pollution Control Officials). The 
rule development process included a cooperative effort in identifying 
data needs; collecting additional data; conducting emission testing 
with shared funding from the EPA and the California Air Resources Board 
(CARB); and meeting with representatives of the various stakeholders to 
share technical information.
    Refineries affected by the standards could achieve the proposed 
requirements by upgrading existing emission controls, installing new 
control devices, or implementing source reduction measures, depending 
on site-specific characteristics of the source and the associated 
refinery operation. Alternative compliance options also are included to 
provide operational flexibility and to encourage pollution prevention. 
For example, facilities which hydrotreat to remove metals from the feed 
can meet the alternative nickel (Ni) standard with a less effective 
control device. Similarly, sulfur plants which recover additional 
sulfur with effective tail gas treatment can meet performance levels 
equivalent to facilities with a vapor incinerator.
    The EPA estimates nationwide HAP emissions from the process vents 
on these three unit operations at about 7,270 megagrams per year (Mg/
yr) (8,000 tons per year (tpy)) at current levels of control. Raising 
the control performance of affected petroleum refinery process units 
with MACT-level standards would reduce nationwide HAP emissions from 
process vents on the three affected unit operations by about 82 percent 
from the current level, with higher reductions achieved at particular 
sites. Other benefits of this action would include a significant 
decrease in nationwide emissions of non-HAP pollutants (over 132,000 
tpy) and lowered occupational exposure levels for employees.
    This emission reduction would be achieved with no adverse economic 
effects on the industry or small refineries. The nationwide total 
capital and annualized costs of control equipment are estimated at $173 
million and $43.7 million/yr, respectively. An additional $6.5 million 
in total capital investment with a total annual cost of $9.8 million/yr 
is estimated for monitoring/implementation costs.

B. NESHAP for Source Categories

    Section 112 of the Act requires that the EPA promulgate regulations 
for the control of HAP emissions from both new and existing major 
sources. The regulations must reflect the maximum degree of reduction 
in emissions of HAP that is achievable taking into consideration the 
cost of achieving the emission reduction, any non-air quality health 
and environmental impacts, and energy requirements. This level of 
control is commonly referred to as maximum achievable control 
technology (MACT). For new sources, MACT standards cannot be less 
stringent that the emission control that is achieved in practice by the 
best-controlled similar source. (See CAA section 112(d)(3).) The MACT 
standards for existing sources cannot be less stringent than the 
average emission limitation achieved by the best-performing 12 percent 
of existing sources for categories and subcategories with 30 or more 
sources, or the best-performing 5 sources for categories or 
subcategories with fewer than 30 sources.
    The control of HAP is achieved through the promulgation of either 
technology-based emission standards

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under sections 112(d) and 112(f) or work practice standards under 
112(h) for categories of sources that emit HAP. Emission reductions may 
be accomplished through the application of measures, processes, 
methods, systems, or techniques including, but not limited to: (1) 
Reducing the volume of, or eliminating emissions of, such pollutants 
through process changes, substitution of materials, or other 
modifications; (2) enclosing systems or processes to eliminate 
emissions; (3) collecting, capturing, or treating such pollutants when 
released from a process, stack, storage or fugitive emissions point; 
(4) design, equipment, work practice, or operational standards 
(including requirements for operator training or certification) as 
provided in section (h); or (5) a combination of the above. (See CAA 
section 112(d)(2).)

C. Health Effects of Pollutants

    The Clean Air Act was created in part to protect and enhance the 
quality of the Nation's air resources so as to promote the public 
health and welfare and the productive capacity of its population. (See 
CAA section 101(b)(1).) Section 112(b) of the Act lists HAP believed to 
cause adverse health or environmental effects. Section 112(d) of the 
Act requires that emission standards be promulgated for all categories 
and subcategories of major sources of these HAP and for many smaller 
``area'' sources listed for regulation under section 112(c) in 
accordance with the schedules established under sections 112(c) and 
112(e). Major sources are defined as those that emit or have the 
potential to emit at least 10 tpy of any single HAP or 25 tpy of any 
combination of HAP.
    As previously explained, in the 1990 Amendments to the CAA, 
Congress specified that each standard for major sources must require 
the maximum reduction in emissions of HAP that the EPA determines is 
achievable considering cost, health and environmental impacts, and 
energy impacts. In essence, these MACT standards would ensure that all 
major sources of air toxic emissions achieve the level of control 
already being achieved by the better controlled and lower emitting 
sources in each category. This approach provides assurance to citizens 
that each major source of toxic air pollution will be required to 
effectively control its emissions. At the same time, this approach 
provides a level economic playing field, ensuring that facilities that 
employ cleaner processes and good emissions control are not at an 
economic disadvantage relative to competitors with poorer controls.
    Emission data collected during development of the proposed NESHAP 
show that pollutants that are listed in section 112(b)(1) and are 
emitted from vents on CCU, CRU, and SRU include both inorganic HAP 
(including metal HAP) and organic HAP. Hazardous air pollutants from 
CCU include acetaldehyde, antimony, arsenic compounds, beryllium, 
benzene, 1,3-butadiene, cadmium, chromium, cobalt compounds, 2,3,7,8-
TCDD, formaldehyde, hexane, lead compounds, mercury compounds, 
manganese, nickel compounds, phenol, polycyclic organic matter, 
toluene, and xylene. Catalytic reforming units emit benzene, chlorine, 
organic chlorides, naphthalene, dibenzo furans and 2,3,7,8-TCDD, 
polycyclic organic matter, toluene, xylene, hexane, and hydrogen 
chloride. Sulfur recovery plants release emissions of benzene, toluene, 
carbonyl sulfide, carbon disulfide, and formaldehyde. The majority of 
these pollutants will be reduced by implementation of the proposed 
emission limits. Following is a summary of the potential health and 
environmental effects associated with exposures, at some level, to 
emitted pollutants that would be reduced by the standard.
    Several metals appearing on the section 112(b) list of HAP are 
emitted from CCU, CRU, and SRU at petroleum refineries. The nonvolatile 
metals of greatest concern that would be reduced by the standard are 
antimony, cadmium, chromium, nickel, beryllium, and manganese. These 
metals can cause effects such as mucous membrane irritation (e.g., 
bronchitis, decreased lung capacity), gastrointestinal effects, nervous 
system disorders (from loss of function to tremor and numbness), skin 
irritation, and reproductive and developmental disorders. Additionally, 
several of the metals accumulate in the environment and in the human 
body. Cadmium, for example, is a cumulative pollutant, which can cause 
kidney effects even after the cessation of exposure. Similarly, the 
onset of effects from beryllium exposure may be delayed 3 months to 15 
years. Many of the metals also are known (arsenic, chromium VI, and 
certain nickel compounds) or probable (cadmium, lead, and beryllium) 
human carcinogens.
    Organic compounds that would be reduced by this standard include 
benzene, formaldehyde, and phenol, among others. Some of the effects of 
these pollutants are similar to those caused by metal HAP and include 
irritation from short-term exposures to eye, nose, and throat; 
respiratory effects (expressed as labored breathing, impaired lung 
function); and reproductive and developmental effects. Developmental 
and kidney effects and cardiac effects have been reported for phenol, 
which is considered to be quite toxic to humans via oral exposure. In 
addition to these noncancer effects, formaldehyde has been classified 
as a probable human carcinogen. Benzene, a class A or known human 
carcinogen, is a concern because long-term exposure causes an increased 
risk of cancer in humans, and is also associated with aplastic anemia, 
pancytopenia, chromosomal breakages, and weakening of the bone marrow.
    Emissions of carbonyl sulfide (COS) also would be reduced by the 
standard. Information as to the potential health effects of COS are 
limited. Short-term inhalation of a high concentration of COS may cause 
narcotic central nervous system effects and skin and eye irritation in 
humans. No information is available on reproductive or developmental 
effects from COS exposure, and the EPA has not classified this 
pollutant with respect to its potential carcinogenicity.
    Adverse health effects from exposure to hydrogen chloride (HCl) 
also have been documented. Chronic occupational exposure to HCl has 
been reported to cause gastritis, chronic bronchitis, dermatitis, and 
photosensitization in workers. Acute inhalation exposure many cause 
coughing, hoarseness, inflammation and ulceration of the respiratory 
tract, chest pain, and pulmonary edema in humans. No information is 
available on any potential carcinogenic effects of HCl in humans and 
the EPA has not classified this chemical with respect to potential 
carcinogenicity. Only limited data are available on the reproductive 
and developmental effects of HCl.
    In addition to HAP, the proposed standard also would reduce some of 
the pollutants whose emissions are controlled to meet National Ambient 
Air Quality Standards (NAAQS). These pollutants include particulate 
matter (PM), carbon monoxide (CO), volatile organic compounds (VOC), 
and lead. The effects of PM, CO, ozone (derived, in part, from VOC) and 
lead that would be reduced by this standard are described in the EPA's 
Criteria Documents, which support the NAAQS. Briefly, PM emissions have 
been associated with aggravation of existing respiratory and 
cardiovascular disease and increased risk of premature death. Volatile 
organic compounds (e.g., formaldehyde) are precursors to the formation 
of ozone in the ambient air.

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At elevated levels, ozone has been shown in human laboratory and/or 
community studies to be responsible for the reduction of lung function, 
respiratory symptoms (e.g., cough, chest pain, throat and nose 
irritation), increased hospital admissions for respiratory causes, and 
increased lung inflammation. Animal studies have shown increased 
susceptibility to respiratory infection and lung structure changes. 
Ambient ozone also has been linked to adverse effects on agricultural 
crops and forests. Carbon monoxide enters the blood stream and reduces 
oxygen delivery to the body's organs and tissues. Exposure to CO has 
been associated with reduced time to onset of angina pain, impairment 
of visual perception, work capacity, manual dexterity, learning 
ability, and performance of complex tasks. Depending on the degree of 
exposure, lead can cause subtle effects on behavior and cognition, 
increased blood pressure, reproductive effects, seizures, and even 
death.
    The EPA recognizes that the degree of adverse effects to health can 
range from mild to severe. The extent and degree to which the health 
effects may be experienced is dependent upon: (1) The ambient 
concentrations observed in the area, (e.g., as influenced by emission 
rates, meteorological conditions, and terrain); (2) the frequency of 
and duration of exposures; (3) characteristics of exposed individuals 
(e.g., genetics, age, pre-existing health conditions, and lifestyle) 
which vary significantly with the population; and (4) pollution 
specific characteristics (e.g., toxicity, half-life in the environment, 
bioaccumulation, and persistence).

D. Petroleum Refining Industry

    The petroleum refining industry in 1997 consisted of 162 petroleum 
refineries operated by 90 firms in 33 States nationwide that refined 
approximately 15 million barrels of crude oil daily. Of the total 
number of U.S. refineries, 71 were located in three States (i.e., 
California, Texas, and Louisiana) and accounted for about 54 percent of 
the crude capacity. The three types of process units (CCU, CRU, and 
SRU) classified within the source category regulated in today's 
proposed rule are commonly found at petroleum refineries throughout the 
U.S. The processes are described below.
1. Catalytic Cracking Units
    Catalytic cracking is a decomposition process whereby heavier 
weight, higher boiling hydrocarbons such as gas oil are broken down by 
heat in the presence of a catalyst to lighter weight, lower boiling, 
higher value hydrocarbons such as gasoline blend stocks and heating 
fuels. Technological developments have allowed catalytic cracking units 
to accept a wide range of feedstocks varying from naphtha to heavy 
crude residues. Current cracking catalysts incorporate zeolites 
(molecular sieves) with alumina-silica matrix.
    Fluidized-bed or moving bed reactors are used by 101 petroleum 
refineries for catalytic cracking. The fluidized-bed processes are 
predominant but some moving bed units are still in operation. Non-
fluidized CCU, which account for only 2.9 percent of the total 
catalytic cracking process charge rate, were operated by 7 refineries 
in 1997.
    Fluid catalytic cracking has gained dominance in the catalytic 
cracking industry because these units are typically more versatile and 
flexible than other (non-fluid) CCU, i.e., they have improved control 
of process variables to maximize desired product yields. In January 
1997, catalytic cracking (fluid or other) charge capacity was 5.2 
million barrels per calendar day. Catalytic cracking charge capacities 
of less than 10,000 barrels per calendar day were reported by 9 
refineries. Charge capacities of greater than 100,000 barrels per 
calendar day were reported by 8 refineries. About one-half of the 
refineries with large charge capacities have more than one CCU.
    Several proprietary fluidized-bed catalytic cracking processes are 
available from various engineering construction companies and oil 
refining research and development groups. In addition, each fluidized-
bed CCU operation is customized based on refinery specific process, 
feedstock, and product mix requirements. Catalyst and feedstock are 
introduced to the reactor through a vertical tube leading to the 
reactor, i.e., the riser; the feedstock undergoes a cracking reaction 
(typically in the riser) and some reaction products are deposited on 
the catalyst; as the mixture of catalyst and products enter the reactor 
vessel, steam is injected to strip products from the catalyst. With 
use, the catalyst in an fluidized-bed CCU unit loses activity; coke and 
some metals remain deposited on the catalyst. To restore catalyst 
activity, the used or spent catalyst is routed continuously from the 
reactor to a regenerator vessel; the catalyst activity is restored 
substantially by burning off the coke in a controlled combustion 
reaction; burning the coke also provides process heat necessary for the 
proper functioning of the fluidized-bed CCU. The source of emissions 
from both fluidized-bed units and moving-bed units is the regenerator 
flue gas stream.
    There are two basic types of fluidized-bed CCU regenerators: 
complete burn/combustion regenerators and partial burn/combustion 
regenerators. In partial burn/combustion regenerators, the controlled 
burn involves addition of less than stoichiometric amounts of air, and 
thus CO is generated rather than carbon dioxide (CO2). In 
complete burn/combustion (also called high temperature) regenerators, 
the regenerator is operated with a slight excess of oxygen (1 to 2 
percent) to ensure complete combustion of the coke to CO2; 
newer units are typically designed for complete combustion. The CO 
content of the flue gas from a high temperature, complete burn/
combustion regenerator is about 0.4 percent by weight as compared to 
the uncontrolled CO content of about 9.3 percent from a partial burn/
combustion regenerator system.
2. Catalytic Reforming Units
    A CRU is designed to reform (i.e., change the chemical structure) 
of naphtha into higher octane aromatics. This is accomplished by 
passing naphtha through a reactor containing a catalyst at elevated 
pressure and temperature to promote dehydrogenation, isomerization, and 
hydrogenolysis reactions. The reforming process uses a platinum or 
bimetal (e.g., platinum and rhenium) catalyst material. Halides 
(chlorine and fluorine) promote the activity of the platinum-alumina 
catalyst and are stripped from the surface of the catalyst as HCl or 
hydrogen fluoride (HF) during the reforming reactions, thus reducing 
catalyst activity.
    Dehydrogenation reactions are favored by low pressure and high 
temperature; however, coke (carbon) is also formed at low pressure 
which tends to deactivate the catalyst and reduce yields. Coke 
formation can be reduced by operating under high hydrogen pressure; 
other important variables in dehydrogenation activity include 
temperature, space velocity, recycle gas rate, and particle size of the 
catalyst used. The desired product quality (octane number) may be 
obtained by balancing the system pressure, temperature, space velocity, 
and recycle gas rate even as catalyst activity decreases. When yields 
can no longer be obtained, the catalyst must be regenerated.
    In January 1997, catalytic reforming charge capacity was 3.65 
million barrels per calendar day. Some form of CRU was operated by 124 
refineries. The three major types of catalytic reforming processes are 
semi-regenerative, cyclic, and continuous. Semi-regenerative,

[[Page 48894]]

used by 111 refineries with 49 percent of reforming capacity, is 
characterized by the shutdown of the entire reforming unit (which 
employs three to four separate reactors) at specified intervals or at 
the operator's convenience, for in situ catalyst regeneration. Cyclic 
regeneration, used by 23 refineries with 24 percent of reforming 
capacity, is characterized by batch regeneration of catalyst in situ in 
any one of several reactors (four or five separate reactors) that can 
be isolated from and returned to the reforming operation, while 
maintaining continuous reforming process operations (i.e., feedstock 
continues flowing through the remaining reactors). Continuous 
regeneration, used by 32 refineries with 27 percent of reforming 
capacity, is characterized by continuous flow of catalyst material 
through a reactor where it mixes with feedstock in counter-current 
direction, and a portion of the catalyst is continuously removed and 
sent to a special regenerator where it is regenerated and recycled back 
to the reactor.
3. Sulfur Plant Units
    Sulfur compounds present in crude oil are converted to hydrogen 
sulfide (H2S) in the cracking and hydro treating processes. 
The H2S or ``acid gas'' is removed from the process vapors 
using amine scrubbers. Amine scrubbers also remove CO2, COS, 
carbon disulfide (CS2), nitrogen (N2) and water 
(H2O). The H2S ``rich'' amine solution is 
subsequently heated to release the H2S and other absorbed 
components, which is then treated in the SRU to yield high purity 
elemental sulfur that is sold as product. Sour water [water that 
contains ammonia (NH3) and H2S] gases are also 
commonly fed to the SRU. The NH3 is oxidized to nitrogen 
dioxide (NO2) and H2O, and the H2S is 
converted to elemental sulfur in the SRU.
    Sulfur recovery (the conversion of H2S to elemental 
sulfur) is typically accomplished using the modified-Claus process, 
which consists of a thermal reactor and multi-stage catalytic reactors 
in series. First, one-third of the H2S is burned with air in 
a thermal reactor furnace to yield sulfur dioxide (SO2). The 
SO2 then reacts reversibly with H2S in the 
presence of a catalyst to produce sulfur, water, and heat. Since the 
reaction is reversible, the reaction occurs in a series of catalytic 
reactors (or stages), and the vapors are cooled to condense the sulfur 
between each reactor to drive the reaction towards completion. The 
Claus gas is then reheated prior to introduction to the next catalytic 
reactor (or stage). The conversion efficiencies of SRU range from 92 
percent for a two-stage to 97 percent for a three-stage unit.
    The gas from the final condenser of the SRU (referred to as the 
``tail gas'') typically consists primarily of inert gases with less 
than two percent sulfur compounds, which may include H2S, 
SO2, CS2, and COS. There are numerous Claus tail 
gas desulfurization systems in commercial operation in the U.S. Tail 
gas treatment processes fall mainly into two categories: low-
temperature processes and single compound processes (e.g., 
SCOTTM, BeavonTM, and Wellman-LordTM. 
SCOTTM tail gas treatment includes: Catalytic reduction to 
convert the tail gas sulfur compounds to H2S; amine 
adsorption to recover and recycle any H2S present in the 
tail gas; and incineration to convert the remaining tail gas sulfur 
compounds to SO2. Sulfur recovery efficiencies of catalytic 
reduction followed by amine recovery typically range from 92 to 97 
percent; therefore, the combined efficiency of the SRU and tail gas 
recovery systems can exceed 99.5 percent. After incineration, the 
treated tail gas consists primarily of inert gases with an 
SO2 concentration of between 200 and 500 parts per million 
(ppm) with trace amounts of H2S, COS, and CS2.
    In 1985, production of sulfur from petroleum refineries was 
reported at 2.9 million Mg compared to 4.2 million Mg in 1990. In 1992, 
130 U.S. refineries reported operating some form of SRU with a 
production capacity of approximately 20,500 Mg/day. Capacities of less 
than 50 Mg/day were reported by 52 refineries. Capacities of greater 
than 300 Mg/day were reported by 24 refineries and 5 refineries 
reported capacities of greater than 500 Mg/day. Of the 130 refineries, 
88 provided the number of SRU or Claus trains at the facility. The 
total number of SRU reported was 144; 38 refineries reported multiple 
trains with 13 refineries reporting 3 or more SRU.
    A new source performance standard (NSPS) for petroleum refineries 
(40 CFR part 60, subpart J) limits PM and CO from fluidized-bed CCU 
catalyst regeneration vents, H2S from fuel gas combustion 
devices, and SO2 from SRU vents on Claus plants of greater 
than 20 long tons per day. This rule affects fluidized-bed CCU 
constructed or modified after June 11, 1973, and Claus SRU constructed 
or modified after October 4, 1976. Any fluidized-bed CCU, constructed 
or modified before January 17, 1984, in which a contact material reacts 
with petroleum derivatives to improve feedstock quality and in which 
the contact material is regenerated by burning-off coke and/or other 
deposits is exempt from the NSPS.

III. Summary of the Proposed Rule

A. Applicability

    The proposed standard would apply to emissions of HAP from process 
vents on each affected source at any petroleum refinery that is a major 
source of HAP emissions as defined in Sec. 63.2 of 40 CFR part 63. All 
of the nation's 162 petroleum refineries are believed to be major 
sources of HAP.
    New and existing sources subject to the proposed NESHAP are: (1) 
The process vent or group of process vents on each fluidized-bed and 
other (i.e., non-fluid) CCU that is associated with regeneration of the 
catalyst used in the unit (i.e., the catalyst regeneration flue gas 
vent); (2) the process vent or group of process vents on each semi-
regenerative, cyclic, or continuous CRU that is associated with 
regeneration of the catalyst used in the unit; and (3) the process vent 
or group of process vents that vent from each Claus or other (i.e., 
non-Claus) SRU or the tail gas treatment unit serving the sulfur 
recovery plant, that is associated with sulfur recovery. Processes 
which do not recover elemental sulfur do not meet the definition of a 
SRU, and therefore, are not subject to the proposed standards. Gaseous 
streams routed to a fuel gas system also are not subject to the 
proposed standards.
    The proposed standard would prevent facilities subject to the NSPS 
control requirements for CCU and SRU from having to do a second 
compliance demonstration for the MACT standard. The owner or operator 
of a fluidized-bed CCU catalyst regenerator subject to and 
demonstrating compliance with the NSPS PM and CO standards and all 
associated requirements (e.g., performance test, monitoring, 
recordkeeping, and reporting) is considered to be in compliance with 
the MACT standard and associated requirements for CCU. The owner or 
operator of a Claus SRU subject to and demonstrating compliance with 
the NSPS sulfur oxides standard and associated requirements is 
considered to be in compliance with the MACT standard and associated 
requirements for SRU. Any CCU or SRU not subject to the NSPS that is 
subject to this MACT standard must comply with the requirements of this 
subpart. For example, an existing CCU not subject to the NSPS must 
demonstrate compliance in accordance with the requirements of this 
subpart. This approach is intended to reduce burden by minimizing 
duplication without affecting the NSPS

[[Page 48895]]

requirements and related requirements such as new source review, 
prevention of significant deterioration, and other Title I 
requirements. The EPA requests comments on this regulatory approach or 
other approaches that minimize duplication without reducing or changing 
the NSPS standards.

B. Subcategories

    Section 112(d) of the Act requires the EPA to establish emission 
standards for each category or subcategory of major and area sources. 
Section 112(d)(1) of the Act provides that the Administrator may 
distinguish among classes, types, and sizes of sources within a 
category in establishing the standards. In establishing subcategories, 
the EPA has considered factors such as air pollution control 
engineering differences, process operations (including differences 
between batch and continuous operations), emission characteristics, 
control device applicability, and opportunities for pollution 
prevention.
    The EPA's analysis of existing CRU resulted in the designation of 
two subcategories for the proposed emission standard for HCl during the 
coke burn-off step that are based primarily on differences in the 
process operations, process equipment, and emissions. One subcategory 
is for existing units using the semi-regenerative regeneration process, 
and the other is a separate subcategory for units using either 
continuous or cyclic regeneration. The composition, quantity, and 
frequency of HCl emissions as well as the level of control achieved 
from the semi-regenerative process are quite different from those 
associated with the other processes. In the semi-regenerative process, 
emissions occur at a much lower frequency and duration because the 
regeneration is performed infrequently at specified intervals, which in 
turn affects the short-term emission rate as well as the performance 
and effectiveness of emission control techniques. No separate 
subcategories were developed for the depressurization or purge cycle 
because the emissions and applicable controls are similar for all three 
types of CRU regeneration processes. However, the proposed control 
requirements for CRU do not apply to depressuring and purging 
operations at a differential pressure between the reactor vent and the 
gas transfer system to the control device of less than 1 pound per 
square inch gauge (psig) or if the reactor vent pressure is 1 psig or 
less.
    No subcategories were developed for the CCU catalyst regeneration 
vent or process vents associated with sulfur recovery plants. The MACT 
emission control technologies for these sources were found to be 
generally applicable for all of these units. However, the EPA is 
collecting additional information to evaluate whether additional 
subcategories may be warranted due to process variations and is 
requesting comments on this topic as discussed in section VI.D of this 
document. (Additional discussion of subcategorization for this source 
category is contained in section IV.C.1 of this document.)

