EPA-453/R-95-015b

NATIONAL EMISSION STANDARDS

FOR HAZARDOUS AIR POLLUTANTS

PETROLEUM REFINERIES -

 BACKGROUND INFORMATION FOR

FINAL STANDARDS

Summary of Public Comments and Responses

Emission Standards Division

U.S. Environmental Protection Agency

Office of Air and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711
EPA-453/R-95-015b

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July 1995
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DISCLAIMER

This Report has been reviewed by the Emissions Standards

Division of the Office of Air Quality Planning and Standards,

EPA, and approved for publication. Mention of trade names or

commercial products is not intended to constitute endorsement

or recommendation for use. Copies of this report are

available through the Library Services Office (MD-35), U.S.

Environmental Protection Agency, Research Triangle Park, NC 

27711, or from the National Technical Information Service,

5285 Port Royal Road, Springfield, VA 22161.
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TABLE OF CONTENTS

Page

1.0 SUMMARY ...................... 1-1

1.1 Significant Comments and Changes Since Proposal 1-1

1.1.1 Process Vents Group Determination ... 1-2

1.1.2 Process Vent Impacts ......... 1-3

1.1.3 Equipment Leaks Compliance Requirements 1-5

1.1.4 Storage Vessels ............ 1-9

1.1.5 Overlapping Regulations ........ 1-12

1.1.6 Source Category Definition ...... 1-15

1.1.7 Emissions Averaging ......... 1-17

1.1.8 Monitoring, Recordkeeping, and 

 Reporting ............... 1-20

1.1.9 Subcategorization ........... 1-22

1.1.10 Economic Analysis ........... 1-23

1.1.11 Benefits Analysis ........... 1-24

1.1.12 Emissions Data ............ 1-25

1.2 Summary of Impacts of Promulgated Action ... 1-26

3.0 APPLICABILITY ................... 3-1

3.1 Definition of Source Category ......... 3-1

3.1.1 General Source Category Definition 

 Comments ................ 3-1

3.1.2 Marine Vessel Loading ......... 3-4

3.1.3 Crude Oil Topping Units ........ 3-6

3.2 Subcategorization ............... 3-7

3.2.1 Small Refineries ............ 3-7

3.2.2 Subcategorization by Ozone Attainment 

 Status. ................ 3-12

3.2.3 Subcategorization for Equipment Leaks. . 3-15

3.3 Selection/Definition of Source ........ 3-17

3.3.1 Petroleum Refinery Process Units .... 3-17

3.3.2 Area Source Designation ........ 3-26

3.3.3 Process Changes and Additions ..... 3-30

3.4 Regulated Pollutants ............. 3-32

3.5 Coordination/Overlap with Other Rules ..... 3-35
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3.5.1 Overlap With Other NESHAP and NSPS ... 3-35

3.5.2 Overlap With Title V ......... 3-45

3.5.3 NESHAP General Provisions Comments ... 3-46

3.5.4 Overlap With State and Local Rules ... 3-47

TABLE OF CONTENTS (CONTINUED)

Page

3.5.5 Relationship to Section 112(g) .... 3-49

3.6 Other Applicability Issues .......... 3-50

4.0 SELECTION OF MACT FLOOR AND MACT - GENERAL

PROCEDURES ..................... 4-1

4.1 Selection of MACT Floor ........... 4-1

4.2 Selection of MACT ............... 4-10

5.0 PROCESS VENT PROVISIONS .............. 5-1

5.1 Definition of Miscellaneous Process Vents ... 5-1

5.2 Emission Control Technology .......... 5-8

5.3 Impacts Analysis ............... 5-10

5.3.1 Database ................ 5-10

5.3.2 Cost Impacts .............. 5-12

5.3.3 Emissions Impact ............ 5-13

5.4 Selection of MACT and MACT Floor For Process

Vents ..................... 5-15

5.4.1 Selection of MACT Floor for Process 

 Vents ................. 5-15

5.4.2 Selection of MACT for Process Vents . . 5-21

5.5 Compliance Demonstration for Process Vents . . 5-30

5.5.1 Testing ................ 5-30

5.5.2 Monitoring ............... 5-34

5.6 Recordkeeping and Recording for Process Vents . 5-36

5.7 Wording of Process Vent Provisions ...... 5-36

5.8 Miscellaneous ................. 5-39

6.0 STORAGE VESSEL PROVISIONS ............. 6-1
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6.1 Definition of Storage Vessels ......... 6-1

6.2 Impacts Analysis ............... 6-3

6.2.1 Database ................ 6-3

6.2.2 Cost Impacts .............. 6-5

6.2.3 Emissions Impacts ........... 6-8

TABLE OF CONTENTS (CONTINUED)

Page

6.3 Selection of MACT Floor and MACT for Storage

Vessels .................... 6-12

6.3.1 Selection of the Storage Vessels 

 Component of the Source-Wide MACT Floor 6-12

6.3.2 Selection of MACT for Storage Vessels . 6-16

6.4 Compliance Schedule for Existing Storage

Vessels .................... 6-22

6.5 Wording of Storage Vessel Provisions ..... 6-27

7.0 WASTEWATER PROVISIONS ............... 7-1

7.1 Definition of Wastewater ........... 7-1

7.2 Impacts Analysis ............... 7-2

7.2.1 Database ................ 7-2

7.2.2 Cost Impacts .............. 7-2

7.2.3 Emissions Impacts ........... 7-3

7.3 Selection of MACT Floor and MACT for Wastewater 7-4

7.3.1 Use of Benzene as a Surrogate ..... 7-4

7.3.2 Selection of the Wastewater Component of 

 the Source-Wide MACT Floor ....... 7-6

7.3.3 Selection of MACT for Wastewater Streams 

 Requiring Control ........... 7-7

7.4 Compliance Demonstration for Wastewater .... 7-10

8.0 EQUIPMENT LEAKS PROVISION ............. 8-1

8.1 Definition of Equipment Leaks ......... 8-1

8.2 Emission Control Technology (General) ..... 8-4
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8.3 Impacts Analysis ............... 8-5

8.3.1 Cost Impacts .............. 8-5

8.3.2 Emission Impacts ............ 8-8

8.4 Selection of MACT Floor and MACT (General

Equipment Leaks) ............... 8-10

8.4.1 Selection of MACT Floor ........ 8-11

8.4.2 Selection of MACT ........... 8-17

8.5 Equipment - Specific Provisions ........ 8-22

TABLE OF CONTENTS (CONTINUED)

Page

8.5.1 Pumps in Light Liquid Service ..... 8-22

8.5.2 Compressors .............. 8-25

8.5.3 Sampling Connection Systems ...... 8-26

8.5.4 Valves in Gas/Vapor and Lines in Light 

 Liquid Service ............. 8-26

8.5.5 Connectors in Gas/Vapor and Light Liquid 

 Service ................ 8-29

8.5.6 Closed Vent Systems and Control Devices 8-34

8.5.7 Delay of Repair ............ 8-35

8.5.8 Quality Improvement Programs ...... 8-35

8.5.9 Other ................. 8-36

8.6 Recordkeeping and Reporting for Equipment 

Leaks .................... 8-38

8.7 Wording of Equipment Leaks Provision ..... 8-40

8.8 Miscellaneous ................. 8-42

9.0 GENERAL MONITORING, RECORDKEEPING, ......... 2

9.1 Use of Monitoring to Determine compliance ... 2

9.2 Recordkeeping Requirements .......... 12

9.3 Reporting Requirements ............ 16

9.3.1 Initial Notification .......... 16

9.3.2 Notification of Compliance Status ... 17

9.3.3 Periodic Reports ............ 21

9.3.4 Additional Reporting .......... 24

9.4 Recordkeeping and Reporting Burden ...... 26
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10.0 EMISSIONS AVERAGING PROVISIONS .......... 10-1

 10.1 Should Emissions Averaging Be Allowed . . 10-1

 10.2 Scope of Emissions Averaging ....... 10-7

 10.3 Interpollutant Trading and Risk Analysis 10-23

 10.4 Number of Points In Averages ...... 10-31

 10.5 Generation of Credits and Debits ... 10-34

10.5.1 What Actions are Creditable . . 10-34

10.5.2 Discount Factors ........ 10-40

 10.6 Averaging Compliance Period ...... 10-44

TABLE OF CONTENTS (CONTINUED)

Page

 10.7 Banking ................ 10-47

 10.8 Monitoring ............... 10-48

 10.9 Recordkeeping and Reporting ...... 10-54

 10.10 Miscellaneous ............. 10-56

11.0 ECONOMICS AND BENEFITS ANALYSIS .......... 11-1

12.0 GENERAL POLICY ISSUES ............... 12-1

 12.1 Common Sense Initiative ......... 12-1

 12.2 Publication of Regulations ........ 12-3

 12.3 Request for Extension .......... 12-4

 12.4 Miscellaneous .............. 12-5
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LIST OF TABLES

Page

2-1 List of Commenters on Proposed National Emission

Standards for Hazardous Air Pollutants ....... 2-2
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ACRONYM AND ABBREVIATION LIST

ACRONYM TERM

Act Clean Air Act

ANSI American National Standards Institute

API American Petroleum Institute

ASTM American Society for Testing and Materials

AQMD Air Quality Management District

BACT best available control technology

BWOM Benzene Waste Operations NESHAP

CEM continuous emissions monitoring

CFR Code of Federal Regulations

COTU crude oil topping unit

DoE Department of Energy

E.O. Executive Order

EPA Environmental Protection Agency

FCC fluidized catalytic cracking

FCCU fluidized catalytic cracking unit

HAP hazardous air pollutant

HEM Human Exposure Model

HON hazardous organic national emission

I&M inspection and maintenance

ICR Information Collection Request

LDAR leak detection and repair

MACT maximum achievable control technology

MTBE methyl tert butyl ether

NCS Notification of Compliance Status

NESHAP national emission standards for hazardous air

 pollutants

NSPS new source performance standards

OPAR Office of Policy Analysis and Review

OTA Office of Technology Assessment

QIP quality improvement program

RACT reasonably available control technology

RCT reference control technology

RFG reformulated gasoline
ACRONYM AND ABBREVIATION LIST

(CONTINUED)

ACRONYM TERM

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RIA Regulatory Impact Analysis

SCAQD South Coast Air Quality District

SIC Standard Industrial Classification

SIP State Implementation Plan

SOCMI synthetic organic chemical

SRU sulfur recovery unit

TRE total resource effectiveness

TRI toxics release inventory

TSDF treatment, storage, and disposal facility

VOC volatile organic compound(s)

ABBREVIATION UNIT OF MEASURE

bbl barrel

bbl/sd barrels per stream day

oC degrees Celsius

cm centimeter

oF degrees Fahrenheit

gal gallon

Kg kilogram

kPa kilopascals

lb pound

gal gallons

Mg megagrams

MMBtu million british thermal units

MW megawatts

ppm parts per million

ppmv parts per million by volume

ppmw parts per million by weight

psia pounds per square inch absolute

psig pounds per square inch (gauge)
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1.0 SUMMARY

On July 15, 1994, the U.S. Environmental Protection

Agency (EPA) proposed national emission standards for

hazardous air pollutants (NESHAP) for petroleum refineries

(59 FR 36130) under authority of section 112 on the Clean Air

Act (Act). Public comments were requested on the proposal in

the Federal Register. There were 62 comment letters received

from industry representatives, governmental entities,

environmental groups, and private citizens during the public

comment period. 

One public hearing was held in Research Triangle Park

(RTP), North Carolina, on August 5, 1994. The hearing was

open to the public and four persons presented oral testimony

on the proposed NESHAP.

The written comments that were submitted and verbal

comments made at the public hearing regarding the technical

and policy issues associated with the proposed rule, along

with responses to these comments, are summarized in the

following chapters. The summary of comments and responses

serves as the basis for the revisions made to the NESHAP

between proposal and promulgation. 

1.1 SIGNIFICANT COMMENTS AND CHANGES SINCE PROPOSAL

In response to comments received on the proposed

standards, several changes have been made to the final rule. 

While several of these changes are clarifications designed to

make the Agency's intent clearer, a number of them are

significant changes to the proposed standard requirements. A

summary of the substantive comments and/or changes made since

the proposal are described in the following sections. 
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Detailed Agency responses to public comments and the revised

analysis for the final rule are contained in the body of this

document and the docket for this rule (Docket No. A-93-48).

The docket for the final rule is available for public

inspection between 8:00 a.m. and 4:00 p.m., Monday through

Friday except for Federal holidays, at the following address: 

U.S. Environmental Protection Agency, Air and Radiation Docket

and Information Center (MC-6102), 401 M Street SW,

Washington DC 20460; telephone: (202) 260-7548. 

1.1.1 Process Vents Group Determination

The proposed NESHAP would have required control of all

miscellaneous process vents with HAP concentrations over

20 ppmv. This level was based on the fact that combustion

control technologies can reduce organic emissions by

98 percent or to 20 ppmv, but cannot necessarily achieve lower

concentrations. Several commenters suggested that other

applicability criteria were needed to determine which process

vents are required to apply control. They pointed out that

the HON and State regulations use a total resource

effectiveness (TRE) or emission rate cutoff to exclude small

vents that have low emission potential and high costs from

control requirements. The commenters contended that the MACT

floor does not include control of such vents.

In response to these comments, the EPA examined potential

control applicability criteria. The EPA reevaluated the

miscellaneous process vents data base. The EPA's information

on miscellaneous process vent streams was insufficient to

establish an emission rate cutoff. This was because industry

did not have sufficient information on the HAP and VOC content

of vent streams requested by the section 114 questionnaires

and ICR's and it would have been impractical to obtain this

information. Therefore, as suggested by a number of

commenters, and after consultations with industry and others,

the EPA decided to use State regulations. 
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The EPA evaluated the current level of control for

miscellaneous process vents in eight States and two air

districts that contain the majority of refineries and were

expected to have the most stringent regulations. Of the

refineries in the United States, the 12 percent that are

subject to the most stringent regulations are located in three

States. In these three States, miscellaneous process vents

emitting greater than 6.8 to 45 kilograms per day (kg/d)

(15 to 100 lb/day) of VOC are required to be controlled. The

median applicability cutoff level for the 12 percent of

U.S. refineries subject to the most stringent regulations is

33 kg/d (72 lb/day VOC). Thus, control of vents with VOC

emissions greater than 33 kg/d (72 lb/day) is the MACT floor

for existing sources, and control of vents with VOC emissions

greater than 6.8 kg/day (15 lb/day) is the MACT level of

control for new sources. The primary organic HAP's at

refineries are also VOC. Additionally, a VOC-based

applicability criteria is most reflective of the current level

of control required for miscellaneous process vents as the

majority of State regulations are expressed in terms of VOC. 

Therefore, the EPA has adopted these emission levels in the

final rule to distinguish Group 1 from Group 2 vents. Group 1

vents, those that emit over 33 kg/day (72 lb/day) for existing

sources and over 6.8 kg/day (15 lb/day) for new sources, must

be controlled, whereas Group 2 vents (which emit less than

33 kg/day (72 lb/day) for existing sources and less than

6.8 kg/day (15 lb/day) for new sources) are not required to

apply controls under the final rule. The 33 kg/day

(72 lb/day) and 6.8 kg/day (15 lb/day) applicability limits

are to be determined as the gases exit from process unit

equipment and not downstream from an emission control device.
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1.1.2 Process Vent Impacts

At proposal, the EPA estimated that the baseline HAP and

VOC emissions from process vents were 9,800 Mg/yr (10,780 tpy)

and 190,000 Mg/yr (209,000 tpy), respectively. Several

commenters contended that the impacts analysis for process

vents should be redone because: (1) The data base used in the

analysis contained several errors, and (2) the emission

estimation methodology was incorrect. The commenters asserted

that these inaccuracies resulted in overestimates of

emissions. Some of the commenters asserted that the data base

flaws included: (1) A lack of data concerning the number,

flowrates, and HAP concentrations of miscellaneous process

vents, and (2) an erroneously high percentage of controlled

vents because many uncontrolled vents were not reported. Some

of the commenters contended that the emission estimation

methodology was flawed because (1) It included wastewater and

maintenance emissions, (2) emission factors were calculated

from a HAP-to-VOC ratio that included reformer emissions, and

(3) alkylation emissions and crude unit emissions were based

on one refinery where vents were uncontrolled at the time of

the questionnaire and are now controlled.

The EPA agrees with the commenters that the process vents

emission impacts estimate has several assumptions that needed

to be reanalyzed. The EPA also agrees that the data base used

at proposal should be reevaluated to consider the commenters'

concerns. Therefore, the EPA has reestimated the emissions

and cost impacts of the process vents provisions using the

commenters' recommendations. 

The emissions at proposal were estimated using responses

from only the section 114 questionnaires extrapolated to the

entire refining industry. Because the section 114

questionnaires were sent to the largest companies, the data

obtained from them skewed the results based on what the

largest refineries did. The revised emissions were estimated
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using data from both the section 114 and ICR responses. The

ICR questionnaires were sent to refineries not receiving the

section 114 questionnaires. This additional data increased

the number of vents in the data base by 1,300. The increase

in vents resulted in a decrease in controlled vents from

40 percent to 24 percent. However, information on the HAP and

VOC content of vent streams remained limited as no new data

was provided by the ICR respondents. Additionally, no new HAP

information was provided by industry after proposal of the

rule.

Additionally, errors in the data base were corrected and

non-miscellaneous process vents were removed from the data

base (e.g., vents from wastewater, maintenance, catalytic

reformer regeneration vents, etc). In the revised emission

estimates, emissions from alkylation and crude units were

estimated from a number of different data points (not just

one, as the commenters have stated). Additionally, the one

data point the commenters have referred to has been changed to

reflect the change in control status. The revised baseline

miscellaneous process vents HAP and VOC emissions are

10,000 Mg/yr (11,000 tpy) and 109,000 Mg/yr (119,900 tpy),

respectively. 

The EPA agrees that the data on HAP concentrations is

limited. However, no new data was supplied by the commenters. 

The EPA's revised emission estimates are based on technically

sound methods and the best available information.

1.1.3 Equipment Leaks Compliance Requirements

The proposed rule for equipment leaks at existing sources

was an above-the-floor option modeled after the HON negotiated

rule for equipment leaks. The floor level of control for

equipment leaks from existing sources was determined to be

control equal to the petroleum refinery NSPS. The modified

negotiated rule was chosen as an above-the-floor option

because it was estimated to be cost effective. The option
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chosen in the proposed rule differed from the HON in that: 

(1) Existing sources were not required to monitor connectors,

and (2) the leak definitions were higher to reflect the

different volatility of materials found in refinery process

lines as opposed to SOCMI process lines. The proposed rule

required one-third of the refinery to be in compliance

6 months after promulgation of the rule, two-thirds of the

refinery to be in compliance 1 year after promulgation of the

rule, and the entire refinery to be in compliance 18 months

after promulgation of the rule.

Several commenters contended that the emissions and cost

information used to determine the cost effectiveness of going

from the floor level of control to the modified negotiated

rule were inaccurate and did not consider recent changes to

the equipment leak correlation equations for petroleum

refineries. The commenters concluded that using the most

recent information for refineries would show that it is not

cost effective to go beyond the floor level of control.

The cost information used in the analysis was the best

data available, and is based on surveys of vendors and

established costs presented in previous projects. No new cost

information was submitted by the industry. The equipment leak

emission factors that are being used to estimate the emissions

and emission reductions of the rule were developed in 1980. 

These are the only complete and accurate emission factors

available for this purpose. To accurately estimate emissions

from equipment leaks, two sets of information are needed. 

These include the amount of emissions generated per piece of

equipment leaking at a given concentration and the percent of

equipment that are actually leaking at these concentrations. 

The 1980 study that was used to estimate the impacts of the

refinery MACT rule used a consistent sampling methodology to

address both of these factors based on sampling at

uncontrolled refineries. The 1993 API study developed new
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information only on emissions per piece of leaking equipment

using a different methodology. As stated in API's report,

this information was developed from refineries in California

for use with other information to estimate facility-specific

equipment leak emissions. Thus, this study was not designed

to provide information on industry average percent leaking

equipment. Therefore, it was not possible to redefine average

emission factors. To actually use this information, however,

EPA would need corresponding new information on the percent of

equipment leaking. The EPA does not believe that it would be

appropriate to combine 1993 information with the 1980 data to

develop new emission factors because sampling methodologies

were different and because the 1993 study collected

information from well-controlled facilities while the

1980 study collected information from uncontrolled facilities. 

However, the EPA agrees that new correlation equations

developed for the refining industry indicate that the refinery

factors may overestimate emissions by as much as a factor of

two, which may make the modified negotiated rule option less

cost effective. This cannot be accurately determined because

the appropriate information to update average emission factors

is not available. The EPA recognizes that enough uncertainty

exists in the emission and cost estimates to question the

results of the cost-effectiveness analysis. 

In recognition of this uncertainty and to provide

compliance flexibility, the EPA has changed the final rule to

provide each existing refinery with a choice of complying with

either: (1) The equipment leaks NSPS requirements

(40 CFR part 60, subpart VV) or (2) a modified version of the

negotiated rule (40 CFR part 63, subpart H). The NSPS

represents the MACT floor for existing sources. The modified

negotiated regulation is the same as what was contained in the

proposed petroleum refinery NESHAP except that the compliance

dates have been extended for reasons described below. 
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Although not required in the final rule, the EPA promotes use

of the modified negotiated rule option because it is believed

to provide considerable product, emissions, and cost savings

to a refinery. 

Under either option, existing refineries will be required

to implement an LDAR program with the same leak definitions

(10,000 ppm) and the same leak frequencies as contained in the

NSPS by 3 years after promulgation. A refinery may opt to

remain at this level of control and do the monitoring,

recordkeeping, and reporting specified in the NSPS. This

option allows refineries that are familiar with the NSPS to

continue to implement that standard without needing to change

their procedures.

Alternatively, a refinery may choose to comply with

Phase I of the negotiated rule (10,000 ppm leak definition)

3 years after promulgation, comply with Phase II 4 years after

promulgation, and comply with Phase III 5 1⁄2 years after

promulgation. Each phase has lower leak definitions for pumps

and valves. In Phase III, monitoring frequencies for valves

are dependent on performance (percent leakers), providing an

incentive (less frequent monitoring and reduced monitoring

costs) for good performance. Refineries choosing to comply

with the modified negotiated rule are subject to monitoring,

recordkeeping, and reporting requirements of subpart H. The

EPA has included this compliance alternative to add

flexibility and opportunities for adjustment for differences

among facilities.

The compliance dates for equipment leaks were revised to

address commenter concerns that contended that small

refineries and refineries in ozone attainment areas would be

at a disadvantage if they were required to comply with the

proposed equipment leak regulations because they would not

have the experience to implement an equipment leaks control

program within 6 to 18 months. 
1-xx

The EPA agrees that small refineries may not have the

experience to implement an LDAR program for equipment leaks in

a short timeframe without significant expense. The EPA also

contends that other refineries that do not currently have LDAR

programs may also have trouble implementing the rule in

6 to 18 months. In response to these comments, the EPA has

changed the final rule to require that existing and new

refineries, regardless of size, comply with an LDAR program

with the same leak definitions (10,000 ppm) and monitoring

frequencies as the petroleum refinery NSPS within 3 years of

promulgation of the rule. At the end of the third year, the

entire refinery must be in compliance with the petroleum

refinery NSPS level of control; there will not be interim

deadlines during the 3-year period by which portions of the

refinery are required to comply during this time. A refinery

owner or operator who chooses to comply with the modified

negotiated rule must then implement Phase II within 4 years

and Phase III within 5 1⁄2 years of promulgation. The total

annual cost estimates for the rule have been revised in

accordance with the changes made to the equipment leak

requirements.

1.1.4 Storage Vessels

The proposed rule required existing storage vessels

containing liquids with vapor pressures greater than or equal

to 8 kPa (1.2 psia) to comply with storage vessel requirements

within 3 years. For tanks that were already controlled with

internal or external floating roofs, the proposed rule allowed

operators to defer upgrading of seals until the next scheduled

maintenance with the following exceptions: (1) Fixed roof

tanks, (2) EFR tanks with only a vapor-mounted primary seal,

and (3) all tanks storing a liquid with a true vapor pressure

greater than 34 kPa (5.0 psia).

Commenters to the proposed rule maintained that before

additional emission controls (e.g., secondary seals) can be
1-xxi

installed, tanks must be removed from service, degassed, and

cleaned. Storage tanks are currently emptied and cleaned

roughly every 10 years for inspection and maintenance. The

commenters contended that removing storage tanks that already

have floating roofs from service before scheduled maintenance

would have adverse environmental impacts that could not be

overcome by the emissions reductions from upgrading the seals

on the tank. The commenters further stated that tank owners

or operators would incur substantial costs as a result of

degassing and cleaning a tank before scheduled maintenance. 

The commenters contended that a 3-year compliance schedule

could not be met because there would not be enough trained and

capable fabricators and contractors to support the tank

modification work. Commenters stated that the reason was that

the refinery rule compliance period overlaps with the

implementation of other EPA rules and that a 10-year

compliance schedule would be consistent with other EPA

rulemakings such as the HON and the benzene storage NESHAP.

The EPA agrees with the commenters that the HON and the

benzene storage NESHAP allow floating roof tanks to achieve

compliance in 10 years or at the time of the next scheduled

degassing. Most existing floating roof storage vessels at

refineries also fall under the 10-year compliance schedule. 

Therefore, these storage vessels will be inspected within 5 to

10 years after promulgation of the rule. This is consistent

with industry practice.

In response to these comments, the EPA analyzed the

emissions resulting from degassing and cleaning storage

vessels using empirical mass-transfer models. The analysis

indicated that degassing and cleaning of floating roof vessels

generally results in substantial volatilization of HAP's to

the air. These emissions could not be balanced in less than

5 years by the emission reductions achieved by controlling the

tank to the requirements in the rule. Additionally, the
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degassing and cleaning information submitted by the refining

industry indicated substantial costs for each degassing and

cleaning activity if required within 3 years after

promulgation of the rule. Based on information provided by

industry and the EPA's empirical analysis, the EPA determined

that the proposed storage vessel provisions were not cost

effective and would, in many cases, result in increased

overall emissions because of the extra degassing emissions.

The final rule allows owners or operators of storage

vessels subject to the rule to defer installation of better

seals on floating roof tanks storing any liquid until the next

scheduled maintenance or within 10 years, whichever comes

first. This change addresses the commenters' concerns about

emissions and costs as well as their concern about the

availability of trained fabricators and contractors to modify

the tanks within a 3-year period. The final rule maintains

the requirement to retrofit IFR tanks at existing sources with

secondary seals that meet 40 CFR part 60 subpart Kb

requirements because it is the MACT floor for IFR vessels.

Based on the EPA's analysis, the emissions from degassing

and cleaning fixed roof tanks can be balanced within 1 year

(justifying a 3-year compliance date) by the emission

reductions achieved by controlling the tank to the

requirements in the rule. Therefore, the final rule maintains

the proposed compliance times (within 3 years) for fixed roof

tanks. The EPA believes that in certain situations, such as

when replacement of a tank is required, it would be reasonable

for States to grant an additional year to comply as authorized

under section 112(i)(3)(B) of the Act. The additional year

would provide time to design and construct the tanks without

disrupting refinery operations which could cause additional

emissions. The EPA will work with the industry and States to

find ways to use the emissions averaging program to deal with
1-xxiii

cases where tanks have to replaced or where it is extremely

difficult or costly to install the required controls.

Several commenters contended that the Group 1 definition

of 8 kPa (1.2 psia) in the proposed NESHAP was based on data

requests in section 114 and ICR questionnaires that were

misinterpreted by respondents. The commenters stated that the

questionnaires did not specify whether respondents were to

provide maximum true vapor pressures or average annual true

vapor pressures. The commenters elaborated that because other

data were provided to estimate emissions on an annual basis,

it was reasonable to assume that respondents provided average

annual true vapor pressures instead of maximum true vapor

pressures. The commenters concluded that vapor pressures

based on the maximum monthly temperatures may be 0.3 psia

higher than the average annual true vapor pressure. The

commenters recommended that the EPA either change the

applicability cutoff to 10 kPa (1.5 psia) maximum true vapor

pressure to account for this difference or specify that the

8 kPa (1.2 psia) cutoff is the average annual true vapor

pressure instead of the maximum true vapor pressure.

The EPA agrees with the commenters that because the

questionnaires did not specify the type of vapor pressure, the

respondents may have provided annual average true vapor

pressures instead of maximum true vapor pressures. In order

to reflect the uncertainty of the type of vapor pressure

provided in the questionnaires, the EPA has decided to change

the storage vessel applicability cutoff in the final rule from

a maximum true vapor pressure of 8 kPa (1.2 psia) to 10 kPa

(1.5 psia). An analysis of the storage vessel data base

indicated that a change from 8.3 kPa (1.2 psia) to 10 kPa

(1.5 psia) will not affect the impacts analysis.

Several commenters requested that a minimum HAP content

be considered as well as a vapor pressure cut-off for storage

vessels because some liquids may have very low HAP
1-xxiv

concentrations and high vapor pressures due to the volatility

of non-HAP compounds in the material. The EPA agrees that

several products, such as asphalt, have minimal HAP's that may

have vapor pressures greater than 10 kPa (1.5 psia) if stored

at elevated temperatures. To determine HAP weight percent

applicability criteria, the EPA reviewed the MACT floor

analysis for storage vessels to determine the HAP weight

percents in controlled storage vessels at the best-controlled

sources. The MACT floor for new sources is based on the bestcontrolled source, while the floor for existing sources is the

average of the best-controlled 12 percent of sources (or

16 refineries). The HAP weight percent applicability

criterion was determined using the same population of storage

tanks used to determine the vapor pressure applicability cutoff (i.e., the best-controlled 16 refineries). The minimum

HAP concentrations for materials stored in the tanks meeting

subpart Kb at the 16 best-controlled sources ranged from

2 weight percent to 22 weight percent. The average HAP weight

percent in the liquids stored in these tanks is 4 percent. 

The best-controlled tanks contain liquids with a HAP weight

percent in the liquid of 2 percent. Therefore, the HAP weight

percent criterion for existing sources is 4 percent HAP in the

liquid; the HAP weight percent for new sources is 2 percent

HAP in the liquid.

1.1.5 Overlapping Regulations

Several commenters contended that the petroleum refinery

NESHAP will lead to overlap with other existing and future

regulations such as the 40 CFR part 60 NSPS, 40 CFR parts 61

and 63 NESHAP, and State and local regulations. Commenters

stated that the overlap between regulations will lead to

confusion, uncertainty, and frustration for sources and

regulators.
1-xxv

The EPA has clarified the applicability of subpart CC as

it relates to other NSPS and parts 61 and 63 NESHAP that apply

to the same source in § 63.640 of the final rule.

The final rule clarifies the applicability of 40 CFR

part 63, subpart CC storage vessel provisions to storage

vessels at existing and new petroleum refinery sources subject

to 40 CFR part 60, subparts K, Ka, or Kb. The specific

provisions are structured such that each vessel is subject to

only the more stringent rule. For example, a Group 1 storage

vessel at an existing refinery that is also subject to

subpart K or Ka is required only to comply with the petroleum

refinery NESHAP storage vessel provisions.

The final rule clarifies the applicability of 40 CFR

part 63, subpart CC wastewater provisions by stating that a

Group 1 wastewater stream managed in a piece of equipment that

is also subject to the provisions of 40 CFR part 60,

subpart QQQ is required only to comply with 40 CFR part 63,

subpart CC. The final rule also clarifies that a Group 2

wastewater stream managed in equipment that is also subject to

the provisions of 40 CFR part 60, subpart QQQ is required only

to comply with subpart QQQ. Clarification of the applicable

provisions for a wastewater stream that is conveyed, stored,

or treated in a wastewater stream management unit that also

receives streams subject to the provisions of 40 CFR part 63,

subpart F has also been included in the final rule.

There should not be any process vent applicability

overlap between subpart CC and any other Federal rule. 

Process vents regulated under the HON are not subject to the

petroleum refinery NESHAP. 

The EPA clarifies the applicability of subpart CC

equipment leak provisions in the final rule by stating that

petroleum refinery sources subject to 40 CFR parts 60 or 61

equipment leaks regulations are required to comply only with

the petroleum refinery NESHAP equipment leak provisions. 
1-xxvi

The EPA has also included a Standard Industrial

Classification (SIC) code definition for petroleum refining

(2911) to the petroleum refinery process units definition in

the final rule in order to clarify which provisions of the

rule apply to storage vessels and equipment leaks. The EPA

believes that the inclusion of the SIC code reference in the

definition of refinery process unit will alleviate confusion

about applicability of this rule (reducing potential confusion

regarding process unit regulatory overlap) and other source

categories scheduled for the development of NESHAP under the

Act. The EPA has also added a list of pollutants covered

under the rule to assist facilities in the determination of

whether emission points are covered under the rule.

Another issue raised by several commenters was the

potential for overlap between the petroleum refinery MACT and

other MACT standards such as the HON. These commenters

requested that the EPA clarify the distinction between process

units subject to the HON or other MACT standards and process

units subject to the petroleum refinery MACT standard. These

commenters thought that the description of refinery process

units was too general and could include chemical processes

subject to the HON or other MACT standards.

The final rule provides that 40 CFR part 63, subpart CC

does not apply to units that are also subject to the

provisions of the HON. The applicability of subpart CC versus

the HON or other MACT standard to an emission point is

determined by the primary product produced in the unit. The

primary product is the product that is produced in the

greatest mass or volume that the unit produces. For example,

if a refinery operates a unit that produces upgraded feedstock

for the alkylation unit and this unit also produces a small

quantity (less than 20 percent) of the chemical MTBE, that

unit is considered to be subject to the petroleum refinery

MACT standard and not to the HON. In contrast, if a facility
1-xxvii

operated a process unit that produced MTBE as the primary

product and also produced small quantities of a mixed

hydrocarbon stream, the unit would be subject to the HON

because the unit produces MTBE as the primary product and the

HON applies to chemical manufacturing units that produce MTBE. 

The distinction between the units is the difference in the

primary product produced in the different units. In the first

case, the unit is integral to the petroleum refinery's

operations and the MTBE is a by-product of the unit. In the

second case, the unit's operation could be replaced by

purchased MTBE and the operation is not integral to the

petroleum refinery's operations.

The EPA believes that by specifying the applicability

determination procedures for a process unit in addition to

including the applicable process unit definitions clarifies

the applicability of the petroleum refinery MACT standard and

other MACT standards for the same emission point and pollutant

to the same process unit. The EPA also believes that by

directly stating that units subject to the HON are also

subject to this rule, the commenter's concerns over

applicability issues have been addressed.

1.1.6 Source Category Definition

In the July 1994 notice of proposed rulemaking, the

proposed rule preamble provided notice of and sought comment

on the issues of a broad affected source definition and source

category; source-wide averaging; and the relationship between

the gasoline distribution affected source definition and

source category and refineries. In the preamble of the

proposed refinery rule, the EPA noted that it did not intend

to include emission points that are subject to the gasoline

distribution standard in the refinery source category, that

all emission points within the refinery source category would

be treated as one stationary source for purposes of the

refinery standard, and that the EPA intended to permit
1-xxviii

averaging among all emission points within the source category

except for equipment leaks.

Comments on both the gasoline distribution rule and the

refinery proposal indicated that the Agency needed to clarify

which rule applied to which emissions points and whether

averaging would apply to collocated emission points. Both

proposed rules addressed similar emission points; for example,

both proposed rules addressed storage tanks and equipment

leaks where refineries were collocated with gasoline

distribution operations. In the preamble accompanying the

final gasoline distribution rule, the EPA indicated the intent

to rely on SIC codes to distinguish between emission points at

refineries covered by the gasoline distribution standard and

those covered by the refinery standard. The Agency noted that

the SIC code for particular equipment would indicate the

department with managerial oversight responsibility for each

emission point. However, the EPA specifically provided that

this rule, if appropriate, would modify the gasoline

distribution standard to incorporate SIC code limits.

The final rule identifies petroleum refinery process

units and the gasoline loading rack emission points by SIC

code for purposes of identifying the appropriate control

requirements. A broad source category and affected source

definition increases the opportunity to use flexible

compliance options such as emissions averaging. Because the

control technology under today's rule for gasoline loading

racks is the same as the requirements under the gasoline

distribution NESHAP, the required emissions reductions from

gasoline loading racks would be at least as great as would

have been required had gasoline loading racks been excluded

from the petroleum refinery source category and affected

source; due to the credit discount factors, overall emissions

may be less than otherwise would be required if gasoline

loading racks are included in an emissions averaging plan.
1-xxix

1.1.7 Emissions Averaging

The preamble to the proposed petroleum refinery rule

requested comments on whether marine loading operations at

refineries should be included in emissions averaging. The EPA

also reopened the comment period for the proposed NESHAP for

marine tank vessel loading operations (59 FR 44955) to request

comment on whether marine terminals collocated at refineries

should be moved to the petroleum refinery source category. In

addition, as noted above, issues related to including gasoline

distribution emissions in averaging at refineries were also

raised in the proposed rule preamble.

During the comment period for the gasoline distribution

NESHAP, commenters requested that gasoline bulk terminals

contiguous to a refinery be regulated by the petroleum

refinery NESHAP. Several commenters on the proposed petroleum

refinery NESHAP and proposed marine tank vessel loading

operations NESHAP supported averaging of refinery process unit

emissions with emissions from marine terminals and gasoline

distribution operations that are located at refineries. The

commenters cited more cost-effective emission reduction as the

advantage of including these emission points in emissions

averaging, and specifically commented that the costs per

megagram emission reduction of the marine loading controls are

high. These commenters also claimed that emission calculation

procedures for loading are well established and that adding

marine loading to the averaging provisions will not

appreciably increase the complexity of enforcement. Other

commenters opposed including marine loading and gasoline

distribution emission points in emissions averaging. Some

commenters claimed that these are separate source categories

and that the Act does not permit averaging across source

categories. Other commenters were of the opinion that the EPA

has the flexibility to allow trading within a facility that

includes units in different source categories. These
1-xxx

commenters argued that it is unnecessary to redefine the

source category to include marine loading operations and

gasoline distribution operations colocated at refineries.

In the final rule, the definitions of the petroleum

refinery source category and affected source have been changed

to include gasoline loading racks classified under SIC

code 2911 (Petroleum Refineries) and marine tank vessel

loading operations that are located at refinery plant sites. 

Because marine loading operations and bulk gasoline transfer

operations located at refineries are supplying raw materials

to, or transferring products from, petroleum refinery process

units, they are logically considered to be part of the same

source as the petroleum refinery process units. The EPA

considers this definition to be the most appropriate

definition and, as noted by several commenters, to present

fewer implementation problems.

A gasoline loading rack classified under SIC code 2911 or

a marine tank vessel loading operation that is located at a

petroleum refinery may be included in an emissions average

with other refinery process unit emission points. Because

these operations are included as part of a single source

within one source category intersource averaging is not an

issue.

In keeping with the EPA's stated goal of increasing

flexibility in rulemakings, this decision has been made to

provide more opportunities to average. This increases the

opportunities for refiners to find cost-effective emission

reductions from overall facility operations onsite. Costs and

cost effectiveness of controlling a particular kind of

emission point, such as marine loading, will vary depending on

many site-specific factors. Emissions averaging allows the

owner and operator to find the optimal control strategy for

their particular situation.
1-xxxi

The EPA is presently reviewing the emission averaging

policy and considering whether any more flexibility can be

provided while maintaining environmental protection. The

issue of intersource averaging will be considered along with

other aspects of the emissions averaging policy. The EPA

believes that any decision to provide additional flexibility

must be based on careful consideration of enforcement issues

as well as equity in environmental protection. Given the

complexity of these issues, the EPA does not believe that the

Refinery MACT standard is the appropriate place to address

these issues. The EPA plans to examine the issue

independently of any specific rulemaking. In this, the EPA

plans to work closely with both the refining and chemical

industries and other interested parties to determine if there

are opportunities for increasing flexibility and reducing the

burden associated with demonstrating compliance with the MACT

rules while remaining within the law.

The EPA would like to clarify that the emissions

averaging program was designed to result in equal or greater

environmental protection while providing sources flexibility

to reduce emissions in the most cost-effective manner. 

Specifically, allowing marine loading operations, and gasoline

loading racks classified under SIC code 2911, located at a

refinery to be included in emissions averages will result in

equivalent or greater overall HAP emission reduction at each

refinery. The averaging provisions are structured such that

"debits" generated by not controlling an emission point that

otherwise would require control must be balanced by achieving

extra control at other refinery emission points covered by the

NESHAP. The averaging provisions also require that a source

demonstrate that compliance through averaging will not result

in greater risk or hazard than compliance without averaging.

Some commenters were concerned that including marine

loading in averages could result in uncontrolled peak
1-xxxii

emissions. With regard to the commenters' concerns about peak

emissions, the quarterly cap on the ratio of debits to credits

is intended to limit the possibility of exposure peaks. 

Furthermore, because loading occurs fairly frequently, and

emissions from an individual vessel filling or loading event

are relatively small, such emissions are not expected to cause

significant exposure peaks. Moreover, no evidence has been

presented that emissions averaging would permit a very

different mix of emissions to occur than would point-by-point

compliance. That is, peaks of exposures from batch streams,

storage, and loading operations should be equally likely under

point-by-point compliance as under emissions averaging, so

emissions averaging does not represent a less effective

control strategy. Furthermore, in order to receive approval

for an emissions average, the owner or operator is required to

demonstrate that the emissions average does not increase the

risk or hazard relative to compliance without averaging. 

1.1.8 Monitoring, Recordkeeping, and Reporting

Several commenters alleged that the recordkeeping and

reporting requirements of the proposed rule were extremely

burdensome. The commenters requested that the EPA reduce the

monitoring, recordkeeping, and reporting burden associated

with the proposed rule. Commenters also requested that

provisions be added to the final rule to avoid duplicative

reporting for equipment subject to multiple NESHAP and NSPS. 

Other commenters requested that flexibility to allow

alternative monitoring, recordkeeping, and reporting be

incorporated into the final rule.

The EPA recognizes that unnecessary monitoring,

recordkeeping, and reporting requirements would burden both

the source and enforcement agencies. Prior to proposal, the

EPA attempted to reduce the amount of monitoring,

recordkeeping, and reporting to only that which is necessary

to demonstrate compliance. For example, at proposal almost
1-xxxiii

all reports were consolidated into the Notification of

Compliance Status, and the Periodic Reports. This was done to

simplify and reduce the frequency of reporting. Sources also

have the option of retaining records either in paper copy or

in computer-readable formats, whichever is less burdensome. 

If multiple performance tests are conducted for the same kind

of emission point using the same test method, only one

complete test report is submitted along with summaries of the

results of other tests. This reduces the number of lengthy

test reports to be copied, reviewed, and submitted. 

Site-specific test plans describing quality assurance in

§ 63.7(c) of 40 CFR part 63, subpart A are not required

because the test methods cited in subpart CC already contain

applicable quality assurance protocols. The quality assurance

provisions in the individual test methods remain applicable

and are not superseded by the nonapplicability of § 63.7(c) of

subpart A. For continuously monitored parameters, periodic

reporting is limited to excursions outside the established

ranges and the in-range values are not required to be

reported.

In response to the commenters, the EPA reevaluated

whether monitoring, recordkeeping, and reporting requirements

could be further reduced while maintaining the enforceability

of the rule. The EPA has made the following changes in the

promulgated rule to further reduce the monitoring,

recordkeeping, and reporting burden:

(1) The requirement to submit an Initial Notification

has been eliminated; 

(2) periodic reports are required to be submitted

semiannually for all facilities that do not use emissions

averaging (the proposal required quarterly reports if

monitored parameters were out of range more than a specified

percentage of the time);
1-xxxiv

(3) a reduction in the frequency for parameter

monitoring and recording. The proposal required values of

monitored parameters to be recorded every 15 minutes and all

15-minute records had to be retained for those days when

excess emissions occurred. The final rule allows hourly

monitoring and recording;

(4) recordkeeping and reporting provisions that

eliminate duplicate reporting for equipment subject to

multiple NESHAP and NSPS were added to the applicability

section (§ 63.640) of the final rule. The additions specify

which rule applies and overrides the less stringent NSPS or

NESHAP. For State and local regulation applicability

determination, the final rule has been amended to state that

the local regulatory authority (e.g., State or permitting

authority) can decide how monitoring, recordkeeping, and

reporting requirements can be consolidated, and can approve

alternative monitoring, recordkeeping, and reporting

requirements. 

These reductions reduce the proposal monitoring,

recordkeeping, and reporting burden by 25 percent. The EPA

plans to continue to work with the industry as well as with

other interested parties to identify further opportunities for

reduction of the monitoring, recordkeeping, and reporting

burden of the rule. The EPA will consider ways to eliminate

overlapping requirements and to address any inconsistencies

among the rules. The EPA will investigate the possibility of

consolidating and simplifying the various rules while

maintaining the same level of environmental protection. 

Assuming that the pilot project with the chemical industry is

successful, the EPA expects to be able to complete the review

of the Refinery rule monitoring, recordkeeping, and reporting

requirements before the compliance date.
1-xxxv

1.1.9 Subcategorization

Several commenters to the proposed petroleum refinery

NESHAP requested that the EPA subcategorize refineries by size

and/or location in an ozone attainment area. Other commenters

stated that subcategorizing small refineries because of an

arbitrary size exemption can result in an unfair competitive

advantage. These commenters further elaborated that large

refineries should not be penalized for an economy of scale

achieved through its own effective competitiveness.

In response to these comments, the refinery data bases

were subcategorized based on crude charge capacity. The

refineries were also subcategorized by ozone attainment status

and by refineries containing processes that are used to

produce gasoline (such as catalytic cracking, coking, and

catalytic reforming). Within each subcategory, the process

vents, storage vessels, and equipment leaks data bases were

sorted from most stringent control to least stringent. The

MACT floor (average of the top 12 percent of sources) for each

subcategory was identified.

The MACT floors for small refineries are not

significantly different from the industry as a whole. The

floor for process vents is the same for small refiners as for

the entire industry. The floor for storage tanks would

increase the materials vapor pressure cutoff from 10 kPa

(1.5 psia) to 11 kPa (1.7 psia), which would result in a

minimal cost savings since there are few petroleum liquids in

this volatility range. The floor for equipment leaks would

reduce the monitoring frequency; however, small refiners would

still incur the cost of setting up and implementing an LDAR

program.

Based on the EPA's analysis and the comments received

during the public comment period, a separate subcategory for

small refineries has not been included in the final rule. 
1-xxxvi

This decision was based on there being no clear relationship

between refinery size or design and emission potential.

1.1.10 Economic Analysis

Comments were received on both the methodology of the

economic analysis and the potential impacts of the analysis

results. The EPA's economic model focused on estimating

changes in product price and quantity of production for

several petroleum products. Once the effects on price and

quantity were evaluated, other impacts were estimated. The

model the EPA used is predicated on neoclassical microeconomic

theory.

The model assumed that those refineries with the highest

per-unit control are marginal (i.e., near the margin between

shutdown and continuing operation) in the post-control

markets, and that they also have the highest underlying perunit cost of production. This assumption may result in an

overstatement of the adverse impacts, such as closure, since

the assumed relationship between per-unit control cost and

per-unit production cost may not hold for all refineries. For

more information, consult the "Economic Impact Analysis for

the Petroleum Refinery NESHAP" in the docket.

Most of the comments about the economic analyses

methodology were focused on possible impacts on other parts of

the petroleum industry other than refineries. The economic

analysis for this rule, like most of the EPA's economic

analyses, focuses on the impacts on the industry being

regulated and does not calculate impacts to other industries

indirectly affected unless those impacts are significant. In

this case, the impacts indirectly affected industries were not

calculated since the impacts estimated for the petroleum

refinery industry were not significant, impacts to indirectly

affected industries would likely be insignificant also.
1-xxxvii

1.1.11 Benefits Analysis

Comments noted that naphthalene is classified as a

possible carcinogen, not a known carcinogen, and therefore

should not be included in the risk analysis. Commenters also

argued that the estimates for monetized VOC benefits were too

high, since the VOC reductions claimed in the regulation would

occur as a result of SIP's required by the Act. Other

commenters wrote that the level of benefits from HAP emissions

reduction was not of sufficient justification for pursuing the

regulation.

When the rule was proposed, naphthalene was classified as

a possible human carcinogen. Naphthalene is no longer

classified as a possible human carcinogen and is not included

in the risk analysis for the final rule.

To estimate the benefits of reducing VOC, the EPA used a

1989 study conducted by the OTA. The study examined a variety

of acute health impacts related to ozone exposure as well as

the benefits of reduced ozone concentrations for selected

agricultural crops. However, two factors not considered in

the analysis suggest that higher benefits may be realized than

were estimated. First, chronic health effects, including

leukemia, craniofacial and limb abnormalities in newborns,

nausea, dizziness, headaches, and irritation of upper

respiratory track and eyes, are difficult to quantify and

consequently were not monetized. Second, health impacts in

the OTA study were estimated for nonattainment areas only. 

The potential impacts of this second factor are likely to be

underestimated due to recent evidence suggesting acute health

effects may also be experienced at ozone concentrations below

the current national ambient air quality standards.

As to the comment about some of the benefits being

attributable to VOC emission reductions brought about by

implementing SIP's, the EPA attempted to include all impacts

possible from SIP implementation in the regulatory baseline. 
1-xxxviii

Control of VOC in this rule will be incorporated into future

SIP's by affecting their baselines, thus making the emission

reductions needed to meet them less, and leading to lower

costs for petroleum refineries to meet those SIP's. 

Therefore, control of VOC emissions in this rule will lead to

lower costs to future SIP implementation. Also, the emission

streams from petroleum refineries are primarily VOC, with a

small fraction of VOC being HAP. Control of any petroleum

refinery emission stream involves control of VOC as well as

HAP. Thus, any benefits estimated to occur from a rule that

controls VOC, though their control is of secondary importance,

should be included as benefits of the rule.

1.1.12 Emissions Data

Commenters raised concerns about the amount and quality

of the data on HAP emissions, and the uncertainties in the

emission estimates. Throughout the rulemaking, the EPA has

been aware of these concerns. During the course of this

rulemaking, the EPA requested information from the petroleum

refining industry on emissions and emission control

technologies. The industry provided sufficient information on

the emission control technologies to determine the best

controlled facilities, as required by section 112 of the Act. 

However, the information received on existing emission control

levels was limited because it was not available. Thus, there

is uncertainty in the refinery baseline emission estimates,

and emission reductions and other benefits achieved from the

emission controls required to comply with the rule. The EPA

and the petroleum refinery industry are unable to reduce this

uncertainty at this time. The Agency has characterized the

costs and emission reductions of the requirements of this rule

as accurately as possible. While there is a great deal of

qualitative information on the benefits of this rule, the

uncertainty in the emission estimates and the monetary value

that can be placed on the emission reductions limits the
1-xxxix

Agency's ability to directly quantify all the benefits of the

refinery MACT rule. The EPA does know, however, that the

controls required in this rulemaking are in widespread use in

the refining industry and that they provide substantial

emission reductions.

Under section 112(f) of the Act, the EPA must determine

whether further control of refinery emissions is necessary to

protect the health of the general public. This determination

will require more accurate emission estimates than currently

exist. The EPA has made a commitment to work cooperatively

with industry to identify the data needed to improve the

emission estimates and any other information that is required

to determine the health risks that may remain after

implementation of the refinery MACT rule.

1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION

The impacts presented in this section include process

vents, storage vessels, equipment leaks, and wastewater

streams from petroleum refinery process units. Impacts for

control of marine tank vessel loading operations and gasoline

loading rack operations classified under SIC code 2911 located

at refineries are presented in the background documentation

for 40 CFR part 63, subparts Y and R.

These standards will reduce nationwide emissions of HAP

from petroleum refineries by 48,000 Mg/yr (53,000 tpy), or

59 percent by 1998 compared to the emissions that would result

in the absence of standards. No adverse secondary air

impacts, water or solid waste impacts are anticipated from the

promulgation of these standards.

The national electric usage required to comply with the

rule is expected to increase by 48 million kilowatt-hours per

year, which is equivalent to approximately 77,500 barrels of

oil.

The implementation of this regulation is expected to

result in an overall annual national cost of $79 million. 
1-xl

This includes a cost of $59 million from operation of control

devices, and a monitoring, recordkeeping, and reporting cost

of $20 million. The monitoring, reporting, and recordkeeping

cost has been reduced by 25 percent from proposal. Table 
1-xli

TABLE 1. NATIONAL CONTROL COST IMPACTS IN THE FIFTH YEAR

Source

Total capital a

costsb

($10 ) 6

Totala annual

costs

($10 /yr) 6

Average HAP cost

effectiveness

($/Mg HAP)

Average VOC cost

effectiveness

($/Mg VOC)

Miscellaneous process vents

21 (2) 12 (1) 1,800 140

Equipment leaks 142 (16) 58 (17) 1,500 400Storage vessels 48 (1) 8 (1) 6,100 380Wastewater collection and treatment

c c c c

Other recordkeeping and reporting 

2 1 d d

Total 213 (21) 79 (20) 1,600 310

Numbers in parentheses are recordkeeping and reporting costs included in total aannual cost and total capital cost estimates. For equipment leaks, activitiesassociated with setting up and operating a LDAR program (e.g., tagging andidentifying, monitoring, data entry, setting up a data management system, etc.) arenot reflected in the equipment leak recordkeeping and reporting costs, but areincluded in the equipment leak total annual cost and total capital cost estimate.Total capital costs incurred in the 5-year period. b

c The MACT level of control is no additional control.d Not applicable.
1-xlii

1 presents the national control cost impacts for petroleum

refinery process vents, storage vessels, wastewater, and

equipment leaks. The control costs for gasoline loading racks

and marine vessel loading operations are discussed in

supporting material for the Gasoline Distribution (Stage I)

and the Marine Vessel Loading Operations rules.

The EPA estimates that changes in the compliance times

for storage vessels with floating roofs and changes to the

existing and new process vents Group 1 applicability cutoffs

will provide substantial cost savings and emissions reductions

for refineries. Estimates of degassing and cleaning storage

tank costs provided by the refining industry indicate that

premature (within 3 years of promulgation) degassing and

cleaning activities would cost between $34,000 and

$213,000 per floating roof tank depending on the type of

material stored. If extrapolated to the entire refining

industry for floating roof tanks, the cost savings from

allowing floating roofs to comply at the next scheduled

maintenance would be $6.6 million per year. 

The EPA determined that substantial HAP emissions occur

when storage vessels are degassed and cleaned. Typically,

storage vessels are inspected and maintained on a 10-year

schedule, at which time tanks are degassed and cleaned. If a

3-year compliance schedule were required, storage vessels 
1-xliii

would be degassed and cleaned prematurely, resulting in

substantial HAP emissions caused by the rule. These HAP

emissions could not be balanced in less than 5 years for

floating roof tanks by the emission reduction achieved from

complying with the rule. By changing the proposed rule to

allow floating roof tanks to comply with the storage vessel

requirements 10 years after promulgation of the rule or at the

next scheduled inspection, the EPA estimates that 3,000 Mg/yr

(2,700 tpy) of HAP, or 8,000 Mg (7,200 tpy) of HAP over

3 years, would be prevented from being emitted.

The process vent applicability cutoff (33 kg/VOC/day

(72 lb/VOC/day)) per vent will exclude 3,000 vents from

requiring control at a total annual cost savings of

$4.5 million. The new process vent applicability cutoff

(6.8 kg/VOC/day (15 lb/VOC/day)) per vent will exclude

35 vents from requiring control at a total annual cost savings

of $25,000. The total annual cost reduction of these changes

in the rule is a reduction of approximately $11 million.

The economic impact analysis for the selected regulatory

alternatives shows that the estimated price increases for

affected products range from 0.24 percent for residual fuel

oil to 0.53 percent for jet fuel. Estimated decreases in

product output range from 0.13 percent for jet fuel to

0.50 percent for residual fuel oil. Annual net exports

(exports minus imports) are predicted to decrease by

2.3 million barrels, with the range of reductions varying from

0.21 million barrels for liquid petroleum gas to 0.91 million

barrels for residual fuel oil.

Between zero and seven refineries, all of which are

classified as small, may close due to the regulation. For

more information, consult the "Economic Impact Analysis for

the Petroleum Refinery NESHAP" in the docket for this rule

(Docket No. A-93-48). The docket for the final rule is

available for public inspection between 8:00 a.m. and
1-xliv

4:00 p.m., Monday through Friday except for Federal holidays,

at the following address: U.S. Environmental Protection

Agency, Air and Radiation Docket and Information Center

(MC-6102), 401 M Street SW, Washington DC 20460; 

telephone: (202) 260-7548.

2.0 SUMMARY OF PUBLIC COMMENTS

A total of 62 written and 4 verbal comments were received

on the proposed standards. A list of the commenters, their

affiliations, and the EPA docket number assigned to their

correspondence is given in table 2-1. 

For the purpose of orderly presentation, the comments

have been categorized under the following topics:

C Applicability.

C Selection of MACT floor and MACT-general procedures.

C Process vent emissions.

C Storage vessel provisions.

C Equipment leaks provisions.

C General monitoring, recordkeeping, and reporting

comments.

C Provisions on emissions averaging.

C Economics and benefits analysis.

C General policy issues.
1-xlv

TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS

Docket numbera Commenter and affiliation

IV-D-01 Mr. David C. Copeland

Environmental Specialist

Occidental Chemical Corporation

Post Office Box 728

Niagra Falls, New York 14302-0728

IV-D-02 Mr. Jim Veach

Senior Attorney

Fina Oil and Chemical Company

Post Office Box 2159

Dallas, Texas 75221

IV-D-03 Mr. Alan J. Cabodi

Vice President

U.S. Oil and Refining Company

Post Office Box 2255

Tacoma, Washington 98401

IV-D-04 Mr. D Sibert

Director, Safety, Health and

 Environmental Affairs

Witco Corporation

One American Lane

Greenwich, Connecticut 06831-2559

IV-D-05 Mr. Norman L. Morrow

Environmental Affairs Department

Post Office Box 3272

Houston, Texas 77253-3272

IV-D-06 Mr. John B. Krider

General Manager, Technical

Chevron U.S.A. Products Company

575 Market Street

San Francisco, California 94105

IV-D-08 Ms. Sandra M. Alofs

Regulatory Affairs Analyst

Giant Industries, Inc.

237333 North Scottsdale Road

Scottsdale, Arizona 85255

IV-D-09 Mr. Walter R. Quanstrom

Environmental Health and Safety

 Department

Amoco Corporation

Post Office Box 87703

Chicago, Illinois 60680-0703
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-xlvi

IV-D-10 Mr. Arthur Lee

Texaco Incorporated

Post Office Box 509

Beacon, New York 12508

IV-D-11 Mr. E. F. Kondis

Vice President, Manufacturing

Mobil Oil Corporation

3225 Gallows Road

Fairfax, Virginia 22037-0001

IV-D-12 Mr. C. A. Moyer

Western Independent Refiners Association

801 South Grand Avenue, Tenth Floor

Los angeles, California 90017

IV-D-13 Mr. Pat Leyden

Deputy Executive Officer

Stationary Source Compliance

21865 E. Coply Drive

Diamond Bar, California 91765-4182

IV-D-14 Ms. Denise A. Bode

President

Independent Petroleum Association

 of America

1101 Sixteenth Street, NW

Washington, DC 20036

IV-D-15 Mr. Stephen P. Piatek

Environmental Health and Safety Manager

Post Office Box 1257

Wilmington, California 90748-1257

IV-D-16 Mr. James Randles

Assistant Control Officer

Northwest Air Pollution Authority

302 Pine Street, No. 207

Mount Vernon, Washington 98273-3852

IV-D-17 Mr. Dale L. McKinnon

Technical Director

Manufacturers of Emission Controls

 Association

1707 L Street, NW

Suite 570

Washington, DC 20036-4201
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-xlvii

IV-D-18 Mr. David W. Gustafson

Environmental and Health Regulatory

 Affairs, and

Mr. Toby A Treet

Legal Department

The Dow Chemical Company

2030 Dow Center

Midland, Michigan 48674

IV-D-19 Mr. John W. Cassey

Environmental Support

Shell Oil Company

One Shell Plaza

Post Office Box 4320

Houston, Texas 77210

IV-D-20 Ms. Barbara J. Price

Vice President

Health, Environmental and Safety

Phillips Petroleum Company

Bartlesville, Oklahoma 74004

IV-D-21 Mr. Brent D. Patterson

Exxon Company, U.S.A.

Post Office Box 2180

Houston, Texas 77252-2180

IV-D-22 Mr. Norbert Dee, Ph.D.

Director, Environmental Affairs

National Petroleum Refiners Association

Suite 1000, 1899 L. Street, NW

Washington, DC 20036

IV-D-23 Mr. John L. Wittenburn

Mrs. LeAnn M. Johnson

Counsel to the Somerset Refinery, Inc.

Collier, Shannol, Rill, and Scott

3050 K Street, NW

Suite 400

Washington, DC 20007
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-xlviii

IV-D-24 Mr. R. T. Columbus

Mr. Gregory M. Scott

Council to the Society of Independent

 Gasoline Marketers of America

Collier, Shannon, Rill, and Scott

3050 K Street, NW

Suite 400

Washington, DC 20007

IV-D-25 Mr. Paul C. Bailey

American Petroleum Institute

1220 L Street, NW

Washington, DC 20005

IV-D-26 Mr. M. L. Mullins

Vice President, Regulatory Affairs

Chemical Manufacturers Association

2501 M Street, NW

Washington, DC 20037

IV-D-27 Mr. Chuck Tilbrook

Environmental and Quality Control Manager

Pride Refinery, Inc.

Post Office Box 3237

Abilene, Texas 79604

IV-D-28 Mr. Richard L. Charter

General Manager, Safety and Environmental

Services

Fina Oil and Chemical Company

Post Office Box 2159

Dallas, Texas 75221

IV-D-29 Caufield Enterprises

1904 Kathryn Court

Bakersfield, California 93312

IV-D-30 Mr. William J. Doyle, Ph.D.

Manager, HES Policy and Analysis

539 South Main Street

Findlay, Ohio 45840-3295
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-xlix

IV-D-31 Mr. Richard T. Metcalf

Health, Safety and Environmental

Coordinator

Louisiana Mid-Continent Oil and Gas 

 Association

801 North Boulevard

Suite 201

Baton Rouge, Louisiana 70802-5727

IV-D-32 Mr. Charles D. Malloch

Director, Regulatory Management

800 North Lindbergh Boulevard

St. Louis, Missouri 63167

IV-D-33 Ms. Nancy A. Wildeboer

Manager, Health, Environmental, and

 Safety Policy

Sun Company, Inc.

Ten Penn Center

1801 Market Street

Philadelphia, Pennsylvania 19103-1699

IV-D-34 Mr. Robert D. Fletcher

Chief, Toxic Air Contaminant Control

 Branch

Air Resources Board

Post Office Box 2815

Sacramento, California 95814-2815

IV-D-35 Ms. Ellen Silbergeld, Ph.D.

 Senior Toxicologist

Ms. Jenna Roberts

 Staff Scientist

Mr. Lois Epstein, PE

 Staff Engineer

1875 connecticut Avenue, NW

Washington, DC 20009

IV-D-36 Ms. Ann Farner

Director, Government Relations

Toxco Refining Company

2300 Clayton Road

Suite 1100

Concord, California 94520-2100
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-l

IV-D-37 Mr. A. S. Anderson

Executive Vice President

Texas Independent Producers and Royalty

 Owners Association

515 Congress Avenue

Suite 1910

Austin, Texas 78701

IV-D-38 Mr. Allen Ellett

Environmental Consultant

BP Oil Company

200 Public Square

Cleveland, Ohio 44114-2375

IV-D-39 Mr. Ray F. Bragg, Jr.

Director

American Independent Refiners Association

Suite 330

One Massachusetts Avenue, NW

Washington, DC 20001

IV-D-40 Mr. John A,. Dege

Manager, Air Programs

Dupont SHE Excellence Center

1007 Market Street

Wilmington, Delaware 19898

IV-D-41 Mr. Michael J. Wax, Ph.D.

Deputy Director

Institute of Clean Air Companies

1707 L Street NW

Sutie 570

Washington, DC 20036-4201

IV-D-42 Mr. Sarosh J. Mariekshaw

Director-Environmental, Safety and Health 

 Affairs

Penzoil Company

Penzoil Place

Post Office Box 2967

Houston, Texas 77252-2967
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-li

IV-D-43 Mr. Joseph A. Tiernan

Vice President-Corporate Affairs

Baltimore Gas and Electric Company

39 West Lexington Street

19th Floor

Baltimore, Maryland 21201

IV-D-44 Ms. Melanie S. Kelly

Vice President-Environment, Safety and 

 Public Affairs

Post Office Box 500

Denver, Colorado 80202-2523

IV-D-45 Mr. George R. Snodgrass

Staff Engineer, Air Sciences

ARCO Alaska, Incorporated

Post Office Box 100360

Anchorage, Alaska 99510-0360

IV-D-46 Ms. Beverly Hartsock

Deputy Executive Director

Office of Air Quality

Texas Natural Resource Conservation

Post Office Box 13087

Austin, Texas 78711-3087

IV-D-47 Mr. Patrick Dolan

Vice President 

Adsitor Technology Incorporated

Post Office Box 51160

Seattle, Washington 98115

IV-D-48 Natural Resources Defense Council

1350 New York Ave., NW

Washington, DC 20005

IV-D-49 Ms. Deborah W. Gates

Vice President, Environment and Health

Ashland Petroleum Company

Post Office Box 391

Ashland, Kentucky 41114

IV-D-50 Mr. Clint W. Ensign

Manager, Government Relations

Small Refiners Coalition

550 E. South Temple

Post Office Box 30825

Salt Lake City, Utah 84130-0825
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-lii

IV-D-51 Mr. George A. Walker

Vice President, Health, Environment

 and Safety

Unocal Corporation

Post Office Box 7600

Los Angeles, California 6683(No.

missing)

IV-D-52 Mr. William O'Sullivan, P.E.

Administrator

Air Quality Regulation Program

State of New Jersey

Department of Environmental Protection

IV-D-53 Mr. Donald F. Thieler, Director

Bureau of Air Management

State of Wisconsin/Department of Natural

 Resources

101 South Webster Street Box 7921

Madison, Wisconsin 53707

IV-D-54 Sierra Club

Lone Star Chapter

Post Office Box 1931

Austin, Texas 78767

IV-D-55 Mr. S.W. Becker

State and Territorial Air Pollution

Program Administrators

Association of Local Air Pollution

Central Officials

444 Capitol Street, N.W.

Washington, DC 20001

IV-D-56 Mr. John W. Walton, P.E.

Technical Secretary

Tennessee Air Pollution Control Board

401 Church Street

L and C Annex, 9th Floor

Nashville, Tennessee 37243-1531

IV-D-57 Mr. Milton Feldstein

Air Pollution Control Officer

Bay Area Air Quality Management District

939 Ellis Street

San Francisco, California 94109
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-liii

IV-D-58 Mr. Harry A. Spannaus

Executive Vice President

Permian Basin Petroleum Association

Post Office Box 132

Midland, Texas 79702

IV-D-59 Mr. David M. Driesen

Senior Project Attorney

Natural Resource Defense Council

1350 New York Ave., NW

Washington, DC 20005

IV-D-60 Mr. Donald P. Schnacke

Kansas Independent Oil and Gas

 Association

105 South Broadway

Suite 500

Wichita, Kansas 67202-4262

IV-D-61 Mr. Matthew L. Kuryla

Jones, Day, Reavis, and Pogue

North Point

901 Lakeside Avenue

Cleveland, Ohio 44114

IV-D-62 Ms. Susan Tierney

Assistant Secretary

Office of Policy, Planning and Program

 Evaluation

Department of Energy

Washington, DC 20585

IV-F-1 Public Hearing in the Matter of:

Proposed Petroleum Refinery NESHAP.

Transcript of Hearing held in the 

ERC Auditorium, Research Triangle Park,

North Carolina.

August 15, 1994

IV-G-03 Mr. Norbert Dee, Ph.D.

Director, Environmental Affairs

National Petroleum Refiners Association

Suite 1000, 1899 L. Street, N.W.

Washington, DC 20036
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

Docket numbera Commenter and affiliation

1-liv

IV-G-04 Mr. Clint W. Ensign

Coordinator

Small Refineries Coalition

P.O. Box 30825

Salt Lake City, UT 84130

IV-G-05 Ms. Kelly A Sakir

Demetriou, Del Guercio, Springer and 

 Moyer

Attorneys at Law

801 South Grand Avenue, 10th Floor

Los Angeles, CA 90017

IV-G-06 Ms. Melanie S. Kelley

Vice President

Environment, Safety and Public Affairs

Total Petroleum, Incorporated

Total Tower

Post Office Box 500

Denver, Colorado 80202

IV-G-08 Mr. Gary E. Goodman

Assistant Plant Manager

Tosco Northwest Company

Ferndale Refinery

3901 Unick Road

Post Office Box 8

Ferndale, WA 98248

IV-G-09 Ms. Lois N. Epsteine, P.E., Engineer

Environmental Defense Fund

and Mr. David Driesen, Attorney

Natural Resources Defense Council

1875 Connecticut Ave., N.W.

Washington, DC 20009

a The docket number for the petroleum refinery docket is 

 A-93-48.
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lv

3.0 APPLICABILITY

3.1 DEFINITION OF SOURCE CATEGORY

3.1.1 General Source Category Definition Comments

Comment: One commenter (IV-D-50) stated that the Act

[section 112(c)(9)] allows the EPA to not impose toxic air

rules in instances where the public air is not threatened. 

The commenter (IV-D-50) contended that petroleum refineries,

especially those facilities located in attainment areas, may

qualify as a source category for the delisting criteria

contained in section 112(c)(9).

Response: To be delisted under 112(c)(9), the cancer

risk to the maximum exposed individual for every source in the

source category must be less than 1-in-1-million, and

emissions of pollutants with other toxic effects must be low

enough to provide an "ample margin of safety and no adverse

environmental effect." The EPA's cancer risk analysis

indicates that the maximum exposed individual for every source

in the source category is greater than 1-in-1-million. 

Additionally, a number of other adverse acute and chronic

health effects, and ecological effects can be attributed to

HAP emissions from petroleum refineries. Therefore, based on

available information the petroleum refinery source category

does not qualify for delisting under section 112(c)(9).

