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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[AD-FRL-5012-3]

National Emission Standards for Hazardous Air Pollutants for

Source Categories: Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule and notice of public hearing.

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SUMMARY: The EPA is proposing to regulate the emissions of certain

hazardous air pollutants from petroleum refineries that are major

sources under section 112 of the Clean Air Act as amended in 1990. The

proposed rule, the national emission standards for hazardous air

pollutants for petroleum refineries, would require sources to achieve

emission limits reflecting the application of the maximum achievable

control technology, consistent with sections 112(d) and 112(h) of the

Clean Air Act as amended in 1990. The proposed rule would regulate the

emissions of the organic hazardous air pollutants identified on the

list of 189 hazardous air pollutants in the Clean Air Act at both new

and existing petroleum refinery sources.

The EPA is also proposing to amend two standards of performance for

new stationary sources: standards of performance for equipment leaks of

volatile organic compounds in the synthetic organic chemicals

manufacturing industry; and standards of performance for volatile

organic compounds emissions from petroleum refinery wastewater systems.

These standards were previously promulgated under section 111 of the

Clean Air Act.

DATES: Comments. Comments must be received on or before September 13,

1994.

Public Hearing. If anyone contacts the EPA requesting to speak at a

public hearing by August 5, 1994, a public hearing will be held on

August 15, 1994, beginning at 9 a.m. Persons wishing to present oral

testimony must contact Ms. Lina Hanzely of the EPA at (919) 541-5673 by

August 5, 1994. Persons interested in attending the hearing should call

Ms. Hanzely at (919) 541-5673 to verify that a hearing will be held.

ADDRESSES: Comments. Comments should be submitted (in duplicate, if

possible), to: The Air and Radiation Docket and Information Center (LE-

131), ATTN: Docket No. A-93-48, Room M1500, U.S. Environmental

Protection Agency, 401 M Street, SW., Washington, DC 20460.

Public Hearing. If anyone contacts the EPA requesting a public

hearing, it will be held at the EPA's Office of Administration

auditorium, Research Triangle Park, North Carolina. Persons interested

in attending the hearing or wishing to present oral testimony should

notify Ms. Hanzely, Chemicals and Petroleum Branch, Emission Standards

Division (MD-13), U.S. Environmental Protection Agency, Research

Triangle Park, North Carolina 27711, telephone number (919) 541-5673.

Docket. The docket listed above under ADDRESSES contains supporting

information used in developing the proposed rule. The docket includes

several memoranda documenting the estimation of impacts of the

regulatory alternatives and the technical basis of the proposed

standards. Dockets are available for public inspection and copying

between 8 a.m. and 4 p.m., Monday through Friday, at the Air and

Radiation Docket and Information Center, Room M1500, U.S. Environmental

Protection Agency, 401 M Street, SW., Washington, DC 20460. A

reasonable fee may be charged for copying.

FOR FURTHER INFORMATION CONTACT: For information concerning the

proposed standards, contact Mr. James F. Durham, at (919) 541-5672,

Chemicals and Petroleum Branch (MD-13), Emission Standards Division,

U.S. Environmental Protection Agency, Research Triangle Park, North

Carolina 27711.

SUPPLEMENTARY INFORMATION: The following outline is provided to aid in

reading the preamble to the proposed regulation.

I. Acronyms, Abbreviations and Measurement Units

A. Acronyms

B. Abbreviations and Measurement Units

II. Background

A. Statutory Authority

B. Previous Regulations

III. Summary of Proposed Rule

A. Applicability and General Standards

B. Miscellaneous Process Vent Provisions

C. Storage Vessel Provisions

D. Wastewater Provisions

E. Equipment Leak Provisions

F. Recordkeeping and Reporting Provisions

G. Emissions Averaging

IV. Summary of Impacts of Proposed Rule

A. Environmental Impact

B. Energy Impact

C. Cost Impact

D. Economic Impact

E. Benefits Analysis

V. Emission and Impact Estimation Methods

VI. Rationale for Proposed Standard

A. Selection of Source Category, Sources, and Pollutants

B. Selection of Miscellaneous Process Vent Provisions

C. Selection of Storage Vessel Provisions

D. Selection of Wastewater Collection and Treatment Operation

Provisions

E. Selection of Equipment Leak Provisions

F. Use of Continuous Monitoring to Determine Compliance

G. Selection of Reporting and Recordkeeping Provisions

H. Rationale for Emissions Averaging Provisions

VII. Amendments to Previous Regulations

A. Amendment to 40 CFR Part 60 Subpart QQQ

B. Amendment to 40 CFR Part 60 Subpart VV

VIII. Administrative Requirements

A. Executive Order 12866

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Review

The proposed regulatory text is not included in this Federal

Register notice, but is available in Docket No. A-93-48, or by written

or telephone request from the Air and Radiation Docket Information

Center (see ADDRESSES). The proposed regulatory language is also

available on the Technology Transfer Network (TTN), on the EPA's

electronic bulletin boards. This bulletin board provides information

and technology exchange in various areas of air pollution control. The

service is free, except for the cost of a telephone call. Dial (919)

541-5742 for up to a 14,400 bps modem. If more information on TTN is

needed call the HELP line at (919) 541-5384.

I. Acronyms, Abbreviations and Measurement Units

The following acronyms, abbreviations and measurement units are

provided to clarify the preamble to the proposed rule.

A. Acronyms

Act--Clean Air Act

BWON--Benzene Waste Operations NESHAP

CEMS--continuous emission monitoring system

CFR--Code of Federal Regulations

CTG--control techniques guideline

E.O.--Executive Order

EFR--External Floating Roof

EPA--U.S. Environmental Protection Agency

FCCU--fluidized catalytic cracking unit

FR--Federal Register

HAP--hazardous air pollutant

HON--hazardous organic national emission standards for hazardous air

pollutants for the SOCMI source category

ICR--information collection request

IFR--internal floating roof

LDAR--leak detection and repair

MACT--maximum achievable control technology

NESHAP--national emission standards for hazardous air pollutants

NSPS--new source performance standards

OMB--Office of Management and Budget

QIP--quality improvement program

RCT--reference control technology

RIA--Regulatory Impact Analysis

SOCMI--synthetic organic chemical manufacturing industry

TAB--total annual benzene

TOC--total organic compounds

VOC--volatile organic compounds

B. Abbreviations and Measurement Units

Btu--British thermal unit

CO--carbon monoxide

hr--hour

kPa--kilopascals

Kw-hr/yr--kilowatt-hour per year

lb--pound

l/min--liters per minute

m\3\--cubic meters

Mg--megagrams

MEK--methyl ethyl ketone

MTBE--methyl tertiary butyl ether

NOX--nitrogen oxides

PM--particulate matter

ppm--parts per million

ppmv--parts per million by volume

ppmw--parts per million by weight

psia--pounds per square inch absolute

SO2--sulfur dioxide

yr--year

II. Background

This section provides background about the legal and policy

criteria that the Administrator took into consideration in selecting

the provisions of this proposed rule. It is included to give the reader

a sense of the rule as a whole. To that end, this section includes

background about the rule, the statutory authority of the rule,

including some statutory history, a summary of the current statutory

requirements for standards developed under section 112 of the Act, and

a summary of previous regulations.

The regulation being proposed today, under section 112 of the Act,

is the petroleum refineries NESHAP, which would set MACT for petroleum

refineries. The petroleum refineries industry group includes any

facility engaged in producing gasoline, naphthas, kerosene, jet fuels,

distillate fuel oils, residual fuel oils, lubricants, or other products

made from crude oil or unfinished petroleum derivatives.

Some components of the petroleum refining industry have already

been subject to various Federal, State, and local air pollution control

rules. Although these existing rules will remain in effect, the

petroleum refinery NESHAP will provide comprehensive coverage of the

petroleum refinery sources not covered by the existing rules. The

petroleum refinery NESHAP, as proposed today, regulates emissions of

all the organic HAP's emitted from emission points at both new and

existing petroleum refinery sources. The proposed NESHAP reflects the

EPA's regulatory experience from previous NESHAP and NSPS rulemakings

involving similar kinds of sources and emission points. Information on

control technology applicability, performance, and cost was developed

to support these NESHAP and NSPS. This information was carefully

reconsidered in light of the Act and used in the selection of MACT and

the other provisions of the proposed rule, such as monitoring,

recordkeeping, and reporting requirements.

A. Statutory Authority

This section provides a brief history of section 112 of the Act and

background regarding the definition of source categories and source for

section 112 standards. This information is included to give the reader

a sense of the statutory, judicial, and Congressional guidance that the

Administrator took into consideration in developing the source category

and source definitions for the petroleum refinery NESHAP.

Section 112 of the Act provides a list of 189 HAP's and directs the

EPA to develop rules to control HAP emissions. The Act requires that

the rules be established for categories of sources of the emissions,

rather than being set by pollutant. In addition, the Act sets out

specific criteria for establishing a minimum level of control and

criteria to be considered in evaluating control options more stringent

than the minimum control level. Assessment and control of any remaining

unacceptable health or environmental risk is to occur 8 years after the

rules are promulgated.

Specifically, section 112(c), as amended, directs the Administrator

to develop a list of all categories or subcategories of major sources

and such categories or subcategories of area sources that meet the

requirements of section 112(c)(3) and emit the HAP's listed pursuant to

section 112(b). Section 112(d) directs the Administrator to promulgate

emission standards for each listed category or subcategory of HAP

sources. Such standards will be applicable to both new and existing

sources and shall require:

the maximum degree of reduction in emissions of the hazardous air

pollutants subject to this section (including a prohibition on such

emissions, where achievable) that the Administrator, taking into

consideration the cost of achieving such emission reduction, and any

nonair quality health and environmental impacts and energy

requirements, determines is achievable for new and existing sources

in the category or subcategory to which such emission standard

applies. . . .

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

The Act further provides that ``the maximum degree of reduction in

emissions that is deemed achievable'' shall be subject to a ``floor,''

which is determined differently for new and existing sources. For new

sources, the standards set shall not be any less stringent than ``the

emission control that is achieved in practice by the best controlled

similar source.'' For existing sources, the standards may not be less

stringent than the average emission limitation achieved by the best

performing 12 percent of existing sources in each category or

subcategory of 30 or more sources. (For smaller categories or

subcategories, the standards may not be less stringent than the average

emission limitation achieved by the best performing five sources in the

category or subcategory.)

In determining whether the standard should be more stringent than

the floor and by how much, the Administrator is to consider, among

other things, the cost of achieving such additional reductions. The

statutory provisions do not limit how the standard is to be set beyond

requiring that it be applicable to all sources in a category and be at

least as stringent as the floor.

B. Previous Regulations and Guidance

The regulations affecting the petroleum refining industry that have

already been promulgated include a number of NSPS in 40 CFR part 60:

subpart J--Standards of Performance for Petroleum Refineries; subparts

K, Ka, and Kb--various standards of performance for storage vessels for

petroleum liquids; subpart GGG--Standards of Performance for Equipment

Leaks of VOC in Petroleum Refineries; and subpart QQQ--Standards of

Performance for VOC Emissions from Petroleum Refinery Wastewater

Systems.

The regulations that have already been promulgated also include a

number of NESHAP in 40 CFR part 61: subpart J--NESHAP for Equipment

Leaks (Fugitive Emission Sources) of Benzene; subpart Y--NESHAP for

Benzene Emissions from Benzene Storage Vessels; and subpart FF--NESHAP

for Benzene Waste Operations.

The EPA has also issued guidance on controlling equipment leaks at

refineries in the refinery CTG. Guideline Series: Control of Volatile

Organic Compound Leaks from Petroleum Refinery Equipment. U.S.

Environmental Protection Agency. Office of Air Quality Planning and

Standards. EPA-450/2-78-036. June 1978.

III. Summary of Proposed Rule

This section of this preamble summarizes the proposed rule (40 CFR

part 63, subpart CC). The rule is made up of seven different subjects:

applicability, definitions, and general standards; miscellaneous

process vent provisions; storage vessel provisions; wastewater

provisions; equipment leak provisions; recordkeeping and reporting

provisions; and emissions averaging. This summary is divided into seven

subsections corresponding to these parts of the regulation.

The discussion in this section briefly summarizes the requirements

of the rule, without accounting for how the provisions were selected or

how applicability criteria were determined. Specific discussion of the

rationale upon which the provisions of the rule are based can be found

in section VI of this preamble.

It should be noted that State rules for VOC (and/or HAP's) may be

more stringent than the rules being proposed today for refineries.

Organic HAP's are only a subset of the VOC emitted from refineries.

This means that the magnitude of VOC emissions from a refinery can be

substantially greater than the HAP emissions, and the cost per unit of

emission reduction of any particular control strategy would be less.

A. Applicability and General Standards

The rule applies to petroleum refining process units that are part

of a plant site that is a major source as defined in section 112 of the

Act. The determination of potential to emit, and therefore major source

status, is based on the total of all HAP emissions from all activities

at the plant site. For example, at some integrated facilities there may

be operations from multiple source categories (e.g., petroleum

refining, SOCMI production, pesticide production). The potential to

emit for such a plant site would include HAP emissions from all source

categories. If that plant-site total potential to emit exceeds 10 tons

per year of a single HAP or 25 tons per year of a combination of HAP's,

the petroleum refinery process units would be subject to the proposed

Petroleum Refinery NESHAP, even if the emissions from the petroleum

refinery process units were below the 10/25 threshold.

The applicability section of the regulation specifies what is

included in the petroleum refining source category and the source

within the source category.

Petroleum refineries are facilities engaged in producing gasoline,

naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel

oils, or other transportation fuels, heating fuels, or lubricants from

crude oil or unfinished petroleum derivatives.

The source comprises the miscellaneous process vents, storage

vessels, wastewater streams, and equipment leaks associated with

petroleum refining process units within a refinery. The rationale for

selecting this source definition is discussed in section VI.A of this

preamble.

The general standards section of the regulation establishes the

compliance dates for new and existing sources and requires that sources

be properly operated and maintained at all times. The general standards

clarify the applicability of the NESHAP General Provisions (40 CFR part

63 subpart A) to sources subject to subpart CC.

B. Miscellaneous Process Vent Provisions

Miscellaneous process vents are defined to include streams

containing greater than 20 ppmv organic HAP that are continuously or

periodically discharged from petroleum refining process units.

Miscellaneous process vents exclude vents that are routed to the

refinery fuel gas system and vents from fluidized catalytic cracking

unit catalyst regeneration, catalytic reformer catalyst regeneration,

and sulfur plants. The vents included in miscellaneous process vents

are defined specifically in the definitions section (Sec. 63.641) of

the proposed rule.

The miscellaneous process vent provisions require the owner or

operator of a miscellaneous process vent to reduce emissions of organic

HAP by 98 percent or to 20 ppmv, or to reduce emissions using a flare

meeting the requirements of Sec. 63.11(b) of the NESHAP General

Provisions (40 CFR part 63 subpart A). The process vent provisions

allow for pollution prevention in that pollution prevention could be

used to reduce organic HAP concentrations to less than 20 ppmv, and the

stream would not be subject to control requirements.