C. Emission Control Technology

    No additional control technology options were identified that had 
been demonstrated to be more effective than the MACT floor technologies 
that would achieve significant additional reductions in HAP emissions. 
Consequently, the technologies associated with the MACT floor were also 
determined to represent the MACT technology from this source category.
    The MACT control option for emissions of metal HAP from the CCU 
catalyst regeneration vent during the coke burn-off is the control of 
PM or Ni by a wet scrubber or electrostatic precipitator (ESP), which 
were found to provide equivalent levels of emission control for metal 
HAP. The MACT control option for organic HAP from the regeneration 
vents for CCUs and for CRUs is complete combustion to destroy the 
organic compounds using complete burn/combustion regeneration process 
for the CCU, or venting either type of unit to a boiler, process 
heater, flare, or other combustion device. The MACT emission control 
technology for the coke burn-off during catalytic reforming 
regeneration is the use of a wet scrubber to remove HCl. For sulfur 
recovery plants, the MACT control option for organic HAP, which are 
reduced sulfur compounds (COS and CS2), is oxidation to 
SO2 using a vapor incinerator.

D. Emission Limits

    Analysis of available information and data led the EPA to conclude 
that the MACT level of control for metal HAP from each new, existing, 
and reconstructed CCU is a PM limit for the catalyst regeneration vent 
of 1.0 kilogram (kg) per 1,000 kg (1.0 lb per 1,000 lb) of coke burn-
off, where PM is a surrogate for total metal HAP. The proposed limit is 
in the same format as the NSPS (40 CFR part 60, subpart J)--kg of PM 
per 1,000 kg of coke burn-off. To provide flexibility in compliance and 
to encourage pollution prevention (such as the use of feedstocks with 
lower metal content), an alternative limit of 13,000 milligrams per 
hour (mg/hr) (0.029 lb/hr) of Ni for the catalyst regenerator vent on 
each CCU also is proposed.
    For organic HAP from each new, existing, or reconstructed CCU, the 
MACT control for the catalyst regeneration vent is complete combustion, 
which is characterized as an emission limit of 500 parts per million by 
volume (ppmv) for CO as an indicator of combustion efficiency. This 
also is the NSPS level used to characterize complete combustion of a 
fluidized-bed CCU catalyst regeneration vent stream.
    Proposed standards also were developed for HCl emissions from the 
catalyst regeneration vent on each new, existing, or reconstructed CRU. 
For an existing semi-regenerative unit, uncontrolled HCl emissions 
during coke burn-off and catalyst regeneration must be reduced by at 
least 92 percent or to an outlet concentration of 30 ppmv or less. For 
an existing unit using cyclic or continuous regeneration or a new or 
reconstructed unit using a semi-regenerative, cyclic, or continuous 
process, HCl emissions must be reduced by at least 97 percent or to an 
outlet concentration of 10 ppmv or less.
    Organic emissions from the catalyst regeneration vent on each new, 
existing, or reconstructed CRU must be controlled by combustion. The 
owner or operator may vent emissions to a flare that meets the EPA's 
design and operation requirements, or use a control device to reduce 
uncontrolled emissions by at least 98 percent or to an outlet 
concentration of 20 ppmv or less.
    Emissions of HAP from each new, existing, or reconstructed SRU, 
expressed as total reduced sulfur (TRS) compounds to represent COS and 
CS2, cannot exceed a concentration of 300 ppmv.

E. Emission Monitoring and Compliance Provisions

    The proposed standard requires an initial performance test to 
demonstrate compliance with the emission limits for vents on each CCU, 
CRU, and SRU. The proposed rule allows 150 days following the 
compliance test date to conduct the tests and report the results in the 
notification of compliance status report. The initial performance test 
for a semi-regenerative CRU may be conducted at the first regeneration 
cycle following the compliance date. The initial performance test, and 
all subsequent performance tests, are to be conducted according to the 
provisions in the NESHAP general provisions in 40 CFR part 63, subpart 
A and in the proposed rule.
    For CCU, Methods 5B or 5F (40 CFR part 60, appendix A) are used to

[[Page 48896]]

determine PM emissions, and Method 29 (40 CFR part 60, appendix A) is 
used to determine Ni emissions. The proposed rule includes calculation 
procedures to demonstrate compliance with the proposed PM limit in the 
kg/1,000 kg (lb/1,000 lb) of coke burn-off format and the Ni limit in 
the mg/hr (lb/hr) format.
    The proposed rule requires a performance test by Method 10 (40 CFR 
part 60, appendix A) to demonstrate compliance with the CO limit for 
CCU catalyst regeneration vents. To determine compliance with the 
requirements for 98 percent removal or an outlet concentration of 20 
ppmv for organic emissions from the CCU catalyst regeneration vent, 
either Methods 18 or 25A (40 CFR part 60, appendix A) can be used. The 
proposed rule contains calculation procedures and equations.
    Emissions of HCl from the CRU catalyst regeneration vent are 
measured using Method 26A (40 CFR part 60, appendix A) to establish 
reduction efficiency or outlet concentration. Method 15 (40 CFR part 
60, appendix A) is used to determine the concentration of TRS compounds 
from SRU.
    Performance tests to show 98 percent destruction of organic 
compounds or an outlet concentration of 20 ppmv or less are not 
required when any of three types of control devices are used: (1) A 
boiler or process heater with a design heat input capacity of 44 
megawatts (MW) or greater; (2) a boiler or process heater in which all 
vent streams are introduced into the flame zone; or (3) a flare that 
complies with the requirements for the proper design and operation of 
flares in * 63.11(b) of the NESHAP general provisions. Flares must also 
meet the requirements in 40 CFR 60.11(b), including the standard for 
visible emissions as determined using Method 22 in appendix A to 40 CFR 
part 60.
    The owner or operator of an existing affected source has up to 3 
years from the promulgation date of the final rule to demonstrate 
compliance. The owner or operator may request an additional year 
(resulting in a compliance date up to 4 years following the 
promulgation date of the final rule) under section 112(i)(3)(B) of the 
Act. A new or reconstructed source must demonstrate compliance upon 
startup or by the date of promulgation of this subpart, whichever is 
later.
    The proposed standard requires the owner or operator to establish a 
maximum or minimum value, as appropriate, for the process and control 
device parameters being monitored that ensures the process or control 
device is operating properly so that the emission limit is not 
exceeded. The proposed standard allows the owner or operator to measure 
and record process or operating parameters on a daily average or hourly 
average basis, depending on the type of control device. Daily averages 
would be calculated as the average of all values for a monitored 
parameter recorded during the operating day. The average will cover a 
24-hour period if the operation is continuous or the number of hours of 
operation per day if operation is not continuous. Monitoring data 
recorded during periods of unavoidable monitoring system breakdowns, 
repairs, calibration checks, and zero (low-level) and high-level 
adjustments; startup, shutdowns, and malfunctions; and periods of 
nonoperating of the process unit resulting in cessation of the 
emissions to which the monitoring applies would not be included in 
monitoring averages. As discussed in section VI.C of this document, the 
EPA requests comments on whether the monitoring averages also should 
exclude periods of excess emissions resulting from non-operation of a 
CCU control device during planned routine maintenance approved by the 
applicable permitting authority.
    If a thermal incinerator is used, the proposed standard requires 
the owner or operator to monitor the daily average combustion zone 
temperature. Monitoring of the daily average combustion temperature 
also would be required for any facility using a boiler or process 
heater less than 44 MW design heat input capacity where the vent stream 
is not introduced into the flame zone. For a catalytic incinerator, the 
owner or operator will monitor the daily average upstream temperature 
and temperature difference across the catalyst bed. When a flare is 
used, a device capable of detecting the presence of a pilot flame is 
required, and the owner or operator will be required to record, for 
each 1-hour period, whether the monitor was continuously operating and 
whether the pilot flame was continuously present.
    Where the owner or operator elects to use an ESP to comply with the 
emission limits for CCU, the average hourly voltage and secondary 
current to the control device or the average hourly total power input 
must be monitored. If the owner or operator uses a wet scrubber to 
comply with the requirements for either a CCU or CRU, the parameters to 
be monitored include the average daily pressure drop across the 
scrubber and the daily average flow rates of gas and water to the 
scrubber from which the liquid-to-gas ratio would be calculated.
    For facilities complying with the CO limit of 500 ppmv for 
catalytic cracking regeneration, the owner or operator has a variety of 
monitoring options. If a combustion control device is not used to 
control emissions from a CCU, the average hourly temperature of the 
regeneration process and the oxygen content of the regeneration vent 
gas must be monitored. The owner or operator is not required to further 
monitor the process or control device if he/she demonstrates that CO 
emissions are less than 50 ppmv based on 30 days of continuous 
monitoring. Alternatively, the owner or operator could install and 
operate a CEM in accordance with the requirements of the NESHAP general 
provisions (40 CFR part 63, subpart A), Performance Specification 4A in 
appendix A to 40 CFR part 60, and the quality control requirements in 
40 CFR part 60, appendix F.
    The proposed standard would require monitoring of the daily average 
coke burn-off rate for each fluidized-bed CCU catalyst regeneration 
vent. The owner or operator would calculate and record the burn-off 
rate using the equation in the proposed rule.
    An owner or operator using a vent system that contains a bypass 
line that could divert a vent stream away from the control device would 
be required to install a flow indicator that determines, at least once 
an hour, whether a vent stream flow is present or to secure the bypass 
line valve in a closed position with a car-seal or a lock and key 
configuration. If a flow indicator is used, a visual inspection must be 
conducted at least once every hour to demonstrate that the monitor is 
operating properly and that gas flow or vapor is not present. If a car-
seal or lock-and-key mechanism is used, a visual inspection must be 
conducted at least once a month to ensure that the valve is maintained 
in the closed position and that no gas or vapor are present. For all 
bypass lines, the proposed rule also requires the owner or operator to 
record the times and durations of any period when the vent stream is 
diverted through a bypass line.
    Following the performance test, more than one exceedance or 
excursion during a semi-annual reporting period would be a violation of 
the standard. As discussed in section VI.I of this document, EPA 
requests comment on this proposed provision. An exceedance or excursion 
may include: (1) An operating day when the daily average value of the 
monitored parameter or any period when the average hourly value of the 
monitored parameter, as applicable, falls below the minimum value (or 
exceeds the maximum value) established for the monitored parameter; (2) 
the average hourly CO concentration

[[Page 48897]]

measured by a CEM exceeds 500 ppmv; (3) an operating day when all pilot 
flames of a flare are absent; (4) an operating day when monitoring data 
are available for less than 75 percent of the operating hours (or less 
than 18 values are recorded if an alterative data compression system is 
used). For a control device where more than one parameter is monitored, 
an excursion by more than one parameter would be considered a single 
violation.
    The proposed NESHAP contains provisions that would allow the owner 
or operator to change control device and process parameter values from 
those established, for example, during an initial performance test, by 
conducting additional emission tests to verify and document compliance. 
A new performance test also is required to establish a revised value 
for the monitored parameter if there has been any change to process or 
operating conditions that could result in a change in control system 
performance since the last performance test. The owner or operator also 
may request to monitor other parameters. Provisions are included for 
the use of alternative monitoring systems such as an automated data 
compression system.

F. Notification, Reporting, and Recordkeeping Requirements

    General notification, reporting, and recordkeeping requirements for 
all MACT standards are established in Sec. 63.10(b) of the NESHAP 
general provisions (40 CFR part 63, subpart A). The proposed standard 
incorporates most of these provisions, except that minor changes were 
made to the notification and reporting requirements. Many initial 
notifications are not required or are included in the notification of 
compliance status report to reduce the burden and to streamline the 
reporting requirements. The EPA believes that these provisions will 
provide sufficient information to determine compliance or operating 
problems at the source. At the same time, the provisions are not labor 
intensive, do not require expensive, complex equipment, and are not 
burdensome in terms of recordkeeping.
1. Notifications
    The proposed requirements include one-time initial written 
notifications of applicability for an area source that subsequently 
becomes a major source and for a new or reconstructed source that has 
an initial startup after the effective date and for which an 
application for approval of construction or reconstruction is not 
required. Notifications of intent to construct or reconstruct, the date 
construction or reconstruction commenced, the anticipated startup date, 
and the actual startup date are required for a new or reconstructed 
major source that has an initial startup after the effective date and 
for which an application for approval of construction or reconstruction 
is required. The owner or operator who intends to construct a new 
affected source or reconstruct an affected source subject to the rule, 
or reconstruct an affected source such that it becomes subject to the 
rule also must provide written notification. The application for 
approval of construction or reconstruction may be used to fulfill this 
requirement. This application must be submitted as far in advance of 
startup as practicable, but not later than 90 days prior to startup for 
a newly constructed or reconstructed source that has not started-up 
before the effective date. The proposed NESHAP also requires written 
notification of the expected date for conducting performance tests and 
visible emission observations for flares.
    Within 150 days of the effective date, the owner or operator of an 
existing, new, or reconstructed affected source is required to submit a 
notification of compliance status report to the applicable permitting 
authority. In a State with an approved permit program which has not 
been delegated authority under section 112(l) of the Act, a duplicate 
report must be provided to the applicable Regional Administrator. The 
owner or operator may submit the information in a permit application or 
amendment, in a separate submittal, or in any combination. If the 
information has already been submitted, a separate notification is not 
required. The notification of compliance status report would include 
information on applicability; affected sources; exempted sources; 
control equipment or method of compliance; methods used to determine 
compliance (e.g., performance test results, engineering assessments, 
monitoring parameter values); and monitoring, maintenance, and quality 
assurance/quality control.
    To ensure continued proper operation of the control devices, the 
proposed rule requires the owner or operator to include a maintenance 
program for control devices in the notification of compliance status 
report. Examples of the elements likely to be included in a maintenance 
plan for wet scrubbers are shown below; similar elements would be 
included in the plan for other types of control devices:
    (1) Perform the manufacturer's recommended maintenance at the 
recommended intervals on fresh solvent pumps, recirculating pumps, 
discharge pumps, and other liquid pumps, and exhaust system and 
scrubber fans and motors associated with pumps and fans;
    (2) Clean the scrubber internals and mist eliminators at intervals 
sufficient to prevent buildup of solids or other fouling that degrades 
performance below emission limits or standards;
    (3) Conduct a periodic inspection of each scrubber and: (a) Clean 
or replace any plugged spray nozzles or other liquid delivery devices, 
(b) repair or replace missing, damaged, or misaligned baffles, trays, 
and other internal components, (c) repair or replace droplet eliminator 
elements as needed, (d) repair or replace any heat exchanger elements 
used for temperature control of fluids entering or leaving the 
scrubber, and (e) check damper settings for consistency with the air 
flow level used to maintain compliance and adjust as required;
    (4) Initiate appropriate repair, replacement, or other corrective 
action when detected; and,
    (5) Maintain a record (i.e., checklist), signed by a responsible 
plant official, showing the date of each inspection, any problems 
detected, a description of the repair, replacement, or other action 
taken, and the date of repair or replacement.
    In addition to correcting defects, the owner or operator is 
required to ensure that the equipment is being operated at an 
appropriate level of reliability, i.e., without the need for continual 
or unusually frequent repairs or alterations that require down time. 
Frequent excursions of control device operating parameters would 
indicate that some aspect of the maintenance program or procedures is 
flawed.
2. Periodic Reports
    The proposed NESHAP requires the owner or operator to develop and 
implement a written plan containing specific procedures for operating 
and maintaining the source during periods of startup, shutdown, and 
malfunctions and a program of corrective action for malfunctioning 
process and control systems. Each plan must contain corrective action 
procedures to be followed in the event any periods of excess emissions 
occur, including procedures to determine the cause of the problem, the 
time the exceedance began and ended, and for recording the actions 
taken to correct the cause of the exceedance or deviation. Examples of 
corrective action procedures that might be included in the plan for 
incinerators include: (1) Inspection of burner assemblies and pilot 
sensing devices for proper operation and cleaning; (2) adjusting 
primary and secondary

[[Page 48898]]

chamber combustion air; (3) inspecting dampers, fans, blowers, and 
motors for proper operation; and (4)shutdown procedures.
    Streamlined recordkeeping and reporting requirements also are 
included in the proposed rule. If actions taken during a startup, 
shutdown, or malfunction are consistent with the plan, no reporting 
would be required but a record of the event must be kept. If the 
actions during such an event are not consistent with the plan, the 
report of this occurrence must be made in the next semi-annual startup, 
shutdown, and malfunction report (which may be included in the semi-
annual excess emissions report).
    The owner or operator must submit a semi-annual report within 60 
calendar days after the end of each 6-month period if any period of 
excess emissions occurs during the reporting period. Reports required 
by other regulations may be used in place or as part of the excess 
emissions report if the report(s) contain the required information. A 
report would not be required if no exceedances or excursions occurred 
during the reporting period. The report also would include any request 
for changing selection of the CCU emission standard (e.g., the PM or Ni 
limit) or the applicability of emission standards and requirements for 
CCU or SRU under the NSPS in 40 CFR part 60, subpart J or subpart UUU.
    Permitting regulations in 40 CFR parts 70 and 71 require the owner 
or operator to make annual certifications of compliance. To aid the 
permitting process, the proposed NESHAP establishes conditions that 
must be met for the compliance certification.

3. Recordkeeping

    Records required under the proposed rule are streamlined to include 
the minimal amount of information needed by the EPA to confirm 
compliance. These requirements are described in Sec. 63.1567(e)(4) of 
this proposed rule. The major requirements include:
     All documentation supporting notification of compliance 
status;
     Startup, shutdown, and malfunction plan with supporting 
documentation;
     Monitoring records required by Sec. 63.10(c) of the NESHAP 
general provisions;
     Each period when a monitoring system or device was 
inoperative or malfunctioning;
     All maintenance, corrective action, and quality assurance/
quality control actions and documentation;
     Any changes to a regulated process;
     Hourly or monthly inspections of bypass line valves and 
bypasses;
     Hourly inspections of flare pilot flame; and
     Daily average coke burn-off rate for fluidized-bed CCU 
catalyst regeneration vent with supporting documentation.
    All records must be retained for at least 5 years following the 
date of each occurrence, measurement, maintenance, corrective action, 
report, or record. The records for the most recent 2 years must be 
retained on site; records for the remaining 3 years may be retained off 
site but still must be readily available for review. The files may be 
retained on microfilm, on microfiche, on a computer, or on computer or 
magnetic disks.

IV. Selection of Proposed Standards

A. Selection of Source Category

    Section 112(c) of the Act directs the EPA to list each category of 
major and areas sources as appropriate emitting one or more of the HAP 
listed in section 112(b) of the Act. ``Petroleum Refineries--Catalytic 
Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur 
Plant Units'' is one of the 174 categories of sources included on the 
initial list of source categories (57 FR 31576, July 16, 1992).
    According to the EPA's schedule for rule development for these 
source categories (58 FR 83841, December 3, 1993), MACT standards for 
these petroleum refinery process unit vents must be promulgated no 
later than November 15, 1997. If standards are not promulgated by May 
15, 1999 (18 months following the promulgation deadline), section 
112(j) of the Act requires States or local agencies with approved 
permit programs to issue new or revised permits containing either an 
emission limitation that is equivalent to the limitation that would 
apply if the MACT standard had been promulgated in a timely manner or 
an alternate emission limitation for HAP control.
    Section 112(c)(3) of the Act directs the Agency to list each 
category of area sources that the Agency finds presents a threat of 
adverse effects to human health or the environment warranting 
regulation. Based on information and data collected during development 
of the proposed standard, the EPA estimates that all process units 
within this source category are located at major sources of HAP 
emission (60 FR 43245, August 18, 1995).

B. Selection of Emission Sources and Pollutants

    The petroleum refinery source category, defined in the EPA report, 
``Documentation for Developing the Initial Source Category List,'' 
(Docket Item II-A-1) specifies these three petroleum refinery process 
units as a source category for regulation. Because little or no HAP 
emission data for this source category were available at the beginning 
of this study, the EPA collected information and data through review of 
existing literature. Section 114 questionnaires were sent to nine 
corporations (representing 27 refineries) and information collection 
requests (ICRs) were sent to the remainder of existing U.S. refineries 
to obtain information and data on refineries during development of the 
initial MACT rule for petroleum refineries (60 FR 43244, August 18, 
1995). Site surveys were conducted by the EPA at 20 petroleum 
refineries as part of the refinery process vent rule development. Also, 
as part of the information and data collection process, a series of 
meetings were held with State representatives and industry trade 
associations (i.e., the American Petroleum Institute (API) and the 
National Petroleum Refiners Association (NPRA)) to first inform the 
industry of the EPA's intentions to develop a MACT for this source 
category and also to solicit their input. As a result, the trade 
associations conducted surveys of their member companies to collect 
additional information and data relative to the three process unit 
operations which would be regulated by today's proposed rule. Based on 
this information and data, and for the reasons described below, the EPA 
is regulating these three vents as emission sources under the proposed 
rule.

C. Selection of Proposed Standards for Existing and New Sources

1. Background
    After the EPA has identified the specific source category or 
subcategories of major sources for regulation under section 112, MACT 
standards must be established for each category or subcategory. Section 
112 of the Act sets a minimum level or floor for the standards. For new 
sources, standards for a source category or subcategory cannot be less 
stringent than the emission control that is achieved in practice by the 
best-controlled similar source. (See CAA section 112(d)(3).) The 
standards for existing sources can be less stringent than the standards 
for new sources, but they cannot be less stringent than the average 
emission limitation achieved by the best-performing 12 percent of 
existing sources for categories or subcategories with 30 or more total 
sources, or the

[[Page 48899]]

best performing 5 sources for categories or subcategories with fewer 
than 30 sources. These minimum requirements for the MACT emission 
limitation(s) for new and existing sources are termed the ``MACT 
floor.''
    After the floor has been determined for a new or existing source in 
a source category or subcategory, the Administrator must set MACT 
standards that are technically achievable and no less stringent than 
the floor. Such standards must be met by all sources within the 
category or subcategory. In establishing the standards, the EPA may 
distinguish among classes, types, and sizes of sources within a 
category or subcategory. (See CAA section 112(d)(1).)
    The next step in establishing MACT standards is traditionally the 
investigation of regulatory alternatives. With MACT standards, only 
alternatives at least as stringent as the floor may be selected. 
Information about the industry is analyzed to develop model plants for 
projecting national impacts, including HAP emission reduction levels 
and cost, energy, and secondary impacts. Regulatory alternatives, which 
may be different levels of emissions control equal to or more stringent 
than the floor levels, are then evaluated to select the regulatory 
alternative that best reflects the appropriate MACT level. The selected 
alternative may be more stringent than the MACT floor, but the control 
level selected must be technically achievable. The regulatory 
alternatives and emission limits selected for new and existing sources 
may be different because of different MACT floors.
    When the EPA considers an alternative which is beyond-the-floor, 
the EPA examines the achievable emission reductions of HAP (and 
possibly other pollutants that are co-controlled), cost and economic 
impacts, energy impacts, and other non-air environmental impacts. The 
objective is to achieve the maximum degree of emissions reduction 
without unreasonable economic or other impacts. (See CAA section 
112(d)(2).)
    Under the Act, subcategorization within a source category may be 
considered when there is enough evidence to demonstrate clearly that 
there are significant differences among the subcategories. The criteria 
to consider include process operations (including differences between 
batch and continuous operations), emission characteristics, control 
device applicability, safety, and opportunities for pollution 
prevention.
    The EPA examined the three process unit operations, the operating 
characteristics of these units, and other relevant factors to determine 
if separate classes of units, operations, or other criteria have an 
affect on air emissions from any of the three process unit operations 
in this source category. For SRU, no basis was established to 
subcategorize or develop separate standards within these unit 
operations. For CCU, the EPA requests additional information and data 
needed to address the potential need for subcategorization due to 
process variations (e.g., the differences between fluidized-bed and 
non-fluidized bed CCU). However, for CRU, an analysis of the 
information and data in the EPA refinery database indicated significant 
differences in both the operating processes and emission controls 
associated with semi-regenerative CRU during the catalyst regeneration 
coke burn-off step. Therefore, the EPA established a subcategory for 
semi-regenerative CRU based on the operating differences and control 
device performance during the coke burn-off step; a separate 
performance standard was established for this subcategory. Cyclic and 
continuous CRU were grouped together and have a different performance 
standard for the coke burn-off step. Subcategorization of semi-
regenerative CRU is further discussed in sections III.B and IV.C.2.b of 
this document.
2. MACT Floor Technology and Emission Limits
    In establishing the MACT floor for existing sources, sections 
112(d)(3) (A) and (B) of the Act directs the EPA to set standards that 
are no less stringent than the ``average'' emission limitation achieved 
by the best performing 12 percent (for which there are emissions data) 
where there are more than 30 sources in the category or subcategory or 
the best performing five sources (for which there are emissions data) 
where there are fewer than 30 sources. Among the possible meanings for 
the word ``average'' as the term is used in the Act, the EPA considered 
two of the most common.
    First, ``average'' could be interpreted as the arithmetic mean. The 
arithmetic mean of a set of measurements is the sum of the measurements 
divided by the number of measurements in the set. The EPA has 
determined that the arithmetic mean of the emission limitations 
achieved by the best performing 12 percent of existing sources (or best 
five sources where there are fewer than 30 sources) in some cases would 
yield an emission limitation that fails to correspond to the emission 
limitation achieved by any particular technology. In such cases, the 
EPA would not select this approach. The word ``average'' could also be 
interpreted as the median emission limitation value. The median is the 
value in a set of measurements below and above which there are an equal 
number of values (when the measurements are arranged in order of 
magnitude). This approach identifies the emission limitation achieved 
by those sources within the top 12 percent (or top five where there are 
fewer than 30 sources), arranges those emissions limitations in order 
of magnitude, and the control level achieved by the median source is 
selected. Either of these two approaches could be used in developing 
standards for different source categories.
    A ``technology'' approach also was used in developing these 
proposed standards. For each source type, the control technologies were 
ranked in the database by performance and the median technology 
represented by the best-controlled sources was selected as the MACT 
floor. Sources having control technology representative of the MACT 
floor were then evaluated and analyzed in order to determine an 
appropriate emission limitation to characterize performance of the MACT 
floor technology.
    As previously noted, data related to operating procedures and 
emissions for the three process unit operations were obtained through a 
combination of literature sources, site visits, ICR, discussions with 
industry and State Agency representatives, and information surveys 
conducted by industry trade associations. These data were then compiled 
into a comprehensive database that was used for the floor analysis.
    a. MACT floor for catalytic cracking units. Catalytic cracking 
(fluid and other) units emit a variety of HAP during catalyst 
regeneration; these HAP can be broadly categorized into two groups: 
metallic HAP (e.g., antimony, beryllium, mercury, and nickel) and 
organic HAP (e.g., benzene, formaldehyde, hexane, and xylene). While 
not exclusively so, the metallic HAP emitted from CCU catalyst 
regeneration vents are primarily emitted as PM. Mercury is the one 
metallic HAP that is expected to be emitted in both solid and gaseous 
forms. The organic HAP emitted from CCU catalyst regeneration vents are 
in the vapor phase. These two HAP emission forms require significantly 
different control technologies.
    The EPA database for CCU contains a considerable amount of 
information on control device types as well as process information, but 
very limited information on vent stream composition