Comment: One commenter (IV-D-42) objected to the EPA

combining two categories of sources for petroleum refineries

and listing requirements for a single petroleum refinery

category that is not listed on the original source category

list. The commenter (IV-D-42) added that the EPA should have

proposed the change in the description of the source category
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lvi

for refineries with this rule so that comments could be made

in conjunction with the refinery MACT standard.

Response: The EPA recognized when the initial list of

source categories and descriptions was published in the

Federal Register (July 16, 1992, 57 FR 31590) that the source

category descriptions and list may be revised from time to

time as better information becomes available. The Agency

stated that it would revise these descriptions as part of the

process of establishing standards for each category. As

stated in the July 16, 1992 notice, it was never the EPA's

intent that the descriptions limit what may be included under

each category for the purposes of establishing emission

standards or for purposes relating to other parts of

section 112 involving the definition of source or category of

sources. Therefore, in establishing emission standards for

the petroleum refinery source category, the EPA defined the

petroleum refinery source category for regulation within the

rule to include those emission points for which sufficient

information was available to establish standards at this time.

The EPA did request comment on the redefinition of the

source category in the July 15, 1994 Federal Register notice

proposing the petroleum refinery MACT standard. Therefore,

the EPA believes that the commenter's concern has been

addressed.

Comment: One commenter (IV-D-57) asserted that the

refinery MACT rule should cover transfer operations of all

refinery raw materials, byproducts, and products. The

commenter (IV-D-57) stated that the EPA may not have included

transfer operations on the assumption that the marine vessel

loading NESHAP, the stage I gasoline distribution NESHAP, and

future rulemakings will control all otherwise subject sources. 

The commenter (IV-D-57) contended that these rules would not
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lvii

regulate non-gasoline refinery products and it was unclear

what sources would be regulated under the Organic Liquids

Distribution source category, for which a standard is due in

2000.

Another commenter (IV-D-34) requested that non-gasoline

transfer operations be included in the petroleum refinery

NESHAP, instead of regulating them in the year 2000 as they

are scheduled. The commenter stated that the standards

contained in the California regulations constitute the MACT

floor for these operations.

Response: The petroleum refinery "affected source"

category is defined to include equipment specifically used to

produce fuels, heating oils, or lubricants by separating,

cracking, or reforming unfinished petroleum derivatives. The

final rule also includes marine vessel loading at refineries

and gasoline loading racks at refineries classified under SIC

2911. (The gasoline distribution NESHAP covers gasoline

terminals classified under other SIC's.) The EPA did not

assume that the marine vessel loading and unloading or the

stage I gasoline distribution NESHAP would control nongasoline refinery products. However, as one commenter

(IV-D-34) noted, these operations will be covered under the

Organic Liquids Distribution source category, for which a

NESHAP is scheduled to be promulgated in the year 2000. As

stated in the preamble, the Organic Liquids Distribution

NESHAP regulation of non-gasoline refinery products will

evaluate and control emissions from organic liquids

distribution (non-gasoline) in the liquids distribution

industry, which includes transfer emissions of non-gasoline

refinery products. 

In determining the MACT floor for a source, the EPA

cannot assume that the MACT floor is at the level established
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lviii

by existing regulations. Under the Act, the EPA is required

to determine the floor based on the average emission

limitation achieved by the best performing 12 percent of

existing sources. The EPA will not cover transfer operations

of non-gasoline refinery products under this NESHAP because

they will be covered under the Organic Liquids Distribution

NESHAP where the MACT floor for the organic liquids

distribution industry can be evaluated as required under the

Act. 

3.1.2 Marine Vessel Loading

Comment: Four commenters (IV-D-16, IV-D-46, IV-D-48,

IV-D-55) opposed the inclusion of marine tank vessel loading

operations in the petroleum refineries source category. One

of the commenters (IV-D-55) stated that including marine tank

vessel loading operations in the source category adds

complexity to the regulation because of differences in

dispersion characteristics, control technologies, and

recordkeeping and reporting requirements. One commenter

(IV-D-46) predicted that additional regulatory and enforcement

complexities would result if the source category was redefined

to include marine tank vessel loading operations. The

commenter (IV-D-46) stated that, though the Act allows for

changes in the definition of source categories, if the

petroleum refinery source category is defined to include

marine tank vessel loading operations, a precedent may be set,

unduly complicating the process of establishing source

categories. The commenter (IV-D-46) further stated that the

Coast Guard is required to approve any equipment that impacts

the safety of a vessel or its occupants. The commenter

(IV-D-46) elaborated that if the "affected source" was

redefined to include marine tank vessel loading operations,
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lix

the Coast Guard could decide that land emissions affect marine

safety and refineries could require Coast Guard approval. 

Two commenters (IV-D-48, IV-D-55) expressed opposition to

the inclusion of marine tank vessel loading operations in the

petroleum refineries source category in order to allow

emissions averaging. One commenter (IV-D-55) alleged that

adding these operations to the source category would allow

emissions from marine tank vessel loading operations to go

uncontrolled due to emissions averaging. These commenters

(IV-D-48, IV-D-55) asserted that marine tank vessel loading

operations and petroleum refineries are separate source

categories and emissions cannot be averaged across the two

unless it is determined that keeping them apart is

impracticable. The commenter (IV-D-48) stated that the Act

allows the EPA to adjust source categories by distinguishing

among different types of sources within an already defined

source category during promulgation of regulation, but does

not allow for redefinition of the source category. One of the

commenters (IV-D-48) stated that if the source category is

redefined to include marine tank vessel loading, promulgation

of the petroleum refinery MACT standard would have to be

accelerated.

Response: The EPA has redefined the petroleum refinery

source category and the "affected source" covered by this rule

to permit averaging among co-located operations subject to the

refinery MACT. In particular, the EPA permits gasoline

loading racks classified under SIC 2911 and marine tank vessel

loading operations co-located at refineries subject to the

petroleum refinery MACT rule to average emissions with other

refinery process unit emission points (process vents, storage,

wastewater) to demonstrate compliance. The EPA has done this

to provide a facility the flexibility to comply with the MACT
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lx

standards in the least costly manner while maintaining a

regulation that is effective in achieving emission reductions. 

Averaging across co-located refinery process units, and

marine tank vessel loading and gasoline loading racks

operations will not result in less emission reductions. If

emissions from one emission point are not controlled, then

greater emission reductions will need to be required of other

refinery emission points. Total emission reductions will be

the same or greater. The emissions averaging provisions

require a demonstration that the emissions average will not

increase risk or hazard relative to compliance without

emissions averaging. Furthermore, the EPA does not agree that

Coast Guard approval would be required on other refinery

equipment because marine vessel loading operations are

included in the definition of "affected source." See chapter

9.0 for further discussion of emissions averaging.

3.1.3 Crude Oil Topping Units

Comment: Two commenters (IV-D-25, IV-D-38) suggested an

exemption for "crude oil topping units associated with a crude

oil pipeline that do not produce fuels for consumption

external to the operation of the pipeline." One commenter

(IV-D-38) explained that COTU's are generally located in oil

fields adjacent to refineries. The COTU's distill a

slipstream of crude oil to power pumps in the field, where a

source of electricity is not convenient. The commenter

(IV-D-38) suggested that these units be covered by the MACT

rule for organic liquid distribution.

One commenter (IV-D-45) requested that the EPA either

(1) create a subcategory for their two COTU's that are totally

enclosed in buildings, or (2) specifically exempt their two

COTU's. The commenter (IV-D-45) stated that their units have

been previously evaluated by the EPA and received an exemption
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lxi

from the NSPS subpart GGG LDAR requirements. The commenter

(IV-D-45) stated that their COTU's operate in a very remote

attainment area and are not major sources of HAP's. The

commenter (IV-D-45) asserted that their in-place state-of-theart hydrocarbon gas detection systems and standard procedures

for maintenance and repair reduce emissions without costly

federally mandated controls. 

Response: The EPA has clarified that process units

covered under the petroleum refinery NESHAP are those used in

an establishment primarily engaged in petroleum refining, as

defined in the SIC code for petroleum refining (2911). Under

this new definition the exemption language suggested by the

commenters (IV-D-25, IV-D-38) is unnecessary as the COTU's

associated with a crude oil pipeline that does not produce

fuels for consumption external to the operation of the

pipeline would not be included as a covered process unit.

3.2 SUBCATEGORIZATION

3.2.1 Small Refineries

Comment: Several commenters (IV-D-08, IV-D-23, IV-D-24,

IV-D-27, IV-D-28, IV-D-37, IV-D-50, IV-F-1, IV-D-58, IV-D-60)

urged the EPA to withdraw the proposed petroleum refinery

NESHAP, and reissue it after taking small refineries into

consideration.

Many commenters (IV-D-07, IV-D-08, IV-D-12, IV-D-14,

IV-D-19, IV-D-22, IV-D-23, IV-D-24, IV-D-27, IV-D-28, IV-D-29,

IV-D-36, IV-D-37, IV-D-39, IV-D-44, IV-D-50, IV-D-58, IV-D-60,

IV-F-1) supported subcategorization of the NESHAP based on

refinery size. Several commenters (IV-D-12, IV-D-22, IV-D-23,

IV-D-28, IV-D-29, IV-D-39, IV-D-50 and IV-F-1, IV-D-58,

IV-D-60) maintained that small refineries would be more

affected by the proposed rule than large refineries and

therefore should be given separate regulatory consideration
TABLE 2-1. LIST OF COMMENTERS ON PROPOSED NATIONAL EMISSION

 STANDARDS FOR HAZARDOUS AIR POLLUTANTS (CONTINUED)

1-lxii

(subcategorization), instead of adopting a single standard

applicable to all refineries. Reasons provided for not

adopting a single standard were that it: (1) fails to meet the

EPA's own criteria for defining a category of sources to which

a MACT standard should apply, (2) violates President Clinton's

Executive Order directing Federal agencies to adopt costbeneficial policies; (3) violates the "Common Sense

Initiative" approach enunciated by the EPA Administrator, and

(4) fails to meet the statutory requirement of

section 112(d)(1) of the Act, which stipulates that MACT

standards must be cost-effective. Several commenters

(IV-D-28, IV-D-50, IV-D-58) stated that by failing to

differentiate among refineries based on size and location, the

EPA threatens to impose disproportionate costs, without

environmental benefits, on small refineries located in

attainment areas. These sources are the smallest contributor

to overall air quality problems.

Seven commenters (IV-D-06, IV-D-09, IV-D-10, IV-D-25,

IV-D-30, IV-D-38, IV-D-53) opposed subcategorizing small

refineries. One commenter (IV-D-09) opposed subcategorizing

refineries based on size (crude running capacity). The

commenter (IV-D-09) cited that it is not the nature of the

processes that changes with crude run, but the number and

capacity of the individual process units that changes. One

commenter (IV-D-30) asserted that refinery size does have a

bearing on "major source" thresholds. However, the commenter

(IV-D-30) contended that vapor pressure and HAP content are

not dependent on refinery size or location. One commenter

(IV-D-38) expressed opposition to exemptions based on crude

throughput. Another commenter (IV-D-38) recommended that the

wastewater provision of the proposed rule be maintained as is,

without subcategorization regarding small refineries. The
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commenter (IV-D-38) contended that the cutoff of 10 metric

tons of benzene containing waste included in the BWON provides

an adequate exemption. The commenter (IV-D-38) supported

exemptions from rules or parts of rules for facilities that

are not major sources of emissions or for facilities that have

reduced their emissions to low levels, regardless of size. 

The commenter (IV-D-38) argued that these exemptions would

reward better-controlled or lower-emitting facilities. 

Another commenter (IV-D-06) also asserted that any refinery

throughput exemption would be arbitrary because the

application of controls is not based on throughput. 

One commenter (IV-D-25) stated that there is no simple

basis for subcategorizing small refineries when considering

available data on the wastewater MACT floor and control costs. 

The commenter (IV-D-25) asserted that refinery size does not

show a strong correlation with HAP emissions from wastewater

or applicability of the BWON. Furthermore, the commenter

(IV-D-25) stated that data gathered on the cost-effectiveness

of wastewater controls (see section 7.3.2) not correlate with

refinery size. The commenter (IV-D-25) stated that the

refinery NESHAP will not cause any additional wastewater

controls at refineries over what is already required by the

BWON.

Two commenters (IV-D-06, IV-D-10) asserted that an

exemption for small refineries would not be justified because

it is not supported by differences in toxic emissions between

refineries of various sizes. One commenter (IV-D-10) stated

that small refineries produce sufficient HAP's to trigger the

9.1/22.7 Mg (10/25 tpy) major source requirements.

Two commenters (IV-D-06, IV-D-10) opposed subcategorizing

small refineries because an arbitrary size exemption could

result in unfair competitive advantages. One commenter
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(IV-D-10) stated that large refineries should not be penalized

for an economy of scale achieved through their own effective

competitiveness.

Nine commenters (IV-D-14, IV-D-22, IV-D-27, IV-D-30,

IV-D-42, IV-D-44, IV-D-49, IV-D-50, IV-F-1) recommended that

the EPA subcategorize based on the definition of a small

refinery as having a crude throughput of 75,000 barrels a day,

which is contained in the Small Business Association and Acid

Rain provisions of the Act [42 U.S.C. 7651(i)(h)(3)]. Some

commenters (IV-D-27, IV-D-49, IV-D-50, IV-F-1) stated that the

definition should not contain any ownership or employment

restrictions. The commenters (IV-D-50, IV-F-1) requested that

the small refinery size definition be defined in terms of

crude oil throughput as reported to DOE each month, rather

than rated capacity.

Other commenters (IV-D-29, IV-D-39, IV-D-45, IV-D-46,

IV-D-58) recommended definitions of small refinery that ranged

from 20,000 to 50,000 barrels per day of throughput or actual

operation. One commenter (IV-D-45) supported the creation of

a subcategory for refineries with a 20,000 barrels per day or

less throughput, that are totally enclosed within a building. 

The commenter (IV-D-45) stated that then the commenter's

refineries would be covered, and they would establish the MACT

floor for such plants and therefore no additional controls

would be required. One commenter (IV-D-46) suggested that

refineries with large capacities be recognized as small

refineries if they take a federally enforced capacity limit of

50,000 barrels per day. Two commenters (IV-D-39, IV-D-58)

recommended the EPA subcategorize using a 50,000 barrels per

day or less throughput as the definition of small refinery,

which is the same definition used to define a small refinery

under section 410(h) in Title IV of the Act.
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Response: Information on small refineries supplied by

commenters did not provide a sufficient basis for withdrawing

the proposed petroleum refinery NESHAP. Information indicated

that many small refineries are major sources of HAP emissions. 

Therefore, the final determination of the MACT floor, MACT,

and estimates of impacts include small refineries. The EPA

evaluated whether small refineries should be given separate

regulatory consideration (subcategorization), instead of

adopting a single standard applicable to all refineries. Upon

evaluation, it was found that refinery design and emissions do

not correlate well with size and that the MACT floor for a

small refinery subcategory would not be significantly

different from the source category as a whole. Therefore, a

separate subcategory for small refineries has not been

included in the final rule.

No information was submitted to refute the EPA's

conclusion that the cutoff of 10 metric tons of benzene in the

wastewater provisions (included in the BWON) provides an

adequate applicability exemption from the rule for small

sources. Therefore, this applicability exemption for

wastewater has been maintained in the final rule. In

addition, an emission rate cutoff for small process vents has

also been added (see chapter 5).

Comment: One commenter (IV-D-29) stated that the EPA

needs to consider the financial impacts of other regulations

in regards to small refineries when establishing compliance

periods. Two commenters (IV-D-10, IV-D-25), however, claimed

that there is no basis in the Act to grant entities relief

from compliance or even an established schedule of compliance

based on size of the owner or operator. One commenter

(IV-D-25) stated that any changes to the rule, such as an
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extension of the time allowed for the equipment leaks

compliance, should apply to all refineries regardless of size.

Response: The EPA considered the additional financial

impacts of this regulation across the source category,

regardless of size, when establishing compliance periods. The

EPA decided that there is no basis for an extension of time

for compliance based on size. However, the EPA has concluded

that all refineries (especially small refineries) would

benefit from additional time to comply with the equipment leak

provisions of the petroleum refinery NESHAP. The EPA decided

that small refineries as well as a number of large refineries

may not have the experience to implement a LDAR program for

equipment leaks in a short time frame without significant

expense. Therefore, an extension of time for equipment leak

compliance has been included in the final rule for all

refineries. The EPA has increased the equipment leak

compliance time to a full three years to meet Phase I leak

definition requirements for LDAR control (equivalent to the

NSPS requirements), and another 2.5 years, which is 5.5 years

total for a refinery to meet Phase III leak definition

requirements for LDAR control (equivalent to the HON

requirements). This change lessens the burden on all affected

sources equitably. 

Comment: In response to the EPA's request for

information from small refineries, one commenter (IV-D-42)

provided the following information: (1) small refineries

would be considered major sources; (2) the HAP content of

process vents is not below 20 ppmv; (3) the HAP content of

petroleum liquids in the processing lines is above the

5 percent by weight applicability level in the equipment leak

provisions; (4) the true vapor pressures of the petroleum

liquids in storage vessels are above the 8.3 kPa (1.2 psia)
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applicability level and (5) the cost of production for many

small refiners is approaching, or exceeds, the average selling

price of base oils. The commenter (IV-D-42) contended that

small refineries should meet the NSPS requirement for

equipment leaks rather than the proposed refinery MACT and

that small refineries should be given 36 months to achieve the

equipment leak requirement rather than 18 months.

Another commenter (IV-D-57) provided the following

information: (1) the Bay Area District has one refinery that

is considered an area source, (2) refineries processing 10,000

to 20,000 barrels per day of crude oil should be considered

major sources, (3) the HAP content of process streams is not

below the applicability limits for the leak provisions, and

(4) the vapor pressure of stored liquids should depend on the

source of the crude oil processed.

Response: The information supplied by commenters was

considered along with other information in the selection of

the final requirements in the petroleum refinery rule. As

discussed in the previous response, the EPA decided, based on

provided information and analysis, that subcategorizing based

on refinery size or location was not warranted. 

3.2.2 Subcategorization by Ozone Attainment Status.

Comment: Many commenters (IV-D-07, IV-D-14, IV-D-23,

IV-D-24, IV-D-27, IV-D-28, IV-D-30, IV-D-36, IV-D-37, IV-D-39,

IV-D-49, IV-D-50, IV-D-58, IV-D-60) supported

subcategorization based on current ozone attainment status.

Two commenters (IV-D-23, IV-D-24) urged the EPA to revise the

proposal so that the more stringent provisions do not apply to

refineries located in ozone attainment areas. The commenters

(IV-D-23, IV-D-24) stated that refineries in ozone attainment

areas should not be forced to undertake high investments to

reduce ozone-forming emissions when ozone is not a problem in
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their area. The commenters (IV-D-23, IV-D-24) asserted that

requiring refineries in ozone attainment areas to adopt the

same emission control standards as refineries in

non-attainment areas is a wasteful use of limited industry

resources. One of the commenters (IV-D-23) was specifically

concerned about small refineries within attainment areas. 

One commenter (IV-D-24) maintained that the various

emissions control mandates contained in the Act are directed

at non-attainment areas. The commenter (IV-D-24) asserted

that unless the EPA quantified the risk from these emissions

in attainment areas, the agency will be hard pressed to defend

a final rule treating refineries in both attainment and

non-attainment areas equally. 

One commenter (IV-D-24) recommended that the EPA withdraw

the proposal for further study and limit its scope by

exempting refineries in ozone attainment areas from the

provisions of the final rule. The commenter (IV-D-24)

maintained that the risk of harm from emissions in ozone

attainment areas is low.

One commenter (IV-D-50) stated that small refineries are

predominantly located in rural areas that are in compliance

with Federal ozone standards and have not implemented programs

and procedures, such as LDAR programs, that have been started

by large refineries to control VOC in ozone nonattainment

areas. 

Two commenters (IV-D-07, IV-D-30) recommended that

varying degrees of control similar to VOC control in

non-attainment areas be developed for refineries. One

commenter (IV-D-44) claimed that to require small refineries

to comply with the same standards as large refineries located

in nonattainment areas would be unnecessary, overly rigid, and

wasteful of limited financial resources. 
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One commenter (IV-D-50 and IV-F-1) stated that the

refineries located in attainment areas will be confronted with

extremely high compliance costs as a result of this rule. The

commenter (IV-D-50) suggested subcategorizing based on ozone

attainment/nonattainment status because nonattainment areas

are usually associated with large industrialized urban areas

where a large number of people are exposed to HAP emissions

from refineries.

One commenter (IV-D-37) stated that over half of the

nation's refineries are located in attainment areas and that

it is not sensible to cause these refineries to close. In

addition, two commenters (IV-D-14, IV-D-27) stated that

refineries located in nonattainment areas are already required

to have many of the proposed controls to meet VOC reduction

requirements. 

Four commenters (IV-D-14, IV-D-27, IV-D-28, IV-D-58)

explained that attainment areas are largely comprised of small

rural communities containing small refineries which usually

serve niche markets that could be adversely affected by the

proposed NESHAP and be forced to go out of business. One

commenter (IV-D-28) stated that the proposed rule may actually

increase human exposure to HAP's, as refineries in

nonattainment areas increase throughput to make up for the

lost refinery capacity in attainment areas. 

One commenter (IV-D-28) presented a table showing that

significant capital and operating costs will be incurred to

comply with the proposed rule by one of their 60,000 bpd

refineries located in an attainment area. The commenter

(IV-D-28) related capital costs of over $4 million in the

first year, with annual operating expenditures around

$2 million in subsequent years. The commenter (IV-D-28)

contended that these estimated compliance costs are
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illustrative of the burden other small refineries in

attainment areas will be faced with under the proposed rule. 

The commenter (IV-D-28) explained that their larger

150,000 bpd facility located in a non-attainment area already

must comply with State nonattainment rules and regulations

which are similar to, and in some cases more stringent than,

the proposed rules. The commenter (IV-D-28) included a table

(Attachment I of their comments) comparing the requirements of

the proposed rule to requirements already imposed on them for

being in a nonattainment area. The commenter (IV-D-28)

explained that under the proposed rule, the only additional

requirements the 150,000 bpd refinery located in the

nonattainment area would only incur were the administrative,

monitoring, recordkeeping and reporting costs.

Two commenters (IV-D-28, IV-D-39) stated that costs

incurred by small refineries would not be shared by larger

refineries, and that small refineries in attainment areas

would be unable to recover the costs by raising prices,

creating a disparity in compliance costs that will increase

when the other petroleum refinery NESHAP is promulgated.

Response: The EPA agrees that refineries located in

attainment areas will have higher compliance costs as a result

of this rule when compared to refineries located in

nonattainment areas. However, as noted by a number of

commenters, the basis for the difference in costs is HAP

emissions control already in place due to VOC emissions

control in ozone nonattainment areas. Refineries in

attainment areas may be uncontrolled, and have greater

emissions than refineries in non-attainment areas. The HAP

emissions in ozone attainments areas will cause similar health

hazards as in nonattainment areas. The cancer and other

health risk to the most exposed individuals near the refinery
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are based on emission rate, dispersion, and how close an

individual lives to the refinery; and does not depend on the

area's population density. Thus, there are health and

environmental concerns regarding uncontrolled refineries in

rural attainment areas. In order to control HAP emissions

equitably across the nation (as required under the Act), it is

not feasible to control HAP to a lesser degree in one area

than another. 

Subcategorization of a source, under the Act, can be

employed among classes, types, and sizes of sources within a

category or subcategory. This would not include

subcategorization based on the location of a source. Measures

to reduce the burden for the entire petroleum refinery source

category have been incorporated in the final rule to address

the commenter's concerns. Measures include extended

compliance times, and reduction in monitoring, reporting, and

recordkeeping requirements. 

3.2.3 Subcategorization for Equipment Leaks.

Comment: Two commenters (IV-D-46, IV-D-44) supported the

equipment leaks option proposed for small refineries. One

commenter (IV-D-44) asserted that small refineries with modest

LDAR programs need additional time to comply with the proposed

regulation. 

One commenter (IV-D-53) claimed that Wisconsin's only

refinery is in an attainment area. The commenter (IV-D-53)

stated that the refinery has a throughput of 35,000 bpd and

has had a LDAR program in place since the early 1980's. The

commenter (IV-D-53) stated that the LDAR program was not too

burdensome and provided a copy of their LDAR program.

One commenter (IV-D-50) believed that the small refinery

LDAR requirements should not be based on the negotiated rule,

which requires a 2,000 ppm level of control. The commenter
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(IV-D-50) stated that this level of control would be difficult

and costly to achieve. The commenter (IV-D-50) stated that if

the EPA were to establish an equipment leak subcategory for

small refineries, the best LDAR controls would be found at

small facilities producing light liquid products in moderate

ozone nonattainment areas.

One commenter (IV-D-36) suggested that a separate

compliance schedule for the equipment leaks provision be

established for refineries in attainment areas. The commenter

(IV-D-36) pointed out that the reason the EPA requested

comment on allowing small refineries a full 18 months to

comply with the equipment leaks provision was that many are

located in attainment areas and have never been required to

implement an LDAR program. Thus they might require more time

to establish and implement an LDAR program. The commenter

(IV-D-36) submitted that all facilities in attainment areas

will require additional time to institute a comprehensive LDAR

program, regardless of size. 

One commenter (IV-D-30) stated that special exemptions or

delays for small refineries in rural areas that have not been

required to implement LDAR are not appropriate. The commenter

(IV-D-30) asserted that special exemptions or delays for

specific refineries may be appropriate if reasonable

justification is given. The commenter (IV-D-30) also pointed

out that a discussion on the savings that would occur from

LDAR exemptions was not provided. Another commenter (IV-D-38)

suggested that if more time is allowed for small refineries

that do not have a LDAR program, it should also be allowed for

other refineries (regardless of size) in the same situation.

Response: The EPA has concluded that special exemptions

or delays for small refineries in rural areas are not

appropriate. As noted in previous responses, there is no
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basis for regulating HAP sources in ozone attainment areas

differently than in ozone nonattainment areas. However, the

EPA concurs that refineries (especially small refineries)

located in attainment areas could benefit from additional time

to comply with the equipment leak provisions of the petroleum

refinery NESHAP. Therefore, as requested by a commenter

(IV-D-38), the EPA has increased the compliance time for all

facilities to a full 3 years from 6 months, to meet Phase I

requirements for LDAR control. Sources choosing to comply

with the modified HON negotiated rule must phase in the more

stringent leak definitions between 3 and 5.5 years after

promulgation.

3.3 SELECTION/DEFINITION OF SOURCE

3.3.1 Petroleum Refinery Process Units

Comment: One commenter (IV-D-48) disagreed with the

proposed regulation's definition of an affected source. The

commenter (IV-D-48) contended that the definition of

stationary source for petroleum refineries has always meant a

type of emissions unit. The commenter (IV-D-48) cited several

Act references to support this conclusion. The commenter

(IV-D-48) provided that the definition of an affected source

in the proposed regulation describes several unrelated parts

of a plant, a set of emission points involved in carrying out

a certain process that are not necessarily part of the same

process or located in a contiguous part of the plant. The

commenter (IV-D-48) asserted that this definition is

inconsistent with the definition in section 111(a)(3) of the

Act which defines a stationary source as a "building,

structure, facility or installation." Four commenters

(IV-D-10, IV-D-11, IV-D-21, IV-D-25) supported the proposed

broad definition of an "affected source." 

Response: The EPA does not agree with the commenter's 
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(IV-D-48) interpretation of previous rules or of the Act. The

EPA has not set a universal practice of a narrow definition

for an "affected facility" or "affected source." For example,

under the NESHAP for Benzene Waste Operations, chemical

manufacturing plants, petroleum refineries, coke by-product

recovery plants, and TSDF's that treat wastes from these

industries are the "affected facilities." The Benzene NESHAP

for Transfer Operations also has a broad definition of source,

which includes all of the loading racks at a site, including

loading racks where benzene is loaded into marine vessels,

railcars, or tank trucks. There are also NSPS's where the

"affected facility" is broad. For example, the Coal

Preparation Plant NSPS's definition of "affected facility"

includes thermal dryers, pneumatic coal cleaning equipment,

processing and conveying equipment, storage systems, and

transfer and loading systems. There are also NSPS's that

define the "affected facility" as a process unit. Reasons for

selection of a broad definition of source for petroleum

refineries were stated in the proposal preamble (59 FR 36130). 

The EPA has maintained this broad definition of "source" in

the final rule. In fact, the definition of "source" has been

revised to also include gasoline loading racks classified

under SIC 2911 and marine loading operations at refineries. 

These operations are closely associated with refinery process

units because they include the storage and transfer of

refinery products.

Comment: One commenter (IV-D-29) stated that the

provisions associating storage vessels with process units is

confusing. The commenter (IV-D-29) maintained that refineries

must remain flexible in their tank usage and suggested that

all tanks of the same type require the same controls.
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Response: The purpose of the storage tank assignment

procedures in § 63.640 is to determine whether the storage

vessels are associated with petroleum refinery process units

covered by subpart CC or other types of process units (such as

chemical manufacturing process units) that are covered by

other NESHAP. This avoids conflicting requirements for the

same vessel as only one NESHAP would apply to the storage

vessel. Provisions are included for storage vessels that can

be used by different process units. If a storage vessel is

assigned to any petroleum refinery process unit, it is subject

to the storage control requirements in subpart CC. If the

vessel is assigned to a chemical process unit, it will be

subject to the HON (40 CFR part 60, subparts F and G) instead

of subpart CC.

Comment: One commenter (IV-D-57) asserted that the

definition of source should be clarified for new source MACT

requirements. The commenter (IV-D-57) recommended that the

definition of source be consistent with the proposed 112(g)

rule, i.e., that a new source be any emission unit or

aggregation thereof, with a potential to emit at least

9.1 Mg/yr (10 tpy) of any single HAP or 22.7 Mg/yr (25 tpy) of

any combination of HAP.

Response: The petroleum refinery NESHAP definition of

source does not need to be consistent with 112(g)'s definition

since each are developed for a different purpose. For this

reason, provisions developed under 112(d) and (h) rulemaking

supersedes 112(g). This rule (§ § 63.640 (i) and (j))

elaborates on the criteria for determining whether an addition

to an existing source qualifies as a new source. These

provisions were developed after consideration of the specific

characteristics of this industry. The EPA has concluded that
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further clarification to assist owners or operators in

determining new source MACT applicability is unnecessary.

Comment: One commenter (IV-D-25) stated that there are

several types of emission sources that are not easily

categorized as miscellaneous process vents, storage vessels,

wastewater, or equipment leaks. In particular, the commenter

(IV-D-25) requested clarification of which, if any, provisions

are applicable to sumps and sulfur pits. The commenter

(IV-D-25) recommended that sumps not be covered because of

their small capacity (usually less than 10 barrels). The

commenter (IV-D-25) also requested exclusion of sulfur pits

used for underground storage that vent small amounts of

hydrogen sulfide to the atmosphere.

Response: Hydrogen sulfide emissions are not covered

under the NESHAP. Therefore, sulfur pits are not covered

under the NESHAP. Insufficient information regarding the

sumps that the commenter refers to was supplied to determine

where and whether the sumps are covered by the NESHAP. 

However, if the sump does not emit any of the listed HAP's, as

with the sulfur pits, it would not be covered under the

NESHAP. In general, emission points that do not meet the

definitions of either miscellaneous process vent, storage

vessel, or equipment leaks, and are not subject to the benzene

wastewater NESHAP, are not covered by subpart CC. The EPA has

also added a list of pollutants covered under the rule to

assist facilities in the determination of whether a process

unit is covered under the rule. Furthermore, process units

that do not meet the definition of a "petroleum refining

process unit" in § 63.641 are not covered by the rule.

Comment: One commenter (IV-D-57) contended that new

transfer operations and transfer of organic HAP from new
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processes at petroleum refineries should be required to meet

the most stringent emission limitations achieved in practice.

Response: Marine loading at refineries and gasoline

loading racks classified under SIC code 2911 at refineries are

subject to the petroleum refinery NESHAP. Loading operations

at new sources must be controlled to the new source MACT level

of control determined under the gasoline distribution and

marine vessel loading NESHAP's. Organic liquid distribution

(non-gasoline) loading emissions will be covered under a

separate MACT standard to be developed by the year 2000. The

EPA listed organic liquid distribution (non-gasoline) sources

for regulation at a later date because more time is necessary

to assess the MACT floor and MACT for this source. The new

source MACT level of control for new loading racks for organic

liquid distribution (non-gasoline) will be determined under

that rulemaking.

Comment: One commenter (IV-D-42) objected to the

refinery MACT regulating several types of facilities that are

not typical refineries, such as specialty plants that produce

white oils and waxes. The commenter (IV-D-42) argued that

these facilities do not process crude, and do not fall under

the OMB's SIC code for refineries, but are classified as

facilities that process "Product of Petroleum and Coal, not

elsewhere classified." The commenter (IV-D-42) asserted that

based on the wording of petroleum refining process units, any

processes that separate petroleum and/or separate, crack,

react or reform intermediate petroleum streams could be

subject to the rule. The commenter (IV-D-42) stated that

specialty plants are currently exempt from the refinery MACT

because they are not major sources, but the commenter

(IV-D-42) expressed concern that they could be included under

future expansions. The commenter (IV-D-42) suggested only
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referencing facilities that meet the SIC code in the

definition of refinery process units.

One commenter (IV-D-42) stated that the language of the

definition could also be interpreted to include oil and gas

facilities. The commenter (IV-D-42) explained that tanks that

separate water from crude oil via gravity could be

misconstrued as a separation process. The commenter (IV-D-42)

recommended that in order to alleviate any confusion, the EPA

should clearly state that oil and gas facilities are not

intended to be covered in the rule.

One commenter (IV-D-26) was concerned with overlap of the

refinery NESHAP and other sources categories. The commenter

(IV-D-26) maintained that the broad petroleum refining process

unit definition, which gives isomerization, polymerization and

thermal processes as examples, could be interpreted to cover

chemical operations that are to be regulated under other

source categories in the future. The commenter (IV-D-26)

cited processes to produce butyl rubber and phthalate

plasticizers as examples. The commenter (IV-D-26) suggested

that the word "react" be deleted from subparagraph 3 of the

proposed definition, and "isomerization" and "polymerization"

deleted from the examples in the definition. The commenter

(IV-D-26) also requested that the EPA provide preamble

language clarifying that the petroleum refinery process unit

does not include those units that may feed material originally

produced in a refinery.

One commenter (IV-D-05) contended that the proposed

definition of petroleum refining process unit is broad enough

to cover many processes that are chemical processes and may be

covered by the HON. The commenter (IV-D-05) recommended

excluding facilities covered under the HON and that paragraph

3 of the definition should be modified to clarify that units
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whose primary product is a chemical are not petroleum refining

process units.

One commenter (IV-D-61) requested that instead of

applying to "petroleum refinery process units" at all major

source facilities, the proposed rule should apply to selected

"process units" at "petroleum refineries," as defined in the

NSPS rules. The commenter (IV-D-61) stated that this approach

would eliminate interpretive issues regarding the rule's

applicability to non-refinery facilities. Specifically, the

commenter (IV-D-61) requested that major source facilities

producing "lubricants" not be subject to the rule because they

do not refine, distill or process crude oil or unfinished

petroleum derivatives.

One commenter (IV-D-20) supported the exclusion of

natural gas liquid processing Units from the proposed rule;

however, the commenter (IV-D-20) stated that the applicability

criteria listed in the regulation were vague in defining the

differences between a natural gas liquid process unit and a

petroleum refining process unit. The commenter (IV-D-20)

requested that the promulgation preamble explain these

differences and that a definition of a natural gas liquid

process unit be put in the definition section of the rule. 

One commenter (IV-D-21) asserted that the existing

definition of a process unit may leave some refinery process

units out or overlap with other source categories. The

commenter (IV-D-21) explained that some refinery units that

contain HAP's produce solvents. The commenter (IV-D-21)

expressed concern that these units will not be regulated

because they produce highly aromatic compounds not on the list

of common refinery products and are not subject to HON because

they are flexible operation units. The commenter (IV-D-21)

stated that these units should be included because their
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operations are similar to those of refinery units. The

commenter (IV-D-21) asserted that these units should not be

regulated by section 112(g) of the Act. 

Response: In the final rule the EPA has incorporated the

SIC code definition for petroleum refining (2911) into the

petroleum refinery process units definition in order to

clarify the process units covered by the rule. This

clarification excludes those facilities that manufacture

lubricating oils and greases by blending and compounding

purchased materials, and those facilities that re-refine used

lubricating oils. Based upon this definition, oils and waxes

produced in a petroleum refinery will be covered under the

petroleum refineries NESHAP and those establishments that

blend oils or waxes from purchased materials will not be

covered under the NESHAP. Under the new definition, it is

clear that natural gas liquid processing units would not be

covered by the rule because they are classified under mining

industries (a different SIC code). The list of example

process units has been expanded to include petroleum-based

solvent units, to avoid any potential ambiguity regarding

these units. Thus, it should be clear that solvents produced

in petroleum refineries and their production units are covered

under the rule. 

The EPA believes that the inclusion of the SIC code

reference in the definition of refinery process unit will

alleviate most of the confusion about overlap with other

source categories scheduled for regulation under the Act. The

EPA has also explicitly excluded units subject to the HON,

ethylene processes, shale oil extraction units, and other

units where there may be confusion from applicability of the

rule. Therefore deleting the words "react," "polymerization,"

and "isomerization" from the definition is unnecessary. These
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process unit examples are for those units that process crude

oil, which would eliminate butyl rubber and phthalate

plasticizer production process units as "polymerization" or

"isomerization" refinery process units subject to the rule. 

Furthermore, the inclusion of the SIC code reference in the

definition should sufficiently clarify that the petroleum

refinery process unit does not include those units that may

feed material originally produced in a refinery. 

The EPA has also added a list of pollutants covered under

the rule to assist facilities in the determination of whether

a processing unit or a specific emission point is covered

under the rule. It is important to understand that the HAP

list is not the only consideration in determining if a process

unit is subject. The first consideration is to determine if

the process unit meets the definition of a petroleum refining

process unit in the rule (including the SIC code wording that

was added). The next step is to determine if the process unit

could emit one of the listed organic HAP's. If none of the

listed HAP's are present in the process unit, it is not

subject. It should be stressed that a process unit may emit a

listed HAP and still not be covered by the petroleum refinery

NESHAP if the process unit does not meet the definition of a

petroleum refining process unit. For example, a chemical unit

that emits HAP's located at a refinery may be subject to the

HON or another source category standard and not the petroleum

refinery NESHAP.

Comment: One commenter (IV-D-21) suggested that

"blending" and "sweetening or treating" be added to the list

of examples of refinery process units. The commenter

(IV-D-21) explained that the sweetening process converts

methyl mercaptans to disulfides to reduce odor.
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The commenter (IV-D-21) requested that "petroleum-based

solvent production units" be added to the list of examples of

process units.

Response: The list of example refinery process units in

the proposed rule was not meant to be all-inclusive. It would

not be feasible, and is not necessary, to provide a complete

list due to the many variations among refinery plants, and

differences in terminology. However, "blending" and

"sweetening or treating" and "petroleum-based solvent

production units" would be covered under the petroleum

refinery process unit definition when "production" and

"blending or sweetening" is done in a petroleum refinery and

crude oil or petroleum derivatives are involved in the

process. 

Comment: One commenter (IV-D-20) suggested that the

current wording of the rule in § 63.640(f)(3), which stated

that any distillation unit that ever receives a refinery

stream is subject to the rule, even if the stream is a minor

part of its feed or is only processed on one occasion should

exclude: (1) any distillation unit that receives less than

40 percent of its feed on an annual basis from a petroleum

process unit, and (2) any distillation unit that sends less

than 40 percent of output on an annual basis to a petroleum

process unit.

One commenter (IV-D-20) contended that a distillation

unit should not have its applicability determined forever due

to the previous year's service. The commenter (IV-D-20)

stated that notification that a distillation unit will not

process petroleum products should allow a unit to be exempted

from the rule [63.640(f)(5)].

Response: The EPA has not included the commenter's

(IV-D-20) suggested exclusions in the final rule. The
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commenter (IV-D-20) misinterpreted § 63.640(f)(3). It is not

true that any distillation unit that ever receives a refinery

stream is subject to the rule. The rule only applies to those

units for which the predominant use is from a petroleum

refining process unit (e.g., if the distillation unit is fed

by multiple on-site process units, it is assigned to the

process unit that contributes the greatest amount). The EPA

proposed to determine the applicability of a distillation unit

to the NESHAP based on the previous year's service when there

is no single predominant use because there needs to be a clear

basis as to where the unit will be permitted. When a

distillation unit receives its feed from off-site, the rule

assigns the distillation unit to the process unit that

receives the greatest amount of material from the distillation

unit. This is also based on usage during the previous year

when there is no single predominant use of the distillation

unit. The distillation unit applicability determination needs

to be made, and predominant use is the most logical

determining factor. If the predominant use is, for example, a

chemical manufacturing process unit instead of a refinery

process unit, the distillation column would be subject to the

HON rather than the refineries NESHAP. This approach also

avoids overlapping MACT standards since there can only be one

predominant use. 

3.3.2 Area Source Designation

Comment: Three commenters (IV-D-20, IV-D-22, IV-D-44)

stated that all limits under EPA-approved programs should be

considered in determining potential to emit, not just

emissions that have federally enforceable controls. One

commenter (IV-D-44) claimed that including only federally

enforceable emissions controls exceeds the intent of the

1990 Amendments. The commenter (IV-D-22) claimed that this
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was inconsistent with the statute and Congressional intent

because section 112(a)(1) makes no mention of Federal

enforceability. One commenter (IV-D-20) contended that to

require additional paperwork simply to meet the definition of

"federally enforceable" overburdens the system without

contributing any benefit to the environment. 

Response: The definition for a petroleum refineries'

"potential to emit" is consistent with the NESHAP General

Provisions (40 CFR part 63, subpart A). The EPA has

consistently interpreted section 112(a)(1) to allow the use of

only "federally enforceable" emissions controls in determining

a source's potential to emit. These controls are the only

controls that EPA would have the authority to require the use

of. The reader is referred to the General Provisions preamble

(59 FR 12413) for the promulgated rule for more information.

Comment: In response to the request for comments on 

whether area sources are within the petroleum refinery source

category, one commenter (IV-D-46) requested that permitting of

area sources as per 40 CFR part 70.3 (b)(1) and (b)(2) be

deferred.

Response: States can override the 40 CFR part 70.3 area

source permitting deferral or any deferral that may be written

into individual NESHAP developed under the Act. The EPA does

not want to mislead area source facilities into believing they

have a deference when the State requires a permit. Therefore,

the EPA has not included a deference of permitting

requirements of area sources within the petroleum refinery

source category in the final rule. However, the NESHAP does

not apply to the area sources.

Comment: In response to the EPA's request for comment on

whether small refineries are major sources, one commenter

(IV-D-23) stated that based on 40 years of operation, the HAP
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emissions from their 3,000 barrel per day refinery would be

over 9.1 Mg/yr (10 tpy) of a single HAP or 22.7 Mg/yr (25 tpy)

of a combination of HAP's.

One commenter (IV-D-50) believed that many small

refineries currently emit less than 22.7 Mg/yr (25 tpy) of

HAP's. The commenter (IV-D-50) also believed that the

9.1 Mg/yr (10 tpy) limitation per HAP in section 112 will

cause most small refineries to be considered a "major source,"

but that the classification will ultimately depend on how the

EPA requires facilities to calculate and estimate HAP

emissions. 

One commenter (IV-D-45) provided emissions information

demonstrating that they were not a major source, and contended

that since their plants are located in remote nonattainment

areas there is no reason to evaluate them for regulation as an

area source. The commenter's (IV-D-45) evaluation of

emissions from their COTU's was conducted using EPA AP-42

emissions factors for tanks, flares, heaters and emergency

generators. The commenter's (IV-D-45) fugitive emissions were

calculated from actual plant tests included in an appendix to

their comments. The commenter (IV-D-45) included Arctic

heating fuel vapor pressures. The commenter (IV-D-45)

explained that the small volume throughput to tankage and the

low vapor pressure resulting from operation in the arctic,

where the average temperature for nine months of the year is

zero degrees Fahrenheit and the other three months of the year

it is fifty degrees Fahrenheit, results in small HAP emissions

from tanks and transfer operations. The commenter (IV-D-45)

stated that the COTU's have no process vents to the

atmosphere, all gas produced in the refining operations is

either recycled for recompression and reuse or is routed to a
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flare, and all pressure safety valves relieve to a flare

system. 

Response: The EPA requires facilities to calculate and

estimate HAP emissions based on a facility's potential to emit

HAP, considering controls, from all activities at the plant

site. Area HAP sources located in a remote nonattainment area

would need to be evaluated for regulation along with other

attainment or nonattainment area HAP sources. The commenter's

(IV-D-45) contention that their petroleum refinery area HAP

source should not be evaluated for regulation along with other

area HAP sources implies that industries located in remote

areas should not have to control their HAP emissions. 

If the commenter's (IV-D-45) plant is demonstrated to be

an area source, it would not be subject to the petroleum

refinery rule. Furthermore, with the inclusion of the SIC

code definition 2911 for petroleum refineries in the

definition of a "petroleum refinery process unit," the

commenter's COTU's may be excluded from coverage under this

rule.

Comment: Two commenters (IV-D-12, IV-D-15) contended

that the 9.1/22.7 Mg/yr (10/25 tpy) HAP limit should be

expanded to 10/35 tons per year and be based on actual

emissions instead of potential emissions. One commenter

(IV-D-15) stated that small facilities may barely meet the

22.7 Mg/yr (25 tpy) cutoff, but potential expansions to the

HAP list may occur which would increase a facility's combined

HAP emissions resulting in more small refineries exceeding the

22.7 Mg/yr (25 tpy) limit. Another commenter (IV-D-12)

objected to the 9.1/22.7 Mg/yr (10/25 tpy) limit because some

HAP's are double counted, once as a generic chemical pollutant

for State requirements, and again for each hazardous
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constituent contained in the generic pollutant for Federal

MACT standards. 

Response: The Act establishes the 9.1/22.7 Mg/yr

(10/25 tpy) major source determination limit criteria based on

a source's potential to emit. The individual NESHAP,

developed under the Act, cannot change these major source

determination limit criteria.

Comment: One commenter (IV-D-11) stated that in the HON

and proposed refinery MACT, the EPA states that a facility may

have more than one HAP emission source, and that marine or

gasoline loading operations by virtue of their co-location at

a refinery, could qualify the refinery as a major source. One

commenter (IV-D-22) objected to the rule regulating co-located

emission sources based on their location at a facility that

qualifies as a major HAP source rather than the emissions that

occur from the co-located emission source. The commenter

(IV-D-22) stated that gasoline loading terminals should be

subject to the MACT only when they have the same environmental

impact as other "free standing" terminals. 

Response: The Act requires the EPA to regulate major HAP

sources. A major HAP source is defined as "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..." This means that

the EPA is obligated to consider the whole site when

determining if a source is major and to regulate co-located

emission sources (e.g., marine or gasoline loading

operations), when applicable.

3.3.3 Process Changes and Additions

Comment: One commenter (IV-D-21) disagreed with the use

of the phrase "the new or reconstructed source" in reference

to additions or changes subject to new source requirements.
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The commenter (IV-D-21) contended that changes to a process

unit should not trigger new source requirements unless they

meet the criteria for "reconstruction." The commenter

(IV-D-21) recommended that in § 63.640(k)(1), (2) and (2)(ii),

"new or reconstructed source" should be replaced with

"reconstructed source, addition or change." The commenter

(IV-D-21) suggested that the entire proposal be searched for

similar phrases that could cause a misinterpretation,

subjecting an entire refinery to new source MACT requirements.

Three commenters (IV-D-21, IV-D-42, IV-D-44) supported

the proposal in § 63.640(i) that additional process units and

additional emissions points or deliberate operational changes

at a process unit should be subject to existing source MACT

provisions instead of new source MACT unless they meet the

criteria in § 63.640(i) or (j).

Two commenters (IV-D-10, IV-D-11) agreed with the EPA's

definition of source. The commenters (IV-D-10, IV-D-11) also

stated that any determination of new source control

requirements must be based on the application of the criteria

to the refinery as a whole (e.g., 50 percent of the fixed

capital cost that would be required to construct a comparable

new refinery).

Response: The EPA evaluated the commenter's (IV-D-21)

request and determined that the commenter's (IV-D-21) proposed

editorial changes met with the intended requirements of the

rule [that additional process units and additional emissions

points or deliberate operational changes at a process unit

should be subject to existing source MACT provisions instead

of new source MACT unless they meet the criteria in

§§ 63.640(i) or (j)]. The EPA determined that the proposed

changes would not change the integrity of the rule and had the

potential to reduce misinterpretation of the rule. Therefore,
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the EPA incorporated the commenter's (IV-D-21) proposed

editorial changes in the final rule. 

Comment: One commenter (IV-D-21) suggested that the

proposed § 63.640(e)(2)(iv) be deleted. The commenter

(IV-D-21) agreed that if the material in a vessel is changed,

the vessel should become subject to any applicable

regulations. The commenter (IV-D-21) stated that this is

covered under § 63.640(l), therefore 63.640(e)(2)(iv) is

unnecessary. If § 63.640(e)(2)(iv) is not deleted, the

commenter (IV-D-21) requested that the term "reevaluate" be

defined. The commenter (IV-D-21) suggested that the

evaluation be through engineering judgment, and that no

special notification beyond the Notification of Compliance

Status be required. The commenter (IV-D-21) also requested

that if § 63.640(e)(2)(iv) is not deleted, provisions be added

stating that storage vessels that already have the required

control technology do not require reevaluation. The commenter

(IV-D-21) also requested that provisions be added that

reevaluation is not required if the new material to be stored

is of a group of materials previously determined to be

storable in a vessel without triggering additional controls.

Response: The EPA concurs that the requirements cited

under § 63.640(e)(2)(iv) are already covered under

§ 63.640(l). The EPA has deleted § 63.640(e)(2)(iv) from the

final rule. 

Comment: One commenter (IV-D-21) requested that

"material" be defined as "common classes of liquids, such as

gasoline, naphtha, distillate, solvent and lubricating oil."

The commenter (IV-D-21) requested that material changes not

include changes in product grades or specifications.

Response: The EPA intended for "material changes" to be

changes in wholesale materials and not changes in product
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grades or specifications. A definition for "material" has

been added to the final rule for clarification of the rule's

intent.

Comment: One commenter (IV-D-09) stated that the

provisions in § 63.460(l) were confusing because the terms

Group 1 and Group 2 emission points were not defined.

Response: Group 1 and Group 2 emission point definitions

were included in § 63.641 of the proposed rule. The EPA has

maintained these definitions in § 63.641 and has added a

reference to these definitions in § 63.460(1) of the final

rule.

3.4 REGULATED POLLUTANTS

Comment: One commenter (IV-D-07) claimed that VOC are

regulated by this rule as much as HAP's are. The commenter

(IV-D-07) contended that VOC are sufficiently regulated under

Title I of the Act. The commenter (IV-D-07) recommended that

the EPA find a way to reduce HAP's without infringing on

Title I requirements.

Response: The EPA agrees that VOC, as well as HAP, would

be controlled by the technologies utilized to comply with this

rule. Over 85 percent of the listed HAP's are VOC, therefore,

control measures for HAP will often end up controlling VOC. 

However, under the Act, the EPA is required to establish MACT

for major HAP sources. If MACT requires greater control than

what exists through Title I requirements, it needs to be

instituted. If controls installed to meet Title I

requirements are sufficient to meet MACT requirements, further

control is unnecessary. Hazardous air pollutants are

controlled under MACT to protect human health, welfare, and

environment. 

Comment: Two commenters (IV-D-21, IV-D-25) noted that

refineries emit fewer than 40 of the chemicals on the HAP list
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in the Act and suggested that testing would be less costly and

the regulation would be more consistently interpreted if the

rule regulated only the organic HAP's applicable to refineries

rather than all "organic HAP's." One commenter (IV-D-21),

explained that polycyclic organic matter (POM) was not

included on their proposed list because, although POM does

exist in petroleum refineries, the emission levels are

insignificant. One commenter (IV-D-21), provided a table of

these 40 HAP's and requested that a table of organic HAP's be

included in the rule. The commenter (IV-D-21) expressed

concern over the phrase "organic chemical" not being defined. 

The commenter, (IV-D-21), provided a table indicating which

pollutants they believe are organic HAP's. 

One commenter (IV-D-29) suggested that all refineries

that do not have light hydrocarbons be exempt from the

proposed regulation. The commenter (IV-D-29) stated that some

small California refiners exclusively handle heavy crude oil

and do not have fuel gas systems or flares as they do not

contain volatile compounds. The commenter (IV-D-29) stated

that some refineries do not produce any products lighter than

kerosene. 

One commenter (IV-D-52) urged the EPA to consider that

petroleum refineries emit pollutants other than organic HAP's,

such as hydrogen chloride, an inorganic HAP. The commenter

stated that focusing on a limited list of pollutants may

underestimate the cost effectiveness of the control options

being proposed for this rule. 

One commenter (IV-D-51) concurred with the EPA that the

proposed rule should only address emissions of organic HAP's

and that metal HAP's, hydrogen chloride, carbonyl sulfide and

carbon disulfide emitted from FCCU catalyst regeneration

vents, catalytic reformer catalyst regeneration vents, and
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sulfur plant vents be considered separately. The commenter

(IV-D-51) stated that these pollutants will be regulated under

a separate source category that has a 1997 promulgation date.

Response: The petroleum refinery process units regulated

by subpart CC emit organic rather than inorganic HAP's. 

Inorganic HAP's are emitted from catalytic cracking catalyst

regeneration vents, sulfur plant vents, and catalytic reformer

catalyst regeneration vents, which will be evaluated for

regulation in the future.

The definition of "miscellaneous process vents" in both

the proposed and final rule specifically excludes the vents

mentioned by the commenters. The EPA has also added a list of

pollutants covered under the rule to assist facilities in the

determination of whether a processing unit or emission point

is covered under the rule and to simplify compliance

determination. Refineries only emit a subset of the organic

HAP's listed in the Act. Those organic HAP's emitted by

refineries are included in the list of regulated HAP's. There

is no need for the rule to cover organic HAP's that refineries

do not emit.

Comment: One commenter (IV-D-21) stated that the

exemption from subpart CC for equipment containing no HAP's is

too restrictive. The commenter (IV-D-21) recommended setting

a de minimis concentration of 0.1 weight percent total

carcinogens and 1.0 weight percent total HAP's. The commenter

(IV-D-21) requested that the de minimis level be no lower than

20 ppmv for total organic HAP's. The commenter (IV-D-21)

recommended that § 63.640(g)(2) be modified to read: 

"Equipment containing organic HAP's in any liquid and vapor at

concentrations below 0.1 weight percent total carcinogens and

below 1.0 weight percent total."
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Response: Section 112 of the Act requires technologybased standards and not health-based standards. Therefore, a

health-based de minimis (i.e., 0.1 weight percent total

carcinogens) would be inappropriate under a NESHAP. However,

the refineries rule includes applicability criteria to

determine if controls must be applied to individual emission

points. For example, there are size and vapor pressure

criteria to determine if storage vessels must apply control. 

As explained in chapter 4 of this document, the final rule

also includes criteria for determining which process vents

require control.

Comment: One commenter (IV-D-21) requested that, when

determining the applicability of a process vent

[§ 63.640(f)(4)], engineering judgement be allowed to

determine if a process vent's organic HAP emissions exceed

20 ppmv in lieu of EPA Method 18 (unless the engineering

judgement is not accepted by the permitting authority).

Response: Miscellaneous process vents are defined to

include only vents with concentrations above 20 ppmv. Those

with concentrations below this level are not subject to any

requirements of the rule. This determination can be based on

testing or process knowledge/engineering assessment. As

explained in Chapter 4 of this document, an emission rate cutoff of 33 kg/day (72 lbs/day) for existing sources and

6.8 kg/day (15 lb/day) for new sources has been added to

distinguish Group 1 from Group 2 vents. Only Group 1 vents

with emissions greater than 33 kg/day (72 lbs/day) for

existing sources and 6.8 kg/day (15 lb/day) for new sources,

are required to apply controls. The determination of whether

a vent is Group 1 or Group 2 can also be based on either

Method 18 or Method 25A testing or process

knowledge/engineering assessment. Specific language has been
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added to the process vent provisions to clarify what

constitutes an "engineering assessment."

3.5 COORDINATION/OVERLAP WITH OTHER RULES

3.5.1 Overlap With Other NESHAP and NSPS

Comment: Two commenters (IV-D-25, IV-D-33) suggested

that the petroleum refinery NESHAP rule supersede the HON for

wastewater streams from chemical manufacturing process units

that are treated within refinery wastewater systems. (The

petroleum refineries NESHAP requires compliance with the BWON,

which is different from the HON.) Two commenters (IV-D-25,

IV-D-33) stated that wastewater streams from chemical process

units are mixed with other refinery wastewater streams for

treatment and benzene could be used as a surrogate for other

HAP's in chemical process wastewater streams at refineries. 

One of the commenters (IV-D-25) asserted that the section 114

responses include chemical process unit wastewater. The

commenters (IV-D-25, IV-D-33) stated that the BWON and HON

wastewater requirements for biodegradation units conflict, in

that the benzene waste NESHAP allows operation within general

guidelines, whereas the HON requires a specific HAP removal

demonstration that includes all streams treated in the unit. 

One commenter (IV-D-25) stated that it would be burdensome to

test all the refinery streams as well as HON streams that are

treated in biounits.

One commenter (IV-D-10) supported streamlining refinery

MACT wastewater and HON wastewater applicability using the

section 114 data. Two commenters (IV-D-06, IV-D-10) contended

that chemical and refinery wastewater streams are co-mingled. 

Additionally, the commenters (IV-D-06; IV-D-10) asserted that

benzene could still be used as a surrogate because it would

still be the largest HAP contributor. The commenters

(IV-D-06, IV-D-10) stated that the HON wastewater standards
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applicable to a refinery's chemical manufacturing process

units should be superseded by the refinery MACT standard once

they are promulgated. One commenter (IV-D-06) emphasized that

this was especially important for mixed streams entering

biodegradation units because the BWON regulation allows

operation within general guidelines and the HON requires

specific HAP removal efficiencies.

Response: Any conflicts that may exist between the BWON

and the HON wastewater provisions need to be addressed within

the context of those rules. The EPA is currently working to

eliminate true conflicts in the requirements. However, the

BWON cannot override the HON because the HON covers 112

organic HAP's whereas the BWON only covers emissions of

benzene because the potential for good biodegradation versus

loss is dependent on the chemical, and because the BWON

applies to waste and wastewater and the HON only applies to

wastewater. The EPA does not believe that demonstration of

control of benzene can equate to sufficient control of all

organic HAP's. For petroleum refinery sources, benzene is a

good surrogate for all organic HAP's because it is the largest

HAP contributor from this source.

The final rule clarifies that a petroleum refinery

wastewater stream that is conveyed, stored, or treated in a

wastewater stream management unit that also receives streams

subject to the provisions of the HON, §§ 63.133 through 63.147

of subpart G shall comply with the provisions in §§ 63.133

through 63.137 and § 63.140 of subpart G for all equipment

used in the storage and conveyance of the Group 1 or Group 2

wastewater stream, the provisions in both 40 CFR part 61,

subpart FF (BWON) and in §§ 63.138 and 63.139 of subpart G for

the treatment and control of the Group 1 or Group 2 wastewater

stream, and the provisions in §§ 63.143 through 63.148 of
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subpart G for monitoring and inspections of equipment and for

recordkeeping and reporting requirements. The final rule also

clarifies that the owner or operator of a wastewater stream

subject to both the BWON and HON is not required to comply

with the monitoring, recordkeeping, and reporting requirements

associated with the treatment and control requirements in

40 CFR part 61, subpart FF. 

Comment: One commenter (IV-D-06) stated that there are

several provisions in the refinery wastewater NSPS that

conflict with the BWON, and therefore, conflict with the

proposed refinery rule. The commenter (IV-D-06) recommended

modifying the NSPS by specifying that compliance with

monitoring, recordkeeping, and reporting requirements be

identical to those in the BWON.

Three commenters (IV-D-19, IV-D-21, IV-D-25), in regard

to wastewater monitoring, recordkeeping and reporting,

requested a statement be included in the rule indicating that

the NESHAP supersedes the NSPS, when both are applicable. The

commenter (IV-D-19) contended that this regulation, combined

with the BWON, SOCMI HON and NSPS will be very confusing to

facilities that must comply with all four, especially in

regard to part 70 operating permits. One commenter (IV-D-38)

suggested that the EPA coordinate the recordkeeping and

reporting requirements that effect petroleum refinery

wastewater systems. The commenter recommended that the

requirements of the petroleum refinery rule take precedence. 

Another commenter (IV-D-20) urged the EPA to state that

compliance with the BWON overrides the requirements of NSPS

QQQ so that a source only has one set of compliance and

reporting duties.

Response: The EPA agrees that, combined with other

rulemakings that may apply to a petroleum refinery wastewater
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stream and/or wastewater stream managed in a piece of

equipment, there may be some confusion and overlapping

requirements. In order to address the commenters' (IV-D-06,

IV-D-19, IV-D-20, IV-D-21, IV-D-25) concern regarding the

potential confusion when a petroleum refinery wastewater

stream and/or wastewater stream managed in a piece of

equipment is subject to multiple regulations, the final rule

clarifies the wastewater provisions that would apply to a

petroleum refinery wastewater stream and/or wastewater stream

managed in a piece of equipment subject to multiple rules.

The final rule clarifies the applicability of 40 CFR

part 63, subpart CC wastewater provisions by stating that a

Group 1 wastewater stream managed in a piece of equipment that

is also subject to the provisions of 40 CFR part 60,

subpart QQQ is required only to comply with 40 CFR part 63,

subpart CC. The final rule also clarifies that a Group 2

wastewater stream managed in equipment that is also subject to

the provisions of 40 CFR part 60, subpart QQQ is required only

to comply with subpart QQQ. Clarification of the applicable

provisions for a wastewater stream that is conveyed, stored,

or treated in a wastewater stream management unit that also

receives streams subject to the provisions of 40 CFR part 63,

subpart F has been included in the final rule.

Comment: Two commenters (IV-D-21, IV-D-25) suggested

that, similar to the HON, the refinery NESHAP should specify

that the equipment leaks provisions of the refinery NESHAP

over-ride other NSPS and NESHAP that apply to the same

equipment.

Response: The EPA has clarified the applicability of

40 CFR part 63, subpart CC equipment leak provisions in the

final rule. The final rule clarifies that petroleum refinery

sources subject to 40 CFR parts 60 and 61 regulations are
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required to comply only with the petroleum refinery NESHAP

equipment leak provisions. This clarification is consistent

with what was done in the HON. Petroleum refinery process

unit equipment leak emission points are distinguished from

SOCMI process unit equipment leak emission points by the

inclusion of SIC code 2911 definition in the petroleum

refinery process unit definition in the final rule. 

Therefore, there should not be any applicability conflicts

between 40 CFR part 63, subpart CC, petroleum refinery

equipment leak provisions and 40 CFR part 63, subpart H HON

equipment leak provisions.

Comment: One commenter (IV-D-25) requested that the EPA

clarify the relationship between the proposed refinery NESHAP

and the gasoline distribution NESHAP currently under

development. The commenter (IV-D-25) recommended that the

gasoline distribution rule apply only to loading racks at

marketing terminals and pipeline breakout stations classified

under SIC codes 5171 and 4613 whereas the refinery NESHAP

storage and fugitive provisions apply to operations at

refineries (SIC Code 2911).

Response: The final rule has been clarified after

consideration of this comment. The NESHAP for Gasoline

Distribution Facilities (40 CFR part 63, subpart R) covers

bulk gasoline terminals and pipeline breakout stations in SIC

codes 5171 and 4613 that may be co-located at a petroleum

refinery in addition to independently located facilities. The

petroleum refinery "affected source" has been clarified in the

final rule to include gasoline loading racks located at

petroleum refineries if they are classified under the

petroleum refineries SIC code (2911). The gasoline loading

rack emission points in SIC 2911 at refineries may be included

in emissions averages. The EPA has done this to encourage the
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use of flexible compliance approaches (i.e., averaging) where

they can be properly monitored and enforced. Furthermore,

gasoline loading operations classified under 2911 receive

their products directly from refinery process units and are

operated by the same entity, so their operation is closely

tied to refinery process units. It is logical to regulate

them under the same rule as part of the same source.

The EPA has also referenced the SIC code (2911) in the

petroleum refinery process units definition in order to

clarify the process units covered by the rule.

Comment: One commenter (IV-D-21), suggested that the

cost to refineries of complying with similar regulations could

be reduced if the refineries were allowed to comply with only

the most stringent. The commenter (IV-D-21) suggested that

compliance with subpart CC of this regulation should exempt

refineries from less stringent NSPS and NESHAP regulations. 

The commenter (IV-D-21) suggested that process vents subject

to subpart CC of this rule be exempt from 40 CFR part 60,

subparts III, NNN, and RRR. The commenter (IV-D-21) also

suggested that storage vessels subject to subpart CC of this

rule be exempt from 40 CFR 60, subparts K and Ka and

40 CFR 61, subpart Y. Conversely, the commenter (IV-D-21)

suggested that storage vessels subject to 40 CFR 60,

subpart Kb be exempt from subpart CC of this rule, because

subpart Kb is more stringent.

Response: The EPA agrees with the commenter (IV-D-21)

that the cost to refineries of complying with similar

regulations could be reduced if the refineries were allowed to

comply with only the most stringent. Section 63.640 of the

final rule (40 CFR part 63, subpart CC) has been amended (as

stated in the previous response) to clarify the provisions

that apply to petroleum refinery emission points that may be
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subject to multiple regulations. Petroleum refinery process

unit emission points are distinguished from SOCMI process unit

emission points by the inclusion of SIC code 2911 in the

petroleum refinery process unit definition in the final rule. 

Therefore, there should be no regulatory overlap between

process vents subject to 40 CFR part 63, subpart CC and 40 CFR

part 60, subpart III, NNN, and RRR.

The final rule clarifies the applicability of 40 CFR

part 63, subpart CC storage vessel provisions to storage

vessels at existing and new petroleum refinery sources subject

to 40 CFR part 60, subparts K, Ka, or Kb. The specific

provisions are structured such that each vessel is subject to

only the more stringent rule. For example, a Group 1 storage

vessel at an existing refinery that is also subject to

subpart K or Ka is required only to comply with the petroleum

refinery NESHAP storage vessel provisions. The benzene

storage vessel NESHAP (40 CFR part 60, subpart Y) would apply

to a SOCMI process unit storage vessel and not a petroleum

refinery process unit storage vessel; therefore, clarification

of applicability in the final rule was unnecessary.

Comment: One commenter (IV-D-36) suggested that when the

EPA applies existing emission standards to HAP sources in this

regulation, such as 40 CFR part 60, subpart Kb for storage

tanks, BWON for Wastewater and SOCMI HON to equipment leaks,

that it be clearly stated that compliance with the

requirements under those rules is sufficient to comply with

this rule. The commenter (IV-D-36) also requested that the

EPA clearly state any new standards and where they apply.

Response: The petroleum refinery NESHAP rule, in

referencing the provisions of other regulations, clearly

specifies those sections of the referenced rules that do and

do not apply. Subpart CC also clearly specifies any
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additional provisions that are not included in the crossreferenced rules. Subpart CC does not impose any requirements

beyond the benzene waste operations NESHAP for wastewater. 

Subpart CC does not reference 40 CFR part 60, subpart Kb for

storage vessels in refinery process units. Instead it

references HON storage vessel provisions without certain

fitting requirements. The equipment leaks section of

subpart CC lists which parts of 40 CFR part 60, subpart VV or

HON apply and which have been changed.

Comment: One commenter (IV-D-19) recommended that it be

made clear that certain provisions supersede other Federal

rulemakings in the applicability section (§ 63.640) of the

final rule. Two commenters (IV-D-19, IV-D-21) suggested that

a table be provided delineating the applicability of

overlapping regulations to a petroleum refinery source subject

to the petroleum refinery NESHAP.

One commenter (IV-D-10) contended that conflicts exist

between existing NSPS requirements and NESHAP's (under the old

section 112) requirements. The commenter (IV-D-10) requested

that the EPA establish whether the NSPS or the NESHAP

requirements supersede in this rulemaking. 

Response: As suggested by the commenter (IV-D-19), the

EPA has clarified the applicability of the petroleum refinery

NESHAP as it relates to other Federal regulations affecting

the same source in § 63.640 of the final rule. The text cites

specific overlaps and clarifies which rule the source must

comply with in each case. The EPA did not use a table format,

as suggested by the commenters (IV-D-19, IV-D-21), because of

the level of specific detail that had to be included in a

table would be more confusing than clarifying.

Comment: One commenter (IV-D-21), stated that a process

unit should not be regulated by both subpart CC of this
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regulation and HON or the Gasoline Distribution MACT. The

commenter (IV-D-21), requested that the following exemption be

added to § 63.640(g): "(7) Process units and emission points

subject to subparts F, G, H, I, and R of this subpart."

One commenter (IV-D-24) was concerned with overlap with

the HON and the proposed petroleum refinery NESHAP. The

commenter specifically mentioned MTBE, benzene, toluene, and

xylene units that are clearly subject to HON and in the broad

petroleum refinery process unit definition. The commenter

suggested that units and emission permits subject to

subparts F, G or H be specifically exempted. The commenter

provided specific regulatory language.

One commenter (IV-D-01) requested that the applicability

section of the proposed rule be clarified to state that a

manufacturing process unit that is subject to the SOCMI source

category, and thus the HON, is exempt from the proposed

petroleum refinery NESHAP. The commenter stated that this

would reflect the wording of section VI(A)(1)(a) of the

proposal preamble.

Response: The EPA agrees that if a process unit is

subject to the HON, 40 CFR part 63, subpart CC should not

apply. The applicability provisions of the refineries rule

were structured to avoid overlapping regulations. Petroleum

refinery process unit emission points are distinguished from

SOCMI process unit emission points by the inclusion of

SIC code 2911 definition for petroleum refining in the

petroleum refinery process unit definition in the final rule. 