C. Storage Vessel Provisions

A storage vessel means a tank or other vessel storing feed or

product for a petroleum refining process unit that contains organic

HAP's. The storage vessel provisions do not apply to the following: (1)

vessels permanently attached to mobile vehicles, (2) pressure vessels

designed to operate in excess of 204.9 kPa (29.7 psia), (3) vessels

with capacities smaller than 40 m\3\ (10,500 gal), and (4) wastewater

tanks.

The storage provisions define two groups of vessels: Group 1

vessels are vessels with a design storage capacity and a maximum true

vapor pressure above the values specified in the proposed regulation

and in section VI.C. of this notice; Group 2 vessels are all storage

vessels that are not Group 1 vessels. The storage provisions require

that one of the following control systems be applied to Group 1 storage

vessels: (1) an IFR with proper seals; (2) an EFR with proper seals;

(3) an EFR converted to an IFR with proper seals; or (4) a closed vent

system with a 95-percent efficient control device. The storage

provisions give details on the types of seals required. The EPA is co-

proposing an option that would also require controlled fittings on

existing floating roof tanks. Vessels at new sources that are equipped

with floating roofs are required to meet specifications for seals and

fittings. Monitoring and compliance provisions for Group 1 vessels

include periodic visual inspections of vessels and roof seals, as well

as internal inspections. If a closed vent system and control device is

used for venting emissions from Group 1 storage vessels, the owner or

operator must establish appropriate monitoring procedures. No controls

or inspections are required for Group 2 storage vessels. The storage

vessel provisions are based on and encourage pollution prevention. The

pollution prevention options specifically listed by the standard are:

IFR, EFR, and a closed vent system routed to a recovery device.

D. Wastewater Provisions

The wastewater provisions of this rule are based on the BWON, using

benzene as a surrogate for all organic HAP's from wastewater in

petroleum refineries. As explained in section VI.D of this preamble,

benzene is a good indicator of the presence of other HAP's in

wastewater. The wastewater streams subject to this rule include water,

raw material, intermediate, product, by-product, co-product, or waste

material that contains organic HAP's and is discharged into an

individual drain system. The wastewater provisions define two groups of

wastewater streams. Group 1 streams are those that contain a

concentration of at least 10 ppmw benzene, have a flow rate of at least

0.02 l/min, are located at a refinery with a total annual benzene

loading of at least 10 megagrams per year and are not exempt from

control requirements under 40 CFR part 61 subpart FF (the BWON). Group

2 streams are wastewater streams that are not Group 1.

The wastewater provisions of the rule refer to the BWON, which

requires owners or operators of a Group 1 wastewater stream to reduce

benzene mass by 99 percent using suppression followed by steam

stripping, biotreatment, or other treatment processes. Vents from steam

strippers and other waste management or treatment units are required to

be controlled by a control device achieving 95 percent emissions

reduction or 20 ppmv at the outlet of the control device. The

performance tests required for wastewater streams and treatment

operations to verify that the control devices achieve the desired

performance are included in the BWON, as are the monitoring, reporting,

and recordkeeping provisions necessary to demonstrate compliance. No

controls or monitoring are required for Group 2 wastewater streams. The

wastewater provisions promote pollution prevention in that pollution

prevention measures could be used to reduce the benzene concentration

to below the criteria for Group 1 wastewater streams. Once the stream

is a Group 2 wastewater stream, control is not required. Pollution

prevention measures may also be taken to reduce the refinery-wide TAB

quantity in waste to below 10 Mg/yr or to reduce the refinery-wide TAB

quantity in wastewater to below 1 Mg/yr, beyond which no further

control would be required. Furthermore, the emissions suppression

requirements of the provisions are pollution prevention measures.

E. Equipment Leak Provisions

The equipment leak standards for the petroleum refinery NESHAP

refer to the negotiated equipment leak regulation included in the HON

(40 CFR part 63 subpart H). These standards are summarized in the

preamble to the promulgated HON (59 FR 19402, April 22, 1994). The

standards for the petroleum refinery NESHAP differ from the HON in the

following ways: only one leak definition for pumps in phase III; leak

definition for pumps is equal to or greater than 2,000 ppmv; leak

definitions for valves in phases II and III; monitoring frequencies for

valves; connectors are not required to be monitored, but sources may

choose to monitor valves less frequently in exchange for monitoring of

connectors. More details and a discussion of the rationale for these

differences are contained in section VI.E. The equipment leaks

standards further the goals of pollution prevention, because many of

the requirements, such as leak detection and repair, are pollution

prevention measures.

F. Recordkeeping and Reporting Provisions

The rule requires petroleum refineries complying with subpart CC to

keep records of information necessary to document compliance for 5

years and to submit the following four types of reports to the

Administrator: (1) An Initial Notification, (2) a Notification of

Compliance Status, (3) Periodic Reports, and (4) other reports. There

are no requirements for reporting compliance with the wastewater

provisions other than the reports already required by the BWON.

1. Initial Notification

The Initial Notification is due 120 days after the date of

promulgation for existing petroleum refinery sources. For new sources

that have an initial start-up more than 90 days after promulgation, the

application for approval of construction or reconstruction required

under the General Provisions (40 CFR part 63 subpart A) must be

submitted in lieu of the Initial Notification. This application is due

as soon as practicable before construction or reconstruction is planned

to commence but it need not be sooner than 90 days after promulgation

of subpart CC. For new sources that have an initial start-up less than

90 days after promulgation, no application for approval of construction

is required, and the Initial Notification is due within 90 days after

promulgation.

The Initial Notification must list the petroleum refining process

units that are subject to the rule. The Initial Notification is not

required if a Title V operating permit application has been submitted

that provides the required information.

2. Notification of Compliance Status

The Notification of Compliance Status must be submitted 150 days

after the sources's compliance date. It contains the information

necessary to demonstrate that compliance has been achieved, such as:

the results of any performance tests for miscellaneous process vents;

design analyses for control devices applied to storage vessels; a

description of equipment subject to the equipment leaks provisions and

the number of pieces of equipment in each equipment type; and the

method of compliance with the equipment leak standard. For emission

points subject to continuous monitoring requirements, the notification

must contain site-specific ranges for each monitored parameter and the

rationale for selection of the ranges. If the information required in

the Notification of Compliance Status has already been submitted to the

operating permit authority, it does not need to be resubmitted.

3. Periodic Reports

Periodic Reports must be submitted semiannually, except that the

implementing agency can request quarterly submittal for emission points

where monitored parameter values are outside their permitted ranges

more than 1 percent or monitors are out of service more than 5 percent

of the total operating time in a semiannual reporting period.

All Periodic Reports must include information required to be

reported under the recordkeeping and reporting provisions for each

emission point. For continuously monitored parameters, the data on

those periods when the parameters are outside their established ranges

are included in the reports. Periodic Reports must also include results

of any performance tests conducted during the reporting period and

reports of equipment failures, leaks, or improper work practices that

are discovered during required inspections.

4. Other Reports

A very limited number of other reports must be submitted as

required by the provisions for each kind of emission point. Other

reports include notifications of storage vessel internal inspections,

and reports of start-up, shut-down, and malfunction required by the

General Provisions (40 CFR part 63 subpart A).

G. Emissions Averaging

The EPA is proposing that emissions averaging be allowed among

existing miscellaneous process vents, storage vessels, and wastewater

streams within a refinery. New sources would not be allowed to use

emissions averaging. Under emissions averaging, a system of emission

``credits'' and ``debits'' would be used to determine whether the

source is achieving the required emission reductions. An owner or

operator who generates an emission debit must control other emission

points to a level more stringent than is required by the regulation to

generate an emission credit. Annual emission credits must exceed

emission debits for a source to be in compliance. The proposed rule

contains specific equations and procedures for calculating credits and

debits. Monitoring of control device operation would be required and

Periodic Reports would be submitted quarterly instead of semiannually

for emission points in emissions averages.

IV. Summary of Impacts of Proposed Rule

This section presents the environmental, energy, cost, and economic

impacts resulting from the control of HAP emissions under the proposed

rule. It is estimated that approximately 190 petroleum refineries would

be required to apply controls by the proposed standards.

Impacts are presented relative to a baseline, the level of control

in the absence of the proposed rule. The estimates include the impacts

of applying control to: (1) existing process units and (2) additional

process units that are expected to begin operation over a 5-year

period. Thus, the estimates represent annual impacts occurring in the

fifth year. Based on a review of annual construction projects over the

years 1988 to 1992 listed in the Oil and Gas Journal, it was assumed

that 34 new process units would be constructed each year over a 5-year

period.

For regulatory purposes, some of the process units constructed in

the first 5 years of the rule may be considered new sources, while

others may be considered part of an existing source. However, for the

purpose of presenting total impacts, this distinction has not been

made.

A. Environmental Impact

The environmental impact of the rule includes the reduction of HAP

and VOC emissions, increases in other air pollutants, and decreases in

water pollution and solid waste resulting from the proposed rule.

Under the proposed rule, it is estimated that the emissions of HAP

from refineries would be reduced by 54,000 Mg/yr, and the emissions of

VOC would be reduced by 350,000 Mg/yr (see table 1). Estimates of

baseline HAP and VOC emissions are presented in conjunction with

emissions reductions estimates to illustrate the level of control being

achieved by the rule. Baseline HAP and VOC emissions take into account

the current estimated level of emissions control, based on previous

regulations and questionnaire responses submitted by refineries. As a

result, baseline HAP and VOC emissions reflect the level of control

that would be achieved in the absence of the proposed rule. The

proposed rule would achieve a 68 percent reduction in HAP emissions and

a 72 percent reduction in VOC emissions relative to the baseline. Table

1 presents the baseline emissions and emission reduction for each of

the four kinds of emission points controlled by this proposed rule.

Table 1.--National Primary Air Pollution Impact in the Fifth Year

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

Baseline emissions Emission reductions

(Mg/yr) -------------------------------------------

Source ---------------------- (Mg/yr) (Percent)

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

HAP VOC HAP VOC HAP VOC

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

Miscellaneous process vents................... 9,800 190,000 8,400 180,000 86 95

Equipment leaks............................... 52,000 190,000 45,000 160,000 87 85

Storage vessels............................... 9,300 111,000 1,300 21,000 14 19

Wastewater collection and treatment........... 10,000 10,000 (a) (a) (a) (a)

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Total..................................... 81,000 500,000 55,000 360,000 68 72

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aThe MACT level of control is no additional control.

Emission levels of other air pollutants (CO, NOX, SO2)

were not quantified. However, slight increases above existing emission

levels would result from the combustion of fossil fuel as part of

control device operations. Additional emissions of CO, NOX, and

SO2 would result from fuel burned to generate energy for operation

of compressors for ducting miscellaneous process vent streams to

control devices.

Impacts for water pollution and solid waste were judged to be

negligible and were not quantified as part of the impact analysis.

B. Energy Impact

Increases in energy use were estimated for operating control

equipment that would be required by the proposed standards (i.e.,

compressors for ducting miscellaneous process vent streams to control

devices). The estimated energy use increase in the fifth year would be

13 million kw-hr/yr of electricity or 21,000 barrels of oil equivalent.

C. Cost Impact

The cost impact of the rule includes the capital cost of new

control equipment, the cost of energy (supplemental fuel, steam, and

electricity) required to operate control equipment, and operation and

maintenance cost. Generally, the cost impact also includes any cost

savings generated by reducing the loss of valuable product in the form

of emissions. The average cost effectiveness of the regulation ($/Mg of

pollutant removed) is also presented as part of the cost impact. The

average cost effectiveness is determined by dividing the annual cost by

the annual emission reduction.

Under the proposed rule, it is estimated that total capital costs

would be $207 million (first quarter 1992 dollars) and total annual

costs would be $84 million (first quarter 1992 dollars) per year. Table

2 presents the capital and annual cost impact of the proposed

regulation for each of the four kinds of emission points as well as the

national totals. In addition to the cost impact shown in Table 2, it is

estimated that monitoring, recordkeeping, and reporting activities

would cost about $26 million/yr, bringing the total national annual

costs to about $110 million.

Table 2.--National Control Cost Impacts in the Fifth Year

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

Total

capital Total Average HAP Average VOC

Source costsa annual cost cost

(106 $ ) costs (106 effectiveness effectiveness

$/yr) ($/Mg HAP) ($/Mg VOC)

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

Miscellaneous

process vents...... 31 12 1,400 66

Equipment leaks..... 130 66 1,500 410

Storage vessels..... 46 6 4,600 340

Wastewater

collection and

treatment.......... (b) (b) (b) (b)

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

Total........... 207 84 ............. .............

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aTotal capital costs incurred in the 5-year period.

bThe MACT level of control is no additional control.

D. Economic Impacts

The preliminary economic impact analysis for the selected

regulatory alternatives shows that the estimated price increases for

affected products range from 0.18 percent for residual fuel oil to 0.51

percent for jet fuel. Estimated decreases in product output range from

0.12 percent for jet fuel to 0.37 percent for residual fuel oil. Total

net exports (exports minus imports) for all petroleum liquids are

predicted to decrease by 1.8 million barrels annually, approximately 1

percent, as a result of the standard.

Industry has expressed concern that the proposed rule could cause

some small refineries to shut down. Using conservative (i.e., worst

case) assumptions, the economic analysis indicates that from none to

seven small refineries are at risk of closure under the proposed rule.

The majority of the closures would occur in refineries that process

less than 10,000 to 20,000 barrels of crude oil per day. Also, the

regulatory flexibility analysis showed that compliance costs as a

percentage of sales are more than twice as high for small refiners

compared to other refiners. For more information, consult ``Economic

Impacts Analysis of the Petroleum Refinery NESHAP'' in the docket.

E. Benefits Analysis

The RIA presents the results of an examination of the potential

health and welfare benefits associated with air emission reductions

projected as a result of implementation of the petroleum refinery

NESHAP. The proposed regulation regulates HAP emissions from storage

tanks, process vents, equipment leaks, and wastewater emission points

at refining sites. Of the HAP's emitted by petroleum refineries, some

are classified as VOC, which are ozone precursors. Hazardous air

pollutant benefits are presented separately from the benefits

associated specifically with VOC emission reductions.

The predicted emissions of a few HAP's associated with this

regulation have been classified as probable or known human carcinogens.

As a result, one of the benefits of the proposed regulation is a

reduction in the risk of cancer mortality. Other benefit categories

include reduced exposure to noncarcinogenic HAP's, and reduced exposure

to VOC.

Emissions of VOC have been associated with a variety of health and

welfare impacts. Volatile organic compound emissions, together with

NOX, are precursors to the formation of tropospheric ozone.

Exposure to ambient ozone is responsible for a series of respiratory

related adverse impacts.

Based on existing data, the benefits associated with reduced HAP

and VOC emissions were quantified. The quantification of dollar

benefits for all benefit categories is not possible at this time

because of limitations in both data and available methodologies.

Although an estimate of the total reduction in HAP emissions for

various control options has been developed for the RIA, it has not been

possible to identify the speciation of the HAP emission reductions for

each type of emission point. However, an estimate of HAP speciation for

equipment leaks has been made. Using emissions data for equipment leaks

and the Human Exposure Model, the annual cancer risk caused by HAP

emissions from petroleum refineries was estimated. Generally, this

benefit category is calculated as the difference in estimated annual

cancer incidence before and after implementation of each regulatory

alternative. Since the annual cancer incidence associated with baseline

conditions was less than one life per year, the benefits associated

with the petroleum refinery NESHAP were determined to be small.