[[Page 48900]]

or HAP concentration for either the metallic HAP or the organic HAP. 
The amount of constituent data currently available is not adequate to 
establish a MACT floor for each individual HAP; the limited data on 
individual HAP cannot be considered representative of the entire 
industry in all but a few cases. Therefore, the floor for CCU (both 
fluidized bed and non-fluidized bed) catalyst regeneration vent HAP 
emissions is being established for the broad classes of HAP that are 
grouped as either metallic HAP or organic HAP.
    The EPA is aware that there are significant process differences 
between the fluidized-bed and non-fluidized bed CCU. These process 
differences include such things as catalyst size and composition, as 
well as reactor operation (e.g., plug downflow versus fluidized riser 
processes). At this time, the EPA does not have adequate data to 
characterize the HAP emissions from the non-fluidized CCU, but 
preliminary data currently available indicate, based on the EPA's 
current understanding, that these units are likely operating at 
emission levels that meet the MACT floor criteria. However, the EPA is 
gathering additional information and data on these processes and, based 
on the new information, will reexamine the possible need to set a 
separate standard for these few non-fluidized CCU.
    (1) Organic HAP MACT floor.
    (a) Existing catalytic cracking units. Available emission data have 
been reviewed to identify the best performing 12 percent of existing 
sources. The available emissions data that relate to organic HAP 
control performance are presented in the database in terms of VOC, THC, 
and CO with only minimal data on individual HAP constituents. The 
performance level formats available in the database that relate to 
organic HAP are an emission rate normalized to coke burn, an emission 
rate expressed in terms of an exit concentration, and a performance 
level expressed as a percent reduction achieved. The amount of 
individual constituent data currently available is not adequate to 
establish a MACT floor for each individual organic HAP; the limited 
data on individual organic HAP cannot be considered representative of 
the entire industry. Therefore, emissions data on VOC, THC, and CO were 
reviewed since these data are indicative of emissions of individual 
organic HAP.
    The CCU catalyst regeneration step that generates the affected gas 
stream involves an initial combustion operation, and the catalyst 
regeneration step can be conducted either as a partial combustion 
operation or a complete combustion operation. A complete burn/
combustion CCU has a catalyst regeneration coke burn stage designed and 
operated with a residence time, temperature, and excess oxygen level to 
achieve complete oxidation of the coke or carbon to CO2; a 
partial burn/combustion CCU has a catalyst regeneration coke burn stage 
designed and operated with less than stoichiometric oxygen, which 
results in incomplete combustion of the carbon and is characterized by 
high levels of CO.
    The emission data for CCU catalyst regeneration vents indicate 
that: (1) Complete burn/combustion CCU and (2) partial burn/combustion 
CCU that are followed by a CO boiler or other combustion device achieve 
similar organic emission rates. Both of these configurations achieve 
complete combustion of the CCU catalyst regeneration vent gases and 
demonstrate similar emissions rates and as a result, both are 
considered types of ``complete combustion.'' These complete combustion 
units have significantly less organic HAP emissions than partial burn/
combustion CCU that are not followed by an additional combustion 
device.
    The petroleum refinery NSPS (40 CFR part 60, subpart J) is a 
regulation that requires catalyst regeneration vent gases from new or 
reconstructed fluidized-bed CCU to have complete combustion by limiting 
the CO concentration to less than or equal to 500 ppmv (dry). 
Information gathered by the EPA indicates that more than 12 percent of 
the existing CCU are currently subject to the petroleum refinery NSPS. 
The NSPS thus represents the average emission limitation achieved, in 
terms of a regulatory requirement, by the best performing 12 percent of 
existing sources. Therefore, a complete burn/combustion CCU or partial 
burn/combustion CCU followed by a CO boiler or other combustion device 
that reduces the CO concentration in the catalyst regeneration vent gas 
to 500 ppmv or less is deemed to be meeting the MACT floor for existing 
CCU.
    (b) New catalytic cracking units. Based on the information and data 
available, the EPA concluded that the MACT floor determination for 
existing CCU sources of organic HAP (i.e., complete combustion of the 
vent gases) also represents the HAP emission control that is achieved 
in practice by the best-controlled similar source in the source 
category. Therefore, the MACT floor for new sources is the same as that 
for existing sources for organic HAP. This fact also leads to the 
conclusion that there is no technology that has been demonstrated in 
this industry to provide a level of control more stringent than the 
MACT floor for organic HAP.
    (2) Metallic (or inorganic) HAP MACT floor.
    (a) Existing catalytic cracking units. Along with low emissions, 
the best-performing existing sources are expected to have the best-
performing control technologies; for metallic HAP that would involve 
either a modern ESP or a venturi scrubber. Available data shows these 
two devices, used by approximately 45 percent of the industry, provide 
similar control of PM and metallic HAP. However, some refineries with 
CCU controlled only by tertiary cyclones, control devices typically 
considered less effective, have told the EPA that their emissions are 
equivalent to those achieved by the more efficient control devices. 
This is in large part a function of the site-specific characteristics 
of the unit (e.g., a low Ni feed) Therefore, rather than set an 
equipment standard based on a control device, the EPA prefers to 
establish a performance standard associated with the best performing 
control technology.
    The petroleum refinery NSPS (40 CFR part 60, subpart J) is a 
performance standard that requires new or reconstructed fluidized-bed 
CCU to reduce PM emissions from the catalyst regeneration vent to 1 kg/
1,000 kg (1 lb/1,000 lb) of coke burn-off. As previously noted, the 
information gathered by the EPA and contained in the petroleum refinery 
database indicates that more that 12 percent of the existing CCU are 
currently subject to the petroleum refinery NSPS. The EPA reviewed this 
emission standard to determine its appropriateness as a performance 
standard to characterize the best-performing control technology for CCU 
metallic HAP emissions. The EPA concluded that for a variety of 
reasons, PM is considered a reasonable surrogate for total metallic HAP 
(excluding mercury):
    (1) The metallic HAP emitted from CCU catalyst regenerator vents 
are primarily emitted as PM;
    (2) In the EPA report, ``Study of Hazardous Air Pollutant Emissions 
from Electric Utility Steam Generating Units--Final Report'' (Docket 
Item II-A-6), it was determined that for those combustion operation 
vent gases ``the HAP metals that exist primarily in particulate form 
are readily controlled by PM control devices''; and
    (3) There is a considerable amount of emission data available for 
PM emitted from CCU catalyst regeneration vents.
    The performance level formats available in the data base for PM are 
an emission rate normalized to coke burn, an emission rate expressed in 
terms of

[[Page 48901]]

an exit concentration, and a performance level expressed as a percent 
reduction achieved. The EPA refinery database shows that CCU ESP 
achieve a PM emission rate that ranges from 0.0002 to 3.6 lb/1,000 lb 
coke; the 26 values reported have a median of 0.81 and a mean of 0.86 
lb/1,000 lb. The NSPS value is 1.0. Nineteen of the 26 CCU have a 
catalyst regeneration PM emission rate of less than 1 lb/1,000 lb of 
coke burn-off. The five CCU that use a venturi scrubber and that have 
PM data show a range of emissions from 0.36 to 0.86 lb/1,000 lb of coke 
burn-off, which is within the range of performance shown by the ESP. 
Thus, the NSPS PM emission limit for the catalyst regeneration vent of 
1 lb/1,000 lb of coke burn-off appears to a reasonable characterization 
of PM control device performance on a ``not-to-be-exceeded'' basis, 
based on the available data. As a result of this analysis, a PM 
emission limit of 1 lb/1,000 lb of coke burn-off is selected to 
characterize the MACT floor for catalyst regeneration vents on existing 
units.
    In addition to characterizing the MACT floor performance in terms 
of a PM emission limit, it is possible to determine an alternative MACT 
floor technology emission limit in terms of the entire metal HAP 
population or an individual metal HAP (i.e., Ni) within that 
population. The reason for determining a MACT floor emission limit as 
an alternative to the PM level but formatted in a terms of total metal 
HAP or an individual metal HAP is to provide for increased operational 
flexibility and to allow opportunities for pollution prevention when 
complying with a MACT standard for this source category.
    In developing a MACT floor emission level formatted in terms of the 
population of metal HAP emitted by CCU, the approach used involved 
analysis of the available metal HAP data. This is most readily done 
using Ni as a surrogate for total metal HAP. Nickel emissions data were 
used for this comparative analysis because of the relative abundance of 
measured Ni emissions data and the paucity of emissions data available 
for other metal HAP. Nickel emissions data (formatted in terms of mass 
per unit time) for catalyst regeneration vents are available for 23 
CCUs. The available measured Ni emissions data from CCU catalyst 
regeneration vents in the EPA refinery database were examined and 
compared to determine the representativeness of these data.
    In examining the database, EPA determined that the Ni emission data 
currently available for CCU catalyst regeneration vents is 
representative of the best-performing units in the industry. The EPA 
based this conclusion on the following considerations. A primary factor 
that influences the Ni emissions from the CCU catalyst regeneration 
vent is the Ni content in the CCU feed. The Ni emission rates in the 
refinery database are for the most part from units with low Ni feed. 
There are 72 CCU that reported the Ni content in their CCU feed. Of 
these 72 CCU, 43 (or 60 percent) of the units had Ni feed 
concentrations of 1 ppmw or lower. However, 12 of 14 CCU (or 86 percent 
of the CCU) that reported both Ni emissions data and Ni feed content, 
had Ni feed concentrations of 1 ppmw or lower. In addition, the 
database reflects Ni emission rates of refineries that hydrotreat the 
CCU feed. Hydrotreating the CCU feed tends to lower the CCU feed Ni 
content. There are 98 CCU that reported the use or non-use of 
hydrotreating. Of these 98 CCU, 56 (or 57 percent) of the units 
hydrotreat. However, 13 of 17 CCU (or 76 percent of the CCU) that 
reported both Ni emissions data and hydrotreating information, 
hydrotreat their CCU feed.
    A second factor that influences the Ni emissions from the CCU 
catalyst regeneration vent is the level of PM control on the unit. The 
EPA refinery database is comprised of units that are subject to 
stringent regulatory requirements that result in control of Ni 
emissions. For example, from the data collected by API and provided to 
the EPA as a part of the database, it appears that at least 36 percent 
of the CCU that reported Ni emissions data are subject to the NSPS, 
whereas the EPA estimates that there are approximately 17 percent of 
the CCU in the entire industry subject to the NSPS. In addition, 
approximately 41 percent of the Ni emissions data are from CCU at 
California refineries, where the State regulations on PM control are 
basically the same as the NSPS PM emission control requirements, 
whereas California refineries operate only about 10 percent of the 
total number of CCU in the U.S. Also, approximately 81 percent of the 
CCU in the database that reported Ni emissions data operate either an 
ESP or venturi wet scrubber on the CCU catalyst regeneration vent, 
whereas only 63 percent of the CCU nationwide operate either an ESP or 
venturi wet scrubber on the CCU catalyst regeneration vent.
    For the reasons discussed above, the EPA considers the available Ni 
emissions data to be representative of the best-performing CCU sources, 
rather than the industry as a whole. Examination of the emission data 
shows an emission rate for the top 12 percent to be 0.055 tpy. In 
conjunction with this, the available Ni source test data were analyzed 
to determine the variability of individual source test runs for a given 
CCU source test. Based on analysis of the relative standard deviation 
of the individual CCU source test data, the standard deviation for a 
unit with emissions of 0.055 tpy is 0.042. Using the upper 95th 
percentile of a normal distribution (i.e., a z-statistic equal to 
1.645), the Ni emission limit determined to reflect the best performing 
12 percent of existing sources is a Ni emission limit on a not-to-be-
exceeded basis of 0.125 tpy (250 lb/yr) or 0.029 lb/hr (i.e., the mean 
+ 1.645 standard deviations). Therefore, a metal HAP MACT floor 
emission limit of 13,000 mg/hr or 0.029 lb/hr of Ni also has been 
determined to characterize the performance of the MACT floor control 
technology for existing CCU catalyst regeneration vents.
    (b) New catalytic cracking units. Based on the information and data 
available, the EPA concluded that the MACT floor determination for 
existing CCU sources of metallic HAP (i.e., use of a PM control device 
such as an ESP or venturi scrubber) also represents the HAP emission 
control that is achieved in practice by the best-controlled similar 
source in the source category. Therefore, the MACT floor for new 
sources is the same as that for existing sources for metallic HAP. This 
fact also leads to the conclusion that there is no technology that has 
been demonstrated in this industry to provide a level of control more 
stringent than the MACT floor for metallic HAP.
    (3) Mercury MACT floor. Mercury (Hg) is not well controlled by PM 
air pollution control devices (ESPs as well as PM scrubbers). This 
situation would be expected because Hg is likely emitted in both a 
solid and gaseous or vapor-phase (elemental) form; the fact that 
``conventional (PM) controls are generally inconsistent in their 
effectiveness'' with regard to Hg removal is documented in the EPA 
report, ``Study of Hazardous Air Pollutant Emissions from Electric 
Utility Steam Generating Units--Final Report''. (See Docket Item II-A-
6.) Combustion devices for control of organic vapor would also provide 
no control for Hg. There are a number of emerging technologies (such as 
activated carbon injection) but none have been show to be applicable to 
CCU catalyst regeneration vents. Therefore, the MACT floor for Hg is 
determined to be no control for both new and existing units.

[[Page 48902]]

    b. MACT floor for catalytic reforming units. Developing a MACT 
floor for CRU catalyst regeneration vents is complicated by the fact 
that there are three types of CRU (continuous, cyclic; and semi-
regenerative), and there are different steps (times and locations) 
during which vent emissions may occur during CRU catalyst regeneration: 
(1) Initial depressurization/purge; (2) coke burn-off; (3) catalyst 
rejuvenation; and (4) final purge. The depressurization/purge vent gas 
contains primarily hydrocarbons from the CRU feedstock that remain on 
the reforming catalyst feed (e.g., benzene, toluene, hexane, and 
ethylbenzene). The predominant HAP emitted during coke burn-off are HCl 
and Cl2. Chlorinated organic compounds used for catalyst 
rejuvenation (e.g., trichloromethane and perchloromethane) as well as 
residual HCl on the reforming catalyst may be emitted during catalyst 
rejuvenation and final purge.
    The EPA database for CRU contains a considerable amount of 
information on control device types as well as process information for 
177 CRU, but very limited information on vent stream composition or HAP 
concentration. There are some data available to characterize HCl 
emissions during coke burn-off; however, the limited data on HCl 
emissions cannot be considered representative of the entire industry as 
most HCl emissions data are from continuous or cyclic units. The 
available data on HAP emissions from CRU catalyst regeneration vents is 
inadequate to characterize the emission reductions achieved by the top-
performing 12 percent of the units during the depressurization/purge, 
catalyst rejuvenation, and final purge cycles. Therefore, the MACT 
floor for CRU catalyst regeneration vent HAP emissions is established 
for each potential CRU vent based on current industry practices rather 
than HAP specific emissions data.
    (1) MACT floor determination for existing CRU catalyst regeneration 
vents.
    (a) MACT floor for CRU depressurization/purge vent. Given the 
limitations of the available data, the MACT floor determination for the 
CRU depressurization/purge vent is based on current practices in use 
and control equipment in place at CRU. Flares, process heaters or other 
combustion devices are used for 21 of the CRU catalyst regeneration 
vents. Based on current information in the EPA database, it is 
difficult to discern whether these control devices are used 
specifically for the depressurization/purge vent. However, all of the 
20 refineries visited by either the EPA or CARB during information 
collection site visits to support the development of this rule vented 
the depressurization/purge gases to either the refinery fuel gas system 
or to a flare. Therefore, based on operational practices for over 12 
percent of the CRU (and 100 percent of the units for which the EPA has 
firsthand information), the MACT floor for emissions vented during the 
depressurization/purge cycle is venting to a combustion device.
    In the first petroleum refinery MACT rule (60 FR 43244, August 18, 
1995), the EPA assigned a performance value for combustion units 
serving miscellaneous process vents. In that floor analysis, it was 
assumed that the various combustors were all well designed and operated 
and would achieve 98 percent destruction of total VOC (and HAP). (See 
Docket A-93-48, Docket Item IV-B-12.) This same performance level is 
therefore assumed for combustion devices that are used on CRU catalyst 
regeneration vents. Therefore, the MACT floor for emissions vented 
during the depressurization/ purge cycle is venting to a combustion 
device that achieves a 98 percent destruction efficiency or reduces the 
total organic HAP or the TOC concentration to below 20 ppmv.
    The 20 ppmv concentration format is included as an alternative in 
the proposed standard because the rule could apply to dilute process 
vent streams and the proposed standard for combustion devices is 
formatted in terms of a weight-percent reduction. The EPA believes the 
proposed standard for combustion devices needs to include the volume 
concentration alternative to account for the technological limitations 
of enclosed combustion devices treating dilute streams. (See 48 FR 
48933, October 21, 1983.) Below a critical concentration level, the 
maximum achievable efficiency for enclosed combustion devices decreases 
as inlet concentration decreases. Consequently, for streams with low 
organic vapor concentrations, the 98-percent mass reduction may not be 
technologically achievable in all cases. Available data show that 20 
ppmv is the lowest outlet concentration of total organic compounds 
achievable with control device inlet streams below approximately 2,000 
ppmv total organics. Therefore, the concentration limit of 20 ppmv has 
been added as an alternative standard for incinerators, process 
heaters, and boilers to allow for the drop in achievable destruction 
efficiency with decreasing inlet organics concentration.
    (b) MACT floor for CRU catalyst regeneration coke burn-off vent. 
The EPA examined the available HCl emissions data for catalyst 
regeneration vents on 22 CRU that reported HCl emissions during the 
coke burn-off cycle, along with the type of CRU and the control device 
used; 17 of these units operate with no emission controls (or unknown 
emission controls). With the limited data available, it is not possible 
to characterize these emissions data as either representative of the 
industry as a whole or representative of the top-performing CRU. For 
example, only 3 (or 14 percent) of the 22 units that reported HCl 
emissions are semi-regenerative CRU, while semi-regenerative CRU 
represent 61 percent of all CRU. It appears that due to the limited 
frequency and duration of the emissions from catalyst regeneration 
vents on semi-regenerative units, few emission source tests have been 
performed at semi-regenerative CRU. Therefore, a MACT floor 
determination cannot be based on the available HCl emissions data for 
the coke burn-off cycle. However, a determination based on control 
technology can be made.
    From a review of the process equipment data, two classes of 
scrubbers were designated to characterize the general classes or groups 
of scrubbers being used to control emissions from CRU catalyst 
regeneration vents during the coke burn-off step: single theoretical 
stage scrubbers and multiple theoretical stage scrubbers. The single 
theoretical stage scrubber classification was used to reflect the 
following CRU scrubbing systems, most of which are considered internal 
to the process: Caustic injection, spray circulating solution, 
hydrocyclone, and once through spray scrubbers. Multiple theoretical 
stage scrubbers which are, for the most part, external to the process 
include: Packed tower, packed column, plate and spray, venturi, and 
otherwise unspecified absorbers or scrubbers. Although there are 
inadequate CRU emissions data to differentiate the removal efficiency 
between single stage scrubbers and multiple stage scrubbers, 
theoretical considerations suggest that multiple stage scrubbers will 
have a higher HCl removal efficiency than a single stage scrubber.
    A summary of the numbers of each type of control device (single or 
multiple stage) for catalyst regeneration vents on each type of CRU 
(continuous, cyclic, or semi-regenerative) shows that for continuous 
CRU, 28 percent use multiple stage scrubbers while only 6 percent use 
single stage; for cyclic CRU, 36 percent use multiple stage while only

[[Page 48903]]

