United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-80-038b
August 1983
Air
SEPA
Bulk
Terminals—
Background
Information for
Promulgated
Standards
Final
EIS
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EPA-450/3-80-038b
Bulk Gasoline Terminals—
Background Information
for
Promulgated Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
August 1983
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This report has been reviewed by the Emission Standards and Engineering 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, N.C. 27711, or from the National Technical Information Services, 5285 Port Royal Road,
Springfield, Virginia 22161.
Publication No. EPA-450/3-80-038b
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final
Environmental Impact Statement
for Bulk Gasoline Terminals
Prepared by:
,,// / Jack R. Farmer / (Date)
/ Director, Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
1. The promulgated standards of performance will limit emissions of
VOC from new, modified, and reconstructed bulk gasoline terminals.
Section 111 of the Clean Air Act (42 U.S.C. 7411), as amended,
directs the Administrator to establish standards of performance
for any category of new stationary source of air pollution that
". . . causes or contributes significantly to air pollution which
may reasonably be anticipated to endanger public health or welfare."
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transportation,
Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; the Council on Environmental Quality; members of the
State and Territorial Air Pollution Program Administrators; the
Association of Local Air Pollution Control Officials; EPA Regional
Administrators; and to other interested parties.
3. For additional information contact:
Mr. James F. Durham
Chemicals and Petroleum Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
telephone: (919) 541-5671
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
m
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TABLE OF CONTENTS
Title
1.0 SUMMARY 1-1
1.1 Summary of Changes Since Proposal 1-1
1.2 Summary of Impacts of Promulgated Action 1-4
1.2.1 Alternatives to Promulgated Action 1-4
1.2.2 Environmental Impacts of Promulgated
Action 1-5
1.2.3 Energy and Economic Impacts of Promulgated
Action 1-5
1.3 References 1-8
2.0 SUMMARY OF PUBLIC COMMENTS 2-1
2.1 General Issues 2-1
2.1.1 Need for the Standard 2-1
2.1.2 Designation of Effective Date of
the Standard 2-11
2.1.3 Definition of a Bulk Gasoline Terminal. . . 2-12
2.1.4 Executive Order 12291 2-14
2.1.5 Other Comments 2-16
2.2 Designation of Affected Facility 2-18
2.3 Modification and Reconstruction 2-19
2.3.1 SIP Conversions 2-19
2.3.2 Interpretation of Reconstruction 2-24
2.3.3 Interpretation of Modification 2-30
2.4 Environmental Impacts 2-31
2.4.1 Calculation of Emission Reductions 2-31
2.4.2 Emission Factors 2-32
2.4.3 Calculated Emission Reductions 2-37
2.4.4 Emission Impact in Clean Areas 2-37
2.4.5 Impact of Tank Truck Testing 2-39
2.5 Economic Impacts 2-39
2.5.1 Underestimation of Industry Costs 2-39
2.5.2 Economic Incentive to Control
Emissions , 2-42
2.5.3 Vapor Processor Costs 2-44
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Table of Contents
Title Page
2.5.4 Costs Associated with Emission Limit. . . . 2-50
2.5.5 Other Terminal Costs ,?-M
2.5.6 Tank Truck Costs 2-53
2.5.7 Ability to Pass Through Control Costs . . . 2-55
2.6 Emission Control Technology 2-56
2.6.1 State-of-the-Art Equipment 2-56
2.6.2 Test Data Presentation 2-57
2.6.3 Adequate Demonstration of Technology . . . 2-60
2.6.4 Test Data Calculations 2-62
2..6.5 Equipment Operation Under Variable
Conditions 2-63
2.6.6 Additional Test Data 2-64
2.6.7 Carbon Adsorption (CA) Control
Technology 2-64
2.6.8 Refrigeration (REF) Control Technology. . . 2-72
2.6.9 Thermal Oxidation (TO) Control
Technology 2-73
2.6.10 General Control Technology 2-74
2.7 Selection of Emission Limit 2-76
2.7.1 Stringency of Emission Limit 2-76
2.7.2 Alternate Suggested Emission Limit 2-77
2.7.3 Efficiency Equivalent of Mass
Standard 2-78
2.8 Test Methods and Monitoring 2-79
2.8.1 Details of Test Methods 2-80
2.8.2 Methods of Testing 2-84
2.8.3 Continuous Monitoring 2-86
2.9 Tank Truck Controls 2-92
2.9.1 Restricting Loadings to Vapor-Tight
Trucks 2-92
2.9.2 Suggested Alternatives 2-96
2.9.3 Administrative Burden 2-102
2.9.4 Tank Truck Population Impacted by
the Standard 2-102
2.9.5 Economic Burden 2-105
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Table of Contents
Title Page
2.10 Legal Considerations 2-107
2.10.1 Tank Trucks Not Stationary Sources 2-107
2.10.2 Loading Restrictions by Terminal Operators . 2-111
2.10.3 Setting of an Operational Standard 2-112
2.10.4 Setting of an Equipment Standard 2-114
2.11 References 2-115
APPENDIX A - EMISSION SOURCE TEST DATA A-l
A.I Introduction A-2
A.2 Summary of Additional Test Activity A-2
APPENDIX B - COST AND ECONOMIC IMPACTS B-l
B.I Introduction B-2
B.2 Current Control Cost Estimates B-2
B.2.1 Model Plant Costs B-2
B.2.2 Nationwide Control Costs B-10
B.3 Economic Impact Analysis B-16
B.4 Socioeconomic and Inflationary Impacts B-23
B.4.1 Executive Order 12291 B-24
B.4.2 Fifth-Year Annualized Costs B-24
B.4.3 Inflationary Impacts B-24
B.4.4 Other Impacts B-25
B.5 Regulatory Flexibility Analysis B-25
B.6 References B-28
vn
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LIST OF TABLES
Title Page
2-1 List of Commenters on the Proposed Standards of
Performance for Bulk Gasoline Terminals 2-2
2-2 VOC Emission Reductions at Model Plants Under the
Regulatory Alternatives (Mg/yr) 2-34
2-3 Nationwide Air Quality Impacts of Regulatory Alternatives
on Bulk Terminal Industry 2-35
2-4 Vapor Return Line Pressures During Loading 2-58
A-l Bulk Terminal Emission Test Data Summary A-3
B-l Estimated Control Costs - New and Existing
Bulk Terminals, Bottom Loaded, No SIP Control B-3
B-2 Estimated Control Costs - Existing Bulk Terminals,
Top Loaded, No SIP Control B-4
B-3 Cost Effectiveness for Various Bulk Terminal
Model Plant Cases B-13
B-4 Five-Year Nationwide Costs to Bulk Terminal Industry . . B-14
B-5 Debt Service Coverage Ratio for New Facilities B-17
B-6 Debt Service Coverage Ratio, Existing Facility—
Baseline B-18
B-7 Debt Service Coverage Ratio, Existing Facility--
Bottom Loaded, No SIP Control B-19
B-8 Debt Service Coverage Ratio, Existing Facility—
Top Loaded, No SIP Control B-20
B-9 Maximum Percentage Price Increases, Cost Pass-Through:
New Facilities, Existing Facilities (Bottom Load), and
Existing Facilities (Top Load) B-21
B-10 After-Controls, After-Tax Return on Investment: New
Facilities, Existing Facilities (Bottom Load), and
Existing Facilities (Top Load) B-22
vm
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1.0 SUMMARY
On December 17, 1980, the Environmental Protection Agency (EPA)
proposed standards of performance for bulk gasoline terminals
(45 FR 83126) under authority of Section 111 of the Clean Air Act.
Public comments were requested on the proposal in the Federal Register.
There were 40 commenters consisting mainly of terminal owners and
operators, trade associations, State and local air pollution control
agencies, and control equipment suppliers. Three U.S. Government
agencies also commented on the proposed standards. The comments that
were submitted, along with responses to these comments, are summarized
in this document. The summary of comments and responses serves as the
basis for the revisions made to the standards between proposal and
promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
Several changes of varying importance have been made to the
standards since proposal. Most of the changes were made in response
to comments, but some of them were made for the sake of clarity or
consistency. One of the most significant of the changes dealt with
proposed Section 60.502(d), which required loadings of gasoline tank
trucks to be restricted to vapor-tight tanks only, as evidenced by an
annual vapor tightness test. Most of the comments on this requirement
were concerned about the terminal operator's apparent liability for
the condition of tank trucks owned by other parties. Several commenters
felt that terminals would have to provide extra personnel at the
loading racks to enforce this restriction (see Section 2.9.1 of this
document). Section 60.502(d) (now 60.502(e)) was expanded to clearly
delineate the terminal owner or operator's responsibilities and to
clarify that on-the-spot monitoring of product loadings would not be
necessary. A terminal operator need only compare a tank identification
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number against the file of vapor tightness documentation within 2 weeks
after a loading of that tank took place. The terminal owner or operator
would have to notify tank truck owners or operators loading nonvapor-tight
tanks that reloading of the tank would not be allowed until the vapor-
tightness documentation was received by the terminal. The terminal
owner or operator would then be required to take steps to prevent
loading into each such nonvapor-tight tank. Thus the final standard
clarifies that a terminal owner or operator can comply with this part
of the standard by cross-checking files and does not have to observe
truck loading 24 hours per day.
One paragraph about facilities with existing vapor processing
equipment was added to Section 60.502. The Agency has concluded that
it is quite costly in light of the resulting emission reduction for an
owner whose existing facility becomes subject to NSPS (e.g., through
modification or reconstruction) to meet 35 mg/liter when the facility
already has a system capable of meeting 80 mg/liter, but not 35 mg/liter.
For these reasons, EPA has added Section 60.502(c), which permits
affected facilities with such vapor control equipment to meet 80 mg/liter
if construction or substantial rebuilding (i.e., "refurbishment") of
that equipment commenced before the proposal date, December 17, 1980.
This is based on the Administrator's judgment that best demonstrated
technology (BDT) for these facilities is no further control, while BDT
for facilities with vapor processing systems on which construction or
refurbishment commenced after proposal is the replacement or add-on
technology that would enable the facility to achieve 35 mg/liter.
Several commenters objected to the requirement for excess emissions
reports and to using an average monitored value as the basis for an
excess emissions determination (see Section 2.8.3 of this document).
Section 60.504, Monitoring of Operations, has been reserved pending
the development and promulgation of performance specifications for
continuous monitoring devices. Therefore, specific comments concerning
the proposed continuous monitoring requirements cannot be addressed at
this time. The Agency is currently investigating several types of
simple, low-cost monitors for various types of vapor processors.
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Alter specifications have been selected, they will be proposed in a
separate action in the Federal Register for public comment.
Two paragraphs of Section 60.505 requiring recordkeeping have
been modified, and two new paragraphs have been added. Both tank
truck vapor tightness documentation and monthly leak inspection records
must still be kept on file at the terminal, but inspection records
must now be kept for 2 years. New paragraph (d) of this section adds
a 2-year recordkeeping requirement for the notifications now required
under Section 60.502(e), and new paragraph (f) of this section adds a
3-year recordkeeping requirement for the costs for determining a
refurbished vapor processing system.
One paragraph in Section 60.500 was deleted and another added.
Since the continuous monitoring section has been reserved, the proposed
Section 50.500(c), releasing the affected facility from the require-
ments of 60.504 until monitoring specifications had been developed,
has been deleted. A new Section 60.500(c) has been added to change
the applicability date from the date of proposal to the date of
promulgation for existing facilities which commenced a component
replacement program before the promulgation date in order to comply
with State or local bulk terminal regulations. Such facilities are
not subject to the standards by means of the reconstruction provisions
of 40 CFR 60.15. Section' 60.506 was added in response to commenters'
concerns about the burden of accumulating records of replacements at
an existing source, over its lifetime, for the purpose of determining
reconstruction. The section also states that no records are required
for small normal maintenance components that are routinely replaced
and are a small part of the total cost.
The terminology used in the emission limits of the regulation has
been changed since proposal. The emission limits are now expressed in
terms of "total organic compounds" (TOC's) rather than VOC's (VOC's
are the proportion of the organic compounds that is regarded as photo-
chemically reactive). This change does not affect the stringency of
the standards, but it does better reflect the intent of the standards
and the data base and test procedures used in establishing the standards,
The standards are intended to reduce emission of VOC's through the
application of BDT (considering costs and other impacts), and the
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emission limits in the standards are selected to reflect the performance
of BDT. However, the best demonstrated technologies applicable to
bulk terminals do not selectively control VOC's, but rather all of the
organic compounds contained in gasoline vapors. Furthermore, the
emission limits are based on test data and test procedures that measure
TOC, and the test methods used to determine compliance with the standards
measure TOC. Therefore, to reflect accurately the performance of the
control technologies selected as BDT and to be consistent with the
data base and test methods on which the emission limits are based, the
emission limits in the proposed standards should have been expressed
in tenns of total organic compounds, and the promulgated emission
limits are expressed in those terms. Since the methane and ethane
content is relatively small, the option to subtract this from measured
TOC emissions using approved methods is retained.
Five definitions in Section 60.501 of the regulation were changed,
and two were added. In response to industry comments (see Section 2.1.3
of this document), a size cutoff by gasoline throughput was added to
the definition of "bulk gasoline terminal" (only facilities handling
more than 76,700 liters, or 20,000 gallons, per day will be covered),
to clarify that smaller facilities (bulk plants) served by ship or
barge will not be covered by these standards. Also, the word "wholesale"
has been removed because the throughput cutoff should exclude retail
outlets (service stations) from possible applicability.
The definition for VOC is replaced by a definition of TOC to be
consistent with the basis on which the emission limits were selected.
The wording of the definitions for "continuous vapor processing
system" and "intermittent vapor processing system" was changed slightly
to make the two terms consistent. The meanings of these terms remain
the same.
The term "loading rack" was modified to include only the components
whose replacement might be considered in a determination of construction,
modification, or reconstruction. The change does not affect the basic
meaning of the term or the designation of affected facility. Definitions
for "existing vapor processing system" and "refurbishment" were added
to clarify which processing systems would be required to meet the less
stringent limit of 80 mg/liter.
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Three paragraphs in Section 60.502 were modified. In paragraph (f),
the word "recovery" was changed to "collection" to more precisely
define the equipment contained on tank trucks.
The phrase "during product loading" was added in paragraph (i),
to clarify that the delivery tank pressure limitation applies only
while the tank is being filled at the terminal.
In proposed paragraph (i) (now 60.502(j)), the requirement to
"visually" inspect the liquid and vapor handling systems on a monthly
basis elicited a comment that vapor leaks are not effectively "seen"
during an inspection (see Section 2.8.2). The word "visually" has
been deleted to clarify that the inspection may be made without instruments,
but that any of the senses may be used in detecting vapor or liquid
leaks.
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Alternatives to Promulgated Action
The regulatory alternatives are discussed in Chapter 6 of the
Background Information Document for the proposed standards, "Bulk
Gasoline Terminals - Background Information for Proposed Standards,"
EPA-450/3-80-038a [hereinafter referred to as BID, Volume I] (III-B-1).
These regulatory alternatives reflect the different levels of emission
control from which is selected the approach that represents the best
demonstrated technology of continuous emission reduction, considering
costs, nonair quality health, and environmental and economic impacts
for bulk gasoline terminals. These alternatives remain the same.
1.2.2 Environmental Impacts of Promulgated Action
The estimated environmental impacts of the proposed standards
were discussed in Chapter 7 of BID, Volume I. Changes in these estimates
have been made since proposal, due to a reconsideration of one of the
emission factors used to calculate emission reductions under the
standards (see Section 2.4.2) and due to limiting of emissions to
80 mg/liter for existing vapor processing systems. Nationwide VOC
emissions from affected bulk terminals will decrease by 5,700 Mg/year,
or about 68 percent, from baseline SIP levels in the fifth year following
promulgation of the standards. This emissions decrease will result in
a reduction of ambient air concentrations of volatile organic compounds
in the vicinity of new, modified, and reconstructed bulk gasoline
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terminals. Only very few thermal oxidation systems are expected to be
installed, and so emissions of CO and NO from these systems will be
/\
negligible.
The water pollution impact will be minimal because water is not
used as a direct control medium in any of the control technologies
considered for the standard. Refrigeration type control systems
discharge a small amount of condensed water from which recovered
gasoline has been decanted. This minimal quantity of water will enter
the terminal's drainage system and is not expected to represent a
significant percentage of the total discharge of the terminal.
Carbon adsorption type control systems could produce a small
amount of solid waste if the activated carbon had to be replaced (due
to fouling or excessive pulverization and consequent reduction in
working capacity) during the life of the system. The extreme worst-case
waste production is estimated at about 50,000 kg (55 tons) per year,
which represents a minimal solid waste impact.
1.2.3 Energy and Economic Impacts of Promulgated Action
The estimated energy impacts of the proposed standards were
discussed in Chapter 7 of BID, Volume I. The assumption that 25 percent
of all affected terminals would install thermal oxidation systems
(which recover no gasoline/energy equivalent) is considered extremely
conservative, based on the updated cost estimates summarized in Tables B-l
and B-2 of Appendix B. These tables indicate that TO systems may be
less cost-competitive than formerly estimated, even for the smallest
terminals. Nonetheless, the previous estimated net energy savings in
the fifth year of the standards has been reduced from 9 million to
7 million liters of gasoline equivalent, due mostly to the emission
factor correction discussed in Section 2.4.2.
The estimated cost and economic impacts of the proposed standards
were discussed in Chapter 8 of BID, Volume I. Since proposal, cost
estimates have been updated in terms of first quarter 1981 dollars,
and are presented in Section B.2.1 of this document. Most net annual-
ized control costs have increased over previous estimates for all
model plant sizes. This is due primarily to the effects of inflation
on most cost elements, a higher assumed interest rate on borrowed
capital, and the addition of continuous monitoring costs. The major
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compensating cost factor lowering net costs is the updated wholesale
gasoline price, $0.29 per liter instead of the previous $0.17 per
liter.
As discussed in Section B.2.2 of Appendix B, the nationwide total
capital investment for the terminal industry in the first five years
is estimated at $10.8 million, or 45 percent of the estimate made
previously. The net annualized cost to the terminal industry in the
fifth year will be $1.6 million, again 45 percent of the previous
estimate. One reason for the decrease in the cost estimates for the
terminal industry was a change in the assumption concerning the number
of terminals converting previously top loading racks to bottom loading
which were not linked to vapor recovery regulations. Since in these
cases the top-to-bottom loading conversions are the replacements which
cause application of New Source Performance Standards (NSPS), the cost
of these conversions will not be attributable to the standards. After
a re-evaluation of the information supplied in Section 114 letter
responses, the previous estimate of 25 top-to-bottom loading conver-
sions directly attributable to the standards was lowered to three terminals.
It was estimated in these three cases that the top-to-bottom loading
conversions would be performed after the facility becomes an affected
facility and would be in an effort to comply with the NSPS. Another
reason for the decrease was the elimination of the costs associated
with add-on controls or replacement for the 10 existing vapor processing
systems assumed in the previous estimates.
The for-hire tank truck industry will incur a total capital
investment in the first five years of $1.4 million. It is estimated
that the total annualized cost in the fifth year will be $0.9 million.
The economic impact analysis presented in Section B.3 updates the
previous analysis contained in Section 8.4 of BID, Volume I. The
general conclusions of the previous analysis are still considered
valid. None of the model plant terminals will encounter a debt service
coverage problem, nor will the maximum price increase necessary to
maintain pre-control profit rates be excessive. The worst case would
require a 0.48 percent gasoline price increase for a 380,000 liter
per day (Model Plant 1) existing top loading facility. The return-on-
investment (ROI) results still support the conclusion that essentially
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no growth in the number of 380,000 liter per day terminals will take
place because both pre-control and after-control ROI's do not meet the
acceptable level. The position of new terminals in the 950,000 liter
per day category (Model Plant 2) has improved, such that they now
remain attractive after-controls investments, even without complete
cost pass-through.
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1.3 REFERENCES
III-B-lh Bulk Gasoline Terminals - Background Information for Proposed
Standards. Draft EIS. Publication No. EPA-450/3-80-038a.
December 1980.
number corresponds to the docket item number in Docket No. A-79-52,
1-9
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2.0 SUMMARY OF PUBLIC COMMENTS
The list of commenters, their affiliations, and the EPA docket
number assigned to each of their comments are shown in Table 2-1.
(Comment letters identified in this table are not repeated in the
references section of this chapter.) Forty-two letters contained
comments, and six people testified at both public hearings on the
proposed standards and Volume I of the the Background Information
Document. The significant comments have been combined into the
following 10 major areas:
1. General Issues
2. Designation of Affected Facility
3. Modification and Reconstruction
4. Environmental Impacts
5. Economic Impacts
6. Emission Control Technology
7. Selection of Emission Limit
8. Test Methods and Monitoring
9. Tank Truck Controls
10. Legal Considerations
The comments, issues, and their responses are discussed in the
following sections of this chapter. A summary of the changes made to
the standards since proposal is included in Section 1.1 of Chapter 1.
2.1 GENERAL ISSUES
2.1.1 Need for the Standard
Comment: Several commenters recommended that the proposed standards
be cancelled and that Alternative I, no additional regulation, be adopted.
Instead, the State implementation plans (SIP's) should be relied upon
to control VOC emissions from bulk gasoline terminals. Also, it was
argued that Stage I and Stage II controls are unfair and not cost-effective,
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS
OF PERFORMANCE FOR BULK GASOLINE TERMINALS
I tern Number in
Docket A-79-52
IV-F-1
IV-F-2, IV-D-20, IV-D-43
• a
IV-F-3, IV-D-46
IV-F-4
IV-F-5, IV-D-53
IV-F-6, IV-D-44
IV-E-19
Commenter and Affiliation
Public Hearing transcript
Environmental Research Center
Research Triangle Park, N.C.
January 21, 1981
Mr. Lem McManness
Marathon Oil Company
Findlay, Ohio 45840
Mr. B.S. DiGiovanni
ARCO Petroleum Products Company
515 South Flower Street
Los Angeles, California 90051
Public Hearing transcript
EPA/Beaunit Complex
Research Triangle Park, N.C.
January 28, 1981
Mr. Ray C. Edwards
Edwards Engineering Corporation
101 Alexander Avenue
Pompton Plains, New Jersey 07444
Mr. Clifford J. Harvison
National Tank Truck Carriers, Inc.
1616 P Street, N.W.
Washington, D.C. 20036
Post-Proposal Industry Meeting
to Hear Comments on the Proposed
Standard. Industry representatives
were:
Lem McManness,
Marathon Oil Company
B.S. DiGiovanni,
ARCO Petroleum Products Company
Byron Stoddard,
Shell Oil Company
C.E. Henderson,
Amoco Oil Company
Charles W. Dougherty,
Texaco, Incorporated
Edward J. Karkalik,
Standard Oil Company of Ohio
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS
OF PERFORMANCE FOR BULK GASOLINE TERMINALS (Continued)
Item Number in
Docket A-79-52 Commenter and Affiliation
IV-D-1 Mr. R.W. Bogan
GATX Terminals Corporation
120 South Riverside Plaza
Chicago, Illinois 60606
IV-D-3 Mr. Francis R. Perry
State of California
Air Resources Board
1102 Q Street
P.O. Box 2815
Sacramento, California 95812
IV-D-4 Mr. Robert Denyszyn
Scott Environmental Technology, Inc.
Plumsteadville, Pennsylvania 18949
IV-D-5 Mr. Albert B. Rosenbaum, III
National Tank Truck Carriers, Inc.
1616 P Street, N.W.
Washington, D.C. 20036
IV-D-6 Mr. W.R. Riedel
United States Coast Guard
Department of Transportation
Washington, D.C. 20593
IV-D-7 Mr. Jack M. Heinemann
Federal Energy Regulatory Commission
Washington, D.C. 20426
IV-D-8 Ms. Barbara J. Faulkner
National Oil Jobbers Council
1707 H Street, N.W., llth Floor
Washington, D.C. 20006
IV-D-9 Mr. Charles L. Miller
Texas City Refining, Inc.
P.O. Box 1271
Texas City, Texas 77590
IV-D-10 Mr. A.D. Davis
Transgulf Pipeline Company
P.O. Box 44
Winter Park, Florida 32790
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS
OF PERFORMANCE FOR BULK GASOLINE TERMINALS (Continued)
Item Number in
Docket A-79-52 Commenter and Affiliation
IV-D-11 Mr. William R. Deutsch
Illinois Petroleum Marketers Assoc.
P.O. Box 1508
112 West Cook Street
Springfield, Illinois 62705
IV-D-12 Mr. Norwood K. Talbert
AGWAY, Inc.
P.O. Box 4933
Syracuse, New York 13221
IV-D-13 Mr. John Prokop
Independent Liquid Terminals Assoc.
101 15th Street, N.W.
Washington, D.C. 20005
IV-D-14 Mr. E.P. Mampe
Crown Central Petroleum Corporation
P.O. Box 1168
Baltimore, Maryland 21203
IV-D-16 Mr. Martin A. Snith
Pacific Resources, Inc.
PRI Tower, 733 Bishop Street
P.O. Box 3379
Honolulu, Hawaii 96842
IV-D-17 Mr. Barnard R. McEntire
Air Pollution Control District
County of San Diego
9150 Chesapeake Drive
San Diego, California 92123
IV-D-18 Mr. Dave Fellers
Texas Oil Marketers Association
701 W. 15th Street
Austin, Texas 78701
IV-D-19 Mr. Willard T. Young
Texas Eastern Transmission Corporation
P.O. Box 2521
Houston, Texas 77001
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS
OF PERFORMANCE FOR BULK GASOLINE TERMINALS (Continued)
I ten Number in
Docket A-79-52 Conimenter and Affiliation
1V-D-23 Mr. J.S. Trout
Mr. I.D. Currdn
Exxon Company, USA
P.O. Box 2180
Houston, Texas 77001
IV-D-24, IV-D-41 Mr. C.E. Henderson
Amoco Oil Company
200 East Randolph Drive
P.O. Box 6110A
Chicago, Illinois 60680
IV-D-25 Mr. J.J. Moon
Phillips Petroleum Company
Bartlesville, Oklahoma 74004
IV-U-26 Mr. C.T. Sawyer
American Petroleum Institute
2101 L Street, N.W.
Washington, D.C. 20037
IV-D-27 Mr. Leonard P. Steuart, II
Independent Fuel Terminal Operators
Association
1700 Pennsylvania Avenue, N.W.
Suite 300
Washington, D.C. 20006
IV-D-28 Mr. Michael J. Duffy
Ashland Oil, Inc.
P.O. Box 391
Ashland, Kentucky 41101
IV-D-29 Ms. Susan R. Kauffman
Union Oil Company of California
Union Oil Center, Box 7600
Los Angeles, California 90051
IV-D-30, IV-D-40 Mr. A.G. Smith
Shell Oil Company
One Shell Plaza
P.O. Box 4320
Houston, Texas 77210
IV-D-31 Mr. R.W. Kreutzen
Chevron U.S.A., Inc.
P.O. Box 3069
San Francisco, California 94119
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS
OF PERFORMANCE FOR BULK GASOLINE TERMINALS (Concluded)
Item Number in
Docket A-79-52
IV-D-32
IV-D-33
IV-D-34
IV-D-35
IV-D-36
1V-D-37, IV-D-38, IV-D-42
IV-D-39
IV-D-45
Commenter and Affiliation
Mr. Darrell D. LaRue
Diamond Shamrock Corporation
P.O. Box 631
Amarillo, Texas 79173
Mr. J.W. Drake
Kerr-McGee Corporation
Kerr-McGee Center
Oklahoma City, Oklahoma 73125
Mr. R.A. Nichols
R.A. Nichols Engineering
519 Iris Avenue
Corona Del Mar, California
92625
Mr. Michael D. Graves
Hall, Estill, Hardwick, et. al
4100 Bank of Oklahoma Tower
Tulsa, Oklahoma 74172
Mr. James C. McGill
McGill, Incorporated
5800 West 68th Street
P.O. Box 9667
Tulsa, Oklahoma 74107
Mr. E.J. Karkalik
Standard Oil Company of Ohio
Midland Building
Cleveland, Ohio 44115
Mr. James F. McAvoy
State of Ohio Environmental
Protection Agency
Box 1049, 361 E. Broad St.
Columbus, Ohio 43216
Ms. Lynne R. Harris
Department of Health & Human
Services (NIOSH)
5600 Fishers Lane
Rockville, Maryland 20857
These documents are transcripts submitted by commenters at the
public hearing and are essentially identical to their oral testimonies.
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and the amount of pollution controlled is minimal. One commenter
further questioned the need for the standards since gasoline demand is
projected to remain stable or decline in the future, so that emissions
from new, modified, or reconstructed sources would not be expected to
present any greater environmental hazard (IV-D-18, IV-D-24, IV-D-26,
IV-D-28, IV-D-41, IV-E-19, IV-F-4, IV-F-6).
Four comnenters felt that the additional emission reduction
achieved under Alternative IV (35 nig/liter from processor plus vapor-
tight tank trucks) as opposed to Alternative II (80 mg/liter from
processor plus vapor-tight tank trucks) would be insignificant. The
control limit of 80 mg/liter required by many SIP's has already reduced
VOC emissions by 90 percent; the proposed 35 mg/liter limit would reduce
nationwide bulk terminal VOC emissions by the year 1985 by only an addi-
tional 0.0058 percent (IV-D-19, IV-D-20, IV-D-30, IV-F-1, IV-F-2).
Another commenter pointed out that Alternative IV would reduce nation-
wide emissions by only an additional 0.9 percent over the reductions
resulting from SIP's (Alternative I). Also, the reduction of 6,620 Mg/yr
due to this alternative would represent only 0.04 percent of the current
15 million Mg/yr nationwide VOC emissions from all sources. Due to
these small reductions, it is apparent that standards have been proposed
simply because they are "technically feasible." Thus, EPA has not
demonstrated, as required by Section 111, that new terminals will present
a significant air pollution problem (IV-D-26).
Response: The Agency proposed these standards of performance under
the authority of Section 111 of the Clean Air Act (42 U.S.C. 7411) as
amended. Section lll(b)(l) requires the Administrator to establish
standards of performance for categories of new, modified, or reconstructed
stationary sources which in the Administrator's judgment cause or con-
tribute significantly to air pollution which may reasonably be anticipated
to endanger public health or welfare.
The Agency's listing of Petroleum Transportation and Marketing
23rd on the Priority List (1-2) required under Section lll(f)
(40 CFR 60.16, 44 FR 49222, August 21, 1979) reflects the Administrator's
determination that this source category contributes significantly to air
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pollution. Before arriving at this decision, the Administrator
considered the projected rate of growth in the number of facilities in
this industry, the emission rates at uncontrolled facilities, and the
emissions allowed under typical SIP's. EPA used the emissions forecasts
in BID, Volume I, and cited by the commenters, in analyzing these factors,
and the Administrator has found no sound reason to alter the conclusions
based on that analysis.
It is important to note that VOC is emitted by a wide variety of
source categories. The emissions contribution from many categories
with VOC emissions that appear small in comparison with the total VOC
emitted by all source categories is nonetheless significant to ozone
formation. This is because failure to control these sources to the
level achievable by the best demonstrated technology would serve to
undermine the Congressionally mandated effort to prevent further
deterioration of air quality caused by additional ozone formation.
Under Section 111, EPA is required to set standards of performance
for those subcategories (within listed categories) for which the Agency
can identify a best demonstrated system of continuous emission reduction,
considering costs ("best demonstrated technology"). As explained at
proposal and elsewhere in this document, the Agency has identified as
best demonstrated technology for the bulk gasoline terminal industry a
combination of capture and control measures aimed at reducing VOC emis-
sions during loading (see Section 2.10.3). For this reason, EPA is
required under Section 111 to promulgate standards for the bulk terminals
subcategory.
The Agency accounted for the projected demand for gasoline in the
coming years in estimating the emission reduction achievable through
the NSPS. Despite a leveling off or reduction in gasoline demand, the
new, modified, and reconstructed sources in this subcategory will continue
to be an important source of VOC emissions.
Standards of performance have other benefits in addition to achieving
reductions in emissions beyond those required by a typical SIP. They
establish a degree of national uniformity, which precludes situations in
which some States may attract new industries as a result of having relaxed
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air pollution standards relative to other States. Further, standards
of performance provide documentation which reduces uncertainty in
case-by-case determinations of best available control technology
(BACT) for facilities located in attainment areas, and lowest achievable
emission rates (LAER) for facilities located in nonattainment areas.
This documentation includes identification and comprehensive analysis
of alternative emission control technologies, development of associated
costs, an evaluation and verification of applicable emission test
methods, and identification of specific emission limits achievable
with alternate technologies. The costs are provided for an economic
analysis that reveals the affordability of controls in an unbiased
study of the economic impact of controls on an industry.
The rulemaking process that implements a performance standard
assures adequate technical review and promotes participation of repre-
sentatives of the industry being considered for regulation, government,
and the public affected by that industry's emissions. The resultant
regulation represents a balance in which government resources are
applied in a well publicized national forum to reach a decision on a
pollution emission level that allows for a dynamic economy and a
healthful environment.
As stated above, the standards reflect application of the best
demonstrated technology for new, modified, and reconstructed sources
in this subcategory. While technical feasibility is a fundamental
criterion for standard-setting, EPA considered additional factors,
including cost, energy requirements, and other impacts, before arriving
at the final standard. Based upon these factors, the Agency selected
at proposal a control alternative which reflects Alternative IV. As
explained in Section 2.3.1, the Agency has revised the standard in
response to these and other comments; the standards are now based on a
control alternative which reflects a combination of Alternatives II
and IV.
Comment: One conunenter indicated that the States are already
using the proposed standards as a new guideline for construction
permit conditions. This was said to constitute needless hardship and
was given as a reason for withdrawal of the proposal (IV-E-19^1.
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Response: Section 111 does not indicate that the existence of
independent State standard-setting authority is a proper basis for
foregoing or postponing establishment of Federal NSPS. States are
free under Section 116 of the Act to establish more stringent emission
limits than those established under Section 111 or 112, or those
necessary to maintain the NAAQS under Section 110. Consequently, it
is possible that new sources may in some cases be subject to 1 im i'catinns
more stringent than standards of performance under Section 111.
Despite these considerations, all States recognize that a proposed
standard of performance for new sources is not considered a final rule
until it has been promulgated. Once the Administrator has considered
all public comments, a proposed standard may undergo certain modifica-
tions in the time period preceding promulgation of the final performance
standard. Only after the standard has been promulgated do the standards
of performance become effective for all new or modified bulk gasoline
terminals.
Comment: One commenter stated that, because of Prevention of
Significant Deterioration (PSD) regulations which apply essentially
the SIP level of control to new or modified sources in attainment
areas, controls proposed under the NSPS will already be largely in
place (IV-D-1). Also, existing and new sources in nonattainment
areas would be adequately controlled by SIP requirements. In attainment
areas, PSD requirements would deal with any shifting of emissions from
one area of the country to another (IV-D-24, IV-E-19).
Response: The typical SIP including provisions for bulk gasoline
terminal emissions will be guided by the two control techniques guide-
lines (CTG) documents (II-A-18, II-A-32) discussed on page 3-21 of BID,
Volume I. The NSPS requirements, reflecting the best control systems
and considering costs and other impacts, will result in additional
emission reduction over the estimated SIP "baseline" level. The
provisions of the PSD regulations were not included in the baseline
analysis because at this time it is unclear how the PSD requirements
will be interpreted in different areas. Congress demonstrated its
concern about this potential variability by requiring EPA to establish
nationally uniform minimum standards as a floor underlying the requirements
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established in the case-by-case PSD and nonattainment area new source
reviews. In addition to achieving further reductions in emissions
beyond those required by a typical SIP, standards of performance
establish the degree of national uniformity sought by Congress for
control of new, modified, and reconstructed facilities.
2.1.2 Designation of Effective Date of the Standard
Comment: One commenter requested that EPA provide its "customary
leeway" between the promulgation date and the date the regulation
becomes effective (IV-D-12).
Response: While the commenter did not elaborate on his reference
to "customary leeway," the Administrator has not traditionally provided
leeway between the promulgation date and the date the regulation
becomes effective. Section lll(b)(l)(B) of the Clean Air Act states
"standards of performance . . . shall become effective upon promulgation."
As stated in Section lll(e) of the Act, "after the effective date on
which the standard has been promulgated, it shall be unlawful for any
owner or operator of a new or modified source to operate such source
in violation of the standard of performance applicable to such source."
Comment: One commenter stated that the current applicability
date of December 17, 1980, would cause disruption in the compliance
schedules of terminals working to comply with the requirements of
SIP's. A revised date of January 7, 1982, was suggested, in order to
allow current efforts to be completed (IV-D-23). Another commenter
felt that a phase-in period should exist between the promulgation date
and the effective date of the standards, to avoid construction delays
which could result from the present arrangement (IV-D-32).
Response: The Administrator believes that some doubt was introduced
in the preamble to the proposed standards as to the application of the
reconstruction provisions to existing facilities undergoing programs
of component replacement due to State and local bulk terminal regulations.
Consequently, owners and operators making plans to install control
systems at these facilities may have been misled to believe that
stricter NSPS requirements might not apply, ^or this reason, the
Administrator has changed the applicability date for facilities in
this situation from the date of proposal to the date of promulgation.
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Under Section 60.500(c), any component replacement program commenced
(as defined In Section 60.2) before the promulgation date, and determined
by the Administrator to be necessitated by State or local bulk terminal
regulations, will not subject a bulk terminal facility to the NSPS by
means of the reconstruction provisions. However, component replacement
programs commenced after the promulgation date, regardless of mandated
requirements, will be considered under the reconstruction provisions of
40 CFR 60.15. A more complete discussion of this issue can be found in
Section 2.3.1 of this document.
2.1.3 Definition of a Bulk Gasoline Terminal
Six commenters recommended that changes to the definition of a
bulk gasoline terminal would make its meaning and applicability clearer.
Comment: Two commenters suggested that the CTG limitation of
throughput greater than 20,000 gallons per day be incorporated into
the definition of a bulk gasoline terminal so that bulk plants which
are served by ship or barge are excluded from the standard (IV-D-26,
IV-D-30). Another commenter suggested that terminals with a throughput
of less than 250,000 gallons per day be exempt from the regulation,
since the costs of installing vapor recovery equipment at such a
facility would far outweigh the environmental benefits (IV-D-16).
Another commenter recommended that the Administrator exempt as nonmajor
sources, facilities that have less than 200,000 gallons per day throughput.