The inclusion of the SIC code for petroleum refinery in the

definition of a petroleum refinery process unit should

alleviate any applicability conflicts between a SOCMI and

petroleum refinery process unit. The definition of the

"affected source" has also been changed in the refineries rule
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to clarify that gasoline loading racks at refineries are

subject to 40 CFR part 63, subpart CC rather than the gasoline

distribution NESHAP if the transfer operation is classified

under SIC code 2911. If the transfer operation has an SIC

code other than 2911, it is covered by 40 CFR part 63,

subpart R.

Comment: Two commenters (IV-D-20, IV-D-49) contended

that the applicability of this rule overlaps the proposed

Stage I Gasoline Distribution NESHAP and that the EPA should

clarify which rule applies for gasoline tanks and waste

operations located at petroleum refineries. One of the

commenters (IV-D-20) suggested that the EPA allow refinery

sources the option of subjecting their gasoline storage tanks

to either the Gasoline Distribution NESHAP or the Petroleum

Refinery NESHAP. The commenter (IV-D-20) suggested notifying

the EPA of the choice through the Initial Notification

Requirements.

Response: The EPA has not included the commenter's

(IV-D-20) suggestion to allow petroleum refineries the option

of subjecting their gasoline storage tanks to either the

Gasoline Distribution NESHAP or the Petroleum Refinery NESHAP. 

Clarification of the applicability of the rule regarding

storage vessels covered by the Petroleum Refinery NESHAP has

been included in the final rule. If a storage vessel can be

classified as a petroleum refining process unit, as defined in

the final rule and is classified under SIC code 2911, then the

storage vessel is subject to the petroleum refinery NESHAP. 

If the storage vessel is part of a gasoline terminal

classified under an SIC code other than 2911 it is not subject

to the petroleum refinery NESHAP. 

The definition of a "petroleum refining process unit" has

been clarified in the final rule as being a process unit used
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in an establishment primarily engaged in petroleum refining,

as defined in the SIC for petroleum refining (2911). Standard

Industrial Classification codes are assigned and used by

facilities to distinguish between equipment. The

incorporation of the SIC code definition for petroleum

refining to the definition keeps the management of air

pollution control equipment under the same management

structure as the surrounding process equipment.

3.5.2 Overlap With Title V

Comment: Three commenters (IV-D-22, IV-D-42, IV-D-51)

supported streamlining the Act regulations by coordinating

requirements in the Title V program, SOCMI, HON, and NESHAP

standards. One commenter (IV-D-42) contended that refineries

were already heavily regulated and before any new regulations

are issued, the EPA should consider these existing regulations

and focus their efforts on what additional regulations are

needed. 

Response: Existing regulations were considered in

developing the petroleum refineries NESHAP. The HON affects

only certain chemical manufacturing units at refineries. 

Applicability provisions of the refineries rule were

structured to avoid overlapping with HON. The refineries

NESHAP wastewater rule refers to the BWON, to avoid placing

additional burden on refineries. The NSPS were considered in

developing the NESHAP. Because the NSPS apply only to new

sources and only to VOC's, there are many HAP emission points

at refineries that are not regulated by the NSPS. The

petroleum refineries NESHAP is necessary to regulate these HAP

emissions as mandated by the Act. Title V does not impose any

new control requirements, so will not conflict with the NESHAP

in terms of control requirements. The recordkeeping and

reporting requirements of the refineries NESHAP have been
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structured to be consistent with Title V and avoid duplicative

reporting.

Comment: One commenter (IV-D-21) pointed out that

section 63.642(a) of subpart CC requires sources affected by

the proposed regulation to obtain a title V operating permit

or submit an implementation plan as a temporary alternative to

comply with the regulation. The commenter (IV-D-21) suggested

that section 63.642(a) of subpart CC be deleted or it be made

clear that the part 70 or 71 application is not required until

the deadline required by those permits. The commenter

(IV-D-21) pointed out that where there are references to an

operating permit in the proposal, there are good alternatives

to the operating permit, such as submitting information in a

separate "submittal."

Response: The EPA agrees with the commenter (IV-D-21)

that a part 70 or 71 application is not required until the

deadline required by those permits. However, the EPA does not

agree that clarification of this is necessary in the rule. As

written, § 63.642(a) of subpart CC simply requires sources to

obtain part 70 or part 71 permits. It does not specify a date

and it does not mention an "implementation plan". The only

time an implementation plan is needed is if a source chooses

to comply by using emissions averaging. The provisions in

§ 63.653(d) of subpart CC state that the required information

"may be submitted in an operating permit application, in an

amendment to an operating permit application, in a separate

submittal, or in any combination of the three". A deadline

for submittal is provided. Where the proposal gives

alternatives such as the notification of compliance status. 

The use of the word "or" reflects an option, not a sole

requirement.
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Comment: One commenter (IV-D-21) suggested that if

acquiring a Title V permit is a requirement of the proposed

regulation, that it be made clear that the rule requires the

application for a Title V permit. The commenter (IV-D-21)

suggested that the word "apply" replace "obtain" since

obtaining a permit is not wholly within the control of the

owner/operator.

Response: The EPA concurs that obtaining a title V

operating permit is not wholly within the owner or operator's

power, and that it is required as a result of this rulemaking. 

Therefore, the EPA has made the commenter's suggested change

to the final rule.

3.5.3 NESHAP General Provisions Comments

Comment: One commenter (IV-D-05) expressed concern that

the potential overlap between MACT regulations will be an

ongoing issue and the EPA should consider ways of addressing

the issues in more general ways such as amending the General

Provisions to specify that no emission point will be subject

to more than one MACT standard. Another commenter (IV-D-21) 

stated that no emissions unit should be regulated under more

than one part 63 source category standard. The commenter

(IV-D-21) asserted that if a emission unit was regulated by

more than one, it is likely that they would conflict. The

commenter (IV-D-21) urged the EPA to add "No emissions unit

shall be regulated under more than one source category under

part 63" to subpart A of the proposed regulation. The

commenter (IV-D-21) provided an explanation of how certain

rules, including the HON, the Gasoline Distribution MACT, and

Non-SOCMI chemical MACT standards may overlap with the

petroleum refinery NESHAP.
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One commenter requested that the EPA consider amending

the part 63 "General Provisions" to specifically state that no

emission point is subject to more than one part 63 subpart.

Response: The General Provisions (40 CFR part 63,

subpart A) were promulgated on March 16, 1994 (59 FR 12408). 

These provisions codify general procedures and criteria to

implement emission standards. It is up to the individual

standards under part 63 to discern the applicability of a

standard to an emission point. The EPA has amended § 63.640

of the final rule to address the applicability of the

petroleum refinery NESHAP when there is potential for overlap

among different MACT standards. The EPA has also made changes

to the applicability and definition sections to avoid overlap.

3.5.4 Overlap With State and Local Rules

Comment: Two commenters (IV-D-21, IV-D-25) suggested

that, as allowed by § 63.102(b) of the HON, refineries subject

to State or local requirements that provide comparable HAP

emission reductions to the refineries NESHAP should be allowed

to comply with the existing State or local requirements. The

commenter (IV-D-25) further requested that, if a facility can

demonstrate that the recordkeeping and reporting requirements

of a State or local rule would be sufficient to demonstrate

compliance with the refinery NESHAP, then they should be

allowed to use the State or local paperwork requirements.

Response: The EPA has amended § 63.640 of subpart CC to

state that the permitting authority for the affected facility

may allow consolidation of the monitoring, recordkeeping, and

reporting requirements under this subpart with the monitoring,

recordkeeping, and reporting requirements under other

applicable requirements in 40 CFR part 60, 61, or 63, and in

any 40 CFR part 52 approved State implementation plan provided

the implementation plan allows for approval of alternative
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monitoring, recordkeeping, and reporting requirements and

provided that the permit contains an equivalent degree of

compliance and control. This would allow an affected source

to submit one set of compliance reports for the source.

Comment: One commenter (IV-D-12) complained that the

proposed rule will threaten the survival of small refineries

by imposing additional compliance, reporting and recordkeeping

requirements, which in many cases duplicate State and local

provisions. Another commenter (IV-D-15) expressed concern

that the proposed rule, by specifying HAP's would result in

significant data collection burdens. The commenter (IV-D-12)

stated that this was because many States require generic

information on pollutants in addition to the Federal HAP list. 

Therefore, the commenter contended, many HAP's would be double

counted.

One commenter (IV-D-12) supported the EPA's assertion

that the HAP's emitted from refineries are all VOC's. 

Therefore, the commenter (IV-D-12) stated that any regulation

which generally controls VOC's will control HAP's. The

commenter (IV-D-12) asserted that there are existing State and

local regulations more stringent than those proposed. The

commenter (IV-D-12) stated that the EPA should either rescind

the rule or provide an exemption for sources already subject

to State and local measures that result in HAP reduction or

control as effectively as the proposed NESHAP, or include

provisions for the EPA approval of more stringent State and

local measures to take the place of the Federal rule in

approved air quality control jurisdiction. The commenter

(IV-D-12) stated that refineries in the SCAQMD should be

exempt from the requirements of the rule.

Response: As noted in a previous response, the EPA has

amended § 63.640 of subpart CC to state that the permitting
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authority for the source may allow consolidation of the

monitoring, recordkeeping, and reporting requirements under

40 CFR part 63, subpart CC with the monitoring, recordkeeping,

and reporting requirements under other applicable requirements

in 40 CFR part 60, 61, or 63, and in any 40 CFR part 52

approved State implementation plan provided the implementation

plan allows for approval of alternative monitoring,

recordkeeping, and reporting requirements and provided that

the permit contains an equivalent degree of compliance and

control. This would allow an affected source to submit one

set of compliance reports for the source.

3.5.5 Relationship to Section 112(g)

Comment: One commenter (IV-D-20) requested clarification

as to whether 40 CFR 63, subpart B [112(g)] applies to changes

at a refinery after promulgation of this rule. The commenter

(IV-D-20) requested that explicit exclusions of sources

subject to this rule from subpart B requirements be noted in

the rule.

Response: The petroleum refinery NESHAP (subpart CC)

overrides 40 CFR part 63, subpart B (under the proposed

subpart B) when changes at a petroleum refinery occur to a

process unit emission point covered under 40 CFR part 63,

subpart CC. However, 40 CFR part 63, subpart B would apply to

those process unit emission points that are not covered under

40 CFR part 63, subpart CC and are located at a refinery. The

petroleum refinery rule includes specific provisions to

determine if additions or changes are subject to the new or

existing source provisions under 40 CFR part 63, subpart CC.

3.6 OTHER APPLICABILITY ISSUES

Comment: One commenter (IV-D-20) recommended including

definitions for the following terms within the proposed rule: 
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natural gas liquid, natural gas liquid process, petroleum, and

petroleum refinery.

Response: The EPA has included the SIC code 2911

definition for petroleum refining in the definition of

"petroleum refinery process unit," which clarifies the

applicability of the petroleum refinery NESHAP. Natural

liquid gas processes are classified under a different SIC

code. Therefore, clarifying definitions, as suggested by the

commenter (IV-D-20), were unnecessary in the final rule.

Comment: One commenter (IV-D-21) agreed with the

exclusions in the definitions of "process changes." The

commenter (IV-D-21) suggested that the exclusions be extended

to include startup and shutdown and temporary process changes

made to protect human life, the environment or property from

serious harm.

Response: The proposed rule never intended for "process

changes" to include startup and shutdown and temporary process

changes. The "process change" definition in the final rule

clarifies that a "process change would not include a change or

modification of an emission point." Requirements for startup,

shutdown, or malfunction of an affected source are dictated by

the General Provisions for part 63 (40 CFR part 63,

subpart A).

Comment: One commenter (IV-D-21) recommended that in the

list of refinery products, the "residual" in "residual fuel

oil" be deleted because home heating oil and other heating

oils are often called "fuel oils." The commenter (IV-D-21)

also requested that asphalt be added to the list of refinery

products.

Response: The EPA agrees with the commenter (IV-D-21)

that "residual" should be deleted from "residual fuel oil" in

the list of refinery products regulated by 40 CFR part 63,
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subpart CC. Therefore, the EPA has deleted the word

"residual" from the definition of "residual fuel oil" in the

final rule. The final rule has not added "asphalt" to the

list of refinery products regulated by 40 CFR part 63,

subpart CC because "asphalt processing" is scheduled for

development of a MACT standard in the year 2000.

4.0 SELECTION OF MACT FLOOR AND MACT - GENERAL PROCEDURES

4.1 SELECTION OF MACT FLOOR 

Comment: Several commenters (IV-D-09, IV-D-21, IV-D-22,

IV-D-25, IV-D-42, IV-D-44) objected to setting the MACT

standard based on the 94th percentile as opposed to the

88th percentile. One commenter (IV-D-25) reasoned that a

94th percentile interpretation leads to more stringent

requirements with poor cost-effectiveness. The commenter

(IV-D-25) cited pulp and paper, refinery storage tanks, and

HON storage tanks as examples of poor cost-effectiveness. 

Another commenter (IV-D-09) opposed the higher floor method

because it leads to application of California style controls

nationwide because the higher floor method requires control at

the level equivalent to the 94th percentile. The commenter

(IV-D-09) also contended that this makes the MACT floor for

existing sources identical to the floor for new sources, and
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results in half of the top 12 percent of existing sources

being out of compliance with the controls specified. The

commenter (IV-D-09) concluded that adoption of the

94th percentile undermines productive work by industry,

States, environmental organizations, and the EPA.

One commenter (IV-D-42) contended that the EPA had

already established a precedent for the 88th percentile in the

HON. The commenter (IV-D-42) stated that the EPA

interpretation is contrary to Congressional intent and

severely restricts the EPA's ability and requirement to take

into consideration other factors such as the cost of achieving

emission reductions or/and nonair quality health and

environmental impacts. The commenter (IV-D-42) noted that the

EPA may always set the standard on a case-by-case basis at

greater than the 88th percentile. 

One commenter (IV-D-09) specifically suggested that the

lower floor (88th percentile) method is more appropriate for

storage vessels. The commenter (IV-D-09) agreed that the EPA

has discretion to adopt the lower floor interpretation method.

Response: Section 112(d)(3)(A) requires that standards

be no less stringent than "the average emission limitation

achieved by the best performing 12 percent of existing

sources." The EPA has interpreted this language to mean that

EPA first determines the emission limitations achieved by

sources within the best performing 12 percent, and then

averages those limitations (See 59 FR 29196, 6/6/94). The EPA

interprets the word "average" in section 112(d)(3) to

authorize the Agency to use any reasonable method, in a

particular factual context, of determining the central

tendency of a data set. In most cases, "average" was

interpreted to be the arithmetic mean or the median. For

example, the "floor" for storage vessels is based upon the
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average vapor pressure of the top 12 percent (arithmetic mean)

while the process vent "floor" is based upon the

94th percentile (median). The choice between using the median

value or mean value depends on which value the EPA determines

best represents the central tendency of the data.

Comment: One commenter (IV-D-21) disagreed with the

procedure used in selecting MACT floor level of controls

because cost effectiveness was not included in the

determinations. The commenter (IV-D-21), cited examples from

API of the cost effectiveness for some miscellaneous process

vents. The commenter (IV-D-21) claimed that the EPA

inappropriately interpreted the Act to require that cost of

achieving emissions reductions can only be considered when

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

The commenter (IV-D-21) contended that Congress did not intend

cost effectiveness only to be considered in setting a level of

control more stringent than the MACT floor.

One commenter (IV-D-21) stated that the EPA's

interpretation of the Act regarding establishing the MACT

floor does not allow non-air quality health impacts to be

taken into consideration. The commenter (IV-D-21) claimed

that this interpretation could prevent the MACT floor from

being lowered, no matter how detrimental the non-air quality

health impacts of controls are. The commenter (IV-D-21)

contended that Congress did not intend non-air quality health

impacts only to be considered in setting a level of control

more stringent than the MACT floor.

Response: Section 112(a)(3)(A) of the Act states that

the MACT floor shall be based on the average emissions

limitation achieved by the best performing 12 percent of

sources. Under the Act, a MACT standard can be no less

stringent than the MACT floor. Therefore, additional criteria
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are not a legal means to evaluate and set the MACT floor. The

cost of control and cost effectiveness of control beyond the

floor are evaluated to determine if control beyond the floor

is feasible. The benefits at the floor and control options

beyond the floor, including non-air quality health impacts,

are evaluated and presented in the preamble. The commenter

did not provide any details specifically regarding non-air

quality impacts or other benefits of the proposed rule. 

Comment: Several commenters (IV-D-48, IV-D-49, IV-D-55,

IV-D-57) alleged that the EPA did not determine the MACT floor

for existing sources from the average of the limitations

achieved by the best performing 12 percent of existing sources

as required by the Act. One commenter (IV-D-48) claimed that

the calculation of existing source MACT floor would be

simplified if a narrow source definition was used. The

commenter (IV-D-48) suggested that the emission reductions

achieved at the best controlled sources be compared and the

average of the best performing 12 percent of vents, wastewater

streams, storage tanks, and equipment leaks, respectively, be

calculated and emission limits set for each component. The

commenter (IV-D-48) stated that calculating a floor from an

abstraction, such as a collection of process vents, in each

refinery is more difficult. The commenter (IV-D-48) requested

a numerical value for the MACT floor and if the EPA cannot

arrive at a numerical value, a more narrow source definition

is necessary. The commenter (IV-D-48) requested that the EPA

provide an explanation, with supporting facts, that shows how

the proposed MACT floors for individual types of sources

correspond to a proper floor for petroleum refineries as a

whole. The commenter (IV-D-48) stated that if this is not

possible, a more narrow source definition be used. 
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Three commenters (IV-D-55, IV-D-34, IV-D-16) suggested

that the EPA evaluate current information provided by the

California State and local agencies and recalculate MACT for

new and existing sources. Two commenters (IV-D-55, IV-D-57)

stated that the Bay Area and South Coast Area Districts of

California have over 12 percent of the affected sources in the

nation in terms of volume of crude oil processed and the

number of facilities. Two commenters (IV-D-55, IV-D-57) also

stated that the two regions have some of the most stringent

air regulations, which are more stringent than the proposed

new source MACT. Therefore, the commenter (IV-D-57) contended

that the programs implemented in these regions constitute MACT

for the refinery industry. 

Response: The average emissions limitation determined as

the MACT floor for existing sources was developed based on the

best available data, which was the data provided in the

section 114 and ICR questionnaire responses. These responses

included facilities located in California. The California

rules are based on a narrow definition of affected source, not

the whole facility. While the narrow definition of affected

source approach may seem to make determining the floor

"simpler", it is not necessarily the best or correct approach

to determine the average emissions limitation achieved by the

best performing sources. 

The Act does not define "affected source." An affected

source may be a facility, a kind of emission point, or a

collection of emission points. The definition chosen for each

MACT standard is dependent on the characteristics of the

industry being regulated and the information available to

characterize the source category. As discussed in the

preamble to the proposed regulation, the standard defines

affected source as the collection of emission points in HAP-
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emitting petroleum refinery processes within the source

category that are part of a major source. This broad

definition of affected source was chosen because it

(1) provides the flexibility to achieve the emission

reductions in a more efficient and cost-effective manner,

(2) is compatible with the BWON definition of affected source,

and (3) provides more flexibility to replace or modify

equipment without triggering the regulatory provisions

governing reconstruction.

The EPA recognizes that State and local air pollution

control standards may have different requirements for

controlling emissions than Federal standards. Many of the

State and local requirements, such as in California, are not

directly comparable to Federal requirements due to differences

in format, applicability, definitions, test methods, and

intent. In addition, many State and local standards, such as

in California, require emission controls or techniques for

which the EPA does not have adequate control effectiveness

information. Without data, such as VOC or HAP control

efficiency of equipment and controls, the EPA cannot determine

if the State or local standard are equal to or more stringent

than Federal standards. Therefore, the EPA does not agree

that control requirements for storage vessels, wastewater, or

equipment leaks are necessarily more stringent in the Bay Area

or South Coast Air Pollution Control District. The EPA reevaluated some aspects of the MACT floor after proposal and

these changes are discussed in sections 3.2 and 5.4.1 of this

document.

Comment: One commenter (IV-D-49) suggested that the EPA

reevaluate the best performing 12 percent of existing sources

because the EPA's methodology is too stringent. The commenter

(IV-D-49) asserted that the EPA's methodology has produced
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results which may be more stringent and costly than any

actually achieved and which has resulted in a hypothetical

refinery based on the best performing emission points located

within the source and not the best performing refineries.

Response: Due to the limitations of the data available

for each kind of emission point, the MACT floor analysis for

the affected source was based on the combination of control

levels for the collection of emission points rather than the

overall facility. The EPA approximated the source-wide floor

by the combinations of point-by-point determined control

levels (i.e., the combinations of the miscellaneous process

vents "floor", storage vessels "floor", equipment leaks

"floor", and wastewater "floor"). 

The approximation of the source-wide floor by

combinations of point-by-point determined control levels was

based on the paucity of data for all three kinds of emission

points and the modeling of wastewater emissions and control

characteristics. The EPA considered whether to aggregate the

available information by facility, and therefore estimate the

source-wide level of control for each facility to determine

the best performing refineries. However, the EPA rejected

that approach to determine the floor as introducing additional

assumptions and such large uncertainties as to render the

analysis meaningless. 

The EPA believes that the approach it used for developing

point-by-point approximations of the source-wide floor level

of control was the most appropriate use of the available data

base to determine the floor. Moreover, the EPA does not

believe that its methodology, when all aspects are considered,

overstated the floor. The choice of methodology was

reasonable since it provided additional assurance that,

notwithstanding the uncertainties inherent in the data base,
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the floor determined by the EPA would be no less stringent

than the actual source-wide floor.

Comment: One commenter (IV-D-48) requested an

explanation of why a percentage reduction requirement

constitutes an emissions limitation for the purposes of a

floor calculation. The commenter (IV-D-48) stated that the

law requires consistency between the floor and the emission

limitation required in the statute.

Response: The emissions limitation achieved at the floor

was based on the application of control technologies to

control specific emission points. The performance of these

technologies was documented under several other regulatory

efforts, such as the SOCMI NSPS for Air Oxidation Processes,

Distillation Operations, and Reactor Processes (40 CFR

part 60, subparts III, NNN, and RRR) and in the HON. 

Therefore, since a direct correlation can be made between the

emissions reduction via the documented performance of the

reference control technology, the percent reduction is

equivalent to the emissions limitation achieved.

Comment: Two commenters (IV-D-48, IV-D-55) alleged that

the EPA did not determine the emissions limitations achieved

by the best performing source to determine the new source

limitations.

Response: Evaluation of the MACT floor for new sources

was based on the best available information, including

section 114 questionnaires and ICR responses and evaluation of

regulations. This information was used to determine the best

controls in use at any refinery, and the characteristics of

emission points that are controlled using the best controls. 

Based on this evaluation, the applicability criteria and

achievable control levels (percent reduction or control

equipment/work practices) that comprise the new source MACT
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floor were determined. An emission rate limitation (e.g.,

lb/yr) was not used to determine the MACT floor because the

achievable emission level depends on the size, types of

process units, specific products and other factors that vary

greatly among refineries. See chapters 5, 6, 7, and 8 for

specific comments and responses on the floor level of control

for miscellaneous PV, ST, WW, and EL.

Comment: Two commenters (IV-D-46, IV-D-48) stated that

if marine loading operations are to be included in the source

category, the MACT floor for marine loading operations will

have to be recalculated for refinery marine loading operations

since the current floor does not distinguish between refinery

and non-refinery marine loading operations. Two commenters

(IV-D-46, IV-D-48) insisted that the rule must be reproposed

to determine the maximum achievable emission reduction for

petroleum refineries and marine loading operations combined. 

One commenter (IV-D-46) estimated that establishing a new MACT

floor will result in a delay of promulgation of the refinery

MACT standards of 2-3 years. One commenter (IV-D-46)

predicted that the floor for non-refinery marine loading would

become less stringent if refinery marine loading operations

are excluded from the determination. The commenter (IV-D-46)

contended that it is inappropriate to make a distinction

between refinery-linked marine vessel loading operations and

other marine vessel loading operations.

Response: At proposal, the MACT floor for refinery

marine loading operations was determined separately from the

rest of the refinery but as part of marine loading operations. 

The same controls are applicable to marine loading at

refineries as other marine loading operations. Therefore,

there is no reason to believe the floor would be different for

marine loading at refineries.
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The commenter did not provide any specific reasons to

support why reproposal would be needed or why the promulgation

would be delayed 2 to 3 years. The refineries proposal

clearly stated that EPA may include marine loading in the

refineries source category and gave ample opportunity for

comment.

Comment: Two commenters (IV-D-52, IV-D-54) said that the

total mass emission rates have not been adequately evaluated. 

One commenter (IV-D-52) was concerned that the EPA did not

have sufficient data on actual emissions from petroleum

refineries to determine the MACT floors, and that they had

used MACT floors based on the applicable NSPS and NESHAPs and

other limited data collected from existing petroleum

refineries. The commenter (IV-D-52) recommended that the EPA

request additional actual emissions data from the bestcontrolled refineries, review State regulations, and

reevaluate all the regulated emission points before

promulgating the rule. One commenter (IV-D-54) expressed

concern that total mass emission rates from refineries were

not being studied, and high emissions were being permitted to

save industry money.

Response: The total mass emissions from applicable

sources within the refineries have been evaluated using the

best available data in the determination of the MACT floor and

in estimating impacts of going beyond the floor for MACT. 

These emissions and reductions were presented in the proposed

rule and have been revised in the promulgated rule and in the

memorandum "Revised Impacts from Controlling Emissions from

Petroleum Refineries" (June 28, 1995). The emission estimates

and reductions are based on applying the best control

technologies. The regulation uses percent reduction and

equipment/work practice formats instead of limiting the total
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mass of emissions because the same emission limit is not

achievable at all refineries given differences in size, types

of process units, products, and other factors. It is not the

intent of the rule to limit production (i.e., penalizing large

facilities).

Prior to proposal, available data were collected through

section 114 and ICR's for a majority of refineries, and State

and Federal regulations were reviewed as a further source of

information on control levels. The commenter stated that more

data should be evaluated, however, the commenter did not

provide any additional data. The preamble to the proposed

regulation requested additional data in numerous places. 

Since no additional data were provided by this or other

commenters, it has been judged that additional emissions data

from commenters are not available. As described in chapter 5

of this document, some additional information on State

regulations of process vent and emissions has been evaluated

since proposal and used to revise the floor analyses. 

Comment: One commenter (IV-D-42) contended that

facilities that do not produce typical refinery products, such

as white oils and waxes, were not included during development

of the refinery MACT floors, although they may be regulated by

the proposed rule.

Response: As discussed in section 3.3, the regulation

has been clarified to be applicable to SIC Code 2911. If

those facilities are included in that SIC code, they would be

subject to the regulation. If not, then they would not be

subject to the rule.

4.2 SELECTION OF MACT

Comment: One commenter (IV-D-49) contended that the EPA

cannot justify going beyond floor controls because the overly
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conservative analysis used already results in control levels

beyond any likely to be found in an actual refinery.

Response: As stated earlier, the MACT floor analysis was

based on section 112(d)(3)(A) which requires that the

standards be based on "the average emissions limitation

achieved by the best performing 12 percent of existing

sources." The approach used to determine the level of

performance for each emission source is discussed in each

section and has been demonstrated as reasonable under the

statute. Additionally, the impacts for going beyond the floor

were considered, but options beyond the floor were not

selected.

Comment: One commenter (IV-D-55) alleged that, according

to the preamble, the EPA used a cost-benefit analysis to

determine MACT. The commenter (IV-D-55) claimed that

subjecting MACT decisions to a cost-benefit analysis is

inappropriate and illegal. The commenter (IV-D-55) cited

Senate Report 101-228 as not supporting the use of

cost-benefit analysis in determining MACT due to the

uncertainty associated with quantifying the benefits and costs

of controls. Two commenters (IV-D-55, IV-D-16) stated that

the EPA should not include cost-benefit analysis in the MACT

standards of the proposed regulation. 

One commenter (IV-D-48) stated that the EPA may consider

cost effectiveness in determining MACT but can not determine

maximum reductions achievable excluding known existing

technology. The commenter (IV-D-48) requested that the EPA

not convert the program from technology-based to cost-benefit

based but that the EPA find a way to take cost into

consideration and establish standards that realize the maximum

emission reductions achievable. The commenter (IV-D-48)

suggested that this may be accomplished by determining the
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level of maximum emission reductions achieved with existing

techniques. The commenter (IV-D-48) contended that the fact

that these controls have been applied in practice proves that

they are achievable considering cost. The commenter (IV-D-48)

cited S. Rep. 101-228 at 168-169 to support this conclusion. 

The commenter (IV-D-48) claimed that the Act requires the

maximum degree of reduction achievable. The commenter

(IV-D-48) cited the 101st Cong. 2d Sess., H. Rep. 101-952 at

339 (1990) (Conference Report) as an example of legislative

history reflecting an emphasis on maximum reductions. The

commenter (IV-D-48) stated that the report states that MACT

standards would generally be stricter than NSPS and stricter

than RACT. The commenter (IV-D-48) claimed that the Act

indicated that MACT standards would often be stricter than

LAER and BACT standards by allowing some sources subject to

all three to delay compliance with MACT standards for five

years to avoid retrofitting.

Response: The MACT floor was determined as discussed in

section 4.1. The cost-benefit analysis is to determine if it

is feasible to set MACT at a level higher than the MACT floor. 

The options above the floor that were examined are

technologically feasible, and are based on technologies in use

at some refineries, but would be more costly than the floor. 

Section 112(d) of the Act specifically states that MACT

decisions are to consider costs of achieving the emissions

reductions, non-air quality health and environmental impacts,

and energy requirements. Thus, costs and benefits of options

above the floor can be considered.

Comment: One commenter (IV-D-59) contended that if the

EPA defines source broadly and cost effectiveness determines

MACT, the cost effectiveness of the source-wide reductions for
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the broader source definition, not the cost effectiveness of

individual pieces of equipment, must be the basis for MACT.

Response: Typically, different controls are applied to

process vents, storage, wastewater, and equipment leak

emission sources. Thus, the only way to determine costs and

costs effectiveness is to calculate costs for each emission

point. Costs determined for individual emission points would

simply be summed to get total source costs and cost

effectiveness. Cost effectiveness for each kind of emission

point can, therefore, be used in selecting MACT alternatives

above the floor. Also, by evaluating the emission points

separately, the most cost effective, or optimum, control

option can be selected for each source type. (For example, if

process vents Option 1 is much more cost effective to control

than equipment leaks Option 1, the method used by EPA would

allow this determination to be made and the process vents

option would be selected while the equipment leaks option

would not. If the analysis were made on a refinery basis, as

has been suggested, MACT floor results would be overly

influenced by the process vent results and a cost-ineffective

option for equipment leaks might be chosen because it would be

overshadowed by the process vents numbers.) There would only

be a difference in the overall cost effective results if

control combinations of equipment at a refinery are different

than typical combinations. Otherwise, the approach will not

have an impact.

Comment: One commenter (IV-D-46) supported the use of

criteria such as pollution prevention, environmental equity,

affordability and technological innovation in determining the

MACT level of control because it will make the regulation more

equitable. The commenter (IV-D-46) recommended that the

criteria be distinctly defined and the reasons for including
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them prove that their inclusion is for the betterment of the

regulation. The commenter (IV-D-46) suggested that it be made

apparent how the criteria are to be implemented and the degree

of influence they have on the MACT floor. The commenter

(IV-D-46) stated that this will make the process effective, as

opposed to complicated.

Response: The benefits of the standard are evaluated as

part of evaluating MACT. Emissions reductions, non-air

quality impacts, including health impacts, and cost and

economic impacts were considered in selecting MACT. The

format of the rules allows for pollution prevention

techniques. The rationale for the MACT decisions, considering

these factors, is discussed in the proposal and promulgation

preambles. MACT, however, cannot be less stringent than the

MACT floor. The MACT floor decision is based only on the

current level of control in the industry and the Act does not

allow for consideration of benefits and costs in determining

the floor. 

Comment: One commenter (IV-D-54) requested that the

wastewater provisions be tightened up since HAP's will be

emitted from wastewater streams also.

Response: Control of wastewater streams is required by

the rule. These provisions are based on the floor level of

control. Control beyond the floor was determined to be cost

prohibitive.

Comment: One commenter (IV-D-40) suggested providing

more incentive beyond the current philosophy of merely meeting

TRE's or concentration limits by allowing measures such as a

lower percent reduction or higher concentration limits for

pollution prevention instead of end-of-pipe controls. 

Response: The proposed regulation encourages pollution

prevention several ways. While the applicability for control
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is based on emission or concentration levels, the means of

control is left for the facility to determine. For example, a

condenser instead of a combustion device could be used to

recover product in a process vent stream if it can reduce

emission rate or concentration to below the applicability

level. The storage controls (floating roofs) and equipment

leak controls (leak detection and repair) are pollution

prevention techniques.

Emissions averaging also encourages pollution prevention. 

Averaging allows facilities the flexibility to control

different emission points and potentially use pollution

prevention technology.

Comment: One commenter (IV-D-59) contended that using

the marginal cost effectiveness of controls as the criteria

for setting MACT is unacceptable if the standard is based on

averaging. The commenter (IV-D-59) stated that averaging

allows sources to forego the relatively high marginal costs of

control at certain emission points in exchange for,

presumably, cheaper reductions elsewhere. The commenter

(IV-D-59) urged that the EPA must require the maximum

achievable reductions from sources.

Response: The standard is based on maximum achievable

emission reductions, considering cost and other factors as

required by the Act. The purpose of averaging is to allow

facilities the flexibility to select the most cost-effective

emission points to achieve the maximum achievable reductions

required by the standard. The incremental costs estimated by

EPA reflect the typical costs of control for each kind of

emission point, and are appropriate to use in considering

alternatives above the floor. In most cases, the estimated

cost impacts are representative of the costs that refineries

will incur in complying with the standard. Many refineries
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are expected to comply with the standards for each kind of

emission point without using emissions averaging. It is

expected that emissions averaging will be used mainly in cases

where site-specific factors make costs of control for an

emission point higher than those estimated by the EPA.

5.0 PROCESS VENT PROVISIONS

5.1 DEFINITION OF MISCELLANEOUS PROCESS VENTS

Comment: One commenter (IV-D-21) offered support for

identifying process vents by name, rather than a partial list

of examples, to simplify interpretation. The commenter

(IV-D-21) claimed that difficulty would result because some

emissions could be considered process vents, but are better

regulated with their associated equipment.

Response: The miscellaneous vent definition was

developed to be a comprehensive definition to allow all

process vents emitting a significant quantity of HAP's to be

regulated. Listing vents by name may cause vents that should

be controlled, according to the MACT floor analysis, to be

excluded. Vents of the same name may have significantly

different HAP emissions in different refineries. 

Additionally, the absence of a vent may suggest that it is

excluded, while it may have been omitted as an oversight or
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included under another name. Listing every possible process

vent would be a time-consuming task that would provide little

benefit. The EPA contends that the existing definition is

sufficient in this regard.

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-21,

IV-D-22, IV-D-25, IV-D-38, IV-D-51) supported expanding the

definition of miscellaneous process vents to include a

pressure threshold, below which delayed coker decoking

emissions may be vented to the atmosphere without control. 

Three commenters (IV-D-21, IV-D-38, IV-D-51) suggested

that "depressuring at or below a coke drum outlet pressure of

10 psig" or similar wording be added to the final sentence of

the proposed definition along with the other coker operations

that are not considered process vents. The commenters

(IV-D-21, IV-D-38) explained the typical coker operations

prior to coke drum unheading, including venting the drum to

the atmosphere once the drum pressure is approximately

10 psig. One commenter (IV-D-21) estimated HAP emissions

vented during coker operation to be five pounds per year for a

95,000 bpcd coker. Four commenters (IV-D-09, IV-D-21,

IV-D-25, IV-D-38) asserted that a MACT floor analysis would

support that there is no incentive for controlling emissions

from coke drums depressured to 10 psig or less prior to

deheading. 

One commenter (IV-D-38) suggested that "repressuring

operations at or below 10 psig" also be added to the coker

operations that are not considered a process vent. The

commenter (IV-D-38) suggested further wording changes to the

definition. 

One commenter (IV-D-10) added that ducting or compressing

the steam vapors from the coke drum into a quench system would

allow air to enter the fuel gas system and potentially create
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an explosion hazard, and other systems may create back

pressure at the coke drum and compromise safety during the

deheading process.

Response: The portion of the definition of miscellaneous

process vents that exclude specific coker operations has been

amended to read as follows: "Coking unit vents associated

with coke drum depressuring at or below a coke drum outlet

pressure of 15 psig, deheading, draining or decoking (Coke

cutting)." The EPA has elected to set the pressure at or

below which emissions from coke drum depressuring do not

require control at 15 psig to encourage vapor recovery. Many

cokers have vapor recovery systems in which overhead vapors

from coke drums are cooled and condensed. Uncondensed gases

are recycled to the main fractionator or flared. According to

information received subsequent to the formal comment period,

the threshold of 10 psig suggested by several commenters

applies to older vapor recovery systems which depend on

flaring. Newly constructed, state-of-the-art design cokers

have efficient closed collection systems that operate at up to

15 psig and recycle vapors to the fractionator. These systems

minimize flaring and maximize vapor recovery. Operating such

a system at 10 psig would mean more flaring, which is contrary

to the design purpose of maximum vapor recovery.

Comment: Several commenters (IV-D-21, IV-D-25, IV-D-38,

IV-D-53) supported the proposed definition of miscellaneous

process vents, which exempts FCC regeneration vents. One

commenter (IV-D-53) disagreed with the exclusion of catalyst

regeneration vents from fluid catalyst cracking units in the

definition of miscellaneous process vents. The commenter

(IV-D-53) suggested that vents that exhaust from the control

device of a FCC also be included in the definition of

miscellaneous process vents. The commenter (IV-D-53) argued
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that exhausts from FCC units are not exclusively metallic and

particulate. The commenter (IV-D-53) contended that FCC units

that use low temperature catalyst regeneration without the use

of a CO boiler have significant hazardous organic emissions. 

The commenter (IV-D-53) provided emission factors to compare

emissions controlled by a CO boiler to emissions that are

uncontrolled. The commenter (IV-D-53) suggested a basis for

determining the MACT floor for existing sources as well as new

sources. The commenter (IV-D-53) also suggested ways that

older units can control their hazardous gaseous and

particulate emissions and cited an FCC unit in Wisconsin as an

example of a successful retrofit on emission-controlling

equipment.

Response: FCC catalyst regeneration vents are not

included in the definition of miscellaneous process vents

because emissions from FCC regeneration vents and control

technologies for FCC regeneration vents are significantly

different from miscellaneous process vents. While emissions

from FCC catalyst regeneration vents are not exclusively

metallic or particulate, the HAP's emitted are primarily metal

HAP's. The petroleum refineries NESHAP specifically regulates

organic HAP emissions. FCC catalyst regeneration vents will

be addressed in a future regulation. 

Comment: Two commenters (IV-D-36, IV-G-08) urged that

catalyst regeneration vents from Thermofor Catalytic Cracking

(TCC) units be added to the list of exemptions under the

definition of miscellaneous process vents. One commenter

(IV-D-36) claimed that the rationale for excluding FCC

catalyst regeneration vents, that the emitted HAP's are

significantly different and would be controlled differently

compared to other refinery emissions, is applicable to TCC

catalyst regeneration vents. The commenters (IV-D-36,
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IV-G-08) explained that while TCC's and FCC's differ in

design, they perform the same function. Another commenter

(IV-D-20) explained that most TCC's are found in smaller

refineries which are expected to bear the heaviest economic

burden from the proposed rule. One commenter (IV-G-08)

included a diagram and a process description of a TCC. 

Two commenters (IV-D-20, IV-D-36) pointed out that TCC's

were included in the preamble among examples of units which

should be exempted from this rulemaking. Two commenters

(IV-D-36, IV-G-08) stated that the EPA has previously

indicated that the exclusion of TCC's from the exemption list

in the definition was an oversight. 

One commenter (IV-D-36) provided that some information

concerning TCC catalyst regeneration vent emissions, control

technology and achievable control does not exist. The

commenter (IV-D-36) predicted that if TCC's catalyst

regeneration vents are included, data acquisition would be a

problem for the EPA and operator of these units. 

One commenter (IV-D-20) contended that if the EPA does

not exclude non-fluidized bed catalytic cracking units, then

they should recognize that, unlike all the other miscellaneous

process vents, these units involve combustion. The commenter

(IV-D-20) recommended requiring non-fluidized bed catalytic

cracking units to add on a combustion device only if the CO

levels in the exit stream of the regenerator exceed 500 ppm, a

good indicator of complete combustion, taken from the

subpart J NSPS for Refineries. 

Two commenters (IV-D-20, IV-D-25) suggested that the

exclusion for "fluidized catalytic cracking units catalyst

regeneration vents" be changed to "catalytic cracking unit

regeneration vents" because this is the more generic term for

such vents. 
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One commenter (IV-D-36) requested an extension of the

comment period for 120 days if catalyst regeneration vents for

TCC's are not included in the exemptions in the definition of

miscellaneous process vents. The commenter (IV-D-36) stated

that this time is required to acquire and submit data on the

emissions characteristics of TCC's, the available control

technology and the level of control achieved by existing

TCC's.

Response: The EPA agrees that TCC's are similar in

operation and emissions characteristics to FCC units and

therefore should be similarly regulated. All references to

catalytic cracking in the definition of miscellaneous process

vents have been amended from "fluidized catalytic cracking" to

"catalytic cracking" to allow the same exemptions for TCC

units as FCC units. Emissions from TCC unit catalyst

regeneration vents will be addressed with FCC unit catalyst

regeneration vents in a future regulation scheduled for

development in 1997.

Comment: One commenter (IV-D-36) suggested that

emissions from combustion devices be specifically excluded

since MACT for process vents is combustion.

Response: Combustion devices such as boilers and heaters

are not addressed by this regulation. Therefore, it is not

necessary to specifically exclude vents from combustion

devices from the definition of miscellaneous process vents. 

The vent definition already excludes vents routed to refinery

fuel gas systems.

Comment: One commenter (IV-D-29) requested that

refineries that do not have fuel gas systems due to lack of

vapors be exempt from process vent provisions.

Response: Routing miscellaneous process vents to

refinery fuel gas system is not the only means of control
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allowed by this regulation. Miscellaneous process vents

requiring control may be combusted in a refinery flare. Any

combustion device or other non-recovery control device that

reduces HAP's in a miscellaneous process vent stream by

98 percent reduction or to 20 ppmv is an acceptable control

technology. Pollution prevention or recovery devices can also

be used to reduce emissions below the cutoff level, and

thereby avoid need for add-on control.

Comment: Two commenters (IV-D-25, IV-D-38) suggested

clarifying the vents definition to exclude storage tank vents. 

One commenter (IV-D-21) stated that PV or conservation vents

found on fixed roof storage vessels should not be considered

process vents, as long as they are not required to have a

closed vent system and control device by subpart CC. The

commenter (IV-D-21) requested confirmation of this

interpretation.

Response: The following was added to the exemptions in

the definition of miscellaneous process vents: "Vents from

storage vessels". Storage vessel vents are regulated under a

separate section of the proposed regulation. This change was

made to provide clarity for the definition of miscellaneous

process vents.

Comment: One commenter (IV-D-20) requested clarification

of whether scrubbers are included or excluded from the

definition of "miscellaneous process vents."

Response: Miscellaneous process vents are defined as "a

gas stream containing greater than 20 parts per million by

volume organic hazardous air pollutant that are continuously

or periodically discharged during normal operation of a

petroleum refining unit..." with some exceptions. One of

these exceptions is "vents from control devices such as

scrubbers, boilers, incinerators, and electrostatic
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precipitators applied to catalytic cracking unit catalyst

regeneration vents, catalytic reformer regeneration vents, and

sulfur plant vents." A gas stream from a scrubber is a

miscellaneous process vent unless it contains less than

20 parts per million by volume organic hazardous air

pollutants or is a control device for one of the vents

described above. 

Comment: One commenter (IV-D-09) stated that the EPA

should exclude all vents from sulfur recovery plant operations

from the rule, including vents not from the "process", such as

sulfur storage pits, and from SRU tail gas units. The

commenter (IV-D-09) contended that the EPA should treat SRU's

as a whole in its next phase of refinery MACT rulemaking.

Response: The definition of miscellaneous process vents

excludes sulfur plant vents. All vents from sulfur plants

will be addressed in a future regulations scheduled for

development in 1997. This regulation will address all vents

from sulfur recovery units, both process and non-process, as

suggested by the commenter. The current definition does not

differentiate between process and non-process vents from

sulfur plants, but exempts "Sulfur Plant vents". The EPA

intends this exemption to be inclusive of all vents from

sulfur plants and contends that it is not necessary to revise

the current definition.

Comment: One commenter (IV-D-06) stated that process

vent provisions should specifically exempt wastewater systems,

tanks, Merox Treaters, Perco Treaters, and Hydrogen plant

vents because these vents are either covered in another

section of the regulation or are a negligible source of HAP's. 

The commenter (IV-D-06) asserted that emissions from tanks and

wastewater systems are already regulated by the sections of

the rule concerning storage tanks and wastewater. The
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commenter (IV-D-06) added that Merox treaters and Perco

treaters are catalytic processes used to remove mercaptans

from gaseous and light liquid streams. The commenter

(IV-D-06) stated that the only process stream vented to the

atmosphere is labeled excess air and is only vented during

startup and malfunction. The commenter (IV-D-06) compared the

vents operation to a pressure relief valve. The commenter

(IV-D-06) contended that the only emissions from hydrogen

plants are CO2 vents which do not contain any HAP. Therefore,

the commenter (IV-D-06) suggested that in order to reduce

administrative burden, the CO2 process vent from steam

reforming processes used to produce hydrogen be exempt from

requirements of the rule.

Response: Releases due to start up, shutdown and

malfunction are not required to meet the process vent emission

standards. This exemption is provided in § 63.6(f) of

subpart A (the NESHAP General Provisions). Vents with a HAP

concentration of 20 parts per million by volume or less are

not considered miscellaneous process vent as specified in the

definition of "miscellaneous process vents" in § 63.641 of

subpart CC. Such vents were excluded because they are

typically not controlled and because the combustion control

technologies that are the basis of the MACT standards cannot

consistently reduce emissions to less than 20 ppmv. The vents

described by the commenter are exempt from the miscellaneous

process vents provision by definition. However, sufficient

data has not been provided to categorically exempt all vents

from all Merox units, Perco units, and Hydrogen Plants.

5.2 EMISSION CONTROL TECHNOLOGY

Comment: One commenter (IV-D-35) suggested that advanced

distillation processes be examined as an alternate control

strategy for miscellaneous process vents. The commenter
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(IV-D-35) alleged that advanced distillation can reduce

furnace energy for distillation units by as much as 65 percent

with corresponding reductions in HAP's and VOC's. The

commenter (IV-D-35) claimed that advanced distillation could

result in a VOC reduction of 2 million Mg/yr nation-wide. The

commenter (IV-D-35) provided a paper further detailing

advanced distillation. The commenter (IV-D-35) suggested that

distillation units be separated from miscellaneous process

vents to utilize the full potential of this new technology.

Response: The commenter suggested that advanced

distillation would reduce furnace energy and therefore the HAP

and VOC emissions. According to the paper provided, the HAP

and VOC reduction would be a result of decreased fuel

consumption in the furnace and the reduction would be in the

furnace emissions. Advanced distillation would not reduce

emissions vented from the distillation unit itself and this

regulation does not apply to emissions from furnaces. 

Combustion devices (e.g., furnaces) are a possible control

device to reduce organic HAP emissions from vents, not a

miscellaneous process vent to be controlled. Furthermore, the

paper provided did not indicate that any refineries in the

United States were using advanced distillation. For these

reasons, advanced distillation was not considered as a control

strategy in determining the new or existing source MACT floor,

or in selecting MACT.

Comment: One commenter (IV-D-17) stated that catalytic

incineration should be identified in the rule as an available

strategy for controlling HAP. The commenter (IV-D-17)

contends that catalyst technology has been proven to be

advantageous because, unlike flares, the effectiveness of the

technology can be measured. Additionally, the commenter

(IV-D-17) claims the catalytic incineration technology has
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been proven in other applications to control VOC to greater

than 98 percent efficiency, whereas, destruction of VOC's in

process heaters or boilers may or may not reduce HAP by

98 percent or to 20 ppmv, depending on conditions. The

commenter (IV-D-17) gave no further details on catalytic

incineration technology.

One commenter (IV-D-41) suggested that the definition of

incinerator be modified to avoid discouraging the use of

catalytic incinerators. The commenter (IV-D-41) recommended

that the word "oxidation" be substituted for the word

"combustion" wherever it appears in the definition of an

incinerator.

Response: This regulation does not exclude the use of

catalytic incineration as a control device. The regulation

requires that the HAP's in a process vent stream be reduced by

98 percent or to 20 parts per million by volume. Catalytic

incineration is specifically mentioned as a possible control

option in § 63.644(ii).

5.3 IMPACTS ANALYSIS

5.3.1 Database

Comment: One commenter (IV-D-29) asserted that the

process vents provision should be withdrawn until the number

of vents that would be covered by this rule and their current

emission rates are determined. One commenter (IV-D-50) urged

the EPA to gain a clearer understanding of miscellaneous

process vents before proceeding with the rule because

miscellaneous process vent configurations differ significantly

from refinery to refinery and it is somewhat difficult to

standardize controls for the industry. 

Response: The EPA provided several opportunities for

industry to provide data through two questionnaires and with

the proposal of this regulation. The EPA contends that any
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information to be gained from industry regarding the number

and characteristics of miscellaneous process vents has been

obtained. The MACT floor and cost and emission impacts of

controlling miscellaneous process vents were reanalyzed after

proposal considering all available information, and the final

rule was revised considering the reanalysis. The process

vents provisions will not be withdrawn as promulgation of this

regulation is mandated by the statute schedule and subsequent

court order.

Comment: One commenter (IV-D-25) stated that the

database developed from the section 114 survey overstates the

percentage of process vents controlled because facilities

tended to report vents which were already identified because

they are controlled. Small vents for which the facility had

no data were less likely to be reported. Two commenters

(IV-D-10, IV-D-22) contended that the respondents to the MACT

floor survey did not fully understand the questionnaire and

may have only reported those vents that are controlled or that

a vent might have been so small that it was exempt under State

regulations and was not reported in the questionnaire at all. 

The commenters (IV-D-10, IV-D-22) asserted that many

facilities could not report flow rates or compositions because

of a lack of data. One commenter (IV-D-21) estimated that the

number of vents reported was deficient by 100 vents per

refinery, most of them uncontrolled. One commenter (IV-D-22)

stated that the effect of underreporting was that average

emission factors are grossly overstated. Because of this

bias, two commenters (IV-D-10, IV-D-22) requested the EPA to

recognize that miscellaneous process vents are not likely

controlled by the best performing 12 percent of the process

vents in the refinery source category. One commenter
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(IV-D-21) does not believe that any refinery controls

100 percent of their miscellaneous process vents.

Response: The EPA recognizes that the percentage of

controlled vents in the database used to estimate emissions

may not have been representative of all refineries. The

database has been revised to include additional data received

concerning the number and control status of miscellaneous

process vents. The addition of these data has decreased the

percentage of controlled vents from approximately 40 percent

to approximately 24 percent. Additionally, the EPA has

surveyed existing State regulations to provide information on

which miscellaneous process vents require control. The survey

indicated that the most stringent State regulations (in States

where refineries are located) do not require control of vents

with VOC or HAP emissions below a cutoff flowrate. The EPA

has developed an applicability criteria for the final rule

from the existing State regulations to define vents that

require control. The State regulations were used because the

database does not contain sufficient information on vent

characteristics to allow determination of the cutoff included

in the miscellaneous process vent component of the source-wide

MACT floor. Thus, the control requirement for miscellaneous

process vents is no longer based on the previous MACT floor

analysis.

5.3.2 Cost Impacts

Comment: One commenter (IV-D-22) contended that the EPA

significantly underestimated the cost-effectiveness and

emission reduction of controlling miscellaneous process vents

because it did not include necessary revisions to the

database. One commenter (IV-D-50) stated that the costeffectiveness of controlling miscellaneous process vents

contained in the proposed rule for existing sources of
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$1,700/Mg of HAP controlled is incorrect. The commenter

(IV-D-50) stated that once the emission estimates are revised,

it is likely that few controls will be needed or will be costeffective.

Response: No specific cost effectiveness estimates or

cost data were provided by these commenters. The cost and

emission reduction impacts analyses have been revised for

process vents to reflect the changes made to the process vents

database. The database has been revised to exclude emissions

from vents that do not fit the definition of miscellaneous

process vents and to include additional data on the number and

control status of process vents. Additionally, the method for

estimating emissions was revised such that data from process

units with relatively high VOC or HAP emissions are no longer

used to estimate emissions from process units for which

insufficient data was provided. Instead, more typical values

are used, as further described in other responses in this

section. Additional changes have been made to the emissions

estimate to allow the applicability criteria developed from

State regulations to be applied in estimating the emission

reduction. Using the revised database and estimating method,

VOC and HAP emission reductions and the cost effectiveness did

not change significantly compared to the estimates provided at

proposal.

Comment: One commenter (IV-D-50) cautioned the EPA that

the cost of process vent emission controls are higher for a

small refinery than a large refinery on a per barrel basis and

that the expense of controlling some single emission points in

this area was as much as one-half million dollars. For these

reasons, the commenter (IV-D-50), who referred to cost

information previously supplied to the EPA on vent emissions

controls for the FCCU regenerator, the sulfur recovery unit
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vent, the CCR vent, and one miscellaneous process unit, urged

the EPA to explore and discuss the most cost-effective control

measures before establishing requirements.

Response: The Clean Air Act does not allow cost

effectiveness to be taken into consideration in the

determination of the MACT floor. Cost effectiveness can be

considered in establishing standards more stringent than the

MACT floor. However, for the miscellaneous process vents

component of the source-wide MACT, the floor level of control

has been selected as MACT and the cost effectiveness of these

controls is not an issue.

5.3.3 Emissions Impact

Comment: One commenter (IV-D-44) claimed that wastewater

emissions and maintenance activities were improperly included

in the miscellaneous process vents determination. The

commenter (IV-D-44) alleged that the inclusion resulted in

higher than actual benefits estimates and over regulation of

the refining industry.

Response: The database used to estimate emissions has

been revised to exclude emissions from vents that do not meet

the definition of miscellaneous process vents. This includes

emissions from catalytic cracking catalyst regeneration,

catalytic reforming catalyst regeneration, coke drum deheading

and decoking, maintenance activities and wastewater. Several

changes have been made to the database and the method used to

estimate emissions. The HAP emissions estimate increased

slightly and cost effectiveness did not change significantly

as a result of the reanalysis. The revised estimate of

emission reduction from miscellaneous process vents is

6,412 Mg/yr (7,068 ton/yr) HAP.

The EPA would like to point out that the effect of

emissions from process vents on the benefits analysis is
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small. The benefits analysis was most affected by data

regarding emissions from equipment leaks. The equipment leaks

data provided the speciation of HAP compounds used in the

benefits analysis. The only information included regarding

process vents was the total estimated HAP emissions. The

speciation of HAP compounds from equipment leaks was applied

to the total HAP emissions from process vents to determine the

emissions of individual compounds. The small percentage of

process vent emissions that may have been associated with

wastewater and maintenance activities is an even smaller

percentage of all emissions from refineries with little effect

on the overall benefits analysis.

Comment: Four commenters (IV-D-10, IV-D-22, IV-D-25,

IV-D-50) disagreed with the emissions extrapolation

methodology using reformer emissions, and stated that the HAP

to other hydrocarbon ratio is different for reformer vents

than for other vents. Three of the commenters (IV-D-10,

IV-D-22, IV-D-50) urged the EPA to correct nationwide HAP

emission estimates. Two commenters (IV-D-10, IV-D-22)

asserted that HAP and VOC survey data from a catalytic

reformer should not be used in the calculation to estimate HAP

and VOC emissions from alkylation and vacuum distillation

units because these vents are significantly different. One

commenter (IV-D-46) provided that methods for emissions

estimation from vacuum distillation units include material

balance, monitoring and parameter factoring, and the permitted

industry chooses from these for emissions reporting. The

commenter (IV-D-46) recommended that the EPA use these methods

consistently, in close consultation with industry and that

they apply extrapolation and assumptions correctly in the 

future to avoid disagreement over emissions estimates. One

commenter (IV-D-22) objected to the EPA utilizing refinery
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wide averages to estimate emissions when none was available

instead of estimating emissions factors on the types of

compounds present within the various units.

Response: The EPA agrees that using an average HAP to

VOC ratio, which included reformer emissions, did not provide

an accurate estimate of emissions from process units for which

HAP or VOC data was not provided. The revised method for

estimating emissions significantly decreases the amount of

data extrapolated from one unit to another. In the few cases

where sufficient data is not available for a process unit, it

is either derived from a similar process unit or from the

median value for all process units. Using the median value as

opposed to the average value decreases the impact that one

unit, with relatively high or low emissions, can have on the

extrapolated data. Further details on the revised methodology

and results of the analysis are contained in a memorandum in

docket No. A-93-48.

5.4 SELECTION OF MACT AND MACT FLOOR FOR PROCESS VENTS

5.4.1 Selection of MACT Floor for Process Vents

Comment: Two commenters (IV-D-21, IV-D-38) asserted that

the data used in performing the MACT floor analysis was

incomplete due to lack of information on process vents. One

commenter (IV-D-21) recommended that the MACT floor be

reevaluated, using technical judgment and considering cost

effectiveness.

Response: The EPA agrees that the data provided by

industry for miscellaneous process vents, on which the process

vent component of the source-wide MACT floor analysis was

performed, was limited and may have incorrectly represented

the percentage of miscellaneous process vents controlled at

the best performing 12 percent of refineries. For this

reason, the EPA elected to survey existing State regulations
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that are applicable to miscellaneous process vents at

petroleum refineries to gain additional information. The EPA

found that there are enough refineries subject to State

regulations for miscellaneous process vents that a conclusion

can be drawn regarding the requirements that the best

performing 12 percent of refineries must meet. The provisions

for the miscellaneous process vent component of the sourcewide MACT floor have been revised to reflect the current level

of control, required by State regulation, of the best

performing 12 percent of refineries. The EPA evaluated the

current level of control for miscellaneous process vents in

eight States and two air districts that contain the majority

of refineries and were expected to have the most stringent

regulations. Of the refineries in the U.S., the 12 percent

that are subject to the most stringent regulations are located

in three States. In these three States, miscellaneous process

vents emitting greater than 6.8 to 45 kg/day (15 to

100 lb/day) of VOC are required to be controlled. The median

applicability cutoff level for the 12-percent of U.S.

refineries subject to the most stringent regulations is

33 kg/day VOC (72 lb/day VOC). Thus, control of vents with

VOC emissions greater than 33 kg/day VOC (72 lb/day) is the

miscellaneous process vent component of the source-wide MACT

floor for existing sources. The miscellaneous process vents

component of the source-wide MACT floor for new sources is

98 percent control of HAP's, or to 20 ppmv, for vents with VOC

emissions greater than 6.8 kg/day (15 lb/day), based on the

most stringent State regulation. The revised analysis is

documented in docket No. A-93-48. 

Comment: Three commenters (IV-D-09, IV-D-10, IV-D-51)

recommended developing a TRE for refinery process vent

emissions as a mechanism for not applying MACT to individual
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miscellaneous process vents that would otherwise be required

to install controls to meet the MACT floor criteria. One

commenter (IV-D-10) stated that a TRE option would recognize

the floor as a type of control device reported at the top

12 percent level and would also recognize the diversity in the

characteristics of miscellaneous process vent streams. 

Several commenters (IV-D-19, IV-D-25, IV-D-29, IV-D-38)

suggested that a methodology similar to the TRE in the SOCMI

HON should be used to segregate vents requiring control. One

commenter (IV-D-19) stated that this would insure those with

greatest potential HAP emissions are controlled. The

commenter (IV-D-19) cited section 112(d) of the Act as

allowing the EPA to consider characteristics of sources in

establishing MACT standards, and requiring that cost and

energy be taken into consideration. The commenter (IV-D-19)

asserted that the EPA has the authority to limit control of

process vents to those for which an economic justification is

made for control.

Three commenters (IV-D-10, IV-D-25, IV-D-51) suggested

using the TRE equations from the HON with a cost-effectiveness

criteria of $5,000/Mg HAP reduction. Two commenters (IV-D-10,

IV-D-25) reasoned that the HON equations were appropriate

because the process vent controls, flaring and incineration,

are the same. One of the commenters (IV-D-25) compared vent

characteristics and control costs for 3 refinery process vents

and found them to be within the parameters of the 680 vents

EPA used to develop the HON TRE. Two commenters (IV-D-10,

IV-D-25) stated that a common approach makes sense because

refinery and chemical units are often located at the same

site, and vents are routed to a common control system and some

States make no distinction in control requirements. Another

commenter (IV-D-38) asserted that there are similarities
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between petroleum refinery vents and SOCMI vents, especially

regarding control technology. One commenter (IV-D-19) does

not agree that the same equations should be used, as

refineries and chemical plants are entirely different. 

Two commenters (IV-D-10, IV-D-25) asserted that, based on

an analysis of vents in the section 114 database, a $5,000/Mg

TRE cutoff would result in an increase in the number of

controlled vents from 48 percent to 66 percent, and an

increase in total process vent HAP emissions control from the

current 17 percent to 94 percent. One commenter (IV-D-19)

recommended that the methodology developed be published in the

Federal Register for comment.

One commenter (IV-D-25) used the EPA's process vent

database to perform a MACT floor analysis they claimed was

similar to the approach EPA used for the HON. The commenter

(IV-D-25) used detailed data available for 17 vents to

characterize 190 vents in the database, and then used the HON

flare TRE equation to calculate cost effectiveness for the

190 vents. The commenter (IV-D-25) then defined the control

status of each vent by assuming that vents located outside

ozone classification areas were not controlled (regardless of

control status information in the database). The actual

reported control status was used for vents in ozone

classification areas 1-6. The commenter (IV-D-25) claimed

this was similar to the EPA's modeling approach for the HON. 

The commenter then ranked the vents by ascending HAP emissions

and plotted HAP emissions and flare TRE cost effectiveness

against the cumulative percent of vents assumed to be

controlled. The commenter (IV-D-25) claimed that, using this

ranking, 12 percent of the vents are controlled (cumulative)

at an incremental cost effectiveness level of $5,000/Mg. The

commenter (IV-D-25) found higher cost effectiveness values if
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the median or average cost effectiveness at the 12 percent

point was used or if the top 6 percent point was used. The

commenter (IV-D-25) stated that a MACT floor in the range of

$3,000 to $5,000/Mg would result in control of 94 percent of

HAP emissions. 

Response: As stated in the preamble to the proposed

regulation, sufficient data was not provided to develop a TRE

equation for miscellaneous process vents. This finding is

confirmed by the fact that sufficient data to characterize the

vents were available for only 17 out of 190 vents. In

particular, information would be needed on vent stream

characteristics, such as flow rate, heating value, and VOC and

HAP content. Given that such information is not available,

the EPA contends that the HON flare TRE equation may not be

appropriate for miscellaneous process vents and that a cost

effectiveness estimate derived using the HON flare TRE

equation may not be accurate for miscellaneous process vents. 

Rather than including a TRE in the rule, the miscellaneous

process vent component of the source-wide MACT floor has been

reassessed to include an emission rate cutoff. The cost

estimate and cost effectiveness of the regulation have been

recalculated to include the emissions cutoff. Directionally,

the cutoff decreases the number of vents that will be required

to be controlled and therefore decreases the cost of this

regulation. However, the database used for estimating

emissions has been revised based on comments and data received

regarding the number of vents that are uncontrolled and were

previously not reported. Consequently, the number of

uncontrolled vents nationwide has increased significantly. 

The combination of increasing the number of uncontrolled vents

nationwide and adding the applicability criteria cutoff

results in a decrease in the number of vents that will be
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required to be controlled. Additional revisions made to the

database resulted in slightly lower emissions estimates for

VOC and slightly higher estimates of HAP emissions. The cost

effectiveness of this regulation for VOC increased by

approximately 63 percent compared to the cost effectiveness

presented at proposal. The cost per megagram of HAP reduction

decreased by approximately 7 percent.

Comment: One commenter (IV-D-42) requested the

development of a separate MACT floor for miscellaneous process

vents for small refineries.

Response: The EPA examined the question of whether

subcategorization would result in a different floor for small

refineries. The EPA has elected to base the miscellaneous

process vent component of the source-wide MACT floor on

existing State regulations for miscellaneous process vents. 

Of the regulations included in the analysis, none provided

requirements that varied according to the size of the

refinery. Using State regulations, it is not possible to

justify less stringent requirements for small refineries. 

Furthermore, the database indicates that combustion controls

are in use at a substantial number of vents at small

refineries, which also indicates that the floor would not be

significantly different. However, using the State regulations

has resulted in an applicability criteria for process vents

based on the mass flowrate of emissions. Vents emitting less

than 33 kg/day of VOC (72 lb/day of VOC) from existing sources

and vents emitting less than 6.8 kg/day (15 lb/day) from new

sources will not be required to be controlled. These criteria

may allow more vents in small refineries to remain

uncontrolled as emissions are generally related to material

throughput.
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Comment: One commenter (IV-D-59) maintained that a floor

control level based on TRE is illegal under the Act because it

is a cost effectiveness criteria and not an emissions level. 

The commenter (IV-D-59) stated that it does not make sense to

use TRE in either case.

Response: The EPA has elected to base the determination

of the miscellaneous process vent component of the source-wide

MACT floor on State regulations and has not adopted a TRE

approach. However, the EPA would like to point out that a TRE

approach, had it been used, would have been legal as long as

it was used correctly. Process vents could be ranked using

cost effectiveness of control (or TRE) as a criteria. TRE

reflects several factors that effect emission rates and

likelihood of current control (flow rate, HAP concentration,

net heating value, and corrosion properties). Using one

parameter, such as TRE, simplifies the comparison. Once

ranked by TRE, the average of the best performing 12 percent

would be determined. The TRE is simply used to characterize

which vents are controlled by the top 12 percent of sources. 

No judgement on whether the cost is reasonable would enter

into the floor decision. The reader is referred to the

preamble and supporting documentation for the Hazardous

Organic NESHAP (promulgated April 22, 1994, 59 FR 19402).

5.4.2 Selection of MACT for Process Vents

Comment: One commenter (IV-D-09) suggested that the EPA

adopt a control requirement of 95 percent rather than

98 percent to encourage adoption of recovery methods and

promote pollution prevention.

Response: The requirement to control HAP emissions to

98 percent was based on the miscellaneous process vent

component of the source-wide MACT Floor and MACT analysis. 

Control of HAP's to 98 percent is consistent with available
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technology. Requiring control to 95 percent would be below

the level established as part of the MACT floor. 

Comment: One commenter (IV-D-54) supported the

provisions to require controls on all miscellaneous process

vents. The commenter (IV-D-54) also supported the 20 ppm

cutoff and the 98 percent control efficiency requirements.

Response: The EPA thanks the commenter for their

support, but notes that for reasons previously described, an

emission cutoff has also been added to the process vent

provisions.

5.4.2.1 Selection of Vents Requiring Control.

Comment: One commenter (IV-D-38) supported adding a

regulatory "stopping point" to exempt vents that emit less

than a certain de minimis level of HAP from control. The

commenter suggested a de minimis level of 15 pounds of HAP per

day. Another commenter (IV-D-21) proposed a de minimis rate

of 100 lb HAP/day. One commenter (IV-D-09) stated that a

de minimis rate has the advantage of simplicity and is

consistent with Group 1/Group 2 distinctions drawn by the EPA

for the HON and with approaches taken by various States. The

commenter (IV-D-09) stated that if a de minimis rate approach

is taken, it should be consistent with the cutoff between

Group 1 and Group 2 vents in the HON.

Response: As stated in the preamble to the proposed

regulation, the data provided with which to develop the

miscellaneous process vent component of the source-wide MACT

floor was limited. The EPA requested additional data at

proposal; few responses containing data that could be

incorporated into the MACT floor analysis were received. The

EPA elected to survey existing State regulations as an

alternative method of determining the current level of control

of process vents. The most stringent regulations in States
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with refineries did not require control of miscellaneous

process vents emitting less than a specified rate of VOC*s or

HAP*s. In order to determine which vents must be controlled,

as required by State regulations, at the best performing

12 percent of refineries, the refineries with miscellaneous

process vents subject to regulation were ranked by the

stringency of the applicable regulation. The regulations were

compared according to the maximum rate of VOC or HAP emissions

that was allowed without control. The best controlled

refinery and the median of the best performing 12 percent of

refineries were then determined to determine the process vent

component of the MACT floor for new and existing sources. The

MACT floors were determined to include emission cutoffs, which

were incorporated into the regulation. As suggested by the

commenter, miscellaneous process vents will now be considered

either Group 1 or Group 2 vents. For existing sources,

miscellaneous process vents emitting 33 kg/day (72 lb/day) or

more of VOC are Group 1 vents and will be required to be

controlled. For new sources, miscellaneous process vents

emitting 6.8 kg/day (15 lb/day) or more of VOC are Group 1 and

will be required to be controlled. All other miscellaneous

process vents will be considered Group 2 miscellaneous process

vents and will not be required to be controlled.

Comment: Three commenters (IV-D-30, IV-D-36, IV-D-44)

requested a minimum flow or pressure, below which process

vents need not be controlled, be included in the definition of

miscellaneous process vents. Two commenters (IV-D-30,

IV-D-36) asserted that the standard is not cost effective

without a flow component. One commenter, (IV-D-30), claimed

that by limiting the definition to continuous streams with an

organic HAP concentration greater than 0.005 weight percent

(50 ppmv), the controls would be required where they would be
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most effective. One commenter (IV-D-10) supported a

volumetric flow cutoff of 0.1 m3/min. The commenter (IV-D-10)

asserted that at these cut-offs, the amount of HAP emission is

approximately 20 pounds/day. Another commenter (IV-D-22)

suggested a cut-off of 0.005 m3/min. Two commenters (IV-D-36,

IV-D-44) expressed support for commenter IV-D-22's suggestion

which would be consistent with the HON definition. One

commenter (IV-D-44) claimed that the definition will allow for

control of vents which may result in organic HAP emissions,

but will eliminate regulation of vents of de minimis volumes

and concentrations. Alternatively, two commenters (IV-D-10,

IV-D-22) stated that the EPA could use a volumetric cut-off

coupled with a de minimis concentration of 50 ppmv. 