11 percent use single scrubbers; and for semi-regenerative CRU, only 3 
percent use multiple while 72 percent use a single stage scrubber. 
Based on these data, the MACT floor for catalyst regeneration vents on 
continuous and cyclic CRU is the use of a multiple stage scrubber 
during the coke burn-off process. The MACT floor for catalyst 
regeneration vents on semi-regenerative CRU is the use of a single 
stage scrubber during the coke burn-off process. Subcategorizing semi-
regenerative CRU is justified based on the operational differences of 
semi-regenerative units (i.e., primarily annual hours the system is 
regenerating). Based on the similarities of the types of controls used 
for catalyst regeneration vents on cyclic and continuous CRU and the 
annual operating hours in which regeneration occurs, it appear 
reasonable that cyclic and continuous CRU be grouped together.
    The performance of CRU scrubbers can be characterized based on 
industry surveys and source test data on HCl scrubbers used in another 
industry--the steel pickling industry. Data from that industry contains 
a range of flow rates and HCl concentrations which span the flow rates 
and HCl concentrations expected for the CRU catalyst regeneration coke 
burn-off vent. The characteristics of the single and multiple stage 
scrubbers that constitute existing source and new source levels of 
control were determined in terms of both HCl reduction efficiency and 
maximum outlet concentration by evaluating the results of emissions 
tests conducted on units currently employed in the steel pickling 
industry. The data from these tests are presented and discussed in 
detail in the preamble to the proposed rule (62 FR 49052, September 18, 
1997) and in the background information document for the proposed 
standard. (See Docket Items II-A-4.) While wet scrubber control devices 
are normally designed for a target emission reduction efficiency, the 
EPA is aware that high reduction efficiencies for process gases that 
contain low concentrations of HCl or HCl in aerosol or droplet form may 
not always be achievable. The EPA therefore has characterized scrubber 
performance in terms of a maximum exhaust gas concentration as well as 
reduction efficiency in recognition of the limitations of the 
technology.
    Based on the median performance of the multiple stage type 
scrubbers tested, the EPA selected an HCl scrubber removal efficiency 
of 97 percent or an outlet concentration of 10 ppmv or less to 
characterize the performance of a multiple stage HCl scrubber. That is, 
the EPA considers that a well-operated and well-maintained scrubber, 
i.e., those considered to be the MACT floor for catalyst regeneration 
vents on continuous and cyclic CRU, can achieve a 97 percent removal 
efficiency or reduce the outlet concentration to 10 ppmv or less. 
Therefore, the MACT floor for the coke burn-off vent for continuous and 
cyclic CRU is to operate a scrubber that achieves 97 percent or greater 
removal of HCl or achieves an outlet concentration of 10 ppmv or less.
    As previously noted, there are few data to support the selection of 
emission limits or HCl control efficiency values for the MACT floor for 
catalyst regeneration vents on semi-regenerative CRU (i.e., single 
stage scrubbers). Examination of performance data of scrubbers used 
outside the source category shows that the lowest control efficiency of 
HCl scrubbers tested by the EPA in the steel pickling industry was 
approximately about 92 percent. (See Docket Item II-A-4.) Based on 
these available data and theoretical engineering design considerations 
of the various HCl single stage scrubber types, a single stage HCl 
scrubber can reasonably be expected to achieve a 92 percent HCl removal 
efficiency on an industry-wide basis for semi-regenerative CRU catalyst 
regeneration coke burn-off vents. This is equivalent to an outlet 
concentration limit of 30 ppmv, based on the 92 percent HCl removal 
efficiency. Therefore, the MACT floor for the catalyst regeneration 
coke burn-off vent for semi-regenerative CRU is to operate a scrubber 
that achieves 92 percent or greater removal of HCl or achieves an 
outlet concentration of 30 ppmv or less.
    (c) MACT floor for CRU catalyst regeneration rejuvenation vent. As 
noted previously, there are very few data available to characterize 
emissions from the CRU catalyst regeneration rejuvenation/final purge 
vent. Additionally, from information gathered during site visits to 
petroleum refineries, there appear to be differences in how/when the 
rejuvenation process occurs. Some units dose the chlorination agent 
into the CRU reactors during the coke burn-off cycle (``coincidental 
rejuvenation''). In this instance, the rejuvenation and coke burn-off 
vent coincide, and the MACT floor for coke burn-off vents previously 
described would apply. Other units circulate the chloriding agent 
through the reactor(s) upon completion of the coke burn-off cycle 
(``sequential rejuvenation''). In this instance, the system is a closed 
recirculation loop with no atmospheric venting. If venting does occur 
during sequential rejuvenation, then the MACT floor is venting to an 
HCl scrubber with the same efficiencies specified for the coke burn-off 
vent. The EPA requests specific comments regarding the prevalence, 
operations, and controls typically associated with this vent.
    (d) MACT floor for CRU catalyst regeneration final purge vent. Upon 
completion of the rejuvenation/coke burn-off cycles, the CRU system is 
purged to remove oxygen from the system and to create a reducing 
atmosphere prior to bringing the unit or reactor back on-line for 
reforming (or returning the catalyst to the reforming reactor in the 
case of continuous units). This final purge vent may be scrubbed, 
released to the atmosphere, vented to the refineries fuel gas system, 
or vented to a flare or other combustion control device. Flares, 
process heaters or other combustion devices are used for catalyst 
regeneration vents on 21 of the CRU. Based on current information in 
the EPA database, it is not possible to discern whether these control 
devices are used specifically for the final purge vent. However, from 
information collected during the site visits to 20 refineries, it is 
known that approximately one-half of these refineries vented the final 
purge vent to a combustion control device. Using the control efficiency 
determined by the EPA for combustion devices (refer to the discussion 
for the depressurization/purge vent), the MACT floor for the final 
purge vent is to vent this stream to a combustion control device that 
achieves 98 percent destruction efficiency or reduces total organic HAP 
or TOC concentration to below 20 ppmv.
    (2) MACT floor determination for new CRU catalyst regeneration 
vents. Except for the catalyst regeneration coke burn-off vent for 
semi-regenerative CRU, the MACT floor for catalyst regeneration vents 
on new CRU is the same as for catalyst regeneration vents on existing 
CRU for all CRU catalyst regeneration vents. This is because the 
catalyst regeneration vent on the best-controlled or top-performing CRU 
applies the same work practices or control devices as the top 12 
percent of CRU catalyst regeneration vents employ (i.e., the MACT floor 
for existing sources). There are two semi-regenerative CRU that employ 
multiple stage type scrubbers to control catalyst regeneration coke 
burn vents. These represent the best-controlled sources for this vent. 
Therefore, the MACT floor for catalyst regeneration vents on new semi-
regenerative CRU (as well as continuous and cyclic CRU) is the use of a 
multiple stage scrubber (i.e., a scrubber that achieves 97 percent or 
greater removal

[[Page 48904]]

of HCl or achieves an outlet concentration of 10 ppmv or less as 
specified in the MACT floor for catalyst regeneration vents on existing 
continuous and cyclic CRU).
    c. MACT floor for sulfur recovery plants. Developing a MACT floor 
for SRU is complicated by the fact that there are different types of 
processes (although Claus units predominate the industry) and numerous 
types of emission control techniques (including different types of tail 
gas treatment units, thermal incineration, or a combination of a tail 
gas treatment unit and incineration). The EPA database for SRU contains 
information regarding the number and types of SRUs as well as the 
control device configuration for 144 units at 82 refineries. The 
database also has information regarding process capacities or sulfur 
production rates and information regarding applicability of the NSPS 
for approximately 60 percent of these SRU.
    The predominant HAP emitted from SRU are COS and CS2. 
There are very few data available regarding HAP emissions from SRUs. 
Consequently, the available data on HAP emissions from the SRU vents 
are inadequate to characterize the emission reductions achieved by the 
top performing 12 percent of the units. Additionally, there are 
inadequate data to determine and differentiate the emission reduction 
efficiencies achieved by the various types of emission control process 
configurations. Therefore, the floor for SRU vent HAP emissions is 
being established based on current industry regulations rather than 
emissions data or process equipment.
    (1) MACT floor determination for existing SRU/sulfur plant vents. 
There are 144 units in the current data base for SRU; information 
regarding the applicability of the refinery NSPS was specifically 
requested for 91 of these units. Of the 91 SRU for which NSPS 
applicability information was requested, 38 units were subject to the 
NSPS, 47 units were not, and 6 units did not respond. Due to the lack 
of emissions data, a MACT floor determination cannot be made based on 
the emission reduction achieved by the top-performing 12 percent of the 
industry. Alternatively, the MACT floor determination can be made based 
on either the emission control equipment in-place for the SRU vent or 
the existing regulations limiting HAP emissions from these vents.
    Although the database contains information regarding the types of 
equipment in-place at the SRU, due to the variety of different tail gas 
treatment units and process configurations and the lack of emissions 
data, it is not possible to make a ranking of the tail gas treatment 
unit types and the process configurations that yield the greatest 
reduction in HAP emissions. On the other hand, the petroleum refinery 
NSPS (Sec. 60.104) specifies emission limits (some of which are 
primarily HAP emission limits) for Claus sulfur recovery plants. As 
Claus units represent 96 percent of the SRU in the EPA database (138 of 
the 144 SRU are Claus units), and approximately 40 percent of the SRU 
(for which NSPS applicability information is available) are subject to 
the NSPS, it is concluded that over 12 percent of all SRU are subject 
to the refinery NSPS. Therefore, the MACT floor for the control of HAP 
emission from the SRU vents is based on the emission reductions 
achieved by facilities subject to the NSPS for petroleum refineries.
    The EPA is aware that there are significant process differences 
between the Claus sulfur units and the non-Claus units. At this time, 
the EPA does not have adequate data to characterize the HAP emissions 
from these non-Claus sulfur units but available data indicate that 
these units are likely operating at emission levels that meet the MACT 
floor criteria. The EPA is requesting comment on these processes and, 
based on the new information, will reexamine the possible need to set a 
separate standard for these few non-Claus SRU.
    The refinery NSPS outlines two options for the control of emissions 
from SRU: (1) For oxidative control systems or reductive control 
systems followed by incineration, the emission limit is 250 ppmv of 
SO2 at zero percent excess air; and (2) for reductive 
control systems not followed by incineration, the emission limit is 300 
ppmv of reduced sulfur compounds and 10 ppmv of H2S, each 
calculated as ppmv SO2 at zero percent excess air. The 
second option translates well into a HAP emission limit because TRS 
compounds are defined as H2S, COS, and CS2. The 
fact that H2S is a component of the TRS and cannot exceed 10 
ppmv suggests that the COS and CS2 (i.e., the HAP) are at 
least 290 ppmv and at most 300 ppmv. The first option is not easily 
translated into a HAP emission limit (i.e., there is no direct way to 
determine the contribution of H2S, a non-HAP, to the total 
limit), but it suggests that use of an oxidation control system or 
incineration effectively controls emissions of TRS. Therefore, it is 
concluded that the MACT floor for the SRU vent is a combined HAP or TRS 
emission limit of 300 ppmv measured as ppmv SO2 at zero 
percent excess air. It is important to note that the EPA is still in 
the process of collecting and validating additional data for both the 
Claus and non-Claus SRU and will re-evaluate and possibly revise the 
floor determination based on the new data.
    (2) MACT floor determination for new SRU/sulfur plant vents. Based 
on the limited information and data available, EPA concluded that the 
MACT floor determination for existing SRU sources of HAP (i.e., the 300 
ppmv HAP emission limit derived from the refinery NSPS) also represents 
the HAP emission control that is achieved by the best-controlled 
similar source in the source category. Therefore, the MACT floor for 
new SRUs is the same as the MACT floor for existing SRUs. No options 
have been identified for this source that would provide a level of 
control more stringent that the MACT floor.

D. Selection of Monitoring Requirements

    The EPA evaluated the hierarchy of monitoring options available for 
this source category. The EPA identified and analyzed several different 
monitoring options taking into consideration the various unit 
operations, the HAP emitted, and the proposed control equipment for 
each of the respective vents. This hierarchy includes measurement of 
HAP (e.g., HCl) by a CEMS, installation of measurement devices for 
continuous monitoring of process and/or control device operating 
parameters, and periodic or one-time performance tests. Each option was 
evaluated relative to its technical feasibility, cost, ease of 
implementation, and relevance to the process or control device.
    A CEMS provides a direct measurement of emissions. For this source 
category, CEMS are commercially available for a number of the 
pollutants of concern, e.g., HCl, CO, metallic HAP/PM, and TRS 
compounds. However, it is important to note that for some of these 
systems the technical feasibility of monitoring the unit operations 
that comprise the source category has not yet been demonstrated. There 
also are other concerns. For example, the EPA believes that HCl 
monitors can be used for CRU catalyst regeneration vent applications 
and TRS monitors can be used for SRU vent COS and CS2 
emissions; but the nationwide capital cost of this option (CEMS for all 
reformer unit HCl scrubbers and sulfur plants) is estimated at $18.5 
million for the HCl monitors and $6.1 million for the TRS monitors, 
with annual costs of $14.2 million and $4.3 million, respectively, for 
operation and maintenance, quality assurance and quality control 
performance evaluation,

[[Page 48905]]

and reporting/recordkeeping requirements. Because of the high cost of 
using CEMS compared with the costs of the emission control devices and 
the cost of monitoring control device and process parameters, the EPA 
is not requiring the blanket use of CEMS to demonstrate compliance for 
this source category. However, CEMS for CO are included as an 
alternative under the proposed rule for affected CCU. These devices are 
commonly used to monitor CCU process operations and are also required 
under the refinery NSPS. The cost associated with continuous CO 
monitors is considered reasonable. Although CEMS are not required, the 
proposed rule does provide the owner or operator a general option of 
installing and operating a CEMS and complying with most of the 
requirements in the general provisions that apply to a CEMS.
    Another option for compliance assurance is monitoring process and/
or control device operating parameters plus conducting routine (e.g., 
annual) emission tests. With the exception of complete burn/combustion 
CCUs, process parameters were not selected as indicators for HAP 
emissions for the unit operations in this source category because an 
adequate correlation does not exist between production or process 
parameters and emission rates. Control device operating parameters were 
selected instead because the EPA's experience has shown that 
measurements outside a specified range of values, for example 
established during an initial performance test, could be used to 
indicate the control device was not operating properly. The estimated 
nationwide capital costs of this option are $7.4 million; annual costs 
are $10.6 million for all three vents in the source category. Note that 
the periodic emission tests required for these vents (for example 
testing using Method 26A in appendix A to 40 CFR part 60 for HCl 
emissions from CRU) would not require a capital investment. The 
estimated cost assumes the use of a test contractor and includes time 
for participation by plant personnel.
    The EPA believes that reasonable assurance of compliance is 
achieved through the combination of continuous emission monitoring, 
process and control device operating parameter monitoring, and the 
periodic emission testing required in the proposed rule. The proposed 
rule requires that each owner or operator of a CCU, CRU, or SRU using a 
combustion device to limit HAP emissions must monitor temperature as a 
control device operating parameter. The owner or operator of a CCU 
using an ESP for control of metallic HAP emissions must monitor the 
voltage and secondary current of the control device or the total power 
input. If a wet scrubber is used to comply with the requirements for 
metallic HAP or HCl control, the owner or operator must monitor the 
pressure drop across the scrubber, the gas and water flow rate to the 
scrubber, and determine the liquid-to-gas ratio. If new information is 
obtained after proposal indicating the use or planned use of dry 
scrubbers, appropriate monitoring provisions will be included in the 
final rule. For CCU subject to the rule, such as complete burn/
combustion CCU, that do not use add-on control devices, the owner or 
operator must continuously monitor the concentration of CO emissions 
from the unit or measure the regeneration process operating temperature 
and the oxygen content of the vent gas. An owner or operator may 
request approval to monitor parameters other than those listed above by 
submitting a request to the applicable permitting authority. The EPA is 
soliciting comment on appropriate monitoring parameters for CRU that do 
not use an external scrubber to control HCl emissions.

V. Summary of Impacts of Proposed Standards

A. Air Quality Impacts

    The impacts presented in this section include the process vent 
emissions from all three of the unit operations listed in the source 
category. The EPA estimates nationwide HAP emissions from process vents 
on these unit operations at approximately 7,270 Mg/yr (8,000 tpy) at 
the current level of control. The proposed standards will reduce 
nationwide HAP emissions by about 5,960 Mg/yr (6,560 tpy), an 82 
percent reduction. Emissions of VOC, CO, and PM (mainly from CCUs), and 
emissions of H2S (mainly from SRUs) would be reduced by 
about 65 percent from the current level of about 185,900 Mg/yr (204,500 
tpy). Little or no adverse secondary air impacts, water or solid waste 
impacts are anticipated from the implementation of these standards.

B. Cost Impacts

    Nationwide capital and annualized costs of control equipment are 
estimated at $179 million and $35.5 million/yr, respectively. The 
implementation of this regulation is expected to result in an overall 
annual national cost of $53.5 million. This includes a cost of $43.7 
million for operation/maintenance of control devices and a monitoring, 
recordkeeping, and reporting cost of $9.8 million.

C. Economic Impacts

    The economic impact analysis for the selected regulatory 
alternatives shows that the estimated price increase of refined 
petroleum products is 0.24 percent for the 127 refineries expected to 
incur compliance costs as a result of the rule. The estimated decrease 
in output is 0.17 percent of domestic refinery products. The decline in 
domestic production is due to higher imports and reduced quantity 
demanded due to higher prices. However, the value of domestic shipments 
is expected to increase by 0.07 percent because the estimated price 
increase more than offsets the lower production volume. Annual net 
exports (exports minus imports) are predicted to decrease by 0.76 
percent. Employment in the industry is likely to decrease by 0.19 
percent (136 jobs). No plant closures or significant regional impacts 
are expected. For more information on the economic impact analysis 
methodology and results, consult the ``Economic Impact Analysis for the 
Petroleum Refinery NESHAP.'' (See Docket Item II-A-5.)

D. Non-air Health and Environmental Impacts

    The proposed NESHAP are based on air pollution control systems 
which are currently in use in the industry. The proposed NESHAP would 
reduce emissions of HAP and ambient pollutants, and consequently, 
occupational exposure levels for plant employees may be lowered.

E. Energy Impacts

    The national electric usage required to comply with the rule is 
expected to increase by about 114,000 MW/hr, primarily for CCU PM and 
CO controls and SRU incinerators. National natural gas usage, primarily 
for SRU incinerators, is expected to increase by about 1.5 billion 
cubic feet. Water usage for CRU scrubbers, is expected to increase by 
about 6.2 million gallons nationwide.

VI. Request for Comments

    The EPA seeks full public participation in arriving at its final 
decisions and encourages comments on all aspects of this proposal from 
all interested parties. Full supporting data and detailed analysis 
should be submitted with comments to allow the EPA to make use of the 
comments. All comments should be directed to the Air and Radiation 
Docket and Information Center, Docket No. A-97-36 (see ADDRESSES). 
Comments on this document must be submitted on or before the date 
specified in DATES.

[[Page 48906]]

    Commentors wishing to submit proprietary information for 
consideration should clearly distinguish such information from other 
comments and clearly label it ``CBI.'' Submissions containing such 
proprietary information should be sent directly to the following 
address, and not to the public docket, to ensure that proprietary 
information is not inadvertently placed in the docket: Attention: Mr. 
Bob Lucas, c/o Ms. Melva Toomer, U.S. EPA Confidential Business 
Information Manager, OAQPS (MD-13), Research Triangle Park, NC 27711. 
Information covered by such a claim of confidentiality will be 
disclosed by the EPA only to the extent allowed and by the procedures 
set forth in 40 CFR part 2. If no claim of confidentiality accompanies 
the submission when it is received by the EPA, it may be made available 
to the public without further notice to the commentor.
    The EPA specifically requests comments on seven topics where 
additional information is desired prior to promulgation. As discussed 
below, topics entail: Emission characteristics and operation of non-
fluidized CCU and non-Claus SRU; HAP emissions from SRU sulfur pits; 
excess emissions from CCU resulting from maintenance/repair of the 
control device; potential subcategorization of CCU; selection of a 
cutoff value for CRU depressuring/purging operations; appropriate 
monitoring parameters for CRU with internal scrubbing systems; and 
consideration of an alternative format for the proposed Ni emission 
limit.

A. Non-fluidized Catalytic Cracking Units and Non-Claus Sulfur Recovery 
Units

    As discussed in section II.D.1 of this document, non-fluidized CCU 
(accounting for only 2.9 percent of the total catalytic cracking 
process charge rate), were operated by 7 refineries in 1997. Although 
the exact number of non-Claus SRU is not known, Claus SRU represent 96 
percent of the SRU in the EPA database. While the EPA observed a small 
number of non-fluid CCU and non-Claus SRU in operation, little or no 
test data are available to determine differences in emissions and 
operation as compared to fluidized-bed CCU or Claus SRU. The EPA 
requests information and data on control status, operating processes, 
and emission measurements using EPA methodology. Based on this 
information and data, the EPA will determine whether a separate 
emission limit is warranted for non-fluidized bed CCU or non-Claus SRU 
and analyze the associated impacts of control. Based on these analyses, 
the EPA may retain the proposed standard with no distinction between 
the processes, include a separate standard in the final rule, or 
determine that no standard is warranted for one or both of these 
subcategories.

B. Potential Emission Sources

    Process observations during plant site visits indicate that SRU 
sulfur recovery pits and certain types of tail gas treatment units may 
be potential HAP emission sources. Emissions from sulfur pits occur at 
each SRU reactor when elemental sulfur is condensed and removed from 
the SRU gas and the liquid sulfur is collected and stored in bins. 
Several refineries are known to purge the sulfur pits to prevent the 
buildup of explosive levels of gases. Emissions are controlled by 
combining the purged gases from the pits with the SRU or tail gas 
treatment unit off-gas and venting to an incinerator. Certain types of 
tail gas treatment units, such as ``Stretford'' units, employ a series 
of open vessels as part of the solution circulation loop and a direct 
air contact cooling tower to cool the solution. Limited data indicate 
that HAP emissions are released from the solution tank and direct air 
contact cooling towers. The EPA specifically requests information and 
data on these process operations, emissions, and control practices. 
Based on analyses of the information and data received, the EPA may 
consider regulation of these sources when developing the final rule.

C. Catalytic Cracking Unit Control Device Maintenance

    The Agency requests comment on the need for allowing operation of 
CCU when control devices such as boilers or venturi scrubbers are out 
of service for maintenance overhauls. Information is specifically 
requested on the number of facilities which have this need, current 
maintenance practices for boilers and scrubbers, their frequency and 
length, safety considerations, and manufacturer's recommendations. 
Should monitoring by other methods be required during such a period? 
Should time limits be applied? Would more frequent, periodic 
preventative maintenance, such as that envisioned by the maintenance 
plan included in the proposed standard preclude or lessen the need for 
2 year or 10-year overhauls? How should the EPA provide operational 
flexibility while ensuring that emissions are minimized and good air 
pollution control practices are followed? The EPA will use comments, 
information, and suggestions received to address this issue in the 
final rule.

D. Subcategorization of Catalytic Cracking Units

    As discussed in section IV.C.1 of this document, the EPA recognizes 
the potential need for CCU subcategorization due to the wide variety of 
process variations. For this reason, additional information and data on 
CCU processes, emissions, and distinguishing characteristics that meet 
subcategorization criteria are requested. Based on the information and 
data received, the EPA will consider whether separate standards for 
different CCU processes are warranted.

E. Catalytic Reforming Unit Depressuring/Purging Cutoff Value

    Under the proposed standards, CRU control requirements do not apply 
to depressuring or purging operations at a differential pressure 
between the gas transfer system to the control device of less than 1 
psig. The EPA evaluated several different approaches to deriving the 
cutoff value, but selected an approach based on differential pressure 
due to the concern that an absolute value would not be appropriate for 
all plants due to process variations. Because differential pressure may 
be more difficult to monitor, EPA also included a cutoff of 1 psig, 
consistent with State rules, for the reactor vent pressure. Comments, 
information, and data on outlet unit pressures for depressuring/purging 
and the feasibility of establishing a differential value are requested. 
The EPA will evaluate the data and information received and address 
this issue in the final rule.

F. Monitoring of Catalytic Reforming Units with Internal Scrubbing 
Systems

    As previously noted the MACT floor for CRU catalyst regeneration 
vents is established based on current industry practices in use and 
control equipment in place at CRU. Two classes of scrubbers were 
designated to characterize the groups of scrubbers used to control 
emissions from CRU catalyst regeneration vents during the coke burn-off 
step, single stage and multiple stage scrubbers. Each of these scrubber 
classes can be further categorized as either a scrubber that is 
internal to the process (e.g., caustic injection) or external to the 
process (e.g., a packed tower). Because the internal type scrubbers are 
contained within the process units itself, there is no convenient 
scrubber operating parameter that can be monitored as is the case with 
an external scrubber. The EPA is therefore requesting comment on 
identification of appropriate monitoring parameters for the internal 
type CRU

[[Page 48907]]

scrubbing systems. For example, would use of a simplified monitoring 
system (such as colorimetric tubes) be adequate to demonstrate that the 
acid gases in the unit are sufficiently controlled. Or, would 
monitoring of the recycle stream within the unit rather than the 
exhaust gas be adequate to characterize the scrubber performance.

G. Alternative CCU Standard

    The EPA is considering the addition of a third alternative standard 
to reduce metal HAP emissions from the CCU regeneration vent. The 
current proposal requires compliance with either a PM limit of 1.0 lb/
1,000 lbs of coke burn-off, or a Ni limit of 0.029 lb/hr. Industry 
representatives have requested inclusion of a metal HAP (or Ni) 
emission limit formatted in terms of lb of metal HAP (or Ni)/1,000 lbs 
of coke burn-off. The EPA requests comments on the need and benefits of 
a third alternative. The EPA will consider all regulatory formats. 
Commenters suggesting a particular emission limit should explain how 
the limit correlates to the MACT floor.
    From the beginning of this project, the EPA has recognized that the 
format for the CCU standard was a significant issue. During initial 
discussions with stakeholders, including early site visits to 
refineries, EPA asked for thoughts on possible formats. Also, from the 
beginning, regulatory alternatives have included the use of PM as a 
surrogate for total metal HAP.
    Using the PM format established by NSPS Subpart J, the MACT floor 
determination set the standard at 1.0 lb/1,000 lbs of coke burn-off as 
characterizing performance of the MACT floor technology. An early draft 
of the regulation included a second alternative that provided a Ni 
emission limit of 0.00047 lb Ni/1,000 lbs of coke burn-off. This second 
alternative was derived from the first alternative by using the average 
Ni concentration in the CCU catalyst regeneration fines to convert the 
PM mass to an equivalent Ni mass. These fines consist of the PM that is 
collected by the air pollution control device following the CCU 
regeneration vent.
    Upon review of this draft regulation, representatives of small 
refineries commented that the format of both regulatory alternatives 
then under consideration was independent of unit size or throughput. 
Therefore, both alternatives, expressed in terms of coke burn-off, 
penalized small CCU. Representatives cited examples of small units with 
very low annual Ni emissions (in terms of tons per year) which would 
not be in compliance with either regulatory alternative. In response, 
the EPA revised the draft regulation by changing the format of the Ni 
standard to a lb/hr format, while keeping the PM limit expressed in 
terms of coke burn-off. The second alternative in the current proposal 
provides a Ni limit of 0.029 lb/hr. Industry representatives supported 
the new format, while also requesting that the previous format be 
included as a third alternative.
    Industry representatives have recommended that the third 
alternative be set at 0.007 lb of Ni/1,000 lbs of coke burn-off to 
account for the highest Ni concentrations found in CCU feed streams and 
to account for the variability in the crude oil. The API/NPRA 
recommended Ni standard is, in their view, technically equivalent to 
the floor. Documents relating to the API/NPRA recommendation are in the 
docket for this rulemaking.
    Since the time of EPA's original suggestion for this format, EPA 
has continued to collect data on the Ni concentration in CCU fines. The 
current data base shows that an alternative based on average Ni fines 
concentration could be set at 0.0013 lb of Ni/1,000 lbs of coke burn-
off. The EPA is continuing to evaluate the API/NPRA recommendation.
    The EPA is requesting comments on providing a third regulatory 
alternative. The alternative could be based on metal HAP (or Ni) 
emissions in terms of lb/1,000 lbs of coke burn-off, or it could have a 
different format. The alternative must be technically equivalent to the 
MACT floor. Specifically, the Agency requests comments regarding: (1) 
The need for and usefulness of a third alternative for specific 
refineries, (2) the use of Ni concentrations as a surrogate for total 
metal HAP, and (3) the use of the arithmetic mean, median, geometric 
mean, 90th percentile value, 95th percentile value, or highest value as 
the representative concentration used in the factor for conversion of 
PM to Ni.