Marginal or small operators cannot invest the additional capital
necessary to install a vapor collection system, leading to the prolonged
life of old, less efficient gasoline truck loading facilities (IV-D-33).
Response: To clarify the intended applicability of the NSPS, a
definition of bulk terminal dependent upon a throughput cutoff has
been included in §60.501. The purpose of this definition is to exclude
the smaller bulk plant. With this intention, a bulk terminal has been
defined to have a gasoline throughput greater than 75,700 liters per
day. The gasoline throughput shall be the maximum calculated design
throughput as may be limited by compliance with an enforceable condition
under Federal, State, or local law. Reference to an enforceable
condition allows a source to limit its maximum design throughput by
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limiting its hours of operation, or any other operating parameter.
The only requirements are that this limitation be a part of an enforceable
document and the source maintain compliance with it. This document
could be issued by any government entity as long as it was discoverable
by both EPA and any citizen as contemplated in Section 304 of the
Clean Air Act. By obtaining such documentation, which would reflect a
source's maximum expected actual throughput, ambiguities as to how one
would determine throughput are eliminated. For example, a bulk plant
which receives gasoline by barge, with a statement (documented in an
enforceable permit) that it will not exceed a throughput of 15,140 liters/
day (4,000 gal/day), could not be misconstrued as a bulk terminal.
Since proposal of these standards, the costs of installing vapor
recovery equipment for smaller terminals have been re-examined in
light of additional information supplied by commenters. The revised
cost impact estimates are presented in Section B.2 of Appendix B.
These revised cost and economic impacts do not indicate an adverse
impact on even the smallest model plant (380,000 liters/day, or
100,000 gallons/day). Therefore, incorporating a throughput cutoff of
200,000 or 250,000 gallons/day is not warranted.
Comment: One commenter advised that by adding the phrase "from a
refinery" to the end of the definition of a bulk gasoline terminal,
certain marine bulk plants of low throughput would be excluded from
the standards (IV-D-29, IV-F-1). Another commenter recommended that
the definition of a bulk gasoline terminal be revised to exclude
refinery facilities which receive gasoline by "pipeline" (IV-D-30).
Response: It is unnecessary to include "from a refinery" in the
revised definition of a terminal. The throughput limitation, which
has been added to the definition, will serve to exclude from the
standards certain marine bulk plants of low throughput, which receive
their gasoline by ship or barge. Also, if the phrase "from a refinery"
were added, it is possible that certain terminal facilities may be
inadvertently excluded from the standards, particularly any terminals
which may not receive gasoline from a refinery.
Gasoline terminals at refineries load gasoline into tank trucks
from loading racks. This operation is identical to operations at
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conventional terminals and is intended to be covered by these standards.
Therefore, any new or modified bulk gasoline terminal of sufficient
throughput which receives gasoline by "pipeline," regardless of location,
will be affected by the standards.
Comment: One commenter stated that many terminals handling
gasoline for others are not wholesale outlets, since they do not own
the gasoline, whereas the proposed regulation defines bulk gasoline
terminals to include only wholesale outlets (IV-D-13).
Response: It was not EPA's intent in the proposed standards to
exclude typical terminals from the regulation which may not be classified
as wholesale outlets. While some terminals, as the commenter points
out, are not "wholesale" outlets since they do not own the gasoline,
they nonetheless perform the gasoline transfer operations. The sole
intent of including the term "wholesale" in the definition at proposal
was to distinguish the facilities from large retail service stations
which may receive gasoline by pipeline. The facility described by the
commenter is clearly not a retail outlet and the intent was to cover
this type of facility. With the addition of a throughput cutoff and
with the retention of the mode-of-delivery definition, EPA believes
that retail outlets will be excluded. Therefore, the term "wholesale"
is considered unnecessary and is deleted from the definition.
2.1.4 Executive Order 12291
Comment: Three commenters stated that the proposed standards
violate the Executive Order 12291 criteria for priority-setting,
evidentiary support, and rational decision-making. This opinion is
based generally on what they felt was EPA's failure to demonstrate an
adequate and favorable cost-benefit situation (IV-D-18, IV-D-26,
IV-D-31).
The commenters stated that the general requirements for Federal
regulations set forth in Executive Order 12291 stress the need for an
analysis of the incremental benefits to society derived from the
incremental costs involved in choosing the more stringent emission
limit (35 mg/liter versus 80 mg/liter). They cited Section 2 of the
Order which, in part, requires the following:
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"(b) Regulatory action shall not be undertaken unless the
potential benefits to society for the regulation outweigh the
potential costs to society;
(c) Regulatory objectives shall be chosen to maximize the
net benefits to society;
(d) Among alternative approaches to any given regulatory
objective, the alternative involving the least net cost to society
shall be chosen; and
(e) Agencies shall set regulatory priorities with the aim
of maximizing the aggregate net benefits to society. . ."
The commenters noted that Section 2(d) of the Order requires that EPA
consider the incremental cost of selecting a 35 mg/liter limit rather
than an 80 mg/liter limit in light of alternative methods of controlling
VOC emissions. This latter analysis was claimed to be entirely lacking
in the BID (IV-D-31).
Response: The original economic analysis in BID, Volume I revealed
fifth-year net annualized costs of $6.0 million ($5.3 million for the
bulk terminal industry and $0.7 for the for-hire tank trucks), which
is well below the $100 million criterion (BID, Volume I, Section 8.5.1),
which would classify this as a major regulation and would mandate an
in-depth cost-benefit analysis. The revised economic analysis
(Section B.3 of Appendix B) supports this conclusion, with the net
cost to industry in the fifth year now estimated to be $2.5 million.
Nevertheless, the Agency has undertaken a comprehensive economic
analysis of the regulatory alternatives. In addition, the Agency has
carefully considered both the emission reduction and costs associated
with each of four regulatory alternatives on both an average and an
incremental basis. Among the alternatives considered were the 35 mg/
liter and 80 mg/liter emission limits addressed by the commenters. As
shown in Chapter 8 of BID, Volume I, the Agency considered these costs
and benefits in connection with 140 combinations of facility classifi-
cation, regulatory alternative, model plant size, and vapor control
unit type.
The Agency has responded in Section 2.5 to specific comments on
the cost analysis presented in BID, Volume I. Based on its consideration
2-15
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of these comments and EPA's projection of the impact of each alternative,
the Agency has concluded that the alternative chosen--35 mg/liter and
loading only into vapor-tight trucks—represents the regulatory alter-
native that would result in the greatest emission reduction achievable
at reasonable cost for new vapor processing systems. Furthermore, as
discussed in Section 2.3.1, affected facilities with existing vapor
control systems installed under SIP programs will be required to meet
an emission limit of 80 mg/liter [§60.502(c)j. In most cases, this is
the limit for which such systems are being designed, and so replace-
ment or upgrading of the system should be unnecessary under NSPS.
This requirement eliminates many of the concerns expressed by the
commenters about the incremental costs and emission reductions of an
80 mg/liter versus 35 mg/liter limit, because the expense of replacing
or upgrading an existing vapor processor which is performing to its
design level will not be incurred by most owners and operators of
modified or reconstructed facilities which are already being controlled
under SIP's. Thus, EPA has undertaken analyses and selected an alterna-
tive that in the Agency's judgment responds to the intent of the
requirements of Executive Order 12291, to the extent permitted by law,
and is permitted under the strict requirements of Section 111.
2.1.5 Other Comments
Comment: One commenter felt that, as a result of the proposed
rule, the States would require all bulk plants and service stations to
install a vapor recovery balance system (IV-D-11).
Response: The performance standard for bulk gasoline terminals
does not limit emissions from either bulk plants or service stations
by requiring the installation of vapor recovery systems at either of
these types of facilities. As discussed in the preamble to the proposed
regulation, the promulgated standards of performance limit TOC emissions
(and hence, VOC emissions) from each affected facility on which construction,
modification, or reconstruction commenced after December 17, 1980.
The affected facility is the total of all the loading racks at a bulk
gasoline terminal which deliver either gasoline into any delivery tank
truck or some other liquid product into trucks which have loaded
gasoline on the immediately previous load.
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Many States require under separate regulatory action that service
stations and bulk plants Install balance systems to Unit VOC emissions
in nonattainment areas. Balance systems are used at gasoline bulk
plants and service stations to limit VOC emissions by exchanging
vapors for delivered product through the use of vapor piping. However,
the regulatory action of this standard is totally independent of State
actions.
Comment: One commenter was concerned about the proper delegation
of the enforcement responsibility for the NSPS standard. This commenter
recommended that the city or county where a bulk gasoline terminal is
located be entrusted with the enforcement of the standard, since they
may already have the responsibility for enforcing State regulations.
This would relieve terminal owners/operators and the States from
complying with differing regulations that possibly duplicate enforcement
efforts (IV-D-32).
Response: The proper delegation of the enforcement responsibility
for the NSPS standard is outlined in Section lll(c)(l) of the Clean
Air Act. Once a performance standard has been promulgated, each State
may develop and submit to the Administrator a procedure for implementing
and enforcing standards of performance for new sources located in each
State. If the Administrator determines that the State procedure is
adequate, authority to implement and enforce such standards will be
delegated to that particular State.
Comment: Another commenter thought that the proposal would have
a substantial impact on many small businessmen and should thus be
revised to conform to the intent of the Regulatory Flexibility Act
(IV-D-5).
Response: The Regulatory Flexibility Act (RFA) does not by its
terms apply to regulations proposed prior to January 1, 1981. Consequently,
the Act does not impose any requirements in the Agency's development
of the bulk gasoline terminal NSPS. Uith regard to totally new bulk
terminals, it is projected that even in the absence of additional
regulation there will be little growth among smaller terminals.
However, most of the existing terminals which become affected due to
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modification or reconstruction are likely to be of the smaller sizes.
Therefore, the Agency has considered the economic impact of the standards
on relatively small terminals and carriers, and the economic analysis
has since been reviewed in reference to the RFA with the results
presented in Appendix B.5. The criteria necessitating a full-scale
regulatory flexibility analysis were reviewed for the small business
sector of this industry. Because of the unlikelihood of significant
differential impacts on either the large or small terminal and tank
truck business sectors resulting from these standards, the in-depth
Regulatory Flexibility Analysis was not indicated to be necessary.
2.2 DESIGNATION OF AFFECTED FACILITY
Comment: One commenter stated that the purpose of NSPS is violated
by designating the affected facility to include more than just the
specific new or modified facility. He pointed out that the benefits
to air quality would probably occur anyway, due to the technology
involved (IV-D-1).
Response: In choosing the affected facility, the Agency decides
which piece or group of equipment is the appropriate unit for separate
emission standards in the particular industrial context involved. The
Agency does this by examining the situation in light of the terms and
purpose of Section 111 of the Clean Air Act. The purpose of Section 111
is to minimize emissions by application of the best demonstrated
control technology at all new and modified sources (considering cost,
other health and environmental effects, and energy requirements). In
some cases a narrower designation of the affected facility may be
appropriate, because it ensures that new emission sources within
plants will be brought under the coverage of the standards as they are
installed. However, if the Agency concludes that a broader designation
would result in greater emission reduction, and that consideration of
the other relevant statutory factors (technical feasibility, cost,
energy, and other environmental impacts) reveals that choosing a
broader designation would be reasonable, then the Agency may choose
the broader designation.
While selection of a narrower designation of affected facility
results in greater emission reduction by earlier coverage of replacement
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equipment, It appears a broader designation would result in greater
emission reduction in the bulk gasoline terminal industry. EPA projects
that if loading rack replacements do occur, they will involve major
changes in the rack system (such as conversion from top to bottom
loading) arid will involve most or all of the racks at the terminal
rather than just one rack. Through modification and reconstruction,
the broader designation of the affected facility will result in the
application of the standards to more loading racks and therefore will
result in greater emission reduction.
The Agency requested comments specifically concerning this issue
at proposal, to verify whether the environmental and economic impacts
of alternative affected facility designations, as projected by the
Agency, are accurate. The Agency also requested specific information
and data which would permit an evaluation of these impacts. This has
been the only written comment to specifically address this issue which
was received by the Agency during the public comment period. Comments
were also received from six industry representatives who stated at a
meeting with EPA that they had no objection to the proposed designation
of the affected facility (IV-E-19). Since the conclusions about emis-
sion reductions and costs have not changed for this facility designation,
EPA has retained the total racks designation of the affected facility.
2.3 MODIFICATION AND RECONSTRUCTION
2.3.1 SIP Conversions
Comment: Several commenters were concerned that conversions now
being made to terminals to satisfy SIP control requirements, such as
top-to-bottom loading conversions and installation of vapor control
equipment, could subject these terminals to more stringent NSPS require-
ments. It was suggested by some of the commenters that the economic
impact on the industry would be great and that these conversions
should be exempted from the reconstruction provisions of 40 CFR 60.15
(IV-D-14, IV-D-25, IV-D-26, IV-D-28, IV-F-1, IV-F-2).
Response: The section entitled "Impacts of Regulatory Alternatives"
in the preamble to the proposed standards discussed the environmental,
cost, and economic impacts on bulk terminal facilities complying with
the requirements of those standards. Included in the discussion were
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impacts on new, modified, and reconstructed facilities. The impacts
estimated for the standards did not include any reconstructions resulting
from application of State or local air pollution requirements. However,
as several commenters pointed out, a large number of terminal facilities
that the Agency did not project as affected could indeed become subject
to the standards in the process of complying with such requirements.
Thus, the preamble discussion suggested that existing facilities
commencing component replacement in response to State or local requirements
would not be subject to 40 CFR 60.15.
The Agency believes that this suggestion introduced some doubt as
to the otherwise straightforward application of the reconstruction
provisions to existing facilities undergoing such changes. Consequently,
owners and operators making plans to install control systems at these
facilities may have been misled to believe that stricter NSPS requirements
might not apply, and may therefore not have considered the stricter
NSPS requirements when designing their systems.
For this reason, the Administrator has determined that any facility
that has commenced substantial component replacement in response to
state or local emission standards after the applicability date (the
proposal date—December 17, 1980) but prior to the date of promulgation
will not be subject to these requirements by operation of the reconstruction
provisions of 40 CFR 60.15. Under Section 60.500(c), any component
replacement program commenced (as defined in Section 60.2) before the
promulgation date, and determined by the Administrator to be necessitated
by State or local bulk terminal regulations, will not subject a bulk
terminal facility to the NSPS by means of the reconstruction provisions.
It should be noted, however, that 40 CFR 60.15 applies by straightforward
application to any existing facility undergoing component replacement.
Neither the language nor the purposes of that provision and the definition
of "new source" in Section 111 supports exemptions based on the owner's
intent in performing construction on the facility.
Because this preamble corrects the misimpression that Section 60.15
does not apply to facilities undergoing SIP component replacement, the
Agency is applying that provision to SIP component replacement programs
commenced after the promulgation date. Of course, owners or operators
performing reconstruction for other purposes, or modifications or new
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construction for any purpose, are still governed by the applicability
date of December 17, 1980, contained in Section 60.500(b).
Comment: Several comnienters stated that the number of facilities
affected by the modification and reconstruction provisions was greatly
underestimated by EPA. EPA had estimated that 110 terminals would be
subject to the proposed regulation within the next 10 years: 10 new
terminals and 100 modified or reconstructed terminals. This estimate
was claimed to be inaccurate since 30 States will require at least
some terminals within their jurisdictions to control TOC emissions to
80 ing/liter. Control of TOC emissions to 80 mg/liter will require
top-to-bottom loading conversions and vapor recovery installation.
These operational changes will usually constitute a "reconstruction"
of the terminal, thereby subjecting the terminal to EPA's proposed
regulation (IV-D-23, IV-D-26, IV-D-35, IV-D-37, IV-E-19, IV-F-1,
IV-F-3).
One commenter estimated that from 250 to 800 reconstructions
could be performed in the next 10 years, and stated that EPA's inclusion
of so many existing sources because of SIP conversions was an invasion
of the State and local sphere of regulation and thus beyond EPA's
statutory authority (IV-D-26). Another commenter stated that as many
as 25 percent of his company's existing terminals could be impacted in
the next 10 years (IV-F-1, IV-F-3).
Response: As stated in the previous response, §60.500(c) changes
the applicability date from the proposal date to the promulgation date
for gasoline loading rack component replacement programs that were
commenced prior to the promulgation date for the purposes of meeting
State or local regulations. Since most State or local regulation-
related component replacement programs at terminals will have commenced
by the promulgation date, the change in the applicability date, in
effect, excludes these terminals from the standards. The commenters
included these State or local regulation-related changes in their
determinations; therefore, the number of affected facilities estimated
by the commenters is much too high. EPA considers its estimate of
110 new, modified, or reconstt uct<.:n tenrinals still to be accurate.
As stated in Section 8.1.2 of BID, Volume I, the estimate of 10 new
2-21
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facilities and 100 modified or reconstructed facilities was based
primarily on information obtained from oil companies through responses
to Section 114 letter requests (II-D-118, II-D-121, II-D-122, II-D-124,
II-D-125, II-D-127-138). This was supplemented by telephone conver-
sations with several control agencies, oil companies, and terminal
construction engineering firms (II-E-34-38, II-E-41-44, II-E-46-49,
II-E-51, II-E-79, II-E-93).
Comment: One comnenter felt that if the proposed standards
further limited allowable VOC emissions from 80 mg/liter to 35 mg/liter
of gasoline loaded, then 30 of his 59 plants would experience "immediate
operational constraints," since they are equipped with vapor processing
units of the compression-refrigeration-absorption (CRA) or lean oil
absorption (LOA) type, which EPA data indicate cannot meet the 35 mg/liter
limit (IV-D-30).
Response: The existing facilities described by the commenter
would not be subject to the standards unless modification or recon-
struction "commenced" after the proposal date of December 17, 1980.
Any such work commenced prior to the proposal date would not apply
under these standards. However, programs of construction, modification,
or reconstruction would subject a terminal owner or operator to the
requirements of the standards, as stated in §60.500(b) of the regulation.
Further, §60.502(c) of the proposed regulation established an emission
limit of 35 mg/liter to be applied to all such facilities. Included
in this group of facilities were those which had previously installed
vapor collection and processing systems under SIP requirements, such
as those referred to by the commenter. EPA estimates that 20 such
facilities will become affected by NSPS through modification or
reconstruction in the first 5 years in which the standards are in
effect. Of these 20 facilities, 10 are likely to have vapor control
systems which already meet a 35 mg/liter limit (CA, TO, and some REF
systems). The remaining 10 systems should be attaining the 80 mg/liter
limit required under most State plans.
One paragraph about facilities with existing vapor processing
equipment was added to Section 60.502. The Agency has concluded that
it is quite costly in light of the resulting emission reduction for an
2-22
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owner whose existing facility becomes subject to NSPS (e.g., through
modification or reconstruction) to meet 35 ing/liter when the facility
already has a system capable of meeting 80 nig/liter, but not 35 mg/liter.
In the Administrator's judgment, however, it is unreasonably costly to
require such a facility to install the add-on technology that will
achieve 35 mg/liter only if the facility began constructing or substantially
rebuilding (i.e., "refurbishing") the control system before receiving
notice December 17, 1980, that BDT for those facilities, were they
later to come under NSPS, would likely be equipment capable of meeting
35 mg/1iter.
By contrast, EPA considers it reasonable to apply the 35 mg/liter
limit to a facility whose owner commenced construction or refurbishment
of d control system not capable of meeting 35 mg/liter despite having
received this notice. It is reasonable to expect such an owner to
avoid the high cost of going from 80 mg/liter to 35 mg/liter simply by
constructing or refurbishing the facility's control system with technology
that would meet EPA's 35 mg/liter limit and make later retrofit unnecessary.
This is reasonable to require even of facilities with existing control
systems constructed or refurbished after December 17, 1980, for the
purpose of meeting an 80 mg/liter State limit.
For these reasons, EPA has added Section 60.502(c), which permits
affected facilities with such vapor control equipment to meet 80 mg/liter
if construction or substantial rebuilding (i.e., "refurbishment") of
that equipment commenced before the proposal date, December 17, 1980.
This is based on the Administrator's judgment that BDT for these
facilities is no further control, while BDT for facilities with vapor
processing systems on which construction or refurbishment commenced
after proposal is the replacement or add-on technology that would enable
the facility to achieve 35 mg/liter.
Definitions for "existing vapor processing system" and "refurbishment"
were added to the regulation to indicate that if in any 2-year period
following the date the facility becomes an affected facility the fixed
capital cost of improvements or changes to an existing vapor processing
system exceeds 50 percent of the cost of a comparable entirely new
vapor processing system, the altered vapor processing system must then
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meet the 35 mg/liter limit. Consequently, refurbishment applies only
to those systems which become extensively altered over this period.
2.3.2 Interpretation of Reconstruction
Comment: One commenter felt that the reconstruction provisions
are contrary to law, because the provisions apply to converted facilities
from which emissions have not increased. An example of the potential
misapplication of these provisions was provided: conversion from top
to bottom loading, in which emissions would be expected to decrease.
The consideration of this situation under reconstruction was said to
be contrary to the legislative intent of Section 111. Further, the
commenter suggested that the reconstruction provisions be deleted from
this and all other NSPS. If this is not done, a thorough legal analysis
in support of EPA's authority to regulate reconstructed sources under
40 CFR 60.15 should be published, as required by Executive Order 12291,
Section 4(a) (IV-D-31).
Response: Since in enacting Section 111 Congress did not define
the term "construction," the question arose whether NSPS would apply
to facilities being rebuilt. Noncoverage of such facilities would
have produced the incongruity that NSPS would apply to completely new
facilities, but not to facilities that were essentially new because
they had undergone reconstruction of much of their component equipment.
This would have undermined Congress's intent under Section 111 to
require strict control of emissions as the Nation's industrial base is
replaced.
EPA promulgated the reconstruction provisions in 1975, after
notice and opportunity for public comment (40 FR 58420, December 16, 1975),
to fulfill this intent of Congress. Since this turnover in the industrial
base may occur independently of whether emissions from the rebuilt
sources have increased, the reconstruction provisions do not focus on
whether the changes that render a source essentially new also result
in increased emissions.
Congress did not attempt to overrule EPA's previous promulgation
of Section 60.15 in passing the Clean Air Act Amendments of 1977.
This indicates that Congress viewed the reconstruction provisions'
focus on component replacement, rather than emissions level, as con-
sistent with Section 111. See, e.g., Red Lion Broadcasting Co. v. FCC,
2-24
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395 U.S. 367 (1969); NLRB v. Bell Aerospace Division, 416 U.S. 267
(1974). Nor has any Court questioned the Agency's authority to subject
reconstructed sources to new source performance standards. In fact,
in ASARCo v. EPA, 578 F. 2d 319, 328 n.31 (D.C. Cir. 1978), the D.C.
Circuit suggested that the reconstruction provisions may not go far
enough toward preventing possible abuses by owners seeking to avoid
NSPS by perpetuating the useful lives of their existing facilities
indefinitely.
Finally, coverage under §60.15 of loading rack conversions comports
well with the intent underlying Section 111. Conversion from top to
bottom loading may involve replacement of much existing equipment with
new equipment. In such cases, the conversion may transform the existing
set of racks into an essentially new set of racks. A key goal of
Section 111 is to enhance air quality over the long term and maximize
the potential for long-term growth by minimizing emissions through
application of the best demonstrated technology to new emission sources,
concurrent with the turnover of the Nation's industrial base. If
owners are permitted to replace most of the equipment in their existing
sets of racks without applying the best demonstrated technology, they
will be installing new equipment without minimizing emissions and
maximizing the potential for long-term industrial growth, as Congress
sought in enacting Section 111. For this reason, NSPS coverage of
sets of racks that undergo substantial component replacement through
conversion accords with Section 111, even where some decrease in
emissions results from the conversion.
As discussed in Section 2.3.1, facilities undergoing reconstruction
which have an existing vapor control system will be required to meet
the 80 mg/liter limit under which they were previously operating. In
addition to this requirement, the other provisions of §60.502 will
apply, including the physical requirements on the vapor collection
system which may not apply under many State regulations. Also, the
tank truck vapor tightness requirements will apply to these facilities.
Comment: Commenters stated that the reconstruction provisions
should apply only to projects in nonattainment areas or areas where
there is a risk of significant deterioration (IV-D-23, IV-D-30).
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Response: In enacting Section 111, Congress sought to require
the best demonstrated level of control at all new sources, irrespective
of the air quality at the location of the site. Only by assuring a
minimum level of control at new sources in all areas would two key
purposes underlying Section 111 be advanced -- enhancing air quality
in all areas by requiring application of the best technology as the
Nation's industrial base is replaced, and preventing States from
relaxing environmental standards below the best demonstrated level of
control to attract industry.
Comment: Several commenters stated that the interpretation of
"reconstruction" in the background information document (BID, Volume I)
and preamble is an unwarranted extension of EPA's past procedure in
defining this provision and is not consistent with the intent of the
Clean Air Act. Reconstruction, as defined in Section 60.15(d), may
apply only to a project which in total meets the 50 percent capital
cost level and not to an accumulation of expenditures which occurs
over an unlimited time period. Under the present interpretation of
reconstruction every existing loading rack, including those in attain-
ment areas, would, through ordinary maintenance and replacement of
components, become a new source long before the end of its useful
life. The commenters said that bulk gasoline terminals were subject
to constantly changing market conditions, resulting in the need for
constant equipment upgrading in order to remain competitive and provide
new services using state-of-the art loading equipment. The use of
cumulative costs would be a tremendous administrative burden on the
industry and EPA, and could have a negative effect on emission reductions
by discouraging replacement of worn-out or defective components of
certain loading facilities, even where such work would bring about
reduced emissions. In particular, costly and overly burdensome
recordkeeping and accounting procedures would be necessary to determine
when the 50 percent total replacement cost level had been exceeded,
the cost of which was not addressed in BID, Volume I (IV-D-20, IV-D-23,
IV-D-24, IV-D-25, IV-D-26, IV-D-30, IV-D-31, IV-D-37, IV-D-41, IV-E-19).
Response: As stated above, EPA promulgated the reconstruction
provisions because failure to require best control at sources that
2-26
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have become essentially new through extensive component replacement
would have undermined Congress's intent that best technology be applied
as the Nation's industrial base is replaced. Failure to cover facilities
thdt have undergone extensive component replacement over a long period
of time similarly postpones the enhancement of air quality Congress
sought under Section 111. The D.C. Circuit recognized this when it
expressed concern in the ASARCo case that, absent a provision for
aggregating replacement expenditures i;over the years," owners could
evade the reconstruction provisions by continually replacing obsolete
or worn-out equipment. 578 F.2d 319, 328 n.31 (D.C. Cir. 1978).
Section 60.15 currently defines "reconstruction" as the replacement
of components of an existing facility to such an extent that "the
fixed capital cost of the new components" exceeds 50 percent of the
"fixed capital cost" that would be required to construct a comparable
entirely new facility and EPA determines that it is technologically
and economically feasible to meet the applicable NSPS. Subsection (d)
indicates that the "new components" whose cost would be counted toward
the 50 percent threshold include those components the owner "proposes
to replace." It is unclear under this wording whether a
reconstruction has occurred in the case of an owner who first seeks to
replace components of an existing facility at a cost equal to 30 percent
of the cost of an entirely new facility and then, shortly after commencing
or completing those replacements, seeks to replace an additional 30 percent.
Specifically, it is uncertain whether the owner should be deemed to have
made two distinct "proposals," or instead a single proposal.
For example, assume that a terminal owner converts one of three
top loading positions to bottom loading, and six months later converts
another loading rack to bottom loading. If the two conversions were
interpreted as separate "proposals" under Section 60.15, neither would
likely exceed the 50 percent replacement cost threshold. Under this
general interpretation, owners could avoid NSPS coverage under
Section 60.15 simply by characterizing their replacement projects as
distinct "proposals," even where the component replacement is completed
within a relatively short period of time.
EPA did not intend, in promulgating the reconstruction provisions,
that the term "propose" exclude from NSPS coverage facilities undergoing
2-27
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this type of extensive component replacement. Failure to cover these
sources serves to underline Congress's intent that air quality be
enhanced over the long term by applying best demonstrated technology
with the turnover in the Nation's industrial base.
To eliminate the ambiguity in the current wording of Section 60.15
and further the intent underlying Section 111 (as described above),
the Agency is clarifying the meaning of "proposed" component replacements
in Section 60.15. Specifically, the Agency is interpreting "proposed"
replacement components under Section 60.15 to include components which
are replaced pursuant to all continuous programs of component replacement
which commence .(but are not necessarily completed) within the period
of time determined by the Agency to be appropriate for the individual
NSPS involved. The Agency is selecting a 2-year period as the appro-
priate period for purposes of the bulk gasoline terminal NSPS
(Section 60.506(b)). Thus, the Agency will count toward the 50 percent
reconstruction threshold the "fixed capital cost" of all depreciable
components (except those described above) replaced pursuant to all
continuous programs of reconstruction which commence within any 2-year
period following proposal of these standards. In the Administrator's
judgment, the 2-year period provides a reasonable, objective method of
determining whether an owner of bulk gasoline terminal facilities is
actually "proposing" extensive component replacement, within the
Agency's original intent in promulgating Section 60.15.
EPA realizes that the bulk gasoline terminal industry is constantly
changing; however, the Agency believes that this 2-year limit will
assure that the owner would have to make a substantial change to the
facility to reach the 50 percent threshold.
The administrative effort to keep the required records should not
be a burden on the industry. The recordkeeping required under a cumu-
lative basis interpretation of reconstruction is the same as the
recordkeeping that would be required under a strictly project-by-
project basis interpretation. In either case, the dollar amount of
the component replacement taking place at the affected facility must
be determined and recorded. Once this dollar amount has been determined
for each change or conversion, the additional requirement of keeping
this information on file at the terminal does not appear to be an
excessive burden.
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Section 60.15 defines the "fixed capital cost" of replacement
components as the capital needed to provide all "depreciable" components.
By excluding nondepreciable components from consideration in calculating
component replacement costs, this definition excludes many components
that are replaced frequently to keep the plant in proper working
order. There may, however, be some depreciable components that are
replaced frequently for similar purposes. In the Agency's judgment,
maintaining records of the repair or replacement of these items may
constitute an unnecessary burden. Moreover, the Agency does not
consider the replacement of these items an element of the turnover in
the life of the facility concerning Congress when it enacted Section 111.
Therefore, in accordance with 40 CFR 60.15(g), these standards
(Section 60.506) exempt certain frequently replaced components, whether
depreciable or nondepreciable, from consideration in applying the
reconstruction provisions to bulk gasoline terminal facilities. The
costs of these components will not be considered in calculating either
the "fixed capital cost of the new components" or the "fixed capital
cost that would be required to construct a comparable entirely new
facility" under Section 60.15. In the Agency's judgment, these items
are pump seals, loading arm gaskets and swivels, coupler gaskets,
overfill sensors, vapor hoses, and grounding cables.
Comment: One commenter requested a clarification of the third
review criterion used in determining a reconstruction, which is stated
in the preamble to the proposed regulation: "(3) The extent to which
the components being replaced cause or contribute to the emissions
from the facility." This commenter felt that the term "reconstruction"
should apply only if a conversion results in an increase in emissions
(IV-D-29).
Response: An existing facility undergoes a "reconstruction,"
under 40 CFR 60.15, when (1) the fixed capital cost of its new components
exceeds 50 percent of the fixed capital cost required to construct a
comparable entirely new facility, and (2) it is technologically and
economically feasible to meet the applicable standards. According tc
§60.15(a), the determination of reconstruction is made irrespective of
any change in the emission rate occasioned by the component replacement.
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This is because applying NSPS to sources which have undergone extensive
component replacement fulfills Congress's intent to enhance air quality
by requiring best demonstrated control as the Nation's industrial base
is replaced.
The review criteria in Section 60.15(f) guide the Administrator's
determination of technological and economic feasibility. The third
criterion, the extent to which the components "cause or contribute to
the emissions from the facility", relates to the replaced components'
role in the facility, not the emission change caused by the replacement.
This criterion provides the Administrator discretion to exclude from
the reconstruction calculation replacement of components not considered
to play an important role in producing emissions. However, this is
only one of the factors guiding the determination. Thus, regardless
of the outcome of this examination, the Administrator retains discretion
under the other criteria to find that compliance by an extensively
rebuilt facility is technologically and economically feasible. The
Administrator's decision under Section 60.15(f) is not affected by
whether any actual change in emission rate has occurred.
Comment: Another commenter was not clear as to whether the
definition of a reconstruction would affect all bulk stations,
terminals, and/or service stations (IV-D-11).
Response: The standards for bulk gasoline terminals, and the
reconstruction provisions associated with the standards, apply only to
bulk terminals which commence construction, reconstruction, or modifi-
cation after the proposal date of December 17, 1980. No requirements
or controls are imposed on bulk stations or service stations by these
standards (see Section 2.1.5).
2.3.3 Interpretation of Modification
Comment: Five commenters felt that the interpretation of
"modification" in the preamble and BID, Volume I, is overly broad
because it may include altered facilities from which the overall
emissions have not increased. A clarification should be made so that
replacement of needed components that improve loading efficiencies
would not be considered "modifications" unless they resulted in an
increase in the average daily emissions. For example, the replacement
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of worn-out pumps with new higher capacity pumps would allow faster
loading, increasing the emissions per tank truckload on a kg/hour
basis during peak periods, but not on a mg/liter basis, which is the
measurement of the standard. In fact, the number of tank trucks
loaded during a day would not necessarily increase due to a faster
loading rate.
The present interpretation of a "modification" would penalize
industry for undertaking cost-saving expansions in terminal throughput
capacity without increasing total VOC emission rates. It is believed
that this mandate is beyond the statutory authority of EPA and is an
impermissible attempt by EPA to apply the proposed standards to additional
facilities (IV-D-23, IV-D-24, IV-D-26, IV-D-31, IV-D-32, IV-D-41).
Response: Section 60.14(e)(2) was purposely included in the
General Provisions to exclude from consideration under the modification
provisions increases in emissions due to relatively small changes. If
a change increases production capacity and yet does not result in a
"capital expenditure" as defined in the definitions in the General
Provisions, the change would not be considered a modification.
2.4 ENVIRONMENTAL IMPACTS
2.4.1 Calculation of Emission Reductions
Comment: One commenter claimed that the analysis of emission
reductions in nonattainment areas assumed that the benefits would
represent the difference between a 35 mg/liter level of control and a
current uncontrolled emissions situation. Actually, most terminals in
those areas are being or will be controlled to 80 mg/liter or better
by SIP regulations. Thus, presented estimates of VOC reductions are
inaccurate (IV-D-13).
Response: The assumption used in analyzing potential emission
reductions in areas which had not attained the National Ambient Air
Quality Standards (NAAQS) for ozone is stated on pages 7-1 and 7-3 of
BID, Volume I:
"The category of terminals in the nonattainment areas includes
new, modified, and reconstructed terminals. The air pollution
impact of the regulatory alternatives on these terminals is the
least because they will already be controlled by State air pollution
regulations (see Section 3.3, Baseline Emissions)."
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As pointed out in Section 3.3.3, Calculation of Baseline Emission
Level, an assumption of emissions equivalent to 80 nig/liter from vapor
processors, plus 10 percent leakage (96 mg/liter) from tank trucks,
was used to calculate emission reductions in nonattainment areas.
2.4.2 Emission Factors
Several comments were received concerning the emission factors
used in the emissions calculations.
Comment: One commenter claimed that it is incorrect to use the
emission factor of 960 mg/liter for all calculations of emissions in
attainment areas. Use of this emission factor is premised on the
incorrect assumption that all deliveries in attainment areas are to
facilities with vapor balance systems. In most instances the normal
service, submerged fill emission factor of 600 mg/liter, is the proper
factor for calculating emissions in attainment areas. Page 8-46 and
Tables 8-17, 8-25, and 8-26 of BID, Volume I were cited as illustrations
of inappropriate applications of these emission factors. This commenter
felt that environmental benefits of the proposed standards, including
the estimated quantity of VOC controlled during loading, are overstated
when the emission factor used is higher than warranted. EPA's calculations
predict a greater benefit to the environment by the imposition of the
proposed standards than would actually occur. In addition, the cost-benefit
analysis was said to be inaccurate since the environmental benefit per
dollar spent is also overstated (IV-D-31).
Another commenter felt that the current emission levels had been
overstated. Trucks returning from service stations without vapor
balance carry vapors which average only about 20 percent of maximum
saturation levels. Since there is no requirement for Stage I vapor
controls, the amount of vapor recoverable is quite small, and the
correct emission factor for uncontrolled trucks is 336 mg/liter,
instead of 600 mg/liter. This commenter also stated that there is no
splash fill loading being practiced, except for that accompanying top
loading with vapor recovery. The saturation is claimed to reach
115 percent in summer, instead of the 150 percent which the emission
factor of 1,440 mg/liter represents (IV-D-34).
Another commenter stated that the emission factor assumed for
bottom loading in balance service should have been 850 mg/liter,
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instead of 960 mg/liter. As a result, this commenter feels that the
assumed emission levels are unrealistically high, distorting emission
inventories, efficiencies, and cost/benefit ratios (IV-D-23). A
second commenter suggested that, based on performance test data, the
correct factor for this type of service is 1,080 mg/liter (IV-D-3).
Response: These comments address two specific topics: the
application of emission factors in attainment areas, and the accuracy
of the factors which were used to calculate emissions.
EPA agrees that the emission factor which should have been applied
in the case of attainment areas is the factor for normal submerged
loading, 600 mg/liter, instead of the balance service factor of
960 mg/liter. A lowering of this factor from 960 mg/liter to 600 mg/
liter reduces the quantities of recovered gasoline shown in the cited
tables. However, the values which were given in Tables 8-17, 8-25,
and 8-26 are appropriate for areas where the full SIP level of control
is in effect; i.e., all nonattainment areas and some attainment areas.
The primary impact of the reconsideration of this emission factor is
on the estimated control costs for the model plants in attainment
areas, because reducing the quantity of recovered gasoline reduces the
recovery cost credits in the calculation of net annualized costs. The
total volume of gasoline recovered was overstated by 60 percent;
however, in re-evaluating the wholesale unit cost of the recovered
gasoline, it was determined that the cost was understated by 65 percent.
The net result was a slight increase in the cost credit for recovered
product. These revised cost impacts are discussed in Section B.2.1 of
Appendix B. The calculated emission reductions under the regulatory
alternatives presented in Tables 7-1 and 7-2 of BID, Volume I are also
affected by the reconsidered emission factor. Estimated nationwide
emission reductions under Alternative IV have decreased by 9.4 percent
from baseline levels, from a 6,620 Mg/yr reduction to a 6,000 Mg/yr
reduction in the fifth year. Tables 2-2 and 2-3 in this document
present the revised emission reduction figures for the regulatory
alternatives. Energy impacts are also affected by this change, as
well as by the revised control system electrical consumption data.