Response: As stated in a previous response, the EPA has

revised the miscellaneous process vents requirement to

incorporate information from State regulations regarding which

vents in refineries are currently required to be controlled. 

An applicability criteria has been added to the process vent

provisions that will allow vents emitting less than 33 kg/day

(72 lb/day) of VOC for existing sources [or less than

6.8 kg/day (15 lb/day) of VOC for new sources] not to be

controlled. The State regulations involved in the analysis

all include either VOC or HAP mass flowrate cutoffs. The mass

flowrate cutoff has been retained so as to most accurately

represent the existing requirements. To convert to a

volumetric or concentration cutoff would require making

assumptions about the vent stream characteristics that may not

be accurate for all vents. The EPA contends that the mass

flowrate cutoff developed satisfies the commenters* requests

for a cutoff that allows vents with relatively low HAP

concentrations to be excluded from the control requirement

while most accurately reflecting the control requirements at
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the best performing 12 percent of facilities. The 20 ppmv

cutoff has also been retained in the process vent definition. 

The 20 ppmv was included in the proposal because the available

control technologies cannot consistently reduce emissions

below 20 ppmv, therefore, it would be technically unreasonable

to require control of such vents.

Comment: One commenter (IV-D-44) stated that the 20 ppmv

benzene concentration is burdensome and not cost effective. 

Response: The EPA assumes that the commenter was

referring to the exclusion of process vents with a HAP

concentration of less than 20 parts per million in the

definition of miscellaneous process vents. This exclusion was

based on the finding that combustion control, which represents

MACT for the miscellaneous process vent component of the

source-wide floor, is capable of reducing HAP concentration by

98 percent or to 20 ppmv. Reducing the HAP concentration of

vent streams with concentrations less than 20 ppmv by

incineration may not be possible. Therefore, these vents are

not included in the definition of miscellaneous process vents. 

The miscellaneous process vents provisions have been revised

so that vents emitting less than 33 kg/day (72 lb/day) of VOC

for existing sources [6.8 kg/day (15 lb/day) for new sources]

will not be required to be controlled. This revision is based

on information obtained from State regulations for

miscellaneous process vents. However, the State regulations

surveyed required that those vents requiring control be

incinerated or controlled to an equivalent level. Therefore,

the there is no basis for increasing the 20 part per million

exclusion from the definition of miscellaneous process vents.

Comment: One commenter (IV-D-30) supported a control

cut-off based on cost effectiveness.
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Response: The Clean Air Act requires that standards are

not less stringent than the average emission limitation

achieved by the best performing 12 percent of existing

sources. The MACT floor is determined from this requirement. 

The Clean Air Act does not allow for the consideration of cost

effectiveness in the determination of the MACT floor. Cost

effectiveness can be taken into consideration in establishing

standards more stringent than the floor. The provisions of

this component of the source-wide MACT are not more stringent

than the source-wide MACT floor, therefore, cost effectiveness

was not considered in their development.

Comment: Two commenters (IV-D-09, IV-D-10) contended

that if a TRE is not used then an alternative cut-off level

should be used. One commenter (IV-D-10) stated the EPA should

consider the regulations provided in Louisiana and Texas,

because these States have more than 12 percent of all refinery

miscellaneous process vent sources. Therefore the commenter

(IV-D-10) contended that the cut-offs provided in these States

should be used in the refinery rule (100 pounds of VOC/day or

15 pounds HAP/day). Another commenter (IV-D-25) suggested

using State rules to determine which process vents require

control. The commenter (IV-D-25) cited Texas and Louisiana

rules which exempt vents emitting less than 100 lb VOC/day

(16.6 Mg/yr) and San Francisco Bay Area rules which exempt

vents emitting less than 15 lb VOC/day (2.5 Mg/yr). Based on

these rules, the commenter (IV-D-25) suggested an exemption of

at least 15 lb HAP/day.

Response: The EPA agrees that State regulations provide

a good basis for determining a cutoff for miscellaneous

process vents requiring control. The EPA has surveyed

existing State regulations, including those applicable to

refineries in Louisiana, Texas and the San Francisco Bay Area,
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and used this information to develop the applicability

criteria to be included in the miscellaneous process vents

provisions. For existing sources, miscellaneous process vents

emitting less than 33 kg/day (72 lb/day) of VOC will not be

required to be controlled. This cutoff corresponds to the

cutoff that the median of the best performing 12 percent of

facilities must comply with according to State regulations. 

For new sources, miscellaneous process vents emitting less

than 6.8 kg/day (15 lb/day) of VOC will not be required to be

controlled. This cutoff corresponds to the level the best

performing facility must comply with according to State

regulations.

Comment: One commenter (IV-D-46) stated that the

applicability levels for HON appear suitable for miscellaneous

process vents because they represent emissions of no more than

the fugitive emissions from a valve subject to LDAR. The

commenter (IV-D-46) contended that a stricter limit would have

little benefit. 

Response: As stated in previous responses, applicability

criteria has been developed for miscellaneous process vents

from existing State regulations. The regulations included in

the analysis were all determined to be applicable to

miscellaneous process vents at petroleum refineries. The EPA

contends that using these State regulations as a basis is the

most accurate method currently available for determining which

vents are currently being controlled.

Comment: One commenter (IV-D-29) stated that the flow

rate and concentration cutoffs are too low. The commenter

(IV-D-29) stated that most of these streams are already

recovered for their energy value or pollution control.

Response: The EPA assumes that the commenter is

referring to the exclusion of vents with HAP concentrations of
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less than 20 ppmv from the definition of miscellaneous process

vents. The EPA disagrees with the comment that the majority

of miscellaneous process vent streams are currently being

recovered. Based on data received from industry, it is

estimated that approximately 24 percent of miscellaneous

process vents are currently being controlled. It is estimated

that the percent of controlled vents will be increased to

approximately 40 percent by this regulation. 

Comment: In response to the EPA's question of whether

the HAP content of the process vents is below the 20 ppmv

applicability level, one commenter (IV-D-45) stated that their

COTU's do not have process vents going to the atmosphere and

all gas produced in the refining operations is either recycled

for recompression and reuse or is routed to a continuous

flare. All pressure safety valves relieve to a continuous

flare system. One commenter (IV-D-23) maintained that all of

the process vents from their 3,000 barrel per day refinery

contained greater than 20 ppmv of HAP.

Response: The EPA appreciates the information provided

by the commenters. The EPA would like to point out that not

all COTU's are covered by the proposed rule. The EPA suggests

referencing SIC 2911 to determine applicability of this

regulation to specific COTU's.

Comment: One commenter (IV-D-35) challenged that the

proposed rule does not sufficiently promote pollution

prevention over pollution control. The commenter (IV-D-35)

suggested that a lower concentration limit be used for control

devices than prevention strategies. The commenter recommended

that the limit for the prevention-based concentration be no

less than 20 ppmv. One commenter (IV-D-40) stated that the

miscellaneous process vents controls should only be applicable
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above 50 ppm as in the HON rule definition for a Group 1

process vent, so as to encourage pollution prevention.

Response: The EPA has determined for existing sources

that miscellaneous process vents emitting less than 33 kg/day

(72 lb/day) of VOC are not required to be controlled. For new

sources, the level is 6.8 kg/day (15 lb/day). This is the

MACT floor level of control for the miscellaneous process vent

component which is the minimum level of control allowed by the

CAA. The EPA contends that with this cutoff pollution

prevention is encouraged. If the concentration or emission

rate of HAP's in a miscellaneous process vent stream is

reduced to below the applicability cutoff, the vent stream is

not required to be controlled.

Comment: One commenter (IV-D-40) requested that the rule

state that where storage vessel or wastewater vents are routed

through a recovery device that includes miscellaneous process

vents, no controls are required if the exit stream is reduced

to 50 ppm organic HAP's or less or if the exit stream meets

the TRE requirements of the HON, § 63.115. The commenter

(IV-D-40) stated that this would help encourage pollution

prevention.

Response: If a recovery device is used to control

emissions from storage or wastewater streams, it must meet the

95 percent control requirements included in those regulations. 

If emissions from process vents at the outlet of the recovery

device are above the emission cutoff (33 kg/day or 72 lb/day

of VOC for existing sources and 6.8 kg/day or 15 lb/day of VOC

for new sources), additional control is required by the

process vent provisions. The EPA contends that providing this

cutoff encourages pollution prevention. If a miscellaneous

process vent stream is reduced to below the applicability

criteria, it is not required to be controlled.
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As previously stated, sufficient data was not provided in

response to requests for information regarding miscellaneous

process vents to develop TRE equations. According to

industry, additional data is not available. Therefore, the

rule does not include TRE equations for miscellaneous process

vents. 

5.4.2.2 Selection of MACT Technology.

Comment: One commenter (IV-D-57) encouraged using

product recovery before destruction as a means of better air

management because it would reduce the quantity of secondary

pollutants generated from combustion.

Response: The EPA contends that recovery is encouraged

by these standards by providing a HAP emission rate cutoff

below which miscellaneous process vent are not required to be

controlled. A recovery device can be used to reduce emissions

to below this cutoff. 

Comment: One commenter (IV-D-36) supported combustion as

the selected level of control. One commenter (IV-D-57) stated

that there is a difference between control efficiency and

environmental benefit between various control devices that can

be used to meet the 98 percent control requirement in the

process vent provisions. The commenter (IV-D-57) recommended

for new sources that the rule should require the use of an

incinerator rather than allowing the use of a flare because

the firebox provides higher temperatures and longer residence

times and therefore more complete combustion than a flare. 

Another commenter (IV-D-46) provided that Texas routinely

requires new sources to route to flares but expressed concern

about retrofitting existing sources. The commenter (IV-D-46)

did not have cost data to provide.

Response: The Clean Air Act requires that standards for

new sources are not less stringent than the emission control
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level achieved by the best controlled similar source. For

existing sources, standards may not be less stringent than the

emission limitation achieved by the average of the best

performing 12 percent of existing sources. Numerical emission

standards must be established unless it is not feasible to

prescribe or enforce an emission standard. Only in such a

case is a design, equipment, or work practice standard allowed

(section 112(h) of the Act). Industry responses to ICR and

section 114 questionnaires indicated that the best controlled

source, and the best controlled 12 percent of sources achieve

emission limitation through combustion control. In developing

previous NSPS and the HON, it has been determined that

combustion achieves at least a 98 percent reduction in organic

HAP or a 20 ppmv outlet concentration. Thus, as required by

the Act, the EPA has established a numerical emission standard

of 98 percent HAP reduction or 20 ppmv outlet concentration. 

A flare, incinerator, boiler, or any other non-recovery

control device that can achieve the required level of control

can be used to comply with the emission standard.

Comment: One commenter (IV-D-29) claimed that controls

should not be proposed based on reformer emissions since many

small refiners do not have reformers.

Response: The EPA agrees that the VOC to HAP ratio from

reformer emissions is not applicable to other units. The

miscellaneous process vents provisions have been revised to

include information obtained by surveying State regulations

for miscellaneous process vents. The result is the inclusion

of applicability criteria which will allow vents emitting less

than the cutoff not to be controlled. Additionally, the

method for estimating emissions, which was influenced by

reformer emissions, has been revised. The revised method for

estimating emissions significantly decreases the amount of
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data extrapolated from one unit to another. In the few cases

where sufficient data is not available for a process unit, it

is either derived from a similar process unit or from the

median value for all process units. Using the median value as

opposed to the average value decreases the impact that one

unit, with relatively high or low emissions, can have on the

extrapolated data.

The EPA examined the question of whether

subcategorization would result in a different floor for small

refineries. The EPA has elected to base the miscellaneous

process vent component of the source-wide MACT floor on

existing State regulations for miscellaneous process vents. 

Of the regulations included in the analysis, none provided

requirements that varied according to the size of the

refinery. Using State regulations, it is not possible to

justify less stringent requirements for small refineries. 

Furthermore, the database indicates that combustion controls

are in use at a substantial number of vents at small

refineries, which also indicates that the floor would not be

significantly different. However, use of the State

regulations has resulted in applicability criteria for process

vents based on the mass flowrate of emissions. Vents emitting

less than 33 kg/day of VOC (72 lb/day of VOC) for existing

sources or 6.8 kg/day (15 lb/day) for new sources will not be

required to be controlled. These criteria may allow more

vents in small refineries to remain uncontrolled as emissions

are generally related to material throughput.

5.5 COMPLIANCE DEMONSTRATION FOR PROCESS VENTS

5.5.1 Testing

Comment: One commenter (IV-D-21) requested that

Method 18 analysis not be required where engineering judgment

can be used to determine if a process vent's emissions exceed
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20 ppm organic HAP's, unless the permitting authority

disagrees with the engineering judgment.

Response: The testing requirements of § 63.645 of the

regulation are applicable only to miscellaneous process vents

as defined in § 63.641. Vents with organic HAP concentrations

less than 20 ppm are exempt from this definition and

therefore, not subject to the requirements of § 63.645. This

regulation does not include monitoring, testing, recordkeeping

of reporting requirements for vents that are not, by

definition, miscellaneous process vents. The owner/operator

will need to determine which vents at a facility must comply

with this regulation. The method used for this determination

may be chosen based on the owner/operators discretion. 

Owner/operators are encouraged to retain records of the

methods used in this determination in order to be able to show

compliance with this regulation.

In addition, the EPA has allowed the use of Method 25A to

measure TOC concentration. If the Method 25A results show

that vent emissions are less than 33 kg VOC/day (72 lb/day)

for existing sources and 6.8 kg/day (15 lb/day) for new

sources, then the vent is a Group 2 vent and is exempt from

control. If the TOC emissions are greater than the VOC cutoff, the owner or operator can use Method 18 to speciate the

non-VOC compounds in order to determine if the VOC emissions

are below the VOC cut-off.

Comment: One commenter (IV-D-59) recommended performance

tests for all types of control devices used on vents,

including boilers and process heaters larger than 44 MW, in

order to make sure that the device remains in good repair and

is being operated properly. Conversely, one commenter

(IV-D-09) supported lowering the threshold for exemption from

boiler/heater firebox temperature monitoring and performance
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tests from 44 MW to 2.9 MW. The commenter (IV-D-09) contended

that there was no reason to believe that the combustion

characteristics of smaller heaters/boilers are much different

than larger ones. The commenter (IV-D-09) stated that

lowering the threshold to 2.9 MW makes the provisions of this

rule consistent with precedent set by the EPA in the NSPS for

small industrial-commercial steam generating units.

Response: The EPA has re-examined the process vent

requirements for boilers and process heaters, and revised the

initial performance test requirements and monitoring

requirements to reduce the recordkeeping and reporting burden,

while maintaining appropriate control levels. The MACT floor

analysis for process vents shows that 98 percent reduction of

HAP's is the MACT floor level of control for the miscellaneous

process vent component of the source-wide floor. This control

level can be achieved using several types of combustion

devices, such as flares and incinerators. The EPA's

information shows that boilers or process heaters larger than

44 MW (150 million Btu/hr) typically operate at temperatures

and residence times necessary to achieve 98 percent reduction

or greater, while boilers or process heaters smaller than

44 MW are frequently not operated to achieve the 98 percent

requirement. Analysis also shows that when vent streams are

introduced into the flame zone, over a 98 percent reduction is

achieved. The EPA references "Reactor Processes in the

Synthetic Organic Chemical Manufacturing Industry--Background

Information for Promulgated Standards," EPA-450/3-90-016b,

March 1993 to support this conclusion. Therefore, the final

rule does not require an initial performance test or

monitoring of boilers or process heaters with a minimum heat

input of 44 MW, or of boilers or process heaters smaller than

44 MW if the vent stream is introduced into the flame zone. 
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The flame zone is defined in the final rule as the portion of

a combustion chamber of a boiler or process heater occupied by

the flame envelope created by the primary fuel. If the vent

stream is not introduced into the flame zone for boilers or

process heaters less than 44 MW an initial performance test

and continuous monitoring of temperature are required in order

to ensure that the boiler or process heater is operating

properly and at temperatures and residence times that would

control HAP emissions by 98 percent. The EPA considers these

requirements to effectively ensure the MACT floor level of

control for all boilers is being met, while also reducing the

burden on the industry.

Comment: One commenter (IV-D-13) generally supported the

EPA's proposed test methods for process vents, and

additionally added that the rule should: (1) include EPA

Methods 3, 3A, and 4 for measuring vent stream flow rate to

account for the moisture in the flow; (2) change the total

organic compounds limits to reference the calibration gas

(e.g., ppmv ethane or propane) used if Method 25A is allowed

as an alternative to Method 18 for demonstrating compliance of

control devices; and (3) provide the State or local agencies

the flexibility to use alternative approved methods (e.g.,

Method 25) instead of prescribed methods without requiring a

section 112(l) equivalency submittal.

Another commenter (IV-D-22) opposed EPA not allowing

Method 25A for demonstrating compliance. The commenter

(IV-D-22) stated that the EPA's rationale for not allowing it

fails to recognize that all of the other pre-approved

continuous compliance methods are concerned only with overall

efficiency, and not with HAP specific controls.

Response: Methods 2, 2A, 2C or 2D were chosen as the

preferred test method for determining vent flow rates in part
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because the regulation specifies that flows and concentrations

be calculated on a dry basis. Other alternatives for

demonstrating compliance with the process vents provision

which do not include the use of Method 2 are available.

Engineering assessment may be used to determine the TOC

emission rate. Engineering assessment includes estimation of

maximum flow based on physical equipment design such as pump

or blower capacities. Additionally, alternate methods for

measuring may be used if validated according to Method 301 of

40 CFR part 63, Appendix A.

The EPA has also decided to allow the use of Method 25A

to determine TOC concentration of the vent stream. The EPA

recognizes that Method 18 is useful if speciation of emissions

is required, but that it is also a costly procedure. Because

the refinery emission cut-off is on a VOC basis (33 kg VOC/day

for existing sources and 6.8 kg/day for new sources), it is

not necessary to determine speciated VOC emissions or to

separate total HAP emissions. However, Method 25A only

measures TOC concentration, including non-VOC compounds such

as ethane. The EPA cannot increase the cut-off to a TOC cutoff in terms of parts per million ethane to incorporate nonVOC compounds because this adjustment would be less stringent

than the floor. In addition, the EPA does not have data to

make this adjustment in emission cut-off. Therefore, if

Method 25A shows that emissions from a process vent are

determined to be below the VOC cut-off (33 kg VOC/day for

existing sources and 6.8 kg/day for new sources) the vent is a

Group 2 vent and is exempt from control. However, if

Method 25A shows that the vent VOC emissions are greater than

33 kg/day or 6.8 kg/day (as applicable), the owner or operator

will be required to control the vent unless they can prove the

VOC emissions are below the applicability criteria by
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speciating out the non-VOC compounds. The owner or operator

may use Method 18 (or an alternative method if validated by

Method 301 of 40 CFR part 63, Appendix A) to determine vent

speciation.

5.5.2 Monitoring

Comment: One commenter (IV-D-30) requested that the

threshold for boilers or process heaters required to install a

temperature monitoring device with a continuous recorder be

reduced from 150 MMBtu/hr to 40 MM Btu/hr or less. One

commenter (IV-D-29) provided that oil field steam generators

equal to or under 65 MMBtu/hr have been used in California to

burn vapors without problems. Another commenter (IV-D-44)

disagreed with the selection of 150 MMBtu/hr as heater size

not to require monitoring. The commenter (IV-D-44) claimed

that the size was selected from the HON, and that refinery

HAP's are not as difficult to destruct as chlorinated solvents

found in SOCMI units, nor are the flow rates as high. The

commenter (IV-D-44) suggested that the minimum size be lowered

to 50 MMBtu/hr.

Response: As discussed in responses to comments on test

methods, the EPA has re-examined the process vent requirements

for boilers and process heaters, and revised the initial

performance test requirements and monitoring requirements to

reduce the recordkeeping and reporting burden. The MACT floor

analysis for process vents shows that 98 percent reduction of

HAP's is the MACT floor level of control for the process vent

component of the source-wide floor. This control level can be

achieved using several types of combustion devices, such as

flares and incinerators. For the reasons presented in the

testing section (5.5.1), the final rule does not require an

initial performance test or monitoring of boilers or process

heaters with a minimum heat input of 44 MW, or for boilers or
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process heaters smaller than 44 MW if the vent stream is

introduced into the flame zone. If the vent stream is not

introduced into the flame zone for boilers or process heaters

less than 44 MW an initial performance test and continuous

monitoring of temperature are required in order to ensure that

the boiler or process heater is operating properly and at

temperatures and residence times that would reduce HAP

emissions by 98 percent.

Comment: One commenter (IV-D-44) stated that any vent

routed to a burner in a process heater or boiler should be

exempt from monitoring. The commenter (IV-D-44) asserted that

the requirement to mix waste gas with primary fuel gas prior

to destruction is unnecessary. The commenter (IV-D-44)

provided that boilers are designed for waste gas destruction

without mixing.

Response: The final rule has been revised to require

monitoring of temperature in boilers or process heaters less

than 44 MW if the vent stream is not introduced into the flame

envelope created by the primary fuel. The flame envelope

generated by the primary fuel is at required temperatures to

ensure 98 percent destruction of HAP's.

The EPA is concerned about situations in which vent

streams represent a small percentage of the total fuel input

to a boiler or process heater and are not mixed with the

primary fuel or introduced into the flame envelope generated

by the primary fuel to ensure destruction at sufficient

temperatures. When vent gases are fed to the combustion

system through a separate burner, the potential exists for a

"flame-out." There is greater potential for this in smaller

combustion systems. Large combustion systems use burner

management systems that reduce the potential for an undetected

flame out. Smaller combustion systems are less likely to have
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equipment, such as flame scanners, that automatically stops

the flow of vent gases that are used as secondary fuel in the

event of a burner flame out. Therefore, the EPA requires

monitoring of vent streams being used as a secondary fuel if

the vent stream is not introduced into the flame envelope

created by the primary fuel in boilers and process heaters

with heat inputs less than 44 MW.

5.6 RECORDKEEPING AND RECORDING FOR PROCESS VENTS

5.7 WORDING OF PROCESS VENT PROVISIONS

Comment: One commenter (IV-D-29) requested that

requirements for combustion devices be stated in BTU's since

equipment in the United States is rated in BTU's or horsepower

as opposed to megawatts. The commenter (IV-D-29) stated that

using megawatts confuses combustion with electrical

generation.

Response: Megawatts are used in the regulation because

it is a Federal government policy to use metric rather than

english units in regulations. Megawatts have been used in

several previous standards without causing confusion.

Comment: One commenter (IV-D-21) suggested that

§ 63.643(a)(2) be revised from "If a boiler or process heater

is used..." to "If a combustion device ..." or "If a boiler,

process heater, or gas turbine is used..." to be consistent

with the commenter's proposed change to the definition of

process controls. The commenter (IV-D-21) suggested that a

similar revision be made to § 63.644(a)(4).

Response: The original wording of the proposed rule has

been retained in the final rule. This section of the rule was

intended to apply specifically to boilers and process heaters,

not other combustion devices.
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Comment: One commenter (IV-D-21) supported the

parenthetical inclusion in § 63.644(a)(2) of typical devices

for detecting the presence of a flare tip flame.

Response: The proposed wording has been retained.

Comment: One commenter (IV-D-21) stated that

§ 63.644(a)(3) and (4), describing different monitoring

options for control devices for process vents, as they are

written, appear to conflict. The commenter (IV-D-21)

suggested that "and all vents that are not introduced with

primary fuel" be added after "is used" in paragraph (4) to

distinguish this option from the one in paragraph (3).

Response: The wording of § 63.644(a)(3) has been changed

to exclude "any boiler or process heater with a design heat

input capacity greater than or equal to 44 megawatts" and "any

boiler or process heater in which all vent streams are

introduced into the flame zone" from monitoring. The wording

of § 63.644(a)(4) has been changed to require temperature

monitoring for "any boiler or process heater less than

44 megawatts design heat input capacity where the vent stream

is not introduced into the flame zone". "Flame zone" is

defined in § 63.641 as "the portion of the combustion chamber

of a boiler or process heater occupied by the flame envelope

created by the primary fuel".

Comment: One commenter (IV-D-21) suggested that

"open-ended valves or lines and pressure relief valves needed

for safety reasons" be added to the list of equipment exempted

from § 63.644(c)(1) and (2) to provide clarity and consistency

with the HON.

Response: The EPA agrees with the commenter and has made

the suggested change to provide clarity and consistency. 

Open-ended lines and pressure relief valves are covered under

the equipment leak provisions in § 63.648.
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Comment: One commenter (IV-D-21) found the first

sentence of § 63.444(e) which requires an owner/operator to

operate a control device in a manner consistent with the

minimum or maximum operation parameter is unnecessary and

troublesome. The commenter (IV-D-21) stated that the

compliance range for an operation could have both a minimum

and maximum, the sentence should say "minimum and/or maximum"

or "minimum or maximum (as appropriate)."

Response: Depending on the type of device, the

acceptable operating parameter range could have a maximum

value, minimum value, or both. Therefore, the change

suggested by the commenter has been made.

Comment: One commenter (IV-D-21) recommended that "an

excess emission" in the last sentence of § 63.644(e) should be

replaced with "a period of excess emissions" to avoid

misinterpretation.

Response: This sentence has been revised according to

the commenter's suggestion.

Comment: One commenter (IV-D-21) suggested that in

table 5, in the requirement for incinerators, catalytic

incinerators and boilers or process heater to "report all

daily average temperatures that are outside the range

established in the NCS," "outside the range" be changed to

"below the minimum."

Response: The table uses "range" as a generic term. For

combustors where temperature is monitored, the acceptable

range will typically mean operating above a specified minimum

temperature. For other devices and parameters, a maximum

value or a range with both minimum and maximum values may be

appropriate. The range must be established on a site-specific

basis.
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Comment: One commenter (IV-D-21) suggested that

recordkeeping for flare pilot flames in table 5 should be

simplified. The commenter (IV-D-21) stated that it is not

necessary to record when one pilot flame is absent and when

all pilot flames are absent since it should not be necessary

to keep records as long as one pilot is working. The

commenter (IV-D-21) suggested specific wording changes to

table 5.

Response: The table (which is table 10 of the final

rule) has been modified to require that the times and

durations when all pilot flames are absent be recorded. This

revision simplifies the recordkeeping requirement without

changing its original intent.

Comment: One commenter (IV-D-25) suggested minor

editorial changes to the flare monitoring requirement in

§ 63.644(a)(2).

Response: The original wording of the proposed

regulation has been retained. The commenter did not provide a

reason for making the changes. The EPA contends that the

original wording is sufficiently clear and the suggested

changes would not provide any additional clarity.

5.8 MISCELLANEOUS

Comment: One commenter (IV-D-05) requested that the EPA

modify the definition of fuel gas system to address shared

systems between chemical and refinery processes that are not

necessarily physically located in refineries. The commenter

(IV-D-05) expressed concern that the proposed definition would

set a precedent by not recognizing chemical plant fuel gas

systems as equivalent to identical systems which happen to be

physically located in refineries.

Response: The definition of fuel gas system includes

"offsite and onsite piping" which implies that systems that
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are not physically located in the refinery can be considered

part of the fuel gas system. It is the EPA's intention to

account for refineries and petrochemical plants with shared

systems in the definition. The EPA contends that the existing

definition does this and therefore has not been changed.

Comment: One commenter (IV-D-21) requested that gas

turbines be added to the list of possible combustion devices

and control devices in the definitions section. The commenter

(IV-D-21) pointed out that combustion conditions can exceed

3000 oF and exit temperatures are equal to or higher than for

flares or incinerators. The commenter (IV-D-21) claimed that

studies and experts have confirmed that gas turbines meet or

exceed 98 percent organic HAP destruction.

Response: The specific devices listed in the definition

of combustion device are provided as examples. The definition

does not exclude gas turbines as combustion devices. 

According to the definition, a combustion device "means an

individual unit of equipment...used for the combustion of

organic hazardous air pollutant vapers." This definition has

been retained.

Comment: One commenter (IV-D-21) requested that the

definition of "flame zone" not be limited to boilers, but it

be defined as "the portion of the combustion chamber of a

combustion device occupied by the flame envelope."

Response: The definition applies to both boilers and

process heaters. The EPA has decided not to expand the

definition to other combustion devices. This section of the

rule was intended to apply specifically to boilers and process

heaters.

Comment: One commenter (IV-D-21) suggested that the

underlined be deleted from the definition of fuel gas: "may

blend them with external sources of natural gas or liquified
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petroleum gas." The commenter (IV-D-21) pointed out that 

other sources of gas are burned in a fuel gas system and gave

examples. The commenter (IV-D-21) stated that petrochemical

plants associated with and adjacent to refineries should not

be considered external sources. The commenter (IV-D-21)

predicted that if the word "external" is left in the

definition, there could be confusion over whether an adjacent

petrochemical plant is "external" or "internal." The

commenter (IV-D-21) proposed that if "external" is left in the

definition, the underlined be added "gaseous streams generated

by refinery and associated petrochemical plant operations." 

Response: The EPA agrees that refineries and

petrochemical plants with a common fuel gas system should be

accounted for in the definition of fuel gas system. The EPA

contends that this is accomplished with the wording "offsite

and onsite piping and control system". The reference to

"external sources of natural gas or liquified petroleum gas"

was meant to include in the definition other sources of gas,

such as natural gas or liquified petroleum gas, supplied by a

vendor. It is not intended as a reference to adjacent

petrochemical plants. However, the words underlined by the

commenter have been deleted to avoid confusion. The EPA

contends that the definition does not exclude fuel gas systems

associated with petrochemical plants.

Comment: One commenter (IV-D-21) requested that the

following sentence be added to the fuel gas system definition: 

"There can be more than one fuel gas system" because, for a

variety of reasons, it is not uncommon for a refinery to have

more than one.

Response: The EPA does not agree that the definition

requires revision to account for refineries with more than one

fuel gas system. The word "system" in the definition refers
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to all piping that performs the functions described in the

definition.

Comment: One commenter (IV-D-21) suggested that the

following be added to the definition of fuel gas system: "The

gaseous streams can contain a mixture of methane, light

hydrocarbons, hydrogen, and other miscellaneous species

(nitrogen, carbon dioxide, hydrogen sulfide, etc.)."

Response: The wording "the gaseous streams can contain a

mixture of methane, light hydrocarbons, hydrogen, and other

miscellaneous species" has been added to improve the clarity

of the definition.

Comment: One commenter (IV-D-21) suggested that "other

than water" be deleted from the definition of a "process

heater." The commenter (IV-D-21) explained a section of a

process heater is often used to heat water or generate steam. 

This is done to make use of what otherwise would have been

waste heat.

Response: The definition of process heater has been

revised to read "an enclosed combustion device that primarily

transfers heat liberated by burning fuel directly to process

streams or to heat transfer liquids other than water." The

EPA contends that the revised definition does not exclude

process heaters that use excess heat to heat water or generate

steam, as their primary function is to heat process streams.

Comment: One commenter (IV-D-21) foresaw a potential

conflict between the definitions of fuel gas system and

"refinery fuel gas." The commenter (IV-D-21) suggested that

"refinery fuel gas" be replaced by "gas supplied by a fuel gas

system" or, less preferably, by "fuel gas." The commenter

(IV-D-21) stated that refineries often share fuel gas systems

with associated petrochemical and HON process units.
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Response: The EPA agrees that it should be recognized

that refineries may share a fuel gas system with an adjacent

non-refinery plant. This is accomplished in the definition of

fuel gas system, which includes the "offsite and onsite piping

control system." The EPA contends that it is not necessary to

revise the definition of refinery fuel gas. The definition of

miscellaneous process vents excludes "gaseous streams to a

fuel gas system." It is in the definition of fuel gas system

that the inclusion of petrochemical and other facilities must

be made.

Comment: One commenter (IV-D-38) suggested minor wording

changes to the definition to more accurately characterize

"refinery fuel gas." The commenter (IV-D-38) suggested that

the word "species" used to describe components of refinery

fuel gas, such as nitrogen and carbon dioxide, be replaced

with "compounds" and the phrase "process heaters throughout

the refinery" be changed to "process heaters in the refinery."

Response: The EPA contends that the original definition

sufficiently and correctly describes refinery fuel gas and

would not be enhanced by the suggestions made by the

commenter. Therefore, the original wording has been retained.

6.0 STORAGE VESSEL PROVISIONS
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6.1 DEFINITION OF STORAGE VESSELS

Comment: One commenter (IV-D-21) stated that the

definition of Group 1 storage vessels should be based on

maximum true vapor pressure as opposed to average true vapor

pressure. The commenter (IV-D-21) asserted that the MACT

floor analysis was based on average true vapor pressure. The

commenter (IV-D-21) claimed that average true vapor pressure

could be corrected to maximum true vapor pressure by adding

2.07 kPa (0.3 psi). The commenter (IV-D-21) recommended that

the Group 1 definition be based on a maximum true vapor

pressure of 10.4 kPa (1.5 psia), as opposed to an average true

vapor pressure of 8.27 kPa (1.2 psia).

Response: The EPA agrees with the commenter that because

the section 114 and ICR questionnaires did not specify the

type of vapor pressure requested, the respondents may have

provided annual average true vapor pressures instead of

maximum true vapor pressures. In order to reflect the

uncertainty of the type of vapor pressure provided in the

questionnaire responses, the EPA has decided to change the

storage vessel applicability cut-off in the final rule from a

maximum true vapor pressure of 8.27 kPa (1.2 psia) to 10.4 kPa

(1.5 psia). This change does not effect the impacts analysis.

Comment: One commenter (IV-D-09) stated that the

definition of maximum true vapor pressure should be clarified

by explicitly stating that a liquid is stored at ambient

temperature when it is not stored in an insulated tank or

heated or cooled while in the tank. The commenter (IV-D-09)

explained that because of thermal inertia, the temperature of

a liquid stored in a tank changes slowly and can be many

degrees hotter or cooler than the temperature of the ambient

air. Therefore, the commenter (IV-D-09) concluded that a

tank's contents are very seldom at ambient temperatures. The
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commenter (IV-D-09) concluded that the EPA's criterion for

determining the maximum true vapor pressure of the stored

liquid is inappropriate since at any given period of time, a

liquid may be at, above, or below ambient temperature.

Response: The EPA does not consider it necessary to

change the rule in the manner suggested by the commenter. The

definition of "maximum true vapor pressure" allows the

equilibrium partial pressure exerted by the stored liquid to

be determined at the temperature equal to the highest

calendar-month average or the liquid storage temperature for

liquids stored above or below the ambient temperature or at

the local maximum monthly average temperature for liquids

stored at the ambient temperature determined with API

publication 2517, standard reference texts, American Society

for Testing and Materials Method D2879-83, or any other method

approved by the Administrator. The EPA considers the rule to

allow maximum true vapor pressure to be determined above or

below ambient temperature for liquids stored in such

conditions.

Comment: One commenter (IV-D-54) requested that the EPA

require a more strict definition of a wastewater tank than

offered in the proposed rule because some of the wastewater

tanks exempted by the proposed rule should be covered. 

Response: The EPA would like to clarify that the storage

vessel provisions apply to raw materials, intermediates, and

final products used and produced by a refinery. Wastewater

tanks are subject to the BWON, which is referenced in the

rule. The EPA does not consider it necessary to change the

rule in the manner suggested by the commenter.

Comment: One commenter (IV-D-29) stated that all heavy

oil tanks as well as tanks having a low concentration of HAP

vapors should be exempt because emissions from them are low.
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Response: The EPA considers that a vapor pressure cutoff of 10.4 kPa (1.5 psia) will exclude most materials with

low HAP concentrations. However, the EPA agrees that some

materials may have low HAP concentrations but also have high

vapor pressures due to the volatility of non-HAP compounds in

the material. Several products, such as asphalt, have minimal

HAP's that may have vapor pressures above 10.4 kPa (1.5 psia)

if stored at elevated temperatures. The EPA has evaluated the

data supplied in the questionnaire responses (see the

memoranda "Petroleum Refinery Liquid HAP and Properties Data"

(August 10, 1993) and "Revised MACT Floor Analysis"

(July 26, 1995) and letter from P.C. Bailey dated

December 23, 1993) and has concluded that a HAP content

criterion should be added to the definition of Group 1 storage

vessel. The Group 1 storage vessel definition includes a HAP

content cutoff of 4 weight percent in the liquid for existing

sources and 2 weight percent in the liquid for new sources. 

The EPA considers these cut-offs adequately exclude heavy oil

tanks with low HAP concentrations. 

Comment: One commenter (IV-D-40) stated that the

95 percent efficiency reduction as defined in the definition

of RCT for storage tanks is inadequate and recommended adding

"or 20 ppmv" to make the requirements consistent with the

miscellaneous process vents and wastewater RCT.

Response: The EPA has determined that a minimum emission

concentration cutoff of 20 ppmv is warranted in cases where

the emission concentration is already low such that it cannot

be reduced by 95 percent. Therefore, the definition of RCT

for storage vessels has been modified to include "A closedvent system to a control device achieving 95 percent reduction

in organic HAP emissions or to an outlet concentration of

20 parts per million by volume. 
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6.2 IMPACTS ANALYSIS

6.2.1 Database

Comment: One commenter (IV-D-29) stated that if the

EPA's database for storage vessels was based on old emission

inventories it must be updated. The commenter (IV-D-29)

indicated that the new AP-42 calculation factor drastically

reduced estimates of tank emissions in the San Joaquin Valley

in California. The commenter (IV-D-29) predicted that tank

emissions are much lower than indicated in previous

inventories.

Response: The EPA would like to clarify that the storage

vessel component of the source-wide MACT floor and the

national impacts from storage vessels were developed using

information supplied by the refining industry in section 114

and ICR questionnaire responses and were not based on old

emission inventories. The EPA asserts that the questionnaire

responses provide the most current data available in the

refining industry. Emissions from storage vessels were

estimated using equations provided in chapter 12 of the

Compilation of Air Pollutant Emission Factors (AP-42), revised

in July 1993.

Comment: One commenter (IV-D-29) questioned the data for

heavy oil vapor pressure used to develop emission factors. 

The commenter (IV-D-29) claimed that water and

non-condensables in heavy oil make it appear to have higher

emissions. The commenter (IV-D-29) suggested that another

factor for heavy oil be developed instead of using one based

on Reid vapor pressure. The commenter (IV-D-29) claimed that

many heavy oil tanks do not produce a reading using Method 21.

Response: The data on heavy oils supplied in the

section 114 and ICR questionnaires was scrutinized by

representatives from the refining industry, State agencies,
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and the other EPA regions. Based on comments supplied by the

industry, reasonable vapor pressures were developed. The EPA

is not aware of how to develop emissions and emission factors

that are not based on the vapor pressure of the liquid stored. 

The commenter did not supply information on alternative

methods for developing emission factors.

6.2.2 Cost Impacts

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-11,

IV-D-19, IV-D-25 and IV-F-1, IV-D-51) contended that the EPA's

cost calculations and cost-effectiveness were incorrect for

Option 1 requirements. The commenters (IV-D-09, IV-D-10,

IV-D-11, IV-D-25, IV-D-51) claimed that the cost impacts were

too low for the following reasons:

C Operating costs were not included; as a result, one

commenter (IV-D-19) estimated that the costs are at

least an order of magnitude lower than they should be.

The commenter (IV-D-19) did not provide additional

estimates of operating costs.

C Lost capacity from installing controls was not

considered; and 

C Incremental costs were not presented separately for

each type of tank. Three commenters (IV-D-09,

IV-D-10, IV-D-25) contended that this resulted in

weighting the cost effectiveness toward fixed-roof

tanks and obscuring the poor cost effectiveness for

tanks already controlled with floating roofs.

One commenter (IV-D-25 and IV-F-1) estimated incremental

cost effectiveness for Option 1 for tanks already equipped

with floating roofs to be $17,000 to $300,000/Mg ($15,400 to

$272,200/ton) HAP reduction, depending on the type of floating

roof, the type of fittings and seals added, and the HAP

content of the stored liquid.

One commenter (IV-D-09) stated that including the factors

listed above would make the cost-effectiveness $9,900/Mg
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($8,980/ton) of HAP instead of $4,400/Mg ($3,990/ton) of HAP

as stated in the proposal.

Response: The EPA contends that all applicable operating

costs for controls were considered in the cost impacts. The

EPA estimated the annual costs from inspecting storage

vessels, recordkeeping and reporting, and annualized capital

costs. As noted above, the commenter did not provide details

on other costs that should be included as part of the annual

costs and did not supply cost data necessary to revise impacts

from storage vessels. 

The EPA agrees the cost estimates at proposal

underestimated degassing and cleaning storage vessels costs

and do not include the cost of lost capacity because the EPA

did not have cost algorithms or information to estimate this

cost. Based on information supplied by the industry, the EPA

considers the cost of lost capacity and the cost of degassing

and cleaning storage vessels to potentially be very high and

could substantially increase the incremental costeffectiveness and average cost-effectiveness of Option 1. 

Therefore, the final rule only requires that existing storage

vessels comply with the MACT floor level of control,

subpart Kb without fittings.

Comment: One commenter (IV-D-50 and IV-F-1) stated that

in instances where a storage tank has a floating roof and a

single seal, adding a second seal and other control measures

will yield very little HAP reduction at a very high cost. The

commenter (IV-D-50 and IV-F-1) estimated that storage controls

will achieve the poorest emissions reductions at a

cost-effectiveness estimate of $4,600/Mg (4,170/ton) and are

based on large tanks at large refineries where the best

coefficients apply. The commenter (IV-D-50) stated that their

analysis indicates that adding a second seal to a floating
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roof tank would only reduce HAP emissions by a de minimis

680 grams/day (1.5 lbs/day) for an average size gasoline tank

at a small refinery.

Response: The requirement for a secondary seal was not

based on cost-effectiveness. The MACT floor analysis for

storage vessels indicated that the best-controlled 12 percent

of sources controlled storage vessels with liquids greater

than 10.4 kPa (1.5 psia) to the requirements in subpart Kb

(without fittings). Subpart Kb requires that floating roof

tanks install a secondary seal. Therefore, the Act requires

that EPA must, at a minimum, require the controls in the MACT

floor, (i.e., secondary seals on floating roof tanks).

Comment: One commenter (IV-D-29) questioned whether the

cost estimate for storage vessels included tank replacement

for all bolted and riveted tanks.

Response: The commenter did not explain the reasons

bolted and riveted tanks would need to be replaced due to the

rule. In estimating the costs of the rule, EPA did not assume

that bolted and riveted tanks would have to be replaced and

the storage vessel costs were estimated for a typical storage

tank. The EPA recognizes that tank specific costs may be

greater or less than the costs estimated from the cost

equations. However, the EPA considers the cost algorithms to

adequately characterize controlling a typical storage vessel

in the refining industry. 

Comment: One commenter (IV-D-50 and IV-F-1) compared the

costs of proposed tank controls for a small refinery to the

costs for a large refinery and found them to be twice that

estimated by the EPA for the industry. The commenter

(IV-D-50) included data on how this comparison was made and

concluded that it was reasonable to assume a cost-
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effectiveness estimate ranging between $8,000 and $10,000/Mg

($7,260 and $9,070/ton) of HAP for tanks at a small refinery.

One commenter (IV-D-50 and IV-F-1) stated that not only

will small refineries incur compliance costs twice as high as

what large refineries will incur due to economy of scale

factors, they will also have twice as many tanks to retrofit

compared to the industry as a whole. 

Response: The EPA examined the possibility of

subcategorizing small refineries to determine if a different

level of control could be developed. The EPA analyzed the

MACT floor for various crude charge capacity cutoffs (10,000;

20,000; 30,000; 40,000; 50,000; and 60,000 bbl/sd), refinery

ozone attainment status, and the types of products at each

refinery. The results of the EPA analysis showed that no

significant changes from the 10.4 kPa (1.5 psia) cutoff would

occur for small refineries. The EPA agrees that controlling

storage vessels at small refineries may be less cost-effective

than at large refineries. However, the EPA would like to

clarify that the MACT floor analysis requires that storage

vessels storing materials with vapor pressures greater than or

equal to 10.4 kPa (1.5 psia) must be controlled to subpart Kb

without fittings regardless of size.

Comment: One commenter (IV-D-06) stated that for

equipment vendors to meet the demand for retrofits in the

3-year time period required by the proposed standards, there

would be an additional cost for expedited services. The

commenter (IV-D-06) concluded that this cost should be

included in the EPA's cost estimates.

Response: The EPA has changed the compliance times in

the final rule to allow 10 years or at the next inspection and

maintenance activity, whichever comes first, for all floating

roof vessels. Fixed-roof vessels must still comply with the
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rule within 3 years of promulgation unless a compliance

extension is received under section 112(i)(3)(B) of the Act. 

If the tank must be replaced to comply with the requirements

of the rule, EPA believes that it would be appropriate to

grant the compliance extension request and that compliance

deadlines would be 4 years in most cases.

The commenter did not explain the basis for their

conclusion that expedited services would be necessary. The

EPA does not have any data on increased costs due to expedited

service and no information was supplied by the commenters. 

Therefore, this cost was not included in the impacts analysis.

6.2.3 Emissions Impacts

Comment: One commenter (IV-D-50 and IV-F-1) contended

that there are increased air emissions associated with

cleaning and degassing tanks for required retrofits. 

Response: The EPA agrees with the commenter's statement. 

An analysis of the emissions from degassing and cleaning

storage vessels was performed using theoretical models

developed by the EPA. For floating roof vessels, the analysis

showed that significant emissions of HAP's occur from

degassing and cleaning activities such that the emissions

cannot be balanced in a reasonable amount of time with the

emission reductions from complying with subpart Kb without

fittings. The analysis also showed that emissions from

degassing and cleaning fixed roof vessels could be balanced

under one year by the emission reductions from complying with

subpart Kb without fittings. Based on the results of this

analysis, the compliance time requirements have been modified

for floating roof vessels to be within 10 years or at the next

inspection and maintenance activity, whichever comes first.

Comment: One commenter (IV-D-22) asserted that the EPA

did not consider the impact of the reformulated gasoline rule
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on emissions of HAP's from storage vessels. The commenter

(IV-D-22) stated that the (reformulated gasoline) RFG rule

will result in a reduction in gasoline vapor pressure and

benzene concentration in storage tanks.

Response: The impacts analysis and data collection for

the refinery standard was done prior to implementation of the

RFG rule. In addition, the Act limits the EPA to exclude from

the MACT floor those sources that have achieved emission

reductions or controls within 18 months before the rule was

proposed or within 30 months before the rule was promulgated.

The EPA concluded that the change in gasoline vapor

pressure and benzene concentration would not significantly

effect the impacts analysis. Data gathered in questionnaire

responses indicated that benzene is only one of 11 HAP's that

are present in gasoline, and benzene is not present in the

highest quantities, nor is it the most volatile.

Comment: One commenter (IV-D-22) asserted that use of

maximum monthly average temperature to calculate vapor

pressure would greatly overestimate the actual annual average

vapor pressure and related emissions from storage vessels

located in areas of fluctuating temperatures. The commenter

(IV-D-22) stated that this would cause disparities in regions

because the amount of HAP emissions controlled would be

substantially less in areas of seasonally fluctuating

temperatures. Additionally, the commenter (IV-D-22) stated

that refineries in colder midcontinent States could claim

credit only for those actual annual average emissions

controlled even though they were required to incur the costs

necessary to control the maximum monthly emissions. The

commenter (IV-D-22) recommended basing the control requirement

on the vapor pressure of the HAP's contained in the liquid as

required by the HON, or to base the vapor control threshold on
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the annual average HAP vapor pressure calculated from annual

average ambient temperatures as available from the National

Weather Service.

Response: The EPA agrees that affected liquids may have

vapor pressures that are below the vapor pressure cutoff for a

portion of the year, but also notes that nonaffected liquids

may have true vapor pressures above the cutoffs for portions

of the year such as daylight hours during summer months. In a

prior rulemaking, EPA realized that basing applicability on

maximum instantaneous vapor pressure would result in the

broadest applicability and, therefore, the largest emission

reduction. This approach could cause planning problems for

the industry because they might not be able to adequately

predict which vessels would be affected. Because industry may

not be able to account for particularly hot days adequately,

the instantaneous vapor pressure was rejected as the basis of

applicability.

The EPA then examined an annual average vapor pressure

format. Vapor pressures of volatile organic liquids are

higher in the warmer, summer months, when ambient ozone levels

are highest. If applicability were based on the annual

average vapor pressure, vessels would not come under the

standards even though they were storing liquids with true

vapor pressures greater than the applicability cutoff. These

vessels would then emit significant quantities of VOC's and

HAP's during the summer when ambient ozone levels are highest. 

Therefore, EPA decided to examine a shorter time frame that

would broaden the applicability of the standards, particularly

during the summer.

An applicability based on maximum monthly average vapor

pressure was selected because this would have a broader

applicability than annual averages without the planning
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problems associated with an applicability based on

instantaneous vapor pressure and would base applicability on

the contribution to VOC and HAP emissions when ozone levels

are highest. The EPA maintains this argument for the refinery

MACT standard.

Other regulations, already promulgated, use the maximum

monthly temperatures to affect the determination of vapor

pressure and applicability. The EPA desires to maintain

consistency between these other regulations, the storage

requirements in the HON (40 CFR 63, subpart G) and the new

source performance standards for volatile organic liquid

storage vessels (40 CFR 60, subpart Kb), because all three

regulations could affect similar storage vessels in similar

processing plants, and because the final refinery rule

significantly cross-references these other rules.

The EPA also contends that the commenters suggestion of

using HAP vapor pressures alone is impractical and costly. 

Existing vapor pressure tests only measure the vapor pressure

of the bulk liquid. For liquids that are comprised mostly of

one HAP, as stored in the SOCMI, this approach would be

satisfactory. The organic liquids stored at petroleum

refineries contain mixtures of compounds, some of which might

be HAP's. Therefore, if HAP partial pressures were required

instead of total vapor pressure, speciation of the stored

liquid would be necessary. The EPA considers this a costly

and unnecessary exercise that would add complexity to the

rule. Therefore, the EPA has not revised the final rule in

the manner the commenter suggested.

Comment: One commenter (IV-D-48) asserted that proposed

exemptions for new sources would encourage facilities to use

small, exempt storage vessels rather than collect all of their

stored evaporated HAP's in controlled storage vessels.
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Response: The EPA disagrees with the commenter. The

capacity cut-off for new storage tanks is 151 m3

(40,000 gallons). The industry practice is to store material

in larger tanks, generally in excess of 380 m3

(100,000 gallons). Additionally, storing material in a number

of smaller storage vessels would be cost and space prohibitive

for refineries. Therefore, it is implausible that anyone

would use this as a means of avoiding control.

6.3 SELECTION OF MACT FLOOR AND MACT FOR STORAGE VESSELS

6.3.1 Selection of the Storage Vessels Component of the

 Source-Wide MACT Floor

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-11,

IV-D-25, IV-D-30, IV-D-51) concurred with the EPA that the

MACT floor for storage tanks should be NSPS subpart Kb without

roof fitting controls. One commenter (IV-D-25) pointed out

that roof fitting controls are not required by subparts K, Ka,

or RACT rules, and that the degree of fitting control required

by subpart Kb has been interpreted differently over time. The

commenter (IV-D-25) concluded that only a very small

percentage of tanks at refineries meet the roof fitting

requirements of subpart Kb, so they do not constitute the

refinery MACT floor for existing tanks. 

Two commenters (IV-D-09, IV-D-51) stated that the fitting

requirements are not found in other rules; therefore, tanks

currently controlled to NSPS subpart K or Ka or to EPA RACT

controls do not contribute to a MACT floor for roof fitting

controls. One commenter (IV-D-19) submitted that fittings

requirements were not included in the floor analysis and

therefore, should not be included in the final floor

determination. One commenter (IV-D-09) added that most tanks

are in ozone non-attainment areas regulated under RACT
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guidelines, which specify Kb-style rim seals but not Kb-style

controls on other roof deck fittings.

Response: The EPA thanks the commenters for their views. 

The final rule requires that storage vessels comply with the

MACT floor level of control (subpart Kb without fittings) for

the storage vessels component of the source-wide MACT floor. 

Comment: One commenter (IV-D-09) stated that the EPA

should explicitly state that compliance with the NSPS

subpart Kb can be substituted for the requirements proposed in

§ 63.646. 

Response: The final rule explicitly directs refineries

which regulations to comply with when there exists overlapping

rules. The final rule allows existing sources complying with

subpart Kb to continue compliance with subpart Kb instead of

the requirements in § 63.646. A Group 1 storage vessel that

is part of a new source and is also subject to subpart Kb is

required to comply only with the storage vessel requirements

in 40 CFR part 63, subpart CC. A Group 2 storage vessel that

is part of a new source and is subject to subpart Kb is

required to comply only with subpart Kb. A Group 2 storage

vessel that is part of a new source and is subject to

subpart Kb, but is not required to apply controls by § 63.110d

or 63.112d of subpart Kb is required to only comply with

40 CFR part 63, subpart CC.

Comment: One commenter (IV-D-42) requested the

development of a separate MACT floor for storage tanks for

small refineries. The commenter (IV-D-42) contended that the

MACT floor for refinery storage vessels would be

disproportionately burdensome for small refineries because

many of these refineries are in attainment areas and these

tanks would not have been subject to any RACT or other VOC

control requirements.
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Response: The EPA examined the possibility of

subcategorizing small refineries to determine if a different

MACT floor level of control could be developed. The EPA

analyzed the MACT floor for various crude charge capacity

cutoffs (10,000; 20,000; 30,000; 40,000; 50,000; and

60,000 bbl/sd), refinery ozone attainment status, and based on

the types of products at each refinery. The results of the

analysis showed that no significant changes from the 10.4 kPa

(1.5 psia) cutoff would occur for small refineries. The EPA

agrees that controlling storage vessels at small refineries

may be less cost-effective than at large refineries. However,

the EPA would like to clarify that the MACT floor analysis

requires that storage vessels storing materials with vapor

pressures greater than or equal to 10.4 kPa (1.5 psia) must be

controlled to subpart Kb without fittings.

Comment: Two commenters (IV-D-25, IV-D-30) supported

selection of the 88th percentile vapor pressure (17.9 kPa

[2.6 psia]) instead of the 94th percentile (8.27 kPa

[1.2 psia]) that was chosen as the applicability criterion for

the storage vessels component of the source-wide MACT floor. 

One commenter (IV-D-25) contended that the EPA has discretion

to select the 88th percentile, and that the incremental cost

effectiveness of the 94th percentile (8.27 kPa [1.2 psia])

applicability criteria is $17,000 to $22,000/Mg ($15,420 to

$19,960/ton) of HAP. 

Response: The Act requires that the MACT floor be

determined from "the average emission limitation achieved by

the best performing 12 percent of existing sources..." As

discussed in section 4.1 of this document, the EPA interprets

the word "average" to authorize the Agency to use any

reasonable method, in a particular factual context, of

determining the central tendency of a data set. The EPA's
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interpretation of "average" for the storage vessels component

of the source-wide MACT floor is the arithmetic mean level of

control. Therefore, the floor level of control for storage

vessels is control to subpart Kb (without fittings) for tanks

storing liquids with vapor pressures greater or equal to

10.4 kPa (1.5 psia).

Comment: Three commenters (IV-D-09, IV-D-21, IV-D-25)

recommended raising the MACT floor control applicability

criterion from 8.27 kPa (1.2 psia) to 10.4 kPa (1.5 psia).

One commenter (IV-D-09) contended that although the EPA

had determined the floor method of control correctly, it had

underestimated the vapor pressure threshold at which the floor

control was applied by 2.07 to 4.82 kPa (0.3-0.7 psia). The

commenters (IV-D-09, IV-D-21, IV-D-25) explained that the

Group 1 storage vessel threshold was based on maximum monthly

average vapor pressure; however, the section 114 questionnaire

responses provided data on yearly average storage temperatures

and this information was used to make the MACT floor decision. 

The commenters (IV-D-09, IV-D-21, IV-D-25) explained that the

two measurements are not interchangeable because the

temperature of a stored liquid will trace the average ambient

temperature. One commenter (IV-D-09) added that in most U.S.

locations the highest monthly average ambient temperature is

approximately 5.6-11.1 oC (10-20 oF) higher than the yearly

average temperature. The commenters (IV-D-09, IV-D-21,

IV-D-25) stated that the highest monthly average true vapor

pressure, assuming a typical 2.3 RVP naphtha, would be

2.07-4.82 kPa (0.3-0.7 psia) higher than the annual average.

Response: The EPA agrees with the commenters that

because the section 114 and ICR questionnaires did not specify

the type of vapor pressure requested, the respondents may have

provided annual average true vapor pressures instead of
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maximum true vapor pressures. In order to reflect the

uncertainty of the type of vapor pressure provided in the

questionnaire responses, the EPA has decided to change the

storage vessel applicability cut-off in the final rule from a

maximum true vapor pressure of 8.27 kPa (1.2 psia) to 10.4 kPa

(1.5 psia). An analysis of the storage vessel database

indicated that a change from 8.27 kPa (1.2 psia) to 10.4 kPa

(1.5 psia) will not effect the impacts analysis.

Comment: One commenter (IV-D-48) disagreed with the

EPA's floor analysis for storage tanks. The commenter

(IV-D-48) asserted that all new and existing vessels should be

controlled. The commenter (IV-D-48) stated that the EPA has

stated that 86 percent of storage vessels are controlled and

cited a reference to support this figure.

Response: The EPA holds the view that its analysis of

the floor is consistent with the statute. The Act requires

that the MACT floor for existing sources be determined as the

average of the best-performing 12 percent of sources, and the

MACT floor for new sources be equal to the control used in the

best-controlled source. The MACT floor analysis shows that

control to subpart Kb (without fittings) is the MACT floor

level of control for the storage vessels component of the

source-wide MACT floor. The analysis also shows that the

average vapor pressure of these tanks is 10.4 kPa (1.5 psia)

and the average HAP weight percent in the liquid is 4. 

Therefore, only existing tanks storing liquids with vapor

pressures greater than or equal to 10.4 kPa (1.5 psia) and HAP

weight percents in the liquid greater than or equal to 4 are

required to be controlled at the floor level of control. The

best-controlled tanks store liquids with vapor pressures

greater than 0.69 kPa (0.1 psia) and HAP weight percents in

the liquid greater than 2. Therefore, new storage tanks with
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vapor pressures greater than or equal to 0.69 kPa (0.1 psia)

and HAP weight percents in the liquid greater than or equal to

2 are required to controlled. 

6.3.2 Selection of MACT for Storage Vessels

Comment: Three commenters (IV-D-46, IV-D-53, IV-D-57)

supported Option 1 requirements (NSPS subpart Kb requirements

for tanks with vapor pressures of 5.17 kPa (0.75 psia) or

greater) for storage tanks as MACT. One commenter (IV-D-53)

pointed out that Option 1 was less than the floor cost on a

dollar per megagram of HAP controlled basis and the

incremental cost per megagram of HAP controlled was less than

the control cost for the floor or Option 1. The commenter

(IV-D-53) concluded that because the provision was not cost

prohibitive and Option 1 was the most cost-effective, it

should be selected as MACT for existing sources. The

commenter (IV-D-46) provided that the incremental value of

Option 1 was below many used by the New Source Review

Permitting Program to justify past additional best available

control technology (BACT).

Several commenters (IV-D-09, IV-D-22, IV-D-25 and IV-F-1,

IV-D-44, IV-D-51) objected to the Option 1 requirements for

storage tanks. Three of the commenters (IV-D-09, IV-D-22,

IV-D-51) supported the MACT floor level of control. Several

commenters (IV-D-25 and IV-F-1, IV-D-36, IV-D-38, IV-D-44)

stated that Option 1 would not be cost effective. One

commenter (IV-D-25) contended that the cost effectiveness for

Option 1 was underestimated, and that Option 1 could only be

justified for existing fixed roof tanks. The commenter

(IV-D-25) claimed that control beyond the floor for tanks

already equipped with floating roofs could not be justified by

reasonable cost effectiveness criteria. Three commenters

(IV-D-36, IV-D-38, and API hearing/transcript) alleged the
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$4,400/Mg ($3,990/ton) incremental cost estimate was low by an

order of magnitude, and that it should be closer to $54,000/Mg

($48,990/ton) VOC. One commenter (IV-D-38) argued that the

estimate was low because operating costs and the cost of lost

capacity were not included. One commenter (IV-D-44) agreed

with the API's finding that baseline emissions were only

59,000 Mg (65,000 ton) as opposed to the 111,000 Mg

(122,400 ton) indicated by the EPA. Another commenter

(IV-D-36) suggested that further study on this issue must be

done. One commenter (IV-D-20) opposed the proposed

requirements for storage vessels based on the cost impacts of

$4,400/Mg ($3,990/ton) of HAP, and suggested that anything

over $3,000/Mg ($2,720/ton) was unreasonable.

Response: The EPA agrees with some of the commenters

that the cost estimates at proposal may have underestimated

the cost of degassing and cleaning storage vessels, and do not

include the cost of lost capacity because the EPA did not have

cost algorithms or information to estimate this cost. Based

on information supplied by the industry, the EPA considers the

cost of lost capacity and the cost of degassing and cleaning

storage vessels to potentially be very high and could

substantially increase the incremental cost-effectiveness and

average cost-effectiveness of Option 1. Therefore, the final

rule only requires that existing storage vessels comply with

the MACT floor level of control for the storage vessels

component of the source-wide MACT floor, subpart Kb without

fittings.

Comment: One commenter (IV-D-09) stated that there

should be a de minimis HAP concentration exclusion for

fixed-roof tanks that would exclude tanks that contain heavy,

viscous hydrocarbon intermediates and products such as

asphalt, which are stored at elevated temperatures to enable
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handling. The commenter (IV-D-09) stated that virtually all

of these liquids have an initial boiling point above 600 oF,

and therefore contain no volatile HAP's. In addition, the

commenter (IV-D-09) stated that these liquids could not be

stored in an internal floating roof tank because of operation

and maintenance problems if the heavy liquid product cooled

and solidified.

Another commenter (IV-D-20) requested that the proposed

rule contain provisions excluding tanks that have a HAP

content of 5 percent or less by weight.

Response: The EPA considers that a vapor pressure cutoff of 10.4 kPa (1.5 psia) will exclude most materials with

low HAP concentrations. However, the EPA agrees that some

materials may have low HAP concentrations but also have high

vapor pressures due to the volatility of non-HAP compounds in

the material. Several products, such as asphalt, have minimal

or no HAP's that may have vapor pressures above 10.4 kPa

(1.5 psia) if stored at elevated temperatures. The EPA has

evaluated the data supplied in the questionnaire responses and

has concluded that a minimum HAP content requirement for the

Group 1 storage vessel provisions is warranted. The final

rule includes a 4 weight percent HAP requirement for existing

Group 1 storage vessels and a 2 weight percent HAP requirement

for new Group 1 storage vessels. 

Comment: Three commenters (IV-D-10, IV-D-12, IV-D-15)

urged the EPA to increase the applicability criterion for

crude oil storage tanks from 34.4 kPa (5 psia) to 55 kPa

(8 psia). The commenters (IV-D-10, IV-D-12, IV-D-15)

contended that many of the hydrocarbons that add volatility to

crude oil such as methane, ethane, and propane have little or

no adverse health affects. The commenters (IV-D-10, IV-D-12,

IV-D-15) asserted because of the presence of these
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hydrocarbons, crude oil storage tanks could become subject to

complex recordkeeping and compliance burdens. The commenters

(IV-D-10, IV-D-12, IV-D-15) concluded that increasing the true

vapor pressure applicability criterion for crude oil storage

tanks to 55 kPa (8 psia) would significantly reduce the cost

burdens of the proposed rule without significantly decreasing

the associated HAP emission reductions.

One commenter (IV-D-10) contended that the EPA should not

base a set of regulations that would affect a large set of

stored products with different characteristics on one product. 

The commenter (IV-D-10) stated that the EPA's selection of

34.4 kPa (5 psia) in the regulation would affect crude oil

tanks and tanks storing intermediate blend stocks. The

commenter (IV-D-10) objected to basing the crude oil storage

requirements on an analysis of gasoline storage tanks with

vapor pressures of 38.6 kPa (5.6 psia). 

Response: The EPA believes the commenters are referring

to a compliance schedule longer than 3 years for storage tanks

storing crude oil. The final rule allows existing floating

roof storage vessels storing materials with vapor pressures

greater than or equal to 10.4 kPa (1.5 psia) and a HAP

concentration greater than or equal to 4 percent to comply

with the rule within 10 years after promulgation or at the

next inspection period. Existing fixed roof vessels storing

materials with vapor pressures greater than or equal to

10.4 kPa (1.5 psia) and a HAP concentration greater than or

equal to 4 percent are still required to comply within 3 years

after promulgation of the rule, unless a compliance extension

is obtained under sec. 112 (i)(3)(B) of the Act. These

changes were made to reflect the effect of emissions from

premature degassing and cleaning of storage vessels. An

analysis conducted by EPA shows that emissions from degassing
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and cleaning fixed roof tanks storing crude oil could be

balanced under 3 years with the emissions reduction from

implementing subpart Kb controls.

Comment: One commenter (IV-D-57) stated that new storage

vessels should at a minimum meet all of the requirements for

existing storage vessels from the San Francisco Bay area

because the Bay Area has the most stringent storage vessel

regulations, including being subject to fitting requirements

as well as standards for seals. Additionally, the commenter

(IV-D-57) stated that seals and fittings should be part of the

inspection and maintenance program, and leak detection and

repair programs, and the tanks should be subject to a pressure

decay test for leaks prior to filling, similar to the testing

proposed in the Gasoline Distribution rule. The commenter

(IV-D-57) also stated that all pressure-relief valves on new

storage vessels should be pilot-operated. The commenter

(IV-D-57) also provided a list of storage controls that they

contended should be required for existing sources.

One commenter (IV-D-54) stated that Group 1 storage tank

requirements should include more actual monitoring with an OVA

rather than visual inspection which can be easily falsified.

Response: EPA's MACT floor analysis for new sources

shows that the best-controlled source has a level of control

equal to subpart Kb for storage vessels. The EPA recognizes

that State or local air pollution control agencies may have

different requirements for controlling emissions from storage

vessels than the requirements in subpart Kb because subpart Kb

was promulgated for new sources. However, the EPA does not

have information that equipment and controls mentioned by the

commenters, such as OVA's and pressure decay tests, would

achieve greater or equivalent control to what is required in

subpart Kb. Without data to support the commenters'
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assertion, such as VOC or HAP control efficiency of these

equipment and controls, the EPA cannot make a determination

that the commenters' control requirements are equal to or more

stringent than the control required in subpart Kb and

therefore would be new source MACT.

Comment: One commenter (IV-D-54) requested a higher

level of options be required for Group 2 storage tanks and

strongly opposed the lack of proposed controls or inspections. 

One commenter (IV-D-54) recommended requiring controls on

Group 1 storage tanks with a capacity of 500 gallons or more.

Response: The MACT floor analysis for storage vessels

shows that (for existing sources) the best-controlled

12 percent of sources have an average level of control equal

to subpart Kb (without fittings) for tanks storing liquids

with vapor pressures greater than or equal to 10.4 kPa

(1.5 psia) and capacities greater than or equal to 177 m3

(46,760 gallons). The average level of control for tanks

storing liquids with vapor pressures less than 10.4 kPa

(1.5 psia) and capacities less than 177 m3 (46,760 gallons) is

no control. The MACT floor analysis also shows that (for new

sources) the best-controlled storage vessels have control

equal to subpart Kb for tanks storing liquids with vapor

pressures greater or equal to 3.4 kPa (0.5 psia) and

capacities greater than or equal to 151 m3 (40,000 gallons). 

The EPA analyzed options above the floor level of control

based on the statutory criteria in the Act. The results of

the analysis showed that options above the floor level of

control (i.e., control of Group 2 tanks) were not costeffective. The lack of cost effective options beyond the

floor prevented the EPA from requiring more stringent control

than the existing source and new source MACT floor levels of
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control. Therefore, control of Group 2 storage tanks was not

required in the rule.

Comment: One commenter (IV-D-29) stated that the

proposed standards for existing storage vessels were too

strict. The commenter (IV-D-29) claimed that it would be too

difficult to make old tanks vapor tight.

Response: The requirements of the storage vessel

provisions were set at the MACT floor. A lower stringency

that would still meet the requirements prescribed in the Clean

Air Act is not possible. For existing storage vessels the

rule requires that liquids with a vapor pressure of 10.4 kPa

(1.5 psia) or greater be stored in internal or external

floating roof vessels meeting the specifications of §§ 63.646

or the vapors from fixed roof tanks be collected and routed to

a control device achieving 95 percent reduction of HAP's. The

collection system must be monitored for leaks according to

§ 63.648. There are no specific requirements for monitoring

emissions from vessels. If existing internal or external

floating roof tanks do not meet the specifications in § 63.646

or the vapor collection system used with the control device

leaks as defined in § 63.648, repairs must be made. The EPA

would also like to clarify that the rule does not require that

tanks be tested for vapor tightness.

6.4 COMPLIANCE SCHEDULE FOR EXISTING STORAGE VESSELS

Comment: Many commenters (IV-D-06, IV-D-09, IV-D-10,

IV-D-11, IV-D-12, IV-D-19, IV-D-20, IV-D-22, IV-D-25 and

IV-F-1, IV-D-38, IV-D-42, IV-D-44, IV-D-50, IV-D-51) opposed

the EPA's decision to require floating roof tanks storing

liquids with vapor pressures above 5.0 psia to achieve

compliance in three years. The commenters (IV-D-06, IV-D-09,

IV-D-10, IV-D-11, IV-D-12, IV-D-19, IV-D-20, IV-D-22, IV-D-25

and IV-F-1, IV-D-38, IV-D-42, IV-D-44, IV-D-50, IV-D-51)
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objected to the 3-year compliance schedule for various

reasons, including consistency with other regulations, alleged

emissions increases, and cost and supply considerations. 