H. Overlap With New Source Performance Standard

    As discussed in section III.A of this document, the EPA recognizes 
that some fluidized-bed CCU and SRU are subject to NSPS and related 
Title I requirements. To minimize the burden of duplicative rule 
requirements, the proposed MACT standard includes provisions allowing 
compliance demonstrations for the NSPS requirements (which govern 
criteria pollutants) to serve as compliance demonstrations for the HAP 
emission control requirements. The intent of these provisions is to 
minimize duplication without reducing or changing the Title I 
requirements. The EPA requests comments on the adequacy of this 
approach, together with suggestions for other approaches that would 
achieve this goal.

I. Status of an Exceedance or Excursion

    Section 63.1565(p) of the proposed standard provides that more that 
one exceedance or excursion by the same control device during a semi-
annual reporting period is a violation. This provision is included in 
the proposed standard to maintain consistency with the earlier MACT 
standard for petroleum refineries in 40 CFR part 63, subpart CC. The 
EPA is further considering this proposed provision and its impacts. 
However, EPA currently does not have adequate information on the long-
term performance of the MACT emission control technologies for the 
affected processes and their ability to continuously achieve 
compliance. For this reason, EPA requests additional information and 
data relative to control device performance. Based on the information 
received, EPA will decide whether to permit facilities to have an 
exceedance or excursion once per semi-annual reporting period.

VII. Administrative Requirements

A. Docket

    The docket is an organized and complete file of all the information 
considered by the EPA in the development of this rulemaking. The docket 
is a dynamic file, because material is added throughout the rulemaking 
development. The docketing system is intended to allow members of the 
public and industries involved to readily identify and locate documents 
so that they can effectively participate in the rulemaking process. 
Along with the proposed and promulgated standards and their preambles, 
the contents of the docket will serve as the record in the case of 
judicial review. (See CAA section 307(d)(7)(A).)

B. Public Hearing

    A public hearing will be held, if requested, to discuss the 
proposed standards in accordance with section 307(d)(5) of the Act. If 
a public hearing is requested and held, the EPA will ask clarifying 
questions during the oral presentation but will not respond to the 
presentations or comments. Written statements and supporting 
information will be considered with equivalent weight as any oral 
statement and supporting information subsequently presented at a public 
hearing. Persons wishing to attend or to make oral presentations or to 
inquire as to whether

[[Page 48908]]

a hearing is to be held should contact the EPA (see FOR FURTHER 
INFORMATION CONTACT). To provide an opportunity for all who may wish to 
speak, oral presentations will be limited to 15 minutes each.
    Any member of the public may file a written statement on or before 
November 10, 1998. Written statements should be addressed to the Air 
and Radiation Docket and Information Center (see ADDRESSES), and refer 
to Docket A-97-36. A verbatim transcript of the hearing and written 
statements will be placed in the docket and be available for public 
inspection and copying, or be mailed upon request, at the Air and 
Radiation Docket and Information Center.

C. Executive Order 12866

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the EPA 
must determine whether the regulatory action is ``significant'' and 
therefore subject to review by the Office of Management and Budget 
(OMB), and the requirements of the Executive Order. The Executive 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 obligation of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    Pursuant to the terms of Executive Order 12866, it has been 
determined that this regulatory action is not ``significant'' because 
none of the listed criteria apply to this action. However, OMB has 
classified this rule as potentially significant and has requested 
review. Consequently, this action will be submitted to OMB for review 
under Executive Order 12866.

D. Enhancing the Intergovernmental Partnership Under Executive Order 
12875

    In compliance with Executive Orders 12875, the EPA involved State 
regulatory experts in the development of this proposed rule. No tribal 
governments are believed to be affected by this proposed rule. State 
and local governments are not directly impacted by the rule, i.e., they 
are not required to purchase control systems to meet the requirements 
of the rule. However, they will be required to implement the rule; 
e.g., incorporate the rule into permits and enforce the rule. They will 
collect permit fees that will be used to offset the resources burden of 
implementing the rule. Comments have been solicited from States and 
have been carefully considered in the rule development process. In 
addition, all States and tribal governments are encouraged to comment 
on this proposed rule during the public comment period, and the EPA 
intends to fully consider these comments in the development of the 
final rule.

E. Unfunded Mandates Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub. 
L. 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, the 
EPA generally must prepare a written statement, including a cost-
benefit analysis, for proposed and final rules with ``Federal 
mandates'' that may result in expenditures to State, local, and tribal 
governments, in the aggregate, or to the private sector, of $100 
million or more in any one year. Before promulgating an EPA rule for 
which a written statement is needed, section 205 of the UMRA generally 
requires the EPA to identify and consider a reasonable number of 
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of section 205 do not apply when they are 
inconsistent with applicable law. Moreover, section 205 allows the EPA 
to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator 
publishes with the final rule an explanation why that alternative was 
not adopted. Before the EPA establishes any regulatory requirements 
that may significantly or uniquely affect small governments, including 
tribal governments, it must have developed pursuant to section 203 of 
the UMRA a small government agency plan. The plan must provide for 
notifying potentially affected small governments, enabling officials of 
affected small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements.
    The EPA has determined that this rule does not contain a Federal 
mandate that may result in expenditures of $100 million or more for 
State, local, or tribal governments, in the aggregate, or the private 
sector in any one year. Thus, today's rule is not subject to the 
requirements of sections 202 and 205 of UMRA. In addition, the EPA has 
determined that this rule contains no regulatory requirements that 
might significantly or uniquely affect small governments because it 
contains no requirements that apply to such governments or impose 
obligations upon them. Therefore, today's rule is not subject to the 
requirements of section 203 of the UMRA.

F. Executive Order 13045

    Executive Order 13045, ``Protection of Children from Environmental 
Health and Safety Risks'' (62 FR 19885, April 23, 1997) applies to any 
rule that EPA determines: (1) ``Economically significant'' as defined 
under E.O. 12866, and (2) the environmental health or safety risk 
addressed by the rule has a disproportionate effect on children. If the 
regulatory action meets both criteria, the Agency must evaluate the 
environmental health or safety effects of the planned rule on children, 
and explain why the planned regulation is preferrable to other 
potentially effective and reasonable feasible alternatives considered 
by the Agency. This proposed rule is not subject to E.O. 13045 because 
it does not involve decisions on environmental health risks or safety 
risks that may disportionately affect children.

G. Regulatory Flexibility

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to conduct a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements unless the agency certifies 
that the rule will not have a significant economic impact on a 
substantial number of small entities. Small entities include small 
business, small not-for-profit enterprises, and small governmental 
jurisdictions.
    In developing these proposed standards, the EPA has worked with 
industry trade groups to identify the special concerns of small 
refineries. Site visits also were conducted to five small refineries 
where the EPA met with facility representatives and listened to their 
concerns. In response, the EPA has exercised the maximum degree of 
flexibility in minimizing impacts on small business through the 
alternative Ni standard and subcategorization of the

[[Page 48909]]

source category for CRU vents. Also, these proposed standards, which 
are based on MACT-floor level control technology, reflect the minimum 
level of control allowed under the Act.
    The EPA economic analysis identified 16 small businesses that 
operate a total of 19 refineries. Two of these refineries operated by 
two different firms are expected to incur compliance costs and the 
remaining 17 refineries are not expected to incur any compliance costs 
as a result of the proposed NESHAP. Annual compliance costs for the two 
affected refineries would be less than one percent of estimated sales 
revenues. Additional information is included in chapter 6 of the 
economic impact analysis for the proposed standards. (See Docket Item 
II-A-5.)
    Based on this information, the EPA has concluded that this proposed 
rule would not have a significant economic impact on a substantial 
number of small entities. Therefore, I certify that this action will 
not have a significant economic impact on a substantial number of small 
entities.

H. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to OMB under the requirements of the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information 
Collection Request (ICR) document has been prepared by EPA (ICR No. 
1844.01), and a copy may be obtained from Sandy Farmer, OPPE Regulatory 
Division, U.S. Environmental Protection Agency (2137), 401 M Street SW, 
Washington, DC 20460, or by calling (202) 260-2740.
    The proposed information requirements include mandatory 
notifications, records, and reports required by the NESHAP general 
provisions (40 CFR part 63, subpart A). These information requirements 
are needed to confirm the compliance status of major sources, to 
identify any nonmajor sources not subject to the standards and any new 
or reconstructed sources subject to the standards, to confirm that 
emission control devices are being properly operated and maintained, 
and to ensure that the standards are being achieved. Based on the 
recorded and reported information, the EPA can decide which plants, 
records, or processes should be inspected. These recordkeeping and 
reporting requirements are specifically authorized under section 114 of 
the Act (42 U.S.C. 7414). All information submitted to the EPA for 
which a claim of confidentiality is made will be safeguarded according 
to Agency policies in 40 CFR part 2, subpart B. (See 41 FR 36902, 
September 1, 1976; 43 FR 39999, September 28, 1978; 43 FR 42251, 
September 28, 1978; and 44 FR 17674, March 23, 1979.)
    The annual public reporting and recordkeeping burden for this 
collection of information (averaged over the first 3 years after the 
effective date of the rule) is estimated to total 18,581 labor hours 
per year at a total annual cost of $597,007/yr. This estimate includes 
certain notifications which are streamlined to incorporate 
notifications of applicability for existing sources, results of initial 
performance tests (including repeat performance tests where needed), 
and monitoring information. The estimates also include one-time 
preparation of a startup, shutdown, and malfunction plan; semi-annual 
reports of any period of excess emissions; and recordkeeping. Reporting 
requirements have been streamlined to allow the owner or operator to 
report only those events where the procedures in the startup, shutdown, 
and malfunction plan were not followed in the semi-annual excess 
emissions report. Total capital costs associated with monitoring 
requirements over the 3-year period of the ICR is estimated at 
$463,000/yr; this estimate includes the capital and startup costs 
associated with installation of monitoring equipment. The total 
operation and maintenance cost is estimated at $4,418,500/yr.
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purpose of collecting, validating, and 
verifying information; process and maintain information and disclose 
and provide information; adjust the existing ways to comply with any 
previously applicable instructions and requirements; train personnel to 
respond to a collection of information; search existing data sources; 
complete and review the collection of information; and transmit or 
otherwise disclose the information.
    An Agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15.
    Comments are requested on the Agency's need for this information, 
the accuracy of the burden estimates, and any suggested methods for 
minimizing respondent burden, including through the use of automated 
collection techniques. Send comments on the ICR to the Director, OPPE 
Regulatory Information Division; U.S. Environmental Protection Agency 
(2136), 401 M Street SW., Washington, DC 20460; and to the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street, NW., Washington, DC 20503, marked ``Attention: Desk 
Officer for EPA.'' Include the ICR number in any correspondence. 
Because OMB is required to make a decision concerning the ICR between 
30 and 60 days after September 11, 1998, a comment to OMB is best 
assured of having its full effect if OMB receives it by October 13, 
1998. The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

I. Pollution Prevention Act

    During the development of the proposed NESHAP, the EPA explored 
opportunities to eliminate or reduce emissions by substitution of non-
HAP for HAP-generating materials. One potential approach is the use of 
a non-chlorinated catalyst material for CRUs. However, available 
information are insufficient to evaluate the feasibility or research 
status of this potential approach. The EPA will continue to work with 
the industry to collect information on the potential use of different 
CRU catalyst materials and encourage new research on this approach. The 
pollution prevention concept is incorporated in the proposed 
alternative Ni emission standard which encourages the use of feed with 
lower metallic HAP content. Also, facilities which hydrotreat to remove 
metals from the feed can meet the proposed standard with a less 
effective PM control device.

J. National Technology Transfer and Advancement Act

    Under section 12(d) of the National Technology Transfer and 
Advancement Act (NTTA), Pub. L. 104-113 (March 7, 1996), the Agency is 
required to use voluntary consensus standards in its regulatory and 
procurement activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, business practices, etc.) which are adopted by 
voluntary consensus standard bodies. Where available and potentially 
applicable voluntary consensus standards are not used by the Agency, 
the Act requires the Agency to provide Congress, through OMB, an 
explanation

[[Page 48910]]

of the reasons for not using such standards. This section summarizes 
the Agency's response to the requirements of the NTTA for the 
analytical test methods proposed as part of today's standards.
    The proposed standard includes test methods and procedures for the 
purpose of emission tests needed to demonstrate initial compliance. 
Although a vast array of test methods and procedures applicable to 
petroleum content and material specifications are published by the 
American Society of Testing and Materials, these methods are not 
applicable to determining the volume and type of air emissions from the 
affected sources. To facilitate the emission testing process and 
associated costs, the proposed standards uses surrogates for the HAPs 
included in emissions from the affected sources. This approach allows 
use of the conventional test methods required by the existing NSPS 
which have been in use by EPA, States, and three-quarters of the 
industry for over 20 years. Alternative test methods also may be used 
subject to EPA approval. In addition, the EPA worked with industry 
experts to revise the NSPS procedure for determining the coke burn-off 
rate. The amended procedure utilizes common industry practice for 
determining the rate, corrects a technical equation error in the older 
NSPS, and reduces costs by allowing the use of existing data rather 
than daily stack tests to obtain needed data.

K. Clean Air Act

    In accordance with section 117 of the Act, publication of this 
proposal was preceded by consultation with appropriate advisory 
committees, independent experts, and Federal departments and agencies. 
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 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.

L. Executive Order 13084

    Under Executive Order 13084, EPA may not issue a regulation that is 
not required by statute, that significantly or uniquely affects the 
communities of Indian tribal governments, and that imposes substantial 
direct compliance costs on those communities, unless the Federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by the tribal governments. If the mandate is unfunded, 
EPA must provide to the Office of Management and Budget, in a 
separately identified section of the preamble to the rule, a 
description of the extent of EPA's prior consultation with 
representatives of affected tribal governments, a summary of the nature 
of their concerns, and a statement supporting the need to issue the 
regulation. In addition, Executive Order 13084 requires EPA to develop 
an effective process permitting elected and other representatives of 
Indian tribal governments to provide meaningful and timely input in the 
development of regulatory policies on matters that significantly or 
uniquely affect their communities. Today's rule does not significantly 
or uniquely affect the communities of Indian tribal governments. 
Accordingly, the requirements of section 3(b) of Executive Order 13084 
do not apply to this rule.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Petroleum refineries, Reporting and recordkeeping 
requirements.
    Dated: August 25, 1998.
Carol M. Browner,
Administrator.
    For the reasons set out in the preamble, part 63 of title 40, 
chapter I, of the Code of Federal Regulations is proposed to be amended 
as follows:

PART 63--[AMENDED]

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

    Authority: 42 U.S.C. 7401 et seq.
* * * * *
    2. Part 63 is amended by adding subpart UUU to read as follows:

Subpart UUU--National Emission Standards for Hazardous Air Pollutants 
From Petroleum Refineries--Catalytic Cracking (Fluid and Other) Units, 
Catalytic Reforming Units, and Sulfur Plants

Sec.

63.1560  Applicability and designation of affected sources.
63.1561  Definitions.
63.1562  Emission standards for existing sources.
63.1563  Emission standards for new or reconstructed sources.
63.1564  Compliance dates and performance tests.
63.1565  Monitoring requirements.
63.1566  Test methods and procedures.
63.1567  Notification, reporting and recordkeeping requirements.
63.1568  Applicability of general provisions.
63.1569  Delegation of authority.
63.1570-63.1579  [Reserved]
Appendix A to Subpart UUU to Part 63--Applicability of General 
Provisions (40 CFR Part 63, Subpart A) to Subpart UUU

Subpart UUU--National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries--Catalytic Cracking (Fluid and 
Other) Units, Catalytic Reforming Units, and Sulfur Plants


Sec. 63.1560  Applicability and designation of affected sources.

    (a) The provisions of this subpart apply to the owner or operator 
of each new and existing catalytic cracking unit, catalytic reforming 
unit, and sulfur recovery plant unit associated with a petroleum 
refinery and located at a major source of hazardous air pollutants 
(HAP) as defined in Sec. 63.2 of this part.
    (b) Affected sources at a facility subject to this subpart are:
    (1) The process vent or group of process vents on each fluidized 
and other (i.e., non-fluidized) catalytic cracking unit, that is 
associated with regeneration of the catalyst used in the unit (i.e., 
the catalyst regeneration flue gas vent);
    (2) The process vent or group of process vents, on each catalytic 
reforming unit (including but not limited to semi-regenerative, cyclic, 
or continuous processes), that is associated with regeneration of the 
catalyst used in the unit. This affected source includes vents that are 
used during the unit depressurization, purging, coke burn, catalyst 
rejuvenation, and reduction or activation purge; and
    (3) The process vent or group of process vents, that vents from a 
Claus or other sulfur recovery plant unit or the tail gas treatment 
unit serving the sulfur recovery plant, that is associated with sulfur 
recovery.
    (c) This subpart does not apply to gaseous streams routed to a fuel 
gas system.
    (d) An owner or operator of a fluidized-bed catalytic cracking unit 
catalyst regenerator subject to and in compliance with the standard for 
particulate matter emissions in Sec. 60.102 of this chapter and all 
associated requirements (including but not limited to testing, 
monitoring, recordkeeping, and reporting provisions) is considered to 
be in compliance with the standard in Sec. 63.1562(a)(1) of this 
subpart and all associated requirements. An owner or operator of a 
fluidized-bed catalytic cracking unit catalyst regenerator subject to 
and in compliance with the standard for carbon monoxide in Sec. 60.103 
of this chapter and all associated requirements (including but not 
limited to testing, monitoring,

[[Page 48911]]

recordkeeping, and reporting provisions) is considered to be in 
compliance with the standard in Sec. 63.1562(a)(2) of this subpart and 
all associated requirements. An owner or operator of a sulfur recovery 
unit subject to and in compliance with the standard for sulfur oxides 
in Sec. 60.104 of this chapter and all associated requirements 
(including but not limited to testing, monitoring, recordkeeping, and 
reporting provisions) is considered to be in compliance with the 
standard in Sec. 63.1562(c) of this subpart and all associated 
requirements.


Sec. 63.1561  Definitions.

    All terms used in this subpart shall have the meaning given them in 
the Clean Air Act, in subpart A of this part, and in this section. If 
the same term is defined in subpart A and in this section, it shall 
have the meaning given in this section for purposes of this subpart.
    Catalytic cracking unit means a refinery process unit in which 
petroleum derivatives are charged; hydrocarbon molecules in the 
presence of a catalyst are fractured into smaller molecules, or react 
with a contact material to improve feedstock quality for additional 
processing; and the catalyst or contact material is regenerated by 
burning off coke and other deposits. The unit includes, but is not 
limited to the riser, reactor, regenerator, air blowers, spent catalyst 
or contact material stripper, catalyst or contact material recovery 
equipment, and regenerator equipment for controlling air pollutant 
emissions and for heat recovery.
    Catalytic cracking unit regenerator means one or more regenerators 
(multiple regenerators) which comprise that portion of the catalytic 
cracking unit in which coke burn-off and catalyst or contact material 
regeneration occurs, and includes the regenerator combustion air 
blower(s).
    Catalytic reforming unit means a refinery process unit that reforms 
or changes the chemical structure of naphtha into higher octane 
aromatics through the use of a metal catalyst and chemical reactions 
that include dehydrogenation, isomerization, and hydrogenolysis. The 
catalytic reforming unit includes the reactor, regenerator (if 
separate), separators, catalyst isolation and transport vessels (e.g., 
lock and lift hoppers), recirculation equipment, scrubbers, and other 
ancillary equipment.
    Catalytic reforming unit regenerator means one or more regenerators 
which comprise that portion of the catalytic reforming unit in which 
the following regeneration steps typically are performed: 
Depressurization, purge, coke burn-off, catalyst rejuvenation with a 
chloride (or other halogenated) compound(s), and a final purge. The 
catalytic reforming unit catalyst regeneration process can be conducted 
either as a semi-regenerative, cyclic, or continuous regeneration 
process.
    Coke burn-off means the coke removed from the surface of the 
catalytic cracking unit catalyst or the catalytic reforming unit 
catalyst by combustion in the catalyst regenerator. The rate of coke 
burn-off is calculated by the formula specified in Sec. 63.1566 (Test 
methods and procedures) of this subpart.
    Combustion device means an individual unit of equipment such as a 
flare, incinerator, process heater, or boiler used for the destruction 
of organic hazardous air pollutants or volatile organic compounds.
    Combustion zone means the space in an enclosed combustion device 
(e.g., vapor incinerator, boiler, furnace, or process heater) occupied 
by the organic HAP and any supplemental fuel while burning. The 
combustion zone includes any flame that is visible or luminous as well 
as that space outside the flame envelope in which the organic HAP 
continues to be oxidized to form the combustion products.
    Contact material means any substance formulated to remove metals, 
sulfur, nitrogen, or any other contaminants from petroleum derivatives.
    Continuous regeneration reforming means a catalytic reforming 
process characterized by continuous flow of catalyst material through a 
reactor where it mixes with feedstock in a counter-current direction, 
and a portion of the catalyst is continuously removed and sent to a 
special regenerator where it is regenerated and continuously recycled 
back to the reactor.
    Control device means any equipment used for recovering, removing, 
or oxidizing HAP in either gaseous or solid form. Such equipment 
includes, but is not limited to, condensers, scrubbers, electrostatic 
precipitators, incinerators, flares, boilers, and process heaters.
    Cyclic regeneration reforming means a catalytic reforming process 
characterized by continual batch regeneration of catalyst in situ in 
any one of several reactors (e.g., four or five separate reactors) that 
can be isolated from and returned to the reforming operation, while 
maintaining continuous reforming process operations (i.e., feedstock 
continues flowing through the remaining reactors without change in feed 
rate or product octane).
    Flame zone means the portion of a combustion chamber of a boiler or 
process heater occupied by the flame envelope created by the primary 
fuel.
    Flow indicator means a device that indicates whether gas is 
flowing, or whether the valve position would allow gas to flow, in a 
line.
    HCl means, for the purposes of this subpart, gaseous emissions of 
hydrogen chloride that serve as a surrogate measure for total emissions 
of hydrogen chloride and chlorine as measured by Method 26A in appendix 
A to part 60 of this chapter or an approved alternative method.
    Incinerator means an enclosed combustion device that is used for 
destroying organic compounds, with or without heat recovery. Auxiliary 
fuel may be used to heat waste gas to combustion temperatures.
    Ni means, for the purposes of this subpart, particulate emissions 
of nickel that serve as a surrogate measure for total emissions of 
metal HAPs, including but not limited to: Antimony, arsenic, beryllium, 
cadmium, chromium, cobalt, lead, manganese, nickel, and selenium as 
measured by Method 29 in appendix A to part 60 of this chapter or by an 
approved alternative method.
    Petroleum refinery means an establishment/installation primarily 
engaged in petroleum refining as defined in the Standard Industrial 
Classification (SIC) code for petroleum refining (SIC 2911), and used 
primarily for:
    (1) Producing transportation fuels (such as gasoline, diesel fuels, 
and jet fuels), heating fuels (such as kerosene, fuel gas distillate, 
and fuel oils), or lubricants;
    (2) Separating petroleum; or
    (3) Separating, cracking, reacting, or reforming an intermediate 
petroleum stream, or recovering a by-product(s) from the intermediate 
petroleum stream (e.g., sulfur recovery).
    PM means, for the purposes of this subpart, emissions of 
particulate matter that serve as a surrogate measure of the total 
emissions of particulate matter and metal HAPs contained in the 
particulate matter, including but not limited to: Antimony, arsenic, 
beryllium, cadmium, chromium, cobalt, lead, maganese, nickel, and 
selenium as measured by Methods 5B or 5F in appendix A to part 60 of 
this chapter or by an approved alternative method.
    Process heater means an enclosed combustion device that primarily 
transfers heat liberated by burning fuel directly to process streams or 
to heat transfer liquids other than water.