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Table 2-2.
VOC EMISSION REDUCTIONS AT MODEL PLANTS UNDER THE
REGULATORY ALTERNATIVES (Mg/yr)
Model Plant
(liters/day)
SIP-Controlled Area
380,000
950,000
1,900,000
3,800,000
Mo SIP Control -
Submerged Fill
380,000
950,000
1,900,000
3,800,000
No SIP Control-
Splash Fill
380,000
950,000
1,900,000
3,800,000
Basel ine
Emissions
23
57
114
227
78
194
388
775
186
465
930
1,860
Alternative II
Emissions
23
57
114
227
18
45
90
180
45
90
180
VOC
Reduction
0
0
0
0
60
149
298
595
168
420
840
1,680
Alternat
ive III
VOC
Emissions Reduction
17
42
85
169
28
69
139
278
28
69
139
278
6
15
29
58
50
125
249
497
158
396
791
1,582
Alternative IV
Emissions
17
42
85
169
12
31
61
123
12
31
61
123
voc a
Reduction
6
15
29
58
66
163
327
652
174
434
869
1,737
i
CO
VOC Reduction = Emissions reduction from baseline emissions.
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Table 2-3. NATIONWIDE AIR QUALITY IMPACTS OF REGULATORY
ALTERNATIVES ON BULK TERMINAL INDUSTRY
VOC Emissions, Mg/Yr
)J)86 Alternatives 1_991 __
1980 Baseline Promulgated3 Promulgated3
Emissions Emissions II 111 IV Standard II 111 IV Standard
Total emissions
from bulk
gasoline terminals 341,900 140,000 134,900 135,200 134,000 134,300 129,800 130,400 128,000 128,600
rv>
^ Emission reductions
en from baseline
emissions 5,100 4,800 6,000 5,700 10,200 9,600 12,000 11,400
Percent reduction
from baseline
emissions 3.6 3.4 4.3 4.1 7.3 6.9 8.6 0.1
Percent Reduction
for new, modified,
and reconstructed
terminals 62 58 73 68 62 58 73 68
3Promulgated standard is a combination of Alternatives 11 (for existing vapor processing systems) and IV (for new vapor processing systems)
-------
The estimated nationwide net energy savings in the fifth year has been
reduced from 9 million to 7 million liters (56,600 to 47,200 barrels)
of gasoline equivalent.
All of the emission factors used to estimate current and future
emission levels were those contained in AP-42, Compilation of Air Pol-
lutant Emission Factors (II-A-9). This document reports the most
current available data which has been considered by the Agency in
establishing emission factors for use in estimating emissions. Data
from the EPA bulk terminal tests have been analyzed to allow a com-
parison with the AP-42 emission factors. In 118 loadings of tank
trucks in balance service, and 123 loadings in normal service, the
current emission factors of 960 mg/liter and 600 mg/liter, respectively,
were corroborated (IV-J-17).
Contacts with State agencies and industry have indicated that a
small amount of splash loading of gasoline is still practiced in some
attainment areas, but it is generally confined to the smaller oil com-
panies (II-E-68, II-E-69, II-E-126, II-E-127). The estimate of 10 percent
splash loading in areas with no bulk terminal vapor recovery regulations
is considered reasonable. The emission factor of 1,440 mg/liter for
splash loading is given in AP-42. Insufficient data from terminal
tests are currently available to determine whether a revision should
be considered for the splash loading emission factor. However, the
150 percent saturation factor for top splash loading is based on tests
of 38 tank loadings performed at various times of the year in several
geographical locations (IV-J-15). The difference between the satura-
tion factor used to derive the AP-42 emission factor and the saturation
factor claimed by the commenter may result from liquid droplet or mist
carryover in these test runs.
The fact that two comnienters suggested changes, one upward and
one downward, to the emission factor for balance service loading
indicates that there may be considerable variation in the vapor
concentrations emitted during this type of loading. In EPA tests,
emissions from 118 individual tank trucks in this service ranged from
37 mg/liter to 4,400 mg/liter, averaging 930 mg/liter. Of these
loadings, 50 percent were less than 850 mg/liter and 27 percent were
more than 1,080 mg/liter. Many of the trucks in these terminal tests
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had serious vapor leaks, which may have caused some emissions to be
lower than expected. Generally, the higher values were associated
with higher ambient temperatures. Data supplied by the commenter
suggesting 1,080 mg/liter were for bulk drops to underground tanks in
southern California, where tank temperatures averaged about 33 degrees
F (IV-J-6, IV-E-11). In light of this information, the current emission
factors in AP-42 are considered at this time to represent a reasonable
national average.
2.4.3 Calculated Emission Reductions
Comment: One commenter stated that the actual average performance
of the control systems in EPA tests was better than the level assumed
for nonattainmerit area baseline emission calculations. Because of
this, the calculated emission reduction is erroneous, with Alternative I
achieving emissions of about 85 percent of that projected for
Alternative II or IV (IV-D-1).
Response: It is not practical to determine precisely the average
emission level from all of the vapor processors operating under a
particular regulatory emission limit. For the purpose of calculating
potential emission reductions in a particular area, it is assumed that
the emission limit represents the average actual emissions, since
vapor processors could emit up to this amount and still meet applicable
standards. For this reason, the emission limit of the alternative is
used for calculating impacts.
2.4.4 Emission Impact in Clean Areas
Comment: One commenter argued that controlling terminals in the
States where no control regulations are required would not appreciably
improve the already clean air which is present at the source and
downstream, since these terminals are located in remote, low-density
population areas. The controls would raise distribution costs: first,
to pay for the installation and capital recovery of equipment in small
terminals, and second, to pay for the higher downtime and maintenance
costs associated with maintaining equipment in areas remote from service
repair facilities (IV-D-34).
Response: Section 111 requires EPA to promulgate uniform new
source performance standards for subcategories of new sources, where-
ever located, within source categories that the Administrator has
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determined are "significant contributors." Under Section 111, these
standards must require control equivalent to that achievable by the
best systems of emission reduction ("best demonstrated technology").
Congress believed that this would serve to prevent new pollution prob-
lems and assure that air quality is enhanced over the long term.
Technology-based standards under Section 111 thus complement, rather
than conform to, the air quality-based requirements of other sections
of the Clean Air Act.
As discussed in Section 2.1.1, EPA has determined that emissions
from the petroleum transportation and marketing industry contribute
significantly to air pollution that may reasonably be anticipated to
endanger public health or welfare. Accordingly, under Section 111 the
Agency is required to set nationally uniform minimum standards for all
industry subcategories within this category for which the Agency can
identify best demonstrated technology, including bulk gasoline terminals.
It should further be noted that emissions from a 950,000 liter/day
submerged loading terminal would be reduced under the standard from
approximately 194 Mg/year to 31 Mg/year, or 84 percent, in an area
without SIP control requirements. In the Agency's view, foregoing
this level of reduction would permit the type of new pollution problems
Congress sought to prevent.
The promulgated standards will increase costs to most of the
affected bulk terminals, as indicated by the revised cost analysis
summarized in Tables B-l through B-3 of Appendix B. The larger facilities
should be able to realize a net cost savings due to the greater product
recovery when using vapor recovery equipment. While some terminals in
"remote" areas may experience higher costs than other terminals, the
magnitude of this cost difference is not likely to be great enough to
seriously affect the ability of such terminals to comply with the
standards. For example, if maintenance costs at a small terminal
doubled, the net annualized cost of control would increase by only
about 11 percent (Table B-l). If the terminal formerly used top
loading and was converted to bottom loading as a result of the standards,
this percentage increase would be reduced to about 4 percent (Table B-2).
The costs of control to these example terminals would remain reasonable.
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However, small, remote terminals would not be profitable even in
pre-control circumstances unless maintenance and repair services were
available at a reasonable cost.
Section 2.5 and Appendix B discuss the updated costs as well as
the economic impacts of the standards on small terminals.
2.4.5 Impact of Tank Truck Testing
Comment: One commenter thought that the effluent from the pre-test
cleaning of tank truck compartments would have "definite negative
environmental consequences" (IV-F-4, IV-F-6).
Response: This commenter felt that 175 gallons of effluent
composed of water, caustic-based cleaning compounds, and petroleum
residue would be created during the tank cleaning necessary before
each test for vapor tightness. Method 27 does not require a thorough
soap-and-water cleaning as suggested by this commenter. The tank
compartments must be emptied of all liquid, and then purged of all
volatile vapors by any safe, acceptable method (such as carrying a
load of nonvolatile fuel or flushing with ambient air). Only in an
unusual case, where a noncompatible fuel or chemical was carried in a
tank truck which was being converted to gasoline service at the time
of the testing, would such liquid cleaning be necessary. Since these
cases are infrequent and since the volume of effluent is small, the
impact of any such instances would be negligible.
2.5 ECONOMIC IMPACTS
2.5.1 Underestimation of Industry Costs
Comment: One commenter stated that the "reasonably accurate cost
estimate" required to demonstrate that the proposed standards are
achievable at reasonable costs had not been presented because: (a) it
is not reasonable to assume that control equipment designed to meet
35 my/liter could be purchased and operated for the same costs as for
current equipment meeting 80 mg/liter, and (b) the number of affected
facilities expected in 10 years had been seriously underestimated,
primarily because of facilities affected due to SIP conversion (IV-D-26).
Response: Many control systems being installed under SIP programs
are capable of controlling emissions below the NSPS limit of 35 mg/liter.
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Test data have shown that, in their normal operating mode, carbon
adsorption (CA) arid thermal oxidation (TO) units can consistently
operate well below the 35 mg/liter limit (II-A-4, II-A-17, II-A-23,
II-A-24, II-A-26, II-A-37, II-A-50, IV-D-54, IV-D-55, IV-D-56, IV-D-57).
Therefore, for CA and TO units there are no additional costs involved
in meeting 35 mg/liter versus meeting 80 mg/liter. Current carbon
systems are designed for levels below 35 mg/liter (IV-D-36, IV-E-20).
Test results on current refrigeration (REF) systems show that
only some of the units meet the 35 mg/liter limit. However, it should
be remembered that most of these systems were installed to meet an
80 mg/liter standard. Conversations with the major manufacturer of
these systems indicate that adjustments to operating parameters can be
made which will increase the control efficiency (IV-E-32). Such
adjustments would increase electrical costs (claims by the manufacturer
of as much as 50 percent increase). The assumption that costs would
not increase in the case of CA and TO units in order to meet 35 mg/liter
is still considered valid. However, since it appears that the REF
technology could be used to meet the standard, at somewhat increased
capital and operating cost levels from the average current system'(as
much as 25 percent increase in capital cost and 50 percent increase in
energy costs (see Section 2.5.3)), and since a large segment of industry
is using this form of control (approximately 25 percent of existing
units are refrigeration units), the potential cost impact to industry
if current use patterns are maintained has been examined. Section 2.5.3
discusses the additional costs associated with REF units designed to
meet the 35 mg/liter limit. Section B.2.1 of Appendix B examines the
updated industry costs.
As pointed out in Section 2.3.1, §60.500(c) changes the applicability
date for a terminal which commenced a loading rack component replacement
program prior to the promulgation date for the purpose of meeting
State or local regulations. This change in applicability dates excludes
the vast majority of these terminals from the standards. The estimate
of 55 facilities affected in the first five years, based on industry
response to Section 114 letters, is still considered appropriate.
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Comment: One commenter stated that EPA's estimate of both the
number of systems requiring replacement by the industry and the cost
of replacement were too low. His estimate was a $28 million nationwide
capital cost over a 5-year period, as opposed to the $25.3 million
estimated by EPA (IV-D-30).
Response: The nationwide cost estimates presented in Table 8-40
of BID, Volume I represented the best estimates possible using infor-
mation from all segments of the bulk terminal industry. The principal
unknowns in calculating total costs included factors such as decisions
made by individual owners and operators as affected by a highly volatile
market situation. EPA recognizes that only si ightly. different assump-
tions could lead to a nationwide capital cost estimate of $28 million,
or 10 percent higher than previous estimates.
Since it is not the intent of the Agency to cover under
reconstruction provisions the facilities which are converted in order
to comply with SIP regulations, the estimate of 55 facilities affected
in five years is still believed to represent a reasonable approximation,
based on Section 114 letter responses. The current declining market
situation could serve to decrease this number because of fewer terminal
expansions. The updated industry costs have been used to recalculate
the nationwide cost impact, with the costs of purchasing arid operating
continuous monitors now included in these estimates, even though
monitors are not required by the standards at this time. By 1986,
industry will spend about $12.2 million in capital investment, and the
net annualized cost in the fifth year will be $2.5 million. The
capital and annualized costs have decreased since the original evaluation
mainly because of re-analysis of top-to-bottom loading conversion
costs and because the promulgated regulation no longer contains a
requirement for the upgrading, replacement, or the addition of add-on
controls for existing vapor processing systems. In the previous
analysis, the costs for the top-to-bottom loading conversions were
attributed to the standards for all top loading terminals in the
nationwide cost determination. However, in the revised evaluation,
the cost of top-to-bottom loading conversions not coupled with vapor
control, which would cause the facility to become affected through the
reconstruction provisions, were not included in costs associated with
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the standards. These costs would be incurred by the terminal owner
regardless of the standards since the conversion was performed voluntarily.
Sections B.2.1 and B.2.2 of Appendix B discuss the revised costs and
the assumptions used in calculating nationwide impacts.
Comment: Another cominenter claimed that "the economic analysis
for the 80 mg/liter standard underestimated the cost by 25 percent;
thus the analysis for the 35 mg/liter standard may incur comparable
error" (IV-D-19).
Response: The economic impacts of Regulatory Alternatives II,
III, and IV were analyzed using the most up-to-date information available
at the time the .analysis was made. Since proposal of the standards,
costs have been updated so that the impact of Alternative IV could be
reassessed. In re-evaluating all cases involved with Alternative IV,
it was found that the cost per unit of emission reduction for the
addition of add-on controls to existing vapor processors or the replacement
of existing vapor processors was unreasonable. For this reason and
because it is not considered reasonable to require upgrading, add-on
controls, or replacement for these vapor processors, the final standards
have been revised to allow existing vapor processors to meet an 80 mg/liter
emission limit instead of the 35 mg/liter limit. The remainder of the
costs associated with Alternative IV, upon re-evaluation were found to
be reasonable. No specific details clarifying the assertions of the
cominenter were given and the re-evaluation of the costs was felt to be
thorough and accurate. The revised costs are presented in Section B.2
of Appendix B.
2.5.2 Economic Incentive to Control Emissions
Comment: One commenter felt that the proposal is unnecessary
since, due to rising gasoline costs and the trend toward larger termi-
nals, the industry will have an ever-increasing financial incentive to
install vapor recovery equipment (IV-D-26). Another commenter felt
that, if the statement that the proposed standards would result in a
net energy savings were correct, then the economic incentive alone
would be sufficient for industry to respond without the need for
regulatory action (IV-D-12).
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Response: A review of the net annualized costs to various model
plants and to the industry as a whole, as summarized in Appendix B and
Section 1.2.3, shows that bulk terminals would in most instances incur
some positive net costs. Only among the larger terminals would net
savings be expected, and even among these facilities, the cost of
planning, designing, purchasing, and installing vapor recovery equip-
ment, might be sufficient to outweigh economic incentives and convince
owners not to expend such effort. Also, while there may be cost
savings, the incentive may not be so great as to warrant controlling
emissons since greater investment opportunities exist elsewhere. In
promulgating this NSPS, the Administrator is establishing minimum
nationally uniform standards reflecting the best demonstrated tech-
nology, as required by Section 111. If the trend toward large terminals
results in an ever-increasing financial incentive to install vapor
recovery equipment, the cost and economic impacts attributable to the
standards will be reduced.
Comment: One commenter pointed out that even the small cost per
gallon to comply with the standards would be sufficient to discourage
a terminal owner or operator from performing modifications at a terminal,
The ultimate result of discouraging investment in present terminals
could be the closing of some terminals with the net result of fewer
terminals, increasing truck movement of products, and increasing
overall pollution (IV-D-12).
Response: The results of both the original and revised economic
analyses showed that for the two smallest model plants the standards
could, in the worst case, have a significant negative impact on
profitability in the unlikely absence of complete control cost pass-
through. The original analysis on existing facilities showed that
both the 380,000 liter/day and 950,000 liter/day terminals would
encounter ROI's of less than 11 percent, taken to be the minimum
acceptable level (Section 8.4.1.2.1 of BID, Volume I). The revised
analysis (Section B.3 of this document) indicates that only the
380,000 liter/day top-loaded facility will experience a significant
decrease in profitability with a post-control ROI range of 7.7 to
8.0 percent. The 950,000 liter/day terminal will still maintain a
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marginal profitability level with a post-control ROI range of 10.6 to
11.0 percent. However, the preceding impacts are worst-case scenarios
and are very unlikely to occur. Since the price increase necessary to
offset the control costs is less than 0.5 percent, the most likely
scenario will involve an impact with most of the control costs passed
through and very little cost absorption. Under this scenario no
existing terminals are expected to close. The industry profile did
forecast a trend away from new small bulk terminals to larger terminals;
however, this is a result of ongoing technological advances and economies
of scale, and of a changing market situation. This trend is not
expected to be accelerated by the implementation of the standards.
2.5.3 Vapor Processor Costs
Comment: One cominenter claimed that the EPA estimate of the unit
purchase cost for a carbon adsorption (CA) vapor recovery system is
low by about 4 percent, while the installation cost is underestimated
by 40 percent (if the facility has bottom loading) or by at least
320 percent (if the facility must convert from top to bottom loading).
Purchase and installation costs of the CA units were presented by this
cominenter on a per-facility basis (IV-D-37, IV-D-38, IV-E-19). Another
commenter submitted cost data indicating typical vapor recovery and
bottom loading expenditures of $254,000 and $805,000 per terminal
(2 racks), respectively (IV-E-19).
Response: Most carbon adsorption units are currently being
produced by two manufacturers. The purchase costs used in the cost
analysis were received from the one major manufacturer at the time the
analysis was performed (mid-1979). Since proposal, estimated costs
have been updated through contacts with both manufacturers (IV-E-20,
IV-E-36), and are presented in Section B.2.1 of Appendix B. Current
average CA unit prices are lower than the previously presented prices
by 20, 16, 12, and 7 percent, respectively, for Model Plants 1, 2, 3,
and 4.
The average cost of installing a vapor processor was estimated as
85 percent of the initial purchase price of the unit, based on 14 actual
installations. Values used to compute the average installation cost
ranged from 37 percent to 147 percent. Since no trend in this percentage
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as a function of purchase cost or unit type was noted, a single value
representing the average was selected. Consequently, some unit
installation costs will be higher and some lower than those presented
in the analysis. As shown in Table 8-20 of BID, Volume I, the cost
elements considered in this figure included such items as engineering
and approvals, pad, piping, electrical, condensate tank, and other
elements concerned directly with the processing system. Loading rack
conversion costs were presented as separate cost elements (BID, Volume I,
Tables 3-32 through 8-34). Data on 13 installations submitted by the
first commenter indicated average costs of $192,100 for the vapor
processor, $220,400 for processor installation, and $142,000 for minor
loading rack modifications (half were already bottom loading and the
remainder were modified rather than rebuilt). Processor installation
costs are seen to average about 115 percent of the purchase price of
the processor, which is consistent with the range of values considered
in deriving EPA's 85 percent figure. The second commenter submitted
data showing that the typical installation cost for a refrigeration
unit at his terminals was $90,000, or 55 percent of the $165,000
purchase price. Again, this percentage falls within the range of
values considered previously by the Agency.
The cost of loading rack conversions varies widely throughout the
industry. In converting racks from top to bottom loading, a terminal
may incur expenses for design and planning work, demolition, loading
rack equipment, delivery pumps, piping, electrical service, fire
protection, concrete drive and drainage, office and canopy structures,
and a host of other miscellaneous equipment and expenses. The total
sum spent for such work is largely dependent on the previous condition
of the terminal and the current requirements and preferences of the
terminal owner. Recent contacts with construction contractors who
have experience with loading rack conversion work indicate that EPA's
previous estimate of $160,000 (BID, Volume I, page 8-53) is toward the
low end of the current cost range for such conversion work (IV-E-33,
IV-E-39). To reflect these cost changes, the estimate for the conversion
cost for a loading rack is increased to $200,000, and is incorporated
in Table B-2 of Appendix B. In the absence of a more detailed breakdown
of the commenter's data, EPA must presume that the higher cost figures
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reported by the commenter include the cost of several aspects of
conversion not attributable to these standards.
Comment: Two commenters stated that operating (electrical) costs
presented for some vapor recovery systems are in error. One of them
forecasted that refrigeration systems designed to meet the proposed
35 mg/liter limit would require 25 percent more capital investment and
cost about 5U percent more for electric power than systems designed to
meet 80 mg/liter (IV-E-19, IV-F-1, IV-F-3). The other commenter
stated that instead of the refrigeration unit consuming twice as much
power as a comparable carbon adsorption unit, as presented in BID,
Volume I, the refrigeration unit actually requires 50 to 60 percent of
the power consumed by carbon adsorption. This commenter also felt
that estimates of electrical costs should be based on field data, and
not only on manufacturers' claims (IV-D-53, IV-F-1).
Response: Operating costs for all control technologies discussed
in BID, Volume I were calculated using electrical consumption data
supplied by the system manufacturers. The refrigeration (REF) unit
purchase cost and electrical consumption figures collected in 1979
applied to systems used to achieve the SIP limit of 80 mg/liter. The
data have subsequently been reassessed using more current costs.
The manufacturer of essentially all of the current REF units was
contacted to obtain present purchase and operating figures which would
be reflected for a system to meet the emission limit of 35 mg/liter
(IV-E-32, IV-J-8). Unit models were selected for application to the
four model plants, based on the parameter suggested by the manufacturer,
peak hourly product loading. For example, Model Plant 2 is estimated
to have a peak hourly loading of 290,000 liters per hour (76,500 gal/hr).
The selected REF unit has a peak hourly capacity of 380,000 liters/hr
(100,000 gal/hr) in the operating mode which limits emissions to
40 mg/liter (considered equivalent to 35 mg/liter for costing purposes).
The corresponding daily capacity of this unit according to the manufacturer
is 3,800,000 liters/day (1,000,000 GPD), or 4 times the model plant's
daily throughput. Units for the other model plants were specified
with a similar amount of excess capacity, so that cost estimates would
be conservative. The price of this unit is $138,150, and it operates
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at an average of 88.4 kilowatts of power. Annual power costs have
been calculated as before, assuming 12 hours per day and 340 days
per year of operation, and a utility cost of $0.06 per kilowatt-hour
($21,640 per year for this model plant). The purchase price is 19 percent
lower than the previous price of $170,000 used in BID, Volume I, and
the power cost is 6 percent higher than the previous figure (Tables 8-19,
8-31, and 8-34 of BID, Volume I). This manufacturer has indicated
that improvements to the technology are still being made, which are
expected to increase efficiency and reduce costs (IV-E-3).
Another reason stated by this manufacturer for reduced prices was
that units in the past had been greatly oversized with respect to
actual requirements (IV-F-1). Further, the new generation of units
being most widely marketed (and different from the units previously
costed) is characterized by lower capital costs (IV-E-32). The unit
purchase and electrical operating costs reported in BID, Volume I were
not simply increased by 25 and 50 percent, respectively, as suggested
by the first commenter in order to estimate current costs of the more
efficient units. Because of the factors noted above, the previously
reported costs would not represent a reliable cost baseline. Instead,
actual prices and power requirements provided by the manufacturer for
units specified to meet 40 mg/liter were used to evaluate the impacts
of the standard (IV-J-8). The updated costs are presented in Section B.2.1
of Appendix B. EPA considers the updated costs, presented in Tables B-l
and B-2 for refrigeration systems designed to meet 35 mg/liter, to be
reasonable.
In order to assess the cost impact of Regulatory Alternative II
(emission limit of 80 mg/liter), the purchase price and electrical
operating costs of REF units specified to achieve 80 mg/liter were
examined using the manufacturer's current specifications (IV-J-8).
These specifications indicate that while unit purchase cost is higher
when a larger unit is specified, the electrical costs of achieving a
limit near 35 mg/liter may actually be lower. However, the relationship
of these costs changes as different sized units are selected to provide
various levels of reserve capacity. Based on this analysis, the
figures claimed by the first commenter were assumed to constitute a
worst-case cost scenario to a REF unit user. The purchase costs of
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units meeting 80 mg/liter were taken directly from the price list, but
electrical costs used in the assessment were calculated as 50 percent
higher than the costs for 40 mg/liter systems. This assumption introduces
a measure of conservatism into the cost analysis of Alternative II,
but does not have a major effect on the net annualized costs.
Field data on power costs for REF units are scarce because most
users do not measure the individual electrical consumption for the
units themselves. One terminal owner whose unit was tested at 97.5 percent
control efficiency (achieving 35 mg/liter) reported a consumption of
38,600 kW-hr per month at his 875,000 GPD terminal (IV-D-47). The
equivalent annual cost of $27,800 compares well with the Model Plant 3
and 4 costs of $21,600 and $28,600, respectively, presented in Appendix B.
The unit manufacturer estimated the electrical operating cost for
equipment achieving 35 mg/liter as $0.0000226 per liter of gasoline
transferred (IV-F-3). Based on this figure, annual power costs for
Model Plants 1, 2, 3, and 4 would be $2,900, $7,300, $14,600, and
$29,200, respectively. While these figures compare with the Appendix B
estimates for the larger terminals, they are significantly lower for
the small terminals. Thus, the presented annualized costs for small
terminals selecting REF units may be conservative, and the cost impact
may be overestimated. Current estimates, however, are considered to
represent sufficiently accurate averages for the purpose of determining
cost impacts.
The power costs for current carbon adsorption (CA) units were
calculated in the same manner as those for REF units, based on infor-
mation supplied by the two major CA unit manufacturers (IV-D-51,
IV-E-20, IV-E-36). The following table shows the comparative requirements
for the two types of systems:
Average for CA Units
Model
1
2
3
4
Plant
Operating
(Hours per
REF Unit
78.2 (12)
88.4 (12)
88.4 (12)
117 (12)
from Two Manufacturers
23 (14)
32 (15)
37 (20)
63 (22)
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As mentioned earlier, the REF units have been specified with considerable
reserve capacity, so that the power figures may be conservative with
respect to the model plants. Annual electrical costs for REF units
are calculated to be 189, 119, 43, and 1 percent higher than the
average costs for CA units, for Model Plants 1, 2, 3, and 4, respectively
(Tables B-l and B-2). Section B.2.1 of Appendix B presents a summary
of these costs.
Field data on CA system electrical costs also have not been
gathered by most users. Two operators have recently reported monthly
costs of about $500-900 for smaller units and $1200 for larger units
(IV-E-40, IV-E-42). These costs correlate well with Appendix B estimates
for the small terminals, but are somewhat lower than estimates for the
larger terminals.
Comment: One commenter indicated that the average maintenance
expense for a carbon adsorption (CA) vapor recovery system was
underestimated by 50 percent. He estimated that the average annual
maintenance cost per terminal is at least $13,300, which does not
include daily preventative maintenance checks (IV-D-37, IV-E-19).
Response: As discussed on page 8-45 of BID, Volume I, the amount
spent by terminals for maintenance is dependent on many factors (such
as whether union labor rates are in effect, maintenance performed by
in-house personnel versus outside contract service, etc.)- Most of
the costs submitted by the commenter applied to new units in operation
less than one year, and were extrapolated to calculate annual costs.
Several operating problems, many of them resulting from extreme winter
conditions, were described. These problems, some of which have been
remedied, undoubtedly contributed to the $13,300 annual average calcu-
lated cost reported by the commenter. These costs ranged from 3.5 to
11.9 percent of the equipment purchase cost, averaging 7.1 percent.
While many users have not accumulated maintenance cost estimates
because their units are quite new (IV-E-41, IV-E-42), one operator
estimated annual maintenance of CA systems to be 3 percent of the
purchase price (IV-E-40). One CA unit manufacturer estimated this
cost as about 2 percent of the purchase price of the equipment (IV-D-36,
IV-D-51). The estimate presented in BID, Volume I, 4 percent of
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purchase cost, is considered representative of CA units nationwide,
based on the information considered prior to proposal of the standards,
and on more recent industry estimates.
2.5.4 Costs Associated with Emission Limit
Comment: One commenter felt that the achievability of the 35 mg/liter
limit has not been adequately demonstrated, taking into consideration
the cost of achieving the limit (IV-D-26). Two other commenters
expressed the opinion that the proposed 35 mg/liter standard is based
on a calculated cost-effectiveness which does not reflect true costs
and emission reductions. One pointed out that EPA estimated a cost-
effectiveness of $632 per ton of VOC controlled for an 80 mg/liter
limitation, whereas State experience under SIPs has shown a cost-
effectiveness of $1,200 per ton of VOC controlled at an 80 mg/liter
standard. The incremental cost of achieving a 35 mg/liter standard
seems unreasonable considering the small net improvement in air quality
(IV-D-25, IV-D-31).
Response: The cost-effectiveness figures presented in Table 8-40
of BID, Volume I were based on the most current information available
on actual costs of vapor control system installations as reported to
EPA. The figures apply to a nationwide distribution of regulatory
coverage, and take into account a mix of terminal sizes, processor
types, and necessary terminal conversion work. The commenter did not
supply a breakdown of costs to support the $l,200/ton figure, but in a
followup conversation (IV-E-52), it was learned that the figure was
based on 12 installations at his own company of CA systems at medium-size
terminals (about 625,000 liters/day). For each case, the cost to
convert the loading racks from top to bottom loading was included.
Since the commenter did not supply a detailed cost breakdown, the
cost elements contributing to the higher cost-effectiveness cannot be
identified. However, since all of the commenter's terminals required
major loading rack conversion work, this is considered to be the most
likely reason for the difference. As shown in Tables 8-29 and 8-32 of
BID, Volume I, the cost-effectiveness for an existing bottom loading
Model Plant 2 terminal installing a CA unit is estimated to be $0.12/kg,
while the cost-effectiveness for a top loading terminal which must
convert to bottom loading is about $0.52/kg. Thus, the commenter's
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costs may be biased toward the high end of the cost range. It should
be remembered that since the figure of $632/ton represented a national
average, individual cases will likely be higher or lower.
The estimated costs of control for the standards have been
re-evaluated and are presented in Table B-4 of Appendix B. Revised
cost-effectiveness figures are presented in Table B-3 of Appendix B.
The Agency believes that these figures demonstrate that the costs
associated with the selected alternative are reasonable, and the
intent of the Clean Air Act is satisfied. Discussions about the
environmental impacts of the standard are contained in Section 2.4.
2.5.5 Other Terminal Costs
Comment: One commenter pointed out that EPA's estimate of "operating
labor" at $3,400 per year for each affected terminal, to ensure that
only vapor-tight gasoline tank trucks use the facility, totally ignores
the operating practice of the gasoline bulk terminal industry. The
"real world" cost of operating labor alone to comply with the proposed
standards would be $37,889,180 per year by 1990 (assuming EPA's 110 affected
terminals), which far exceeds anything considered by EPA in the rulemaking.
These costs not only would be certain to drive many independent terminals
out of business, but demonstrate that the proposed standards are not
cost-effective (IV-D-35).
Response: As pointed out on pages 8-43 and 8-45 of BID, Volume I,
the operating labor cost considered in the tables reflected the daily
unit inspections and the monthly system leak inspection. Estimated to
average one hour per day, the annual cost at $10 per hour would be
$3,400. To reflect labor rate increases in the past two years, the
hourly rate has been increased to $15 per hour in the revised costs
presented in Section B.2.1 of Appendix B, producing a per-terminal
cost of $5,100 per year. The cost to 110 terminals over 10 years
would be about $0.56 million.
The commenter presumed that at least two extra personnel, to
check the vapor tightness documentation of tank trucks as they enter
the terminal, and to check hose connections, would be required at each
affected terminal. These extra personnel are not in fact required
under the regulation, and will not be needed to carry out the provisions
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of the regulation. Section 2.9.1 discusses the question of additional
personnel and tank truck vapor tightness.
Comment: One commenter stated that vapor processor energy consumption
calculations introduced a major error into BID, Volume I. The energy
consumed at the generating station should have been used in the calculations
to avoid an overstatement of net energy recovery. Overall energy
consumption was underestimated by a factor of 10 (IV-D-23).
Response: The net energy consumption of a model plant is calculated
by subtracting energy equivalent of the amount of recovered product
from the energy required by the plant to control emissions to the
level of the standard. The national energy impact on the industry
represents the total net consumption of all terminals affected under
NSPS. If the energy consumed at the generating station to produce the
electricity for the terminal were used in the calculations, the amount
of energy saved which would have been spent to produce the gasoline at
the refinery would have to be calculated to make comparisons on an
equivalent basis. A comparison of costs and credits on such a basis
is considered neither logical nor practical by the Agency.
Comment: One commenter felt that there would be no economic
benefit to an emission limit more stringent than 80 mg/liter because
the operating costs would become excessive in relation to the value of
the recovered product (IV-F-1).
Response: The emission limit of 35 mg/liter was selected for new
vapor processing systems to reflect the performance of the best available
control systems as required by Section 111 of the Clean Air Act, and
not necessarily to assure that each facility operator realizes the
maximum return due to recovered product. For some systems, the operating
cost of an 80 mg/liter system may be less than the cost to operate the
more efficient systems achieving 35 mg/liter. However, the Agency's
concern in evaluating alternative emission limits is with the economic
impact of each particular alternative on the industry and on individual
plants. The economic analysis was thoroughly reviewed and showed that
attainment of the limit would not result in an unreasonable cost or
economic burden for those affected facilities installing new vapor
2-52
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processing systems. The review of costs and other factors did indicate
that the costs for replacing or adding additional control onto an
existing control device may be unreasonable. For this reason, affected
facilities with existing control devices are required to meet an
81) mg/liter limit instead of a 35 mg/liter limit. The costs of complying
with the regulation have been updated, the economic impact has been
re-examined, and these assessments are presented in Appendix B.
2.5.6 Tank Truck Costs
Comment: One commenter questioned the estimated costs for
retrofitting and testing tank trucks. He estimated the retrofit cost
for a four-compartment trailer to be $8,800, instead of the $6,400
given in the preamble. In addition, some costs associated with the
vapor tightness testing were not considered, including cleaning,
purging, and reinspection and hydrostatic retesting of tanks. Loss of
revenue due to the tank downtime caused by testing was also cited as a
missing cost element (IV-F-4, IV-F-6). A second commenter questioned
EPA's cost estimate of $400 per compartment for tank truck vapor
recovery conversions. This commenter also felt that the proposed
regulations would create undue economic hardship and paperwork for
those bulk plants which operate a small number of tank trucks.
Particularly significant are tank truck conversion costs and the
revenue lost as a result of the time required to take tank trucks out
of operation (at least one day) for testing (IV-D-11).
Response: Estimated costs were presented in BID, Volume I, for
conversion of top loading trucks to bottom loading, addition of vapor
recovery provisions to new and older tank trucks, and for the annual
vapor tightness test for delivery tanks. Conversion to bottom loading
was estimated at $4,000 (page 8-63), vapor recovery at $1,600 for new
trucks (page 8-39) and $2,400 for the average older truck (page 8-63),
and the vapor tightness test at $150 (page 8-46). These costs have
been re-evaluated through contacts with companies which perform tank
truck conversion work (IV-E-22, IV-E-23, IV-E-24, IV-E-25, IV-E-26).
In the cost re-evaluation in Appendix B, several costs have been
revised. Conversion shops have indicated that the cost for bottom
loading and vapor recovery retrofitting ranges from $6,400 to $8,000
2-53
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for pre-1967 tank trucks, from $4,800 to $7,200 for 1967-75 tank
trucks, and from $4,400 to $4,800 for tank trucks manufactured after
1975. Thus, the previous estimate of $6,400 still represents an
accurate average cost for the overall population. However, the estimates
of $1,600 and $2,400 for vapor recovery addition to new and older
trucks, respectively, have been increased to $2,000 and $3,000, based
on updated cost information. The cost for incorporating vapor recovery
provisions is revised to $500 and $750 per compartment for new and
older tank trucks, respectively. The actual cost for the annual vapor
tightness testing is still estimated to be $150, but a cost impact for
loss of revenue due to downtime has been included in the testing cost.
Data submitted by the first commenter indicate a downtime cost per day
of $300 (IV-D-44); this has been added to the cost of a test, which
would take approximately one full day to perform if a tank truck firm
had the test performed by an independent shop. The added cost to
terminals, which generally have the facilities to perform their own
testing, would be the one-half day cost of $150. The revised annual
testing costs are thus $450 for tank truck firms and $300 for bulk
terminals.
The smaller businesses will generally be most affected financially
by this regulation. Although the original economic analysis found
that both the 380,000 and 950,000 liter/day terminals would encounter
ROI's of less than 11 percent, the final impact on these plants will
be minimal since most of the control costs can be passed through in
the form of higher rates (see Section 2.5.6). The economic impacts
are re-examined in Section B.3 of Appendix B.
The regulation imposes no direct paperwork requirements on operators
of bulk plants which receive gasoline in their own tank trucks from
bulk terminals. However, since a verification of each truck's vapor
tightness must be kept on file at the affected terminal (§60.505(a)),
the tank truck owner would have to supply test documentation for these
tank trucks annually. This paperwork would be minimal, especially for
operators of a small number of tank trucks.
Comment: Another commenter stated that, due to the limited
financial resources of the independent tank truck owner, such owners
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would be unable to comply with the vapor tightness requirements of the
regulation. As a result, the small business tunk truck owner would be
refused access to an affected bulk terminal (IV-D-18).
Response: The original economic analysis in BID, Volume I
(Section 8.4) used the debt service coverage analysis to assess whether
firms can meet the increased annual debt service costs under controls.
The debt service coverage ratio is defined as a firm's cash flow
divided by its current maturity of long-term debt. If this ratio is
2.0 or higher, debt service coverage is considered to be healthy, but
if it is less than 1.0 the annual debt service costs cannot be met and
the firm will find its access to capital markets restricted.
The original economic analysis suggested f» decrease in the debt
service coverage ratio from the range of 2.1 to 2.4 to the range of
1.7 to 2.2. This decrease does represent a slight increase in lender
risk, but not enough to affect the capital financing capability of the
independent tank trucking firms. Therefore, access to capital markets
for financing air pollution control measures would not be impaired by
the regulation.