Recommendations for compliance times ranged from at the next

scheduled tank maintenance to 10 years from promulgation.

Several commenters (IV-D-06, IV-D-10, IV-D-11, IV-D-19,

IV-D-22, IV-D-25, IV-D-38, IV-D-51) argued that a 10-year

compliance period for floating roof tanks would be consistent

with the intent and purpose of the Clean Air Act, the HON

storage tank requirements, and the Benzene Storage NESHAP to

reduce HAP emissions. Two commenters (IV-D-11, IV-D-25) added

that a 10-year compliance period should be an integral part of

the MACT floor requirements for storage vessels because it has

been included in all previous federal regulations affecting

storage tanks at refineries.

Several commenters (IV-D-20, IV-D-22, IV-D-25, IV-D-42,

IV-D-50) recommended that affected facilities should be

allowed to retrofit tanks with the required controls at their

next scheduled maintenance.

One commenter (IV-D-22) asserted that the proposed

control requirements for storage vessels are in conflict with

the applicable compliance dates in subpart CC. The commenter

(IV-D-22) provided language to resolve this conflict.

Several commenters (IV-D-09, IV-D-11, IV-D-10, IV-D-19,

IV-D-25, IV-D-51) asserted that a 3-year compliance schedule

would result in increased HAP and VOC emissions. One

commenter (IV-D-11) explained that under normal circumstances,

tanks are inspected infrequently for corrosion because

corrosion rates are low and because tank cleaning and

degassing results in emissions of VOC's. The commenter

(IV-D-11) referenced a study done by API (commenter IV-D-25)

to explain that higher emissions would occur because storage
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tanks would be degassed and inspected earlier than scheduled

resulting in emissions from an additional degassing and

cleaning cycle. One commenter (IV-D-10) contended that the

3-year compliance period was based on an incomplete analysis

done for the gasoline distribution MACT rule. The commenter

(IV-D-10) stated that because the 3-year compliance period

would come sooner than the typical 10-year cleaning cycle, the

EPA attempted to calculate the number of years it would take

to balance the emissions that would be emitted as a result of

tank cleaning and degassing with the emission reductions that

would be achieved because of the earlier retrofit. The

commenter (IV-D-10) asserted that for this analysis, the EPA

did not include emissions that may come from the handling of

sludge removed from the tank bottom. The commenter (IV-D-10)

concluded that the incompleteness of the analysis invalidates

the EPA's conclusions because the tank cleaning process could

generate sludge that is 90 percent liquid. The commenter

(IV-D-10) recommended re-doing the analysis with an estimate

of the emissions from sludge handling. One commenter

(IV-D-25) performed an analysis of emissions from degassing of

tanks in order to apply controls within 3 years versus

allowing vessels to wait 10 years or until a scheduled

degassing. The commenter (IV-D-25) concluded that it would

take several years of control to offset the emissions caused

by an earlier degassing. The same commenter (API

hearing/transcript) said that their analysis showed that for

IFR vessels storing gasoline, the proposed 3-year MACT

requirements would not result in a net emission reduction

benefit. One commenter (IV-D-11) stated that internal

floating roof tanks controlled with subpart Kb rim seals and

storing gasoline would require more than 5 years of added

emission control to offset degassing and cleaning emissions
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from these tanks, and the years required for liquids other

than gasoline would be longer. One commenter (IV-D-19)

estimated a compliance schedule of more than five years would

be required to balance tank cleaning emissions for a typical

floating roof gasoline storage tank.

One commenter (IV-D-57) asserted that emissions

reductions from tanks not currently meeting the NSPS would

more than offset the HAP emissions from degassing and cleaning

during installation of new controls, if the requirement is

imposed within three years rather than at the scheduled

maintenance. However, the commenter (IV-D-57) stated that

tanks that currently meet control standards may not have

substantial emissions reductions; therefore their reductions

may not offset the emissions from degassing and cleaning. The

commenter (IV-D-57) recommended allowing tanks that meet a

certain level of control to delay compliance with the NESHAP

until the scheduled maintenance date.

Several commenters (IV-D-19, IV-D-21, IV-D-25, IV-D-44)

stated that the 3-year compliance schedule would be cost

prohibitive. One commenter (IV-D-25) estimated that it would

cost from $167,000 to $323,000/Mg ($151,500 to $293,000/ton)

of HAP to meet the subpart Kb rim seal requirements, including

the degassing, cleaning, and inspection costs associated with

a 3-year compliance time. Two commenters (IV-D-21, IV-D-25)

contended that, as an option above the floor, this would not

be cost effective. One commenter (IV-D-44) asserted that the

3-year compliance schedule was a needless burden which would

control small risks.

One commenter (IV-D-11) referenced cost estimates made by

API showing that upgrading internal floating roof tanks

storing gasoline to NSPS subpart Kb rim seal requirements

would result in a cost-effectiveness ranging from $170,000 to
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$320,000/Mg ($151,500 to $293,000/ton) of HAP reduced. The

commenter (IV-D-11) stated that the costs did not include

disruptions to operations that could occur from forcing tanks

to adhere to a 3-year compliance schedule. Based on these

estimates, the commenter (IV-D-11) concluded that there was no

justification for requiring a 3-year compliance on internal

floating roof tanks storing gasoline.

Several commenters (IV-D-09, IV-D-11, IV-D-19, IV-D-22,

IV-D-25, IV-D-51) argued that a 3-year compliance schedule

would disrupt gasoline and fuel supplies to the public because

the refinery MACT compliance period overlaps with RFG

implementation. The commenters (IV-D-09, IV-D-11, IV-D-22,

IV-D-25 and IV-F-1, IV-D-51) explained that refiners subject

to RFG requirements will have additional oxygenated and

reformulated gasoline grades that will add to the number of

products handled at many refineries, thereby compounding the

storage tank availability problem. One commenter (IV-D-25 and

API hearing/transcript) stated that having different

compliance times based on vapor pressure would cause

complications for refineries that frequently change crude oil

sources and change the feedstock they store in their tanks. 

Several commenters (IV-D-06, IV-D-11, IV-D-25, IV-D-51)

noted that the 3-year compliance schedule in the proposed

refinery MACT overlaps with the HON, the gasoline distribution

NESHAP, and many new State rules. These commenters (IV-D-06,

IV-D-11, IV-D-25, IV-D-51) asserted that the result of having

so many overlapping compliance schedules will be that there

will not be enough trained and capable fabricators and

contractors to support tank modification work. 

Several commenters (IV-D-20, IV-D-42, IV-D-50 and IV-F-1)

urged the rule to be revised to allow small refineries to make

required tank modifications and upgrades during scheduled
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maintenance. Two commenters (IV-D-20, IV-D-50 and

Hearing/Ensign) stated that the proposed 3-year storage tank

compliance schedule is beyond the reach of small refineries to

comply with without adversely affecting fuel supplies to the

general public. The commenters (IV-D-20, IV-D-50 and IV-F-1)

said this would be consistent with the HON rule.

Additionally, one commenter (IV-D-50) provided the

following reasons for not supporting the proposed 3-year

storage tank compliance schedule: 1) small refineries have

twice as many tanks to retrofit as the industry at large,

2) heavy summer/winter demand because of vacationers,

3) temporary product shortages and subsequent price increases

sometimes occur, and 4) for refineries located in colder

climates, tank modifications can only be done during warmer

months. One commenter (IV-D-46) did not support an extension

of the compliance period for storage vessels beyond the three

years required in the proposed rule. The commenter (IV-D-46)

provided that the New Source Permitting Review in Texas rarely

allows more than three years to commence installation of

pollution controls equipment.

Response: The EPA recognizes the concerns of the

commenters and has revised the final rule to allow some

storage vessels to comply with the rule 10 years after

promulgation or at the next inspection period. A study of the

emissions from degassing and cleaning storage vessels was

analyzed using theoretical models developed by the EPA. The

analysis showed that significant emissions of HAP's occur from

degassing and cleaning activities such that the emissions

cannot be balanced in a reasonable amount of time for floating

roof vessels by the emission reductions from complying with

subpart Kb without fittings. The analysis also showed that

emissions from degassing and cleaning fixed roof vessels could
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be balanced under one year by the emission reductions from

complying with subpart Kb without fittings. Based on the

results of this analysis, the compliance time requirements

have been modified for floating roof vessels to be within

10 years or at the next inspection and maintenance activity,

whichever comes first. The compliance for fixed roof vessels

is still 3 years unless a compliance extension is obtained

under sec. 112 (i)(3)(B) of the Act.

6.5 WORDING OF STORAGE VESSEL PROVISIONS

Comment: One commenter (IV-D-25) suggested clarification

of the provisions for guide poles for new storage tanks. The

commenter (IV-D-25) suggested requiring a pole wiper, which

they characterized as a new control technique that goes beyond

the requirements of HON and subpart Kb, and is cost effective. 

The commenter (IV-D-25) also recommended that pole sleeves be

allowed as an option to provide flexibility.

Response: The EPA is evaluating the use of polewipers

and pole sleeves. After review, if the EPA has determined

that these controls are appropriate, revisions to the NSPS to

allow them will be proposed.

Comment: One commenter (IV-D-21) pointed out that

§ 63.646 as written required covers, lids, rim vent spaces and

automatic bleeder vents closed at all times. The commenter

(IV-D-21) assumed that the EPA meant these requirements to

only apply to Group 1 storage vessels and suggested that this

be clarified.

Response: The commenter is correct. The final rule has

been clarified to only require covers, lids, rim vent spaces

and automatic bleeder vents closed at all times for Group 1

storage vessels.
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Comment: One commenter (IV-D-25) stated that the

approach of cross-referencing the HON storage provisions and

then listing modifications and exceptions was confusing.

Response: The EPA recognizes the HON is a large and

complex rule. The EPA decided to cross reference the refinery

rule requirements to the HON as well as the Benzene Waste

NESHAP to reduce repetition in the rule and the size of the

rule. The EPA contends that cross-referencing allows the rule

to be more easily read and is not a burden on sources. 

However, the EPA has further clarified and simplified the

requirements in the final rule by providing clarifying

language where necessary, and by providing tables summarizing

the recordkeeping and reporting requirements.

7.0 WASTEWATER PROVISIONS

7.1 DEFINITION OF WASTEWATER

Comment: One commenter (IV-D-21) suggested that "feed"

be deleted from "feed tank drawdown" in the definition of

wastewater.

Response: The term "feed tank drawdown" used in the

definition for wastewater is used as an example of a

wastewater stream. This does not mean that any other type of

tank drawdown is not a wastewater. Because the commenter
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feels that this would add some clarity to the rule, this

change has been made.

Comment: One commenter (IV-D-29) suggested that all

wastewater systems in refineries handling only heavy crude oil

be exempt because they do not have significant VOC emissions,

especially small refineries.

Response: The EPA contends that the exemption provided 

for refineries with a TAB less than 10 Mg (11 tons) allows

refineries without significant wastewater HAP or VOC emissions

to be exempt from this regulation. Because composition and

emissions from heavy crude oil vary from refinery to refinery,

the EPA is continuing to base exemptions on quantifiable

parameters (i.e., flow rate and concentration) as used in the

BWON.

Comment: One commenter (IV-D-51) stated that Group 1 and

Group 2 wastewater emission points are referenced in

§ 63.640(l)(2)(ii) but are not included in the definitions

in § 63.641. The commenter (IV-D-51) recommended correcting

this problem.

Response: The final rule clearly distinguishes

requirements for Group 1 and Group 2 wastewater streams, and

also provides separate definitions for them. The term

"emission point" is also defined to mean an individual process

vent, storage vessel, wastewater stream, or equipment leak. 

Thus, a Group 1 emission point includes a Group 1 wastewater

stream.

7.2 IMPACTS ANALYSIS

7.2.1 Database

Comment: One commenter (IV-D-29) suggested that the EPA

review its database for heavy oil refineries regarding

wastewater streams and the controls already imposed on them. 
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Response: The database did consider controls in place at

heavy oil refineries. Many heavy oil refineries, which tend

to be small refineries and which would be expected to have

lower emissions of benzene and other HAP relative to fullrange crude oil refineries, may be exempt from this regulation

due the 10 Mg (11 tons) TAB criterion. Additionally, this

regulation does not impose any further control than already

required by the BWON; neither does this regulation exempt a

refinery from current applicable requirements of other rules,

including the BWON.

7.2.2 Cost Impacts

Comment: One commenter (IV-D-49) urged the EPA to use

the actual compliance costs associated with the Benzene Waste

NESHAP. The commenter (IV-D-49) stated that the EPA estimated

capital costs to be $250 million, but that actual costs were

approximately $2 billion, almost 10 times the EPA estimate. 

Another commenter (IV-D-25, IV-F-1) stated that control

experience shows that cost-effectiveness of wastewater control

options above the floor are higher than EPA estimated. The

commenter (IV-D-25) used data from 9 companies on the costs of

complying with the benzene NESHAP. The commenter (IV-D-25)

found control cost effectiveness in the range of $2,000/Mg

($1,800/ton) to $1,200,000/Mg ($1,088,500/ton) of BTEX for

individual control options within each refinery, and costs

from $2,500 to $1,500,000/Mg ($2,270 to $1,361,000/ton) of

BTEX for the 9 refineries as a whole. The commenter (IV-D-25)

also noted that costs are likely to be higher for facilities

with low initial TAB ($100,000 to $1,000,000/Mg ($90,700 to

907,100/ton) of HAP). Two commenters (IV-D-25 and IV-D-49)

cited the following as reasons their cost analysis results in

higher numbers than the EPA's analysis:
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C it is based on real-life costs incurred by existing

facilities,

C the amount of benzene and HAP emissions that would be

controlled at the nine refineries is lower than EPA

might estimate, because some control and recycling is

already in place, and the uncontrolled streams have

lower emissions, 

C control options other than steam strippers were

examined by the commenter.

One commenter (IV-D-06) added that the total cost of

compliance, including drain and sewer sealing, waste treatment

units, vapor control devices, monitoring, reporting and

administrative costs is double that of the EPA's estimate. 

Response: The MACT floor level of control for the

refinery wastewater stream component of the source-wide floor

was determined to be control equivalent to the BWON. The EPA

cannot legally require control that is less stringent than the

MACT floor. Based on the EPA's current cost estimating

approach, the EPA determined that controls more stringent than

the BWON would not be cost effective.

7.2.3 Emissions Impacts

Comment: One commenter (IV-D-49) stated that it appears

that the EPA is over-estimating HAP emissions from petroleum

refinery wastewater operations in a manner similar to the

over-estimate made for the Benzene Waste NESHAP.

Response: Emission estimates were developed based on

section 114 questionnaire responses, 90-day BWON reports and

equilibrium calculations. The EPA has endeavored to use

actual operating data whenever possible. When estimates and

assumptions were required, sound engineering judgement and

accepted practices were employed. The EPA contends that the

emissions estimates developed are quite representative of
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typical conditions and should more closely approximate actual

conditions due to the data from industry surveys.

7.3 SELECTION OF MACT FLOOR AND MACT FOR WASTEWATER

7.3.1 Use of Benzene as a Surrogate

Comment: One commenter (IV-D-19) agreed with the

1/4 ratio for the relationship of benzene to other HAP's that

the EPA determined. One commenter (IV-D-52) disagreed with

the ratio, stating that the concentration ratio of benzene to

other HAP's may differ greatly in various wastewater streams. 

The commenter (IV-D-52) was concerned that for streams with

low benzene loading but high loading of other HAP's, those

HAP's will be unregulated.

Response: For emissions and cost estimating, ratios of

benzene concentration to HAP concentration were developed for

wastewater streams from various process units. The ratios

were developed from section 114 questionnaire responses and

90-day BWON reports and are reflective of actual reported

wastewater stream concentrations. Based on these data,

wastewater from petroleum refinery process units, except for

product blending and MEK dewaxing units, have a HAP-to-benzene

ratio about 4 to 1. Product blending and MEK dewaxing units

have higher HAP-to-benzene ratios. For product blending,

however, the levels of HAP and benzene are relatively low with

this unit contributing less than one percent of the total HAP

emissions (including benzene). For MEK dewaxing units, MEK is

added; therefore, the 4-to-1 HAP-to-benzene ratio does not

appropriately represent this unit. However, the benzene

concentration from these units is greater than 10 ppmw;

therefore, the streams would be controlled, making the HAP-tobenzene ratio irrelevant.

Comment: Several commenters (IV-D-06, IV-D-15, IV-D-22,

IV-D-25 and IV-F-1, IV-D-30, IV-D-36, IV-D-38, IV-D-44,
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IV-D-51) supported the EPA's conclusion that benzene is a good

surrogate for other volatile HAP's in refinery process unit

wastewater. One commenter (IV-D-25) referred to EPA analyses

in the docket to support this position. The commenter

(IV-D-25) stated that uncontrolled HAP in refineries

controlled by the benzene waste NESHAP, and HAP in refineries

exempt from the benzene waste NESHAP, are "insignificant."

One commenter (IV-D-46) disagreed with using benzene as a

surrogate for other HAP's in wastewater. The commenter

(IV-D-46) contended that using benzene only does not define

the components of a wastewater stream. Additionally, the

commenter (IV-D-46) claimed that benzene has a short residence

time and may give a lower than actual organics concentration. 

The commenter (IV-D-46) stated that if benzene is used as a

surrogate for other HAP's in wastewater, no definition of a

wastewater stream's components will be available to determine

the hazard of the mixture so that it could be included in

emissions averaging. Additionally, the commenter (IV-D-46)

pointed out that no information would be available on the

stream's non-organic HAP content. The commenter (IV-D-46)

provided that the State of Texas requires an accurate

inventory of emissions for public disclosure and assessing

fees.

Response: The EPA believes that benzene is an acceptable

surrogate for predicting the presence of other HAP's in

petroleum refinery wastewater streams. The EPA used the

available technical information, within time and resource

constraints, to develop an organic HAP-to-benzene ratio for a

certain limited number of model streams where data on the

presence of all organic HAP's were not available. For the

purpose of assessing nationwide emissions and control options-

-including the floor--this approach adequately characterizes
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the wastewater stream. The EPA would like to emphasize that

the HAP-to-benzene ratio does account for the presence and

emissions of other organic HAP's and that this relationship

was developed at the point of generation of the wastewater

streams before losses could occur. Docket item II-B-10

contains additional information on benzene as a surrogate. 

Additionally, this regulation does not mandate that emissions

averaging be used. If an owner or operator elects to use

emissions averaging, further testing on wastewater streams

will be required. The EPA also has no data to indicate that

inorganic HAP's are emitted to the atmosphere from petroleum

refinery wastewater streams.

Comment: One commenter (IV-D-52) suggested that the EPA

select 5 to 10 compounds to represent groups of HAP's with

similar characteristics because they felt that benzene loading

is not a comprehensive indicator of all HAP emissions from

wastewater treatment at a refinery. The commenter (IV-D-52)

continued that chemically and structurally benzene is quite

different from HAP's which are aliphatics and those which have

chloride and nitro groups. 

Response: The EPA contends that benzene is an acceptable

surrogate for HAP's in petroleum refinery wastewater streams. 

As stated in the preamble, data shows that the HAP compounds

found in petroleum refinery wastewater are very similar in

structure and volatility to benzene. The EPA points out that

the predominant HAP's found in petroleum refinery wastewater

are benzene, toluene, ethylbenzene and xylene, none of which

have chloride or nitro groups. The data contained in the

section 114 questionnaire responses confirms the EPA's

conclusion that there is a strong correlation between benzene

and the other organic HAP's.
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7.3.2 Selection of the Wastewater Component of the 

 Source-Wide MACT Floor

Comment: Five commenters (IV-D-30, IV-D-33, IV-D-36) 

(IV-D-38, IV-D-44) supported the use of the benzene waste

NESHAP's control strategy as an appropriate floor for

wastewater HAP's. One commenter (IV-D-49) recommended that

the MACT floor for wastewater operations not be more stringent

than the Benzene Waste Operations NESHAP.

One commenter (IV-D-44) claimed that the Benzene Waste

Operations NESHAP is more stringent than the refinery MACT

floor needs to be. However, the commenter (IV-D-44) still

endorsed the selection as MACT floor because it is in place

and risk analysis does not justify any new controls.

Response: The wastewater component of the source-wide

MACT floor was developed using data in 90-day BWON reports. 

The approach followed the requirements established by the

Clean Air Act. The EPA contends that the BWON is the

wastewater component of the source-wide floor and represents

the average emission limitation achieved by the best

performing 12 percent of existing sources. In fact, more than

12 percent of existing sources are complying with the BWON.

7.3.3 Selection of MACT for Wastewater Streams Requiring

 Control

Comment: Several commenters (IV-D-06, IV-D-10, IV-D-11,

IV-D-22, IV-D-42, IV-D-50, IV-D-51, IV-F-1) supported the

Benzene Waste NESHAP as the MACT standard for wastewater HAP

emissions. The commenters (IV-D-06, IV-D-11, IV-D-10,

IV-D-22, IV-D-51) asserted that control beyond the BWON is not

cost-effective. Four commenters (IV-D-19, IV-D-33, IV-D-36,

IV-D-38) expressed support for API's study concluding that

controls above the BWON floor are cost ineffective and are

actually higher than the EPA estimated. 
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One commenter (IV-D-06) stated that the drain controls

specified in the BWON are appropriate and no additional

benefit would be gained by imposing stricter drain control

standards. One commenter (IV-D-20) agreed with the EPA that

the controls required by Benzene Waste Operations NESHAP also

control other HAP in wastewater streams present at petroleum

refineries.

Two commenters (IV-D-21, IV-D-19) concluded that the

uncontrolled emissions remaining after applicable refineries

achieve the BWON level of control would be insignificant and

therefore it would not be cost effective to control beyond the

BWON level of control.

One commenter (IV-D-48) demanded wastewater controls at

all facilities. The commenter (IV-D-48) cited the EPA as

stating that 43 percent of refineries are controlled to the

level required by the BWON. The commenter (IV-D-48) concluded

that more than 12 percent of the sources are controlled. The

commenter (IV-D-48) stated that the EPA must also require

emission reductions from wastewater streams in facilities not

required to be controlled to the level required under the

BWON. Another commenter (IV-D-53) disagreed with the EPA's

determination that the BWON, which includes the 10 Mg

(11 tons) TAB applicability cutoff, should be existing source

MACT. The commenter (IV-D-53) asserted that the control

requirements of the BWON without the 10 Mg (11 tons) TAB

cutoff (control Option 1 above the floor) should be existing

source MACT. The commenter (IV-D-53) contended that the BWON,

with the 10 Mg TAB cutoff, is less stringent than the average

emissions limitations achieved by the best performing

12 percent of existing sources because, based on the EPA's

analysis, more than 12 percent of existing sources achieve the

emissions limitation required by the BWON. One commenter
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(IV-D-36) supported the application of the proposed regulation

to only refineries with a TAB of 10 Mg (11 tons) or greater. 

One commenter (IV-D-52) recommended that the benzene loading

limit be lowered from the proposed 10 Mg/year (11 tpy) to

1 Mg/year (1.1 tpy) to reduce other HAP's along with benzene.

Response: The exemption from the wastewater provisions

for refineries with a TAB less than 10 Mg (11 tons) was

determined to be the wastewater component of the source-wide

MACT floor. The 43 percent of refineries that are controlled

have TAB greater than 10 Mg (11 tons). No information is

available that indicates that refineries with TAB less than

10 Mg (11 tons) are controlled to the same level; thus control

of such refineries is not part of the floor. Also, there is

no information that the top 12 percent of the refineries

control benzene wastes to less than 10 Mg (11 tons). The

analyses concluded that the cost of control of going beyond

the floor (e.g., controlling refineries with less than 10 Mg

(11 tons) TAB) is unreasonable. The commenters did not

provide additional data to support their positions, therefore,

the EPA has no basis for lowering or removing this criterion.

Comment: One commenter (IV-D-53) disagreed with the

EPA's determination that the BWON with the 10 Mg (11 tons)

benzene applicability cutoff is new source MACT. The

commenter (IV-D-53) asserted that the control requirements of

the BWON without the 10 Mg (11 tons) benzene cutoff (Option 1)

is new source MACT. The commenter (IV-D-53) argued that the

only refinery in Wisconsin will be required (by 1995) to

control HAP emissions from wastewater units in a manner

essentially equivalent to the BWON. The commenter (IV-D-53)

stated that before the proposed regulation is promulgated, an

existing facility will be achieving an emissions limitation

that is lower than the current definition of new source MACT. 
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The commenter (IV-D-53) cited the 1990 Amendments as requiring

a new source standard to be at least as stringent as the best

performing source. The commenter (IV-D-53) provided a copy of

Wisconsin's wastewater control requirements.

Response: The EPA has reviewed the emission limitations

to be imposed on the facility and has found them to be no more

stringent than those required by the BWON. As argued by the

commenter, the specific emission suppression and control

techniques for waste management units are the same as under

the BWON. Although the commenter did not supply sufficient

data to support the claim that the 10 Mg (11 tons) TAB cut-off

should not apply to new source MACT, the EPA was still able to

examine the applicability requirements of the controls to be

put in place. Based on the available data, the applicability

of such requirements is not more strict than the BWON. 

Exemption levels from streams at the refinery in question are,

in fact, more lenient than exemption criteria in the BWON;

therefore, the requirements in question do not form the basis

of new source MACT.

7.3.3.1 Selection of Wastewater Streams Requiring

Control.

Comment: Two commenters (IV-D-13, IV-D-57) recommended

that a more stringent limit of 5 ppmw of VOC in wastewater be

required for existing and new sources. One commenter

(IV-D-13) contended that under the AQMD rule 1176 if the VOC

content of the inlet liquid to a sump or wastewater separator

is 5 ppmw or more, the equipment should be subject to control

requirements.

Response: The EPA holds firm in its position that

applicability determinations for wastewater emission controls

under the NESHAP program must be made at the point of

generation before concentrations possibly become reduced from
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dilution or volatilization. Concentration measurements made

at the sump may be subject to these limitations, especially

given the variability of collection sewer configurations from

refinery to refinery. Even the use of a lower threshold

concentration (e.g., 5 ppmw) would not necessarily achieve a

more stringent or even a consistent MACT control level across

all subject refineries because of the inherent wastewater

system differences.

7.3.3.2 Selection of MACT Technology.

Comment: One commenter (IV-D-36) requested that air

stripping be allowed as an alternative to steam stripping. 

The commenter (IV-D-36) contended that air stripping can be an

effective means of HAP reduction as well as provide

significant cost and energy savings.

Response: This regulation does not restrict petroleum

refineries to steam stripping as the only acceptable control

technology for wastewater emissions. Any technology that

meets the reduction requirements of the regulation is

acceptable.

7.4 COMPLIANCE DEMONSTRATION FOR WASTEWATER

Comment: One commenter (IV-D-36) requested clarification

that reduction of TAB to below 10 Mg (11 tons) is an

acceptable level of control for MACT compliance. The

commenter (IV-D-36) requested clarification regarding the

timing of TAB reduction required for MACT compliance.

Response: If a source has already reduced its TAB to

less than 10 Mg (11 tons) for compliance with the BWON, then

that source is, in fact, achieving the MACT requirements of

this regulation.
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8.0 EQUIPMENT LEAKS PROVISION

8.1 DEFINITION OF EQUIPMENT LEAKS

Comment: One commenter (IV-D-40) requested clarification

of the term "tubing" used in the refinery regulation. The

commenter (IV-D-40) stated that it should be stated in the

rule that "tubing" means pipe, and that construction of piping

standards normally specify "seamless" or "welded" tubing with

certain wall thicknesses, welding techniques, etc.

Response: The term "tubing is not used in the refinery

rule. However, it is part of the definition of hard-piping in

the HON, which is referenced throughout the refinery rule. 

The EPA would like to clarify that the term hard-piping in the

HON has been corrected to mean piping or tubing that is

manufactured and properly installed using good engineering

standards, such as ANSI B31-3. The EPA considers this

correction to specify requirements for piping and tubing.

Comment: Two commenters (IV-D-09, IV-D-10) supported

changing the definition of light liquid. One commenter

(IV-D-10) asserted that the definition of light liquid service

should be consistent with NSPS subpart GGG, that is "equipment

in light liquid service if the percent evaporated is greater

than 10 percent at 150 oC (302 oF) as determined by ASTM

Method D-86." The commenter (IV-D-10) stated that this

definition would facilitate the use of the ASTM test data when

the vapor pressure data are not available, and be consistent
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with other rules. Another commenter (IV-D-09) supported

changing the definition because refineries have distillation

information but rarely have detailed speciation data to

satisfy the current definition. The commenter (IV-D-09) also

stated that the cost of running ASTM methods for distillation

is usually much less than running a complete GC/MS analysis to

speciate the stream.

Response: The EPA agrees with the commenters and has

decided to revise the definition of light liquid to crossreference the NSPS subpart GGG definition.

Comment: One commenter (IV-D-57) recommended clarifying

whether measurements at the interface of equipment refers to

touching the component or as close as possible to the

component. The commenter (IV-D-57) expressed concern that

industry sources believe interface to mean 1 cm (0.39 in) away

from the component. The commenter (IV-D-57) also stated that

usage of the 1993 correlation equations emissions with the

1 cm (0.39 in) interface measurements may understate emissions

by a factor between 2 and 7. The commenter (IV-D-57)

recommended defining the term interface and include a maximum

allowable stand-off from the component. The commenter

(IV-D-57) recommended 1 cm (0.39 in) as the limiting distance,

and also recommended that any correlation equations published

by the EPA be based on the 1 cm stand-off.

Response: The EPA does not consider it necessary to

specify the leak measurement distance. The rule references

Method 21 as the basis for measuring emissions. Method 21

specifies that measurements with a hydrocarbon analyzer be

made at the interface, i.e., 0 cm from the leak, unless the

monitored equipment has moving parts. If the equipment has

moving parts, such as a pump or compressor, a farther distance

is allowed for safety reasons. 
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The EPA would also like to clarify that all correlation

equations and emission factors developed by the EPA were based

on measurements at a 0 cm distance from the leak.

Comment: One commenter (IV-D-22) requested that the EPA

define "in organic service" to be consistent with the HON.

Response: The EPA has revised the final rule to include

"in organic HAP service" in order to reduce confusion in the

rule.

Comment: One commenter (IV-D-30) requested an

explanation of what an "agitator" in a petroleum refinery is.

Response: The proposed rule required affected sources to

comply with the requirements of § 63.169 of subpart H. The

requirements in this section apply to equipment in heavy

liquid service, and agitators. Agitators are primarily used

for mixing in batch operations. These type of operations are

not typical in petroleum refineries. The final rule clarifies

that affected sources must comply with § 63.169 of subpart H,

except for the agitator provisions. 

Comment: One commenter (IV-D-25) suggested the

definition of "process unit shutdown" be changed so that

unscheduled events that stop production for less than 72 hours

are not considered shutdowns. The commenter (IV-D-25) stated

that a longer time than 72 hours would be required to safely

make repairs when working with high temperature and high

pressure refinery equipment. Another commenter (IV-D-21)

agreed with the definition of "process vent shutdown".

Response: The definition of "process unit shutdown" is

taken from subpart H of this part, and includes the following

language: " Process unit shutdown is a work practice or

operational procedure that stops production from a process

unit or part of a process unit during which it is technically

feasible to clear process material from a process unit or part
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of a process unit consistent with safety constraints and

during which repairs can be affected." This language allows

sources to not make a repair even if more than 24 hours have

elapsed if they can show that it is not technically feasible

or safe to make the repair. Until more detailed information

is received that shows why a change is needed, EPA does not

believe that it would be appropriate to revise the definition

as suggested.

Comment: One commenter (IV-D-21) pointed out that the

phrase "organic monitoring device" was not used in the

proposal and suggested that it be deleted from the

definitions. The commenter (IV-D-21) requested that if the

phrase is not deleted, gas chromatographs should also be

listed, as they work under the same principles.

Response: The commenter is correct. "Organic monitoring

device" was defined in the proposed rule, but never used in

the provisions. The EPA deleted the phrase from the final

rule.

8.2 EMISSION CONTROL TECHNOLOGY (GENERAL)

Comment: One commenter (IV-D-47) requested that EPA

consider revising Method 21 specifications to allow trial of

newer and better adapted leak detection technologies. The

commenter (IV-D-47) contended that OVA's do not perform well

at concentrations levels of 1,000 and 500 ppm. The commenter

(IV-D-47) specifically stated that at these concentrations,

the OVA readings become unstable and are not reproducible

because variations in sample intake may occur and because

leaks are not well-mixed systems. The commenter (IV-D-47)

stated that the solution to this problem is to allow the use

of leak sensing equipment whereby the leak sensing element is

brought into close proximity to the leak rather than conveying

escaped gas from the leak to the leak sensor by means of a
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sample pump. The commenter (IV-D-47) stated that this would

result in a zero sample intake rate, which results in

accurate, reproducible, and reliable test results, and will

also reduce the variations in test results caused by wind and

operator technique. The commenter (IV-D-47) supplied results

of an experiment demonstrating variability in sample intake. 

The commenter (IV-D-47) provided an example of a zero intake

leak sensing device.

Response: The EPA recognizes that there are a variety of

combinations of sampling and analytical methods that can be

used to detect leaks, some of which will be more sensitive to

small leaks than others. Method 21 is not limited to one

detection principle, but to change Method 21 in the manner

suggested by the commenter could affect the stringency of the

standard, and thus would not be acceptable. The commenter is

referred to the General Provisions (40 CFR part 63,

subpart A), which provides a mechanism for requesting an

alternative monitoring method, and to Method 301, which

discusses requirements for validating alternative testing or

monitoring techniques.

Comment: One commenter (IV-D-44) suggested that a

provision similar to the one set forth in § 63.177 be included

to allow alternative means of leak detection approved by the

EPA to be utilized. Two commenters (IV-D-19, IV-D-25)

requested that the refinery NESHAP be changed to incorporate

the "alternative means of emission limitation" provisions in

§§ 63.177, 63.178, and 63.179 of HON in order to allow

flexibility.

Response: The EPA would like to clarify that §§ 63.177

through 63.179 of subpart H do not involve the monitoring

instrument alternative standards. Sections 63.177 through

63.179 provide alternative standards for batch operations,
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building controls, and provide a mechanism for either a

manufacturer of equipment or sources to petition for

alternative standards. The General Provisions (40 CFR

part 63, subpart A) already provides opportunity for alternate

means of emission limitation; therefore, referencing these

sections from subpart H is not necessary. However, in order

to clarify any confusion that may arise, the EPA has decided

to reference §§ 63.177 and 63.179 of subpart H. Section

63.178 was not included because it applies to batch processes. 

The EPA does not consider batch processes to be applicable to

the refining industry.

8.3 IMPACTS ANALYSIS

8.3.1 Cost Impacts

Comment: One commenter (IV-D-22) contended that the cost

estimate for equipment leaks was flawed. The commenter

(IV-D-22) objected that an option above the floor requiring

more stringent control was determined to be less costly than

the floor. The commenter (IV-D-22) stated that in developing

costs, the EPA substituted a fivefold increase in repairs and

the potential for a threefold decrease in monitoring for the

provisions of the petroleum refinery NSPS floor. The

commenter (IV-D-22) asserted that because the negotiated rule

has a leak definition that is 5 times stricter than the NSPS

the chance for reduced monitoring will be eliminated. 

Therefore, the commenter (IV-D-22) argued that such provisions

must necessarily require more frequent repairs than the

petroleum refinery NSPS and cannot be less expensive than the

NSPS. The commenter (IV-D-22) concluded that because costs

have been erroneously estimated, the EPA has not met the

statutory requirement of considering cost for above the floor

options.
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Response: The EPA used the best information available to

estimate costs. Cost information was obtained from surveys

sent to equipment leak control vendors and refineries, and

previously developed costs presented in the Equipment Leaks

Enabling document. If cost information were supplied by

commenters, the EPA would consider this new information to

reassess its costs. No information was provided by the

commenter. 

However, the EPA agrees that enough question in the

emissions estimate exists, and therefore the credit from

controlling emissions, due to possible overestimates from the

equipment leak emission factors that Option 1 may not be a

better option. Therefore, the final rule allows sources to

comply with the requirements in subpart VV (equivalent to the

petroleum refinery NSPS [40 CFR part 60, subpart GGG]) or

Option 1, the negotiated rule without connector monitoring. 

The selection of the alternative is left to the owner or

operator and can be revised in each permit renewal.

Comment: One commenter (IV-D-50 and IV-F-1) stated that

many small refineries have not been required to implement LDAR

programs and they do not have expertise in setting up and

operating such programs. The commenter (IV-D-50) explained

that small refineries will experience high LDAR compliance

costs compared to the industry at large because of high startup costs, less computer applications, and poorer economies of

scale. The commenter (IV-D-50 and IV-F-1) estimated that the

first year costs associated with implementing and operating a

LDAR program for a small refinery would be approximately onehalf million dollars. The commenter (IV-D-50 and IV-F-1)

added that small refineries will incur additional costs to

install required computer applications associated with LDAR

programs. The commenter (IV-D-50) went on to say that a small
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refinery will incur higher LDAR costs than a large facility on

a per barrel basis, because both facilities will have a

similar number of points to monitor and maintain, but the

small refinery will have fewer barrels in which to allocate

LDAR costs.

Response: The EPA agrees that controlling equipment

leaks at small refineries may be less cost-effective than at

large refineries. The EPA examined the possibility of

subcategorizing small refineries to determine if a different

MACT floor level of control for equipment leaks could be

developed. MACT floors were analyzed for various crude charge

capacity cutoffs (10,000; 20,000; 30,000; 40,000; 50,000; and

60,000 bbl/sd), refinery ozone attainment status, and based on

the types of products at each refinery. The results of the

analysis showed that no significant changes from the equipment

leaks component of the source-wide MACT floor, the petroleum

refinery NSPS equipment leaks program (40 CFR part 60,

subpart GGG), would occur for small refineries. Therefore,

all refineries are subject to the control equivalent to the

petroleum refinery NSPS level of control. The EPA did revise

the final rule to address concerns of small refineries

regarding the cost of establishing the program by removing the

criteria to have 1/3 of the refinery comply within 6 months

after promulgation, 2/3 of the refinery comply within

12 months after promulgation, and the entire refinery comply

within 18 months after promulgation. The final rule requires

the entire refinery to comply with the standard within 3 years

after promulgation. The EPA believes this extra time will

benefit small refineries and refineries that have never

implemented an equipment leaks program by allowing sufficient

time to establish and properly operate a leak detection

program.
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8.3.2 Emission Impacts

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-11,

IV-D-12, IV-D-22, IV-D-25 and IV-F-1, IV-D-51) contended that

the equipment leak provisions were not cost-effective because

the EPA's emission factors significantly overestimate

emissions, and therefore, emission reductions. Three

commenters (IV-D-09, IV-D-22, IV-D-25) explained that a

recently published API study undermines the theoretical basis

of the negotiated rule, resulting in equipment leak fugitive

emissions being overestimated by as much as a factor of 10. 

Two commenters (IV-D-25, IV-D-51) noted that the EPA adopted a

new set of equipment leak emission factors and correlation

equations for petroleum refineries, but did not use these new

correlation equations and emission factors to determine costeffectiveness of the equipment leak provisions. Two

commenters (IV-D-09, IV-D-25) concluded that the result is

that the cost-effectiveness is in actuality $15,000/Mg

($13,600/ton) of HAP vs the EPA's estimate of $1,500/Mg

($1,360/ton) of HAP. Therefore, one commenter (IV-D-09)

stated that it is obsolete to control equipment leak fugitives

by means of traditional leak detection and repair programs. 

One commenter (IV-D-51) contended that using the updated

equations and factors would show that controls more stringent

than the proposed rule cannot be justified. One commenter

(IV-D-30) stated that the new fugitive emission factors for

equipment leaks developed by API are more reflective of

current technology and operating practices.

Several commenters (IV-D-13, IV-D-16, IV-D-34, IV-D-57)

did not support the use of new AP-42 correlation equations for

equipment leaks. Three commenters (IV-D-13, IV-D-34, IV-D-57)

raised a number of concerns with the new equations, including:

sample population being too small, not a representative
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sampling of component sizes, pressures, and temperatures. One

commenter (IV-D-34) stated that they provided comments to the

EPA on June 21, 1994, on a 1993 study that the equations are

based on. Two commenters (IV-D-13, IV-D-57) added that

adoption of these revisions in conjunction with the NESHAP may

pressure air agencies in California to abandon a stringent,

cost-effective method of controlling emissions. 

Response: The EPA would like to clarify that the

equipment leak data that are being used to estimate the costs

and emission reductions of the equipment leak rules were

developed in 1980. The data provided in 1993 by API cannot be

used to revise the factors because two sets of information are

needed. These include the amount of emissions generated per

piece of equipment leaking at a given concentration and the

percent of equipment that are actually leaking at these

concentrations. The 1980 study that was used to estimate the

impacts of the refinery MACT rule used a consistent sampling

methodology to address both of these factors based on sampling

at uncontrolled refineries. The 1993 American Petroleum

Institute (API) study developed new information only on

emissions per piece of leaking equipment using a different

methodology. As stated in API's report, this information was

developed from refineries in California for use with other

information to estimate facility-specific equipment leak

emissions. The EPA used the API data to revise the equipment

leak correlation equations and default zero emission rates. 

EPA could not revise the average equipment leak factors for

refineries because percent leaking data were not provided. 

The EPA also believes it would be inappropriate to combine the

1993 information with the 1980 data to develop new emission

estimates because the sampling methodologies were different

and it is not clear that it is appropriate to use information
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from well controlled refineries to estimate emissions from

facilities that have never been subject to a leak detection

and repair program. Therefore, the 1993 study data was not

used to revise the emission estimates.

The EPA recognizes that new correlation equations

developed for the refining industry indicate that the refinery

factors may overestimate emissions, which may make the

negotiated rule (without connector monitoring) costineffective. This cannot be accurately determined because the

appropriate information to update average emission factors is

not available. The EPA recognizes that enough uncertainty

exists in the emission and cost estimates to question the

results of the cost-effectiveness analysis. In recognition of

this uncertainty and to provide compliance flexibility, the

EPA has changed the final rule to provide each existing

refinery with a choice of complying with either: (1) 40 CFR

part 60 subpart VV, or (2) the negotiated rule without

connector monitoring. Although not required in the final

rule, the EPA promotes use of the negotiated rule without

connector monitoring because it is believed to provide

considerable product, emissions, and cost savings to a

refinery. 

8.4 SELECTION OF MACT FLOOR AND MACT (GENERAL EQUIPMENT

LEAKS)

Comment: One commenter (IV-D-29) suggested that the EPA

exempt equipment already controlled by VOC regulations.

Response: The EPA agrees in general that it may be very

burdensome for sources to be subject to several equipment leak

regulations with similar, but not identical, requirements. In

an effort to reduce the burden, the EPA has provided in

subpart H that compliance with that rule will constitute

compliance with any overlapping NSPS or NESHAP. In addition,
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on April 10, 1995 EPA proposed amendments to subpart H to

allow an owner or operator to elect to comply with subpart H

for all VOC containing equipment in lieu of compliance with

subpart VV, GGG, or KKK of part 60. For owners or operators

who elect to comply with subpart VV instead of subpart H of

part 63, there will be only one Federal program and

overlapping requirements should not be an issue.

Comment: One commenter (IV-D-29) asserted that all

equipment in contact with heavy oil should be exempt from the

equipment leaks provisions, including recordkeeping

requirements, because the VOC emissions are insignificant.

Response: The EPA disagrees with the commenter. Heavy

oil that leaks and mixes with water may be a source of

significant emissions. The EPA considers the requirements for

components in heavy liquid service to be minimal.

Comment: Two commenters (IV-D-36, IV-D-38) supported the

exclusion of equipment in contact with material containing

less than 5 percent HAP's. One commenter (IV-D-36) requested

that it be clarified that this is an option and equipment in

contact with less than 5 percent HAP's may be included if it

is more convenient. The commenter (IV-D-36) explained that

many existing leak monitoring programs include all components

containing material lighter than kerosene and requiring a

different accounting would be extremely burdensome.

Response: The EPA thanks the commenters for their

support. The five percent value is the minimum concentration

of HAP's that the EPA considers to indicate a stream in HAP

service. A source may chose to include streams that are less

than 5 percent HAP in the monitoring program.
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8.4.1 Selection of MACT Floor

Comment: Two commenters (IV-D-36, IV-D-44) supported the

use of petroleum refinery NSPS levels as the MACT floor. One

commenter (IV-D-44) argued that petroleum refinery NSPS should

be adopted as MACT floor for administrative simplicity. The

commenter (IV-D-44) also alleged that the risk analysis does

not support a more stringent level of control than the

petroleum refinery NSPS standards. The commenter (IV-D-44)

stated that compliance with the NSPS standards and HON should

be considered compliance with the leak detection provisions of

the proposed regulation and wording should be added to the

regulation to make this clear.

Response: The refinery MACT standard is not based on

risk, but the statutory criteria required in the Act. The Act

requires that the floor be determined based on the average

emissions limitation achieved at the best-controlled

12 percent of sources. The EPA's MACT floor analysis

indicated that the equipment leak component of the source-wide

MACT floor is control equal to the petroleum refinery NSPS

(40 CFR part 60, subpart GGG). As stated earlier, due to the

uncertainty in the impacts analysis and to provide compliance

flexibility, the EPA has changed the final rule to provide

each existing refinery with a choice of complying with 40 CFR

part 60 subpart VV (which is equivalent to 40 CFR part 60,

subpart GGG) or the negotiated rule without connector

monitoring provisions.

Comment: Two commenters (IV-D-22, IV-D-42) requested the

development of a separate MACT floor for equipment leaks at

small refineries, in which the floor should not exceed the

petroleum refinery NSPS requirements. Several commenters

(IV-D-12, IV-D-22, IV-D-42) stated that compliance with the

NSPS would be less burdensome than compliance with the
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proposed refineries NESHAP. Two commenters (IV-D-12, IV-D-42)

supported longer initial compliance periods for the proposed

rule (18 months) and supported requiring the NSPS control with

a 3 year compliance time for small refineries since short-term

initial compliance for small refineries, which do not have an

LDAR system, would be infeasible.

Two commenters (IV-D-22, IV-D-44) explained that the best

equipment leak controls, which will set the MACT standard,

will be found at large refineries located in the worst ozone

attainment areas. However, the commenters (IV-D-22, IV-D-44)

stated that these refineries do not accurately reflect the

best controls found in small refining companies or refineries

located in ozone attainment areas. One commenter (IV-D-22)

added that LDAR programs are non-existent at small refineries

and at many refineries located in ozone attainment areas. The

commenter (IV-D-22) claimed that small refineries in

nonattainment areas produce heavier petroleum products such as

fuel oils, lubes, or asphalt, which are generally not included

in LDAR that focus on light liquid streams. Therefore, the

commenter (IV-D-22) supported extended compliance times to

help many small refineries and refineries located in

attainment areas digest significant start-up costs associated

with LDAR.

Another commenter (IV-D-57) asserted that there should be

no difference in equipment leak requirements for small and

large refineries. 

Response: The EPA would like to clarify that the

equipment leaks component of MACT floor analysis predicates

that refineries control equipment leaks at least to the

petroleum refinery NSPS (40 CFR part 60, subpart GGG) level of

control. As discussed in section 4.0 of this document, EPA

examined the question of whether subcategorization would
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result in significantly different requirements for small

refineries. In this analysis, the EPA analyzed the equipment

leak component of the source-wide MACT floor for various crude

charge capacity cut-offs and determined that no significant

changes from the NSPS equipment leaks program would occur for

small refineries (refineries under 10,000 bbl/sd to

50,000 bbl/sd of crude). Therefore, all refineries are

subject to control equivalent to the NSPS level of control.

The EPA agrees that small refineries may not have the

experience to implement an LDAR program for equipment leaks in

a short time-frame without significant expense. The EPA also

contends that other refineries that do not currently have LDAR

programs may also have trouble implementing the rule in 6 to

18 months. In response to these comments, the EPA has changed

the final rule to require that all refineries, regardless of

size, comply with a LDAR program with the same leak definition

and monitoring frequency as 40 CFR part 60 subpart VV (which

is equivalent to 40 CFR part 60, subpart GGG) within 3 years

after promulgation of the rule; there will not be interim

deadlines during the 3-year period by which portions of the

refinery are required to comply during this time. A refinery

that chooses to comply with the modified negotiated rule must

then implement Phase II within 4 years and Phase III

5 1/2 years after promulgation of the rule. A refinery that

chooses to comply with subpart VV would continue to implement

that program.

Comment: Two commenters (IV-D-13, IV-D-57) contended

that the since more than 12 percent of refineries are located

in the Bay Area and South Coast Area in California, and these

regions have the most stringent equipment leaks regulations in

the nation, the EPA should adopt the requirements from these

regions as MACT floor for existing and for new equipment. One
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commenter (IV-D-13) asserted these leak standards include not

allowing leaks to exceed 1,000 ppm measured at a source, i.e.,

0 cm from the source or up to 1 cm (0.29 in) away from the

source if 0 cm reading is impractical. The commenter

(IV-D-13) asserted that the AQMD's best available control

technology both for VOC and toxics require all new valves and

flanges less than 5.08 cm (2 in) in diameter to be leakless.

One commenter (IV-D-57) stated that use of special seals

should not release the source from performing at least annual

inspection of pumps. The commenter (IV-D-57) added that

equipment leaks from new process units should be subject to

more stringent I&M and LDAR than existing sources. The

commenter (IV-D-57) stated that valves and connectors should

meet monthly I&M with LDAR at 100 ppm with one cm stand-off,

because there are refinery processes in the Bay Area that

currently meet this level. Additionally, the commenter

(IV-D-57) asserted that new pumps and compressors should meet

quarterly I&M with LDAR at 500 ppm measured at 1 cm (0.39 in).

Response: The equipment leak component of the sourcewide MACT floor for existing sources was developed based on

the best available data, which was the data provided in the

section 114 and ICR questionnaire responses. The MACT floor

analysis at proposal was based on equating control information

reported on the questionnaires to the control effectiveness of

Federal programs on a model refinery. This method may have

underestimated the control efficiency at some sources that had

lower leak definitions and had higher equipment counts than

those in the model refinery. In order to correct these

oversights, the equipment leaks component of the source-wide

floor was revised to include the effect of actual equipment

counts and leak definitions. The results of the revised
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analyses showed that the existing source floor is still

control equal to the control required by the NSPS.

Both the proposal and revised floor analysis were

determined using a broad definition of source (i.e., the

collection of all leaking equipment at a refinery). The EPA

believes that the commenters view is based on a narrow

definition of affected source. The EPA contends that when the

total effect of the South Coast and Bay Area rules are

analyzed on a refinery, including all the exemptions, these

rules are not more stringent than the MACT floor level of

control.

The EPA's position was arrived at from a study that

compared the overall control efficiency of the Bay Area and

South Coast equipment leaks rules, and subpart VV. Average

leak rate equations, leak frequencies, and equipment leak

control efficiencies presented in the Equipment Leaks Protocol

Document were used to estimate overall efficiency of

controlling equipment leaks from a refinery. The results of

the comparison showed that the control efficiency for

refineries complying with the South Coast or Bay Area

regulations was similar to the control efficiency for

refineries complying with the requirements in 40 CFR part 60

subpart VV. Within, the accuracy of this analysis, the EPA

considered the control effectiveness of the South Coast, Bay

Area, and subpart VV to be equivalent in most cases.

Regarding one commenter's (IV-D-57) concern for the need

for annual inspection of sealless pumps, the EPA believes that

the rule does require this. The EPA did not adopt the

suggestions of other commenters that the rule require new

sources to install "leakless" valves and connectors. As

discussed in previous rulemakings, information available to

EPA shows that "leakless" equipment can have significant
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emissions when failures occur and this equipment is not

available for all situations in refinery operations. The

commenters did not provide any information that indicated that

this equipment is available and suitable for installation in

new refinery operations.

Comment: One commenter (IV-D-57) asserted that equipment

leaks must be subject to I&M no less frequently than

quarterly. The commenter (IV-D-57) stated that a study showed

that quarterly I&M decreases emissions by 50 to 60 percent

from I&M performed annually. The commenter (IV-D-57) added

that by allowing I&M frequency to decrease biannually, the EPA

provides for a substantial number of components to remain

leaking for up to 2 years, which is 8 times longer than what

is allowed in the Bay Area or South Coast. The commenter

(IV-D-57) recommended the EPA only allow less frequent I&M

only when the previous 3 inspections found components in

compliance with a more stringent leak definition (1,000 ppm)

or when a greater percentage are in compliance, (e.g., fewer

than 0.25 percent leaking instead of 0.5). The commenter

(IV-D-57) stressed that under no circumstances should I&M be

performed less frequently than annually.

Response: The EPA disagrees with the commenters

conclusion. The EPA believes that there is a trade-off

between emissions reductions and inspection frequency. In

examining the appropriateness of the HON valve standards to

refinery operations, the EPA considered whether to extend some

of the concepts of the negotiated valve standard to the valve

and pump standards for refineries. The negotiated valve

standard included incentive provisions to encourage better

performance and two forms of penalty options to consider

differences among the facilities ability to undertake a

quality improvement program. The EPA determined that the
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continuous use of better performing equipment, i.e., equipment

that does not leak at the low leak definitions of Phase III,

would result in lower emissions than more frequent monitoring

of the equipment. After considering the predicted differences

in effectiveness of different monitoring intervals for pumps,

the EPA also concluded that an incentive for better

performance could be included in the pump standard and still

assure better emission performance. Therefore, the proposed

rule and the final refinery standard allow a QIP for both

valves and pumps in Phase III.

8.4.2 Selection of MACT

Comment: One commenter (IV-D-50 and IV-F-1) commended

the EPA for proposing to extend the equipment leak compliance

time by 18 months to help small refineries implement programs,

but encouraged the EPA to further extend the compliance time

to the 3 year period allowed under section 112.

 Two commenters (IV-D-45, IV-D-50 and IV-F-1) supported

the maximum 3 year LDAR implementation time to achieve

compliance with the petroleum refinery NSPS level of control. 

One commenter (IV-D-10) added that the EPA should provide the

full 3 year compliance period for the equipment leaks

provisions to all refineries. The commenter (IV-D-10)

contended that the cost of implementing and complying with the

rule will be as much for large refineries as small ones. Two

commenters (IV-D-45, IV-D-50, and IV-F-1) believed that the

small refinery LDAR requirements should be based on the

petroleum refinery NSPS requirements instead of the negotiated

rule. One commenter (IV-D-45) stated that they use in-place

state-of-the-art hydrocarbon gas detection systems and high

quality standard procedures for maintenance and repair and

included (in Appendix C of their comment) the results of

fugitive testing at their units.
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Response: The EPA would like to clarify that the

equipment leak component of the source-wide MACT floor

analysis predicates that refineries control equipment leaks to

a level of control equal to the petroleum refinery NSPS

(40 CFR part 60, subpart GGG). The EPA analyzed the

equipment leak component of the source-wide MACT floor for

various crude charge capacity cut-offs and determined that no

significant changes from the petroleum refinery NSPS equipment

leaks program would occur for small refineries (refineries

under 10,000 bbl/sd to 50,000 bbl/sd of crude). Therefore,

all refineries are subject to control equivalent to the

petroleum refinery NSPS level of control.

The EPA agrees that small refineries may not have the

experience to implement an LDAR program for equipment leaks in

a short time-frame without significant expense. The EPA also

contends that other refineries that do not currently have LDAR

programs may also have trouble implementing the rule in 6 to

18 months. Furthermore, special consideration could provide

small refineries with unfair competitive advantage over large

refineries. In response to these comments, the EPA has

changed the final rule to require that all refineries,

regardless of size, comply with a LDAR program with the same

leak definition and monitoring frequency as 40 CFR part 60

subpart VV (which is equivalent to subpart GGG) within 3 years

after promulgation of the rule. At the end of the third year

the entire refinery must be in compliance with the level of

control specified in subpart VV; there will not be interim

deadlines during the 3-year period by which portions of the

refinery are required to comply during this time. A refinery

that chooses to comply with the modified negotiated rule must

then implement Phase II within 4 years and Phase III

5 1/2 years after promulgation of the rule. 
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Comment: One commenter (IV-D-48) recommended that the

EPA adopt the numerical standards negotiated for the HON for

the equipment leaks provisions. The commenter (IV-D-48)

alleged that these standards are achievable and that adopting

identical provisions will make compliance and enforcement

simpler. The commenter (IV-D-48) stated the proposed

equipment leaks provisions are weaker than the HON provisions. 

The commenter (IV-D-48) asserted that the equipment leaks

standard involves enforceable maximum achievable emission

limitations. The commenter (IV-D-48) listed several specific

recommendations to strengthen the equipment leaks provisions. 

One commenter (IV-D-57) contended that the standards for

leaking valves and connectors should be set at 500 ppm. The

commenter (IV-D-57) disagreed with the EPA's conclusion that

technology is not available for refineries to meet the same

stringent standards required under the HON. The commenter

(IV-D-57) stated that in the Bay area all refineries meet a

500 ppm leak definition and by 1997 some refineries will be

required to meet 100 ppm definition. The commenter (IV-D-57)

stated that in the South Coast a leak definition of 1000 ppm

measured at 0 cm is equivalent to 500 ppm measured at 1 cm. 

The commenter (IV-D-57) asserted that the EPA should

explicitly chose one standard and specify a screening

distance. 

One commenter (IV-D-54) expressed disappointment at the

equipment leaks provisions because the leak definition is too

high. The commenter (IV-D-54) contended that the EPA should

require a leak definition of 500 ppm, as Texas has done in its

MID program, rather than the 2,000 ppm that is currently in

the rule. The commenter (IV-D-54) contended that a leak

definition of 2,000 does not provide adequate protection for a
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community and also does not consider the clusters of petroleum

refineries around a community.

Another commenter (IV-D-19) expressed appreciation for

the consistency demonstrated by using subpart H of the HON as

a framework for the equipment leaks section and the effort

made to differentiate refineries from chemical plants. 

Another commenter (IV-D-11) agreed that the EPA has made

reasonable adjustments to the negotiated rule to be applicable

to refineries which affords refineries some flexibility. 

One commenter (IV-D-29) contended that a 10,000 ppm TOC

emissions standard leak definition is sufficient for existing

refineries. The commenter (IV-D-29) claimed that a stricter

standard will force equipment replacements or facility

shutdowns.

Response: The final rule allows refineries to comply

with either subpart VV (which is equivalent to the petroleum

refinery NSPS [40 CFR part 60, subpart GGG]) or the modified

negotiated regulation. The leak definition for subpart VV

equipment leaks is 10,000 ppmv. The leak definition levels

prescribed in the proposed rule, and in the modified

negotiated regulation option, were developed based on the

standards in the HON. Process streams in the SOCMI industry

have a higher concentration of HAP's than streams in

refineries. In order to provide a comparable control level

for the refinery industry, the HON leak definitions were

adjusted based on the stream composition information available

to the EPA.

Comment: One commenter (IV-D-22) objected to a 1000 ppm

valve standard because the EPA's own analysis shows that no

refinery out of a list of 134 achieves an equipment leak

control efficiency greater than that of the petroleum refinery

NSPS. The commenter (IV-D-22) admits that one State has a
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leak definition at that level. However, the commenter

(IV-D-22) asserted that the existence of a standard in a

single State proves neither its technical feasibility, its

cost-effectiveness, nor its equivalency to the statutory

definition of a MACT floor.

One commenter (IV-D-09) contended that the EPA should

focus on restructuring the equipment leak provisions to

concentrate on the rapid repair of gross emitters, i.e., those

equipment components that leak relatively large amounts. The

commenter (IV-D-09) stated that refineries agreed that it was

appropriate to adopt the structure of the negotiated rule, but

not necessarily the numerical standards.

Response: The EPA considers the proposed rule to focus

on the largest emitting equipment: pumps in light liquid

service, compressors, and valves in light liquid and gas

service. The baseline emissions analysis indicates that over

80 percent of the emissions are from these pieces of

equipment. The promulgated rule limits emissions from these

components by over 70 percent.

Comment: One commenter (IV-D-22) opposed using the

negotiated rule in the refinery MACT because it was based on

another proceeding to which the commenter was not included. 

Therefore, the commenter (IV-D-22) claimed that the EPA's use

of the negotiated rule ignores both applicable administrative

and due process requirements. Two commenters (IV-D-45,

IV-D-50 and IV-F-1) stated that even though the EPA has

indicated that the petroleum refinery NSPS represents the MACT

floor for equipment leaks, a more stringent approach was

negotiated with API, who represents large refineries.

Response: The EPA views the negotiated regulation as

another existing equipment leak control program, and, as such,

it can be included in the impacts analysis. The fact that no
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refinery is currently complying with it is not relevant

because it is an option above the floor level of control. 

Proposal of this option was based on the finding that it will

achieve additional emissions reductions in a cost effective

manner. The proposal of the refineries MACT allowed ample

opportunity for comments to be submitted and considered in

promulgating the final standards. No administrative or due

process requirements have been violated.

The HON was not developed exclusively from negotiations

with API. The refining industry, represented by API,

participated with representatives from the chemical industry

in developing the negotiated regulation for equipment leaks,

which was used in the HON. The HON equipment leak provisions

were developed with the understanding that the refining

industry is not included in the HON equipment leaks standard. 

Additionally, the equipment leak provisions in the refinery

MACT standard are not the same as the HON provisions; they

have been modified to apply to the refining industry. The

commenter's non-participation in the regulatory negotiation

for equipment leaks is not relevant to this rulemaking.

8.5 EQUIPMENT - SPECIFIC PROVISIONS

8.5.1 Pumps in Light Liquid Service

Comment: One commenter (IV-D-25) supported the Phase III

leak definition for pumps (2,000 ppm) in the proposed refinery

NESHAP, which is higher than in the HON rule. The commenter

(IV-D-25) claimed the HON approach of using one level for the

leak definition and another to trigger repair requirements for

pumps is complicated, would achieve little HAP emission

reduction, and would not be cost effective.

Two commenters (IV-D-22, IV-D-44) suggested that the

definition for pump leaks should be 10,000 ppm, the petroleum

refinery NSPS standard leak definition, instead of 2,000 ppm. 
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One commenter (IV-D-22) objected to the 2,000 ppm leak

definition for pumps because the technology may not perform in

the same manner in all situations. The commenter (IV-D-22)

asserted that there is no justification for extending an

isolated performance level to all process services as an

enforceable standard. The commenter (IV-D-22) argued that EPA

admits that the risk from HAP emissions is very low in the

base case before implementing controls. Given this fact, the

commenter (IV-D-22) stated that it does not make any real or

measurable difference to the risk by imposing a standard of

10,000 ppm instead of 2,000 ppm. The commenter (IV-D-22)

added that given the low risk, industry should be given the

choice as to whether to install single or dual seal pumps and

whether or not to monitor.

Response: The final rule allows owners or operators the

option of complying with subpart VV (which is equivalent to

the petroleum refinery NSPS) or modified subpart H equipment

leak standards. Subpart VV has a leak definition of

10,000 ppmv.

The EPA disagrees that the 2,000 ppmv leak definition in

the modified subpart H cannot be met. Based on information

used to develop previous regulations, the EPA believes that a

2,000 ppmv leak definition can be met with existing control

technologies for pumps, such as dual or mechanical seals. The

EPA would like to clarify that the equipment leak provisions

are work practices. The standard requires repair of leaking

pumps exceeding the leak definition, and exceedences are not a

violation by themselves.

The EPA would also like to clarify that the MACT

standards were based on the statutory criteria. The Act

specifically requires EPA to set technology-based rather than

risk-based standards when developing the MACT standards. The
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residual risk of the rule will be analyzed 8 years after the

MACT standards have been promulgated.

Comment: One commenter (IV-D-48) supported the inclusion

of pumps in light liquid service and heavy liquid service. 

The commenter (IV-D-48) demanded that if the EPA concludes

that reductions in emissions from this equipment is not

achievable, it must provide an explanation based on evidence

in the record.

Response: Equipment in light liquid service and heavy

liquid service are both regulated in the equipment leak

provisions. 

Comment: Several commenters (IV-D-21, IV-D-22, IV-D-25,

IV-D-42) stated that reciprocating pumps in light liquid

service should be excluded from the equipment leaks provisions

because these pumps are designed to leak small amounts for

lubricating purposes, and no available packing technology can

effectively reduce levels to 2000 ppm. One commenter

(IV-D-25) added that retrofitting reciprocating pumps with

secondary seals can be very costly or infeasible depending on

the design and dimensions. The commenter (IV-D-25) added that

they did not know of any data for setting a reasonable

standard. Two commenter (IV-D-21, IV-D-22) added that

reciprocating pumps are used infrequently and usually only for

maintenance activities. Three commenters (IV-D-22, IV-D-25,

IV-D-42) also contended that for the same reasons,

reciprocating compressors should be excluded from the rule. 

 Another commenter (IV-D-57) asserted that reciprocating

pumps and compressors should be regulated because they are

sources of substantial emissions. One commenter (IV-D-46)

noted that the State of Texas makes no distinction between

reciprocating pumps and others in light liquid service subject

to LDAR requirements. The commenter (IV-D-46) acknowledged
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that reciprocating pumps are more difficult to make leak free,

but argued that this is made up for by the fact that there

tend to be far fewer in a refinery. The commenter (IV-D-46)

recommended that reciprocating pumps not be exempted.

Response: The EPA contends that reciprocating pumps are

sources of emissions that cannot categorically be exempted

from the rule. However, the EPA agrees that replacing

reciprocating pumps may be costly. Therefore, the final rule

exempts reciprocating pumps in heavy liquid service, and in

light liquid service if recasting the distance piece or

reciprocating pump replacement is required. This exemption is

consistent with the MACT floor.

Comment: One commenter (IV-D-10) contended that the

provision in § 63.648 allowing quarterly monitoring for pumps

if the percent leak rate is less than 3 percent of pumps or

one pump is not clear as to when such monitoring may start. 

The commenter (IV-D-10) recommended that quarterly monitoring

of pumps may begin in Phase I if leak rate frequency is met. 

Response: The EPA has clarified that the QIP for pumps

begins in Phase III of the rule. This is consistent with the

valve monitoring QIP requirements. The rule does not preclude

an owner or operator from complying with the Phase III leak

provisions earlier. If the owner or operator wishes to

monitor pumps and valves less frequently earlier than 2000,

the owner or operator will need to have the monitoring data to

show that they are meeting the percent leaking pumps criteria.

Comment: One commenter (IV-D-10) stated that leak rate

triggers for pumps should be clarified by allowing a choice

between the percentage of pumps or the specified number of

pumps. 

Response: The purpose of allowing a specified number of

pumps leaking rather than a percentage of pumps is for cases
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when a limited number of pumps exist such that the percentage

of pumps specified would allow less than one pump leaking. 

For example, if there are fewer than 33 pumps at a facility,

the percent leaking pumps allowed to conduct quarterly

monitoring would be less than one. The EPA rounded this

number to the next highest integer, i.e., one. The EPA does

not consider it appropriate to allow owners or operators to

choose between a specified number of pumps and the percent

leaking pumps. In situations other than the one described,

the specified number will always be less than the number of

pumps calculated from the percent leaking pumps. The EPA does

not consider it appropriate to allow a less stringent

requirement. Therefore, the pump provisions qualify the

choice between the percent leaking criteria and the specified

number by requiring the owner or operator to choose whichever

is the greater number.

8.5.2 Compressors

Comment: One commenter (IV-D-46) contended that

compressors in light liquid service are easily maintained by

leak prevention repairs and are controlled by venting to

control devices and should not be exempt from the equipment

leaks provision.

Response: The EPA would like to clarify that:

(1) compressors are not used for light liquids, but only to

provide motive force for gaseous fluids, and (2) the proposed

rule does not exempt compressors. Compressors are required to

be controlled with a closed-vent system or be equipped with

mechanical seals that meet the criteria of the rule. The EPA

also disagrees with the commenters opinion that compressors

should be part of a LDAR program. It is not feasible to

require an LDAR program for compressors because compressor

leaks cannot be repaired easily and may require removing the
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component from service. Additionally, monitoring compressors

may pose a safety risk because the area of the leak contains

moving parts.

8.5.3 Sampling Connection Systems

Comment: One commenter (IV-D-10) recommended that

sampling valves and sampling connectors be excluded from

applicability because they already have self-closing plugs

that contribute only de minimis emissions.

Response: The sampling connection provisions apply to

the sample purge which occurs when sampling is done. The

presence or absence of plugs is not relevant. The EPA

requires that the purge be captured and returned to the

process, or destroyed.

8.5.4 Valves in Gas/Vapor and Lines in Light Liquid Service

Comment: Several commenters (IV-D-10, IV-D-11, IV-D-25,

IV-D-38) noted that the preamble indicates that in calculating

percent leaking valves, up to 1 percent of valves per year to

a maximum of 3 percent of valves may be excluded if they are

non-repairable. Three commenters (IV-D-10, IV-D-25, IV-D-38)

believed this provision had been inadvertently omitted from

the proposed regulation and suggested regulatory wording to

include it. Another commenter (IV-D-11) contended that the

provision for nonrepairable valves and connectors in the HON

should also be included in the refinery MACT standard because

refinery turnaround schedules typically are longer than those

of chemical plants. Therefore, the commenter (IV-D-11) stated

that it makes sense to include the HON provisions in the

manner discussed in the preamble. One commenter (IV-D-38)

provided specific language for this provision to be added to

§ 63.648.

Response: The final rule has been corrected to include

language that allows exclusion of up to a maximum of 3% of the
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valves from the percent leaking valve calculation. The EPA

would also like to clarify that the non-repairable valve

provisions are only applicable to refineries complying with

the modified subpart H requirements, and do not apply to the

subpart VV equipment leak requirements.

Comment: The commenter (IV-D-25) supported the Phase II

and III leak definitions (1,000 ppm) and benchmark performance

levels (percent leaking equipment) selected for valves in the

proposed refinery NESHAP. The commenter (IV-D-25) reasoned

that the selection of different levels than the HON is

justified because refinery processes have larger equipment,

have longer run times between turn-arounds, and cannot achieve

the same average leak rates as chemical plants. They

(IV-D-25) stated that a leak definition of 500 ppm would

result in minimal HAP reductions and would not be cost

effectiveness. One commenter (IV-D-44) suggested that the

definition for valve leaks should be 10,000 ppm, the petroleum

refinery NSPS standard leak definition, instead of 2,000 ppm.