[[Page 48912]]

    Semi-regenerative reforming means a catalytic reforming process 
characterized by shutdown of the entire reforming unit (e.g., which may 
employ three to four separate reactors) at specified intervals or at 
the owner's or operator's convenience for in situ catalyst 
regeneration.
    Sulfur recovery unit means a process unit that recovers elemental 
sulfur from gases that contain reduced sulfur compounds and other 
pollutants, usually by a vapor-phase catalytic reaction of sulfur 
dioxide and hydrogen sulfide. This definition does not include a unit 
where the modified reaction is carried out in a water solution which 
contains a metal ion capable of oxidizing the sulfide ion to sulfur, 
e.g., the LO-CAT II process.
    TRS means, for the purposes of this subpart, emissions of total 
reduced sulfur compounds, expressed as an equivalent sulfur dioxide 
concentration, that serve as a surrogate measure of the total emissions 
of sulfide HAPs carbonyl sulfide and carbon disulfide as measured by 
Method 15 in appendix A to part 60 of this chapter or by an approved 
alternative method.
    TOC means, for the purposes of this subpart, emissions of total 
organic compounds excluding methane and ethane that serve as a 
surrogate measure of the total emissions of organic HAP compounds, 
including but not limited to acetaldehyde, benzene, hexane, phenol, 
toluene, and xylenes and non-HAP volatile organic compounds as measured 
by Method 18 or Method 25A in appendix A to part 60 of this chapter or 
an approved alternative method.


Sec. 63.1562  Emission standards for existing sources.

    (a) Catalytic cracking unit regeneration. The owner or operator of 
a catalytic cracking unit shall comply with the standards in paragraphs 
(a)(1)(i) or (a)(1)(ii) of this section and the standard in paragraph 
(a)(2) of this section.
    (1) The owner or operator shall identify the standard selected in 
the notification of compliance status report as required by 
Sec. 63.1567(a)(6) of this subpart. Following any 6-month reporting 
period, the owner or operator may change the standard selected for 
compliance by submitting a request to the applicable permitting 
authority containing the information specified in Sec. 63.1567(b)(7) of 
this subpart.
    (i) Emissions of PM shall not exceed 1.0 kilogram (kg)/1,000 kg 
[1.0 pound (lb)/1,000 lb] of coke burn-off in the catalyst regenerator; 
or
    (ii) Emissions of nickel (Ni) from the catalyst regenerator vent on 
each catalytic cracking unit shall not exceed 13,000 milligrams/hour 
(mg/hr) [0.029 pound per hour (lb/hr)].
    (2) The concentration of carbon monoxide (CO) exiting the catalyst 
regenerator vent or CO boiler (if a CO boiler is used as the combustion 
device) shall not exceed 500 parts per million (ppm) by volume (dry 
basis).
    (b) Catalytic reforming unit regeneration. The owner or operator of 
a catalytic reforming unit shall comply with paragraphs (b)(1) through 
(b)(3) of this section.
    (1) During depressurization and purging, comply with the 
requirements in paragraphs (b)(1)(i) or (b)(1)(ii) of this section.
    (i) The owner or operator shall vent TOC emissions from the 
regenerator to a flare that meets the requirements for control devices 
in Sec. 63.11(b) of this part; or
    (ii) The owner or operator shall reduce uncontrolled emissions of 
TOC using a control device, by 98 percent by weight or to a 
concentration of 20 ppm by volume, on a dry basis, corrected to 3 
percent oxygen, whichever is less stringent. If a boiler or process 
heater is used to comply with the percent reduction requirement or 
concentration limit, the vent stream shall be introduced into the flame 
zone, or any other location that will achieve the required percent 
reduction or concentration.
    (iii) The control device requirements of paragraphs (b)(1)(i) and 
(b)(1)(ii) of this section do not apply to depressuring and purging 
operations at a differential pressure between the reactor vent and the 
gas transfer system to the control device of less than 1 pound per 
square inch gauge (psig) or if the reactor vent pressure is 1 psig or 
less.
    (2) During coke burn-off and catalyst regeneration, the owner or 
operator of a semi-regenerative catalytic reforming unit shall reduce 
uncontrolled emissions of HCl by 92 percent by weight using a control 
device, or to a concentration of 30 ppm by volume, on a dry basis, 
corrected to 3 percent oxygen; and
    (3) During coke burn-off and catalyst regeneration, the owner or 
operator of a cyclic or continuous catalytic reforming unit shall 
reduce uncontrolled emissions of HCl by 97 percent by weight using a 
control device, or to a concentration of 10 ppm by volume, on a dry 
basis, corrected to 3 percent oxygen.
    (c) Sulfur recovery units. The owner or operator of a sulfur 
recovery unit shall not discharge or cause to be discharged into the 
atmosphere any emissions of total reduced sulfur (TRS) compounds, 
expressed as an equivalent sulfur dioxide (SO2) 
concentration, in excess of 300 ppm by volume, on a dry basis, at zero 
percent oxygen.


Sec. 63.1563  Emission standards for new or reconstructed sources.

    (a) Catalytic cracking unit regeneration. The owner or operator of 
a catalytic cracking unit shall comply with the standards for existing 
affected sources in Sec. 63.1562(a) of this subpart.
    (b) Catalytic reforming unit regeneration. The owner or operator a 
catalytic reforming unit shall comply with the standards in paragraphs 
(b)(1) and (b)(2) of this section.
    (1) During depressurization and purging from semi-regenerative 
processes, comply with the standards for existing affected sources in 
Secs. 63.1562(b)(1)(i) or (b)(1)(ii) of this subpart; and
    (2) During coke burn-off and catalyst regeneration, reduce 
uncontrolled emissions of HCl from semi-regenerative, cyclic, or 
continuous processes by 97 percent by weight using a control device, or 
to a concentration of 10 ppm by volume, on a dry basis, corrected to 3 
percent oxygen.
    (c) Sulfur recovery units. The owner or operator shall comply with 
the standard for existing affected sources in Sec. 63.1562(c) of this 
subpart.


Sec. 63.1564  Compliance dates and performance tests.

    (a) Compliance dates. The owner or operator of a catalytic cracking 
unit, catalytic reforming unit, or sulfur recovery unit shall 
demonstrate initial compliance with the requirements of this subpart by 
the following dates:
    (1) [Insert date 3 years following the date of publication date of 
the final rule in the Federal Register] for an existing source unless 
an extension has been granted by the Administrator as provided in 
Sec. 63.6(i) of this part.
    (2) [Insert date of publication of final rule in the Federal 
Register] or upon initial startup, whichever is later, for a new source 
that commences construction or reconstruction after September 11, 1998.
    (b) Performance tests--catalytic cracking units. (1) During the 
first 150 days following the compliance date, the owner or operator 
shall conduct a performance test for each new or existing catalytic 
cracking unit to determine and demonstrate compliance with the PM or Ni 
emission standard using the test methods and procedures in Sec. 63.1566 
of this subpart.
    (2) During the first 150 days following the compliance date, the 
owner or

[[Page 48913]]

operator of a new or existing catalytic cracking unit that does not use 
a combustion device to comply with the CO emission standard and elects 
to comply with the continuous emission monitoring requirements of 
Sec. 63.1565(d)(1) of this subpart shall determine and demonstrate 
compliance according to the following procedures:
    (i) The owner or operator shall conduct a performance evaluation of 
the CO continuous emission monitoring system to determine and 
demonstrate compliance with the requirements of Performance 
Specification 4A in appendix B to part 60 of this chapter. The span 
value shall be 1,000 ppm CO. The performance evaluation shall be 
conducted according to the procedures in Sec. 63.8(e) of this part.
    (ii) Using the continuous emission monitoring system, the owner or 
operator shall measure and record the average hourly concentration of 
CO emissions from each catalytic cracking unit during 7 consecutive 
operating days. The data shall be reduced to 1-hour averages computed 
from four or more data points equally spaced over each 1-hour period. 
Compliance is demonstrated where the average hourly concentration is 
less than or equal to 500 ppm by volume (dry basis).
    (3) During the first 150 days following the compliance date, the 
owner or operator of a catalytic cracking unit that does not use a 
combustion control device and elects to comply with the operating 
parameter monitoring requirements of Sec. 63.1565(d)(2) of this 
subpart, shall conduct a performance test for each unit to determine 
and demonstrate compliance with the CO emission standard using the test 
methods and procedures in Sec. 63.1566 of this subpart.
    (4) During the first 150 days following the compliance date, the 
owner or operator of a new or existing catalytic cracking unit that 
uses a boiler or process heater with a design heat capacity less than 
44 megawatts (MW) where the vent stream is not introduced into the 
flame zone shall conduct a performance test for each unit to determine 
and demonstrate compliance with the TOC emission standard using the 
test methods and procedures in Sec. 63.1566 of this subpart.
    (c) Performance tests--catalytic reforming units. (1) During the 
first 150 days following the compliance date, the owner or operator of 
a new or existing cyclic or continuous catalytic reforming unit shall 
conduct a performance test for each unit to determine and demonstrate 
compliance with applicable TOC and HCl emission standards using the 
test methods and procedures in Sec. 63.1566 of this subpart.
    (2) At the first regeneration cycle following the compliance date, 
the owner or operator of a new or existing semi-regenerative catalytic 
reforming unit shall conduct an initial performance test for each unit 
to determine and demonstrate compliance with applicable TOC and HCl 
emission standards using the test methods and procedures in 
Sec. 63.1566 of this subpart.
    (3) The owner or operator of a new or existing catalytic reforming 
unit is not required to conduct a performance test to demonstrate 
compliance with the TOC percent reduction or concentration emission 
standards in Sec. 63.1562(b)(1)(ii) of this subpart when any of the 
following control devices are used:
    (i) Any boiler or process heater with a design heat input capacity 
of 44 MW or greater;
    (ii) Any boiler or process heater in which all vent streams are 
introduced into the flame zone; or
    (iii) Any flare that complies with the control device requirements 
in Sec. 63.11(b) of this part.
    (d) Performance tests--sulfur recovery units. During the first 150 
days following the compliance date, the owner or operator of a new or 
existing sulfur recovery unit shall conduct a performance test for each 
unit to determine and demonstrate compliance with the applicable 
emission standard for TRS compounds using the test methods and 
procedures in Sec. 63.1566 of this subpart.
    (e) Test conditions. Each performance test shall be conducted 
according to the requirements of Sec. 63.7(e) of this part except that 
performance tests shall be conducted at maximum representative 
operating capacity for the process. The owner or operator shall conduct 
the test while operating the control device at conditions which result 
in lowest emission reduction.
    (1) Each performance test shall consist of three separate runs. 
Compliance is demonstrated when the average of three runs is less than 
or equal to the applicable standard.
    (2) Data shall be reduced in accordance with the EPA-approved 
methods specified in Sec. 63.1566 of this subpart or, if other test 
methods are used, the data and methods shall be validated in accordance 
with the protocol in Method 301 of appendix A to this part.
    (f) Process/operating parameter range. The owner or operator of a 
new or existing catalytic cracking unit, catalytic reforming unit, or 
sulfur recovery unit shall establish a minimum and/or maximum operating 
value or procedure for each parameter to be monitored as required by 
Sec. 63.1565 of this subpart that ensures compliance with the 
applicable emission standard. To establish the minimum and/or maximum 
value, the owner or operator shall use the procedures in paragraphs 
(f)(1) through (f)(9) of this section, as applicable to the control 
device, and submit the information required by Sec. 63.1567(a)(6) in 
the notification of compliance status report.
    (1) For a thermal incinerator, the owner or operator shall measure 
and record the combustion zone temperature over the full period of the 
performance test, record each hourly or 1-hour block average value, and 
determine the minimum and average combustion zone temperature.
    (2) For a catalytic incinerator, the owner or operator shall 
measure the upstream and downstream temperatures and temperature 
difference across the catalyst bed over the full period of the 
performance test, record each hourly or 1-hour block average value, and 
determine the minimum and average upstream temperature and temperature 
difference across the catalyst bed.
    (3) For a boiler or process heater with a design heat capacity less 
than 44 MW where the vent stream is not introduced into the flame zone, 
the owner or operator shall measure the combustion zone temperature 
over the full period of the performance test, record each hourly or 1-
hour block average value, and determine the minimum and average 
combustion zone temperature.
    (4) For a flare, the owner or operator shall record the presence of 
a flame at the pilot light over the full period of the compliance 
determination.
    (5) For an electrostatic precipitator, the owner or operator shall 
measure the voltage and secondary current or the total power input over 
the full period of the performance test, record each hourly or 1-hour 
block average value, and determine the minimum and average hourly 
voltage and secondary current or total power input.
    (6) For a wet scrubber, the owner or operator shall measure the 
pressure drop across the scrubber, the gas flow rate, and the total 
water (or scrubbing liquid) flow rate to the scrubber over the full 
period of the performance test, record each hourly or 1-hour block 
average value, and determine the minimum and average pressure drop, the 
maximum and average gas flow rate, the minimum and average total water 
(or scrubbing liquid) flow rate, and the minimum and average liquid-to-
gas ratio.
    (7) For a catalytic cracking unit that does not use a combustion 
device where

[[Page 48914]]

the owner or operator elects to monitor operating parameters under 
Sec. 63.1565(d)(2) of this subpart, the owner or operator shall measure 
the temperature of the catalytic cracking unit and the oxygen content 
of the regenerator exhaust gas over the full period of the performance 
test, record each hourly or 1-hour block average value, and determine 
the minimum and average hourly temperature and oxygen content.
    (8) The owner or operator of a catalytic cracking unit catalyst 
regenerator subject to the PM emission standard in 
Sec. 63.1562(a)(1)(i) of this subpart shall determine and record the 
average coke burn-off rate (thousands of kg/hr) and the hours of 
operation for the unit.
    (9) For all control devices, the owner or operator shall record 
whether the flow indicator, if required, was operating and whether flow 
was detected at any time during each hour of the full period of the 
performance test.


Sec. 63.1565  Monitoring requirements.

    (a) Combustion control device. Except as provided in paragraph 
(a)(4) of this section, the owner or operator of a new or existing 
catalytic cracking unit, catalytic reforming unit, or sulfur recovery 
unit that uses a combustion control device to comply with the emission 
standards of this subpart shall install, operate, and maintain the 
monitoring equipment specified in paragraph (a)(1), (a)(2), or (a)(3) 
of this section, depending on the type of combustion control device 
used.
    (1) Where an incinerator is used:
    (i) For each thermal incinerator, a measurement device equipped 
with a continuous recorder to measure and record the daily average 
combustion zone temperature. The measurement device shall be installed 
in the combustion zone or in the ductwork immediately downstream of the 
combustion zone in a position before any substantial heat exchange 
occurs; or
    (ii) For each catalytic incinerator, a measurement device equipped 
with a continuous recorder to measure and record the daily average 
upstream temperature and temperature difference across the catalyst 
bed. The measurement devices shall be installed in the gas stream 
immediately before and after the catalyst bed.
    (iii) The accuracy of the temperature measurement device shall be 
1 percent of the temperature being measured, expressed in 
degrees Celsius (C) or 0.5 deg.C, whichever is greater.
    (iv) The owner or operator shall verify the calibration of the 
temperature measurement device every 3 months.
    (2) Where a flare is used, a device (including but not limited to a 
thermocouple, an ultraviolet beam sensor, or an infrared sensor) that 
continuously detects the presence of a pilot flame. The owner or 
operator shall record, for each 1-hour period, whether the monitor was 
continuously operating and whether a pilot flame was continuously 
present during each hour.
    (3) Where a boiler or process heater with a design heat capacity 
less than 44 MW where the vent stream is not introduced into the flame 
zone is used, a measurement device equipped with a continuous recorder 
to measure and record the daily average combustion zone temperature.
    (i) The accuracy of the temperature measurement device shall be 
1 percent of the temperature being measured, expressed in 
degrees C or 0.5 deg.C, whichever is greater.
    (ii) The owner or operator shall verify the calibration of the 
temperature measurement device every 3 months.
    (4) Any boiler or process heater with a design heat capacity 
greater than or equal to 44 MW or any boiler or process heater in which 
all vent streams are introduced into the flame zone is exempt from the 
monitoring requirements in this paragraph.
    (b) Catalytic cracking unit--electrostatic precipitator. The owner 
or operator of a new or existing catalytic cracking unit that uses an 
electrostatic precipitator to comply with the emission standards of 
this subpart shall install, operate, and maintain a measurement device 
equipped with a continuous recorder to measure and record the average 
hourly voltage and secondary current or the average hourly total power 
input.
    (c) Catalytic cracking unit/catalytic reforming unit--scrubber. The 
owner or operator of a new or existing catalytic cracking unit or 
catalytic reforming unit that uses a wet scrubber to comply with the 
emission standards of this subpart shall install, calibrate, operate, 
and maintain:
    (1) A measurement device equipped with a continous recorder to 
measure and record the average daily pressure drop across the scrubber, 
the average daily gas flow rate to the scrubber, and the average daily 
total water (or scrubbing liquid) flow rate to the scrubber.
    (i) The pressure drop monitor is to be certified by the 
manufacturer to be accurate within 250 pascals 
(1 inch water gauge) over its operating range. The flow 
rate monitors are to be certified by their manufacturers to be accurate 
within 5 percent over their operating ranges.
    (ii) The owner or operator shall verify the calibration of the 
pressure drop and flow rate monitors every 3 months.
    (2) The owner or operator shall calculate and record the daily 
average liquid-to-gas ratio.
    (d) Catalytic cracking unit--no combustion device. Each owner or 
operator of a new or existing catalytic cracking unit regenerator that 
does not use a combustion device to comply with the CO emission 
standard in Sec. 63.1562(a)(2) of this subpart shall install, 
calibrate, operate, and maintain a continuous emission monitoring 
system as described in paragraph (d)(1) of this section or a continous 
parameter monitoring system as described in paragraph (d)(2) of this 
section.
    (1) The owner or operator shall install, operate, calibrate, and 
maintain a continuous emission monitoring system to measure and record 
the concentration of CO in the exhaust gases of each catalytic cracking 
unit regenerator vent and determine the hourly average concentration in 
ppm by volume (dry basis) of CO emissions into the atmosphere.
    (i) The continuous emission monitoring system shall meet the 
requirements of Performance Specification 4A in part 60 of this 
chapter. The span value for this system is 1,000 ppm CO.
    (ii) Each continuous emission monitoring system shall complete a 
minimum of one cycle of operation (sampling, analyzing, and data 
recording) for each successive 15-minute period.
    (iii) The owner or operator shall operate and maintain each 
continuous emission monitoring system in accordance with the 
requirements of Sec. 63.8 of this part and the quality assurance 
procedures in appendix F to part 60 of this chapter.
    (2) The owner or operator shall install, calibrate, operate, and 
maintain:
    (i) A measurement device equipped with a continuous recorder to 
measure and record the average hourly temperature of the catalytic 
cracking unit regeneration unit exhaust gas; and
    (ii) A measurement device equipped with a continuous recorder to 
measure and record the average hourly oxygen content of the regenerator 
exhaust gas.
    (iii) The accuracy of the temperature measurement device shall be 
1 percent of the temperature being measured, expressed in 
degrees C or 0.5 deg.C, whichever is greater. The accuracy 
of the oxygen sensor shall be 1 percent over its operating 
range.

[[Page 48915]]

    (iv) The owner or operator shall verify the calibration of the 
temperature and oxygen measurement devices every 3 months.
    (3) The monitoring requirements in paragraphs (d)(1) and (d)(2) of 
this section do not apply if the owner or operator demonstrates that 
the average CO emissions are less than 50 ppm by volume (dry basis) and 
also files a written request for exemption with the applicable 
permitting authority and receives such an exemption. The demonstration 
shall consist of continuously monitoring CO emissions for 30 days using 
an instrument that meets the requirements of Performance Specification 
4A of appendix B to part 60 of this chapter. The span value shall be 
100 ppm CO instead of 1,000 ppm, and the relative accuracy limit shall 
be 10 percent of the average CO emissions or 5 ppm CO, whichever is 
greater. For instruments that are identical to Method 10 in appendix A 
to part 60 of this chapter and employ the sample conditioning system of 
Method 10A in appendix A to part 60 of this chapter, the alternative 
relative accuracy test procedure in section 10.1 of Performance 
Specification 2 of appendix B to part 60 of this chapter may be used in 
place of the relative accuracy test.
    (e) Catalytic cracking unit catalyst regenerator. The owner or 
operator of a catalytic cracking unit catalyst regenerator subject to 
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart shall 
calculate the daily average coke burn-off rate (thousands of kg/hr) 
using the calculation procedure in Sec. 63.1566(a)(3) of this subpart 
(Test methods and procedures) and record the information specified in 
Sec. 63.1567(e)(4)(xii) of this subpart (Notification, reporting, and 
recordkeeping requirements). For purposes of daily average coke burn-
off calculations, the exhaust gas flow can be calculated from process 
data.
    (f) Catalytic cracking unit--no electrostatic precipitator or 
scrubber. An owner or operator of a new or existing catalytic cracking 
unit that does not use an electrostatic precipitator or scrubber to 
comply with the PM or Ni emission standards in Sec. 63.1562(a)(1) of 
this subpart shall include, subject to approval of the applicable 
permitting authority, a recommended continuous parameter monitoring 
system for each affected source in the part 70 or part 71 permit 
application. Each application shall include the information required in 
Sec. 63.1567(a)(6)(v)(B) of this subpart (Notification, reporting, and 
recordkeeping requirements).
    (g) Sulfur recovery unit--no combustion device. The owner or 
operator of a new or existing sulfur recovery unit that does not use a 
combustion device to comply with the TRS emission standard in 
Sec. 63.1562(c) of this subpart shall include, subject to approval by 
the applicable permitting authority, a recommended continuous parameter 
monitoring system for each affected source in the part 70 or part 71 
permit application. Each application shall include the information 
required in Sec. 63.1567(a)(6)(v)(B) of this subpart (Notification, 
reporting, and recordkeeping requirements).
    (h) Bypass line. The owner or operator of a new or existing 
catalytic cracking unit, catalytic reforming unit, or sulfur recovery 
unit using a vent system that contains a bypass line that could divert 
a vent stream away from the control device used to comply with the 
emission limits in this subpart shall comply with the requirements of 
either paragraph (h)(1) or (h)(2) of this section. Equipment such as 
low leg drains, high point bleed, analyzer vents, open-ended valves or 
lines, or pressure relief valves needed for safety reasons are not 
subject to the requirements of this paragraph.
    (1) Install, calibrate, operate, and maintain a flow indicator. The 
device shall be installed at the entrance to any bypass line that could 
divert the vent stream away from the control device to the atmosphere. 
The owner or operator shall visually inspect the flow indicator at 
least once every hour to determine that the flow indicator is operating 
properly and whether gas or vapor are present in the bypass line and 
record the information specified in Sec. 63.1567(e)(4)(x) of this 
subpart (Notification, reporting, and recordkeeping requirements); or
    (2) Secure the bypass line valve in the closed position with a car-
seal or a lock-and-key type configuration. The device shall be placed 
on the mechanism by which the bypass device position is controlled 
(e.g., valve handle, damper level) when the bypass device is in the 
closed position such that the bypass line valve cannot be opened 
without breaking the seal or removing the device. The owner or operator 
shall visually inspect the seal or closure mechanism at least once 
every month to ensure that the valve is maintained in the closed 
position and the vent stream is not diverted through the bypass line, 
and record the information specified in Sec. 63.1567(e)(4)(x) of this 
subpart (Notification, reporting, and recordkeeping requirements).
    (i) Installation, calibration, operation, and maintenance of 
monitoring systems and devices. All continuous parameter monitoring 
systems and devices required or allowed by this section shall be 
installed, calibrated, maintained, and operated according to 
manufacturer's specifications or according to other written procedures 
that provide adequate assurance that the equipment will monitor 
accurately.
    (j) Averaging times for continuous parameter monitoring systems. 
Each continuous parameter monitoring system shall measure data values 
at least once every hour and record either:
    (1) Each measured data value; or
    (2) Block average values for each 1-hour period or shorter periods 
calculated from all measured data values during each period. If values 
are measured more frequently than once per minute, a single value for 
each minute may be used to calculate the hourly (or shorter period) 
block average instead of all measured values.
    (3) Daily averages shall be calculated as the average of all values 
for a monitored parameter recorded during the operating day. The 
average shall cover a 24-hour period if operation is continuous or the 
number of hours of operation per day if operation is not continuous.
    (4) Monitoring data recorded during periods of unavoidable 
monitoring system breakdowns, repairs, calibration checks, and zero 
(low-level) and high-level adjustments; startup, shutdowns, and 
malfunctions; and periods of nonoperation of the process unit resulting 
in cessation of the emissions to which the monitoring applies shall not 
be included in any average computed under this subpart.
    (k) Operation of control device. The owner or operator of a new or 
existing affected source equipped with a control device subject to the 
monitoring provisions of this section shall operate the control device 
above or below, as appropriate, the minimum or maximum value specified 
in the notification of compliance status report.
    (l) Parameter changes. (1) The owner or operator may change the 
established level of control device or process operating parameters by 
conducting additional performance tests to verify that, at the new 
control device or process parameter level, the owner or operator is in 
compliance with the applicable emission standard in Secs. 63.1562 or 
63.1563 of this subpart.
    (2) The owner or operator shall conduct a new performance test to 
establish a revised minimum or maximum value for the monitored process 
or operating parmeter to determine and demonstrate compliance under the 
new operating conditions if any change to the process or operating