Therefore, these benefits are not incorporated into this benefit

analysis.

The benefits of reduced emissions of VOC from a MACT regulation of

petroleum refineries were quantified using the technique of ``benefits

transfer.'' Because analysis by the Office of Technology Assessment

from which benefits transfer values were obtained only estimated health

benefits in nonattainment areas, the transfer values can be applied to

VOC reductions occurring only in nonattainment areas. (Nonattainment

areas are geographical locations in which the National Ambient Air

Quality Standard for ozone has been violated.) The benefit transfer

ratio range for acute health impacts used in this analysis is from $25

to $1,574 per megagram of VOC with an average of $800 per megagram of

VOC. In order to quantify VOC emission reductions, these ratios were

multiplied by VOC emission reductions from petroleum refineries located

in ozone nonattainment areas. Estimated benefits for VOC reductions are

$148.3 million for the proposed regulation and $153.9 million for a

more stringent alternative.

The quantified benefits exceed costs by $15.9 million 1992 dollars

per year for the proposed alternative. The quantified benefits exceed

costs by $5.5 million 1992 dollars per year for the more stringent

alternative. Thus, a comparison of the incremental difference in the

two alternatives indicates that the incremental net benefits are

negative for the more stringent alternative.

V. Emission and Impact Estimation Methods

Emissions from petroleum refineries and the impact of controlling

emissions were estimated using information published in the Oil and Gas

Journal and provided by petroleum refineries in response to information

collection requests and questionnaires sent out under section 114 of

the Act. For a general discussion of the estimation methods for

existing and new petroleum refinery sources and references for

memoranda on the specific methods used for each kind of emission point,

refer to the memorandum, Emission and Impact Estimation Methods,

available in the Docket. It is noted that API provided the EPA with

emissions data that it has collected relatively recently on leaking

equipment. The EPA is evaluating this data. Once this review is

complete, the EPA intends to incorporate it into documents which are

used for estimating emissions, particularly on an individual plant

basis. It could also affect the emission reduction estimates provided

for the promulgated standard.

VI. Rationale for Proposed Standard

A. Selection of Source Category, Sources, and Pollutants

This section of the preamble describes the rationale for the

selection and definition of the petroleum refinery source category and

for the factors that the Administrator took into consideration in

defining the sources within the petroleum refinery source category.

1. Selection of Source Category

The definition of the source category is important in setting

standards because it sets the boundary for what emission points will be

regulated under this standard. A large plant site such as a refinery

could comprise multiple source categories. For example, a refinery is

likely to contain equipment that would be regulated under the

industrial cooling tower source category, the process heater source

category, the industrial boiler source category, or the SOCMI source

category. The petroleum refinery source category regulated under this

NESHAP is defined to include equipment specifically used to produce

fuels, heating oils, or lubricants by separating petroleum or

separating, cracking, or reforming unfinished petroleum derivatives.

The EPA's source category list (57 FR 31576, July 16, 1992),

required by section 112(c) of the Act, identifies categories of sources

for which NESHAP are to be established. This list includes all

categories of major sources of HAP's known to the EPA at this time, and

all area source categories for which findings of adverse effects

warranting regulation have been made. Two categories of sources are

listed for petroleum refineries: (1) catalytic cracking (fluid and

other) units, catalytic reforming units, and sulfur plant units,

scheduled for promulgation in 1997, and (2) other sources not

distinctly listed, scheduled for promulgation in 1995 (58 FR 63952,

December 3, 1993).

Based on review of information on petroleum refineries during

development of the proposed standards, it was determined that some of

the emissions points from the two listed categories of sources have

similar characteristics and can be controlled by the same control

techniques. In particular, miscellaneous process vents emitting organic

HAP's, storage vessels, wastewater streams, and leaks from equipment in

organic HAP service within catalytic cracking units, catalytic

reforming units, and sulfur plant units are similar to emission points

from the other process units at petroleum refineries (i.e., units in

the category of ``other sources not distinctly listed''). Because it is

most effective to regulate these emission points in a single

regulation, the EPA intends to amend the source category list when the

standards proposed today are promulgated. Upon revision, all emission

points from petroleum refining units included in today's proposed

standards will be in a single source category.

The petroleum refinery source category selected for regulation by

subpart CC includes process units for catalytic cracking (fluid and

other), catalytic reforming, sulfur plants, and other petroleum

refinery units not distinctly listed. The other units not distinctly

listed include, but are not limited to, process units for thermal

cracking, vacuum distillation, crude distillation, hydrotreating/

hydrorefining, alkylation, isomerization, polymerization, lube oil

processing, and hydrogen production. Units for processing natural gas

liquids, refining units for recycling discarded oil, and shale oil

extraction units are not covered by this rule. Ethylene processes are

not covered by this rule because they are included in a separate source

category.

Miscellaneous process vents, as defined in Sec. 63.641 of the

proposed rule, from the process units subject to this rule are part of

the petroleum refinery source category. Three kinds of vents at

petroleum refineries would not be included in the source category for

today's proposed rule. These vents--the catalytic cracking catalyst

regeneration vent, the catalytic reformer catalyst regeneration vent,

and the sulfur plant vents--will be included in a separate category

subject to a 1997 deadline. These vents have significantly different

HAP emission characteristics and would be controlled with different

controls than the rest of the refinery emission points. The standard

proposed today addresses emissions of organic HAP's. The FCCU catalyst

regeneration vent emits primarily metal HAP's, which would be

controlled using particulate controls. Catalytic reformer catalyst

regeneration vents emit hydrogen chloride, and sulfur plant vents emit

carbonyl sulfide and carbon disulfide. Because of their unique

characteristics, the EPA concluded that these emission points warranted

separate consideration. Because limited data are currently available,

these emission points will be included in a separate source category

under a separate schedule. (However, the EPA would like to clarify that

miscellaneous process vents (as defined in Sec. 63.641 of the proposed

rule) from catalytic cracking, catalytic reforming, and sulfur plant

units that emit organic HAP's would be subject to subpart CC.)

a. Distinction between petroleum refinery and SOCMI source

categories. This petroleum refineries NESHAP generally covers refinery

processes that produce petroleum liquids (such as gasoline, naphthas,

and kerosene) for use as fuels. Often, products of refinery processes

are used to make synthetic organic chemicals other than fuels. The

petroleum refineries NESHAP will not cover chemical manufacturing

process units that are covered under the SOCMI source category, even if

these units are located at a refinery site. A SOCMI chemical

manufacturing process unit that is located at a refinery and produces

one or more of the chemicals listed in the HON (40 CFR part 63 subpart

F, table 1) as a single chemical product or as a mixed chemical used to

produce other chemicals would be considered a SOCMI process and would

be subject to the HON rather than to the petroleum refineries NESHAP.

For example, MTBE, an additive used for octane enhancement in

gasoline, is a SOCMI chemical that can be produced at some petroleum

refineries and is made from a petroleum refinery product. The feedstock

for MTBE is a mixed C4, C5 hydrocarbon stream produced in an FCCU; the

FCCU is subject to the petroleum refineries NESHAP. However, MTBE is on

the list of SOCMI chemicals in the HON (40 part 63 subpart F), so the

process unit used to produce MTBE from the C4, C5 hydrocarbon feedstock

is regulated under the HON, not under the petroleum refineries NESHAP.

b. Exclusion of area sources. A petroleum refining process would be

subject to the proposed standard only if it is part of a major source.

A major source is any stationary source or group of stationary sources

located within a contiguous area and under common control that emits or

has the potential to emit, considering controls, more than 10 tons per

year of any HAP or more than 25 tons per year of total HAP. An area

source is any stationary source or group of stationary sources that are

not major sources. The General Provisions for the NESHAP (40 CFR part

63 subpart A), provide a definition of potential to emit. The General

Provisions apply to the petroleum refinery source category.

Based on the information available on petroleum refineries and

emission estimates developed for this standard, the EPA has no

information that can be used to determine whether area sources in the

petroleum refinery source category would present a threat of adverse

effects to human health or to the environment. It is believed that most

refineries are major sources, and that there are few, if any, area

sources. The EPA requests comments containing information on whether

there are area sources within the petroleum refining source category

and on the emissions from such sources. Commenters should provide the

basis for any emission estimates.

c. Exclusion of research and development facilities. The proposed

standard would not apply to research and development facilities, such

as laboratories and pilot plants, regardless of whether the facilities

are located on the same site as a commercial petroleum refinery.

Research and development facilities connected with petroleum refineries

are believed to be small, and the EPA has limited information about

their operations or about the appropriate controls for these

facilities. The EPA concluded, therefore, that it would not be

appropriate to include research and development facilities in this

regulation. In accordance with section 112(c)(7) of the Act, a separate

source category for research and development facilities may be

established at a later date if more comprehensive information becomes

available. Standards for such facilities may be developed at a later

date, if the EPA determines that such action is warranted.

d. Exclusion of transfer operations. Transfer operations at

petroleum refineries, that is, loading products into tank trucks,

railcars, or marine vessels, is not included in the source category

regulated by this rule. Loading of marine vessels will be regulated

under the Federal Standards for marine tank vessel for loading and

unloading operations and NESHAP for marine tank vessel for loading and

unloading operations. Emissions from loading tank trucks and railcars

will be regulated under the NESHAP for the gasoline distribution and

organic liquids distribution (nongasoline) source categories in the

liquids distribution industry group. The NESHAP for the gasoline

distribution source category was proposed in February 1994; the NESHAP

for the organic liquids distribution source category is scheduled to be

promulgated by 2000.

e. Small refineries. The standard proposed today would apply to all

refineries that are major sources including small refineries. Small

refineries maintain that they will be more severely affected by the

proposed rule than large refineries and therefore should be given

separate regulatory consideration. Small refiners point out that they

are predominately located in rural areas that are in compliance with

the Federal ambient air quality standard for ozone. Therefore, many of

them have not implemented LDAR programs and other control procedures

that have been started by large refiners to control VOC in ozone

nonattainment areas. As a result they will be confronted with

relatively high costs for starting LDAR programs and retrofitting

storage tanks. Moreover, small refiners point out that LDAR costs are

related more to refinery complexity than size. Therefore, refineries

that differ in size but have similar processing configurations will

incur similar costs. However, the costs on a per-barrel basis will be

higher for the small refineries.

The proposed rule does not treat small refineries as a separate

subcategory because the EPA could not identify fundamental technical

differences between small and large refineries. In addition, even if

small refineries were in a separate source category it appears that the

minimum control levels (floors) would not be much different from those

for the larger refineries. Comments are requested on whether a basis

exists for subcategorizing small refineries, and if so, at what size,

along with supporting data and rationale.

2. Selection of Source

The definition of source is an important element of this NESHAP

because it describes the specific grouping of emission points within

the source category to which each standard applies.

The EPA has broad discretion in defining ``sources.'' Section

112(d) directs the Administrator to set standards for all ``major

sources'' within every listed category. Area sources meeting the

requirements of sections 112(c)(3) or 112(k) must also be regulated.

Major sources are ``stationary sources,'' or groups of stationary

sources, of a given size, as defined in section 112(a)(1). The

definition of ``stationary source'' included in section 112 is

identical to the definition used in section 111(a), which is ``any

building, structure, facility, or installation which emits or may emit

any air pollutant.'' 42 U.S.C. 7411(a). However, section 112, as

amended, does not require that the standards set under section 112(d)

be set for the same components of the categories as was done under

section 111. Thus, there is no requirement that the section 112(d)

NESHAP for stationary sources be set for precisely the same portions of

the industry as the section 111 NSPS.

As the Supreme Court has recognized in Chevron, USA, Inc., versus

Natural Resources Defense Council, 467 U.S. 837 (1984) (hereafter

referred to as Chevron), EPA has broad discretion to define ``source.''

The Court recognized in Chevron that if any Congressional intent can be

discerned from the statutory language of section 111(a)(3) (the

definition of source that is used in section 112), ``the listing of

overlapping, illustrative terms was intended to enlarge, rather than

confine, the scope of the EPA's power to regulate particular sources in

order to best effectuate the policies of the Act.'' Chevron. Thus, the

court found that a ``source'' can encompass ``any discrete, but

integrated operation, which pollutes.'' Chevron. As such, the EPA has

flexibility, within the broad definition of ``stationary source,'' to

define the source for each section 112(d) standard as broadly or

narrowly as is appropriate for the particular industry being regulated.

Previous regulations have, in light of this flexibility, defined source

in a variety of ways, ranging from narrow to broad definitions. For

example, for BWON, the source was defined as the plant site, for the

petroleum refinery equipment leaks NSPS (40 CFR part 60, subpart GGG)

the source was the process unit, and for the petroleum refinery

wastewater NSPS (40 CFR part 60 subpart QQQ) the source was more

narrowly defined. There is no presumptive definition.

The proposed standard defines source as the collection of emission

points in HAP-emitting petroleum refining processes within the source

category that are part of a major source. The source comprises all

miscellaneous process vents, storage vessels, wastewater streams, and

equipment leaks associated with petroleum refining process units that

are located at a single plant site covering a contiguous area under

common control.

The way the source is defined has implications for setting MACT and

for compliance with the proposed rule. Emission standards for new and

for existing sources promulgated under section 112(d) of the Act must

represent the maximum degree of emission reduction achievable; this is

typically referred to as MACT. The EPA considered two possible

definitions of source for the petroleum refinery NESHAP. The source

could be defined narrowly as each individual process vent, storage

vessel, or wastewater stream or piece of equipment; or the source could

be defined broadly, as the collection of all such emission points at

the refinery.

The narrow definition of the petroleum refinery source, defining

the source as each individual emission point, was rejected because a

narrow definition is more appropriate when all emission points have

consistent characteristics and because it would not allow compliance

flexibility. For example, if each storage vessel were comparable to

each other storage vessel, so that the same performance level could

apply to them all, a narrow definition might be appropriate. In fact,

storage vessels can vary widely in size and material stored, and the

emission performance level appropriate for one may be inappropriate for

another. In addition, the control strategy for a refinery is decided at

a refinery level. Often, individual emission points within a refinery

are controlled together (e.g., multiple miscellaneous process vents can

be routed to one control system). Thus, it is reasonable to look at the

overall level of control a refinery is achieving because the size,

level of emissions, and significance of emissions can vary from point

to point.

A broad definition of source allows consideration of site-specific

differences and compliance flexibility, including emissions averaging.

With a broad definition, a source may exercise some choice in the level

of control of each individual emission point as long as the sourcewide

MACT level of emission reduction is met. This flexibility results in

benefits of achieving maximum emission reductions in a more efficient

and cost-effective manner.

Another reason for selection of the broad definition of source is

compatibility with the BWON source definition. This compatibility

allows the standards to be consistent and eliminates the burden of

overlapping standards and implementation problems that would arise if

the source for today's proposed rule was defined much more narrowly

than the BWON source.

The definition of source also affects refineries making changes to

existing facilities. Under the Act, sources that are constructed or

reconstructed after proposal of a standard are considered to be new

sources. Reconstructions are defined in Sec. 63.2 of the NESHAP General

Provisions (59 FR 12408, March 16, 1994) as the replacement of

components of an affected source to such an extent that the fixed

capital cost of the new component exceeds 50 percent of the fixed

capital cost that would be required to construct a comparable new

source. Upon reconstruction, an affected source is subject to standards

for new sources, including compliance dates, irrespective of any change

in emissions of hazardous air pollutants from that source.