2.5.7 Ability to Pass Through Control Costs
Comment: Two commenters stated that the costs of tank truck
control cannot be easily passed through to the consumer by common
carriers (IV-D-11, IV-F-4, IV-F-6). One of them further stated that
the proposed rule would "tend to eliminate" bulk plant operations.
These smaller operators could not remain competitive with major oil
companies, since control costs would have to be absorbed and the
profit margin reduced (IV-D-11). One commenter stated that EPA has
failed to recognize that pipeline companies may be legally unable to
pass through costs. Most pipeline companies are common carriers whose
rates are regulated by the Federal Energy Regulatory Commission (FERC).
To pass through a cost, the company must publish a new tariff with
FERC. A pipeline tariff may be denied, suspended, or modified, and it
may take years before an increased tariff rate is fully in effect.
EPA must consider this tariff process in its economic analysis of the
proposed regulation (IV-D-35).
Response: According to the Motor Carriers Act of 1980, Section II,
49 U.S.C. 10708, the tank truck operators are allowed to increase
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their rates by 10 percent per year without any restrictions, and
beyond the 10 percent per year level with the provision of protest by
customers and a followup investigation by the Interstate Commerce
Commission (IV-E-46). The cost pass-through analysis from the original
economic analysis in BID, Volume I revealed a range of necessary rate
increases from 0.6 to 3.0 percent. This range of values is substan-
tially less than the unrestricted 10 percent per year limit; therefore,
no regulatory-related rate problems of cost pass-through are forecasted
for the independent tank truck industry.
Pipeline companies must apply for rate increases with the FERC.
According to the FERC, the average processing time for an application
to increase their rates is 10 to 12 months. However, the pipeline
company is allowed to increase its rates, subject to refund, 5 months
after the application date. Any divergence from the average processing
time is usually due to inaccurate presentation and documentation of
the increased operating costs (IV-E-45). Based on these findings, no
unfair economic hardship would be created for the pipeline industry.
The original economic analysis found no significant impact resulting
from the proposed standards even when complete control cost absorption
was assumed, and no plant closures resulting from the standards were
forecast. The industry profile did forecast a trend away from new
small bulk terminals to larger terminals; however, this trend is not
expected to be accelerated by the implementation of the regulation.
2.6 EMISSION CONTROL TECHNOLOGY
2.6.1 State-of-the-Art Equipment
Comment: One commenter stated that the EPA test data presented
in the BID do not represent the present state-of-the-art in vapor
recovery equipment (IV-D-53, IV-F-1).
Response: Most EPA-sponsored testing of vapor control systems at
bulk terminals was performed between November 1973 and October 1978.
Test sites and vapor processors were selected to represent the various
control technologies which were being widely used to control loading
rack VOC emissions. At the beginning of the standards development in
November 1978, the data from these tests constituted most of the
available information on the performance of these systems. Since
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these tests were performed, the state-of-the-art in the reliability
and collection efficiency of processors has advanced considerably.
Test results on newer systems are being evaluated as they become
available, and all of the most recent information has been considered
in drafting the final rule. Data received after proposal on over
40 days of testing on CA, TO, and REF control systems indicate that
all test results, except for one of the REF tests, are below the
proposed limit of 35 nig/liter. These results are summarized in
Appendix A.
2.6.2 Test Data Presentation
Comment: This commenter also felt that the data presentation
should indicate the actual volume of air-vapor mixture which passed
through the processing units during testing, as well as the system
backpressure contributing to vapor leakage (IV-D-53, IV-F-1).
Response: The EPA test data presentation in BID, Volume I,
(Tables 4-1 and C-l) indicated the approximate daily gasoline through-
put of each terminal test site, in order to provide an indication of
the capacity of each vapor processor. The actual volume of air-vapor
mixture passing through the processor depends on the actual product
throughput during the test period, any vapor growth or shrinkage in
the vapor return line, and the amount of system leakage, primarily at
the tank trucks. The volume of vapor returned from loading per volume
of liquid loaded ((V/L) ), the potential volume of vapor returned, if
no leakage occurred, per volume of liquid loaded ((V/L) ), and the
ratio of these parameters (F factor) are presented in Table C-l, and
indicate the effect of the abovementioned variables on the processed
volume, relative to the amount of product actually loaded during the
test. This information is considered sufficiently detailed to allow
evaluation of control system performance.
During each test (except Test No. 4) the average static pressure
in the vapor return line near the tank truck was recorded for each
loading. Table 2-4 summarizes the backpressure data recorded in the
EPA-sponsored emission tests and presents data obtained after proposal
from six tests performed in California. The test numbers for the
EPA-sponsored tests in Table 2-4 correspond to the test numbers assigned
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TABLE 2-4. VAPOR RETURN LINE PRESSURES DURING LOADING'
Test No. Type of
(Reference) Unit
Lowest
Pressure
(mm H20)
Highest
Pressure
(mm H20)
Mean
Value
(mm H20)
No. of
Readings
EPA-Sponsored Tests
1 (II-A-17)
2 (II-A-26)
3 (II-A-37)
4 (II-A-4)
5 (II-A-24)
6 (II-A-50)
7 (II-A-23)
8 (Il-A-5)
9 (II-A-10)
10 (II-A-14)
11 (II-A-40)
12 (II-A-41)
13 (II-A-43)
14 (H-A-6)
15 (II-A-11)
16 (II-A-28)
17 (II-A-29)
18 (II-A-42)
19 (II-A-38)
20 (II-A-27)
21 (II-A-39)
22 (II-A-25)
Tests Received
1 (IV-J-16)
2 (IV-J-2)
3 (IV-J-3)
4 (IV-J-4)
5 (IV-J-1)
6 (IV-J-5)
CA
CAC
CA
TOC
TO
TO
TOC
REF
REF
REF
REF
REF
REF
CRAC
CRAC
CRAC
CRAC
CRAC
CRAC
CRCC
CRCC
LOA
After
CA
CA
CA
REF
REF
TO
229
107
36
d
51
30
25
25
5
28
8
20
8
15
64
30
20
127
25
33
38
18
Proposal
254
305
127
51
97
51
386
218
107
d
165
330
178
241
64
307
76
193
165
419
140
132
127
470
236
343
371
279
533
610e
483
305
208
178
318
183
56
d
119
152
97
66
25
124
33
81
46
117
107
74
76
236
84
104
175
124
417
381
333
85
142
125
29
20
40
d
37
30
52
24
38
39
41
46
56
20
43
54
19
59
65
38
34
33
12
7
21
9
11
14
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TABLE 2-4. VAPOR RETURN LINE PRESSURES DURING LOADING3 (Concluded)
Average gauge pressure at loading rack during tank filling.
CA - Carbon Adsorption
TU - Thermal Oxidation
REF - Refrigeration
CRA - Compression-Refrigeration-Absorption
CRC - Compression-Refrigeration-Condensation
LOA - Lean Oil Absorption
c
Vapor holder in collection system.
Pressures not measured in this test.
r\
Highest value occurred during the simultaneous loading of two
compartments.
2-59
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in Tables 4-1 and C-l of BID, Volume I. The mean value of pressure
for 21 of the 22 EPA-sponsored tests ranged from 25 to 318 mm of water
(1.0 to 12.5 inches of water), averaging 112 mm of water (4.4 inches
of water) pressure. The required collection system maximum pressure
of 450 mm of water was exceeded during only two tank truck loadings in
one test of a CRA type unit (Test No. 18). For the California data,
the backpressure for the CA systems was consistently higher than that
of the REF and TO systems. A total of 8 of the 40 truck loadings
tested exceeded the 450 mm of water pressure value. It was determined
that a majority of these cases took place at a terminal where the high
backpressure was due to faulty check valves in the vapor line more so
than the type of control device (IV-E-54). This emphasizes the fact
that since this pressure is measured close to a loading tank truck,
the backpressure includes pressure drop contributions from the number
of arms loading at one time and from variables in the collection
system itself (such as length and diameter of piping, elbows and
joints, liquid traps, and in-line valving), as well as from the pro-
cessor. Even though these carbon adsorption backpressures were higher
than for other systems, the data illustrated that a properly designed
vapor collection system in conjunction with a CA vapor processor can
operate below the 450 mm of water limit.
The emission test reports (reference numbers in Table 2-4) provide
more detailed information on processed volumes and system backpressure.
2.6.3 Adequate Demonstration of Technology
Comment: Several commenters remarked that the technology to
achieve the standard has not been demonstrated, because only a few
short-term tests were performed. These commenters stressed the necessity
for data on continuous performance, and on the ability of the systems
to achieve the limit over the long term (IV-D-19, IV-D-20, IV-D-26,
IV-D-53, IV-E-19, IV-F-1, IV-F-3).
Response: Although vapor recovery at bulk terminals has been
used in California for over 20 years, the current generation of control
units has been in operation only since about 1977. Most EPA testing
was performed between November 1973 and October 1978, and thus represents
the performance primarily of older systems (Section 2.6.1). The types
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of control systems which represented the newest technologies and with
the consistently lowest TOC mass emission rates were selected as the
best demonstrated technology, and the emission limit was based on
these systems.
Since the beginning of the standards development, the Agency has
sought the most recent results of tests performed by oil companies and
State agencies, in order to collect the best possible data base.
Since all of the tested systems were installed in response to SIP
limitations at or near 80 mg/liter, oil company and system manufacturer
technical representatives were consulted in order to determine the
assumed design conditions for the installed systems and the collection
potential of the various control technologies. Emission test results
on several CA units tested between 1979 and 1981 representing over
30 days of testing have been received from four State agencies and one
control system manufacturer (IV-D-49, IV-D-54, IV-D-55, IV-D-56,
IV-D-57, IV-J-2, IV-J-3). Outlet TOC mass emissions measured in these
tests ranged from 0.34 to 17.9 mg/liter, with 28 of the daily test
values below 10 mg/liter. Three REF units owned by a single oil
company in two States were tested in 1980 and 1981 (IV-B-2, IV-D-55,
IV-J-4). Daily average emissions in these tests were 21.9, 22.6, and
41.8 nig/liter. These results support the observation that current REF
units vary with respect to the 35 mg/liter limit, with some units
above and some units below the limit. The apparent reason for this is
that the control settings (compressor cut-in set point) can serve as a
thermostat to maintain a desired range of condenser temperatures,
which means that a range of emission levels is possible from a parti-
cular unit (IV-E-32). Recent tests by two State agencies on straight
TO and compression-oxidation hybrid systems yielded daily average
emissions of 0.20 and 0.22 mg/liter for the TO systems (IV-D-55) and
0.22 mg/liter for the hybrid system (IV-J-5). The hybrid system is
capable of some degree of gasoline recovery; however, this has not
been adequately quantified (see Section 2.6.9).
Even though these recently obtained test reports did not follow
the EPA procedures exactly, the Agency feels that these data demonstrate
the ability of the new systems to meet 35 mg/liter and finds no basis
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for these commenters' apprehension about the eventual inability of the
best control systems to achieve the required emission limit. As is
the case with all complex mechanical systems, adequate routine maintenance
and occasional component replacement are necessary if design performance
levels are to be maintained. However, no specific components or sub-
systems of the best systems have been identified which cannot be
maintained so that adequate system performance is achieved over an
extended period. Terminal operators and control system manufacturers
were contacted to determine the extent and the cost involved in
performing normal maintenance on th^ processing units necessary to
maintain the units in proper operating condition. These costs have
been incorporated into the cost and economic impacts contained in
Chapter 8 of BID, Volume I, and Appendix B of this document.
2.6.4 Test Data Calculations
Comment: One commenter stated that the presented test data have
gross errors so large that a comparison of control systems is impossible.
Much of the error in the "Processor VOC Emissions" column of Table 4-1
of BID, Volume I, was attributed to the "complicated" EPA calculation
method (IV-D-34).
Response: The data presented by EPA are not in error. EPA's
calculation procedures are direct and not based on assumptions or
indirect calculation of a parameter. There are differences between
EPA's and the commenter's results because the procedure used by the
cornmenter includes assumptions which are not appropriate for this
application.
For example, in the EPA procedure the outlet volume is measured
directly, whereas the commenter determines the volume indirectly from
other measured parameters. The differences in the results for thermal
oxidizers occur because the commenter's equation assumes an air balance
which does not account for the dilution air that is necessary to the
operation of this control device. Furthermore, the commenter's emission
values are obtained from a single calculation using average parameter
values for the entire 4- to 10-hour test period. EPA's results, on
the other hand, are obtained using specific values for each 5- to
20-minute test interval.
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2.6.5 Equipment Operation Under Variable Conditions
Comment: Two commenters stated that it has not been shown that
the proposed standards are achievable under sll the variable operating
conditions that may be present throughout the industry (IV-D-26,
IV-D-28).
Response: These commenters did not iuer.tify any specific variable
operating conditions which they felt may affect emission levels, nor
was any technical information included with the comments. The typical
performance test on bulk terminal control systems does nor measure
operating parameters and their possible effect on emissions, because
generally all that is required in these tests is the outlet mass
emissions or control efficiency average over several hours. However,
EPA collected data in its test program and has identified the following
variables as having a possible effect on the mass emission level or
control efficiency of the control technologies considered capable of
achieving the emission limit of the standard:
1. Gasoline composition. Gasolines with different Reid vapor
pressures (RVP) are marketed in different seasons of the year, in
order to maintain approximately constant actual vapor pressure as mean
ambient temperatures change. For example, in Southern California, the
mean average RVP is approximately 8.4 in summer, but is increased to
11.2 in winter (II-D-149). Under winter conditions, therefore, mass
emissions may be higher for some systems because of increased light
ends in the inlet vapors. If CA and REF units are sized with sufficient
collection area to meet the emission limit in winter, emissions in
summer will then be well below the limit. TO systems are often designed
to handle saturated streams stored in vapor holders, and should not be
affected by the variable RVP. EPA tests and the tests in Appendix A
show that the emission limit was achieved at various times of year and
therefore under various gasoline compositions.
2. Inlet TOC concentration. Both CA and REF systems have been
tested under a range of inlet concentrations returned from tank trucks
(Appendix A and BID, Volume I, Appendix C), and theoretical estimations
and analyses have indicated that these systems will collect efficiently
throughout a range of concentrations (IV-A-2, IV-D-38). Efficiencies,
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in fact, are likely to increase with increasing inlet concentration
(Section 2.6.8). TO systems are easily designed to handle saturated
inlet streams.
3. Peak loading levels. Most control systems are designed for
peak loading hours at a terminal, rather than daily throughput, because
of the fluctuation in loading activity throughout the day. Thus, a
properly sized unit can handle peak periods, and should have improved
performance during the remainder of the day. As pointed out in
Section D.3.1 of BID, Volume I, it is recommended that testing be
conducted during the 6-hour period in which the highest throughput
normally occurs; at least 300,000 liters of gasoline must be loaded in
order for the test to be valid. Therefore, the test results considered
valid by the Agency reflect representative normal operation at a
terminal during periods of the highest input to the unit.
The conclusion can be drawn that the operational variables at a
terminal are merely design variables which affect the selection and
sizing of the vapor processor. No variables have been identified
which would prevent the standard from being met on a consistent basis.
2.6.6 Additional Test Data
Comment: Three commenters felt that no change in current emission
limits should be considered until additional data on system performance
have been obtained (IV-D-53, IV-E-19, IV-F-1, IV-F-3).
Response: The Agency has carefully considered test results on
six control technologies tested between 1976 and 1981 at about 60 bulk
terminals. These results are presented and discussed in Appendix C of
BID, Volume I, and Appendix A of this document. These data are considered
sufficient to adequately evaluate the performance of currently available
types of control systems.
2.6.7 Carbon Adsorption (CA) Control Technology
Comment: Two commenters felt that the CA system might have
difficulty meeting even an 80 nig/liter standard under the Stage I
situation of richer vapor mixtures returned to the unit (IV-F-1,
IV-F-2, IV-E-19).
Response: Theoretical projections of the performance of both
carbon adsorption and refrigeration systems indicate that increasingly
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more concentrated inlet streams will be collected with increasing
efficiency (IV-A-2, IV-D-38, IV-E-36). Test data are insufficient to
determine the exact relationship of these two parameters, but some EPA
tests indicate that the CA type system is capable of high collection
efficiency and low outlet emissions under inlet concentrations higher
than the 35 percent, as propane, expected in Stage I areas. In Test
No. 1 of BID, Volume I, daily average inlet concentrations of 60.4 and
48.8 percent as propane were accompanied by control efficiencies
exceeding 99 percent, and by outlet mass emissions of 8.5 and 3.9 mg/liter,
respectively. In Test No. 3, concentrations of 45.0 and 40.1 percent
were controlled at over 98 percent efficiency, with outlet emissions
of 11.0 and 9.7 mg/liter, respectively. Another test performed in
California, where Stage I controls and vapor-tight tank truck requirements
are in effect, indicated that the emissions from a CA system were less
than 12 mg/liter with an inlet concentration of over 40 percent (II-D-149).
These data indicate that the 35 mg/liter emission limit can be achieved
by properly operated CA units throughout the range of inlet concentrations
which may be encountered at terminals affected by these standards.
Thus, no basis has been found which indicates the inability of
carbon adsorption to control the higher concentration vapor streams
expected in Stage I areas to the outlet emission rate required by the
standards.
Comment: One commenter felt that EPA should not have omitted
test data considered unrepresentative of CA system performance in its
evaluation of the system, because these data represented normal conditions.
The commenter believes these data indicate a rapid deterioration in
system efficiency for the carbon adsorption technology. Further, the
CA technology is capable of only marginally achieving 80 mg/liter
consistently (IV-D-34). A second commenter agreed that adequate data
on the control efficiency deterioration of CA units after a period of
operation have not been collected (IV-D-29).
Response: As discussed in Appendix C (Sections C.3.1 and C.3.3)
of BID, Volume I, two test days were omitted from the CA system tech-
nology evaluation because of abnormal system and terminal operations,
as explained in the test reports.
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In Test No. 1, the system was quite new, having been installed
about 5 months before the test. The bed switching timer had been set
to accommodate a low-volume lean stream (primarily fuel oil loading).
During testing, a higher volume, rich stream was processed by the
unit, due to increased gasoline business. This led to bed breakthrough
on the first test day, and resulting high emissions of 92.6 mg/liter
(II-D-41). Each time that loading started, the carbon unit switched
to the same carbon bed regardless of whether the regeneration cycle
had been completed. Since one carbon bed was repeatedly exposed to
the inlet vapor stream without adequate regeneration, system performance
on the first test day is not considered to represent the capability of
this technology to control emissions. The timer was adjusted on the
morning of the second test day, and emissions on the second and third
test days were very low (8.5 mg/liter and 3.5 mg/liter, respectively).
Emissions on the first two days of Test No. 3, performed at the same
terminal as Test No. 1, were also very low (11.0 mg/liter and 9.7 mg/liter),
indicating the ability of this system to maintain high collection
efficiency after 17 months. The schedule at this terminal calls for
str gered tank truck loadings, with half-hour intervals between loadings,
and the CA unit had been sized to handle the resulting vapor loading
(ID,000 gallons in 15 minutes). On the third test day, the design
capacity of the unit was intentionally exceeded by loading two trucks
simultaneously. This produced the expected reduction in collection
efficiency and increase in emissions (63.4 mg/liter). Thus, the third
test day is not considered representative of system performance under
normal conditions at this terminal, and the data were not used in
assessing the performance capabilities of this technology.
Therefore, since the first occurrence of high emissions was due
to a system maladjustment and the second occurrence was due to
purposefully exceeding the design requirements in order to observe the
results, these test results do not indicate performance of the CA
technology under representative conditions and should not be included
when evaluating the capability of this technology to meet a specified
emission limit.
Any of the control technologies can be expected to undergo some
degree of deterioration throughout their operating lives. As discussed
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in Section 2.6.3, this deterioration in control efficiency should be
able to be controlled through regular adjustment, repair, and replace-
ment of worn or broken components. As long as the critical operating
parameters of a system are maintained within the recommended limits,
control efficiency should be relatively consistent. In the case of CA
units, these parameters include bed vacuum and adsorption cycle time,
which depend on pumps, valves, and electrical components. Both vacuum
and cycle time can be easily checked on a periodic basis to spot trouble
areas.
The activated carbon itself has the potential to lose some of its
working capacity through fouling or partial pulverization during bed
repressurization. However, EPA is not aware of any total carbon
replacements performed for these reasons in the five years since CA
units were first commercially installed at bulk terminals. While the
guarantee on the carbon from one unit manufacturer is 3 years (II-D-84,
II-E-75), industry sources indicate that an assumption of a 10-year
lifetime is reasonable (II-E-94, II-E-99, IV-E-29). For the purpose
of costing potential carbon replacements, the 10-year period assumed
in the original cost analysis (BID, Volume I) has been retained.
Existing units have shown the ability to maintain the necessary working
capacity over several years of operation.
Data from recent performance tests on newer CA units indicate
that most units limit emissions initially to well below 35 mg/liter
(see Table A-l of Appendix A). Considerable deterioration would have
to occur before the 35 mg/liter li.nit was exceeded.
Comment: Two commenters referred to the high level of collection
system backpressure with CA units, which can lead to excessive vapor
leakage from the system (IV-D-53, IV-F-1, IV-F-2, IV-F-4).
Response: As discussed in Section 2.6.2, recent test data did
indicate some higher backpressures with CA systems. However, the data
also indicated that a properly designed collection system in conjunction
with CA systems could operate below the 450 mm of water limit specified
in the regulation. It should be emphasized that the backpressure
depends upon the design of the complete system, which includes not
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only the vapor processor but also vapor piping, valving, knockout tanks,
and flame arresters.
Comment: Two commenters discussed the phenomenon of aspiration
in CA units. One claimed it is possible for TOC vapors to bypass
control through aspiration of some vapors into the product being
returned to the storage tank, and that this may be occurring in some
systems. He recommended installation of an in-line sight glass in
these systems to observe the returned product (IV-F-4, IV-D-53). The
second commenter stated that such aspiration would not be possible,
saying that vapor transfer by a centrifugal pump would constitute
"extraordinary ope'ration" (IV-D-36).
Response: The Agency recognizes the potential for circumvention
of the standards by routing vapors around a control unit, but this
practice has not been observed in any EPA tests. As discussed in
Appendix C of BID, Volume I, an air balance analysis in Test No. 3 did
not reveal any significant reduction in the air stream at the CA
processor exhaust when compared to the processor inlet. It is considered
highly unlikely that aspiration occurs, due to the capabilities of the
centrifugal pumps which return liquid gasoline from the separator tank
back to the storage tank. These pumps would not operate properly on a
liquid stream containing an appreciable percentage of vapor (IV-D-15,
IV-E-10).
Although the installation of in-line sight glasses may help to
determine whether aspiration is occurring, EPA does not wish to make
this a requirement of the standard. Based on technical and engineering
considerations, it is highly unlikely that the aspiration described by
the commenter occurs, and therefore, EPA feels that this would be an
unnecessary requirement. As stated in Section 60.12 of the General
Provisions, EPA does not allow circumvention of the standards by any
means.
Comment: Three commenters referred to carbon bed temperature
excursions at several CA unit installations during the summer of 1980.
Due to the resulting extended shutdowns, one commenter felt that doubt
had been cast on the ability of currently designed systems to consis-
tently maintain high efficiency (IV-D-23, IV-D-53, IV-E-19, IV-F-1,
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IV-F-4). Another commenter pointed out that through the institution
of certain design and operational measures, the overheating problem
had been solved, with no units having problems since the original few
incidents had occurred (IV-D-36).
Response: In conversations and correspondence with two carbon
system manufacturers, a major supplier of activated carbon, and oil
industry representatives, the apparent reasons for the incidents of
carbon bed overheating were discussed (IV-D-36, IV-D-48, IV-D-49,
IV-E-18, IV-E-19, IV-E-20, IV-E-29, IV-E-30, IV-E-40, IV-E-43). Six
occurrences of carbon bed overheating were brought to the attention of
EPA. These discussions indicated that the overheating incidents were
primarily the result of improper flow distribution and improper startup
procedures resulting in the insufficient preloading of the virgin
carbon in some new, larger units. Precautionary measures to prevent
overheating would include (1) complete conditioning of the virgin
carbon to ensure that an adequate heel has been placed on the carbon
to minimize subsequent high adsorption heat releases, and (2) sizing
the unit to maintain proper vapor velocity and flow distribution
through the carbon beds (IV-D-49).
In a report of a test program performed by one manufacturer
(IV-D-49), it was determined that the carbon bed temperature excursions
were due to oxidation reactions of some of the hydrocarbons in the
gasoline vapors. In these tests, bed temperatures of 750°F were
measured during a temperature excursion event. It was determined,
however, that these reactions do not take place until the bed temperature
has increased to a certain level. This threshold temperature where
oxidation reactions begin to occur depends upon the type of carbon in
the bed. Two types of carbon are used by the carbon system manu-
facturers, wood-based carbon and coal-based carbon. Onset of reactions
in wood-based carbon occurs at bed temperatures around 250°F and in
coal-based carbon at around 450°F. The report indicates that the
conditions favoring temperature excursions include (1) large carbon
beds which inhibit heat dissipation, (2) high ambient temperatures,
(3) poor vapor distribution and/or low vapor velocities through the
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beds, (4) high concentrations of hydrocarbon vapor in the inlet air
stream, and (5) long carbon bed adsorption periods without proper
regeneration.
One manufacturer who uses wood-based carbon has now incorporated
cooling coils in the carbon bed design to aid in heat dissipation
(IV-D-49, IV-E-20). The cooling coils circulate the cool gasoline
from storage which is already brought to the unit for the vapor absorption
cycle. Another manufacturer considered using cooling coils but could
not get them to perform to his satisfaction (IV-E-30). This manufacturer
feels the problem can be eliminated by specifying coal-based carbon
and carefully employing proper startup procedures for presaturating
the carbon beds (IV-D-36, IV-E-30). Nevertheless, bed cooling options,
using a water-glycol solution, are being offered on current units.
Industry representatives have addressed the carbon bed overheating
issue by incorporating emergency shutdown measures and bed cooling
devices on the new systems (IV-E-19). It appears that these measures
could produce cost increases of up to $20,000 for carbon systems (up
to 15 percent of unit cost). Two other oil industry representatives
indicated that on any new carbon system ordered (and possibly retrofit
to existing systems), they will specify cooling provisions and additional
temperature sensors (IV-E-40, IV-E-43).
Since only six temperature excursion occurrences have been identified
in the approximately 200 operating carbon systems, EPA does not believe
that this is a widespread problem. EPA agrees with the manufacturers
and with industry representatives that an effort should be made to
carefully follow the recommended startup and operational procedures to
minimize the conditions which may promote temperature excursions.
Since one manufacturer of CA units now uses cooling coils in all new
units, the cost of the cooling coils has already been incorporated
into the new unit costs developed for CA units in Section 2.5.3 and
Appendix B.
Comment: One commenter stated that there are still operating
problems to be worked out with the CA systems (IV-D-19). Another
comiiienter expressed concern that only the CA control technology has
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shown the potential to consistently achieve the 35 mg/liter standard,
and that this technology is still in the developmental stages (IV-D-25).
Response: The first carbon adsorption system for bulk terminal
vapor recovery was installed in November of 1976, and today the market
is shared by two manufacturers with approximately 200 units in operation.
Most types of vapor processors can be considered to be under develop-
ment in the sense that continual design improvements are being made.
Other technologies have shown the ability or the potential to meet the
proposed standard. Test results on the TO system have consistently
been below the 35 mg/liter limit. Several test results for REF systems
have been below or near the standard limit and have indicated the
potential for the system to meet the 35 mg/liter standard.
The first commenter did not specify any particular operating
problems, but EPA is not at this time aware of any major operational
problems with carbon adsorption systems. Previous difficulties which
have occurred with CA systems have involved vacuum valve actuators and
vacuum pump glycol seals (IV-D-37, IV-E-43). Currently, the terminal
industry and equipment manufacturers are working to solve these equipment
problems, and have made progress toward reducing the maintenance and
repair needed by system components (IV-E-53).
Comment: Five commenters indicated that the CA system tests were
performed on small units at small terminals, and do not represent even
average size terminals. They felt that data on smaller systems may
not indicate the performance of the large systems (IV-D-19, IV-D-26,
IV-D-34, IV-D-53, IV-E-19, IV-F-1, IV-F-2, IV-F-3).
Response: As described in Section C.3 of BID, Volume I, EPA Test
Nos. 1, 2, and 3 on CA systems were performed at two terminals having
daily gasoline throughputs of approximately 200,000 and 300,000 liters
(Model Plant 1). The other CA system referred to in Section C.I.3 of
BID, Volume I, was sized to process 950,000 liters per day (Model
Plant 2), although the daily average throughput is approximately
230,000 liters (II-D-149). Daily average emissions in these four
tests were 2.7, 5.4, 1.8, 2.8, 3.9, 11.0, 9.7, and 12.0 mg/liter,
respectively. More recent tests have been performed on CA units
(Section 2.6.3) at terminals of various sizes. Table A-l of Appendix A
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shows the results of these tests, including the volume of product
loaded during each test. Emissions well below 35 mg/liter were measured
throughout the size range of terminals which will be affected by the
standards.
These commenters provided no supporting rationale or test data
suggesting that the Agency's conclusions regarding the capabilities of
the carbon adsorption control technology at larger terminals are inac-
curate. Nor is EPA aware of process reasons that CA technology cannot
achieve 35 mg/liter at such terminals.
2.6.8 Refrigeration (REF) Control Technology
Comment: One commenter felt that the proposed 35 mg/liter limit
is too stringent for most control systems, including currently available
REF systems. While REF systems can be designed to meet this limit, it
may not be economically practical (IV-D-23). Another commenter stated
that, based on experience with current REF units, the ability of such
units to achieve a 35 mg/liter limit may depend on the time of year or
time of day at which a unit is tested (IV-D-17). A third commenter
stated that only one of his four REF units tested in California had
demonstrated emissions below 35 mg/liter (IV-E-19).
Response: Some types of currently available vapor processors,
most of which are designed to achieve an emission limitation of at
least 80 mg/liter, may not be able to meet the 35 mg/liter emission
limit. The emission limit of the proposed standards was selected to
reflect the performance of the best control systems, which test data
showed to be the CA and TO technologies. The most current refrigeration
systems have generally been operated to meet the 80 mg/liter limit and
have achieved 35 mg/liter in only some instances, with most units
slightly above the 35 mg/liter limit. These units can be specified
and operated to meet 35 mg/liter, at increased capital and operating
costs over most current units, according to a principal manufacturer
of REF units (II-E-74, II-E-85, IV-D-53, IV-E-3, IV-E-32, IV-F-1,
IV-F-4). A recently completed EPA-sponsored program used a computer
model to simulate a refrigeration vapor recovery system (IV-A-2).
This computer model indicated that the 35 mg/liter limit is achievable
by a refrigeration system cooling vapors to -100°F. Some systems
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currently operating in the field indicate condenser temperatures as
low as -120°F (IV-B-4), which should allow a vapor temperature of
-100°F to be achieved. The costs to purchase and operate REF units
which will achieve the limit of the standard are affordable by the
terminals which will be affected by the standards. Section 2.5.3
discusses the estimated costs associated with refrigeration units
installed to meet the 35 mg/liter emission limit.
Current REF units may exhibit variable capabilities with respect
to the 35 mg/liter limit, and the factors affecting system performance
can include seasonal variations (weather and gasoline composition) as
well as terminal loading schedules. However, as pointed out above,
these systems in the field are sized and operated to comply with an
80 mg/liter limit. Recent tests on newer REF units indicate that an
increasing number of units are controlling emissions below 35 mg/liter
(IV-D-55, IV-E-38, IV-J-4). Thus, even though most current REF units
are not operated to achieve 35 mg/liter, the Agency does not consider
this technology invalidated for application under this regulation.
2.6.9 Thermal Oxidation (TO) Control Technology
Comment: Three commenters felt that the proposed emission limit
encouraged the use of TO units, which do not recover any product, and
this implied endorsement is inconsistent with the Nation's energy
conservation policy (IV-D-23, IV-D-25, IV-D-26). Another commenter
felt that only TO systems could consistently meet a 35 mg/liter standard
(IV-D-34).
Response: Test data have indicated that CA and some REF systems
can also meet the 35 mg/liter limit, so the TO system is not the only
system considered under the standard. Furthermore, the cost analysis
presented in Appendix B indicates that in most cases TO systems may
not be cost-competitive with CA and REF systems when the value of
recovered product is considered (see Section B.2.1). In addition to
economic considerations, the trend toward larger terminals (consolidation
as well as new construction) will tend to limit installations of TO
systems, since product recovery cost credits make CA and REF systems
more attractive at larger terminals (Tables B-l and B-2).
An alternative approach to straight thermal oxidation involves a
"hybrid" system composed of a compression-aftercooler stage, followed
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by a burner section. These systems achieve the high control efficiency
of the thermal oxidation technique (99+ percent) while recovering some
of the vapors displaced during loading (II-B-59, IV-J-5). The actual
pr^di-ct recovery efficiency of these systems has not been evaluated.
2.6.10 General Control Technology
Comment: One commenter believed that most types of control units
could achieve an 80 mg/liter limit, although some marginally. The
commenter felt there would be problems with attempting to meet 80 mg/liter
in areas without Stage I controls (IV-D^34).
Response: Much of the EPA testing of vapor processors performed
to date has been in areas without Stage I controls, with most processors
meeting the 80 mg/liter limit contained in SIP's. The best systems
have the ability to achieve 35 mg/liter under various levels of inlet
VOC concentration, from nonStage I levels (about 15 percent by volume)
to Stage I levels (about 35 percent by volume) (see Sections 2.6.5 and
2.6.7).
Comment: Several commenters objected to the requirement in
proposed §60.502(b), for a system design which would prevent vapor
flow from one rack to another. These commenters interpreted this
requirement as necessitating the installation of check valves in the
vapor collection system. Reasons for opposition included: (a) the
requirement constitutes an equipment standard, contrary to Section 111,
(b) malfunctioning valves can cause excessive backpressure, leading to
leakage, (c) all tank trucks should be vapor-tight, so the requirement
is unnecessary, and (d) check valves are ineffective in low pressure
drop vapor applications (IV-D-23, IV-D-25, IV-D-26, IV-E-19).
Response: Section 60,502(d) does not specify the use of check
valves in the collection system, to avoid imposing a particular equipment
standard. Rather, §60.502(d) requires that the system be designed in
any manner adequate to prevent TOC vapors collected at one loading
rack from passing to another loading rack. The requirement was included
in the standard because of past observations of excessive vapor leakage
from tank trucks which were connected to the collection system, but
not loading product. This potential crossover of flow between racks
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is prevented in current systems observed during visits by EPA, generally
through the use of check valves or similar devices (II-B-54, II-B-55,
II-B-56, II-B-57, II-B-58, II-B-59, II-B-61, IV-B-6). In some cases
all tank trucks are required to hook up to the terminal's vapor collection
system, and since all tank trucks loading at a terminal nay not be
vapor-tight (such as dedicated diesel transports), tank truck vapor
tightness alone cannot be relied on for vapor containment in the
collection system. Also, losses due to vapors short-circuiting the
system by escaping through open vapor recovery connectors at idle
loading rack positions could be eliminated.
Malfunctioning valves can significantly increase backpressure at
the tank truck. However, in recent terminal visits, terminal managers
stated that the valves used in their vapor collection systems were not
high maintenance items and did not malfunction often (IV-B-6). Also,
since these valve devices have been used successfully in many of the
terminals visited, EPA believes that they are effective in loading
rack applications.
Comment: Two commenters questioned the need for the requirements
in §60.502(h) and (i), which set limits on the gauge pressure in the
delivery tank and on the opening pressure of the system P-V vents.
One recommended a pressure limit of 7,000 pascals (700 mm of water)
instead of the proposed 4,500 pascals (450 mm of water), to correspond
to the design relieving pressure for tank trucks (IV-D-36). The other
felt that these two sections of the regulation deal with engineering
details and should be left to the design engineer working with performance
specifications (IV-D-12).
Response: The pressure limit of 4,500 pascals corresponds to the
pressure limit at which the tank trucks are tested using Method 27.
Specifying a pressure of greater than 4,500 pascals would subject the
tank to a pressure beyond the level at which it has proven to be
vapor-tight and could possibly cause a leak. Department of Trans-
portation requirements indicate that the relief vents are supposed to
be full open at 7,000 pascals, but in fact the spring-loaded valves
begin to open at a lower pressure. The 4,500 pascal limit is the
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maximum pressure level the tank relief vents have been found to sustain
prior to beginning to open (II-A-41) and, therefore, was selected as
the limit for testing tanks for pressure integrity.
There are many engineering details that must be considered in
achieving this backpressure stipulation, such as pressure drop across
the processor, pipe diameter, length of pipe run, and other flow
restriction devices. All the engineering details to meet the 4,500 pascal
limit are left to the system designers.
Comment: One commenter stated that, since a terminal's vapor
collection system may receive vapors from sources other than loading
racks, §60.502(6) should be revised to read:
"Emissions from the gasoline loading racks shall not contribute
more than 35 milligrams of VOC per liter of gasoline loaded to
the bulk gasoline terminal's vapor collection system" (IV-D-12).
Response: The standards apply only to loading operations at bulk
terminals. Section 60.502(b) and (c) limit emissions from the vapor
collection system "due to the loading of liquid product into gasoline
tank trucks." This wording is specific to the contribution from
loading racks, and does not include, for example, storage tank emissions
during product delivery. However, the terminal operator is free to
route emissions from other sources if he so chooses.
2.7 SELECTION OF EMISSION LIMIT
2.7.1 Stringency of Emission Limit
Comment: One commenter stated that the proposed emission limit
of 35 mg/liter appears to be overly stringent, since only carbon
adsorption and thermal oxidation type processing units would be likely
to meet the standard (IV-D-3). Another commenter felt that the proposed
limit is unnecessarily stringent, and it would be "arbitrary and
capricious" to impose the limit. The commenter felt that millions of
dollars would be wasted due to the abandonment of RACT (80 mg/liter)
controls already in place. An 80 mg/liter limit was recommended for
the standards (IV-D-33).
Response: Standards of performance, in the form of numerical
emission limits, are intended to reflect the degree of emission
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limitation achievable through application of the best adequately
demonstrated technological system of continuous emission reduction,
taking into consideration the cost of achieving such emission reduction,
any nonair quality health and environmental impacts, and energy
requirements.