[[Page 48916]]

conditions (including but not limited to feedstock, capacity, control 
device or capture system) that could result in a change in the control 
system performance or designated conditions has been made since the 
last performance or compliance tests were conducted.
    (m) Alternative parameters. (1) The owner or operator of a 
catalytic cracking unit, catalytic reforming unit, or sulfur recovery 
unit may request approval to monitor parameters other than those listed 
in paragraphs (a) through (d) of this section. The request shall be 
submitted according to the procedures specified in paragraph (m)(2) of 
this section. Approval shall be requested if the owner or operator:
    (i) Uses a control device other than an incinerator, boiler, 
process heater, flare, electrostatic precipitator, or scrubber;
    (ii) Uses one of the control devices listed in paragraphs (a) 
through (c) of this section, but seeks to monitor a parameter other 
than those specified in paragraphs (a) through (d) of this section; or
    (iii) Uses no control device or a control method, such as 
pretreatment, rather than an add-on control device.
    (2) To apply for use of alternative monitoring parameters, the 
owner or operator shall submit a request for review and approval or 
disapproval by the applicable permitting authority. The submittal shall 
include:
    (i) A description of each affected source and the parameter(s) to 
be monitored to determine whether periods of excess emissions occur, as 
defined in paragraph (o) of this section, and an explanation of the 
criteria used to select the parameter(s);
    (ii) A description of the methods and procedures that will be used 
to demonstrate that the parameter can be used to determine excess 
emissions and the schedule for this demonstration. The owner or 
operator must certify that he/she will establish a minimum and/or 
maximum value, as applicable, for the monitored parameter(s) that 
represents the conditions in existence when the control device is being 
properly operated and maintained; and
    (iii) The frequency and content of monitoring, recording, and 
reporting, if monitoring and recording are not continuous. The 
rationale for the proposed monitoring, recording, and reporting system 
shall be included.
    (n) Automated data compression system. The owner or operator may 
request approval to use an automated data compression system that does 
not record monitored operating parameter values at a set frequency 
(e.g., once every hour) but records all values that meet set criteria 
for variation from previously recorded values.
    (1) The requested system shall be designed to:
    (i) Measure the operating parameter value at least once every hour;
    (ii) Record at least 24 values each day during periods of 
operation;
    (iii) Record the date and time when monitors are turned off or on;
    (iv) Recognize unchanging data that may indicate the monitor is not 
functioning properly, alert the operator, and record the incident; and
    (v) Compute daily average values of the monitored operating 
parameter based on recorded data.
    (2) The request shall contain a description of the monitoring 
system and data recording system including the criteria used to 
determine which monitored values are recorded and retained, the method 
for calculating daily averages, and a demonstration that the system 
meets all criteria of paragraph (j)(1) of this section.
    (o) Excess emissions. (1) Period of excess emissions means any of 
the following conditions:
    (i) For a thermal incinerator, an operating day when the daily 
average temperature falls below the minimum value specified in the 
notification of compliance status report;
    (ii) For a catalytic incinerator, an operating day when the daily 
average upstream temperature or the daily average temperature 
difference across the catalyst bed falls below the minimum value 
specified in the notification of compliance status report;
    (iii) For a boiler or process heater with a design heat capacity 
less than 44 MW where the vent stream is not introduced into a flame 
zone, an operating day when the daily average temperature falls below 
the minimum value specified in the notification of compliance status 
report;
    (iv) For an electrostatic precipitator, any period when the average 
hourly voltage or secondary current or the average hourly total power 
input falls below the minimum value specified in the notification of 
compliance status report;
    (v) For a wet scrubber, an operating day when the daily average 
pressure drop or daily average liquid-to-gas ratio falls below the 
minimum value specified in the notification of compliance status 
report;
    (vi) For a catalytic cracking unit with no combustion device, any 
period when the average hourly CO concentration measured by the CO 
continuous emission monitoring system required by paragraph (d)(1) of 
this section exceeds 500 ppmv or any period when the average hourly 
temperature or oxygen content falls below the minimum value specified 
in the notification of compliance status report;
    (vii) For a catalytic cracking unit catalyst regenerator subject to 
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart, an 
operating day when the daily average coke burn-off rate exceeds the 
value specified in the notification of compliance status report;
    (viii) An operating day when all pilot flames of a flare are 
absent;
    (ix) An operating day when monitoring data are available for less 
than 75 percent of the operating hours;
    (x) For data compression systems approved under paragraph (n) of 
this section, an operating day when the monitor operated for less than 
75 percent of the operating hours or a day when less than 18 monitoring 
values were recorded; or
    (xi) A period when flow to the control device is diverted or 
otherwise by-passed.
    (2) Multiple excursions from the same control device during the 
applicable averaging period (e.g. 1-hour, 24-hours) constitutes a 
single excursion.
    (p) Violation. Monitoring data under this subpart are directly 
enforceable to determine compliance with the required operating 
conditions for the monitored control devices. For each period of excess 
emissions, as defined in paragraph (o) of this section, the owner or 
operator shall be deemed to have failed to have applied the control in 
a manner that achieves the required operating conditions. More than one 
exceedance or excursion by the same control device during a semi-annual 
reporting period is a violation of this subpart.


Sec. 63.1566  Test methods and procedures.

    (a) The owner or operator of a catalytic cracking unit shall 
determine compliance with the PM emission standard in 
Sec. 63.1562(a)(1)(i) of this subpart as follows:
    (1) The emission rate (E) of PM shall be computed for each run 
using Equation 1:
[GRAPHIC] [TIFF OMITTED] TP11SE98.022

where,

E = Emission rate of PM, kg/1,000 kg (lb/1,000 lb) of coke burn-off;
Cs = Concentration of PM, g/dscm (lb/dscf);
Qsd = Volumetric flow rate of effluent gas, dscm/hr (dscf/
hr);
Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr); and
K = Conversion factor, 1.0 (kg2/g)/(1,000 kg) [1,000 lb/
(1,000 lb)].


[[Page 48917]]


    (2) Method 5B or 5F in appendix A to part 60 of this chapter is to 
be used to determine PM emissions and associated moisture content from 
affected facilities without wet flue gas desulfurization (FGD) systems; 
only Method 5B in appendix A to part 60 of this chapter is to be used 
after wet FGD systems. The sampling time for each run shall be at least 
60 minutes and the sampling rate shall be at least 0.015 dscm/min (0.53 
dscf/min), except that shorter sampling times may be approved by the 
permitting authority when process variables or other factors preclude 
sampling for at least 60 minutes.
    (3) The coke burn-off rate (Rc) shall be computed for 
each run using Equation 2:
[GRAPHIC] [TIFF OMITTED] TP11SE98.023

Where,

Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from catalyst 
regenerator before additional air or gas streams are added (e.g., 
measurements may be made after an ESP, but must be made before a CO 
boiler), dscm/min (dscf/min);
Qa = Volumetric flow rate of air to regenerator, as 
determined from the catalytic cracking unit control room 
instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in regenerator exhaust, 
percent by volume (dry basis);
%CO = Carbon monoxide concentration in regenerator exhaust, percent by 
volume (dry basis);
%O2 = Oxygen concentration in regenerator exhaust, percent 
by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/
(hr-dscm-%) [0.1303 (lb-min)/(hr-dscf-%)];
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) [(0.0062 (lb-min)/(hr-dscf-%)];
Qoxy = Volumetric flow rate of oxygen-enriched air stream to 
regenerator, as determined from the catalytic cracking unit control 
room instrumentation, dscm/min (dscf/min); and
%Oxy = Oxygen concentration in oxygen-enriched air stream, 
percent by volume (dry basis).

    (i) Method 2 in appendix A to part 60 of this chapter shall be used 
to determine the volumetric flow rate (Qr) for a performance 
test; for daily calculations, the volumetric flow rate can be 
determined using process data.
    (ii) The emission correction factor, integrated sampling and 
analysis procedure of Method 3 in appendix A to part 60 of this chapter 
shall used to determine CO2, CO, and O2 
concentrations.
    (b) The owner or operator shall determine compliance with the Ni 
standard in Sec. 63.1562(a)(1)(ii) of this subpart using the procedures 
in paragraphs (b)(1) through (b)(3) of this section.
    (1) Method 29 in appendix A to part 60 of this chapter shall be 
used to determine the concentration of Ni in the catalytic cracking 
unit catalyst regenerator flue gas. The sampling time for each run 
shall be at least 60 minutes and the sampling rate shall be at least 
0.014 dscm/min (0.5 dscf/min).
      
    (2) Method 2 in appendix A to part 60 of this chapter shall be used 
to determine volumetric flow rate (Qsd).
    (3) The mass emission rate (ENi) shall be computed for 
each run using Equation 3:
[GRAPHIC] [TIFF OMITTED] TP11SE98.024

Where,

ENi = Mass emission rate of Ni, mg/hr (lb/hr);
CNi = Ni concentration in the catalytic cracking unit 
catalyst regenerator flue gas as measured by Method 29 in appendix A to 
part 60 of this chapter, mg/dscm (lbs/dscf); and
Qsd = Volumetric flow rate of the catalytic cracking unit 
catalyst regenerator flue gas as measured by Method 2 in appendix A to 
part 60 of this chapter, dscm/hr (dscf/hr).

    (c) The owner or operator shall determine compliance with the CO 
emission standard in Sec. 63.1562(a)(2) of this subpart by using the 
integrated sampling technique of Method 10 in appendix A to part 60 of 
this chapter to determine the CO concentration (dry basis). The 
sampling time for each run shall be 60 minutes.
    (d) The owner or operator of a catalytic reforming unit using a 
flare to comply with the TOC emission standard in Sec. 63.1562(b)(1) of 
this subpart shall determine compliance with the visible emission 
standard as required by Sec. 63.11(b)(4) of this part using Method 22 
in appendix A to part 60 of this chapter.
    (e) Except as provided in the performance test provisions for 
catalytic reforming units in Sec. 63.1564(c)(3) of this subpart and in 
paragraph (i) of this section, the owner or operator shall determine 
compliance with the 98 percent reduction standard for TOC in 
Sec. 63.1562(b)(1)(ii) of this subpart by measuring emissions at the 
inlet and at the outlet of the control device to determine percent 
reduction using the following test methods and procedures:
    (1) Methods 1 or 1A in appendix A to part 60 of this chapter shall 
be used for selection of the sampling site.
    (2) No traverse site selection method is needed for vents smaller 
than 0.10 meter in diameter.
    (3) The gas volumetric flow rate shall be determined using Methods 
2, 2A, 2C, or 2D in appendix A to part 60 of this chapter, as 
appropriate.
    (4) Method 18 or Method 25A in appendix A to part 60 of this 
chapter shall be used to measure TOC concentration. Alternatively, any 
other method or data that has been validated according to the protocol 
in Method 301 of appendix A of this part may be used. The following 
procedures shall be used to calculate ppm by volume concentration:
    (i) The minimum sampling time for each run shall be 1 hour in which 
either an integrated sample or four grab samples shall be taken. If 
grab sampling is used, then the samples shall be taken at approximately 
equal intervals in time, such as 15-minute intervals during the run;
    (ii) The TOC concentration (CTOC) is the sum of the 
concentrations of the individual components and shall be computed for 
each run using Equation 4 if Method 18 is used:
[GRAPHIC] [TIFF OMITTED] TP11SE98.025

Where,

CTOC = Concentration of TOC (minus methane and ethane), dry 
basis, parts per million by volume;
Cji = Concentration of sample component j of the sample i, 
dry basis, parts per million by volume;
n = Number of components in the sample; and

[[Page 48918]]

x = Number of samples in the sample run.

    (5) The emission rate of TOC minus methane and ethane 
(ETOC) shall be calculated using Equation 5 if Method 18 in 
appendix A to part 60 of this chapter is used:
[GRAPHIC] [TIFF OMITTED] TP11SE98.026

Where,

E = Emission rate of TOC (minus methane and ethane) in the sample, 
kilograms per hour;
K2 = Constant, 2.494  x  10-6 (parts per 
million)-1 (gram-mole per standard cubic meter) (kilogram 
per gram) (minutes per hour), where the standard temperature (standard 
cubic meter) is at 20 deg.C;
Cj = Concentration on a dry basis of organic compound j in 
ppm as measured by Method 18 in appendix A to part 60 of this chapter. 
Cj includes all organic compounds measured minus methane and 
ethane;
Mj = Molecular weight of organic compound j, gram per gram-
mole; and
Qs = Vent stream flow rate, dry standard cubic meters per 
minute, at a temperature of 20  deg.C.

    (6) If Method 25A in appendix A to part 60 of this chapter is used 
the emission rate of TOC (ETOC ) shall be calculated using 
Equation 6:
[GRAPHIC] [TIFF OMITTED] TP11SE98.027

Where,

E = Emission rate of TOC (minus methane and ethane) in the sample, 
kilograms per hour;
K3 = Constant, 2.64  x  10-3 (parts per 
million)-1 (gram-mole per standard cubic meter) (gram per 
gram-mole) (kilogram per gram) (minutes per hour), where the standard 
temperature (standard cubic meter) is at 20 deg.C;
CTOC = Concentration of TOC on a dry basis in ppm by volume 
as propane as measured by Method 25A in appendix A to part 60 of this 
chapter, as indicated in paragraph (f)(4) of this section; and
Qs = Vent stream flow rate, dry standard cubic meters per 
minute, at a temperature of 20  deg.C.

    (f) Except as provided in the performance test provisions for a 
catalytic reforming unit in Sec. 63.1564(c)(3) of this subpart and 
paragraph (i) of this section, the owner or operator shall determine 
compliance with the requirements for a TOC limit of 20 ppm in 
Sec. 63.1562(b)(1)(ii) of this subpart by sampling at the outlet of the 
control device using Methods 18 or 25A in appendix A to part 60 of this 
chapter and the procedures in paragraph (e)(4) of this section to 
determine concentration.
    (g) The owner or operator shall determine compliance with the TRS 
standards in Secs. 63.1562(c) and 63.1563(c) of this subpart as 
follows:
    (1) Method 15 of appendix A to part 60 of this chapter shall be 
used to determine the concentration of TRS. Each run shall consist of 
16 samples taken over a minimum 3 hours. The sampling point in the duct 
shall be the centroid of the cross section if the cross-sectional area 
is less than 5 square meters (m2) or 54 square feet 
(ft2) or at a point no closer to the walls than 1 meter (m) 
or 39 inches (in) if the cross-sectional area is 5 m2 or 
more and the centroid is more than 1 m from the wall. To ensure minimum 
residence time for the sample inside the sample lines, the sampling 
rate shall be at least 3 liters per minute (lpm) or 0.10 cubic feet per 
minute (cfm). The SO2 equivalent for each run shall be 
calculated after being corrected for moisture and oxygen as the 
arithmetic average of the SO2 equivalent for each sample during the 
run.
    (2) Method 4 of appendix A to part 60 of this chapter shall be used 
to determine the moisture content of the gases. The sampling time for 
each sample shall be equal to the time it takes for four Method 15 
samples.
    (3) The oxygen concentration used to correct the emission rate for 
excess air shall be obtained by the integrated sampling and analysis 
procedure of Method 3 in appendix A to part 60 of this chapter. The 
samples shall be taken simultaneously with reduced sulfur or moisture 
samples. The reduced sulfur samples shall be corrected to zero percent 
excess air using Equation 7:
[GRAPHIC] [TIFF OMITTED] TP11SE98.028

Where,

Cadj = pollutant concentration adjusted to zero percent 
oxygen, ppm or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm 
or g/dscm;
20.9c = 20.9 percent oxygen--0.0 percent oxygen (defined 
oxygen correction basis), percent;
20.9 = oxygen concentration in air, percent; and
%O2 = oxygen concentration measured on a dry basis, percent.

    (h) The owner or operator shall determine compliance with the HCl 
emission standards in Secs. 63.1562(b)(2) and (b)(3) and 
Sec. 63.1563(b)(2) of this subpart using Method 26A in appendix A to 
part 60 of this chapter. To determine percent reduction, sampling shall 
be performed at the inlet and at the outlet of the control device. The 
sampling time for each run shall be at least 60 minutes and the 
sampling rate shall be at least 0.021 dscm/min (0.74 dscf/min).
    (i) Engineering assessment may be used to determine the emission 
reduction or outlet concentration for the representative operating 
condition expected to yield the highest daily emission rate. 
Engineering assessment includes, but is not limited to, the following:
    (1) Previous test results provided the tests are representative of 
current operating practices at the process unit;
    (2) Bench-scale or pilot-scale test data representative of the 
process under representative operating conditions;
    (3) TOC emission rate specified or implied within a permit limit 
applicable to the process vent;
    (4) Design analysis based on accepted chemical engineering 
principles, measurable process parameters, or physical or chemical laws 
or properties. Examples of analytical methods include, but are not 
limited to:
    (i) Use of material balances based on process stoichiometry to 
estimate maximum TOC concentrations;
    (ii) Estimation of maximum flow rate based on physical equipment 
design such as pump or blower capacities; and
    (iii) Estimation of TOC concentrations based on saturation 
conditions.
    (5) Engineering assessments based on approaches other than those 
listed above shall be subject to review and approval by the applicable 
permitting authority.
    (6) All data, assumptions, and procedures used in the engineering 
assessment shall be documented to the satisfaction of the applicable 
permitting authority.
    (j) The owner or operator may use an alternative test method 
subject to approval by the Administrator.


Sec. 63.1567  Notification, reporting, and recordkeeping requirements.

    (a) Notifications. The owner or operator shall submit written 
initial notifications to the applicable permitting authority as 
described in paragraphs (a)(1) through (a)(7) of this paragraph:
    (1) As required by Sec. 63.9(b)(1) of this part, the owner or 
operator shall provide notification for an area source that 
subsequently increases its emissions such that the source is a major 
source subject to the standard.

[[Page 48919]]

    (2) As required by Sec. 63.9(b)(3) of this part, the owner or 
operator of a new or reconstructed affected source, or a source that 
has been reconstructed such that it is an affected source, that has an 
initial startup after the effective date of this subpart and for which 
an application for approval or construction or reconstruction is not 
required under Sec. 63.5(d) of this part, shall provide notification 
that the source is subject to the standard. The notification shall 
contain the general information required for the notification of 
compliance status in paragraph (a)(6)(i) of this section.
    (3) As required by Sec. 63.9(b)(4) of this part, the owner or 
operator of a new or reconstructed major affected source that has an 
initial startup after the effective date of this subpart and for which 
an application for approval of construction or reconstruction is 
required by Sec. 63.5(d) of this part shall provide the following 
notifications:
    (i) Notification of intention to construct a new major affected 
source, reconstruct a major source, or reconstruct a major source such 
that the source becomes a major affected source;
    (ii) Notification of the date when construction or reconstruction 
was commenced (submitted simultaneously with the application for 
approval of construction or reconstruction if construction or 
reconstruction was commenced before the effective date of this subpart 
or no later than 30 days of the date construction or reconstruction 
commenced if construction or reconstruction commenced after the 
effective date of this subpart);
    (iii) Notification of the anticipated date of startup; and
    (iv) Notification of the actual date of startup.
    (4) As required by Sec. 63.9(b)(5) of this part, after the 
effective date of this subpart, an owner or operator who intends to 
construct a new affected source or reconstruct an affected source 
subject to this subpart, or reconstruct a source such that it becomes 
an affected source subject to this subpart shall provide notification 
of the intended construction or reconstruction. The notification shall 
include all the information required for an application for approval of 
construction or reconstruction as required by Sec. 63.5(d) of this 
part. For major sources, the application for approval of construction 
or reconstruction may be used to fulfill these requirements.
    (i) The application shall be submitted as soon as practicable 
before the construction or reconstruction is planned to commence (but 
no sooner than the effective date) if the construction or 
reconstruction commences after the effective date of this subpart; or
    (ii) The application shall be submitted as soon as practicable 
before startup but no later than 90 days after the effective date of 
this subpart if the construction or reconstruction had commenced and 
initial startup had not occurred before the effective date.
    (5) As required by Secs. 63.9(e) and 63.9(f) of this part, the 
owner or operator shall provide notification of the anticipated date 
for conducting performance tests and visible emission observations for 
flares. The owner or operator shall notify the Administrator of the 
intent to conduct a performance test or perform visible emission 
observations to determine compliance with flare requirements at least 
30 days before the test is scheduled.
    (6) Each owner or operator of a source subject to this subpart 
shall submit a notification of compliance status report within 150 days 
after the compliance dates specified in Sec. 63.1564(a) of this 
subpart. The notification shall be signed by the responsible official 
who shall certify its accuracy. A complete notification compliance 
status report shall include the information in paragraphs (a)(6)(i) 
through (a)(6)(vii) of this section. This information may be submitted 
in an operating permit application, in an amendment to an operating 
permit application, in a separate submittal, or in any combination. In 
a State with an approved operating permit program where delegation of 
authority under section 112(l) of the Act has not been requested or 
approved, the owner or operator shall provide a duplicate notification 
to the applicable Regional Administrator. If the required information 
has been submitted before the date 150 days after the compliance date 
specified in Sec. 63.1564(a) of this subpart, a separate notification 
of compliance status report is not required. If an owner or operator 
submits the information specified in paragraphs (a)(6)(i) through 
(a)(6)(vii) of this section at different times or in different 
submittals, later submittals may refer to earlier submittals instead of 
duplicating and resubmitting the previously submitted information.
    (i) General information:
    (A) The name and address of the owner or operator;
    (B) The address (i.e., physical location) of the affected source;
    (C) An identification of the relevant standard, or other 
requirement, that is the basis of the notification and the source's 
compliance date; and
    (D) A statement of whether the source is a major source or an area 
source. If the facility is an area source, the remaining informational 
requirements in this paragraph are not applicable.
    (ii) A brief description of each affected source, including:
    (A) The nature, size, design, and method of operation;
    (B) Operating design capacity; and
    (C) Identification of each point of emission for each HAP, or if a 
definitive identification is not yet possible, a preliminary 
identification of each point of emission for each HAP.
    (iii) A brief description of each affected source not subject to 
the monitoring requirements of this subpart, including:
    (A) Identification of any boiler or process heater with a design 
heat input capacity greater than or equal to 44 MW or any boiler or 
process heater in which all vent streams are introduced into the flame 
zone for which monitoring is not required;
    (B) Identification of any catalytic cracking unit regenerator that 
does not use a combustion device to comply with CO emission standard in 
Sec. 63.1562(a)(2) of this subpart for which monitoring is not 
required, including CO emission monitoring data and quality assurance 
test results as described in Sec. 63.1564(b)(2) of this subpart, a copy 
of the exemption approved by the applicable permitting authority, and 
information and data demonstrating that the average CO emissions are 
less than 50 ppm by volume as required by Sec. 63.1565(d)(3) of this 
subpart; and
    (C) Identification of each catalytic reforming unit for which 
control device requirements do not apply due to depressuring and 
purging operations at a differential pressure between the reactor vent 
and the gas transfer system to the control device of less than 1 psig 
or when the reactor vent pressure is 1 psig or less.
    (iv) A description of the air pollution control equipment or method 
of compliance for each affected source, including the PM or Ni emission 
standard selected under Sec. 63.1562(a) and the catalytic cracking unit 
and sulfur recovery unit emission standards and requirements selected 
under Sec. 63.1560(d) of this subpart (Applicability and designation of 
sources).
    (v) The methods used to determine compliance for each affected 
source, including:
    (A) The engineering assessment specified in Sec. 63.1566(i) of this 
subpart or the results of the performance test specified in 
Sec. 63.1564 of this subpart. Performance test results shall include 
operating ranges of key process and control parameters during the