One commenter (IV-D-22) opposed the 1,000 ppm leak definition

for valves because the EPA does not demonstrate that this

requirement meets the statutory criteria in 112(d)(3)(A). The

commenter (IV-D-22) stated that Texas and Louisiana's recent

requirements for LDAR programs cannot be used in the analysis

because they were promulgated within the last 18 months. The

commenter (IV-D-22) asserted that choosing the 1,000 ppm

standard because it can be reliably implemented and is

achievable is not the statutory requirement which the EPA must

apply.

The commenter (IV-D-22) added that the proposed standard

imposes a penalty QIP for poor performance and makes good

performance harder to achieve and higher repair costs

inevitable by reducing the leak definition by a factor of 10.
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Response: The EPA would like to clarify that in the

final rule, owners or operators are only required to comply

with the equipment leak standards of subpart VV (which is

equivalent to the petroleum refinery NSPS [40 CFR part 60,

subpart GGG)]; however, the EPA allows owners or operators the

option to comply with a modified version of subpart H instead

of subpart VV. Subpart VV has a leak definition of

10,000 ppmv. Refineries that choose to comply with the

modified subpart H must meet the leak definitions specified in

the rule. The EPA disagrees with the commenters who contended

that lower leak definitions should not used because they were

taken from standards that were promulgated within the last

18 months. The leak definitions at proposal have been used at

several facilities in Texas since the late 1980's, and thus

before the 18 month limitation. In addition, the leak

definitions were part of an option above the floor level of

control. The EPA selected this option at proposal after

considering the statutory criteria (emission reduction, cost,

or other impacts).

Comment: One commenter (IV-D-21) stated that it is

unclear when an owner/operator must elect to comply with the

percent leaking calculation basis in the valve standard. The

commenter (IV-D-21) supported the interpretation that the

decision can be made at any time. Additionally, the commenter

(IV-D-21) stated that facilities will not have enough

information initially to determine which valve monitoring

program to select. The commenter (IV-D-21) suggested that the

EPA, rather than making this a one-time decision, allow

facilities to change the basis infrequently, perhaps once per

year with a notification of the change three months prior.

Two commenters (IV-D-20, and IV-D-25) requested that the

requirement in § 63.648(d) to choose whether to calculate
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percent leakers on a facility or process unit basis be

required before entering the first monitoring period of

Phase III because fugitive sources are required to be

monitored on a quarterly basis up until Phase III requirements

become applicable.

Response: The final rule clarifies when owners or

operators are required to comply with Phase III of the valve

requirements. The final rule specifies that facilities

complying with the optional connector monitoring requirements

and the reduced valve monitoring frequency comply in

Phase III. The rule does not preclude an owner or operator

from complying with the Phase III leak definitions earlier. 

If the owner or operator wishes to monitor pumps and valves

less frequently or use the connector monitoring option earlier

than in Phase III, the owner or operator will need to show

that they have monitoring data that qualifies them for less

frequent monitoring. The rule also requires that owners or

operators shall decide no later than the first monitoring

period after Phase I whether to calculate the percentage of

leaking valves on a process unit or source-wide basis.

Because Phase I begins 3 years after promulgation of the

rule, the EPA believes that sufficient time has been allowed

for owners or operators to comply fully with the rule. The

EPA disagrees with the commenters' suggestion of allowing

facilities to change the percent leaking basis with a

notification of change, because there would be no guarantee

that a consistent program would be maintained or would not be

manipulated. The EPA has clarified in the final rule that

once owners or operators have decided to choose to calculate

percent leaking valves either source-wide or on a process unit

basis, all subsequent calculations shall be made on the same

basis unless a permit change is made.
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Comment: Two commenters (IV-D-10, IV-D-25) asserted that

the provisions for leaking valves in table 4 of subpart CC,

entitled "Valve Monitoring Frequency Alternatives" should be

corrected to show that for percent leaking valves greater than

5 percent, monthly monitoring or a QIP is allowed as an

option. 

Response: The EPA agrees with the commenter. The final

rule has been revised to reflect these changes.

8.5.5 Connectors in Gas/Vapor and Light Liquid Service

Comment: Several commenters (IV-D-09, IV-D-22, IV-D-25,

IV-D-31, IV-D-36, IV-D-38) supported the optional connector

monitoring program in the proposed rule. One commenter 

(IV-D-25) saw the proposed approach as being consistent with

common sense, E.Q. 12866, and statements by Carol Browner to

the effect of affording compliance flexibility. Two

commenters (IV-D-20, IV-D-25) added that a mandatory connector

LDAR program is likely to be costly and produce few HAP

emission reductions. 

One commenter (IV-D-49) claimed that scheduled testing of

connectors should not be required as part of a LDAR program

for fugitive emissions and that the requirement for connectors

should be no more burdensome than that contained in the NSPS. 

One commenter (IV-D-50 and IV-F-1) recommended limiting the

inclusion of connectors in LDAR programs. The commenter

(IV-D-50) stated that because connectors rarely leak, the

identification and monitoring of connectors represents an

inefficient and wasteful regulatory cost. The commenter

(IV-D-50) stated that LDAR programs for small refineries can

be made much more cost-effective if the EPA extends the

following proposed connector options to small facilities: 1) a

random 200 connector survey, 2) a connector inspection

program, and 3) the negotiated rule's connector program. One
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commenter (IV-D-31) disagreed with the position of the

Louisiana Department of Environmental Quality who is currently

attempting to impose a connector fugitive program in

Louisiana. The commenter (IV-D-31) stated that Louisiana has

not performed a cost benefit analysis to justify such a

program. 

One commenter (IV-D-19) stated that while they

appreciated the attempt at providing flexibility, they

questioned the wisdom of including a provision requiring the

monitoring of connectors. Even though the commenter (IV-D-19)

understands that the provisions are optional, they claimed

that connectors do not leak if installed properly. The

commenter (IV-D-19) contended that the program will not reduce

HAP emissions and was only included to pacify State agencies. 

The commenter (IV-D-19) concluded that there is no valid basis

for including or excluding connectors in a leak detection

program and therefore the percent leaking valve targets in

table 5 should remain as the required measures of success. 

The commenter (IV-D-19) suggested that § 63.649(b) and (c) be

stricken and the requirements of table 5 be incorporated as

the standard for compliance. One commenter (IV-D-57)

contended that connectors are a source of substantial

emissions at refineries and should not be excluded from a

stringent I&M and LDAR requirements. 

Response: The final rule requires that refineries meet

the equipment leak requirements in subpart VV; subpart VV does

not require connector monitoring. Connector monitoring is

only an option that may be chosen if the owner or operator

elects to comply with subpart H provisions and elects to use

the provisions of §63.648 (c)(2)(ii) for valve monitoring

rather than subpart VV. Because connector monitoring is only

an option, the EPA does not consider that any additional
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burden is placed on the industry. The connector monitoring

alternatives were included in the rule to allow owners or

operators the flexibility to combine State and Federal

regulations and avoid complying with multiple equipment leak

programs. The EPA also contends that the emission reduction

with the connector alternatives is essentially the same as

without the alternatives. Thus, the alternatives do not

decrease the emission reductions or stringency.

Comment: One commenter (IV-D-21) recommended that

connectors not be included with components subject to the

one-third or two-thirds compliance deadline. The commenter

(IV-D-21) claimed that if a source elects not to monitor

connectors or to monitor 200 random connectors, they would not

have a basis for estimating the total number of connectors.

Response: The final rule does not require that

compliance be phased-in. Instead, the entire refinery must be

in compliance with equipment leak provisions in subpart VV

(which is equivalent to the petroleum refinery NSPS [40 CFR

part 60, subpart GGG)] or a modified version of subpart H

within 3 years after promulgation of the rule. The connector

monitoring option of the modified subpart H is only applicable

if the owner or operator meets the performance levels

specified for Phase III. Phase III starts 5 1/2 years after

promulgation of the rule. The owner or operator may elect to

do connector monitoring options earlier if they can prove they

are meeting the Phase III performance requirements. The EPA

believes that these modifications will allow sufficient time

for refineries to establish and effectively operate leak

detection and repair programs.

Comment: One commenter (IV-D-21) requested that the

option to monitor leaking equipment on a process unit or
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source wide basis be extended to connectors whenever there are

percent leaking criteria.

Response: The final rule allows source-wide or process

unit wide calculation of percent leaking connectors. This is

only applicable for the connector inspection alternative or

the subpart H connector alternative. Once the owner or

operator has decided whether to calculate percent leaking

connectors on a process unit or source-wide basis, all

subsequent calculations shall be made on the source basis

unless a permit change is made.

Comment: One commenter (IV-D-21) stated that it is

unclear when an owner/operator must elect to comply with the

connector program. The (IV-D-21) supported the interpretation

of making this decision at any time. Two commenters (IV-D-10,

IV-D-25) suggested that the alternative connector monitoring

provisions begin in Phase III. One commenter (IV-D-25) added

that visual inspection could be done in Phases I and II, and

LDAR monitoring could be introduced in Phase III when a

control strategy is selected.

One commenter (IV-D-21) also suggested that the

requirement to elect a random 200 connector program 12 months

after promulgation be changed to 24 months. Additionally, the

commenter (IV-D-21) suggested that the EPA, rather than making

this a one-time decision, allow facilities to change the basis

infrequently, perhaps once per year with a notification of the

change three months prior.

Response: The final rule clarifies that the owner or

operator shall decide no later than the first monitoring

period after the Phase III compliance date which connector

monitoring alternative they will comply with. The owner or

operator may select the connector monitoring options earlier

than Phase III if they can prove they are meeting the
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Phase III performance criteria. The EPA has also specified in

the final rule that the Random 200 connector program be on a

source-wide basis in order to alleviate confusion.

The EPA disagrees with the commenters' suggestion of

allowing facilities to change the type of connector option

with a notification of change. The EPA contends that there

would be no guarantee that a consistent program would be

maintained or that the equipment leak provisions would not be

manipulated. The EPA has clarified in the final rule that

once the owners or operators have chosen a connector

monitoring option any election to change after the initial

election shall be treated as a permit modification according

to the terms of 40 CFR part 70.

Comment: One commenter (IV-D-21) recommended the

1 percent per year maximum for nonrepairable leaking

connectors be phased in to allow for problems implementing

monitoring programs in the first year. The commenter

(IV-D-21) suggested that the number of nonrepairable

connectors allowed during the first year be 2 percent and

1 percent the year after.

Response: The EPA contends that the commenter's

suggestion would add complexity and confusion to the rule

without providing much benefit. The EPA contends that

sufficient time has been allowed in the final rule for owners

or operators to establish a working leak detection and repair

program. The EPA would also like to clarify that the

connector monitoring alternatives are only an option, and are

not required by the rule. Therefore, the EPA chose not to

incorporate the commenter's suggestion in the final rule.

Comment: One commenter (IV-D-21) recommended that the

random 200 connector program be based on the source-wide

population of connectors as opposed to 200 random connectors
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per refinery or 200 random connectors per process unit. One

commenter (IV-D-22) agreed that testing of connectors should

not be required, but that it should be allowed as an option. 

The commenter (IV-D-22) supported either testing 200 randomly

selected connectors initially, with subsequent testing of

200 connectors on a frequency determined by the percent

leaking, or monitoring all connectors initially and again on a

frequency determined by the percent leaking. The commenter

(IV-D-22) supported testing of connectors on lines of 2" in

diameter or larger for the case when a facility chooses to

test connectors.

Another commenter (IV-D-10) recommended that the random

200 connector alternative be used with the owner or operators

discretion in the choice of the 200 connectors to be chosen

for each monitoring episode. The commenter (IV-D-10)

supported not tagging 200 connectors. The commenter (IV-D-10)

asserted that if the sample of 200 connectors can be selected

either the same or differently at the discretion of the owner

or operator for one monitoring episode to the next, then the

burden of tracking the connectors would be reduced without

sacrificing statistical validity.

Response: The final rule specifies that the Random 200

alternative be done on a source-wide basis. The EPA maintains

that a random sample is necessary in order to prevent

manipulation of the results. Therefore, the EPA has not

changed the random sampling requirements in the final rule in

the manner the commenter suggested.

8.5.6 Closed Vent Systems and Control Devices

Comment: One commenter (IV-D-06) contended that sample

valves and tank mixers on storage tanks are part of the tank

and should be exempt from equipment leak provisions. Two

commenters (IV-D-06, IV-D-25) asserted that converting sample
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valves on tanks to closed vent systems would be costly and

have a minimal impact on emissions. The commenters (IV-D-06,

IV-D-25) provided estimates of $5,000/tank or a total cost of

$500,000 for 100 tanks, at a cost-effectiveness of $15,000/Mg

($13,600/ton) HAP.

Response: The EPA agrees with the commenters. Tank

mixers and sample valves on storage tanks are not subject to

the equipment leak provisions in the refinery MACT rule.

8.5.7 Delay of Repair

Comment: One commenter (IV-D-48) recommended that to

determine if emissions from purged material resulting from an

immediate repair are greater than fugitive emissions from

delaying a repair one should compare the controlled purge

material to cumulative emissions from the leak assumed at the

intensity measured throughout the delay period. The commenter

(IV-D-48) also requested that the decision to delay repair be

documented. 

Response: The final rule references both subpart VV and

subpart H. Subpart VV and subpart H both describe procedures

for delay of repair and the required documentation. The EPA

does not consider it necessary to specify additional

requirements.

8.5.8 Quality Improvement Programs

Comment: One commenter (IV-D-48) noted that they

negotiated a QIP as an alternative to providing for a

violation every time a leak definition was exceeded as quid

pro quo for tougher leak definitions and frequent monitoring. 

The commenter (IV-D-48) reserved the right to raise legal

questions if the final rule does not match the HON rule.

Response: The refining industry, represented by API,

participated with representatives from the chemical industry

in developing the negotiated regulation for equipment leaks,
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which was used in the HON. The HON equipment leak provisions

were developed with the understanding that the refining

industry is not included in the HON equipment leaks standard. 

There is no obligation in this rulemaking to require the same

provisions as in the HON equipment leaks standard. Thus, the

proposed and final refinery NESHAP differs from the HON where

appropriate due to differences between refinery and chemical

plants.

8.5.9 Other

Comment: One commenter (IV-D-06) stated that because

maintenance on tank mixers is linked with taking tanks out of

service, tank mixers should not be treated as equipment leak

emissions. The commenter (IV-D-06) added that repair or

maintenance of tank mixers often requires dropping the tank

liquid level or taking the tank out of service, resulting in

an increase in cleaning and degassing emissions if the tank is

taken out of service before normally scheduled. The commenter

(IV-D-06) explained that the tank mixer needs to continue

operating until the tank is taken out of service to prevent

increased buildup of sludge in the tank, resulting in higher

emissions when the tank is cleaned. The commenter (IV-D-06)

recommended requiring maintenance on tank mixers during the

next scheduled time for taking the tank out of service. One

commenter (IV-D-25) argued that tank mixers, which are

installed in the side of the tank wall to maintain a

consistent liquid mixture throughout the tank, should not be

regulated under equipment leaks. The commenter (IV-D-25) said

that maintenance or repair of tank mixers often requires

taking the tank out of service, and should not be required any

sooner than the next scheduled time for taking the tank out of

service.
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Response: The EPA agrees with the commenter and the rule

has been revised to clarify this point.

Comment: One commenter (IV-D-21) requested that the

calibration levels from the HON be modified for leak

definitions in the proposed regulation. The commenter

(IV-D-21) stated that, preferably, all of the calibration

levels for the different leak definitions would be the same to

avoid recalibrating instruments. The commenter (IV-D-21)

suggested that the EPA allow calibration of instruments at

10,000 ppm or else 10,000 ppm as long as there are valves or

pumps in Phase I, 2,000 ppm when there are pumps in Phase II

and 1,000 ppm thereafter.

Response: The EPA has been working to clarify the

provisions in subpart H. The EPA proposed revisions to

§ 63.180 of subpart H on April 10, 1995, to address this

point. These modifications will be finalized well before

compliance date for the Refinery rule.

Comment: One commenter (IV-D-21) suggested that it be

clarified that the one-third (or two-thirds) criteria apply to

the source-wide population, whether the owner/operator elects

to comply on a source-wide or process unit basis. The

commenter (IV-D-21) pointed out that this would allow

flexibility for difficult to control process units. 

Additionally, The commenter (IV-D-21) claimed that assigning

components to units to determine if one-third or two-thirds of

the components are in compliance does not make sense if the

owner/operator elects to comply on a source-wide basis. The

commenter (IV-D-21) recommended that § 63.640(h)(3)(i) should

begin "At least one-third" and § 63.640(h)(3)(i) should begin

"At least two-thirds." Another commenter (IV-D-20) suggested

the addition of the word "approximately" in front of the 1/3

and 2/3 refinery components that must be in compliance with
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the rule, stating that the exact counts of fugitive sources

are not necessarily available and can easily change in a

6 month time period and that requiring exactly 1/3 or 2/3 will

result in increased recordkeeping that is not justified.

One commenter (IV-D-21) stated that facilities will not

have enough information six months after promulgation to elect

for either source-wide or process unit monitoring. The

commenter (IV-D-21) suggested that the EPA, rather than making

this a one-time decision, allow facilities to change the basis

infrequently, perhaps once per year with a notification of the

change three months prior. The commenter (IV-D-21) also

recommended that the instructions for calculating the

source-wide population of components be clarified to indicate

that estimates of counts are acceptable for components not in

the monitoring program until 18 months after promulgation.

Response: The final rule no longer requires phased-in

compliance. Instead, the entire refinery must be in

compliance with the control requirements of subpart VV within

3 years after promulgation of the rule. The final rule also

specifies that facilities complying with the optional

connector monitoring requirements, and the reduced valve and

pump monitoring frequency of the modified negotiated

regulation comply in Phase III. The rule also requires that

owners or operators shall decide no later than the first

monitoring period after Phase I whether to calculate the

percentage of leaking valves on a process unit or source-wide

basis. Because Phase I begins 3 years after promulgation of

the rule, the EPA believes that sufficient time has been

allowed for owners or operators to comply fully with the rule.

The EPA disagrees with the commenters' suggestion of

allowing facilities to change the percent leaking basis with a

notification of change, because there would be no guarantee
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that a consistent program would be maintained or would not be

manipulated. The EPA has clarified in the final rule that

once owners or operators have decided to choose to calculate

percent leaking valves or connectors either source-wide or on

a process unit basis, all subsequent calculations shall be

made on the same basis unless a permit change is made. The

EPA believes these changes simplify the rule and makes it

easier for all refineries to establish leak detection and

repair programs in order to reduce HAP and VOC emissions.

8.6 RECORDKEEPING AND REPORTING FOR EQUIPMENT LEAKS 

Comment: One commenter (IV-D-21) found the compliance

dates for equipment leaks unclear and difficult to meet. The

commenter (IV-D-21) asserted that more time will be required

to upgrade such equipment as agitators, sampling connection

systems, open-ended lines, surge control vessels, bottoms

receivers and instrumentation systems since these are not

normally monitored. The commenter (IV-D-21) made several

suggestions that they claimed would provide clarity and

flexibility. 

Response: The EPA contends that minimal upgrades are

required for the equipment listed by the commenter. 

Agitators, surge control vessels, and bottoms receivers are

not included in the equipment leak provisions of the Refinery

MACT rule. Instrumentation systems have minimal monitoring

requirements, and sampling connectors and open-ended lines

have minimal control requirements.

Comment: One commenter (IV-D-25) asserted that the

requirement in § 63.652(b) to comply with the HON subpart H

recordkeeping and reporting sections is too general, because

some portions of subpart H are not incorporated into the

petroleum refineries NESHAP. The commenter (IV-D-25)

suggested more detailed language or a table similar to table 5
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of the proposed rule to specify which HON recordkeeping and

reporting requirements apply to refineries.

Response: The final rule clarifies the recordkeeping and

reporting requirements of subpart H applicable to the refinery

rule. A table has also been provided in the final rule that

summarizes the applicable subpart H recordkeeping and

reporting requirements.

Comment: One commenter (IV-D-09) stated that the EPA

should exempt components covered by more stringent equipment

leak programs because recordkeeping and reporting requirements

are different or repetitive and mistakes in paperwork may

cause heavy liabilities. Another commenter (IV-D-22) stated

that the EPA should eliminate overlapping and duplicate

monitoring, testing recordkeeping and reporting requirements

by adding the same language to the applicability section last

that found in HON (40 CFR 63.160(b) and (c)).

Response: The EPA agrees with the commenters that

elimination of overlapping and duplicate recordkeeping and

reporting requirements is necessary to provide a clear and

understandable rule for owners and operators who must comply

with it. The final rule clarifies which recordkeeping and

reporting requirements are to be met when different equipment

leak regulations are applicable.

Comment: One commenter (IV-D-11) requested that the EPA

not require detailed documentation on connector location

because the work associated with the optional program is to be

random. The commenter (IV-D-11) stated that it was consistent

with common sense and Executive Order 12866.

Response: The EPA agrees with the commenter that

requiring detailed connector locations would be overly

burdensome and would not be very useful. The final rule

allows connectors to be identified by the area or length of
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pipe and need not be individually identified. The EPA

believes that this modification will reduce the burden on the

industry while maintaining necessary documentation to verify

compliance.

8.7 WORDING OF EQUIPMENT LEAKS PROVISION

Comment: One commenter (IV-D-21) suggested that

"indications of liquids dripping" in § 63.649(c)(4)

concerning connector inspections be replaced with "leaks" to

avoid the citation of oil stains as indications of liquids

dripping.

Response: The EPA has revised § 63.649(c)(4) in the

final rule to state that "a leak is detected if liquids are

observed to be dripping at a rate greater than three drops per

minute." This language is consistent with other sections of

the equipment leak provisions, and with other equipment leak

standards.

Comment: One commenter (IV-D-21) requested that "as

defined in § 63.174" be added to the last sentences of

§ 63.649(b) and (c) to provide clarification that the words

"inaccessible" and "unsafe-to-monitor" have been previously

defined.

Response: The EPA agrees with the commenter, and has

edited the rule as suggested.

Comment: One commenter (IV-D-21) found the phrase

"technically feasible" too broad. The commenter (IV-D-21)

stated that some repairs may be technically feasible, but not

cost effective. The commenter (IV-D-21) suggested that the

phrase be modified to " technically feasible by normal repair

techniques" in the proposed regulation. Alternatively, the

commenter (IV-D-21) suggested that the correction could be

made in the HON and § 63.649(e) in the proposed regulation

could be deleted.
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Response: Connectors are not sources of high emissions

and some connector repairs may be very costly. The EPA agrees

with the commenter that the phrase "by normal repair

provisions" be added to the connector repair provisions. This

change was made in the final rule.

Comment: One commenter (IV-D-19) stated that table 3 has

been incorrectly printed to indicate that the QIP program for

valves is mandatory. The commenter (IV-D-19) stated that this

is not consistent with agreements reached by API and EPA nor

with the HON. The commenter (IV-D-19) contended that the QIP

program for valves should be a voluntary program.

Response: The EPA agrees with the commenter and has

revised table 3 to indicate that the QIP is a voluntary

program.

Comment: One commenter (IV-D-48) stated that the

equipment leaks provision exempts those who monitor connectors

from any inspection of valves, though no mention of this is

made in the preamble. The commenter (IV-D-48) concluded that

this is a drafting error and recommended that it be fixed in

the final rule.

Response: The commenter is correct that the proposed

rule contained a drafting error. The final rule corrects this

mistake; those who monitor connectors may monitor valves less

frequently.

Comment: One commenter (IV-D-21) suggested changes that

will clarify that § 63.648(b), which defines leaks for pumps

and valves, and § 63.168(a)(1)(ii) apply to pumps in light

liquid service and valves in gas/vapor and light liquid

service. The commenter (IV-D-21) claimed § 63.648, the

monthly light liquid pump monitoring provision, should include

the underlined: "Except as provided in paragraph (h) of this

section, owners or operators that achieve less than
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(1) 10 percent if light liquid pumps leaking or (2) three

light liquid pumps leaking, whichever is greater, shall

monitor light liquid pumps monthly."

Response: The EPA has made this change in order to

clarify the requirements and reduce confusion.

Comment: Two commenters (IV-D-21, IV-D-25) stated that

§ 63.148(a) and (f) of the proposed refinery rule crossreference § 63.169 of the HON. Section 63.169(b) of HON

defines a leak as 500 ppm for valves, connectors, and

instrumentation systems; however, § 63.648(b) and § 63.649

define leaks as 1,000 ppm. The commenters (IV-D-21, IV-D-25)

suggested language to establish a consistent definition of

1,000 ppm for valves, connectors, and instrumentation systems. 

One commenter (IV-D-38) requested that the underlined be added

to the end of § 63.649(f) to make the definition consistent

with other leak definitions in the refinery rule: 

(f) Connectors in gas/vapor service or light liquid service

are subject to the requirements for connectors in heavy liquid

service in § 63.169 of subpart H of this part except the leak

definition for connectors is the same as the definition for

valves in table 2 of this subpart.

Response: The EPA has clarified the final rule by adding

the following language: "The leak definition for valves,

connectors, and instrumentation systems subject to § 63.169 is

1,000 parts per million volume." The leak definition was

developed from the HON definition of 500 ppmv factored taking

into consideration the lower HAP concentrations in process

streams for refineries than in SOCMI facilities.

8.8 MISCELLANEOUS

Comment: In response to EPA's request for comment on

whether the HAP contents of the petroleum liquids in the

processing lines are below the 5 percent (by weight)
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applicability level in the equipment leak provisions, one

commenter (IV-D-23) stated that they are confident that all of

their process lines have greater than 5 percent HAP in them,

since they all have greater than 3.7 percent benzene. Another

commenter (IV-D-45) stated that HAP content in the crude oil

delivered to the COTU's has less than 5 percent benzene,

toluene, ethylbenzene and xylenes (BTEX) and n-hexane as

measured in lab speciation of their crudes. The commenter

(IV-D-45) included speciated lab results from testing of the

HAP content in the crude from their facilities. 

Response: The EPA thanks the commenters for their

information.

Comment: One commenter (IV-D-21) requested that the EPA

allow facilities to establish there own boundaries for process

units, so long as they are disclosed to the regulating agency

upon request and are not drawn to avoid regulation.

Response: The final rule does not preclude owners or

operators from establishing boundaries for process units. The

final rule only requires that petroleum refining process units

classified under SIC code 2911 comply with the rule. The

final rule also affords the owners or operators the choice of

drawing boundaries on a process unit or on a source-wide

basis.

9.0 GENERAL MONITORING, RECORDKEEPING,
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AND REPORTING COMMENTS

9.1 USE OF MONITORING TO DETERMINE COMPLIANCE

Comment: Three commenters (IV-D-22, IV-D-42, IV-D-44)

suggested that the EPA allow for alternative forms of

compliance monitoring besides CEM's. Two commenters (IV-D-22,

IV-D-42) requested that the EPA allow the use of other

monitoring technologies, such as predictive emission and

parametric monitors. One commenter (IV-D-44) recommended that

the EPA allow requests for alternative monitoring methods

subject to review and approval by the Administrator.

Response: Neither the proposed rule required nor the

final rule requires the use of CEM's to demonstrate or assure

compliance. Instead, it requires a combination of performance

testing and continuous control device operating monitoring. 

The final rule also allows sources to request approval to use

alternative monitoring 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. Other alternative

monitoring methods may also be allowed if they are approved by

the implementing agency as provided in part 63, subpart A

(General Provisions).

Comment: Five commenters (IV-D-21, IV-D-22, IV-D-29,

IV-D-44, IV-D-59) provided suggested changes to the frequency

of data collected or the wording on the method of calculating

daily averages. One commenter (IV-D-44) suggested that the

15 minute monitoring period be extended to hourly. The

commenter (IV-D-44) claimed that 15 minute monitoring would be
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ludicrous for data that do not vary significantly from day to

day, such as data regarding storage tanks. Three commenters

(IV-D-22, IV-D-29, IV-D-44) asserted that monitoring periods

should be no less frequent than daily. 

One commenter (IV-D-59) suggested that the monitoring

frequency be deleted from the rule altogether and left to

40 CFR part 63, subpart A (General Provisions). The commenter

(IV-D-59) suggested that States be free to require more

frequent monitoring than required by the General Provisions

whenever they think necessary or appropriate.

One commenter (IV-D-21) requested that the calculation of

daily averages be clarified. The commenter (IV-D-21)

suggested that "...calculated as the average of all values for

a monitored parameter" in § 63.652(h)(3)(v)(A) be revised to

"...calculated as the average of all data recorded pursuant to

§ 63.652(h)(3)(ii) for a monitored parameter..." because daily

averages should not be based on all values for a parameter.

Response: The final rule has been changed to require

retention of hourly average values of continuously monitored

values. The proposal required calculation of 15-minute

averages. Under the proposal, if the daily average value was

outside the established ranges (i.e., excess emissions

occurred), the 15-minute values had to be retained; if the

daily average value was within the established range, the

15-minute values could be converted to hourly averages and the

hourly averages could be retained instead of the 15-minute

averages. Upon reconsideration, the EPA finds the proposed

2-step process (of first computing and recording 15-minute

averages, and then being allowed to convert them to hourly

averages for record retention) to be burdensome and

unnecessary. Hourly average values provide a sufficient

record to support the calculation of the daily average value
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of a parameter. Therefore, to reduce the recordkeeping

burden, the rule has been changed to specify that hourly

averages must be retained for all days, regardless of whether

or not excess emissions occurred. The rule no longer requires

recording of 15-minute average values. 

As at proposal, the daily averages values of a parameter

are used to determine whether excess emissions have occurred. 

This allows for minor fluctuations in hourly data as long as

the daily average is within the established range. The EPA

has revised the wording of the rule to incorporate the changes

discussed above and clarify the calculation of daily averages

as suggested by the commenter (IV-D-21). These changes do not

change the rule, but rather clarify what was originally

intended.

For process vents where continuous parameter monitoring

is required, the value of the parameter must still be measured

at least once every 15 minutes, although only the hourly

average must be recorded and retained. Many facilities

already have computerized systems and monitor parameters more

frequently than once every 15 minutes for process control

purposes. The 15-minute monitoring frequency is also

consistent with the General Provisions and previous NSPS and

NESHAP for process vents from similar industries. 

The EPA believes that some commenters may be under a

misimpression that the rule requires continuous monitoring for

storage vessels. Under both the proposed and final rules,

continuous (e.g, every 15 minutes) monitoring is not required

for storage vessels. If the vessels are controlled by

floating roofs, periodic inspections are required. If the

vessels are routed to control devices, the owner/operator must

submit for approval a control device design and operating plan

that specifies the parameters to be monitored and the
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frequency. Storage vessel emissions are not continuous;

therefore, continuous emissions monitoring is not warranted. 

Sources subject to this NESHAP must comply with all

applicable monitoring requirements contained in the rule. In

response to the commenters (IV-D-59) suggestion that

monitoring requirements be left to the General Provisions, the

EPA notes that the General Provisions provide a broad general

regulatory framework for all part 63 NESHAP's; however, the

specific provisions of each NESHAP override the General

Provisions in those instances where requirements differ. At

proposal and promulgation of the refineries NESHAP, the EPA

determined that it is appropriate to override some of the

General Provisions to reduce the monitoring, recordkeeping,

and reporting burden for refineries, or to clarify how the

requirements apply to refineries.

The Act allows State and local agencies to enforce

regulations that are more stringent than Federal rules. A

more stringent rule may or may not have more stringent

monitoring, recordkeeping, and reporting provisions. All

sources subject to the final petroleum refinery NESHAP must

comply with the monitoring, recordkeeping, and reporting

provisions contained in the rule. A source with a more

stringent State or local standard would be required to comply

with the provisions of that standard.

Comment: Two commenters (IV-D-39, IV-D-46) supported the

use of parameter monitoring as an alternative to CEM. One of

the commenters (IV-D-46) also supported the formation of

parameter ranges and their approval process. 

One commenter (IV-D-44) recommended that a daily average

be used to determine if an excursion or noncompliance has

occurred, not an exceedence on the CEM. 
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Response: Under the NSPS and NESHAP programs, parameter

monitoring has generally been used in place of CEM's,

especially for VOC control devices. The final rule, as at

proposal, requires monitoring of control device operating

parameters and reporting of periods when daily average

parameter values are outside site-specific ranges. The source

is provided the flexibility to establish appropriate sitespecific parameter ranges with their permitting authority. 

These operating parameter ranges are then written into their

operating permit and are enforceable. If the daily average

value is outside the established range then it is a violation

of the emission standards. Neither the proposed nor the final

rule require the use of CEMs to assure compliance.

Comment: One commenter (IV-D-25) pointed out that the

rule is unclear on how long a flare pilot light must be absent

to be considered excess emissions, and suggested wording

changes.

Response: The proposal and promulgation provisions for

process vents and wastewater sections require reporting only

if all pilot flames to a flare are out. Records must be kept

of periods when each individual monitoring device or pilot

light is not working, but if the flare has multiple pilot

lights, reporting is not required unless all pilot flames are

out. 

If all pilot flames are out, it indicates that the flare

is not functioning, and emissions being routed to the flare

are not being controlled. Failure to operate a required

control device for any length of time is a violation of the

NESHAP, unless it is during a period of startup, shutdown, or

malfunction. The refineries NESHAP and the General Provisions

include startup, shutdown, and malfunction provisions.
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Comment: One commenter (IV-D-25) suggested that, for

purposes of determining periods of excess emissions, the rule

should exclude periods of startup, shutdown, malfunction, or

monitoring system calibration. The commenter (IV-D-25)

contended that the startup, shutdown, and malfunction plan is

not necessary because the refinery NESHAP already specifies

many work practices, and the OSHA Process Safety Management

Regulation already includes start-up and shutdown plan

requirements for petroleum refinery process units. The

commenter (IV-D-25) also suggested limitations to the scope of

the plan if the EPA still decides to require a plan. 

One commenter (IV-D-06) requested that the administrative

requirements be reduced by eliminating or reducing the

requirements for startup, shutdown, and malfunction plans

because most of the requirements are included in the

regulation as work practices. The commenter (IV-D-06)

expressed confusion as to what level of detail is needed for

startup, shutdown, and malfunction plans. The commenter

(IV-D-06) stated that if a startup, shutdown, and malfunction

plan is required, the following limitations should be

included: (1) for equipment leaks, the startup, shutdown, and

malfunction plan should only include the dates of process unit

shutdowns and startups. This commenter (IV-D-06) stated that

this information is pertinent to the repair work required to

take place during process unit turnarounds and there is no

relevance to maintaining procedures checklists to the proper

operation and maintenance of fugitive sources; (2) for storage

tanks, the startup, shutdown, and malfunction plan should only

include the date when a tank is taken out of service and

returned to service; (3) for miscellaneous process vents, the

startup, shutdown, and malfunction plan is applicable in its

present requirements; and (4) for wastewater, the startup,
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shutdown, and malfunction plan should not be applicable since

the information is already covered in the BWON. 

One commenter (IV-D-20) requested that reporting required

by § 63.652(g)(1), such as reports of start-up, shutdown, and

malfunction be removed and changed to a recordkeeping

requirement since other reports already require the same data

to be reported. The commenter (IV-D-20) stated that

substitution of other reports which require similar data

should be allowed.

Response: The NESHAP General Provisions [§ 63.6(f)(1)]

state that "emission standards...apply at all times except

during periods of startup, shutdown, and malfunction...". 

During such periods, a source must follow their site-specific

startup, shutdown, and malfunction plan. 

Start-up, shutdown, and malfunction plans are described

in the General Provisions. Therefore, they are not described

in the refineries NESHAP. The General Provisions

[§ 63.6(e)(3)(vi)] clearly state that a source's SOP manual or

an OSHA plan may be used to satisfy the requirements for a

startup, shutdown, and malfunction plan if they contain all

the required information and are available for inspection by

the regulatory authority. This provision will avoid

duplicative efforts.

One purpose of the startup, shutdown, and malfunction

plan is to ensure that sources and pollution control equipment

are operated in a manner consistent with good air pollution

control practices for minimizing emissions during these

events. Another purpose is to minimize the reporting burden

associated with startup, shutdown, and malfunction events. 

The plan allows the source to describe the procedures they

will follow during these events. If the plan is followed,

then a simple letter report can be submitted semiannually to
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state that the plan was followed during start-ups, shutdowns,

and malfunctions during that 6-month period [§ 63.10(d)(5)(i)

of subpart A]. If the plan is not followed, an immediate

report describing the malfunctions and the actions that are

inconsistent with the plan is required. If a plan were not

required, then detailed reports would be needed for all

malfunctions to demonstrate that the event was a malfunction

and that emissions were minimized during the event. Thus, the

plan greatly reduces the ongoing reporting burden. The plan

also avoids questions over whether an event envisioned in the

plan is a malfunction or a violation of the emission standard. 

If a malfunction occurs and it is covered by the source's

start-up, shutdown, and malfunction plan, and the procedures

in the plan are followed, the occurrence is not counted as an

emissions exceedence.

The commenter is correct in stating that equipment leaks

from pumps, valves, and other components are not considered

malfunctions. For equipment leaks, only startup, shutdown,

and malfunction of any control device would need to be

considered. The detection and repair of such leaks is

addressed in the NESHAP, and therefore does not need to be

included in the startup, shutdown, and malfunction plan.

Comment: One commenter (IV-D-40) contended that the

non-automated monitoring requiring operator manual records

once per hour contained in the rule is unreasonable for some

operations. The commenter (IV-D-40) explained that some

States such as New Jersey allow different monitoring

frequencies based on the type of operation (e.g. batch plants

often are only required to manually record the flow of water

to a scrubber once per batch cycle. The commenter (IV-D-40)

also said that batch times may range from 1 hour to 2 days. 

The commenter (IV-D-40) said the plant maintains low-flow
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interlocks or alarms to insure adequate water flow to the

control device. For these reasons, the commenter (IV-D-40)

stated that the one-hour requirement is not cost-effective or

appropriate in many cases. The commenter (IV-D-40) suggested

allowing up to 4-hour intervals for manual monitoring after

review and approval with the permit authority. 

Response: The EPA estimates that there are relatively

few facilities that do not already have automated computer

monitoring systems in place. The EPA agrees that there is

often only a need for a minimum amount of data to obtain a

valid average. The EPA addressed this issue on the HON in

order to reduce the burden on those sources that did not have

automated computer monitoring systems in place. The

refineries NESHAP refers to provisions contained in

§ 63.151(g) of the HON subpart G, which allow non-automated

sources to request approval from the permitting authority to

manually read and record the value of the relevant operating

parameter less frequently. In approving the request, the

implementing agency may consider the variability of the

parameter, and whether a longer monitoring frequency is

sufficient to characterize control device operation.

There are very few batch process vents within petroleum

refineries. Cokers are batch operations, however, provisions

have been added to exclude "coking unit vents associated with

coke drum depressuring at or below a coke drum outlet pressure

of 15 psig, deheading, draining, or decoking (coke cutting)." 

The implementing agency may consider and approve less frequent

monitoring and recordkeeping for batch process vents as long

as the minimum data for a valid average is obtained.

Comment: One commenter (IV-D-25) noted that the proposed

rule appeared to use the term "period of excess emissions" and
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"excess emissions" interchangeably, and recommended some

editorial clarifications. 

One commenter (IV-D-52) was confused with the provisions

describing excess emissions as an operating day when

monitoring data are insufficient to constitute a valid hour of

data for at least 75 percent of the operating hours. The

commenter (IV-D-52) considers excess emissions to be those

which are higher than allowable emissions and considers the

EPA definition to be closer to the commenter's definition of

downtime. Downtime would include any operating time when a

CEM is not recording valid monitoring data at least 75 percent

of the hour while the source is in operation, because of

maintenance or some other similar circumstance. The commenter

(IV-D-52) stated that such downtime is not considered a

violation if less than specified availability levels. The

commenter (IV-D-52) recommended that the required operating

time for monitors should be 90 percent of the source's

operating time over a calendar quarter, because many CEM's

exceed 90 percent availability. The commenter (IV-D-52)

recommended that the period of excess emissions be based on a

shorter period than a daily average and suggested the hourly

average. The commenter (IV-D-52) added that their State is

switching to hourly averages for CEM data that is used to

determine compliance with an hourly limit.

Response: The monitoring under this rule is not

CEM-based. Multiple options are available to demonstrate

compliance with the performance-based standard. Because of

the number of differing operation and production differences

across petroleum refineries, an absolute emissions limit would

not be practical. Therefore, periods of excess emissions are

defined based on operations and emissions control performance. 
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Period of excess emissions means any of the following

conditions:

(A) An operating day when the daily average value of a

monitored parameter, except presence of a flare pilot flame,

is outside the range specified in the Notification of

Compliance Status Report.

(B) An operating day when all pilot flames of a flare

are absent.

(C) An operating day when monitoring data are

insufficient to constitute a valid hour of data for at least

75 percent of the operating hours. Monitoring data are

insufficient to constitute a valid hour of data if measured

values are available for less than three 15-minute periods

within the hour. For data compression systems approved under

paragraph (g)(5)(iv) of § 63.651, monitoring data are

insufficient to constitute a valid hour of data if there are

less than four data values recorded during the hour.

The EPA's definition for process downtime has nothing to

do with CEM. If monitoring data are not collected or the

monitored parameter is out of range due to a "malfunction", as

defined in the NESHAP general provisions, this is not

considered to be a violation. (Requirements for startups,

shutdown and malfunction plans, records, and reports contained

in the NESHAP General Provisions address malfunction

situations). However, if there is not a monitor malfunction,

it is reasonable to consider days when insufficient monitoring

data are collected to be periods of excess emissions and

violations of the emission standards. Otherwise, monitors

could be turned off when excess emissions were occurring.

While many monitors may be able to function 90 percent of

the time on a long-term average basis, it would be

unreasonable to consider it a violation if monitors operate
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less than 90 percent of the time in each single day. 

Requiring monitors to operate greater than 90 percent of the

time in each single day would add substantially to the

operating cost of the rule. The 75 percent level allows for

short-term monitor problems that are promptly corrected; and

if 75 percent of the data are available, this is sufficient to

determine whether the monitoring parameter is within its range

on a daily average basis. 

Comment: One commenter (IV-D-59) strongly agreed that

violations of the parameters on which the compliance plan is

based must be considered violations of the emissions standard.

Response: As the commenter stated, an excursion of the

daily average value of a parameter outside the established

range would constitute a violation of the emission standards. 

Comment: One commenter (IV-D-59) maintained that if the

EPA wishes to allow data compression systems, it should also

require that these systems regard all deviations from the

operating parameters established as indicating noncompliance.

Response: Approved data compression systems are a fully

acceptable alternative type of continuous alternative type of

continuous monitoring system. As with any continuous

monitoring system, if the daily average recorded by the data

compression system is outside the established range, this is

considered a period of excess emissions and a violation of the

emission standard. The commenter is suggesting a different

standard for facilities using data compressor systems. Under

the commenter's suggestion, if a single measured value was

outside the range this would be considered a violation, even

if the excursion was for only a few minutes. For continuous

monitoring systems, including approved data compressions

systems, the rule determines excess emissions based on the

daily average value of the monitored parameter. It would be
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inequitable to establish a more stringent standard for sources

with data compression systems.

The proposed and final rule allows a source to request

approval to monitor using data compression as an alternative

monitoring, recordkeeping, and reporting system. Sources

wishing to use data compression must apply to the permitting

authority for the approval of this alternative. The EPA has

established minimum criteria that data compression systems

must satisfy in order to ensure recorded data are sufficient

to represent the process and determine whether excess

emissions have occurred. These minimum criteria assure that

data compression systems will be equivalent to traditional

continuous monitoring and recordkeeping systems.

In order to be approved, an acceptable data compression

system must be capable of: (1) measuring the operating

parameter value more frequently than at least once every

15 minutes; (2) recording the hourly average values each hour

during periods of operation; (3) recording the date and time

when monitors are turned off or on; (4) recognizing unchanging

data that may indicate the monitor is not functioning

properly, alerting the operator, and recording the incident;

and (5) computing daily average values of the monitored

operating parameter based on recorded data. The request for

approval must contain a description of the monitoring system

and data compression recording system, including the criteria

used to determine which monitored values are recorded and

retained, the method for calculating hourly and daily

averages, and a demonstration that the system meets the five

criteria previously discussed. 
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9.2 RECORDKEEPING REQUIREMENTS

Comment: One commenter (IV-D-36) disagreed with the

five-year record retention requirements. The commenter

(IV-D-36) found the requirement burdensome and not a direct

benefit to the environment. Two commenters (IV-D-36, IV-D-44)

recommended a three-year record retention policy.

Another commenter (IV-D-59) strongly disagreed with the

proposal to allow records to be destroyed after five years. 

The commenter maintained that records should be retained as

long as necessary in order to document possible violations.

Response: The petroleum refinery NESHAP and General

Provisions require records to be kept for five years, which is

consistent with the recordkeeping requirements of section 70.6

of the operating permit program and other NESHAP. The rule

has been changed to state that records must be maintained in

such a manner that they are readily accessible (e.g., within

24 hours). Records may be maintained on-site or off-site, in

hard copy or computer readable format, as long as they are

readily accessible. This replaces the proposed provisions

that required records to be retained on-site or accessible

from a central location by computer for the first 2 years. As

long as a record can be retrieved within 24 hours, the intent

of the standards is met. There is no need to be overly

restrictive in specifying how and where to maintain the

record. Storage of records for more than 5 years would be

burdensome, and any compliance issues should be identified

within 5 years. Furthermore, the statute of limitations for

enforcement is 5 years so there is no reason to keep records

for a longer period of time.

Comment: Two commenters (IV-D-19, IV-D-21) stated that

the words "each" in § 63.652(h)(3)(i)(A) and "all" in (B)

would make recordkeeping burdensome because many of the
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refineries have computers to measure data values frequently. 

The commenters (IV-D-19, IV-D-21) suggested that the

requirements of § 63.652(h)(ii) be rewritten so that if data

is measured more than once per minute, only one measurement

from each one-minute block need be used to satisfy

§ 63.652(h)(3)(i)(A) or (B).

Response: As explained in a previous response, the final

rule has been changed to require records of hourly average

values rather than 15-minute averages. However, parameter

values must still be measured at least once every 15 minutes. 

Generally, all measured values must be used to calculate the

hourly average. If values are measured once every 15 minutes,

4 values would be used to calculate each hourly average. 

However, as the commenter pointed out, if a value is measured

more frequently than once per minute, more than 60 values

would be used to calculate the hourly average, if the wording

of the rule required use of all measured values. In

accordance with the commenter's suggestion, the wording has

been revised such that if data are measured more frequently

than once per minute, one measurement from each 15-minute

block may be used in calculating the hourly averages. This

procedure will yield a representative hourly average. It will

reduce the burden of the calculation and avoid penalizing

sources that measure values much more frequently than is

required by the standard.

As stated in previous responses, only the hourly average

values are required to be retained on record. If a source

wishes to keep records of 15-minute or more frequent average

values instead of or in addition to hourly averages, they may

do this, but it is not required by the final rule. These

provisions ensure that there will be enough monitoring values

recorded and retained to be representative of the monitoring
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period, while reducing 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

or more frequently measured values had to be retained. 

Comment: One commenter (IV-D-29) requested that

recordkeeping costs be minimized. The commenter (IV-D-29) did

not agree with the approach of using recordkeeping instead of

testing for enforcement. The commenter (IV-D-29) asserted

that recordkeeping places a high cost on the industry and

regulatory agencies to monitor unnecessary records. 

One commenter (IV-D-22) asserted that the language of the

proposed rule does not reflect some of the flexibility which

the EPA seems to be intending in the preamble language. The

commenter (IV-D-22) explained that the level of data required

in a complete test report for each test method used for a

particular source is an overly burdensome requirement. The

commenter (IV-D-22) stated that test reports should be on one

performance report per facility and should be submitted to the

EPA at the discretion of the source as to which report.

Response: Monitoring and recordkeeping is necessary to

demonstrate compliance on an ongoing basis. If testing alone

were used, repeated testing would be required. Periodic

testing of every emission point subject to the standards would

be extremely burdensome and is not necessary to determine

compliance. Instead, the rule specifies initial testing for

vents that are not routed to the fuel gas system. (Some

boilers and flares do not require a performance test.) After

the initial test, operating parameters are monitored and

recorded to assure compliance. Because monitoring can be done

on a continuous basis, it is a better indicator of ongoing

compliance than periodic testing, and it is also less

burdensome than frequent testing would be. For storage
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vessels, periodic inspections of floating roof seals must be

performed because testing is not feasible.

The EPA recognizes that unnecessary recordkeeping

requirements would burden both the source and the enforcement

agencies. Every attempt has been made to reduce the amount of

recordkeeping to only that which is necessary to demonstrate

compliance. For example, sources have the option of retaining

records either in paper copy or in computer readable formats,

whichever is less burdensome and less costly. For

continuously monitored parameters, the rule has been changed

to require retention of only the hourly average data rather

than 15-minute data. For storage and equipment leak

inspections that reveal no problems, only the date of the

inspection must be recorded, not detailed results. Periodic

reports include only periods of excess emissions, not a

summary of all the data.

If multiple performance tests are conducted for the same

kind of emission point using the same test method, only one

complete test report is submitted along with summaries of the

results of the other tests. This reduces the number of

lengthy test reports to be copied and submitted. 

The test report provisions apply primarily to process

vents. The storage vessel provisions allow a design analysis

instead of a performance test; and the refineries NESHAP

refers to subpart VV of part 60 or to the HON subpart H for

equipment leaks, recordkeeping and reporting, and to BWN for

wastewater, and does not impose any new requirements. For

process vents, it is necessary to submit one complete test

report for each test method in order for the enforcement

authority to verify that the test protocol, sampling and

analysis, quality assurance procedures, and calculations have

been done correctly. If the same method is used to test other
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process vents, the test reports for the other vents may be

retained on site and only the results must be reported. The

EPA considers this level of recordkeeping the minimum

necessary to ensure compliance. 

9.3 REPORTING REQUIREMENTS

9.3.1 Initial Notification

Comment: One commenter (IV-D-59) stated that the initial

notification is a simple matter and should be required within

60 days of promulgation instead of 180. The commenter noted

that, with respect to construction and reconstruction,

consistency with the statute requires immediate notification,

since after promulgation new sources must comply with new

source MACT. The commenter stated that the State agencies

administering new source review programs must know whether a

source seeking a construction permit has a MACT obligation

before the permit is granted.

Response: The final rule has been changed to delete the

requirement for an initial notification. This decision was

made as part of a reanalysis of the recordkeeping and

reporting requirements to eliminate duplicative requirements

and reduce the recordkeeping burden of the standards. As

summarized in section 9.4, many commenters believed the

proposed recordkeeping and reporting requirements were overly

burdensome.

The Initial Notification is not necessary for refineries

because it would duplicate the operating permit program and

because the name and location of all the refineries in the

U.S. are already known. Several readily available journals

(e.g., Hydrocarbon Processing, Oil and Gas Journal) publish

lists of refineries. Thus, States and EPA regional offices

can easily determine which sources in each State will be

subject to the petroleum refineries NESHAP. Furthermore,
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refineries that are major sources are required to obtain

Title V operating permits. The due-dates for title V operating

permit applications will generally fall after proposal or

shortly after promulgation of the petroleum refineries NESHAP,

depending on State schedules, but prior to the 3-year

compliance time in the NESHAP. The Title V applications will

identify that the refineries are subject to the NESHAP. 

Therefore, a separate Initial Notification would be

duplicative and has been eliminated from the final rule. 

9.3.2 Notification of Compliance Status

Comment: Several commenters (IV-D-09, IV-D-20, IV-D-21,

IV-D-22, IV-D-36, IV-D-42) objected to some of the

Notification of Compliance Status Report requirements in the

proposed rule. Several commenters (IV-D-09, IV-D-20, IV-D-21,

IV-D-22, IV-D-36) objected to the requirement that refineries

that make changes to feedstock type make a Notification of

Compliance Status Report to the EPA or delegated authority. 

The commenters (IV-D-09, IV-D-20, IV-D-22) asserted that

refineries change crude slate constantly based on world-wide

market condition, product demand, transportation costs and

availability, and equipment operating conditions. One

commenter (IV-D-20) urged the EPA not to require a

Notification of Compliance Status Report for changes in the

throughput rate. The commenters (IV-D-09, IV-D-20) concluded

that these requirements would require almost constant

notification. 

Four commenters (IV-D-21, IV-D-22, IV-D-36, IV-D-42)

contended that the reporting requirements associated with

operational changes or addition of minor emission points are

too burdensome. The commenters (IV-D-22, IV-D-42) contended

that refineries make many deliberate operational changes each

week that do not increase significant emissions; therefore, it
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would be difficult to document each change in a Notification

of Compliance Status Report. The commenters (IV-D-21,

IV-D-22, IV-D-42) recommended that only when a deliberate

operational change causes a Group 2 point to become a Group 1

point or meets the criteria for reconstruction should

additional reporting or recordkeeping be triggered. Two

commenters (IV-D-21, IV-D-36) urged that notification not be

required for feedstock and operational changes due to their

frequency and the insignificant effect they have on emissions. 

One commenter (IV-D-21) recommended that the underlined text

in the following sentence from § 63.640(i)(3) be deleted: "A

process change to an existing petroleum refining process unit

shall be subject to the reporting requirements...". 

Two commenters (IV-D-22, IV-D-42) stated that minor

emission points such as valves and connectors are added

periodically, which result in small increases in emissions,

and is it therefore unreasonable to require an Notification of

Compliance Status for additional equipment leak emission

points. One commenter (IV-D-42) suggested that either

equipment leaks be removed from the definition of emission

point or the phrase "emission point" in § 63.640(l)(3) be

replaced with "storage vessel, miscellaneous vents, or

wastewater stream" because the commenter (IV-D-42) contended

that it was not the EPA's intention that added potential

equipment leaks trigger a Notification of Compliance Status

Report because such emission points are tracked through a LDAR

program.

Response: The proposed provisions in § 63.640(l) and (m)

were intended to require a Notification of Compliance Status

Report only if a process vent, storage vessel, or wastewater

stream is added or if an operational change causes a process

vent or storage vessel to change from Group 2 to Group 1. 
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Most feedstock changes would not cause the group status of a

vent or storage vessel to change, and therefore, most

feedstock changes would not need to be reported. It was the

EPA's intent to require a Notification of Compliance Status

Report if a petroleum refinery makes an equipment change or

rebuilt equipment. It was not the EPA's intent to require a

Notification of Compliance Status Report if a petroleum

refinery makes a change within the original design. The

wording of the final regulation has been revised to clarify

the intent.

The EPA has also removed the phrase "emission point" and

replaced it with "storage vessel, miscellaneous process vent,

or wastewater stream" to clarify that the addition of valves

and connectors does not trigger a Notification of Compliance

Status Report.

Comment: One commenter (IV-D-21) supported the

flexibility provided by allowing information to be submitted

in an operating permit application, an amendment to an

operating permit application, a separate submittal, or a

combination of the three. The commenter (IV-D-21) stated that

this minimizes the number of time consuming management reviews

required.

Response: The EPA has made every effort to reduce the

reporting burden, and to require only those reports necessary

to determine compliance. If the information required in the

notification of compliance status report has been previously

submitted in an operating permit application or amendment,

then the requirements of the rule have been fulfilled.

Comment: One commenter (IV-D-21) suggested that if a

Notification of Compliance Status or additional data is

required due to a changed or added emission point, the

Notification of Compliance Status Report or data should be
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included with other periodic reports the next regular

reporting date after the Notification of Compliance Status

Report was due. The commenter (IV-D-21) asserted that

additional deadlines beyond normal reporting are not worth the

added burden because there is no associated emissions

decrease. The commenter (IV-D-21) requested that the sentence

"The applicable reports include, but are not limited to:" be

changed to read "The applicable reports shall be submitted

with other periodic reports required by §§ 63.652(f) and (g)

and include but are not limited to:" 

Response: The final rule has been clarified such that

when a Notification of Compliance Status Report is required

due to the addition of an emission point or a change from

Group 2 to Group 1, the Notification of Compliance Status

Report may be submitted either in the next periodic report or

within 150 days after the new or changed emission point is

required to achieve compliance, whichever is later. This will

allow the operator flexibility, and reduce the reporting

burden and the number of separate reports that must be

submitted. Subpart CC requires periodic reports to be

submitted semiannually within 60 days of the end of each

6-month period. Thus, if the Notification of Compliance

Status Report is submitted in the next periodic report, it

will be within 8 months of the compliance date, even if the

compliance date falls on the first day of a reporting period;

and on the average the next periodic report would be 5 months

(150 days) after the compliance date for the new or changed

emission point. Allowing sources to include the Notification

of Compliance Status Report in the periodic report will

simplify reporting and reduce the number of submittals. 

However, if a change is made near the end of a reporting

period, a source may not have time to perform any required
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testing, receive the test results, and prepare the

Notification of Compliance Status Report before the next

periodic report is due. In these cases, the source will be

allowed 150 days from the date the added or changed Group 1

emission point is required to achieve compliance. This is the

same amount of time as allowed for the initial Notification of

Compliance Status Report.

Comment: One commenter (IV-D-57) asserted that 150 days

is too long for filing a Notification of Compliance Status

Report because sources have 3 years to comply and should be

able to prepare the notice in a shorter time frame.

Response: The final provisions allow 150 days after the

compliance date for a source to submit their Notification of

Compliance Status Report. This amount of time is necessary

and sufficient for the source to complete the performance

tests and set monitoring parameter ranges. The rule requires

control equipment to be installed and operating on the

compliance date. Testing cannot take place until the control

equipment has been installed. Time is needed after the

compliance date to conduct performance tests, receive

analytical results from the lab, prepare test reports and

other compliance demonstration documentation, and allow for

management review. The 150 days is based on information

submitted by the chemical industry during development of the

HON on the length of time it takes to conduct a performance

test and receive the analytical results. The scope of the

MACT standard will involve large amounts of information, where

150 days is necessary. Both the HON and NESHAP General

Provisions allow 150 days or more for these activities. A

source is always allowed to submit a report prior to the due

date.
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9.3.3 Periodic Reports

Comment: Some commenters (IV-F-19, IV-D-21, IV-D-22)

expressed opposition to quarterly reporting of an emission

point if the parameter values are outside the established

range for more than 1 percent of the operating time or its

monitoring device has a downtime greater that 5 percent in a

semiannual reporting period. One commenter (IV-D-19)

suggested that only semiannual reporting be required. The

commenters found this requirement burdensome and inconsistent

with other recordkeeping requirements. One commenter

(IV-D-19) attested that penalties for noncompliance are

sufficient incentive for compliance and increased reporting

does not improve enforceability. One commenter (IV-D-21)

claimed that the proposed percentages could be interpreted as

requiring calculation of percentages based on 15 minute

averages rather than periods of excess emissions (days). The

commenter (IV-D-21) claimed that this interpretation would

make the data compression provision useless. The commenter

(IV-D-21) provided changes to avoid interpretation that

15 minute averages should be used in determining percent of

time outside of a compliance range. The commenter (IV-D-21)

suggested several minor corrections concerning the period of

excess emissions. One commenter (IV-D-22) recommended using

5 percent monitor noncompliance and 5 percent monitor downtime

provisions as a standard for submittal of quarterly reports. 

One commenter (IV-D-44) suggested that the continuous

emissions monitor noncompliance rates should be a 5 percent

monitor noncompliance rate and a 10 percent monitor downtime

rate measure for each monitor, not across the refinery or

process units. 

In response to a request for comments on requiring more

frequent reporting dependent upon the frequency or duration of
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exceedences, one commenter (IV-D-46) suggested that the

requirements address the periodicity of exceedences, in order

to encourage fundamental problems that result in frequent, but

short duration exceedences to be corrected.

One commenter (IV-D-59) was concerned about the

complexity of making the frequency of reporting depend upon

the number of violations. The commenter stated that it is

unlikely that the State agency will have the time necessary to

determine whether sources claiming the right to report less

frequently have earned it. The commenter suggested that if

the EPA wishes to reduce the frequency of reporting for

facilities with good compliance histories, it should set

reasonably high standards for these reductions and require

companies to report more frequently if violations occur. The

commenter recommended that EPA require a statement listing 

Act requirements that applied during the last two years and

certification that there had been no violations.

One commenter (IV-D-59) suggested that companies that

qualify for semiannual reporting must report more frequently

if a violation occurs after qualifying for semiannual

reporting. The commenter specifically suggested that

reporting should be quarterly if a violation occurs within the

year. The commenter stated that if any non-compliance is

tolerated for this purpose, 1 percent of time out of

compliance is better than 5 percent. 

Response: The final rule has been changed to remove the

requirement for quarterly reporting in cases where monitoring

parameters are out of range or monitors are not operating more

than a specified percent of time. Instead, semi-annual

reporting is required for all facilities. At proposal, all

facilities were required to report semiannually, but if the
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specified percentages were exceeded and the regulatory

authority requested it, quarterly reporting could be required.

This change was made because the EPA agrees that the

quarterly reporting system proposed added complexity to the

rule, it may not be helpful for enforcement, and that

penalties for noncompliance are a sufficient deterrent for

poor performance. The rule specifies that if the daily

average value of a monitored parameter is outside the

established range or if valid monitoring data are not

available for at least 75 percent of the operating hours in a

day, then excess emissions have occurred and the emission

standard has been violated. Thus, sources have a clear

incentive to keep monitors operating and parameters within

range. Because a single day out of the 6-month (182 days)

reporting period can be a violation, sources with parameters

out of range as little as 0.5 percent of the time may have a

violation. 

Semiannual reporting is consistent with Title V operating

permit reporting requirements. Requiring separate quarterly

reports for some facilities adds complexity and increases the

reporting burden for both the facility and the enforcement

agency. It would require calculation of percentages, tracking

of which facilities and emission points are on quarterly

versus semiannual schedules, and extra report preparation and

review time. Semiannual reports will provide the regulatory

agency information on excess emissions within about 6 months

of the occurrence. This is well within the 1-year timeframe

in which the agency can take administrative enforcement

actions (see later comments in this section).

Comment: One commenter (IV-D-52) suggested periodic

reports be submitted within 30 days of the recording period,

instead of 60 days as currently required.
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Response: The final provisions require periodic reports

to be submitted no later than 60 days after the end of each

6-month period. This time period should allow enough time for

the source to gather data, prepare, review, and finalize the

periodic report. Because of the large number of emission

points at a refinery, 30 days may be inadequate. A source is

always allowed to submit a report prior to the due date.

Comment: One commenter (IV-D-20) suggested annual

reports instead of semiannual reports for those reports

required by § 63.652(f)(1) and (f)(6).

One commenter (IV-D-59) stated that a chaotic situation

will exist where the frequency of reporting varies from

standard to standard.

Response: The periodic reporting system of semiannual

reporting is in conformance with § 70.5(c) of the operating

permits program, which states that sources are required to

submit reports no less frequently than once every six months. 

Annual reporting was not selected as requested by the

commenters, because it would significantly reduce the EPA's

ability to take administrative enforcement actions. 

Section 113(d) of the Act limits assessment of administrative

penalties to violations that occur no more than 12 months

prior to the initiation of the administrative proceeding. 

Periodic reports are a primary means of identifying possible

violations, and annual submittal would not give the

enforcement agency time to review the report and take action

on a violation that occurred early in the reporting period

within one year after the event. Administrative proceedings

are far less costly than judicial proceedings for both the EPA

and the regulated community. 
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9.3.4 Additional Reporting

Comment: One commenter (IV-D-29) stated that

notification before tank inspections is unnecessary. Another

commenter (IV-D-20) requested that the reporting requirements

for notifications of inspections for storage vessels be

removed and changed to a recordkeeping requirement. One of

the commenters (IV-D-29) questioned the existence of data

showing that occasional tank inspections are a significant

health risk. The commenter (IV-D-29) questioned who was going

to pay for the local inspector and if the emissions created by

the local inspector coming to the tank site had been

considered.

Response: The proposed and final refineries NESHAP

requires the same notification as previous storage tank

regulations including HON and the NSPS (40 CFR part 60,

subpart Kb). The EPA has determined that the notification

requirements for an owner or operator to inform the

implementing agency of an upcoming seal gap measurement (for

EFR vessels) and of vessel refilling when a vessel has been

emptied and degassed (for both IFR vessels and EFR vessels) is

a reasonable requirement and is not unnecessarily burdensome. 

These notifications are not required to be submitted very

frequently. For IFR vessels, which is a common type of

floating roof vessel, the notification requirement for vessel

refilling will be required once per ten years, or each time

the vessel is emptied and degassed. For EFR vessels, the

notification requirement for vessel refilling has no

specified schedule, as the notification is required each time

this type of vessel is emptied and degassed, according to the

schedule established by the facility operating the vessel. 

The EPA anticipates that EFR vessels will be emptied and

degassed no more frequently than once every ten years. Also
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for EFR vessels, the notification requirement for seal gap

measurements will be required once per year. The EPA

maintains that this notification requirement is not

unnecessarily burdensome; these notifications are necessary

for effective enforcement of the rule.

The EPA also concluded that these notification

requirements are not likely to result in findings of

noncompliance against sources. If a source cannot notify the

implementing agency within 30 days due to an unplanned event,

a source is not necessarily in noncompliance. Both of these

notification provisions specify that if the seal gap

measurement or internal inspection associated with the vessel

refilling were unplanned, then the notification could be made

seven days in advance of the measurement or refilling, rather

than the standard 30 days in advance. 

The EPA has also concluded that, based on discussions

with State agencies, these notifications will result, in many

cases, in observers being sent to facilities to be present

during the measurement or inspection. The EPA recognizes that

some implementing agencies may choose to send observers to

these measurements and inspections less frequently than other

implementing agencies; however, the EPA anticipates that the

majority of implementing agencies will use these notifications

for enforcement purposes.

Comment: One commenter (IV-D-36) recommended that the

EPA make modifications necessary to allow reports required by

the Benzene NESHAP's and NSPS programs to satisfy all

reporting requirements of Title III and the proposed refinery

NESHAP regulation.

Response: The EPA agrees that duplicative reporting

should be avoided, and has clarified the refineries NESHAP to

state which compliance and reporting requirements apply to
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emission points that are subject to the refineries NESHAP as

well as previous NSPS or NESHAP. The proposed refineries

NESHAP specified that the only reporting required for

wastewater is the reporting required by the BWON. This

provision has been retained in the final rule. The refineries

NESHAP equipment leaks reporting is the same as "for 40 CFR

part 60, subpart VV or the HON (40 CFR part 63, subpart G),

depending on the compliance method chosen by an owner or

operator." The HON overrode reporting requirements of the

SOCMI equipment leaks NSPS in cases where the same equipment

was subject to both rules. Wording has been included in the

final refineries NESHAP to clearly state that the refineries

NESHAP reporting requirements also over-ride the petroleum

refinery equipment leaks NSPS and the benzene equipment leaks

NESHAP for equipment subject to multiple rules. For storage,

provisions have been added to the final rule to state whether

the refineries NESHAP, the benzene storage NESHAP, or the NSPS

(40 CFR part 60, subparts K, Ka, and Kb) apply for storage

vessels subject to multiple rules. This will result in only a

single report for each storage vessel. For process vents, no

other NSPS or NESHAP are expected to apply to the same process

vents that are subject to the petroleum refineries NESHAP. 

The reader is referred to section 3.5 of this document for

additional discussion of regulatory overlap issues.

Comment: One commenter (IV-D-44) suggested that test

reports be combined so that one performance report can be

submitted on the frequency established in the Title V permit.

Two commenters (IV-D-42, IV-D-51) recommended

incorporating MACT reporting requirements into the Title V

permitting program.

Response: A source must comply with all rules that apply

to each emission point. If some of the monitoring,
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recordkeeping, and reporting for these different rules

requires submittal of the same information, then the source

can discuss with the implementing agency how to avoid

duplicative monitoring, recordkeeping, and reporting.

If test reports and other information required by the

Notification of Compliance Status have already been submitted

as part of a Title V operating permit program they do not have

to be submitted again.

9.4 RECORDKEEPING AND REPORTING BURDEN

Comment: Many commenters (IV-D-13, IV-D-19, IV-D-22,

IV-D-34, IV-D-36, IV-D-39, IV-D-42, IV-D-51) alleged that the

recordkeeping and reporting requirements are extremely

burdensome, and do not contribute to improvement in air

quality and may divert resources away from compliance

activities. One commenter (IV-D-39) urged the EPA to continue

to look for ways to reduce the monitoring and reporting burden

associated with the proposed rule. Some commenters (IV-D-13,

IV-D-34) contended that State and local agencies need

flexibility to allow alternative recordkeeping, reporting, and

monitoring approaches that are more cost effective, but

provide equally effective compliance determinations. 

Otherwise, one commenter (IV-D-13) asserted, that sources

would be subject to duplicate recordkeeping requirements and

would incur additional costs and use of resources. One

commenter (IV-D-34) believed that States and local agencies

need flexibility to allow alternative recordkeeping and

reporting requirements as an incentive for enhanced inspection

and maintenance and the installation of high performance

equipment. One commenter (IV-D-51) also requested that the

EPA consider monitoring, reporting and recordkeeping required

for compliance with State and local standards to be equivalent
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to the MACT monitoring, reporting and recordkeeping

requirements of the refinery NESHAP.

Response: The EPA recognizes that unnecessary

monitoring, recordkeeping, and reporting requirements would

burden both the source and the enforcement agencies. Every

attempt has been made to reduce the amount of monitoring,

recordkeeping, and reporting to only that which is necessary

to demonstrate compliance.

Consistent with the Paperwork Reduction Act, the EPA

always attempts to reduce the burden of recordkeeping and

reporting requirements on the regulated community to the

maximum extent, while still maintaining the enforceability of

the rule. The types of data required and frequency of

monitoring and recordkeeping are based on the likely

variability of emissions from the kind of point being

regulated. The EPA believes that the recordkeeping and

reporting requirements in the petroleum refinery NESHAP are

the "bare minimum" necessary to determine compliance on a

continuous basis.