With a narrower source definition, enforcement of the standard

would be difficult because any change to any emission point could

trigger regulatory provisions governing reconstruction. Reconstructed

sources are treated as new sources, so many small ``new'' sources could

be scattered throughout an existing refinery. Determining requirements

for different emission points would be complex, and the new or

reconstructed sources (which are treated as new sources) may require

control systems separate from the control systems for existing sources.

This could increase the cost and economic impact of the regulation.

With a broad source definition, the replacement or addition of new

equipment would be unlikely to exceed 50 percent of the fixed capital

cost of the source.

3. Determining New Source Status

The proposed rule clarifies the process for determining if new or

existing source requirements would apply to a particular petroleum

refining process unit or emission point. The requirements and

definitions used by the proposed petroleum refineries rule to

distinguish new and existing sources are consistent with section 112(a)

and the related components of the subpart A General Provisions. The

following would be subject to the subpart CC requirements for new

sources: (1) Petroleum refining process units constructed after the

date of proposal of subpart CC and having the potential to emit major

quantities (10 tons per year of any HAP or 25 tons per year of any

combination of HAP's); (2) existing sources reconstructed after that

date; and (3) ``greenfield'' petroleum refining process units that

constitute all or part of a major source constructed after that date.

(New source requirements would not be triggered by the addition of an

individual emission point, such as a storage vessel.) Thus, any change

or addition to an existing petroleum refinery plant site must meet the

same three criteria as a ``greenfield'' plant to be considered a new

source. The EPA proposes this approach for determining what is subject

to new source requirements to avoid providing an incentive for

petroleum refinery owners and operators to construct processes as area

sources. Also, EPA wanted to ensure that new sources built at existing

plant sites are subject to the same requirements as new sources that

are ``greenfield'' sites. Additions to an existing plant that do not

meet the requirements of being a petroleum refining process unit and do

not have the potential to emit major amounts, would be subject to

existing source requirements.

4. Selection of Pollutants

The HAP's that are emitted from the emission points that make up

the source in this source category are all organic HAP's; the

predominant HAP's are benzene, toluene, xylene, ethylbenzene, and

hexane. Therefore, the provisions of this NESHAP apply to the organic

HAP's listed in section 112(b) of the Act.

B. Selection of Miscellaneous Process Vent Provisions

The definition in Sec. 63.641 of the proposed rule describes the

vents that are considered to be ``miscellaneous process vents.'' The

available data indicated that these vents have similar emission

characteristics and can be controlled by the same type of control

technologies.

1. Selection of Emission Control Requirements

The Act specifies that the EPA, in determining the MACT level of

control for sources regulated under section 112, must select emission

control requirements that are at least as stringent as, or more

stringent than, the emission control level identified as the floor. As

a result, the EPA began the process of selecting control requirements

for miscellaneous process vents by determining MACT floors for existing

and new sources. The MACT floor determinations are fully described in a

memorandum ``Determination of the Petroleum Refinery MACT Floors for

Existing and New Sources,'' available in the docket. This section

summarizes the MACT floors as they relate to miscellaneous process

vents, and the selection of the proposed process vent provisions.

The Act requires that the EPA determine MACT based on consideration

of cost, energy requirements and nonair quality health and

environmental impacts. The EPA maintains that the requirements of this

proposed rule were determined based on these statutorily-specified

criteria. The EPA requests comment on the appropriateness of

considering additional criteria such as pollution prevention,

environmental equity, affordability, and technology innovation.

a. Existing sources. Based on information contained in industry

responses to the EPA's ICR and section 114 questionnaires, it was

determined that the average emission limitation achieved by the best

performing 12 percent of sources is combustion control of all

miscellaneous process vents. Data analyses conducted in developing

previous NSPS and the HON determined that combustion controls can

achieve 98 percent organic HAP reduction or an outlet organic HAP

concentration of 20 ppmv for all vent streams. The selection of these

numerical levels is described in the preamble for the proposed reactor

processes NSPS (55 FR 26953, June 29, 1990).

The MACT floor level of control for existing sources, therefore,

includes reduction of organic HAP emissions from miscellaneous process

vents by 98 percent or to a level of 20 ppmv for miscellaneous process

vents with concentrations that exceed de minimis levels. A de minimis

level of 20 ppmv was selected. Process vents with organic HAP emission

levels below this concentration would not be subject to the proposed

rule because the available technologies may not be able to reduce

organic emissions below this level. Regulatory options more stringent

than the floor were not investigated for miscellaneous process vents

because no available technology that is generally applicable can

achieve a more stringent level of control than the MACT floor.

Therefore, the standard being proposed for miscellaneous process vents

at existing sources is the MACT floor.

The estimated emission reductions and cost impacts for the proposed

standards for all emission points are shown in table 3. The

miscellaneous process vent costs are based on routing the vents to the

refinery fuel gas or flare systems. Some industry representatives have

expressed concerns that the costs may be underestimated. The EPA

requests specific cost data and information on how miscellaneous

process vents at existing sources would be controlled and what the cost

would be.

Table 3.--Control Options and Impacts

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

HAP Cost effectiveness ($/Mg

Baseline -------------------------- HAP)

Source emissions Control Emission Percent Annual cost -------------------------

(Mg/yr) optiona reduction emission ($1,000/yr)

(Mg/yr) reduction Average Incremental

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

Miscellaneous

Process Vents:

Existing 8,900 Floor*........ 7,600 85 13,000 1,700 N/A

sources.

New sourcesb.. 900 Floor*........ 770 85 370 480 N/A

Storage Vessels:

Existing 9,000 Floor*........ 1,300 14 11,400 8,500 N/A

sourcesc.

Option 1*..... 1,800 20 13,600 7,800 4,400

Option 2...... 2,600 29 37,000 14,000 30,000

New sourcesb.. 290 Floor*........ 4 1.4 98 24,000 N/A

Option 1...... 14 4.8 550 39,000 45,000

Wastewater:

Existing 9,200 Floor*........ ........... N/A ........... N/A N/A

sources.

Option 1...... 7,700 93 120,000 15,000 15,000

New sourcesb.. 960 Floor*........ ........... N/A ........... N/A N/A

Option 1...... 930 97 18,000 20,000 20,000

Equipment Leaks:

Existing 50,000 Floord........ 35,000 69 69,000 2,000 N/A

sources.

Option 1*..... 44,000 87 66,000 1,500 -330

Option 2...... 46,000 91 78,000 1,700 6,000

New sources... 1,300 Floor*,d...... 640 49 -210 -330 -330

Option 1...... 760 59 840 1,100 8,300

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

aExplanation of control options:

Storage Vessels

Existing Sources

Floor=Subpart Kb floating roof with specified seals or closed vent systems and control devices for vessels 177 m3 storing liquid with the vapor pressures 8.3 kPa.

Option 1=Floating roof with subpart Kb specified seals and fittings for vessels 151 m3 storing

liquids with true vapor pressure 5.2 kPa.

Option 2=Floating roof with subpart Kb specified seals and fittings for vessels 151 m3 storing

liquids with true vapor pressure 0.014 kPa.

New Sources

Floor=Floating roof with subpart Kb specified seals and fittings for vessels 151 m3 storing liquid

with the vapor pressures 3.4 kPa, and vessels 76 m3 storing liquids with vapor

pressures equal to or greater than 77 kPa.

Option 1=Floating roof with specified seals and fittings for vessels 151 m3 storing liquids with

true vapor pressures 0.014 kPa, and vessels 76 m3 storing liquids with vapor pressures

equal to or greater than 77 kPa.

Equipment Leaks

Existing Sources

Floor=Compliance with the petroleum refinery NSPS.

Option 1=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63, without

connectors.

Option 2=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63.

New Sources

Floor=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63, without

connectors.

Option 1=Compliance with the negotiated equipment leaks regulation in HON, subpart H of part 63.

Wastewater

Existing and New Sources

Floor=Compliance with the BWON for any refinery with > 10 Mg/yr of benzene loading in waste. Controlling waste

streams > 10 ppm benzene by weight with flow rates > 0.02 1/min.

Option 1=Compliance with the BWON for all refinery wastewater streams.

Miscellaneous Process Vents Existing and New Sources

Floor=Control to 20 ppm HAP or 98 percent reduction of HAP by combustion.

bImpacts were estimated for new process units constructed in the 5 years after promulgation. For regulatory

purposes, some of these units may be considered new sources while others may be considered part of an existing

source.

cThe floor and option 1 are being co-proposed for storage vessels at existing sources and the EPA is requesting

comment on which should be selected.

dFor equipment leaks at both new and existing sources the option identified as the ``floor'' is slightly more

stringent than the actual floor. For ease of costing, these options were chosen to represent the floor. See

footnote ``a'' for an explanation of the control options.

*=Control option chosen.

N/A=Not applicable.

Industry has commented that the control requirements for the

process vents should be based on a cost-effectiveness method similar to

the TRE approach used in the HON rule. Industry recommendations are

based on limited information which indicates that the control cost per

ton of HAP reduction can differ by several hundred percent. As in the

HON, the differences are apparently due to wide variations in the

control costs and the HAP content of the process vents.

The EPA requests comment on whether or not the control requirements

for the miscellaneous process vents should be based on a cost-

effectiveness approach similar to the TRE method used in the HON. The

EPA does not have the information to determine if a cost-effectiveness

approach is needed or to develop one and to relate it to the floor. The

required information includes descriptions of the sources of emissions

and the emission controls. The vent stream characteristics such as flow

rate, heating value, VOC, and HAP contents are also required.

Information provided by industry in response to two formal EPA

questionnaires contained little information with respect to the vent

stream characteristics. It is not possible to develop TRE equations

that are specific to petroleum refineries without this information. In

the event that the EPA develops a TRE, the Agency requests the

information that is needed to develop cost-effectiveness equations for

the refining industry similar to those in the HON. The information is

requested for a representative segment of the refining industry. If

this information is received, the EPA will analyze it before

promulgation of this rule and will utilize a TRE approach if such an

approach appears appropriate.

Industry has commented that the cost equations for the TRE

requirements in the HON rule may be applicable to the refining

industry. The EPA solicits comment with supporting information on the

applicability of the HON cost equations to the refining industry such

as information on the similarity or differences between the refining

industry and the SOCMI in terms of vent stream characteristics (flow,

concentration, heating value) and for combustion control device designs

in use.

Industry has commented that the applicability levels for the HAP

concentration (50 ppmv) and the flow rate (0.005 standard cubic meter

per minute) in the process vents provisions of the HON should be

applicable to the refining industry. The purpose of the applicability

levels is to avoid affecting large numbers of small vents whose

cumulative emissions are small relative to the control costs and the

costs of monitoring, recordkeeping and reporting. The EPA requests

information to determine if there are large numbers of small vents with

low HAP concentrations in the refining industry, and whether such vents

are controlled. If such vents exist, the EPA also requests information

to determine the applicability levels that would avoid affecting vents

where the emission control and administrative costs are inordinately

high relative to the emission reductions. If sufficient data are

received and the MACT floor does not require control of such vents, the

EPA will include appropriate applicability levels in the final rule.

Industry has commented that the EPA has overestimated the HAP and

VOC emissions from the miscellaneous process vents--particularly from

the alkylation and vacuum distillation units. The estimates are based

on: (1) Information submitted by the petroleum refining industry in

response to the EPA questionnaires, and (2) emission estimation

extrapolations and assumptions by the EPA where reported data were

insufficient. Industry has questioned the assumptions made by the EPA

in their analysis. Industry maintained that part of the reported

emissions may be from water blowdowns, equipment leaks or from other

emission sources that are not true process vents. The EPA will consider

revising the emission estimates if the EPA receives new data

demonstrating that revisions are appropriate.

Industry has commented that since the HAP to VOC ratio for

reformers is dissimilar to other process units, the EPA should not use

it to estimate HAP emissions from process units other than reformers.

The EPA agrees with industry on this point and plans to revise the

estimates after considering any new information submitted.

b. New sources. Because the best performing source controls all

miscellaneous process vents by combustion, the new source MACT floor

includes reduction of emissions from miscellaneous process vents by 98

percent or to a level of 20 ppmv. A 20 ppmv de minimis concentration

was selected for the same reason as existing sources. There are no

available control options that are generally applicable that can

achieve emission levels more stringent than the floor. Therefore, the

standard being proposed for miscellaneous process vents at new sources

is the MACT floor. The cost and emission reduction for new source are

presented in table 3.

2. Selection of Format

The format of the regulation for miscellaneous process vent streams

depends on the kind of control device the refinery selects. For vent

streams controlled by control devices other than flares, the format of

the regulation is a combination of a weight-percent reduction and an

outlet concentration. A weight-percent reduction format is appropriate

for process vent streams with HAP concentrations above 1,000 ppmv,

because a weight-percent limit is the best measure of the performance

of combustion control devices and will assure that MACT is applied. For

process vent streams with HAP concentrations below 1,000 ppmv, the

format of the regulation is a 20 ppmv outlet concentration, because 98

percent HAP reduction may not be achievable.

For vent streams controlled by a flare, the proposal refers to the

performance specifications in the General Provisions (40 CFR part 63,

subpart A, section 63.11). An emission limit or percent reduction

format was not selected because it is very difficult to measure the

emissions from a flare to determine its efficiency.

The petroleum refinery fuel gas system is considered part of the

refinery processes; therefore, any vent stream being recovered and

routed to the fuel gas system is also considered part of the process.

These vent streams are not considered miscellaneous process vents and

are not subject to subpart CC. Furthermore, these vents are already

controlled to the most stringent levels achievable.

3. Selection of Performance Tests, Monitoring Requirements, and Test

Methods

The standard specifies the performance tests, monitoring

requirements, and test methods necessary to determine whether a

miscellaneous process vent stream is required to apply control devices

and to demonstrate that the allowed emission levels are achieved when

controls are applied. The format of these requirements, as with the

format of the miscellaneous process vent provisions, depends on the

control device selected.

a. Performance test. Performance tests ensure that a control device

can achieve the required control level and help establish operating

parameters that indicate proper operation and maintenance. Initial

performance tests are required for control devices other than flares

and certain boilers and process heaters. Specifically, testing would be

required for incinerators, and for boilers and process heaters smaller

than 44 MW (150 million Btu/hr) where the vent stream is not used as

the primary fuel or mixed with the primary fuel prior to being

introduced into the boiler.

As previously stated, miscellaneous process vent streams routed to

the refinery fuel gas system are not subject to these standards, and

boilers and process heaters that use refinery fuel gas are not required

to be tested.

An initial performance test is not required for boilers and process

heaters larger than 44 MW (150 million Btu/hr) because they operate at

high temperatures and residence times. Analysis shows that when vent

streams are introduced into the flame zone of these boilers and process

heaters, over 98 percent reduction or an outlet concentration of 20

ppmv is achieved. Therefore, a performance test is not necessary.