As discussed in Sections 2.6.3 and 2.6.4, test data indicate that
systems other than the CA and TO systems can meet the 35 nig/liter
limit. Carbon adsorption vapor processors manufactured by both of the
major suppliers have demonstrated the capability to regularly achieve
emission levels below 35 mg/liter. Also, thermal oxidation units have
shown the capability to achieve 35 mg/liter, although some TO systems
may require a vapor holder to reliably achieve this limit. Compression-
oxidation hybrid systems have been found to achieve the same high
control efficiencies as the straight TO systems. In addition, test
data and the manufacturer's claims suggest that REF systems can be
designed and operated to meet 35 mg/liter.
Based on a number of emission tests, EPA has identified carbon
adsorption and thermal oxidation as the best demonstrated technologies
for controlling vapors from gasoline loading racks. Section 111
requires EPA to set numerical emission limits achievable through
application of the best demonstrated technology (considering the
statutory factors), even if by doing so the Agency precludes the use
of less effective systems. Owners are nonetheless free to use any
technology that will achieve the limit.
The third response in Section 2.3.1 discusses new regulation
Section 60.502(c) which allows control systems already in place to
continue meeting an 80 mg/liter standard. This will prevent the
abandonment of current controls and will save the money referred to by
the second commenter. However, the 35 mg/liter limit is reasonable
and attainable for newly constructed facilities, for facilities without
current controls which are voluntarily modified or reconstructed, and
for facilities with refurbished vapor control systems.
2.7.2 Alternate Suggested Emission Limit
Comment: One commenter stated that mass emission rates from REF
and CRA units vary with inlet temperature, humidity, and gasoline
volatility. Thus, while refrigeration type systems would probably
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meet the proposed 35 mg/liter limit for most of the year, a limit of
55 mg/liter is more realistic and is achievable on a year-round basis
(IV-D-17).
Response: No data to support the recommended 55 mg/liter standard
were received from the commenter. EPA agrees that mass emission rates
from many types of processors may vary with operating and environmental
conditions. While CRA units have not shown the ability to consistently
achieve 35 mg/liter under any of the conditions at which they were
tested, REF units appear likely to achieve the limit under widely
variable conditions (see Section 2.6.5). The major manufacturer of
REF systems has stated that they can be specified and operated to
achieve the 35 mg/liter limit (Section 2.6.8). Test data show that
many of the most current REF unit installations are controlling emissions
below 35 mg/liter (Section 2.6.8).
Nonetheless, test data show that best demonstrated technology,
the basis for the standard of performance, consists of the carbon
adsorption and thermal oxidation technologies, which are currently
achieving the limit under the varying conditions mentioned by the
cominenter.
2.7.3 Efficiency Equivalent of Mass Standard
Comment: One commenter stated that an 80 mg/liter standard is
nearly equivalent to a 95 percent efficiency standard, particularly in
areas such as Southern California, where Stage I controls are in
effect. Thus, the statement on page 3-22 of BID, Volume I, that the
80 nig/liter and 90 percent efficiency standards can be considered
essentially equivalent, is not valid (IV-D-34).
Response: The efficiency which is equivalent to a particular
mass emission rate depends on the inlet mass loading to the vapor
processor. The inlet mass concentration is a variable quantity which
depends on such factors as atmospheric conditions, the type of loading
done at a terminal, and whether vapor balancing was performed prior to
loading the tank truck. In vapor balance (Stage I) service, the
Agency's estimated inlet loading of 960 mg/liter (II-A-9) would have
to be controlled at (960-80)/960 = 91.7 percent in order for an 80 mg/liter
standard to be met. The commenter's assumed control efficiency of
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95 percent presumes an inlet loading of 80/(1-0.95) = 1,600 mg/liter,
which is considerably higher than the values measured in tests. Since
all control processors were evaluated on their ability to maintain
outlet mass emissions within certain limits, the issue of control
efficiency is not relevant to this particular standard. The Agency's
rationale for selecting various emission factors is discussed in the
response to similar comments contained in Section 2.4.2.
2.8 TEST METHODS AND MONITORING
EPA has been investigating alternative ways of reducing monitoring,
recordkeeping, and reporting burdens on bulk terminal owners and
operators. The goal is to reduce all recordkeeping and reporting that
is not essential to ensuring the proper operation and maintenance of
the control system. After reviewing the requirements in the proposal,
EPA determined that monitoring and the compilation of monitoring data
are essential for both the owner or operator and EPA to ensure proper
operation and maintenance. The owner or operator of an affected
facility would need monitoring information compiled in a usable form
to determine when adjustments to the control system are needed to
ensure that it is performing at its intended effectiveness level. EPA
is therefore requiring only the additional step of filing the information
in an accessible location. Because EPA judges that monitoring and
recordkeeping are essential for proper operation and maintenance,
these requirements have not been changed since proposal. It was judged,
however, that reporting of terminal monitoring data is not essential
to EPA. Therefore, the reporting requirements have been removed since
proposal. In addition, when States are delegated the authority to
enforce these standards, they may prefer either not to have reporting
or to have reporting on a different schedule than EPA proposed. A
State, however, is free at any time to impose its own reporting
requirements in conjunction with this regulation.
At this time, no monitoring specifications have been developed to
meet the requirements of the proposed §60.504. To avoid confusion,
the monitoring requirements of §60.504 have been reserved and will be
reproposed along with performance specifications at a later date in
the Federal Register. Section 2.8.3 of this document has been included
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to respond, as much as possible at this time, to the comments received
concerning the continuous monitoring section.
2.8.1 Details of Test Methods
Comment: One commenter felt that the details of test instrument
calibration should not be specified in the test methods. A statement
requiring all instruments used in the test to be appropriate for the
intended use and calibrated according to applicable standards was
suggested (IV-D-23).
Response: The calibration requirements of the test methods are
the minimum required to assure accurate and precise data. As the data
from the tests will be used to determine compliance of the control
system, it is imperative that the test methods be completely definitive
and repeatable. The specific calibration and test procedures of the
methods for this regulation satisfy this need. As with all EPA methods,
alternative measurement systems and calibration procedures may be used
upon prior approval from the Administrator.
Comment: Two commenters addressed the calibration meters required
in Method 2A. One stated that spirometers or wet test meters of
sufficient size to calibrate large turbine meters are not readily
available (IV-F-1). The other asked whether the calibration requirement
of a spirometer or liquid displacement meter is consistent with the
expected meter capacity which will be required for the tests, and what
alternate references may be considered approvable by the Administrator
(IV-D-39).
Response: Turbine meters used in previous Agency tests reported
in the proposed standards were calibrated according to the procedures
specified in Method 2A. Since that time, larger volume control devices
have been installed or are in development that require much larger
volume measurement devices. The commenters are correct that spirometers
or other calibration meters of this capacity are not readily available.
As an alternative, the Agency has revised Method 2A to include wind
tunnel calibration against a standard pi tot as an acceptable procedure
for large volume gas meters.
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Comment: One commenter recommended that turbine meters not be
specified in the test methods for the measurement of the exhaust
volume from chilled brine and cascade refrigeration systems. Tests
have indicated discrepancies between measured and calculated volumes
due to icing problems and an increase in lubricating oil viscosity due
to very low stack exhaust temperatures (IV-D-17). Another commenter
inquired why the applicability of Method 2A was limited to the temperature
range of 0 to 50 degrees Celsius, and asked what alternatives were
available if the temperature during testing were below 0 degrees (C)
(IV-D-39).
Response: The applicable temperature range of Method 2A is
specified to avoid the freezing and viscosity variability problems
mentioned by the first commenter. If extremely low exhaust temperatures
are encountered, one acceptable alternative procedure is to extend the
stack or duct using duct material or hose so that the exhaust gas is
warmed by the ambient air to a more acceptable level. Agency tests
have shown the turbine meter to be applicable for measuring the exhaust
of refrigeration systems, provided the proper precautions discussed
above are taken toward preventing significant freezing or change in
meter calibration.
Comment: One commenter felt that alternative methods to Method 2A
should be allowed for measuring volume at the exhaust vent, since
there are existing systems that are not readily adaptable to Method 2A
measurements without substantial rework (IV-D-33).
Response: A total volume measurement method, as specified in
Method 2A, is necessary for these sources because of the highly variable
flow rates and the long test periods. The Agency is aware that some
control devices have been installed which have reverse flow in the
exhaust stack and/or large diameter stacks, both of which require
modifications to the measurement systems. To date, adding adapters to
existing exhaust stacks has proved satisfactory in allowing the use of
total flow meters for these sources. In particular, for a control
device with a larger diameter exhaust stack, the modification may
include use of a reducing flange or a manifold system with multiple
meters in parallel. For a control device with reverse flow in the
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exhaust stack, pressure-vacuum adapter valves and bypass plumbing may
be used. These temporary testing adapters are practical, do not
involve substantial rework, and have been used routinely in State
compliance testing programs.
Comment: One commenter questioned why the calibration gas for
test instruments was limited to propane or butane, and whether the
balance gas (air, synthetic air, or N2) made any difference in the
calibration standards (IV-D-39).
Response: Section 60.503(c)(2) specifies use of either propane
or butane as calibration gases as the carbon numbers for these gases
correspond to the carbon numbers found for most emission gases.
Additionally, these calibration gases are readily available, and
National Bureau of Standards calibration gases for certification
purposes are also available. The use of air or nitrogen as the balance
gas should have no significant effect on the calibration values.
Comment: The same commenter suggested changing the definition of
Calibration Drift in Section 2.5 of Method 25A to read:
"The difference in the measurement system response to a mid-level
value calibration gas before and after a stated period of operation
during which no unscheduled maintenance, repair or adjustment
took place" (IV-D-39).
Response: This change has been made to Method 25A to allow the
determination of drift in the same range as the measurement.
Comment: This commenter also requested the reason why the sample
probe sample hole size of 4 mm in diameter was specified in Section 3.2
of Method 25A (IV-D-39).
Response: Tests the Agency has conducted in the laboratory have
shown that sample hole diameters of 4 mm or smaller are required for
multihole rake-type probes to assure equal flows through all sample
holes. This applies for sample flow rates of about 1 liter per minute
or less, typically required for flame ionization detectors. Larger
sample hole sizes may be required to deliver greater sample volumes.
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Comment: Another commenter claimed that the statement in Section 4
of Method 25A, that the cylinder gas pressure for organic species is
limited by the critical pressure of the organic material, is incorrect.
Instead, the final pressure depends on the material 's vapor pressure
and its final concentration when pressurized. The same commenter
stated that the utilization of stainless steel cylinders for storage
of calibration gas mixtures, as referred to in the same section, is
unnecessary, and increases the cost of such gases to the end user
(IV-D-4).
Response: Revisions to Method 25A have been made to incorporate
both of these comments.
Comment: One commenter recommeded that the effects of nonisothermal
testing of tank trucks should be discussed in Section 4.3 of Method 27,
instead of stating that delivery tanks should be protected from direct
sunlight during testing. The following wording was suggested:
"Every effort should be made to ensure that the test is conducted
under isothermal conditions. The tanks should be allowed to
equilibrate in the test environment. Tanks should be protected
from extreme environmental variability, such as, direct sunlight."
This commenter further stated that, if the tank leaks, the pressure
would never stabilize after closing the shutoff valve (IV-D-39).
Another commenter recommended that the specification requiring
tank truck vapor tightness testing be limited to a performance speci-
fication to permit all acceptable methods. Alternatively, in addition
to the specific gas pressure methods, the commenter suggested that EPA
approve and publish the submitted water test method as an alternate
acceptable method. A detailed discussion and text of the water test
method were submitted with this comment (IV-D-23).
Response: The first commenter is correct in stating that the
purpose of protecting the tank from direct sunlight during testing is
to minimize the effects of changing temperature. Method 27 has been
revised to reflect this and to explain the importance of having stable
conditions inside the tank prior to and during testing.
The commenter is further correct in that, if a large leak exists,
the initial test pressure (in this case, 18 inches of water) cannot be
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maintained for more than an instant. However, if a small, slow leak
exists, the pressure does not decrease quickly. Instead, the pressure
nay vary around the 18-inch level due to unstable conditions in the
tank (as mentioned above), or due to lag time in the response of the
pressure measurement device. Thus, the pressure inside the tank may
require readjustment prior to testing in order to have a reliable
steady initial pressure.
The "water test method" submitted by the second commenter is
essentially equivalent to the procedure specified in Method 27.
Revisions to Method 27 have been made to incorporate this alternative.
Comment: .One commenter stated the concern that, due to a lag
time of several minutes in the response of measuring instruments, the
TOC concentrations recorded at the exhaust of the vapor processor
during testing could be matched to the inappropriate volume measurements
in the calculation of mass emissions (IV-F-1).
Response: A response time determination procedure has been added
to Methods 25A and 25B and the regulation has been revised to direct
the tester to correlate volume and concentration measurements accounting
for the response time.
Comment: This commenter also asked whether the assumption in
Section 1.1 of Method 2B, that the amount of auxiliary fuel used in
gasoline vapor incinerators is negligible, is consistent with test
data (IV-D-39).
Response: The auxiliary fuel for gasoline terminal incinerators
is used only to ignite the pilot burner; it is not needed to sustain
combustion of the gasoline vapors. At terminals tested by EPA, the
amount of auxiliary fuel for the pilot is indeed negligible when
compared to the large volumes of vapors processed. If there is a
question as to the validity of this assumption at a particular terminal,
one can refer to the terminal's records to compare the amount of
auxiliary fuel used over several months relative to the gasoline
throughput.
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2.8.2 Methods of Testing
Comment: One commenter stated that the proposed visual inspection
of the loading racks and vapor control system, means nothing with
regard to vapor leaks (IV-D-12).
Response: The purpose of the requirement for a monthly inspection
of the loading racks and vapor collection and processing systems is to
ensure that the benefits of the control system are not lost due to
large liquid or vapor leaks. While small vapor leaks may go undetected,
larger leaks can generally be detected through sight, sound, or smell
during an inspection. An inspection procedure involving the use of a
combustible gas detector was considered for this requirement, but
since the same results of finding and repairing large leaks could be
accomplished using a method of sight, sound, or smell, the instru-
mentation approach was not selected. A particular terminal operator
may decide to use improved methods to detect smaller leaks, and such
procedures are not discouraged by the Agency.
The word "visual" in the inspection requirement in §60.502(j) of
the regulation was deleted to clarify that the operator may use sight,
hearing, or other means to detect large leaks.
Comment: One commenter suggested that, in order to determine
whether a vapor recovery system was operating as guaranteed, EPA
should strive to set a test basis which would evaluate each system in
terms of its particular design criteria. The use of a vapor generator
was recommended to produce design conditions for testing (IV-D-36).
Response: While a test basis that would evaluate a control
system in terms of its particular design or guaranteed conditions may
be required when the use of a specific control system is indicated, it
is not appropriate in the case of a numerical emission limit, which
may be met by whatever control system the owner or operator of an
affected facility selects. Also, to implement the commenter's suggestion
would require detailed knowledge of each control system that could be
used to meet the standard. This would be impractical due to the
variety of control systems now manufactured for controlling VOC emissions
from bulk gasoline terminals and the continuing changes and improvements
-------
being made by the air pollution control vendors. Such a requirement
is also unnecessary since the test methods and procedures specified in
the regulation are adequate to be applied to any kind of control
system that could meet the standard. Additionally, as required by
§60.8(c) of the General Provisions, compliance with the numerical
emission limit is determined by a performance test conducted during
representative performance at the affected facility. The evaluation
of specific control systems in terms of their particular design conditions,
while not discouraged by the Agency, is left up to the individual
vendors and purchasers of the control systems.
Comment: The same commenter expressed support for the proposed
6-hour performance test period, as long as the test period represents
peak loading conditions. Since this commenter's carbon adsorption
control units are designed around a 4-hour peak loading profile, it
was felt that the 6-hour test performed during a period of peak loading
activity should be a valid indicator of system performance (IV-D-36).
Response: While the performance test may or may not represent
peak loading conditions, the test is to be run under conditions specified
by the Administrator based on representative performance of the affected
facility (40 CFR 60.8(c)). Additionally, to ensure that adequate data
are obtained to constitute a valid performance test, a minimum gasoline
throughput of 300,000 liters during the test is required in the regulation.
2.8.3 Continuous Monitoring
Comment: One commenter felt he saw a contradiction in two statements
in the preamble to the proposed regulation. One statement says that
extremely accurate measurements with monitors would not be required to
determine exact outlet emissions; the other says that the average
concentration or parameter value measured during the performance test
would become the limit for the quarterly reports of excess emissions.
The contradiction, according to the commenter, lies in basing excess
emissions reports on numbers which are not precise (IV-D-29, IV-F-1).
Response: The records of the continuous monitors, kept on file
at the terminal, should provide enforcement agencies with sufficient
means of ensuring that the control devices are properly maintained and
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operated on a continuous basis.
The intent of monitoring is to identify control equipment whose
operation and/or maintenance may be preventing the standard from being
achieved. Records of monitoring results are not used to determine
compliance with the numerical emission limit. According to 40 CFR 60.11(a),
compliance with the standards of performance is to be determined only
by performance tests, unless otherwise specified in the standard.
Therefore, since the concentration or parameter value would not be
used for a determination of compliance with the numerical emission
limit, it is not important that the value be precise. Such information,
however, can be used as an indicator of proper operation and maintenance
of the control system when compared with the value of the same parameter
obtained during the performance test.
EPA believes that changes in TOC concentration or parameters from
those measured during a performance test are good indicators for an
owner or operator to use to ensure good operation and maintenance and
for an enforcement agency to use to determine whether an owner or
operator is in violation of the §60.11(d) requirement to "maintain and
operate any affected facility including associated air pollution
control equipment in a manner consistent with good air pollution
control practice for minimizing emissions." Periods of excursions or
reductions of the measured value (depending on the control device) as
determined by the continuous monitors may also indicate to an enforcement
agency the need to conduct a performance test to determine compliance
with the numerical emission limit.
Comment: Four commenters felt that reports of excess emissions
should consist of periods when the numerical emission limit was actually
indicated to have been exceeded. Two of them felt that, instead of
the average value measured during the performance test, the VOC (now
TOC) concentration necessary to cause the standard to be exceeded
should be reported (IV-D-3, IV-D-20). Others agreed that such reports
should indicate violations of the standard, but opposed the application
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of continuous monitoring and excess emissions reports to bulk terminals
(IV-D-29, IV-D-32, IV-F-1). The fourth commenter pointed out that due
to the expected degradation of units in service, most operators would
be faced with the burden of filing excess emissions reports even on
units which are operating within the standard (IV-D-26).
Response: As pointed out in the preamble to the proposed regulation,
there are presently no demonstrated continuous monitoring systems
commercially available which monitor vapor processor exhaust TOC
emissions at bulk terminals in the units of the standard (mg/liter).
If continuous monitors which reliably record emissions in units of the
standard are developed, such monitors will likely be quite complex and
expensive. EPA is investigating simple, low-cost continuous monitors
which record exhaust TOC concentration and processor operating parameters
(such as temperature recorders). Thus, data recorded by the available
monitors do not permit a determination as to whether the numerical
standard has been exceeded. Also, as discussed above, continuous
monitoring records are not used to make determinations of compliance
with the emission limit.
Comment: One commenter felt that a fixed outlet VOC concentration
level could be set as a limit for the continuous monitor in REF systems,
based on curves of vapor processor control efficiency under various
inlet concentrations (IV-F-4).
Response: Since a format in terms of mass units (milligrams of
TOC emitted per liter of gasoline loaded into tank trucks) has been
selected, there is no single value of TOC concentration associated
with the numerical emission limit. The mass emissions are calculated
using both the TOC concentration and gas volume data collected during
a performance test. Various types of vapor processors, all operating
at the level of the standard, may exhaust different TOC concentrations.
For example, carbon adsorption and thermal oxidation units operating
at 35 mg/liter may emit lower concentrations than refrigeration units
meeting 35 mg/liter, because the introduction of outside air into CA
and TO systems increases the volumetric flow rate. Thus, the mass
standard in mg/liter is composed of a range of TOC concentrations,
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depending on the flow rates through various processors. If a TOC
concentration limit based on inlet concentration were set for REF
systems, then the inlet concentration would have to be known in order
to select the appropriate concentration limit. However, EPA testing
at bulk terminals indicates that the TOC concentration returned from
tank trucks is highly variable among regions, among terminals, and
even among individual trucks in the same type of service at a particular
terminal. Thus, it would be extremely difficult to assign a single
inlet concentration to a given REF unit in order to determine the
concentration limit for that processor.
Beyond the question of TOC concentration alone, however, several
commenters seemed to have difficulty with the idea of using the "average
value" of a measured parameter as the number of significance in determining
"excess emissions." EPA recognizes that any reported values in excess
of the average value recorded during a performance test do not necessarily
indicate violations of the standard. Several commenters pointed out
that normal equipment degradation over time may lead to a natural
shift in the monitored value. The plant owners and operators have the
option of repeating the performance test, thereby establishing a new
monitoring value, if they feel some change has occurred to the control
device and the numerical emission limit can still be met.
Comment: Several commenters questioned the advisability of
continuous monitoring, one of them suggesting the alternative of
frequent visual checks of operating parameters to determine proper
system operation (IV-D-31). Another felt that a "monitoring-by-people"
approach, supplemented by appropriate gauges and indicators, would
assure that performance parameters of a processing unit would be
observed and fine-tuned as necessary. This commenter took the position
that no single instrument or group thereof is an appropriate mechanism
for the requisite management of a vapor processing system (IV-E-19).
Two other commenters felt that existing gauges supplied on some vapor
processors should be considered for use as monitors of performance,
instead of add-on instruments (IV-E-19). Also, the calculation of
"average value" is extremely complex and beyond the capabilities of
regular terminal personnel (IV-D-26). One commenter was concerned
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about the availability of adequate monitors and about the criteria
used for monitor certification (IV-D-29), while a second commenter
said that the type of monitors referred to in the proposed regulation
have shown poor reliability in refinery applications in California
(IV-D-19). Two commenters argued that personnel qualified to properly
maintain monitors are not available at bulk terminals. The necessary
instrumentation would require constant calibration and maintenance,
and this would represent a significant manpower and cost burden,
without compensating benefit (IV-D-25, IV-F-1).
Response: Discussions concerning the availability, reliability,
complexity, maintenance, and cost of continuous monitoring systems are
inappropriate at this time because monitoring specifications have not
been finalized. EPA is investigating several types of monitors and
developing monitoring specifications that are appropriate for application
at bulk gasoline terminals. In selecting these specifications, EPA
will consider the reliability and usefulness of these monitors as well
as the cost and difficulty of maintaining them. After the specifications
have been selected, they will be proposed in a separate action in the
Federal Register for public comment. Section 60.504, Monitoring of
Operations, has been reserved at this time, so that monitoring requirements
and performance specifications can be added at a later date.
Continuous monitoring of the performance of bulk terminal vapor
processors is considered essential to help ensure that the standard is
being achieved on a continuous basis. Many of the alternate methods
suggested by commenters for accomplishing this end have a great deal
of merit as supplemental measures. Frequent visual checks are already
being performed at most controlled terminals (many of them record
operating parameters on daily logs), and this practice is encouraged.
However, such checks are generally performed only once per day, and
often at times when the processor does not happen to be operating,
such as when tank trucks are not loading. The parameters recorded may
not indicate system performance, for example, during peak loading
periods, when its performance is most critical. Therefore, visual
checks should be considered an important, but supplemental, means of
tracking a system's operation. The commenter suggesting a "monitoring-
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by-people" approach advocates a weekly checklist similar to the one
described above, and a subsequent comparison of parameter values with
the ranges suggested by the manufacturer (IV-E-12). Again, such
periodic checks would be useful in terns of proper maintenance of the
system, but may be too limited to provide sufficient information about
the system's likely emission level. Continuous monitoring instruments
cannot by themselves lead to the proper operation and management of a
vapor processor. However, data from several properly selected instruments
is believed to be the best means of monitoring processor performance
over a period of time. More detailed information, such as that collected
on checklists, should be used by the terminal in its maintenance
program.
EPA acknowledges that exhaust TOC concentration is only one of
several parameters of operation which influence the amount of TOC
emitted from a control device. Ideally, a terminal owner or operator
would monitor all parameters which influence emissions and then enter
values for these parameters into a formula in order to calculate emis-
sions. However, it would be burdensome for the owner or operator to
be required to collect this much data and perform such calculations on
a continuous basis. At a bulk terminal there are too many parameters
which are necessary to calculate mass emissions for continuous monitoring
of all of them (using simple, currently available monitors) to be
practical. Therefore, a form of monitoring which indicates whether
the control unit is being properly operated and maintained is considered
an effective means of minimizing emissions over an extended period.
EPA believes that in most cases the best way to demonstrate proper
operation and maintenance is to monitor only one parameter which
directly influences the actual emission rate from the processor.
As stated in the preamble to the proposed standards, it is possible
that monitoring systems included with a processor may be substituted
for an add-on system, with the approval of the Administrator. Many
processors currently being installed have parameter monitors which may
be suitable for this purpose. Some unit manufacturers are developing
more sophisticated monitoring packages for use with their equipment
(IV-D-36, IV-D-53).
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Comment: One commenter indicated that proposed Section 60.500(c),
which states that the provisions for monitoring of operations will not
apply until performance specifications are promulgated, makes it very
difficult (for a terminal owner or operator) to apply effective budget
and planning principles (IV-D-12). Several other commenters objected
to the inclusion of pending provisions for monitoring in the proposed
regulation. One recommended that such provisions not be included
until a system which would not be capital-intensive, operationally
complex, or require excessive maintenance has been developed (IV-E-19).
Response: By including the general requirements for monitoring
systems in the- standards at the time of proposal, the Agency intended
to make planning and budgeting more straightforward for owners and
operators. However, because the monitoring specifications are not
available at promulgation, the continuous monitoring section of the
standards has been reserved. The monitoring requirements and specifications
will be proposed in the Federal Register' at a later date and comments
will be requested at that time.
2.9 TANK TRUCK CONTROLS
Approximately 20 commenters objected to the mechanism for assuring
that loadings of gasoline tank trucks be restricted to vapor-tight
vehicles. These comments are summarized in the following sections.
2.9.1 Restricting Loadings to Vapor-Tight Trucks
Comment: Several commenters felt that the terminal owner or
operator should not have any responsibility for the vapor-tight status
of for-hire tank trucks. It was felt that the terminal operator
should not be required to police the testing and use of tank trucks
which are owned by others. A common carrier would be free to send an
unauthorized tank truck to an unattended terminal, without the knowledge
of the terminal operator, and the ensuing liability of the terminal
operator would be inappropriate (IV-D-1, IV-D-9, IV-D-10, IV-D-12,
IV-D-13, IV-D-20, IV-D-24, IV-D-26, IV-D-27, IV-D-28, IV-D-29, IV-D-30,
IV-D-32, IV-D-33, IV-D-37, IV-E-19, IV---1, IV-F-2, IV-F-3, IV-F-6).
Furthermore, several commenters felt that requiring the terminal
operator to restrict loadings to vapor-tight trucks would require
manning the terminal 24 hours per day. It was felt that this would
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impede the trend toward more efficient, automated terminals (IV-D-9,
IV-D-24, IV-D-25, IV-D-26, IV-D-27, IV-D-28, IV-D-32, IV-D-33, IV-D-35,
IV-D-41, IV-E-19).
Response: Fugitive VOC emissions from tank trucks which occur
during loading can be a significant emission source. It is estimated
that on the average, nonvapor-tight tanks lose an average of 30 percent
of the potential vapor transferred, through leaks in dome covers and
pressure-vacuum vents. By requiring the tanks which handle gasoline
to pass an annual vapor tightness test, the average vapor loss due to
leakage during the year between tests can be reduced to about 10 percent
of the potential vapors transferred (II-I-69). Oil industry represen-
tatives also have agreed that fugitive losses from tank trucks can be
a significant problem and should be controlled (IV-E-19, IV-F-3).
Fugitive VOC losses from tank trucks not only increase the pollution
problem but decrease the amount of liquid that can be recovered in
vapor recovery equipment. The terminal owner or operator could lose
as much as $2 in recovered product per loading into nonvapor-tight
trucks. For a small 380,000 liter/day (100,000 gallon/day) terminal
this could represent a daily loss of over $25. For a large 3,800,000 liter/
day (1,000,000 gallon/day) terminal the losses could be over $250/day.
To reflect the best demonstrated technology in controlling tank
truck leakage, the standards require that the loading of product into
gasoline tank trucks be into vapor-tight tanks only. A vapor-tight
tank is defined as one that has passed a vapor tightness test within
the preceding year. EPA Method 27 outlines the annual vapor tightness
test. This test would reduce average fugitive VOC losses from tank
trucks by 67 percent (from 30 percent to 10 percent average vapor
loss).
The objections from the terminal industry arise concerning the
responsibility for assuring loadings are into vapor-tight tanks. The
industry feels the responsibility should be on the tank truck operator
instead of the terminal operator. However, for the responsibility
under NSPS to be on the tank truck operator, the tank truck would have
to be part of the affected facility. As discussed in BID, Volume I
and the preamble to the proposed standards, the feasibility of including
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the tank truck in the affected facility was reviewed. The first case
considered both the tank truck and the terminal as separate affected
facilities under the standards. This would lead to difficulties
associated with enforcing two standards governing a single polluting
operation. For example, provisions would have to be made for the
problem of NSPS applicability when an existing tank was loaded at a
new terminal. The second case considered the truck tank and the
terminal as a single affected facility under one standard. Again, it
would be unreasonable to attempt to regulate a hybrid and changeable
affected facility that would exist only during a loading operation and
would frequently have more than one owner. It was felt, therefore,
that the best approach to controlling fugitive tank truck leakage was
by applying NSPS controls only to bulk terminals, and permitting
NSPS-covered terminals to load only into truck-mounted tanks that have
passed a vapor tightness test. Since tank trucks load primarily with
equipment owned by the terminal owner, and on the property of the
terminal owner, EPA believes it is reasonable to presume for the
purpose of this regulation that these owners can exercise sufficient
control over the source to justify making them responsible for the
emissions therefrom.
As stated in the preamble to the proposed regulation, it was not
intended that terminal personnel should man the racks 24 hours per
day, or observe the loading of every tank truck to verify that each
truck had passed an annual vapor tightness test. EPA felt that requiring
documentation on file that gasoline tank trucks operating out of the
terminal had passed a vapor tightness test would provide a sufficient
means of promoting loadings into vapor-tight tanks. Industry opposition
is centered around the liability placed on the terminal owner for
trucks he does not own. At unmanned, automated terminals, the terminal
operator is usually not present and cannot determine which trucks are
loading. EPA realizes these limitations but believes that the vapor
tightness requirement is necessary for the standards to be effective.
Changes to the vapor tightness requirement have been incorporated
into the promulgated regulation to clarify that the standards do not
require the terminal operator to man the racks on a 24-hour basis. At
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terminals, even automated computer-billed terminals, some hard copy
manifest is given to the driver of a for-hire tank truck to verify the
date and the type and amount of product loaded. The driver keeps this
copy for his own records and often a copy is returned to the terminal
to cross-check the computer billing. In several cases it has been
observed that the truck or tank identification number is logged on
this hard copy manifest (IV-B-6). These records are used for billing
purposes and would allow the terminal owner to identify the truck
driver if he desired to do so in the future. The Agency has incor-
porated into the final regulation a requirement that the terminal
owner obtain the tank identification number of all gasoline tank
trucks operating at affected facilities. The owner is further required
to periodically cross-check the tank identification with the vapor
tightness documentation on file at the terminal. This cross-checking
is required within 2 weeks of the loading. Since the identification
numbers would be supplied to the terminal by the tank truck company,
and the tank truck company would be identified on the billing manifest
at the time of loading, cross-checking of identification numbers
should be rapid and should not represent an excessive burden on the
terminal operator.
If the terminal discovers that an unauthorized tank truck has
received gasoline, the terminal operator is required to notify the
tank owner, indicating that only vapor-tight trucks may load gasoline
at the NSPS-covered terminal. This notification would have to be
documented and kept on file at the terminal. The terminal operator
would then have to take steps to assure that the unauthorized tank
truck does not reload at the terminal until the required vapor tight-
ness documentation had been provided. Methods available to the terminal
owner or operator for achieving this could include revocation of
loading privileges, or contractual agreements between the terminal
owner or operator and the truck owner or operator. However, the
regulation does not specify any particular methods, to allow the
terminal owner or operator the flexibility to meet the requirements
with minimum disruption to the terminal operations. As specified in
Section lll(h)(3) of the Clean Air Act, the regulation provides that
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if the terminal owner, after notice and opportunity for public hearing,
"establishes to the satisfaction of the Administrator that an alterna-
tive means of emission limitation will achieve a reduction in emissions ...
at least equivalent to the reduction in emissions of such air pollutant"
achieved under these vapor-tight tank truck requirements, the Administrator
"shall permit the use of such alternatives ...." Thus, the terminal
owner is free, with EPA approval under Section lll(h)(3), to develop a
different strategy for controlling such fugitive emissions.
Comment: Two commenters stated that access cards at automated
terminals are not issued for a specific vehicle, so that loadings of
particular delivery tanks could not be monitored (IV-D-24, IV-D-29,
IV-E-19).
Response: EPA realizes that the access cards at these terminals
are not issued by vehicle, but are issued by company and by driver.
However, the method for limiting loadings to vapor-tight trucks does
not require on-the-spot monitoring or lock-out by the computer access
equipment. All that is required is that the terminal operator obtain
the tank identification number of each truck loading at the facility
on a particular day. Cross-checking against the vapor tightness data
on file could be done at a time more convenient to the terminal operator.
2.9.2 Suggested Alternatives
Several commenters suggested alternatives to the section of the
regulation dealing with tank trucks, either in the wording of the
regulation or an alternate approach. These alternatives are discussed
in this section.
Comment: One commenter felt that the owner of an affected facility
should be required to "clearly advise" tank truck operators of the
requirements, with actual responsibility for compliance on the operators
of the trucks (IV-D-1).
Response: EPA agrees that as a terminal becomes affected by the
regulation, the owner or operator of the facility should notify those
tank truck firms that operate out of that facility of the requirements
for vapor recovery equipment and vapor tightness. The terminal owner
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or operator would have to notify tank truck owners in order to comply
with the requirement under §60.502(e)(l) to obtain vapor tightness
documentation. Therefore, a separate requirement for terminal owners
to advise truck operators of the terminal's equipment and operational
requirements is not considered necessary. Operators of the trucks
cannot be made responsible for compliance, since the tank truck is not
part of the affected facility. Truck operators will, however, have to
install the proper equipment and have their trucks tested for vapor
tightness, in order to load at any affected terminal. Reasons for not
including the tank truck in the affected facility were discussed in
Section 2.9.1.
Comment: Another commenter suggested a system of vehicle inspection
stickers to enforce the vapor tightness provisions (IV-F-1, IV-F-2).
Response: It is possible that the use of stickers may expedite
the day-to-day, spot checking of tanks for vapor tightness, as shown
in the system used in California. However, since this type of checking
may impose an unreasonable burden on the terminal operator, and is
impractical at unattended terminal operations, it has not been made a
part of the regulation. EPA feels that the system of obtaining tank
identification numbers and cross-checking against vapor tightness
documentation will accomplish the objective of limiting tank truck
fugitive VOC emissions during loading.
Comment: Another commenter felt that it was reasonable to require
the owner or operator to request written documentation of vapor tightness,
but that he should not be held responsible for the completeness or
accuracy of the documentation (IV-F-1, IV-F-3).
Response: The intent of keeping the vapor tightness documentation
on file at the terminal is not to require the terminal operator to
observe the tests or verify the test results for those trucks he does
not own. In the regulation, §60.505(b) describes the minimum information
that the terminal operator should accept as documentation that a tank
truck has passed the vapor tightness test.
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Comment: One conmenter suggested revisions to proposed Sections 60.502(d),
(e), and (f) of the regulation, which would require the terminal owner
or operator to "implement a program designed to" restrict loadings to
vapor-tight tank trucks with compatible vapor recovery equipment, and
require connection of the truck's and the terminal's collection systems
during each loading (IV-D-10).
Response: Allowing the terminal operator to simply "implement a
program" to restrict loadings to vapor-tight trucks would require that
the Administrator review all programs on a case-by-case basis to
determine adequacy. Under this approach, no guidelines for an accept-
able program would be available to the owner or operator. Changes
made to the regulation represent a program which is reasonable, but
which still allows the terminal to use any method which EPA judges
equivalent under the terms of Section lll(h)(3), as described in
Section 2.9.1 of this document. This will permit flexibility in com-
plying with these requirements while reducing the case-by-case determinations
necessary by the Administrator.
Comment: One commenter stated that the independent tank truck
operator would be restricted in his business because his access to
regulated terminals would be limited, and he could not operate at
various terminals because they would not have vapor tightness docu-
mentation for his tank trucks on file at the terminal. The commenter
proposed as an alternate scheme that tank truck operators carry the
documentation and be responsible for connecting vapor collection
equipment during loading. Terminal operators would only have to train
drivers in the hookup procedures (IV-D-9).
Response: Having the tank truck operator carry the documentation
as the only means of vapor tightness verification would require the
terminal operator to review the information before each loading. This
would be impossible at unmanned automated terminals, and such a require-
ment would be a burden on both the terminal and truck operators. At
most terminals, the truck driver performs all the loadings at the
racks and is responsible for performing these operations within the
operating rules of the terminal, with terminal operators training
drivers in the loading procedures.
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Tank truck owners can alleviate any possible restriction on the
number of terminals at which their trucks may load by sending documen-
tation to all affected terminals at which their trucks might conceivably
load in the coming year. For manned terminals, this documentation
could be provided at the initial loading at each individual terminal.
This one-time filing of information would be much more practical than
having to present documentation at each loading.
Comment: Another commenter felt that the regulation should make
clear that a terminal owner or operator would not be required to test
for-hire tank trucks for compliance, nor to keep documentation on such
trucks at the terminal. He suggested the following revised Section 60.505(a)
"The owner or operator of each bulk gasoline terminal, prior
to loading gasoline into a tank truck, shall request the
tank truck driver to provide a certificate indicating the
tank truck meets all EPA requirements and testing to qualify
as a vapor-tight gasoline tank truck" (IV-D-13).