For example, at proposal almost all reports were

consolidated into the Notification of Compliance Status, and

the Periodic Reports. This simplifies and reduces the

frequency of reporting. Sources have the option of retaining

records either in paper copy or in computer readable formats,

whichever is less burdensome. If multiple performance tests

are conducted for the same kind of emission point using the

same test method, only one complete test report is submitted

along with summaries of the results of the other tests. This

reduces the number of lengthy test reports to be copied and

submitted. For continuously monitored parameters, periodic

reporting is limited to excursions outside the established

ranges. The in-range values are not required to be reported.
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Changes have been made between proposal and promulgation

to further reduce the recordkeeping and reporting burden. In

particular, the requirement to submit an Initial Notification

has been eliminated. Periodic reports are required to be

submitted semiannually for all facilities that do not use

emissions averaging (the proposal would have required

quarterly reports if monitored parameters were out of range

more than a specified percent of the time.)

The final rule also allows retention of hourly average

values of monitored parameters, whereas the proposal would

have required retention of 15-minute records on days when

excess emissions occurred. Provisions were added to avoid

duplicative reporting for equipment subject to multiple NESHAP

and NSPS. The rationale for these changes is presented in the

preceding sections of this chapter. 

The rule contains provisions to request the use of

alternative monitoring and recordkeeping systems, providing

sources the flexibility to use their existing monitoring and

recordkeeping equipment as long as the source can demonstrate

compliance with the rule. Non-automated sources can request

approval to take manual readings and record a value at least

once an hour, for use in determining daily average values. 

Sources wishing to use data compression systems can request

approval to do so. This will allow sources that have data

compression systems already installed or who plan to install a

system to monitor process control, to utilize these systems if

they demonstrate compliance with the rule. These requests can

be approved by the State permit authority. The General

Provisions (§ 63.8(f)(4) of subpart A) also include procedures

for sources to apply to use alternative monitoring procedures.

State and local agencies have the option of enforcing

different, but equivalent, monitoring, recordkeeping, and
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reporting requirements if they submit information on their

program to the EPA for approval under the procedures for

delegation of NESHAP authority under section 112(l) of the

Act.

Furthermore, in cases where reporting requirements of

State or local rules duplicate those of the petroleum

refineries NESHAP, a source can work with their State or local

Title V permit authority to avoid duplicate submittals.

Comment: One commenter (IV-D-20) was concerned that the

4,281 hours estimated per refinery for recordkeeping and

reporting in the preamble represents 2.25 employees per

refinery, which seems excessive since the associated costs

will do nothing to improve the environment. 

One commenter (IV-D-19) argued that the estimate of 4,281

hours per record keeper annually may be valid for smaller,

less complex refineries, but would be much greater for

refineries with greater throughput and complexity. The

commenter (IV-D-19) suggested that the EPA be required to

demonstrate net cost benefit to the recordkeeping and

reporting requirements contained in the proposal, similar to

analyses prepared on the stringency of controls.

One commenter (IV-D-22) added that recordkeeping and

reporting costs were not included in the cost impact analysis. 

Response: The EPA disagrees with the commenter (IV-D-20)

that the recordkeeping and reporting associated costs do

nothing to improve the environment. Although direct HAP

emissions reduction does not occur as a result of

recordkeeping and reporting, it is the only way that the EPA

can ensure that control requirements, and thus HAP emissions

reductions, are met.

The EPA included monitoring, recordkeeping, and reporting

costs along with the cost of control in the cost impact
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analysis done to support the MACT determination. Therefore, a

separate cost analysis for monitoring, recordkeeping and

reporting is not necessary. The EPA has also reduced the

monitoring, recordkeeping, and reporting burden 20 percent

since proposal.

The EPA agrees with the commenter (IV-D-19) that

refineries with a greater throughput and complexity may incur

a greater burden than a smaller refinery. However, those

refineries that are more complex with greater throughputs have

more emission points for which control must be assured. 

Although a larger, more complex refinery may incur a larger

burden than average, the revenue from greater production would

offset any inequities.

Comment: One commenter (IV-D-20) requested that

performance tests conducted prior to the effective date of

this rule be allowed in demonstrating compliance with this

rule (e.g., if flares have previously demonstrated compliance

with the NSPS requirements contained in § 60.18, this should

suffice since these requirements are identical to § 63.11).

Response: Previous test results may be used as long as

the test methods required by the petroleum refineries NESHAP

were used and the process emission characteristics during the

test are still representative of current operations.

Comment: One commenter (IV-D-39) supported an

alternative method of providing operational flexibility that

the EPA would establish through a case-by-case waiver system. 

The commenter's suggested waiver system would allow sources

that meet specific threshold criteria to determine an

alternative compliance option where the control level for the

entire source is at least as stringent as the MACT level of

control. The commenter (IV-D-39) offered to participate in a

pilot project if the EPA decided to pursue one.
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Response: In keeping with the EPA's stated goal in

rulemakings, the EPA is allowing an owner or operator of a

petroleum refinery to emissions average among different

emission points defined under the "affected source" to comply

with the petroleum refinery NESHAP. Similar to the

commenter's suggestion, this offers refineries more

opportunities to find cost-effective emission reductions from

overall facility operations. The averaging provisions are

structured such that "debits" generated by not controlling an

emission point that otherwise would require control must be

balanced by achieving extra control at other refinery emission

points covered by the NESHAP.

10.0 EMISSIONS AVERAGING PROVISIONS

10.1 SHOULD EMISSIONS AVERAGING BE ALLOWED

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-19,

IV-D-20, IV-D-21, IV-D-22, IV-D-25, IV-D-30, IV-D-36, IV-D-38,

IV-D-42, IV-D-44, IV-D-50, IV-D-51, and IV-F-1) expressed

support for the concept of emissions averaging to allow more

cost-effective HAP emission reduction. One commenter

(IV-D-19) found the philosophy of emissions averaging to be

consistent with the published statements of Administrator

Browner, the Common Sense Initiative and Executive Order
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12866. The commenter (IV-D-19) maintained that requiring

facilities to install costly controls when less expensive

controls will achieve the same or greater results does not

make sense. The commenter (IV-D-19) cited the Amoco Yorktown

study as a good example of what emissions averaging attempts

to accomplish. One commenter (IV-D-25) recommended several

changes to the proposed averaging provisions to improve

overall cost-effectiveness, as summarized under sections 10.2

through 10.10 of this chapter. Three commenters (IV-D-12,

IV-D-22, IV-D-42) stated that emissions averaging provides

flexibility to facilities for developing site-specific and/or

the most cost-effective controls for HAP's. Two commenters

(IV-D-20, IV-D-50 and IV-F-1) supported the concept of

emissions averaging as a cost- effective way to achieve

environmental benefits. 

Three commenters (IV-D-15, IV-D-35, IV-D-51) were opposed

to emissions averaging in the proposed rule. One commenter

(IV-D-35) opposed emissions averaging because they do not

believe that it is possible to prove emissions "equally

hazardous." One commenter (IV-D-54) objected to any emissions

averaging scheme because the commenter claimed it is a

loophole for refineries to perform peak pollution dumping. 

The commenter (IV-D-54) contended that averaging lets industry

use cost instead of toxicity as the basis of making emissions

reductions. One commenter (IV-D-52) had serious reservations

about emissions averaging because of the difficulties inherent

in determining compliance and risk.

Three commenters (IV-D-16, IV-D-55, IV-D-57) opposed the

use of emissions averaging for existing and new sources. One

commenter (IV-D-55) expressed concern that emissions averaging

would result in less environmental protection and increased

administrative and enforcement burdens. Two commenters
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(IV-D-55, IV-D-16) suggested that emissions averaging be

eliminated from the proposed regulation. One commenter

(IV-D-55) provided their comments opposing the proposed

emissions averaging provision in the HON for further

explanation of their opposition to the emissions averaging

provision in the proposed regulation. One commenter (IV-D-57)

objected to emissions averaging because it would promote

regulatory and enforcement complexity by allowing averaging

between emission points that operate under different

conditions, processing different materials, and at remote

locations.

One commenter (IV-D-46) stated that emissions averaging

is costly and resource intensive and the level of effort could

be applied to other areas of compliance with greater results. 

The commenter (IV-D-46) asserted that paperwork and workload

could be reduced by eliminating emissions averaging.

Response: Emissions averaging has been maintained in the

final rule as an option for sources to use to comply with

subpart CC. This decision is in keeping with the EPA's

general policy of encouraging the use of flexible compliance

approaches where they can be properly monitored and enforced. 

Under particular circumstances, emissions averaging can

provide sources the flexibility to comply in the least costly

manner while still maintaining a regulation that is workable

and enforceable. The EPA's goal in crafting the emissions

averaging provisions in the final rule has been to make

emissions averaging available to sources faced with some

emission points that are particularly difficult or costly to

control. At the same time, the EPA has structured the

emissions averaging provisions to ease the enforcement burden

on implementing agencies. 
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The rationale for the specific provisions of the

emissions averaging policy is detailed throughout this

chapter. 

Comment: One commenter (IV-D-53) was opposed to

emissions averaging. The commenter (IV-D-53) stated that if

the BWON level of control without the 10 Mg benzene cutoff is

selected as Wastewater MACT and Option 1 is chosen as MACT for

storage vessels, any possibility of emissions averaging will

be eliminated and therefore the provision is unnecessary.

Response: Neither of the options described by the

commenter were chosen as MACT for wastewater or storage

vessels in this rule. Hence, there are opportunities for a

source to use emissions averaging. Moreover, the final rule

has expanded opportunities for using emissions averaging

because emission points at marine terminals can now be

considered as part of the source subject to the rule.

Comment: Four commenters (IV-D-22, IV-D-25 and IV-F-1,

IV-D-42, ID-F-49) opposed allowing States the discretion to

include or exclude emissions averaging. One commenter

(IV-D-22) opposed giving States the option to not include

emissions averaging in the implementation of refinery MACT

because it will allow States to circumvent statutory

requirements to demonstrate increased stringency for not using

emissions averaging. The commenter (IV-D-22) added that it

was possible that the over-control of credit sources will lead

to even greater HAP emission reduction than if all sources

were controlled without averaging. The commenter (IV-D-22)

contended that the rule is a national regulation instead of a

site-specific rule; therefore, all facilities should be

governed by the same standard and compliance approaches. 

Otherwise, the commenter (IV-D-22) asserted some facilities

would suffer economic disadvantages. The commenter (IV-D-22)
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concluded that if States exclude averaging, they should be

required to develop a section 112(l) delegation process. 

Another commenter (IV-D-25) stated that the provision to allow

States to eliminate emissions averaging as a compliance option

is inconsistent with E.O. 12866. The commenter (IV-D-25)

contended that without averaging the rule "specifies the

behavior or manner of compliance that regulated entities must

adopt," ignores the directive that regulations be designed "in

the most cost-effective manner to achieve regulatory

compliance," and stifles innovation. The commenter (IV-D-25)

said that the proposed section 112(l) rule provides ample

flexibility for State agencies, and that the special

provisions to allow adoption of the rule with or without

averaging will actually make the adoption process more complex

for many States. Two commenters on the marine loading rule

(Docket A-90-44: IV-D-92, IV-D-93) argued that State and local

discretion to preclude averaging might effectively eliminate

the utility of emissions averaging.

On the other hand, one commenter (IV-D-55) urged that the

restriction allowing states to implement the MACT standards

without emissions averaging be maintained. The commenter

(IV-D-55) supported the portions of the preamble that allow

State and local agencies "to obtain delegation of the

standards without the averaging provisions without having to

undergo section 112(l) delegation and approval process." The

commenter (IV-D-55) requested that these provisions be

included and clearly stated in the final rule and in the

preamble. Another commenter (IV-D-13) opposed emissions

averaging unless, in addition to allowing States the

flexibility to exclude averaging, the regulation requires that

sources must demonstrate that emissions averaging is more

stringent than MACT and allows States and local agencies to
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require demonstration of no net increase in risk when

emissions averaging is used.

Response: The EPA maintains that States should have

discretion on whether to allow emissions averaging for a

number of reasons. First, the EPA acknowledges that averaging

can be more complex to administer than the rule allowing only

point-by-point compliance, so allowing averaging could

increase the administrative burden, which is an especially

important concern for implementing agencies with limited

personnel and resources. However, the determination of what

constitutes too much administrative burden will differ from

State to State. Some States may consider emissions averaging

an acceptable strategy for compliance and will retain the

program.

Second, the EPA recognized that averaging in the rule

could be inconsistent with some States' ongoing air pollution

control programs. The EPA supports the use of emissions

averaging where it may be appropriate, and maintains again

that the program has been designed to be enforceable and

protective of health and welfare. However, the EPA also

acknowledges that its use must be balanced by the individual

needs of State and local agencies that bear the responsibility

for administering and enforcing the rule. Furthermore, with

the inclusion of these provisions, the EPA does not consider

the stringency of the rule with or without averaging to be an

issue. 

This rule is a national rule that must fit into a

situation that is already not an even "playing field"; States

have differing rules and sites are all unique in terms of

their mix of products, rules that govern them, site layout,

etc. Allowing this discretion will not add to the uneven

"playing field" because without this provision, most States
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already have the ability to exclude emissions averaging

through the section 112(l) rule adjustment process encoded in

40 CFR 63.92, 63.93, and 63.94. Rather, the EPA has decided

to make excluding averaging more simple by exempting the

decision from the section 112(l) rule adjustment process. 

Including this provision will reduce paperwork burdens on

States, expedite delegation of the rule to States, and remove

a potential source of uncertainty for sources subject to the

petroleum refineries NESHAP.

The EPA does not agree that providing for State

discretion in the rule itself is either unnecessary or

burdensome for States. While the section 112(l) rule

adjustment process would also permit States to choose to

implement the rule without averaging, providing for that

choice in the rule itself streamlines the process by

eliminating EPA review of the choice. In addition, since the

section 112(l) rule permits States to make the choice,

providing for the exercise of such discretion in the rule

itself cannot be viewed as placing any new burdens on States. 

The provision of an option will not impose a burden or impose

new requirements; it increases choice and flexibility. 

Because emissions averaging is an alternative compliance

method to the primary control strategy, States should have the

discretion to exclude it as opposed to other provisions that

are essential to the rule and for which no alternative

compliance mechanism has been provided. 

Finally, the EPA predicts that instead of creating

promulgation difficulties and uncertainties, providing the

clarifications in this provision at this time will benefit

sources as well as States. Without this provision, sources

might be uncertain during the section 112(l) rule adjustment

process about whether averaging ultimately would be allowed or
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not in their State, yet would be given no added time for

compliance. The EPA predicts that because of their complex

nature, many sources will need the full time period allowed

for compliance.

Comment: One commenter (IV-D-34) urged the EPA to adopt

emissions averaging with provisions similar to those developed

in the HON. Another commenter (IV-D-57) added that all

restrictions on averaging included in the HON should be

incorporated into this standard.

In contrast, three commenters (IV-D-19, IV-D-21, IV-D-44)

maintained that attaching conditions to emissions averaging,

as was done for the HON, would make emissions averaging

virtually useless for cost-effective HAP emission reduction.

Response: The emissions averaging program in this rule

includes essentially the same provisions as those featured in

the emissions averaging program in the HON. Similarities

between the two rules include the following: inclusion of all

points except equipment leaks and biotreatment units;

interpollutant trading; no averaging at new sources or between

sources; a limit on the number of points that can be included

in averages; no banking of credits; States discretion to allow

averaging; and risk or hazard consideration in averages. More

similarities between the two rules exist other than those

listed here. The similarities are intentional because the

program designed for the HON addressed most of the same

concerns voiced during this rule proposal. The averaging

programs designed for the HON and for this rule strike the

appropriate balance between allowing sources flexibility to

comply and adequately protecting the environment.
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10.2 SCOPE OF EMISSIONS AVERAGING

Comment: Three commenters (IV-D-19, IV-D-25, IV-D-30)

supported including new sources in emissions averaging. One

commenter (IV-D-25) argued that because new source MACT is

based on the single best-controlled source and is very

stringent, it is inevitable that cost-ineffective controls

will be required for some emission points. The commenter

(IV-D-25) therefore concluded that there is a great need for

new and reconstructed sources to be included in the emissions

averages in order to allow more cost-effective means of

achieving equivalent emission reductions. The commenter

(IV-D-25) also disputed the relevance of the proposal

statement that averaging would not be useful because new

sources would be required to meet the NSPS, and commented that

in cases where the NSPS is less stringent than MACT, averaging

would be possible.

On the other hand, three commenters (IV-D-16, IV-D-52,

IV-D-55) supported the exclusion of new sources from emissions

averaging. One commenter (IV-D-55) requested that this

provision be included and clearly stated in the final rule and

in the preamble.

Response: The EPA agrees with some of the commenters

that it is appropriate that emissions averaging be restricted

to existing sources only. Averaging is a mechanism designed

to provide each source the flexibility to comply with the MACT

standard in a way that is most practical and cost-effective

for the individual source. By employing averaging, a source

is able, for example, to avoid adding controls to an outlying

emission point that would be very expensive to control, or to

avoid replacing expensive control technology that does not

achieve enough emission reduction to meet the standard. These

concerns are applicable to existing sources. A new source can
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be designed to avoid expensive outlying emission points, and

retrofitting is obviously not an issue. In addition, when a

new source is constructed, it can be designed to accommodate

the required MACT controls in the most practical and costeffective manner, thus reducing the need for the flexibility

of averaging.

The EPA does not agree with the commenters who argue that

prohibiting averaging at new sources would result in a more

stringent standard. This rule has been drafted to provide

that averaging is no less stringent than the standard without

averaging. Thus, allowing new sources to comply only via use

of the reference control technologies and not via averaging

does not require those sources to meet a more stringent

standard. Instead, it requires them to meet a more specific,

and thus more easily implemented standard. However, even if

prohibiting averaging at new sources would result in new

sources being held to a more stringent standard, such a result

would not be unlawful as the statute clearly provides that new

source standards may be more stringent than those for existing

sources.

Comment: Eight commenters (IV-D-10, IV-D-19, IV-D-20,

IV-D-21, IV-D-22, IV-D-42, IV-D-48, IV-D-51) contended that a

facility composed of several source categories should be

allowed to average emissions across the entire facility. 

Seven commenters on the proposed marine loading rule

(Docket A-90-44: IV-D-23, IV-D-91, IV-D-92, IV-D-93, IV-D-97,

IV-D-99, IV-D-101) also supported averaging across source

categories. Three commenters (IV-D-10, IV-D-22, IV-D-42)

contended that fugitive emissions, marine vessel loading and

gasoline distribution operations should also be included in

emissions averaging. One commenter (IV-D-19) stated that

averaging should be allowed anywhere and everywhere within the 
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contiguous boundaries of a major source. Two commenters

(IV-D-19, IV-D-21) cited facilities where marine operations,

refining operations, gasoline distribution operations and/or

pipeline breakout stations are co-located as being a critical

example because promulgation of MACT standards for these fall

within a seven-month window. The commenter (IV-D-19) 

suggested that the position to prohibit inter-source category

averaging be reconsidered.

One commenter (IV-D-19) claimed that inter-source

category averaging is not precluded by law, citing

section 112(a)(1) in which Congress defined a "major source"

as "a contiguous area under common control." Two commenters

(IV-D-19 and IV-F-1) submitted that inter-source averaging is

supported philosophically by the Common Sense Initiative and

Executive Order 12866.

One commenter (IV-D-25 and IV-F-1) recommended that

emissions averaging should be broadened to include all

emission points subject to MACT controls within a contiguous

major source facility regardless of whether the emission

points are within the same source category. Specifically, the

commenter (IV-D-25 and IV-F-1) would like to include process

units subject to the refineries NESHAP, marine vessel loading

operations, gasoline distribution systems, and process units

subject to the HON in the same emissions averaging when these

units are co-located at refineries. The commenter (IV-D-25

and IV-F-1) cited more cost-effective emission reductions as

an advantage of a broader averaging program and stated that

without emissions averaging the cost of the marine loading

regulation is over $100,000/Mg of HAP reduction. The

commenter (IV-D-25) attached a legal analysis to support their

position that the EPA has ample legal authority to allow MACT

compliance by emissions averaging across source categories. 
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Another commenter (Docket A-90-44: IV-D-91) argued that

emissions averaging will increase flexibility, encourage

innovative control strategies, and result in more cost

effective control and greater HAP emission reduction.

Two commenters (IV-D-51, IV-D-57) recommended that the

earliest compliance date be used for different source

categories with different compliance dates that are included

in an emissions averaging scheme. One commenter (IV-D-25)

suggested that differences in compliance deadlines among

difficult NESHAP should not prevent averaging across source

categories. The commenter (IV-D-25) observed that the

standards for petroleum refineries, marine vessel loading, and

gasoline marketing will be promulgated within a short time

period. The commenter (IV-D-25) suggested that EPA could

address the issue of different compliance dates by requiring

that any emission debits be offset by credits generated at the

same time as the earlier compliance date.

One commenter (IV-D-22) contended that the EPA includes

facilities that are co-located in applicability

determinations; therefore, the same criterion should be used

in emissions averaging provisions. The commenter (IV-D-22)

supported making the refinery MACT rule compatible with the

112(d) intent to base MACT rules on average emission

limitation instead of best controls for each category of

emissions for the best refineries. One commenter (IV-D-49)

recommended including as an option emissions averaging across

all organic source categories co-located at the petroleum

refinery site.

On the other hand, two commenters (IV-D-13, IV-D-57)

contended that it was inappropriate to allow emissions

averaging between source categories. Three commenters on the

proposed marine loading rule (Docket A-90-44: IV-D-94,
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IV-D-98, IV-D-100) opposed averaging emissions between

separate source categories. Two commenters (IV-D-13, IV-D-57)

objected to emissions averaging across facilities and source

categories for MACT standards unless the rule allowed

flexibility for State and local agencies to exclude emission

averaging. One commenter (IV-D-57) contended that the EPA

indicated that such an option would be available, but it was

not in the proposed rules. Another commenter (IV-D-12)

expressed concern that emissions averaging in the proposed

rule would allow too many different kinds of emission points

to be averaged. The commenter (IV-D-12) opposed emissions

averaging across divergent processes and operations because it

would augment the already substantial competitive advantages

enjoyed by large refineries without creating any air quality

benefits. The commenter (IV-D-12) contended that unlike small

refineries, large refineries are vertically integrated with a

diverse array of operations allowing them to cut back high

cost reductions in refinery process and offset them with low

cost reductions in other areas. Therefore, the commenter

(IV-D-12) concluded that emissions averaging should not

include marine loading operations, distribution, or SOCMI

areas.

Response: After studying the arguments presented by the

commenters both for and against a broader averaging approach,

the EPA has decided to retain the narrower approach contained

in the proposed rule.

The EPA agrees with the commenters who argued that the

statute provides broad discretion to define "source," and does

not prohibit averaging in setting standards under

section 112(d) of the Act. However, the EPA has determined

that section 112 does provide some limits on the scope of
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averaging, and that the broader averaging approach exceeds

those limits.

The statute requires the EPA to consider emissions from

the entire facility in order to determine whether it is a

major source subject to a given MACT standard. However, the

EPA is also required to develop a list of source categories,

which are to be composed of "sources" that are then subject to

regulation under MACT standards. Both the language of

section 112(d) and the legislative history indicate that

sources in the category can be co-located with a major source,

but are just as likely to be merely a portion of a facility. 

Thus, a large facility emitting more than 25 tons of multiple

HAP's will, in most cases, be composed of multiple sources in

different source categories subject to standards on different

dates. It does not follow that, because applicability under

section 112 (i.e., whether a facility emits sufficient HAP's

to be considered a major source) is determined on a facilitywide basis, compliance with specific standards written for

sources that comprise only a part of a facility should be

permitted on a facility-wide basis. The most that can be

inferred is that the entire facility is the largest entity

that can be defined as a source within any category, but that

the source in a category can, and often will be, smaller than

the entire facility.

In accordance with section 112(i) of the Act, all sources

in the category for which a standard is in effect must be in

compliance by a specified date. Commenters' arguments that

section 112(i) allows compliance with a standard that is set

for a source category to be achieved by a "source" that is

more extensive than the source in the category (i.e., the

entire major source that the source in the category is a

fraction of), is inconsistent with the specific language of
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section 112(i). Section 112(i) provides different compliance

requirements for new and existing sources. New sources must

comply with an applicable standard earlier than existing

sources, which can be given up to three years to comply. 

Moreover, section 112(i)(3) provides for compliance dates to

be established for "each category or subcategory of existing

sources." This provision clearly applies to compliance by

sources in a category rather than compliance with a standard

by any points within an entire major source. Therefore,

section 112(i) clearly provides for compliance by individual

sources within the relevant category rather than overall

compliance by a major source with a standard applicable to

only part of the major source.

Thus, the EPA is adopting the more limited approach to

averaging that was contained in the proposed rule. All

sources within a given source category must comply

individually with the standard either by application of the

reference control technology or by compliance with an approved

emissions average. Transferring emission reduction

obligations to points outside of the source within the

category would be inconsistent with the requirement of

section 112(d) of the Act that standards be set for sources in

a listed category, and the requirements of section 112(i) that

compliance with such standard be achieved by sources in the

category. 

The petroleum refineries source category has been

redefined since proposal to include marine loading and

gasoline distribution operations located at refineries for

reasons described in the response to the next comment. Thus

these operations can be included in emissions averages. 

Sources in other source categories, such as SOCMI process

units located at refineries, cannot be included in emissions
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averages. The SOCMI is a distinct source category for which a

NESHAP (the HON) was promulgated in April 1994, over a year

ago. The commenters have provided no compelling information

or rationale for changing the source category definition that

was already established under the HON. The HON compliance

date is already established in the April 1994 standards, and

cannot legally be extended beyond the 3-year period allowed by

the Act. Detailed implementation plans for HON sources using

emission averaging must be submitted by October 1995. Thus,

significant planning and investment has already been made

toward compliance with the HON. Changing the source category

and source definitions and allowing averaging across HON and

refinery process units would be disruptive and of little

practical value. Both the HON and refineries NESHAP provide

significant flexibility, without the added complexity of

averaging across SOCMI and refinery process units.

Comment: Four commenters (IV-D-19, IV-D-21, IV-D-25 and

IV-F-1, IV-D-51) supported averaging of refinery emissions

with emissions from marine terminals. In response to the

EPA's request for comments, one commenter (IV-D-25) stated

that including marine loading in emissions averaging will not

appreciably increase the complexity of rule enforcement. The

commenter (IV-D-25) observed that assessment of compliance for

marine loading is no more difficult than for storage vessels,

process vents, or wastewater operations and should not be a

reason to exclude marine loading from emissions averaging. 

The commenter (IV-D-25) added that emission factors for marine

loading and other transfer operations are well characterized

and accepted, so credit and debit calculations will be

practical.

In response to EPA concerns about the equity of allowing

emissions averaging for marine loading at refineries, while
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other marine loading operations would not have a similar means

of reducing compliance costs, the commenter (IV-D-25)

suggested two solutions. First, commenter (IV-D-25) suggested

expanding averaging outside the source category such that

marine loading operations located at gasoline marketing

terminals or other sources could also use emissions averaging. 

Second, commenter (IV-D-25) suggested that the proposed marine

loading rule should be revised to exclude small operations

emitting low levels of HAP's. Another commenter (IV-D-51)

added that marine terminals connected to the refinery

operations by pipeline, located near the refinery and

associated with its operations, or if a marine terminal is

integrally linked with the refinery, should be considered "colocated." The commenter (IV-D-51) stated that where the

operations of a refinery are dependant on the marine terminal

for its supply, and the refinery is the main supplier of

commodities going to the marine terminal they should be

considered one facility. The commenter (IV-D-51) recommended

allowing averaging of refining emission sources with those at

marine terminal loading operations because it would reduce

costs and provide flexibility in achieving the required

reductions. 

In contrast, four commenters (IV-D-46, IV-D-48, IV-D-52,

IV-D-57) opposed the inclusion of marine loading emissions in

the emissions averaging scheme. One commenter on the marine

loading rule (Docket A-90-44: IV-D-98) also opposed including

marine loading in emissions averaging. Two commenters

(IV-D-48, Docket A-90-44: IV-D-98) argued that marine loading

and petroleum refineries are two separate source categories

and that the Act does not permit averaging across source

categories. (See section 3.1 for additional comments on

source category selection.) 
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Three commenters (IV-D-46, IV-D-48, Docket A-90-44:

IV-D-98) claimed that averaging with marine loading operations

will result in uncontrolled peak emissions. The commenters

(IV-D-46, IV-D-48) pointed out that marine loading generates

significant emissions during loading and little between

loading. The commenters (IV-D-46, IV-D-48) claimed that

including marine loading operations in emissions averaging

would allow high peak concentrations and augment a facilities

emissions' contribution to peak ozone concentrations,

violating the health standard and limiting the health effects

of the proposed regulation. One commenter (IV-D-46) added

that making up for marine loading emissions by controlling

other refinery units would be complicated because of the

variability of materials due to changes in market demand. The

commenter (IV-D-46) contended that balancing the emissions

would be difficult and cumbersome and the owner/operator could

easily be in noncompliance. 

Two commenters (IV-D-48, Docket A-90-44: IV-D-98) claimed

that the EPA has not proposed monitoring sufficient to

reliably determine the amount of emissions allowed or emission

reductions generated for marine loading operations. One

commenter (IV-D-48) also provided that the Amoco Yorktown

study identified marine loading as a cost-effective emission

reduction opportunity. Two commenters (IV-D-46, IV-D-48)

stated that this opportunity should be addressed by the marine

loading rule. One commenter (IV-D-48) disagreed with the

study's conclusion that supported a broader averaging. The

commenter (IV-D-48) stated that there were many technical

deficiencies in the study. The commenter (IV-D-48) suggested

that emissions reductions could be achieved by additional

controls on wastewater, which the commenter did not agree are
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cost ineffective, as opposed to including marine loading

operations. 

One commenter (IV-D-46) recommended variables to be taken

into consideration in calculating emissions from marine vessel

loading operations, if they are to be included in emissions

averaging. The commenter (IV-D-46) also suggested potential

methods to be used and potential difficulties that may be

encountered.

One commenter (IV-D-57) provided the following reasons

for objecting to averaging between refineries and marine

vessels: (1) the categories are separate because marine

terminals are major sources in their own right and their

operation is not continuous; (2) SOCMI products are covered

under the Marine Vessel category as well as refinery products;

(3) marine terminals are often separated from the refinery

plant site by a substantial distance; which has significant

impacts on the exposed population, because there may be two or

more entirely separate exposed populations; and (4) the

disparate nature of the operations could reasonably result in

exposure spikes, when batch processes are left uncontrolled in

exchange for control of continuous emissions. 

One commenter (IV-D-52) disagreed with the proposal to

include marine vessel loading operations in emissions

averaging because emissions from marine vessels are so high

that an incidental amount of overcontrol might allow a

refinery to avoid control of most other HAP sources, thereby

circumventing the intent of Title III to apply MACT to all HAP

sources. Additional comments for and against including marine

loading in emissions averages that were submitted to the

marine loading regulation docket (A-90-44) are summarized in

the promulgation BID for that regulation.
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Response: In the final rule, emission points in marine

vessel loading and unloading facilities and bulk gasoline

terminals co-located with a refinery have been included in the

petroleum refinery source category and in the definition of

"source" for the petroleum refineries NESHAP. Under the final

rule, emission points from marine vessel loading and bulk

gasoline terminal transfer racks may be included in an

emissions average with other refinery process unit emission

points. Because marine loading operations and bulk gasoline

transfer operations located at refineries are supplying raw

materials to petroleum refinery process units or transferring

products of the refinery process units, they are logically

considered part of the same source as the petroleum refinery

process units. (In a similar way, loading of SOCMI chemical

products into tank trucks and railcars was considered part of

the chemical manufacturing process unit for sources subject to

the HON). Marine loading and bulk gasoline terminal

operations at refineries must be operated in close connection

with refinery process units since they supply feed to and

receive products from these units. Because marine loading and

bulk gasoline terminals have been defined to be part of the

source subject to the petroleum refineries rule, the

prohibition against intersource averaging is not violated.

In keeping with the EPA's stated goal of increasing

flexibility in rulemakings, this decision has been made to

provide more opportunities to average and in so doing optimize

the opportunities for finding cost-effective emission

reductions from overall facility operations on-site. Controls

cannot be designated for each and every point in a refinery

source due to economics and site-specific variations. 

Emissions averaging allows the owner or operator to find the

optimal control strategy for their particular situation.
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In this line, the Amoco Yorktown study must not be overused to conclude that marine loading is always cost effective

to control. Specific emission estimates, cost estimates, and

control strategies for the Yorktown facility may not represent

other refineries due to site-specific differences, and

uncertainties in the Yorktown cost and emission estimates. 

The study does highlight the importance of compliance

flexibility and site-specific pollution prevention strategies

to achieve cost-effective control. Emissions averaging allows

this flexibility. 

In regards to the comments on peak exposure, the EPA took

this into account by requiring a quarterly check along with

the requirement that debits and credits balance annually. If

a State believes that further consideration of peak exposure

is needed, it can be taken into account in their own risk

assessment methodologies; they are free to consider it in the

hazard or risk equivalency demonstration.

Comment: One commenter (IV-D-48) stated if marine

operations are included in emissions averaging, the deadlines

for establishing emission standards for petroleum refineries

must be accelerated to the marine vessel schedule. Another

commenter (IV-D-46) stated that all deadlines for petroleum

refineries and marine vessels should remain separate, except

for the emission averaging deadlines. The commenter (IV-D-46)

suggested that averaging plans and compliance deadlines should

be based on promulgation of the regulation that is promulgated

last.

Response: Because marine loading and bulk gasoline

terminals located at refineries are now included in the

petroleum refineries source category and are subject to

subpart CC, the compliance date for these operations is the

same as for petroleum refining process units. The EPA has
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amended the marine vessel loading and unloading operations

NESHAP MACT standards schedule to the same schedule as the

petroleum refineries NESHAP. Marine vessel loading operation

sources subject to reasonably available control technology

(RACT) standards, under section 63.560(c), must be in

compliance with the MACT provisions (RACT is equal to MACT) on

and after 2 years after the promulgation date. 

Comment: One commenter (IV-D-19) objected to the

exclusion of fugitive emissions from averaging. One commenter

(IV-D-25) requested that the EPA reconsider including

equipment leaks in the emissions averaging program. The

commenter (IV-D-25) suggested that emission data they have

previously submitted to the EPA could be used to quantify

emissions for purposes of averaging. The commenter (IV-D-25)

gave specific examples of equipment leak control programs that

could generate credits, such as using lower leak definition

rates than required by the rule or performing LDAR on streams

that would otherwise be excluded.

Response: The EPA acknowledges that methods are

available for quantifying emissions from equipment leaks;

however, this is not at issue in emissions averaging. 

Equipment leaks cannot be included in emissions averages for

two reasons. First, a reference control efficiency cannot be

established for the standard for equipment leaks because the

percent reduction achieved by complying with the equipment

leaks provisions of subpart CC will vary depending on the

characteristics of the process and the equipment being

controlled. Second, no method currently exists for

determining allowable emissions for leaks, i.e., residual

emissions from equipment controlled according to subpart CC. 

Without a reference control efficiency or the ability to

assign allowable emissions, debits and credits cannot be
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established for any kind of point. Third, there is no

practical way for enforcement to verify compliance.

Comment: One commenter (IV-D-20) requested that the

wording in § 63.650(d)(4) be revised to say "Wastewater,

whether or not treated in a biological treatment unit, cannot

be used to generate credits or debits." Another commenter

(IV-D-46) who requested that wastewater streams be excluded

from emissions averaging claimed that wastewater emissions are

difficult to quantify due to changing conditions and lack of

calculation techniques. The commenter (IV-D-46) contended

that the transitory nature of wastewater is contradictory to

the basis of emissions averaging. The commenter (IV-D-46)

requested that if wastewater emissions are not excluded, they

be subject to more rigorous monitoring and testing and a more

conservative discount factor, such as three to one, be used.

Response: The EPA considers the estimation of wastewater

emissions on an annual basis to be as reliable as for the

other kinds of points and hence, suitable for inclusion in

emissions averaging.

The EPA has recognized that the testing procedures for

measuring emissions from areas such as surface impoundments

influence the emission mechanisms and would not yield accurate

estimates of actual emissions. Therefore, credits for

wastewater streams, as well as applicability of this rule to

wastewater streams and Group status of streams, are determined

at the stream point of generation. Also, if a wastewater

stream is being controlled as a credit generator, the stream

must comply with the standards for transport and handling

equipment, which require suppression to eliminate the

influence of factors such as wind speed, and surface

configurations. This ensures that the only emissions that

need to be considered are those from the control device.
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As in the case of other emission points, characteristics

such as HAP concentration, temperature, and flow rate remain

relatively constant in wastewater streams so that

representative values can be used. The rule provides that if

operating conditions change such that previously measured

values are no longer representative, the values must be

redetermined.

The rule specifies that wastewater streams treated in

biological treatment units are not eligible for emissions

averaging. All other types of control are acceptable as long

as their reduction efficiency can be determined. The EPA is

confident that by making biological treatment of wastewater

ineligible for averaging, the potential for underestimation of

wastewater emissions will be minimized.

Comment: One commenter (IV-D-48) recommended that

emissions averaging be limited to allow only emission points

that are unfeasible or impractical to control in some

extraordinary way to be included.

Response: Emissions averaging is intended to be used for

just such emission points referred to by the commenter. 

However, the source does not have to make any type of

demonstration of feasibility or practicality of controlling an

emission point to include it in an average. As long as

emissions credits and debits can be calculated accurately

through use of the equations in the rule, the kinds of

emission points specified in the rule will be eligible for

inclusion in averages.

Comment: One commenter (IV-D-46) supported use of the

HON threshold criteria (hazard or risk equivalency, discount

factor) in the petroleum refinery NESHAP. The commenter

(IV-D-46) did not support including cost as a threshold

criterion for an interpollutant averaging scheme. The
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commenter (IV-D-46) contended that extreme cost would be

different for different size refineries and difficult to

define. The commenter (IV-D-46) agreed with using

environment-based criteria, but asserted that using cost-based

criteria is beyond the authority of the EPA.

Response: In the final rule the EPA has maintained the

threshold criteria used at proposal and in the HON (hazard or

risk equivalency and a discount factor). No additional

threshold criteria was added, including ones based on cost.

Comment: Two commenters (IV-D-57, Docket A-90-44:

IV-D-100) asserted that emissions averaging should not be

allowed if a net VOC increase would occur. The commenter

(IV-D-57) stated that HAP decreases should not occur at the

expense of potential ozone increases.

Response: If another State or Federal regulation applies

to an emission point subject to this rule, the more stringent

of the requirements takes precedence. As such, if another

rule requires control more stringent than the reference

control technology (RCT) established by this rule, the point

cannot be left uncontrolled or undercontrolled as a debit

generator in an emissions average. However, if controls are

installed after 1990 and achieve more stringent control than

is required by the other State or Federal rule, the emission

point is eligible as a credit generator in an emissions

average, but only for the control above what is required by

the other rule.

Even if the RCT established in this rule is the more

stringent of two requirements, the source must maintain the

control established by the other requirement. If the point

were controlled with the RCT from this rule, both requirements

would be met. However, if the source plans to use the point

as a debit generator, the point must still meet the other
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requirement. The emission point can be used as an

undercontrolled (according to this rule) debit generator for

which the difference in control between this rule and the

other requirement is the basis for the debits.

Comment: One commenter (IV-D-57) supported a case-bycase review of proposals to average, rather than making a

blanket allowance for the category. The commenter (IV-D-57)

supported requiring a source to demonstrate the burden faced

by the source in complying without averaging as well as

enhanced environmental benefits from averaging. 

One commenter (IV-D-46) stated opposition to an option

for compliance allowing case-by case waivers for facilities

meeting certain threshold criteria. The commenter (IV-D-46)

claimed that the system would be too burdensome with a third

option. Additionally, the commenter (IV-D-46) stated that

case-by-case waivers should be administered at the State, not

Federal, level. The commenter (IV-D-46) asserted that if

waivers are allowed, the associated emission points should be

considered in an averaging program.

Response: Emissions averaging is allowed for all sources

except those in States that exercise the discretion to exclude

it from their implementation of the rule. Including the

program in the rule is preferable to a case-by-case "variance

waiver" approach to allowing or disallowing emissions

averages. Again, the decision to include emissions averaging

was made to increase the flexibility of sources to comply with

the rule as long as equivalent emission reductions to pointby-point compliance is ensured.

The EPA does not consider it necessary for a source to

submit comparative cost or burden analyses with proposals to

emissions average. As long as the emissions average achieves

equivalent emission reductions to compliance on a point-by-
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point basis, the average is suitable. Furthermore,

incorporation of a discount factor in the averaging program

provides some assurance of an enhanced environmental benefit

from the use of averaging.

10.3 INTERPOLLUTANT TRADING AND RISK ANALYSIS

Comment: Four commenters (IV-D-16, IV-D-48, IV-D-52,

IV-D-55) supported the requirement that sources demonstrate

equivalent risk in their emissions average and that the

methodology chosen to make this assessment will be determined

by the implementing agency. One commenter (IV-D-46) requested

that specific steps for determining equivalent risk be

provided. The commenter (IV-D-46) recommended that the health

risk analysis include carcinogenicity, acute and chronic

impacts, bioaccumulation, and existing chemical background

levels. The commenter (IV-D-46) also requested that the

effects of dispersion and exposure spikes be addressed. Two

commenters (IV-D-46, IV-D-57) supported making risk

demonstrations required for refinery sources as stringent as

those for the HON. One commenter (IV-D-57) stated that the

rule should specify that where the assessment methods

available can not adequately address the potential health

impacts of a proposed averaging scenario, the averaging should

be disallowed. The commenter (IV-D-57) stated that Protocols

must be approved in advance on a case-by-case basis. 

In contrast, five commenters (IV-D-10, IV-D-19, IV-D-22,

IV-D-25, IV-D-36) opposed the requirement to demonstrate

equivalent risk when opting for emissions averaging. Two

commenters on the proposed marine loading rule (Docket A-90-

44: IV-D-92, IV-D-93) commented that equivalent risk

demonstration has no place in a technology-based regulation. 

One commenter (IV-D-22) concluded that the MACT provisions do

not require risk to be equal across different source
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categories and also do not require risk to be equal within a

given source category. One commenter (IV-D-36) stated that

health risk assessment should not be required as it is

expensive and time-consuming.

One commenter (IV-D-25) contended that risk assessments

will be a significant burden and will discourage emissions

averaging. The commenter (IV-D-25) thought it is unreasonable

and arbitrary to require risk demonstrations without regard to

whether risks are significant or insignificant. The commenter

(IV-D-25) further contended that there is no evidence that

averaging will create unacceptable risks, and that in some

cases averaging may reduce risks. One commenter (IV-D-10)

also added that after installation of MACT controls or

establishment of work practices, health risks would be

significantly reduced. The commenter (IV-D-10) concluded that

addressing health risks now would halt any emissions averaging

program. 

Response: It is appropriate to introduce the

consideration of risk in emissions averaging. The floor and

the RCT's for the rule were determined without any

consideration of risk. On the other hand, averaging

represents an alternative to the technology-based system of

point-by-point compliance, and as an alternative, must be

demonstrated to result in equivalent control. This

demonstration can consider risk without violating the intent

of section 112(d) of the Act.

It is possible that in some cases having to make a risk

equivalency demonstration may so increase the cost of

averaging that it is no longer more cost-effective to average,

but the EPA does not think this is likely in most cases

because of the limited size of most averages. Even though it

is difficult to predict whether averaging would be more likely
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to increase or decrease risk, any possibility of increased

risk would represent HAP control that is not completely

equivalent to point-by-point compliance. 

The EPA considers risk assessment methodologies and

toxicological information to be developed sufficiently to make

adequate risk and hazard equivalency determinations. The EPA

will not establish a presumptive minimum process for making

determinations; however, an annotated bibliography of hazard

and risk assessment references is being published by EPA to

assist State and local agencies and the industry in locating

suitable methods for their situation. The provisions of the

final rule are that risk or hazard equivalency demonstrations

are to be made to the satisfaction of the implementing agency. 

As such, the process is left entirely at the discretion of the

implementing agencies. They are free to use any methodologies

and procedures they choose. 

Comment: Three commenters (IV-D-10, IV-D-22, IV-D-25)

argued that the proposed risk equivalency demonstration

provisions should be eliminated. Two commenters (IV-D-10,

IV-D-25) claimed that it is inappropriate to address risk

under section 122(d) of the Act because standards prescribed

under section 112(d)(2) are to be based on technology, not

risk, and risk will be adequately addressed in the future

under section 112(f). One commenter (IV-D-19) cited

section 112(f) of the Act as reserving risk assessments for

eight years after promulgation of a section 112(d) standard. 

One commenter (IV-D-25) noted that section 112(d) lists

emission reduction, costs, and other factors to be considered

in setting MACT standards, but does not list risk. The

commenter (IV-D-25) claimed that Congress' exclusion of risk

from section 112(d) was deliberate, and that Congress intended

EPA to establish technology-based standards first, and then
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address remaining residual risks 8 years later. One commenter

(IV-D-10) added that residual health risk is to be addressed

after the installation of MACT controls or the establishment

of work practice standards. The commenter (IV-D-25) contended

that the refinery NESHAP, with averaging, will achieve

substantial emission and risk reductions, and that the

potential for small remaining health risks should not

compromise the effort to make the NESHAP requirements as

efficient and cost-effective as possible.

Response: The EPA believes it has the authority under

the Act to establish provisions as part of the alternative

averaging system that will assure that there is no increase in

risk or hazard as a result of a source's election of the

averaging compliance option. The fact that section 112(f) of

the Act contemplates that residual risk will be evaluated at a

later time and that other provisions specifically call for the

consideration of risk does not mean that the EPA is precluded

from considering risk or hazard in other contexts. 

Consequently, the EPA maintains that it has the authority to

address risk and hazard in the averaging program through a

procedure such as the one adopted in the final rule--the

requirement that sources that 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.

Comment: Four commenters (IV-D-35, IV-D-48, IV-D-54,

IV-D-55) opposed interpollutant trading. 

Two commenters (IV-D-35, IV-D-55) explained that they are

opposed to emissions averaging because they do not believe

that it is possible to determine equitable trades for

chemicals with varying toxicity. Two commenters (IV-D-35,

IV-D-48) asserted that interpollutant trading is legally and
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scientifically unsound because not enough data exist for

ranking and a sophisticated methodology that can be used to

accurately rank chemicals has yet to be developed. 

One commenter (IV-D-35) maintained that interpollutant

trading would not ensure greater emission reductions than a

direct implementation of MACT. The commenter (IV-D-35)

further claimed that one-directional "equivalence" is

theoretically more feasible than two-directional. The

commenter (IV-D-35) contended that while it is possible to

determine which chemical's emissions should be a high priority

for reduction, it is not possible to determine how much

emissions of a less hazardous chemical must be reduced to

account for increased or continued emissions of a more

hazardous chemical. The commenter (IV-D-35) further explained

the above arguments by providing summary of their comments on

the ranking scheme proposed by section 112(g) of the Act. The

commenter (IV-D-35) also provided the complete comments as an

attachment.

One commenter (IV-D-54) objected to interpollutant

trading on the grounds that interpollutant trading would

increase workplace hazards and increase adverse health effects

to the community. One commenter (IV-D-55) asserted that the

public health risks of interpollutant trading are uncertain

and should be reviewed by experts in public health risk

assessment before being included in any national policy. 

One commenter (IV-D-48) claimed that trading can be

accomplished without interpollutant trading. The commenter

(IV-D-48) contended that the reasoning for allowing

interpollutant trading in the HON, that there are a large

number of chemicals and chemical processes in SOCMI

facilities, does not hold true for petroleum refineries. The

commenter (IV-D-48) stated that if the EPA concluded that
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trading cannot be accomplished without interpollutant trading,

trading should not be allowed at all.

The commenter (IV-D-48) contended that if interpollutant

trading is allowed by the proposed regulation, the

requirements for evaluating risk should be much stronger than

those required by the HON. The commenter (IV-D-48) suggested

that the EPA require demonstration that the trade reduces

hazard, reduces risk, and provides greater benefit for the

environment. The commenter (IV-D-48) claimed that it is

inappropriate for companies to determine which health risk a

community will be exposed to; the commenter (IV-D-48)

requested that the population a certain distance from the

facility have the right to veto the proposed average.

On the other hand, one commenter (IV-D-36) suggested that

trading HAP's on a pound for pound basis would have little

adverse effect on the surrounding community because in

petroleum refineries HAP's generally exist in low

concentrations. The commenter (IV-D-36) also proposed that a

simplified method of determining toxicity could be used. The

commenter (IV-D-36) offered a weighing factor method developed

by the Bay Area Quality Management District in California as

an example. The commenter (IV-D-36) suggested that

pound-for-pound or weight-factor tradeoffs be allowed if the

nearest residential area is more than a specified distance

from a facility. 

Response: As stated at proposal, the EPA considers it

appropriate to allow interpollutant trading, i.e., to allow

emissions of different HAP's to be included in emissions

averages. To restrict averaging to only points emitting the

same HAP would be excessively restrictive in this industry

where emission streams are mixtures of different HAP's. The

requirement in the final rule of a risk or hazard equivalency
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demonstration should help to allay concerns for public health

and welfare. Worker health and safety continues to be guarded

by other Federal statutes, and allowing averaging of different

HAP's will not compromise that protection.

The EPA is also sensitive to the charges that a HAPspeciated averaging system would consume additional resources

and increase the administrative burden for both sources and

implementing agencies. However, many States already require

risk or hazard examinations, and so would not consider the

demonstration of risk or hazard equivalency an additional

burden. Moreover, the limit on the number of points that can

be included in averages should minimize any additional burden

and cost.

The EPA agrees with the claims that sources have no

incentive to propose emissions averages that could increase

risk or hazard, and stated as much at proposal. However, the

EPA was equally persuaded that a source's decision to average

will be based largely on technical and economic criteria, and

so recognized the necessity of elevating risk or hazard as a

consideration in averaging as well. If sources will control

the most hazardous emissions first for the reasons commenters

stated, then they need not fear that a risk or hazard

examination would severely limit their averages.

The EPA acknowledges that limitations in the scientific

understanding of HAP toxicity exist. However, the EPA does

not believe the limitations are substantial enough to make

interpollutant trading impossible or to bar implementing

agencies from making adequate risk and hazard evaluations. 

The EPA agrees that trades should not result in increased

hazard or risk from any source. In the final rule, the State

or local regulatory agency can prevent any of the situations

described by commenters from occurring by restricting or
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rejecting emissions averaging plans that do not demonstrate

hazard or risk equivalency to their satisfaction.

Comment: Four commenters (IV-D-55, IV-D-35, IV-D-16)

urged that the hazard ranking system developed under

section 112(g) of the Act not be used for emissions averaging

in this rule. One commenter (IV-D-55) asserted that the

section 112(g) de minimis and hazard ranking scheme were

developed to comply with specific conditions and are not

applicable to other situations because of the assumptions

used. The commenter (IV-D-55) recommended that the EPA

prepare a memorandum on how the de minimis and hazard ranking

were derived and warn that they not be adapted to other

regulations. The commenter (IV-D-57) added that until the

hazard ranking scheme in section 112(g) has undergone full

peer review and has been tested in practice on similar

sources, it should not be used to determine the acceptability

of a trade. One commenter (IV-D-25) contended that

toxicity-based credit and debit determination would add

complexity and difficulty. The commenter (IV-D-25) also noted

that several compounds, (including 2,2,4-trimethylpentane

[iso-octane], which is a common component of refinery

emissions) are unranked under the proposed section 112(g)

rules.

In contrast, two commenters (IV-D-46, IV-D-48)

recommended that the restrictions on interpollutant trading be

at least as stringent as those in section 112(g). One

commenter (IV-D-46) requested that an offsetting definition of

"less hazardous pollutant" be used instead of "less hazardous

quantity."

Response: The EPA has published an annotated

bibliography of references that represents a collection of

methods for carrying out comparative risk and hazard
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determinations. States can select a method from this

bibliography as guidance or they may use their own established

procedures, or review procedures used by plants proposing

averages on a case-by-case basis. A State agency has full

discretion if it so chooses to employ a method similar to or

based on the system incorporated into the proposed rule

implementing section 112(g) of the Act. On the other hand, if

a State has an established risk estimation protocol for their

State air toxics rules, they may choose to use those

procedures. 

Comment: Two commenters (IV-D-13, IV-D-57) supported

requiring risk demonstrations for emissions averaging without

requiring a section 112(l) equivalency submittal. One

commenter (IV-D-34) contended that the two most important

provisions to include in this NESHAP and to allow without

requiring a section 112(l) equivalency submittal are: (1) that

States (or local agencies) be allowed to decide when emissions

averaging is appropriate, and (2) that States be allowed to

require a demonstration of no net increase in risk when

emissions averaging is used.

Response: The commenters' concerns have been met because

as stated in section 10.1 of this chapter, States do have the

discretion to exclude emissions averaging from their

implementation of the rule without having to go through the

section 112(l) rule adjustment process. Likewise, a risk or

hazard equivalency determination is required for proposed

emissions averages. Furthermore, the provision allowing

States to avoid the section 112(l) rule adjustment process has

no bearing on the requirement for a risk or hazard

determination.

10.4 NUMBER OF POINTS IN AVERAGES
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Comment: Six commenters (IV-D-10, IV-D-19, IV-D-22,

IV-D-25, IV-D-36, IV-D-49) opposed limiting the number of

points that can be included in an average to 20. One

commenter (IV-D-36) stated that regardless of the number of

emission points, the net result will be emissions equal to or

less than without averaging. The commenter (IV-D-36)

contended that the limit is an additional constraint without

corresponding environmental benefit. One commenter (IV-D-10)

stated that the EPA did not provide any factual basis for

limiting the number of points. The commenter (IV-D-10) added

that because the EPA has legal authority to allow emissions

averaging within a major source, the EPA must first show a

logical and rational basis to limit the number of emission

points before imposing such a limitation. 

One commenter (IV-D-25) claimed that the EPA has not

demonstrated that the burden that would result from

eliminating the limitation on the number of emission points

would outweigh the advantages to facilities that would use

emissions averaging. The commenter (IV-D-25) contended that

the additional monitoring, recordkeeping, and reporting

requirements for emissions averaging will reduce the burden of

agency enforcement activities, so a limitation on the number

of emission points is not necessary to address enforcement

concerns. The commenter (IV-D-25) also argued that the

limitation on the number of emission points would preclude the

future possibility of equipment leaks being included in

emissions averaging. The commenter (IV-D-25) observed that

averaging may be used to avoid costs of control for numerous

small emission points by over-controlling a few large emission

points, and that a limitation on the number of points would

preclude use of averaging in such a situation.
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Two commenters on the marine loading and unloading

operations rule (Docket A-90-44: IV-D-92, IV-D-93) contended

that the limitation on the number of emission points has no

sound basis, and that its elimination will not significantly

increase the burden on implementing agencies.

In contrast, one commenter (IV-D-55) supported limiting

the number of emissions points in a average. The commenter

(IV-D-55) requested that this provision be included and

clearly stated in the final rule and in the preamble. 

Response: The final rule, as at proposal, limits a

source to including no more than 20 Group 1 and Group 2

emission points in an emissions average. Where pollution

prevention measures are used to control emission points to be

included in an average, no more than 25 points can be

included. For example, if two points to be included in an

average are controlled by the use of a pollution prevention

measure, the source can include up to 22 points in their

emissions average. However, if six or more points in the

average are controlled by pollution prevention, the source can

include no more than 25 points in their average.

It is anticipated that most sources will not find a large

number of opportunities to generate cost-effective credits. 

If so, most averages will involve a limited number of emission

points, and imposing a limit should not affect most sources. 

The EPA rejected the choice of a fixed percentage of points at

a source because for larger sources, this could result in

hundreds of emission points in averages, which is unacceptable

from an enforcement perspective.

The limit of 20 points, 25 if pollution prevention is

used, was chosen because the EPA anticipates that most sources

will rarely want to include more than 20 points in an average. 

A higher number of points is allowed where pollution
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prevention is used in order to encourage pollution prevention

strategies, and because the same pollution prevention measure

may reduce emissions from multiple points. Otherwise,

allowing much more than 20 to 25 points would make enforcement

increasingly untenable. Thus, the competing interests of

flexibility for sources and enforceability were balanced in

this decision. 

There may be situations where overcontrolling a point

could generate enough credits to offset emissions from a

number of smaller debit-generating points, but the limit on

the number of points should not discourage averaging in these

cases. If one credit generator could balance more than

19 debit generators, the limit would ensure that the source

had credits to spare. However, it should be pointed out that

this is not the situation for which emissions averaging was

designed. The more likely situation is where a source finds

it more cost-effective to control some Group 2 points or

overcontrol other Group 1 points than it is to apply the RCT

to a Group 1 point that would otherwise be required. In other

words, averages will probably be constructed by identifying

debit generators first and then locating enough credit

generators to offset the debit generators' emissions.

The EPA does not agree that the implementing agency would

not bear much of the burden of averaging. The source's effort

to comply with monitoring, recordkeeping and reporting

requirements will be matched equally by the agency's oversight

and approval. Nor is future inclusion of equipment leaks in

averages a sufficient reason to not restrict averages. The

limit addresses present concerns. If equipment leaks can be

addressed in averaging at a later date, the limit may be

reexamined at that time.

10.5 GENERATION OF CREDITS AND DEBITS 
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10.5.1 What Actions are Creditable

Comment: Four commenters (IV-D-19, IV-D-20, IV-D-22,

IV-D-25) asserted that the EPA should give credit for

shutdowns. One commenter (IV-D-25) contended that shutdowns

are a legitimate means of reducing emissions and should be

useable to generate credits. The commenter (IV-D-25) proposed

that: shutdowns be creditable for a 5-year lifespan, at

20 percent per year; and shutdowns that are part of the Early

Reductions program, pollution prevention program, or

33/50 program should be creditable based on recent actual

emission estimates.

In contrast, two commenters (IV-D-52) opposed including

shutdown credits in the emissions averaging provisions. One

commenter (IV-D-59) requested that the EPA clarify that slow

downs cannot generate credits. The commenter (IV-D-59) stated

that shutdowns are obviously off limits in § 63.650(d)(3).

Response: It is not appropriate to allow credit in

emissions averaging for permanent shutdowns or slowdowns even

if they are part of an Early Reductions commitment under

section 112(i)(5) of the Act. No matter what the motivation

for a shutdown or slowdown, the emission reductions from the

production curtailment are not made permanent if emissions

averaging credit is allowed. If credit were granted for the

emission reduction, the source could then emit an equal amount

of emissions from its debit generators. This is in contrast

to point-by-point compliance, where if a point is shut down,

the emissions reduction is permanent. To allow credit in

emissions averaging for permanent shutdowns and slowdowns

results in less stringent compliance and more total emissions

than point-by-point compliance, in which case emissions

averaging does not represent an equivalent compliance

alternative.
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Comment: One commenter (IV-D-48) claimed that allowing

facilities to credit prior reductions lowers emission

reductions to less than the maximum achievable. The commenter

(IV-D-48) stated that EPA does not have the authority to allow

facilities to achieve less than the maximum achievable

reduction in emissions. The commenter (IV-D-48) claimed that

facilities that have voluntarily reduced emissions have

already been rewarded by an extension of the facilities MACT

compliance deadline, improved public relations, reduced future

compliance costs. The commenter (IV-D-48) asserted that the

EPA never promised industry that voluntary reduction would be

creditable toward future requirements. The commenter

(IV-D-48) alleged that Congress has determined that early

reductions cannot be used for crediting. The commenter

(IV-D-48) cited Title One. Cong. Rec. S. 2989 (March 22, 1990)

and rejection of a Bush Administration proposal as proof that

Congress does not support allowing the 90 percent early MACT

reductions as a creditable surplus because they were required.

The commenter (IV-D-48) argued that Congress intended sources

to fully comply with MACT standard once the 6-year period of

the alternative emission limitation is over. The commenter

(IV-D-48) claimed that some refineries would be able to exempt

themselves from MACT standards completely due to post-1990

reductions. The commenter (IV-D-48) also claimed that the

credits proposed by the EPA go against Congressional intent by

crediting non-enforceable prior reductions. The commenter

contended that Congress intended the Early Reductions program

to offer deadline extensions for enforceable reductions. The

commenter (IV-D-48) claimed that allowing credits for early

reductions is double-counting. The commenter (IV-D-48)

provided an example of how a prior emission reduction could be
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double-counted. The commenter (IV-D-48) suggested that

double-counting be prohibited.

Response: As at proposal, credit is not allowed in the

final rule for actions taken prior to November 15, 1990, the

date of passage of the 1990 Amendments to the Act. Emission

reductions from previous actions prior to that date occurred

for reasons unrelated to the Amendments (such as other State

requirements) or this rule and are included in the source's

control on the baseline date. If the EPA allowed reductions

from such previous actions to qualify for credits, then the

source would be able to generate more debits and, thus, more

total emissions than would be allowed under point-by-point

compliance.

The provision is necessary to maintain emissions

averaging as an alternative means of compliance, achieving

equal or greater reductions than the rule without averaging. 

Credit cannot be allowed for previous actions (taken prior to

November 15, 1990), which enables a source to emit more

pollution than would otherwise be allowed. Also, if a

previous reduction was required by another State or Federal

rule, the control can be used to meet the requirements for

Group 1 points in this rule as long as the control is to the

level that the rule specifies. However, the control cannot be

used to generate emissions averaging credit.

It is possible that because no credit is allowed for

previous actions, some owners and operators may choose to

relocate existing controls from Group 2 points to other points

instead of installing new devices as long as the controls on

the Group 2 points were not required by other State or Federal

rules. However, as long as the higher-emitting Group 1 points

are controlled to the required level or reductions equivalent
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to controlling Group 1 points are achieved, the objective of

the rule is realized.

Comment: One commenter (IV-D-59) maintained that if a

source-wide average is used, the EPA must take emission

reductions achieved through pollution prevention into account

in determining the MACT achievable emission reduction for the

source.

Response: Credit is allowed for reductions achieved by a

pollution prevention measure applied after November 15, 1990

to a Group 2 point or to a Group 1 point if the pollution

prevention measure achieves reductions greater than what could

be achieved using the RCT.

The EPA acknowledges that some of the emission reductions

from a pollution prevention measure will be offset by emission

increases elsewhere in the source if the pollution prevention

measure is used to generate credit for an average. However,

the EPA does not agree that emissions averaging interferes

with the intent of pollution prevention by allowing emissions

to be "shifted" instead of preventing their release

altogether. The intent of pollution prevention is to reduce

emissions in an economical and environmentally sound manner. 

Under emissions averaging, it does not matter how emissions

are controlled so long as the level of reduction required by

the rule is achieved.

Pollution prevention is a method to reduce emissions that

is highly desirable because it often results in emission

reductions in several media. The EPA encourages its use to

the fullest extent; this emphasis in encouraging pollution

prevention is one of the reasons for allowing the use of

emissions averaging.

Comment: One commenter (IV-D-40) suggested revising the

pollution prevention provisions to include out-of-process
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recycling. The commenter (IV-D-40) stated that pollution

prevention is defined too narrowly. The commenter (IV-D-40)

suggested adding preventive maintenance programs to the list

of pollution prevention measures contained in

§ 63.650(j)(1)(ii).

Response: Because in-process recycling is a pollution

prevention measure, it can be used to generate credits. 

Credits would be calculated as provided in the rule for any

pollution prevention measure. On the other hand, it has been

determined that emission reductions from out-of-process

recycling, which is not a pollution prevention measure, cannot

be included in emissions averaging because out-of-process

recycling is out of the jurisdiction of this rule. Out-ofprocess recycling involves waste management outside of the

source, and thus is not subject to this standard.

Comment: One commenter (IV-D-25) found it acceptable to

exclude credits for greater efficiency for reference control

technologies.

One commenter (IV-D-59) asked the EPA to clarify in

§ 63.650(d)(2) that sources may never claim credit for using

RCT at greater than the efficiency presumed by the EPA; and

only technologies that are fundamentally different from the

reference control technologies and that achieve better results

than the reference control efficiency are allowed credit.

Response: Reference control efficiency ratings for RCT

were established because there is a minimum level of emissions

reduction that can be achieved by each RCT. It is

acknowledged that due to the different characteristics of

emissions to be controlled, RCT can sometimes achieve greater

emission reductions than predicted by the RCT's reference

efficiency rating. However, the EPA still maintains that

providing credits for these instances of better RCT
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performance is inappropriate for the same reasons stated in

the proposal preamble.

First, the magnitude of debits, not just credits, is

based on the RCT's reference efficiency ratings. Emission

debits are calculated as the difference between the actual

uncontrolled or undercontrolled emissions and the emissions if

RCT had been installed. Of course, because debit generators

are uncontrolled or undercontrolled, the actual control

efficiency that would have been achieved by the RCT cannot be

determined, so a reference control efficiency must be assumed. 

It is impractical to require continuous testing of the debit

generator to determine the actual level of control that would

be achieved if RCT were applied.

If it could be determined that the RCT on a debit

generator could achieve greater reductions than its rated

efficiency, the magnitude of debits from the point would be

greater. Thus, to give credit for reductions above an RCT's

rated efficiency and not to increase the magnitude of debits

as well would represent a windfall from averaging. It would

also result in a net increase in emissions over the level that

would be expected if there were no emissions averaging. The

policy of reference control efficiency ratings for RCT is fair

as long as it is applied equally to debit and credit

generators.

Second, to grant credits for the small amount of emission

difference that might occur above a reference efficiency would

lead to significant enforcement problems. It would be very

difficult for a source to ensure that, on a continuous basis,

an RCT achieves an emissions reduction above its reference

efficiency rating. It would be even more difficult, if not

impossible, for sources to prove to inspectors that they are

in fact achieving these higher levels of efficiency. Use of a
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reference control efficiency for each RCT allows inspectors to

simply check that the equipment is in place and operating as

planned. Then, the implementing agency can check records to

examine the calculation of debits and credits in order to make

a compliance determination.

Hence, the use of reference efficiency ratings helps

ensure that the emissions averaging system will result in the

same or greater emission reductions as point-by-point

compliance. In addition, the use of reference efficiency

ratings simplifies the emissions averaging system, thus making

it more easily enforced.

Allowing credits for reductions that go beyond a

benchline standard (i.e., the reference control efficiency) is

consistent with the concept of MACT. Although reference

efficiencies have been established for the RCT's, the EPA does

not consider it inconsistent to allow credit for higher

efficiencies achieved by means other than the RCT's. If a

source can achieve a higher control efficiency than a RCT

through use of an alternative technology or pollution

prevention measure, it is achieving more emission reduction

than required by MACT. The source's alternative technology or

pollution prevention measure may not have been established as

MACT because MACT must be set for a source category, and as

such, must be universally available for that source category. 

The fact that one source can employ control technologies that

exceed MACT does not mean all sources can use the same

technologies.

Comment: One commenter (IV-D-22) contended that the RCT

for storage tanks should not include fittings. The commenter

stated that if fittings are installed the emissions averaging

provisions should allow credit to be generated for the

fittings.
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Response: The RCT for storage tanks does not include

controlled fittings. In other words, an owner or operator

does not have to apply controlled fittings to a storage tank

for the assigned 95 percent reference control efficiency to

apply. Installing controlled fittings to a storage tank only

increases the percent emission reduction by about 1 percent. 

Because emissions from a storage tank are relatively low, the

amount of credit that would result from applying controlled

fittings is very small. It should be noted that an owner or

operator can request approval for a higher nominal efficiency

for technologies that are unique or for situations where the

RCT is used in a unique way. Approval for a higher nominal

efficiency for certain fittings may be possible.

10.5.2 Discount Factors

Comment: Four commenters (IV-D-19, IV-D-25 and IV-F-1,

IV-D-36, IV-D-38) objected to the 10 percent discount factor

to be applied to emissions savings. One commenter (IV-D-19)

submitted that a discount factor does not support the purpose

of emissions averaging or Executive Order 12866. Two

commenters (IV-D-19, IV-D-36) objected to the discount factor

as a penalty for attempting to be innovative and achieve

compliance cost-effectively. One of the commenters (IV-D-19)

asserted that the purpose of emissions averaging was to

provide options for achieving compliance in a cost-effective

manner without invoking a penalty. Two commenters (IV-D-36,

IV-D-38) asserted that the discount factor reduces the utility

and incentive of using emissions averaging as well as reducing

flexibility. One of the commenters (IV-D-36) argued that the

EPA's justification that the cost savings should be shared

with the environment was weak and that the environment will

benefit from the regulation without the penalty. Two

commenters on the proposed marine loading and unloading
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operations rule (Docket A-90-44: IV-D-92, IV-D-93) argued that

the 10 percent discount unfairly penalizes those who utilize

emissions averaging and will act as a deterrent to use.

Four commenters (IV-D-22, IV-D-25, IV-D-49, IV-D-51)

opposed using discount factors. One commenter (IV-D-25)

opposed any discounting because discounting will act as a

deterrent to averaging and defeat the cost-effectiveness of

the averaging program. The commenter (IV-D-25) argued that a

discount factor will preserve the competitive disadvantage of

facilities with higher than typical compliance costs. The

commenter (IV-D-25) also argued that a discount factor will

penalize innovation by requiring innovative compliance methods

to achieve greater emission reduction. One commenter

(IV-D-22) stated that there is no justification for any

discount. The commenter (IV-D-22) contended that a facility

should not be punished because it implements a cost-effective

approach to compliance. Another commenter (IV-D-51) asserted

that any discounting of emission credits is unnecessary and

will act as a disincentive to participating in an averaging

program, ultimately defeating the cost-effectiveness of the

program. However, the commenter (IV-D-51) stated that if a

discount factor is unavoidable to promulgate an emissions

averaging provision, then it should not exceed more than

10 percent. The commenter (IV-D-51) stated that proposed MACT

and RACT reductions are significant and the flexibility to

meet the standard by emissions averaging should not be

precluded by additional reductions.

In contrast, one commenter (IV-D-55) supported the

inclusion of a discount factor for emissions averaging. The

commenter (IV-D-55) requested that this provision be included

and clearly stated in the final rule and in the preamble.
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Response: A discount factor of 10 percent is required

in calculating credits in the final rule. An exception is

provided for reductions accomplished by the use of pollution

prevention measures. For pollution prevention measures, full

credit with no discounting is allowed.