Because percent reduction and outlet concentration cannot feasibly

be measured at flares, the flare must meet the requirements for

operating conditions in Sec. 63.11 of 40 CFR part 63 subpart A.

b. Test methods. The proposed miscellaneous process vent provisions

would require the use of approved test methods to ensure consistent and

verifiable results for initial performance tests and compliance

demonstrations. The proposed regulation refers to the HON (40 CFR part

63, subpart G) for performance test provisions; but the rationale for

the use of these provisions for petroleum refineries is presented

below. For performance tests, Methods 2, 2A, 2C, or 2D of 40 CFR part

60, appendix A, are specified for measuring vent stream flow rate.

Method 18 of 40 CFR part 60, appendix A, is specified for measuring

total vent stream HAP or TOC concentration at the outlet of the control

device to determine whether outlet HAP concentration is below 20 ppmv

or at both the inlet and outlet of the control device to determine if

HAP emissions are reduced by 98 percent. In order to allow owners or

operators greater flexibility, the proposed provisions also allow the

use of any test method or test results validated according to the

protocol in Method 301 of 40 CFR part 63, appendix A.

The EPA considered allowing Method 25A as an alternative to Method

18 for demonstrating compliance of control devices applied to process

vents; however, Method 25A is not included as an alternative for

demonstrating compliance with the emissions reduction. The basis for

the decision was that the EPA determined that the results obtained with

Method 25A would not consistently demonstrate HAP control efficiency.

Miscellaneous process vent streams often contain mixtures of multiple

organic HAP's and other organic compounds. The TOC measurements

obtained with Method 25A would vary depending on how the method is

calibrated, because response factors for individual compounds vary.

Furthermore, some compounds are not well detected by Method 25A.

Another concern is that the relative proportion of individual organic

compounds may change across the combustor. Therefore, specifying

calibration with the principal HAP in the inlet would not necessarily

produce reliable results.

c. Monitoring. Control devices used to comply with the proposed

standard need to be maintained and operated properly if either a 98

percent reduction or outlet concentration of 20 ppmv is to be achieved

on a continuing basis. Monitoring of the control device operating

parameters can be used to determine if the emission limit is being met

on a continuous basis. The monitoring of operating parameters

constitutes enhanced monitoring, as discussed in section VI.F of this

notice.

The EPA considered two monitoring options: (1) the use of CEMS to

measure HAP's and (2) continuous monitoring of control device operating

parameter. Continuous emission monitoring systems are not currently

available for all of the organic HAP's found in miscellaneous process

vent streams. Thus, direct monitoring of HAP emission reduction or

concentration is not possible for every stream. Furthermore, for those

HAP's where CEMS are available, the costs of installing, calibrating,

operating, and maintaining CEMS and flow monitors at both the inlets

and outlets of every control device (which would be needed to determine

percent reduction) would be much higher than the costs of parameter

monitoring. The use of CEM's would, therefore, increase the cost

impacts of the rule.

It is proposed that the continuous monitoring of control device

operating parameters be used to determine whether continuous compliance

is achieved. The proposed standard lists the parameters that can be

monitored for the common types of combustion devices: thermal

incinerators, catalytic incinerators, boilers and process heaters, and

flares. These parameters were selected because they are good indicators

of combustion device performance, and instruments are available at a

reasonable cost to monitor these parameters continuously. The proposed

rule also allows the owner or operator to request to monitor parameters

not listed in the proposed standard on a site-specific basis.

The proposed standard would require the owner or operator to

establish site-specific parameter ranges through the Notification of

Compliance Status report or the operating permit submitted to comply

with Title V of the Act. Site-specific parameter ranges accommodate

site-specific differences in control design and process vent stream

characteristics. Failure to maintain the established values of the

monitored parameters would be an enforceable violation of the emission

limits of the standard.

The proposed petroleum refineries NESHAP does not require

monitoring boilers or process heaters with a heat capacity of 44 MW

(150 million Btu/hr) or greater, or boilers or process heaters with a

heat capacity less than 44 MW (150 million Btu/hr) that introduce the

process vent stream as a primary fuel or mix it with the primary fuel

and introduce it through the same burner. These devices operate at

temperatures and residence times that the EPA has concluded will ensure

compliance with the emission limits (at least 98 percent reduction of

total HAP). Therefore, if the vent stream is routed to the devices as

described above and enters at the specified locations, continuous

compliance is demonstrated.

C. Selection of Storage Vessel Provisions

1. Selection of Emission Control Requirements

This section summarizes the MACT floors for new and existing

sources as they relate to storage vessels, regulatory alternatives more

stringent than the floors, and the rationale for the selected

alternatives for storage vessels.

a. Existing sources. Based on information on storage vessel control

levels and vessel capacities and vapor pressures submitted to the EPA

by petroleum refineries, the MACT floor level of control was determined

to be: storage vessels with capacities greater than or equal to 177

m3 storing liquids with true vapor pressures greater than or equal

to 8.3 kPa must control to the level of 40 CFR part 60 subpart Kb with

the exception of fitting requirements for floating roof vessels. This

represents the average level of storage vessel control achieved at the

best-performing 12 percent of sources. The control applicability

criterion of 177 m3 (1,115 barrels or 47,000 gallons) was selected

because the best-performing sources do not control storage vessels with

capacities below this size. The vapor pressure of 8.3 kPa (1.2 psia)

was determined by screening the data set for controlled tanks (tanks

that met subpart Kb seal requirements) at increasing vapor pressures

until the cumulative number of tanks identified as controlled equalled

12 percent of the entire data set. The average vapor pressure of the

petroleum liquids in these controlled tanks was 8.3 kPa.

The EPA also considered two alternative levels of emission

limitation. Each required control to subpart Kb levels including

controlled fittings for floating roof vessels and were for control of

vessels with capacities greater than or equal to 151 m3 (950

barrels or 40,000 gallons). However, each of the alternatives had a

different true vapor pressure applicability criterion. The first

alternative required that vessels storing liquids with a true vapor

pressure greater than or equal to 5.2 kilopascals (0.75 psia) be

controlled. This alternative was analyzed because it also corresponds

to one of the applicability tiers of subpart Kb of 40 CFR part 60. The

second alternative was for controls being required for vessels storing

liquids with a true vapor pressure greater than or equal to 0.014

kilopascals (0.002 psia). This alternative was chosen in order to

assess the impact of control of vessels storing low vapor pressure

liquids such as diesel/distillate, jet kerosene/kerosene, heavy gas

oil, residual fuel oil, and asphalt. Table 3 presents the emission

reductions and cost for the MACT floor level of control and the two

options above the floor.

The EPA is co-proposing the floor level of control, and option 1,

for storage tanks in order to promote comment on both options. The

floor requires that petroleum liquids with true vapor pressures of 8.3

kPa (1.2 psia) or higher be placed in floating roof storage tanks

equipped with seals that comply with the NSPS for volatile organic

liquids (subpart Kb of 40 CFR part 60). The floor control will reduce

the current HAP emissions from storage tanks by 14 percent. This

relatively small emission reduction is due to the fact that most

volatile petroleum liquids are stored in floating roof tanks to reduce

product losses or to comply with VOC control requirements in ozone

nonattainment areas. The emission reductions associated with upgrading

the seals on such tanks to comply with subpart Kb requirements are, in

many cases, modest.

Controlling both the fittings and the seals to subpart Kb

requirements was evaluated as option 1. The EPA seeks comment on

whether the floor level or control or option 1 should be selected. In

particular, the EPA requests comment on whether or not the incremental

cost effectiveness of option 1--$4,400 per ton of HAP emissions

reduced--should be viewed as making that option unachievable

considering cost. The EPA also requests comment on whether option 1

should be selected because of a combination of factors. Specifically,

option 1 achieves a greater degree of pollution prevention because even

less product is lost due to evaporation. In addition, the vapor

pressure and storage tank size applicability levels for option 1

correspond to the HON's applicability levels for large storage tanks.

Also, since HAP emissions represent roughly 10 percent of VOC

emissions, additional cost-effective VOC reductions would result from

option 1. Finally, option 1 would provide a 20 percent reduction,

rather than a 14 percent reduction, in emissions of the types of HAP

emitted from petroleum refinery storage tanks.

No nonair quality health impacts, energy, or other environmental

impacts were expected from any of the alternatives. Thus, these

considerations did not affect the choice of the proposed rule. The

controls required by the proposed requirements are not expected to

create any secondary emissions of carbon monoxide or nitrogen oxides.

b. New sources. The MACT floor for new sources is control of

vessels equal to or greater than 151 m3 (950 barrels or 40,000

gallons) with vapor pressures equal to or greater than 3.4 kPa (0.5

psia), and vessels with capacities equal to or greater than 76 m3

(475 barrels or 20,000 gallons) storing liquids with vapor pressures

equal to or greater than 77 kPa (11.1 psia). Such vessels would be

required to meet requirements essentially equivalent to 40 CFR part 60

subpart Kb (i.e., use of floating roofs with proper seals and

controlled fittings, or a closed vent system with a 95 percent

efficient control device). The applicability criteria are based on the

most stringent regulations that apply to petroleum refinery storage

vessels including Rule 463 of California's South Coast Air Quality

Management District and the storage vessel NSPS (subpart Kb).

The MACT floor and an option more stringent than the floor

requiring control of storage vessels with vapor pressures above 0.014

kPa (0.002 psia) (which is the same as option 3 for existing sources)

was also considered. The proposed level of control for new sources is

the MACT floor. Vessels with capacities greater than or equal to 151 m3

(950 barrels or 40,000 gallons) storing liquids with true vapor

pressures greater than or equal to 3.4 kPa (0.5 psia), and vessels with

capacities greater than or equal to 76 m\3\ (475 barrels or 20,000

gallons) storing liquids with vapor pressures equal to or greater than

77 kPa (11.1 psia) would be required to comply with the subpart Kb

(including the controlled fitting requirements). The option more

stringent than the floor was not selected because it would result in

high costs relative to HAP emission reduction.

2. Selection of Format

The storage vessel provisions in the HON rule are very similar to

the requirements of subpart Kb. The HON storage provisions are clearer

and give more details in explaining the controlled fitting requirements

than subpart Kb. The HON provisions have an allowance for existing

source owners and operators to wait for the next scheduled maintenance

for the upgrading of certain seals and installation of fittings on

vessels already equipped with floating roofs; this provision is not in

subpart Kb because it applies only to new storage vessels. In addition,

the HON storage vessel provisions clarify the provisions that apply

when an EFR is converted to an IFR as a means of compliance. Because of

all these reasons, the EPA elected to refer directly to the

requirements in the HON. The format of the HON includes equipment and

work practice standards; if control devices are used, there is an

emission standard (percent reduction) format. For storage vessels at

existing sources the HON storage vessel provisions are referred to

without the controlled fitting requirements. For storage vessels at new

sources all of the requirements in the HON storage vessel provisions

are referred to.

The proposed regulation differs from the HON in that storage

vessels that contain petroleum liquids with true vapor pressures of 5.0

psia or greater are required to comply with the proposed rule within 3

years. That is, refiners are not permitted to wait until the next

scheduled maintenance to install the emission controls if such

maintenance is beyond the compliance date. Calculations indicate that

when the true vapor pressure of the material in the tanks exceeds 5.0

psia, the emission reductions that result from installing controls

within 3 years more than offset the HAP emissions created from cleaning

and degassing the storage vessels. The EPA requests comment on this

conclusion with supporting data and calculations.

3. Selection of Compliance Determination Provisions

The proposed compliance determination provisions for storage

vessels include inspections of floating roofs and design evaluations

and monitoring of closed vent systems and control devices. The use of

monitoring and inspections to determine continuous compliance

constitute enhanced monitoring.

For storage vessels controlled with floating roofs, it is not

feasible to capture and continuously monitor emissions. Therefore,

periodic inspection of roof seals for IFR's and EFR's and seal gap

measurements for EFR's are used to determine compliance with the

storage vessel equipment and work practice standards. If defects are

found during inspections they must be repaired within specified times.

There are provisions for requests for extensions and delay of repair of

certain conditions are met. These inspection and repair provisions are

similar to the HON, and the proposed rule cross-references the HON

where appropriate. Failure to perform inspections or to complete

repairs as specified constitutes an enforceable violation of the

standards.

For storage vessels controlled by closed vent systems and control

devices, the EPA considered the use of CEMS to measure HAP's and

control device operating parameter monitoring. Continuous emissions

monitoring was determined to be infeasible for the same reasons

described in the miscellaneous process vents section. Furthermore,

emissions from storage vessels have low flow rates and also have highly

variable flows and concentrations with the majority of emissions

occurring during filling. These characteristics would complicate

emission monitoring. Control device operating parameter monitoring is

proposed as a means of determining continuous compliance with the

percent reduction specified for control devices. The petroleum

refineries rule, which cross-references the HON, provides for sources

to establish site-specific control device operating parameters and

ranges appropriate to their storage vessel control system.

D. Selection of Wastewater Collection and Treatment Operation

Provisions

1. Selection of Emission Control Requirements

This section summarizes the determination of the MACT floors for

new and existing sources as they apply to wastewater, regulatory

alternatives more stringent than the floors, and the rationale for the

selected alternative for wastewater.

The alternative selected for proposal is the floor level of control

(compliance with BWON). The BWON controls 75 percent of the benzene in

refinery wastewater nationwide and 76 percent of the volatile organic

HAP in refinery wastewater. (For more information, refer to the

memorandum in the docket entitled ``The Effectiveness of the Benzene

Waste Operations NESHAP for Controlling Volatile HAP Loading in

Petroleum Refinery Wastewater''). The EPA believes that benzene is an

effective surrogate for indicating the presence of all HAP compounds in

petroleum refinery wastewater because data show that the majority of

the total HAP compound loading in wastewater consists of compounds that

are very similar to benzene in terms of both chemical structure and

volatility (from the water phase to the air phase). Volatile HAP

compounds are present in a fairly constant ratio to benzene

(approximately four-to-one on a mass basis) except in two

circumstances, product blending and MEK dewaxing units. Because of the

different nature of these processes, different ratios would be

expected. In both of these process units HAP's are added. In the case

of MEK dewaxing units the benzene concentration is relatively low, less

than 1 ppmw on average; however, the baseline volatile HAP emissions

from MEK dewaxing units are also relatively low, less than 1 percent of

the HAP baseline emissions. For product blending, the benzene

concentration is relatively high, greater than 10 ppmw on average;

therefore, even though the HAP-to-benzene ratio is not the same as with

other process units, wastewater streams from product blending process

units have a sufficient benzene concentration that control would be

required at applicable facilities. Thus, the EPA maintains that benzene

is a good surrogate for all HAP compounds. The EPA requests comment on

this position and any supporting data.

Because the proposed standard for wastewater requires compliance

with the existing BWON, no additional emission reduction, cost, energy,

or other environmental or health impacts are associated with the

proposed standard.

a. Wastewater: Existing sources. The best performing wastewater

control systems are those that are in place to comply with the BWON.

These systems control not only benzene, but are also expected to

control the other organic HAP's in petroleum refinery wastewater. The

BWON applies to wastewater streams that contain 10 ppmw benzene or

greater, have a flow of 0.02 l/min or greater, and are located at

facilities with a TAB loading of at least 10 Mg/yr in waste and

wastewater. Based on data provided to the EPA through the BWON 90-day

reports, the EPA determined that the BWON was applicable to 43 percent

of the refineries. No refineries are known to have more stringent

controls than the BWON. Therefore, the MACT floor, or the average of

the top performing 12 percent of sources, is control to the BWON level

of control.