Response: As indicated in the response to the previous comment,
a requirement for the tank truck driver to present vapor tightness
documentation before each loading would necessitate that the terminal
be manned at all times. This would not be feasible at the state-of-the-
art automated terminals. By requiring that the driver record the tank
I.D. number at the time of loading, the terminal operator can verify
the vapor-tight truck loadings at a time when the terminal office is
manned. As currently phrased, the regulation makes clear that the
terminal operator is not required to test trucks for compliance, but
only to keep documentation on file, record tank truck identification
numbers, cross-check identification numbers, and make the specified
notifications (§§60.502(e) and 60.505(a)).
Comment: One commenter felt that an extensive file would have to
be checked to verify each tank truck's status before each product
loading. A suggested alternate approach is to require the owner of
each fleet or truck which may use an affected terminal to file an
annual certification that all trucks used have been proved vapor-tight,
with this file being maintained only at the central office which
controls each terminal complex (IV-D-23).
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Response: The intent of the proposed regulation was not to
require that the data file be checked prior to each loading. The
final regulation requires the vapor tightness documentation to be
obtained from the truck owner or operator and to be kept on file at
the terminal. It is possible that in some cases a terminal operator
may be permitted to keep the documentation file at a location other
than the affected terminal, especially in the case of unmanned terminals.
This file will be checked against the tank identification numbers
recorded for tank truck loadings within a time limit of 2 weeks. The
commenter's alternative would be impractical, since the terminal owner
would be unable to verify whether only the vapor-tight trucks operated
by a particular firm are loading at the affected facility.
Comment: One commenter offered the suggestion that State regulations
would be the best vehicle for enforcement of tank vapor tightness, and
stated that enforcement penalties on truck operators in California
lead to an effective system in that State (IV-F-1, IV-F-3). Two
commenters felt that in areas with no SIP coverage, the controls on
tank trucks would not be effective, because of the variety of schedules
and equipment in those areas. Both agreed that many truck drivers
might be inclined to circumvent the requirements if there were no
direct penalties, and that SIP regulation would be a more effective
means of control than NSPS (IV-F-1).
Response: Section 111 requires that NSPS reflect application of
best demonstrated technology for new, modified, and reconstructed
terminals in both attainment and nonattainment areas. The Agency has
determined that the CTG vapor tightness requirements reflect application
of such technology to tank trucks. Therefore, this NSPS extends the
CTG level of control to affected facilities in attainment areas that
may not be controlled by the States, thereby ensuring control to
minimum national levels at all new, modified, and reconstructed facilities,
The various schedules of tank truck deliveries in nonSIP areas should
not affect the effectiveness of vapor tightness controls in these
areas. Once a tank truck owner had installed vapor collection equipment
and tested a tank truck for vapor tightness, he would be free to
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follow any delivery schedule compatible with local business patterns
with no disruption resulting from the standards. The tank truck's
equipment would have to be compatible with the terminal's, as in all
instances, so that loading and vapor recovery could be accomplished.
Such equipment requirements are not unusual, and would be similar to
the requirements on tank trucks loading at terminals in SIP-controlled
areas.
As stated before, since the tank truck is not part of the affected
facility, the regulation can directly apply only to the terminal. EPA
believes that adherence to the logging and notification method of
compliance specified in the regulation will reduce the level of gasoline
loadings into nonvapor-tight trucks.
Comment: One commenter proposed an alternative to the tank vapor
tightness program, in which a fan would be installed in the vapor
collection system to draw air-vapor mixture out of the tank trucks
during product loading. This would make tank vapor tightness unnecessary,
because large positive pressures, causing leakage, would not be created
in the tank (IV-C-9, IV-F-1).
Response: EPA did not select the commenter's proposed alternative
to the tank truck vapor tightness requirement since no system of this
type has been installed or demonstrated at a commercial bulk gasoline
terminal.
Comment: Another commenter suggested an alternative which would
require that the owner or operator of the terminal maintain files
documenting gasoline tank trucks that are authorized to load at that
facility, and that gasoline tank truck owners or operators not load
unauthorized or incompatibly equipped gasoline tank trucks at the
facility. The documentation file could include a contractual requirement
that the gasoline tank truck owner would not present for loading any
unauthorized or incompatible units. Violations of the contract could
subject the owner to revocation of the provisions of the contract,
such as loss of loading privileges for his gasoline fleet (IV-D-24,
IV-D-41).
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Response: EPA does not choose to specify requirements for or
restrict any contractual agreement between the tank truck operator and
the terminal operator. However, enforcement of contractual provisions
between the terminal and tank truck operators may be an effective
method of assuring that the terminal operator obtains the correct tank
truck identification numbers and prevents a nonvapor-tight truck from
loading a second time. Also, contract enforcement may form part of a
compliance strategy different from that specified in the standards.
As discussed in Section 2.9.1 above, terminal owners may use methods
of compliance different from that specified by EPA if, after notice
and opportunity for public hearing, the Administrator determines that
the alternative method would result in emission reduction at least
equivalent to that resulting from adherence to the compliance method
specified in the regulation. The Administrator must review and determine
the equivalency of any alternative approaches on a case-by-case basis,
in accordance with Section lll(h)(3) of the Clean Air Act.
2.9.3 Administrative Burden
Comment: One commenter felt that an administrative burden would
be created by a requirement to keep vapor tightness documentation for
as many as 400 to 500 transport trucks using a given terminal (IV-F-1,
IV-F-2). Several other commenters generally argued that the tank
truck controls would represent an administrative burden, as well as
being costly and inequitable (IV-D-12, IV-D-27, IV-E-19).
Response: The testing and maintenance of tank trucks for vapor
tightness has been shown to have a significant effect in reducing
total emissions during loading (Section 2.9.1). Thus, this procedure
has a very important function in bulk terminal VOC emissions limitation.
The administrative burden of keeping the documentation on file would
be minimal since the information would in most cases be supplied by
the owner of for-hire tank trucks and the terminal would simply file
the data. As discussed in Section 2.9.1, cross-checking these files
with tank identification numbers logged during loading should be a
simple process and should not represent an excessive burden.
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2.9.4 Tank Truck Population Impacted By The Standard
Comment: One commenter said that the total population of tank
semi-trailers in gasoline service had been seriously underestimated in
BID, Volume I, and hence the economic impact of controls on the tank
truck industry had not been fully considered. He further stated that
for-hire or common carriers cannot dedicate particular tank trucks to
particular terminals so that regulatory coverage of a terminal could
impact all common carriers in the same area (IV-F-4, IV-F-6).
Response: The economic impact on the for-hire tank truck industry
is performed on an individual firm basis rather than a nationwide
basis. Only tank trucks in attainment areas will be impacted by the
standards since the tank truck requirements are identical to SIP
requirements being implemented in nonattainment areas. Since the
standards affect only about 7 percent of all terminals in attainment
areas, it seems very unlikely that all tank trucks in attainment areas
would be affected. Or, looking at it in another way, it seems unlikely
that, if a trucking firm operated out of 100 terminals, it would
convert all trucks to the NSPS requirements if only 7 of these terminals
became affected facilities. However, for purposes of the economic
impact analysis to determine if these individual trucking firms could
afford the NSPS requirements, the following assumptions were made:
(1) for trucking firms in the smallest two firm sizes (operating
2 tank vehicles and 7 tank vehicles, respectively), it was assumed
that all tank vehicles would be converted to meet the NSPS requirements,
and (2) for trucking firms in the two largest firm sizes (operating
30 tank vehicles and 100 tank vehicles, respectively), it was assumed
that 50 percent of the tank vehicles would be converted to meet the
NSPS requirements. EPA believes these assumptions are realistic in
determining the worst case economic impact on each model firm. As
discussed in Section 8.4.2 of BID, Volume I, the economic analysis
using these worst case assumptions showed a small impact on the for-hire
tank truck industry.
Many attempts have been made by several organizations to estimate
the total national tank truck population. An analysis by the Tank
Trailer Manufacturer Association (TTMA) in 1979 concluded that there
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are about 80,000 liquid petroleum tank trailers in service. The
analysis indicated that government and industry estimates at that time
ranged from 70,000 to 132,000. The estimate of 100,000 tank vehicles
in flammable liquid service made in Section 8.1.3.2 of BID, Volume I
is still considered a reasonable figure, in light of the unavailability
of exact population data. The estimate of 85,000 gasoline tank vehicles
taken from an EPA survey is considered conservative, considering the
variety of petroleum products which are not normally transported in
gasoline tank trucks. The commenter does not explain his contention
that "it is safe to assume that virtually every one of those (petroleum
service) trailers finds its way into gasoline service at one time or
another." EPA does not agree with this assumption.
As stated in the Arthur D. Little (ADL) report (II-A-47), tank
wagons (at bulk plants) usually have tank capacities between 2,000 and
4,000 gallons, whereas transports (at bulk terminals) usually have
capacities between 8,000 and 9,000 gallons. Bureau of the Census data
were used to estimate the percentage of liquid tank vehicles having a
capacity greater than 4,000 gallons (15,140 liters). This percentage
was found to be 31 percent, indicating that there are approximately
26,300 gasoline tank trucks in operation at bulk terminals. This is
consistent with the ADL statement that, in 1978, there were an estimated
29,200 gasoline tank trailers in operation at bulk terminals. The
45,000 semi-trailers which the commenter says are operated by National
Oil Jobbers Council (NOJC) members transport all petroleum products
between all marketing distribution points.
The percentage of the 26,300 bulk terminal tank trucks which will
require conversion to bottom loading or vapor recovery as a result of
the standards can only be estimated roughly. The tank trucks in
nonattainment areas, approximately 72 percent of the total, or 18,900,
are expected to be regulated under SIP's. This leaves about 7,400 tank
trucks potentially eligible for retrofit under the standards (in
attainment areas). The percentage of affected existing facilities in
these areas by 1986 is expected to be 7.1 percent, so that approximately
525 tank trucks will be affected in the first 5 years. Assuming the
number of terminal-owned tank trucks at each model plant as shown in
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Table 6-2 of BID, Volume I, the remaining number of for-hire trucks
would be 370, or 70 percent of the total. This is consistent with the
ADL statement that most gasoline transports are owned by common carriers
and not by terminal operators. Thus, the total number of for-hire
gasoline tank trucks operating at bulk terminals can be estimated to
be 70 percent of 26,300, or 18,400, and the number of affected for-hire
trucks would be about 2 percent of this total.
While many more tank trucks are likely to be retrofitted for
bottom loading during the first 5 years, these conversions will be
performed for reasons of safety, modernization, and fleet utilization
flexibility. In addition, State vapor recovery regulations in most
areas will tend to encourage bottom-loaded, vapor recovery-equipped
tank trucks to become the industry standard.
2.9.5 Economic Burden
Comment: One commenter felt that the impact on oil jobbers, who
would be indirectly affected because loadings of gasoline tank trucks
would be restricted to those which had passed an annual vapor tightness
test, would be minimal. The commenter also stated that the costs
associated with this test would not be excessive (IV-D-8).
Response: EPA has examined the costs of the vapor tightness test
and found them to be reasonable. The analyses in Section 2.5 and
Appendix B support this comment.
Comment: One commenter pointed out that tank trucks would require
adapters in order to load at several terminals having different vapor
recovery systems. In this situation the independent for-hire truck
operator could not be competitive with trucking companies operating
with larger fleets of trucks. This commenter also assumed that any
gasoline tank truck loading at an affected facility would deliver only
to those service stations or bulk plants with vapor control systems.
The commenter questioned what the requirements on tank trucks would be
for those which loaded alternately between affected and unaffected
facilities. This commenter further questioned whether tank trucks
would be required to install overfill protection. It was suggested
that further studies on the for-hire motor carriers be initiated,
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which should include additional data obtained from State associations
and their members, and should verify the accuracy of 1977 data relative
to today's market situation (IV-D-11).
Response: An economic analysis was performed for each model tank
truck firm size and the results were presented in BID, Volume I. The
analysis indicated only a minor economic impact on the smaller independent
for-hire truck firms. The regulation will apply only to the loading
of gasoline tank trucks at new, modified, or reconstructed bulk gasoline
terminals. The NSPS does not apply to tank truck unloading or loading
operations at bulk plants or unloading operations at service stations,
nor do the standards specifically require overfill protection. However,
the tank truck operator would have to comply, as at any terminal, with
the loading requirements of that individual terminal. If a terminal
requires overfill protection, as most bottom-loading terminals do,
then the tank truck operator would have to install overfill protection
in order to load at that terminal.
Since independent trucking firms are able to operate in SIP-controlled
areas where the same types of adapters would be required for loading
and vapor recovery systems, EPA does not feel that the requirement for
adapters is an excessive burden on the independent tank truck operator.
Since the independent typically operates out of several terminals with
a variety of equipment and procedures, the need for several adapters
should not be unusually burdensome for these truck owners. Oil company
representatives have informed EPA that common carriers do not require
a large assortment of adapters to load product, because such equipment
is manufactured according to the specifications of the American Petroleum
Institute (API) (IV-E-19, VI-J-21).
As stated in previous responses, the control of fugitive leakage
emissions from tank trucks is very important to achieving meaningful
reductions in bulk terminal overall emissions. A typical leaking
truck may lose 30 percent of its displaced vapors through worn or
defective equipment, or 288 mg/liter in fugitive losses. This amounts
to over eight times the emissions from a state-of-the-art vapor processor.
Considering the importance of controlling these emissions, EPA believes
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it is reasonable to set standards that effectively require independent
tank truck owners that typically service a variety of terminals to
load only into vapor-tight trucks at NSPS-covered facilities.
Additional data gathering and consideration of costs to the
for-hire tank truck industry have been undertaken since proposal. The
cost and economic impacts are discussed in Sections 2.5.5 and 2.5.6,
and in Sections B.2.2 and B.3 of Appendix B.
2.10 LEGAL CONSIDERATIONS
2.10.1 Tank Trucks Not Stationary Sources
Comment: Several commenters questioned EPA's legal authority to
impose restrictions, i.e., retrofitting and vapor tightness testing,
on gasoline tank trucks. Two of the commenters felt that, since tank
trucks do not fall within the definition of a "stationary" source,
they may not be regulated under Section 111 (IV-D-20, IV-D-35, IV-F-4,
IV-F-6). One comtnenter expressed the opinion that tank trucks are
neither "major" nor "stationary" sources, and that the proposed controls
on tank trucks constitute ultra vires requirements. These requirements
were characterized as "arbitrary and capricious," and said to constitute
"the taking of private property without cause, compensation, or due
process" (IV-D-33). Another commenter stated that the proposed standard
usurps State regulatory functions by imposing an extra layer of Federal
regulation on top of effective State rules, and by "artificially"
treating tank trucks as stationary sources subject to the standards
(IV-D-26).
One commenter stated that EPA has no authority to promulgate NSPS
which control emissions from mobile sources directly or indirectly.
He does feel, however, that it is reasonable to require a terminal
owner or operator to request written vapor tightness verification from
tank truck operators (IV-F-1, IV-F-3). Another commenter stated that
EPA has no authority to directly regulate tank trucks under Section 111,
and EPA cannot do indirectly what it cannot do directly (citing Brown v. EPA,
566 F.2d 665 (9th Cir. 1977)) (IV-D-35).
Response: For purposes of this NSPS, the stationary source, or
affected facility, is the total of all bulk terminal loading racks
loading liquid product into gasoline tank trucks. Those loading racks
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are essential to carrying out the activity known as product loading.
While product loading involves both the affected facility and mobile
equipment, including the tank truck, it is clearly a stationary activity,
since it requires no movement from the affected facility site. Among
the pollutants created by product loading are vapors forced from the
tank truck as a direct result of the pumping of liquid product into
the tank truck. Since escape of these vapors is caused by stationary
activities at a stationary facility, they are "stationary source"
emissions subject to regulation under Section 111 -- even though the
tank trucks from which they escape during that activity have the
capability to move.
As indicated above, the tank truck is not included in the designation
of the "affected facility" under these standards. The standards place
responsibility on the terminal owner only, requiring the owner to
restrict loadings to vapor-tight tank trucks equipped with compatible
vapor collection equipment. The regulation would not directly require
either new or old tank trucks to be vapor-tight or equipped with
certain types of hardware. (See next comment and response.)
Section lll(a)(2) defines "stationary source" as any "building,
structure, facility, or installation which emits or may emit any air
pollutant." EPA identifies the "stationary source" as certain specified
stationary equipment (termed the "affected facility") that "emits" a
pollutant. In the Administrator's view, stationary equipment "emits"
a pollutant if it causes that pollutant to enter the atmosphere.
EPA's authority to define the term "emits" in this way derives from
Section 301 of the Act, as interpreted in the cases fi-ee, e.g., Alabama Power
v. Costle, 636 F.2d 323 (D.C. Cir. 1979)). In accordance with this provision,
the Agency is interpreting the term "emits" broadly, to serve the
broad purposes of Section 111 (described in the text below).
In the Administrator's view, affected facility emissions subject
to regulation under Section 111 include all pollutants that enter the
atmosphere as a result of the stationary industrial activities at the
affected facility, even those that enter the atmosphere after contacting
equipment with mobility. Stated differently, the test for whether
emissions are "stationary source" emissions subject to regulation
under Section 111 is whether the emissions are caused by a stationary
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facility during activities that require no movement from the facility,
not whether the emissions escape to the atmosphere without touching
equipment having the capability to move.
Interpreting "stationary source" emissions to include emissions
resulting from stationary activities in which both the affected facility
and some mobile equipment take part serves the intent of the statute.
Congress enacted Section 111 for the "overriding purpose" of "preventing]
new pollution problems." S. Rep. No. 91-1196, 1970 J_eg_. Hist, at 416.
The Senate Report states that Section 111 seeks to attain this goal by
requiring control of new commercial and industrial establishments "to
the maximum practicable degree regardless of their ... industrial
operations." Id. Similarly, the Report states that "maximum use of
available means of preventing and controlling air pollution is essential"
to the attainment of the goals of Section 111. Id. The legislative
history thus indicates that Congress intended Section 111 to address
emissions from all stationary operations at industrial establishments
when the Agency can identify the maximum practicable degree of control
for these emissions. To interpret Section lll(a)(2) so that emissions
resulting from certain stationary activities involving the stationary
source would not constitute "stationary source" emissions simply
because those emissions pass through some equipment with the capability
to move would be incompatible with that intent.
The Ninth Circuit Court of Appeals case cited by the commenter
casts no doubt on EPA's authority to regulate these vapors as emissions
from the loading rack. That case stands for the proposition that
under the Clean Air Act, as amended in 1977, a State highway is not an
"indirect source" of pollution simply by virtue of the State's failure
to adopt an inspection and maintenance program to control pollutants
emitted by automobiles that travel on those highways. The decision
turns primarily on the legislative history of Section 110. The Court
in no way implied that when pollutants escape as a direct result of a
stationary activity at an industrial unit, those pollutants are not
"stationary source" emissions within the intent of Section 111.
The Agency recognizes that promulgation of standards regulating
loading racks as "stationary sources" may significantly affect tank
truck owners and other segments of the Petroleum Transportation and
Marketing industry. That standards within an agency's statutory
authority indirectly affect nonregulated entities, however, does not
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in itself diminish the authority to set the standards. Nothing in the
statute or its history indicates that, in the case at hand, the indirect
impact of loading rack standards on certain tank truck owners deprives
the Agency of its clear authority to set these new source performance
standards. Nor does the case cited by the commenter suggest that
otherwise valid regulation of "stationary sources" is rendered invalid
simply because the regulation indirectly affects other segments of the
industry involved.
In fact, it is likely that most NSPS's based in whole or in part
on process changes affect industries other than that to which the
standards directly apply. The standards for electric utility steam
generators (40 CFR 60.40a-49a), for instance, significantly affect
several other industries. Those standards are based on a combination
of scrubbing and coal washing. For this reason, they will affect
vitally the coal-washing and scrubbing industries. Similarly, the
NSPS's for different coating application industries (e.g., the metal
furniture industry), based typically on use of low-solvent coatings,
will undoubtedly affect manufacturers of low-solvent coatings, high-
solvent coatings, and coating application equipment.
The impact on tank trucks of a requirement that certain bulk
terminals load only into vapor-tight trucks equipped with compatible
equipment does not differ in kind from the indirect impacts resulting
from these other new source performance standards. Bulk terminals
deal extensively with delivery vehicles. As a result, it is to be
expected that regulation of bulk terminals would affect delivery
vehicles in some manner, particularly in connection with the most
significant activity at bulk terminals — product loading. It was not
Congress's intent that because of this effect EPA may not set bulk
terminal emission standards otherwise authorized by Section 111.
Nor does the potential effect on tank truck owners amount to a
denial of due process or an unconstitutional taking of property.
Because the commenter did not elaborate on the specific bases for
these claims of unconstitutionality, the Agency can respond only
generally. The Clean Air Act reflects a congressional determination
that air pollution has a substantial effect on interstate commerce and
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therefore may be regulated by Congress (and, through proper delegation,
EPA) under the commerce clause. District of Columbia v. Train, 521 F.2d
971, 980 (D.C. Cir. 1975). It is unreasonable to suggest that regulation
of emissions forced from the tank truck during loading bears no rational
relationship to protection of public health and welfare, and thus
violates the due process clause of the Fifth Amendment. There is a
rational relationship between escape of these vapors and the public
health and welfare, because these emissions contribute to ozone formation.
Sierra Club v. EPA, 540 F.2d 1114, 1139 (D.C. Cir. 1976). There is
also a proper legislative purpose underlying the requirements aimed at
controlling these emissions. Moreover, the means the Agency has
chosen, as discussed above, are reasonable and appropriate. Id., at
1139 n.80 (citing Heart of Atlanta Motel, Inc. v. United States,
379 U.S. 241, 258-59 (1964)).
Nor do these standards transgress the takings prohibition in the
Constitution. Given the substantial public interest in preserving
clean air, tight restrictions may constitutionally be imposed on
private property. South Terminal Corp. v. EPA. 504 F.2d 646, 678-80
(1st Cir. 1974). While this NSPS indirectly limits the uses of tank
trucks, the limitation is not so extreme as to constitute an appro-
priation of the vehicles. Sierra Club v. EPA, supra, at 1140. This
regulation affects only one of the tank truck uses available to the
truck owner — loading at affected facilities. The right to use
nonvapor-tight tank trucks at other facilities is neither extinguished
nor transferred to someone else.
2.10.2 Loading Restrictions by Terminal Operators
Comment: One commenter claimed that EPA does not have the authority
to confer upon terminals the police power of a government to inspect,
control, regulate, and certify the equipment (tank trucks) owned by
other private commercial corporations and taxpayers, or to require
terminals to undertake and perform the tasks and responsibilities of
EPA. A terminal operator could be subject to lawsuits by tank truck
operators if the proposed restrictions on tank truck loadings were
carried out (I-V-D-13).
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Response: In requiring terminal owners to restrict loading at
affected facilities to vapor-tight trucks with compatible vapor collection
equipment, EPA is not attempting to confer government police power on
terminal owners. Rather, the Agency is requiring terminal owners to
exercise control over loading activities conducted at their facilities.
These requirements are based on the assumption that because loading is
carried out with equipment largely owned by the terminal owners, with
the owners' permission and on their property, it is reasonable to
charge these owners with responsibility for the emissions that result
from loading.
Thus, in accordance with Section 111, EPA is requiring terminal
owners to take certain steps to assure that VOC emissions from activities
reasonably considered to be under the owners' control are reduced to
the level reflecting application of the best system of continuous
emission reduction. Nothing in the statute indicates that EPA lacks
authority to establish such standards that may effectively require
owners to exercise some control over the activities of persons using
the owners' facilities.
As described earlier in Section 2.9.1, the promulgated regulation
specifies a method of compliance that would permit terminal owners to
meet the standards without manning the affected racks on a 24-hour
basis. The revised compliance requirements will limit the owner's
responsibility under the promulgated standards.
The Agency cannot determine how the promulgated requirements will
result in lawsuits by tank truck operators against terminal owners.
The commenter did not provide an explanation and the Agency is not
aware of the basis for the commenter's suggestion. Therefore, EPA
does not at this time consider it appropriate to speculate about the
legal problems that might arise between terminal and tank truck owners.
2.10.3 Setting of an Operational Standard
Comment: One commenter stated that the requirements on terminal
owners and operators to control the access of gasoline tank trucks is
a "work practice" or "operational" standard, which may be promulgated
only instead of standards of performance, according to Section lll(b)(l)
arid (2) of the Clean Air Act. Since a standard of performance has
been set, the operational standard is inappropriate (IV-D-35).
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Response: Under Section 111, the standards EPA sets must reflect
application of the best demonstrated technological system of continuous
emission reduction to the affected facility. The Agency has determined
that the best demonstrated system for controlling VOC emitted during
tank truck loading is the combination of the following actions: restricting
loading to vapor-tight tank trucks; collecting the vapors that can be
captured by installing a vapor collection system and connecting the
system during loading; and controlling emissions from the vapor collection
system with an adsorber, an oxidizer, or some other acceptable system.
The Agency has determined that even after applying this system at
loading racks, it is both technologically and economically impracticable
to measure total organic compound emissions from the loading process
for the purpose of comparing the amount of emissions to a numerical
emission limit. This is because residual fugitive (leakage) emissions
from vapor-tight trucks still escape directly to the atmosphere and
are not captured by the vapor collection system. Section lll(h)
permits EPA to set work practice and equipment standards "instead of"
a standard of performance for those sources for which it would not be
feasible to prescribe and enforce a standard of performance. The
statute states that prescribing such a standard is not feasible where
the measurement is technologically or economically impracticable.
Accordingly, the Agency is including in this regulation a work practice
standard ained at controlling emissions from leaks and similar emission
sources during loading. This would require that loading be restricted
to vapor-tight trucks.
Complementing this requirement are additional equipment and
operational requirements assuring the effectiveness of the vapor
tightness standards. Specifically, these requirements seek to minimize
the chance that those vapors not able to escape through leaks in the
vapor-tight tank are emitted through a number of other potential
escape routes in the loading system. These standards require that:
(1) each loading rack be equipped with a vapor collection system
designed to collect the vapors displaced from the tank truck during
loading; (2) gasoline loadings into tank trucks be limited to those
equipped with compatible vapor collection equipment; (3) the racks'
2-113
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vapor collection system be designed to prevent any vapors collected at
one loading rack from passing to another loading rack; (4) the two
vapor collection systems be connected during each loading of a gasoline
tank truck; (5) the vapor collection and liquid loading equipment be
designed and operated to prevent excess gauge pressure during loading;
(6) the terminal's vapor collection system be designed so that no
pressure-vacuum vent begins to open below the specified cutoff pressure;
and (7) the collection and loading equipment be inspected for leaks at
certain times during loading.
The primary result of these steps is that most vapors will become
centralized in the terminal's vapor collection system. Only from this
source is it technologically and economically practicable to measure
TOC emissions.. The Agency has established a standard of performance
for vapors collected by the vapor collection system because it is
feasible to prescribe and enforce such a standard for these emissions.
In sum, the Agency is setting equipment and work practice standards
"instead of" a standard of performance to control those fugitive emis-
sions for which measurement is impracticable. EPA is establishing a
standard of performance for those emissions for which measurement is
practicable. This action accords with the language of Section lll(h)
and Congress's intent that, where feasible, the Agency establish
emission limitations.
2.10.4 Setting of an Equipment Standard
Comment: One commenter felt that, since it is not desirable to
burn collected vapors, the carbon adsorption system was being proposed
as the only control technology to achieve the standard. This was said
to constitute an equipment standard which is contrary to the requirements
of Section lll(h) (IV-D-31).
Response: Section 111 requires EPA to set standards achievable
through application of the best demonstrated technology. Even if the
statutory factors pointed to selection of only one technology as the
best demonstrated technology for controlling the vapors collected by
the vapor collection system, the emission limit based on that technology
would not constitute a standard requiring the use of particular equipment
(for which a Section lll(h) finding would be necessary). Rather, a
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standard based on the use of one technology would still permit source
owners to use any system of continuous emission reduction capable of
meeting the limit; e.g., one that may not have been demonstrated for
use by the entire industry, but which is demonstrated for use at a
particular type of source. Furthermore, owners are free under the
standard of performance to apply for technology waivers under Section lll(j)
to obtain EPA approval to use certain innovative technologies to meet
the numerical 1imit.
In any event, the Agency has determined that for this industry,
two technologies—oxidation and carbon adsorption—are the best demon-
strated technology. While in some cases a source owner may prefer not
to use oxidation, in the Agency's judgment both technologies are
adequately demonstrated, considering adverse impacts.
2-115
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2.11 REFERENCES
I-2b U.S. Environmental Protection Agency. Priority list and
additions to the list of categories of stationary sources,
final rule. Washington, D.C. Office of the Federal Register.
August 21, 1979.
II-A-4 Amoco Oil Company. Demonstration of Reduced Hydrocarbon
Emissions from Gasoline Loading Terminals. U.S. Environmental
Protection Agency. Publication No. EPA-650/2-75-042. June
1975. 51 p.
II-A-5 Betz Environmental Engineers, Incorporated. Emissions from
Gasoline Transfer Operations at Exxon Company, USA, Baytown
Terminal, Baytown, Texas. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. EMB Report. No. 75-GAS-8.
September 1975. 75 p.
II-A-6 Betz Environmental Engineers, Incorporated. Emissions from
Gasoline Transfer Operations at Exxon Company, USA, Philadelphia
Terminal, Philadelphia, Pennsylvania. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. EMB Report
No. 75-GAS-10. September 1975. 91 p.
II-A-9 Compilation of Air Pollution Emission Factors, Transportation
and Marketing of Petroleum Liqu-ids. U.S. Environmental
Protection Agency. Publication No. AP-42. February 1976.
II-A-10 Betz Environmental Engineers, Incorporated. Gasoline Vapor
Recovery Efficiency Testing at Bulk Transfer Terminals
Performed at Diamond Shamrock, Incorporated, Terminal, Denver,
Colorado. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Contract No. 68-02-1407, Task 12.
Project No. 76-GAS-16. September 1976. 98 p.
II-A-11 Betz Environmental Engineers, Incorporated. Gasoline Vapor
Recovery Efficiency Testing at Bulk Transfer Terminals Performed
at Pasco-Denver Products Terminal. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Contract
No. 68-02-1407. Project No. 76-GAS-17. September 1976.
97 p.
II-A-14 Betz Environmental Engineers, Incorporated. Gasoline Vapor
Recovery Efficiency Testing at Bulk Transfer Terminals
Performed at the Texaco Terminal, Westville, New Jersey.
U.S. Environmental Protection Agency. Research Triangle
Park, N.C. EMB Report No. 77-GAS-18. November 1976. 87 p.
These numbers correspond to the docket item number in Docket No. A-79-52.
2-116
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II-A-17 Scott Environmental Technology, Incorporated. Gasoline
Vapor Recovery Efficiency Testing Performed at the Phillips
Fuel Company Bulk Loading Terminal, Hackensack, New Jersey.
U.S. Environmental Protection Agency. Research Triangle
Park, N.C. EMB Report No. 77-GAS-19. October 1977. 47 p.
II-A-18 Polglase, W., et al. Control of Hydrocarbons from Tank
Truck Gasoline Loading Terminals. U.S. Environmental Protection
Agency. Publication No. EPA-450/2-77-026. October 1977.
II-A-23 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at the Amoco Terminal, Baltimore,
Maryland. U.S. Environmental Protection Agency. Philadelphia,
Pennsylvania. Contract No. 68-01-4145, Task 12. September
1978. 133 p.
II-A-24 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at Belvoir Terminal, Newington,
Virginia. U.S. Environmental Protection Agency. Philadelphia,
Pennsylvania. Contract No. 68-01-4145. September 1978.
105 p.
II-A-25 The Research Corporation of New England. Report on Performance
of Vapor Control System at Boron Terminal, Coraopolis,
Pennsylvania. U.S. Environmental Protection Agency.
Philadelphia, Pennsylvania. Contract No. 68-01-4145, Task
12. September 1978. 104 p.
II-A-26 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at British Petroleum Terminal,
Finksburg, Maryland. U.S. Environmental Protection Agency.
Philadelphia, Pennsylvania. Contract No. 68-01-4145, Task 12.
September 1978. 69 p.
II-A-27 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at the Combined Citgo, Gulf,
Texaco, and Amoco Terminals, Fairfax, Virginia. U.S.
Environmental Protection Agency. Philadelphia, Pennsylvania.
Contract No. 68-01-4145, Task 12. September 1978. 117 p.
II-A-28 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at Crown Central Terminal,
Baltimore, Maryland. U.S. Environmental Protection Agency.
Philadelphia, Pennsylvania. Contract No. 68-01-4145, Task
12. September 1978. 125 p.
II-A-29 The Research Corporation of New England. Report on Performance
Test of Vapor Control System at Texaco Terminal, Coraopolis,
Pennsylvania. U.S. Environmental Protection Agency.
Philadelphia, Pennsylvania. Contract No. 68-01-4145, Task 12.
September 1978. 80 p.
2-117
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II-A-32 Shedd, S.A., et al. Control of VOC Leaks from Gasoline Tank
Trucks and Vapor Collection Systems. U.S. Environmental
Protection Agency. Publication No. EPA-450/2-78-051.
December 1978.
II-A-37 The Research Corporation of New England. Report on Performance
Test of HydroTech Carbon Bed Vapor Control System at Phillips
Fuel Oil Terminal, Hackensack, New Jersey. U.S. Environmental
Protection Agency. New York, N.Y. Contract No. 68-01-4145,
Task 12. April 1979. 215 p.
II-A-38 The Research Corporation of New England. Report on Performance
Test of Parker Hannifin, CRA Vapor Control System at Mobil
Terminal, Paulsboro, New Jersey. U.S. Environmental Protection
Agency. New York, N.Y. Contract No. 68-01-4145, Task 36.
April 1979. 212 p.
II-A-39 The Research Corporation of New England. Report on Performance
of Gesco, CRC Vapor Control System at Sunoco Terminal,
Newark, New Jersey. U.S. Environmental Protection Agency.
New York, N.Y. Contract No. 68-01-4145, Task 36. April
1979. 141 p.
II-A-40 The Research Corporation of New England. Report on Performance
Test of Tenney Refrigeration Vapor Control System at Amerada
Hess Terminal, Pennsauken, New-Jersey. U.S. Environmental
Protection Agency. New York, N.Y. Contract No. 68-01-4145,
Task 36. April 1979. 175 p.
II-A-41 The Research Corporation of New England. Report on Performance
Test of Tenney Refrigeration Vapor Control Systems at Exxon
Terminal, Paulsboro, New Jersey. U.S. Environmental Protection
Agency. New York, N.Y. Contract No. 68-01-4145, Task 36.
April 1979. 185 p.
II-A-42 The Research Corporation of New England. Report of Performance
Test of Trico-Superior CRA Vapor Control System at ARCO
Terminal, Woodbury, New Jersey. U.S. Environmental Protection
Agency. New York, N.Y. Contract No. 68-01-4145, Task 36.
April 1979. 231 p.
II-A-43 The Research Corporation of New England. Report on Performance
Test of Edwards Refrigeration Vapor Control System at Tenneco
Terminal, Newark, New Jersey. U.S. Environmental Protection
Agency. New York, N.Y. Contract No. 68-01-4145, Task 36.
April 1979. 171 p.
II-A-47 McCarthy, R.J. Economic Impact of Vapor Control Regulations
on Bulk Storage Industry. Arthur D. Little, Inc. Publication
No. EPA-450/5-80-001. June 1979.
2-118
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II-A-50 Scott Environmental Technology, Inc. Gasoline Vapor and
Benzene Control Efficiency of Chevron Loading Terminal,
Perth Amboy, New Jersey. U.S. Environmental Protection
Agency. Research Triangle Park, N.C. EMB No. 78-BEZ-5.
May 1970. 166 p.
II-B-46 Memorandum from Polglase, W., Environmental Protection
Agency (CPDD), to Helms, G.T., Environmental Protection
Agency (CPDD). September 19, 1979. Summary of SIP VOC
regulations.
II-B-54 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to Aminoil terminal in Stockton,
Cal iform'a.
II-B-55 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to Union Oil terminal in Los
Angeles, California.
II-B-56 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to Aminoil terminal in West
Sacramento, California.
II-B-57 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to Shell Oil terminal in Los
Angeles, California.
II-B-58 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to SOHIO terminal in Cuyahoga
Heights and Niles, Ohio.
II-B-59 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to STC Corporation in Stockton,
California.
II-B-61 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
August 22, 1980. Trip report to ARCO terminal in Stockton,
California.
II-D-41 Letter and attachment from McGill, G., HydroTech Engineering,
Inc., to Shedd, S., Environmental Protection Agency. July 6,
1977. Comments on EPA test of carbon adsorption unit.
2-119
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II-D-84 Letter from McGill, J.C., HydroTech Engineering, to Kleeberg,
C.F., Environmental Protection Agency. November 3, 1978.
Comments on carbon adsorption units and carbon life.
II-D-118 Letter and attachments from McLaughlin, W.F., Husky Oil
Company, to Goodwin, D.R., Environmental Protection Agency.
June 5, 1979. Response to Section 114 letter on terminals.
II-D-121 Letter and attachments from Crane, R.E., Triangle Refineries,
Incorporated, to Goodwin, D.R., Environmental Protection Agency.
June 18, 1979. Response to Section 114 letter on terminals.
II-D-122 Letter and attachments from McGirr, J.J., F.L. Roberts and
Company, to Goodwin, D.R., Environmental Protection Agency.
June 21, 1979. Response to Section 114 letter on terminals.
II-D-124 Letter and attachments from Woodard, D.E., Standard Oil Company
(Ind.), to Goodwin, D.R., Environmental Protection Agency.
June'25, 1979. Response to Section 114 letter on terminals.
II-D-125 Same as Docket Item No. II-D-124 (Confidential information).
II-D-127 Letter and attachments from Karkalik, K.J., Standard Oil of
Ohio, to Goodwin, D.R., Environmental Protection Agency.
July 5, 1979. Response to Section 114 letter on terminals.
II-D-128 Letter and attachments from Bond, F.K., ARCO Petroleum
Products, to Goodwin, D.R., Environmental Protection Agency.
July 6, 1979. Response to Section 114 letter on terminals.
II-D-129 Same as Docket Item No. II-D-128 (Confidential information).
II-D-130 Letter and attachments from Hooper, L.R., Marathon Oil
Company, to Goodwin, D.R., Environmental Protection Agency.
July 13, 1979. Response to Section 114 letter on terminals.