The EPA acknowledges that a credit discount factor will

make averaging of points with marginal differences in cost

effectiveness unlikely. However, the EPA disagrees with

commenters that a discount factor could completely eliminate

the incentive to achieve compliance through emissions

averaging. 

The goal of emissions averaging is not to enable sources

to reduce their overall compliance costs to the industry

average, or to gain a competitive advantage. Rather, the

purpose of averaging is to allow sources to comply with the

rule in the least costly manner for their site-specific

situation. Sources will definitely realize cost savings using

emissions averaging instead of installing RCT; otherwise, they

will not use emissions averaging. The purpose of a discount

factor, then, is to ensure that the emission points selected

for averages are the ones where truly significant cost savings

can be realized and to share this savings with the

environment.

The EPA accepts the rationale for using a credit discount

factor that the environment should also benefit from cost

savings achieved through emissions averaging. On the other

hand, the use of a discount factor is not inconsistent with

the Act nor does it represent a "price" or penalty for using

averaging. Emissions averaging is an alternative method for

complying with the MACT standard that offers flexibility and

the opportunity to apply a more cost-effective control option

for compliance. Sources are able to lower their control costs
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for the points included in the average below the cost required

to comply on a point-by-point basis. The decision to include

a discount factor recognizes that a portion of the cost

savings could be used to benefit the environment, i.e., to

achieve more emission reductions than is required under pointby-point compliance.

The EPA does not consider sharing a 10 percent portion of

savings with the environment to be so great a disincentive to

dissuade many sources from choosing to use averaging. Sources

will always realize lower control costs under averaging versus

point-by-point compliance. If this were not so or if the

source does not consider the cost savings substantial enough,

the option of emissions averaging would not be selected.

Credits generated by pollution prevention measures are

not discounted in the final rule. The EPA is not concerned

that a discount factor would discourage the use of pollution

prevention or any other type of control that could achieve

significant cost savings. Rather, no discount factor is being

applied to pollution prevention to identify it as the

preferred method of achieving emission reductions and thus

encourage its use.

Only measures that qualify as pollution prevention

activities according to the EPA's Pollution Prevention

Strategy are considered pollution prevention measures under

the rule and therefore are not discounted. The emissions

reductions from these measures are fully quantifiable. The

EPA cannot confirm one commenter's suggestion that pollution

prevention measures are less expensive to implement than other

types of controls; the commenter provided no accompanying

data. In fact, these measures can require more planning,

process redesign, and lead time than add-on measures. The EPA

does not share the concern that the discount factor selected
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for the final rule will discourage the development of

innovative control technologies because the value of the

discount factor is small. The EPA expects that new

technologies that can reduce emissions more than existing

technologies, and do so more cost-effectively, will be

developed and implemented regardless of the application of a

small discount factor.

10.6 AVERAGING COMPLIANCE PERIOD

Comment: One commenter (IV-D-25) supported the proposed

annual average compliance period with quarterly reporting

because it will allow for seasonal and other short-term

variation. The commenter (IV-D-25) opposed any shorter

compliance periods (with or without banking) because shorter

periods do not allow enough flexibility for seasonal variation

in emissions or short-term production variations and would

significantly discourage the use of emissions averaging. The

commenter (IV-D-25) contended that the quarterly excursion

limits and reports will provide sufficient information for

enforcement on a timely basis and prevent excessive short-term

emissions.

Another commenter (IV-D-46) suggested that the compliance

period is adequate if a violation is considered to have

occurred at the end of the compliance period, when

noncompliance is reported, as opposed to when a device fails. 

The commenter (IV-D-46) explained that this allows

administrative action to be taken up to one year after the end

of the compliance period.

On the other hand, one commenter (IV-D-48) opposed the

annual compliance period because peak exposures would be

higher than they would be with a shorter compliance period. 

The commenter (IV-D-48) asserted that the EPA recognized this

in its proposed economic incentives rule. Another commenter
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(IV-D-48) claimed that the annual compliance period may make

administrative enforcement impossible. The commenter

(IV-D-48) cited administrative enforcement as a

Congressionally approved, inexpensive tool that should not be

made unusable. The commenter (IV-D-48) stated that the

quarterly cap permitting administrative enforcement when

sources produce more than 30 percent extra emissions does not

provide an adequate check because administrative enforcement

could not be used if sources stayed within the cap but

violated the annual limit. The commenter (IV-D-48) asserted

that the EPA should not allow exceedances of 5 to 29 percent

to become unenforceable through administrative enforcement

mechanisms.

Response: The compliance period for averaging that was

proposed, an annual period with quarterly checks, has been

maintained for the final rule. Allowing averaging over a

year's time instead of just one quarter provides flexibility

for sources whose production rates vary over time. It also

factors in the seasonal changes in products of refineries. 

This is an extremely critical factor for this industry. The

additional requirement that debits cannot exceed credits by

more than 30 percent in any one quarter should assure that

wide-ranging fluctuations in HAP emissions will not occur.

A shorter averaging period than annual would preclude the

use of some emission points in averages. An annual period

allows inclusion of points that: (1) do not have the same

emission rates during some periods of the year; and (2) must

undergo temporary maintenance shutdowns at different times

during the year. Hence, an annual period provides sources the

necessary latitude to construct the most cost-effective

averages. Moreover, the EPA considers it within their
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authority under the Act to establish the averaging period as

any length that can be demonstrated to be enforceable. 

The EPA is satisfied that the annual period will not pose

any significant enforcement and administrative problems. It

is true that the annual averaging period could reduce the

EPA's ability to use administrative enforcement actions. 

However, the requirement of a quarterly emissions check

enables use of the administrative enforcement mechanism and

allows more frequent enforcement than just once a year. 

Judicial proceedings can also be undertaken against sources

violating the annual average or the quarterly check.

Comment: One commenter (IV-D-25) suggested that debits

be allowed to exceed credits by 30 percent in any quarterly

reporting period to allow for seasonal variation. However,

the commenter (IV-D-25) also commented that, in some cases,

the alternative quarterly excursion limit based on allowable

emissions in the operating permit may be an improvement over

the percentage-based quarterly limit because the emission

level might be easier to calculate than the percentage and

would be more consistent with permit requirements.

Response: The commenter is commenting on an option

proposed in the proposed HON. This option was not chosen for

the final HON nor the proposed petroleum refinery NESHAP. The

rationale for not choosing this option follows.

The EPA did not adopt the allowable emissions alternative

for the quarterly emissions check because of concerns about an

absolute emissions limit based on projections. Operating

levels for calculating allowable emissions are based on

representative predictions of realistic operating scenarios. 

The use of such a system creates an incentive to "game,"

i.e., to project higher operating rates for credit-generating

points than is representative or realistic. In contrast, the
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quarterly check included in the final rule depends on the

actually demonstrated operating rate during the quarter, not

projections.

Under the industry-proposed allowable emissions

alternative, it would make no difference whether the emissions

from a debit generator increase or the emissions from a credit

generator decrease; as long as the total emissions are below

the cap, the facility remains in compliance. However, in

order for a source to be in compliance on an annual basis,

credits from overcontrol must equal or exceed debits from

undercontrolled points in order to result in the same or

greater emission reductions as would have occurred under

point-by-point compliance. A quarterly limit on the debit-tocredit ratio is more consistent with this approach. If the

emissions from a debit point increase and/or the emissions

from the credit point decrease significantly, it could impact

whether or not the facility is in compliance. A large

increase of emissions from a debit generator or decrease in

emissions from a credit generator (i.e., a deviation greater

than 30 percent from the emissions that would have occurred

under a point-by-point compliance) is significant. Therefore,

the debit-to-credit ratio limit represents a better check on

potential annual noncompliance.

In this rule, the source does not need to know what its

total allowable emissions are in any period because the total

emissions are not limited. The source must either maintain

RCT's properly or ensure that debits are balanced by an equal

number of credits with a leeway of 30 percent each quarter. 

The EPA maintains that instead of allowing for an easier

compliance determination, a system of assigning credits based

on allowable emissions requires a great deal more scrutiny of

the source's prediction of operating levels. As stated
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previously, the entire rule is designed to be consistent with

the operating permit program rule encoded at 40 CFR part 70. 

There should be no conflict between this rule and the

operating permit because the quarterly check, as well as the

annual credit/debit balance and the monitoring requirements

will be stipulated as permit conditions.

10.7 BANKING

Comment: One commenter (IV-D-46) stated that banking

should not be included as a compliance provision. The

commenter (IV-D-46) claimed that banking with an annual

compliance period is redundant and banking between compliance

periods would make enforcement problematic and not be

beneficial to public health. Another commenter (IV-D-48)

supported quarterly block averaging without banking as the

best compliance period. The commenter (IV-D-48) expressed

opposition to banking because it increases peak emissions,

allows credits for reduction that would have happened anyway,

and increases gaming and the administrative burden. 

Additionally, the commenter (IV-D-48) found banking to be

inconsistent with maximum achievable reductions.

In contrast, one commenter (IV-D-22) supported banking of

credits. The commenter (IV-D-22) claimed that without

banking, a source will run the risk that unexpected events

will throw off the credit-debit balance during the compliance

period.

Response: Banking of extra credits generated in one

compliance period for use in a future compliance period is not

allowed. The likelihood of significant administrative burden

resulting from tracking the generation and use of banked

credits was the primary reason for not including banking. With

the goal in mind of keeping the administration of the rule as

simple as possible, credit banking represents a complication
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that would affect the source and implementing agency alike. 

Another reason for excluding banking from the proposed and

final rule was the possibility that communities near sources

could experience peak HAP exposures if banked credits were

allowed to offset unexpected increases in emission debits. 

Any additional flexibility offered by banking is offset by the

increased administrative burden and potential for peak

exposures such that little overall advantage can be gained

from allowing credit banking.

10.8 MONITORING

Comment: One commenter (IV-D-25) suggested that EPA

should clarify that if a single monitor is malfunctioning,

then the assumption of minimum credits or maximum debits

applies only to the emission point(s) addressed by the monitor

in question.

Response: The only emission point that is affected by

this provision is the point exhibiting the excursion. If that

point is a credit generator, it will be assumed that the point

generated no credits for the duration of the excursion. No

other points are affected, and the source will not be doubly

penalized.

Comment: The EPA requested comments on whether exposure

spikes could result if batch emission streams were left

uncontrolled in exchange for control of continuous emission

streams, or vice versa. One commenter (IV-D-51) replied that

if a continuous stream is controlled in exchange for control

of a batch stream, emissions reductions could be estimated

using established emission factors for a defined period of

time for the continuous stream, and emissions from the batch

process could be quantified using emission factors. The

commenter (IV-D-51) stated that emissions averaging could work

for batch processes if total emissions over a specific period
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of time were quantified. One commenter on the proposed marine

loading and unloading operations rule (Docket A-90-44:

IV-D-92) stated that the concern about potential exposure

spikes is unwarranted, and that there are many factors that

would need to be analyzed before any conclusions could be made

regarding exposure spikes and adverse health effects.

One commenter (Docket A-90-44: IV-D-100) stated that an

intermittent process should be allowed to offset a continuous

process, but that continuous processes should never be allowed

to offset an intermittent process. The commenter contended

that resulting exposure spikes from intermittent processes

would likely exceed threshold criteria levels for health and

environment equivalency, and gave an example of an

intermittent process occurring once a month that offsets its

emissions with the daily emissions of a continuous process. 

In the commenter's example, actual excess emissions for the

one-day intermittent process are 30 times the offset during

that one day the process emits. The commenter contended that

this emissions spike would dramatically increase acute

exposure and that unfavorable weather conditions and the

location of the loading operation could increase the risk of

public exposure.

Response: In the absence of any significant volume of

response to the request for comment on this issue, the EPA

will allow emissions from batch emission streams to be

included in emissions averages and allow marine terminal and

gasoline distribution loading operations to be included in the

average. The quarterly cap on the ratio of debits to credits

is intended to limit the possibility of exposure peaks. 

Furthermore, the averaging provisions require that the owner

or operator demonstrate to the satisfaction of the State or

local agency, that the emissions average does not increase
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risk or hazard relative to point-by-point compliance. If peak

exposures are a concern, the agency can consider this in

determining whether to approve the average.

Furthermore, there are only a small number of batch vents

at refineries. Coking units are batch processes but the

miscellaneous process vents definition exempts specific vents

from coking units, so these batch vents are not subject to the

standards and would not be included in an average. Thus, it

is expected that few, if any batch vents will be included in

averages. It should be recognized that some emission points

such as storage vessels and loading racks are also

characterized by intermittent emissions somewhat similar to

the discontinuous emissions from batch processes. However,

because loading occurs fairly frequently, and emissions from

an individual loading event are relatively small compared to

total petroleum refinery emissions, such emissions are not

expected to cause significant exposure peaks. The commenter's

example of once per month is not typical of many operations. 

Moreover, no evidence has been presented that emissions

averaging would permit a very different mix of emissions to

occur than would point-by-point compliance. That is, peaks of

exposures from batch streams should be equally likely under

point-by-point compliance as under emissions averaging, so

emissions averaging does not represent a less effective

control strategy on this point.

Comment: One commenter (IV-D-59) supported the EPA's

proposal to assume that points within an average are out of

compliance during the time when some points exceed operating

parameters. The commenter (IV-D-59) suggested, however, that

the EPA should specify that this non-compliance will extend

for the duration of the compliance period, absent proof that

the emissions average was balanced based on comprehensive
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measured emissions data. The commenter (IV-D-59) explained

that if emissions limits were exceeded during a limited period

of time, that provides no justification for assuming, without

proof, that those exceedances were balanced later in the

compliance period. The commenter (IV-D-59) stated that

temporary exceedances should still be a separate short-term

violation even when the short-term violation is balanced out.

Response: Because of the effect an excursion could have

on a control device's effectiveness, a source that experiences

excursions might be in violation of the standard. Hence, as

specified in the rule, when points in an average experience

excursions outside the established operating parameter ranges,

no credits would be assigned to a credit generator and maximum

debits would be assigned to a debit generator for the period

of the excursion. The presumption is that the excursion is

caused by a significant problem in control device operation

and the device is not achieving emission reductions. However,

if the source has data indicating that some partial credits or

debits may be warranted, the rule provides that the source can

submit that information to the implementing agency with their

next Periodic Report. Partial credits and debits can be

assigned with the approval of the implementing agency.

The periodic report will show credits and debits for the

entire quarter, including periods of time when there was not

an excursion. When there is no excursion, the credits and

debits are calculated using the previously established control

device efficiencies and the equations in the rule. If a

control device has been rated at, for example, 98 percent,

that number is used for periods when there is not an

excursion. 

The periodic report will show credits and debits for the

entire quarter, including periods of time when there was not
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an excursion. When there is no excursion, the credits and

debits are calculated using the previously established control

device efficiencies and the equations in the rule. If a

control device has not been rated at, for example, 98 percent,

that number is used for periods when there is not an

excursion. As long as a source uses the equations specified

in the rule correctly and determines the inputs to the

equations according to the stipulated methods, there is no

reason to doubt the accuracy of the debit and credit

estimations.

An exceedance of a monitored operating parameter would

also be considered a short-term violation if the daily average

value is outside the range established in the NCS or operating

permit and if the exceedance is not due to a startup,

shutdown, or malfunction. This provision is the same as for

Group 1 points that are controlled using point-by-point

compliance rather than emissions averaging.

Comment: One commenter (IV-D-59) complained that there

is no basis to verify whether industry estimates of the amount

of the emissions to be debited proves correct in practice,

because the emissions monitoring is inadequate because there

is no monitoring of uncontrolled Group 1 points. The

commenter (IV-D-59) stated that the monitoring of credits is

unreliable, especially for highly variable streams like

wastewater, storage, and loading. The commenter (IV-D-59)

concluded that because the credit is a product of the

percentage reduction and the inlet concentration, a reliable

testing procedure for both numbers on a frequent basis is

necessary to be able to check whether the claimed quantity of

credits is correct. The commenter (IV-D-59) recommended that

the EPA require CEM's where feasible especially for streams

involved in emissions averaging. The commenter maintain that
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in cases where CEM's are not practicable, emissions averaging

should be prohibited. A commenter on the proposed marine

loading and unloading operations rule (Docket A-90-44:

IV-D-98) stated that because the rule does not require realtime monitoring of marine loading and unloading operations

emissions, there is no basis for reliability checking a

source's estimates of credits and debits. The commenter

(Docket A-90-44: IV-D-98) further stated that the 10 percent

discount factor may compensate for the likely imprecision of

emission estimates.

Response: There are several mechanisms for enforcement

of emissions averaging. Monthly credits and debits must be

calculated based on measured and recorded values for different

parameters depending on the kind of emission point, such as

HAP concentration, flow rate, and monthly operating hours for

process vents and rack throughputs for transfer operations. 

Values for some of these parameters (e.g., concentration and

flow) are determined initially rather than measured

continuously, but the rule requires a re-determination when

process or operating changes are made to a debit or credit

generator that could cause the previously measured values to

be no longer representative. Other values that vary from

month to month, such as operating hours for process vents and

throughput for transfer racks, are recorded for each month,

and the monthly values are used to calculate debits and

credits. These procedures and equations in the rule allow

sufficiently accurate estimation of monthly credits and debits

to determine compliance. If credits do not equal or exceed

debits in a year's time, or if debits exceed credits by more

than 30 percent in any quarter, this is a violation of the

emission standard, and enforcement action can be taken.
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Furthermore, the controls applied to most Group 1 and

Group 2 points in an emissions average must be monitored

continuously. It is a violation of the standards if the

monitored average parameter values are outside the established

range, and enforcement actions can be taken. Finally,

provisions in the rule require conservative estimation of

credits and debits during excursions. These procedures will

assure debits are not underestimated and credits are not

overestimated during monitoring excursions.

The EPA considered various means of determining credits

and debits, and concluded that it is not technically feasible

or necessary to use CEM's. To measure emissions continuously,

both CEM's to measure HAP concentrations and continuous flow

monitors would be needed at every emission point. There are

no CEM's available for measurement of some organic HAP's. 

Where CEM's are available, they are generally more costly and

more complex to calibrate and operate than operating parameter

monitors, and may have greater downtime and greater

uncertainty in their measurements. It was determined that the

combination of credit and debit calculations based on

representative operating conditions and records of process

operation such as monthly operating hours and throughputs,

along with continuous monitoring of control device operating

parameters would be a more reliable and efficient means of

enforcing emissions averaging than requiring CEM's. 

10.9 RECORDKEEPING AND REPORTING

Comment: One commenter (IV-D-19) objected strongly to

the requirement for monthly credit and debit calculations,

citing them as unnecessary and unwarranted. The commenter

(IV-D-19) suggested that the requirement should be quarterly

calculations and compliance reporting as required by a

source's part 70 permit. The commenter (IV-D-19) reiterated
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opposition to requirements any more demanding than those they

have suggested, arguing that no added value is provided. 

Another commenter (IV-D-51) contended that the quarterly

reporting of credits and debits is overly burdensome and

unnecessary. Two commenters (IV-D-22, IV-D-51) recommended

annual reporting instead.

Response: The EPA recognizes that some additional

monitoring, recordkeeping, and reporting is necessary for

emissions averaging. For example, credits and debits must be

calculated monthly and reported quarterly to ensure that the

required emission reductions are achieved, and Group 2 points

being used to generate credits must apply the same control

device monitoring as Group 1 points. Owners or operators

should take the recordkeeping and reporting requirements into

account when deciding whether to utilize emissions averaging.

The EPA considers the monitoring, recordkeeping, and

reporting requirements to be the minimum necessary to

demonstrate compliance. The EPA has considered ways to reduce

the general recordkeeping and reporting burden without

sacrificing enforceability. For example, the rule requires

reporting of monitored parameter values only when they are

outside the established range. The rule also allows case-bycase requests to use data compression and other alternative

monitoring and recordkeeping systems that may allow continued

use of current or more cost-effective systems at plants. 

Another provision allows retention of hourly rather than

15-minute average values of monitored parameters. The goal of

these provisions is to reduce the burden for all plants,

including those that utilize emissions averaging.

Comment: One commenter (IV-D-52) contended that the

emissions averaging provisions will be virtually impossible to
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enforce and will result in undue administrative burdens for

tracking and recordkeeping.

Response: The administrative burden of implementing the

emissions averaging program of the rule is one issue voiced by

all concerned parties to which the EPA paid particular

attention. The proposed and final rule were designed with the

express purpose of easing perceived administrative burdens. 

However, some provisions are necessary to improve

enforceability or to ensure public health protection, which

may contribute to the administrative burden. 

Calculation of emission debits and credits are required

for only the points included in an emissions average, not for

all emission points at a source. An average can contain no

more than 20 points, 25 if pollution prevention is used, so

the concern over the number of points for which emission

estimates are required has been addressed. The source need

only calculate two emission values for a debit generator and

two values for the credit generator. For a debit generator,

actual emissions based on the controls in place (if any) and

emissions if the RCT had been applied need to be calculated

and compared. These values can be easily calculated using

estimates of uncontrolled emissions and the reduction

efficiencies of controls that were demonstrated in initial

performance tests, and specific procedures for making

estimates and carrying out performance tests are provided in

the rule. For a credit generator, the emissions that are

allowed under the rule and the actual emissions are calculated

using procedures specified in the rule as well.

The EPA does not consider the estimation methodologies

for averaging to be too complex. Tracking emissions is not

unduly complex either as the points included in averages must

be identified separately in the Implementation Plan or the
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operating permit. Debits and credits are calculated monthly

based on limited inputs such as monthly operating hours and

previously measured values. Adjustment of emission

calculations for fluctuations is required only if an excursion

occurs, and specific procedures have been included in the

final rule to address such situations. It was acknowledged

earlier that some additional monitoring, recordkeeping, and

reporting is necessary to implement emissions averaging and to

ensure proper operation. But, again, the EPA maintains that

with the limits on averaging, any additional burden has been

limited as well and does not far exceed that associated with

compliance on a point-by-point. If, however, an implementing

agency does realize greater costs in administering averages,

the cost could be addressed by applying a higher permit fee

for the points included in emissions averaging.

10.10 MISCELLANEOUS

Comment: One commenter (IV-D-46) expressed an interest

in reviewing the calculations and methods used by the EPA to

determine that emissions averaging between refinery units and

marine loading operations would provide for greater emissions

reductions than reductions achieved without averaging.

Response: The equations and calculations included in the

final rule for estimating emissions from any emission point

included in an average are taken from well-established and

available references. The opportunity for reviewing and

commenting on the use of such equations is during the public

comment period of this and other rules establishing such

equations. The rule is designed to require that emissions

reductions achieved by every emissions average are greater

than or equal to reductions that would be required without

averaging. As required by the rule, the equivalency of

emissions reductions between an emissions average and point-
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by-point compliance is demonstrated by calculating the

difference in the emissions under both scenarios for each

emission point in the average to calculate the credit or debit

for each point. The emission credits (for greater reductions

than required by the standards) must outweigh the debits for

the average to be allowed. Thus, if the average does not

achieve equal reductions to point-by-point compliance

(actually, greater reductions for the average because a

discount factor is applied) then the average cannot be

allowed.

Comment: One commenter (IV-D-54) stated that if

emissions averaging is not removed from the rule, it needs to

be made more stringent by using emission numbers instead of

percentages to reflect the net result of emissions averaging.

Response: It is assumed that by emission numbers, the

commenter is referring to emission rates in units such as

pounds per hour. Emissions averages are balanced in terms of

actual mass of emissions, not percentages. The equations in

the rule result in emission credits and debits in Mg/yr, and

the credits must outweigh the debits. However, calculating

the mass emissions for emissions averaging also depends on

establishing reference control efficiencies. It is not

possible in this rule to determine reference control

efficiencies or emission limits in terms of an emissions rate

because of the large diversity and hence variance in emissions

from the same kind of emission point found in petroleum

refineries. Because of the variation in mass emissions, any

single mass limit would be achievable by some sources with no

controls whereas it could not be achieved by other (e.g.,

larger) sources even if the best controls were applied. On

the other hand, a control efficiency can be established for a

kind of emission point regardless of its emission rate. 
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Because the same percent control efficiencies are applied to

both debit and credit generators, there is no chance of a

discrepancy in comparing emissions between the two.

11.0 ECONOMICS AND BENEFITS ANALYSIS

Comment: Two commenters (IV-D-44, IV-D-07) stated that

the proposed regulation has little environmental benefit while

creating economic hardships for the refining industry. Two

commenters (IV-D-44, IV-D-14) claimed that the costs of the

proposed regulation outweigh the benefits and go against

Executive Order 12866 and the Common Sense Initiative. One

commenter (IV-D-44) suggested that the proposal be withdrawn. 

The commenter (IV-D-44) argued that the risk benefit

calculation by the EPA does not warrant additional controls.

Response: The final regulation provides for significant 

reductions of 48,000 Mg per year of HAP emissions and

252,000 Mg per year of VOC emissions. The refining industry

will as a whole experience a loss of production of less than

one percent of U.S. refining capacity, as estimated in the

economic impact analysis. Between 0 and 7 refineries are

expected to be at risk of closure, with the estimate likely
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being closer to 0 than 7. This was calculated based on

assumptions that likely overestimate the given range. 

The monetized benefits, $153.4 million, exceeded the

social costs (equal to the compliance costs plus $16 million

from increased imports beyond exports) by $58.1 million. All

benefits from VOC control were not monetized. Among the

benefits from VOC control not monetized were chronic health

benefits such as reductions in chronic health effects

(e.g., sinusitis, hay fever),reduced materials damage

(corrosion, deterioration), ecosystem effects (decreased

biomass, decline in species richness and diversity, decreased

lifespan for organisms), aesthetics (unpleasant odors,

visibility), and acute health effects (increased cancer

incidence, genetic damage, reduction in pulmonary function) in

attainment areas.

Thus, there is evidence for additional control and for

not withdrawing the rule. For more information, consult the

regulatory impact analysis. 

Comment: One commenter (IV-D-07) alleged that due to the

fact the current U.S. refining capacity is close to maximum

utilization, if seven refineries are required to close because

of the proposed regulation, the nation's dependence on foreign

oil will increase. The commenter (IV-D-07) also cited the

loss of productivity and jobs, and greater prices for motor

fuels as additional negative effects of the proposed

regulation. The commenter (IV-D-07) requested a more cost

effective regulation.

Response: The economic impact analysis estimated a one

percent reduction in net exports (exports-imports), and a less

than one percent reduction in domestic output of affected

petroleum products. Thus, there is a slight increase in the

U.S.'s demand for foreign petroleum products, which may
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translate into a slight increase in use of foreign oil for

that purpose. The estimate for the number of refineries at

risk of closure was from between 0 and 7, with the estimate

likely being closer to 0 than 7. However, this was calculated

based on assumptions that likely overestimate the given range.

Estimated job losses are expected to be small, with the

reduction being less than 0.5 percent of the U.S. refinery

workforce as of 1993. The price increase for motor fuels

should also be small, as the price increase for five affected

products, including gasoline, is estimated to be under

0.6 percent. 

Comment: One commenter (IV-D-14) claimed that the

proposed regulation will have a major cost impact on

independent producers, who depend on refineries to purchase

wellhead hydrocarbons, but will provide little benefit to the

environment. Commenters (IV-D-14, IV-D-29) requested that the

proposed regulation be re-assessed considering the resultant

consequences from the closure of small refineries. The

commenter (IV-D-14) alleged that less competition and higher

compliance costs for refiners due to the proposed regulation

will drive wellhead prices down. The commenter (IV-D-14) also

stated that closing of small refineries will increase

transportation costs for independent producers, who will have

to use trucks or railcars as opposed to existing pipelines. 

The commenter (IV-D-14) claimed that this increase in cost

could result in severe economic damage to struggling

producers.

Response: The Agency's economic impact analysis focused

on the effects to the refinery industry, the industry most

directly affected by the final regulation. The EPA focuses on

the primary industry (the refinery industry, in this case)
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affected by a regulation since the economic impacts to

secondarily affected industries are usually insignificant.

For more explanation of this, refer to the economic impact

analysis in the public docket. For this analysis, EPA

believes the economic impact on secondarily affected

industries are small because there are only small changes in

domestic output for affected products. As to effects on

transportation costs, the estimate for closures of small

refineries is a range, and it is possible no small refiners

may close. If there are any increases in transportation

costs, they should be small and unlikely to result in severe

economic damage to producers. Since the economic analysis

focused on impacts to the refinery industry, EPA did not

estimate effects on transportation costs, and the resulting

impacts. 

Comment: One commenter (IV-D-14) claimed that the

proposed regulation will increase emissions due to the

estimated closure of up to 30 small refineries. The commenter

(IV-D-14) explained that independent producers will be

required to use trucks and railcars to get oil to larger

refineries when the small refineries that they had pipelines

to are shut down. The commenter (IV-D-14) claimed that trucks

and railcars can pollute more than pipelines. The commenter

(IV-D-14) also contended that large refineries in

nonattainment areas will increase production and therefore

emissions to make up for the loss of production from the

shutdown of small refineries.

Response: The estimate of 30 closures comes from the

"Analysis of the Impact of Environmental Compliance on Plant

Operations," developed by the Agency's OPAR, and its estimate

referred to the possibility that between zero and

30 refineries may be at risk of closure, not that up to
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30 refineries will close. The OPAR's analysis examined the

impacts from a number of EPA regulations from a financial

standpoint, and did not compute the closure risk estimate from

a market analysis standpoint, as was done here to arrive at

the 0 to 7 range. The OPAR's analysis looked at the impacts

from a number of EPA regulations, but did not account for this

NESHAP. 

Any increase in production from refineries in

nonattainment areas should be small, given the small price

increases on affected products. Therefore, any increase in

emissions should also be small. 

Comment: One commenter (IV-D-44) disagreed with the

EPA's estimate of 0.52 statistical life per year for the total

cancer risk from benzene and naphthalene. The commenter

(IV-D-44) contended that naphthalene is classified as a

possible carcinogen, not a known carcinogen, by the EPA and

therefore should not be included in the risk analysis. The

commenter (IV-D-44) estimated that the exclusion of

naphthalene produces a lifetime cancer risk for 0.015 per

million persons. The commenter (IV-D-44) asserted that the

Act permits the EPA to delist a source category if no source

in the category emits HAP's in quantities which may cause a

lifetime cancer risk greater than 1.0 per million persons. 

The commenter (IV-D-44) also alleged that the HEM-I used to

estimate the cancer risks is overly conservative and biases

risk estimates upwards. 

Response: The EPA has revised the risk assessment and

benefits analysis and did not include naphthalene as a

carcinogen. Benzene and cresols are the two HAP's identified

as carcinogens in the revised analysis. While the values in

HEM-I are conservative, the benefit analysis attempted to

calculate values that were not conservative. Our analytical
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methodology did not presume conservative assumptions for

values other than the annual cancer incidence inputs.

Comment: One commenter (IV-D-44) disagreed with the

EPA's estimate of $148.3 million for health effects benefits

resulting from reduction in VOC emissions. The commenter

(IV-D-44) alleged that there were inaccuracies in the

calculation of emissions from miscellaneous process vent

emissions and equipment leaks and explained these

inaccuracies. The commenter (IV-D-44) estimated the general

human health benefits from refinery MACT to be approximately

$49 million. The commenter (IV-D-44) claimed that the VOC

reductions claimed by this regulation will occur as a result

of State Implementation Plans required by the Act.

Response: The EPA appreciates any data that will assist

the Agency in accurately calculating emissions from sources

that will be covered by our regulations. The benefits

calculated by the EPA are in annual terms since the emission

reductions are in annual terms, thus the $49 million estimate

mentioned by the commenter must also be an annual value. 

Controls used to reduce HAP's also reduce VOC in the same

emission streams. Thus, it is appropriate for the Agency to

account for VOC reductions in this rule. 

Comment: One commenter (IV-D-44) alleged that the

proposed regulation fails to take into account the costs

imposed on the refining industry due to other Federal

regulations.

Response: The costs calculated were not cumulative in

that they did not include capital and annual costs from

concurrent and other recently promulgated regulatory actions

affecting the refinery industry. However, the regulatory

alternatives chosen were based on requirements from existing

regulations the refinery industry was already familiar with,
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and thus will make the industry's effort at compliance less

difficult and less costly. 

Comment: One commenter (IV-D-48) alleged that the EPA

ignored Congress' decision not to base standards on

cost-benefit analysis in citing cost benefit analysis as a

rationale for the exemptions in the proposal.

Response: While all MACT rules must control to at least

the MACT floor for the source categories of concern, the

Agency has discretion in going above the floor based on costs.

The promulgated alternatives meet the MACT floor for each type

of emission point except for equipment leaks, and the

alternative is a choice of control levels that each represent

a more stringent alternative than the floor. 

Comment: One commenter (IV-D-48) claimed that the

cost-benefits analysis contains serious flaws. The commenter

(IV-D-48) alleged that toxics release data indicate that

pollutants not quantified or discussed in the RIA are emitted

from petroleum refineries in large quantities. The commenter

(IV-D-48) stated that excluding these pollutants caused the

cost to benefit ratio to be overestimated.

Response: The eleven organic HAP's known to be in

equipment leak emissions are listed in the final RIA and are

listed in the final preamble. Information identifying these

HAP's was taken from the TRI database. While the Agency may

have not included some pollutants from refineries, EPA did

attempt to use the most recent emissions data available. The

commenter did not identify or include data on those pollutants

that the Agency is claimed to not have looked at. 

Comment: One commenter (IV-D-48) claimed that the

cost-benefit analysis is incorrect because non-cancer related

health effects were not characterized or quantified.
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Response: Non-cancer related health effects were

characterized in Chapter 7 of the RIA, and one of those, an

estimate of increases in agricultural yields was quantified

and listed in the promulgation preamble. 

Comment: One commenter (IV-D-48) alleged that the

cost-benefit analysis is inadequate under the E.O. on

environmental justice because it did not consider the health

risks from multiple and cumulative exposures from the combined

pollutants of petroleum and non-petroleum sources. The

commenter (IV-D-48) claimed that this analysis cannot be used

as a decision making tool.

Response: The benefit analysis considered all the

available data from affected sources that were relevant to the

necessary calculations. Data for cumulative exposures to

pollutants from petroleum and non-petroleum sources was not

included in the benefit analysis because it was not available.

Comment: One commenter (IV-D-29) requested that the 

proposed regulation be withdrawn due to a lack of benefits. 

The commenter (IV-D-29) claimed that the EPA has shown that

there is no HAP reduction health benefit associated with this

regulation. The commenter (IV-D-29) acknowledged that the

proposed regulation will reduce VOC, but contended that VOC

reduction does not justify the regulation. The commenter

(IV-D-29) claimed that VOC emissions in nonattainment areas

were already being reduced. Additionally, the commenter

(IV-D-29) alleged that the VOC benefits were overestimated.

Response: There are health benefits from HAP reduction

associated with this regulation. The monetized benefits did

exceed the costs of regulation by $58.1 million, and the

regulatory baseline did account for the latest VOC emission

estimates in ozone nonattainment areas. As to the estimate of

VOC benefits, the estimate does not include VOC benefits for
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the following: 1) acute health benefits in ozone attainment

areas, and 2) chronic health effects, such as fewer cases of

sinusitis, hay fever, damage to materials, and ecosystem

effects. Thus, the estimate may underestimate benefits from

VOC emission reductions. 

Comment: One commenter (IV-D-30) stated that the

proposed emissions standards will increase costs. The

commenter (IV-D-30) stated that the increased costs include

capital costs for additional control equipment and monitoring

systems as well as significant manpower costs to comply with

the recordkeeping and reporting requirements.

Response: The final standard will increase costs, but

the economic impact analysis determined that the impacts from

these costs were insignificant. Price changes and production

decreases were both estimated at under 0.6 percent for

affected products. Estimated recordkeeping and reporting

costs for the final regulation are one-third less than at

proposal ($20 million instead of $30 million), a significant

reduction. This occurred due to reductions in the level of

monitoring required, and reduction in redundant recordkeeping

and reporting activities. 

Comment: One commenter (IV-D-25) claimed that the

economic impact analysis underestimates the portion of the

total refinery MACT compliance costs borne by refiners and

overstates the costs passed on to petroleum product consumers

in the form of price increases.

Response: In estimating these impacts, EPA's analysis

did include price elasticities of demand for the affected

products in the calculations. The price elasticity of demand

is a measure of the response of consumers to a 1 percent

change in the market price for a product. In the case of the

products modeled, the highest elasticity point estimate was
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-0.8 (liquified petroleum gas) to a low of -0.15 (jet fuel). 

Since the price elasticities of demand are all less than -1,

the regulatory control costs are more likely to be paid by the

consumers of these products when compared to products with

elastic demand, all other factors equal. Also, price

increases for products with inelastic demand lead to revenue

increases for their producers. Thus, the price increases

estimated here should lead to higher revenues for the refining

industry, again all other factors being equal. 

While a portion of the compliance cost is borne entirely

by the refiners, they should be able to pass on much of the

remaining costs to consumers given the low demand elasticities

they face. In the long-run, given a high level of

competition, all the costs of control can be passed on to

consumers. As to Gulf and East Coast refiners, it is possible

that they face higher elasticities of demand than those used

in the report, and thus perhaps can pass less of their costs

to consumers by increased product prices. No information was

submitted by the commenter on specific elasticities of demand

for Gulf and East Coast refiners. However, since the

elasticities mentioned earlier incorporate the behavior of

consumers of products produced by these refiners also, the

industry impacts calculated should not be a significant

underestimate. 

Comment: One commenter (IV-D-25) said the economic

impact analysis should distinguish between refineries in

attainment versus nonattainment areas because the magnitude of

the impact will be different.

Response: The cost analysis calculated costs specific to

each affected refinery, and the data used as input to the

costs analysis distinguished between whether a refinery was in
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an ozone nonattainment area or not. Consequently, the

economic impact analysis reflects the distinction. 

Comment: One commenter (IV-D-25) suggested that if

contract workers were considered, estimated employment losses

would be 50 percent higher.

Response: It should be noted that the estimate of

employment losses was quite small (slightly more than 100

nationwide), and even if the analysis considered contract

workers, the job losses would not increase much in the

aggregate. In general, control cost estimates tend to

overstate the costs of emissions control. The Agency

questions the basis for a 50 percent increase in the

employment losses, and hoped that the commenter would provide

more data on how effects on the labor could be better

examined. 

Comment: The commenter (IV-D-25) said the assertion that

an increase in petroleum product imports will be accomplished

by a worsening of merchandise trade balance is simplistic and

not necessarily true.

Response: An increase in petroleum product net imports

will be accompanied by a worsening of the merchandise trade

balance, all other trade factors being equal. It should be

noted that one of the reasons the U.S. merchandise trade

balance has been largely negative for the past several years

has been due to large domestic expenditures on foreign oil, an

increase due to ever-increasing demand for petroleum products. 

However, increasing exports of other goods may offset future

increases in petroleum product imports. The statement made

that the "merchandise trade balance is not a simple function

of a change in imports" is correct. 

Comment: One commenter (IV-D-22) asserted that the EPA's

analysis of the benefits of the proposed MACT rule is
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factually and technically flawed. The commenter (IV-D-22)

stated that the EPA used its HEM-I model which is overly

conservative. The commenter (IV-D-22) also asserted that

naphthalene should not have been used in the risk analysis

because it is not classified as a known carcinogen.

Response: The benefits analysis incorporated the best

information available on the species of HAP's known to be in

refinery emission streams, and while the Agency did use the

HEM-I model for its risk assessment, it did not use those

calculations to calculate overly conservative, worst-case

benefits values. Used in the benefit analysis was a

methodology known as "benefits transfer" that takes a range of

monetary benefits per ton VOC emission reduction from a 1989

study (OTA, "Catching our Breath") and transfers it to the

level of VOC reductions from this rule. This methodology is a

standard way of estimating monetary VOC benefits from

compliance with NESHAP's. Naphthalene will no longer be

classified as a carcinogen in the RIA for promulgation, but

cresols will. 

Comment: One commenter (IV-D-09) contended that the

proposed rule grossly underestimates the cost of compliance

with the proposed regulation, perhaps by as much as a factor

of 3. The commenter (IV-D-09) asserted that industry's 5-year

capital cost will approach $600 million as opposed to the

EPA's estimate of $207 million. The commenter (IV-D-09)

extrapolated this estimate based on estimated costs for their

5 refineries and the total capacity of their industry. The

commenter (IV-D-09) stated that the EPA has historically

underestimated costs at refineries and cited the BWON as an

example. 

Response: The EPA has undertaken its best efforts to

accurately estimate the costs of compliance associated with
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the final regulation. In no way did we attempt to provide an

underestimate of the capital costs of the regulation. The

assertion that industry's 5-year capital cost will approach

attempts an extrapolation from a limited number of refineries

that is inappropriate based on the information submitted to

the Agency. The EPA's estimate was based on the best

information available as to what refineries would have to do

to comply, and the $207 million estimate is based on that

information. 

Comment: One commenter (IV-D-22) contended that the

closure of 7 refineries as a result of the rule will effect

competition. The commenter (IV-D-22) added that the loss of

small businesses and the loss of jobs will have a significant

effect on the national economy. Another commenter (IV-D-12)

asserted that the EPA had underestimated the number of small

refinery closures, and also underestimated the regulatory and

economic impact because it underestimated the costs when

compared to industry estimates. Another commenter (IV-D-06)

asserted that the refinery MACT regulation may not result in

refinery closures as this would more likely be due to Title II

requirements. The commenter (IV-D-06) recommended that the

EPA determine whether any double counting of refinery closures

was included in its analysis.

Response: A range of 0 to 7 refineries that were at risk

of closure was estimated in the economic analysis and further

elaborated on in the regulatory flexibility analysis, an

analysis of the impacts on small businesses from federal

regulations. Due to certain assumptions (e.g., that the firms

with the highest per-unit cost of compliance are the marginal

firms), it is likely that the number of refineries at risk of

closure is closer to 0 than 7. The level of job loss is

expected to be insignificant (less than one-fourth of
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1 percent of all refinery jobs), and the regulatory

flexibility analysis shows that the impact on small refineries

and their employees, while higher than for other refineries,

will be low as well. 

The estimates of costs are not underestimates of the

costs of compliance. We included as much data from industry

as was deemed possible, particularly cost data. 

The comment on possible refinery closures resulting from

compliance with Title II provisions comes from the estimate

provided in the March 1994 EPA report, "Analysis of the Impact

of Environmental Compliance on Plant Operations." It should

be noted that this report came out before the economic impacts

of this regulation were estimated, and the report did not

account for the refineries affected by this Title III

standard. As far as known, there should be no double counting

of refineries at risk of closure. It should be recognized,

however, that the closure risk estimates given in each case

are in ranges, not point estimates. 

Comment: Two commenters (IV-D-12, IV-D-22) noted that

the EPA's own RIA demonstrated that the total cancer risk of

HAP emissions from refineries is low. Therefore, the

commenters (IV-D-12, IV-D-22) contended the rule is

unnecessary, and is an example of one that is in conflict with

the Common Sense Initiative.

Response: While the total cancer risk is low, there is a

sufficiently high level of risk from exposure to HAP's in some

individual refinery emission streams to conclude that risks to

some exposed to emissions from refineries in ozone

nonattainment areas are reduced significantly as a result of

this standard. Our revised risk assessment has shown that

approximately 4.5 million people exposed to refinery emissions

experience a risk of mortality from cancer of greater than
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1 in 1 million, a level of risk that is the cutpoint between a

source category on the list of HAP's in Title III of the Act. 

In addition, the Agency, as it is doing through the Common

Sense Initiative, attempted to enlist industry cooperation at

all points of the rule-making process, and attempted to link

provisions of the rule to regulations already promulgated,

thus limiting additional paperwork and expenditure. 

Comment: One commenter (IV-D-12) urged the EPA to

determine the emission reduction benefits of the rule in

non-attainment areas taking into account the HAP reductions

produced by other federal, state, and local rules.

Response: The regulatory baseline took into account HAP

reductions from other rules as much as possible for ozone

nonattainment and attainment areas. For further detail, refer

to the "Regulatory Impact Analysis for the Petroleum Refinery

NESHAP" document. This document can be retrieved from the

docket for the final rule. The docket for the final rule is

available for public inspection between 8:00 a.m. and

4:00 p.m., Monday through Friday except for Federal holidays,

at the following address: U.S. Environmental Protection

Agency, Air and Radiation Docket and Information Center

(MC-6102), 401 M Street SW, Washington, DC 20460; telephone: 

(202) 260-7548.

Comment: One commenter (IV-D-42) stated that because the

refinery MACT rule is for controlling HAP emissions, the

justification for any refinery MACT requirements should be

based solely on a cost-benefit analysis of HAP's and not VOC. 

However, the commenter (IV-D-42) asserted that the EPA admits

that it was not possible to identify the speciation of HAP

emission reductions for each type of emission point, so the

EPA reported that the benefits associated with the petroleum

refinery NESHAP were determined to be small. The commenter
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(IV-D-42) contended that this was inconsistent with the

requirements of the Act because MACT is a standard from HAP's

not VOC. Therefore, the commenter (IV-D-42) asserted that the

proposed rule is flawed because the stringency of the proposed

refinery MACT rule would not be justified by a cost/benefit

analysis based solely on the reduction of HAP's. The

commenter (IV-D-42) stated that the EPA should not promulgate

the rule until it has done a cost-benefit analysis based on

HAP's.

Response: While this regulation is meant to control HAP

emissions, the Agency recognizes that control of one type of

pollutant often leads to control of other pollutants at the

same time. The emission streams from refineries are primarily

VOC, with a small fraction of HAP's within. Thus, any

benefits estimated to occur from a rule that controls VOC,

though their control is of secondary importance, should be

included as benefits attributable to the rule unless the

reductions will occur as a result of another rule or program

(certain Title I rules, for example). A benefit-cost

comparison based solely on known HAP's leads to negative net

benefits from the rule, but to exclude the benefits from VOC

reduction would be inappropriate. In addition, there are

benefits to HAP reduction we cannot quantify at present

(e.g., reduction of HAP exposure to concentration levels

before the inhalation reference-dose concentration, and

ecosystem effects). 

Comment: One commenter (IV-D-22) asserted that the EPA's

RIA analysis did not include other Act rulemakings that will

be concurrent with the refinery MACT rule. The commenter

(IV-D-22) stated that the EPA's analysis of impacts of

environmental compliance indicate that in addition to the
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7 refinery closures estimated for the refinery MACT, another

30 would be closed because of other rules.

Response: It should be noted that the risk of closure

estimate given in this economic analysis and the other one are

ranges, with zero being at the bottom of the range. Since the

March 1994 analysis of impacts of environmental compliance did

not include the results of the economic analysis for this

rule, there should be no double counting. However, the number

of refineries estimated at risk of closure in these analyses

are likely much lower than 37. 

Comment: Three commenters (IV-D-27, IV-D-28, IV-D-49)

referred to President Clinton's Executive Order 12866 which

directs federal agencies to choose regulatory approaches where

the benefits outweigh the costs. The commenters (IV-D-27,

IV-D-28) contended that the proposed petroleum refinery NESHAP

does not follow this mandate, and therefore should be reevaluated and/or withdrawn completely. [Also see

section 3.2.1 for similar comments about small refineries.] 

Five commenters (IV-D-08, IV-D-27, IV-D-28, IV-D-49, IV-F-1)

stated that the costs of the rule ($207 million in capital

costs and $110 million in annual costs) do not outweigh the

benefits (less than one cancer case per year) and contended

that the proposed rule should be re-evaluated and reproposed

with benefits that justify the costs. 

Response: The final alternatives for each emission point

are at the MACT floor, which is the minimum level of control.

The only exception is equipment leaks, where a more stringent

alternative (to be more precise, a choice of alternatives)

than the floor was found to be more cost-effective. 

Also, the VOC benefits at these alternatives exceeded the

compliance costs by $58.1 million. The HAP benefits

associated with the regulation are low, but control of VOC
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occurs along with HAP control. Consequently, it is proper to

include the benefits of VOC emissions control as part of the

benefits of the rule. 

Comment: Five commenters (IV-D-27, IV-D-28, IV-D-39, 

IV-D-49, IV-F-1) were concerned that the EPA has sought to

justify the costs of this regulation based on VOC reductions,

in light of the minimal HAP reductions. One of the commenters

(IV-D-27) reminded the EPA that the intent of Title III rules

is to minimize the emissions of HAP's. One commenter

(IV-D-27) was under the impression that VOC emissions would be

addressed in the SIP's under Title I of the Act.

Response: The intent of Title III rules is to minimize

emissions of HAP's, but many sources being affected by these

rules have emission streams with high concentrations of VOC. 

Thus, control of VOC often occurs along with control of HAP's

for the same rules. 

Comment: One commenter (IV-D-27) encouraged the EPA to

develop a tiered approach in risk assessments, as recommended

by the National Academy of Sciences report "Science and

Judgement in Risk Assessment." The commenter (IV-D-27)

contended that this tiered approach would recognize the

differences between those refineries that pose a risk to

public health versus those that do not.

Response: The Agency is reviewing the National Academy

of Sciences report. 

Comment: One commenter (IV-D-39) stated that there is

considerable competition in the refining market, that the

number of independent refineries which have historically been

the major oil companies primary competitors, continue a

downward trend. The commenter (IV-D-39) stated that the

number of U.S. refineries has declined by over 45 percent

(315 to 172) with small refineries constituting the majority
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of those shutdowns and job losses of over 500,000. The

commenter (IV-D-39) stated that many independent and small

refineries occupy geographic market niches which if disrupted,

could result in supply shortages and price spikes in certain

areas of the U.S.

Response: While the number of U.S. refineries has

declined considerably over the last fifteen years, the level

of U.S. refinery output has increased from 14.36 million

barrels per day in 1981 to 16.16 million barrels per day in

1992, an increase of 13 percent. These results are associated

with increases in economies of scale associated with petroleum

refining. While many independent and small refineries occupy

geographic market niches, the results from the economic

analysis show that the Refinery NESHAP should not cause supply

shortages and price spikes in rural locations through most of

the U.S.

Comment: One commenter (IV-D-49) contended that the

proposed rule will act as a subsidy for foreign gasoline

imports which is not only unsound public policy, but is in

direct opposition to the Congressional intent of the Act. 

Response: Foreign gasoline importers may experience

additional revenues from the imposition of this regulation,

but the increase will be modest, since the projected product

price changes will be under 0.6 percent at the wholesale

level. The rule is not a subsidy for foreign gasoline

imports.

Comment: One commenter (IV-F-1) contended that the EPA's

cost-effectiveness estimates and overall cost projections of

the proposed rule are understated since the agency did not

include the input of a single small refinery. The commenter

(IV-F-1) estimated that the compliance costs for a small

refinery would be twice that of a larger facility, on a per
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barrel basis. One commenter (IV-D-39) cautioned the EPA that

compliance costs for small refineries as a percentage of sales

are more than twice as high as larger refineries.

Response: The EPA sent ICR's to all facilities in the

industry. The ICR's requested information on HAP emissions,

characteristics of refinery liquids, and control devices at

refinery process units for process vents, storage vessels, and

equipment leaks. No responses were received from refineries

and useable information on all three kinds of emission points

was received from 116 out of 132 refineries. This information

was considered in developing estimates of emissions, emission

reductions possible from application of controls, and cost of

the rule. 

The Agency did include information from small refineries

in the development of the rule and the analyses associated

with it. As part of EPA's Regulatory Flexibility Analysis,

compliance costs for small refineries as a percentage of sales

were estimated at more than twice as high as larger

refineries. This was a calculation required under the Federal

Guidelines for doing Regulatory Flexibility Analyses, and is

consistent with EPA's more recent Guidelines for accomplishing

Regulatory Flexibility Analyses. The economic impacts reflect

this estimate. 

Comment: One commenter (IV-D-50) referred to a report

showing that 91 of 120 petroleum refineries that have shut

down since 1980 were small refineries. The commenter

(IV-D-50) also contended that in the past 14 years, more than

half (56 percent) of all small refineries in the U.S. have

shut down. The commenter (IV-D-50) stated that after the

closures in the early 1980's due primarily to the elimination

of government programs, closures have been related to
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compliance costs of environmental regulations which have

rendered these facilities uneconomic.

Response: It is uncertain as to whether compliance costs

of environmental regulations are related to increased closures

of small refineries. However, economies of scale for refinery

production have grown, and that may be an alternate

explanation as to why average refinery production capacity has

grown, and the smaller refineries are closing.

Comment: One commenter (IV-D-50) stated that the EPA's

economic analysis for the proposed rule fails to consider the

collective costs and impacts of other government requirements

on the petroleum refining industry. The commenter (IV-D-50)

cited a 1993 report contending that the U.S. refining industry

would need to spend $37 billion during this decade to meet

environmental requirements. The commenter (IV-D-50) stated

that small refineries have limited ability to finance the

requirements contained in the proposed rule.

Response: Results from the Regulatory Flexibility

Analysis showed that while there is a possibility that some

small refineries are at risk of closure, most small refineries

will have adequate capital available to finance the purchase

of equipment needed to comply with the requirements. 

Comment: One commenter (IV-F-1) reported that the job

loss connected with the 7 refinery closures due to the

proposed rule would be approximately 10,000 jobs. The

commenter (IV-F-1) included details in an appendix to the

comments.

Response: The economic analysis analyzed the direct

impacts of the regulation, and did not analyze the effects on

nearby communities and other entities. Given that between

0 and 7 refineries are at risk of closure, with the estimate

most likely closer to 0 than 7, the job loss due to indirect
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effects should be nowhere close to 10,000. Estimates of job

losses in the analysis are between 0 and 114. 

Comment: One commenter (IV-D-50) stated that refineries

with operating capacity ranging between 10,000 and

20,000 barrels/day experience a high level of competition

among ourselves as well as from other refineries. The

commenter (IV-D-50) cited a report that stated that most of the

markets served by the small refineries tend to be less

populated regions where economic activity within the area can

hardly support large scale refining operations and most of the

products are sold within a 200 mile radius of the refinery. 

The commenter (IV-D-50) also stated that most of the small

refineries indicated that about 70 percent of the products

moving within their distribution were marketed by major oil

companies.

Response: What is mentioned here about the markets

served by small refiners is consistent with information

already collected by the Agency. Small refiners tend to serve

niche markets, markets that larger refiners typically do not

find profitable to service. There is, however, increasing

competition in regions normally served only by small refiners. 

Major refiners are starting to extend pipelines to more rural

areas, and to market their products in areas of the country

that they have traditionally not served. 

Comment: Two commenters (IV-D-27, IV-D-39) stated that

while the EPA estimated in the proposed rule that more than

7 refineries may be forced to close, that number appears too

low. One commenter (IV-D-27) referred to the draft final

report "Analysis of the Impact of Environmental Compliance on

Plant Operations," which has estimated that up to 30 small

refineries (17 percent of U.S. refineries) would be closed as

a result of Act requirements. The commenter (IV-D-27)
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reminded the EPA that during the Act floor debates it was

stated "MACT is not intended to drive sources to the brink of

shutdown." Commenters stated that the closures of small

refineries will: increase foreign imports of finished

products, permanently damage local economies, as well as

disrupt the chain of local commerce, affecting crude suppliers

and producers, gasoline distributors, independent marketers,

and others. 

Two commenters (IV-D-37, IV-D-60) stated that the

proposed rule is likely to force many producers to ship their

oil further distances, thus driving up costs and increasing

the risk that some oil will be spilled while in transit,

because the proposed emission controls are based on those in

place on large refineries in nonattainment areas and smaller

refineries are likely to be forced to close. 

Three commenters (IV-D-28, IV-D-40, IV-D-50) provided

reasons why smaller refineries will incur higher costs to

reach compliance per unit of output than larger refiners under

the proposed rule: there are diseconomics of scale in

building small facilities; small refineries usually incur

higher capital costs than their larger better financed

competitors; small refineries are predominantly located in

attainment areas where the emission controls are less

stringent than in non-attainment areas; small refineries tend

to be older and less sophisticated, and therefore have further

to go to reach compliance, and would not be able to recover

the costs of implementing control technology by raising

product prices, since competing refineries in non-attainment

areas would not be as significantly impacted. 

Response: The number of refineries at risk of closure

predicted in the economic analysis was from 0 to 7, not 7. 

Due to a number of assumptions that likely overstate the level
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of impact, this range may be an overestimate. The estimate

provided in the other EPA report was also a range; the number

of refineries at risk of closure was from 0 to 30. Since the

ranges given here are likely overstatements, the effects

mentioned on local economies and the chain of suppliers should

be minor. While smaller refineries are more likely to be at

risk of closure than others, again the number should be small

enough that effects from possible closures will have an

insignificant impacts on affected products. The reasons given

by commenters as to why smaller refineries incur higher costs

to reach compliance per unit of output are correct; they are

in the economic impact analysis and the associated Regulatory

Flexibility Analysis.

Comment: One commenter (IV-F-1) stated that

geographically, small refineries that produce light liquid

products, such as gasoline, are located in attainment areas or

in areas that experience few problems; LDAR programs are

modest or non-existent in such facilities. Small refineries

that are located in ozone nonattainment areas generally

manufacture heavier petroleum products such as lubes or

asphalt, or fuel oil. The commenter (IV-F-1) noted, however,

that LDAR programs focus on leaks from light liquid streams. 

The commenter (IV-F-1) stated that the result is an over

regulation of small refineries.

Response: Small refineries typically produce heavy

petroleum products such as lubes, asphalt, or residual fuel as

a greater percentage of their product mix than larger

refineries. The Agency has looked into the possibility that

many refineries making these products may not be subject to

the applicability criteria in the regulation, and therefore

will not be subject to this rule. 
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As part of the consideration of issues regarding the

effects of this rule on small refiners, the EPA analyzed the

refinery data bases to see if subcategorization would change

the requirements for small refiners. The EPA explored

subcategorization based on crude charge capacity, by ozone

attainment status, and by refineries containing processes that

are used to produce gasoline (such as catalytic cracking,

coking, and catalytic reforming). Within each subcategory,

the process vents, storage vessels, and equipment leaks data

bases were sorted from most stringent to least stringent

control. 

 The MACT floor (average of the top 12 percent of

sources) for each subcategory was identified. The MACT floors

for small refineries are not significantly different from the

industry as a whole. The floor for process vents is the same

for small refiners as for the entire industry. The floor for

storage tanks would increase the materials vapor pressure

cutoff from 10 kPa (1.5 psia) to 11 kPa (1.7 psia), which

would result in a minimal cost savings since there are few

petroleum liquids in this volatility range. The floor for

equipment leaks would reduce the monitoring frequency;

however, small refiners would still incur the cost of setting

up and implementing an LDAR program. This analysis is

documented in the docket for this rule.

Based on the EPA's analysis and the comments received

during the public comment period, a separate subcategory for

small refineries has not been included in the final rule. 

This decision was based on there being no clear relationship

between refinery size or design emission potential. 

Comment: Two commenters (IV-D-23, IV-D-24) objected to

the potential for the refinery NESHAP to close seven small

refineries. One commenter (IV-D-24) was concerned that the
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closing of these independent sources of fuel would lessen the

competition in the marketplace and fuel prices will go up.

Response: The results of the economic impact analysis

show that it is likely that reductions in product output will

be small (less than 0.6 percent), and that the number of

refineries at risk of closure is from 0 to 7, with the likely

number of closures between closer to 0 than 7 due to the

assumptions in the economic analysis. Since the estimated

impacts on the refinery industry are small, the chances of

fuel prices (or refinery products prices) increasing are

small, and there would then be minimal changes in the level of

competition in the marketplace. 

Comment: One commenter (IV-D-23) stated that the cost of

complying with refinery NESHAP will be extraordinarily high

for the refinery industry, as reported in the RIA and

specifically for their refinery. In addition, the commenter

(IV-D-23) continued, the refinery NESHAP is only one of many

capital expenditures that increasing regulations demand that

the refinery undertake. Currently, the commenter (IV-D-23)

explained, all of the refinery's available capital is

dedicated to coming into compliance with RCRA rules,

development of reformulated gasoline, low sulfur diesel,

wastewater improvements, and underground storage tank

regulations. The commenter (IV-D-23) contended that the

current EPA policy has promoted an environment where only the

large mega-refineries can survive and is forcing smaller

refineries out of business.

Response: The EPA, in compliance with the Regulatory

Flexibility Act of 1980 and its own Regulatory Flexibility

Analysis Guidelines, attempts to analyze the impacts its rules

have on affected small businesses, not only to determine the

impacts but to find ways of mitigating those impacts if they
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are found to be significant. The Agency has explored

different ways to mitigate the impacts on small businesses

while still promulgating a MACT standard. Those efforts are

underway. The Agency is aware of the rules that refineries

are having to comply along with this standard, and is

cognizant of considering them as we review this standard prior

to promulgation. 

A Regulatory Flexibility Analysis has been completed for

this rule, and its findings were considered in the preparation

of the rule. 

Comment: One commenter (IV-D-24) was concerned about the

cost of the rule being passed on to gasoline marketers, chain

retailers, and, ultimately, the American consumer.

Response: The economic impact analysis showed that the

price changes that consumers, whether they be marketers,

retailers, or drivers, will be small. Estimated price changes

to refiners for affected products should be less than

0.6 percent, and consumers will experience a price change less

than that. This is the case because the incidence of impacts

from the compliance costs will be shared by refiners and

consumers. 

Comment: One commenter (IV-D-24) stated that there is no

rationale for the proposed regulation: the adjusted cancer

risk is very low, and the general benefits to human health

resulting from the proposal do not justify the estimated costs

of the program to the refinery industry. The commenter

(IV-D-24) quoted the EPA cost estimates for complying with the

proposed rule of $850 million and $110 million per year for

monitoring, testing, reporting and compliance costs, and the

estimated benefits to improved human health over the next five

years of $49 million, and concluded that the proposal cannot

be justified and must not be finalized.
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Response: The capital costs for the proposed rule are

$213 million and the total annual costs are $79 million. 

The total annual costs do include a component for capital

recovery, so the capital and annual costs are not additive. 

In addition, the estimated benefits from VOC emissions

reductions are $153.4 million annually. Thus, the annual

benefits, which include benefits from increased agricultural

yields along with those to human health, exceed the annual

costs. In addition, the monetized benefits are likely to be an

underestimate. Reductions in VOC emissions that lead to

reductions in ozone concentrations may contribute to

reductions in chronic health impacts (e.g., sinusitis, hay

fever), and reduced damage to some materials

(e.g., elastomers). None of these benefits were monetized.

Benefits from compliance in ozone attainment areas were also

not accounted for. The same controls for HAP's also control

VOC, and thus these emission reductions are also credited to

the rule. 

12.0 GENERAL POLICY ISSUES

12.1 COMMON SENSE INITIATIVE

Comment: One commenter (IV-D-42) contended that the rule

is in conflict with Executive Order 12866 by not being clearly
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understood, and by using excessive reference to other rules. 

Five commenters (IV-D-10, IV-D-19, IV-D-21, IV-D-25, IV-D-57)

asserted that reading, understanding and complying with the

regulation in the specified compliance periods has been made

more difficult by cross-referencing with provisions in the

SOCMI HON. Three commenters (IV-D-19) (IV-D-21) IV-D-48)

suggested that if a provision of a MACT standard is to be

duplicated, it should be reprinted in the new regulation. 

Additionally, one commenter (IV-D-19) pointed out that

amending regulations to which other regulations refer could

prove difficult.

Two commenters (IV-D-06, IV-D-25) suggested rewriting the

rule to flow logically without cross-referencing other

sections or other regulations. The commenters (IV-D-06,

IV-D-25) also suggested use of flow charts to describe

applicability and tables to summarize requirements. The

commenters (IV-D-06, IV-D-25) also suggested listing the

reporting and recordkeeping requirements with the sections for

each type of emission point instead of at the end of the

entire rule. One commenter (IV-D-57) recommended providing a

table of HON requirements and those of other incorporated

rules.

Response: The EPA appreciates the commenters'

suggestions for improving the structure of the proposed

regulation. The EPA agrees that efforts should be made to

ensure that a regulation can be read and understood with

minimal difficulty.

Many changes were made to the final rule to make it

clearer: all recordkeeping and reporting requirements were

included in the rule instead of being referred to in other

rules, a table was provided describing which general provision

requirements pertain, and guidance was given on overlapping
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requirements. However, the rule still cross-references other

regulations control requirements. This was done to avoid

inadvertently introducing errors through small changes in

wording and because of the savings in time, paper and printing

costs. The EPA does not consider the proposed rule to be in

conflict with Executive Order 12866.

Comment: One commenter (IV-D-57) recommended providing a

table of the HON requirements and those of other incorporated

rules. One commenter (IV-D-06) stated that the format of the

Refinery MACT regulation should be simplified, showing all the

section and sub-section designations on each sub-section, or

by indenting each sub-section further than in the section it

belongs in. 

Response: The format for section and subsection

designations is standard for all Federal regulations and

cannot be changed for this rule.

The EPA evaluated whether the use of tables or charts

could be used to simplify the regulation and found that the

kind and volume of information that would be required for

provisions not already presented in these formats made it an

impractical option.

Comments received on previous rules (e.g., HON) indicated

a preference for this format and there would be no substantive

difference in the rule by putting recordkeeping and reporting

requirements with each emission point. Therefore, the EPA

maintained recordkeeping and reporting all in one place

instead of with each kind of emission point.

12.2 PUBLICATION OF REGULATIONS

Comment: Several commenters (IV-D-09, IV-D-10, IV-D-19,

IV-D-40, IV-D-38, IV-D-42, IV-D-51) objected to the EPA not

publishing the rule in the Federal Register. One commenter

(IV-D-51) stated that without publication of the proposed rule
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in the Federal Register, it is difficult if not impossible for

the owner or operator of new or modified sources to ensure

exactly its legal and technical changes to the source to

comply with the final rule. The commenter (IV-D-51) also

stated that not printing in the Federal Register undermines

any enforcement action the EPA may wish to take against an

owner or operator. The commenter (IV-D-51) contended that

this additional time, given to sources caught in the trap

between the proposal date and the final date of a NESHAP rule,

has been provided explicitly in the Act at section 112(i)(2).

One commenter (IV-D-09) added that not publishing the

rule in the Federal Register resulted in confusion and delay

during the comment period. Another commenter (IV-D-42) stated

that those who do not have the computer capability to access

the EPA bulletin board are left out of the comment process. 

Two commenters (IV-D-25, IV-D-38) asserted that failure to

publish regulations in the Federal Register impairs the

public's ability to comment on proposals. One commenter

(IV-D-19) cited the Administrative Procedures Act and the CAA

as regulations requiring the EPA to publish proposals in the

Federal Register. Another commenter (IV-D-40) stated that the

monetary savings of not including the regulations are minimal

and that they were considering the legality of the EPA's

omission. One commenter (IV-D-10) added that changes and

corrections that may be posted electronically to the bulletin

board at a later data may not provide adequate notice. The

commenter (IV-D-10) stated that electronic dissemination of

information should be done in an organized manner that would

satisfy the public notice requirement of the Administrative

Procedures Act and would serve as an additional method of

dissemination instead of the sole method. The commenter
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(IV-D-10) also stated that software incompatibilities exist

between the EPA and many in the regulated community.

Response: The EPA agrees that publication of the

proposed rule in the Federal Register would have increased

availability of the document and facilitated the comment

process. The EPA elected not to publish the proposed

regulation based on precedents set by previous regulations and

in the interest of conserving resources. The EPA would like

to clarify that the comprehensive summary of the regulation

was provided in the Federal Register. The summary included

all important aspects of the proposed regulation in addition

to relevant information that is not in the regulation. The

summary provides interested parties sufficient information to

determine whether they require a copy of the entire proposed

regulation. If a copy is required, several options for

obtaining one are available. In addition to the Technology

Transfer Network, the proposed regulation is available in the

Air and Radiation Docket, which is open to the public, and by

either written or telephone request. The EPA contends that

the method used disseminate information regarding the proposed

regulation and the regulation itself was the most efficient

and adequately fulfills the EPA's responsibility to the

public.

12.3 REQUEST FOR EXTENSION

Comment: One commenter (IV-D-09) objected to not being

allowed to have a full 90 days to comment on the regulation.

One commenter (IV-D-12) requested that the comment period

be extended by 60 days to allow further study of the proposed

regulation so small refineries may provide comments and

supporting data on the EPA requests for information in the

rule. One commenter (IV-D-29) requested an extension. The

commenter (IV-D-29) claimed that additional time was required
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to obtain economic impact and health risk data for small

refineries. The commenter (IV-D-29) asserted that small

refineries do not have the manpower or economic data to

respond to the comments. The commenter (IV-D-29) asserted

that the EPA should be responsible for collecting the data or

not propose the regulation. 

Several commenters requested that the 60 day comment

period be extended (IV-G-09) an additional 30 days (IV-D-02,

IV-G-03, IV-G-04, IV-G-05, IV-G-06). Reasons commenters

(IV-G-03, IV-G-04) provided for why an extension was needed

included: (1) significant changes were made to the rule at the

last minute that were not discussed with industry

(specifically, emissions averaging among marine terminals and

other emission points and a requirement that storage tanks

must be in compliance in 3 years), (2) the proposal contained

41 specific requests for information which is difficult to

obtain in 60 days, (3) legal and technical analyses will need

to be performed by commenters to adequately respond to the EPA

(the regulation has been classified as Tier (1), (4) it took a

while to receive the RIA and the proposed rule from the EPA.

Response: Because of the short amount of time the EPA

had available to review and respond to all comments and then

promulgate the final rule by the court ordered deadline,

additional time was not available to provide for the public

comment period. The EPA did however provide a 60 day comment

period for this rule, which is more than the amount of time

required for Federal Regulations. Furthermore, the EPA has

received and considered comments from interested parties since

the comment period closed. Every effort has been made to

respond to comments submitted during the comment period and

after the comment period was closed.
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12.4 MISCELLANEOUS

Comment: One commenter (IV-D-21) claimed that the total

emissions equation in § 63.642 should be deleted. The

commenter (IV-D-21) submitted that the equation is ambiguous

because some terms are not defined in a way that explains how

to calculate them. The commenter (IV-D-21) stated that the

equation is unnecessary and is not actually used and

calculation is exempted from all situations. 

Response: The equation given in § 63.642 of subpart CC

is a representation of the source regulated by this rule. It

is not necessary to use this equation to calculate values for

complying with the rule. The terms are defined in the final

rule.