The EPA considered an alternative level of emission reduction more

stringent than the MACT floor that would be achieved by controlling all

wastewater streams with at least 10 ppmw benzene at any refinery

regardless of the size of its annual benzene loading. Table 3 presents

the cost and emission reductions for the MACT floor and the alternative

more stringent than the floor.

Alternative control option 1 was not selected because the

additional emission reduction achieved through further control was not

significant, given the associated costs (see table 3). Also, this

option would primarily affect small refineries and it is expected that

it could have significant impact on small businesses. There may be some

additional nonair quality benefits, such as reduced generation of

hazardous waste and reduced water contamination, and air quality

benefits from reduction of non-HAP VOC; however, these benefits could

not be quantified.

b. Wastewater: New sources. The analysis of the data base also

showed that the maximum emission reduction being achieved at any source

is determined by the control requirements for the BWON. Thus, the floor

for new sources is control to the BWON level of control. The floor

alternative was selected as the proposed level of control for new

sources. As with existing sources, the option more stringent than the

floor was considered, and the impacts are shown in table 3. Option 1

was rejected for new sources for the same reasons described above for

existing sources.

2. Selection of Format

Because the BWON is the basis of the selected level of control for

both new and existing sources, the EPA elected to refer directly to

those requirements. The provisions for controlling air emissions from

wastewater streams are a combination of equipment, operational, work

practice, and emission standards. The reasons for selection of these

formats are described in the preamble to the proposed BWON standards

(54 FR 38083, September 14, 1989).

3. Selection of Testing and Monitoring Provisions

Because the proposed refineries NESHAP refers directly to the BWON

equipment, operational, work practice, and emission standards, it is

also appropriate to refer to the testing and monitoring requirements of

BWON for compliance determination. The monitoring procedures required

by the BWON would be used to determine compliance with the standard.

Failure to maintain the established values of monitored parameters, or

failure to conduct the required measurements and inspections would be

an enforceable violation of the standards.

E. Selection of Equipment Leak Provisions

1. Selection of Emission Control Requirements

This section of the preamble summarizes the MACT floors as they

relate to equipment leaks within new and existing sources, regulatory

alternatives more stringent than the floors, and the rationale for the

selected alternative for equipment leaks. As mentioned in section

VI.B.1 of this preamble, the EPA requests comment on consideration of

pollution prevention, environmental equity, affordability, and

technology innovation as additional criteria in the selection of MACT.

a. Equipment leaks: Existing sources. The EPA's analysis indicated

that the average control level of the best-controlled 12 percent of

sources, the MACT floor level of control, is between the level of

control required by the petroleum refinery CTG and the petroleum

refinery NSPS. For costing purposes, the petroleum refinery NSPS level

of control was used for the MACT floor option. This was done because it

would have been difficult to determine the requirements for an option

in between the two levels of control. Also by using the NSPS the

results were a conservative estimate of the cost of the MACT floor; and

the option was not less stringent than the floor.

Two options above the floor were also considered based on the

negotiated rule for equipment leaks (40 CFR part 63, subpart H). As

discussed in the preamble presenting the rationale for the negotiated

rule (57 FR 62659 and 57 FR 62660), the framework developed in the

regulatory negotiation was the presumptive basis for the refinery

standard. The EPA also agreed in the negotiation to consider whether

the numerical standards and leak definitions established for SOCMI

sources were achievable by refineries. While both options 1 and 2 are

based on the negotiated rule, option 1 does not include the connector

provisions. Table 3 presents the estimated cost and emission reduction

for the floor and the two additional options.

The proposed standard is the negotiated rule without the connector

provisions and with a few exceptions. (The exceptions to the negotiated

rule are discussed in the remainder of this subsection.) This option,

which is similar to option 1, was selected because it is consistent

with the negotiated rule, and it achieves significant emission

reduction at a reasonable cost relative to the MACT floor. As discussed

later in this section, more frequent valve monitoring is allowed in

place of connector monitoring because, as shown in the table for option

2, the cost of connector monitoring is high relative to the emission

reduction achieved, and additional valve control is a more cost

effective way to reduce emissions.

No nonair quality health impacts, energy, or other environmental

impacts were expected from any of the alternatives. Thus, these

considerations did not affect the choice of the proposed requirements.

In light of the agreements made during the negotiation, the EPA

considered whether leaks should be defined differently in the proposed

refinery standard than in subpart H, what performance level should be

established in phase III of the pump and valve standards, and which

provisions in the negotiated rule were relevant and applicable to

refinery operations. Available monitoring data from a few refineries

and differences between typical refinery operations and SOCMI

operations (e.g., turnaround schedules, line sizes, percent HAP in

process fluids, line pressures) were considered. The differences were

found to affect the availability of some low emission technologies and

the achievable performance levels. The EPA concluded that a few changes

to the provisions of the negotiated rule (40 CFR part 63 subpart H)

were necessary to ensure that the proposed standard for refineries is

achievable. The changes to the provisions and the reasons for the

changes are discussed below.

One change that was considered was a change to the definition of

``in organic hazardous air pollutant service.'' Using the definition

from the negotiated rule, equipment that contains or comes in contact

with fluid that is less than 5 percent by weight total organic HAP's

would not be subject to the equipment leak provisions.

Pump standard. The negotiated rule for equipment leaks implements

the leak detection and repair program for pumps in three phases, with

lower leak definitions in the later phases. The EPA considered the

available information on emission performance of mechanical seals and

concluded that the negotiated standard for pumps was achievable. The

proposed standard for refineries, however, has been simplified to

specify only one leak definition in phase III. The negotiated

provisions for pumps in polymerizing monomer service and food/medical

service are not relevant to this category, and therefore have not been

included in the refinery standard. In addition, to simplify the rule, a

leak has been defined as a concentration of 2,000 ppm or greater. This

change makes the level at which repair is required the same as the leak

definition. Additionally, low emission single seal technology has

progressed to the point where these seals can achieve a 2,000 ppm leak

definition for certain process services. It is expected that this will

result in lower costs to comply than if dual seals were necessary.

Additionally, in examining the appropriateness of the pump standard

to refinery operations, the EPA considered whether to extend some of

the concepts of the negotiated valve standard to the pump standard for

refineries. Specifically, the EPA considered whether to allow reduced

monitoring frequency for better performance and to allow increased

monitoring frequency as an alternative to the QIP for poor performance.

The negotiated valve standard included incentive provisions to

encourage better performance and two forms of penalty options to

consider differences among facilities' ability to undertake a QIP.

After considering the predicted differences in effectiveness of

different monitoring intervals for pumps, the EPA concluded that an

incentive for better performance could be included in the pump standard

and still assure better emission performance. The pump standard for

refineries thus would allow facilities that achieve less than 3 percent

of pumps leaking, or one pump leaking, to monitor pumps quarterly; and

facilities that have greater than 3 percent (or 1 pump) but fewer than

10 percent, or 3 pumps, leaking would be required to conduct monthly

monitoring of pumps. The EPA considered whether an alternative to the

QIP could be provided for those facilities that have greater than 10

percent, or 3 pumps, leaking. It was determined that in such

situations, the only alternative is an engineering analysis to

determine the cause of the high leak frequency. Therefore, facilities

with 10 percent, or 3 pumps, leaking or greater will still be required

to implement a QIP for pumps.

The EPA also considered whether LDAR should be required for

reciprocating pumps in heavy liquid service. In most cases when drips

are observed, monitored concentration is below the leak definition, and

elimination of such drips would be infeasible due to spare or design

limitations. The replacement of such pumps would be very expensive, and

would result in little emission reduction. Therefore, the EPA concluded

that requirements to monitor and repair such pumps would be

unproductive.

The proposed rule would require monitoring and repair for

reciprocating pumps in light liquid service. The EPA requests comment

on the feasibility and cost of controlling leaks from reciprocating

pumps in light liquid service. Commenters are requested to include

technical information to support their comments.

Similarly, comment is requested on the feasibility and cost of

control measures for reciprocating compressors. As with pumps, there

may be space and design constraints that may preclude adding seals and

repair or replacement could be costly.

Valve standard. The EPA considered whether the negotiated standard

was appropriate for values, and proposes to adjust the leak definition

for phases II and III. The proposed leak definition of 1,000 ppm for

phases II and III was selected based on consideration of monitoring

data from a few facilities, existing state programs, and the expected

emission reduction and cost associated with different leak definitions.

The EPA considered but rejected using 10,000 ppm as the concentration

that defines a leak because several state programs recently established

leak definitions of 500 to 1,000 ppm. However, there is only one State

program that has a leak definition/performance standard framework

consistent with subpart H and leak definition lower than 10,000 ppm.

This program has been in effect for a number of years and controls

refineries with a leak definition of 1,000 ppm. This program has shown

that a valve performance standard for refineries can be reliably

implemented and is achievable with a leak definition of 1,000 ppm. This

program and the fact that significant additional emission reduction can

be achieved cost-effectively, led the EPA to conclude that a 1,000 ppm

leak definition was practical and achievable. A leak definition lower

than 1,000 ppm was not selected because the additional emission

reduction achievable was small (<1 percent) and the lack of data from

refineries with performance standards utilizing a leak definition of

less than 1,000 ppm.

Owing to the limited data available in this rulemaking, the EPA

selected the performance levels considering the differences in total

HAP content of process fluids in SOCMI processes and refinery processes

and the performance levels selected in the equipment leak negotiation.

It was determined that with an equipment leak definition of 1,000 ppm,

a performance standard based on 5 percent allowable leaking valves for

petroleum refineries is equivalent to the subpart H performance

standard for the SOCMI. This determination was based on the calculation

procedures in ``Protocol for Equipment Leak Emission Estimates,'' (EPA-

453/R-93-026) and average HAP/VOC ratios for process fluids.

The EPA also evaluated what monitoring frequencies should be

established for given performance levels (i.e., percent leaking

valves). Using the average HAP to VOC ratio estimated for HON, the EPA

concluded that equivalent performance requirements would be established

if the refinery standard required quarterly monitoring for facilities

achieving less than 5 percent leaking valves. Similarly, semiannual

monitoring would be allowed for facilities achieving less than 4

percent leaking valves; and annual monitoring for facilities achieving

less than 3 percent leaking valves.

In addition to the basic valve program described above, EPA

developed an optional, more stringent performance standard, that can be

used by facility owners or operators electing not to implement a

connector program. EPA has concluded a connector LDAR program is a

costlier way to achieve emission reductions, as compared with a more

stringent valve standard. The EPA, thus concluded that a more cost

effective approach would be to allow facilities the option to elect

lower performance levels for valves in lieu of implementing a connector

LDAR program.

Based on the Protocol document, an equivalent emissions reduction

can be achieved by a one percent differential of the allowable leakers

at the 1,000 ppm leak definition. Therefore, a facility electing not to

implement the connectors LDAR program can elect to comply with a valve

performance standard of 4 percent leaking valves with quarterly LDAR, 3

percent leaking valves with semi-annual LDAR and 2 percent leaking

valves with annual LDAR program.

The nonrepairable valve allowance was also adjusted to consider

differences between refinery operations and SOCMI operations. The

proposed standard would allow exclusion of 1 percent per year up to a

maximum of 3 percent of the valves in HAP service from the calculation

of percent leaking valves. The nonrepairables provision is structured

in this manner to take into consideration the typically longer

turnaround schedules in refineries than in SOCMI process units, while

recognizing that some refinery units may operate on shorter schedules.

Connectors in gas/vapor and light liquid service. The EPA

considered whether application of the negotiated standard for

connectors to refinery operators was appropriate. In this evaluation,

the EPA considered differences between designs, capacities, and

operations of refinery and SOCMI units and how these might alter the

cost of a LDAR program for connectors. Because the existing connector

emission factor predicts very low emission rates from connectors, it

appears that a connector LDAR program is relatively costly to achieve

additional emission reductions. Table 3 provides a comparison of the

costs and emission reductions for control alternatives that include and

control alternatives that exclude the negotiated rule's connector

standard. The EPA, thus, concluded that a more cost effective approach

would be to allow sources the option to elect less frequent monitoring

for valves if a connector LDAR program is implemented.

The proposed equipment leak provisions give three options for a

connector LDAR program which, if any of these are implemented, would

allow for less frequent monitoring of valves. The three options are:

(1) A random 200 connector survey; (2) a connector inspection program,

and (3) the negotiated rule's connector program. In the random 200

connector survey, the monitoring frequency depends on the percent

leaking connectors identified in 200 randomly chosen connectors. At

higher leak frequencies, the owner or operator has to survey connectors

more frequently and repair any leaking connectors detected. In the

connector inspection program, all connectors of 2 in. or greater

nominal diameter in gas/vapor service are to be monitored using Method

21 of 40 CFR part 60, appendix A, and all connectors of 2 in. or

greater nominal diameter in light liquid service are to be inspected

for indications of liquids dripping. This alternative was developed

because the majority of connectors in refinery process units that will

be subject to the equipment leak provisions of the standard are in

light liquid service and a visual inspection program should be less

costly to implement than Method 21 monitoring of these connectors. The

monitoring frequency of this program also varies with the percentage of

leaking connectors. The negotiated rule's program is included as a

third option, because some refinery units may be required under their

state program to implement these provisions.

A nonrepairable connector allowance is included because increased

monitoring frequency, if triggered by nonrepairable components, would

be of little benefit. The proposed alternative standard for connectors

allows for excluding 1 percent of the connectors per year up to a

maximum of 3 percent of the connectors from the calculation of the

percentage of leaking connectors. The nonrepairable allowance was

selected considering the need to provide an incentive to limit the

number of nonrepairable connectors while also trying to avoid

imposition of unproductive costs.

b. Equipment leaks: New sources. The floor for new sources is

between the NSPS and the rule proposed for existing sources. Available

data shows that many refineries are complying with the NSPS and several

are also complying with State rules that have lower leak definitions

(i.e., 1,000 ppm for values). The EPA therefore did not consider the

NSPS as an option for new sources because it would be below the floor.

For costing purposes, the same requirements as option 1 for existing

sources were considered the floor for new sources. The EPA considered

option 2 for existing sources as another option for new sources (option

1 for new sources). (See table 3 and the text in section VI.E.1.a of

this preamble.) The proposed standard for new sources, which is similar

to the option costed as the new source floor, is the negotiated rule

(40 CFR part 63 subpart H) without the connector provisions and with a

few other differences. This is the same as the standard proposed for

existing sources. This option was selected because it is at least as

stringent as the floor and achieves significant emission reduction at a

more reasonable cost than option 1 for new sources. No nonair quality

health impacts, energy, or other environmental impacts were expected

from either of the alternatives, so these considerations did not affect

the choice of the proposed requirements. The rationale for not

requiring connector LDAR and the rationale for the differences between

the proposed rule and subpart H are discussed in section VI.E.1.a.