II-D-131 Letter and attachments from Martin, D.P., Gulf Oil Company,
to Goodwin, D.R., Environmental Protection Agency. July 24,
1979. Response to Section 114 letter on terminals.
II-D-132 Letter and attachments from Beall, F.J., Texaco, Incorporated,
to Goodwin, D.R., Environmental Protection Agency. July 30,
1979. Response to Section 114 letter on terminals.
II-D-133 Same as Docket Item No. II-D-132 (Confidential information).
II-D-134 Letter and attachments from Weber, G.H., Chevron U.S.A.,
Incorporated, to Goodwin, D.R., Environmental Protection
Agency. August 9, 1979. Response to Section 114 letter
on terminals.
2-120
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II-D-135 Letter and attachments from Richardson, O.K., Mobil Oil
Company, to Goodwin, D.R., Environmental Protection Agency.
August 14, 1979. Response to Section 114 letter on terminals.
II-D-136 Letter and attachments from Sparveri, A.J., Automatic Comfort,
Corporation, to Goodwin, D.R., Environmental Protection Agency.
August 16, 1979. Response to Section 114 letter on terninals.
II-D-137 Same as Docket Item No. II-D-136 (Confidential information).
II-D-138 Letter and attachments from Ada, A.E., Exxon Corporation, to
Goodwin, D.R., Environmental Protection Agency. September 5,
1979. Response to Section 114 letter on terminals.
II-D-149 Letter and attachments from Perry, F.R., California Air
Resources Board, to Farmer, J.R., Environmental Protection
Agency. November 30, 1979. Comments on draft BID Volume I
and four test reports.
II-E-34 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Pitruzello, V., EPA Region II, February 6,
1979. Information on new terminal development in Region II.
II-E-35 Telecon. Collins, F., EPA Region IV, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 6,
1979. Information on new terminals in Florida.
II-E-36 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Ikalainen, B., EPA Region I, February 6,
1979. Information on new terminals in Region I.
II-E-37 Telecon. Thayil, B., EPA Region V, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 7,
1979. Information on new terminals in Region V.
II-E-38 Telecon. Sydmore, J., EPA Region III, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 9,
1979. Information on new terminals in Region III.
II-E-41 Telecon. Davidson, I.W., Getty Oil, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 12,
1979. Information on new terminal construction.
II-E-42 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Yee, D., EPA Region IX, February 12,
1979. Information on new terminals in Region IX.
II-E-43 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Potter, G., Exxon Company, U.S.A.
February 12, 1979. Information on new terminal construction.
2-121
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II-E-44 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Hooper, M., EPA Region X. February 14,
1979. Information on new terminals in Region X.
II-E-46 Telecon. Wright, G., EPA Region VII, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 15,
1979. Information on new terminals in Region VII.
II-E-47 Telecon. Perry, A.W., Union Oil Company, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 15,
1979. Information on new terminal construction.
II-E-48 Telecon. Wheeler, D., EPA Region VII, with Norton, R.L.,
Pacific Environmental Services, Incorporated. February 20,
1979. Information on new terminals in Region VII.
II-E-49 Telecon. Dougherty, C., Texaco, Incorporated, with Norton,
R.L., Pacific Environmental Services, Incorporated. March 1,
1979. Information on new terminal construction.
II-E-51 Teleconl Norton, R.L., Pacific Environmental Services,
Incorporated, with Ruffing, J., Allegheny County BAPC.
April 2, 1979. Information on new terminals in Allegheny
County.
II-E-68 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Bolsted, J., Montana Air Quality Board.
June 7, 1979. Information on method of loading at uncontrolled
terminals.
II-E-69 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Anderson, A., Georgia Department of
Natural Resources. June 7, 1979. Information on SIP coverage
of terminals in Georgia.
II-E-74 Telecon. Edwards, R.C., Edwards Engineering, with LaFlam,
G.A., Pacific Environmental Services, Incorporated. July 2,
1979. Information on costs and performance of refrigeration
units.
II-E-75 Telecon. Schmidt, E., Edwards Engineering, with LaFlam,
G.A., Pacific Environmental Services, Incorporated. July 3,
1979. Information on costs of carbon adsorption units.
II-E-79 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Welpe, B., Hunn Corporation. July 11,
1979. Cost information on installation of vapor control
systems.
II-E-85 Telecon. Edwards, R., Edwards Engineering, with LaFlam,
G.A., Pacific Environmental Services, Incorporated. August 21,
1979. Information on capabilities of refrigeration units.
2-122
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II-E-93 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Malek, B., Petrochem Cons., Incorporated.
October 16, 1979. Provided corrections to Section 114
letter.
II-E-94 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Maxwell, S., HydroTech Engineering.
October 18, 1979. Information on costs of carbon adsorption
add-on units.
II-E-99 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Schmidt, E., HydroTech Engineering.
November 7, 1979. Information on costs of carbon
replacement for carbon adsorption systems.
II-E-126 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Beall, F.J., Texaco, Incorporated.
January 18, 1980. Information on use of open splash loading.
II-E-127 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Percy, A.W., Union Oil Company. January 18,
1980. Information on use of open splash loading.
II-I-69 Norton, R.L. Monitoring Procedures for Fugitive Hydrocarbon
Emissions from Gasoline Tank Truck Loading. Paper at APCA
73rd meeting, Montreal, Quebec. June 22, 1980.
IV-A-2 Battye, W., et al. Control of Hydrocarbon Emissions from
Gasoline Loading by Refrigeration Systems. U.S. Environmental
Protection Agency. Publication No. EPA-600/7-81-121.
July 1981.
IV-B-2 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
March 23, 1981. Trip report of March 9, 1981, meeting with
Bay Area Air Quality Management District regarding Edwards
refrigeration source test.
IV-B-4 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
March 23, 1981. Trip report to ARCO terminal for monitoring
testing.
IV-B-6 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Docket A-79-52. April 28, 1981. Trip
reports to BP, Texaco, and AMOCO terminals.
IV-C-9 Letter and attachments from LaFlam, G.A., Pacific Environmental
Services, Incorporated, to Smith, W.S., Entropy Environmentalists,
February 19, 1981. Summary of meeting held February 9,
1981, regarding vapor recovery at bulk terminals.
2-123
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IV-D-15 Letter from Bierck, R.C., Dean Brothers Pumps, Incorporated,
to Shedd, S.A., Environmental Protection Agency. February 18,
1981. Information on pump performance.
IV-D-47 Letter and attachments from McDaniel, R.R., Southern Pacific
Pipe Lines, to LaFlam, G.A., Pacific Environmental Services,
Incorporated. April 2, 1981. Information on operating data
for vapor recovery units.
IV-D-48 Letter and attachments from Bossi, F.R., Calgon Corporation,
to LaFlam, G.A., Pacific Environmental Services, Incorporated.
April 8, 1981. Information on various control technologies.
IV-D-49 Letter and attachments from Kaitschuck, J., John Zink Company,
to LaFlam, G.A., Pacific Environmental Services, Incorporated.
April 15, 1981. Information on carbon adsorption unit.
IV-D-51 Letter and attachments from Schmidt, E.L., McGill, Incorporated,
to Norton, R.L., Pacific Environmental Services, Incorporated.
April 30, 1981. Information on prices and power consumption
for vapor processors.
IV-D-54 Letter and attachments from Surla, E., Indiana State Board
of Health, to Gschwandtner, K.C., Pacific Environmental
Services, Incorporated. March 30, 1981. Performance and
compliance test results.
IV-D-55 Letter and attachments from St. Louis, R., Pennsylvania
Department of Environmental Resources, to Gschwandtner,
K.C., Pacific Environmental Services, Incorporated. May 27,
1981. Performance and compliance test results.
IV-D-56 Letter and attachments from Weinberg, B.D., Ohio Environmental
Protection Agency, to Gschwandtner, K.C., Pacific Environmental
Services, Incorporated. June 4, 1981. Performance and
compliance test results.
IV-D-57 Letter and attachments from St. Louis, R., Pennsylvania
Department of Environmental Resources, to Gschwandtner,
K.C., Pacific Environmental Services, Incorporated. June 12,
1981. Performance and compliance test results.
IV-E-3 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Edwards, R., Edwards Engineering Corporation.
February 23, 1981. Information on refrigeration units.
IV-E-10 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Bierck, R., Dean Brothers Pumps, Incorporated,
March 4, 1981. Information on Dean Brothers pumps.
2-124
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IV-E-11 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Perry, F.R., California Air Resources
Board. March 6, 1981. Information on bottom loading vapor
balance emission factor.
IV-E-12 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, to Stoddard, B., Shell Oil Company. March 18,
1981. Clarification of Shell comment on recommended control
unit monitoring program.
IV-E-18 Telecon. Bossi, F.R., Calgon Corporation, with LaFlam,
G.A., Pacific Environmental Services, Incorporated.
April 3, 1981. Information on overheating of carbon adsorption
units.
IV-E-20 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Kaitschuck, J., John Zink Company.
April 14, 1981. Information on carbon adsorption units.
IV-E-22 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Todd, J., Heil Company. April 14, 1981.
Information on tank truck conversion costs.
IV-E-23 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Mr. Glidden, Tennile Company. April 15,
1981. Information on tank truck conversion costs.
IV-E-24 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Hemphill, R., Fruehauf Corporation.
April 20, 1981. Information on tank truck conversion costs.
IV-E-25 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Botkin, L., Fruehauf Corporation.
April 20, 1981. Information on tank truck conversion costs.
IV-E-26 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Ritterbush, J., J & L Tanks. April 20,
1981. Information on tank truck conversion costs.
IV-E-29 Telecon. Zanitsch, R., Calgon Corporation, with LaFlam,
G.A., Pacific Environmental Services, Incorporated. April
22, 1981. Information on carbon adsorption units.
IV-E-30 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with McGill, J., McGill, Incorporated. April
23, 1981. Information on carbon adsorption units.
IV-E-32 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Edwards, R., Edwards Engineering Company.
April 28, 1981. Information on refrigeration units.
IV-E-33 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Welpe, B., Hunn Corporation. April 29,
1981. Information on cost of loading rack conversions.
2-125
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IV-E-36 Telecon. Schmidt, E., McGill, Incorporated, with Norton,
R.L., Pacific Environmental Services, Incorporated.
April 30, 1981. Information on carbon adsorption units.
IV-E-38 Telecon. Lowery, E., ARCO, with LaFlam, G.A., Pacific
Environmental Services, Incorporated. May 5, 1981. Information
on maintenance and electrical costs of Edwards DE Model
refrigeration unit.
IV-E-39 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Ottoson, R.S., Ray Construction Company,
Incorporated. May 6, 1981. Information on design and costs
associated with loading rack conversions.
IV-E-40 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Ogden, J., Union Oil Company. May 7,
1981. Information on maintenance costs of carbon adsorption
units.
IV-E-41 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Stahl, R., AMOCO Oil Company. May 7,
1981. Information on maintenance costs of carbon adsorption
units.
IV-E-42 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Dale, A., Phillips Petroleum Company.
May 8, 1981. Information on operating and maintenance costs
of carbon adsorption units.
IV-E-43 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Durbin, R., AMOCO Research. May 11,
1981. Information on sight glasses installed on carbon
adsorption units.
IV-E-45 Telecon. Deardorff, K., JACA Corporation, with Moorehead,
A., Federal Energy Regulatory Commission. May 19, 1981.
Information on price pass through for pipelines.
IV-E-46 Telecon. Deardorff, K., JACA Corporation, with Sado, J.,
Interstate Commerce Commission. May 19, 1981. Information
on price pass through for independent tank truckers.
IV-E-52 Telecon. Lorden, J., Phillips Petroleum Company, with LaFlam,
G., Pacific Environmental Services, Incorporated. September 22,
1981. Cost-effectiveness of SIP controls at bulk terminals.
IV-E-53 Telecon. Durbin, R., AMOCO Research, with LaFlam, G.,
Pacific Environmental Services, Incorporated. September 28,
1981. Field experience and technical problems with carbon
adsorption units.
IV-E-54 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with Jones, K., California Air Resources
Board. November 5, 1981. Discussion of bulk terminal
tests.
2-126
-------
IV-J-1 California Air Resources Board. Certification Evaluation
Report No. C-9-021 of Edwards Vapor Recovery Unit. May 1979.
IV-J-2 California Air Resources Board. Certification Evaluation
Report No. C-9-072 of McGill Vapor Recovery Unit. May 1980.
IV-J-3 California Air Resources Board. Certification Evaluation
Report No. C-9-073 of McGill Vapor Recovery Unit. May 1980.
IV-J-4 California Air Resources Board. Certification Evaluation
Report No. C-80-034 of Edwards Vapor Recovery Unit. June
1980.
IV-J-5 California Air Resources Board. Certification Evaluation
Report No. C-9-058 of Hirt Vapor Recovery Unit. August
1980.
IV-J-6 California Air Resources Board (CARB) proceedings on vapor
recovery consultation meeting. March 17, 1978. CARB staff
report on public hearing to revise suggested vapor recovery
rules. July 27, 1978.
IV-J-8 Edwards Engineering Corporation. Hydrocarbon vapor recovery
units price list. January 1, 1981.
IV-J-10 Marketplace at a Glance. National Petroleum News. 73(4).
April 1981.
IV-J-15 API Bulletin on Evaporation Loss from Tank Cars, Tank Trucks,
and Marine Vessels. American Petroleum Institute. API
Bulletin 2514. November 1959.
IV-J-16 California Air Resources Board. Certification Evaluation
Report No. C-80-047 of McGill Vapor Recovery Unit. June 1980.
IV-J-17 LaFlam, G.A., Osbourn, S., and Norton, R.L. Documentation
for AP-42 Emission Factors: Section 4.4 Transportation
and Marketing of Petroleum Liquids. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. May 1982.
IV-J-21 Bottom Loading and Vapor Recovery for MC-306 Tank Motor
Vehicles. American Petroleum Institute. API RP 1004.
September 1, 1977.
2-127
-------
APPENDIX A
EMISSION SOURCE TEST DATA
A-l
-------
APPENDIX A - EMISSION SOURCE TEST DATA
A.I INTRODUCTION
A major group of the comments received after proposal of the
standards questioned the adequacy of the emission test data which
served as the basis for the selected emission limit of 35 milligrams
of TOC per liter of gasoline loaded. Commenters claimed that: state-of-
the-art control equipment was not represented in the testing (Section 2.6.1);
the systems selected as best available technology have not been adequately
demonstrated (Section 2.6.3); certain technologies show marginal
performance or have operating problems which make them unsuitable
choices (Sections 2.6.7, 2.6.8, and 2.6.10); and additional test data
should be collected (Section 2.6.6).
Although the test data presented at the time of proposal are
considered adequate to support the selected limit, the Agency has
continued to collect results of recent testing in order to obtain the
largest possible data base. The intent was to review these recent
tests of the current generation of vapor processors in order to verify
their performance under a broader range of operating conditions.
Additional test data on the carbon adsorption, refrigeration, and
thermal oxidation type systems were obtained from State pollution
control agencies, oil companies, and a control unit manufacturer.
Section A.2 presents these data and discusses the results in terms of
the 35 mg/liter emission limit.
A.2 SUMMARY OF ADDITIONAL TEST ACTIVITY
Results of tests performed between 1979 and 1981 to demonstrate
compliance with SIP requirements are presented in Table A-l. These
test results were not available to EPA until after Appendix C of BID,
A-2
-------
Table A-l. BULK TERMINAL EMISSION TEST DATA SUMMARY
Test
ID No.
1
la
~\
i.
3
4
5
6
71
31
91
10
11
12
13
14
15
16
17
18
19
20
21
22i
23
24
25
26
271
23
29
30
31
32
33
34
35
36
37
38
39
Test
Date
6/6/79
9/21/79
4/29-30/80"1
5/21-22/80"1
7/8/80
7/9/80
7/10/80
7/80
8/80
9/80
9/16/80
9/17/80
9/17/80
9/22/80
9/26/80
9/29/80
10/1/80
10/1/80
10/2/80
10/3/80
10/6/80
10/10/80
10/80
11/12/80
11/13/80
11/14/80
12/9/80
1/6/81
1/8/81
2/2/81
2/6/81
2/11/81
1/22/81
2/04/81
5/29-30/80m
3/26/81
2/19-20/811"
5/13-14/80m
12/16/80
1/20/81
Control
Unit3
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
REF
REF
REF
T0k
' TO
TO
Volume
Loaded .
(liters)0
100.5506
n
701,650s
2,469,900s
421, 5009
439, 2009
375, ISO9
h
h
h
243,200e
132.5006
194,100e
124,800s
488,200s
1,223,200s
387,700s
223,600s
367,150s
728,150s
834,850s
63,900s
h
172,200s
265,350s
174,900s
202,500s
443,200e
165,800s
102,950s
184,700s
136, 6509
613,000s
306,950s
784,550s
1,006,000s
1,288,200s
2,353,700s
205,200s
162, 5509
Inlet
CC
41. 7f
h
h
h
h
3.3
3.0
14.0
5.7
6.3
23.6
20.1
11.1
6.74
8.37
4.86
6.63
h
h
6.22
5.93
8.0
6.4
h
h
h
h
h
19.2
27.7
22.8
20.0
19.7
30.2
h
h
h
h
h
h
Outlet
Cc
0.64f
0.30
0.30
0.30
0.24
0.15
0.19
h
h
h
0.05
0.01
0.02
0.05
0.25
0.86
0.19
0.17
2.25
0.39
0.12
0.13
h
0.44
0.51
0.50
0.51
h
0.10
0.05
0.05
0.05
0.05
0.05
1.40
1.75
1.45J
2 ppm
Negl.
Negl.
Control
Efficiency
(percent)
99.0
90.3
h
h
h
95.6
94.0
h
h
h
99.6
99.9
99.8
99.3
97.3
83.2
97.3
h
h
94.1
98.0
98.5
h
h
h
h
h
h
99.5
99.9
99.8
99.8
99.8
99.9
h
h
h
99
h
h
Processor
Emissions .
(ng/1iterr
5.9
h
6.9
7.9
6.0
6.2
7.9
5.9
4.2
8.4
1.2
0.34
0.42
0.66
4.5
15.6
6.3
1.8
17.9
11.0
2.3
5.0
13.1
4.8
5.6
4.5
7.7
1.7
7.5
1.6
1.6
5.2
1.5
1.2
21.9
22.6
41.8
1.2
0.-20
0.22
Docket
Item
Reference
IV-D-54
IV-D-54
IV-J-2
IV-J-3
IV-D-56
IV-D-56
IV-D-56
IV-D-38
IV-D-38
IV-D-38
IV-D-49
IV-D-49
IV-0-49
IV-D-56
IV-D-38,56
IV-D-56
IV-D-38,56
IV-D-GO
IV-D-60
IV-D-38,56
IV-D-56
IV-D-56
IV-D-38
IV-D-57
IV-D-57
IV-D-57
IV-D-60
IV-D-55
IV-D-60
IV-D-60
IV-D-60
IV-D-60
IV-D-60
IV-D-57, 60
IV-J-4
IV-D-57
IV-B-2
IV-J-5
IV-D-60
IV-D-57
A-3
-------
NOTES FOR TABLE A-l
aCA - Carbon Adsorption.
REF - Refrigeration.
TO - Thermal Oxidation.
Total volume of all products or gasoline only actually loaded during
test period.
GVolume percent TOC concentration as propane, except as noted.
Mass emissions in terms of gasoline volume loaded where known;
otherwise, in terms of all products loaded.
eTotal products loaded, or not determinable from test report.
Weight percent of total hydrocarbons.
^Volume of gasoline loaded.
hNo data.
^o test report available.
^Volume percent TOC concentration as butane.
\,
Compression-oxidation type system.
m24-hour test.
A-4
-------
Volume I (Emission Source Test Data) was prepared. Thus, the results
could not be considered as background information for the proposed
standards. While these data were not used to determine the emission
limit which represents the performance of the best available systems,
they have served as additional information against which to compare
and evaluate the selected limit.
None of these recent tests was performed by EPA, and only the
test reports are available as information sources. Details regarding
test methods, conditions at the terminals, and methods of calculation
are often incomplete. However, enough information is presented for
most of the test results to be evaluated in terms of the test methods
and procedures developed for use by new sources under the NSPS. For
many of the tests, results were adjusted to correspond to the NSPS
reporting criteria. All throughputs in Table A-l are reported as the
volume of gasoline loaded during the test, where this information was
available, and emission levels are reported in terns of this quantity.
Thus, some of the data in Table A-l differ from the values contained
in the test reports.
The following subsections contain brief discussions of the tests
in Table A-l, including an evaluation of the reliability of the data.
A more detailed evaluation has been prepared by EPA's Emission Measurement
Branch (IV-B-10).
A.2.1 Test Data Evaluation
Some of the test reports indicate only slight deviations from the
NSPS test procedures (which are a combination of Methods 2A, 2B, 21, 25A,
25B, and 27), and thus the results are considered essentially acceptable.
However, in other cases, very different test procedures were used,
introducing a bias and uncertainty regarding several of the measured
and calculated results. Where possible, the extent of bias was estimated,
and a determination was made as to the applicability of the tests as
supporting information. The individual tests are discussed briefly in
the following subsections, grouped according to the party which performed
the tests, since each party used the same testing approach for all of
its tests.
A.2.1.1 Tests by Firm A. Firm A conducted terminal test nos. 4,
5, 6, 13, 14, 15, 16, 19, 20, and 21 on CA units at eight terminals
A-5
-------
during the summer and fall of 1980 (test nos. 4, 5, and 6 were conducted
at the same terminal on consecutive days). Deviations from the NSPS
procedures probably introduced a certain amount of bias into the
results.
Since no information about the terminal and processor operating
conditions is given in the reports, it is impossible to determine the
representativeness of the testing or the relative load on the processor
during testing. Gasoline throughput in test nos. 13 and 21 was
considerably less than the recommended 300,000 liters. Each test was
conducted for 8 hours.
In measuring outlet TOC concentrations, instrument calibrations
were performed less frequently than recommended, reducing confidence
in the accuracy of the measurements. Reduction of strip chart data
included time periods when no loading was taking place, which would
tend to bias the results low. Outlet volumes were determined using
nonstandard methods.
The reports for these tests are well-documented and contain
sufficient information to allow thorough report evaluations. In spite
of probable low biases in reported results, if the outlet concentration
were determined correctly, the mass emission rate from all of these CA
systems would likely be below 35 mg/liter.
A.2.1.2 Tests by Firm B. Firm B conducted test nos. 27, 28, 29,
30, 31, 32, and 33 on CA systems at seven terminals during January and
February of 1981. Deviations from NSPS procedure and lack of detailed
documentation reduce confidence in these test results.
Insufficient information is provided to determine the
representativeness of the terminal and processor operation during
testing. Several tests (four out of seven) do not satisfy the 300,000 liter
minimum throughput requirement. Documentation is not sufficient to
determine whether Method 25B calibration procedures were used. Also,
no-loading periods were apparently averaged into the time averages of
outlet TOC concentration, biasing the results low.
An air-balance procedure was used to determine the outlet gas
volume used in calculating the mass emission rate. This nonstandard
procedure is not comparable to the recommended method (2A), and the
results are questionable.
A-6
-------
Reported outlet emissions range between 1.2 and 7.5 ing/liter.
Even if the reported outlet TOC concentration values (0.05 percent)
were low by a factor of 10 to 20, the outlet emissions in these tests
would still most likely be below 35 mg/liter.
A.2.1.3 Tests by Firm C. Firm C conducted test nos. 1, 17, 18,
23, 24, 25, 26, 38, and 39 at nine terminals. The first seven tests
were on CA type units; test nos. 38 and 39 were on TO type units. As
in the tests discussed previously, several deviations from NSPS procedures
and reference methods lead to uncertainties regarding the accuracy of
the reported test results.
Since no information is provided about the terminal or vapor
processor operations during the tests, the representativeness of the
testing cannot be determined. Most of the 1-day tests did not meet
the throughput criterion, but the combined throughputs during the
3-day test (test nos. 23, 24, and 25) and the 2-day test (test nos. 17
and 18) constitute a sufficient business volume for a meaningful test.
The methods used to measure outlet volume are not documented, and
so the values cannot be accepted as accurate. Concentration values
are similarly unacceptable because of the apparent large deviations
from recommended procedures. However, if the concentration values are
accepted as accurate within ±100 percent, all of the tests except test
no. 18 would probably demonstrate compliance with the 35 mg/liter
limit.
A.2.1.4 Tests by Firm D. Four bulk terminal vapor processors
were tested by Firm D: two CA units (test nos. 2 and 3), one REF unit
(test no. 34), and one TO unit (test no. 37). These tests were conducted
to determine compliance with the California limit of 0.6 lb/1000 gallons
(72 mg/liter). The description given of the terminal and processor
operations allows an evaluation to be made regarding the represen-
tativeness of the testing. The written procedure of the California
Air Resources Board (CARB), which is similar to the NSPS procedure,
was followed in these tests.
All four tests exceed the 300,000 liter throughput criterion.
However, the tests were conducted for 24 hours, and the low business
volume hours were included, probably biasing the results low. Also,
the instrument specifications and the calibration procedure, which are
A-7
-------
not as strict as the recommended procedure, reduce confidence in the
results. Finally, mass emissions were calculated using 24-hour average
values, instead of the 5-ninute averages specified in the NSPS procedure.
This would usually bias the results low.
Mass emission rates in all tests were considerably below the
35 mg/liter limit, and even with some low bias accounted for, test
nos. 2, 3, and 37 would still likely meet this limit.
A.2.1.5 Other Tests. Test no. la was conducted by Firm E on a
CA unit. This test was an efficiency test, and emissions in units of
mg/liter were not determined. The test was short-term (3.5 hours,
with 41 minutes of loading time), and an air-balance procedure was
used. However, if outlet TOC concentrations were measured correctly.
the processor would probably meet the 35 mg/liter limit.
Test nos. 10, 11, and 12 were conducted by Firm F on a CA unit at
one terminal. These three 1-day tests (9, 5, and 8 hours, respectively)
are well-documented, allowing a thorough evaluation of the results to
be made. The NSPS procedure was generally followed, and the results
are considered acceptable. However, reported outlet TOC concentrations
are considered to be too low, since they are below the lowest detectable
limit of the Horiba PIR-2000 NDIR detector used to measure outlet
concentration. The processor would likely meet the limit of 35 mg/liter,
even if true concentrations were 0.5 to 1.0 percent, an increase of
10 to 20 fold above the reported outlet concentrations.
Test no. 35 was performed by Firm F on a dual refrigeration unit.
The test procedure is generally similar to the NSPS procedures, although
detailed calibration documentation is not provided. The results are
considered acceptable, with the processor shown to be attaining the
35 mg/liter 1imit.
Test no. 36 was performed by Firm G on a dual refrigeration
system. Although documentation is not complete, the CARB procedure
was most likely followed, and so the results can be marginally accepted.
This processor slightly exceeded the 35 mg/liter limit.
The results for test nos. 7, 8, 9, and 22 were received by EPA in
tabular form, without any test reports or supporting documentation.
Since no documentation is presently available to EPA, the results of
these four tests, all of which indicated emissions below 35 mg/liter
A-8
-------
for CA systems, are not acceptable as supporting information for the
emission limit of the new source standards.
A.3 CONCLUSIONS
The nominal emission results reported to the States in these
tests are seen to be considerably below the limit of 35 mg/liter.
Lven after a consideration of the low bias which appears to exist in
most tests, the results most likely still substantiate the selected
limit. As in the tests performed by EPA and reported in Appendix C of
BID, Volume I, these recent State tests were performed on vapor processors
designed to comply with State limits of 72 to 80 mg/liter. State-of-
the-art CA and TO processors designed for State limits routinely
achieve emission levels below 35 mg/liter. Manufacturers' claims and
theoretical analyses indicate that REF processors can be designed,
sized, and operated for improved performance over currently installed
systems. Many current REF systems are achieving the 35 mg/liter
1imit.
A-9
-------
A.4 REFERENCES
IV-B-2 Memorandum from Norton, R.L., Pacific Environmental Services,
Incorporated, to Shedd, S., Environmental Protection Agency.
March 23, 1981. Trip report of March 9, 1981, meeting with
Bay Area Air Quality Management District regarding Edwards
refrigeration source test.
IV-B-10 Memorandum from Mclaughlin, N.D., Emission Measurement Branch,
EPA, to Ajax, R.L., and Colyer, R., Standards Development Branch,
EPA. February 19, 1982. Review of Terminal Test Reports.
IV-D-38 Letter and attachments from Karkalik, E.J., The Standard Oil
Company of Ohio, to Colyer, R., Environmental Protection
Agency. March 13, 1981. SOHIO comments and enclosed exhibit
emission test reports.
IV-D-49 Letter and attachments from Kaitschuck, J., John Zink Company,
to LaFlam, G.A., Pacific Environmental Services, Incorporated.
April 15, 1981. Information on carbon adsorption unit.
IV-D-54 Letter and attachments from Surla, E., Indiana State Board
of Health, to Gschwandtner, K.C., Pacific Environmental
Services, Incorporated. March 30, 1981. Performance and
compliance test results.
IV-D-55 Letter and attachments from St. Louis, R., Pennsylvania
Department of Environmental Resources, to Gschwandtner, K.C.,
Pacific Environmental Services, Incorporated. May 27, 1981.
Performance and compliance test results.
IV-D-56 Letter and attachments from Weinberg, B.D., Ohio Environmental
Protection Agency, to Gschwandtner, K.C., Pacific Environmental
Services, Incorporated. June 4, 1981. Performance and
compliance test results.
IV-D-57 Letter and attachments from St. Louis, R., Pennsylvania
Department of Environmental Resources, to Gschwandtner, K.C.,
Pacific Environmental Services, Incorporated. June 12,
1981. Performance and compliance test results.
IV-D-60 Letter and attachments from St. Louis, R., Pennsylvania
Department of Environmental Resources, to Gschwandtner, K.C.,
Pacific Environmental Services, Incorporated. July 16,
1981. Performance test reports.
IV-J-2 California Air Resources Board. Certification Evaluation
Report No. C-9-072 of McGill Vapor Recovery Unit. May 1980.
These numbers correspond to the docket item number in Docket
No. A-79-52.
A-10
-------
IV-J-3 California Air Resources Board. Certification Evaluation
Report No. C-9-073 of McGill Vapor Recovery Unit. May 1980,
IV-J-4 California Air Resources Board. Certification Evaluation
Report No. C-80-034 of Edwards Vapor Recovery Unit. June
1980.
IV-J-5 California Air Resources Board. Certification Evaluation
Report No. C-9-058 of Hirt Vapor Recovery Unit. August
1980.
A-ll
-------
APPENDIX B
COST AND ECONOMIC IMPACTS
B-l
-------
APPENDIX B - COST AND ECONOMIC IMPACTS
B.I INTRODUCTION
Both cost and economic analyses of various regulatory alternatives
were presented in Sections 8.2 and 8.4 of BID, Volume I. Most of the
cost estimates were made in 1979, and all costs were converted to
the equivalent of mid-1979 dollars, generally using the "Chemical
Engineering Plant Cost Index." This was necessary so that all costs
could be compared on the basis of monetary units of equal value.
When the regulation was proposed in December 1980, several commenters
remarked that many of the costs were out-of-date and/or underestimated.
Principal among these were vapor processor purchase, installation,
operating, and maintenance costs (see Section 2.5.3 of this document);
loading rack and tank truck conversion and testing costs (Sections 2.5.3,
2.5.4, and 2.5.5); and total costs to industry (Section 2.5.1). It is
clear that costs estimated during a particular time period are likely
to appear low at some later period, especially during highly inflationary
times. In order to respond to the comments concerning costs, all of
the principal cost figures were re-evaluated in order to retain the
ability to make valid cost comparisons. Section B.2 presents updated
control costs, and Section B.3 discusses the effect which these costs
have on industry economic impacts.
B.2 CURRENT CONTROL COST ESTIMATES
B.2.1 Model Plant Costs
Tables 8-31 and 8-34 of BID, Volume I, were revised to produce
two new tables containing current control costs for the four model
plants. Table B-l presents the costs to comply with the standards for
new and existing bottom-loaded terminals in areas with no SIP regulation.
While the costs to an existing facility affected by the standards may
be slightly more than to a new facility, the higher costs are presented
and presumed to apply in both cases. Table B-2 presents costs for an
existing top-loaded terminal in an area with no SIP control. This
type of terminal would incur additional costs over a bottom-loaded
B-2
-------
Table B-l. ESTIMATED CONTROL COSTS - NEW AND EXISTING BULK TERMINALS
BOTTOM LOADED, NO SIP CONTROL
(Thousands of First Quarter 1981 Dollars)
CO
1
CO
.Q^soJ !_'!§. Throughput:
Vapor Processing Uni t:
Capital Investment
Uni t Purchase Cost
Urii t Installation Cost
Continuous Monitor
Truck Vapor Recovery Cost
Annual Operating Costs
Electricity
Propane (Pilot)1
Carbon Replacement
Maintenance
Operating Labor
Compl iance Cost
Subtotal (Direct Operating Cost)
Truck Maintenance
Capital Charges^
Gasoline Recovery (Credit)''
Net Annual ized Cost
Total VOC Controlled (Mg/yr)'
f.ost-t tfect iveness ($/kg)
380,000 //day
CAa T0l) REFC
128 108 134
109 91.8 114
13.0 15.0 13.0
9.0 9.0 9.0
6.6 3.0 19.1
3.0
1.2
5.7 4.9 6.0
5.1 5.1 5.1
5.7 6.2 5.7
24.3 22.2 35.9
0.9 0.9 0.9
61.5 52.2 64.2
(28.2) -- (28.2)
58.5 75.3 72.8
65.2 65.2 65.2
0.90 1.15 1.12
950,000 //day
CAd T0b REFC
155 118 138
132 100 117
13.0 15.0 13.0
18.0 18.0 18.0
9.8 7.7 21.6
5.4
1.8
7.0 5.5 6.3
5.1 5.1 5.1
5.7 6.2 5.7
29.4 29 . 9 38 . 7
1.8 1.8 1.8
76.2 59.0 68.2
(70.6) -- (70.6)
36.8 90.7 38.1
163 163 163
0.23 0.56 0.23
1,900,000 //day
CAd 10b RCFC
163 118 138
139 100 117
13.0 15.0 13.0
27.0 27.0 27.0
15.1 14.3 21.6
9.9
1.8
7.3 5.5 6.3
5.1 5.1 5.1
5.7 6.2 5.7
35.0 41.0 38.7
2.7 2.7 2.7
82.2 61.2 70.5
(141) -- (Ml)
-21.1 105 -29.1
326 326 326
U) 0.32 (s)
3,800,000 //day
CAd mb RtFC
210 122 1/6
179 104 150
13.0 15.0 13.0
60.0 60.0 60.0
28.3 27.3 28.6
13.0
9.4 5.9 8.0
5.1 5.1 5.1
5.7 6.2 5.7
50.6 57.5 4/4
6.0 6.0 6.0
112 71.5 96.5
(282) -- (2H/)
-113 1 i'j -M2
652 652 652
(s) 0.21 (s)
-------
Table B-2. ESTIMATED CONTROL COSTS - EXISTING BULK TERMINALS
TOP LOADED, NO SIP CONTROL
(Thousands of First Quarter 1981 Dollars)
DO
Gasoline Throughput:
Vapor Processing Unit:
._ _ .
Capital 1 lives tment
Unit I'urthase Cost
Uni t Instal In t ion Cost
Continuous Moni tor
Rack Conversion Cost
[ruck Conversion Cosl^
Annual Operating Costs
Electricity1'
Propane (Pilot)1
Carbon Replacement^
Maintenance
Opera tint) tabor
Compl iance Cost
Subtotal (Direct Opera tiny Cost)
[ruck Maintenance
Capital Charges''
Gasoline Recovery (Credit)^
Net Annual ized Cost
Total VOC Controlled (Mg/yr)'
Cost-Effectiveness ($/kg)
300,000 //day
CAa T0b REFC
128 100 134
109 91.0 114
13.0 15.0 13.0
400 400 400
19.2 19.2 19.2
6.6 3.0 19.1
3.0
1.2 —
5.7 4.9 6.0
5.1 5.1 5.1
5.7 6.2 5.7
24.3 22.2 35.9
0.9 0.9 0.9
164 155 167
(20.2) -- (28.2)
161 178 176
65.2 65.2 65.2
2.47 2.73 2.69
950,000 //day
CAa T0b REFC
155 118 138
132 100 117
13.0 15.0 13.0
600 600 600
38.4 38.4 38.4
9.8 7.7 21.6
5.4
1.8
7.0 5.5 6.3
5.1 5.1 5.1
5.7 6.2 5.7
29.4 29.9 38.7
1.8 1.8 1.8
231 214 223
(70.6) -- (70.6)
192 246 193
163 163 163
1.18 1.51 1.18
1,900,000 //day
CAa TO5 REFC
163 118 138
139 100 117
13.0 15.0 13.0
600 600 600
57.6 57.6 57.6
15.1 14.3 21.6
9.9
1.8
7.3 5.5 6.3
5.1 5.1 5.1
5.7 6.2 5.7
35.0 41.0 30.7
2.7 2.7 2.7
240 219 220
(141) -- (141)
137 263 128
326 326 326
0.42 0.81 0.39
3,800.000 //day
CAa T0b RFFC
210 122 1/6
179 104 150
13.0 15.0 13.0
800 800 000
128 120 120
28.3 27.3 28.6
13.0
2.1
9.4 5.9 8.0
5.1 5.1 5.1
5.7 6.2 5.7
50.6 57.5 47.4
6.0 6.0 6.0
329 288 314
(282) -- (282)
104 352 85.4
652 652 652
0.16 0.54 0.13
-------
NOTES FOR TABLES B-l AND B-2
aCarbon Adsorption Unit.
Thermal Oxidation Unit.
c
Refrigeration Unit.
Includes one performance test plus $5,000 equipment cost.
Cost of installing vapor collection eq
loading tank trucks, $3,000 per truck.
eCost of installing vapor collection equipment on existing bottom
Cost of converting top loading racks to bottom loading and vapor
recovery, $200,000 per rack.
9Cost of retrofitting existing top loading tank trucks with bottom
loading and vapor collection equipment, $6,400 per tank truck.
Electricity costs are based on average consumption rates reported by
manufacturers.
Propane for pilot burner estimated at 12.5 liters per hour, at $0.18 per
liter.
^Estimated activated carbon replacement period is 10 years, at $3.85 per
kilogram carbon cost.
u
Estimated as 4 percent of unit purchase cost, plus annual rack vapor
collection maintenance of $200 per rack and $200 per terminal.