[[Page 48920]]

performance test; the value, averaged over the period of the 
performance test, of each parameter identified in the operating permit 
as being monitored in accordance with Sec. 63.1565 of this subpart; and 
applicable supporting calculations;
    (B) The minimum and/or maximum parameter value, as applicable for 
each monitored parameter for each emission point and the data and 
rationale used to develop the range, including any data and 
calculations used to develop the value and a description of why the 
value indicates proper operation of the control device. For any 
recommended continuous parameter monitoring system for a catalytic 
cracking unit that does not use an electrostatic precipitator or 
scrubber to comply with the PM or Ni emission standard in 
Sec. 63.1562(a)(1) of this subpart or a sulfur recovery unit that does 
not use a combustion device to comply with the TRS emission standard in 
Sec. 63.1562(c) of this subpart, the owner or operator shall provide 
data and rationale for the recommended system. Following approval of 
the recommended system by the permitting authority, the owner or 
operator shall provide the information described in this paragraph for 
each monitored parameter;
    (C) The definition of ``operating day'' for each incinerator, 
flare, boiler or process heater with a design input capacity less than 
44 MW where the vent stream is not introduced into the flame zone, and 
catalytic cracking unit or catalytic reforming unit using a scrubber 
for the purpose of determining daily average values of monitored 
parameters. The definition, subject to approval by the applicable 
permitting authority, shall specify the times at which an operating day 
begins and ends; it may be from midnight to midnight or another daily 
period; and
    (D) If a flare is used to comply with the TOC standards in 
Sec. 63.1562(b)(1) of this subpart, the flare design (e.g., steam-
assisted, air-assisted, or non-assisted), all visible emission 
readings, heat content determinations, flow rate measurements, and exit 
velocity determinations made during the compliance determination and 
all periods when the pilot flame is absent.
    (vi) Operation, maintenance, and monitoring information, including:
    (A) A description of the method that will be used for determining 
continuing compliance for each affected source, including a description 
of the monitoring and reporting requirements and test methods;
    (B) A monitoring schedule, including identification of those time 
periods when control device or process parameter monitoring would be 
conducted and when monitoring would not be conducted (e.g., monitoring 
of emissions from catalytic reforming unit regeneration vents is 
required only when the regeneration process is performed);
    (C) A maintenance schedule for each process and control device 
consistent with the manufacturer's instructions and recommendations for 
routine and long-term maintenance; and
    (D) Quality control program for continuous parameter monitoring 
systems and continuous emission monitoring systems, including 
procedures (as applicable) for initial and subsequent calibrations, 
preventative maintenance, accuracy audit procedures; corrective action; 
and data recording, calculation, reporting, and recordkeeping 
procedures to document conformance.
    (vii) A statement by the owner or operator as to whether the 
existing, new, or reconstructed source is in compliance with the 
requirements of this subpart.
    (b) Reports--periodic. The owner or operator of a source subject to 
this subpart shall submit semi-annual reports no later than 60 calendar 
days after the end of each 6-month period if any period of excess 
emissions, as defined in Sec. 63.1565(o) of this subpart, occurs during 
the reporting period. The first 6-month period shall begin on the date 
the notification of compliance status report is required to be 
submitted. An owner or operator may submit reports required by other 
regulations in place of or as part of the periodic report required by 
this paragraph if the reports contain the information required by 
paragraphs (b)(1) through (b)(7) of this section. A periodic report is 
not required if none of the exceptions specified in paragraphs (b)(1) 
through (b)(5) of this section occur during a 6-month period:
    (1) Monitoring results for an operating day when:
    (i) For a thermal incinerator, the daily average temperature falls 
below the minimum value specified in the notification of compliance 
status report;
    (ii) For a catalytic incinerator, the daily average upstream 
temperature or the daily average temperature difference across the 
catalyst bed falls below the minimum value specified in the 
notification of compliance status report;
    (iii) For a boiler or process heater with a design heat capacity 
less than 44 MW where the vent stream is not introduced into a flame 
zone, the daily average temperature falls below the minimum value 
specified in the notification of compliance status report;
    (iv) For an electrostatic precipitator, the average hourly voltage 
or secondary current or average hourly total power input falls below 
the minimum value specified in the notification of compliance status 
report;
    (v) For a wet scrubber, the daily average pressure drop or daily 
average liquid-to-gas ratio falls below the minimum value specified in 
the notification of compliance status report;
    (vi) For a catalytic cracking unit with no combustion device, the 
average hourly CO concentration measured by the CO continuous emission 
monitoring system required by Sec. 63.1565(d)(1) of this subpart 
exceeds 500 ppmv or any period when the average hourly temperature or 
oxygen content falls below the minimum value specified in the 
notification of compliance status report; or
    (vii) For a catalytic cracking unit catalyst regenerator subject to 
the PM emission standard in Sec. 63.1562(a)(1)(i) of this subpart, the 
daily average coke burn-off rate (thousands kg/hr) exceeds the maximum 
value specified in the notification of compliance status report.
    (2) The duration of a period during an operating day when 
monitoring data were not available for 75 percent of the operating 
hours;
    (3) The duration of a period during an operating day when all pilot 
flames of a flare are absent;
    (4) The time and duration of any period a vent stream is diverted 
through a bypass line; or
    (5) For data compression systems approved under Sec. 63.1565(n) of 
this subpart, an operating day when the monitor operated for less than 
75 percent of the operating hours or a day when less than 18 monitoring 
values were recorded.
    (6) The owner or operator shall submit the results of any 
performance test conducted during the reporting period including one 
complete report for each test method used for a particular kind of 
emission point tested. For additional tests performed for a similar 
emission point using the same method, results and any other information 
required shall be submitted, but a complete test report is not 
required. A complete test report shall contain a brief process 
description, sampling site data, description of sampling and analysis 
procedures and any modifications to standard procedures, quality 
assurance procedures, record of operating conditions during the test, 
record of preparation of standards, record of calibrations, raw data 
sheets for field sampling, raw data sheets for field and laboratory 
analyses, documentation of

[[Page 48921]]

calculations, and any other information required by the test method.
    (7) A request for changing applicability of the PM or Ni emission 
standard in Sec. 63.1562(a) of this subpart or for changing the 
applicability of emission standards in this subpart to/from the new 
source performance standard in subpart J to part 60 of this chapter as 
allowed under Sec. 63.1560(d) of this subpart (Applicability and 
designation of affected sources) shall be included in a periodic 
report. The request must be accompanied by all information and data 
necessary to demonstrate compliance with the emission standard and 
associated requirements of this subpart.
    (c) Reports--startup, shutdown, and malfunctions. The owner or 
operator shall develop and implement a written plan containing specific 
procedures to be followed for operating the source and maintaining the 
source during periods of startup, shutdown, and malfunction and a 
program of corrective action for malfunctioning process and control 
systems used to comply with the standard in accordance with the 
operation and maintenance requirements in Sec. 63.6(e)(3) of this part. 
The duty to develop and implement the plan shall be incorporated in the 
facility's part 70 or part 71 operating permit. Each plan shall contain 
corrective action procedures to be followed if any of the events in 
paragraphs (b)(1) through (b)(3) of this section occur during the 6-
month reporting period, including procedures to determine the cause of 
the exceedance or deviation, the time the exceedance or deviation began 
and ended, and for recording the actions taken to correct the cause of 
the exceedance or deviation. The following reporting and recordkeeping 
requirements apply to startups, shutdowns, and malfunctions:
    (1) When the actions taken to respond are consistent with the plan, 
keep records to document the event and the response as required in 
Sec. 63.6(e)(3)(iii) of this part. The owner or operator is not 
required to report these events in the semi-annual startup, shutdown, 
and malfunction report required under Sec. 63.10(d)(1) of this part 
when the actions are consistent with the plan, and the reporting 
requirements in Sec. 63.6(e)(3)(iii) and Sec. 63.10(d)(5) of this part 
do not apply.
    (2) When the actions taken to respond are not consistent with the 
plan, keep records to document the event and the response as required 
in Sec. 63.6(e)(3)(iv) of this part. The owner or operator shall report 
these events and the response taken in the semi-annual startup, 
shutdown, and malfunction report required under Sec. 63.10(d)(1) of 
this part. In this case, the reporting requirements in 
Sec. 63.6(e)(3)(iv) and Sec. 63.10(d)(5) of this part do not apply.
    (3) The owner or operator may include the semi-annual startup, 
shutdown, and malfunction report required under Sec. 63.10(d)(1) of 
this part in the periodic report required by paragraph (b) of this 
section.
    (d) Annual compliance certification. For the purpose of annual 
certifications of compliance required by the permitting regulations in 
parts 70 or 71 of this chapter, the owner or operator shall certify 
continuing compliance based upon the following conditions:
    (1) All periods of excess emissions, including exceedances or 
excursions, that occurred during the year have been reported as 
required by this subpart; and
    (2) All monitoring, recordkeeping, and reporting requirements were 
met during the year.
    (e) Recordkeeping. (1) The owner or operator must retain each 
record required by this subpart for at least 5 years following the date 
of each occurrence, measurement, maintenance activity, corrective 
action, report, or record. The most recent 2 years of records must be 
retained at the facility. The remaining 3 years of records may be 
retained off site;
    (2) The owner or operator may retain records on microfilm, on a 
computer, on computer disks, on magnetic tape, or on microfiche;
    (3) The owner or operator may report required information on paper 
or on a labeled computer disc using commonly available and compatible 
computer software; and
    (4) The owner or operator shall maintain records of the following 
information:
    (i) A copy of the startup, shutdown, and malfunction plan;
    (ii) Records documenting the actions taken when a startup, 
shutdown, or malfunction occurred and information to demonstrate that 
such actions were consistent with the plan;
    (iii) All maintenance performed on air pollution control equipment;
    (iv) Each period when a continuous monitoring system or continuous 
emission monitor was inoperative or malfunctioning;
    (v) All measurements, test results (including a complete 
performance test report for each affected source), and any other 
information needed to demonstrate compliance with the standards in this 
subpart;
    (vi) All documentation supporting notifications of compliance 
status;
    (vii) All documentation supporting conformance with appendix F of 
part 60 of this chapter for each continuous emission monitoring system, 
including calibration checks and relative accuracy test audits;
    (viii) For owners or operators using continuous monitoring systems 
or continuous emission monitoring systems to demonstrate compliance, 
records for such systems as required by Sec. 63.10(c) of this part;
    (ix) Records of any changes to a regulated process, including a 
record of any changes in the location at which the vent stream is 
introduced into the flame zone for a boiler or process heater;
    (x) Where a bypass line is equipped with a flow indicator, records 
of each hourly inspection demonstrating whether the flow indicator was 
operating properly and whether gas or vapor flow was detected or where 
a bypass line is secured with a car-seal or a lock-and-key type device, 
records of each monthly inspection demonstrating that the bypass line 
valve is maintained in the closed position and whether gas or vapor 
flow was detected; and for all bypass line valves, records of the times 
and durations of all periods when the vent stream is diverted through a 
bypass line;
    (xi) Records of hourly inspections of flare pilot flame; and
    (xii) For each catalytic cracking unit catalytic regenerator 
subject to the PM emission standard in Sec. 63.1562(a)(1)(i) of this 
subpart, records of the daily average coke burn-off rate, the hours of 
operation for each unit, and process data used to determine the 
volumetric flow rate of exhaust gas.


Sec. 63.1568  Applicability of general provisions.

    The requirements of the general provisions in subpart A of this 
part that are applicable to the owner or operator subject to the 
requirements of this subpart are shown in appendix A to this subpart.


Sec. 63.1569  Delegation of authority.

    In delegating implementation and enforcement authority to a State 
under section 112(l) of the Act, all authorities are transferred to the 
State.


Sec. 63.1570-63.1579  [Reserved]

Appendix A to Subpart UUU to Part 63--Applicability of General 
Provisions (40 CFR Part 63, Subpart A) to Subpart UUU

[[Page 48922]]



----------------------------------------------------------------------------------------------------------------
              Citation                 Applies to  subpart UUU                       Comment                    
----------------------------------------------------------------------------------------------------------------
63.1(a)(1)-63.1(a)(3)...............  Yes.....................  General Applicability.                          
63.1(a)(4)..........................  No......................  This table specifies applicability of General   
                                                                 Provisions to Subpart UUU.                     
63.1(a)(5)..........................  No......................  [Reserved].                                     
63.1(a)(6)-63.1(a)(8)...............  No.                                                                       
63.1(a)(9)..........................  No......................  [Reserved].                                     
63.1(a)(10).........................  No......................  Subpart UUU specifies calendar or operating day.
63.1(a)(11)-63.1(a)(14).............  Yes.                                                                      
63.1(b)(1)..........................  No......................  Initial Applicability Determination Subpart UUU 
                                                                 specifies applicability.                       
63.1(b)(2)..........................  Yes.                                                                      
63.1(b)(3)..........................  No.                                                                       
63.1(c)(1)..........................  No......................  Subpart UUU specifies requirements.             
63.1(c)(2)..........................  No......................  Area sources are not subject to subpart UU.     
63.1(c)(3)..........................  No......................  [Reserved].                                     
63.1(c)(4)..........................  Yes.                                                                      
63.1(c)(5)..........................  Yes.....................  Except that notification requirements in subpart
                                                                 UUU apply.                                     
63.1(d).............................  No......................  [Reserved].                                     
63.1(e).............................  Yes.....................  Applicability of Permit Program.                
63.2................................  Yes.....................  Definitions Sec.  63.1561 specifies that if the 
                                                                 same term is defined in Subparts A and UUU, it 
                                                                 shall have the meaning given in Subpart UUU.   
63.3................................  Yes.....................  Units and Abbreviations.                        
63.4(a)(1)-63.4(a)(4)...............  Yes.....................  [Reserved].                                     
63.4(a)(5)..........................  Yes.                                                                      
63.4(b)-63.4(c).....................  Yes.....................  Circumvention/Severability.                     
63.5(a)(1)..........................  Yes.....................  Construction and Reconstruction--Applicability  
                                                                 Replace term ``source'' and ``stationary       
                                                                 source'' in Sec.  63.5(a)(1) with ``affected   
                                                                 source''.                                      
63.5(a)(2)..........................  Yes.                                                                      
63.5(b)(1)..........................  Yes.....................  Existing, New, Reconstructed Sources--          
                                                                 Requirements.                                  
63.5(b)(2)..........................  No......................  [Reserved].                                     
63.5(b)(3)..........................  Yes.                                                                      
63.5(b)(4)..........................  Yes.....................  Replace the reference to Sec.  63.9 with Sec.   
                                                                 63.9(b)(4) and (b)(5).                         
63.5(b)(5)-(6)......................  Yes.                                                                      
63.5(c).............................  No......................  [Reserved].                                     
63.5(d)(1)(i).......................  Yes.....................  Application for Approval of Construction or     
                                                                 Reconstruction Except Subpart UUU specifies the
                                                                 application is submitted as soon as practicable
                                                                 before startup but no later than 90 days       
                                                                 (rather than 60) after the promulgation date   
                                                                 where construction or reconstruction had       
                                                                 commenced and initial startup had not occurred 
                                                                 before promulgation.                           
63.5(d)(1)(ii)......................  Yes.....................  Except that emission estimates specified in Sec.
                                                                  63.5(d)(1)(ii)(H) are not required.           
63.5(d)(1)(iii).....................  No......................  Sec.  63.1567(b) specifies submission of        
                                                                 notification of compliance status report.      
63.5(d)(2)..........................  No.                                                                       
63.5(d)(3)..........................  Yes.....................  Except Sec.  63.5(d)(3)(ii) does not apply.     
63.5(d)(4)..........................  Yes.                                                                      
63.5(e).............................  Yes.....................  Approval of Construction or Reconstruction.     
63.5(f)(1)..........................  Yes.....................  Approval of Construction or Reconstruction Based
                                                                 on State Review.                               
63.5(f)(2)..........................  Yes.....................  Except that 60 days is changed to 90 days and   
                                                                 cross-reference to (b)(2) does not apply.      
63.6(a).............................  Yes.....................  Compliance with Standards and Maintenance--     
                                                                 Applicability.                                 
63.6(b)(1)..........................  No......................  New and Reconstructed Sources--Dates Subpart UUU
                                                                 specifies compliance dates.                    
63.6(b)(2)..........................  No.                                                                       
63.6(b)(3)..........................  Yes.                                                                      
63.6(b)(4)..........................  No......................  May apply to standards under section 112(f).    
63.6(b)(5)..........................  No......................  Subpart UUU specifies notification requirements.
63.6(b)(6)..........................  No......................  [Reserved].                                     
63.6(b)(7)..........................  No.                                                                       
63.6(c)(1)..........................  No......................  Existing Sources--Dates Subpart UUU specifies   
                                                                 compliance dates.                              
63.6(c)(2)-63.6(c)(3)...............  No.                                                                       
63.6(c)(4)..........................  No......................  [Reserved].                                     
63.6(c)(5)..........................  Yes.                                                                      
63.6(d).............................  No......................  [Reserved].                                     
63.6(e)(1)-(2)......................  Yes.....................  Operation and Maintenance Requirements.         
63.6(e)(3)(i)-(ii)..................  Yes.....................  Startup, Shutdown, and Malfunction Plan.        
63.6(e)(3)(iii).....................  Yes.                                                                      
63.6(e)(3)(iv)......................  Yes.....................  Except that reports of actions not consistent   
                                                                 with plan are not required within 2 and 7 days 
                                                                 of action but rather must be included in next  
                                                                 periodic report.                               
63.6(e)(3)(v)-(viii)................  Yes.                                                                      
63.6(f)(1)..........................  Yes.....................  Compliance with Emission Standards.             
63.6(f)(2)(i).......................  Yes.                                                                      
63.6(f)(2)(ii)......................  Yes.....................  Subpart UUU specifies use of monitoring data in 
                                                                 determining compliance.                        
63.6(f)(2)(iii)(A)-63.6(f)(2)(iii)(C  Yes.                                                                      
 ).                                                                                                             
63.6(f)(2)(iii)(D)..................  No.                                                                       
63.6(f)(2)(iv)-(v)..................  Yes.                                                                      
63.6(f)(3)..........................  Yes.                                                                      
63.6(g).............................  Yes.....................  Alternative Standard.                           

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63.6(h).............................  No......................  Compliance with Opacity/VE Standards Subpart UUU
                                                                 does not include opacity/VE standards.         
63.6(i)(1)-63.6(i)(14)..............  Yes.....................  Extension of Compliance.                        
63.6(i)(15).........................  No......................  [Reserved].                                     
63.6(i)(16).........................  Yes.                                                                      
63.6(j).............................  Yes.....................  Exemption from Compliance.                      
63.7(a)(1)..........................  No......................  Performance Test Requirements--Applicability and
                                                                 Dates Subpart UUU specifies the applicable test
                                                                 and demonstration procedures.                  
63.7(a)(2)..........................  No......................  Test results must be submitted in the           
                                                                 notification of compliance status report due   
                                                                 150 days after the compliance date.            
63.7(a)(3)..........................  Yes.                                                                      
63.7(b).............................  Yes.....................  Notifications Except Subpart UUU specifies      
                                                                 notification at least 30 days prior to the     
                                                                 scheduled test date rather than 60 days.       
63.7(c).............................  Yes.....................  Quality Assurance/Test Plan Sec.  63.1564(b)(2) 
                                                                 requires a Q/A plan for CO continuous emission 
                                                                 monitoring systems.                            
63.7(d).............................  Yes.....................  Testing Facilities.                             
63.7(e)(1)..........................  Yes.....................  Conduct of Tests.                               
63.7(e)(2)-63.7(e)(3)...............  No......................  Subpart UUU specifies the applicable methods and
                                                                 procedures.                                    
63.7(e)(4)..........................  Yes.                                                                      
63.7(f).............................  No......................  Alternative Test Method Subpart UUU specifies   
                                                                 the applicable methods and provides            
                                                                 alternatives.                                  
63.7(g).............................  No......................  Data Analysis, Recordkeeping, Reporting Subpart 
                                                                 UUU specifies performance test reports and     
                                                                 requires additional records for continuous     
                                                                 emission monitoring systems.                   
63.7(h)(1)..........................  Yes.....................  Waiver of Tests.                                
63.7(h)(3)-63.7(h)(4)...............  No.                                                                       
63.7(h)(5)..........................  Yes.                                                                      
63.8(a).............................  No......................  Monitoring Requirements Applicability.          
63.8(b)(1)..........................  Yes.....................  Conduct of Monitoring.                          
63.8(b)(2)..........................  No......................  Subpart UUU specifies the required monitoring   
                                                                 locations.                                     
63.8(b)(3)..........................  Yes.                                                                      
63.8(c)(1)(i).......................  Yes.....................  CMS Operation and Maintenance.                  
63.8(c)(1)(ii)......................  No......................  Addressed by periodic reports in Sec.           
                                                                 63.1567(b) of Subpart UUU.                     
63.8(c)(1)(iii).....................  Yes.                                                                      
63.8(c)(2)..........................  Yes.                                                                      
63.8(c)(3)..........................  Yes.....................  Except that operational status verification     
                                                                 includes completion of manufacturer written    
                                                                 specifications or installation operation, and  
                                                                 calibration of the system or other written     
                                                                 procedures that provide adequate assurance that
                                                                 the equipment will monitor accurately.         
63.8(c)(4)..........................  No......................  Monitoring frequency is specified in Sec.       
                                                                 63.1565 of Subpart UUU.                        
63.8(c)(5)..........................  No.                                                                       
63.8(c)(8)-63.8(d)..................  Yes.....................  Quality Control.                                
63.8(e).............................  Yes.....................  CMS Performance Evaluation May be required by   
                                                                 Administrator.                                 
63.8(f)(1)..........................  Yes.....................  Alternative Monitoring Method.                  
63.8(f)(2)..........................  Yes.                                                                      
63.8(f)(3)..........................  Yes.                                                                      
63.8(f)(4)(i).......................  No......................  Sec.  63.1565(f) specifies procedure.           
63.8(f)(4)(ii)......................  Yes.                                                                      
63.8(f)(4)(iii).....................  No.                                                                       
63.8(f)(5)(i).......................  Yes.                                                                      
63.8(f)(5)(ii)......................  No.                                                                       
63.8(f)(5)(iii).....................  Yes.                                                                      
63.8(f)(6)..........................  Yes.....................  Applicable to CO continuous emission monitoring 
                                                                 system.                                        
63.8(g).............................  Yes.....................  Data Reduction Applicable to CO continuous      
                                                                 emission monitoring system; Subpart UUU        
                                                                 specifies data reduction for CMS.              
63.9(a).............................  Yes.....................  Notification Requirements--Applicability        
                                                                 Duplicate notification of compliance status    
                                                                 report to RA may be required.                  
63.9(b)(1)(i).......................  Yes.....................  Initial Notifications.                          
63.9(b)(1)(ii)......................  Yes.                                                                      
63.9(b)(1)(iii).....................  Yes.                                                                      
63.9(b)(2)..........................  Yes.                                                                      
63.9(b)(3)..........................  Yes.                                                                      
63.9(b)(4)..........................  Yes.....................  Except that notification is to be submitted     
                                                                 within 150 days as part of the compliance      
                                                                 status report.                                 
63.9(b)(5)..........................  Yes.....................  Except that notification is to be submitted     
                                                                 within 150 days as part of the compliance      
                                                                 status report.                                 
63.9(c).............................  Yes.....................  Request for Compliance Extension.               
63.9(d).............................  Yes.....................  New Source Notification for Special Compliance  
                                                                 Requirements.                                  
63.9(e).............................  Yes.....................  Except notification is required at least 30 days
                                                                 before test.                                   
63.9(f).............................  Yes.....................  Notification of VE/Opacity Test.                
63.9(g).............................  No.                                                                       
63.9(h).............................  No......................  Notification of Compliance Status Sec.  63.1567 
                                                                 specifies the applicable requirements.         
63.9(i).............................  Yes.....................  Adjustment of Deadlines.                        

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63.9(j).............................  No......................  Change in Previous Information.                 
63.10(a)............................  Yes.....................  Recordkeeping/Reporting--Applicability.         
63.10(b)(1).........................  No......................  General Requirements Subpart UUU specifies      
                                                                 applicable record retention requirements.      
63.10(b)(2)(i)-(xiv)................  Yes.                                                                      
63.10(b)(3).........................  No.                                                                       
63.10(c)............................  Yes.....................  Additional CMS Recordkeeping.                   
63.10(d)(1).........................  No......................  General Reporting Requirements.                 
63.10(d)(2).........................  No......................  Performance Test Results Sec.  63.1567 specifies
                                                                 performance test reporting requirements.       
63.10(d)(3).........................  Yes.....................  Opacity or VE Observations.                     
63.10(d)(4).........................  Yes.....................  Progress Reports.                               
63.10(d)(5)(i)......................  Yes.....................  Startup, Shutdown, and Malfunction Reports.     
                                                                 Except that reports are not required if actions
                                                                 are consistent with SSM plan, unless requested 
                                                                 by permitting authority.                       
63.10(d)(5)(ii).....................  Yes.....................  Except that reports of actions not consistent   
                                                                 with the plan are not required within 2 and 7  
                                                                 days of action but must be included in next    
                                                                 periodic report.                               
63.10(e)(1).........................  Yes.....................  Additional CMS Reports.                         
63.10(e)(2).........................  No.                                                                       
63.10(e)(3).........................  No......................  Excess Emissions/CMS Performance Reports Subpart
                                                                 UUU specifies the applicable requirements.     
63.10(e)(4).........................  No......................  COMS Data Reports.                              
63.10(f)............................  Yes.....................  Recordkeeping/Reporting Waiver.                 
63.11...............................  Yes.....................  Control Device Requirements Applicable to       
                                                                 flares.                                        
63.12...............................  Yes.....................  State Authority and Delegations.                
63.13...............................  Yes.....................  Addresses.                                      
63.14...............................  No......................  Incorporation by Reference.                     
63.15...............................  Yes.....................  Availability of Information/Confidentiality.    
----------------------------------------------------------------------------------------------------------------

[FR Doc. 98-23508 Filed 9-10-98; 8:45 am]
BILLING CODE 6560-50-P