One difference between the proposed rule for new and existing

sources is that pumps and valves at new sources must be in compliance

with phase II at start-up, rather than phase I. This is consistent with

the negotiated rule. It is reasonable to expect new sources to be

designed to achieve the phase II level of control because they do not

experience retrofit constraints that affect existing sources.

c. Equipment leaks: Small refineries. The EPA is considering

whether it is appropriate to establish a different standard for small

refineries. As proposed, the equipment leaks provisions would be the

same for small and large refineries, except that all equipment at small

refineries would be allowed 18 months to begin compliance (instead of

requiring one-third of the equipment to comply in 6 months, one-third

in 12 months, and the remainder in 18 months). Compliance in 6 or 12

months could be infeasible for many small refineries. Many are located

in attainment areas and have never been required to implement LDAR

programs and their owners or operators do not have expertise in setting

up and operating such programs. It will require more time for these

refineries to develop and implement LDAR programs and the associated

recordkeeping and reporting systems.

The EPA is also considering a less stringent standard and a longer

compliance time for small refineries. In particular, small refinery

existing sources could be required to comply with the provisions of the

equipment leaks NSPS 40 CFR part 60 subpart GGG instead of the proposed

option. As discussed in section VI.E.1.a, the MACT floor for equipment

leaks at existing sources is between the CTG and the NSPS, so the NSPS

is at least as stringent as the MACT floor. The NSPS has a leak

detection level of 10,000 ppm and does not have the phased-in lower

leak definitions and performance levels or the QIP provisions of the

proposed rule. Thus, the NSPS would be simpler and less costly for

small refiners to implement. There is also concern that because of

start-up costs for the LDAR program and the relationship of costs to

refinery complexity, the cost per Mg of emission reduction for options

above the floor could be somewhat higher for small refiners. The EPA

solicits comments on whether the standard for small refineries should

be based on the NSPS instead of the negotiated rule. In particular,

documentation of the control level of small refineries, and the costs

of complying with the NSPS versus the proposed rule would be helpful.

Commenters should provide the technical bases for their cost estimates

and other comments.

The EPA is also considering allowing small refineries 3 years to

achieve compliance with the NSPS level of control. As previously

stated, small refineries may need additional time to design and

implement LDAR programs. Section 112 of the Act allows the EPA to

establish compliance times up to a maximum of 3 years for existing

sources. New sources would be required to comply upon start-up or

promulgation of the rule, whichever is later, as required by the Act.

The EPA requests comments and supporting rationale on what compliance

times are reasonable for small refineries.

2. Selection of Format

Because it is not practical to measure emissions from equipment

leaks, an equipment and work practice format was chosen for the

standards. Format selection is discussed in the preamble to the

proposed HON (57 FR 62608). Because the HON negotiated rule for

equipment leaks is the basis of the standard chosen to regulate

petroleum refinery equipment leaks for both new and existing sources,

the EPA elected to refer directly to the requirements in the negotiated

rule. The differences for pumps, valves, and connectors are specified

in the proposed subpart CC.

3. Selection of Monitoring and Compliance

Determination Provisions. Because the equipment leak provisions of

the proposed rule are work practice and equipment standards,

monitoring, repairing leaks, and maintaining the required records

constitutes compliance with the rule. The HON equipment leak provisions

are appropriate to determine continuous compliance with the petroleum

refinery equipment leak standards. In summary, these provisions require

periodic monitoring with a portable hydrocarbon detector to determine

if equipment is leaking. If leaks are detected, repair is required

within specified time periods. There are provisions for delay of repair

in certain circumstances. Failure to perform the required monitoring or

to repair leaking equipment within the specified time period or

document a delay of repair would constitute an enforceable violation of

the standards.

F. Use of Continuous Monitoring to Determine Compliance

The EPA has considered how sources subject to this NESHAP should

demonstrate continuous compliance with the standards. The EPA has

concluded that where CEMS were not feasible operating parameter

monitoring can be used for this purpose. As explained under

miscellaneous process vents in section VI.B of this notice, use of CEMS

is not feasible for measuring emissions from petroleum refineries;

however, continuous operating parameter monitoring is required for some

emission points. An excursion of a parameter outside the established

range would constitute a violation of the emission standards. Owners or

operators are required to establish site-specific ranges for operating

parameters based on performance test data and/or other information.

This allows owners or operators to demonstrate the parameter ranges

that correspond to meeting the emission limits for their particular

emission points and control devices. If a parameter is outside the

range it would be considered a violation of the emission limits unless

the excursion is caused by a start-up, shut-down, or malfunction that

meets the criteria for a malfunction specified in the NESHAP general

provisions (40 CFR part 63 subpart A).

A daily averaging period for monitored parameters was selected for

determining whether an excursion has occurred. This averaging period

allows for short-term (e.g., 15-minute or hourly) parameter

fluctuations that are expected and unavoidable for the types of control

devices required, and gives the owner or operator a reasonable period

of time to take action if there is a problem. If a shorter averaging

period (for example 3 hours) were selected, sources would be likely to

have multiple excursions caused by the same operational problem because

it would not be possible to correct problems in one 3-hour reporting

period.

The EPA requests comment on the proposed approach for determination

of compliance based on continuous parameter monitoring, and on possible

alternative approaches.

As explained in section VI.B, (Miscellaneous Process Vents section)

not all vents are required to use continuous monitors. Most

miscellaneous process vents would probably be ducted to the refinery

fuel gas system for combustion in boilers, and such vents would not be

regulated under the proposed rule and would not be required to perform

any monitoring.

For some emission points, such as storage vessels equipped with

floating roofs and equipment leaks, continuous monitoring is not

feasible. In such cases, failure to comply with the required inspection

and repair procedures would constitute a violation of the equipment and

work practice standards.

G. Selection of Reporting and Recordkeeping Provisions

The proposed rule would require sources to submit up to four types

of reports: Initial Notification, Notification of Compliance Status,

Periodic Reports, and Other reports. The purpose and contents of each

of these reports are described in this section. The wording of the

proposed rule requires all draft reports to be submitted to the

``Administrator''. The term Administrator means either the

Administrator of the EPA, an EPA regional office, a State agency, or

other authority that has been delegated the authority to implement this

rule. In most cases, reports will be sent to State agencies. Addresses

are provided in the General Provisions (subpart A) of 40 CFR part 63.

Records of reported information and other information necessary to

document compliance with the regulation are generally required to be

kept for 5 years. A few records pertaining to equipment design would be

kept for the life of the equipment.

1. Initial Notification

The proposed rule would require owners or operators who are subject

to subpart CC to submit an Initial Notification. This report

establishes early communication between the source and the regulatory

agency, allowing both to plan for regulatory compliance. If the

information contained in the Initial Notification has already been

submitted to the operating permit authority, no Initial Notification is

required for this rule. For existing sources, the Initial Notification

is due 120 days after the date of promulgation. For new sources, the

Initial Notification is due as soon as practicable before construction

or reconstruction is planned to commence but it need not be sooner than

90 days after promulgation of subpart CC.

The Initial Notification must include a list of the petroleum

refining processes at the source that are subject to subpart CC, and

which provisions may apply (e.g., the provisions for miscellaneous

process vents, storage vessels, or equipment leaks). A detailed

identification of emission points is not required, because these data

would be included in the operating permit application.

2. Notification of Compliance Status

The Notification of Compliance Status would be submitted 150 days

after the source's compliance date. For new sources, the compliance

date is at start-up or the promulgation date of subpart CC, whichever

is later. For existing sources, the proposed compliance date is 3 years

after promulgation, except that equipment leaks compliance would be

staggered, with one-third of the equipment complying 6 months after

promulgation, another third in 12 months, and the remainder in 18

months. The timing of compliance-related reporting for equipment leaks

is specified in 40 CFR part 63 subpart H, which was referenced by

subpart CC. The Notification of Compliance Status contains the

information necessary to demonstrate that compliance has been achieved,

such as the results of performance tests and design analyses. If this

information has already been submitted as part of a Title V operating

permit program it does not have to be repeated in a Notification of

Compliance Status. If it is not already submitted, however, it must be

submitted as specified in this rule.

Sources with a large number of emission points are likely to submit

results of multiple performance tests for each kind of emission point.

For each test method used for a particular kind of emission point

(e.g., a process vent), one complete test report would be submitted.

For additional tests performed for the same kind of emission point

using the same method, the results would be submitted, but a complete

test report is not required. Results would include values needed to

determine compliance (e.g., inlet and outlet concentrations, flow

rates, and percent emission reduction) as well as the values of

monitored parameters averaged over the period of the test. Submitting

one test report will allow the regulatory authority to verify that the

source has followed the correct sampling and analytical procedures and

has done calculations correctly. Complete test reports for other

emission points may be kept at the plant rather than submitted. This

reporting system was established to ensure that reviewing authorities

have sufficient information to evaluate the monitoring and testing used

to demonstrate compliance with the petroleum refineries NESHAP, while

minimizing the reporting burden.

Another type of information to be included in the Notification of

Compliance Status is the specific range for each monitored parameter

for each emission point, and the rationale for why this range indicates

compliance with the emission standards. (If this range has already been

established in the operating permit, it does not need to be repeated in

the Notification of Compliance Status.)

Although in some previous NSPS and NESHAP, the EPA has specified a

pre-determined range of operating parameter values, such values could

be considered inadequate given the increased importance of parameter

monitoring in determining and certifying compliance due to the new

requirements in section 114 of the Act. For the proposed petroleum

refinery NESHAP, the EPA is requiring sources to establish site-

specific ranges. Allowing site-specific ranges for monitored parameters

accommodates site-specific variation in emission point characteristics

and control device designs. Based on the information available at

proposal, it appeared to be difficult to establish ranges or minimum or

maximum values that would be applicable in all cases.

The proposed system for establishing operating parameter ranges

attempts to balance the need for technical certainty and operational

feasibility. The ranges may be established by performance testing

supplemented by engineering assessments and manufacturer's

recommendations. However, the performance test is not required to be

conducted over the entire range of permitted parameter values because

such a requirement could impose significant technical difficulties and

costs on the source. The EPA believes that a performance test conducted

for a smaller, yet representative, range of operating conditions can

still provide a range for the operating parameters that ensures

compliance with the emission limit. For emission points and control

devices where a performance test is not required (for example, a closed

vent system and control device on a storage vessel), the range may be

established by engineering assessment.

As an example, for a miscellaneous process vent controlled by an

incinerator, the notification of compliance status would include the

site-specific minimum firebox temperature that will ensure that the

emission limit is met and the data and rationale to support this

minimum temperature.

3. Periodic Reports and Records of Monitoring Data

Periodic Reports are required to ensure that the standards continue

to be met and that control devices are operated and maintained

properly. Generally, Periodic Reports would be submitted semiannually.

If monitoring results show that the parameter values for a particular

emission point are outside the established range for more than 1

percent of the operating time in a reporting period, or the monitor is

out of service for more than 5 percent of the time, the implementing

agency may request that the owner or operator submit quarterly reports

for that emission point. After 1 year, the source can return to

semiannual reporting, unless the regulatory authority requests

continuation of quarterly reports.

The EPA has established this reporting system in order to provide

an incentive (less frequent reporting) for good performance. Because of

uncertainty about the periods of time over which sources are likely to

experience excursions outside the parameter ranges or monitoring system

failures, the EPA is seeking comment on the 1 and 5 percent criteria

triggering more frequent reporting. In particular, data are requested

on both the frequency of excursions and monitoring system downtime.

Periodic Reports specify periods when the values of monitored

parameters are outside the ranges established in the Notification of

Compliance Status or operating permit. If the values of the monitored

parameters are within the established range, records are kept, but the

values are not reported. This will reduce the volume of information in

reports and will reduce the reporting burden while still allowing

determination of continuous compliance.

For continuous parameter monitoring, records must be kept of the

parameter recorded once every 15 minutes. If a parameter is monitored

more frequently than once every 15 minutes, 15-minute or more frequent

averages may be recorded instead of the individual values. For days

when the monitored values are not outside their ranges, the owner or

operator may convert the 15-minute values to hourly averages and then

discard the 15-minute values. These provisions ensure that there will

be enough monitoring values recorded and retained to be representative

of the monitoring period, while reducing by a factor of four the burden

that would be associated with digital conversion of data, transferring

data to tape or hard copy, copying, and storing the data if all the 15-

minute values had to be retained.

The proposed rule would allow sources to request approval to use

alternative monitoring and recordkeeping systems. This will reduce the

burden by allowing greater use of existing systems. Alternative

monitoring systems specifically discussed in the rule include

nonautomated systems and data compression systems. These systems will

be allowed on a site-specific basis, dependent upon approval of the

implementing agency. The proposed rule includes specific minimum

requirements for applications to use nonautomated systems. For example,

parameters must be manually read and recorded at least once per hour

and the source must demonstrate that the frequency is sufficient to

represent control device operating conditions. Data compression systems

do not record monitored operating parameter values at a set frequency,

but record all values that meet set criteria for variation from

previously recorded values. The proposed rule would require sources

applying to use such systems to show that they are designed to: Measure

and record at least four representative values per hour, recognize and

alert the operator to unchanging data, and calculate daily averages.

Additional details and rationale for these provisions are contained in

the preamble to the promulgated HON (59 FR 19402, April 22, 1994).

For some types of emission points and controls, periodic (e.g.,

monthly, quarterly, or annual) inspections or measurements are required

instead of continuous monitoring. Records that such inspections or

measurements were done must be kept; but results are included in

Periodic Reports only if a problem is found. This requirement is

designed to minimize the recordkeeping and reporting burden of the

proposed rule.

4. Other Reports

There are a very limited number of other reports. Where possible,

subpart CC is structured to allow information to be reported in the

Periodic Reports. However, in a few cases, it is necessary for the

source to provide information to the regulatory authority shortly

before or after a specific event. For example, for storage vessels,

notification prior to internal tank inspections is required to allow

the regulatory authority to have an observer present. Requests for

approval to monitor control device operating parameters other than

those listed in the rule and requests for approval to use alternatives

to continuous monitoring must be submitted 18 months prior to the

compliance date for existing sources. This will allow the regulatory

authority and the source to reach agreement on monitoring requirements

prior to the compliance date. Certain notifications and reports

required by the part 63 General Provisions must also be submitted.

H. Rationale for Emissions Averaging Provisions

The EPA is proposing that emissions averaging be allowed for

miscellaneous process vents, storage tanks, and wastewater streams

within petroleum refineries. The EPA requests comments on whether

emissions averaging should be included in the final rule, and on

specific features of the proposed emissions averaging provisions.

Commenters should provide the reasons for their recommendations and

supporting information.

The EPA proposed a NESHAP for Marine Tank Vessel Loading and

Unloading Operations in the Federal Register Vol. 59, No. 92 on Friday,

May 13, 1994. Marine Tank Vessel Loading and Unloading Operations is a

source category included on the list of source categories for

regulation under Section 112. The NESHAP addresses HAP from these

operations; loading and unloading operations can occur at refineries as

well as other types of plants.