Daily system inspections at 1 hour per day, plus a monthly inspection
for liquid and vapor leaks in the vapor collection and processing
systems.
mlncludes capital charges on continuous monitor investment plus
$2,500 annual operating cost.
nCost to perform annual vapor tightness testing, including one-half
day downtime, $300 per truck.
^Total capital investment (less monitor) x (capital recovery factor +
0.04), where interest rate = 17 percent, equipment economic life =
10 years.
B-5
-------
NOTES FOR TABLES B-l AND B-2 (Concluded)
^Amount recovered per year, at $0.29 per liter.
rDifference between uncontrolled submerged fill loading and NSPS level
of control.
sCost-effectiveness not calculated because net annualized cost is a negative
quantity (cost credit).
B-6
-------
terminal to convert its loading racks and tank trucks to a bottom-
loading configuration, which is a substantial additional cost.
Control unit purchase and installation costs are the same in both
tables. Current purchase costs have been obtained from manufacturers
for carbon adsorption (CA) (IV-D-51, IV-E-20, IV-E-36), refrigeration
(REF) (IV-E-3, IV-E-32, IV-J-8), and thermal oxidation (TO) type units
(IV-E-35, IV-E-37). Prices for CA and TO units represent the average
for two manufacturers, and REF prices represent a single manufacturer.
While the average price of TO units has risen 15 percent, CA and REF
prices have decreased 13 and 17 percent, respectively, from previously
reported values. The estimate of installation cost as 85 percent of
purchase cost has been retained (see Section 2.5.3). The cost of
continuous monitors has been added to the tables, using the reference
costs for Compliance Option 2 in Table 8-38 of BID, Volume I.
The costs for converting tank trucks and loading racks to a
bottom loading/vapor recovery configuration were reassessed through
contacts with companies currently performing these conversions (see
Section 2.5.5) (IV-E-22, IV-E-24, IV-E-25, IV-E-26). While costs vary
for trucks of different configurations, the previous cost of $6,400 for
a bottom loading/vapor recovery tank truck conversion still represents
a good average for Table B-2. The cost of adding vapor recovery
provisions alone has increased from $1,600 and $2,400 (cost adder on
new tank truck and conversion cost on older truck, respectively) to
$2,000 and $3,000. The higher value of $3,000 has been used for both
new and existing terminal cases in Table B-l. The costs associated
with loading rack conversions are highly variable, depending on the
level of work to be done. The costs attributable to the standard must
represent the basic conversion which is necessary for compliance with
the standard to be achieved. It is often in a terminal's interest to
perform general modernization and equipment replacement during a rack
conversion project. This may include costs for improvements in concrete
driveways, drainage systems, fire protection, or structures. Contacts
with construction contractors involved in recent projects of this type
indicate that the previous estimate of $160,000 per rack conversion
B-7
-------
may represent the low end of the range for a basic conversion (IV-E-33,
IV-E-39). To reflect this increase, a cost of $200,000 has been
assumed for Table B-2.
Electrical operating costs were re-evaluated by contacting
manufacturers and users of CA (IV-E-20, IV-E-40, IV-E-42), REF (IV-D-47,
IV-E-32, IV-E-38, IV-J-8), and TO units (IV-E-35, IV-E-37). Annual
power costs for Tables B-l and B-2 were calculated using the manufacturers'
reported unit power consumption, daily operating schedules for each
type of unit, 340 days of operation, and power cost of $0.06 per
kilowatt-hour (see Section 2.5.3). Calculated costs are generally
confirmed by the costs reported by users, but considerable variability
may be expected in individual cases due to unit control settings,
terminal schedules, and climatic conditions. The cost of propane used
for the pilot burners of TO units has been raised from $0.12 per liter
to the current price of $0.18 per liter. The price of activated
carbon has increased from $3.30 per kilogram to $3.85 per kilogram
(IV-E-30). The cost of maintaining a vapor processor is quite variable,
but user input indicates that this cost can be represented quite well
as 4 percent of the unit purchase cost (see Section 2.5.3). This
percentage is unchanged for CA and TO units, but represents a considerable
reduction from the previous value of 8 percent assumed for REF units.
Newer generation units appear to have lower maintenance requirements
than the brine systems which make up a considerable percentage of the
existing population of refrigeration units. The additional rack vapor
recovery maintenance cost of $200 per rack annually, plus $200 per
facility has been retained unchanged. The level of operating labor
required to perform daily unit checks and a monthly leak inspection is
assumed to remain valid, but the hourly rate has been increased from
$10 per labor-hour to $15 per labor-hour to cover the expected inflation
rate over the next several years as well as the possibility of more
technically oriented personnel being employed to check continuous
monitors. The annual compliance cost in both tables represents Compliance
Option 2 in Table 8-38 of BID, Volume I. The total direct operating
costs for the model plants are generally higher than the previous
values presented in BID, Volume I, primarily due to higher electrical
consumption and the addition of compliance costs.
B-8
-------
Tank truck maintenance costs, representing the annual vapor
tightness test, have been increased from $150 to $300 per truck, to
include the estimated one-half day of lost revenue due to transport
downtime during the test. Capital charges on the initial investnent
have been re-calculated to account for a higher interest rate. If the
rate is 17 percent, then for an equipment economic life of 10 years
the capital recovery factor (Table 8-22 of BID, Volume I) would be
0.21. Adding property taxes, insurance, and administrative costs of
0.04, the capital charges total 25 percent of the total capital cost.
Capital charges on the continuous monitors are included separately
under the compliance cost. The gasoline recovery cost credits are
calculated as before, using revised values of gasoline price and total
gasoline recovered. The nationwide average wholesale price for regular
leaded gasoline during first quarter 1981 was approximately $0.29 per
liter (IV-J-10). The gasoline recovery rates in Table 8-25 of BID,
Volume I, were mistakenly based on an uncontrolled emission factor of
960 nig/liter in areas with no SIP regulation of gasoline loading at
bulk terminals. If the correct emission factor of 600 mg/liter (submerged
loading, normal service) is used, the recovery rate is:
600 mg/liter - (0.10)(600 mg/liter) - 35 mg/liter = 505 mg/liter,
or 39 percent lower than the previous figure of 829 mg/liter. The
recovery cost credits entered in Tables B-l and B-2 are thus $28,200,
$70,600, $141,000, and $282,000, which average only 4 to 5 percent
higher than the previous estimates. Because of the lowered emission
factor referred to above, the total annual VOC controlled has been
reduced by 39 percent for all model plants.
Most net annualized costs presented in Tables B-l and B-2 have
increased from the previously presented values. Annualized costs for
CA and REF installations at previously bottom-loaded terminals are
22 and 14 percent higher, respectively, than before for Model Plants 1
and 2. These costs remain negative for Model Plants 3 and 4, indicating
that terminals in this size range (greater than 1,400,000 liters/day
throughput) installing CA or REP units would realize a net income from
the installation. New annual costs for TO installations, however,
have increased an average of 61 percent in the cost re-evaluation,
6-9
-------
causing them to appear less competitive for all model plant sizes. In
particular, whereas the TO installation previously involved the lowest
net annualized cost for Model Plant 1, the revised estimates indicate
the TO installation to involve net costs which are 29 and 3 percent
higher, respectively, than CA and REF installations. All net annual-
ized costs shown in Table B-2 for top-loaded terminals affected by the
regulation are higher than previous estimates. Section B.3 discusses
the economic impact considerations of the revised cost estimates.
The compression-oxidation systems discussed on page 4-12 of BID,
Volume I, have not been included in the revised tables because the
gasoline recovery rate has not been determined (IV-E-27). One system
tested recently in California showed over 99 percent control efficiency
(emissions less than 1.2 mg/liter), and it was estimated that 22 gallons
were recovered during a gasoline throughput of 2.3 million liters in
24 hours (IV-J-5). Preliminary estimates indicate that the net cost
for this system would be higher than for .any of the three units shown
in the tables.
B.2.2 Nationwide Control Costs
The cost impacts on the bulk terminal and for-hire tank truck
industries have been re-calculated based on the updated model plant
and tank truck costs discussed in Sections 2.5 and B.2.1. Several
changes have been made to the calculations.
Based on industry responses to Section 114 letter requests for
information, it is estimated that five new bulk terminals will be
built in the first five years of the standard (Table 8-12 of BID,
Volume I). As noted on page 3-26 of BID, Volume I, approximately
71 percent of the nationwide gasoline loading at existing terminals
will be controlled to the level recommended by the terminal CTG. This
implies that about 71 percent, or three of the five new terminals, are
likely to be constructed in areas already requiring emission control
to the 80 mg/liter limit. Since the NSPS will require an emission
limitation to 35 mg/liter, there may be added costs associated with
achieving this limit as compared to the SIP limit of 80 mg/liter.
Although these added costs are likely only in the case of refrige-
ration recovery systems (since current CA and TO units can meet the
B-10
-------
lower limit), they have been accounted for in the case of all t'nree of
these terminals to assess worst case costs. The costs of installing
and operating continuous monitors, outlined in Tables B-l and 8-2,
have also been included for these terminals. The remaining two terminals
in areas with no SIP control will incur the full costs summarized in
Table B-l. One Model Plant 2 and one Model Plant 3 have been assumed
for these terminals (the largest terminals are expected in SlP-controlled
areas, which are generally associated with the higher-demand urban
areas). The previous analysis was based on the incorrect assumption
that all five new terminals would incur the full control costs of the
standard.
It was assumed that, since all state-of-the-art CA and TO units
are considered capable of meeting the 35 mg/liter limit, the REF unit
would be the typical choice of a terminal owner intending to comply
with an 80 mg/liter limit. The costs for a REF system meeting
35 mg/liter were presented in Table B-l. Purchase prices of $128,000
and $134,000 for Model Plant 3 and 4 size units meeting 80 mg/liter
were obtained from the manufacturer's current price list (IV-J-8).
The lower prices of the less efficient units created lower installa-
tion, electricity, and maintenance costs, as well as lower capital
charges than for the units meeting 35 mg/liter. Electrical costs for
the 80 mg/liter units were assumed to be 50 percent less than these
costs for the 35 mg/liter units, as suggested by the manufacturer
(IV-E-32). The gasoline recovery cost credit for units controlling to
35 mg/liter is greater, which tends to offset the increased purchase
and operating costs of these units. In fact, for the Model Plant 3
size terminal in this situation, the net annualized cost is $1,000
less for the 35 mg/liter system than for the 80 mg/liter system. All
net costs remain negative, however, indicating that more money would
be made from recovered product than would be spent to operate the
control system.
All terminals replacing or adding onto existing systems to meet
the NSPS limit were assumed to be represented by Model Plant 2 for the
purpose of the calculations. The assumptions used to derive Tables 8-35
and 8-36 of BID, Volume I, were retained, but updated costs corresponding
to those in Table B-l were substituted.
B-ll
-------
The cost per unit of emission reduction was also reviewed for
each of the cases associated with the standard. These costs are shown
in Table B-3. The cost per unit emission reduction was considered
excessive for cases 3a and 3b. Based upon these costs and the fact
that EPA does not feel it is reasonable to require costly add-on
controls or replacements of recently installed equipment at bulk
gasoline terminals, EPA decided that existing control devices meeting
80 mg/liter would not require additional emission reduction.
The previous cost analysis also assumed that 25 of the 30 modified
or reconstructed terminals in attainment areas would become affected
facilities due to loading rack conversions and would incur the costs
summarized in Table 8-34 of BID, Volume I (new Table B-2), because
conversion of these previously top loading racks to bottom loading
would be required to meet the emission limit of the standard. However,
since no SIP requirements led to the conversions and because the
loading rack conversion was the item that triggered the reconstruction
provisions of the standards, the cost impact of the conversions them-
selves will not be attributable to the standard, and so the costs
summarized in Table B-l will apply. Only 5 of the 30 modified or
reconstructed terminals in attainment areas in the first 5 years
would become affected facilities for reasons other than top to bottom
loading conversions. However, it is estimated that two of these
terminals will already use bottom loading, leaving three terminals
which will incur the full costs shown in Table B-2. Based on the
distribution of terminal sizes (Table 8-4 of BID, Volume I), two of
these terminals will be of Model Plant 1 size and one terminal will be
of Model Plant 2 size.
Table 8-4 presents the number and sizes of the terminals expected
to incur control costs as a result of the standard, as well as the
per-facility costs as shown in Tables B-l and B-2. The costs associated
with CA, TO, and REF installations were averaged for Model Plant 1,
whereas only CA and REF costs were averaged for Model Plants 2 and 3.
The incremental costs of meeting 35 mg/liter instead of 80 mg/liter,
and the costs of continuous monitors applied to existing control
systems, both not contained in Tables B-l and B-2, were derived using
the assumptions described above.
B-12
-------
Table B-3. COST EFFECTIVENESS FOR VARIOUS BULK TERMINAL MODEL PLANT CASES
Case8
1
2
3a
3b
4
TOTALb
Quantity
13
2
-
_
-
Model
Plant 1
($/Mg)c
1100
2600
15
Quantity
8
1
5
5
-
Model
Plant 2
($/Mg)c
340
1300
6000
4300
19
Model
Plant 3
Quantity ($/Mg)c
8 (s)d
-
_
1 (s)d
9
Model
Plant 4
Quantity ($/Mg)c
e
-
-
_
2 450
2
CO
I
Case 1: New, modified, or reconstructed terminals in areas unaffected by SIP regulations (Table B-l)
Case 2: Modified or reconstructed terminals requiring bottom loading conversion (Table B-2).
Case 3a: Terminals replacing an existing SIP-level (80 mg/liter) control system.
Case 3b: Terminals adding onto an existing SIP-level (80 mg/liter) control system.
Case 4: New terminals installing NSPS-level equipment instead of SIP-level equipment (CRA or
REF units only).
Remaining 10 of the 55 affected terminals will have previously installed equipment which meets
35 mg/1iter.
GCost effectiveness is the average of the control devices. TO included in averages for Model
Plants 1 and 2, excluded in average for Model Plants 3 and 4.
(s) = cost savings.
e"-" = no affected terminals assumed in this model plant size.
-------
TABLE B-4. FIVE-YEAR NATIONWIDE COSTS TO BULK TERMINAL INDUSTRY
(Thousand of First Quarter 1981 Dollars)
CO
Bulk Terminals
Case3 Model Plant
1
1 2
3
1
2 2
2
Affected
No. of Occurences
13
8
8
2
1
10
3
•4 4
TOTALS
1
2
45b
Capital Investment
Investment/Terminal
251
302
319
661
922
13C
Total
3,260
2,420
2,550
1,320
922
130
18.0
78.0
18.0
156
10,776
Net
Cost/Terminal
68.9
37.5
-25.1
172
193
5.7C
Annual ized Cost
Total Net Cost/Year
896
300
-201
344
193
57
-1.0
13.0
-1.0
26.0
1,614
"Case 1:
Case 2:
Case 3:
Case 4:
New, modified, or reconstructed terminals in areas unaffected by SIP regulations (Table B-l).
Modified or reconstructed terminals requiring bottom loading conversion (Table B-2).
Terminals with existing SIP-level (80 mg/liter) control systems.
New terminals install inn NSPS-level equipment instead of SIP-level equipment.
Remaining 10 of the 55 affected terminals will have previously installed equipment which meets 35 my/liter.
°No replacement or add-on contra1 are required for existing vapor processing systems under the promulgated
standard. Only costs associated with the facilities would be fr>r continuous monitors.
-------
Table B-4 shows a nationwide total capital investment for the
terminal industry in the first 5 years of $10.8 million, or
45 percent of the previous estimate. The net annualized cost in the
fifth year will be $1.6 million, or 45 percent of the former figure.
The costs to the for-hire tank truck industry have increased
slightly in the cost impacts re-evaluation. As stated in Section 2.9.4,
approximately 370 for-hire tank trucks will require conversion due to
the standard. Of these, 35 will require both bottom loading and vapor
recovery retrofitting, at $6,400 per tank truck, and 285 will require
only the addition of vapor recovery equipment, at $3,000 per tank
truck (Section 2.5.5). The capital and annualized costs are calculated
as in Sections 8.2.5.1 and 8.2.5.2 of BID, Volume I. The total capital
investment in the first 5 years will be:
(85 tank trucks) x ($6,400/tank truck) = $544,000, plus
(285 tank trucks) x ($3,000/tank truck) = $855,000,
which totals $1.4 million. The annualized cost in the fifth year will
consist of capital charges and the costs of maintenance and testing.
Assuming an interest rate of 17 percent and an equipment life of
12 years, capital charges will total:
($1.4 million) x (24 percent) = $336,000/yr.
With maintenance costs at $1,000 per year and testing at $450 per
year, the total annualized cost for 370 tank trucks in the fifth year
wi 11 be:
370 x ($l,000/yr + $450/yr) + $336,000/yr = $0.9 million.
In summary, the total capital investment required by both the
bulk terminal and for-hire tank truck industries in the first 5 years
of the standard will be $12.2 mill ion. The annualized cost for
both industries in the fifth year will be $2.5 million. Section B.3
B-15
-------
discusses the changes to the economic impact analysis resulting from
the revised cost estimates.
B.3 ECONOMIC IMPACT ANALYSIS
Tables 8-43 through 3-53 of BID, Volume I, were revised to account
for the current control costs presented in Section B.2.1, the current
price of leaded regular gasoline, and a current level of investment
costs. All monetary values in this section are specified in first quar-
ter 1981 dollars; older values not updated through direct contacts were
converted using the "Chemical Engineering Plant Index" (IV-J-14). Except
for these three changes, all of the assumptions used in the calculations
in BID, Volume I, remain the same.
The change in1 the price of leaded regular gasoline from $0.17 per
liter to $0.29 per liter impacts the results presented in Tables B-5
through B-10 either indirectly as a change in after-tax profits or directly
in the calculation of a maximum percentage price increase (see
Sections 8.4.1.2.1 and 8.4.1.2.2 of BID, Volume I). The change in
total investment costs impacts the results in all the tables except
Table B-9, either indirectly through a change in CMLTD and depre-
ciation or directly in the calculation of ROI (see Sections 8.4.1.2.1.
and 8.4.1.2.2.2 of BID, Volume I).
It is not necessary to thoroughly explain and examine each of the
individual Tables B-5 through B-10 since the methodology and results
are similar to those in the original economic analysis. In general,
the revised debt service coverage ratios are much higher for all
regulatory alternatives and all model plants. The revised ROI's are
also considerably higher for new facilities but only slightly higher
for existing facilities. The revised maximum percentage price increases
presented in Table B-9 are in addition slightly higher for all model
plants (for comparison purposes see Tables 8-45 and 8-52 of BID, Volume I).
The general conclusions presented in Sections 8.4.1.2.4 and 8.4.1.3.5
of BID, Volume I, are thoroughly supported by the results in Tables B-5
through B-10. None of the model plants will encounter a debt service
coverage problem, nor will the maximum price increase necessary to
maintain pre-control profit rates be excessive. The worst possible
case is a necessary 0.48 percent price increase for a 380,000 liter/day
existing top-loading facility.
B-16
-------
DO
I
Table B-5. DEBT SERVICE COVERAGE RATIO FOR NEW FACILITIES
(Monetary Values in $000 1981)
380,000 lyday 950,000 1/dAy
Basel ine Facility
Total Investment
Long-Term Debt (LTD)
Current Maturity LTD
(CMLTD)
Depreciable Assets
After-Tax Profit
Depreciation
Cash Flow (CH)
CF t CMLTD
Controlled Facil i ty
Total Investment*1
LTDb
CMLTDC
After-Tax Profit^
Depreciation^
Cash Flow
CF i CMLTD
CA TO
2,900
1,160
116
1,887
303
180
483
4.2
3,159 3,232
1,419 1,492
142 149
271 262
206 213
477 4/b
3.4 3.2
REF CA TO REF
4,500
1,800
180
2,942
758
284
1,042
5.8
3,170 4,818 4,751 4,786
1,430 2,118 2,051 2,086
143 212 205 209
264 738 709 737
207 316 309 313
471 1.054 1,018 1,050
3.3 5.0 5.0 5.0
1,900,000 I/day
CA TO REF
6,600
2,640
264
4,222
1,517
395
1,912
7.2
6,942 6,860 6,895 1
2,777 2.744 2,758
278 274 276
1,528 1,460 1,533
429 421 425
1.957 1,881 1,958
7.0 6.9 7.1
3,800,000 I/day
CA TO REF
10,900
4,360
436
7.0/5
J.OJ5
706
2,741
8.6
1,362 11,201 11,299
4,822 4.661 4.759
482 466 476
3.096 2,%2 J.106
752 736 746
3.8-1H J.69U 3.8bZ
8.0 7.9 8.1
Baseline investment plus capital control costs.
Baseline LTD plus capital control costs.
CO.IO x ITD.
Baseline after-tax profit minus [(1-tax rate) x annualized control costs].
ebaseline depreciation plus (0.10 x control capital costs).
-------
Table B-6. DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY — BASELINE
(Monetary Values in $000 1981)
Existing Facility
Total Investment3
Long-Term Debt (LTD)
Current Maturity LTD
(CMLTD)
Depreciable Assets
After-Tax Profitb
Depreciation
Cash Flow (CF)
CF - CMLTD
380,000
I/day
1,960
780
78
1 ,280
303
128
431
5.5
950,000
I/ day
3,050
1 ,220
122
1 ,990
758
199
957
7.8
1 ,900,000
I/ day
4,470
1,790
179
3,260
1,517
326
1,843
10.3
3,800,000
I/ day
7,380
2,950
295
4,810
3,035
481
3,516
11.9
aTable 8-47 values from BID, Volume I adjusted to reflect 1976 cost levels using
M&S equipment cost index (IV-J-Hj.
Calculated using $0.29 per liter wholesale price for leaded regular gasoline.
This assumes an average retail price of $0.356 per liter ($1.347 per gallon)
for leaded regular as of the first quarter of 1981.
B-18
-------
DO
UD
Table B-7. DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY-BOTTOM LOADED, NO SIP CONTROL
(Monetary Values in $000 1981)
.
Total Investment
LTOb
CMLTOC
After-Tax Profits'1
Depreciation6
Cash Flow (CF)
CF i CMLTD
380
CA
2,219
888
89
271
154
425
4.0
,000 I/day
TO
2,292
917
92
262
161
423
4.6
REF
2,230
892
89
264
155
419
4.7
950
CA
3,368
1,347
135
738
231
969
7.2
,000 I/day
TO
3,301
1.320
132
709
224
933
7.1
REF
3,336
1.334
133
737
228
965
7.3
1,900
CA
4.812
1.925
193
1,528
360
1,888
9.8
,000 I/ day
TO
4,730
1,892
189
1.460
352
1.812
9.6
REF
4,765
1.906
191
1.533
356
l ,«ay
9.9
3,800,000 I/Jay
CA
7.842
3,137
314
3.096
527
3,o23
11.5
TO
7.681
3.072
307
iJ.962
bll
3.47J
11.3
REF
7,779
3.112
311
3,106
521
3,fa^/
11.7
dBaseline investment plus capital control costs.
Baseline III) plus capital control costs.
C0.10 x LTD.
Baseline after-tax profit minus [(1-tax rate) x annual 1 zed control costs).
eBaseline depreciation plus (0.10 x control capital costs).
-------
CO
I
PO
o.
Table B-8. DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY-TOP LOADED, NO SIP CONTROL
(Monetary Values in $000 1981)
Total Investment
LTD6
CMLTDC
After-Tax Profitsd
Depreciation6
Cash Flow (CF)
CF * CMLTD
380
CA
2,629
1,449
145
216
195
411
2.8
, JO I/day
TO
2,594
1,414
141
207
191
398
2.8
REF
2,640
1,460
146
208
196
404
2.8
950,000 I/day
CA
3,988
2,158
216
654
293
947
4.4
TO
3,921
2,091
209
625
286
911
4.4
REF
3,956
2,126
213
654
290
944
4.4
1 .900,000 I/day
CA
5,443
2,763
276
1,443
388
1,831
6.6
TO
5,361
2.6H1
268
1,375
380
1,755
6.5
REF
5,396
2,716
272
1,448
384
1,832
6.7
iti!
CA
8.710
4,280
428
2,979
614
3,593
8.4
30,000 1,
TO
8,549
4,119
412
2,845
MB
3.443
8.4
REF
8,647
4,217
422
2,989
608
3,597
0.5
aBaseline investment plus capital control costs.
Baseline LTD plus capita) control costs.
C0.10 x LTD.
Baseline after-tax profit minus [(1-tax rate) x annualized control costs].
Baseline depreciation plus (0.10 x control capital costs).
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I
ro
Table B-9. MAXIMUM PERCENTAGE PRICE INCREASES, COST PASS-THROUGH:
NEW FACILITIES, EXISTING FACILITIES (BOTTOM LOAD), AND EXISTING FACILITIES (TOP LOAD)
(Percent)
380,000 I/day 9SO.OOO I/day li 900,000 1/da^ liMMi^OO J
CA TO REF CA TO REF CA~ TO' REF" CA TO REF
New and Existing Fact- .16 .20 .19 .04 .10 .04 (.01)" .06 (.02)" (.03)" .04 (.03)'
OT lities (Bottom load)
Existing Facilities .43 .48 .47 .20 .26 .21 .07 .14 .07 .03 .09 .02
(Top Load)
d( ) indicates control cost savings, which may result in price reductions.
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Table B-10. AFTER-CONTROLS, AFTER-TAX RETURN ON INVESTMENT: NEW FACILITIES, EXISTING
FACILITIES (BOTTOM LOAD), AND EXISTING FACILITIES (TOP LOAD)
(Percent)
(Bottom Loaded)
380.000 I/day 950.000 I/day 1.900.000 I/day 3.800.000 I/day
CA TO REF CA TO REF CA TO .REF CA TO REF
New Facility
Baseline 10.4 16.8 23.0 27.8
After-Control 8.6 U.I 8.3 15.3 14.9 15.4 22.0 21.3 22.2 27.2 26.4 27.5
Existing Facility
Baseline 15.0 15.0 15.0 15.0
After-Control 11.9 11.7 11.5 13.7 13.4 14.0 14.6 14.0 14.7 15.0 14.4 15.0
Existing Facility
(Top Loaded)
Baseline 15.0 15.0 15.0 15.0
After-Control 8.0 7.8 7.7 10.9 10.6 11.0 13.0 12.5 13.1 13. 8 13.3 13.9
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The conclusions based on the ROI analysis are also the same with
the exception of a new 950,000 liter/day facility. The conclusion
based on the original ROI analysis stated that "terminals in the
950,000 liter/day category, marginally attractive before controls,
would have to pass through most of the control costs to remain attractive.
The ROI results from Table B-10 suggest that a new 950,000 liter/day
facility will be marginally attractive for both the baseline and
after-control cases since the 15 percent ROI criterion is maintained.
The ROI results still support the conclusion that growth in the form
of 380,000 liter/day bulk terminals will not take place because both
pre-control and after-control ROI's do not meet the 15 percent condition.
The 380,000 liter/day existing terminal will still encounter an ROI of
less than 11 percent, the minimum acceptable return, but the
950,000 liter/day existing terminal now maintains a marginal ROI level
of between 10.6 and 11.0 percent.
The economic impacts on the for-hire tank truck industry are
slightly higher as a result of the revised costs; however, the basic
conclusions from the original analysis remain intact. Revised rates
of return on transportation investment decrease slightly to a range
of 3.N9 to 11.0 percent for Scenario 1, and a range of 2.8 to 10.2 percent
for Scenario 2. These results further support the original conclusion
that the viability of the three largest firms could become threatened
with the imposition of any of the regulatory alternatives in the unlikely
event that control costs are totally absorbed. If, however, the control
costs are fully passed through to the consumer in the form of higher
prices, gasoline prices would increase by a maximum of 0.02 to
0.08 percent. As discussed in Section 2.5.7, tank truck firms are
expected to be able to pass through their costs of control. Finally,
the firm's ability to meet debt service costs is maintained since the
values calculated in the revised debt service coverage analysis remain
the same as those presented in Table 8-59 of BID, Volume I.
B.4 SOCIOECONOMIC AND INFLATIONARY IMPACTS
Section B.3 presented the revisions to the original economic
analysis for the bulk terminal and for-hire tank truck industries.
This section will review the results of the original Socioeconomic and
B-23
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Inflationary Impacts section (Section 8.5 of BID, Volume I) with
respect to the directives of Executive Order 12291 and the updated
scenario presented in Section B.3, to determine whether the results
and conclusions of the original analysis have changed.
B.4.1 Executive Order 12291
According to the directives of Executive Order 12291, a "major
rule" means any regulation with the potential to result in:
• an annual effect on the economy of $100 million or more,
• a major increase in costs or prices for consumers, individual
industries, Federal, State, or local government agencies, or
geographic regions, or
• significant adverse effects on competition, employment,
investment, productivity, innovation, or on the ability of
the United States-based enterprises to compete with foreign-
based enterprises in domestic or export markets.
The following sections evaluate these criteria in relation to the
promulgated action.
B.4.2 Fifth-Year Annualized Costs
Section B.2.2 recalculated fifth-year annual ized costs to be
$1.6 million for the bulk terminal industry and $0.9 million for the
for-hire tank truck industry. The total of $2.5 million is well
within the $100 million level; thus, no major impact is indicated
according to this criterion.
B.4.3 Inflationary Impacts
In Section B.3 it was determined that the worst case impact the
regulatory alternative would have on the price of gasoline, via the
bulk terminal industry, was 0.48 percent. In Section 8.4.2.2.2 of
BID, Volume I, it was also determined that the worst case impact the
regulatory alternative would have on the price of gasoline, via the
for-hire tank truck industry, was 0.07 percent. The total worst case
impact on the price of gasoline from both industries is 0.55 percent.
Since a rise in the price of gasoline by 0.55 percent cannot be con-
sidered a major price or cost increase, no major economic impact is
indicated according to this criterion.
B-24
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B.4.4. Other Impacts
The regulatory alternative will not curtail a businessman's
opportunity to enter the gasoline terminal market. Sufficient ROI's
are available to make it attractive to build large terminals in both
pre-control and post-control situations. At the other extreme a small
businessman is already limited by the lower returns from small facilities
in a pre-control situation. For smaller existing terminals low ROI's
may make closure a necessary alternative; however, few facilities
will find themselves in a position of being unable to pass along most
of the control costs. Therefore, employment impacts and adverse
effects on the regional economies will be negligible.
Finally, foreign trade and the balance of payments should not be
influenced by the standard, since bulk terminals export and import
relatively small amounts of gasoline. No major impact is indicated
according to this criterion.
B.5 REGULATORY FLEXIBILITY ANALYSIS
The Regulatory Flexibility Act of 1980 (RFA) requires that
differential impacts on small businesses resulting from all Federal
regulations be identified and analyzed. The definition of a small
business in the bulk terminal industry (SIC 5171), according to the
criterion to qualify for SBA loans, is a firm with less than $22 million
in annual receipts (IV-E-47). Approximately 50 to 60 percent of the
bulk terminal industry can be considered as small businesses
according to this criterion (IV-J-13). In the for-hire tank truck
industry (SICs 4212, 4213, and 4214) a small business is defined as a
firm with less than $6.5 to $7 million in annual receipts (IV-E-47).
Approximately 60 percent of the for-hire tank truck industry can be
considered as small businesses according to this criterion (IV-J-12).
The RFA further stipulates that the analysis must be prepared if
20 percent of the small businesses are significantly affected.
As described in Section B.2.2, five new terminals are expected to
be constructed in the first five years, and approximately 50 facilities
will become affected through modification or reconstruction. Of the
55 affected facilities, 15 facilities, a 27 percent share, can be
B-25
-------
considered small business entities (assuming Model Plant 1 approximates
a small business), and so the 20 percent criterion is exceeded.
Only the modified and reconstructed category of the affected
facilities need be examined for significant impact since the five new
terminals are all medium to large sized plants. New small facilities
are considered not economically feasible (based on stand-alone economics),
with or without imposition of the promulgated standards. The 15 affected
facilities considered to be small business entities will be impacted
according to the costs presented in Table B-2 for top-loaded, existing
bulk terminals. The analysis presented in Section B.3 concluded that
a significant impact for small business entities (assumed to be Model
Plant 1) would occur only under the worst-case assumption of complete
cost absorption. Under a more likely scenario, further analysis revealed
no significant impact. This conclusion was based on the more realistic
assumption that most of the costs will be passed through with very
little cost absorption affecting the ROI. Small terminals in remote
areas will be at the same disadvantage with respect to parts and
service access as they were prior to the standards, but this should
not affect their ability to comply with the standards at a reasonable
cost. Since the impact on small bulk terminal businesses is not
expected to be significant, no Regulatory Flexibility Analysis is
required for this industry sector.
Thirty-four model firms in the for-hire tank truck industry are
expected to be affected by 1985. Twenty-three of these affected firms
are expected to be small business entities, representing a 68 percent
share, which exceeds the 20 percent criterion.
The potential exists for a significant impact to occur in a
worst-case scenario if control costs are completely absorbed. The
results from the return-on-transportation investment (ROTI) analysis,
Section 8.4.2.2.1 of BID, Volume I, not only suggested a significant
worst-case impact, but that the impacts are more severe for the largest
model trucking firms. The decrease for the worst-case situation in
the ROTI's range from 9.6 and 55.6 percent. A more likely scenario was
analyzed and no significant economic impact was found. This scenario
was based on the realistic assumption that most of the control costs
B-26
-------
will be passed through with very little cost absorption affecting the
ROTI. Even under complete cost pass-through the price of gasoline
increases at most, by 0.03 percent. Since the impact on small independent
tank truck firms is not expected to be significant, no Regulatory
Flexibility Analysis is required for this industry sector.
B-27
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B.6 REFERENCES
IV-D-51 Letter and attachments from Schmidt, E.L., McGill, Incorporated,
to Norton, R.L., Pacific Environmental Services, Incorporated.
April 30, 1981. Information on prices and power consumption
for vapor processors.
IV-E-3 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Edwards, R., Edwards Engineering Corporation.
February 23, 1981. Information on refrigeration units.
IV-E-20 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Kaitschuck, J., John Zink Company.
April 14, 1981. Information on carbon adsorption units.
IV-E-22 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Todd, J., Heil Company. April 14, 1981.
Information on tank truck conversion costs.
IV-E-24 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Hemphill, R., Fruehauf Corporation.
April 20, 1981. Information on tank truck conversion costs.
IV-E-25 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Botkin, L., Fruehauf Corporation. April 20,
1981. Information on tank truck conversion costs.
IV-E-26 Telecon. Gschwandtner, K.C., Pacific Environmental Services,
Incorporated, with Ritterbush, J., J & L Tanks. April 20,
1981. Information on tank truck conversion costs.
IV-E-27 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Kirkland, J., Hirt Combustion Engineering.
April 20, 1981. Information on cost of compression-oxidation
vapor control units.
IV-E-30 Telecon. Norton, R.L., Pacific Environmental Services,
Incorporated, with McGill, J., McGill, Incorporated. April
23, 1981. Information on carbon adsorption units.
IV-E-32 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Edwards, R., Edwards Engineering Company.
April 28, 1981. Information on refrigeration units.
IV-E-33 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Welpe, B., Hunn Corporation. April 29,
1981. Information on cost of loading rack conversions.
These numbers correspond to the docket item number in Docket No. A-79-52.
B-28
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IV-E-35 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Bitter!ich, G., National Airoil Burner
Company. April 30, 1981. Information on cost of thermal
oxidizer units.
IV-E-36 Telecon. Schmidt, E., McGill, Incorporated, with Norton,
R.L., Pacific Environmental Services, Incorporated. April 30,
1981. Information on carbon adsorption units.
IV-E-37 Telecon. Guischard, C., AER Corporation, with LaFlan, G.A.,
Pacific Environmental Services, Incorporated. May 4, 1981.
Information on cost of thermal oxidizer units.
IV-E-38 Telecon. Lowery, E., ARCO, with LaFlam, G.A., Pacific
Environmental Services, Incorporated, flay 5, 1981. Information
on maintenance and electrical costs of Edwards DE Model
refrigeration unit.
IV-E-39 Telecon. LaFlam, G.A., Pacific Environmental Services,
Incorporated, with Ottoson, R.S., Ray Construction Company,
Incorporated. May 6, 1981. Information on design and costs
associated with loading rack conversions.
IV-E-47 Telecon. Cryer, C., JACA Corporation, with Sheirik, K.,
Small Business Association. June 17, 1981. Size criteria
for small businesses.
IV-J-5 California Air Resources Board. Certification Evaluation
Report No. C-9-058 of Hirt Vapor Recovery Unit. August
1980.
IV-J-8 Edwards Engineering Corporation. Hydrocarbon vapor recovery
units price list. January 1, 1981.
IV-J-12 American Trucking Associations, Incorporated. 1978 Motor
Carrier Annual Report—Financial and Operating Statistics.
Washington, D.C. 1979. 812 p.
IV-J-13 Robert Morris Associates. Annual Statement Studies. 1980.
p. 217.
IV-J-14 Chemical Engineering. McGraw-Hill, Inc. May 18, 1981. p. 7.
B-29
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before cornz'.cnm::
1 REPORT NO
EPA-450/3-80-038b
2. >3. RECIPIENT'S ACCESSION NO.
4 TITLE AND SUBTITLE
Sulk Gasoline Terminals - Background Information for
Promulgated Standards
7 AUTHOR(S)
5. REPORT OATE
August 1933
6. PERFORMING ORGANIZATION CODE
8 PERFORMING ORGANIZATION REPORT NC
9 °E3FORMING ORGANIZATION NAME AND ADDRESS . TO. PROGRAM ELEMENT NO.
Offirp nf Air Quality PlApm'nn and Stan Hard-;
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
,11. CONTRACT/GRANT NO.
68-02-3060
12. SPONSORING AGENCY NAME AND ADDRESS
OAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVEREC
14. SPONSORING AGENCY CODE
EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
Standards of performance to control volatile organic compound emissions from
new, modified, and reconstructed bulk gasoline terminal loading racks are being
promulgated under the authority of Section 111 of the Clean Air Act. This document
contains a detailed summary of the public comments on the proposed standards
(45 FR 83126), responses to these comments and a summary of the changes to the
proposed standards.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATi f-ieid/Group
Air Pollution
Pollution Control
Standards of Performance
Bulk Gasoline Terminals
VOC
Air Pollution Control
13b
Unlimi ted
19. SECURITY CLASS (This Reponi
Unclassified
I 21. NO. OF PAGES
i 136
I 20. SECURITY CLASS ,'This page;
i Unclassified
|22. PRICS
."PA Form 2220-1 (Rev. 4-771 PREVIOUS EDITION is OSSOLE'E
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