Today's proposed rule addresses only the 4 emission points in

refinery operations discussed earlier in this notice. Although no

regulatory text is included in today's proposal, the EPA requests

comments on the concept of expanding the petroleum refinery source

category covered by today's rule to include marine vessel loading and

unloading operations subject to the requirements of section 112 that

occur at refineries. The marine vessel requirements proposed for

purposes of compliance with section 183(f), however, would remain

unchanged. If the above change is made to the petroleum refinery source

category, the source category currently listed in accordance with

section 112(c) as Marine Tank Vessel Loading and Unloading Operations

would be split into two parts--those which are collocated at refineries

and those which are not. The ones collocated at refineries would be

combined with and become part of the refinery source category addressed

by today's proposed rule. The source category list would be amended

accordingly. The purpose would be to allow emissions averaging between

the HAP emissions from marine vessel loading and unloading and the HAP

emissions from the refinery emission points identified in today's rule

as suitable for emissions averaging. It appears that in some cases,

there may be opportunities to control some of these emission points

(e.g. storage tanks) more cost-effectively than marine vessel loading

and unloading operations. In other cases, it may be more cost-effective

to control marine vessel operation emissions than the refinery emission

points. Integrating marine loading and unloading operations into the

refinery category and utilizing emissions averaging may provide an

opportunity for more emissions reductions at a lower cost than would

occur if the categories remain separate. In addition, because of the 10

percent discount factor, additional emissions reductions will be

achieved if emissions averaging is used. The EPA requests comments on

whether there would be additional regulatory and enforcement

complexities if this approach were adopted.

If the suggested approach were adopted, the limitations of the

proposed emissions averaging provisions included in today's proposal

would also apply to the loading and unloading operations. With regard

to calculating the emissions for purposes of averaging, the May 13

proposal included procedures for determining HAP emissions from marine

vessel loading operations for purposes of determining applicability of

the rule; the EPA solicited comment on these procedures. These emission

estimating procedures will also be considered for the purpose of

emission averaging. The promulgation date, and thus the compliance

date, for the marine vessel loading and unloading standard is currently

expected to be earlier than the petroleum refinery standard. The EPA

requests comments on whether and how these compliance dates should be

made consistent, and what legal factors should be considered.

The EPA's database which serves as the basis for the May 13

proposed rule for marine vessels does not identify which loading and

unloading operations occur at refineries as opposed to other types of

plants. However, the EPA has no data to indicate that marine vessel

loading operations at refineries are dissimilar to marine vessel

loading operations located at other facilities or that their control

levels differ. Therefore, the EPA anticipates that the floors for

neither the petroleum refinery nor the marine vessel rules would be

affected by redefining the source categories as described. If any data

were received which could lead to changes in the floor calculations,

the public would be given an opportunity to review the data as well as

an opportunity to comment on any proposed changes to the floors.

If the EPA expands the refinery source category to include marine

vessel loading and unloading operations, loading operations at

refineries would have an opportunity to average emissions and reduce

costs. In addition, they would be required to achieve additional

emission reductions in accordance with the 10 percent discount

requirement contained in the emissions averaging provisions. Loading

operations that stand alone would not have this same opportunity to

reduce costs. Public comment is solicited on the magnitude of these

impacts and the appropriateness of this distinction.

Some marine terminals handle products with low concentrations of

HAP's but high concentrations of non-HAP VOC. In such circumstances, it

may be cost-effective to forego control of HAP's from marine terminals

by overcontrolling HAP's from another emission point. If, however, the

emission point being controlled does not offset the non-HAP VOC

foregone by not controlling the marine terminals, a net increase in

non-HAP VOC could result. The EPA solicits comments on what

considerations should be given to this type of situation in deciding to

combine marine terminals and refineries for the purpose of emission

averaging.

The EPA requests comment on the extent to which emissions averaging

between marine vessel loading and unloading operations and other

refinery operations could result in exposure spikes. This could occur

if batch emission streams were left uncontrolled in exchange for

control of continuous emission streams, or vice versa.

Several regulatory alternatives were considered for each emission

point covered by today's rule. In some cases, more stringent

alternatives than those selected as the basis of the proposal were

rejected based on cost considerations. If the EPA were to decide to

allow emissions averaging between marine vessel loading and unloading

operations and those emission points allowed to average by today's

proposal, sources would likely have an opportunity to reduce compliance

costs. It is possible that reduction in compliance costs could make

other control options more affordable. Public comment is solicited on

whether the 10 percent discount factor included in the emissions

averaging provisions adequately addresses this issue or how the

potential cost savings resulting from the redefinition of the source

category should be considered when the EPA reevaluates the regulatory

alternatives as part of the final rule.

The EPA also requests that commenters submit data on possible

emission factors and/or alternative emission calculation procedures for

marine vessel operations for consideration in the final rule.

The EPA will consider all comments and data received on this issue

in publishing a final rule. If the EPA decides to promulgate a final

rule allowing emissions averaging between marine vessel loading and

unloading operations and other emission points at refineries, the

Administrator may decide to publish a supplemental proposal or notice

of data availability to provide the public an opportunity to comment,

particularly on the specific averaging provisions of the rule.

1. Reasons for Proposing Averaging for the Four Emission Points

Emissions averaging is proposed as a means of providing sources

flexibility to comply in the least costly manner while still

maintaining a regulation that is workable and enforceable. Recently,

the EPA and Amoco Corporation conducted a joint study of environmental

releases at the Amoco facility in Yorktown, Virginia. A focus of the

study was to identify cost-effective pollution prevention and control

opportunities. Specific emission estimates and control strategies for

the Yorktown facility may not apply to other refineries due to site-

specific differences. However, the study did highlight the importance

of compliance flexibility and the potential of pollution prevention

strategies to achieve cost-effective emission reductions. Emissions

averaging is one way to allow compliance flexibility within the

statutory limitations of section 112 of the Act.

The EPA has included emissions averaging provisions in this rule as

one way of providing operational flexibility, however, implementing

agencies can seek approval of the State rules or authorities which

differ in form from the federal rule developed under section 112 of the

CAA. An implementing agency could submit a formal request under 40 CFR

part 63, subpart E demonstrating that the State rule, among other

criteria, is at least as stringent for each affected source as the

federal rule. Therefore, implementing agencies have the option of

developing their own rule that provides operational flexibility through

the State program approval and delegation process.

For some facilities, including small refineries, use of emissions

averaging could prevent serious economic impacts or potential closures.

For example, economic impacts could be caused by removing fixed roof

storage vessels from service to retrofit controls when the number of

products is increasing due to the upcoming reformulated gasoline rules,

and all the vessels may need to be in service to maintain production

levels. Facilities in Northern climates have a limited season during

which retrofits could be done, which corresponds to the gasoline

production season. Averaging would provide some flexibility to not

retrofit all storage vessels if other emission points could be more

easily over-controlled. Similarly, due to site-specific equipment

configurations and emission characteristics, it may be infeasible to

route a particular miscellaneous process vent to the existing fuel gas

or flare system. Control of such a vent could be costly. Another case

where averaging would be useful is where facilities already control

storage vessels or process vents, but the controls do not fully meet

the specifications of the regulation. It could be costly to retrofit

such emission points, and might only result in a few percent emission

reduction. Emissions averaging might allow facilities to retain the

current control levels for such points and balance this by over-control

of emission points that can be controlled more cost effectively.

The EPA requests comment on the usefulness of emissions averaging

provisions for the petroleum refinery industry.

The EPA is also interested in making sure that any flexibility

provisions be appropriately tailored to each particular source category

so that environmental protection is continually assured, and real

flexibility provided. For that reason, the EPA is requesting comment on

the specific provisions of the emissions averaging approach discussed

below (recordkeeping and reporting, monitoring, compliance periods,

debits, credits, credit discount factors, limits on averaging,

interpollutant trading and averaging, and scope).

This request for comment includes the threshold criteria (hazard or

risk equivalency, discount factor) established in the HON for the use

of averaging, and its appropriateness for this source category. For

example, during discussions on the HON rule, concerns were raised about

interpollutant trades resulting from the use of averaging provisions.

As a result of these concerns, threshold criteria were added to ensure

equal or greater environmental protection by requiring a demonstration

of equivalent protection, and by requiring a 10 percent increase in

reductions resulting from the use of averaging. Given that emission

points in SOCMI sources and refinery sources have similar emission

characteristics (multiple pollutant streams) which make interpollutant

trading virtually inescapable under any averaging system, the EPA is

seeking comment on these threshold criteria for use with this MACT

standard.

For the purposes of this MACT standard, the EPA would also like to

solicit comment on cost as a threshold criteria for the use of an

interpollutant averaging scheme. The Agency's assumption is that cost

would likely be a prime motivator for the use of any averaging. It may

be, however, that an explicit criteria for the demonstration of extreme

costs (e.g., related to space constraints, safety concerns, near term

plans for process changes, or additional control of well controlled

points), as a pre-condition for the use of an interpollutant averaging

scheme, would better protect against potential risk increases. This

criteria would also likely result in less flexibility for the source.

An alternative method of providing for operational flexibility

would be to establish a case-by-case waiver system. This approach would

allow sources that meet specific threshold criteria to determine an

alternative compliance option for certain emission points. A source

would need to demonstrate, to the satisfaction of the implementing

agency, that MACT cannot be met for certain emission points because of

extreme costs related to space constraints, safety concerns, near term

process changes, or additional control of well controlled emission

points. The alternative compliance option would, at a minimum, have to

ensure that the control level for the entire source is at least as

stringent as the MACT level of control. Some of the provisions of the

HON averaging system (e.g., hazard [risk] equivalency, discount factor)

could also be incorporated into this approach. While this approach only

allows flexibility for those facilities that make the required

demonstration, it provides sources and implementing agencies more

flexibility to design a more tailored control scenario.

The EPA requests comment on the concept of a case-by-case waiver

system, the specific threshold criteria and the appropriateness of

adopting HON-based provisions.

2. Overview of Averaging

In the emissions averaging scheme proposed for petroleum

refineries, a system of emissions ``credits'' and ``debits'' is used to

determine whether the required emission reductions are achieved.

Basically, the petroleum refineries provisions for each kind of

emission point require Group 1 points (those meeting certain

applicability criteria) to achieve a particular emissions reduction or

apply a certain control technology. These technologies are called the

``reference control technologies,'' or RCT's, and the EPA has

established a control efficiency (percent emission reduction) for the

RCT for each kind of emission point. If an owner or operator does not

achieve the control efficiency of the RCT for a Group 1 emission point,

an emission debit is generated.

An owner or operator who generates an emission debit must control

other emission points to a level more stringent than is required for

that kind of point to generate emission credits. Credits may come from:

(1) control of Group 1 emission points using technologies that the EPA

has rated as being more effective than the appropriate RCT, (2) control

of Group 2 emission points, and (3) pollution prevention projects that

result in greater emission reduction than the standard requires for the

relevant point or points.

Emission credits would need to exceed debits on an annual basis for

a source to be in compliance. Monitoring and quarterly credit/debit

ratio checks would also be used to determine compliance, as described

in section H.3 below. Furthermore, prior to using emissions averaging,

a source would need to demonstrate to the satisfaction of the

implementing agency that the planned emissions average would not result

in increased risk or hazard relative to compliance without averaging.

3. Selection of Averaging Provisions

This section describes the rationale for specific aspects of the

proposed emissions averaging provisions and the alternative policies

that were considered in developing these provisions.

a. The scope of emissions averaging. The EPA proposes to allow

emissions averaging across miscellaneous process vents, storage

vessels, and wastewater streams within a single existing source, as

defined for the petroleum refining source category. This proposed scope

allows as much flexibility as possible while adhering to statutory

requirements and maintaining an enforceable standard.

The EPA decided against allowing equipment leaks to be included in

emissions averaging. While there are methods available for quantifying

emissions from equipment leaks, equipment leaks cannot be included in

emissions averages at this time because the proposed standard for

equipment leaks has no fixed performance level. Although it would be

possible to establish site-specific emission levels, the cost would be

high, and it would also be costly to maintain the documentation

necessary to demonstrate compliance.

Based on the complexity and cost of developing a scheme to include

equipment leaks in emissions averaging and the likelihood of a high

compliance determination burden for both the industry and enforcement

agencies, the EPA decided the public cost of including equipment leaks

in emissions averaging is not warranted at this time.

The EPA proposes not to allow emissions averaging at new sources.

New sources have historically been held to a stricter standard than

existing sources because it is most cost-effective to integrate state-

of-the art controls into equipment design and to install the technology

during construction of new sources. One reason for allowing averaging

is to permit existing sources flexibility to achieve compliance at

diverse points with varying degrees of control already in place in the

most economically and technically reasonable fashion. This concern does

not apply to new sources which can be designed and constructed with

compliance in mind. Also, because new sources will have to comply with

applicable NSPS (e.g., 40 CFR part 60 subpart Kb), there would be

little opportunity for emissions averaging at new sources.

Averaging would be permitted only among emission points within the

petroleum refineries source category. Other emission points (e.g.,

SOCMI emission points) located within the contiguous facility could not

be averaged with petroleum refinery emission points. The fundamental

problem with allowing averaging among different source categories is

that it allows averaging among multiple sources. The proposed petroleum

refineries NESHAP defines the source as the collection of emission

points within petroleum refinery processes within a major source. Many

major sources containing such points will also contain other points

that are not covered by this standard but are covered by different MACT

standards (e.g., the HON). Each of these standards may have a separate

floor, and the statute requires that each standard be no less stringent

than its floor.

It would be inconsistent with section 112(d) to allow averaging to

be used to permit a source subject to a MACT standard to avoid

compliance with that standard. In addition, different sources would

have different compliance deadlines. Section 112(i) requires compliance

by a source within a set timeframe. Transferring emission reduction

obligations to points outside of the source would be inconsistent with

the requirement of section 112(d) that standards be set for sources in

a listed category and the requirement of section 112(i) that compliance

with such standard be achieved by sources in the category.

b. Interpollutant trading and risk analysis. The majority of HAP

emissions at refineries are composed of a few chemicals, including

benzene, toluene, xylenes, ethylbenzene, and hexane. There is a

narrower range of variation in emission stream composition among

petroleum refinery emission points than there is in some other source

categories (e.g., SOCMI emission points regulated by the HON). However,

the different HAP's emitted have different toxicities, and there are

some variations in the concentrations of individual HAP's and the

emission release characteristics of different emission points.

Therefore, there is a potential that some emissions averaging scenarios

could increase the health risk to the public relative to the risk of

compliance without emissions averaging. For this reason, the EPA

proposes that sources who elect to use averaging must demonstrate, to

the satisfaction of the implementing agency, that compliance through

averaging would not result in greater risk or hazard than compliance

without averaging. The EPA would provide guidance for making the

demonstration based on existing procedures, but the actual methodology

to be used by the source would be chosen by the implementing agency.

The EPA believes that this approach provides assurance of health

protection while allowing for site-specific evaluations. This approach

also gives all implementing agencies the authority to consider risk in

approving averages. A more complete discussion of the reasons for this

decision and the alternatives considered is provided in the preamble to

the promulgated HON (59 FR 19402, April 22, 1994). The EPA requests

comment on whether the provisions regarding risk or hazard

demonstration should be the same for petroleum refineries as for the

HON.

The EPA also requests comment on whether sources should be required

to use the hazard ranking system developed for the purposes of section

112(g) to demonstrate that compliance through averaging would not

result in greater hazard. States would still have the option of also

requiring a risk analysis.

c. Limits on averaging. The EPA proposes that emissions averages be

limited to 20 points at a source, or 25 points if pollution prevention

measures are used to control some points in the average. A limitation

on the number of points is proposed because the complexity of averaging

across a large number of points would raise significant enforcement

concerns, as well as concerns about the resource burden on implementing

agenc

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